10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

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

For the fiscal year ended December 31, 2018

OR

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

Commission File Number: 001-37964

BRAZOS VALLEY LONGHORN, L.L.C.

(Successor in interest to WildHorse Resource Development Corporation)

(Exact name of Registrant as specified in its Charter)

Delaware	83-3294278
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
6100 N. Western Avenue, Oklahoma City, OK	73118
(Address of principal executive offices)	(Zip Code)

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

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

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

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

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

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

Indicate by check mark whether the Registrant has submitted electronically every Interactive Data File required to be submitted 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 such files).    Yes   ☒     No   ☐

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405) is not contained herein, and will not be contained, to the best of Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.   ☒

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

Large accelerated filer	☐	Accelerated filer	☐
Non-accelerated filer	☒	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   ☒

The registrant is a wholly owned subsidiary of Chesapeake Energy Corporation and meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and is therefore filing this Form with the reduced disclosure format as permitted by Instruction I(2).

As of March 4, 2019,  Chesapeake owns 100% of the outstanding LLC units of Brazos Valley Longhorn, L.L.C., the successor company to WildHorse Resource Development Corporation.

BRAZOS VALLEY LONGHORN, L.L.C.

(Successor in interest to WildHorse Resource Development Corporation)

TABLE OF CONTENTS

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

GLOSSARY OF OIL AND NATURAL GAS TERMS

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

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 ratio reflects an energy content equivalency and not a price or revenue equivalency. Despite holding this ratio constant at six mcf to one bbl, prices have historically often been higher or substantially higher for oil than natural gas on an energy equivalent basis, although there have been periods in which they have been lower or substantially lower.

Boe/d: One Boe per day.

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

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

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

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.

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

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

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

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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.

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.

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

Play: A geographic area with hydrocarbon potential.

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

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

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

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

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

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

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

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

Proved properties: Properties with proved reserves.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Unproved properties: Properties with no proved reserves.

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

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

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

WTI: West Texas Intermediate.

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Commonly Used Defined Terms

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

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

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

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

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

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

· “Esquisto I” refers to Esquisto Resources, LLC;

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

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

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

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

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

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

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

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

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

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

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

· “North Louisiana Acreage” refers to acreage in North Louisiana in and around the highly prolific Terryville Complex, which was historically owned and operated by WHR II, and where we primarily targeted the overpressured Cotton Valley play until it was sold in March 2018;

· “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;

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

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

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

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

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

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FORWARD–LOOKING STATEMENTS

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

Forward-looking statements may include statements about:

· the effects of the Merger;

· 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;

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· uncertainty regarding our future operating results; and

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

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

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

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

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

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

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PART I

ITEM 1.     BUSINESS

Overview

We operate in one reportable segment engaged in the acquisition, exploration, 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 Trend.

Recent Developments

Merger with Chesapeake Energy Corporation

In February 2019, we were acquired by Chesapeake for approximately 717.3 million shares of Chesapeake common stock and $381.1 million in cash. Immediately following the completion of the acquisition, WildHorse Development merged with and into Brazos Valley Longhorn, L.L.C., a newly formed Delaware limited liability company and wholly owned subsidiary of Chesapeake. Following the completion of the Merger on February 1, 2019, Brazos Valley Longhorn, L.L.C., as successor to WildHorse Development, was a wholly owned subsidiary of Chesapeake.

Amendments to Credit Agreement

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

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

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.

WildHorse Senior Notes

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

The 2025 Senior Notes are the senior unsecured obligations of Brazos Valley Longhorn, L.L.C., BVL Finance Corp. and the other BVL Guarantors. The 2025 Senior Notes will not be obligations of Chesapeake or any of its subsidiaries other than Brazos Valley Longhorn, L.L.C., BVL Finance Corp. and the other BVL Guarantors. The 2025 Senior Notes will rank equally in right of payment with all other senior unsecured indebtedness of Brazos Valley Longhorn, L.L.C., BVL Finance Corp. and the other BVL Guarantors, and will be effectively subordinated to Brazos Valley Longhorn L.L.C.’s, BVL Finance Corp.’s and the other BVL Guarantors’ senior secured indebtedness, including their obligations

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under WildHorse Development’s revolving credit facility, to the extent of the value of the collateral securing such indebtedness.

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

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

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

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

Development of In-field Sand Mine

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

Our Properties

Eagle Ford Acreage

We currently target a portion of the Eagle Ford Shale at depths between 6,000 feet and 13,000 feet primarily in Burleson, Lee, Brazos and Washington Counties, Texas.

We have completed multiple bolt-on acquisitions and in-fill leases to build our current position in the Eagle Ford Shale and have identified a substantial inventory of drilling locations across Burleson, Brazos, Lee, Robertson and Washington Counties.

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

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Reserve Data

Preparation of Reserve Estimates

Our reserve estimates as of December 31, 2018 included in this Annual Report are based on evaluations prepared by Cawley, Gillespie & Associates, Inc. (“CG&A”), a third-party engineering firm in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Evaluation Engineers and definitions and guidelines established by the SEC.

Proved reserves are reserves which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. If deterministic methods are used, the term “reasonable certainty” implies a high degree of confidence that the quantities of oil or natural gas actually recovered will equal or exceed the estimate. If probabilistic methods are used, there should at least be a 90% probability that the quantities actually recovered will equal or exceed the estimate. The technical and economic data used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps, well-test data, production data (including flow rates), well data (including lateral lengths), historical price and cost information, and property ownership interests. Reserve engineers use this technical data, together with standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, and analogy. The proved developed reserves and EURs per well are estimated using performance analysis and volumetric analysis. The estimates of the proved developed reserves and EURs for each developed well are used to estimate the proved undeveloped reserves for each proved undeveloped location (utilizing type curves, statistical analysis, and analogy).

Internal Controls

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

Reserve engineering is and must be recognized as a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil, natural gas and NGLs that are ultimately recovered. Estimates of economically recoverable oil, natural gas and NGLs and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs. Please read “Item 1A. Risk Factors” appearing elsewhere in this Annual Report.

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

· Over 15 years of practical experience in the oil and gas industry, with 12 years in reservoir engineering;

· Bachelor of Science degree in Geology and Environmental Sciences;

· Master’s Degree in Petroleum and Natural Gas Engineering;

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· Executive Master of Business Administration; and

· Member in good standing of the Society of Petroleum Engineers.

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

Estimated Proved Reserves

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

	Oil	Natural Gas	NGLs	Total
	(MBbls)	(MMcf)	(MBbls)	(MBoe)
Estimated Proved Reserves
Total Proved Developed	66,398	88,936	14,135	95,356
Total Proved Undeveloped	218,868	289,237	43,620	310,694
Total Proved Reserves	285,266	378,173	57,755	406,050

Development of Proved Undeveloped Reserves

As of December 31, 2018, we had 310.7 MMBoe of proved undeveloped reserves consisting of 218.9 MMBbls of oil, 289.2 Bcf of natural gas and 43.6 MMBbls of NGLs, compared to 339.8 MMBoe of proved undeveloped reserves at December 31, 2017, consisting of 217.8 MMbbls of oil, 462.3 Bcf of natural gas and 45.0 MMBbls of NGLs. None of our PUDs as of December 31, 2018 are scheduled to be developed on a date more than five years from the date the reserves were initially booked to PUDs. PUDs will be converted from undeveloped to developed as the applicable wells begin production.

Our PUDs changed during 2018 as a result of:

· downward performance and price revisions of 69.1 MMBoe;

· acquisitions of 0.5 MMBoe;

· divestures of 40.0 MMBoe;

· reserve additions of 86.8 MMBoe; and

· transfers to proved developed producing of 7.3 MMBoe

We estimate that we incurred $80.9 million to convert proved undeveloped reserves from 13 locations into proved developed reserves in 2018.

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Production, Revenue and Price History

The following tables summarize our average net production, average unhedged sales prices by product and average production costs by geographic region for the years ended December 31, 2018, 2017 and 2016, respectively:

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

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

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

Reconciliation of PV‑10 to Standardized Measure

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

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

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

Productive Wells

Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we own an interest, and net wells are the sum of our fractional working interests owned in gross wells. The following table sets forth information relating to the productive wells in which we owned a working interest as of December 31, 2018.

	Oil			Natural Gas
			Average			Average
	Gross	Net	Working	Gross	Net	Working
	Wells	Wells	Interest	Wells	Wells	Interest
Eagle Ford Acreage
Operated	942.0	901.7	95.7%	53.0	48.0	90.6%
Non-operated	212.0	30.9	14.6%	30.0	6.3	21.0%
Total	1,154.0	932.6	80.8%	83.0	54.3	65.4%

Acreage

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

	Developed Acres		Undeveloped Acres		Total Acres
Region	Gross	Net	Gross	Net	Gross	Net
Eagle Ford Acreage	33,106	28,066	438,141	297,605	471,247	325,671

Approximately 74% of our net Eagle Ford Acreage was held by production at December 31, 2018.

Undeveloped Acreage Expirations

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

Region	2019	2020	2021	2022	2023
Eagle Ford Acreage	31,031	27,616	12,434	552	20

We intend to extend substantially all of the net acreage associated with our drilling locations through a combination of development drilling and leasehold extension and renewal payments.

Drilling Activities

The following table summarizes our approximate gross and net interest in wells completed during the periods indicated (including both operated and non-operated wells), regardless of when drilling was initiated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation

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

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

At December 31, 2018, 27.0 gross (25.9 net) wells (including wells temporarily suspended) were in the process of being drilled. We are currently running a four-rig program in our Eagle Ford Acreage, which we are utilizing on a well-to-well basis. We are not currently a party to any long-term drilling rig contracts. We plan to operate an average of four drilling rigs in the Eagle Ford Shale and Austin Chalk Trend in 2019.

Major Customers

The following table sets forth the percentage of our revenues attributed to our customers who have accounted for 10% or more of our revenues during 2018, 2017 and 2016.

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

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

Competition

We compete with both major integrated and other independent oil and natural gas companies in all aspects of our business to explore, develop and operate our properties and market our production. Some of our competitors may have larger financial and other resources than us. Competitive conditions may be affected by future legislation and regulations as the United States develops new energy and climate-related policies. In addition, some of our competitors may have a competitive advantage when responding to factors that affect demand for oil and natural gas production, such as changing prices, domestic and foreign political conditions, weather conditions, the price and availability of alternative fuels, the proximity and capacity of natural gas pipelines and other transportation facilities and overall economic conditions. We also face indirect competition from alternative energy sources, including wind and solar power. We believe that our

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

Seasonality of Business

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

Title to Properties

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

Public Policy and Government Regulation

All of our operations are conducted onshore in the United States. Our industry is subject to a wide range of regulations, laws, rules, taxes, fees and other policy implementation actions that have been pervasive and are under constant review for amendment or expansion. Numerous government agencies have issued extensive regulations which are binding on our industry, some of which carry substantial penalties for failure to comply. These laws and regulations increase the cost of doing business and consequently affect profitability. Additionally, currently unforeseen environmental incidents may occur or past non-compliance with environmental laws or regulations may be discovered.  We actively monitor regulatory developments applicable to our industry in order to anticipate, design and implement required compliance activities and systems.  The following are significant areas of government control and regulation affecting our operations.

Regulation of Environmental and Occupational Safety and Health Matters

Our operations are subject to federal, tribal, state, and local laws and regulations. These laws and regulations relate to matters that include, but are not limited to, the following:

Ÿ reporting of workplace injuries and illnesses;

Ÿ industrial hygiene monitoring;

Ÿ worker protection and workplace safety;

Ÿ mine safety;

Ÿ approval or permits to drill and to conduct operations;

Ÿ provision of financial assurances (such as bonds) covering drilling and well operations;

Ÿ calculation and disbursement of royalty payments and production taxes;

Ÿ seismic operations and data;

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Ÿ location, drilling, cementing and casing of wells;

Ÿ well design and construction of pad and equipment;

Ÿ construction and operations activities in sensitive areas, such as wetlands, coastal regions or areas that contain endangered or threatened species, their habitats, or sites of cultural significance;

Ÿ method of completing wells;

Ÿ hydraulic fracturing;

Ÿ water withdrawal;

Ÿ well production and operations including processing and gathering systems;

Ÿ emergency response, contingency plans and spill prevention plans;

Ÿ air emissions and fluid discharges;

Ÿ climate change;

Ÿ use, transportation, storage and disposal of fluids and materials incidental to oil and gas operations;

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

Ÿ plugging and abandoning of wells; and

Ÿ transportation of production.

Failure to comply with these laws and regulations can lead to the imposition of remedial liabilities, fines, or criminal penalties or to injunctions limiting our operations in affected areas. Moreover, multiple environmental laws provide for citizen suits which allow environmental organizations to act in the place of the government and sue operators for alleged violations of environmental law. We consider the costs of environmental protection and of safety and health compliance to be necessary, manageable parts of our business. We have been able to plan for and comply with environmental, safety and health initiatives without materially altering our operating strategy or incurring significant unreimbursed expenditures. However, based on regulatory trends and increasingly stringent laws, our capital expenditures and operating expenses related to compliance with the protection of the environment, safety and health have increased over the years and may continue to increase. We cannot predict with any reasonable degree of certainty our future exposure concerning such matters.

Our operations are also subject to conservation regulations, including the regulation of the size of drilling and spacing units or proration units, the number of wells that may be drilled in a unit, the rate of production allowable from oil and gas wells, and the unitization or pooling of oil and gas properties. In the United States., some states allow the forced pooling or integration of tracts to facilitate exploration.  Other states rely on voluntary pooling of lands and leases which may make it more difficult to develop oil and gas properties. In addition, federal and state conservation laws generally limit the venting or flaring of natural gas, and state conservation laws impose certain requirements regarding the ratable purchase of production. These regulations limit the amounts of oil and gas we can produce from our wells and the number of wells or the locations at which we can drill.

Regulatory proposals in some states and local communities have been initiated to require or make more stringent the permitting and compliance requirements for hydraulic fracturing operations.  Federal and state agencies have continued to assess the potential impacts of hydraulic fracturing, which could spur further action toward federal, state and/or local

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legislation and regulation.  Further restrictions of hydraulic fracturing could reduce the amount of oil, natural gas and natural gas liquids (NGLs) that we are ultimately able to produce in commercial quantities from our properties.

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

Delays in obtaining permits or an inability to obtain new permits or permit renewals could inhibit our ability to execute our drilling and production plans. Failure to comply with applicable regulations or permit requirements could result in revocation of our permits, inability to obtain new permits and the imposition of fines and penalties.

Related Permits and Authorizations

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

Related Insurance

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

Employees

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

Legal Proceedings

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

In January 2019, putative class action lawsuits in U.S. District Courts for the District of Delaware and Southern District of New York were filed against us and other defendants. The lawsuits generally allege various violations of the Securities Exchange Act of 1934 in connection with the disclosure contained in the joint proxy statement/prospectus filed in connection with the Merger. The lawsuits seek rescission of the Merger or rescissory damages and, in each case, attorney's fees, costs and interest. We intend to vigorously defend these claims.

Due to the nature of our business, we are, from time to time, involved in other routine litigation or subject to disputes or claims related to our business activities, including workers' compensation claims and employment related disputes. In the opinion of our management, none of these other pending litigation, disputes or claims against us, if decided adversely, will have a material adverse effect on our financial condition, cash flows or results of operations.

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Offices

Our principal executive office is located at 6100 N. Western Avenue, Oklahoma City, OK 73118. Our main telephone number is (405) 848-8000.

Available Information

Our annual reports on Form 10‑K, quarterly reports on Form 10‑Q, current reports on Form 8–K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are available on the SEC's website at www.sec.gov.

ITEM 1A.     RISK FACTORS

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

Risks Related to Our Business

Oil, natural gas and NGL prices fluctuate widely, and lower prices for an extended period of time are likely to have a material adverse effect on our business.

Our revenues, operating results, profitability, liquidity and ability to grow depend primarily upon the prices we receive for the oil, natural gas and NGL we sell. We incur substantial expenditures to replace reserves, sustain production and fund our business plans. Low oil, natural gas and NGL prices can negatively affect the amount of cash available for capital expenditures, debt service and debt repayment and our ability to borrow money and, as a result, could have a material adverse effect on our financial condition, results of operations, cash flows and reserves. In addition, periods of low oil and natural gas prices may result in impairments of our oil and natural gas properties.

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

· domestic and worldwide supplies of oil, natural gas and NGL, including U.S. inventories of oil and natural gas reserves;

· weather conditions;

· changes in the level of consumer and industrial demand;

· the price and availability of alternative fuels;

· technological advances affecting energy consumption;

· the effectiveness of worldwide conservation measures;

· the availability, proximity and capacity of pipelines, other transportation facilities and processing facilities;

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· the level and effect of trading in commodity futures markets, including by commodity price speculators and others;

· U.S. exports of oil, natural gas, liquefied natural gas and NGL;

· the price and level of foreign imports;

· the nature and extent of domestic and foreign governmental regulations and taxes;

· the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

· political instability or armed conflict in oil and natural gas producing regions;

· acts of terrorism; and

· domestic and global economic conditions.

These factors and the volatility of the energy markets make it extremely difficult to predict future oil, natural gas and NGL price movements with any certainty. Even with oil, natural gas and NGL derivatives currently in place to mitigate price risks associated with a portion of our 2019 cash flows, we have substantial exposure to oil, natural gas and NGL prices in 2020 and beyond. In addition, a prolonged extension of lower prices could reduce the quantities of reserves that we may economically produce.

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

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

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

· the prices at which our production is sold;

· our proved reserves;

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

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

· the amount of our operating expenses;

· limits on Chesapeake's ability to make investments in us contained in its credit agreement;

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· cash settlements from our derivative activities; and

· our ability to borrow under our revolving credit facility.

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

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

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

Our decisions to develop or purchase prospects or properties will depend, in part, on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, which are often inconclusive or subject to varying interpretations. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves. In addition, our cost of drilling, completing and operating wells is often uncertain.

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

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

· pressure or irregularities in geological formations;

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

· equipment failures, accidents or other unexpected operational events;

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

· lack of available capacity on interconnecting transmission pipelines;

· adverse weather conditions;

· issues related to compliance with environmental regulations;

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

· declines in oil and natural gas prices;

· limited availability of financing on acceptable terms;

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· title issues; and

· other market limitations in our industry.

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

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

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

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

The terms and conditions governing our indebtedness:

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

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

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

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

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

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· limit management's discretion in operating our business.

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

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

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

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

Increases in interest rates could adversely affect our business.

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

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

In order to manage our exposure to price volatility, we enter into oil, natural gas and NGL price derivative contracts. Our oil, natural gas and NGL derivative arrangements may limit the benefit we would receive from increases in commodity prices. The fair value of our oil, natural gas and NGL derivative instruments can fluctuate significantly between periods. Our decision to mitigate cash flow volatility through derivative arrangements, if any, is based in part on our view of current and future market conditions and our desire to stabilize cash flows necessary for the development of our proved reserves. We may choose not to enter into derivatives if the pricing environment for certain time periods is not deemed to be favorable. Additionally, we may choose to liquidate existing derivative positions prior to the expiration of their contractual maturities to monetize gain positions for the purpose of funding our capital program.  As of December 31, 2018, we had entered into swaps and deferred premium puts through December 2020 covering a total of 12.9 MMBbls of our projected oil production and 11.3 TBtu of our projected natural gas production. Accordingly, our earnings may fluctuate significantly as a result of changes in fair value of our derivative instruments.

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

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

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

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

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

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

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

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

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

The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of our reserves. In order to prepare reserve estimates, we must project production rates and timing of

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

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

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

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

Standardized measure is a reporting convention that provides a common basis for comparing oil and natural gas companies subject to the rules and regulations of the SEC. Standardized measure requires historical twelve-month pricing as required by the SEC as well as operating and development costs prevailing as of the date of computation. Consequently, it may not reflect the prices ordinarily received or that will be received for oil and natural gas production because of varying market conditions, nor may it reflect the actual costs that will be required to produce or develop the oil and natural gas properties. As a result, estimates included herein of future net cash flow may be materially different from the future net cash flows that are ultimately received. Therefore, the Standardized measure of our estimated reserves included in this Annual Report should not be construed as accurate estimates of the current fair value of our proved reserves.

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

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

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

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

Leases on oil and natural gas properties typically have a term of three to five years, after which they expire unless, prior to expiration, a well is drilled and production of hydrocarbons in paying quantities is established. If our leases on our undeveloped properties expire and we are unable to renew the leases, we will lose our right to develop the related properties. Although we seek to actively manage our undeveloped properties, our drilling plans for these areas are subject to change based upon various factors, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals. Low commodity prices may cause us to delay our drilling plans and, as a result, lose our right to develop the related properties.

Unless we replace our reserves with new reserves and develop those new reserves, our reserves and production will decline, which would adversely affect our future cash flows and results of operations.

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

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

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

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

All of our producing properties and estimated proved reserves are geographically concentrated in the Eagle Ford Shale. As a result, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in the Eagle Ford Shale caused by governmental regulation, processing or transportation capacity constraints, market limitations, availability of equipment and personnel, water shortages or other drought related conditions or interruption of the processing or transportation of oil, natural gas or NGLs.

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The marketability of our production is dependent upon transportation and other facilities, certain of which we do not control. If these facilities are unavailable, our operations could be interrupted and our revenues reduced.

The marketability of our oil and natural gas production depends in part upon the availability, proximity and capacity of transportation facilities owned by third parties. Our oil production is transported from the wellhead to our tank batteries by our gathering systems. The oil is then transported by us or the purchaser by truck to a transportation facility. Our natural gas production is generally transported by our or third-party gathering lines from the wellhead to a gas processing facility or transmission pipeline. We do not control these trucks and other third-party transportation facilities and our access to them may be limited or denied. Insufficient production from our wells to support the construction of pipeline facilities by our purchasers or a significant disruption in the availability of our or third-party transportation facilities or other production facilities could adversely impact our ability to deliver to market or produce our oil and natural gas and thereby cause a significant interruption in our operations. If, in the future, we are unable, for any sustained period, to implement acceptable delivery or transportation arrangements or encounter production related difficulties, we may be required to shut in or curtail production. Any such shut-in or curtailment, or an inability to obtain favor able terms for delivery of the oil and natural gas produced from our fields, would materially and adversely affect our financial condition and results of operations.

