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~~September 30, 2018

☐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 smaller reporting company)~~ Smaller reporting company ☐ Emerging growth company ☒

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

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

As of ~~July~~October 31, 2018, the registrant had ~~102~~101,~~005~~995,~~515~~729 shares of common stock, $0.01 par value outstanding.

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WILDHORSE RESOURCE DEVELOPMENT CORPORATION

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		Page
	Glossary of Oil and Natural Gas Terms	2
	Commonly Used Defined Terms	6
	Cautionary Note Regarding Forward-Looking Statements	7
	PART I—FINANCIAL INFORMATION	9
Item 1.	Financial Statements	9
	Unaudited Condensed Consolidated Balance Sheets as of June 30, 2018 and December 31, 2017	9
	Unaudited Condensed Consolidated Balance Sheets as of September 30, 2018 and December 31, 2017	9
	Unaudited Statements of Condensed Consolidated Operations for the Three and Six Months Ended June 30, 2018 and 2017	10
	Unaudited Statements of Condensed Consolidated Operations for the Three and Nine Months Ended September 30, 2018 and 2017	10
	Unaudited Statements of Condensed Consolidated Cash Flows for the Six Months Ended June 30, 2018 and 2017	11
	Unaudited Statements of Condensed Consolidated Cash Flows for the Nine Months Ended September 30, 2018 and 2017	11
	Unaudited Condensed Consolidated Statement of Changes in Stockholders’ Equity for the Six Months Ended June 30, 2018	12
	Unaudited Condensed Consolidated Statements of Changes in Stockholders’ Equity for the Nine Months Ended September 30, 2018 and 2017	12
	Note 1 – Organization and Basis of Presentation	13
	Note 2 – Summary of Significant Accounting Policies	1415
	Note 3 – Acquisitions and Divestitures	1921
	Note 4 – Fair Value Measurements of Financial Instruments	2123
	Note 5 – Risk Management and Derivative Instruments	2325
	Note 6 – Accounts Receivable	2527
	Note 7 – Accrued Liabilities	2527
	Note 8 – Asset Retirement Obligations	2627
	Note 9 – Long Term Debt	2628
	Note 10 – Preferred Stock	2830
	Note 11 – Equity	2931
	Note 12 – Earnings Per Share	2931
	Note 13 – Long Term Incentive Plans	3032
	Note 14 – Incentive Units	3032
	Note 15 – Related Party Transactions	3133
	Note 16 – Segment Disclosures	3234
	Note 17 – Income Taxes	3335
	Note 18 – Commitments and Contingencies	3336
	Note 19 – Subsequent Events	3437
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	3538
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	4954
Item 4.	Controls and Procedures	5055
	PART II—OTHER INFORMATION	5155
Item 1.	Legal Proceedings	5155
Item 1A.	Risk Factors	5155
Item 2.	Unregistered Sales Of Equity Securities and Use of Proceeds	5157
Item 3.	Defaults Upon Senior Securities	5258
Item 4.	Mine Safety Disclosures	5258
Item 5.	Other Information	5258
Item 6.	Exhibits	5258
	Signatures	5461

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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.

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

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

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

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.

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

Play: A geographic area with hydrocarbon potential.

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

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

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

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

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.

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

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

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

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

Reserves: Estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to market and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

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

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

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

Spacing: The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.

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

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

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

Unproved properties: Properties with no proved reserves.

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

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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,” “WRD,” “we,” “our,” “us” or like terms refer collectively to WildHorse Resource Development Corporation and its consolidated subsidiaries;

“Chesapeake” refers collectively to Chesapeake Energy Corporation and its consolidated subsidiaries, as applicable;

“WHR II” refers to WildHorse Resources II, LLC, together with its consolidated subsidiaries, which previously owned all of our North Louisiana Acreage;

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

“Acquisition Co.” refers to WHE AcqCo., LLC;

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

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

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

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

· “Eagle Ford Acreage” refers to our acreage in the northern area of the Eagle Ford Shale and in the Giddings Austin Chalk Trend in Southeast Texas;

“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 II 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”).~~

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stock, par value $0.01 per share, designated as “Series A Perpetual Convertible Preferred Stock” (the “Preferred Stock”).

FORWARD–LOOKING 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, including matters relating to our merger with Chesapeake, 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, 2017 (“2017 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 merger with Chesapeake;

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.

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We· ~~caution~~uncertainty ~~you~~regarding ~~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,~~future 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,~~results; ~~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 2017 Form 10-K.

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, the possibility that the proposed merger with Chesapeake does not close when expected or at all because required regulatory, shareholder or other approvals are not received or other conditions to the closing are not satisfied on a timely basis or at all, the risk that regulatory approvals required for the proposed merger are not obtained or are obtained subject to conditions that are not anticipated, potential adverse reactions or changes to business or employee relationships, including those resulting from the announcement or completion of the proposed merger, uncertainties as to the timing of the proposed merger; competitive responses to the proposed merger, the possibility that the anticipated benefits of the proposed merger are not realized when expected or at all, including as a result of the impact of, or problems arising from, the integration of the two companies, the possibility that the proposed merger may be more expensive to complete than anticipated, including as a result of unexpected factors or events, diversion of management’s attention from ongoing business operations and opportunities, the ability of Chesapeake to complete the acquisition and integration of WRD successfully, litigation relating to the proposed merger, other factors that may affect future results of WRD and Chesapeake and the other risks described under “Part II—Item 1A. Risk Factors” of this Quarterly Report and “Part I—Item 1A. Risk Factors” of our 2017 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 those 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.

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PART I—FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS.

WILDHORSE RESOURCE DEVELOPMENT CORPORATION

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except outstanding shares)

	June 30,		December 31,
	September 30,		December 31,
	2018		2017
ASSETS
Current Assets:
Cash and cash equivalents	$	191,~~139~~745	$	226
Accounts receivable, net		~~109~~111,~~017~~354		84,103
Derivative instruments		—		2,336
Prepaid expenses and other current assets		45,~~669~~734		3,290
Total current assets		~~132~~118,~~825~~833		89,955
Property and equipment:
Oil and gas properties		3,~~007~~271,~~462~~422		2,999,728
Other property and equipment		5379,~~124~~120		53,003
Accumulated depreciation, depletion and amortization		(~~351~~426,~~248~~373)		(368,245)
Total property and equipment, net		2,~~709~~924,~~338~~169		2,684,486
Other noncurrent assets:
Derivative instruments		~~491~~574		86
Debt issuance costs		3,~~618~~301		3,573
Other		1317,~~256~~575		—
Total assets	$	23,~~859~~064,~~528~~452	$	2,778,100
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	6566,~~710~~423	$	53,005
Accrued liabilities		~~193~~169,~~552~~665		199,952
Derivative instruments		~~107~~131,~~206~~539		58,074
Total current liabilities		~~366~~367,~~468~~627		311,031
Noncurrent liabilities:
Long-term debt		~~935~~1,~~609~~085,997		770,596
Asset retirement obligations		7,~~518~~899		14,467
Deferred tax liabilities		2044,~~612~~141		71,470
Derivative instruments		6181,~~866~~736		18,676
Other noncurrent liabilities		874		1,085
Other		762		1,085
Total noncurrent liabilities		1,~~026~~220,~~479~~535		876,294
Total liabilities		1,~~392~~588,~~947~~162		1,187,325
Commitments and contingencies (Note 18)
Preferred Stock, $0.01 par value: 50,000,000 shares authorized
Series A perpetual convertible preferred stock, $0.01 par value: 500,000 shares authorized; 435,000 shares issued and outstanding at June 30, 2018 and December 31, 2017, respectively, (involuntary liquidation preference of $450,389 and $448,146 at June 30, 2018 and December 31, 2017, respectively)		447,726		445,483
Series A perpetual convertible preferred stock, $0.01 par value: 500,000 shares authorized; 435,000 shares issued and outstanding at September 30, 2018 and December 31, 2017, respectively, (involuntary liquidation preference of $450,389 and $448,146 at September 30, 2018 and December 31, 2017, respectively)		447,726		445,483
Stockholders’ equity:
Common stock, $0.01 par value 500,000,000 shares authorized; 102,007,516 shares and 101,137,277 shares issued and outstanding at June 30, 2018 and December 31, 2017 respectively		1,020		1,012
Common stock, $0.01 par value 500,000,000 shares authorized; 101,996,754 shares and 101,137,277 shares issued and outstanding at September 30, 2018 and December 31, 2017 respectively		1,020		1,012
Additional paid-in capital		1,~~141~~146,~~140~~149		1,118,507
Accumulated earnings (deficit)		(~~123~~118,~~305~~605)		25,773
Total stockholders’ equity		1,~~018~~028,~~855~~564		1,145,292
Total liabilities and equity	$	23,~~859~~064,~~528~~452	$	2,778,100

See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements

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WILDHORSE RESOURCE DEVELOPMENT CORPORATION

UNAUDITED STATEMENTS OF CONDENSED CONSOLIDATED OPERATIONS

(In thousands, except per share amounts)

For the Three Months Ended June 30,

For the Six Months Ended June 30,

For the Three Months Ended September 30,

For the Nine Months Ended September 30,

2018

2017

2018

2017

Revenues and other income:

Oil sales

~~207~~236,~~392~~040

52100,~~963~~391

~~389~~625,~~771~~811

92192,~~040~~431

Natural gas sales

89,~~106~~298

1314,~~277~~906

3545,~~736~~034

2540,~~422~~328

NGL sales

913,~~668~~883

36,~~404~~881

1730,~~116~~999

612,~~067~~948

Other income

~~247~~269

~~529~~308

1,~~547~~816

~~936~~1,244

Total revenues and other income

~~225~~259,~~413~~490

70122,~~173~~486

~~444~~703,~~170~~660

~~124~~246,~~465~~951

Operating expenses:

Lease operating expenses

1214,~~088~~221

612,~~837~~435

2842,~~515~~736

1326,~~765~~200

Gathering, processing and transportation

~~476~~3,225

13,~~942~~761

15,~~828~~053

37,~~642~~403

Taxes other than income tax

1214,~~779~~193

46,~~509~~047

2438,~~560~~753

814,~~408~~455

Depreciation, depletion and amortization

7074,~~694~~842

3351,~~229~~843

~~130~~205,~~577~~419

59111,~~672~~515

Impairment of NLA Disposal Group (Note 3)

—

214,274

—

(Gain) loss on sale of properties

~~(3,167)~~217

—

(32,~~167~~950)

—

General and administrative expenses

1216,~~917~~033

1011,~~049~~043

2541,~~644~~677

1728,~~531~~574

Incentive unit compensation expense

~~13,776~~—

—

13,776

—

Exploration expense

413,~~369~~814

114,~~504~~749

619,~~077~~891

1317,~~119~~868

Other operating (income) expense

~~111~~169

259

~~769~~938

4453

Total operating expense

~~124~~136,~~043~~714

6889,~~095~~887

~~442~~579,~~853~~567

~~116~~206,~~181~~068

Income (loss) from operations

~~101~~122,~~370~~776

232,~~078~~599

1124,~~317~~093

840,~~284~~883

Other income (expense):

Interest expense, net

(1415,~~002~~718)

(68,~~633~~749)

(2743,~~309~~027)

(1220,~~204~~953)

Gain (loss) on derivative instruments

(~~110~~76,~~805~~358)

46(40,~~116~~288)

(~~151~~227,~~175~~533)

7737,~~407~~119

Other income (expense)

(13122)

(212)

(~~150~~272)

2412

Total other income (expense)

(~~124~~92,~~820~~198)

39(49,~~481~~049)

(~~178~~270,~~634~~832)

6516,~~227~~178

Income (loss) before income taxes

~~(23~~30,~~450)~~578

41(16,~~559~~450)

(~~177~~146,~~317~~739)

7357,~~511~~061

Income tax benefit (expense)

9(19,~~356~~055)

~~(15~~5,~~193)~~646

4728,~~449~~394

(2621,~~893~~247)

Net income (loss) available to WRD

~~(14~~11,~~094)~~523

26(10,~~366~~804)

(~~129~~118,~~868~~345)

4635,~~618~~814

Preferred stock dividends

76,~~961~~756

736,450

1522,~~350~~106

736,523

Undistributed earnings allocated to participating securities

—1,233

~~387~~—

—

~~434~~3,234

Net income (loss) available to common stockholders

~~(22~~3,~~055)~~534

25(17,~~906~~254)

(~~145~~140,~~218~~451)

4626,~~111~~057

Earnings per common share:

Basic

(0.~~22)~~04

(0.2817)

(1.4641)

0.4927

Diluted

(0.~~22)~~04

(0.2817)

(1.4641)

0.4927

Weighted-average common shares outstanding:

Basic

99,~~411~~639

9399,~~685~~142

99,~~328~~433

9395,~~452~~369

Diluted

99,~~411~~639

9399,~~685~~142

99,~~328~~433

9395,~~452~~369

See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements

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WILDHORSE RESOURCE DEVELOPMENT CORPORATION

UNAUDITED STATEMENTS OF CONDENSED CONSOLIDATED CASH FLOWS

(In thousands)

	For the Six Months Ended June 30,
	For the Nine Months Ended September 30,
	2018		2017
Cash flows from operating activities:
Net income (loss)	$	(~~129~~118,~~868~~345)	$	4635,~~618~~814
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		~~130~~205,~~249~~419		59111,~~367~~515
Accretion of asset retirement obligations		328		305
Impairments of unproved properties		8,226		13,910
Impairments of unproved properties		5,866		10,663
Impairment of NLA Disposal Group		214,274		—
Amortization of debt issuance cost		12,~~421~~184		1,~~277~~962
Accretion of senior notes discount		~~105~~108		~~105~~197
(Gain) loss on derivative instruments		~~151~~227,~~175~~533		(7737,~~407~~119)
Cash settlements on derivative instruments		(5081,~~054~~177)		16,~~093~~895
Deferred income tax expense (benefit)		(5027,~~925~~396)		2620,~~893~~263
Debt extinguishment expense		—		(11)
Amortization of equity awards		611,~~991~~988		14,~~803~~217
Incentive unit compensation expense		13,776		—
(Gain) loss on sale of properties		(32,~~167~~950)		—
Consideration paid to customers, net of amortization		(1,328)		—
Loss on equity investment		103
Consideration paid to customers, net of amortization		(1,806)		—
Changes in operating assets and liabilities
Decrease (increase) in accounts receivable		(1823,~~321~~492)		(2242,~~307~~081)
Decrease (increase) in prepaid expenses		(~~831~~503)		(1,~~760~~245)
Decrease (increase) in inventories		648		—
(Decrease) increase in accounts payable and accrued liabilities		2118,~~168~~784		2528,~~395~~875
Net cash flow provided by operating activities		~~291~~447,~~507~~374		72143,~~034~~192
Cash flows from investing activities:
Acquisitions of oil and gas properties		(1953,~~914~~188)		(~~547~~549,~~389~~033)
Additions to oil and gas properties		(~~578~~824,~~669~~656)		(~~211~~443,~~263~~210)
Additions to and acquisitions of other property and equipment		(2557,~~010~~987)		(610,~~189~~070)
Construction deposits		(71,~~948~~714)		—
Contribution to equity method investee		(10,177)		—
Proceeds from NLA Divestiture		206,406		—
Net cash used in investing activities		(~~425~~741,~~135~~316)		(~~764~~1,~~841~~002,313)
Cash flows from financing activities:
Advances on revolving credit facilities		~~530~~842,000		~~161~~363,500
Payments on revolving credit facilities		(~~567~~729,353)		(~~258~~447,~~250~~765)
Debt issuance cost		(3,~~246~~502)		(1013,~~756~~545)
Proceeds from senior notes offering		204,000		~~347~~494,~~354~~744
Proceeds from the issuance of preferred stock		—		435,000
Costs incurred in conjunction with the issuance of preferred stock		—		(2,~~416~~662)
Proceeds from issuance of common stock		—		34,457
Cost incurred in conjunction with issuance of common stock		—		(2,~~097~~698)
Cost incurred in conjunction with the initial public offering		—		(601)
Preferred stock dividends		(13,512)		—
Preferred stock dividends		(6,756)		—
Repurchase of vested restricted stock		(4,172)		—
Repurchase of vested restricted stock		(4,104)		—
Net cash provided by financing activities		295,461		861,031
Net cash provided by financing activities		152,541		704,191
Net change in cash, cash equivalents and restricted cash		1,519		1,910
Net change in cash, cash equivalents and restricted cash		18,913		11,384
Cash, cash equivalents and restricted cash, beginning of period		226		4,001
Cash, cash equivalents and restricted cash, end of period	$	191,~~139~~745	$	155,~~385~~911

See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements

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WILDHORSE RESOURCE DEVELOPMENT CORPORATION

UNAUDITED CONDENSED CONSOLIDATED ~~STATEMENT~~STATEMENTS OFCHANGES IN STOCKHOLDERS’ EQUITY

(In thousands)

	Stockholders’ Equity
	For the Nine Months Ended September 30, 2018
	CommonStock		AdditionalPaid inCapital		AccumulatedEarnings(Deficit)		Total
December 31, 2017	$	1,012	$	1,118,507	$	25,773	$	1,145,292
Cumulative effect of accounting change (Note 2)		—		—		~~243~~241		~~243~~241
Net income (loss)		—		—		(~~129~~115,~~868~~774)		(~~129~~115,~~868~~774)
Preferred stock paid-in-kind dividend		—		—		(2,243)		(2,243)
Preferred stock cash dividend		—		—		(6,756)		(6,756)
Accrued preferred stock cash dividend		—		—		(4,480)		(4,480)
Accrued preferred stock cash dividend		—		—		(4,479)		(4,479)
Beneficial conversion feature of preferred stock		—		1,872		—		1,872
Amortization of beneficial conversion feature		—		—		(~~1,872~~668)		(~~1,872~~668)
Repurchase of vested restricted common stock		—		—		(69)		(69)
Amortization of equity awards		1		3,155		—		3,156
March 31, 2018		1,013		1,123,534		(97,220)		1,027,327
Cumulative effect of accounting change (Note 2)		—		—		2		2
Net income (loss)		—		—		(14,094)		(14,094)
Preferred stock cash dividend		—		—		(6,756)		(6,756)
Accrued preferred stock cash dividend		—		—		1		1
Amortization of beneficial conversion feature		—		—		(1,204)		(1,204)
Contribution related to incentive unit compensation expense		—		13,776		—		13,776
Repurchase of vested restricted common stock		(2)		—		(4,~~103~~034)		(4,~~105~~036)
Amortization of equity awards		109		63,~~985~~830		—		63,~~995~~839
June 30, 2018	$	1,020	$	1,141,140	$	(123,305)	$	1,018,855
Net income (loss)		—		—		11,523		11,523
Preferred stock cash dividend		—		—		(6,756)		(6,756)
Contribution related to incentive unit compensation expense		—		—		—		—
Repurchase of vested restricted common stock		—		—		(67)		(67)
Amortization of equity awards		—		5,009		—		5,009
September 30, 2018	$	1,020	$	1,146,149	$	(118,605)	$	1,028,564


	For the Nine Months Ended September 30, 2017
	Common Stock		Additional Paid in Capital		Accumulated Earnings (Deficit)		Total
December 31, 2016	$	917	$	1,017,368	$	(10,397)	$	1,007,888
Net income (loss)		—		—		20,252		20,252
Proceeds from issuance of common stock		23		34,434		—		34,457
Costs incurred in connection with issuance of common stock		—		(1,872)		—		(1,872)
Amortization of equity awards		—		495		—		495
March 31, 2017		940		1,050,425		9,855		1,061,220
Net income (loss)		—		—		26,366		26,366
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		1,292		—		1,308
June 30, 2017		1,011		1,112,416		36,148		1,149,575
Net income (loss)		—		—		(10,804)		(10,804)
Accrual of preferred stock paid-in-kind dividend		—		—		(6,450)		(6,450)
Amortization of equity awards		1		2,413		—		2,414
September 30, 2017	$	1,012	$	1,114,829	$	18,894	$	1,134,735

See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements

Table of Contents

WILDHORSE RESOURCE DEVELOPMENT CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED 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 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” refers to WildHorse Resources II, LLC, together with its consolidated subsidiaries. Reference to “Esquisto II” refers to Esquisto Resources II, LLC. Reference to “Acquisition Co.” refers to WHE AcqCo., LLC. Reference to “WildHorse Investment Holdings” refers to WildHorse 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 II and Acquisition Co.

