WildHorse Resource Development Corp (Form: 10-Q, Received: 08/10/2017 16:21:17)

WildHorse Resource Development Corporation

(Registrant)

August 10, 2017

/s/ Andrew J. Cozby

Andrew J. Cozby

Executive Vice President and

Chief Financial Officer

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2017

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

For the transition period from to .

Commission File Number: 001-37964

WildHorse Resource Development Corporation

(Exact name of Registrant as specified in its Charter)

Delaware		81-3470246
( State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

9805 Katy Freeway, Suite 400, Houston, TX		77024
(Address of principal executive offices)		(Zip Code)

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

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

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

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

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

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

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definition of “large accelerated filer”, “accelerated filer”, “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer	☐		Accelerated filer	☐

Non-accelerated filer	☒	(Do not check if a small reporting company)	Small reporting company	☐

			Emerging growth company	☒

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

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

As of July 31, 2017, the registrant had 101,135,300 shares of common stock, $0.01 par value outstanding.

WILDHORSE RESOURCE DEVELOPMENT CORPORATION

TABLE OF CONTENTS

		Page

	Glossary of Oil and Natural Gas Terms	2
	Commonly Used Defined Terms	6
	Cautionary Note Regarding Forward-Looking Statements	8

	PART I—FINANCIAL INFORMATION
Item 1.	Financial Statements	10
	Unaudited Condensed Consolidated Balance Sheets as of June 30, 2017 and December 31, 2016	10
	Unaudited Statements of Condensed Consolidated and Combined Operations for the Three Months and Six Months Ended June 30, 2017 and 2016	11
	Unaudited Statements of Condensed Consolidated and Combined Cash Flows for the Three Months and Six Months Ended June 30, 2017 and 2016	12
	Unaudited Condensed Consolidated Statement of Changes in Stockholders’ Equity for the Six Months Ended June 30, 2017	13
	Note 1 – Organization and Basis of Presentation	14
	Note 2 – Summary of Significant Accounting Policies	15
	Note 3 – Acquisitions and Divestitures	16
	Note 4 – Fair Value Measurements of Financial Instruments	18
	Note 5 – Risk Management and Derivative Instruments	20
	Note 6 – Accounts Receivable	22
	Note 7 – Accrued Liabilities	22
	Note 8 – Asset Retirement Obligations	22
	Note 9 – Long Term Debt	23
	Note 10 – Preferred Stock	24
	Note 11 – Equity	26
	Note 12 – Earnings Per Share	27
	Note 13 – Long Term Incentive Plans	27
	Note 14 – Incentive Units	27
	Note 15 – Related Party Transactions	28
	Note 16 – Segment Disclosures	30
	Note 17 – Income Tax es	30
	Note 18 – Commitments and Contingencies	31
	Note 19 – Subsequent Events	32

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	33
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	45
Item 4.	Controls and Procedures	46

	PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	47
Item 1A.	Risk Factors	47
Item 2.	Unregistered Sales Of Equity Securities and Use of Proceeds	47
Item 3.	Defaults Upon Senior Securities	47
Item 4.	Mine Safety Disclosures	47
Item 5.	Other Information	47
Item 6.	Exhibits	47

	Signatures	48

GLOSSARY OF OIL AND NATURAL GAS TERMS

The following are abbreviations and definitions of 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.

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

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

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

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

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

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

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

Differential: An adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.

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

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

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

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

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

Field: 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 surfa ce and the underground productive formations. For a complete definition of field, refer to the SEC’s Regulation S-X, Rule 4-10(a)(15).

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

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

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

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

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

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

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

MBoe: One thousand Boe.

Mcf: One thousand cubic feet of natural gas.

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

MMBoe: One million Boe.

MMBtu: One million British thermal units.

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

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

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

NYMEX: The New York Mercantile Exchange.

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

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

Play: A geographic area with hydrocarbon potential.

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

Present value of future net revenues or PV-10: 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.

Product ion 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 equ ipment and facilities. For a complete definition of production costs, refer to the SEC’s Regulation S-X, Rule 4-10(a)(20).

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

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

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

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

Proved properties: Properties with proved reserves.

Proved reserves: Those quantities of oil, natural gas and NGLs, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. For a complete definition of proved oil and natural gas reserves, refer to the SEC’s Regulation S-X, Rule 4-10(a)(22).

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

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

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

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

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 rema ining 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 expect ation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to market and all permits and financing required to implement the project. Reserves sho uld 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 accum ulation 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.

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.

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.

COMMONLY USED DEFINED TERMS

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

•

the “Company,” “WildHorse Development,” “we,” “our,” “us” or like terms refer collectively to WHR II and Esquisto, together with their consolidated subsidiaries before the completion of our Corporate Reorganization and to WildHorse Resource Development Corporation and its consolidated subsidiaries, including WHR II, Esquisto and Acquisition Co., as of and following the completion of our Corporate Reorganization;

•

“WHR II” 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 February 16, 2015, to Esquisto I (iii) for the period beginning February 17, 2015 (date of common control) through January 11, 2016, to Esquisto I and Esquisto II on a combined basis and (iv) for the period beginning January 12, 2016 through the completion of our initial public offering on December 19, 2016, to Esquisto II;

•

“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;

•

“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 formed to acquire the Burleson North Assets;

•

“Previous owner” refers to both Esquisto and Acquisition Co.;

•

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

•

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

•

“WildHorse 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 issued by WildHorse Holdings in connection with our initial public offering;

•

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

•

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

•

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

•

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

•

“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 North Louisiana 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;

•

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

•

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

•

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

•

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

FORWARD–LOOKI NG STATEMENTS

This Quarterly Report on Form 10-Q (“Quarterly Report”) contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact included in this Quarterly Report, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Quarterly Report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on management’s current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under “Part I—Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2016 (“2016 Form 10-K”) and “Part II—Item 1A. Risk Factors” appearing within this Quarterly Report and elsewhere in this Quarterly Report.

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;

•

competition and government regulations;

•

our ability to obtain permits and governmental approvals;

•

pending legal or environmental matters;

•

our marketing of oil, natural gas and NGLs;

•

our leasehold or business acquisitions;

•

costs of developing our properties;

•

general economic conditions;

•

credit markets;

•

uncertainty regarding our future operating results; and

•

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

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the development, production, gathering and sale of oil and natural gas. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures and the other risks described under “Part I—Item 1A. Risk Factors” of our 2016 Form 10-K.

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 Quarterly Report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from th ose expressed in any forward-looking statements.

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

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

PART I—FINANCI AL INFORMATION

ITEM 1. FINANCIAL STATEMENTS.

WILDHORSE RESOURCE DEVELOPMENT CORPORATION

UNAUDITED CONDENSE D CONSOLIDATED BALANCE SHEETS

(In thousands, except outstanding shares)

	June 30,			December 31,
	2017			2016
ASSETS
Current Assets:
Cash and cash equivalents	$	14,633		$	3,115
Accounts receivable, net		41,997			26,428
Short-term derivative instruments		28,192			—
Prepaid expenses and other current assets		3,695			1,633
Total current assets		88,517			31,176
Property and equipment:
Oil and gas properties		2,475,082			1,573,848
Other property and equipment		41,320			34,344
Accumulated depreciation, depletion and amortization		(259,636	)		(200,293	)
Total property and equipment, net		2,256,766			1,407,899
Other noncurrent assets:
Restricted cash		752			886
Long-term derivative instruments		24,435			—
Debt issuance costs		3,080			2,320
Total assets	$	2,373,550		$	1,442,281
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	25,176		$	21,014
Accrued liabilities		125,746			23,371
Short-term derivative instruments		822			14,087
Asset retirement obligations		90			90
Total current liabilities		151,834			58,562
Noncurrent liabilities:
Long-term debt		485,033			242,750
Asset retirement obligations		13,661			10,943
Deferred tax liabilities		139,445			112,552
Long-term derivative instruments		49			8,091
Other noncurrent liabilities		1,296			1,495
Total noncurrent liabilities		639,484			375,831
Total liabilities		791,318			434,393

Commitments and contingencies

Series A perpetual convertible preferred stock, $0.01 par value: 50,000,000 shares authorized; 435,000 shares issued and outstanding at June 30, 2017		432,657			—

Stockholders’ equity:
Common stock, $0.01 par value 500,000,000 shares authorized; 101,136,017 shares and 91,680,441 shares issued and outstanding at June 30, 2017 and December 31, 2016, respectively		1,011			917
Additional paid-in capital		1,112,416			1,017,368
Accumulated earnings (deficit)		36,148			(10,397	)
Total stockholders’ equity		1,149,575			1,007,888
Total liabilities and equity	$	2,373,550		$	1,442,281

See Accompanying Notes to Unaudited Condensed Consolidated and Combined Financial Statements

WILDHORSE RESOURCE DEVELOPMENT CORPORATION

UNAUDITED STATEMENTS OF CONDENSED CONSOLIDATED AND COMBINED OPERATIONS

(In thousands, except per share amounts)

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2017			2016			2017			2016
Revenues:
Oil sales	$	52,963		$	18,683		$	92,040		$	31,936
Natural gas sales		13,277			9,233			25,422			19,439
NGL sales		3,404			1,225			6,067			2,170
Other income		529			574			936			1,297
Total operating revenues		70,173			29,715			124,465			54,842
Operating expenses:
Lease operating expenses		6,837			2,302			13,765			5,062
Gathering, processing and transportation		1,942			1,583			3,642			3,474
Gathering system operating expense		25			64			44			118
Taxes other than income tax		4,509			1,785			8,408			3,257
Depreciation, depletion and amortization		33,229			19,923			59,672			41,986
General and administrative		10,049			4,683			17,531			9,132
Exploration expense		11,504			80			13,119			7,523
Total operating expense		68,095			30,420			116,181			70,552
Income (loss) from operations		2,078			(705	)		8,284			(15,710	)
Other income (expense):
Interest expense, net		(6,633	)		(1,781	)		(12,204	)		(3,753	)
Debt extinguishment costs		—			—			11			(358	)
Gain (loss) on derivative instruments		46,116			(15,610	)		77,407			(12,364	)
Other income (expense)		(2	)		(74	)		13			(62	)
Total other income (expense)		39,481			(17,465	)		65,227			(16,537	)
Income (loss) before income taxes		41,559			(18,170	)		73,511			(32,247	)
Income tax benefit (expense)		(15,193	)		(111	)		(26,893	)		(250	)
Net income (loss)		26,366			(18,281	)		46,618			(32,497	)
Net income (loss) attributable to previous owners		—			(5,265	)		—			(7,782	)
Net income (loss) attributable to predecessor		—			(13,016	)		—			(24,715	)
Net income (loss) available to WildHorse Development		26,366			—			46,618			—
Preferred stock dividends		73			—			73			—
Undistributed earnings allocated to participating securities		387			—			434			—
Net income (loss) available to common stockholders	$	25,906		$	—		$	46,111		$	—

Earnings per common share:
Basic	$	0.28		n/a			$	0.49		n/a
Diluted	$	0.28		n/a			$	0.49		n/a
Weighted-average common shares outstanding:
Basic		93,685		n/a				93,452		n/a
Diluted		93,685		n/a				93,452		n/a

See Accompanying Notes to Unaudited Condensed Consolidated and Combined Financial Statements

WILDHORSE RESOURCE DEVELOPMENT CORPORATION

UNAUDITED STATEMENTS OF CONDENSED CONSOLIDATED AND COMBINED CASH FLOWS

(In thousands)

	For the Six Months Ended June 30,
	2017			2016
Cash flows from operating activities:
Net income (loss)	$	46,618		$	(32,497	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		59,367			41,788
Accretion of asset retirement obligations		305			198
Dry hole expense and impairments of unproved properties		10,663			62
Amortization of debt issuance cost		1,277			228
(Gain) loss on derivative instruments		(77,407	)		12,364
Cash settlements on derivative instruments		1,093			5,898
Accretion of senior note discount		105			—
Deferred income tax expense (benefit)		26,893			230
Debt extinguishment expense		(11	)		358
Amortization of equity awards		1,803			—
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable		(22,307	)		(3,876	)
Decrease (increase) in prepaid expenses and other current assets		(1,760	)		2,390
(Decrease) increase in accounts payable and accrued liabilities		25,395			(9,830	)
Net cash flow provided by operating activities		72,034			17,313
Cash flows from investing activities:
Acquisitions of oil and gas properties		(547,389	)		(4,228	)
Additions to oil and gas properties		(211,264	)		(73,375	)
Additions to and acquisitions of other property and equipment		(6,189	)		(2,827	)
Change in restricted cash		135			(86	)
Net cash used in investing activities		(764,707	)		(80,516	)
Cash flows from financing activities:
Advances on revolving credit facilities		161,500			89,000
Payments on revolving credit facilities		(258,250	)		(101,000	)
Debt issuance cost		(10,756	)		(480	)
Termination of second lien		—			(225	)
Proceeds from senior notes offering		347,354			—
Proceeds from the issuance of preferred stock		435,000			—
Costs incurred in conjunction with the issuance of preferred stock		(2,416	)		—
Proceeds from the issuance of common stock		34,457			—
Cost incurred in conjunction with the issuance of common stock		(2,097	)		—
Cost incurred in conjunction with the initial public offering		(601	)		—
Previous owner contributions		—			25,000
Predecessor contributions		—			13,280
Net cash provided by financing activities		704,191			25,575
Net change in cash and cash equivalents		11,518			(37,628	)
Cash and cash equivalents, beginning of period		3,115			43,126
Cash and cash equivalents, end of period	$	14,633		$	5,498

See Accompanying Notes to Unaudited Condensed Consolidated and Combined Financial Statements

WILDHORSE RESOURCE DEVELOPMENT CORPORATION

UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF

CHANGES IN STOCKHOLDERS’ EQUITY

(In thousands)

	Stockholders’ Equity
	Common Stock		Additional Paid in Capital			Accumulated Earnings (Deficit)			Total Stockholders' Equity
December 31, 2016	$	917	$	1,017,368		$	(10,397	)	$	1,007,888
Net income (loss)		—		—			46,618			46,618
Issuance of common stock		23		34,434			—			34,457
Costs incurred in connection with the issuance of common stock		—		(1,872	)		—			(1,872	)
Issuance of common stock in connection with the Acquisition		55		60,699			—			60,754
Accrual of preferred stock paid-in-kind dividend		—		—			(73	)		(73	)
Amortization of equity awards		16		1,787			—			1,803
June 30, 2017	$	1,011	$	1,112,416		$	36,148		$	1,149,575

See Accompanying Notes to Unaudited Condensed Consolidated and Combined Financial Statements

WILDHORSE RESOURCE DEVELOPMENT CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Note 1. Organization and Basis of Presentation

WildHorse Resource Development Corporation is a publicly traded Delaware corporation, the common stock of which are listed on the New York Stock Exchange (“NYSE”) under the symbol “WRD.” Unless the context requires otherwise, references to “we,” “us,” “our,” “WRD,” or “the Company” are intended to mean the business and operations of WildHorse Resource Development Corporation and its consolidated subsidiaries. We are an independent oil and natural gas company focused on the acquisition, exploitation, development and production of oil, natural gas and NGL resources in the United States of America.