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

As of December 31, 2018, approximately 76.5% of our total estimated proved reserves were classified as proved undeveloped. Development of these proved undeveloped reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Estimated future development costs relating to the development of our PUDs at December 31, 2018 are approximately $5.05 billion over the next five years. We expect to fund these expenditures through cash generated by operations, borrowings under our revolving credit facility and other sources of capital. Our ability to fund these expenditures is subject to a number of risks. Delays in the development of our reserves, increases in costs to drill and develop such reserves or decreases in commodity prices will reduce the value of our estimated PUDs and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our PUDs as unproved reserves. Furthermore, there is no certainty that we will be able to convert our PUDs to developed reserves or that our undeveloped reserves will be economically viable or technically feasible to produce.

Further, SEC rules require that, subject to limited exceptions, PUDs may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement has limited and may continue to limit our ability to book additional PUDs as we pursue our drilling program. As a result, we may be required to write down our PUDs if we do not drill those wells within the required five-year timeframe.

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

We periodically review the carrying value of our properties for possible impairment. Based on prevailing commodity prices and specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our properties. A write down constitutes a non-cash impairment charge to earnings. Lower commodity prices in the future could result in impairments of our properties, which could have a material adverse effect on our results of operations for the periods in which such charges are taken. For example, during the first quarter of 2018, we impaired our North Louisiana properties for $214.3 million, which we divested at the end of March 2018.  We could experience further material write downs as a result of lower commodity prices or other factors, including low production results or high lease operating expenses, capital expenditures or transportation fees.

The Company's sand mining operations are subject to the Federal Mine Safety and Health Act of 1977 and amending legislation, which impose stringent health and safety standards on numerous aspects of the Company's sand mining operations.

The Company's sand mining operations are subject to the Federal Mine Safety and Health Act of 1977, as amended by the Mine Improvement and New Emergency Response Act of 2006, which imposes stringent health and safety standards on numerous aspects of mineral extraction and processing operations, including the training of personnel, operating procedures, operating equipment and other matters. This Act, as amended, is a strict liability statute and any failure by the Company to comply with such existing or any future standards, or any more stringent interpretation or enforcement thereof, could have a material adverse effect on the Company's sand mining operations or otherwise impose significant restrictions on the Company's ability to conduct mineral extraction and processing operations. In addition, the Mine Safety and Health Administration ("MSHA") may propose changes in their regulations regarding workplace exposure to crystalline silica, such as permissible exposure limits and required controls and personal protective equipment. If any new rule issued by MSHA lowers the workplace exposure limit significantly, the Company could incur significant capital and operating expenditures for equipment to reduce this exposure.

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

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

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

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

· abnormally pressured formations;

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

· fires, explosions and ruptures of pipelines;

· personal injuries and death;

· natural disasters; and

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

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

· injury or loss of life;

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

· pollution and other environmental damage;

· regulatory investigations and penalties; and

· repair and remediation costs.

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

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

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

· unexpected drilling conditions;

· title issues;

· pressure or lost circulation in formations;

· equipment failures or accidents;

· adverse weather conditions;

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

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

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

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

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

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

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

Our operations are subject to extensive federal, state, tribal, local and other laws, rules and regulations, including with respect to environmental matters, worker health and safety, wildlife conservation, the gathering and transportation of oil, gas and NGLs, conservation policies, reporting obligations, royalty payments, unclaimed property and the imposition of taxes. Such regulations include requirements for permits to drill and to conduct other operations and for provision of financial assurances (such as bonds) covering drilling, completion and well operations. If permits are not issued, or if unfavorable restrictions or conditions are imposed on our drilling or completion activities, we may not be able to conduct our operations as planned. In addition, we may be required to make large, sometimes unexpected, expenditures to comply with applicable governmental laws, rules, regulations, permits or orders.

In addition, changes in public policy have affected, and in the future could further affect, our operations. Regulatory changes could, among other things, restrict production levels, impose price controls, alter environmental protection requirements and increase taxes, royalties and other amounts payable to the government. Our operating and compliance costs could increase further if existing laws and regulations are revised or reinterpreted or if new laws and regulations become applicable to our operations. We do not expect that any of these laws and regulations will affect our operations materially differently than they would affect other companies with similar operations, size and financial strength.  Although we are unable to predict changes to existing laws and regulations, such changes could significantly impact our profitability, financial condition and liquidity.  As is discussed below this is particularly true of changes related to pipeline safety, seismic activity, hydraulic fracturing, climate change and endangered species designations.

Pipeline Safety. The pipeline assets in which we own interests are subject to stringent and complex regulations related to pipeline safety and integrity management. The Pipeline and Hazardous Materials Safety Administration (PHMSA) has established a series of rules that require pipeline operators to develop and implement integrity management programs for gas, NGL and condensate transmission pipelines as well as certain low stress pipelines and gathering lines transporting hazardous liquids, such as oil, that, in the event of a failure, could affect “high consequence areas.” Additional action by PHMSA with respect to pipeline integrity management requirements may occur in the future. For example, in 2016 PHMSA proposed new rules for gas pipelines that extend pipeline safety programs beyond high consequence areas to newly proposed “moderate consequence areas or rural areas” and would also impose more rigorous testing and reporting requirements on such pipelines. Elements of a final rulemaking, commonly referred to as the “Gas Mega Rule,” continues to be deliberated by PHMSA’s Gas Pipeline Advisory Committee (GPAC).  To date, no final regulatory action has been taken. More recently, in January 2017, PHMSA finalized regulations for hazardous liquid pipelines that significantly extend and expand the reach of certain PHMSA integrity management requirements (i.e., periodic assessments, leak detection and repairs), regardless of the pipeline’s proximity to a high consequence area. The final rule also imposes new reporting requirements for certain unregulated pipelines, including all hazardous liquid gathering lines. Per direction provided via a “Regulatory Freeze” Memo published on January 20, 2017 by the Trump Administration, this final regulatory action was withdrawn and continues to be evaluated by executive leadership. In July 2018, PHMSA issued an advance notice of proposed rulemaking seeking comment on the class location requirements for natural gas transmission pipelines, and particularly the actions operators must take when class locations change due to population growth or building construction near the pipeline.  At this time, we cannot predict the cost of these requirements or other potential

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new or amended regulations, but they could be significant. Moreover, violations of pipeline safety regulations can result in the imposition of significant penalties.

Seismic Activity. Earthquakes have prompted concerns about seismic activity and possible relationships with the energy industry. Legislative and regulatory initiatives intended to address these concerns may result in additional levels of regulation or other requirements that could lead to operational delays, increase our operating and compliance costs or otherwise adversely affect our operations.

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

We cannot predict whether additional federal, state or local laws or regulations applicable to hydraulic fracturing will be enacted in the future and, if so, what actions any such laws or regulations would require or prohibit. If additional levels of regulation or permitting requirements were imposed on hydraulic fracturing operations, our business and operations could be subject to delays, increased operating and compliance costs and potential bans. Additional regulation could also lead to greater opposition to hydraulic fracturing, including litigation.

Climate Change. Continuing political and social attention to the issue of climate change has resulted in legislative, regulatory and other initiatives to reduce greenhouse gas emissions, such as carbon dioxide and methane. Policy makers at both the U.S. federal and state levels have introduced legislation and proposed new regulations designed to quantify and limit the emission of greenhouse gases through inventories, limitations and/or taxes on greenhouse gas emissions. EPA and the BLM have issued regulations for the control of methane emissions, which also include leak detection and repair requirements, for the oil and gas industry; however, following the change in presidential administrations, both agencies took actions to rescind or revise the rules.  In September 2018, BLM issued a final rule that rescinded certain requirements of its venting and flaring rule.  Similarly, in October 2018, EPA published a proposed rule that amends certain requirements of its methane rule.  The EPA rule remains in effect.  Nevertheless, several states where we operate have imposed venting and flaring limitations designed to reduce methane emissions from oil and gas exploration and production activities. Legislative and state initiatives to date have generally focused on the development of cap-and-trade and/or carbon tax programs. Cap and trade programs offer greenhouse gas emission allowances that are gradually reduced over time. A cap and trade program could impose direct costs on us through the purchase of allowances and could impose indirect costs by incentivizing consumers to shift away from fossil fuels.  A carbon tax could directly increase our costs of operation and similarly incentivize consumers to shift away from fossil fuels.

In addition, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult to secure funding for exploration and production activities.

These various legislative, regulatory and other activities addressing greenhouse gas emissions could adversely affect our business, including by imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations, which could require us to incur costs to reduce emissions of greenhouse gases associated with our operations. Limitations on greenhouse gas emissions could also adversely affect demand for oil and gas, which could lower the value of our reserves and have a material adverse effect on our profitability, financial condition and liquidity.  Furthermore, increasing attention to climate change risks has resulted in increased likelihood of governmental investigations and private litigation, which could increase our costs or otherwise adversely affect our business.

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Endangered Species. The Endangered Species Act (ESA) prohibits the taking of endangered or threatened species or their habitats. While some of our assets and lease acreage may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are in material compliance with the ESA. However, the designation of previously unidentified endangered or threatened species in areas where we intend to conduct construction activity or the imposition of seasonal restrictions on our construction or operational activities could materially limit or delay our plans.

The taxation of independent producers is subject to change, and changes in tax law could increase our cost of doing business.

We are subject to taxation by various taxing authorities at the federal, state and local levels where we do business. New legislation increasing our tax burden could be enacted by any of these governmental authorities making it more costly for us to explore for oil and natural gas resources.

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

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

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

Our business has become increasingly dependent on digital technologies to conduct certain exploration, development and production activities. We depend on digital technology to estimate quantities of oil, natural gas and NGL reserves, process and record financial and operating data, analyze seismic and drilling information, and communicate with our customers, employees and third-party partners. We have been the subject of cyber-attacks on our internal systems and through those of third parties, but these incidents did not have a material adverse impact on our results of operations. Nevertheless, unauthorized access to our seismic data, reserves information, customer or employee data or other proprietary or commercially sensitive information could lead to data corruption, communication interruption, or other disruptions in our exploration or production operations or planned business transactions, any of which could have a material adverse impact on our results of operations. If our information technology systems cease to function properly or our cybersecurity is breached, we could suffer disruptions to our normal operations, which may include drilling, completion, production and corporate functions. A cyber-attack involving our information systems and related infrastructure, or that of our business associates, could result in supply chain disruptions that delay or prevent us from transporting and marketing our production, non-compliance leading to regulatory fines or penalties, loss or disclosure of, or damage to, our or any of our customer’s or supplier’s data or confidential information that could harm our business by damaging our reputation, subjecting us to potential financial or legal liability, and requiring us to incur significant costs, including costs to repair or restore our systems and data or to take other remedial steps.

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

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Risks Associated with the Merger

We have incurred substantial transaction fees and costs in connection with the Merger.

We expect to incur a number of non-recurring transaction-related costs associated with completing the Merger, combining our operations with Chesapeake’s 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.

We may fail to realize all of the anticipated benefits of the Merger.

The success of the Merger will depend, in part, on our ability to realize the anticipated benefits and cost savings from combining Chesapeake’s and WildHorse’s businesses, including operational and other synergies that we believe the combined company will achieve. We expect that the Merger will provide substantial cost savings due to operational and capital efficiencies as a result of Chesapeake’s significant expertise with unconventional assets and technical and operational. The anticipated benefits and cost savings of the Merger may not be realized fully or at all, may take longer to realize than expected or could have other adverse effects that we do not currently foresee. Some of the assumptions that we have made, such as the achievement of operating synergies, may not be realized. The integration process may, for us and Chesapeake, result in the loss of key employees, the disruption of ongoing businesses or inconsistencies in standards, controls, procedures and policies. There could be potential unknown liabilities and unforeseen expenses associated with the Merger that were not discovered in the course of performing due diligence. The integration will require significant time and focus from management following the acquisition.

ITEM 1B.     UNRESOLVED STAFF COMMENTS

None.

ITEM 2.       PROPERTIES

Information regarding our properties is contained in Item 1. “Business”.

ITEM 3.       LEGAL PROCEEDINGS

In January 2019, putative class action lawsuits in U.S. District Courts for the District of Delaware and Southern District of New York were filed against us and other defendants. The lawsuits generally allege various violations of the Securities Exchange Act of 1934 in connection with the disclosure contained in the joint proxy statement/prospectus filed in connection with the Merger. The lawsuits seek rescission of the Merger or rescissory damages and, in each case, attorney’s fees, costs and interest. We intend to vigorously defend these claims.

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

ITEM 4.       MINE SAFETY DISCLOSURES

The information concerning mine safety violations and other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.104) is included in Exhibit 95.1 to this Annual Report on Form 10-K.

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PART II

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

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

ITEM 6.       SELECTED FINANCIAL DATA

The information called for by Item 6 is omitted pursuant to Instruction I(2) to Form 10-K (Omission of Information by Certain Wholly-Owned Subsidiaries).

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

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

Overview

In February 2019, we were acquired by Chesapeake for approximately 717.3 million shares of Chesapeake common stock and $381.1 million in cash. Immediately following the completion of the acquisition, WildHorse Development merged with and into Brazos Valley Longhorn, L.L.C., a newly formed Delaware limited liability company and wholly owned subsidiary of Chesapeake. Following the completion of the Merger on February 1, 2019, Brazos Valley Longhorn, L.L.C., as successor to WildHorse Development, was a wholly owned subsidiary of Chesapeake.  As a result of no longer being a publicly traded company, we expect to realize certain cost savings including, but not limited to, expenses associated with Exchange Act reporting; expenses associated with being listed on a national securities exchange; expenses related to investor relations; expenses related to director and officer liability insurance; and expenses related to independent director compensation.

Business and Industry Outlook

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

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

Sources of Our Revenues

Our revenues are primarily derived from the sale of our oil, natural gas, and NGL production entirely from the continental United States. For the year ended December 31, 2018, approximately 89% of our revenues was from oil sales, 6% from natural gas sales, 4% from NGL sales and less than 1% from other revenues.

Critical Accounting Policies and Estimates

Use of Estimates in the Preparation of Financial Statements

Preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. We base

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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. The most significant estimates with regard to these financial statements include:

Successful Efforts Method of Accounting for Oil and Natural Gas Activities

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

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

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

Oil and Natural Gas Reserve Quantities

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

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

Our estimates of proved reserves are based on the quantities of oil, natural gas and NGLs, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs under existing economic conditions, operating methods and government regulations

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prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Reserves and economic evaluation of all of our properties are prepared on a well-by-well basis. The accuracy of reserve estimates is a function of the:

· quality and quantity of available data;

· interpretation of that data;

· accuracy of various mandated economic assumptions; and

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

Derivative Instruments

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

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

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

Income Tax

We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the tax basis in assets and liabilities and their reported amounts in the financial statements and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. Deferred tax assets are reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of deferred tax assets will not be realized. We recognize interest and penalties accrued to unrecognized tax benefits in other income (expense) in our consolidated statement of operations.

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

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Results of Operations

	For the Year Ended December 31,
	2018		2017		2016
Revenues and other income (in thousands):
Oil sales	$	843,244	$	342,868	$	75,938
Natural gas sales		60,129		59,924		43,487
NGL sales		41,961		22,964		5,786
Other income		2,052		1,431		2,131
Total revenues and other income		947,386		427,187		127,342
Operating expenses (in thousands):
Lease operating expenses		61,620		39,770		12,320
Gathering, processing and transportation		9,856		11,897		6,581
Taxes other than income tax		52,410		24,158		6,814
Depreciation, depletion and amortization		296,685		168,250		81,757
Impairment of NLA Disposal Group		214,274		—		—
Gain on sale of properties		(2,781)		—		—
General and administrative expenses		65,710		40,663		23,973
Incentive unit compensation expense		13,776		—		—
Exploration expense		22,483		36,911		12,026
Other operating expense		1,064		73		99
Total operating expenses		735,097		321,722		143,570
Income (loss) from operations		212,289		105,465		(16,228)
Other income (expense) (in thousands):
Interest expense, net		(60,119)		(31,934)		(7,834)
Gain (loss) on derivative instruments		35,393		(55,483)		(26,771)
North Louisiana settlement		—		(7,000)		—
Other expense		(859)		8		(1,818)
Total other expense		(25,585)		(94,409)		(36,423)
Income (loss) before income taxes		186,704		11,056		(52,651)
Income tax benefit (expense)		(40,196)		38,824		5,575
Net income (loss)		146,508		49,880		(47,076)
Net loss attributable to previous owners		—		—		(2,681)
Net loss attributable to predecessor		—		—		(33,998)
Net income (loss) available to WRD	$	146,508	$	49,880	$	(10,397)
Net income (loss) per common share:
Basic and diluted	$	0.88	$	0.32	$	(0.11)
Weighted-average common shares outstanding:
Basic and diluted		99,498		96,324		91,327
Oil and natural gas revenue (in thousands):
Crude oil	$	843,244	$	342,868	$	75,938
Natural gas		60,129		59,924		43,487
NGLs		41,961		22,964		5,786
Total oil, natural gas and NGL revenue	$	945,334	$	425,756	$	125,211
Production volumes:
Oil (MBbls)		12,585		6,606		1,848
Natural gas (MMcf)		21,531		20,463		17,820
NGLs (MBbls)		2,143		1,206		471
Total (MBoe)		18,316		11,222		5,289
Average sales price:
Oil (per Bbl)	$	67.00	$	51.90	$	41.09
Natural gas (per Mcf)	$	2.79	$	2.93	$	2.44
NGLs (per Bbl)	$	19.58	$	19.04	$	12.28
Total (per Boe)	$	51.61	$	37.94	$	23.67
Average production volumes:
Oil (MBbls/d)		34.5		18.1		5.0
Natural gas (MMcf/d)		59.0		56.1		48.7
NGLs (MBbls/d)		5.9		3.3		1.3
Average net production (MBoe/d)		50.2		30.7		14.5
Average unit costs per Boe:
Lease operating expenses	$	3.36	$	3.54	$	2.33
Gathering, processing and transportation	$	0.54	$	1.06	$	1.24
Taxes other than income tax	$	2.86	$	2.15	$	1.29
General and administrative expenses	$	3.59	$	3.62	$	4.53
Depletion, depreciation and amortization	$	16.20	$	14.99	$	15.46

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Year Ended December 31, 2018 Compared to the Year Ended December 31, 2017

For purposes of the following discussion, references to 2018 and 2017 refer to the years ended December 31, 2018 and 2017, respectively, unless otherwise indicated.

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

· LOE was $61.6 million and $39.8 million for 2018 and 2017, respectively. On a per Boe basis, total LOE was $3.36 and $3.54 for 2018 and 2017, respectively.  The decrease in LOE on a per unit basis is largely attributable to the increased production due to the drilling of successful wells in the Eagle Ford Shale along with increased efficiencies in 2018 compared to 2017.  We recorded $10.2 million of workover expenses in 2018 in comparison to $7.7 million in 2017 to increase efficiency on legacy wells.  Net production in 2018 consisted of 69% oil compared to 59% oil in 2017, an increase of approximately 17%.

· GP&T expenses were $9.9 million and $11.9 million for 2018 and 2017, respectively.  On a per Boe basis, GP&T expenses were $0.54 and $1.06 for 2018 and 2017, respectively.  The 49% 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 properties and an increase in production from our drilling activities in the Eagle Ford Shale.

· Taxes other than income tax were $52.4 million and $24.2 million for 2018 and 2017, respectively, an increase of $28.2 million (approximately 117%).  On a per Boe basis, taxes other than income tax were $2.86 and $2.15 for 2018 and 2017, respectively.  The $28.2 million increase was primarily due to an increase in production taxes of $25.8 million and ad valorem taxes of $2.4 million.  The production taxes increased due to higher realized prices and increased volumes. The ad valorem taxes increased due to increased property valuations.

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

· Impairment losses from the sale of the NLA Disposal Group were $214.3 million in 2018.  We did not have any similar impairments from the sale of assets in 2017.

· Gains from the sale of properties were $2.8 million in 2018.  We did not have any gains from the sale of assets in 2017.

· G&A expenses were $65.7 million and $40.7 million (an increase of approximately 61%) for 2018 and 2017, respectively.  The $25.0 million increase was primarily due to increased salary, wage and stock-based compensation costs, costs associated with divesting the NLA properties, and incremental G&A expenses as a result of being a publicly traded company including, but not limited to, expenses associated with Sarbanes Oxley compliance and incremental independent auditor fees; offset by lower acquisition expenses.

· Exploration expense was $22.5 million and $36.9 million for 2018 and 2017, respectively.The $14.4 million decrease in exploration expense was largely due to an $11.5 million decrease in seismic acquisition expenses, a $10.3 million decrease in undeveloped leasehold impairments and abandonments, a decrease of $2.1 million in delay rentals and a $1.9 million decrease in mapping costs.  These costs were offset by $11.1 million of geophysical costs for the drilling of certain developmental well and $0.2 million of sand mine exploration costs.

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

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

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

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

For purposes of the following discussion, references to 2017 and 2016 refer to the years ended December 31, 2017 and 2016, respectively, unless otherwise indicated.

· Oil, natural gas and NGL revenues were $425.8 million for 2017 compared to $125.2 million for 2016, an increase of $300.6 million. Revenue increased because production increased 5.9 MMBoe and an increase in the average realized sales price of $14.27 per Boe due to higher overall commodity prices and a higher percentage of oil in the production mix.