WHR II, Esquisto II, Acquisition Co., WHR Eagle Ford LLC (“WHR EF”), ~~and~~ Burleson Sand LLC (“Burleson Sand”) and WHCC Infrastructure LLC (“WHCC”) are wholly owned subsidiaries of the Company as of ~~June~~September 30, 2018. WildHorse Resources Management Company, LLC (“WHRM”) is a wholly owned subsidiary of WHR II. Esquisto II has two wholly owned subsidiaries – Petromax E&P Burleson, LLC, and Burleson Water Resources, LLC (“Burleson Water”). WHRM is the named operator for all oil and natural gas properties owned by us.

In June 2018, we formed a wholly-owned subsidiary, WHCC Infrastructure LLC, and in July 2018, made an initial capital contribution of approximately $10.0 million in such subsidiary for midstream opportunities.

Basis of Presentation

Our consolidated financial statements include our accounts and those of our subsidiaries. Restricted cash was previously presented as a component of cash flows from investing activities on the unaudited statements of condensed consolidated cash flows. Restricted cash is now being included in cash and cash equivalents when reconciling the beginning of period and end of period totals within the unaudited statements of condensed consolidated cash flows due to the adoption of a new accounting standard. See Note 2 for additional information.

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

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

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WILDHORSE RESOURCE DEVELOPMENT CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~environmental~~ Investment ~~remediation costs; (8) valuation of derivative instruments; (9) contingent liabilities and (10) impairment expense. Although management believes these estimates are reasonable, changes~~ in ~~facts~~Unconsolidated ~~and circumstances or discovery of new information may result in revised estimates, and such revisions could be material.~~Affiliate

WHCC and an undisclosed joint venture partner (“JV Partner”) each made an approximate $10.2 million cash capital contribution for a 50% membership interest in JWH Midstream LLC (“JWH”) during July 2018. JWH used the capital contributions to finance the acquisition of a holding company from a third party that had an existing lease with the Port of Corpus Christi Authority (“Port”) for approximately 55 acres of land on the north side of the Corpus Christi Ship Channel in the Inner Harbor. WHCC’s 50% membership interest in JWH is subject to a call and put option.

The call option gives JV Partner the right, but not the obligation, to purchase WHCC’s membership interest after December 1, 2018 in the event that WHCC and JV Partner have not entered into definitive documentation regarding a proposed joint venture terminal development plan on or before December 1, 2018. The put option gives WHCC the right, but not the obligation, to require JV Partner to purchase WHCC’s membership interest after June 1, 2019 in the event that WHCC and JV Partner have not entered into definitive documentation regarding a proposed joint venture terminal development plan on or before June 1, 2019. The predetermined sales price of WHCC’s membership interest will be equal to aggregate capital contributions made by WHCC to JWH, less any distributions made by JWH to WHCC, plus a rate of return equal to three percent. We determined that the call and put options did not meet the definition of a derivative.

A $47.5 million irrevocable standby letter of credit was issued on July 27, 2018 under the Company’s revolving credit facility in favor of the Port to cover future minimum annual wharfage fee payment deficits under the lease. The Port requires that either a guaranty or letter of credit be in place for the first 10 years of the 20-year lease. Until the proposed marine terminal is built and operational, the letter of credit cannot be drawn upon by the Port. If the put or call option is exercised, JV Partner is contractually required to take all actions, including but not limited to, providing a letter of credit or similar guarantee to the Port, as necessary to have WRD fully released from its letter of credit.

We determined that JWH is a variable interest entity (“VIE”) due to our disproportionate obligation to absorb losses compared to our voting rights and substantially all of JWH’s current activities involve us. We are exposed to losses above and beyond our 50% membership interest in JWH since we provided the Port with the irrevocable standby letter of credit naming the Port as beneficiary. A reporting entity is the primary beneficiary of a VIE and must consolidate it when that party has a variable interest, or combination of variable interests, that provides it with a controlling financial interest. A party is deemed to have a controlling financial interest if it meets both of the power and losses/benefits criteria. The power criterion is the ability to direct the activities of the VIE that most significantly impact its economic performance. The losses/benefits criterion is the obligation to absorb losses from, or right to receive benefits from, the VIE that could potentially be significant to the VIE. The VIE model requires an ongoing reconsideration of whether a reporting entity is the primary beneficiary of a VIE due to changes in facts and circumstances. The Company has determined it is not the primary beneficiary. On the basis of governing provisions set forth in JWH’s limited liability agreement, all decisions regarding activities requires joint or unanimous consent. The power to direct activities that most significantly impact JWH’s economic performance is shared. Our maximum exposure to loss cannot be quantified, but would be limited to our investment and any amounts withdrawn by the Port under the standby letter of credit previously discussed.

Our investment in JWH is being accounted as an equity method investee. Investments in a limited liability company that maintains a specific ownership account for each investor should generally be accounted for under the equity method of accounting unless the investment is so minor that the member may have virtually no influence over the company’s operating and financial policies. In practice, investments of more than 3 to 5 percent are viewed as more than minor. Our $10.1 million investment in JWH is reflected on our balance sheet under other noncurrent assets as a component of the “Other” financial statement line item. Equity losses of $0.1 million for the three and nine months ended September 30, 2018 is reflected on our income statement under other income (expense) as a component of the “Other income (expense)” financial statement line item.

Table of Contents

WILDHORSE RESOURCE DEVELOPMENT CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 2. Summary of Significant Accounting Policies

A discussion of our significant accounting policies and estimates is included in our 2017 Form 10-K. There have been no changes except as discussed below.

Oil and Gas Properties

Significant costs associated with development wells in progress or awaiting completion are excluded from depletion until the well is completed. Effective July 1, 2018, we lowered our significance threshold and as a result, we excluded capitalized costs of $60.9 million at September 30, 2018.

Supplemental Cash Flow Information

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

	For the Six Months Ended June 30,
	For the Nine Months Ended September 30,
	2018		2017
Supplemental cash flows:
Cash paid for interest, net of capitalized interest	$	2245,~~487~~496	$	~~306~~13,465
Noncash investing activities:
Increase (decrease) in capital expenditures in accounts payables and accrued liabilities		(2345,~~993~~838)		8295,~~295~~292
(Increase) decrease in accounts receivable related to capital expenditures and acquisitions		(31,~~027~~780)		(87,~~687)~~990

New Accounting Standards

Definition of a Business

In January 2017, the Financial Accounting Standards Board (the “FASB”) issued an accounting standards update to clarify the definition of a business. The definition of a business affects many areas of accounting including acquisitions, disposals, goodwill, and consolidation. The amendments are intended to help companies and other organizations evaluate whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The amendments provide a more robust framework to use in determining when a set of assets and activities is a business. The amendments are effective for annual periods beginning after December 15, 2017, including interim periods within those periods. Early adoption was permitted and the guidance is to be applied on a prospective basis to purchases or disposals of a business or an asset. The Company adopted this guidance on January 1, 2018 and it did not have a material impact on our consolidated financial statements.

Statement of Cash Flows – Restricted Cash a consensus of the FASB Emerging Issues Task Force

In November 2016, the FASB issued an accounting standards update to clarify the guidance on the classification and presentation of restricted cash in the statement of cash flows. The changes in restricted cash and restricted cash equivalents that result from the transfers between cash, cash equivalents, and restricted cash and restricted cash equivalents should not be presented as cash flow activities in the statement of cash flows. The new guidance is effective for reporting periods beginning after December 15, 2017 and interim periods within those fiscal years. The new guidance requires transition under a retrospective approach for each period presented. The Company adopted this guidance on January 1, 2018 and it did not have a material impact on our consolidated financial statements.

Statement of Cash Flows – Classification of Certain Cash Receipts and Cash Payments

In August 2016, the FASB issued an accounting standards update to address eight specific cash flow issues with the objective of reducing the current and potential future diversity in practice. The new guidance is effective for reporting periods beginning after December 15, 2017 and interim periods within those fiscal years. The new guidance requires transition under a retrospective approach for each period presented. If it is impracticable to apply the amendments retrospectively for some of the issues, the amendments for those issues would be applied prospectively as of the earliest

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Table of Contents

WILDHORSE RESOURCE DEVELOPMENT CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

transition under a retrospective approach for each period presented. If it is impracticable to apply the amendments retrospectively for some of the issues, the amendments for those issues would be applied prospectively as of the earliest date practicable. The Company adopted this guidance on January 1, 2018 and it did not have a material impact on our consolidated financial statements.

Leases

In February 2016, the FASB issued a revision to its lease accounting guidance. The FASB retained a dual model, ~~requiring~~which ~~leases~~requires toclassification beof ~~classified~~leases as finance or operating ~~leases~~. The classification is ~~will be~~ based on criteria that are similar to the current lease accounting guidance. The revised guidance requires lessees to recognize a right-of-use asset and lease liability for all leasing transactions regardless of classification. ~~For~~The ~~leases~~new ~~with~~standard ~~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 right-of-use 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. Originally, entities were the required to use the modified retrospective approach, including applicable practical expedients related to leases commenced before the effective date. However, in July 2018, the FASB issued targeted improvements to the new leasing standard, which now allows entities the option of recognizing the cumulative effect of applying the new standard as an adjustment to the opening balance of retained earnings in the year of adoption while continuing to present all prior periods under previous lease accounting guidance. 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 standard will extend over future periods. The Company is also currently evaluating which transition approach will be used upon adoption.

Originally, entities were required to use a modified retrospective approach, where the date of initial application to existing leases would be to the beginning of the earliest period presented in the annual financial statements where we first apply the new standard (i.e. financial statements as of and for the year ending December 31, 2019). Under this method therefore, leases commencing as early as January 1, 2017 would be impacted by the new standard and comparative periods presented in those financials would likely be adjusted (“the comparative method”). In July 2018, the FASB issued targeted improvements to the new leasing standard, which now allows entities the option to use the January 1, 2019 effective date as the date of initial application (“the effective date method”). As a result, comparative periods will not require adjustment because only contracts existing as of January 1, 2019 are within the scope of the new standard. The Company currently intends to adopt the standard using the effective date method.

Further, the new standard allows lessees to adopt a package of practical expedients upon transition to the new standard, whereby contracts existing as of January 1, 2019 will not require reassessment under the new definition of a lease or new lease classification criteria. Therefore, a contract existing on January 1, 2019 that did not meet the definition of a lease under the current standard, will not be accounted for or reported as a lease under the new standard. Effectively, the current identification and classification will remain for those leases (under the new standard) unless those leases are modified or require reassessment under the new standard. The Company currently intends to make this accounting policy election upon adoption.

For leases with a term of 12 months or less (i.e. a short-term lease), a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize right-of-use assets and lease liabilities. If a lessee makes this election, it should generally recognize lease expense for such leases on a straight-line basis over the lease term and short-term lease costs must be disclosed for each period. The Company currently intends to make this accounting policy election for most or all classes of assets.

The new standard provides a scope exclusion for the rights to use land easements related to oil and gas activities, for which many of our land easement will qualify. Additionally, the standard allows a practical expedient not to reassess whether land easements existing on January 1, 2019 meet the definition of a lease under the new standard if they were not accounted for as leases under the current standard. The Company currently intends to make this accounting policy election upon adoption.

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. Though the full quantitative impacts of the new standard are dependent on the leases in force at the time of adoption, we have determined that the adoption of the standard will result in a material increase to our assets and liabilities due to the recognition on our balance sheet of our office leases and certain equipment. As we complete our evaluation, we will determine all contracts that are impacted throughout our various disciplines.

Table of Contents

WILDHORSE RESOURCE DEVELOPMENT CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Revenue from Contracts with Customers

Our revenues are derived through the sale of our hydrocarbon production, specifically the sale of crude oil, natural gas and NGLs. On January 1, 2018 the Company adopted ASC 606, Revenue from Contracts with Customers and all the related amendments (“new revenue standard”) to all contracts that were not completed as of January 1, 2018 using the cumulative effect transition method. The cumulative effect of adopting the standard was recognized through an adjustment to opening accumulated earnings. The new revenue standard provides a five-step model to analyze contracts to determine when and how revenue is recognized. Central to the five-step model is the concept of control and the timing of the transfer of that control determines the timing of when revenue can be recognized. Control as defined in the standard is the “ability to direct the use of, and obtain substantially all of the remaining benefits from, the asset.” We review our contracts through the five-step model at inception, and as any new contracts are executed or existing contracts are modified, to determine when to recognize revenue. We expect the overall impact to net income to be immaterial on an ongoing basis.

Previous periods have not been revised or adjusted and reflect the revenue standard in effect for those periods. Under the previous revenue recognition standard, revenues were recognized when the product was delivered at a fixed and determinable price, title transferred and collectability was reasonably assured and evidenced by a contract.

Crude oil sales contracts

We have performance obligations under our crude oil sales contracts to deliver barrels of oil, where each barrel of oil is considered to be its own performance obligation under the new revenue standard. Volumes are generally not predetermined and pricing for the crude oil is index-based, adjusted for location and other economic factors. We recognize revenue from the sale of our crude oil at a point in time, when we transfer control of the crude oil to our purchaser, which occurs when the oil passes through our facilities (typically a tank battery or our third-party contracted trucks) into our purchaser’s receiving equipment (typically a truck or their pipeline). Once the crude oil has been delivered, we have fulfilled our obligation and we no longer have the ability to direct the use of, or obtain any of the remaining benefits from that crude oil. Sales of crude oil are presented on the “Oil sales” line item of our statement of operations. The adoption of the new revenue standard did not result in any material changes to the accounting or presentation of oil sales.

15Natural gas sales contracts

Our natural gas contracts stipulate that we deliver unprocessed natural gas to a contractually specified delivery point. Once the natural gas enters our customer’s facilities, it may be compressed, dehydrated, treated, separated into residue gas (predominately methane) and NGLs, or otherwise processed. For a majority of our natural gas sales contracts, WildHorse transfers control of the natural gas (which could include both residue gas and NGLs) to our customer upon delivery into their facilities and we recognize revenue at that point in time. Our performance obligation within these contracts is to deliver unprocessed natural gas. Once delivered, we have fulfilled our obligation and our customers have full control over the use, sale or disposition of the gas. Any charges assessed to us by our customer, including but not limited to gathering, processing, compression, treating and dehydration are considered to be a reduction to the transaction price because we did not receive a distinct good or service from the customer. Services are not deemed to be provided to us because the related activities occur after we transfer control of the gas to our customer. Prior to the adoption of the new revenue standard, these charges were reported within “Gathering, processing and transportation” expense in our statement of operations, while these costs are now being netted against revenues.

For the other portion of our natural gas sales contracts, our contracts are structured such that both the customer and WildHorse have shared contractual control over the natural gas. Contractual terms dictate that payment to us is based on actual extracted volumes of NGLs/residue gas. Further, the contracts stipulate that a portion of that processed gas is retained by our customer as compensation for their services, thereby incentivizing the customer to process our gas and operate their facilities efficiently in our best interest. Under these contracts, the value associated with the volumes our customer retains and any charges assessed by our customer are recognized on our “Gathering, processing and transportation” expense line item. This is because the gas is contractually controlled jointly by both us and our customer until our performance obligation is fulfilled at the tailgate of our customer’s plant (once processing has been completed).

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~~that~~Our ~~crude~~performance ~~oil~~obligation under these contracts is to sell the extracted NGLs and residue gas. ~~Sales~~ We ofrecognize ~~crude~~revenue ~~oil~~at ~~are~~a ~~presented~~point onin time (at the ~~“Oil~~plant ~~sales”~~tailgate) ~~line~~when ~~item~~we ofhave fulfilled our ~~statement~~performance ~~of operations~~obligation. ~~The~~Prior to the adoption of the new revenue standard, we did not ~~result~~recognize inthe ~~any~~volumes ~~material~~retained ~~changes~~by toour ~~the~~customer ~~accounting~~as oran ~~presentation~~expense and we reported revenues net of ~~oil~~the ~~sales~~volumes they retained.

Natural gas sales contracts

Residue gas contracts

In certain of the natural gas sales contracts discussed above, the residue gas separated during plant processing is not sold to the processor but is instead redelivered back to us at the tailgate of the plant. We directly market these volumes to third parties using index-based natural gas prices and utilize our pipeline capacity (under our transportation agreements) to deliver these volumes from the plant tailgate to market. Our performance obligation in our residue gas contracts is the delivery of residue gas. Control over residue gas transfers upon delivery, at which point we have fulfilled our performance obligation and can recognize revenue.

Performance obligations fulfilled in a prior period

We record revenue in the month oil or natural gas volumes are delivered to the customer, based on estimated production, prices and revenue deductions. Any variances between our estimates and the actual amounts received are generally recorded one month after delivery for operated oil sales, two months after delivery for operated natural gas and NGL sales and three months after delivery for non-operated oil, natural gas and NGL sales.

Disaggregation of revenue

The new revenue standard requires that we disaggregate revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. Our statement of operations disaggregates revenue to reflect pricing realities present in our contracts with our customers. The terms of our natural gas sales contracts stipulate that the pricing we receive for our unprocessed natural gas will be based on the volumes of lower value natural gas and higher value NGLs present in the unprocessed natural gas we deliver. Fees assessed by our customers (that reduce revenue) are allocated between gas and NGLs on a volumetric basis or based upon the nature of the fee.

16Contributions in aid of construction

Certain of our contracts require us to make up-front payments to our customers to reimburse them for the cost of installing metering and custody transfer equipment or constructing pipelines from our wells to their facilities. These long-term assets are amortized over the period of the benefit and are presented as a reduction to natural gas and NGL revenue or as a gathering, processing and transportation expense. Prior to the adoption of the new revenue standard, these assets were recorded to our “Oil and gas properties” line item on the balance sheet and depleted using the units of production method. As depicted below, we adjusted the balance sheet and accumulated earnings for the cumulative effect of this accounting change.

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customers. The terms of our natural gas sales contracts stipulate that the pricing we receive for our unprocessed natural gas will be based on the volumes of lower value natural gas and higher value NGLs present in the unprocessed natural gas we deliver. Fees assessed by our customers (that reduce revenue) are allocated between gas and NGLs on a volumetric basis or based upon the nature of the fee.

Contributions in aid of construction

Certain of our contracts require us to make up-front payments to our customers to reimburse them for the cost of installing metering and custody transfer equipment or constructing pipelines from our wells to their facilities. These long-term assets are amortized over the period of the benefit and are presented as a reduction to natural gas and NGL revenue. Prior to the adoption of the new revenue standard, these assets were recorded to our “Oil and gas properties” line item on the balance sheet and depleted using the units of production method. As depicted below, we adjusted the balance sheet and accumulated earnings for the cumulative effect of this accounting change.

The cumulative effect of the changes made to our consolidated January 1, 2018 balance sheet for the adoption of the new revenue standard is as follows (in thousands):


	At December 31,		Adjustments for		At January 1,
	2017		ASC 606		2018
Assets:
Oil and gas properties	$	2,999,728	$	(4,041)	$	2,995,687
Accumulated depreciation, depletion and amortization		(368,245)		371		(367,874)
Other non-current assets		—		3,978		3,978
Liabilities:
Deferred tax liabilities	$	71,470	$	67	$	71,537
Stockholders’ Equity:
Accumulated earnings (deficit)	$	25,773	$	243	$	26,016

Other topics

Production Imbalances - We recognize revenues from the sale of oil, natural gas and NGLs using the sales method of accounting, whereby revenue is recorded based on our share of volume sold, regardless of whether we have taken our proportional share of volume produced. These differences result in gas imbalances. We record a liability to the extent there are not sufficient reserves to cover an over delivered gas imbalance. No receivables are recorded for those wells on which the Company has taken less than its proportionate share of production.