Reference to “WHR II” or our “predecessor” refers to WildHorse Resources II, LLC, together with its consolidated subsidiaries. Reference to “Esquisto I” refers to Esquisto Resources, LLC. Reference to “Esquisto II” refers to Esquisto Resources II, LLC. Reference to “Esquisto Merger” refers to the merger of Esquisto I with and into Esquisto II on January 12, 2016. Reference to “Esquisto” refers (i) for the period beginning February 17, 2015 (date of common control) through January 11, 2016, to Esquisto I and Esquisto II on a combined basis and (ii) for the period beginning January 12, 2016 through the completion of our initial public offering on December 19, 2016, to Esquisto II. Reference to “Acquisition Co.” refers to WHE AcqCo., LLC, an entity that was formed to acquire the Burleson North assets (see Note 3—Acquisitions and Divestitures). Reference to “WildHorse Investment Holdings” refers to WildHorse Investment Holdings, LLC. Reference to “Previous owner” refers to both Esquisto and Acquisition Co. Reference to “Esquisto Investment Holdings” refers to Esquisto Investment Holdings, LLC. Reference to “WildHorse Holdings” refers to WHR Holdings, LLC. Reference to “Esquisto Holdings” refers to Esquisto Holdings, LLC. Reference to “Acquisition Co. Holdings” refers to WHE AcqCo Holdings, LLC. Reference to “NGP” refers to Natural Gas Partners, a family of private equity investment funds organized to make direct equity investments in the energy industry, including the funds invested in WHR II, Esquisto and Acquisition Co.

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

Basis of Presentation

Our predecessor’s financial statements were retrospectively recast due to common control considerations. Because WHR II, Esquisto and Acquisition Co. were under the common control of NGP, the sale and contribution of the respective ownership interests were accounted for as a combination of entities under common control, whereby the assets and liabilities sold and contributed were recorded based on historical cost. As such, the financial statements included herein for the three and six months ended June 30, 2016 have been derived from the combined financial position and results attributable to our predecessor and Esquisto. For periods after the completion of our initial public offering, our consolidated financial statements include our accounts and those of our subsidiaries.

Certain amounts in the prior year financial statements have been reclassified to conform to current presentation. Gathering, processing, and transportation costs were previously accounted for as revenue deductions and are now being presented as costs and expenses on our statements of operations on a separate line item. Oakfield drip condensate was reclassified from oil sales to other income.

All material intercompany transactions and balances have been eliminated in preparation of our condensed consolidated and combined financial statements. The accompanying condensed consolidated and combined interim financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”).

WILDHORSE RESOURCE DEVELOPMENT CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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, natural 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 (“ARO”); (6) environmental remediation costs; (7) valuation of derivative instruments; (8) incentive unit compensation cost; (9) contingent liabilities and (10) impairment expense. Although management believes these estimates are reasonable, changes in facts and circumstances or discovery of new information may result in revised estimates, and such revisions could be material.

Note 2. Summary of Significant Accounting Policies

A discussion of our significant accounting policies and estimates is included in our 2016 Form 10-K.

Supplemental Cash Flow Information

Supplement cash flow for the periods presented (in thousands):

	For the Six Months Ended June 30,
	2017		2016
Supplemental cash flows:
Cash paid for interest, net of capitalized interest	$	306	$	3,671
Noncash investing activities:
Increase (decrease) in capital expenditures in accounts payables and accrued liabilities		82,295		(5,321	)

New Accounting Standards

Improvements to Employee Share-Based Payment Accounting. In March 2016, the Financial Accounting Standards Board (“FASB”) issued an accounting standards update to simplify the guidance on employee share-based payment accounting. The update involved several aspects of accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification in the statement of cash flows. This new standard became effective for annual periods beginning after December 15, 2016. The Company adopted this guidance as of January 1, 2017 and it did not have a material impact on our consolidated financial statements. We elected to account for forfeitures on share-based payments by recognizing forfeitures of awards as they occur.

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. Although early adoption is permitted for all entities as of the beginning of an interim or annual reporting period, the Company will apply the revised lease rules for our interim and annual reporting periods starting January 1, 2019 using the required modified retrospective approach, including applicable practical expedients related to leases commenced before the effective date. As the Company is the lessee under various agreements for office space, compressors and equipment currently accounted for as operating leases, the new rules will increase reported assets and liabilities. The full quantitative impacts of the new standard are dependent on the leases in force at the time of adoption and, as a result, the evaluation of the effect of the new standards will extend over future periods.

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

WILDHORSE RESOURCE DEVELOPMENT CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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 reco gnized. 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 effective for fiscal years, and interim periods within those years, beginning after December 15, 2017. Although early adoption was permitted, the Company decided not to early adopt. The new guidance will be applicable to us beginning on January 1, 2018. The standard permits the use of either the retrospective or cumulative effect trans ition method. The Company has not yet selected a transition method. We do not currently expect that adoption of the new revenue recognition standard will materially impact revenue recognition for many types of our arrangements. Documentation of our reven ue streams and related contract reviews is currently underway and expected to be completed by the end of September. During the fourth quarter, we plan to update our existing business process and internal control documentation for any new or revised proces ses and controls .

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.

Note 3. Acquisitions and Divestitures

Acquisition-related costs

Acquisition-related costs for both related party and third party transactions are included in general and administrative expenses in the accompanying statements of operations for the periods indicated below (in thousands):

For the Three Months Ended June 30,				For the Six Months Ended June 30,
2017		2016		2017		2016
$	2,199	$	72	$	2,798	$	72

2017 Acquisitions

The Acquisition. On May 10, 2017, we, through our wholly owned subsidiary, WHR EF, entered into a Purchase and Sale Agreement (the “First Acquisition Agreement”) by and among WHR EF, as purchaser, and APC and KKR (together with APC, the “First Sellers”), as sellers, to acquire certain acreage and associated production in Burleson, Brazos, Lee, Milam, Robertson, and Washington Counties, Texas (the “Purchase”). Also on May 10, 2017, WHR EF entered into a Purchase and Sale Agreement (together, with the First Acquisition Agreement, the “Acquisition Agreements”), by and among WHR EF, as purchaser, and APC and Anadarko Energy Services Company (together, with APC, the “APC Subs” and together, with the First Sellers, the “Sellers”), as sellers, to acquire certain acreage and associated production in Burleson, Brazos, Lee, Milam, Robertson, and Washington Counties, Texas (together, with the Purchase, the “Acquisition”).

On June 30, 2017, we completed the Acquisition. The aggregate purchase price for the Acquisition, which is subject to customary adjustments as provided in the Acquisition Agreements, consisted of approximately $533.6 million of cash to the APC Subs and approximately 5.5 million shares of our common stock valued at approximately $60.8 million to KKR (collectively, the “Adjusted Purchase Price”). The common stock consideration price payable to KKR was issued pursuant to a Stock Issuance Agreement that was executed on May 10, 2017 (the “Stock Issuance Agreement”), by and among us and KKR.

WILDHORSE RESOURCE DEVELOPMENT CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

The following table summarizes the fair value assessment of the assets acquired and liabilities assumed as of the closing of the Acquisition (in thousan ds):

Consideration :
Cash	$	533,609
Common stock		60,754
Total consideration	$	594,363

Preliminary Purchase Price Allocation:
Proved oil and gas properties	$	264,144
Unproved oil and gas properties		333,778
Accounts receivable		967
Asset retirement obligations		(2,500	)
Accrued liabilities		(2,026	)
Total identifiable net assets	$	594,363

Supplemental Pro forma Information . The following unaudited pro forma combined results of operations are provided for the three months and six months ended June 30, 2017 and 2016 as though the Acquisition had been completed on January 1, 2016 (in thousands, except per share amounts). The unaudited pro forma financial information was derived from the historical combined statements of operations of the predecessor and previous owners and adjusted to include: (i) the revenues and direct operating expenses associated with oil and natural gas properties acquired in the Acquisition and (ii) depletion expense applied to the adjusted basis of the properties acquired in the Acquisition. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the Acquisition occurred on the basis assumed above, nor is such information indicative of expected future results of operations.

	For the Three Months Ended June 30,					For the Six Months Ended June 30,
	2017		2016			2017		2016
Revenues	$	93,471	$	55,198		$	172,674	$	100,868
Net Income		38,747		(7,674	)		69,777		(17,510	)
Earnings per share (basic and diluted)		0.41	n/a				0.74	n/a

Burleson 2017 Acquisitions. We announced multiple transactions to acquire certain oil and natural gas producing and non-producing properties from third-parties in Burleson County, Texas. On February 2, 2017, we closed one transaction for approximately $2.4 million. We allocated $2.3 million of the purchase price to unproved oil and natural gas properties after customary post-closing adjustments. On April 18, 2017, we closed the remaining transactions for an aggregate price of approximately $12.5 million, subject to customary post-closing adjustments. We allocated $7.0 million to proved oil and gas properties and $5.5 million to unproved oil and gas properties. In addition to the transactions we previously announced, on May 17, 2017 we entered into an agreement to acquire unproved oil and natural gas properties from a third party in Burleson County, Texas. On June 27, 2017, we closed this transaction for approximately $2.2 million. The purchase price was allocated entirely to unproved oil and gas properties.

2016 Acquisitions

Burleson North Acquisition . As discussed in our 2016 Form 10-K, we completed an acquisition of approximately 158,000 net acres of oil and natural gas properties adjacent to our existing Eagle Ford acreage on December 19, 2016 in connection with our initial public offering (the “Burleson North Acquisition”). Funds wired on December 19, 2016 were $389.8 million. During the three months ending March 31, 2017, we received a post-closing receipt of $3.9 million. The following table summarizes the fair value assessment of the assets acquired and liabilities assumed as of the acquisition date after customary post-closing adjustments (in thousands). We allocated $162.9 million of the purchase price to unproved oil and natural gas properties.

WILDHORSE RESOURCE DEVELOPMENT CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

	Purchase Price
Oil and natural gas properties	$	395,591
Other property and equipment		478
Accounts receivable		1,257
Accounts payable		(1,816	)
Asset retirement obligations		(3,101	)
Accrued liabilities		(6,503	)
Total identifiable net assets	$	385,906

Supplemental Pro forma Information . The following unaudited pro forma combined results of operations are provided for the three months and six months ended June 30, 2016 as though the Burleson North Acquisition had been completed on January 1, 2015 (in thousands, except per share amounts). The unaudited pro forma financial information was derived from the historical combined statements of operations of the predecessor and previous owners and adjusted to include: (i) the revenues and direct operating expenses associated with oil and natural gas properties acquired and (ii) depletion expense applied to the adjusted basis of the properties acquired. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the Burleson North acquisition occurred on the basis assumed above, nor is such information indicative of expected future results of operations.

	For the Three Months Ended June 30, 2016			For the Six Months Ended June 30, 2016
Revenues	$	43,393		$	78,727
Net income (loss)		(13,822	)		(28,051	)
Basic and diluted earnings per share	n/a			n/a

Note 4. Fair Value Measurements of Financial Instruments

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. Fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk. A three-tier hierarchy has been established that classifies fair value amounts recognized or disclosed in the financial statements. The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3). All of the derivative instruments reflected on the accompanying balance sheets were considered Level 2.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The carrying values of cash and cash equivalents, restricted cash, accounts receivables, accounts payables (including accrued liabilities) and amounts outstanding under long-term debt agreements with variable rates included in the accompanying balance sheets approximated fair value at June 30, 2017 and December 31, 2016. The fair value estimates are based upon observable market data and are classified within Level 2 of the fair value hierarchy. These assets and liabilities are not presented in the following tables.

The fair market values of the derivative financial instruments reflected on the balance sheets as of June 30, 2017 and December 31, 2016 were based on estimated forward commodity prices (including nonperformance risk). Nonperformance risk is the risk that the obligation related to the derivative instrument will not be fulfilled. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement in its entirety. The significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

WILDHORSE RESOURCE DEVELOPMENT CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

The following table presents the derivative assets and liabilities that are measured at fair value on a recurring basis at June 30, 2017 and December 31, 2016 for each of the fair value hierarch y levels:

	Fair Value Measurements at June 30, 2017 Using
	Quoted Prices in Active Market (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Fair Value
	(In thousands)
Assets:
Commodity derivatives	$	—	$	53,379	$	—	$	53,379

Liabilities:
Commodity derivatives	$	—	$	1,623	$	—	$	1,623

	Fair Value Measurements at December 31, 2016 Using
	Quoted Prices in Active Market (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Fair Value
	(In thousands)
Assets:
Commodity derivatives	$	—	$	7	$	—	$	7

Liabilities:
Commodity derivatives	$	—	$	22,185	$	—	$	22,185

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Certain assets and liabilities are reported at fair value on a nonrecurring basis as reflected on the balance sheets. The following methods and assumptions are used to estimate the fair values:

•

The fair value of AROs is based on discounted cash flow projections using numerous estimates, assumptions, and judgments regarding such factors as the existence of a legal obligation for an ARO; amounts and timing of settlements; the credit-adjusted risk-free rate; and inflation rates. The fair value estimates are based on unobservable market data and are classified within Level 3 of the fair value hierarchy. See “Note 8—Asset Retirement Obligations” for a summary of changes in AROs.