· LOE was $39.8 million and $12.3 million for 2017 and 2016, respectively. On a per Boe basis, LOE was $3.54 and $2.33 for 2017 and 2016, respectively. The increase in LOE on a per unit basis was largely attributable to acquisitions that came with less efficient legacy wells and to higher workover expense. We recorded $7.7 million of workover expenses in 2017. Net production in 2017 consisted of 59% oil compared to 35% oil in 2016, an increase of approximately 68%.

· GP&T expenses were $11.9 million and $6.6 million for 2017 and 2016, respectively. On a per Boe basis, GP&T expenses were $1.06 and $1.24 for 2017 and 2016, respectively. The increase in total GP&T expenses was primarily attributable to increased expenses associated with higher production. On a per Boe basis, the decrease is primarily due to an increase in production from our drilling activities.

· Taxes other than income tax were $24.2 million and $6.8 million for 2017 and 2016, respectively. The $17.4 million increase was primarily due to higher realized prices, changes in commodity mix, higher ad valorem taxes associated with increased property valuations, and Louisiana franchise taxes incurred as a result of our Corporate Reorganization that occurred in conjunction with our initial public offering. On a per Boe basis, taxes other than income tax were $2.15 and $1.29 for 2017 and 2016, respectively.

· DD&A expense for 2017 was $168.3 million compared to $81.8 million for 2016, an $86.5 million increase primarily due to an increase in production volumes related to drilling and acquisition activities. Increased

41

production volumes caused DD&A expense to increase by $91.7 million and the change in the DD&A rate between periods caused DD&A expense to decrease by $5.2 million.

· We did not record impairment expenses on our proved properties in 2017 and 2016.

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

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

· Interest expense was $31.9 million and $7.8 million for 2017 and 2016, respectively. The $24.1 million increase was primarily due to an increase in the average debt outstanding as a result of the issuance of $350 million and $150 million of 2025 Senior Notes in February and September 2017, respectively. Interest is comprised of interest on our credit facilities, interest on our senior notes and amortization of debt issue costs offset by capitalized interest. Capitalized interest was $3.1 million for 2017 due to increased drilling activities compared to less than $0.1 million for 2016.

· During 2017, we recognized a $55.5 million loss on derivative instruments, of which $3.3 million was a realized loss and a $52.2 million was an unrealized loss. Net losses on commodity derivatives of $26.8 million were recognized during 2016, of which $4.5 million was a realized gain and $31.3 million was an unrealized loss.

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

· Income tax benefits were $38.8 million and $5.6 million for 2017 and 2016, respectively. The increase of $33.2 million was primarily due to a $43.4 million deferred tax benefit in 2017 resulting from the Tax Act partially offset by $10.2 million associated with pretax income in 2017 as compared to the pretax loss in 2016 and the change in our tax status from a pass-through entity to corporation subsequent to our initial public offering in 2016. The effective tax rate for 2017 differed from the federal statutory income tax rate primarily due to a change in tax rate, state income tax and changes in estimates related to a prior-period tax provision. The effective tax rate for 2016 differed from the federal statutory income tax rate primarily due to the impact of pass-through entities and state income tax.

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.

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

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additional capital expenditures will be required to more fully develop our properties and acquire additional properties. We are also an unrestricted subsidiary of Chesapeake and as such, are limited in our ability to receive investments from, and transact with, Chesapeake.

As of December 31, 2018, we had $14.9 million of cash and cash equivalents and $796.0 million of available borrowings under our revolving credit facility. As of December 31, 2018, we had a working capital deficit of $32.8 million primarily due to the accrual of capital expenditures and losses on our short-term derivative instruments. As of December 31, 2018, the borrowing base under our Credit Agreement was $1.30 billion and we had outstanding borrowings of $504.0 million.

Debt Agreements

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

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

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.

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.

Our revolving credit facility is reserve-based, and thus our borrowing base is primarily based on the estimated value of our oil and natural gas properties and our commodity derivative contracts as determined by our lenders in their sole discretion consistent with their normal and customary oil and gas lending practices semi-annually, from time to time at our election in connection with material acquisitions, or no more frequently than twice in any fiscal year at the request of the Required Lenders or us, in each case based on engineering reports with respect to our estimated oil, NGL and natural gas reserves, and our commodity derivative contracts. Unanimous approval by the lenders is required for any increase to the borrowing base pursuant to a Redetermination, while only Required Lender approval is required to maintain or decrease the borrowing base pursuant to a Redetermination. The borrowing base may also automatically decrease upon the issuance of certain debt, including the issuance of senior notes, the sale or other disposition of certain assets and the early termination of certain swap agreements. In the future, we may be unable to access sufficient capital under our revolving credit facility as a result of (i) a decrease in our borrowing base due to a borrowing base redetermination or (ii) an unwillingness or inability on the part of our lenders to meet their funding obligations. For more information, please see “Item 1A. Risk Factors—Risks Related to Our Business—Any significant reduction in our borrowing base under our revolving credit facility as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.”

A decline in commodity prices could result in a redetermination that lowers our borrowing base and, in such case, we could be required to repay any indebtedness in excess of the borrowing base, or we could be required to pledge other oil and natural gas properties as additional collateral. If a redetermination of our borrowing base results in our borrowing base being less than our aggregate elected commitments, our aggregate elected commitments will be automatically reduced to the amount of such reduced borrowing base. We do not anticipate having any substantial unpledged properties, and we

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may not have the financial resources in the future to make any mandatory principal prepayments required under our revolving credit facility.

Borrowings under our revolving credit facility are secured by liens on substantially all of our properties, but in any event, not less than 85% (or 75% with respect to certain properties prior to February 2, 2017) of the total value, as determined by the Administrative Agent, of the proved reserves attributable to our oil and natural gas properties using a discount rate of 9%, all of our equity interests in any future guarantor subsidiaries and all of our other assets including personal property but excluding equity interests in and assets of unrestricted subsidiaries.

The Credit Agreement requires us to maintain (x) a ratio of total debt to EBITDAX (as defined under the Credit Agreement) of not more than 4.00 to 1.00 and (y) a ratio of current assets (including availability under the facility) to current liabilities of not less than 1.00 to 1.00. As of December 31, 2018, we were in compliance with all applicable financial covenants under the Credit Agreement and we were able to borrow up to the full availability under the revolving credit facility.

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

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

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

WHR II Revolving Credit Facility. We repaid and terminated WHR II's prior revolving credit facility in connection with the completion of our initial public offering.

Esquisto Revolving Credit Facility. We repaid and terminated Esquisto's prior revolving credit facility in connection with the completion of our initial public offering.

Esquisto Terminated Revolving Credit Facility and Second Lien Loan. Esquisto retired and terminated a prior revolving credit facility and second lien loan in January 2016 in connection with the merger of Esquisto I and Esquisto II.

See “Note 9—Long Term Debt” included under “Item 8. Financial Statements and Supplementary Data” of this Annual Report for additional information regarding our revolving credit facility.

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 $200.0 million of the 2025 Senior Notes, issued at 102% of par.  The April Notes are treated as a single class of debt securities with the other outstanding 2025 Senior Notes. 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

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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 February 1, 2019, we made a $24.1 million interest payment on the 2025 Senior Notes.  As of September 24, 2018, all of the 2025 Senior Notes had 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.

Additionally, if the 2025 Senior Notes are downgraded within 90 days after the consummation of the acquisition of WildHorse (which constitutes a “Change of Control” under the WildHorse Indenture), the WildHorse Indenture requires Brazos Valley Longhorn (or a third party, in certain circumstances) to make an offer to repurchase the 2025 Senior Notes at 101% of their principal amount, plus accrued and unpaid interest, within 30 days of such downgrade.

See “Note 9—Long Term Debt” included under “Item 8. Financial Statements and Supplementary Data” of this Annual Report for additional information regarding the 2025 Senior Notes.

Commodity Derivative Contracts

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

For additional information regarding the volumes of our production covered by commodity derivative contracts and the average prices at which production is hedged as of December 31, 2018, see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk.”

Counterparty Exposure

Our hedging policy permits us to enter into derivative contracts with major financial institutions or major energy entities. Our derivative contracts are currently with major financial institutions, certain of which are also lenders under the Credit Agreement. We have rights of offset against the borrowings under our revolving credit facility. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk—Counterparty and Customer Credit Risk” for additional information.

Cash Flows from Operating, Investing and Financing Activities

The following table summarizes our cash flows from operating, investing and financing activities for the periods indicated. Our predecessor's cash flows were retrospectively revised due to common control considerations. As such, the cash flows for 2016 have been derived from the combined financial position and results attributable to the predecessor for periods prior to our initial public offering and for the previous owner for periods from the inception of common control (February 17, 2015) through our initial public offering. For periods after the completion of our initial public offering, our consolidated financial statements include our accounts and those of our subsidiaries. Because WHR II, Esquisto and Acquisition Co. Holdings were under the common control of NGP, the sale and contribution of the respective ownership interests was accounted for as a combination of entities under common control, whereby the assets and liabilities sold and contributed were recorded based on historical cost.

For information regarding the individual components of our cash flow amounts, see the Statements of Consolidated and Combined Cash Flows included under “Item 8. Financial Statements and Supplementary Data” contained herein.

	For Year Ended December 31,
	2018		2017		2016
	(in thousands)
Net cash provided by operating activities	$	616,526	$	277,372	$	22,262
Net cash used in investing activities	$	991,555	$	1,267,747	$	567,210
Net cash provided by financing activities	$	389,750	$	986,600	$	505,272

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Year Ended December 31, 2018 Compared to the Year Ended December 31, 2017

For purposes of the following discussion, references to 2018 and 2017 refer to the years ended December 31, 2018 and 2017, respectively, unless otherwise indicated.

Operating Activities. Net cash provided by operating activities was $616.5 million for 2018 compared to $277.4 million of net cash provided by operating activities for 2017.  Cash provided by operating activities increased because production increased 7.1 MMBoe (approximately 63 %) and because the average realized sales price increased to $51.61 per Boe for 2018 compared to $37.94 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 $113.6 million of cash payments on derivative instruments during 2018 compared to $1.5 million in cash receipts during 2017.  There was a $12.2 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 $991.6  million and $1,267.7 million, respectively. In 2018, we received $207.9 million of net proceeds related to the NLA Divestiture. Acquisitions of oil and gas properties were $53.8 million and $551.2 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 $1,051.9 million and $700.5 million during 2018 and 2017, respectively, related to our drilling and completion activities and land leasing activities in the Eagle Ford Shale and Austin Chalk Trend. Additions to and acquisitions of other property and equipment were $83.6 million and $16.0 million during 2018 and 2017, respectively. Approximately $66.1 million of the $83.6 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 also recorded at $10.2 million contribution related to our equity method investee, JWH Midstream LLC.

Financing Activities. Net cash provided by financing activities during 2018 of $389.8 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 $217.6 million associated with our revolving credit facility.  During 2018 we also paid $20.3 million in preferred stock dividends and had debt issuance costs of $4.7 million. We withheld $6.9 million for tax payment remittance to appropriate taxing authorities primarily related to vesting of the 2016 LTIP awards during 2018.   The restricted common shares were net-settled to cover the required withholding tax upon vesting. 

Net cash provided by financing activities during 2017 of $986.6 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 $43.6  million in net borrowings under our revolving credit facility. These cash inflows were further offset by credit facility debt issuance costs of $15.3 million, $2.7 million of issuance costs associated with the underwriters’ exercise of their over-allotment option and $0.6 million of repurchases of vested restricted stock to satisfy employees’ tax obligations upon vesting.

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

Operating Activities. Net cash provided by operating activities was $277.4 million for 2017, compared to $22.3 million of net cash provided by operating activities for 2016. Cash provided by operating activities increased because production increased by 5.9 MMBoe (approximately 112%) and average realized sales prices increased to $37.94 per Boe for 2017 compared to $23.67 per Boe during 2016 as previously discussed above under “Results of Operations.”  The overall year-to-year increase in net cash provided by operating activities was also impacted by higher G&A expenses and LOE due to the growth of the company. Net cash provided by operating activities included $1.5 million of cash receipts on derivative instruments during 2017 compared to $4.9 million during 2016. There was a $55.6 million increase in cash flow attributable to the timing of cash receipts and disbursements related to operating activities during 2017 compared to 2016.

Investing Activities. During 2017 and 2016, cash flows used in investing activities were $1.27 billion and $567.2 million, respectively. Acquisitions of oil and gas properties were $551.2 million during 2017. Acquisitions of oil and gas

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properties were $436.1 million during 2016. We closed the Burleson North Acquisition in December 2016 for $389.8 million. Additions to oil and gas properties were $700.5 million during 2017, primarily related to our land leasing activities and drilling and completion activities in the Eagle Ford Shale. Additions to oil and gas properties were $125.8 million during 2016, of which $107.5 million was attributable to Esquisto's drilling and completion activities in the Eagle Ford Shale.

Financing Activities. Net cash provided by financing activities during 2017 of $986.6 million was primarily attributable to $432.3 million in net proceeds from the issuance of our Preferred Stock, $494.7 million in proceeds from the issuance of our 2025 Senior Notes, $513.5 million in advances on our revolving credit facilities and $34.5 million from the partial exercise of the underwriters' over-allotment option in connection with our initial public offering. These cash inflows were offset by payments under our revolving credit facility of $469.9 million during 2017, debt issuance costs of $15.3 million, $2.7 million of issuance costs associated with the underwriters' exercise of their over-allotment option and $0.6 million of repurchases of vested restricted stock to satisfy employees' tax obligations upon vesting. Net proceeds from the issuance of our Preferred Stock partially funded the cash consideration portion of the Acquisition. We used proceeds from the issuance of our 2025 Senior Notes to primarily pay down borrowings under our revolving credit facility. Amounts borrowed under our revolving credit facility funded our lease acquisition and drilling programs, activities related to Oakfield and Burleson Water infrastructure projects and our working capital needs.

Net cash provided by financing activities during 2016 of $505.3 million was primarily attributable to $394.1 million in net proceeds from our initial public offering and capital contributions of $13.3 million and $97.0 million, respectively, from our predecessor and previous owner prior to our initial public offering. Net borrowings under our revolving credit facilities were $4.8 million during 2016. Amounts borrowed under our revolving credit facility were primarily incurred to repay the amounts outstanding under our predecessor and previous owner credit facilities in connection with the closing of our initial public offering. Amounts borrowed under our predecessor and previous owner credit facilities were primarily used for additions to oil and natural gas properties and working capital. Debt issuance costs were $3.6 million.

Contractual Obligations

In the table below, we set forth our contractual obligations as of December 31, 2018. The contractual obligations we will actually pay in future periods may vary from those reflected in the table because the estimates and assumptions used in creating the table are subjective.

	Payment or Settlement due by Period
Contractual Obligation	Total		2019		2020-2021		2022-2023		Thereafter
		(In thousands)
Revolving credit facility (1)	$	504,000	$	—	$	504,000	$	—	$	—
Estimated interest payments (2)		60,658		20,462		40,196		—		—
2025 Senior Notes and interest payments (3)		992,760		48,125		96,250		96,250		752,135
Office leases		18,669		2,399		4,833		4,467		6,970
Compressors (4)		15,715		4,143		7,850		3,626		96
Dedicated fracturing fleet service agreement (5)		21,000		21,000		—		—		—
Interruptible water availability agreement		1,602		534		1,068		—		—
Sand mine equipment		8,491		5,055		3,436		—		—
Right-of-way		1,920		40		80		80		1,720
Total	$	1,624,815	$	101,758	$	657,713	$	104,423	$	760,921

(1) As of December 31, 2018, we had $504.0 million outstanding under our revolving credit facility. This amount represents the scheduled future maturities of the principal amount outstanding. See Note 9 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data” of this Annual Report for information regarding our revolving credit facility.

(2) Estimated interest payments are based on the principal amount outstanding under our revolving credit facility at December 31, 2018. In calculating these amounts, we applied the weighted-average interest rate during 2018 associated with such debt. See Note 9 of the Notes to Consolidated and Combined Financial Statements included

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under “Item 8. Financial Statements and Supplementary Data” of this Annual Report for the weighted-average variable interest rate charged during 2018 under our revolving credit facility.

(3) Interest payments are based on the $700.0 million aggregate principal amount of our 2025 Senior Notes. See Note 9 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data” of this Annual Report for additional information regarding our 2025 Senior Notes.

(4) Represents compressor rentals which are on month-to-month terms without any significant long-term contracts.

(5) Represents aggregate fixed monthly payments related to fleet service agreement that we entered into in June 2017.  See Note 18 of the Notes to Consolidated and Combined Financial Statements included under “Item 8. Financial Statements and Supplementary Data” of this Annual Report for additional information regarding these agreements.

Off–Balance Sheet Arrangements

As of December 31, 2018, we had no off–balance sheet arrangements.

ITEM 7A.     QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Commodity Price Risk

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

During the period from January 1, 2014 through January 1, 2018, the WTI spot price for oil has declined from a high of $107.95 per Bbl on June 20, 2014 to $26.19 per Bbl on February 11, 2016, and the Henry Hub spot price for natural gas has declined from a high of $8.15 per MMBtu on February 10, 2014 to a low of $1.49 per MMBtu on March 4, 2016. Since 2016, prices have generally increased. As of February 22, 2019, the NYMEX WTI oil price was $57.08 per bbl and the NYMEX Henry Hub natural gas price was $2.72 per MMBtu. The prices we receive for our oil, natural gas and NGLs production depend on numerous factors beyond our control. A sustained decline in oil, natural gas and NGL prices could adversely affect our business, financial condition and results of operations and our ability to meet our capital expenditure obligations and financial commitments.

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

Swaps. In a typical commodity swap agreement, we receive the difference between a fixed price per unit of production and a price based on an agreed upon published third-party index, if the index price is lower than the fixed price we receive the difference. If the index price is higher, we pay the difference. By entering into swap agreements, we effectively fix the price that we will receive in the future for the hedged production. Our swaps are settled in cash on a monthly basis as each month is due.

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Collars. In a typical collar arrangement, we receive the excess, if any, of the contract floor price over the reference price, based on NYMEX or regional quoted prices, and pay the excess, if any, of the reference price over the contract ceiling price. Collars are typically exercised in cash on a monthly basis only when the reference price is outside of floor and ceiling prices (the collar), otherwise they expire.

Put options.  In a typical put option, we receive the difference between the agreed upon strike price of the option and the price of the underlying commodity if market prices decline below the strike price. When put options are settled we would receive the difference between the strike price and market price less any deferred premiums associated with the put option contract. If commodity markets rise above the strike price, any losses incurred are limited to the deferred premium amount associated with the put option. Put options typically settle in cash on a monthly basis, otherwise they expire.

The following table summarizes our derivative contracts as of December 31, 2018 and the average prices at which the production will be hedged:

	2019		2020
Crude Oil Derivative Contracts:
Fixed price swap contracts:
Volume (Bbls)		6,652,369		4,511,681
Weighted-average fixed price	$	54.45	$	53.49
Put options:
Volume (Bbls)		1,749,757		—
Weighted-average floor price	$	53.83	$	—
Weighted-average put premium	$	(5.43)	$	—
Natural Gas Derivative Contracts:
Fixed price swap contracts:
Volume (MMBtu)		6,425,146		4,846,020
Weighted-average fixed price	$	2.79	$	2.76

Interest Rate Risk

At December 31, 2018, we had $504.0 million of debt outstanding under our revolving credit facility, with a weighted average interest rate of 4.06%. Additionally, borrowings under our revolving credit facility will bear interest, at our option, at either: (i) the Alternate Base Rate, which is based on the greatest of (x) the prime rate as determined by the Administrative Agent, (y) the federal funds effective rate plus 0.50%, and (z) the adjusted LIBOR for a one month interest period plus 1.0%, in each case, plus a margin that varies from 0.50% to 1.50% per annum according to the total commitments usage (which is the ratio of outstanding borrowings and letters of credit to the least of the total commitments, the borrowing base and the aggregate elected commitments then in effect), (ii) the adjusted LIBOR plus a margin that varies from 1.50% to 2.50% per annum according to the total commitment usage or (iii) the applicable LIBOR market index rate plus a margin that varies from 1.50% to 2.50% per annum according to the total commitment usage. The unused portion of the total commitments are subject to a commitment fee that varies from 0.375% to 0.50% per annum according to our total commitments usage. From the inception of the Credit Agreement, predominately all our debt outstanding was in the form of Eurodollar borrowings based on the adjusted LIBOR.

Assuming no change in the amount outstanding, the impact on interest expense of a 1% increase or decrease in the assumed weighted average interest rate would be approximately $5.0 million per year. We do not currently have any derivative arrangements to protect against fluctuations in interest rates applicable to our outstanding indebtedness but may enter into such derivative arrangements in the future. To the extent we enter into any such interest rate derivative arrangement, we would subject to risk for financial loss. For more information, please see “Item 1A. Risk Factors—Risks Related to Our Business—Our derivative activities could result in financial losses or could reduce our earnings.”

49

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 discounts/premiums and debt issuance cost) is compared to the estimated fair value in the table below (thousands):

	At December 31, 2018
	Carrying Amount		Estimated Fair Value
2025 Senior Notes, fixed-rate due February 2025	$	687,376	$	661,500

Counterparty and Customer Credit Risk

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

Our principal exposures to credit risk are through receivables resulting from joint interest receivables and receivables from the sale of our oil and natural gas production due to the concentration of our oil and natural gas receivables with several significant customers. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. However, we believe the credit quality of our customers is high.