Contract assets - The new revenue standard requires certain disclosure around contract assets. Contract assets are rights to consideration in exchange for goods or services that the entity has transferred to a customer when that right is conditional on something other than the passage of time. We have an unconditional right to payment upon completion of our performance obligations and have therefore recorded no contract assets as of ~~June~~September 30, 2018.

Unsatisfied performance obligations - We have no unsatisfied performance obligations under our contracts. The majority of our contracts do not have stated volumes and we consider our performance obligations to be satisfied upon transfer of control of the commodity. In our remaining contracts where we are obligated to deliver a stated volume, all volumes are delivered in the period and we do not have any unsatisfied performance obligations under those contracts at the end of a period.

Other Income - During the period, we owned the Oakfield gathering system, substantial fresh water supply and storage, a saltwater disposal well and several compressors. Though the Oakfield gathering system, saltwater disposal well and compressors were sold to Tanos Energy Holdings III, LLC (“Tanos”) as part of the NLA Divestiture (see Note 3), these assets were used during the period in the operations of our wells. Non-operators who own a portion of our wells are billed for the use of these assets, utilizing rates based on industry-accepted joint interest accounting rules and market conditions. We report income from this source as “Other income” on our statement of operations in accordance with accounting guidance on collaborative arrangements. Operating expenses related to these activities are recorded to the “Other operating (income) expense” line item on the statement of operations. Prior to the adoption of the new revenue standard, income net of expenses from saltwater disposal wells and compressors were recorded within lease operating expense and income net of expenses for the Burleson water supply and storage assets were recorded within other income.

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accounting guidance on collaborative arrangements. Operating expenses related to these activities are recorded to the “Other operating (income) expense” line item on the statement of operations. Prior to the adoption of the new revenue standard, income net of expenses from saltwater disposal wells and compressors were recorded within lease operating expense and income net of expenses for the Burleson water supply and storage assets were recorded within other income.

In accordance with the new revenue standard requirements, the disclosure of the impact of adoption on our consolidated income statement, balance sheet and statement of cash flows was as follows (in thousands):

For the Three Months Ended June 30, 2018

For the Six Months Ended June 30, 2018

For the Three Months Ended September 30, 2018

For the Nine Months Ended September 30, 2018

As Reported

Without ASC 606

Increase/-

As Reported

Without ASC 606

Increase/-

Under ASC 606

Adoption

Decrease

Under ASC 606

Adoption

Decrease

Revenues:

Oil sales

~~207~~236,~~392~~040

~~207~~236,~~421~~056

(2916)

~~389~~625,~~771~~811

~~389~~625,~~800~~856

(2945)

Natural gas sales

89,~~106~~298

910,~~540~~378

(1,~~434~~080)

3545,~~736~~034

3748,~~975~~353

(23,~~239~~319)

NGL sales

913,~~668~~883

1216,~~193~~125

(2,~~525~~242)

1730,~~116~~999

2137,~~601~~727

(46,~~485~~728)

Other Income

~~247~~269

~~304~~269

~~(57)~~—

1,~~547~~816

1,~~738~~625

(191)

Operating expenses:

Lease operating expenses

1214,~~088~~221

1214,~~395~~681

(~~307~~460)

2842,~~515~~736

2843,~~816~~736

(~~301~~1,000)

Gathering, processing and transportation

~~476~~3,225

46,~~022~~246

(3,~~546~~021)

15,~~828~~053

814,~~120~~366

(69,~~292~~313)

Depreciation, depletion and amortization

7074,~~694~~842

7075,~~849~~023

(~~155~~181)

~~130~~205,~~577~~419

~~130~~205,~~866~~889

(~~289~~470)

Other operating (income) expense

~~111~~169

~~282~~1

~~(171)~~168

~~769~~938

~~1,080~~460

~~(311)~~478

Income (loss) before income taxes

~~(23~~30,~~450)~~578

~~(23~~30,~~583)~~422

~~133~~156

(~~177~~146,~~317~~739)

(~~177~~147,~~565~~142)

~~248~~403

Income tax benefit (expense)

9(19,~~356~~055)

9(19,~~383~~022)

(2733)

4728,~~449~~394

4728,~~503~~481

(5487)

Net income (loss)

~~(14~~11,~~094)~~523

~~(14~~11,~~200)~~400

~~106~~123

(~~129~~118,~~868~~345)

(~~130~~118,~~062~~661)

~~194~~316

	At June 30, 2018
	At September 30, 2018
	As Reported		Without ASC 606		Increase/-
	Under ASC 606		Adoption		Decrease
Assets:
Oil and gas properties	$	3,~~007~~271,~~462~~422	$	3,~~012~~277,~~871~~335	$	(5,~~409~~913)
Accumulated depreciation, depletion and amortization		(~~351~~426,~~248~~373)		(~~351~~427,~~907~~213)		~~659~~840
Other non-current assets		1317,~~256~~575		711,~~951~~792		5,~~305~~783
Liabilities:
Deferred tax liabilities		2044,~~612~~141		2043,~~492~~988		~~120~~153
Stockholders' Equity
Accumulated earnings (deficit)		(~~123~~118,~~305~~605)		(~~122~~117,~~629~~741)		(~~676~~864)

	For the Six Months Ended June 30, 2018
	For the Nine Months Ended September 30, 2018
	As Reported		Without ASC 606		Increase/-
	Under ASC 606		Adoption		Decrease
Cash flows from operating activities:
Net income	$	(~~129~~118,~~868~~345)	$	(~~130~~118,~~062~~661)	$	~~194~~316
Depreciation, depletion and amortization		~~130~~205,~~249~~419		~~130~~205,~~538~~889		(~~289~~470)
Deferred income tax expense (benefit)		(5027,~~925~~396)		(5027,~~979~~483)		5487
Consideration paid to customers, net of amortization		(1,~~328~~806)		—		(1,~~328~~806)
Cash flows from investing activities:
Additions to oil and gas properties		(~~578~~824,~~669~~656)		(~~577~~826,~~301~~528)		(1,~~368)~~872

18Other 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.

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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~~ accounted for as business combinations 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,
For the Three Months Ended September 30,					For the Nine Months Ended September 30,
2018		2017		~~2018~~	2018		~~2017~~	2017
$	~~129~~424	$	~~2,199~~998	$	~~488~~$	912	$	~~2,798~~$	3,796

2018 Acquisitions

~~Lee~~Eagle ~~County~~Ford ~~Acquisition~~Acquisitions. OnDuring ~~March~~the 1nine months ended September 30, 2018, we, ~~through~~closed ~~our~~on ~~wholly~~multiple ~~owned~~transactions ~~subsidiary,~~to ~~WHR~~acquire ~~EF, acquired~~ certain acreage and associated production infrom ~~Lee~~third ~~County,~~parties ~~Texas~~ for approximately $1853.62 million ~~from an undisclosed seller~~. ~~This~~ These ~~was~~transactions were accounted for as an asset ~~acquisition~~acquisitions since substantially all the fair value was concentrated in a group of similar assets. As such, an additional $01.40 million of acquisition costs were capitalized as part of ~~the~~these ~~acquisition~~acquisitions. We assigned $1648.92 million to unproved oil and natural gas properties.

Sand Mine Acquisition. On January 4, 2018, Burleson Sand acquired surface and sand rights on approximately 727 acres in Burleson County, Texas for approximately $9.0 million to construct and operate an in-field sand mine. Our capitalized sand assets were $2544.15 million at ~~June~~September 30, 2018. In addition, we have $71.97 million of unapplied construction deposits that were paid during the ~~six~~nine months ended ~~June~~September 30, 2018.

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 Anadarko E&P Onshore LLC (“APC”) and Admiral A Holding L.P., TE Admiral A Holding L.P. and Aurora C-I Holding L.P. (collectively, “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. Consideration consisted of approximately $533.6 million in cash and approximately 5.5 million shares of our common stock. The common stock was issued pursuant to a Stock Issuance Agreement that was executed on May 10, 2017, by and among us and KKR. We finalized our purchase price allocation during the ~~six~~first ~~months~~quarter ~~ended~~of ~~June 30,~~ 2018 and received a $0.6 million cash payment from the Sellers on February 1, 2018.

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The following table summarizes the fair value assessment of the assets acquired and liabilities assumed after customary purchase price adjustments of the Acquisition (in thousands):


Consideration
Cash	$	533,002
Common stock		60,754
Total consideration	$	593,756

Final Purchase Price Allocation
Proved oil and gas properties	$	264,467
Unproved oil and gas properties		333,778
Accounts receivable		60
Asset retirement obligations		(2,500)
Accrued liabilities		(2,049)
Total identifiable net assets	$	593,756

Supplemental Pro forma Information. The following unaudited pro forma combined results of operations are provided for the ~~three~~nine ~~and six~~ months ended ~~June~~September 30, 2017 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 statements of operations and adjusted to include: (i) the revenues and direct operating expenses associated with oil and natural gas properties acquired, (ii) depletion expense applied to the adjusted basis of the properties acquired and (iii) interest expense on additional borrowings necessary to finance 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 Three Months Ended			For Six Months Ended
		For Nine Months Ended
	June 30,			June 30,
		September 30,
	~~2017~~	2017		~~2017~~
Revenues	$	~~93,471~~$	295,160	$	~~172,674~~
Net income (loss)		~~38,747~~	57,221		~~69,777~~
Earnings per share (basic and diluted)	$	~~0.41~~	0.47	$	~~0.74~~

Burleson 2017 Acquisitions. During the ~~six~~nine months ended ~~June~~September 30, 2017, we closed on multiple transactions to acquire oil and natural gas producing and non-producing properties from third parties in Burleson County, Texas for approximately $1719.73 million, of which $1011.6 million was allocated to unproved oil and natural gas properties.

2018 Divestiture

On February 12, 2018, WHR II entered into a Purchase and Sale Agreement with Tanos for the sale of all of our producing and non-producing oil and natural gas properties, including Oakfield, primarily located in Webster, Claiborne, Lincoln, Jackson and Ouachita Parishes, Louisiana (“NLA Assets”). On March 29, 2018, we completed the sale of the NLA Assets for a total net sales price of approximately $206.4 million, including $21.7 million previously received as a deposit, which ~~includes~~included preliminary purchase price adjustments of approximately $0.9 million related to certain assets that were retained pending receipt of a consent to assign certain assets at the initial closing and approximately $9.7 million related to the net cash flows from the effective date to the closing date (the “NLA Divestiture”). We received the necessary consent to assign approximately $0.9 million of NLA Assets and assigned such NLA Assets to Tanos on August 1, 2018. ~~We have recorded this $0.9 million as a component of “Prepaid expenses and other current assets” on our Unaudited Condensed Consolidated Balance Sheets.~~

In addition, WRD could receive contingent payments of up to $35.0 million, of which $0.4 million has been accrued at September 30, 2018, based on the number of wells spud on such properties over the next four years. Our contingent consideration arrangement is not recognized as a derivative under the guidance and, accordingly, we have made an accounting policy election to record the contingent consideration when it is deemed to be realizable. In October 2018, we received $0.4 million in contingent payments from Tanos.

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~~meets~~ Our ~~the~~NLA ~~definition~~Assets were deemed to meet held-for-sale accounting criteria as of aFebruary ~~derivative~~12, ~~but~~2018, ~~qualifies~~at ~~for~~which apoint ~~scope~~we ~~exception~~ceased recording depletion and depreciation. WeBased ~~have~~on ~~made~~the Company’s sale proceeds after customary preliminary purchase price adjustments, we recorded an ~~accounting~~impairment ~~policy~~charge ~~election~~of $214.3 million during the first quarter of 2018 to ~~record~~adjust the ~~contingent~~carrying ~~consideration~~amount ~~when~~of itthe isdisposal ~~deemed~~group (“NLA Disposal Group”) to beits ~~realizable~~estimated fair value less costs to sell. The impairment is reflected on our Unaudited Statements of Condensed Consolidated Operations as “Impairment of NLA Disposal Group.” For the nine months ended September 30, 2018 and 2017, the NLA Disposal Group had pre-tax losses of $202.2 million and $6.8 million, respectively.

~~Our~~During ~~NLA~~the ~~Assets~~nine ~~were~~months ~~deemed~~ended toSeptember ~~meet held-for-sale accounting criteria as of February 12~~30, 2018, ~~at which point~~ we ~~ceased~~recognized ~~recording~~an ~~depletion~~estimated ~~and~~gain ~~depreciation~~of $3.0 ~~Based~~million onwhich ~~the~~we ~~Company’s~~expect ~~sale~~to ~~proceeds~~realize ~~after~~upon ~~customary~~final ~~preliminary~~settlement. We ~~purchase~~have ~~price adjustments, we~~ recorded ana ~~impairment charge of~~ $~~214~~4.38 million ~~during~~final ~~the~~settlement ~~six~~receivable ~~months~~from ~~ended~~Tanos ~~June~~at September 30, 2018, toall ~~adjust the carrying amount~~ of ~~the~~which ~~disposal~~was ~~group~~received ~~(“NLA~~in ~~Disposal~~October ~~Group”) to its estimated fair value less costs to sell~~2018. ~~The~~ We ~~impairment~~provided isTanos ~~reflected~~with ontransitional ~~our~~accounting ~~Unaudited~~and ~~Statements~~land ofservices ~~Condensed~~during ~~Consolidated Operations as “Impairment of NLA Disposal Group.” For~~ the ~~six~~three months ended June 30, 2018 and ~~June~~recognized ~~30,~~$0.9 ~~2017~~million ~~the~~of ~~NLA~~fees ~~Disposal~~as ~~Group had~~ a ~~$201.8~~reduction ~~million~~to ~~pre-tax~~our ~~loss~~general and ~~$0.6~~administrative ~~million pre-tax profit, respectively~~expenses.

During the three and six months ended June 30, 2018, we recognized an estimated gain of $3.2 million which we expect to realize upon final settlement. We have recorded a $3.5 million final settlement receivable from Tanos at June 30, 2018. We recorded a $4.3 million receivable from Tanos related to the transition services agreement, which was collected on July 20, 2018. We provided Tanos with transitional accounting and land services during the three months ended June 30, 2018 and recognized $1.0 million of fees as a reduction to our general and administrative expenses.

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~~September 30, 2018 and December 31, 2017. 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~~September 30, 2018 and December 31, 2017 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.

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The following table presents the derivative assets and liabilities that are measured at fair value on a recurring basis at ~~June~~September 30, 2018 and December 31, 2017 for each of the fair value hierarchy levels:

Fair Value Measurements at June 30, 2018 Using

Fair Value Measurements at September 30, 2018 Using

Quoted Pricesin ActiveMarket(Level 1)

SignificantOtherObservableInputs(Level 2)

SignificantUnobservableInputs(Level 3)

Fair Value

(In thousands)

Assets:

Commodity derivatives

—

~~491~~574

—

~~491~~574

Liabilities:

Commodity derivatives

—

~~169~~213,~~072~~275

—

~~169~~213,~~072~~275


	Fair Value Measurements at December 31, 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	$	—	$	2,422	$	—	$	2,422
Liabilities:
Commodity derivatives	$	—	$	76,750	$	—	$	76,750

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 initial fair value of asset retirement obligations (“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 initial 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 to proved oil and natural gas properties during the three and six months ended June 30, 2018 and 2017.~~

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·respective ~~Unproved~~ oil and natural gas properties ~~are reviewed for impairment based on passage of time or geologic factors~~. ~~Information~~We ~~such~~did asnot ~~remaining~~record ~~lease~~impairments ~~terms, drilling results, reservoir performance, seismic interpretation or future plans~~ to ~~develop~~proved ~~acreage~~oil isand ~~also~~natural ~~considered.~~gas ~~When unproved~~ properties ~~are~~during ~~deemed to be impaired,~~ the ~~expense is recorded as a component of exploration expenses. For the~~ three and ~~six~~nine months ended ~~June~~September 30, 2018, ~~we recorded $4.4 million~~ and ~~$5.9 million of impairments of unproved properties, respectively. We recorded $10.0 million and $10.7 million of impairments of unproved properties for the three and six months ended June 30,~~ 2017~~, respectively~~.

· WeUnproved ~~recorded~~oil anand natural gas properties are reviewed for impairment ~~associated~~based ~~with~~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 ~~NLA~~expense ~~Assets~~is ~~during~~recorded as a component of exploration expenses. For the ~~six~~three and nine months ended ~~June~~September 30, 2018, we recorded $2.4 ~~See~~million ~~Note~~and $8.2 million of impairments of unproved properties, respectively. We recorded $3~~—“Acquisitions~~.2 million and ~~Divestitures—2018~~$13.9 ~~Divestiture”~~million of impairments of unproved properties for ~~additional~~the ~~information~~three and nine months ended September 30, 2017, respectively.

We recorded an impairment associated with the NLA Assets during the first quarter of 2018. See Note 3—“Acquisitions and Divestitures—2018 Divestiture” for additional information.

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, basis swaps, and deferred purchased puts to accomplish our hedging strategy. Through our basis swap instruments, we receive a fixed price differential and pay a variable price differential to the contract counterparty. 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 paid or received on settled derivative positions during the ~~six~~nine months ended ~~June~~September 30, 2018 and 2017 is net of deferred premiums of $46.21 million and $02.61 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, all of which are also lenders under our credit agreement, 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~~September 30, 2018 we had net derivative liabilities of $~~168~~212.6 7 million and we did not have a right of offset as we were in a net liability position with all of our counterparties.