•

If sufficient market data is not available, the determination of the fair values of proved and unproved properties acquired in transactions accounted for as business combinations are prepared by utilizing estimates of discounted cash flow projections. The factors to determine fair value include, but are not limited to, estimates of: (i) economic reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital. To compensate for the inherent risk of estimating and valuing unproved properties, the discounted future net revenues of probable and possible reserves are reduced by additional risk-weighting factors. The fair value of supporting equipment, such as plant assets, acquired in transactions accounted for as business combinations are commonly estimated using the depreciated replacement cost approach.

•

Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate the carrying value of such properties may not be recoverable. The factors used to determine fair value include, but are not limited to, estimates of proved 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 natural gas properties. We did not record impairments during the three and six months ended June 30, 2017 and 2016.

WILDHORSE RESOURCE DEVELOPMENT CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

•

Unproved oil and natural gas properties are reviewed for impairment based on passage of time or geologic factors. Information such as remaining lease terms, drilling results, reservoir performance, seismic interpretation or future plans to develop acreage is also considered. When unproved properties are deemed to be impaired, the expense is recorded as a component of exploration expenses. For the three and six months ended June 30, 2017, we recorded $10.0 million and $10.7 million of impairments of unpro ved properties. We recorded $0.1 million in impairments on unproved properties for both the three and six months ended June 30, 2016.

Note 5. Risk Management and Derivative Instruments

We have entered into certain derivative arrangements with respect to portions of our oil and natural gas 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 oil and natural gas 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.

Commodity Derivatives

We have fixed price commodity swaps, collars and deferred purchased puts to accomplish our hedging strategy. Collars consist of a sold call and a purchased put that establish a ceiling and floor price for expected future oil and natural gas sales. We recognize all derivative instruments at fair value; however, certain of our derivative instruments have a deferred premium. The deferred premium is factored into the fair value measurement and where the Company agrees to defer the premium paid or received until the time of settlement. Cash received on settled derivative positions during the three and six months ended June 30, 2017 is net of deferred premiums of $0.5 million and $0.6 million, respectively.

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 only lenders under our revolving credit facility, which 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. Master netting agreements are used to mitigate risk of loss due to default with counterparties on derivative instruments by providing us and each of our counterparties with rights of set-off upon the occurrence of defined acts of default by either us or our counterparty to a derivative or other financial instrument, whereby the party not in default may set-off all liabilities owed to the defaulting party against all net derivative and other financial asset receivables from the defaulting party. At June 30, 2017 we had net derivative assets of $51.8 million. As a result, had certain counterparties failed completely to perform according to the terms of existing contracts, we would have the right to offset $43.7 million against amounts outstanding under our revolving credit facility, thereby reducing our maximum credit exposure to approximately $8.1 million which was with one counterparty.

See “Note 4—Fair Value Measurements of Financial Instruments” for further information.

WILDHORSE RESOURCE DEVELOPMENT CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

The following derivative contracts were in place at June 30, 2017:

	Remainder 2017			2018			2019
Crude Oil Derivative Contracts:
Fixed price swap contracts:
Volume (Bbls)		1,185,971			5,023,163			3,284,623
Weighted-average fixed price	$	52.57		$	53.29		$	53.80

Collar contracts:
Volume (Bbls)		28,240			25,096			—
Weighted-average floor price	$	50.00		$	50.00		$	—
Weighted-average ceiling price	$	62.10		$	62.10		$	—

Put options:
Volume (Bbls)		1,215,036			597,850			410,525
Weighted-average floor price	$	55.00		$	50.00		$	50.00
Weighted-average put premium	$	(4.77	)	$	(5.95	)	$	(5.95	)

Natural Gas Derivative Contracts:
Fixed price swap contracts:
Volume (MMBtu)		4,000,500			11,565,800			9,877,900
Weighted-average fixed price	$	3.12		$	3.03		$	2.81

Collar contracts:
Volume (MMBtu)		2,760,000			—			—
Weighted-average floor price	$	3.00		$	—		$	—
Weighted-average ceiling price	$	3.36		$	—		$	—

Put options:
Volume (MMBtu)		2,971,208			—			—
Weighted-average floor price	$	3.40		$	—		$	—
Weighted-average put premium	$	(0.37	)	$	—		$	—

Balance Sheet Presentation

The following table summarizes both: (i) the gross fair value of derivative instruments by the appropriate balance sheet classification even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the balance sheet and (ii) the net recorded fair value as reflected on the balance sheet at June 30, 2017 and December 31, 2016 (in thousands). There was no cash collateral received or pledged associated with our derivative instruments since the counterparties to our derivative contracts are lenders under our credit agreement.

		Asset Derivatives						Liability Derivatives
		June 30,			December 31,			June 30,			December 31,
Type	Balance Sheet Location	2017			2016			2017			2016
Commodity contracts	Short-term derivative instruments	$	28,543		$	4		$	1,173		$	14,091
Netting arrangements	Short-term derivative instruments		(351	)		(4	)		(351	)		(4	)
Net recorded fair value		$	28,192		$	—		$	822		$	14,087

Commodity contacts	Long-term derivative instruments	$	24,836		$	3		$	450		$	8,094
Netting arrangements	Long-term derivative instruments		(401	)		(3	)		(401	)		(3	)
Net recorded fair value		$	24,435		$	—		$	49		$	8,091

WILDHORSE RESOURCE DEVELOPMENT CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

(Gains) & Losses on Derivatives

All gains and losses, including changes in the derivative instruments’ fair values, are included as a component of “Other income (expense)” in the Unaudited Statements of Condensed Consolidated and Combined Operations. The following table details the gains and losses related to derivative instruments for the three and six months ending June 30, 2017 and 2016 (in thousands):

	Statements of	For the Three Months Ended June 30,					For the Six Months Ended June 30,
	Operations Location	2017			2016		2017			2016
Commodity derivative contracts	(Gain) loss on derivative instruments	$	(46,116	)	$	15,610	$	(77,407	)	$	12,364

Note 6. Accounts Receivable

Accounts receivable consist of the following (in thousands):

	June 30,			December 31,
	2017			2016
Oil, natural gas and NGL sales	$	25,437		$	13,390
Joint interest billings		13,710			7,898
Derivative receivable		1,948			—
Severance tax		33			392
Other current receivables		969			4,848
Allowance for doubtful accounts		(100	)		(100	)
Total	$	41,997		$	26,428

Note 7. Accrued Liabilities

Accrued liabilities consist of the following (in thousands):

	June 30,		December 31,
	2017		2016
Capital expenditures	$	100,491	$	17,934
Deferred rent		398		386
Lease operating expense		3,070		2,608
General and administrative		4,377		1,471
Severance and ad valorem taxes		4,678		194
Interest expense		10,043		346
Derivative payable		—		428
Other accrued liabilities (1)		2,689		4
Total	$	125,746	$	23,371

(1)

Other accrued liabilities include $1.5 million for seismic acquisition.

Note 8. Asset Retirement Obligations

The Company’s AROs primarily relate to the Company’s portion of future plugging and abandonment costs for wells and related facilities. The following table presents the changes in the asset retirement obligations for the six months ended June 30, 2017 (in thousands):

Asset retirement obligations at beginning of period	$	11,033
Accretion expense		305
Liabilities incurred		2,698
Revisions		(285	)
Asset retirement obligations at end of period		13,751
Less: current portion		(90	)
Asset retirement obligations – long-term	$	13,661

WILDHORSE RESOURCE DEVELOPMENT CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Note 9. Long Term Debt

Our debt obligations consisted of the following at the dates indicated (in thousands):

	June 30,			December 31,
Credit Facility	2017			2016
WRD revolving credit facility	$	146,000		$	242,750
2025 Senior Notes (as defined below) (1)		350,000			—
Unamortized discounts - 2025 Senior Notes		(2,541	)		—
Unamortized debt issuance costs - 2025 Senior Notes		(8,426	)		—
Total long-term debt	$	485,033		$	242,750

(1)	The estimated fair value of this fixed-rate debt was $328.1 million at June 30, 2017. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.

On April 27, 2017, standby letters of credit of $1.9 million were issued to the Railroad Commission of Texas under our revolving credit facility.

Borrowing Base

Credit facilities tied to borrowing base are common throughout the oil and natural gas industry. Our borrowing base is subject to redetermination, on at least a semi-annual basis, primarily based on estimated proved reserves. The borrowing base for our revolving credit facility was the following at the date indicated (in thousands):

	June 30,
Credit Facility	2017
WRD revolving credit facility	$	650,000

Amendment to Credit Agreement

On June 30, 2017, the Company, each of the Company’s wholly owned subsidiaries (each as a guarantor), Wells Fargo Bank, National Association, as administrative agent (the “Administrative Agent”), and the lenders party thereto entered into a Second Amendment (the “Amendment”) to the Credit Agreement dated as of December 19, 2016, among the Company, the Administrative Agent and the other agents and lenders party thereto (as amended, the “Credit Agreement”).

The Amendment, among other things, modified the Credit Agreement to (i) permit the Company to enter into the Acquisition, and the Preferred Stock Purchase Agreement, and perform its obligations under and in connection therewith, including the issuance of the Preferred Stock (see Note 10), (ii) increase the Company’s borrowing base and elected commitment amount from $450 million to $650 million, (iii) increase the annual cap on certain restricted payments from $50 million to $75 million, and (iv) modify the definition of net debt so that certain contingent obligations, accounts payable, obligations to make deliveries in respect of advance payments, take or pay obligations, disqualified capital stock and obligations in respect of production payments are excluded from net debt for purposes of the Company’s leverage covenant.

2025 Senior Notes

On February 1, 2017, we completed a private placement of $350.0 million aggregate principal amount of 6.875% senior unsecured notes due 2025 (the “2025 Senior Notes”). The 2025 Senior Notes were issued at a price of 99.244% of par and resulted in net proceeds of approximately $338.6 million. The 2025 Senior Notes will mature on February 1, 2025 and interest is payable on February 1 and August 1 of each year. The 2025 Senior Notes are fully and unconditionally guaranteed on a joint and several basis by all of our existing and certain future subsidiaries (subject to customary release provisions). The net proceeds from the 2025 Senior Notes were used to repay borrowings outstanding under our revolving credit facility and for general corporate purposes.

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

WILDHORSE RESOURCE DEVELOPMENT CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

In connection with the issuance and sale of the 2025 Senior Notes, the Company and our subsidiary guarantors entered into a registration right s agreement (the “Registration Rights Agreement”) with a representative of the initial purchasers of the 2025 Senior Notes, dated February 1, 2017. Pursuant to the Registration Rights Agreement, we agreed to file a registration statement with the SEC so th at holders of the 2025 Senior Notes can exchange the 2025 Senior Notes for registered notes that have substantially identical terms. In addition, we have agreed to exchange the guarantees related to the 2025 Senior Notes for registered guarantees having su bstantially the same terms as the original guarantees. The Company and the guarantors will use commercially reasonable best efforts to cause the exchange to be consummated within 365 days after the issuance of the 2025 Senior Notes. The Company and the gua rantors are required to pay additional interest if they fail to comply with their obligations to register the 2025 Senior Notes within the specified time periods.

Weighted-Average Interest Rates

The following table presents the weighted-average interest rates paid on our consolidated and combined variable-rate debt obligations for the periods presented:

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
Credit Facility	2017			2016			2017			2016
WRD revolving credit facility		3.40	%	n/a				3.48	%	n/a
WHR II revolving credit facility terminated December 2016	n/a				3.00	%	n/a				3.00	%
Esquisto - revolving credit facility terminated December 2016	n/a				2.80	%	n/a				2.81	%
Esquisto - revolving credit facility terminated January 2016	n/a			n/a			n/a				2.97	%
Esquisto - Second lien terminated in January 2016	n/a			n/a			n/a				9.50	%

Unamortized Debt Issuance Costs

Unamortized deferred financing costs associated with our consolidated debt obligations were as follows at the dates indicated (in thousands):

	June 30,		December 31,
	2017		2016
WRD revolving credit facility (1)	$	3,966	$	2,904
6.875% senior unsecured notes, due February 2025		8,426	n/a
Total	$	12,392	$	2,904

(1)

We classified $0.9 million and $0.6 million of unamortized deferred financing costs at June 30, 2017 and December 31, 2016, respectively, under current assets as a component of “prepaid expenses and other current assets.”

Note 10. Preferred Stock

Preferred Stock Issuance

On June 30, 2017, we completed the Acquisition, which was partially funded through the issuance of the Preferred Stock. On May 10, 2017, we entered in to a Preferred Stock Purchase Agreement (the “Preferred Stock Purchase Agreement”), by and among us and CP VI Eagle Holdings, L.P. (the “Carlyle Investor”), an affiliate of The Carlyle Group, L.P., for $435.0 million dollars in exchange for 435,000 shares of Preferred Stock.

	Series A Perpetual Convertible Preferred Stock (in thousands)
Balance at December 31, 2016	$	—
Issuance of preferred stock in connection with the Acquisition		435,000
Costs incurred related to the issuance of preferred stock		(2,416	)
Preferred stock dividends		73
Balance at June 30, 2017	$	432,657

WILDHORSE RESOURCE DEVELOPMENT CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

The Preferred Stock ranks senior to our common stock with respect to dividend rights and with respect to rights on liquidation, winding-up and dissolution. The Preferred Stock has an initial Accreted Value (as defined in the Certificate) of $1,000 per share and is entitled to a dividend at a rate of 6% per annum on the Accreted Value payable in cash if, as and when declared by our board of directors. If a cash dividend is not declared and paid in respect of any dividend payment period, then the Accreted Value of each outstanding share of Preferred Stock will automatically be increased by the amount of the dividend otherwise payable for such dividend payment period. Any increase in the Accreted Value will, among other things, increase the number of shares of common stock issuable upon conversion of each share of Preferred Stock. The Preferred Stock also participates in dividends and distributions on our common stock on an as-converted basis. If at any time following December 30, 2019, the closing sale price of our common stock equals or exceeds 130% of the Conversion Price (as defined below) for at least 25 consecutive trading days, our obligation to pay dividends on the Preferred Stock shall terminate permanently.