By using derivative instruments that are not traded on an exchange to hedge exposures to changes in commodity prices, we expose ourselves to the credit risk of our counterparties. Credit risk is the potential failure of the counterparty to perform under the terms of the contract. When the fair value of a contract is positive, the counterparty is expected to owe us, which creates the credit risk. To minimize the credit risk in derivative instruments, it is our policy to enter into contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market-makers. The creditworthiness of our counterparties is subject to periodic review. As of December 31, 2018, our derivative contracts were with major financial institutions, all of which were also lenders under the Credit Agreement. While collateral is generally not required to be posted by counterparties, credit risk associated with these instruments is minimized by limiting exposure to any single counterparty and entering into derivative instruments only with creditworthy counterparties that are generally large financial institutions. Additionally, master netting agreements are used to mitigate risk of loss due to default with counterparties on derivative instruments. We have also entered into the International Swaps and Derivatives Association Master Agreements (“ISDA Agreements”) with each of our counterparties. The terms of the ISDA Agreements provide 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, whereby the party not in default may set-off all liabilities owed to the defaulting party against all net derivative asset receivables from the defaulting party. At December 31, 2018, we had net derivative assets of $72.2 million. Had certain counterparties failed completely to perform according to the terms of existing contracts, we would have the right to offset $72.2 million against amounts outstanding under our revolving credit facility, thereby eliminating any credit exposure. See Note 9 under “Item 8. Financial Statements and Supplementary Data” for additional information regarding our revolving credit facility.

We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers and the inability of our significant customers to meet their obligations to us 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.

ITEM 8.       FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Our Financial Statements, together with the report of our independent registered public accounting firm begin on page F‑1 of this Annual Report.

50

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

None.

ITEM 9A.     CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

We maintain disclosure controls and procedures designed to ensure that information required to be disclosed in reports we file or submit under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and that such information is accumulated and communicated to management, including our principal executive and principal financial officers, as appropriate, to allow timely decisions regarding required disclosure.

As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rule 13a-15(b). Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded as of December 31, 2018 that our disclosure controls and procedures were effective.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during the quarter ended December 31, 2018 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Management's Report on Internal Control Over Financial Reporting

It is the responsibility of the Company's management to establish and maintain adequate internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. Management utilized the Committee of Sponsoring Organizations of the Treadway Commission's Internal Control-Integrated Framework (2013) in conducting the required assessment of effectiveness of the Company's internal control over financial reporting.

Management has performed an assessment of the effectiveness of the Company's internal control over financial reporting and has determined the Company’s internal control over financial reporting was effective as of December 31, 2018.

/s/ ROBERT D. LAWLER

Robert D. Lawler

President and Chief Executive Officer

/s/ DOMENIC J. DELL'OSSO, JR.

Domenic J. Dell'Osso, Jr.

Executive Vice President and Chief Financial Officer

March 4, 2019

ITEM 9B.     OTHER INFORMATION

None.

51

PART III

ITEM 10.      DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The information called for by Item 10 is omitted pursuant to Instruction I(2) to Form 10-K (Omission of Information by Certain Wholly-Owned Subsidiaries).

ITEM 11.     EXECUTIVE COMPENSATION

The information called for by Item 11 is omitted pursuant to Instruction I(2) to Form 10-K (Omission of Information by Certain Wholly-Owned Subsidiaries).

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

The information called for by Item 12 is omitted pursuant to Instruction I(2) to Form 10-K (Omission of Information by Certain Wholly-Owned Subsidiaries).

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

The information called for by Item 13 is omitted pursuant to Instruction I(2) to Form 10-K (Omission of Information by Certain Wholly-Owned Subsidiaries).

ITEM 14.     PRINCIPAL ACCOUNTANT FEES AND SERVICES

The following table provides information regarding the aggregate fees incurred by the Company, and its predecessor and the previous owners, from KPMG LLP during the last two fiscal years (dollars in thousands):

	Company, or its
	Predecessor and
	the Previous
	Owners
	2018		2017
Audit Fees (1)	$	2,450	$	1,648
Audit Related Fees (2)		—		96
Tax Fees (3)		—		—
All Other Fees (4)		—		—
Total	$	2,450	$	1,744

(1)Audit fees represent amounts billed for each of the years presented for professional services rendered in connection with those services normally provided in connection with statutory and regulatory filings or engagements including comfort letters, consents and other services related to SEC matters. These fees primarily related to the (i) audit of our annual financial statements, (ii) the review of our quarterly financial statements filed on Form 10-Q.

(2)Audit-related fees represent amounts billed in each of the years presented for assurance and related services that are reasonably related to the performance of the annual audit or quarterly reviews (e.g., audits of benefit plans, due diligence for possible acquisitions or consultations pertaining to new and proposed accounting or regulatory rules). Services primarily related to a consultation pertaining to our implementation of ASC 842, Leases and ASC 606, Revenue From Contracts With Customers in 2018 and 2017, respectively.

(3)Tax fees represent amounts billed in each of the years presented for professional services rendered in connection with tax compliance, tax advice and tax planning.

(4)All other fees represent amounts billed in each of the years presented for services not classifiable under the other categories listed in the table above. No such services were rendered by KPMG during the years ended December 31, 2018 and 2017.

52

PART IV

ITEM 15.     EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)(1) Financial Statements

Our Financial Statements are included under Part II, Item 8 of the annual report. For a listing of these statements and accompanying footnotes, see “Index to Financial Statements” Page F‑1 of this Annual Report.

(a)(2) Financial Statement Schedules

All schedules have been omitted because they are either not applicable, not required or the information called for therein appears in the consolidated and combined financial statements or notes thereto.

(a)(3) Exhibits

The exhibits listed on the accompanying Exhibit Index are filed or incorporated by reference as part of this Annual Report, and such Exhibit Index is incorporated herein by reference.

Exhibit Number	Description
2.1	Master Contribution Agreement, dated December 12, 2016, by and among WildHorse Resource Development Corporation and the other parties named therein (incorporated by reference to Exhibit 2.1 to the Company's Form 8‑K filed on December 16, 2016) (SEC File No. 001-37964).
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 of the Company's Form 10‑Q filed on May 15, 2017) (SEC File No. 001-37964).
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 of the Company's Form 10‑Q filed on May 15, 2017) (SEC File No. 001-37964).
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) (SEC File No. 001-37964).
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, as amended (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on October 30, 2018) (SEC File No. 001-37964).
2.6	Amendment No. 1 to Agreement and Plan of Merger, dated as of December 12, 2018, by and among Chesapeake Energy Corporation, Coleburn Inc. and WildHorse Resource Development Corporation (incorporated by reference to Exhibit 2.2 to Annex A to the Company’s Proxy Statement on Schedule 14A filed on December 26, 2018) (SEC File No. 001-37964).
3.1	Certificate of Formation of Brazos Valley Longhorn, L.L.C. (incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K filed on February 1, 2019) (SEC File No. 001-37964).
3.2	Operating Agreement for Brazos Valley Longhorn, L.L.C. (incorporated by reference to Exhibit 3.2 to the Company’s Form 8-K filed on February 1, 2019) (SEC File No. 001-37964).
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) (SEC File No. 001-37964).

53

Exhibit Number	Description
4.2	Fourth Supplemental Indenture, dated as of February 1, 2019 among Brazos Valley Longhorn, L.L.C., the Guarantors (as defined in the Indenture referred to therein) and U.S. Bank National Association. (incorporated by reference to Exhibit 4.1 to the Company’s Form 8-K filed on February 1, 2019) (SEC File No. 001-37964).
4.4	Third Supplemental Indenture, dated as of August 2, 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-Q filed on August 9, 2018) (SEC File No. 001-37964).
4.5	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) (SEC File No. 001-37964).
4.6	First Supplemental Indenture, dated as of June 30, 2017, by and among WHR Eagle Ford LLC, WildHorse Resource Development Corporation, the other subsidiary guarantors named therein and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.6 to the Company’s Form 10-Q filed on August 10, 2017) (SEC File No. 001-37964).
10.1	Sixth Amendment to Credit Agreement, dated as of February 1, 2019 among Brazos Valley Longhorn, L.L.C., each of the Guarantors party thereto, each of the Lenders party thereto and Wells Fargo Bank, National Association (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on February 1, 2019) (SEC File No. 001-37964).
10.2	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 (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on October 30, 2018 (incorporated by reference to Exhibit 10.1 to the Company’s Form 10-Q filed on November 8, 2018) (SEC File No. 001-37964).
10.3	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) (SEC File No. 001-37964).
10.4	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) (SEC File No. 001-37964).
10.5	Credit Agreement, dated December 19, 2016, by and among WildHorse Resource Development Corporation, as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, BMO Harris Bank, N.A., as Syndication Agent, the Lenders party thereto and the other parties party thereto (incorporated by reference to Exhibit 10.3 to the Company's Form 8-K filed on December 22, 2016) (SEC File No. 001-37964).
10.11	Third Amendment to Credit Agreement, dated as of October 4, 2017, by and among WildHorse Resource Development Corporation, each of the guarantors party thereto, and Wells Fargo Bank, National Association, as Administrative Agent  for the Lenders party thereto, BMO Harris Bank, N.A., as Syndication Agent, the Lenders party thereto and the other parties party thereto (incorporated by reference to Exhibit 10.1 to the Company's Form 8-K filed on October 5, 2017) (SEC File No. 001-37964).
10.12	Second Amendment to Credit Agreement, dated as of June 30, 2017, by and among WildHorse Resource Development Corporation, each of the guarantors party thereto, and Wells Fargo Bank, National Association, as Administrative Agent  for the Lenders party thereto, BMO Harris Bank, N.A., as Syndication Agent, the Lenders party thereto and the other parties party thereto (incorporated by reference to Exhibit 10.1 to the Company's Form 8-K filed on July 7, 2017) (SEC File No. 001-37964).

54

Exhibit Number	Description
10.13	First Amendment to Credit Agreement, dated as of April 4, 2017, by and among WildHorse Resource Development Corporation, each of the guarantors party thereto, and Wells Fargo Bank, National Association, as Administrative Agent  for the Lenders party thereto, BMO Harris Bank, N.A., as Syndication Agent, the Lenders party thereto and the other parties party thereto (incorporated by reference to Exhibit 10.1 to the Company's Form 10-Q filed on May 15, 2017) (SEC File No. 001-37964).
21.1†	Subsidiaries of WildHorse Resource Development Corporation.
23.1*	Consent of Cawley, Gillespie and Associates, Inc.
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*	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*	Certification of 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.
99.1*	Report of Cawley, Gillespie and Associates, Inc.
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 Annual Report on Form 10‑K.

†We have omitted the list of subsidiaries exhibit required by Item 601 of Regulation S-K pursuant to Instruction I(2) to Form 10-K (Omission of Information by Certain Wholly-Owned Subsidiaries).

ITEM 16.     FORM 10‑K SUMMARY

Not applicable.

55

Signatures

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	BRAZOS VALLEY LONGHORN, L.L.C.
Date: March 4, 2019	By:	/s/ Robert D. Lawler
		Robert D. Lawler
		President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Capacity	Date
/s/ Robert D. Lawler	President and Chief Executive Officer (Principal Executive Officer)	March 4, 2019
Robert D. Lawler
/s/ Domenic J. Dell’Osso, Jr.	Executive Vice President and Chief Financial Officer (Principal Financial Officer)	March 4, 2019
Domenic J. Dell'Osso, Jr.
/s/ William M. Buergler	Senior Vice President and Chief Accounting Officer (Principal Accounting Officer)	March 4, 2019
William M. Buergler
/s/ Robert D. Lawler	Sole Member	March 4, 2019
Chesapeake Energy Corporation
By:    Robert D. Lawler Its:     President and Chief Executive Officer

56

ITEM 8.     FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

BRAZOS VALLEY LONGHORN, L.L.C.

(Successor in interest to WildHorse Resource Development Corporation)

INDEX TO FINANCIAL STATEMENTS

	Page No
Report of Independent Registered Public Accounting Firm	F – 2
Consolidated Balance Sheets as of December 31, 2018 and 2017	F – 3
Statements of Consolidated and Combined Operations for the Years Ended December 31, 2018, 2017 and 2016	F – 4
Statements of Consolidated and Combined Cash Flows for the Years Ended December 31, 2018, 2017 and 2016	F – 5
Consolidated and Combined Statement of Changes in Equity for the Years Ended December 31, 2018, 2017 and 2016	F – 6
Notes to Consolidated and Combined Financial Statements	F – 7
Note 1 – Organization and Basis of Presentation	F – 7
Note 2 – Summary of Significant Accounting Policies	F – 9
Note 3 – Acquisitions and Divestitures	F – 19
Note 4 – Fair Value Measurements of Financial Instruments	F – 22
Note 5 – Risk Management and Derivative and Other Financial Instruments	F – 25
Note 6 – Accounts Receivable	F – 27
Note 7 – Accrued Liabilities	F – 27
Note 8 – Asset Retirement Obligations	F – 28
Note 9 – Long Term Debt	F – 28
Note 10 – Preferred Stock	F – 32
Note 11 – Equity	F – 35
Note 12 – Earnings Per Share	F – 36
Note 13 – Long Term Incentive Plans	F – 37
Note 14 – Incentive Units	F – 37
Note 15 – Related Party Transactions	F – 38
Note 16 – Segment Disclosures	F – 40
Note 17 – Income Taxes	F – 41
Note 18 – Commitments and Contingencies	F – 42
Note 19 – Quarterly Financial Information (Unaudited)	F – 44
Note 20 – Supplemental Oil and Gas Information (Unaudited)	F – 45
Note 21 – Subsequent Events	F – 49

F – 1

Report of Independent Registered Public Accounting Firm

To the Board of Directors of Chesapeake Energy Corporation in its capacity as sole member of Brazos Valley Longhorn, L.L.C. (Successor in interest to WildHorse Resource Development Corporation)

Opinion on the Consolidated and CombinedFinancial Statements

We have audited the accompanying consolidated balance sheets of Brazos Valley Longhorn, L.L.C. (Successor in interest to WildHorse Resource Development Corporation) and subsidiaries (the Company) as of December 31, 2018 and 2017, the related consolidated and combined statements of operations, cash flows, and changes in equity for each of the years in the three‑year period ended December 31, 2018, and the related notes (collectively, the consolidated and combined financial statements). In our opinion, the consolidated and combined financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the years in the three‑year period ended December 31, 2018, in conformity with U.S. generally accepted accounting principles.

Basis of Presentation

As discussed in Note 1 to the consolidated and combined financial statements, the statements of operations, cash flows, and changes in equity for the periods from inception of common control (February 17, 2015) through the initial public offering (December 19, 2016), have been prepared on a combined basis of accounting.

Basis for Opinion

These consolidated and combined financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated and combined financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated and combined financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the consolidated and combined financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated and combined financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated and combined financial statements. We believe that our audits provide a reasonable basis for our opinion.

We have served as the Company’s auditor since 2013.

Houston, Texas
March 4, 2019

F – 2

BRAZOS VALLEY LONGHORN, L.L.C.

(Successor in interest to WildHorse Resource Development Corporation)

CONSOLIDATED BALANCE SHEETS

(In thousands, except outstanding shares)

	December 31,		December 31,
	2018		2017
ASSETS
Current Assets:
Cash and cash equivalents	$	14,947	$	226
Accounts receivable, net		91,558		84,103
Derivative instruments		54,131		2,336
Prepaid expenses and other current assets		7,851		3,290
Total current assets		168,487		89,955
Property and equipment:
Oil and gas properties		3,457,897		2,999,728
Other property and equipment		107,279		53,003
Accumulated depreciation, depletion and amortization		(518,054)		(368,245)
Total property and equipment, net		3,047,122		2,684,486
Other noncurrent assets:
Derivative instruments		18,579		86
Debt issuance costs		3,592		3,573
Other		17,250		—
Total assets	$	3,255,030	$	2,778,100
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	76,189	$	53,005
Accrued liabilities		124,633		199,952
Derivative instruments		508		58,074
Total current liabilities		201,330		311,031
Noncurrent liabilities:
Long-term debt		1,191,376		770,596
Asset retirement obligations		8,226		14,467
Deferred tax liabilities		112,731		71,470
Derivative instruments		—		18,676
Other		2,233		1,085
Total noncurrent liabilities		1,314,566		876,294
Total liabilities		1,515,896		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 December 31, 2018 and December 31, 2017, (involuntary liquidation preference of $450,389 and $448,146 at December 31, 2018 and December 31, 2017, respectively)		447,726		445,483
Stockholders’ equity:
Common stock, $0.01 par value 500,000,000 shares authorized; 101,793,855 shares and 101,137,277 shares issued and outstanding at December 31, 2018 and December 31, 2017, respectively		1,018		1,012
Additional paid-in capital		1,153,617		1,118,507
Accumulated earnings		136,773		25,773
Total stockholders’ equity		1,291,408		1,145,292
Total liabilities and equity	$	3,255,030	$	2,778,100

See Accompanying Notes to Consolidated and Combined Financial Statements

F – 3

BRAZOS VALLEY LONGHORN, L.L.C.

(Successor in interest to WildHorse Resource Development Corporation)

STATEMENTS OF CONSOLIDATED AND COMBINED OPERATIONS

(In thousands, except per share amounts)

	For Year Ended December 31,
	2018		2017		2016
Revenues and other income:
Oil sales	$	843,244	$	342,868	$	75,938
Natural gas sales		60,129		59,924		43,487
NGL sales		41,961		22,964		5,786
Other income		2,052		1,431		2,131
Total revenues and other income		947,386		427,187		127,342
Operating expenses:
Lease operating expenses		61,620		39,770		12,320
Gathering, processing and transportation		9,856		11,897		6,581
Taxes other than income tax		52,410		24,158		6,814
Depreciation, depletion and amortization		296,685		168,250		81,757
Impairment of NLA Disposal Group (Note 3)		214,274		—		—
Gain on sale of properties		(2,781)		—		—
General and administrative expenses		65,710		40,663		23,973
Incentive unit compensation expense		13,776		—		—
Exploration expense		22,483		36,911		12,026
Other operating expense		1,064		73		99
Total operating expenses		735,097		321,722		143,570
Income (loss) from operations		212,289		105,465		(16,228)
Other income (expense):
Interest expense, net		(60,119)		(31,934)		(7,834)
Gain (loss) on derivative instruments		35,393		(55,483)		(26,771)
North Louisiana settlement (Note 18)		—		(7,000)		—
Other income (expense)		(859)		8		(1,818)
Total other expense		(25,585)		(94,409)		(36,423)
Income (loss) before income taxes		186,704		11,056		(52,651)
Income tax benefit (expense)		(40,196)		38,824		5,575
Net income (loss)		146,508		49,880		(47,076)
Net loss attributable to previous owners		—		—		(2,681)
Net loss attributable to predecessor		—		—		(33,998)
Net income (loss) available to WRD		146,508		49,880		(10,397)
Preferred stock dividends		28,862		13,146		—
Undistributed earnings allocated to participating securities		30,344		5,612		—
Net income (loss) available to common stockholders	$	87,302	$	31,122	$	(10,397)
Earnings per common share:
Basic	$	0.88	$	0.32	$	(0.11)
Diluted	$	0.88	$	0.32	$	(0.11)
Weighted-average common shares outstanding:
Basic		99,498		96,324		91,327
Diluted		99,498		96,324		91,327

See Accompanying Notes to Consolidated and Combined Financial Statements

F – 4

BRAZOS VALLEY LONGHORN, L.L.C.

(Successor in interest to WildHorse Resource Development Corporation)

STATEMENTS OF CONSOLIDATED AND COMBINED CASH FLOWS

(In thousands)

	For Year Ended December 31,
	2018		2017		2016
Cash flows from operating activities:
Net income (loss)	$	146,508	$	49,880	$	(47,076)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		296,685		168,250		81,757
Impairments of unproved properties		10,504		20,834		3,051
Impairment of NLA Disposal Group		214,274		—		—
Amortization of debt issuance cost		3,098		2,575		479
Accretion of senior notes discount		132		342		—
(Gain) loss on derivative instruments		(35,393)		55,483		26,771
Cash settlements on derivative instruments		(113,637)		1,517		4,975
Deferred income tax expense (benefit)		41,193		(39,831)		(5,575)
Debt extinguishment expense		—		(11)		1,667
Amortization of equity awards		19,468		6,644		68
Incentive unit compensation expense		13,776		—		—
(Gain) loss on sale of properties		(2,781)		—		43
Loss on equity investment		676		—		—
Consideration paid to customers, net of amortization		(1,817)		—		—
Changes in operating assets and liabilities
Increase in accounts receivable		(8,206)		(56,828)		(16,300)
Increase in prepaid expenses		(576)		(390)		(448)
Increase in inventories		(1,056)		(648)		—
(Decrease) increase in accounts payable and accrued liabilities		33,678		69,555		(27,150)
Net cash provided by operating activities		616,526		277,372		22,262
Cash flows from investing activities:
Acquisitions of oil and gas properties		(53,814)		(551,242)		(436,072)
Additions to oil and gas properties		(1,051,891)		(700,546)		(125,837)
Additions to and acquisitions of other property and equipment		(83,597)		(15,959)		(5,403)
Contribution to equity method investee		(10,177)		—		—
Sales of other property and equipment		—		—		102
Proceeds from NLA Divestiture		207,924		—		—
Net cash used in investing activities		(991,555)		(1,267,747)		(567,210)
Cash flows from financing activities:
Advances on revolving credit facilities		1,085,000		513,500		383,450
Payments on revolving credit facilities		(867,353)		(469,897)		(378,700)
Debt issuance cost		(4,736)		(15,279)		(3,607)
Termination of second lien		—		—		(225)
Proceeds from senior notes offering		204,000		494,744		—
Proceeds from the issuance of preferred stock		—		435,000		—
Costs incurred in conjunction with the issuance of preferred stock		—		(2,663)		—
Proceeds from issuance of common stock		—		34,457		412,500
Cost incurred in conjunction with issuance of common stock		—		(2,698)		(18,426)
Preferred stock dividends		(20,267)		—		—
Previous owner and predecessor contributions		—		—		110,280
Repurchase of vested restricted stock		(6,894)		(564)		—
Net cash provided by financing activities		389,750		986,600		505,272
Net change in cash, cash equivalents and restricted cash		14,721		(3,775)		(39,676)
Cash, cash equivalents and restricted cash, beginning of period		226		4,001		43,677
Cash, cash equivalents and restricted cash, end of period	$	14,947	$	226	$	4,001

See Accompanying Notes to Consolidated and Combined Financial Statements

F – 5

BRAZOS VALLEY LONGHORN, L.L.C.