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

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The following derivative contracts were in place at ~~June~~September 30, 2018:

	Remainder 2018		2019		2020
Crude Oil Derivative Contracts:
Fixed price swap contracts:
Volume (Bbls)		21,~~958~~398,~~527~~947		6,652,369		4,511,681
Weighted-average fixed price	$	52.3633	$	54.45	$	53.49
Put options:
Volume (Bbls)		1989,~~656,378~~379		1,749,757		—
Weighted-average floor price	$	5049.0455	$	53.83	$	—
Weighted-average put premium	$	(3.6469)	$	(5.43)	$	—
LLS basis swaps:
Volume (Bbls)		31,~~339~~711,~~230~~789		—		—
Spread-WTI	$	3.02	$	—	$	—
Natural Gas Derivative Contracts:
Fixed price swap contracts:
Volume (MMBtu)		42,~~723~~184,~~634~~376		6,425,146		4,846,020
Weighted-average fixed price	$	2.79	$	2.79	$	2.76

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~~September 30, 2018 and December 31, 2017 (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	~~Asset Derivatives~~					Liability Derivatives	~~Liability Derivatives~~
Type		Balance Sheet Location		June 30, 2018			December 31, 2017			June 30, 2018			December 31, 2017
			September 30,			December 31,			September 30,			December 31,
Commodity contracts		Short-term derivative instruments		$	—		$	2,336		$	107,206		$	58,074
Type	Balance Sheet Location		2018			2017			2018			2017
Netting arrangements		Short-term derivative instruments			—			—			—			—
Commodity contracts	Short-term derivative instruments		$	—		$	2,336		$	131,539		$	58,074
Net recorded fair value				$	—		$	2,336		$	107,206		$	58,074
Netting arrangements	Short-term derivative instruments			—			—			—			—
Commodity contacts		Long-term derivative instruments		$	491		$	86		$	61,866		$	18,676
Net recorded fair value			$	—		$	2,336		$	131,539		$	58,074
Netting arrangements		Long-term derivative instruments			—			—			—			—
Commodity contacts	Long-term derivative instruments		$	574		$	86		$	81,736		$	18,676
Net recorded fair value				$	491		$	86		$	61,866		$	18,676
Netting arrangements	Long-term derivative instruments			—			—			—			—
Net recorded fair value			$	574		$	86		$	81,736		$	18,676

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 Operations. The following table details the gains and losses related to derivative instruments for the three and ~~six~~nine months ending ~~June~~September 30, 2018 and 2017 (in thousands):

	Statements of	For the Three Months Ended ~~June~~September 30,				For the ~~Six~~Nine Months Ended ~~June~~September 30,
	Operations Location	2018		2017		2018		2017
Commodity derivative contracts	Gain (loss) on derivative instruments	$	(~~110~~76,~~805~~358)	$	46(40,~~116~~288)	$	(~~151~~227,~~175~~533)	$	7737,~~407~~119

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 6. Accounts Receivable

Accounts receivable consist of the following (in thousands):

	June 30,		December 31,
	September 30,		December 31,
	2018		2017
Oil, gas and NGL sales	$	7783,~~866~~674	$	67,584
Joint interest billings		18,~~595~~129		9,467
Severance tax		~~987~~304		171
North Louisiana Settlement receivable		—		5,955
Environmental remediation		1,~~258~~511		—
Other current receivables		2,~~627~~672		1,026
NLA Divestiture and transition		7,884		—
NLA Divestiture		5,264		—
Allowance for doubtful accounts		(200)		(100)
Total	$	~~109~~111,~~017~~354	$	84,103

The following table presents our allowance for doubtful accounts activity for the ~~periods~~nine ~~indicated~~months ended September 30, 2018 (in thousands):

	June 30,		December 31,
Balance at beginning of period	$	100
	2018		2017
Charged to costs and expenses		100
Balance at beginning of period	$	100	$	100
Balance at end of period	$	200
Charged to costs and expenses		100		—
Balance at end of period	$	200	$	100

Note 7. Accrued Liabilities

Accrued liabilities consist of the following (in thousands):

	June 30,		December 31,
	September 30,		December 31,
	2018		2017
Capital expenditures	$	~~136~~121,~~615~~123	$	162,260
Preferred stock cash dividends		4,479		—
Lease operating expense		45,~~708~~410		5,796
General and administrative		69,~~243~~150		1,642
Severance and ad valorem taxes		79,~~267~~265		3,463
Interest expense		208,~~122~~190		17,177
Derivative payable		1011,~~804~~919		5,281
Environmental liability		297		—
Income taxes		—		991
Income taxes		2,166		991
Other accrued liabilities		129		3,342
Other accrued liabilities		851		3,342
Total	$	169,665	$	199,952
Total	$	193,552	$	199,952

25Note 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 nine months ended September 30, 2018 (in thousands):


Asset retirement obligations at beginning of period	$	14,557
Accretion expense		448
Liabilities incurred		611
Disposition of wells and gathering system		(7,627)
Asset retirement obligations at end of period		7,989
Less: current portion		90
Asset retirement obligations – long-term	$	7,899

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Note 8. Asset Retirement Obligations

Asset retirement obligations at beginning of period	$	14,557
Accretion expense		328
Liabilities incurred		350
Disposition of wells and gathering system		(7,627)
Asset retirement obligations at end of period		7,608
Less: current portion		90
Asset retirement obligations – long-term	$	7,518

Note 9. Long Term Debt

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

	June 30,		December 31,
	September 30,		December 31,
Debt Obligation	2018		2017
WRD revolving credit facility	$	~~249~~399,000	$	286,353
2025 Senior Notes (as defined below) (1)		700,000		500,000
Unamortized net discounts - 2025 Senior Notes		(~~809~~805)		(4,914)
Unamortized debt issuance costs - 2025 Senior Notes		(12,~~582~~198)		(10,843)
Total long-term debt	$	~~935~~1,~~609~~085,997	$	770,596

(1) The estimated fair value of this fixed-rate debt was $~~713~~722.28 million and $511.3 million at ~~June~~September 30, 2018 and December 31, 2017, respectively. The estimated fair values are based on quoted market prices and are classified as Level 2 within the fair value hierarchy.

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,
	September 30,
Credit Facility	2018
WRD revolving credit facility	$	1,050,000

Letter of Credit

See “Note 1—Organization and Basis of Presentation—Investment in Unconsolidated Affiliate” for information related to our $47.5 million letter of credit outstanding.

Amendment to Credit Agreement

On March 23, 2018, the Company, each of the Company’s wholly owned subsidiaries (each as a guarantor), the Administrative Agent, and the lenders party thereto entered into a Fourth Amendment (the “Fourth 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 Fourth Amendment, among other things, modified the Credit Agreement to increase the borrowing base from $875.0 million to $1.05 billion.

~~2025~~Subsequent ~~Senior~~Event. ~~Notes~~On October 15, 2018, the Company, each of the Company’s wholly owned subsidiaries (each as a guarantor), the Administrative Agent, and the lenders party thereto entered into a Fifth Amendment (the “Fifth Amendment”) to the Credit Agreement. The Fifth Amendment, among other things, (i) modified the Credit Agreement to increase the borrowing base from $1.05 billion to $1.30 billion and (ii) decreased the pricing grid by 25 basis points across the grid as seen in the following table:


Borrowing Base Utilization	LIBOR Margin	Base Rate Margin	Commitment Fee
>= 90%	250.0 bps	150.0 bps	50.0 bps
>= 75%; < 90%	225.0 bps	125.0 bps	50.0 bps
>=50%; < 75%	200.0 bps	100.0 bps	50.0 bps
>= 25%; < 50%	175.0 bps	75.0 bps	37.5 bps
< 25%	150.0 bps	50.0 bps	37.5 bps

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~~in net proceeds of approximately $144.7 million. Additionally, on April 20, 2018, we completed a private placement of $200.0 million aggregate principal amount of our~~ 2025 Senior Notes ~~(the “April Notes”) issued at 102.00% of par, which resulted in net proceeds of approximately $201.0 million.~~

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. On September 19, 2017, we completed a private placement of $150.0 million aggregate principal amount of the 2025 Senior Notes issued at 98.26% of par, which resulted in net proceeds of approximately $144.7 million. Additionally, on April 20, 2018, we completed a private placement of $200.0 million aggregate principal amount of our 2025 Senior Notes (the “April Notes”) issued at 102.00% of par, which resulted in net proceeds of approximately $201.0 million.

The notes issued in September 2017 and April 2018 are treated as a single class of debt securities with the 2025 Senior Notes issued in February 2017. 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). We have no material assets or operations that are independent of our existing subsidiaries. There are no restrictions on the ability of the Company to obtain funds from its subsidiaries through dividends or loans. The net proceeds from each of the February 2017, September 2017 and April 2018 offerings of the 2025 Senior Notes were used to repay borrowings outstanding under our revolving credit facility and for general corporate purposes.

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

InPursuant ~~connection~~to ~~with the issuance and sale of the April Notes, the Company and the Guarantors entered into~~ a registration rights agreement ~~(the~~entered ~~“Registration~~into ~~Rights~~in ~~Agreement”)~~connection with the ~~Initial~~issuance ~~Purchaser,~~of ~~dated~~the April 20Notes, ~~2018.~~we ~~Pursuant to the Registration Rights Agreement, the Company and the Guarantors~~ agreed to file a registration statement with the ~~Securities~~SEC ~~and Exchange Commission~~ so that holders of the April Notes ~~can~~could exchange the unregistered April Notes for registered notes that have substantially identical terms ~~as the April Notes~~. In addition, ~~the~~we ~~Company and the Guarantors have~~ agreed to exchange the unregistered guarantees related to the April Notes for registered guarantees having substantially ~~the~~identical ~~same~~ terms. asOn September 24, 2018, all of the ~~original~~then-outstanding ~~guarantees.~~2025 ~~The~~Senior ~~Company~~Notes ~~and~~were ~~the~~exchanged ~~Guarantors~~for ~~will~~an ~~use~~equal ~~commercially~~principal ~~reasonable~~amount ~~efforts~~of toregistered ~~cause~~6.875% ~~the~~senior ~~exchange~~notes due 2025 pursuant to bean ~~consummated~~effective byregistration ~~April~~statement ~~20,~~on ~~2019~~Form S-4.

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.

Weighted-Average Interest Rates

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

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
Credit Facility	2018		2017		2018		2017
WRD revolving credit facility	34.8412	%	3.4071	%	34.9702	%	3.4863	%

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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,
	September 30,		December 31,
	2018		2017
WRD revolving credit facility
Current	$	1,~~462~~486	$	1,203
Long-term		3,~~618~~301		3,573
6.875% senior unsecured notes, due February 2025		12,~~582~~198		10,843
Total	$	1716,~~662~~985	$	15,619

Note 10. Preferred Stock

The following is a summary of the changes in our preferred stock for the ~~three~~nine months ended ~~June~~September 30, 2018:

	Series A Perpetual
	Convertible Preferred
	Stock
	(in thousands)
Balance at December 31, 2017	$	445,483
Accrual of paid-in-kind dividend		2,243
Beneficial conversion feature ("BCF")		(1,872)
Amortization of BCF		1,872
Balance at June 30, 2018	$	447,726
Balance at September 30, 2018	$	447,726

Preferred Stock Dividend

The terms of our outstanding preferred stock require us to pay a quarterly dividend. Because we are legally obligated to pay cumulative dividends, whether or not declared, we accrue the dividends as earned. The declaration of a dividend after the balance sheet date, but before the financial statements are issued is considered to be a recognizable subsequent event that provides additional evidence about conditions that existed at the date of the balance sheet. A recognized subsequent event is to be recognized in the financial statements as if they occurred before the balance sheet date. Declaration of paid-in-kind dividends subsequent to the balance sheet date are recorded as an increase to the carrying amount of the preferred stock. Declaration of a cash dividends subsequent to the balance sheet date are recorded as an accrued liability.

On January 31, 2018, an aggregate quarterly dividend of $6.656 million on our outstanding shares of preferred stock was paid by an automatic increase to the Accreted Value (as defined in the Certificate of Designations 6.00% Series A Perpetual Convertible Preferred Stock) of each such share of preferred stock as of the date of issuance. The declared dividend was for the period from November 1, 2017 to January 31, 2018 and was paid to holders of record on January 15, 2018. In connection with this paid-in-kind dividend, we recognized a $1.9 million BCF that ~~will~~was befully amortized ~~over~~as ~~the~~of ~~earliest~~June ~~preferred~~30, ~~stock~~2018. The ~~conversion~~table ~~period~~below assummarizes ~~additional~~the quarterly cash dividends~~. At~~ ~~June~~paid ~~30,~~to ~~2018,~~holders weof ~~have~~record ~~amortized~~at ~~$1.9~~the ~~million~~dates indicated of ~~the~~our ~~BCF.~~preferred stock:

On April 30, 2018, an aggregate quarterly cash dividend of $6.756 million was paid to holders of record as of April 15, 2018 for the period from February 1, 2018 to April 30, 2018.


	Period Covered
Date of Record	From	To	Cash Dividends Paid		Payment Date
			(in millions)
April 15, 2018	February 1, 2018	April 30, 2018	$	6.756	April 30, 2018
July 15, 2018	May 1, 2018	July 31, 2018		6.756	July 31, 2018

Subsequent Event. On ~~July~~October 31, 2018, an aggregate quarterly cash dividend of $6.756 million was paid to holders of record as of ~~July~~October 15, 2018 for the period from ~~May~~August 1, 2018 to ~~July~~October 31, 2018.

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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~~nine months ended ~~June~~September 30, 2018:

Balance, December 31, 2017		101,137,277
Restricted common shares issued		1,~~071~~076,~~565~~165
Restricted common shares forfeited		(4860,~~660~~911)
Repurchase of vested restricted shares (1)		(~~152~~155,~~666~~777)
Balance, June 30, 2018		102,007,516
Balance, September 30, 2018		101,996,754

(1) Restricted common shares are generally net-settled by shareholders to cover the required withholding tax upon vesting. Shareholders surrendered shares with value equivalent to the employee’s minimum statutory obligation for the applicable income and other employment taxes. Total payments remitted for employee tax obligations to the appropriate taxing authorities were approximately $4.12 million for the ~~six~~nine months ended ~~June~~September 30, 2018. The net-settlements had the effect of share repurchases by the Company as they reduced the number of shares that would have otherwise been outstanding due to the vesting and did not represent an expense to the Company.

See “Note 13—Long Term Incentive Plans” for additional information regarding the shares of restricted common stock that were granted during the ~~six~~nine months ended ~~June~~September 30, 2018. Restricted shares of common stock are considered issued and outstanding on the grant date of the restricted stock award.

Note 12. Earnings Per Share

The following sets forth the calculation of earnings (loss) per share, or EPS, for the three and ~~six~~nine months ended ~~June~~September 30, 2018 and 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 Months Ended June 30,				For the Six Months Ended June 30,
	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2018		2017		2018		2017
Numerator:
Net income (loss) available to WRD	$	~~(14~~11,~~094)~~523	$	26(10,~~366~~804)	$	(~~129~~118,~~868~~345)	$	4635,~~618~~814
Less: Preferred stock dividends		76,~~961~~756		736,450		1522,~~350~~106		736,523
Less: Undistributed earnings allocated to participating securities		—1,233		~~387~~—		—		~~434~~3,234
Net income (loss) available to common stockholders	$	~~(22~~3,~~055)~~534	$	25(17,~~906~~254)	$	(~~145~~140,~~218~~451)	$	4626,~~111~~057
Denominator:
Weighted-average common shares outstanding (in thousands) (1)		99,411		93,685		99,328		93,452
Weighted-average common shares outstanding (in thousands) (1) (2)		99,639		99,142		99,433		95,369
Basic EPS	$	(0.~~22)~~04	$	(0.2817)	$	(1.4641)	$	0.4927
Diluted EPS (1)	$	(0.22)	$	0.28	$	(1.46)	$	0.49
Diluted EPS (1) (2)	$	0.04	$	(0.17)	$	(1.41)	$	0.27

(1) The Company used the two-class method for both basic and diluted EPS. Restricted shares were excluded from the calculation of diluted EPS ~~under the treasury stock method~~ due to their antidilutive effect as we were in a loss position for the ~~three~~nine ~~and six~~ months ended ~~June~~September 30, 2018. For the three ~~and six~~ months ended ~~June~~September 30, ~~2017~~2018, ~~455~~546 incremental restricted shares ~~and 308 incremental restricted shares~~ were excluded in the calculation of diluted EPS ~~due to their antidilutive effect~~ under the treasury stock method. For the three and ~~six~~nine months ended ~~June~~September 30, 2018, 32,402 shares and 32,~~323~~349 shares, were excluded in the calculation of diluted EPS due to their antidilutive effect under the if-converted method. ~~For 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.~~

29 (2) The Company used the two-class method for both basic and diluted EPS. For the three months ended September 30, 2017, restricted shares were excluded in the calculation of diluted EPS due to their antidilutive effect as we were in a loss position. For the nine months ended September 30, 2017, 481 incremental restricted shares were excluded in the calculation of diluted EPS due to their antidilutive effect under the treasury stock method. For the three and nine months ended September 30, 2017, 10,696 and 31,400 shares, respectively, were excluded in the calculation of diluted EPS due to their antidilutive effect under the if-converted method.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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:

		Weighted-Average
	Number of	Grant Date Fair
	Shares	Value per Share (1)
Restricted common stock outstanding at December 31, 2017	1,897,790	$	13.95
Granted (2)	1,~~071~~076,~~565~~165	$	25.5857
Forfeited	(4860,~~660~~911)	$	1516.2903
Vested	(~~548~~561,~~669~~581)	$	13.9588
Restricted common stock outstanding at June 30, 2018	2,372,026	$	19.18
Restricted common stock outstanding at September 30, 2018	2,351,463	$	19.23

(1)

Determined by dividing the aggregate grant date fair value of stock subject to granted awards by the number of awards.

(2) The aggregate grant date fair value of restricted common stock awards granted in 2018 was $27.45 million based on the grant date market price of ranging from $18.14 to $27.07 per share.

For the three months ended ~~June~~September 30, 2018 and 2017, we recorded $35.80 million and $12.34 million of recognized compensation expense, respectively, associated with these awards. For the ~~six~~nine months ended ~~June~~September 30, 2018 and 2017, we recorded $712.0 million and $14.82 million of recognized compensation expense, respectively, associated with these awards. Unrecognized compensation cost associated with the restricted common stock awards was an aggregate of $4136.43 million at ~~June~~September 30, 2018. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 2.392 years.

Note 14. Incentive Units

Certain officers and employees have been granted awards of incentive units in WildHorse Investment Holdings and WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings (the “LLCs”). Any future compensation expense recognized will be a non-cash charge, with the settlement obligation resting with WildHorse Investment Holdings and the LLCs. Accordingly, no payments will ever be made by us related to these incentive units; however, non-cash compensation expense (income) will be allocated to us in future periods offset by deemed capital contributions (distributions). As such, these awards are not dilutive to our stockholders. Compensation cost is recognized only if the performance condition is probable of being satisfied at each reporting date or as a result of an actual distribution. Compensation cost related to an actual distribution by Esquisto Holdings to incentive unitholders of 500,932 shares of our common stock on May 14, 2018 resulted in non-cash compensation expense of $13.8 million offset by a deemed capital contribution. Compensation costs associated with satisfying the remaining performance conditions were not deemed probable at ~~June~~September 30, 2018.

Under the respective limited liability company agreements of WildHorse Investment Holdings and the LLCs, WildHorse Investment Holdings and the LLCs are obligated to provide to the holders of incentive units, including named executive officers, a portion of their respective distributions, but only after a substantial priority distribution, the amount of which is specified in each respective limited liability company agreement and is referred to as a "distribution threshold," has first been made to the holders of capital interests in WildHorse Investment Holdings and the LLCs (who are the investors in these entities). The distribution threshold differs with regard to each class (referred to as a "tier") of incentive units in WildHorse Investment Holdings (which has five tiers) and the LLCs (each of which has two tiers). As the only assets of the LLCs are shares of our common stock, any distributions to the named executive officers holding incentive units in the LLCs would be dependent on distributions of cash proceeds of sales of shares of our common stock or distribution of our common stock to holders of capital interests sufficient in amount to exceed the applicable distribution threshold, thereby enabling the commencement of participation by holders of incentive units in additional distributions.

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All incentive units not vested are forfeited upon a termination of employment. All incentive units will be forfeited if a holder resigns whether the incentive units are vested or not. If the payouts have not yet occurred, then all incentive units, whether or not vested, will be forfeited automatically (unless extended).

Upon and subject to the consummation of our merger with Chesapeake, all unvested incentive units will become fully vested in accordance with their terms and will remain outstanding following the effective time of such merger. See “Note 19—Subsequent Events” for information regarding our merger with Chesapeake.

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~~September 30, ~~2018 and~~ 2017, we received $0.5 million, $1from Genesis.2 We ~~million~~did not have any purchases from Genesis for the three months ended September 30, 2018. We received $01.62 million and $1.59 million for the nine months ended September 30, 2018 and 2017, respectively, from Genesis.

Ms. Stephanie Hildebrandt has served as a member of our board of directors since December 2017. Ms. Hildebrandt has served as Senior Vice President, General Counsel, and Secretary of Archrock Inc., (“Archrock”) since August 2017. Archrock is a provider of compression services. ~~During~~We ~~the three and six months ended June 30, 2018, we~~ had ~~disbursement~~disbursements of ~~less than~~ $0.1 million ~~and~~to ~~$0.1~~Archrock ~~million,~~for ~~respectively,~~the tonine ~~Archrock~~months ended September 30, 2018.

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, which 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. An affiliate of the Carlyle Group, L.P. purchased 435,000 shares of our preferred stock on June 30, 2017.

NGP ECM. During the three and ~~six~~nine months ended ~~June~~September 30, 2017, we had net disbursements of less than $0.1 million and $0.1 million, respectively, related to director and advisory fees and reimbursement of initial public offering costs. We did not have any related party payments or receipts due to or from NGP ECM for the three and ~~six~~nine months ended ~~June~~September 30, 2018.