The Preferred Stock is convertible at the option of the holders at any time after June 30, 2018 into the amount of shares of common stock per share of Preferred Stock (such rate, the “Conversion Rate”) equal to the quotient of (i) the Accreted Value in effect on the conversion date divided by (ii) a conversion price of $13.90 (the “Conversion Price”), subject to customary anti-dilution adjustments and customary provisions related to partial dividend periods. The holders of Preferred Stock may also convert their Preferred Stock at the Conversion Rate prior to June 30, 2018 in connection with certain change of control transactions and in connection with sales of common stock by certain of our existing stockholders.

Following June 30, 2021, the Company may cause the conversion of the Preferred Stock at the Conversion Rate, provided the closing sale price of the common stock equals or exceeds 140% of the Conversion Price for the 20 trading days ending on the date immediately prior to the date of delivery of the Company’s notice to convert and subject to certain other requirements regarding registration of the shares issuable upon conversion. Notwithstanding the foregoing, the Company shall only be permitted to deliver one conversion notice during any 180 day period and the number of shares of common stock issued upon conversion of the Preferred Stock for which such automatic conversion notice is given shall be limited to 25 times the average daily trading volume of our common stock during the 20 trading days ending on the date immediately prior to the date of delivery of the Company’s notice to convert.

If the Company undergoes certain change of control transactions, the holders of the Preferred Stock are entitled to cause the Company to redeem the Preferred Stock for cash in an amount equal to the Accreted Value, plus the net present value of dividend payments that would have been accrued as payable to the holders following the date of the consummation of such change of control and through December 30, 2019, in the case of any change of control occurring prior to December 30, 2019 (the “COC Redemption Price”). In addition, the Company has the right in connection with any such change of control transaction (i) to elect to redeem any Preferred Stock contingent upon and contemporaneously with the consummation of such change of control or (ii) to redeem any Preferred Stock following the consummation of such control that is not otherwise converted or redeemed as described in the preceding sentence and clause (i) of this sentence for cash at the COC Redemption Price.

At any time after June 30, 2022, the Company may redeem the Preferred Stock, in whole or in part, for an amount in cash equal to, per each share of Preferred Stock, (i) on or prior to the June 30, 2023, the Accreted Value multiplied by 112%, (ii) on or prior to June 30, 2024, the Accreted Value multiplied by 109% or (ii) after June 30, 2024, the Accreted Value multiplied by 106%.

Until conversion, the holders of the Preferred Stock vote together with our common stock on an as-converted basis and also have rights to vote as a separate class on certain customary matters impacting the Preferred Stock. However, the Preferred Stock is not entitled to vote with the common stock on an as-converted basis, is not convertible into our common stock and is not entitled to the board election rights described below until the Requisite Approvals Notice Date (as defined in the Certificate).

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

WILDHORSE RESOURCE DEVELOPMENT CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Note 11. Equity

Common Stock

The Company’s authorized capital stock includes 500,000,000 shares of common stock, $0.01 par value per share. The following is a summary of the changes in our common stock issued for the six months ended June 30, 2017:

Balance, December 31, 2016			91,680,441
Common stock issued			7,815,225
Restricted common stock issued			1,640,351
Balance, June 30, 2017			101,136,017

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

On June 30, 2017, pursuant to the Acquisition Agreements, we issued 5,518,125 shares of our common stock valued at approximately $60.8 million as partial consideration to KKR. See Note 3 for additional information regarding the Acquisition.

See “Note 13—Long Term Incentive Plans” for additional information regarding the shares of restricted common stock that were granted in connection with our initial public offering. Restricted shares of common stock are considered issued and outstanding on the grant date of the restricted stock award.

Previous Owner Equity

Our previous owner received capital contributions of $25.0 million from its members during the six months ended June 30, 2016.

Predecessor Equity

The predecessor received capital contributions of $13.3 million from its members during the six months ended June 30, 2016.

WILDHORSE RESOURCE DEVELOPMENT CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Note 12. Earni ngs Per Share

The following sets forth the calculation of earnings (loss) per share, or EPS, for the three and six months ending June 30, 2017 (in thousands, except per share amounts). In the calculation of basic net income (loss) per share attributable to common stockholders, participating securities are allocated earnings based on actual dividend distributions received plus a proportionate share of undistributed net income attributable to common stockholders, if any, after recognizing distributed earnings. The Company’s participating securities do not participate in undistributed net losses because they are not contractually obligated to do so.

	For the Three		For the Six
	Months Ended		Months Ended
	June 30, 2017		June 30, 2017
Numerator:
Net income (loss) available to WildHorse Development	$	26,366	$	46,618
Less: Preferred stock dividends		73		73
Less: Undistributed earnings allocated to participating securities		387		434
Net income (loss) available to common stockholders	$	25,906	$	46,111
Denominator:
Weighted-average common shares outstanding (in thousands) (1)		93,685		93,452
Basic EPS	$	0.28	$	0.49
Diluted EPS (1)	$	0.28	$	0.49

(1)

The Company used the two-class method for both basic and diluted EPS. For the three and six months ended June 30, 2017, 455 incremental restricted shares and 308 incremental restricted shares, respectively, were excluded in the calculation of diluted EPS due to their antidilutive effect under the treasury stock method. For both the three and six months ended June 30, 2017, 344 shares and 173 shares were excluded in the calculation of diluted EPS due to their antidilutive effect under the if-converted method.

Note 13. Long Term Incentive Plans

In connection with our initial public offering, our board of directors adopted the 2016 Long-Term Incentive Plan (or “2016 LTIP”). The 2016 LTIP, authorizes the issuance of 9,512,500 shares of our common stock. The following table summarizes information regarding restricted common stock awards granted under the 2016 LTIP for the periods presented:

	Number of Shares		Weighted-Average Grant Date Fair Value per Share (1)
Restricted common stock outstanding at December 31, 2016		353,334	$	14.50
Granted (2)		1,640,351	$	13.94
Restricted common stock outstanding at June 30, 2017		1,993,685	$	14.04

(1)	Determined by dividing the aggregate grant date fair value of shares subject to granted awards by the number of awards.

(2)	The aggregate grant date fair value of restricted common stock awards granted in 2017 was $22.9 million based on grant date market prices ranging from $13.94 per share to $14.22 per share.

For the three and six months ended June 30, 2017, we recorded $1.3 million and $1.8 million of recognized compensation expense, respectively, associated with these awards. Unrecognized compensation cost associated with the restricted common stock awards was an aggregate of $26.1 million at June 30, 2017. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 2.82 years.

Note 14. Incentive Units

The governing documents of WHR II provided for the issuance of incentive units. WHR II granted incentive units to certain of its members who were key employees at the time of grant. The incentive units were accounted for similar to liability-classified awards as achievement of the payout conditions required settlement of such awards by transferring cash to the incentive unit holder. Compensation cost was recognized only if the performance condition was probable of being satisfied at each reporting date. The payment likelihood related to the WHR II incentive units was not deemed probable at June 30, 2016. As such, no compensation expense was recognized by our predecessor.

WILDHORSE RESOURCE DEVELOPMENT CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

In connection with the Corporate Reorganization, the WHR II incentive units were transferred to WildHorse Investment Holdings in exchange for substantially similar ince ntive units in WildHorse Investment Holdings and WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings granted certain officers and employees awards of incentive units in WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings. The fair value of the incentive units will be remeasured on a quarterly basis until all payments have been made. Any future compensation expense recognized will be a non-cash charge, with the settlement obligation resting with WildHorse Investment Holdings, W ildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings, respectively. Accordingly, no payments will ever be made by us related to these incentive units; however, non-cash compensation expense (income) will be allocated to us in future periods o ffset by deemed capital contributions (distributions). As such, these awards are not dilutive to our stockholders. Compensation cost is recognized only if the performance condition is probable of being satisfied at each reporting date. The payment likeliho od related to these incentive units was not deemed probable at June 30, 2017. As such, no compensation expense was recognized by us. Unrecognized compensation costs associated with these incentive units was $21.7 million at June 30, 2017.

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

		Incentive Unit Valuation As Of June 30, 2017
Expected life (years)		1.04 - 5.29
Expected volatility (range)		54.0% - 62.0%
Dividend yield		0.0%
Risk-free rate (range)		1.24% - 1.91%

Note 15. Related Party Transactions

Board of Directors Relationships

Mr. Grant E. Sims has served as a member of our board of directors since February 2017. Mr. Sims has served as a director and Chief Executive Officer of the general partner of Genesis Energy Partners, L.P. (“Genesis”) since August 2006 and Chairman of the board of directors of the general partner since October 2012. Genesis is one of our purchasers of hydrocarbons and other liquids. During the three and six months ended June 30, 2017, we received $0.6 million and $1.5 million, respectively, from Genesis.

NGP Affiliated Companies

Carlyle Group, L.P. The Carlyle Group, L.P. and certain of its affiliates indirectly own a 55% interest in certain gross revenues of NGP ECM, is a limited partner entitled to 47.5% of the carried interest from NGP XI, and is entitled to 40% of the carried interest from NGP X US Holdings (without, in either case, any rights to vote or dispose of either such fund’s direct or indirect interest in us). NGP ECM manages investment funds, including NGP IX US Holdings, L.P. (“NGP IX US Holdings”), NGP X US Holdings and NGP XI, that collectively directly or indirectly through their equity interests in WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings own a majority of our outstanding shares of common stock. As described above, Carlyle purchased 435,000 shares of our preferred stock on June 30, 2017.

NGP ECM. During the three and six months ended June 30, 2017, we had net disbursements of less than $0.1 million and $0.1 million, respectively, related to fourth quarter 2016 director and advisory fees and reimbursement of initial public offering costs. During both the three and six months ended June 30, 2016, our predecessor paid less than $0.1 million for director fees.

Highmark Energy Operating, LLC. During the three and six months ended June 30, 2017, we, respectively, had net disbursements of less than $0.1 million to and net receipts of less than $0.1 million from Highmark Energy Operating, LLC, a NGP affiliated company, for non-operated working interests in oil and natural gas properties we operate. During the three and six months ended June 30, 2016, our predecessor had net receipts of $0.1 million and $0.2 million, respectively, to Highmark Energy Operating, LLC.

Cretic Energy Services, LLC. During the three and six months ended June 30, 2016, we made payments of $0.3 million and $0.4 million, respectively, to Cretic Energy Services, LLC, a NGP affiliated company, for services related to our drilling and completion activities. We recorded payments of $0.1 million for both the three and six months ended June 30, 2017.

WILDHORSE RESOURCE DEVELOPMENT CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

PennTex Midstream Partners, LP. During both the three and six months ended June 30, 2016, we made net payments of less than $0.1 million and $0.1 million to PennTex Midstream Partners, LP (“PennTex”), a former NGP affiliated company, for the gathering, processing and transportation of natural gas and NGLs. Our related party relationship ceased in the fall of 2016 when a third-party acquired controlling interests in PennTex.

WildHorse Resources, LLC . WildHorse Resources, LLC (“WHR”), an entity formerly under common control with WHR II, ceased being a related party in September 2016 when its parent company was acquired by a third party. During both the three and six months ended June 30, 2016, we paid net payments of less than $0.1 million to WHR’s parent company for non-operated working interests in oil and natural gas properties we operate.

CH4 Energy. CH4 Energy entities are NGP affiliated companies and Mr. Brannon is President of these entities. During the three and six months ended June 30, 2017 we had net disbursements of $0.3 million and less than $0.1 million, respectively, to certain CH4 Energy entities for non-operated working interests in oil and natural gas properties we operate, office rental and parking payments, and landman services and expenses. We did not have any related party payments or receipts for the three and six months ended June 30, 2016.

Garland Exploration LLC. During both the three and six months ended June 30, 2017, we had net receipts of $0.3 million from Garland Exploration, LLC, a NGP affiliated company, for non-operated working interests in oil and natural gas properties we operate. We did not have any related party payments or receipts for the three and six months ended June 30, 2016.

Promissory Notes. WHR II issued promissory notes in favor of certain members of WHR II’s management to fund future capital commitments and carried an interest rate of 2.5% . On November 9, 2016, the management members conveyed to the predecessor certain ownership interests in the predecessor in exchange for the discharge in full and the termination of all the promissory note advances then outstanding. WHR II accrued promissory note interest of $0.1 million during the six months ended June 30, 2016.

Previous Owner Related Party Transactions

Notes payable to members. During the three and six months ended June 30, 2016, Esquisto accrued $1.1 million and $2.1 million, respectively, as general and administrative expenses payable to its members. In connection with our initial public offering, the Esquisto notes payable to its members were paid off.

Services provided by member. Esquisto paid Calbri Energy, Inc. (“Calbri”), a less than 1% former owner, $0.1 million and $0.2 million for the three and six months ended June 30, 2016, respectively, for completion consulting services.

Operator. Esquisto paid Petromax Operating Company, Inc. (“Petromax”), who was the operator of the majority of Esquisto’s wells, $0.3 million and $0.6 million during the three and six months ended June 30, 2016, 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 33.3% by Mike Hoover, the former Chief Operating Officer of Esquisto, who also indirectly owned one of the former members of Esquisto.

Related Party Agreements

Stockholders’ Agreement

A discussion of this agreement is included in our 2016 Form 10-K.

Registration Rights Agreement

On June 30, 2017, in connection with the Acquisition, our registration rights agreement was amended and restated in order to grant certain registration rights to KKR and the Carlyle Investor. Pursuant to the amended and restated registration rights agreement, we have agreed to register the sale of shares of our common stock under certain circumstances.