(Successor in interest to WildHorse Resource Development Corporation)

CONSOLIDATED AND COMBINED STATEMENT OF CHANGES IN EQUITY

(In thousands)

	Stockholders' Equity
	Common Stock		Additional Paid in Capital		Accumulated Earnings (Deficit)		Predecessor		Previous Owner		Total
December 31, 2015	$	—	$	—	$	—	$	274,133	$	374,556	$	648,689
Capital contributions		—		—		—		10,837		97,000		107,837
Property contributions		—		—		—		—		329		329
Net loss		—		—		(10,397)		(33,998)		(2,681)		(47,076)
Proceeds from public offering		275		412,225		—		—		—		412,500
Costs incurred in connection with initial public offering		—		(19,252)		—		—		—		(19,252)
Notes receivable from members		—		—		—		(132)		—		(132)
Dissolution of notes receivable from members		—		—		—		2,575		—		2,575
Amortization of equity awards		4		64		—		—		—		68
Issuance of shares in connection with Corporate Reorganization		625		721,994		—		(253,415)		(469,204)		—
Issuance of shares in connection with acquisition of properties		13		19,613		—		—		—		19,626
Tax related effects in connection with Corporate Reorganization and initial public offering		—		(117,276)		—		—		—		(117,276)
December 31, 2016		917		1,017,368		(10,397)		—		—		1,007,888
Net income		—		—		49,880		—		—		49,880
Proceeds from issuance of common stock		23		34,434		—		—		—		34,457
Costs incurred with issuance of common stock		—		(1,872)		—		—		—		(1,872)
Issuance of common stock in connection with the Acquisition		55		60,699		—		—		—		60,754
Deferred tax adjustment related to initial public offering		—		1,251		—		—		—		1,251
Accrual of preferred stock paid-in-kind dividend		—		—		(13,146)		—		—		(13,146)
Repurchase of vested restricted common stock		—		—		(564)		—		—		(564)
Amortization of equity awards		17		6,627		—		—		—		6,644
December 31, 2017		1,012		1,118,507		25,773		—		—		1,145,292
Cumulative effect of accounting change (Note 2)		—		—		243		—		—		243
Net income		—		—		146,508		—		—		146,508
Preferred stock paid-in-kind dividend		—		—		(2,243)		—		—		(2,243)
Accrued preferred stock cash dividend		—		—		(4,479)						(4,479)
Preferred stock cash dividend		—		—		(20,267)		—		—		(20,267)
Beneficial conversion feature of preferred stock		—		1,872		—		—		—		1,872
Amortization of beneficial conversion feature		—		—		(1,872)		—		—		(1,872)
Repurchase of vested restricted common stock		(4)		—		(6,890)		—		—		(6,894)
Contribution related to incentive unit compensation expense		—		13,776		—		—		—		13,776
Amortization of equity awards		10		19,462		—		—		—		19,472
December 31, 2018	$	1,018	$	1,153,617	$	136,773	$	—	$	—	$	1,291,408

See Accompanying Notes to Consolidated and Combined Financial Statements

F – 6

BRAZOS VALLEY LONGHORN, L.L.C.

(Successor in interest to WildHorse Resource Development Corporation)

Note 1. Organization and Basis of Presentation

Merger with Chesapeake Energy Corporation

In February 2019, we were acquired by Chesapeake for approximately 717.3 million shares of Chesapeake common stock and $381.1 million in cash. Immediately following the completion of the acquisition, WildHorse Development merged with and into Brazos Valley Longhorn, L.L.C., a newly formed Delaware limited liability company and wholly owned subsidiary of Chesapeake.

Initial Public Offering and Corporate Reorganization

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

The Company was formed in August 2016 to serve as a holding company for the assets of WHR II and Esquisto. We did not have any operations until we completed our initial public offering on December 19, 2016. In connection with our initial public offering and Corporate Reorganization (defined below), our accounting predecessor, WHR II was contributed to us. In addition to WHR II, we received Esquisto and Acquisition Co. We are an independent oil and natural gas company focused on the acquisition, exploration, development and production of oil, natural gas and NGL resources.

WHR II, Esquisto II, Acquisition Co., WHR Eagle Ford LLC (“WHR EF”), Burleson Sand LLC (“Burleson Sand”) and WHCC Infrastructure LLC (“WHCC”) are wholly owned subsidiaries of the Company as of December 31, 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.

The Company issued and sold to the public in its initial public offering 27,500,000 shares of common stock. The gross proceeds from the sale of the common stock were $412.5 million, net of underwriting discounts of $14.1 million and other offering costs of $5.0 million. The net proceeds from our initial public offering were $393.4 million. Debt issuance costs of $2.9 million related to the establishment of the Company's revolving credit facility were also incurred in conjunction with our initial public offering.

Contemporaneously with our initial public offering, (i) the owners of WHR II exchanged all of their interests in WHR II for equivalent interests in WildHorse Investment Holdings and the owners of Esquisto exchanged all of their interests in Esquisto for equivalent interests in Esquisto Investment Holdings, (ii) WildHorse Investment Holdings contributed all of the interests in WHR II to WildHorse Holdings, Esquisto Investment Holdings contributed all of the interests in Esquisto to Esquisto Holdings and the owner of Acquisition Co. contributed all of its interests in Acquisition Co. to Acquisition Co. Holdings and (iii) WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings contributed all of the interests in WHR II, Esquisto and Acquisition Co., respectively, to us in exchange for shares of our

F – 7

BRAZOS VALLEY LONGHORN, L.L.C.

(Successor in interest to WildHorse Resource Development Corporation)

common stock. We refer to these reorganization transactions as the “Corporate Reorganization.” As a result of the Corporate Reorganization, WHR II, Esquisto and Acquisition Co. became direct, wholly owned subsidiaries of WildHorse Resource Development Corporation.

Basis of Presentation

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

Our consolidated and combined 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 consolidated and combined statements of cash flows. Restricted cash is now being included in cash and cash equivalents when reconciling the beginning of period and end of period totals due to the adoption of a new accounting standard.

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

Investment in Unconsolidated 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. In December 2018, we accrued an additional $1.9 million capital contribution which was funded in January 2019.   

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.  We have incurred letter of credit fees of approximately $0.4 million.

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

F – 8

BRAZOS VALLEY LONGHORN, L.L.C.

(Successor in interest to WildHorse Resource Development Corporation)

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 $11.5 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 $0.7 million for the year ended December 31, 2018 is reflected on our income statement under other income (expense) as a component of the “Other income (expense)” financial statement line item.

Note 2. Summary of Significant Accounting Policies

Use of Estimates in the Preparation of Financial Statements

Preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about carrying values of assets and liabilities that are not readily apparent from other sources. We evaluate the estimates and assumptions on a regular basis; however, actual results may differ from these estimates and assumptions used in the preparation of the financial statements. Significant estimates with regard to these financial statements include (1) the estimate of proved oil, natural gas and NGL reserves and related present value estimates of future net cash flows therefrom; (2) depreciation, depletion and amortization expense; (3) valuation of accounts receivable; (4) accrued capital expenditures and liabilities; (5) asset retirement obligations; (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.

Cash and Cash Equivalents

We consider all highly liquid investment instruments purchased with original maturities of three months or less to be cash equivalents for purposes of the Consolidated and Combined Statements of Cash Flows and other statements. These investments are carried at cost, which approximates fair value. In case a book overdraft exists at the end of a period, we reclassify the negative cash amount to accounts payable.

Restricted Cash

Historically, restricted cash consisted of certificates of deposit in place to collateralize letters of credit. The letters of credit were required as part of normal business operations. The certificates of deposit were in place for a period greater than 12 months and were considered noncurrent. We had no restricted cash at December 31, 2018 and 2017.

Oil and Gas Properties

We use the successful efforts method of accounting for crude oil and natural gas producing activities. Costs to acquire mineral interests in natural gas and crude oil properties are capitalized. Significant costs associated with development wells in progress or awaiting completion are excluded from depletion until the well is completed.  We have

F – 9

BRAZOS VALLEY LONGHORN, L.L.C.

(Successor in interest to WildHorse Resource Development Corporation)

excluded capitalized costs of $98.1 million at December 31, 2018. Costs to drill exploratory wells that do not find proved reserves, delay rentals and geological and geophysical costs are expensed.

The following table reflects the net changes in capitalized exploratory well costs for the periods indicated (in thousands):

	For Year Ended December 31,
	2018		2017		2016
Balance, beginning of period	$	—	$	7,064	$	15,198
Additions to capitalized exploratory well costs pending the determination of proved reserves		—		—		60,847
Reclassifications to wells, facilities and equipment based on the determination of proved reserves		—		(7,064)		(68,981)
Capitalized exploratory well costs charged to expense		—		—		—
Balance, end of period	$	—	$	—	$	7,064

We acquire leases on acreage not associated with proved reserves or held by production with the expectation of ultimately assigning proved reserves and holding the leases with production. The costs of acquiring these leases, including primarily brokerage costs and amounts paid to lessors, are capitalized and excluded from current amortization pending evaluation. When proved reserves are assigned, the leasehold costs associated with those leases are depleted as producing oil and gas properties. Costs associated with leases not held by production are impaired when events and circumstances indicate that carrying value of the properties is not recoverable. We recorded impairment of $10.5 million, $20.8 million and $3.1 million as exploration expense for unproved oil and gas properties for the years ended December 31, 2018, 2017 and 2016, respectively.

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

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

Oil and Gas Reserves

The estimates of proved crude oil, natural gas, and natural gas liquids reserves utilized in the preparation of the financial statements are estimated in accordance with guidelines established by the Securities and Exchange Commission (“SEC”) and the Financial Accounting Standards Board (“FASB”), which require that reserve estimates be prepared under existing economic and operating conditions using a 12‑month average price with no provision for price and cost escalations in future years except by contractual arrangements. Our proved reserves are prepared by Cawley, Gillespie & Associates, Inc. ("CG&A"), a third-party independent reserve engineer.

We emphasize that reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. It is possible that, because of changes in market conditions or the inherent imprecision of these reserve estimates, the estimates of future cash inflows, future gross revenues, the amount of natural

F – 10

BRAZOS VALLEY LONGHORN, L.L.C.

(Successor in interest to WildHorse Resource Development Corporation)

gas, crude oil and natural gas liquids reserves, the remaining estimated lives of the natural gas and crude oil properties, or any combination of the above may be increased or reduced. See Note 20—“Supplemental Oil and Gas Information (Unaudited)” for further information.

Other Property and Equipment

Other property and equipment includes our sand mine, saltwater disposal wells, Burleson water assets, leasehold improvements, office furniture, automobiles, computer equipment, software, pipelines, office buildings and land. Other property and equipment is depreciated using a straight-line method over the expected useful lives of the respective assets. Leasehold improvements are amortized over the remaining term of the lease and land is not depreciated or amortized.

Capitalized Interest

We capitalize interest costs to oil and gas properties on expenditures made in connection with certain projects such as drilling and completion of new oil and natural gas wells and major facility installations. Interest is capitalized only for the period that such activities are in progress. Interest is capitalized using a weighted average interest rate based on our outstanding borrowings. For the year ended December 31, 2018, 2017 and 2016, we recorded $5.9 million, $3.1 million and $0.1 million in capitalized interest, respectively.

Properties Acquired in Asset Acquisitions and Business Combinations

For asset acquisitions, the purchase price recorded at cost and is allocated to identifiable assets on a relative fair value basis.  Therefore, we would need to determine the fair value of the assets at acquisition.

Assets and liabilities acquired in a business combination are required to be recorded at fair value. If sufficient market data is not available, we determine the fair values of proved and unproved properties acquired in transactions accounted for as business combinations by preparing our own estimates of crude oil and natural gas reserves. To compensate for the inherent risk of estimating and valuing unproved reserves, discounted future net cash flows of probable and possible reserves are reduced by additional risk-weighting factors. See Note 3—“Acquisitions and Divestitures.”

Asset Retirement Obligations

We recognize a liability equal to the fair value of the estimated cost to plug and abandon our natural gas and crude oil wells and associated equipment. The liability and the associated increase in the related long-lived asset are recorded in the period in which the related assets are placed in service or acquired. The liability is accreted to its expected future cost each period and the capitalized cost is depleted using the units-of-production method of the related asset. The accretion expense is included in depreciation, depletion and amortization expense.

The fair value of the estimated cost is based on historical experience, managements' expertise and third-party proposals for plugging and abandoning wells. The estimated remaining lives of the wells is based on reserve life estimates and federal and state regulatory requirements. At the time the related long-lived asset is placed in service, the estimated cost is adjusted for inflation based on the remaining life, then discounted using a credit-adjusted risk-free rate to determine the fair value.

Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs, including non-operated plug and abandonment expense, changes in the remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements. At the time of abandonment, we recognize a gain or loss on abandonment to the extent that actual costs do not equal the estimated costs.

F – 11

BRAZOS VALLEY LONGHORN, L.L.C.

(Successor in interest to WildHorse Resource Development Corporation)

Environmental Costs

As an owner or lessee and operator of oil and gas properties, we are subject to various federal, state and local laws and regulations relating to discharge of materials into, and protection of, the environment. Environmental expenditures that relate to an existing condition caused by past operations and that do not have future economic benefit are expensed. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable and the costs can be reasonably estimated.

Revenue 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.

Natural 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, the Company 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.

F – 12

BRAZOS VALLEY LONGHORN, L.L.C.

(Successor in interest to WildHorse Resource Development Corporation)

For the other portion of our natural gas sales contracts, our contracts are structured such that both the customer and the Company 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).  Our performance obligation under these contracts is to sell the extracted NGLs and residue gas.  We recognize revenue at a point in time (at the plant tailgate) when we have fulfilled our performance obligation.  Prior to the adoption of the new revenue standard, we did not recognize the volumes retained by our customer as an expense and we reported revenues net of the volumes they retained.

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.

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 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.

F – 13

BRAZOS VALLEY LONGHORN, L.L.C.

(Successor in interest to WildHorse Resource Development Corporation)

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 December 31, 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 -"Acquisitions and Divestitures"), 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.

F – 14

BRAZOS VALLEY LONGHORN, L.L.C.

(Successor in interest to WildHorse Resource Development Corporation)

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 Year Ended December 31, 2018
	As Reported		Without ASC 606		Increase/-
	Under ASC 606		Adoption		Decrease
Revenues:
Oil sales	$	843,244	$	843,329	$	(85)
Natural gas sales		60,129		64,896		(4,767)
NGL sales		41,961		51,052		(9,091)
Other Income		2,052		1,861		191
Operating expenses:
Lease operating expenses		61,620		63,043		(1,423)
Gathering, processing and transportation		9,856		22,703		(12,847)
Depreciation, depletion and amortization		296,685		297,295		(610)
Other operating expense		1,064		459		605
Income before income taxes		186,704		186,180		524
Income tax expense		(40,196)		(40,083)		(113)
Net income		146,508		146,097		411

	At December 31, 2018
	As Reported		Without ASC 606		Increase/-
	Under ASC 606		Adoption		Decrease
Assets:
Oil and gas properties	$	3,457,897	$	3,463,857	$	(5,960)
Accumulated depreciation, depletion and amortization		(518,054)		(519,035)		981
Other non-current assets		17,250		11,439		5,811
Liabilities:
Deferred tax liabilities		112,731		112,551		180
Stockholders' Equity
Accumulated earnings		136,773		137,785		(1,012)

	For the Year Ended December 31, 2018
	As Reported		Without ASC 606		Increase/-
	Under ASC 606		Adoption		Decrease
Cash flows from operating activities:
Net income	$	146,508	$	146,097	$	411
Depreciation, depletion and amortization		296,685		297,295		(610)
Deferred income tax expense		41,193		41,080		113
Consideration paid to customers, net of amortization		(1,817)		—		(1,817)
Cash flows from investing activities:
Additions to oil and gas properties		(1,051,891)		(1,053,811)		1,920

Incentive Units

For details regarding incentive units, please see “Note 14. Incentive Units.”

Accounts Receivable

We grant credit to creditworthy independent and major natural gas and crude oil marketing companies for the sale of crude oil, natural gas and natural gas liquids. In addition, we grant credit to our oil and gas working interest partners.

F – 15

BRAZOS VALLEY LONGHORN, L.L.C.

(Successor in interest to WildHorse Resource Development Corporation)

Receivables from our working interest partners are generally secured by the underlying ownership interests in the properties.

Accounts receivable balances primarily relate to joint interest billings and oil and gas sales, net of our interest. The accounts receivable balance generally includes one month of accrued revenues for operated oil properties, two months of accrued revenues for operated natural gas properties and three months of accrued revenues for non-operated properties net of any collections related to those periods. The accounts receivable balance also includes other miscellaneous balances.

Accounts receivable are recorded at the amount we expect to collect. We use the specific identification method of providing allowances for doubtful accounts. We recorded a provision for uncollectible accounts of $0.2 million and $0.1 million at December 31, 2018 and 2017, respectively.

Derivative Instruments

We periodically enter into derivative contracts to manage our exposure to commodity price risk. These derivative contracts, which are placed with major financial institutions that we believe have minimal credit risks, take the form of variable to fixed price commodity swaps, basis swaps, collars and deferred purchased puts. The natural gas reference price, upon which the commodity derivative contracts are based, reflects market indices that have a high degree of historical correlation with actual prices received for natural gas sales.

All derivative instruments are recorded on the balance sheet as either an asset or liability measured at fair value. Derivative instruments are netted when the right to net exists under a master netting agreement, future liabilities and assets correspond to the same commodity type and future cash flows have the same balance sheet current or non-current classification. Changes in fair value are recognized currently in earnings. Realized and unrealized gains and losses from our oil, gas and natural gas liquids derivatives are recorded as a component of “Other income (expense)” on our Statements of Consolidated and Combined Operations. We compute the fair value of the unrealized gains and losses of our derivative instruments using forward prices and dealer quotes provided by a third party.

For our forward commodity contracts that meet the definition of a derivative, we have elected the normal purchases and normal sales scope exclusion, because we believe it is probable that physical delivery of the product will occur under the contract and we do not intend on net settling the contract. Therefore, all activity under these contracts was recorded as revenue in our consolidated financial statements.

See Note 5—“Risk Management and Derivative and Other Financial Instruments” for additional information regarding our derivative instruments.

Corporate Lease Expenses

We record escalating lease expenses for our corporate office over the life of the lease on a straight-line basis.

Debt Issuance Costs

Debt issuance costs associated with line-of-credit arrangements, including arrangements with no outstanding borrowings, are classified as an asset, and amortized over the term of the arrangements. Debt issuance costs related to term loans and senior notes are presented as a direct deduction from the carrying amount of the associated debt liability and amortized over the term of the associated debt using the effective yield method.

Fair Value Measurements

Accounting guidance for fair value measurements establishes a fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three levels. The fair value hierarchy gives the highest priority to

F – 16

BRAZOS VALLEY LONGHORN, L.L.C.

(Successor in interest to WildHorse Resource Development Corporation)

quoted market prices (unadjusted) in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Level 2 inputs are inputs, other than quoted prices included within Level 1, which are observable for the asset or liability, either directly or indirectly. We use Level 1 inputs when available as Level 1 inputs generally provide the most reliable evidence of fair value. See Note 4—“Fair Value Measurements of Financial Instruments.”

Income Taxes

We are a corporation subject to federal and certain state income taxes. Prior to our initial public offering, we were primarily organized as pass-through entities for federal income tax purposes and were not subject to federal income taxes.

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 carry forwards. 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 and Combined 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.

Commitments and Contingencies

Accruals for loss contingencies arising from claims, assessments, litigation, environmental and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. These accruals are adjusted as additional information becomes available or circumstances change.

Supplemental Cash Flow Information

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

	For Year Ended December 31,
	2018		2017		2016
Supplemental cash flows:
Cash paid for interest, net of capitalized interest	$	48,717	$	12,246	$	7,152
Noncash investing activities:
Increase (decrease) in capital expenditures in accounts payables and accrued liabilities		(82,358)		134,589		(4,492)
(Increase) decrease in accounts receivable related to capital expenditures and acquisitions		(1,247)		(847)		(5,175)

Due to Hurricane Harvey, the Internal Revenue Service (“IRS”) granted relief to affected taxpayers by allowing taxpayers to defer the deadline for tax return filings and payment of estimated taxes to January 31, 2018. The Company paid $2.3 million related to its 2017 estimated alternative minimum tax to the IRS on January 31, 2018.

F – 17

BRAZOS VALLEY LONGHORN, L.L.C.

(Successor in interest to WildHorse Resource Development Corporation)

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. The Company adopted this guidance on January 1, 2018 on a prospective basis 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 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, which requires classification of leases as finance or operating. The classification is 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. The new standard is effective for financial statements issued for annual periods beginning after December 15, 2018 and interim periods within those fiscal years. 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 adopted the standard using the effective date method on January 1, 2019.

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 old 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 has made this accounting policy election beginning January 1, 2019.

F – 18

BRAZOS VALLEY LONGHORN, L.L.C.

(Successor in interest to WildHorse Resource Development Corporation)

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 has made this accounting policy election for all classes of assets beginning January 1, 2019.

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 has made this accounting policy election beginning January 1, 2019.

The Company is a lessee under various agreements for office space, compressors and other equipment.  Though we are finalizing the implementation of certain processes to monitor and track all lease information, we anticipate leases as recognized under the new standard will create right-of-use assets and initial lease liabilities between $35 million and $65 million on our consolidated balance sheet.