Cretic Energy Services, LLC. We ~~recorded~~During ~~payments of $0.1 million for both~~ the three and ~~six~~nine months ended ~~June~~September 30, 2017, we had disbursements of $0.1 million and $0.2 million, respectively, to Cretic Energy Services, LLC, a NGP affiliated company, for services related to our drilling and completion activities. We did not have any related party payments to Cretic Energy Services, LLC for the three and ~~six~~nine months ended ~~June~~September 30, 2018.

CH4 Energy. CH4 Energy entities are NGP affiliated companies and Mr. Brannon, a former member of our board of directors, is President of these entities. During the three and ~~six~~nine months ended ~~June~~September 30, 2018 we had disbursements of less than $0.1 million and $0.12 million, respectively, to certain CH4 Energy entities for office rental and parking payments. During the three and ~~six~~nine months ended ~~June~~September 30, 2017 we had disbursements of ~~less than~~ $0.1 million and $0.45 million to certain CH4 Energy entities, respectively. For the ~~six~~nine months ended ~~June~~September 30, 2017, $0.3 million was a reimbursement of landman services and expenses incurred in 2016 that CH4 Energy entities had paid on our behalf and $0.12 million was related to office rental and parking payments.

~~Related Party Agreements~~33

Stockholders’ Agreement

A discussion of this agreement is included in our 2017 Form 10-K.

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Related Party Agreements

Stockholders’ Agreement

A discussion of this agreement is included in our 2017 Form 10-K.

Registration Rights Agreement

A discussion of this agreement is included in our 2017 Form 10-K.

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 exchange for such services, we agreed to pay a monthly management fee to the Service Providers. NGP and certain former management members of Esquisto own the Service Providers. The transition service agreement was terminated on March 31, 2017 and $0.1 million was paid to the Service Providers during the ~~six~~nine months ended ~~June~~September 30, 2017.

Note 16. Segment Disclosures

Our chief executive officer has been identified as our chief operating decision maker (“CODM”). As of ~~June~~September 30, 2018, we identified one operating segment and one reportable segment—the Eagle Ford—that is engaged in the acquisition, exploitation, development and production of oil, natural gas and NGL resources in the United States. Historically, we had two operating segments – the Eagle Ford and North Louisiana – that were aggregated into one reportable segment. On March 29, 2018 we closed the NLA Divestiture, which involved substantially all of the assets previously included in our North Louisiana operating segment. See Note 3 for additional information related to the NLA Divestiture. 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, a non-GAAP financial measure, 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):~~34

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2018		2017		2018		2017
Adjusted EBITDAX reconciliation to net (loss) income:
Net income (loss)	$	(14,094)	$	26,366	$	(129,868)	$	46,618
Interest expense, net		14,002		6,633		27,309		12,204
Income tax (benefit) expense		(9,356)		15,193		(47,449)		26,893
Depreciation, depletion and amortization		70,694		33,229		130,577		59,672
Exploration expense		4,369		11,504		6,077		13,119
Impairment of NLA Disposal Group		—		—		214,274		—
(Gain) loss on derivative instruments		110,805		(46,116)		151,175		(77,407)
Cash settlements received (paid) on derivative instruments		(29,508)		2,076		(50,054)		1,093
Stock-based compensation		3,835		1,308		6,991		1,803
Incentive unit compensation		13,776		—		13,776		—
Acquisition related costs		129		2,199		488		2,798
(Gain) loss on sale of properties		(3,167)		—		(3,167)		—
Debt extinguishment costs		—		—		—		(11)
Initial public offering costs		—		—		—		182
Total Adjusted EBITDAX	$	161,485	$	52,392	$	320,129	$	86,964

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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


	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2018		2017		2018		2017
Adjusted EBITDAX reconciliation to net (loss) income:
Net income (loss)	$	11,523	$	(10,804)	$	(118,345)	$	35,814
Interest expense, net		15,718		8,749		43,027		20,953
Income tax (benefit) expense		19,055		(5,646)		(28,394)		21,247
Depreciation, depletion and amortization		74,842		51,843		205,419		111,515
Exploration expense		13,814		4,749		19,891		17,868
Impairment of NLA Disposal Group		—		—		214,274		—
(Gain) loss on derivative instruments		76,358		40,288		227,533		(37,119)
Cash settlements received (paid) on derivative instruments		(31,123)		5,802		(81,177)		6,895
Stock-based compensation		4,997		2,414		11,988		4,217
Incentive unit compensation		—		—		13,776		—
Acquisition related costs		424		998		912		3,796
(Gain) loss on sale of properties		217		—		(2,950)		—
Debt extinguishment costs		—		—		—		(11)
Initial public offering costs		—		—		—		182
Total Adjusted EBITDAX	$	185,825	$	98,393	$	505,954	$	185,357

Note 17. Income Taxes

The Company is a corporation subject to federal and state income taxes. The Company records its tax provision in interim periods using the estimated annual effective tax rate. Discrete items are excluded from the Company’s estimated annual effective tax rate and income tax effects associated with discrete items are recognized in the period in which they occur. We have a $2.3 million federal income tax refund at September 30, 2018 recorded as a component of “Prepaid expenses and other current assets” on our balance sheet.

The Company recorded an income tax ~~benefit~~expense of $919.41 million and an income tax ~~expense~~benefit of $155.26 million for the three months ended ~~June~~September 30, 2018 and 2017, respectively. The change is primarily due to the pretax ~~loss~~income in 2018 as compared to the pretax ~~income~~loss in 2017. The effective tax rate for the three months ended ~~June~~September 30, 2018 and 2017 was 3962.93% and 3634.63%, respectively. The increase in the effective tax rate was primarily due to state income taxes ~~and incentive unit compensation~~, offset by a reduction in the federal corporate income tax rate from 35% to 21% as a result of tax legislation enacted in December 2017~~, and an excess tax benefit related to stock-based compensation recorded in the three months ended June 30, 2018~~. The effective tax rate differed from the statutory federal income tax rate of 21% for 2018, primarily due to ~~incentive unit compensation, stock-based compensation and~~ the impact of the state income tax provision related to a change in the estimated annual effective tax rate. The effective tax rate differed from the statutory federal income tax rate of 35% for 2017, primarily due to the impact of the state income tax provision.

The Company recorded an income tax benefit of $4728.54 million and an income tax expense of $2621.92 million for the ~~six~~nine months ended ~~June~~September 30, 2018 and 2017, respectively. The change is primarily due to the pretax loss in 2018 as compared to the pretax income in 2017. The effective tax rate for the ~~six~~nine months ended ~~June~~September 30, 2018 and 2017 was 2619.83% and 3637.62%, respectively. The decrease in the effective tax rate was primarily due to incentive unit compensation, the impact of the state income tax provision, and a reduction in the federal corporate income tax rate from 35% to 21% as a result of tax legislation enacted in December 2017, partially offset by an excess tax benefit associated with stock-based compensation, and state tax adjustments associated with the NLA Divestiture~~, and the impact of the state income tax provision~~. The effective tax rate differed from the statutory federal income tax rate of 21% for 2018, primarily due to incentive unit compensation, stock-based compensation, state tax adjustments associated with the NLA Divestiture, and the state income tax provision. The effective tax rate differed from the statutory federal income tax rate of 35% for 2017, primarily due to the impact of the state income tax provision.

~~The Company reported no liability for unrecognized tax benefits as of June 30, 2018 and expects no significant change to the unrecognized tax benefits in the next twelve months.~~35

Note 18. Commitments and Contingencies

Lease Obligations

We executed a new lease for corporate office space in June 2018 that has escalating payments starting, if certain conditions are satisfied, on October 1, 2018 through December 31, 2026. Assuming certain conditions are satisfied, the lease for our current corporate office will terminate on September 30, 2018. The table below reflects our estimated minimum commitments as of June 30, 2018 related to our corporate office leases (in thousands):

	Remaining 2018			2019			2020			2021			2022			Thereafter
Office Lease	$	801		$	1,958		$	1,994		$	2,036		$	2,066		$	8,621

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, 2018 and December 31, 2017. 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.

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~~Klein~~The v.Company ~~Graham,~~reported etno ~~al.:~~liability Onfor ~~August~~unrecognized 2,tax ~~2018,~~benefits ~~James~~as ~~M. Klein filed a derivative action in the Delaware Court~~ of ~~Chancery~~September ~~against seven of the Company’s directors and one of its former directors (the “Director Defendants”)~~30, ~~NGP~~2018 ~~Energy Capital Management, LLC, CP VI Eagle Holdings, L.P. (the “Carlyle Investor”),~~ and ~~(as~~expects ano ~~nominal~~significant ~~defendant~~change ~~only) the Company. The complaint asserts claims relating~~ to the ~~Company’s~~unrecognized ~~entry~~tax ~~into~~benefits ain ~~Preferred Stock Purchase Agreement with~~ the ~~Carlyle~~next ~~Investor,~~twelve ~~dated May 10, 2017~~months. ~~The lawsuit seeks monetary damages and attorneys’ fees. The Company believes the claims are entirely without merit and intends to vigorously defend against them.~~

~~From~~Note ~~time to time, we could be liable for environmental claims arising in the ordinary course of business~~18. We ~~recorded~~Commitments ~~$0.3 million of environmental obligations at June 30, 2018~~ and ~~did not record any environmental obligations at December 31, 2017.~~Contingencies

Lease Obligations

We executed two office leases during the nine months ended September 30, 2018. In June 2018, we executed a new lease for corporate office space that has escalating payments. The estimated commencement date is January 1, 2019 and the lease terminates on December 31, 2026. The lease for our current corporate office is expected to terminate on December 31, 2018. In August 2018, we executed a new lease for our Fort Worth office with a start date of October 1, 2018 and terminating on September 30, 2021, with a penalty-free early termination clause after two years.

The table below reflects our estimated minimum commitments as of September 30, 2018 related to our office leases (in thousands):


	Remaining 2018		2019		2020		2021		2022		Thereafter
Office Leases	$	390	$	2,249	$	2,285	$	2,254	$	2,066	$	8,621

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 September 30, 2018 and December 31, 2017. 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.

Klein v. Graham, et al.: On August 2, 2018, James M. Klein filed a derivative action in the Delaware Court of Chancery against seven of the Company’s directors and one of its former directors (the “Director Defendants”), NGP Energy Capital Management, LLC, CP VI Eagle Holdings, L.P. (the “Carlyle Investor”), and (as a nominal defendant only) the Company. The complaint asserts claims relating to the Company’s entry into a Preferred Stock Purchase Agreement with the Carlyle Investor, dated May 10, 2017. The lawsuit seeks monetary damages and attorneys’ fees. The Company believes the claims are entirely without merit and intends to vigorously defend against them. On October 2, 2018, a stipulation of dismissal without prejudice was granted as it relates to Messrs. Clarkson and Sims.

From time to time, we could be liable for environmental claims arising in the ordinary course of business. We did not record environmental obligations at September 30, 2018 and at December 31, 2017.

Firm Gas Transportation Service Agreement

The Company had a firm gas transportation service agreement with Regency Intrastate Gas LLC as discussed in our 2017 Form 10-K. In connection with the NLA Divestiture, we transferred this agreement to Tanos.

Dedicated Fracturing Fleet Services Agreements

A discussion of these agreements are included in our 2017 Form 10-K.

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 $0.5 million and $0.4 million during the six months ended June 30, 2018 and 2017, respectively.

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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 $0.5 million and $0.4 million during the nine months ended September 30, 2018 and 2017, respectively.

Note 19. Subsequent Events

Proposed Merger with Chesapeake Energy Corporation

On October 30, 2018, we jointly announced with Chesapeake that we entered into a definitive agreement to merge with Chesapeake, an independent exploration and production company engaged in the acquisition, exploration and development of properties in the Eagle Ford Shale in South Texas, the stacked pay in the Powder River Basin in Wyoming, the Anadarko Basin in northwestern Oklahoma, the Marcellus Shale in the northern Appalachian Basin in Pennsylvania and the Haynesville/Bossier Shales in northwestern Louisiana and East Texas, for the production of oil, natural gas and NGLs from underground reservoirs. At the election of each Company stockholder, Chesapeake will acquire each outstanding share of the Company in exchange for either 5.989 shares of Chesapeake common stock, $0.01 par value per share, or a combination of 5.336 shares of Chesapeake common stock and $3.00 cash. The merger, which is expected to close in the first half of 2019, has been unanimously approved by the board of directors of each company and is subject to stockholder approvals from both companies, customary closing conditions and regulatory approvals.

Quarterly Preferred Stock Dividend

See Note 10—“Preferred Stock” for information regarding quarterly dividends paid on our outstanding preferred stock.

34Fifth Amendment to the Credit Agreement

See Note 9—“Long Term Debt” for information regarding the Fifth Amendment, which was entered into on October 15, 2018.

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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, 2017 filed with the SEC on March 12, 2018 (“2017 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 2017 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 this 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 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 with multiple producing stratigraphic horizons, or stacked pay zones, and attractive single-well rates of return. We primarily operate in Burleson, Lee and Washington Counties where we primarily target the Eagle Ford Shale and the Austin Chalk.

As of December 31, 2017, we had assembled a total leasehold position of approximately 585,941 gross (477,153 net) acres across our expanding acreage, including approximately 460,000 gross (387,091 net) acres in the Eagle Ford and approximately 125,941 gross (90,062 net) acres in North Louisiana. We have identified a total of approximately 6,069 gross (3,739 net) drilling locations across our acreage as of December 31, 2017 including 4,675 gross (3,097 net) drilling locations in the Eagle Ford and 1,394 gross (642 net) drilling locations in North Louisiana. On March 29, 2018 WHR II completed the sale of all of our producing and non-producing oil and natural gas properties in North Louisiana. See “—Recent Developments” below for additional information regarding the sale of these properties.

Recent Developments

~~April~~Proposed ~~2018~~Merger ~~Issuance~~with ofChesapeake ~~Additional~~Energy ~~2025 Senior Notes~~Corporation

On ~~April~~October 2030, 2018, we ~~completed~~jointly announced with Chesapeake that we entered into a ~~private~~definitive ~~placement~~agreement ofto merge with Chesapeake, an ~~additional~~independent ~~$200.0~~exploration ~~million~~and production company engaged in ~~aggregate~~the ~~principal~~acquisition, ~~amount~~exploration and development of ~~our~~properties ~~2025~~in ~~Senior~~the ~~Notes~~Eagle (Ford Shale in South Texas, the ~~“April~~stacked ~~Notes”). The~~pay ~~April~~in ~~Notes~~the ~~are~~Powder ~~treated~~River asBasin ain ~~single~~Wyoming, ~~class~~the ofAnadarko ~~debt~~Basin ~~securities~~in ~~with~~northwestern Oklahoma, the ~~other~~Marcellus ~~outstanding~~Shale ~~2025~~in ~~Senior~~the ~~Notes. The~~northern ~~April~~Appalachian ~~Notes~~Basin ~~were~~in ~~issued~~Pennsylvania atand athe ~~price~~Haynesville/Bossier ofShales ~~102%~~in northwestern Louisiana and East Texas, for the production of ~~par~~oil, natural gas and NGLs from underground reservoirs. ~~This~~At ~~issuance~~the ~~resulted~~election of each Company stockholder, Chesapeake will acquire each outstanding share of the Company in ~~net~~exchange ~~proceeds~~for either 5.989 shares of ~~approximately~~Chesapeake common stock, $~~201.~~0.01 ~~million~~par value per share, ~~after~~or ~~deducting~~a ~~the~~combination ~~initial~~of ~~purchaser’s~~5.336 ~~discount~~shares ~~and~~of ~~commissions~~Chesapeake common stock and ~~estimated~~$3.00 ~~offering~~cash. ~~expenses~~The ~~and~~merger, ~~excluding~~which ~~accrued~~is ~~interest. We~~expected ~~used~~to close in the ~~net~~first ~~proceeds~~half toof ~~repay~~2019, ~~borrowings~~has ~~outstanding~~been ~~under~~unanimously ~~our~~approved ~~revolving~~by ~~credit~~the ~~facility~~board of directors of each company and ~~for~~is ~~general~~subject ~~corporate~~to ~~purposes~~stockholder approvals from both companies, customary closing conditions and regulatory approvals.

~~Amendment to Credit Agreement~~38

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Amendment to Credit Agreement

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

On March 23, 2018, the Company, each of the Company’s wholly owned subsidiaries (each as a guarantor), the Administrative Agent, and the lenders party thereto entered into a Fourth Amendment (the “Fourth Amendment”) to the Credit Agreement. The Fourth Amendment, among other things, modified the Credit Agreement to increase the borrowing base from $875.0 million to $1.05 billion.

April 2018 Issuance of Additional 2025 Senior Notes

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

North Louisiana Divestiture

In February 2018, WHR II entered into a Purchase and Sale Agreement with Tanos Energy Holdings III, LLC (“Tanos”) for the sale of all of our producing and non-producing oil and natural gas properties, including Oakfield, primarily located in Webster, Claiborne, Lincoln, Jackson and Ouachita Parishes, Louisiana (“NLA Assets”). In March 2018, we completed the sale of the NLA Assets for a total net sales price of approximately $206.4 million, including $21.7 million previously received as a deposit, which ~~includes~~included preliminary purchase price adjustments of approximately $0.9 million related to certain assets that were retained pending receipt of a consent to assign certain assets at the initial closing and approximately $9.7 million related to the net cash flows from the effective date to the closing date (the “NLA Divestiture”). We received the necessary consent to assign approximately $0.9 million of NLA Assets and assigned such NLA Assets to Tanos on August 1, 2018.

In addition, WRD could receive contingent payments of up to $35.0 million, of which $0.4 million has been accrued, based on the number of wells spud on such properties over the next four years. Our contingent consideration arrangement meets the definition of a derivative, but qualifies for a scope exception. We have made an accounting policy election to record the contingent consideration when it is deemed to be realizable. In October 2018, we received the $0.4 million payment from Tanos.

Our NLA Assets were deemed to meet held-for-sale accounting criteria as of February 12, 2018, at which point we ceased recording depletion and depreciation. Based on the Company’s sale proceeds after preliminary customary purchase price adjustments, we recorded an impairment charge of $214.3 million during the ~~six~~first ~~months~~quarter ~~ended~~of ~~June 30,~~ 2018 to adjust the carrying amount of the disposal group to its estimated fair value less costs to sell. See “Note 3—Acquisitions and Divestitures” of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this Quarterly Report for additional information.

Sources of Our Revenues

Our revenues are largely derived from the sale of our oil and natural gas production and the sale of NGLs that are extracted from our natural gas during processing. Production revenues are derived entirely from the continental United States.

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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 oil and natural gas prices on revenues, or to protect the economics of property acquisitions, we typically enter into derivative contracts with respect to a significant portion of estimated oil and natural gas 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, chemical 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.

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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 the production of our oil, natural gas and NGLs to market. Costs for these expenses can vary based on the volume of oil, natural gas and NGLs produced as well as the cost of commodity processing. As we continue to truck or pipe our product to destination markets (i.e. Houston and/or Corpus Christi) we may see an increase in GP&T costs. Based on our current set of contracts, the majority of these costs will be reported as a reduction to our natural gas and NGL revenues. See “Note 2—Summary of Significant Accounting Policies” of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this Quarterly Report for additional ~~detail and for~~ information regarding our adoption of the new revenue recognition standard.

Taxes Other Than Income Taxes. Production taxes are paid on produced oil and natural gas based on rates established by federal, state or local taxing authorities. In general, the production taxes we pay correlate to the changes in oil, natural gas and NGLs revenues. Production taxes for our Texas properties are based on the market value of our production at the wellhead. Production taxes for our Louisiana properties were based on our gross production at the wellhead. We were also subject to ad valorem taxes in the counties and parishes where our production was 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 were 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.

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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.

Incentive Unit Compensation Expense. See “Note 14—Incentive Units” of the Notes to Unaudited Condensed Consolidated 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 discounts and premiums, 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.