Transition Services Agreement

Upon the closing of our initial public offering, we entered into a transition services agreement with CH4 Energy IV, LLC, PetroMax and Crossing Rocks Energy, LLC (collectively, the “Service Providers”), pursuant to which the Service Providers agreed to provide certain engineering, land, operating and financial services to us for six months relating to our Eagle Ford Acreage. In

WILDHORSE RESOURCE DEVELOPMENT CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

exchange for such services, we agreed to pay a monthly management fee to the Service Providers. NGP and certain form er management members of Esquisto own the Service Providers. During the three and six months ended June 30, 2017, we paid the Service Providers less than $0.1 million and $0.1 million, respectively.

Note 16. Segment Disclosures

Our chief executive officer has been identified as our chief operating decision maker (“CODM”). We have identified two operating segments – the Eagle Ford and North Louisiana – that have been aggregated into one reportable segment that is engaged in the acquisition, exploitation, development and production of oil, natural gas and NGL resources in the United States. Our reportable segment includes midstream operations that primarily support the Company’s oil and natural gas producing activities. There are no differences between reportable segment revenues and consolidated revenues. Furthermore, all of our revenues are from external customers. The Company uses Adjusted EBITDAX as its measure of profit or loss to assess performance and allocate resources. Information regarding assets by reportable segment is not presented because it is not reviewed by the CODM.

The following table presents a reconciliation of Net income (loss) to Adjusted EBITDAX (in thousands):

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2017			2016			2017			2016
Adjusted EBITDAX reconciliation to net (loss) income:
Net income (loss)	$	26,366		$	(18,281	)	$	46,618		$	(32,497	)
Interest expense, net		6,633			1,781			12,204			3,753
Income tax (benefit) expense		15,193			111			26,893			250
Depreciation, depletion and amortization		33,229			19,923			59,672			41,986
Exploration expense		11,504			80			13,119			7,523
(Gain) loss on derivative instruments		(46,116	)		15,610			(77,407	)		12,364
Cash settlements received (paid) on derivative instruments		2,076			2,525			1,093			5,898
Stock-based compensation		1,308			—			1,803			—
Acquisition related costs		2,199			72			2,798			72
Debt extinguishment costs		—			—			(11	)		358
Public offering costs		—			—			182			—
Non-cash liability amortization		—			(103	)		—			(286	)
Total Adjusted EBITDAX	$	52,392		$	21,718		$	86,964		$	39,421

Note 17. Income Taxes

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

Income tax expense for the three and six months ended June 30, 2017 was $15.2 million and $26.9 million, respectively, compared to income tax expense of $0.1 million and $0.3 million for the three and six months ended June 30, 2016, respectively. The period-to-period increase in income tax expense was primarily a result of being a corporation subject to federal and state income taxes subsequent to our initial public offering. The effective tax rate for both the three and six months ended June 30, 2017 was 36.6% compared to approximately 0.0% for both the three and six months ended June 30, 2016. The effective tax rate differed from the statutory federal income tax rate during the three and six months ended June 30, 2017 primarily due to the impact of state income tax. The effective tax rate differed from the statutory federal income tax rate during the three and six months ended June 30, 2016 primarily due to the impact of pass-through entities and state income tax.

The Company reported no liability for unrecognized tax benefits as of June 30, 2017 and expects no significant change to the unrecognized tax benefits in the next twelve months.

WILDHORSE RESOURCE DEVELOPMENT CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Note 18. Commitments and Contingencies

Litigation & Environmental

We are party to various ongoing and potential 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 June 30, 2017 and December 31, 2016. 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.

From time to time, we could be liable for environmental claims arising in the ordinary course of business. No environmental obligations were recognized at June 30, 2017 and December 31, 2016.

Firm Gas Transportation Service Agreement

The Company has an existing firm gas transportation service agreement with Regency Intrastate Gas LLC as discussed in our 2016 Form 10-K.

Letters of Credit and Certificate of Deposit

The company has existing standby letters of credit issued to the Louisiana Office of Conservation and the Railroad Commission of Texas. These standby letters of credit are cash collateralized by certificates of deposits. The fair value of the certificates of deposits were $0.8 million and $0.9 million at June 30, 2017 and December 31, 2016, respectively, and were recorded on our balance sheet as restricted cash.

Dedicated Fracturing Fleet Services Agreements

During the six months ended June 30, 2017, the Company entered into two dedicated fracturing fleet services agreements to complete wells in a timely manner following conclusion of drilling operations.

On March 15, 2017, we entered into 20-month dedicated fracturing fleet services agreement. The agreement may be extended for an additional twelve months. We have agreed to pay a fixed monthly service fee of $2.7 million that covers equipment and personnel costs. In addition to the fixed monthly service charge, we have agreed to pay a fixed fee for each stage completed in excess of 360 stages per calendar quarter. We have also agreed to pay a pass through fee for the cost of chemicals and fuel plus 10%. We have the right to terminate the contract with appropriate notice; however, an early termination fee of approximately $1.4 million times the number of months remaining under the initial term of the contract would be payable on the termination date.

On June 1, 2017, we entered into a 23-month dedicated fracturing fleet services agreement, which may be extended for an additional twelve months. We have agreed to pay a fixed monthly service fee of $2.8 million that covers equipment and personnel costs. In addition, we have agreed to pay a fixed fee for each stage completed in excess of 115 stages per month. We have also agreed to pay a pass through fee for the cost of chemicals and fuel plus 10%. We have the right to terminate the contract with appropriate notice; however an early termination fee of $1.4 million times the number of months remaining under the initial term of the contract would be payable on the termination date.

Interruptible Water Availability Agreement

The Company entered into an interruptible water availability agreement with the Brazos River Authority (“BRA”) that began on February 1, 2017 and ends on December 31, 2021. The agreement provides us with an aggregate of 6,978 acre-feet of water per year from the Brazos River at prices that may be adjusted periodically by BRA. The agreement requires annual payments to be made on or before February 15 of each year during the term of the agreement. We recorded a payment of $0.4 million during the six months ended June 30, 2017.

WILDHORSE RESOURCE DEVELOPMENT CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Note 19. Subse quent Events

Preferred Stock Dividend – Payment In Kind

On July 31, 2017, we announced an aggregate quarterly dividend of $2.175 million on our outstanding shares of Preferred Stock. The dividend was paid by an automatic increase to the accreted value of each such share of Preferred Stock, which were issued with an initial accreted value of $1,000. The dividend is for the period beginning on June 30, 2017 (the issuance date of the Preferred Stock) to July 31, 2017 and was paid to holders of record on July 15, 2017.

2025 Senior Notes Payment

On August 1, 2017, we made an interest payment of $12.0 million on our 2025 Senior Notes. Our next payment is due February 1, 2018.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the financial statements and related notes in “Item 1. Financial Statements” contained herein and our Annual Report on Form 10-K for the year ended December 31, 2016 filed with the SEC on March 31, 2017 (“2016 Form 10-K”). The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil, natural gas and NGLs, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, drilling results, regulatory changes and other uncertainties, as well as those factors discussed in “Part I—Item 1A. Risk Factors” of our 2016 Form 10-K, “Part II—Item 1A. Risk Factors” contained in this Quarterly Report and “Cautionary Statement Regarding Forward-Looking Statements” in the front of the Quarterly Report. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.

Overview

WildHorse Resource Development Corporation (the “Company”) is a Delaware corporation, the common stock, par value $0.01 per share, of which is listed on the New York Stock Exchange (“NYSE”) under the symbol “WRD.”

We operate in one reportable segment engaged in the acquisition, exploitation, development and production of oil, natural gas and NGL resources. Our assets are characterized by concentrated acreage positions in 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 primarily operate in Burleson, Lee and Washington Counties where we primarily target the Eagle Ford Shale. In North Louisiana, we operate in and around the highly prolific Terryville Complex, where we primarily target the over-pressured Cotton Valley play.

As of December 31, 2016, we had assembled a total leasehold position of approximately 467,319 gross (371,198 net) acres across our expanding acreage, including approximately 321,661 gross (262,742 net) acres in the Eagle Ford and approximately 145,658 gross (108,456 net) acres in North Louisiana. We have identified a total of approximately 4,548 gross (2,350 net) drilling locations across our acreage as of December 31, 2016.

Recent Developments

APC/KKR Acquisition

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

Pursuant to the Acquisition Agreements, on June 30, 2017, we completed the acquisition of certain acreage and the associated production therefrom. The aggregate purchase price for the assets, as described in the Acquisition Agreements, subject to customary adjustments as provided in the Acquisition Agreements, consisted of an aggregate of approximately $533.6 million of cash to the APC Subs and approximately 5.5 million shares of our common stock valued at approximately $60.8 million to KKR (in the aggregate, the “Adjusted Purchase Price”). The common stock portion of the Purchase price payable to KKR was issued pursuant to a Stock Issuance Agreement that was executed, on May 10, 2017 (the “Stock Issuance Agreement”), by and among us and KKR.

Preferred Stock Issuance

On June 30, 2017, we completed the Acquisition, which was partially funded through the issuance of the Preferred Stock. On May 10, 2017, we entered into a Preferred Stock Purchase Agreement (the “Preferred Stock Purchase Agreement”), by and among us and CP VI Eagle Holdings, L.P. (the “Carlyle Investor”), an affiliate of The Carlyle Group, L.P., for $435.0 million dollars in exchange for 435,000 shares of Preferred Stock.

The Preferred Stock ranks senior to our common stock w ith respect to dividend rights and with respect to rights on liquidation, winding-up and dissolution. The Preferred Stock has an initial Accreted Value (as defined in the Certificate) of $1,000 per share and is entitled to a dividend at a rate of 6% per an num on the Accreted Value payable in cash if, as and when declared by our board of directors. If a cash dividend is not declared and paid in respect of any dividend payment period, then the Accreted Value of each outstanding share of Preferred Stock will a utomatically be increased by the amount of the dividend otherwise payable for such dividend payment period. Any increase in the Accreted Value will, among other things, increase the number of shares of common stock issuable upon conversion of each share of Preferred Stock. The Preferred Stock also participates in dividends and distributions on our common stock on an as-converted basis. If at any time following December 30, 2019, the closing sale price of our common stock equals or exceeds 130% of the Conver sion Price for at least 25 consecutive trading days, our obligation to pay dividends on the Preferred Stock shall terminate permanently.

Amendment to Credit Agreement

On June 30, 2017, the Company, each of the Company’s wholly owned subsidiaries (each as a guarantor), Wells Fargo Bank, National Association, as administrative agent (the “Administrative Agent”), and the lenders party thereto entered into a second amendment (the “Amendment”) to the Credit Agreement dated as of December 19, 2016, among the Company, the Administrative Agent and the other agents and lenders party thereto (as amended, the “Credit Agreement”).

The Amendment, among other things, modified the Credit Agreement to (a) permit the Company to enter into the Acquisition, and the Preferred Stock Purchase Agreement, and perform its obligations under and in connection therewith, including the issuance of the Preferred Stock (see Note 10), (b) increase the Company’s borrowing base and elected commitment amount from $450 million to $650 million, (c) increase the annual cap on certain restricted payments from $50 million to $75 million, and (d) modify the definition of net debt so that certain contingent obligations, accounts payable, obligations to make deliveries in respect of advance payments, take or pay obligations, disqualified capital stock and obligations in respect of production payments are excluded from net debt for purposes of the Company’s leverage covenant.

Eagle Ford Acquisitions

In February 2017, we announced multiple transactions to acquire certain oil and natural gas producing and non-producing properties from third-parties in Burleson County, Texas for an aggregate price of approximately $14.9 million, subject to customary post-closing adjustments. One transaction closed in February 2017 and the remaining transactions closed in April 2017. In addition to the transactions we previously announced, on May 17, 2017 we entered into an agreement to acquire unproved oil and natural gas properties from a third party in Burleson County, Texas. On June 27, 2017, we closed this transaction for $2.2 million.

Sources of Our Revenues

Our revenues are largely 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. Production revenues are derived entirely from the continental United States.

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

Principal Components of Cost Structure

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

•

Lease Operating Expenses. Lease operating expenses (“LOE”) are the costs incurred in the operation of producing properties and workover costs. Expenses for utilities, direct labor, water injection and disposal, compressor expenses, workover rigs and workover expenses, materials and supplies comprise the most significant portion of our LOE. Certain items, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges, but can fluctuate depending on activities performed during a specific period. For instance, repairs to our pumping equipment or surface facilities result in increased LOE in periods during which they are performed. Certain of our operating cost components are variable and increase or decrease as the level of produced hydrocarbons and water increases or decreases. For example, we incur power costs in connection with various production-related activities, such as pumping to recover oil and natural gas and separation and treatment of water produced in connection with our oil and natural gas production.

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

•

Gathering, Processing and Transportation (“GP&T”). These are costs incurred to deliver production of our natural gas, NGLs and oil to the market. Cost levels of these expenses can vary based on the volume of natural gas, NGLs and oil produced as well as the cost of commodity processing.

•

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.

•

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

•

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization (“DD&A”) is the systematic expensing of the capitalized costs incurred to acquire and develop oil and natural gas properties. We use the successful efforts method of accounting for oil and natural gas activities and, as such, we capitalize all costs associated with our development and acquisition efforts and all successful exploration efforts, which are then allocated to each unit of production using the unit of production method. 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. Impairment of unproved leasehold costs are recorded within exploration expense.

•

General and Administrative Expenses. General and administrative (“G&A”) expenses are costs incurred for overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production and development operations, stock-based compensation, public company expenses, IT expenses, audit and other fees for professional services, including legal compliance and acquisition-related expenses.

•

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

•

Incentive Unit Compensation Expense. See “Note 14—Incentive Units” of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under “Item 1. Financial Statements” of this Quarterly Report for additional information.

•

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

•

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

•

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

Critical Accounting Policies and Estimates

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, natural 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; (8) incentive unit compensation cost; (9) contingent liabilities and (10) impairment expense. Although management believes these estimates are reasonable, changes in facts and circumstances or discovery of new information may result in revised estimates, and such revisions could be material.