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

We account for third-party acquisitions under the acquisition method. The assets acquired and the liabilities assumed have been measured at fair value based on various estimates. These estimates are based on key assumptions related to the business combination, including reviews of publicly disclosed information for other acquisitions in the industry, historical experience of the companies, data that was available through the public domain and due diligence reviews of the acquired businesses. Acquisition-related transaction costs and acquisition-related restructuring charges are not included as components of consideration transferred but are accounted for as expenses in the period in which the costs are incurred.

Acquisition-related costs

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

For the Year Ended December 31,
	2018	2017		2016
$	1,117	$	4,348	$	553

2018 Acquisitions

Eagle Ford Shale Acquisitions. During the year ended December 31, 2018, we closed on multiple transactions to acquire certain acreage and associated production from third parties for approximately $53.8 million.   These transactions were accounted for as asset acquisitions since substantially all the fair value was concentrated in a group of similar assets.  As such, an additional $1.5 million of acquisition costs were capitalized as part of these acquisitions.  We assigned $48.0 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 $66.1 million at December 31, 2018.

F – 19

BRAZOS VALLEY LONGHORN, L.L.C.

(Successor in interest to WildHorse Resource Development Corporation)

2017 Acquisitions

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

On June 30, 2017, we completed the Acquisition. The aggregate purchase price for the Acquisition, as described in the Acquisition Agreements, consisted of an aggregate of approximately $533.6 million of cash to the APC Subs and approximately 5.5 million shares of our common stock valued at approximately $60.8 million to KKR (collectively, the “Adjusted Purchase Price”). The common stock portion of the Adjusted Purchase Price payable to KKR was issued pursuant to a Stock Issuance Agreement that was executed on May 10, 2017, by and among us and KKR. For the year ended December 31, 2017, revenues of $42.6 million were recorded in the statement of operations, which generated $11.1 million of income subsequent to the closing date.

The following table summarizes the fair value assessment of the assets acquired and liabilities assumed as of the closing 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 year ended December 31, 2017 and 2016 as though the Acquisition had been completed on January 1, 2016 (in thousands, except per share amounts). The unaudited pro forma financial information was derived from the historical combined statements of operations of the predecessor and previous owners and adjusted to include: (i) the revenues and direct operating expenses associated with oil and natural gas properties acquired, (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

F – 20

BRAZOS VALLEY LONGHORN, L.L.C.

(Successor in interest to WildHorse Resource Development Corporation)

operations that would have occurred had the Acquisition occurred on the basis assumed above, nor is such information indicative of expected future results of operations.

	For the Year Ended December 31,
	2017		2016
Revenues	$	475,396	$	226,502
Net income (loss)	$	71,287	$	(11,290)
Earnings per share (basic and diluted)	$	0.51	$	(0.10)

Burleson 2017 Acquisitions. During the year ended December 31, 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 $19.7 million, of which $11.6 million was allocated to unproved oil and natural gas properties.

2016 Acquisitions

Burleson North Acquisition. On December 19, 2016, in connection with our initial public offering, we completed an acquisition of approximately 158,000 net acres of oil and natural gas properties adjacent to our existing Eagle Ford Acreage (the “Burleson North Acquisition”). Funds wired on December 19, 2016 were $389.8 million. During the three months ended March 31, 2017, we received a post-closing receipt of $3.9 million. We allocated $162.9 million of the purchase price to unproved oil and natural gas properties.  For the year ended December 31, 2016, revenues of $2.0 million were recorded in the statement of operations and generated a loss of approximately $0.4 million subsequent to the closing date.

The following table summarizes the fair value assessment of the assets acquired and liabilities assumed as of the acquisition date after customary post-closing adjustments (in thousands):

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

Rosewood Acquisition. On December 19, 2016, we acquired from certain third parties approximately 7,500 net acres, consisting primarily of additional working interests in our Eagle Ford Acreage in Lee County (the “Rosewood Acquisition”). The closing of the acquisition occurred contemporaneously with the closing of our initial public offering, and we issued 1,308,427 shares to such third parties as consideration. We allocated $18.3 million of the purchase price to unproved oil and natural gas properties with the remainder allocated to proved oil and natural gas properties.

November Acquisition. On November 8, 2016, Esquisto acquired from certain third parties approximately 4,900 net acres and nine producing wells in Burleson County for approximately $30.0 million (the “November Acquisition”), of which $29.4 million of the purchase price was allocated to unproved oil and natural gas properties with the remainder allocated to proved oil and natural gas properties.

The following table summarizes the fair value assessment of the assets acquired and liabilities assumed as of the acquisition date for the November Acquisition and Rosewood Acquisition (in thousands):

		Rosewood Acquisition		November Acquisition
Oil and gas properties	$	19,626	$	29,973

F – 21

BRAZOS VALLEY LONGHORN, L.L.C.

(Successor in interest to WildHorse Resource Development Corporation)

The following unaudited pro forma combined results of operations are provided for the years ended December 31, 2016 as though the Burleson North Acquisition had been completed on January 1, 2015. The unaudited pro forma financial information was derived from the historical combined statements of operations of the Company, the predecessor and previous owners and adjusted to include: (i) the revenues and direct operating expenses associated with oil and gas properties acquired and (ii) depletion expense applied to the adjusted basis of the properties acquired. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of expected future results of operations.

	For Year Ended December 31,
	2016
Revenues	$	176,082
Net loss	$	(34,894)
Basic and diluted earnings per unit		n/a

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 final purchase price adjustments of $4.8 million, the final sales price of $211.2 million has been fully collected at December 31, 2018. The Company has paid $3.8 million in expenses related to the divestiture and has received $0.4 million in contingent payments from Tanos.

In addition, the Company could receive contingent payments of up to $35.0 million, based on the number of wells spud on such properties over the next three 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. We received $0.4 million in contingent payments 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 customary preliminary purchase price adjustments, we recorded an impairment charge of $214.3 million during the first quarter of 2018 to adjust the carrying amount of the disposal group (“NLA Disposal Group”) to its 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 years ended December 31, 2018 and 2017, the NLA Disposal Group had pre-tax losses of $202.7 million and $5.9 million, respectively.

During the year ended December 31, 2018, we recognized a gain of $2.8 million. We received a $4.8 million final settlement payment from Tanos in October 2018.  We provided Tanos with transitional accounting and land services during the three months ended June 30, 2018 and recognized $0.9 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

F – 22

BRAZOS VALLEY LONGHORN, L.L.C.

(Successor in interest to WildHorse Resource Development Corporation)

and predictable than those based primarily on unobservable inputs (Level 3). The characteristics of fair value amounts classified within each level of the hierarchy are described as follows:

Level 1 — Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. An active market is one in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 — Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. At December 31, 2018 and 2017, all of the derivative instruments reflected on the accompanying balance sheets were considered Level 2.

Level 3 — Measure based on prices or valuation models that require inputs that are both significant to the fair value measurement and are less observable from objective sources (i.e., supported by little or no market activity).

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 December 31, 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 December 31, 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.

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

	Fair Value Measurements at December 31, 2018
	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	$	—	$	72,710	$	—	$	72,710
Liabilities:
Commodity derivatives	$	—	$	508	$	—	$	508

F – 23

BRAZOS VALLEY LONGHORN, L.L.C.

(Successor in interest to WildHorse Resource Development Corporation)

	Fair Value Measurements at December 31, 2017
	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 gas properties. We did not record impairments on proved properties for the year ended December 31, 2018, 2017 and 2016.

· Unproved oil and natural gas properties and other assets are reviewed for impairment based on passage of time or geologic factors.  Information such as remaining lease terms, drilling results, reservoir performance, seismic interpretation or future plans to develop acreage is also considered.  When unproved properties are deemed to be impaired, the expense is recorded as a component of exploration expenses.  For the years ended December 31, 2018, 2017 and 2016, we recorded $10.5 million, $20.8 million and $3.1 million of impairments of unproved properties, respectively.

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

F – 24

BRAZOS VALLEY LONGHORN, L.L.C.

(Successor in interest to WildHorse Resource Development Corporation)

Note 5. Risk Management and Derivative and Other Financial 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, historically, used fixed price commodity swaps, basis swaps, collars 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. Collars consist of a sold call and a purchased put that establish a ceiling and floor price for expected future oil and natural gas sales. We recognize all derivative instruments at fair value; however, certain of our derivative instruments have a deferred premium. The deferred premium is factored into the fair value measurement and where the Company agrees to defer the premium paid or received until the time of settlement. Cash received on settled derivative positions during the years ended December 31, 2018 and 2017 is net of deferred premiums of $9.3 million and $6.3 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, certain of which are also lenders under the 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 December 31, 2018 we had net derivative assets of $72.2 million. Had certain counterparties failed completely to perform according to the terms of existing contracts, we would have the right to offset $72.2 million against amounts outstanding under our revolving credit facility, thereby eliminating any credit exposure.

F – 25

BRAZOS VALLEY LONGHORN, L.L.C.

(Successor in interest to WildHorse Resource Development Corporation)

The following derivative contracts were in place at December 31, 2018:

	2019		2020
Crude Oil Derivative Contracts:
Fixed price swap contracts:
Volume (Bbls)		6,652,369		4,511,681
Weighted-average fixed price	$	54.45	$	53.49
Put options:
Volume (Bbls)		1,749,757		—
Weighted-average floor price	$	53.83	$	—
Weighted-average put premium	$	(5.43)	$	—
Natural Gas Derivative Contracts:
Fixed price swap contracts:
Volume (MMBtu)		6,425,146		4,846,020
Weighted-average fixed price	$	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 December 31, 2018 and 2017. There was no cash collateral received or pledged associated with our derivative instruments since the counterparties to our derivative contracts are lenders under our collective credit agreements.

		Asset Derivatives				Liability Derivatives
		(in thousands)				(in thousands)
Type	Balance Sheet Location	2018		2017		2018		2017
Commodity contracts	Short-term derivative instruments	$	54,131	$	2,336	$	508	$	58,074
Netting arrangements	Short-term derivative instruments		—		—		—		—
Net recorded fair value		$	54,131	$	2,336	$	508	$	58,074
Commodity contacts	Long-term derivative instruments	$	18,579	$	86	$	—	$	18,676
Netting arrangements	Long-term derivative instruments		—		—		—		—
Net recorded fair value		$	18,579	$	86	$	—	$	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 Statements of Combined and Consolidated Financial Statements. The following table details the gains and losses related to derivative instruments for the years ending December 31, 2018, 2017 and 2016 (in thousands):

	Statements of	For the Year Ended December 31,
	Operations Location	2018		2017		2016
Commodity derivative contracts	Gain (loss) on derivative instruments	$	35,393	$	(55,483)	$	(26,771)

F – 26

BRAZOS VALLEY LONGHORN, L.L.C.

(Successor in interest to WildHorse Resource Development Corporation)

Note 6. Accounts Receivable

Accounts receivable consist of the following (in thousands):

	At December 31,
	2018		2017
Oil, gas and NGL sales	$	70,900	$	67,584
Joint interest billings		17,491		9,467
Severance tax		1,352		171
Derivative receivable		308		—
North Louisiana Settlement receivable		—		5,955
Environmental remediation		1,511		—
Other current receivables		196		1,026
Allowance for doubtful accounts		(200)		(100)
Total	$	91,558	$	84,103

The following table presents our allowance for doubtful accounts activity for the periods indicated (in thousands):

	2018		2017		2016
Balance at beginning of period	$	100	$	100	$	50
Charged to costs and expenses		100		—		50
Balance at end of period	$	200	$	100	$	100

Note 7. Accrued Liabilities

Accrued liabilities consist of the following (in thousands):

	At December 31,
	2018		2017
Capital expenditures	$	80,897	$	162,260
Preferred stock cash dividends		4,479		—
Deferred rent		—		410
Lease operating expense		6,604		5,796
General and administrative		4,335		1,642
Severance and ad valorem taxes		5,283		3,463
Interest expense		20,122		17,177
Derivative payable		1,746		5,281
Income taxes		—		991
Other accrued liabilities		1,167		2,932
Total	$	124,633	$	199,952

F – 27

BRAZOS VALLEY LONGHORN, L.L.C.

(Successor in interest to WildHorse Resource Development Corporation)

Note 8. Asset Retirement Obligations

The following table presents the changes in the asset retirement obligations for the year ended December 31, 2018 and 2017 (in thousands):

	For the Year Ended December 31,
	2018		2017
Asset retirement obligations at beginning of period	$	14,557	$	11,033
Accretion expense		573		713
Liabilities incurred		743		3,137
Liabilities settled		—		—
Revisions		70		(326)
Disposition of wells and gathering system		(7,627)		—
Asset retirement obligations at end of period		8,316		14,557
Less: current portion		90		90
Asset retirement obligations – long-term	$	8,226	$	14,467

Note 9. Long Term Debt

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

	At December 31,
Debt Obligation	2018		2017
WRD revolving credit facility	$	504,000	$	286,353
2025 Senior Notes (as defined below) (1)		700,000		500,000
Unamortized net discounts - 2025 Senior Notes		(782)		(4,914)
Unamortized debt issuance costs - 2025 Senior Notes		(11,842)		(10,843)
Total long-term debt	$	1,191,376	$	770,596

(1) The estimated fair value of this fixed-rate debt was $661.5 million and $511.3 million at December 31, 2018 and 2017, respectively. The estimated fair values are based on quoted market prices and is 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):

	December 31,
Credit Facility	2018
WRD revolving credit facility	$	1,300,000

Revolving Credit Facility

On December 19, 2016 after the closing of our initial public offering, 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, which had an initial borrowing base of $450.0 million but was automatically reduced to $362.5 million in connection with the consummation of our 2025 Senior Notes (defined below) offering on February 1, 2017.

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

F – 28

BRAZOS VALLEY LONGHORN, L.L.C.

(Successor in interest to WildHorse Resource Development Corporation)

among the Company, the Administrative Agent and the other agents and lenders party thereto (as amended, the “Credit Agreement”).

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

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

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 to the Credit Agreement (the “Fourth Amendment”).  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 a Fifth Amendment to the Credit Agreement (the “Fifth Amendment”).  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

Our revolving credit facility is reserve-based, and thus our borrowing base is primarily based on the estimated value of our oil and natural gas properties and our commodity derivative contracts as determined by our lenders in their sole discretion consistent with their normal and customary oil and gas lending practices semi-annually (in the case of scheduled redeterminations), from time to time at our election in connection with material acquisitions, or no more frequently than twice in any fiscal year at the request of the required lenders or us (in the case of interim redeterminations), in each case based on engineering reports with respect to our estimated oil, NGL and natural gas reserves, and our commodity derivative contracts. Unanimous approval by the lenders is required for any increase to the borrowing base pursuant to a redetermination, while only required lender approval is required to maintain or decrease the borrowing base pursuant to a redetermination. The borrowing base may also automatically decrease upon the issuance of certain debt, including senior notes, the sale or other disposition of certain assets and the early termination of certain swap agreements. In the future, we may be unable to access sufficient capital under the Credit Agreement as a result of (i) a decrease in our borrowing base due to a borrowing base redetermination or (ii) an unwillingness or inability on the part of our lenders to meet their funding obligations.

F – 29

BRAZOS VALLEY LONGHORN, L.L.C.

(Successor in interest to WildHorse Resource Development Corporation)

A decline in commodity prices could result in a redetermination that lowers our borrowing base and, in such case, we could be required to repay any indebtedness in excess of the borrowing base, or we could be required to pledge other oil and natural gas properties as additional collateral. If a redetermination of our borrowing base results in our borrowing base being less than our aggregate elected commitments, our aggregate elected commitments will be automatically reduced to the amount of such reduced borrowing base. We do not anticipate having any substantial unpledged properties, and we may not have the financial resources in the future to make any mandatory principal prepayments required under the Credit Agreement.

Borrowings under our revolving credit facility are secured by liens on substantially all of our properties, but in any event, not less than 85% (or 75% with respect to certain properties prior to February 2, 2017) of the total value, as determined by the administrative agent, of the proved reserves attributable to our oil and natural gas properties using a discount rate of 9%, all of our equity interests in any future guarantor subsidiaries and all of our other assets including personal property but excluding equity interests in and assets of unrestricted subsidiaries.

Additionally, borrowings under our revolving credit facility will bear interest, at our option, at either: (i) the Alternate Base Rate, which is based on the greatest of (x) the prime rate as determined by the Administrative Agent, (y) the federal funds effective rate plus 0.50%, and (z) the adjusted LIBOR for a one month interest period plus 1.0%, in each case, plus a margin that varies per annum according to the total commitments usage (which is the ratio of outstanding borrowings and letters of credit to the least of the total commitments, the borrowing base and the aggregate elected commitments then in effect), (ii) the adjusted LIBOR plus a margin that varies per annum according to the total commitment usage or (iii) the applicable LIBOR market index rate plus a margin that varies per annum according to the total commitment usage. The unused portion of the total commitments are subject to a commitment fee that varies per annum according to our total commitments usage.

The Credit Agreement requires us to maintain (x) a ratio of total debt to EBITDAX (as defined under our revolving credit facility) of not more than 4.00 to 1.00 and (y) a ratio of current assets (including availability under the facility) to current liabilities of not less than 1.00 to 1.00.

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

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

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

2025 Senior Notes

On February 1, 2017, we completed a private placement of $350.0 million aggregate principal amount of 6.875% senior unsecured notes due 2025 (the “2025 Senior Notes”).  The 2025 Senior Notes were issued at a price of 99.244% of par and resulted in net proceeds of approximately $338.6 million.  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.

F – 30

BRAZOS VALLEY LONGHORN, L.L.C.

(Successor in interest to WildHorse Resource Development Corporation)

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.

The indenture governing the 2025 Senior Notes (the "2025 Indenture") contains customary reporting covenants (including furnishing quarterly and annual reports to the holders of the 2025 Senior Notes) and restrictive covenants that, among other things, restrict the ability of the Company and its subsidiaries to: (i) pay dividends on, purchase or redeem the Company's equity interests or purchase or redeem subordinated debt; (ii) make certain investments; (iii) incur or guarantee additional indebtedness or issue certain types of equity securities; (iv) create or incur certain secured debt; (v) sell assets; (vi) consolidate, merge or transfer all or substantially all of the Company's assets; (vii) enter into agreements that restrict distributions or other payments from the Company's restricted subsidiaries to the Company; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries. These covenants are subject to a number of important qualifications and limitations. In addition, most of the covenants will be terminated before the 2025 Senior Notes mature if at any time no default or event of default exists under the 2025 Indenture and the 2025 Senior Notes receive an investment grade rating from both of two specified ratings agencies. The 2025 Indenture also contains customary events of default.

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 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.

Pursuant to a registration rights agreement entered into in connection with the issuance of the April Notes, we agreed to file a registration statement with the SEC so that holders of the April Notes could exchange the unregistered April Notes for registered notes that have substantially identical terms. In addition, we agreed to exchange the unregistered guarantees related to the April Notes for registered guarantees having substantially identical terms. On September 24, 2018, 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.

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.

F – 31

BRAZOS VALLEY LONGHORN, L.L.C.

(Successor in interest to WildHorse Resource Development Corporation)

Weighted-Average Interest Rates

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

	At December 31,
Credit Facility	2018		2017		2016
WRD revolving credit facility	4.06	%	3.60	%	3.52	%
WHR II revolving credit facility terminated December 2016	n/a		n/a		3.03	%
Esquisto - revolving credit facility terminated December 2016	n/a		n/a		2.84	%
Esquisto - revolving credit facility terminated January 2016	n/a		n/a		2.97	%
Esquisto - Second lien terminated in January 2016	n/a		n/a		9.50	%

Unamortized Deferred Financing Costs

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

	At December 31,
	2018		2017
WRD revolving credit facility
Current	$	1,823	$	1,203
Long-term		3,592		3,573
6.875% senior unsecured notes, due February 2025		11,842		10,843
Total	$	17,257	$	15,619

Note 10. Preferred Stock

Preferred Stock Issuance

We partially funded the Acquisition through the issuance of 435,000 shares of Preferred Stock in exchange for $435.0 million on June 30, 2017, pursuant to a Preferred Stock Purchase Agreement (the “Preferred Stock Purchase Agreement”), by and among us and CP VI Eagle Holdings, L.P. (the “Carlyle Investor”), an affiliate of The Carlyle Group, L.P.

	Series A Perpetual
	Convertible Preferred
	Stock
	(in thousands)
Balance at December 31, 2016	$	—
Issue of preferred stock in connection with the Acquisition		435,000
Costs incurred related to the issuance of preferred stock		(2,663)
Accrual of preferred stock paid-in-kind dividend		13,146
Balance at December 31, 2017		445,483
Paid-in-kind dividend		2,243
Beneficial conversion feature ("BCF")		(1,872)
Amortization of BCF		1,872
Balance at December 31, 2018	$	447,726

The Preferred Stock ranks senior to our common stock with respect to dividend rights and with respect to rights on liquidation, winding-up and dissolution. The Preferred Stock had an initial Accreted Value (as defined in the Certificate of Designations 6.00% Series A Perpetual Convertible Preferred Stock (the “Certificate”)) of $1,000 per share and is

F – 32

BRAZOS VALLEY LONGHORN, L.L.C.

(Successor in interest to WildHorse Resource Development Corporation)

entitled to a dividend at a rate of 6% per annum on the Accreted Value payable in cash if, as and when declared by our board of directors. If a cash dividend is not declared and paid in respect of any dividend payment period, then the Accreted Value of each outstanding share of Preferred Stock will automatically be increased by the amount of the dividend otherwise payable for such dividend payment period. Any increase in the Accreted Value, among other things, increases the number of shares of common stock issuable upon conversion of each share of Preferred Stock. With respect to each of the quarterly periods from issuance until January 31, 2018, our board of directors elected to pay the dividend on the preferred stock by increasing the Accreted Value rather than paying cash. As such, as of January 31, 2018, the Accreted Value was $1,024 per share. The Preferred Stock also participates in dividends and distributions on our common stock on an as-converted basis. If at any time following December 30, 2019, the closing sale price of our common stock equals or exceeds 130% of the Conversion Price (as defined below) for at least 25 consecutive trading days, our obligation to pay dividends on the Preferred Stock shall terminate permanently.