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significant interest expense as we continue to grow. Interest expense includes the amortization of discounts and premiums, 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 or losses 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. We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the tax basis in assets and liabilities and their reported amounts in the financial statements and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. Deferred tax assets are reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of deferred tax assets will not be realized. We recognize interest and penalties accrued to unrecognized tax benefits in other income (expense) in our consolidated statement of operations. We recognize a tax benefit from an uncertain tax position when it is more likely than not that the position will be sustained upon examination, based on the technical merits of the position. The tax benefit recorded is equal to the largest amount that is greater than 50% likely to be realized through effective settlement with a taxing authority.

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upon examination, based on the technical merits of the position. The tax benefit recorded is equal to the largest amount that is greater than 50% likely to be realized through effective settlement with a taxing authority.

Critical Accounting Policies and Estimates

Use of Estimates in the Preparation of Financial Statements

On January 1, 2018 the Company adopted ASC 606, Revenue from Contracts with Customers and all the related amendments (“new revenue standard”), using the cumulative effect transition method. The cumulative effect of adopting the standard was recognized through an adjustment to opening accumulated earnings. Previous periods have not been revised or adjusted and reflect the revenue standard in effect for those periods. We expect the overall impact to net income to be immaterial on an ongoing basis.

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The impact of adoption of the new revenue standard on our consolidated income statement and balance sheet and statement of cash flows was as follows (in thousands):

For the Three Months Ended June 30, 2018

For the Six Months Ended June 30, 2018

For the Three Months Ended September 30, 2018

For the Nine Months Ended September 30, 2018

As Reported

Without ASC 606

Increase/-

As Reported

Without ASC 606

Increase/-

Under ASC 606

Adoption

Decrease

Under ASC 606

Adoption

Decrease

Revenues:

Oil sales

~~207~~236,~~392~~040

~~207~~236,~~421~~056

(2916)

~~389~~625,~~771~~811

~~389~~625,~~800~~856

(2945)

Natural gas sales

89,~~106~~298

910,~~540~~378

(1,~~434~~080)

3545,~~736~~034

3748,~~975~~353

(23,~~239~~319)

NGL sales

913,~~668~~883

1216,~~193~~125

(2,~~525~~242)

1730,~~116~~999

2137,~~601~~727

(46,~~485~~728)

Other Income

~~247~~269

~~304~~269

~~(57)~~—

1,~~547~~816

1,~~738~~625

(191)

Operating expenses:

Lease operating expenses

1214,~~088~~221

1214,~~395~~681

(~~307~~460)

2842,~~515~~736

2843,~~816~~736

(~~301~~1,000)

Gathering, processing and transportation

~~476~~3,225

46,~~022~~246

(3,~~546~~021)

15,~~828~~053

814,~~120~~366

(69,~~292~~313)

Depreciation, depletion and amortization

7074,~~694~~842

7075,~~849~~023

(~~155~~181)

~~130~~205,~~577~~419

~~130~~205,~~866~~889

(~~289~~470)

Other operating (income) expense

~~111~~169

~~282~~1

~~(171)~~168

~~769~~938

~~1,080~~460

~~(311)~~478

Income (loss) before income taxes

~~(23~~30,~~450)~~578

~~(23~~30,~~583)~~422

~~133~~156

(~~177~~146,~~317~~739)

(~~177~~147,~~565~~142)

~~248~~403

Income tax benefit (expense)

9(19,~~356~~055)

9(19,~~383~~022)

(2733)

4728,~~449~~394

4728,~~503~~481

(5487)

Net income (loss)

~~(14~~11,~~094)~~523

~~(14~~11,~~200)~~400

~~106~~123

(~~129~~118,~~868~~345)

(~~130~~118,~~062~~661)

~~194~~316

	At June 30, 2018
	As Reported		Without ASC 606		Increase/-
	Under ASC 606		Adoption		Decrease
Assets:
Oil and gas properties	$	3,007,462	$	3,012,871	$	(5,409)
Accumulated depreciation, depletion and amortization		(351,248)		(351,907)		659
Other non-current assets		13,256		7,951		5,305
Liabilities:
Deferred tax liabilities		20,612		20,492		120
Stockholders' Equity
Accumulated earnings (deficit)		(123,305)		(122,629)		(676)

	For the Six Months Ended June 30, 2018
	As Reported		Without ASC 606		Increase/-
	Under ASC 606		Adoption		Decrease
Cash flows from operating activities:
Net income	$	(129,868)	$	(130,062)	$	194
Depreciation, depletion and amortization		130,249		130,538		(289)
Deferred income tax expense (benefit)		(50,925)		(50,979)		54
Consideration paid to customers, net of amortization		(1,328)		—		(1,328)
Cash flows from investing activities:
Additions to oil and gas properties		(578,669)		(577,301)		(1,368)

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	At September 30, 2018
	As Reported		Without ASC 606		Increase/-
	Under ASC 606		Adoption		Decrease
Assets:
Oil and gas properties	$	3,271,422	$	3,277,335	$	(5,913)
Accumulated depreciation, depletion and amortization		(426,373)		(427,213)		840
Other non-current assets		17,575		11,792		5,783
Liabilities:
Deferred tax liabilities		44,141		43,988		153
Stockholders' Equity
Accumulated earnings (deficit)		(118,605)		(117,741)		(864)


	For the Nine Months Ended September 30, 2018
	As Reported		Without ASC 606		Increase/-
	Under ASC 606		Adoption		Decrease
Cash flows from operating activities:
Net income	$	(118,345)	$	(118,661)	$	316
Depreciation, depletion and amortization		205,419		205,889		(470)
Deferred income tax expense (benefit)		(27,396)		(27,483)		87
Consideration paid to customers, net of amortization		(1,806)		—		(1,806)

Cash flows from investing activities:
Additions to oil and gas properties		(824,656)		(826,528)		1,872

A discussion of our critical accounting policies and estimates is included in our 2017 Form 10-K. There have been no significant changes to our critical accounting policies and estimates except as disclosed in “Note 2—Summary of Significant Accounting Policies” of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this Quarterly Report for additional information.

Incentive Units

Certain officers and employees have been granted awards of incentive units in WildHorse Investment Holdings and WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings (the “LLCs”). The fair value of the incentive units will be remeasured on a quarterly basis until all payments have been made. Any future compensation expense recognized will be a non-cash charge, with the settlement obligation resting with WildHorse Investment Holdings, WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings, respectively. Accordingly, no cash payments or issuance of stock will ever be made by us related to these incentive units; however, non-cash compensation expense (income) will be allocated to us in future periods offset by deemed capital contributions (distributions). As such, these awards are not dilutive to our stockholders. Compensation cost is recognized only if the performance condition is probable of being satisfied at each reporting date or as a result of an actual distribution. Compensation cost related to an actual distribution by Esquisto Holdings to incentive unitholders of 500,932 shares of our common stock on May 14, 2018 resulted in non-cash compensation expense of $13.8 million offset by a deemed capital contribution. Compensation costs associated with satisfying the remaining performance conditions were not deemed probable at September 30, 2018. Unrecognized compensation cost associated with these incentive units was $59.4 million at September 30, 2018.

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stock will ever be made by us related to these incentive units; however, non-cash compensation expense (income) will be allocated to us in future periods offset by deemed capital contributions (distributions). As such, these awards are not dilutive to our stockholders. Compensation cost is recognized only if the performance condition is probable of being satisfied at each reporting date or as a result of an actual distribution. Compensation cost related to an actual distribution by Esquisto Holdings to incentive unitholders of 500,932 shares of our common stock on May 14, 2018 resulted in non-cash compensation expense of $13.8 million offset by a deemed capital contribution. Compensation costs associated with satisfying the remaining performance conditions were not deemed probable at June 30, 2018. Unrecognized compensation cost associated with these incentive units was $71.1 million at June 30, 2018.

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, 2018
		September 30, 2018
Expected life (years)		1.2904 - 4.2904
Expected volatility (range)		4648.0% - 5659.0%
Dividend yield		0.00%
Risk-free rate (range)		2.3657% - 2.6687%

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executive officers, a portion of their respective distributions, but only after a substantial priority distribution, the amount of which is specified in each respective limited liability company agreement and is referred to as a "distribution threshold," has first been made to the holders of capital interests in WildHorse Investment Holdings and the LLCs (who are the investors in these entities). The distribution threshold differs with regard to each class (referred to as a "tier") of incentive units in WildHorse Investment Holdings (which has five tiers) and the LLCs (each of which has two tiers). As the only assets of the LLCs are shares of our common stock, any distributions to the named executive officers holding incentive units in the LLCs would be dependent on distributions of cash proceeds of sales of shares of our common stock or distribution of our common stock to holders of capital interests sufficient in amount to exceed the applicable distribution threshold, thereby enabling the commencement of participation by holders of incentive units in additional distributions.

Results of Operations

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:

Incentive unit compensation expense of $13.8 million;

the new revenue recognition standard, which was adopted as of January 1, 2018;

the NLA Divestiture, which was completed on March 29, 2018;

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

the $435.0 million issuance of preferred stock to an affiliate of Carlyle;

a more active drilling program; and

the private placement of $350.0 million, $150.0 million and $200.0 million in February 2017, September 2017 and April 2018, respectively, of aggregate principal amount of 6.875% senior unsecured notes due 2025.

As a result of the factors listed above, the 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.

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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,
	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2018		2017		2018		2017
Revenues and other income:
Oil sales	$	~~207~~236,~~392~~040	$	52100,~~963~~391	$	~~389~~625,~~771~~811	$	92192,~~040~~431
Natural gas sales		89,~~106~~298		1314,~~277~~906		3545,~~736~~034		2540,~~422~~328
NGL sales		913,~~668~~883		36,~~404~~881		1730,~~116~~999		612,~~067~~948
Other income		~~247~~269		~~529~~308		1,~~547~~816		~~936~~1,244
Total revenues and other income		~~225~~259,~~413~~490		70122,~~173~~486		~~444~~703,~~170~~660		~~124~~246,~~465~~951
Operating expenses:
Lease operating expenses		1214,~~088~~221		612,~~837~~435		2842,~~515~~736		1326,~~765~~200
Gathering, processing and transportation		~~476~~3,225		13,~~942~~761		15,~~828~~053		37,~~642~~403
Taxes other than income tax		1214,~~779~~193		46,~~509~~047		2438,~~560~~753		814,~~408~~455
Depreciation, depletion and amortization		7074,~~694~~842		3351,~~229~~843		~~130~~205,~~577~~419		59111,~~672~~515
Impairment of NLA Disposal Group		—		—		214,274		—
(Gain) loss on sale of properties		~~(3,167)~~217		—		(32,~~167~~950)		—
General and administrative expenses		1216,~~917~~033		1011,~~049~~043		2541,~~644~~677		1728,~~531~~574
Incentive unit compensation expense		~~13,776~~—		—		13,776		—
Exploration expense		413,~~369~~814		114,~~504~~749		619,~~077~~891		1317,~~119~~868
Other operating (income) expense		~~111~~169		259		~~769~~938		4453
Total operating expenses		~~124~~136,~~043~~714		6889,~~095~~887		~~442~~579,~~853~~567		~~116~~206,~~181~~068
Income (loss) from operations		~~101~~122,~~370~~776		232,~~078~~599		1124,~~317~~093		840,~~284~~883
Other income (expense):
Interest expense		(1415,~~002~~718)		(68,~~633~~749)		(2743,~~309~~027)		(1220,~~204~~953)
Gain (loss) on derivative instruments		(~~110~~76,~~805~~358)		46(40,~~116~~288)		(~~151~~227,~~175~~533)		7737,~~407~~119
Other income (expense)		(13122)		(212)		(~~150~~272)		2412
Total other income (expense)		(~~124~~92,~~820~~198)		39(49,~~481~~049)		(~~178~~270,~~634~~832)		6516,~~227~~178
Income (loss) before income taxes		~~(23~~30,~~450)~~578		41(16,~~559~~450)		(~~177~~146,~~317~~739)		7357,~~511~~061
Income tax benefit (expense)		9(19,~~356~~055)		~~(15~~5,~~193)~~646		4728,~~449~~394		(2621,~~893~~247)
Net income (loss) available to WRD	$	~~(14~~11,~~094)~~523	$	26(10,~~366~~804)	$	(~~129~~118,~~868~~345)	$	4635,~~618~~814
Net income (loss) per common share:
Basic and diluted	$	(0.~~22)~~04	$	(0.2817)	$	(1.4641)	$	0.4927
Weighted-average common shares outstanding:
Basic and diluted		99,~~411~~639		9399,~~685~~142		99,~~328~~433		9395,~~452~~369
Oil and natural gas revenue:
Crude oil	$	~~207~~236,~~392~~040	$	52100,~~963~~391	$	~~389~~625,~~771~~811	$	92192,~~040~~431
Natural gas		89,~~106~~298		1314,~~277~~906		3545,~~736~~034		2540,~~422~~328
NGLs		913,~~668~~883		36,~~404~~881		1730,~~116~~999		612,~~067~~948
Total oil, natural gas and NGL revenue	$	~~225~~259,~~166~~221	$	69122,~~644~~178	$	~~442~~701,~~623~~844	$	~~123~~245,~~529~~707
Production volumes:
Oil (MBbls)		3,~~041~~268		12,~~133~~097		59,~~857~~125		14,~~916~~012
Natural gas (MMcf)		3,~~954~~985		45,~~299~~133		1216,~~750~~735		813,~~148~~281
NGLs (MBbls)		~~550~~572		~~205~~413		~~982~~1,554		~~365~~778
Total (MBoe)		4,~~249~~504		23,~~054~~365		813,~~964~~468		37,~~639~~004
Average sales price:
Oil (per Bbl)	$	6872.2123	$	4647.7789	$	6668.5458	$	4847.0596
Natural gas (per Mcf)	$	2.0533	$	32.0990	$	2.8069	$	3.1204
NGLs (per Bbl)	$	1724.5929	$	16.5965	$	1719.4395	$	16.6264
Total (per Boe)	$	5257.9956	$	3336.9030	$	4952.3811	$	3335.9508
Average production volumes:
Oil (MBbls/d)		3335.45		1222.58		3233.4		1014.67
Natural gas (MMcf/d)		43.53		4755.28		7061.43		4548.06
NGLs (MBbls/d)		6.02		24.35		5.47		2.08
Average net production (MBoe/d)		4649.70		2236.6		49.53		2025.17
Average unit costs per Boe:
Lease operating expenses	$	23.8416	$	3.3370	$	3.1817	$	3.7874
Gathering, processing and transportation	$	0.1172	$	01.9512	$	0.2038	$	1.0006
Taxes other than income tax	$	3.0115	$	21.2080	$	2.7488	$	2.3106
General and administrative expenses	$	3.0456	$	43.8928	$	23.8609	$	4.8208
Depletion, depreciation and amortization	$	16.6462	$	1615.1841	$	1415.5725	$	1615.4092

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Three Months Ended ~~June~~September 30, 2018 Compared to the Three Months Ended ~~June~~September 30, 2017

For purposes of the following discussion, references to 2018 and 2017 refer to the three months ended ~~June~~September 30, 2018 and the three months ended ~~June~~September 30, 2017, respectively, unless otherwise indicated.

· Oil, natural gas and NGL revenues were $~~225~~259.2 million for 2018 compared to $69122.62 million for 2017, an increase of $~~155~~137.60 million (approximately ~~224~~112%). Production increased ~~2.2~~1,139 MMBoe primarily due to increased production from drilling successful wells in the Eagle Ford ~~and the Acquisition~~. The average realized sales price increased $1921.0926 per Boe (approximately 5659%) due to higher overall commodity prices and a higher percentage of oil in the production mix. Oil revenues increased $~~154~~135.46 million, which was comprised of $6579.25 million and $8956.21 million due to favorable pricing and production variances, respectively. Natural gas revenues decreased $5.26 million, which was comprised of $42.13 million due to unfavorable pricing variances and $13.13 million due to a reduction of production volumes as a result of the NLA Divestiture. The unfavorable pricing variance for natural gas revenues included a $1.1 million decrease associated with the adoption of the new revenue recognition standard. NGL revenues increased $67.30 million, which was comprised of $04.64 million and $52.76 million due to favorable price and volume variances, respectively. The favorable price variance was offset by $2.2 million associated with the adoption of the new revenue recognition standard.

· LOE was $1214.12 million and $612.84 million for 2018 and 2017, respectively. On a per Boe basis, total LOE was $23.8416 and $3.3370 for 2018 and 2017, respectively. The decrease in LOE on a per unit basis is largely attributable to the increased production due to the ~~Acquisition and~~ drilling of successful wells in the Eagle Ford along with increased efficiencies in 2018 compared to 2017. We recorded $12.8 million of workover expenses in 2018 in comparison to $02.96 million in 2017 to increase efficiency on legacy wells. Net production in 2018 consisted of 7273% oil compared to 5562% oil in 2017, an increase of approximately 3016% due primarily to the sale of the NLA properties.

· GP&T expenses were $03.52 million and $13.98 million for 2018 and 2017, respectively. On a per Boe basis, GP&T expenses were $0.1172 and $01.9512 for 2018 and 2017, respectively. The 8836% decrease in GP&T expenses on a per Boe basis was primarily attributable to the impact from the new revenue recognition standard, the sale of the NLA Disposal Group and an increase in production from our drilling activities.

· Taxes other than income tax were $1214.82 million and $46.50 million for 2018 and 2017, respectively; an increase of $8.32 million (approximately ~~183~~137%). On a per Boe basis, taxes other than income tax were $3.0115 and $21.2080 for 2018 and 2017, respectively. The $8.32 million increase was primarily due to an increase in production taxes of $7.81 million and ad valorem taxes of $01.51 million. The production taxes increased $45.73 million and $3.1.8 million due to favorable price and volume variances, respectively. The ad valorem taxes increased due to increased property valuations.

· DD&A expense for 2018 was $7074.78 million compared to $3351.28 million for 2017, a $3723.50 million increase (approximately ~~113~~44%) primarily due to an increase in production volumes related to ~~acquisitions~~successful ~~and~~ drilling activities. Increased production volumes caused DD&A expense to increase by $3517.56 million and the change in the DD&A rate between periods caused DD&A expense to increase by $25.04 million.

· ~~Gains~~Estimated ~~from~~losses associated with the sale of the NLA Disposal Group were $30.2 million in 2018. We did not have any gains or losses from the sale of assets in 2017.

· G&A expenses were $1216.90 million and $1011.0 million (an increase of approximately 2945%) for 2018 and 2017, respectively. The $25.90 million increase was primarily due to increased salaries and wages and stock-based compensation costs. Salaries and wages and other employee benefits increased by $21.45 million primarily due to additional staffing and stock-based compensation costs increased $2.5 million related to our long term incentive plan. ~~These~~In ~~increases~~2018, ~~were~~we ~~offset~~had byincreases aof $21.02 million ~~decrease~~related into ~~acquisition~~professional ~~expenses.~~fees, Ininformation ~~2018~~technology, weaccounting ~~received~~and $1legal services.0 ~~million~~These ofincreases ~~transition~~were ~~services~~offset ~~fees~~by ~~from~~a ~~Tanos~~$0.6 million decrease in acquisition expenses.

· Exploration expense was $413.48 million and $114.57 million for 2018 and 2017, respectively. The $79.1 million ~~decrease~~increase in exploration expense was largely due to a $111.54 million ~~decrease~~of ingeophysical ~~seismic acquisition~~ costs ~~and~~incurred arelated ~~$5.8~~to ~~million decrease in abandonment costs. In 2017, we had $0.2 million of impairments of undeveloped leases. We did not record undeveloped lease impairments in 2018.~~the

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·drilling ~~Incentive~~of ~~unit~~certain ~~compensation~~developmental ~~expense~~wells, ~~was~~a $131.84 million ~~for~~decrease ~~2018 related to common stock distributions to incentive unit holders~~ in ~~May~~delay ~~2018.~~rentals ~~This~~and ~~non-cash charge was offset by~~ a ~~deemed~~$0.9 ~~capital~~million ~~contribution~~decrease ~~under~~in ~~the~~undeveloped ~~Esquisto~~leasehold ~~Holding~~impairments ~~plan~~and ~~from NGP~~abandonments.