A discussion of our critical accounting policies and estimates is included in our 2016 Form 10-K. There have been no significant changes to our critical accounting policies and estimates.

Results of Operations

The results of operations of our predecessor were retrospectively recast due to common control considerations. Because WHR II, Esquisto and Acquisition Co. were under the common control of NGP, the sale and contribution of the respective ownership interests were accounted for as a combination of entities under common control, whereby the assets and liabilities sold and contributed were recorded based on historical cost. As such, the results of operations presented below for the three and six months ended June 30, 2016 have been derived from the combined results attributable to our predecessor and Esquisto. For periods after the completion of our initial public offering, our consolidated financial statements include our accounts and those of our subsidiaries.

Factors Affecting the Comparability of the Combined Historical Financial Results

The comparability of the results of operations among the periods presented is impacted by the following:

•

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

•

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

•

increases in our drilling programs; and

•

the February 2017 private placement of $350.0 million aggregate principal amount of 6.875% senior unsecured notes due 2025 (the “2025 Senior Notes”).

As a result of the factors listed above, the combined historical results of operations and period-to-period comparisons of these results and certain financial data may not be comparable or indicative of future results.

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

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2017			2016			2017			2016
	(In thousands, except per share data)						(In thousands, except per share data)
Revenues:
Oil sales	$	52,963		$	18,683		$	92,040		$	31,936
Natural gas sales		13,277			9,233			25,422			19,439
NGL sales		3,404			1,225			6,067			2,170
Other income		529			574			936			1,297
Total operating revenues		70,173			29,715			124,465			54,842
Operating expenses:
Lease operating expenses		6,837			2,302			13,765			5,062
Gathering, processing and transportation		1,942			1,583			3,642			3,474
Gathering system operating expense		25			64			44			118
Taxes other than income tax		4,509			1,785			8,408			3,257
Depreciation, depletion and amortization		33,229			19,923			59,672			41,986
General and administrative expenses		10,049			4,683			17,531			9,132
Exploration expense		11,504			80			13,119			7,523
Total operating expenses		68,095			30,420			116,181			70,552
Income (loss) from operations		2,078			(705	)		8,284			(15,710	)
Other income (expense):
Interest expense		(6,633	)		(1,781	)		(12,204	)		(3,753	)
Debt extinguishment costs		—			—			11			(358	)
Gain (loss) on derivative instruments		46,116			(15,610	)		77,407			(12,364	)
Other income (expense)		(2	)		(74	)		13			(62	)
Total other income (expense)		39,481			(17,465	)		65,227			(16,537	)
Income (loss) before income taxes		41,559			(18,170	)		73,511			(32,247	)
Income tax benefit (expense)		(15,193	)		(111	)		(26,893	)		(250	)
Net income (loss)		26,366			(18,281	)		46,618			(32,497	)
Net income (loss) attributable to previous owners		—			(5,265	)		—			(7,782	)
Net income (loss) attributable to predecessor		—			(13,016	)		—			(24,715	)
Net income (loss) available to WildHorse Development	$	26,366		$	—		$	46,618		$	—

Net income (loss) per common share:
Basic and diluted	$	0.28		n/a			$	0.49		n/a
Weighted-average common shares outstanding:
Basic and diluted		93,685		n/a				93,452		n/a
Oil and natural gas revenue:
Natural gas	$	13,277		$	9,233		$	25,422		$	19,439
Crude oil		52,963			18,683			92,040			31,936
Natural gas liquids		3,404			1,225			6,067			2,170
Total oil and natural gas revenue	$	69,644		$	29,141		$	123,529		$	53,545
Production volumes:
Natural gas (MMcf)		4,299			4,739			8,148			9,540
Oil (MBbls)		1,133			434			1,916			880
NGLs (MBbls)		205			104			365			215
Total (MBoe)		2,054			1,328			3,639			2,685
Average sales price:
Natural gas (per Mcf)	$	3.09		$	1.95		$	3.12		$	2.04
Oil (per Bbl)		46.77			43.07			48.05			36.30
NGLs (per Bbl)		16.59			11.74			16.62			10.08
Total (per Boe)	$	33.90		$	21.94		$	33.95		$	19.94
Average production volumes:
Natural gas (MMcf/d)		47.2			52.1			45.0			52.4
Oil (MBbls/d)		12.5			4.8			10.6			4.8
NGLs (MBbls/d)		2.3			1.1			2.0			1.2
Average net production (MBoe/d)		22.6			14.6			20.1			14.8
Average unit costs per Boe:
Lease operating expenses	$	3.33		$	1.73		$	3.78		$	1.89
Gathering, processing and transportation	$	0.95		$	1.19		$	1.00		$	1.29
Taxes other than income tax	$	2.20		$	1.34		$	2.31		$	1.21
General and administrative expenses	$	4.89		$	3.53		$	4.82		$	3.40
Depletion, depreciation and amortization	$	16.18		$	15.00		$	16.40		$	15.64

Three Months Ended June 30, 2017 Compared to the Three Months Ended June 30, 2016

For purposes of the following discussion, references to 2017 and 2016 refer to the three months ended June 30, 2017 and the three months ended June 30, 2016, respectively, unless otherwise indicated.

•

Oil, natural gas and NGL revenues were $69.6 million for 2017 compared to $29.1 million for 2016, an increase of $40.5 million (approximately 139%). Production increased 0.7 MMBoe (approximately 55%) primarily due to the December 2016 Burleson North acquisition and to drilling successful wells in the Eagle Ford. The average realized sales price increased $11.96 per Boe (approximately 55%) due to a higher percentage of oil in the production mix. Oil revenues increased $4.2 million and $30.1 million due to favorable pricing and production variances, respectively. Natural gas revenues increased $4.9 million due to a favorable pricing variance offset by a $0.9 million decrease due to an unfavorable volume variance. NGL revenues increased $1.0 million and $1.2 million due to favorable price and volume variances, respectively.

•

LOE was $6.8 million and $2.3 million for 2017 and 2016, respectively. On a per Boe basis, total LOE was $3.33 and $1.73 for 2017 and 2016, respectively. The increase in LOE on a per unit basis is largely attributable to the Burleson North acquisition which came with less efficient legacy production. Net production in 2017 consisted of 55.1% oil compared to 32.7% oil in 2016. Generally, the production of oil is more expensive than natural gas on a per Boe basis.

•

GP&T expenses were $1.9 million and $1.6 million for 2017 and 2016, respectively. The 19% increase in GP&T expenses was primarily attributable to increased expenses associated with our properties in the Eagle Ford due to increased volumes. These increases were partially offset by lower expenses associated with our North Louisiana properties due to reduced gas volumes. On a per Boe basis, GP&T expenses were $0.95 and $1.19 for 2017 and 2016, respectively.

•

Taxes other than income tax were $4.5 million and $1.8 million for 2017 and 2016, respectively; an increase of $2.7 million (approximately 150%). On a per Boe basis, taxes other than income tax were $2.20 and $1.34 for 2017 and 2016, respectively. The 64% increase was primarily due to higher price realizations, higher ad valorem taxes associated with increased property valuations, and Louisiana franchise taxes incurred as a result of our corporate reorganization that occurred in conjunction with our initial public offering.

•

DD&A expense for 2017 was $33.2 million compared to $19.9 million for 2016, a $13.3 million increase (approximately 67%) primarily due to an increase in production volumes related to acquisitions and drilling activities. Increased production volumes caused DD&A expense to increase by $10.9 million and the change in the DD&A rate between periods caused DD&A expense to increase by $2.4 million.

•

G&A expenses were $10.0 million and $4.7 million (an increase of approximately 113%) for 2017 and 2016, respectively. The $5.3 million increase was primarily due to increased staffing for 2017 compared to 2016 and increased costs associated with being a public company. During 2017, we recorded $2.1 million of acquisition expenses and we recorded $1.3 million in stock-based compensation costs related to our long term incentive plan. Salaries and wages increased by $2.5 million primarily due to additional staffing offset by the previous owner’s $1.1 million G&A accrual payable to its members during 2016. Fees related to accounting and audit services increased $0.6 million between 2017 and 2016.

•

Exploration expense was $11.5 million and $0.1 million for 2017 and 2016, respectively. The $11.4 million increase in exploration expense was primarily due to an increase in undeveloped leasehold impairments of $9.9 million due to expiring acreage leases. Increases in exploration expense also included a $1.5 million increase in seismic acquisitions.

•

Interest expense was $6.6 million and $1.8 million for 2017 and 2016, respectively. The $4.8 million increase (approximately 267%) was due to an increase in the average debt outstanding as a result of the February 2017 issuance of the 2025 Senior Notes. Interest is comprised of interest on our credit facilities, interest on our senior notes and amortization of debt issue costs offset by capitalized interest. Amortization of debt issue costs was $0.4 million for 2017 compared to $0.1 million for 2016. Capitalized interest increased to $0.7 million from less than $0.1 million for the three months ended June 30, 2017 and 2016, respectively, due to increased drilling activities.

•

Net gains on commodity derivatives of $46.1 million were recognized during 2017, which consisted of a $42.8 million increase in the fair value of open positions and $3.3 million of cash settlements received. During 2016, we recognized a $15.6 million loss on derivative instruments, which consisted of $2.3 million of cash settlements received and a $17.9 million decrease in the fair value of open positions.

•

Income tax expense was $15.2 million and $0.1 million for 2017 and 2016, respectively. The $15.1 million increase was primarily a result of being a corporation subject to federal and state income taxes subsequent to our initial public offering. The effecti ve tax rate for 2017 differed from the federal statutory income tax rate primarily due to the impact of state income tax. The effective tax rate for 2016 differed from the federal statutory income tax rate primarily due to the impact of pass-through entiti es and state income tax.

Six Months Ended June 30, 2017 Compared to the Six Months Ended June 30, 2016

For purposes of the following discussion, references to 2017 and 2016 refer to the six months ended June 30, 2017 and the six months ended June 30, 2016, respectively, unless otherwise indicated.

•

Oil, natural gas and NGL revenues were $123.5 million for 2017 compared to $53.5 million for 2016, an increase of $70.0 million (approximately 131%). Production increased 1.0 MMBoe (approximately 36%) primarily due to the December 2016 Burleson North acquisition and to drilling successful wells in the Eagle Ford. The average realized sales prices increased to $33.95 per Boe for 2017 compared to $19.94 per Boe during 2016 due to higher overall commodity prices and a higher percentage of oil in the production mix. Oil revenues increased $22.5 million and $37.6 million due to favorable pricing and production variances, respectively. Natural gas revenues increased $8.8 million due to a favorable pricing variance offset by a $2.8 million decrease due to an unfavorable volume variance. NGL revenues increased $2.4 million and $1.5 million due to favorable price and volume variances, respectively.

•

LOE was $13.8 million and $5.1 million for 2017 and 2016, respectively. On a per Boe basis, total LOE was $3.78 and $1.89 for 2017 and 2016, respectively. The increase in LOE on a per unit basis is largely attributable to the Burleson North acquisition which came with less efficient legacy production. Net production in 2017 consisted of 52.6% oil compared to 32.8% oil in 2016. Generally, the production of oil is more expensive than natural gas on a per Boe basis.

•

GP&T expenses were $3.6 million and $3.5 million for 2017 and 2016, respectively. The 5% increase in GP&T expenses was primarily attributable to increased expenses associated with the Burleson North properties due to higher volumes. These increases with were mostly offset by decreased expenses associated with our North Louisiana properties due to decreases in volumes. On a per Boe basis, GP&T expenses were $1.00 and $1.29 for 2017 and 2016, respectively.

•

Taxes other than income tax were $8.4 million and $3.3 million for 2017 and 2016, respectively, an increase of $5.1 million (approximately 158%). On a per Boe basis, taxes other than income tax were $2.31 and $1.21 for 2017 and 2016, respectively. The 91% increase was primarily due to higher price realizations, higher ad valorem taxes associated with increased property valuations, and Louisiana franchise taxes incurred as a result of our corporate reorganization that occurred in conjunction with our initial public offering.

•

DD&A expense for 2017 was $59.7 million compared to $42.0 million for 2016, a $17.7 million increase (approximately 42%) primarily due to an increase in production volumes related to acquisitions and drilling activities. Increased production volumes caused DD&A expense to increase by $14.9 million and the change in the DD&A rate between periods caused DD&A expense to increase by $2.8 million.

•

G&A expenses were $17.5 million and $9.1 million (an increase of approximately 92%) for 2017 and 2016, respectively. The $8.4 million increase was primarily due to increased staffing for 2017 compared to 2016 and increased costs associated with being a public company. During 2017, we recorded $2.7 million in acquisition expenses and $1.8 million in stock-based compensation costs related to our long term incentive plan. Salaries and wages increased by $4.9 million primarily due to additional staffing offset by the previous owner’s $2.1 million G&A accrual payable to its members during 2016. Fees related to accounting and audit services increased $1.1 million between 2017 and 2016.

•

Exploration expense was $13.1 million and $7.5 million for 2017 and 2016, respectively. The $5.6 million increase (approximately 75%) in exploration expense was primarily associated with an increase in undeveloped leasehold impairments of $10.6 million, and an increase in seismic acquisitions of $1.8 million, offset by $6.8 million in expenses associated with the early termination of a rig contract, which was laid down in June 2016 due to low commodity prices.

•

Interest expense was $12.2 million and $3.8 million for 2017 and 2016, respectively. The $8.4 million increase (approximately 221%) was due to an increase in the average debt outstanding primarily as a result of the February 2017 issuance of the 2025 Senior Notes. Interest is comprised of interest on our credit facilities, interest on our senior notes and amortization of debt issue costs offset by capitalized interest. Amortization of debt issue costs was $1.3 million for 2017 compared to $0.1 million for 2016. Capitalized interest increased to $1.0 million from less than $0.1 million for the six months ended June 30, 2017 and 2016, respectively, due to increased drilling activities.

•

Debt extinguishment costs were $0.4 million in 2016 due to Esquisto’s retirement and termination of its revolving credit facility and second lien in January 2016 in connection with the merger of Esquisto I and Esquisto II. There were nominal debt extinguishment costs in 2017.