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

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

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

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

Until conversion, the holders of the Preferred Stock vote together with our common stock on an as-converted basis and also have rights to vote as a separate class on certain customary matters impacting the Preferred Stock.

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

F – 33

BRAZOS VALLEY LONGHORN, L.L.C.

(Successor in interest to WildHorse Resource Development Corporation)

Preferred Stock and shares of our common stock, including shares of common stock issuable upon the conversion of Preferred Stock, representing 5% or more of our outstanding common stock on an as-converted basis.

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

On October 31, 2017, an aggregate quarterly dividend of $6.558 million was paid by an automatic increase to the Accreted Value of each such share of Preferred Stock as of the date of issuance. The declared dividend was for the period beginning on August 1, 2017 to October 31, 2017 and was paid to holders of record on October 15, 2017.

On January 31, 2018, an aggregate quarterly dividend of $6.656 million was paid by an automatic increase to the Accreted Value of each such share of Preferred Stock as of the date of issuance. The declared dividend was for the period beginning on 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 beneficial conversion feature that was amortized over the earliest Preferred Stock conversion period as additional dividends. The table below summarizes the quarterly cash dividends paid to holders of record at the dates indicated of our preferred stock:

	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
October 15, 2018	August 1, 2018	October 31, 2018	$	6.756	October 31, 2018

Subsequent Event.On January 31, 2019, an aggregate quarterly cash dividend of $6.831 million was paid to holders of record as of January 15, 2019 for the period from November 1, 2018 to February 1, 2019.  In connection with the Merger and in accordance with the voting agreement with Carlyle, all the Company's preferred stock was converted into the Company's common stock prior to the effective time of the Merger.

F – 34

BRAZOS VALLEY LONGHORN, L.L.C.

(Successor in interest to WildHorse Resource Development Corporation)

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 shares issued since December 31, 2016:

Balance, December 31, 2016	91,680,441
Common stock issued	7,815,225
Restricted common shares issued	1,676,284
Restricted common shares forfeited	(717)
Repurchase of vested restricted shares (2)	(33,956)
Balance, December 31, 2017	101,137,277
Restricted common shares issued	1,076,165
Restricted common shares forfeited	(63,768)
Repurchase of vested restricted shares (2)	(355,819)
Balance, December 31, 2018	101,793,855

(1) We were incorporated in August 2016 under the laws of the State of Delaware.

(2) Restricted common shares are generally net-settled by 2016 LTIP participants to cover the required withholding tax upon vesting of restricted stock awards. Participants surrendered shares with value equivalent to the employee's minimum statutory obligation for the applicable income and other employment taxes. Total payments remitted for the employees' tax obligations to the appropriate taxing authorities were approximately $6.9 million and $0.6 million for the years ended December 31, 2018 and 2017, respectively. These net-settlements had the effect of shares repurchased by the Company as they reduced the number of shares that would have otherwise been outstanding as a result of the vesting and did not represent an expense to the Company.

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

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

See “Note 13—Long Term Incentive Plans” for additional information regarding the shares of restricted common stock that were granted during the years ended December 31, 2018 and 2017. Restricted shares of common stock are considered issued and outstanding on the grant date of the restricted stock award.

Dividend Policy

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

Predecessor Equity

The predecessor received capital contributions of $10.8 million from its members during the year ended December 31, 2016, respectively. Promissory note advances were available to management to fund future capital commitments and carried an interest rate of 2.5%.

F – 35

BRAZOS VALLEY LONGHORN, L.L.C.

(Successor in interest to WildHorse Resource Development Corporation)

The table below summarizes advances and payments of the promissory note advances for the year ended December 31, 2016 (in thousands):

	Principal		Interest		Total
Balance, December 31, 2015	$	2,367	$	76	$	2,443
Advances		101		—		101
Payments		(20)		—		(20)
Accrued Interest		—		51		51
Dissolution		(2,448)		(127)		(2,575)
Balance, December 31, 2016	$	—	$	—	$	—

On November, 9, 2016, the management members conveyed to the predecessor certain ownership interests in the predecessor in exchange for the discharge in full and the termination of all the promissory note advances then outstanding. The promissory note advances and the related accrued interest receivable are presented in the balance sheet as a deduction from predecessor equity.

Previous Owner Equity

The previous owner received capital contributions of $97.0 million from its members during the year ended December 31, 2016. As a result of the Corporate Reorganization (as discussed in Note 1) and common control accounting, Esquisto's net assets were recorded at NGP's historical cost basis.

Note 12. Earnings Per Share

The following sets forth the calculation of earnings (loss) per share, or EPS, for the years ended December 31, 2018, 2017 and 2016 (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 Year Ended December 31,
	2018 (1)		2017 (2)		2016 (3)
Numerator:
Net income (loss) available to WRD	$	146,508	$	49,880	$	(10,397)
Less: Preferred stock dividends		28,862		13,146		—
Less: Undistributed earnings allocated to participating securities		30,344		5,612		—
Net income (loss) available to common stockholders	$	87,302	$	31,122	$	(10,397)
Denominator:
Weighted-average common shares outstanding (in thousands)		99,498		96,324		91,327
Basic EPS	$	0.88	$	0.32	$	(0.11)
Diluted EPS	$	0.88	$	0.32	$	(0.11)

(1) The Company used the two-class method for both basic and diluted EPS.  For the year ended December 31, 2018, 775 incremental restricted shares were excluded in the calculation of diluted EPS due to their antidilutive effect under the treasury stock method.  For the for the year ended December 31, 2018, 32,363 shares were excluded from the calculation of diluted EPS due to their antidilutive effect under the if-converted method.

(2) The Company used the two-class method for both basic and diluted EPS.  For the year ended December 31, 2017, 628 incremental restricted shares were excluded in the calculation of diluted EPS due to their antidilutive effect under the treasury stock method.  For the year ended December 31, 2017, 16,008 shares were excluded from the calculation of diluted EPS due to their antidilutive effect under the if-converted method.

(3) The Company used the two-class method for both basic and diluted EPS. For the year ended December 31, 2016, restricted shares were excluded from the calculation of diluted EPS due to their antidilutive effect as we were in a loss position for the period.

F – 36

BRAZOS VALLEY LONGHORN, L.L.C.

(Successor in interest to WildHorse Resource Development Corporation)

Note 13. Long Term Incentive Plans

In connection with the initial public offering, our Board 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 share awards granted under the 2016 LTIP for the periods presented:

		Weighted-Average
	Number of	Grant Date Fair
	Shares	Value per Share (1)
Restricted common shares outstanding at January 1, 2016	—	$	—
Granted (2)	353,334	$	14.50
Restricted common stock outstanding at December 31, 2016	353,334	$	14.50
Granted (2)	1,676,284	$	13.88
Forfeited	(717)	$	13.94
Vested	(131,111)	$	14.50
Restricted common stock outstanding at December 31, 2017	1,897,790	$	13.95
Granted (2)	1,076,165	$	25.57
Forfeited	(63,768)	$	16.45
Vested	(1,069,933)	$	15.66
Restricted common stock outstanding at December 31, 2018	1,840,254	$	19.66

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

(2) The aggregate grant date fair value of restricted common share awards granted in 2017 was $23.3 million based on grant date market price ranging from $10.91 to $14.22 per share. The aggregate grant date fair value of restricted common share awards granted in 2018 was $27.5 million based on grant date market price ranging from $18.14 to $27.07 per share. Our awards have contractual vesting periods between one and three years.

For the year ended December 31, 2018, 2017 and 2016, we recorded $19.5 million, $6.6 million and less than $0.1 million of recognized compensation expense associated, respectively, with these awards. Unrecognized compensation cost associated with the restricted common share awards was an aggregate of $28.7 million at December 31, 2018. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 2.0 years. We elect to account for forfeitures on share-based payments by recognizing forfeitures of awards as they occur.

Subsequent event. In January 2019, all outstanding shares granted under the 2016 LTIP were supervested.  On February 1, 2019, the shares were converted to common shares of Chesapeake using the conversion method elected by the shareholder as outlined in the merger agreement.

Note 14. Incentive Units

Prior to December 31, 2018, certain officers and employees were granted awards of incentive units in WildHorse Investment Holdings and WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings (the “LLCs”). 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 December 31, 2018. 

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).

F – 37

BRAZOS VALLEY LONGHORN, L.L.C.

(Successor in interest to WildHorse Resource Development Corporation)

Subsequent event. In connection with the Merger, all unvested incentive units became fully vested in accordance with their terms and will remain outstanding following the effective time of the merger. See “Note 1—Organization and Basis of Presentation” for information regarding our merger with Chesapeake.

Note 15. Related Party Transactions

Corporate Reorganization

As described in Note 1, in connection with our initial public offering, we completed certain reorganization transactions pursuant to which we acquired all of the interests in WHR II, Esquisto and Acquisition Co. owned by WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings, respectively, in exchange for 21,200,084 shares, 38,755,330 shares and 2,563,266 shares, respectively, of our common stock.

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. We received $1.2 million and $2.2 million for the years ended December 31, 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 the year ended December 31, 2018, we had disbursements of $0.1 million to Archrock.

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 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 year ended December 31, 2017, we had disbursements of $0.2 million related to director and advisory fees and reimbursement of initial public offering costs. We did not have any related party payments or receipts for the year ended December 31, 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 year ended December 31, 2018 we had disbursements of $0.2 million to certain CH4 Energy entities for office rental and parking payments. During the year ended December 31, 2017 we had disbursements of $0.5 million to certain CH4 Energy entities, of which $0.3 million was a reimbursement of landman services and expenses incurred in 2016 that CH4 Energy entities had paid on our behalf and $0.2 million was related to office rental and parking payments.   Additionally, the Company acquired incremental leasehold interests from CH4 Energy entities for $0.1 million during the year ended December 31, 2017 in connection with the Corporate Reorganization.

F – 38

BRAZOS VALLEY LONGHORN, L.L.C.

(Successor in interest to WildHorse Resource Development Corporation)

Cretic Energy Services, LLC. During the year ended December 31, 2017, we had disbursements of $0.2 million to Cretic Energy Services, LLC, an NGP affiliated company, for services related to our drilling and completion activities. We did not have any related party payments for the year ended December 31, 2018.

Related Party Agreements

Registration Rights Agreement. We are parties to an amended and restated registration rights agreement with WildHorse Investment Holdings, Esquisto Investment Holdings, WildHorse Holdings, Esquisto Holdings, Acquisition Co. Holdings, NGP XI US Holdings, L.P. (“NGP XI”), Jay Graham and Anthony Bahr (collectively, the “Sponsor Group”), CP VI Eagle Holdings, L.P. (the “Carlyle Investor”), and EIGF Aggregator LLC, TE Admiral A Holding L.P. and Aurora C‑1 Holding L.P. (collectively, “KKR”). Pursuant to the amended and restated registration rights agreement, we have agreed to register the sale of shares of our common stock under certain circumstances.

Demand rights. Subject to the limitations set forth below, at any time after (i) for the Sponsor Group, the 180 day lock-up period, related to our initial public offering, or (ii) for the Carlyle Investor, June 30, 2018, and subject to the limitations set forth below, each member of the Sponsor Group and the Carlyle Investor (or its permitted transferees) have the right to require us by written notice to prepare and file a registration statement registering the offer and sale of a certain number of its shares of our common stock. Generally, we are required to provide notice of the request to certain other holders of our common stock who may, in certain circumstances, participate in the registration. Subject to certain exceptions, we will not be obligated to effect a demand registration within 90 days after the closing of any underwritten offering of shares of our common stock. Further, we are not obligated to effect more than a total of four demand registrations for each of WildHorse Holdings, Esquisto Holdings and WHE Holdings, and more than a total of six demand registrations for the Carlyle Investor.

Subject to certain exceptions, we are also not be obligated to effect any demand registration in which the anticipated aggregate offering price for our common stock included in such offering is less than $75 million. We have in effect a registration on Form S‑3, therefore, any such demand registration would be for a shelf registration statement. We will be required to use reasonable best efforts to maintain the effectiveness of any such registration statement until the earlier of (i) 180 days (or two years in the case of a shelf registration statement) after the effective date thereof or (ii) the date on which all shares covered by such registration statement have been sold (subject to certain extensions).

In addition, each member of the Sponsor Group (or its permitted transferees) have the right to require us, subject to certain limitations, to effect a distribution of any or all of its shares of our common stock by means of an underwritten offering. In general, any demand for an underwritten offering (other than the first requested underwritten offering made in respect of a prior demand registration and other than a requested underwritten offering made concurrently with a demand registration) shall constitute a demand request subject to the limitations set forth above.

Piggyback Rights. Subject to certain exceptions, if at any time we propose to register an offering of common stock or conduct an underwritten offering, whether or not for our own account, then we must notify each Holder (or its permitted transferees), NGP XI, Mr. Graham, Mr. Bahr, the Carlyle Investor and KKR of such proposal to allow them to include a specified number of their shares of our common stock in that registration statement or underwritten offering, as applicable. KKR was made a Holder under the amended and restated registration rights agreement for purposes of obtaining such piggyback rights; however, as of December 31, 2018, they no longer own any of our common stock.

Conditions and Limitations; Expenses. These registration rights are subject to certain conditions and limitations, including the right of the underwriters to limit the number of shares to be included in a registration and our right to delay or withdraw a registration statement under certain circumstances. We will generally pay all registration expenses in connection with our obligations under the registration rights agreement, regardless of whether a registration statement is filed or becomes effective.

F – 39

BRAZOS VALLEY LONGHORN, L.L.C.

(Successor in interest to WildHorse Resource Development Corporation)

Stockholders' Agreement. In connection with our initial public offering, we entered into a stockholders' agreement with WildHorse Holdings, Esquisto Holdings, and Acquisition Co. Holdings. Among other things, the stockholders' agreement provides the right to designate nominees to our board of directors as follows:

· so long as WildHorse Holdings, Esquisto Holdings, Acquisition Co. Holdings and their affiliates, including NGP XI, collectively own greater than 50% of our common stock, WildHorse Holdings and Esquisto Holdings can each nominate up to three nominees to our board of directors;

· so long as WildHorse Holdings, Esquisto Holdings, Acquisition Co. Holdings and their affiliates, including NGP XI, collectively own at least 35% of our common stock but less than 50% of our common stock, WildHorse Holdings and Esquisto Holdings can each nominate two nominees to our board of directors;

· so long as WildHorse Holdings, Esquisto Holdings, Acquisition Co. Holdings and their affiliates, including NGP XI, collectively own at least 15% of our common stock but less than 35% of our common stock, WildHorse Holdings and Esquisto Holdings can each nominate one nominee to our board of directors and can nominate a third nominee by agreement between them;

· so long as WildHorse Holdings, Esquisto Holdings, Acquisition Co. Holdings and their affiliates, including NGP XI, collectively own at least 5% of our common stock but less than 15% of our common stock, WildHorse Holdings and Esquisto Holdings can each nominate one nominee to our board of directors; and

· once WildHorse Holdings, Esquisto Holdings, Acquisition Co. Holdings and their affiliates, including NGP XI, collectively own less 5% of our common stock, WildHorse Holdings and Esquisto Holdings will not have any board designation rights.

Pursuant to the stockholders' agreement we are required to take all necessary actions, to the fullest extent permitted by applicable law (including with respect to any fiduciary duties under Delaware law), to cause the election of the nominees designated by WildHorse Holdings and Esquisto Holdings.

In addition, the stockholders' agreement provides that for so long as WildHorse Holdings, Esquisto Holdings, Acquisition Co. Holdings and their affiliates, including NGP XI, own at least 15% of the outstanding shares of our common stock, WildHorse Holdings and Esquisto Holdings will have the right to cause any committee of our board of directors to include in its membership at least one director designated by WildHorse Holdings or Esquisto Holdings, except to the extent that such membership would violate applicable securities laws or stock exchange rules. The rights granted to WildHorse Holdings and Esquisto Holdings to designate directors are additive to and not intended to limit in any way the rights that WildHorse Holdings, Esquisto Holdings, Acquisition Co. or any of their affiliates, including NGP XI, may have to nominate, elect or remove our directors under our certificate of incorporation, bylaws or the Delaware General Corporation Law.

Note 16. Segment Disclosures

Our chief executive officer has been identified as our chief operating decision maker (“CODM”).  As of December 31, 2018, we identified one operating segment and one reportable segment—the Eagle Ford—that is engaged in the acquisition, exploration, 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-"Acquisitions and Divestitures" 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.

F – 40

BRAZOS VALLEY LONGHORN, L.L.C.

(Successor in interest to WildHorse Resource Development Corporation)

Major Customers

The following table sets forth the percentage of our revenues attributed to our customers who have accounted for 10% or more of our revenues during 2018, 2017 or 2016.

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

Note 17. Income Taxes

The components of income tax expense (benefit) are as follows (in thousands):

	For the Year Ended December 31,
	2018		2017		2016
Current income taxes:
Federal	$	(997)	$	997	$	—
State		—		10		—
Total current income tax expense (benefit)		(997)		1,007		—
Deferred income taxes:
Federal		43,143		(40,529)		(5,737)
State		(1,950)		698		162
Total deferred income tax expense (benefit)		41,193		(39,831)		(5,575)
Total income tax expense (benefit)	$	40,196	$	(38,824)	$	(5,575)

The actual income tax expense (benefit) differs from the expected amount computed by applying the federal statutory corporate tax rate of 21%, 35% and 35% for 2018, 2017 and 2016, respectively, as follows:

	For the Year Ended December 31,
	2018		2017		2016
Expected tax expense (benefit) at federal statutory rate	$	39,208	$	3,870	$	(18,428)
State income tax expense (benefit), net of federal benefit		(3,360)		460		105
Pass-through entities (1)		—		—		12,499
Incentive unit compensation		2,893		—		—
Stock-based compensation		(1,070)		—		—
Valuation allowance		1,820		—		234
Change in tax rate (2)		—		(43,431)		—
Change in prior period estimates		24		315		—
Other		681		(38)		15
Total income tax expense (benefit)	$	40,196	$	(38,824)	$	(5,575)

(1) Our predecessor was a pass-through entity for federal income tax purposes.

(2) The federal corporate income tax rate was reduced from 35% to 21% as a result of the Tax Act.

F – 41

BRAZOS VALLEY LONGHORN, L.L.C.

(Successor in interest to WildHorse Resource Development Corporation)

The components of net deferred income tax liabilities are as follows:

Components of net deferred income tax liabilities:	2018		2017
Deferred income tax assets:
Net operating loss Carryforwards	$	47,609	$	29,866
Disallowed interest carryforwards		9,992		—
Minimum tax credit Carryforward		—		997
Asset retirement obligation		1,796		3,311
Derivatives		—		16,903
Other		3,860		2,153
Total deferred income tax assets		63,257		53,230
Valuation allowance		(1,820)		—
Net deferred income tax assets		61,437		53,230
Deferred income tax liabilities:
Property, plant and equipment		158,868		124,700
Derivatives		15,300		—
Total deferred income tax liabilities		174,168		124,700
Net deferred income tax liabilities	$	112,731	$	71,470

Uncertain Income Tax Position.  The Company must recognize the tax effects of any uncertain tax positions it may have if the position taken by us is more likely than not sustainable based on its technical merits. For those benefits to be recognized, an income tax position must be more likely than not to be sustained upon examination by taxing authorities. The Company had no unrecognized tax benefits as of December 31, 2018 and expects no significant change to the unrecognized tax benefits over the next twelve months ending December 31, 2019.

Tax Audits and Settlements. Generally, the Company's income tax years 2015 through 2018 remain open and subject to examination by federal and various state tax authorities which include Louisiana and Texas and certain other state taxing jurisdictions where the Company previously had operations. In certain jurisdictions the Company operates through more than one legal entity, each of which may have different open years subject to examination.

Tax Attribute Carryforwards and Valuation Allowance.  As of December 31, 2018, the Company had federal net operating loss (NOL) carryforwards of approximately $218.0 million. The federal NOL carryforwards generated prior to 2018 expire in 2036 and 2037. The 2018 federal NOL carryforward of $65.9 million has no expiration. The Company also had state tax carryforwards of approximately $28.8 million, which expire in 2036 through 2038. In addition, the Company had disallowed business interest carryforward of approximately $47.6 million, which can be carried forward indefinitely. The Company recorded a valuation allowance of approximately $1.8 million against its deferred tax assets related to state tax attributes due to the NLA Divestiture.  The Company recorded no other valuation allowance based upon management's evaluation that it is more likely than not that the Company will realize its deferred tax assets.

Note 18. Commitments and Contingencies

Litigation & Environmental

We are party to various ongoing and potential legal actions relating to our entitled ownership interests in certain properties. We evaluate the merits of existing and potential claims and accrue a liability for any that meet the recognition criteria and can be reasonably estimated. We did not recognize any liability as of December 31, 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.

On February 1, 2018, we settled a dispute related to a possible area of mutual interest (“AMI”) associated with our North Louisiana assets with a third party.  Pursuant to such settlement, the third party agreed to pay the actual net costs

F – 42

BRAZOS VALLEY LONGHORN, L.L.C.

(Successor in interest to WildHorse Resource Development Corporation)

attributable to interests in certain leases and/or wells it elected to acquire.  We agreed to provide the third party with a $7.0 million credit towards purchasing the interests selected by the third party, which is reflected in the accompanying statements of operations for the year ended December 31, 2017 as “North Louisiana Settlement.”  The settlement loss was partially offset by a tax benefit of $1.6 million.  A settlement receivable of $5.9 million from the third party was collected by us during 2018.