· Interest expense was $1415.07 million and $68.67 million for 2018 and 2017, respectively. The $7.40 million increase (approximately ~~111~~80%) was due to an increase in the average debt outstanding as a result of the issuance of the 2025 Senior Notes and increased borrowings under our revolving credit facility. Interest is comprised of interest on our credit facility, interest on ~~our~~the ~~senior~~2025 ~~notes~~Senior Notes, premium/discount amortization on the 2025 Senior Notes and amortization of debt issue costs offset by capitalized interest. Interest expense before the premium/discount amortization, amortization of debt issuance costs and capitalized interest was $1416.56 million for 2018 and $68.8 million for 2017. Amortization of premiums and discounts on the 2025 Senior Notes was a ~~premium~~discount of less than $0.1 million for 2018 and ~~a discount~~ $0.1 million for 2017. Amortization of debt issue costs was $0.8 million for 2018 compared to $0.47 million for 2017. Capitalized interest was $1.27 million and $0.78 million for the 2018 and 2017, respectively, primarily due to drilling activities.

· Net losses on derivative instruments of $~~110~~76.84 million were recognized during 2018, which consisted of a $7844.1 million decrease in the fair value of open positions and $32.73 million of cash settlements paid or accrued. Net ~~gains~~losses on derivative instruments of $4640.13 million were recognized during 2017, which consisted of a $4244.83 million ~~increase~~decrease in the fair value of open positions and $34.30 million of cash settlements received or accrued.

· Income tax ~~benefit~~expense for 2018 was $919.41 million compared to income tax ~~expense~~benefit of $155.26 million for 2017. The change is primarily due to the pretax ~~loss~~income in 2018 as compared to the pretax ~~income~~loss in 2017. The effective tax rate for 2018 was 3962.93%, compared to 3634.63% for 2017. The increase ~~of 3.3%~~ in the effective tax rate was primarily due to state income taxes ~~and an excess tax benefit associated with stock-based compensation~~ in 2018, offset by a reduction in the federal corporate income tax rate from 35% to 21% as a result of tax legislation enacted in December 2017~~, and incentive unit compensation expense in 2018~~. The effective tax rate differed from the statutory federal income tax rate of 21% for 2018 primarily due to ~~incentive~~the ~~unit~~impact ~~compensation,~~of ~~excess~~the state income tax ~~benefit~~provision related to ~~stock-based~~a ~~compensation,~~change ~~and~~in the ~~impact~~estimated ofannual ~~the~~effective ~~state income~~ tax ~~provision~~rate. The effective tax rate differed from the statutory federal income tax rate of 35% for 2017 primarily due to the impact of the state income tax provision.

~~Six~~Nine Months Ended ~~June~~September 30, 2018 Compared to the ~~Six~~Nine Months Ended ~~June~~September 30, 2017

For purposes of the following discussion, references to 2018 and 2017 refer to the ~~six~~nine months ended ~~June~~September 30, 2018 and the ~~six~~nine months ended ~~June~~September 30, 2017, respectively, unless otherwise indicated.

· Oil, natural gas and NGL revenues were $~~442~~701.68 million for 2018 compared to $~~123~~245.57 million for 2017, an increase of $~~319~~456.1 million (approximately ~~258~~186%). Production increased ~~5.3~~6,464 MMBoe primarily due to increased production from drilling successful wells in the Eagle Ford and the Acquisition. The average realized sales price increased $1517.4303 per Boe (approximately 4549%) due to higher overall commodity prices and a higher percentage of oil in the production mix. Oil revenues increased $~~297~~433.74 million, which was comprised of $~~108~~188.32 million and $~~189~~245.42 million due to favorable pricing and production variances, respectively. Natural gas revenues increased $104.37 million, which was comprised of a decrease of $45.18 million and an increase of $1410.45 million due to unfavorable pricing and favorable production variances, respectively. The unfavorable pricing variance for natural gas revenues included a $3.3 million decrease associated with the adoption of the new revenue recognition standard. NGL revenues increased $1118.10 million, which was comprised of $05.81 million and $1012.39 million due to favorable price and volume variances, respectively. The favorable price variance was offset by a $6.7 million decrease associated with the adoption of the new revenue recognition standard.

· LOE was $2842.57 million and $1326.82 million for 2018 and 2017, respectively. On a per Boe basis, total LOE was $3.1817 and $3.7874 for 2018 and 2017, respectively. The decrease in LOE on a per unit basis is largely attributable to the increased production due to the Acquisition and drilling successful wells in the Eagle Ford along with increased efficiencies in 2018 compared to 2017. We recorded $36.86 million of workover expenses in 2018 in comparison to $14.84 million in 2017 to increase efficiency on legacy wells. Net production in 2018 consisted of 6568% oil compared to 5357% oil in 2017, an increase of approximately 2418% due primarily to the sale of the NLA properties.

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· GP&T expenses were $15.81 million and $37.64 million for 2018 and 2017, respectively. On a per Boe basis, GP&T expenses were $0.2038 and $1.0006 for 2018 and 2017, respectively. The 8064% decrease in GP&T expenses on a per Boe basis, was primarily attributable to the impact from the new revenue recognition standard, the sale of the NLA Disposal Group and an increase in production from our drilling activities.

· Taxes other than income tax were $2438.68 million and $814.45 million for 2018 and 2017, respectively, an increase of $1624.23 million (approximately ~~192~~168%). On a per Boe basis, taxes other than income tax were $2.7488 and $2.3106 for 2018 and 2017, respectively. The $1624.23 million increase was primarily due to an increase in production taxes of $1522.34 million and ad valorem taxes of $1.09 million~~, offset by reduced franchise taxes of $0~~.2 ~~million.~~ The production taxes increased $712.87 million and $79.57 million due to favorable price and volume variances, respectively. The ad valorem taxes increased due to increased property valuations.

· DD&A expense for 2018 was $~~130~~205.64 million compared to $59111.75 million for 2017, a $7093.9 million increase (approximately ~~119~~84%) primarily due to an increase in production volumes related to acquisitions and drilling activities. Increased production volumes caused DD&A expense to increase by $87102.39 million and the change in the DD&A rate between periods caused DD&A expense to decrease by $169.40 million.

· Gains from the sale of the NLA Disposal Group were $3.20 million in 2018. We did not have any gains from the sale of assets in 2017.

· G&A expenses were $2541.67 million and $1728.56 million (an increase of approximately 46%) for 2018 and 2017, respectively. The $813.1 million increase was primarily due to increased salaries and wages and stock-based compensation costs. Salaries and wages and other employee benefits increased by $56.18 million primarily due to additional staffing and stock-based compensation costs increased $57.05 million related to our long term incentive plan. In 2018, we also had increases of $1.8 million related to professional fees, information technology, accounting and legal services. These increases were offset by a $2.3.0 million decrease in acquisition expenses. In 2018, we received $1.0.9 million of transition services fees ~~from~~after ~~Tanos~~the sale of the NLA properties.

· Exploration expense was $619.19 million and $1317.19 million for 2018 and 2017, respectively. The $72.0 million ~~decrease~~increase in exploration expense was largely due to $11.4 million due to geophysical costs incurred related to the drilling of certain developmental wells, a $1.87 million decrease in seismic acquisition expenses, a $75.37 million decrease in ~~abandonment~~undeveloped ~~costs~~leasehold impairments and abandonments and a decrease of $02.61 million in delay rentals. The decreased components of exploration expenses were offset by a $0.2 million increase in sand mine exploration expenses. ~~Additionally, we recorded $2.5 million in impairments of undeveloped leases in 2017 but did not record any for 2018.~~

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

· Interest expense was $2743.30 million and $1221.20 million for 2018 and 2017, respectively. The $1522.10 million increase (approximately ~~124~~105%) was primarily due to an increase in the average debt outstanding as a result of the issuance of the 2025 Senior Notes and increased borrowings under our revolving credit facility. Interest is comprised of interest on our credit facility, interest on our ~~senior~~2025 ~~notes~~Senior Notes, premium/discount amortization on the 2025 Senior Notes and amortization of debt issue costs offset by capitalized interest. Interest expense before the premium/discount amortization, amortization of debt issuance costs and capitalized interest was $2844.17 million for 2018 and $1120.87 million for 2017. Amortization of discounts on the 2025 Senior Notes was $0.1 million for ~~both~~ 2018 and $0.2 million for 2017. Amortization of debt issue costs was $12.42 million for 2018 compared to $12.30 million for 2017. Capitalized interest was $2.3.9 million and $1.09 million for 2018 and 2017, respectively, primarily due to drilling activities.

· Net losses on derivative instruments of $~~151~~227.25 million were recognized during 2018, which consisted of a $95139.67 million decrease in the fair value of open positions and $5587.68 million of cash settlements paid or accrued. Net gains on commodity derivatives of $7737.41 million were recognized during 2017, which consisted ~~of a $73.9 million increase in the fair value of open positions and $3.5 million of cash settlements received or accrued.~~

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·of ~~Income~~a ~~tax benefit for 2018 was~~ $4729.56 million ~~compared~~increase ~~to income tax expense of $26.9 million for 2017. The change is primarily due to the pretax loss~~ in ~~2018 as compared to~~ the ~~pretax~~fair ~~income~~value ~~in 2017. The effective tax rate for 2018 was 26.8%, compared to 36.6% for 2017. The decrease~~ of ~~9.8%~~open inpositions ~~the effective tax rate was primarily due to a reduction in the federal corporate income tax rate from 35% to 21% as a result of tax legislation that was enacted in December 2017~~ and incentive unit compensation expense, offset by state tax adjustments associated with the NLA Divestiture, an excess tax benefit associated with stock-based compensation and the impact of the state income tax provision$7.5 ~~The~~million ~~effective tax rate differed from the statutory federal income tax rate~~ of ~~21%~~cash ~~for~~settlements ~~2018~~received ~~primarily~~or ~~due to incentive unit compensation, stock-based compensation, state tax adjustments associated with the NLA Divestiture, and the impact of the state income tax provision~~accrued. ~~The effective tax rate differed from the statutory federal income tax rate of 35% for 2017 primarily due to the impact of the state income tax provision.~~

Income tax benefit for 2018 was $28.4 million compared to income tax expense of $21.2 million for 2017. The change is primarily due to the pretax loss in 2018 as compared to the pretax income in 2017. The effective tax rate for 2018 was 19.3% compared to 37.2% for 2017. The decrease in the effective tax rate was primarily due to a reduction in the federal corporate income tax rate from 35% to 21% as a result of tax legislation that was enacted in December 2017, incentive unit compensation expense, and the impact of the state income tax provision, offset by state tax adjustments associated with the NLA Divestiture, and an excess tax benefit associated with stock-based compensation. The effective tax rate differed from the statutory federal income tax rate of 21% for 2018 primarily due to incentive unit compensation, stock-based compensation, state tax adjustments associated with the NLA Divestiture, and the impact of the state income tax provision. The effective tax rate differed from the statutory federal income tax rate of 35% for 2017 primarily due to the impact of the state income tax provision.

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;

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Cash settlements paid on derivative instruments;

Gain on sale of properties; and

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

Management believes Adjusted EBITDAX is a useful performance measure because it allows them to more effectively evaluate our operating performance without regard to our financing methods or capital structure. We exclude the items listed above from net (loss) income in arriving at Adjusted EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net (loss) income as determined in accordance with GAAP. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDAX. Our presentation of Adjusted EBITDAX should not be construed as an inference that our results will be unaffected by unusual or non-recurring items. Our computations of Adjusted EBITDAX may not be comparable to other similarly titled measures of other companies.

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,

For the Three Months Ended September 30,

For the Nine Months Ended September 30,

2018

2017

2018

2017

Adjusted EBITDAX reconciliation to net (loss) income:

Net income (loss)

~~(14~~11,~~094)~~523

26(10,~~366~~804)

(~~129~~118,~~868~~345)

4635,~~618~~814

Interest expense, net

1415,~~002~~718

68,~~633~~749

2743,~~309~~027

1220,~~204~~953

Income tax (benefit) expense

(919,~~356)~~055

15(5,~~193~~646)

(4728,~~449~~394)

2621,~~893~~247

Depreciation, depletion and amortization

7074,~~694~~842

3351,~~229~~843

~~130~~205,~~577~~419

59111,~~672~~515

Exploration expense

413,~~369~~814

114,~~504~~749

619,~~077~~891

1317,~~119~~868

Impairment of NLA Disposal Group

—

214,274

—

(Gain) loss on derivative instruments

~~110~~76,~~805~~358

~~(46~~40,~~116)~~288

~~151~~227,~~175~~533

(7737,~~407~~119)

Cash settlements received (paid) on derivative instruments

(2931,~~508~~123)

25,~~076~~802

(5081,~~054~~177)

16,~~093~~895

Stock-based compensation

34,~~835~~997

12,~~308~~414

611,~~991~~988

14,~~803~~217

Incentive unit compensation

~~13,776~~—

—

13,776

—

Acquisition related costs

~~129~~424

~~2,199~~998

~~488~~912

23,~~798~~796

(Gain) loss on sale of properties

~~(3,167)~~217

—

(32,~~167~~950)

—

Debt extinguishment costs

—

(11)

Initial public offering costs

—

182

Total Adjusted EBITDAX

~~161~~185,~~485~~825

5298,~~392~~393

~~320~~505,~~129~~954

86185,~~964~~357

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. 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 development drilling activities over the next twelve months. 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.

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Asadditional ofcapital ~~June~~expenditures ~~30,~~will ~~2018,~~be werequired ~~had~~to ~~$19.1~~more ~~million~~fully ofdevelop ~~cash~~our ~~and~~properties ~~cash equivalents~~ and ~~$801.0~~acquire ~~million~~additional ~~of available borrowings under our revolving credit facility~~properties. AsWe ofcannot ~~June~~assure ~~30,~~you ~~2018,~~that weoperations ~~had~~and aother ~~working~~needed capital ~~deficit~~will ofbe ~~$233.6~~available ~~million~~on ~~primarily~~acceptable ~~due to the accrual of capital expenditures. As of June 30~~terms, ~~2018,~~or ~~the~~at ~~borrowing base under our Credit Agreement was $1~~all.~~05 billion and we had outstanding borrowings of $249.0 million.~~

OnAs ~~March~~of 23September 30, 2018, ~~the~~we ~~Company,~~had ~~each~~$1.7 million of ~~the~~cash ~~Company’s~~and ~~wholly~~cash ~~owned~~equivalents ~~subsidiaries (each as a guarantor), the Administrative Agent,~~ and ~~the lenders party thereto entered into the Fourth Amendment to the Credit Agreement, which, among other things, (i) increased the borrowing base from~~ $~~875~~651.0 million toof ~~$1.05~~available ~~billion.~~borrowings ~~The borrowing base~~ under our revolving credit facility. isAs ~~subject~~of toSeptember ~~redetermination~~30, on2018, atwe ~~least~~had a ~~semi-annual~~working ~~basis~~capital ~~based~~deficit onof an$248.8 ~~engineering~~million ~~report~~primarily ~~with~~due ~~respect~~ to ~~our~~the ~~estimated~~accrual ~~oil~~of ~~and~~capital ~~natural~~expenditures ~~gas reserves, which will take into account the prevailing oil~~ and ~~natural~~losses ~~gas~~on ~~prices at such time, as adjusted for the impact of~~ our ~~commodity~~short-term derivative ~~contracts~~instruments. ~~Unanimous~~As ~~approval~~of bySeptember ~~the~~30, ~~lenders~~2018, isthe ~~required~~borrowing ~~for~~base ~~any~~under ~~increase~~our toCredit ~~the~~Agreement ~~borrowing~~was ~~base~~$1. ~~The~~05 ~~next~~billion ~~scheduled~~and ~~borrowing~~we ~~base~~had ~~redetermination~~outstanding isborrowings ~~set~~of ~~for~~$399.0 ~~October 2018~~million.

On March 23, 2018, the Company, each of the Company’s wholly owned subsidiaries (each as a guarantor), the Administrative Agent, and the lenders party thereto entered into the Fourth Amendment to the Credit Agreement, which, among other things, (i) increased the borrowing base from $875.0 million to $1.05 billion. On October 15, 2018, the Company, each of the Company’s wholly owned subsidiaries (each as a guarantor), the Administrative Agent, and the lenders party thereto entered into the Fifth Amendment to the Credit Agreement, which, among other things, increased the borrowing base from $1.05 billion to $1.30 billion.

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.

Preferred Stock

We are authorized to issue up to 50,000,000 shares of preferred stock. We are authorized to issue up to 500,000 shares of Series A perpetual convertible preferred stock and have 435,000 shares of our Series A perpetual convertible preferred stock issued and outstanding. See “Note 10—Preferred Stock” of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this Quarterly Report for additional information regarding our Series A perpetual convertible preferred stock.

Capital Expenditure Budget

We established a 2018 drilling and completion capital expenditure budget of $700 million to $800 million. For the ~~six~~nine months ended ~~June~~September 30, 2018, our drilling and completion expenditures were approximately $~~450~~657.03 million primarily related to the development of our Eagle Ford properties. We established a 2018 sand mine capital expenditure budget of $65 million to $75 million. For the ~~six~~nine months ended ~~June~~September 30, 2018, our sand mine expenditures were approximately $2544.15 million related to the development of our in-field sand mine.

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. On March 23, 2018, the Company, each of the Company’s wholly owned subsidiaries (each as a guarantor), the Administrative Agent, and the lenders party thereto entered into Fourth Amendment to the Credit Agreement. The Fourth Amendment, among other things, modified the Credit Agreement to increase the borrowing base from $875.0 million to $1.05 billion. On October 15, 2018, the Company, each of the Company’s wholly owned subsidiaries (each as a guarantor), the Administrative Agent, and the lenders party thereto entered into Fifth Amendment to the Credit Agreement. The Fifth Amendment, among other things, modified the Credit Agreement to increase the borrowing base from $1.05 billion to $1.30 billion.

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~~September 30, 2018.

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

~~2025 Senior Notes~~51

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~~corporate purposes, including funding a portion of our capital expenditures. The~~ 2025 Senior Notes are governed by an indenture dated as of February 1, 2017, 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). We have no material assets or operations that are independent of our existing subsidiaries. There are no restrictions on the ability of the Company to obtain funds from its subsidiaries through dividends or loans. 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. On August 1, 2018, we made a $24.1 million interest payment on the 2025 Senior Notes.

In February 2017, we completed a private placement of $350.0 million of the 2025 Senior Notes, issued at 99.244% of par and resulted in net proceeds of $338.6 million. In September 2017, we completed another private placement of $150.0 million aggregate principal amount of the 2025 Senior Notes issued at 98.26% of par, which resulted in net proceeds of approximately $144.7 million. In April 2018, we completed the private placement of the April Notes. The April Notes are treated as a single class of debt securities with the other outstanding 2025 Senior Notes. The April Notes were issued at a price of 102% of par. This issuance resulted in net proceeds of approximately $201.0 million, after deducting the initial purchaser’s discount and commissions and estimated offering expenses and excluding accrued interest. We used the net proceeds from all issuances to repay the borrowings outstanding under our revolving credit facility and for general corporate purposes, including funding a portion of our capital expenditures. The 2025 Senior Notes are governed by an indenture dated as of February 1, 2017, 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). We have no material assets or operations that are independent of our existing subsidiaries. There are no restrictions on the ability of the Company to obtain funds from its subsidiaries through dividends or loans. 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. On August 1, 2018, we made a $24.1 million interest payment on the 2025 Senior Notes. As of September 24, 2018, all of the 2025 Senior Notes have been exchanged for an equal principal amount of registered 6.875% senior notes due 2025 pursuant to an effective registration statement on Form S-4.