•

Net gains on commodity derivatives of $77.4 million were recognized during 2017, which consisted of a $73.9 million increase in the fair value of open positions and $3. 5 million in cash settlements received. During 2016, we recognized a $12.4 million loss on derivative instruments, which consisted of $5.4 million in cash settlements received and $17.8 million decrease in the fair value of open positions.

•

Income tax expense was $26.9 million and $0.3 million for 2017 and 2016, respectively. The $26.6 million increase was primarily a result of being a corporation subject to federal and state income taxes subsequent to our initial public offering. The effective tax rate for 2017 differed from the federal statutory income tax rate primarily due to the impact of state income tax. The effective tax rate for 2016 differed from the federal statutory income tax rate primarily due to the impact of pass-through entities and state income tax.

Calculation of Adjusted EBITDAX

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

We define Adjusted EBITDAX as Net income (loss):

Plus:

•

Interest expense;

•

Income tax expense;

•

DD&A;

•

Exploration expense;

•

Impairment of proved oil and natural gas properties;

•

Loss on derivative instruments;

•

Cash settlements received on derivative instruments;

•

Stock-based compensation;

•

Incentive-based compensation expenses;

•

Acquisition related costs;

•

Debt extinguishment costs;

•

Loss on sale of properties;

•

Initial public offering costs; and

•

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

Less:

•

Interest income;

•

Income tax benefit;

•

Gain on derivative instruments;

•

Cash settlements paid on derivative instruments;

•

Gain on sale of properties; and

•

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

Management believes Adjusted EBITDAX is a useful performance measure because it allows them to more effectively evaluate our operating performance without regard to our financing methods or capital structure. We exclude the items listed above from net (loss) income in arriving at Adjusted EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were

acqui red. 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 a n 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.

Reconciliation of Net Income to Adjusted EBITDAX

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

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2017			2016			2017			2016
Adjusted EBITDAX reconciliation to net (loss) income:	(in thousands)						(in thousands)
Net income (loss)	$	26,366		$	(18,281	)	$	46,618		$	(32,497	)
Interest expense, net		6,633			1,781			12,204			3,753
Income tax (benefit) expense		15,193			111			26,893			250
Depreciation, depletion and amortization		33,229			19,923			59,672			41,986
Exploration expense		11,504			80			13,119			7,523
(Gain) loss on derivative instruments		(46,116	)		15,610			(77,407	)		12,364
Cash settlements received (paid) on derivative instruments		2,076			2,525			1,093			5,898
Stock-based compensation		1,308			—			1,803			—
Acquisition related costs		2,199			72			2,798			72
Debt extinguishment costs		—			—			(11	)		358
Initial public offering costs		—			—			182			—
Non-cash liability amortization		—			(103	)		—			(286	)
Total Adjusted EBITDAX	$	52,392		$	21,718		$	86,964		$	39,421

Liquidity and Capital Resources

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

Based on our current oil and natural gas price expectations, we believe our cash flows provided by operating activities and availability under our revolving credit facility will provide us with the financial flexibility and wherewithal to meet our cash requirements, including normal operating needs, and pursue our currently planned 2017 development drilling activities. However, future cash flows are subject to a number of variables, including the level of our oil and natural gas production and the prices we receive for our oil and natural gas production, and significant additional capital expenditures will be required to more fully develop our properties and acquire additional properties. We cannot assure you that operations and other needed capital will be available on acceptable terms, or at all.

As of June 30, 2017, we had $14.6 million of cash and cash equivalents and $502.1 million of available borrowings under our revolving credit facility. As of June 30, 2017, we had a working capital deficit of $63.3 million primarily due to the accrual of capital expenditures. As of June 30, 2017, the borrowing base under our revolving credit facility was increased to $650.0 million upon the closing of the Acquisition and we had outstanding borrowings of $146.0 million. The borrowing base under our revolving credit facility is subject to redetermination on at least a semi-annual basis based on an engineering report with respect to our estimated oil and natural gas reserves, which will take into account the prevailing oil and natural gas prices at such time, as adjusted for the impact of our commodity derivative contracts. Unanimous approval by the lenders is required for any increase to the borrowing base. The next scheduled borrowing base redetermination is set for October 2017. A continuing decline in oil and natural gas prices could result in a reduction of our borrowing base under our revolving credit facility and could trigger mandatory principal repayments. On April 27, 2017, standby letters of credit of $1.9 million were issued to the Railroad Commission of Texas under our revolving credit facility.

Preferred Stock

We are authorized to issue up to 50,000,000 shares of preferred stock. On June 30, 2017, we issued 435,000 shares of preferred stock in connection with the Acquisition. See “Note 10—Preferred Stock” of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under “Item 1. Financial Statements” of this Quarterly Report for additional information regarding our preferred stock issuance.

Capital Expenditure Budget

We established a 2017 drilling and completion capital expenditure budget of $550.0 million to $675.0 million. For the six months ended June 30, 2017, our drilling and completion expenditures were approximately $267.6 million primarily related to the development of our Eagle Ford properties.

Debt Agreements

Revolving Credit Facility. In December 2016, we, as borrower, and certain of our current and future subsidiaries, as guarantors, entered into a five-year, $1.0 billion senior secured revolving credit facility. In April 2017, our revolving credit facility borrowing base was increased from $362.5 million to $450.0 million in connection with the semi-annual borrowing redetermination by our lenders. Our 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.” On June 30, 2017, the Company, each of the Company’s wholly owned subsidiaries (each as a guarantor), the Administrative Agent, and the lenders party thereto entered into the Amendment to the Credit Agreement.

The Amendment, among other things, modified the Credit Agreement to (i) permit the Company to enter into the Acquisition, and the Preferred Stock Purchase Agreement, and perform its obligations under and in connection therewith, including the issuance of the Preferred Stock, (ii) increase the Company’s borrowing base and elected commitment amount from $450 million to $650 million, (iii) increase the annual cap on certain restricted payments from $50 million to $75 million, and (iv) modify the definition of net debt so that certain contingent obligations, accounts payable, obligations to make deliveries in respect of advance payments, take or pay obligations, disqualified capital stock and obligations in respect of production payments are excluded from net debt for purposes of the Company’s leverage covenant. In the future, we may be unable to access sufficient capital under our 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.

We believe we were in compliance with all the financial (interest coverage ratio and current ratio) and other covenants associated with our revolving credit facility as of June 30, 2017.

See “Note 9—Long Term Debt” of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under “Item 1. Financial Statements” of this Quarterly Report for additional information regarding our revolving credit facility.

2025 Senior Notes

In February 2017, we completed a private placement of the 2025 Senior Notes. The 2025 Senior Notes, issued at 99.244% of par, mature on February 1, 2025 and are fully and unconditionally guaranteed on a joint and several basis by all of our existing and certain future subsidiaries (subject to customary release provisions). The 2025 Senior Notes are governed by an indenture dated as of February 1, 2017. The 2025 Senior Notes accrue interest at 6.875% per annum and payable semi-annually in arrears on February 1 and August 1 of each year. We used the net proceeds to repay the borrowings outstanding under our revolving credit facility and for general corporate purposes, including funding our 2017 capital expenditures. On August 1, 2017, we made a $12.0 million interest payment on the 2025 Senior Notes.

Commodity Derivative Contracts

Our hedging policy is designed to reduce the impact to our cash flows from commodity price volatility.

For additional information regarding the volumes of our production cove red by commodity derivative contracts and the average prices at which production is hedged as of June 30, 2017, see “Item 3. Quantitative and Qualitative Disclosures About Market Risk — Counterparty and Customer Credit Risk.”

Counterparty Exposure

Our hedging policy permits us to enter into derivative contracts with major financial institutions or major energy entities. Our derivative contracts are currently with major financial institutions, certain of which are also lenders under our revolving credit facility. We have rights of offset against the borrowings under our revolving credit facility. See “Item 3. Quantitative and Qualitative Disclosures About Market Risk — Counterparty and Customer Credit Risk” for additional information.

Cash Flows from Operating, Investing and Financing Activities

The following table summarizes our cash flows from operating, investing and financing activities for the periods indicated. Our predecessor’s cash flows were retrospectively revised due to common control considerations. As such, the cash flows for the six months ended June 30, 2016 have been derived from the combined financial position and results attributable to the predecessor and the previous owner. For periods after the completion of our initial public offering, our consolidated financial statements include our accounts and those of our subsidiaries. Because WHR II, Esquisto and Acquisition Co. Holdings were under the common control of NGP, the sale and contribution of the respective ownership interests was accounted for as a combination of entities under common control, whereby the assets and liabilities sold and contributed were recorded based on historical cost.

For information regarding the individual components of our cash flow amounts, see the Unaudited Statements of Condensed Consolidated and Combined Cash Flows included under “Item 1. Financial Statements” contained herein.

	For the Six Months Ended June 30,
	2017			2016
	(in thousands)
Net cash provided by (used in) operating activities	$	72,034		$	17,313
Net cash used in investing activities	$	(764,707	)	$	(80,516	)
Net cash provided by financing activities	$	704,191		$	25,575

Six Months Ended June 30, 2017 Compared to the Six Months Ended June 30, 2016

For purposes of the following discussion, references to 2017 and 2016 refer to the six months ended June 30, 2017 and the six months ended June 30, 2016, respectively, unless otherwise indicated.

Operating Activities. Net cash provided by operating activities was $72.0 million for 2017, compared to $17.3 million of net cash provided by operating activities for 2016. Production increased 1.0 MMBoe (approximately 36%) and average realized sales prices increased to $33.95 per Boe for 2017 compared to $19.94 per Boe during 2016 as previously discussed above under “Results of Operations.” The overall period-to-period increase in net cash provided by operating activities was unfavorably impacted by higher G&A expenses and LOE. Net cash provided by operating activities included $1.1 million of cash receipts on derivative instruments during 2017 compared to $5.9 million in cash receipts during 2016. There was a $12.6 million increase in cash flow attributable to the timing of cash receipts and disbursements related to operating activities during 2017 compared to 2016.

Investing Activities. During 2017 and 2016, cash flows used in investing activities were $764.7 million and $80.5 million, respectively. Acquisitions of oil and gas properties were $547.4 million and $4.2 million during 2017 and 2016, respectively. We received post-closing adjustment receipts of $3.9 million during 2017 related to the Burleson North Acquisition. Additions to oil and gas properties were $211.3 million during 2017 primarily related to our drilling and completion activities in the Eagle Ford. Additions to oil and gas properties were $73.4 million during 2016, of which $58.5 million was attributable to Esquisto’s drilling and completion activities in the Eagle Ford and $14.9 million was attributable to our predecessor’s drilling and completion activities in North Louisiana.

Financing Activities. Net cash provided by financing activities during 2017 of $704.2 million was primarily attributable to $432.6 million in net proceeds from the issuance of our Preferred Stock, $347.4 million in proceeds from the issuance of our 2025 Senior Notes, $161.5 in advances on our revolving credit facilities and $34.5 million from the partial exercise of the underwriters’ over-allotment option. These cash inflows were offset by payments under our revolving credit facilities of $258.3 million during 2017, debt issuance costs of $10.8 million, and $2.7 million of issuance costs associated with the underwriters’ exercise of their over-allotment option and costs related to our initial public offering which were previously accrued and cash settled during 2017. Net proceeds from the issuance of our Preferred Stock partially funded the cash consideration portion of the Acquisition. We used

proceeds from the issuance of our 2025 Senior Notes to pay down our revolver. Amounts borrowed under our revolver funded our drilling program and working capital needs.

Net cash provided by financing activities of $25.6 million during 2016 was primarily attributable to capital contributions of $13.3 million from our predecessor and $25.0 million in contributions from our previous owners. Net payments under our revolving credit facilities were $12.0 million during 2016. Amounts borrowed under our predecessor and previous owner credit facilities were primarily used for additions to oil and natural gas properties and working capital. Debt issuance costs were $0.5 million. Costs associated with Esquisto’s termination of its second lien were $0.2 million.

Contractual Obligations

During the six months ended June 30, 2017, there were no significant changes in our consolidated contractual obligations from those reported in our 2016 Form 10-K filed except for the additions of two long-term dedicated fracturing fleet services agreements and interruptible water availability agreement all of which were entered into as part of our ordinary course of business. For more information see “Note 18—Commitments and Contingencies” of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under “Item 1. Financial Statements” of this Quarterly Report. Additionally, we had $146.0 million outstanding under our revolving credit facility at June 30, 2017 compared to $242.8 million at December 31, 2016. As previously discussed, our 2025 Senior Notes were issued in February 2017. See “Note 9—Long Term Debt” of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under “Item 1. Financial Statements” of this Quarterly Report for additional information on our indebtedness.

Off–Balance Sheet Arrangements

As of June 30, 2017, we had no off–balance sheet arrangements.

Recently Issued Accounting Pronouncements

For a discussion of recent accounting pronouncements that will affect us, see “Note 2—Summary of Significant Accounting Policies” of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under “Item 1. Financial Statements” of this Quarterly Report.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES 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.

For additional information regarding the volumes of our production covered by commodity derivative contracts and the average prices at which production is hedged as of June 30, 2017, see “Note 5—Risk Management and Derivative Instruments” of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under “Item 1. Financial Statements” of this Quarterly Report.

Interest Rate Risk

At June 30, 2017, we had $146.0 million outstanding under our revolving credit facility. We do not currently have any derivative arrangements to protect against fluctuations in interest rates applicable to indebtedness we may incur but may enter into such derivative arrangements in the future. To the extent we enter into any such interest rate derivative arrangement, we would be subject to risk for financial loss.

The fair value of our 2025 Senior Notes is sensitive to changes in interest rates. We estimate the fair value of 2025 Senior Notes using quoted market prices. The carrying value (net of any discount and debt issua nce cost) is compared to the estimated fair value in the table below (in thousands):

	June 30, 2017
	Carrying Amount		Estimated Fair Value
2025 Senior Notes, fixed-rate due February 2025	$	339,033	$	328,125

Counterparty and Customer Credit Risk

We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. We do not require our customers to post collateral, and the inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.

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.

In addition, 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. Each of the counterparties to our derivative contracts currently in place has an investment grade rating. See “Note 5—Risk Management and Derivative Instruments” of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under “Item 1. Financial Statements” of this Quarterly Report for additional information regarding credit risk associated with our derivative instruments.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures.

As required by Rules 13a-15(b) and 15d-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including the principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) and under the Exchange Act) as of the end of the period covered by this Quarterly Report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including the principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, the principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective at the reasonable assurance level as of June 30, 2017.

Changes in Internal Controls Over Financial Reporting

No changes in our internal control over financial reporting occurred during the quarter ended June 30, 2017 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

The certifications required by Section 302 of the Sarbanes-Oxley Act of 2002 are filed as Exhibits 31.1 and 31.2, respectively, to this Quarterly Report.

PART II—OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

As part of our normal business activities, we may be named as defendants in litigation and legal proceedings, including those arising from regulatory and environmental matters. If we determine that a negative outcome is possible and the amount of loss is reasonably estimable, we accrue the estimated amount. We are not aware of any litigation, pending or threatened, that we believe will have a material adverse effect on our financial position, results of operations or cash flows. No amounts have been accrued at June 30, 2017. For additional discussion of current legal proceedings, please see “Note 18—Commitments and Contingencies” of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under “Item 1. Financial Statements” of this Quarterly Report.

ITEM 1A. RISK FACTORS

In addition to the information set forth in this report, you should carefully consider the factors discussed in Part I, Item IA. “Risk Factors” in our 2016 Form 10-K, which could materially affect our business, financial condition or future results. There have been no material changes with respect to the risk factors since those disclosed in our 2016 Form 10-K.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

(a)

Recent sales of unregistered securities.

We did not have any sales of unregistered securities during the three months ended June 30, 2017, except as set forth in our Current Report on Form 8-K filed on May 16, 2017.

(b)

Use of proceeds.

None.

(c)

Purchases of equity securities by the issuer and affiliated purchasers.

During the three months ended June 30, 2017, there were no repurchases of our common stock by us or our affiliates.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

The information required by this Item 6. Exhibits is set forth in the Exhibit Index accompanying this Quarterly Report on Form 10-Q, which is incorporated herein by reference.

SIGNAT URES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this Quarterly Report to be signed on its behalf by the undersigned, thereunto duly authorized.

Exhibit Number		Description

2.1		Master Contribution Agreement, dated December 12, 2016, by and among WildHorse Resource Development Corporation and the other parties named therein (incorporated by reference to Exhibit 2.1 to the Company’s Form 8-K filed on December 16, 2016).

2.2		Purchase and Sale Agreement, dated May 10, 2017, by and among Anadarko E&P Onshore LLC, Admiral A Holding L.P., TE Admiral A Holding L.P., Aurora C-I Holding L.P. and WHR Eagle Ford LLC (incorporated by reference to Exhibit 2.2 to the Company’s Form 10-Q filed on May 15, 2017).

2.3		Purchase and Sale Agreement, dated May 10, 2017, by and among Anadarko E&P Onshore LLC, Anadarko Energy Services Company and WHR Eagle Ford LLC (incorporated by reference to Exhibit 2.3 to the Company’s Form 10-Q filed on May 15, 2017).

3.1		Amended and Restated Certification of Incorporation of WildHorse Resource Development Corporation (incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K filed on December 19, 2016).

3.2		Amended and Restated Bylaws of WildHorse Resource Development Corporation, effective December 19, 2016 (incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K filed on December 19, 2016).

3.3		Certificates of Designations, 6.00% Series A Perpetual Convertible Preferred Stock (incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K filed on July 7, 2017).

4.1		Indenture, dated as of February 1, 2017, by and among WildHorse Resource Development Corporation, the subsidiary guarantors named therein and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.1 to the Company’s Form 8-K filed on February 1, 2017).

4.2		Form of 6.875% Senior Note due 2025 (incorporated by reference to Exhibit 4.2 to the Company’s Form 8-K filed on February 1, 2017).

4.3		Registration Rights Agreement, dated as of February 1, 2017, by and among WildHorse Resource Development Corporation, the subsidiary guarantors named therein and Wells Fargo Securities, LLC, as representative of the initial purchasers named therein (incorporated by reference to Exhibit 4.3 to the Company’s Form 8-K filed on February 1, 2017).

4.4		Amended and Restated Registration Rights Agreement dated as of June 30, 2017 by and between WildHorse Resource Development Corporation and WHR Holdings, LLC, Esquisto Holdings, LLC, WHE AcqCo Holdings, LLC, NGP XI US Holdings, L.P., Jay C. Graham, Anthony Bahr, CP VI Eagle Holdings, L.P., EIGF Aggregator LLC, TE Drilling Aggregator LLC and Aurora C-1 Holding L.P. (incorporated by reference to Exhibit 4.1 to the Company’s Form 8-K filed on July 7, 2017).

4.5		Preferred Stock Purchase Agreement, dated as of May 10, 2017, by and among WildHorse Resource Development Corporation and CP VI Eagle Holdings, L.P. (incorporated by reference to Exhibit 4.4 to the Company’s Form 10-Q filed on May 15, 2017).

4.6*		First Supplemental Indenture, dated as of June 30, 2017, by and among WHR Eagle Ford LLC, WildHorse Resource Development Corporation, the other subsidiary guarantors named therein and U.S. Bank National Association, as Trustee.

10.1		Second Amendment to Credit Agreement, dated as of June 30, 2017, by and among WildHorse Resource Development Corporation, each of the guarantors party thereto, and Wells Fargo Bank, National Association, as Administrative Agent for the Lenders party thereto, BMO Harris Bank, N.A., as Syndication Agent, the Lenders party thereto and the other parties party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on July 7, 2017).

10.2		First Amendment to Credit Agreement, dated as of April 4, 2017, by and among WildHorse Resource Development Corporation, each of the guarantors party thereto, and Wells Fargo Bank, National Association, as Administrative Agent for the Lenders party thereto, BMO Harris Bank, N.A., as Syndication Agent, the Lenders party thereto and the other parties party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Form 10-Q filed on May 15, 2017).

10.3		Indemnification Agreement, dated as of June 30, 2017, by and between WildHorse Resource Development Corporation and Brian A. Bernasek (incorporated by reference to Exhibit 10.2 to the Company’s Form 8-K filed on July 7, 2017).
10.4		Indemnification Agreement, dated as of June 30, 2017, by and between WildHorse Resource Development Corporation and Martin W. Sumner (incorporated by reference to Exhibit 10.3 to the Company’s Form 8-K filed on July 7, 2017).

Exhibit Number		Description

10.5		Stock Issuance Agreement, dated as of May 10, 2017, by and among WildHorse Resource Development Corporation and Admiral A Holding L.P., TE Admiral A Holding L.P. and Aurora C-I Holding L.P. (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on May 16, 2017).

31.1*		Certification of Chief Executive Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.

31.2*		Certification of Chief Financial Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.

32.1*		Certifications of Chief Executive Officer and Chief Financial Officer pursuant to 18. U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.CAL*		XBRL Calculation Linkbase Document

101.DEF*		XBRL Definition Linkbase Document

101.INS*		XBRL Instance Document

101.LAB*		XBRL Labels Linkbase Document

101.PRE*		XBRL Presentation Linkbase Document

101.SCH*		XBRL Schema Document

*	Filed or furnished as an exhibit to this Quarterly Report on Form 10-Q.

Exhibit 4.6

FIRST SUPPLEMENTAL INDENTURE

FIRST SUPPLEMENTAL INDENTURE (this “ Supplemental Indenture ”), dated as of June 30, 2017 among WHR Eagle Ford LLC (the “ Guaranteeing Subsidiary ”), a subsidiary of WildHorse Resource Development Corporation, a Delaware corporation (the “ Issuer ”), the other Guarantors (as defined in the Indenture referred to herein) and U.S. Bank National Association, as trustee under the Indenture referred to below (the “ Trustee ”).

W I T N E S S E T H

WHEREAS, the Issuer has heretofore executed and delivered to the Trustee an indenture (the “ Indenture ”), dated as of February 1, 2017 providing for the issuance of 6.875% Senior Notes due 2025 (the “ Notes ”);

WHEREAS, the Indenture provides that under certain circumstances the Guaranteeing Subsidiary shall execute and deliver to the Trustee a supplemental indenture pursuant to which the Guaranteeing Subsidiary shall unconditionally Guarantee all of the Issuer’s Obligations under the Notes and the Indenture on the terms and conditions set forth herein (the “ Note Guarantee ”); and

WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Supplemental Indenture.

NOW, THEREFORE, in consideration of the foregoing and for other good and valuable consideration, the receipt of which is hereby acknowledged, the Guaranteeing Subsidiary, the other Guarantors, the Issuer and the Trustee mutually covenant and agree for the equal and ratable benefit of the Holders of the Notes as follows:

1. CAPITALIZED TERMS. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

2. GUARANTEE. The Guaranteeing Subsidiary hereby unconditionally Guarantees all of the Issuer’s Obligations under the Notes and the Indenture on the terms and subject to the conditions set forth in the Indenture including but not limited to Article 10 thereof.

3. NO RECOURSE AGAINST OTHERS. No director, officer, partner, employee, incorporator, manager or unitholder or other owner of Capital Stock of the Issuer or any Guarantor, as such, will have any liability for any obligations of the Issuer or the Guarantors under the Notes, the Indenture or the Note Guarantees or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each Holder of Notes by accepting a Note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the Notes.

4. NEW YORK LAW TO GOVERN. THE SUPPLEMENTAL INDENTURE SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF NEW YORK.

5. COUNTERPARTS. The parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

US 5112785v.2

6. EFFECT OF HEADINGS. The Section headings herein are for convenience only and shall not affect the construction hereof.

7. THE TRUSTEE. The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of this Supplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made solely by the Guaranteeing Subsidiary, the other Guarantors and the Issuer.

IN WITNESS WHEREOF, the parties hereto have caused this Supplement al Indenture to be duly executed and attested, all as of the date first above written.

Dated: June 30, 2017

WHR EAGLE FORD LLC

By:	/s/ Andrew J. Cozby
	Name: Andrew J. Cozby
	Title: Executive Vice President and Chief
	Financial Officer

WILDHORSE RESOURCE DEVELOPMENT
CORPORATION

By:	/s/ Andrew J. Cozby
	Name: Andrew J. Cozby
	Title:

WILDHORSE RESOURCES II, LLC,

	By: WildHorse Resource Development
	Corporation, its sole member

ESQUISTO RESOURCES II, LLC,

	By: WildHorse Resource Development
	Corporation, its sole member

WHE ACQCO., LLC,

	By: WildHorse Resource Development
	Corporation, its sole member

By:	/s/ Andrew J. Cozby
Name:	Andrew J. Cozby
Title:	Executive Vice President and Chief
	Financial Officer

Signature Page to First Supplemental Indenture

WILDHORSE RESOURCES MANAGEMENT
COMPANY, LLC,

	By: WildHorse Resources II, LLC, its sole
	member,
		By:WildHorse Resource
		Development Corporation, its sole
		member

OAKFIELD ENERGY LLC,

	By: WildHorse Resources II, LLC, its sole
	member,
		By: WildHorse Resource
		Development Corporation, its sole
		member

By:	/s/ Andrew J. Cozby
Name:	Andrew J. Cozby
Title:	Executive Vice President and Chief
	Financial Officer

PETROMAX E&P BURLESON, LLC,

	By: Esquisto Resources II, LLC, its sole
	member,
		By:WildHorse Resource
		Development Corporation, its sole
		member

By:	/s/ Andrew J. Cozby
Name:	Andrew J. Cozby
Title:	Executive Vice President and Chief
	Financial Officer

BURLESON WATER RESOURCES, LLC,

	By: Esquisto Resources II, LLC, its sole
	member,
		By: WildHorse Resource
		Development Corporation, its sole
		member

Signature Page to First Supplemental Indenture

U.S. BANK NATIONAL ASSOCIATION,
As Trustee

By:	/s/ Steven Finklea
	Name: Steven Finklea
	Title: Vice President

Signature Page to First Supplemental Indenture

Exhibit 31.1

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

PURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A)

OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, Jay C. Graham, certify that:

1.	I have reviewed this Quarterly Report on Form 10-Q of WildHorse Resource Development Corporation (the “registrant”);

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.	The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

[Omitted];

Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.	The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 10, 2017		/s/ Jay C. Graham
		Jay C. Graham
		Chief Executive Officer
		WildHorse Resource Development Corporation

Exhibit 31.2

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER

PURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A)

OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, Andrew J. Cozby, certify that:

1.	I have reviewed this Quarterly Report on Form 10-Q of WildHorse Resource Development Corporation (the “registrant”);

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.	The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

[Omitted];

5.	The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 10, 2017		/s/ Andrew J. Cozby
		Andrew J. Cozby
		Executive Vice President & Chief Financial Officer
		WildHorse Resource Development Corporation

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report on Form 10-Q of WildHorse Resource Development Corporation (the “Company”), as filed with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned, Jay C. Graham, Chief Executive Officer of WildHorse Resource Development Corporation and Andrew J. Cozby, Executive Vice President & Chief Financial Officer of WildHorse Resource Development Corporation, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to their knowledge:

(1)

the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2)

the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


Date: August 10, 2017	/s/ Jay C. Graham
	Jay C. Graham
	Chief Executive Officer
	WildHorse Resource Development Corporation

Date: August 10, 2017	/s/ Andrew J. Cozby
	Andrew J. Cozby
	Executive Vice President & Chief Financial Officer
	WildHorse Resource Development Corporation

The foregoing certifications are being furnished as an exhibit to the Report pursuant to Item 601(b)(32) of Regulation S-K and Section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code) and, accordingly, are not being filed as part of the Report for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and are not incorporated by reference into any filing of the Company, whether made before or after the date hereof, regardless of any general incorporation language in such filing.