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 covered by commodity derivative contracts and the average prices at which production is hedged as of ~~June~~September 30, 2018, see “Note 5—Risk Management and Derivative Instruments” of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this Quarterly Report.

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, all 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. The cash flows for the ~~six~~nine months ended ~~June~~September 30, 2018 and 2017 have been derived from our consolidated financial statements. For information regarding the individual components of our cash flow amounts, see the Unaudited Statements of Condensed Consolidated Cash Flows included under “Item 1. Financial Statements” contained herein.

	For the Six Months Ended June 30,
	For the Nine Months Ended September 30,
	2018		2017
Net cash provided by operating activities	$	~~291~~447,~~507~~374	$	72143,~~034~~192
Net cash used in investing activities	$	~~(425~~741,~~135)~~316	$	~~(764~~1,~~841)~~002,313
Net cash provided by financing activities	$	~~152~~295,~~541~~461	$	~~704~~861,~~191~~031

~~Six Months Ended June 30, 2018 Compared to the Six Months Ended June 30, 2017~~52

For purposes of the following discussion, references to 2018 and 2017 refer to the six months ended June 30, 2018 and the six months ended June 30, 2017, respectively, unless otherwise indicated.

Operating Activities. Net cash provided by operating activities was $291.5 million for 2018, compared to $72.0 million of net cash provided by operating activities for 2017. Production increased 5.3 MMBoe (approximately 146%) and average realized sales prices increased to $49.38 per Boe for 2018 compared to $33.95 per Boe during 2017. The overall period-to-period increase in net cash provided by operating activities was also impacted by higher G&A, LOE and other expenses due to the growth of the Company, as previously discussed above under “Results of Operations.” Net cash provided by operating activities included $50.1 million of cash payments on derivative instruments during 2018 compared to $1.1 million in cash receipts during 2017. There was a $1.3 million increase in cash flow attributable to the timing of cash receipts and disbursements related to operating activities during 2018 compared to 2017.

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~~Investing~~Nine ~~Activities.~~Months ~~During~~Ended ~~2018~~September ~~and 2017~~30, cash flows used in investing activities were $425.1 million and $764.8 million, respectively. We received $206.4 million of net proceeds related to the NLA Divestiture. See “—Recent Developments” for additional information on the NLA Divestiture. Acquisitions of oil and gas properties were $19.9 million and $547.4 million during 2018 ~~and~~Compared ~~2017, respectively. In June 2017, we completed the Acquisition for cash consideration of $533.6 million. Additions~~ to ~~oil and gas properties were $578.7 million and $211.3 million during 2018 and 2017, respectively, related to our drilling and completion activities and land leasing activities in~~ the ~~Eagle~~Nine ~~Ford~~Months ~~and~~Ended ~~Austin~~September ~~Chalk. Additions to and acquisitions of other property and equipment were $25.0 million and $6.2 million during 2018 and 2017~~30, respectively. Approximately $18.3 million of the $25.0 million in additions to and acquisitions of other property and equipment during 2018 was related to the acquisition and development of our in-field sand mine. In 2018, we have $7.9 million of unapplied construction deposits related to the development of our in-field sand mine.2017

~~Financing~~For ~~Activities.~~purposes ~~Net cash provided by financing activities during 2018~~ of ~~$152.5 million was primarily attributable to proceeds of $204.0 million from~~ the ~~April~~following ~~2018 issuance of our 2025 Senior Notes~~discussion, ~~offset~~references by net payments of approximately $37.4 million associated with our revolving credit facility. During 2018 we also paid $6.8 million in preferred stock dividends. We withheld $4.1 million for tax payment remittance to ~~appropriate taxing authorities related to the scheduled May~~ 2018 ~~vesting~~and of2017 ~~the~~refer ~~2016 LTIPs. The restricted common shares were net-settled~~ to ~~cover~~ the ~~required~~nine ~~withholding~~months ~~tax~~ended ~~upon~~September ~~vesting. Net~~30, ~~cash~~2018 ~~provided~~and ~~by financing activities during 2017 of $704.2 million was primarily attributable to $432.6 million in net proceeds from~~ the ~~issuance~~nine ofmonths ~~preferred~~ended ~~stock~~September 30, ~~$347.4 million as a result of proceeds from the February~~ 2017 ~~senior notes offering~~, $34.5 million in proceeds from the partial exercise of the underwriters’ over-allotment option in connection with our initial public offering and offset by $96.8 million in net payments under our revolving credit facility. These cash inflows were further offset by credit facility debt issuance costs of $10.8 millionrespectively, ~~and~~unless ~~$2.7~~otherwise 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 2017indicated.

Operating Activities. Net cash provided by operating activities was $447.4 million for 2018 compared to $143.2 million of net cash provided by operating activities for 2017. Production increased 6.5 MMBoe (approximately 92%) and average realized sales prices increased to $52.11 per Boe for 2018 compared to $35.08 per Boe during 2017. The overall period-to-period increase in net cash provided by operating activities was also impacted by higher G&A, LOE and other expenses due to the growth of the Company, as previously discussed above under “Results of Operations.” Net cash provided by operating activities included $81.2 million of cash payments on derivative instruments during 2018 compared to $6.9 million in cash receipts during 2017. There was a $9.9 million increase in cash flow attributable to the timing of cash receipts and disbursements related to operating activities during 2018 compared to 2017.

Investing Activities. During 2018 and 2017, cash flows used in investing activities were $741.3 million and $1,002.3 million, respectively. We received $206.4 million of net proceeds related to the NLA Divestiture. See “—Recent Developments” for additional information on the NLA Divestiture. Acquisitions of oil and gas properties were $53.2 million and $549.0 million during 2018 and 2017, respectively. In June 2017, we completed the Acquisition for cash consideration of $533.6 million. Additions to oil and gas properties were $824.7 million and $443.2 million during 2018 and 2017, respectively, related to our drilling and completion activities and land leasing activities in the Eagle Ford and Austin Chalk. Additions to and acquisitions of other property and equipment were $58.0 million and $10.1 million during 2018 and 2017, respectively. Approximately $44.0 million of the $58.0 million in additions to and acquisitions of other property and equipment during 2018 was related to the acquisition and development of our in-field sand mine. In 2018, we have $1.7 million of unapplied construction deposits related to the development of our in-field sand mine. In 2018, we have also recorded at $10.2 million contribution related to our midstream solution equity method investee, JWH Midstream LLC.

Financing Activities. Net cash provided by financing activities during 2018 of $295.5 million was primarily attributable to proceeds of $204.0 million from the April 2018 issuance of our 2025 Senior Notes and net advancements of approximately $112.6 million associated with our revolving credit facility. During 2018 we also paid $13.5 million in preferred stock dividends and had debt issuance costs of $3.5 million. We withheld $4.2 million for tax payment remittance to appropriate taxing authorities primarily related to the scheduled May 2018 vesting of the 2016 LTIP awards. The restricted common shares were net-settled to cover the required withholding tax upon vesting.

Net cash provided by financing activities during 2017 of $861.0 million was primarily attributable to $432.3 million in net proceeds from the issuance of preferred stock, $494.7 million as a result of proceeds from the 2017 issuances of our 2025 Senior Notes, $34.5 million in proceeds from the partial exercise of the underwriters’ over-allotment option in connection with our initial public offering and offset by $84.3 million in net payments under our revolving credit facility. These cash inflows were further offset by credit facility debt issuance costs of $13.5 million associated with the underwriters’ exercise of their over-allotment option and $2.7 million of costs related to our initial public offering which were previously accrued and cash settled during 2017.

Contractual Obligations

During the ~~six~~nine months ended ~~June~~September 30, 2018, there were no significant changes in our consolidated contractual obligations from those reported in our 2017 Form 10-K except for:

· indebtedness under our revolving credit facility ~~decreased~~increased from $286.4 million at December 31, 2017 to $~~249~~399.0 million at ~~June~~September 30, 2018;

· a newly executed office ~~lease~~leases which increased lease commitments from $4.4 million to an estimated $17.29 million;

the issuance of the April Notes; and

the assignment of a gas transportation agreement to Tanos associated with the NLA Divestiture.

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Off–Balance Sheet Arrangements

As of ~~June~~September 30, 2018, 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 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.

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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.

Interest Rate Risk

At ~~June~~September 30, 2018, we had $~~249~~399.0 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 issuance cost) is compared to the estimated fair value in the table below (in thousands):

	At June 30, 2018
	At September 30, 2018
	Carrying Amount		Estimated Fair Value
2025 Senior Notes, fixed-rate due February 2025	$	686,~~609~~997	$	~~713~~722,~~160~~750

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.

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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 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 September 30, 2018.

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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, 2018.

Changes in Internal Controls Over Financial Reporting

There were no changes in our internal control over financial reporting during the quarter ended ~~June~~September 30, 2018 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~~September 30, 2018. For additional discussion of current legal proceedings, please see “Note 18—Commitments and Contingencies” of the Notes to Unaudited Condensed Consolidated 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 and the risk factors set forth below, you should carefully consider the factors discussed in Part I—Item IA. “Risk Factors” of our 2017 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 2017 Form 10-K.~~

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Set forth below are certain material changes to the Risk Factors disclosed in our 2017 Form 10-K:

Our merger with Chesapeake is subject to conditions, including certain conditions that may not be satisfied, or completed on a timely basis, if at all. Failure to complete the merger with Chesapeake could have a material and adverse effect on us.

Completion of our merger with Chesapeake is subject to a number of conditions set forth in our merger agreement with Chesapeake, including the approval by Chesapeake’s shareholders of the issuance of shares of its common stock as merger consideration and approval by Company stockholders of the adoption of the merger agreement, which make the completion and timing of the consummation of the merger uncertain. Also, either we or Chesapeake may terminate the merger agreement if the merger has not been consummated by May 31, 2019 (or, at either party’s discretion, if any governmental entity having jurisdiction over either us or Chesapeake has issued any order, decree, ruling or injunction or taken any other action permanently restraining, enjoining or otherwise prohibiting the consummation of the merger).

If the transactions contemplated by the merger agreement are not completed, our ongoing business may be adversely affected and, without realizing any of the benefits of having completed the transactions, we will be subject to a number of risks, including the following:

we will be required to pay our costs relating to the transactions, such as legal, accounting, financial advisory and printing fees, whether or not the transactions are completed;

time and resources committed by our management to matters relating to the transactions could otherwise have been devoted to pursuing other beneficial opportunities, and our ongoing business and financial results may be adversely affected;

the market price of our common stock could decline to the extent that the current market price reflects a market assumption that the transactions will be completed;

being required to pay a termination fee or expense reimbursement fee of $85 million or $25 million, respectively, under certain circumstances as provided in the merger agreement;

the manner in which customers, vendors, business partners and other third parties perceive us may be negatively impacted, which in turn could affect our marketing operations or our ability to compete for new business or obtain renewals in the marketplace more broadly;

we may experience negative reactions from employees; and

if the merger agreement is terminated and our board of directors seeks another transaction, our shareholders cannot be certain that we will be able to find a party willing to enter into a transaction at a value to stockholders equal to the merger with Chesapeake.

The exchange ratio is fixed and will not be adjusted in the event of any change in either our or Chesapeake’s stock price.

At the effective time of the merger with Chesapeake, each share of our common stock outstanding immediately prior to the effective time will be converted into the right to receive 5.989 shares of Chesapeake common stock or 5.336 shares of Chesapeake common stock and $3.00, at the election of each of our stockholders. This exchange ratio will not be adjusted for changes in the market price of either our common stock or Chesapeake’s common stock between the date of signing the merger agreement and completion of the merger with Chesapeake. Changes in the price of Chesapeake’s common stock prior to the merger with Chesapeake will affect the value of Chesapeake’s common stock that our stockholders will receive on the date of such merger.

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The prices of Chesapeake’s common stock and our common stock at the closing of the merger with Chesapeake may vary from their prices on the date the merger agreement was executed and on the date of each special meeting in connection with the merger. As a result, the value represented by the exchange ratio may also vary, and you will not know or be able to calculate the market value of the merger consideration you will receive upon completion of the merger with Chesapeake.

The merger agreement limits our ability to pursue alternatives to the merger with Chesapeake.

The merger agreement entered into with Chesapeake contains provisions that may discourage a third party from submitting a competing proposal that might result in greater value to our stockholders than the merger with Chesapeake, or may result in a potential competing acquirer of the Company, proposing to pay a lower per share price to acquire us than it might otherwise have proposed to pay. These provisions include a general prohibition on us from soliciting or, subject to certain exceptions relating to the exercise of fiduciary duties by our board, entering into discussions with any third party regarding any competing proposal or offer for a competing transaction.

We will be subject to business uncertainties while the merger with Chesapeake is pending, which could adversely affect our businesses.

Uncertainty about the effect of the merger with Chesapeake on employees and customers may have an adverse effect on the Company. These uncertainties may impair our ability to attract, retain and motivate key personnel until such merger is completed and for a period of time thereafter and could cause customers and others that deal with us to seek to change their existing business relationships with us. Retention of our employees may be particularly challenging during the pendency of the merger, as employees may experience uncertainty about their roles with Chesapeake following such merger. In addition, the merger agreement restricts us from entering into certain corporate transactions and taking other specified actions without the consent of Chesapeake, and generally requires us to continue our operations in the ordinary course, until completion of the merger with Chesapeake. These restrictions may prevent us from pursuing attractive business opportunities that may arise prior to the completion of such merger.

We and Chesapeake will incur substantial transaction fees and costs in connection with the proposed merger.

We and Chesapeake expect to incur a number of non-recurring transaction-related costs associated with completing the proposed merger, combining the operations of the two organizations and achieving desired synergies. These fees and costs may be substantial. Non-recurring transaction costs include, but are not limited to, fees paid to legal, financial and accounting advisors, filing fees and printing costs. Many of these costs will be borne by us even if the merger with Chesapeake is not completed.

We and Chesapeake may be targets of securities class action and derivative lawsuits which could result in substantial costs and may delay or prevent the proposed merger from being completed.

Securities class action lawsuits and derivative lawsuits are often brought against public companies that have entered into merger agreements. Even if the lawsuits are without merit, defending against these claims can result in substantial costs and divert management time and resources. An adverse judgment could result in monetary damages, which could have a negative impact on our and Chesapeake’s respective liquidity and financial condition. Additionally, if a plaintiff is successful in obtaining an injunction prohibiting completion of the merger with Chesapeake, then that injunction may delay or prevent such merger from being completed, which may adversely affect our and Chesapeake’s respective businesses, financial position and results of operations.

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

(a)

Recent sales of unregistered equity securities.

We did not have any sales of unregistered equity securities during the three months ended ~~June~~September 30, 2018.

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(b)

Use of proceeds.

None.

(c)

Purchases of equity securities by the issuer and affiliated purchasers.

Period	Total Number of Shares Purchased		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans
						(in thousands)
Restricted Share Repurchases (1)
April 1, 2018-April 30, 2018		—	$	—	n/a	n/a
July 1, 2018 - July 31, 2018		277	$	22.40	n/a	n/a
May 1, 2018-May 31, 2018		149,060	$	27.07	n/a	n/a
August 1, 2018 - August 31, 2018		2,834	$	21.74	n/a	n/a
June 1, 2018-June 30, 2018		—	$	—	n/a	n/a
September 1, 2018 - September 30, 2018		—	$	—	n/a	n/a

(1)

Restricted common shares are generally net-settled by shareholders to cover the required withholding tax upon vesting. See Note 11 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this Quarterly Report.

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ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

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

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

ExhibitNumber		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).
2.4		Purchase and Sale Agreement, dated February 12, 2018, by and between WildHorse Resources II, LLC and Tanos Energy Holdings III, LLC (incorporated by reference to Exhibit 2.1 to the Company’s Form 8-K filed on February 15, 2018).
2.4**		Purchase and Sale Agreement, dated February 12, 2018, by and between WildHorse Resources II, LLC and Tanos Energy Holdings III, LLC (incorporated by reference to Exhibit 2.1 to the Company’s Form 8-K filed on February 15, 2018).
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 22, 2016).
3.2		Amended and Restated Bylaws of WildHorse Resource Development Corporation, effective December 19, 2016 (incorporated by reference to Exhibit 3.2 to the Company’s Form 8-K filed on December 22, 2016).
3.3		Certificate 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 4.1 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).

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ExhibitNumber		Description
2.5**		Agreement and Plan of Merger by and among Chesapeake Energy Corporation, Coleburn Inc. and WildHorse Resource Development Corporation, dated as of October 29, 2018 (incorporated by reference to Exhibit 2.1 to the Company’s Form 8-K filed on October 30, 2018).
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 22, 2016).
3.2		Amended and Restated Bylaws of WildHorse Resource Development Corporation, effective December 19, 2016 (incorporated by reference to Exhibit 3.2 to the Company’s Form 8-K filed on December 22, 2016).
3.3		Certificate 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 4.1 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*		Third Supplemental Indenture, dated as of August 2, 2018 among WHCC Infrastructure LLC, WildHorse Resource Development Corporation, the other subsidiary guarantors named therein and U.S. Bank national Association, as Trustee.
4.6		Third Supplemental Indenture, dated as of August 2, 2018 among WHCC Infrastructure LLC, WildHorse Resource Development Corporation, the other subsidiary guarantors named therein and U.S. Bank national Association, as Trustee (incorporated by reference to Exhibit 4.6 to the Company’s Form 10-Q filed on August 9, 2018).
4.7		Second Supplemental Indenture, dated as of January 8, 2018 among Burleson Sand LLC, WildHorse Resource Development Corporation, the other subsidiary guarantors named therein and U.S. Bank national Association, as Trustee (incorporated by reference to Exhibit 4.6 to the Company’s Form 10-K filed on March 12, 2018).
4.8		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 (incorporated by reference to Exhibit 4.6 to the Company’s Form 10-Q filed on August 10, 2017).
4.9		Registration Rights Agreement, dated as of September 19, 2017, by and among WildHorse Resource Development Corporation, the subsidiary guarantors named therein and Wells Faro 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 September 20, 2017).
4.10		Registration Rights Agreement, dated as of April 20, 2018, by and among WildHorse Resource Development Corporation, the subsidiary guarantors named therein and Wells Fargo Securities, LLC (incorporated by reference to Exhibit 4.3 to the Company’s Form 8-K filed on April 23, 2018).
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

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Exhibit Number		Description

4.10		Registration Rights Agreement, dated as of April 20, 2018, by and among WildHorse Resource Development Corporation, the subsidiary guarantors named therein and Wells Fargo Securities, LLC (incorporated by reference to Exhibit 4.3 to the Company’s Form 8-K filed on April 23, 2018).

10.1*		Fifth Amendment to Credit Agreement, dated as of October 15, 2018, 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.

10.2		Voting and Support Agreement, by and among Jay Carlton Graham, Esquisto Holdings, LLC, WHE AcqCo Holdings, LLC, WHR Holdings, LLC, NGP XI US Holdings, L.P., Chesapeake Energy Corporation and WildHorse Resource Development Corporation, dated as of October 29, 2018 (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on October 30, 2018).

10.3		Voting and Support Agreement, by and among CP VI Eagle Holdings, L.P., Chesapeake Energy Corporation and WildHorse Resource Development Corporation, dated as of October 29, 2018 (incorporated by reference to Exhibit 10.2 to the Company’s Form 8-K filed on October 30, 2018).

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.

95.1*		Mine Safety Disclosure Exhibit

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.

53** Schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The Company hereby undertakes to furnish

supplemental copies of any of the omitted schedules upon request by the SEC.

Table of Contents

SIGNATURES

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.

	WildHorse Resource Development Corporation
	(Registrant)
Date: August 9, 2018	By:	/s/ Andrew J. Cozby
Date: November 8, 2018	By:	/s/ Andrew J. Cozby
	Name:	Andrew J. Cozby
	Title:	Executive Vice President and Chief Financial Officer

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