In January 2019, putative class action lawsuits in U.S. District Courts for the District of Delaware and Southern District of New York were filed against us and other defendants. The lawsuits generally allege various violations of the Securities Exchange Act of 1934 in connection with the disclosure contained in the joint proxy statement/prospectus filed in connection with the Merger. The lawsuits seek rescission of the Merger or rescissory damages and, in each case, attorney's fees, costs and interest. We intend to vigorously defend these claims.

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 December 31, 2018 and at December 31, 2017.

Lease Obligations

We executed two office leases during the year ended December 31, 2018.  In June 2018, we executed a new lease for corporate office space that has escalating payments.  The commencement date was December 1, 2018 and the lease terminates on December 31, 2026.  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. Total office lease expense for the year ended December 31, 2018, 2017 and 2016 was $0.8 million, $1.0 million and $0.9 million.

In 2017, we entered into two dedicated fracturing fleet services agreements to complete wells in a timely manner following conclusion of drilling operations in the Eagle Ford Shale.

On March 15, 2017, we entered into a 20 month dedicated fracturing fleet services agreement. The agreement may be extended for an additional twelve months. We have agreed to pay a fixed monthly service fee of $2.7 million that covers equipment and personnel costs. In addition to the fixed monthly service charge, we have agreed to pay a fixed fee for each stage completed in excess of 360 stages per calendar quarter. We have also agreed to pay a pass through fee for the cost of chemicals and fuel plus 10%. We have the right to terminate the contract with appropriate notice; however, an early termination fee of approximately $1.4 million times the number of months remaining under the initial term of the contract would be payable on such termination date.  Our obligations under the contract ended in December 2018.

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

We have entered into drilling services agreements with varying terms, all of which have contractual terms of less than one year.

F – 43

BRAZOS VALLEY LONGHORN, L.L.C.

(Successor in interest to WildHorse Resource Development Corporation)

We have entered into compressor rental agreements, which have contractual terms of 13 months or less, after which they can be terminated with notice.  Total compressor and equipment rental expense incurred in 2018, 2017 and 2016 was $5.4 million, $2.0 million and $0.6 million, respectively.

The table below reflects our minimum commitments as of December 31, 2018:

	2019		2020		2021		2022		2023
Office Leases	$	2,399	$	2,435	$	2,398	$	2,216	$	2,251
Dedicated Fracturing Fleet Services Agreement		21,000		—		—		—		—
Sand Mine Equipment		5,055		3,436		—		—		—
Compressors		4,143		3,991		3,859		2,724		902
Total	$	32,597	$	9,862	$	6,257	$	4,940	$	3,153

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 years ended December 31, 2018 and 2017, respectively.

Note 19. Quarterly Financial Information (Unaudited)

The following tables present selected quarterly financial data for the periods indicated (in thousands except per share amounts). Earnings per share are computed independently for each of the quarters presented and the sum of the quarterly earnings per share may not necessarily equal the total for the year.

	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter (1)
For the Year Ended December 31, 2018
Revenues	$	218,757	$	225,413	$	259,490	$	243,726
Operating income (loss)		(100,053)		101,370		122,776	$	88,196
Net income (loss) available to WRD		(115,774)		(14,094)		11,523	$	264,853
Preferred stock dividends		7,389		7,961		6,756		6,756
Net income (loss) available to common stockholders		(123,163)		(22,055)		3,534		228,986
Basic earnings (loss) per share	$	(1.24)	$	(0.22)	$	0.04	$	1.92
Diluted earnings (loss) per share	$	(1.24)	$	(0.22)	$	0.04	$	1.92
For the Year Ended December 31, 2017
Revenues	$	54,292	$	70,173	$	122,486	$	180,236
Operating income		6,206		2,078		32,599	$	64,582
Net income (loss)		20,252		26,366		(10,804)	$	14,066
Preferred stock dividends		—		73		6,450		6,623
Net income (loss) available to common stockholders		20,252		25,906		(17,254)		2,218
Basic earnings (loss) per share	$	0.22	$	0.28	$	(0.17)	$	0.06
Diluted earnings (loss) per share	$	0.22	$	0.28	$	(0.17)	$	0.06

(1) Net income for the three months ended December 31, 2017 includes a deferred tax benefit of $43.4 million as a result of the re-measurement of our deferred tax assets and liabilities as a result of the Tax Act.

F – 44

BRAZOS VALLEY LONGHORN, L.L.C.

(Successor in interest to WildHorse Resource Development Corporation)

Note 20. Supplemental Oil and Gas Information (Unaudited)

Oil and Natural Gas Reserves

Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.

Proved reserves are those quantities of oil and natural gas that 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.

Our proved reserves are prepared CG&A, a third-party independent reserve. All proved reserves are located in the United States and all prices are held constant in accordance with SEC rules.

	For the Year Ended December 31,
	2018		2017		2016
Oil ($/Bbl)
West Texas Intermediate (1)	$	65.56	$	51.34	$	42.75
NGL ($/Bbl)
West Texas Intermediate (1)	$	65.56	$	51.34	$	42.75
Natural Gas ($/Mmbtu)
Henry Hub (2)	$	3.10	$	2.98	$	2.48

(1) The unweighted average West Texas Intermediate price was adjusted by lease for quality, transportation fees, and a regional price differential.

(2) The unweighted average Henry Hub price was adjusted by lease for energy content, compression charges, transportation fees, and regional price differentials.

F – 45

BRAZOS VALLEY LONGHORN, L.L.C.

(Successor in interest to WildHorse Resource Development Corporation)

The following tables set forth estimates of the net reserves as of December 31, 2018, 2017 and 2016, respectively:

	For the Year Ended December 31, 2018
	Oil (MBbls)	Gas (MMcf)	NGL (MBbls)	Equivalent (MBoe)
Proved developed and undeveloped reserves:
Beginning of the year	282,798	683,808	57,550	454,315
Extensions, discoveries and additions	81,174	129,962	16,377	119,211
Purchase of minerals in place	520	727	116	757
Sales of minerals in place	(1,272)	(393,057)	(398)	(67,180)
Production	(12,585)	(21,531)	(2,143)	(18,316)
Revision of previous estimates	(65,369)	(21,736)	(13,747)	(82,737)
End of year	285,266	378,173	57,755	406,050
Proved developed reserves:
Beginning of year	65,023	221,517	12,553	114,495
End of year	66,398	88,936	14,135	95,356
Proved undeveloped reserves:
Beginning of year	217,775	462,291	44,997	339,820
End of year	218,868	289,237	43,620	310,694

	For the Year Ended December 31, 2017
	Oil (MBbls)	Gas (MMcf)	NGL (MBbls)	Equivalent (MBoe)
Proved developed and undeveloped reserves:
Beginning of the year	87,447	325,102	10,874	152,505
Extensions, discoveries and additions	93,454	279,368	22,545	162,559
Purchase of minerals in place	59,169	28,106	6,740	70,593
Production	(6,606)	(20,463)	(1,206)	(11,222)
Revision of previous estimates	49,334	71,695	18,597	79,880
End of year	282,798	683,808	57,550	454,315
Proved developed reserves:
Beginning of year	19,192	145,880	3,765	47,270
End of year	65,023	221,517	12,553	114,495
Proved undeveloped reserves:
Beginning of year	68,255	179,222	7,109	105,235
End of year	217,775	462,291	44,997	339,820

F – 46

BRAZOS VALLEY LONGHORN, L.L.C.

(Successor in interest to WildHorse Resource Development Corporation)

	For the Year Ended December 31, 2016
	Oil (MBbls)	Gas (MMcf)	NGL (MBbls)	Equivalent (MBoe)
Proved developed and undeveloped reserves:
Beginning of the year	36,650	344,959	8,897	103,040
Extensions, discoveries and additions	18,870	32,782	2,606	26,940
Purchase of minerals in place	26,835	13,545	1,823	30,916
Production	(1,848)	(17,820)	(471)	(5,289)
Revision of previous estimates	6,940	(48,364)	(1,981)	(3,102)
End of year	87,447	325,102	10,874	152,505
Proved developed reserves:
Beginning of year	7,503	142,990	2,235	33,570
End of year	19,192	145,880	3,765	47,270
Proved undeveloped reserves:
Beginning of year	29,147	201,969	6,662	69,470
End of year	68,255	179,222	7,109	105,235

Noteworthy amounts included in the categories of proved reserve changes in the above tables include:

· During 2018, extensions, discoveries and additions increased proved reserves by 119,211 MBoe. These increases were partially offset by sales of minerals in place related to the North Louisiana Divestiture, which reduced proved reserves by  67,180 Mboe and production reducing proved reserves by 18,316  MBoe. We also had downward revisions of 82,737 Mboe, of which 86,953 MBoe were performance related partially offset by 4,216 MBoe related to commodity price increases.  

· During 2017, extensions, discoveries and additions increased proved reserves by 20,313 MBoe and 142,246 MBoe related to North Louisiana and Eagle Ford Shale, respectively.

· During 2017, purchases of minerals in place of 70,593 MBoe was attributable to the Acquisition.

· During 2017, we had upward revisions of 79,880 MBoe, of which 7,461 MBoe related to commodity price changes and 72,419 MBoe was performance related.

· During 2016, extensions, discoveries and additions increased proved reserves by 4,131 MBoe and 22,809 MBoe related to drilling in the RCT field in North Louisiana and Eagle Ford Shale, respectively.

· During 2016, purchase of minerals in place of 30,916 MBoe was primarily attributable to the Burleson North Acquisition.

· During 2016, we had downward revisions of proved reserves of 3,102 MBoe, of which 711 MBoe related to commodity price changes and 2,391 MBoe was performance related.

See Note 3-"Acquisitions and Divestitures" for additional information on acquisitions and divestitures.

A variety of methodologies are used to determine our proved reserve estimates. The principal methodologies employed are reservoir simulation, decline curve analysis, volumetric, material balance, advance production type curve matching, petro-physics/log analysis and analogy. Some combination of these methods is used to determine reserve estimates in substantially all of our fields.

F – 47

BRAZOS VALLEY LONGHORN, L.L.C.

(Successor in interest to WildHorse Resource Development Corporation)

Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves

As required by the FASB and SEC, the standardized measure of discounted future net cash flows presented below is computed by applying first-day-of-the-month average prices, year-end costs and legislated tax rates and a discount factor of 10 percent to proved reserves. We do not believe the standardized measure provides a reliable estimate of the Company's expected future cash flows to be obtained from the development and production of its oil and gas properties or of the value of its proved oil and gas reserves. The standardized measure is prepared on the basis of certain prescribed assumptions including first-day-of-the-month average prices, which represent discrete points in time and therefore may cause significant variability in cash flows from year to year as prices change.

The standardized measure of discounted future net cash flows is as follows (in thousands):

	For the Year Ended December 31,
	2018		2017		2016
Future cash inflows	$	21,269,502	$	16,967,369	$	4,434,117
Future production costs		(3,440,203)		(3,305,941)		(1,220,067)
Future development costs		(5,168,271)		(4,008,916)		(1,146,632)
Future income tax expense		(2,398,612)		(1,814,510)		(442,285)
Future net cash flows for estimated timing of cash flows		10,262,416		7,838,002		1,625,133
10% annual discount for estimated timing of cash flows		(6,144,980)		(4,994,097)		(1,082,092)
Standardized measure of discounted future net cash flows	$	4,117,436	$	2,843,905	$	543,041

Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves

The following is a summary of the changes in the standardized measure of discounted future net cash flows for the proved oil and natural gas reserves during each of the years in the three-year period ended December 31, 2018 (in thousands):

	For the Year Ended December 31,
	2018		2017		2016
Beginning of year	$	2,843,905	$	543,041	$	451,930
Sale of oil and natural gas produced, net of production costs		(822,471)		(351,031)		(104,596)
Purchase of minerals in place		4,313		507,095		188,317
Sales of minerals in place		(319,858)		—		—
Extensions and discoveries		1,829,564		1,595,385		168,796
Changes in income taxes, net		(277,050)		(488,484)		(206,817)
Changes in prices and costs		1,380,323		398,713		(57,034)
Previously estimated development costs incurred		67,575		49,977		15,067
Net changes in future development costs		(13,317)		(87,375)		11,985
Revisions of previous quantities		(1,057,523)		653,567		3,943
Accretion of discount		323,927		74,999		103,000
Change in production rates and other		158,048		(51,982)		(31,550)
End of year	$	4,117,436	$	2,843,905	$	543,041

F – 48

BRAZOS VALLEY LONGHORN, L.L.C.

(Successor in interest to WildHorse Resource Development Corporation)

Capitalized Costs Relating to Oil and Natural Gas Producing Activities

The total amount of capitalized costs relating to oil and natural gas producing activities and the total amount of related accumulated depreciation, depletion and amortization is as follows at the dates indicated (in thousands).

	For the Year Ended December 31,
	2018		2017		2016
Evaluated oil and natural gas properties	$	2,764,875	$	2,265,525	$	1,144,857
Unevaluated oil and natural gas properties		693,023		734,203		428,991
Accumulated depletion, depreciation and amortization		(498,811)		(362,406)		(196,567)
Total	$	2,959,087	$	2,637,322	$	1,377,281

Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities

Costs incurred in property acquisition, exploration and development activities were as follows for the periods indicated:

	For the Year Ended December 31,
	2018		2017		2016
Property acquisition costs, proved	$	4,422	$	269,429	$	230,910
Property acquisition costs, unproved		85,863		386,515		235,652
Exploration and extension well costs		11,979		16,076		72,875
Development		927,985		795,273		63,006
Total	$	1,030,249	$	1,467,293	$	602,443

Note 21. Subsequent Events

Quarterly Preferred Stock Dividend

Merger with Chesapeake

In February 2019, we were acquired by Chesapeake for approximately 717.3 million shares of Chesapeake common stock and $381.1 million in cash. Immediately following the completion of the acquisition, WildHorse Development merged with and into Brazos Valley Longhorn, L.L.C., a newly formed Delaware limited liability company and wholly owned subsidiary of Chesapeake. Following the completion of the Merger on February 1, 2019, Brazos Valley Longhorn, L.L.C., as successor to WildHorse Development, was a wholly owned subsidiary of Chesapeake.

On February 1, 2019, we paid our financial advisors $23.1 million of advisory fees, which were contingent upon the closing of the merger with Chesapeake.  The contingent fee was not deemed probable at December 31, 2018.

On February 1, 2019, Brazos Valley Longhorn, L.L.C., as successor by merger to WildHorse, entered into a sixth amendment (the "Sixth Amendment") to its Credit Agreement. Among other things, the Sixth Amendment (i) amended the merger covenant and the definition of change of control to permit the WildHorse Merger and (ii) permits borrowings under the Credit Agreement to be used to redeem or repurchase the 2025 Senior Notes so long as certain conditions are met.

On February 1, 2019, Brazos Valley Longhorn, L.L.C., as successor by merger to WildHorse, and Brazos Valley Longhorn Finance Corp., a Delaware corporation ("BVL Finance Corp.") and wholly owned subsidiary of the Company, entered into a fourth supplemental indenture (the "Fourth Supplemental Indenture") to the 2025 Indenture. Pursuant to the Fourth Supplemental Indenture, (i) the Brazos Valley Longhorn, L.L.C. assumed the rights and obligations of WildHorse

F – 49

BRAZOS VALLEY LONGHORN, L.L.C.

(Successor in interest to WildHorse Resource Development Corporation)

as issuer under the 2025 Indenture and (ii) BVL Finance Corp. was named as a co-issuer of the 2025 Senior Notes under the 2025 Indenture.

If the 2025 Senior Notes are downgraded within 90 days after the consummation of the WildHorse Merger (which constitutes a "Change of Control" under the 2025 Indenture), the 2025 Indenture requires the Company (or a third party, in certain circumstances) to make an offer to repurchase the 2025 Senior Notes at 101% of their principal amount, plus accrued and unpaid interest, within 30 days of such downgrade. If any holder of 2025 Senior Notes accepts such offer, the Company may (subject to the terms and conditions thereof) fund the purchase price with loans under the Credit Agreement, use cash on hand, issue debt securities or use other sources of liquidity to fund such repurchase.

F – 50

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

We hereby consent to the inclusion in or incorporation by reference into the 2018 annual report on Form 10-K (the "Annual Report") of Brazos Valley Longhorn, L.L.C. of  our report, dated February  26, 2019, with respect to our audit of estimates of proved reserves and future net revenues as of December 31, 2018 for Brazos Valley Longhorn, L.L.C. We also hereby consent to all references to our firm or such reports included in or incorporated by reference into such Annual Report.

Very truly yours,

/s/ W. Todd Brooker, P. E.

W. Todd Brooker, P. E.

President

Cawley, Gillespie & Associates, Inc.

Texas Registered Engineering Firm F-693

Austin, Texas

March 4, 2019

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Robert D. Lawler, certify that:

1.    I have reviewed this Annual Report on Form 10-K of Brazos Valley Longhorn, L.L.C.;

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

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

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

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

(b)    designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)    evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

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

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

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

(b)    any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

March 4, 2019	By:	/s/ Robert D. Lawler
		Robert D. Lawler
		President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Domenic J. Dell’Osso, Jr., certify that:

1. I have reviewed this Annual Report on Form 10-K of Brazos Valley Longhorn, L.L.C.;

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

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

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

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

(b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

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

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

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

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

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

March 4, 2019	By:	/s/ Domenic J. Dell’Osso, Jr.
		Domenic J. Dell’Osso, Jr.
		Executive Vice President and Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Brazos Valley Longhorn, L.L.C. (the “Company”) on Form 10-K for the year ended December 31, 2018 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Robert D. Lawler, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

1.    The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

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

March 4, 2019	By:	/s/ Robert D. Lawler
		Robert D. Lawler
		President and Chief Executive Officer

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Brazos Valley Longhorn, L.L.C. (the “Company”) on Form 10-K for the year ended December 31, 2018 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Domenic J. Dell’Osso, Jr., Executive Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

1.    The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

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

4
March 4, 2019	By:	/s/ Domenic J. Dell’Osso, Jr.
		Domenic J. Dell’Osso, Jr.
		Executive Vice President and Chief Financial Officer

EX-95.1

Exhibit 95.1

Mine Safety Disclosure

Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Act") and Item 104 of Regulation S-K, requires certain disclosures by companies required to file periodic reports under the Securities Exchange Act of 1934, as amended, that operate mines regulated under the Federal Mine Safety and Health Act of 1977 (the "Mine Act").

Burleson Sand LLC (“Burleson Sand”) is a wholly owned subsidiary of Brazos Valley Longhorn, L.L.C. (Successor in interest to WildHorse Resource Development Corporation) (“WRD”).  On January 4, 2018, Burleson Sand acquired surface and sand rights on approximately 727 acres in Burleson County, Texas to construct and operate an in-field sand mine to support WRD’s exploration and development operations.   Burleson Sand began operations in September 2018 and is subject to regulation by the federal Mine Safety and Health Administration (“MSHA”) under the Mine Act.  The MSHA inspects mining facilities on a regular basis and issues citations and orders when it believes a violation has occurred under the Mine Act.

The MSHA, upon determination that a violation of the Mine Act has occurred, may issue a citation or an order which generally proposes civil penalties or fines upon the mine operator.  Citations and orders may be appealed with the potential of reduced or dismissed penalties.

During the year ended December 31, 2018, Burleson Sand did not receive any of the following from MSHA: (i) a citation for a violation of a mandatory health or safety standard that could significantly and substantially contribute to the cause and effect of a mine safety or health hazard under Section 104 of the Mine Act; (ii) an order issued under Section 104(b) of the Mine Act; (iii) a citation or order for unwarrantable failure to comply with mandatory health or safety standards under Section 104(d) of the Mine Act; (iv) written notice of a flagrant violation under Section 110(b)(2) of the Mine Act; (v) an imminent danger order issued under Section 107(a) of the Mine Act; (vi) any proposed assessments under the Mine Act; (vii) written notice of a pattern of violations of mandatory health or safety standards that are of such nature as could have significantly and substantially contributed to the cause and effect of mine health or safety hazards under Section 104(e) of the Mine Act; or (viii) written notice of the potential to have such a pattern. Moreover, during the year ended December 31, 2018, Burleson Sand did not experience a mining-related fatality or have any pending legal action before the Federal Mine Safety and Health Review Commission.

EX-99.1

Exhibit 99.1

CAWLEY, GILLESPIE & ASSOCIATES, INC.

PETROLEUM CONSULTANTS
13640 BRIARWICK DRIVE, SUITE 100 AUSTIN, TEXAS 78729-1106 512-249-7000	306 WEST SEVENTH STREET, SUITE 302 FORT WORTH, TEXAS 76102-4987 817- 336-2461 www.cgaus.com	1000 LOUISIANA STREET, SUITE 1900 HOUSTON, TEXAS 77002-5008 713-651-9944

February 26, 2019

Director of Corporate Reserves
Chesapeake Energy Corporation
6100 North Western Avenue Oklahoma City, Oklahoma 73118
	Re:	Evaluation Summary
		Brazos Valley Longhorn, L.L.C. (successor in interest to
		WildHorse Resource Development Corporation) Interests
		Total Proved Reserves Certain Properties in East Texas As of December 31, 2018
		Pursuant to the Guidelines of the Securities and Exchange Commission for Reporting Corporate  Reserves and Future Net Revenue

Ladies and Gentlemen:

As you have requested, this report was completed on February 26, 2019 for the purpose of submitting our estimates of proved reserves and forecasts of economics attributable to the Brazos Valley Longhorn, L.L.C. (“BVL LLC”, successor in interest to WildHorse Resource Development Corporation) interests.. We evaluated 100% of BVL LLC total proved reserves, which are made up of oil and gas properties in various counties in East Texas. This report utilized an effective date of December 31, 2018, was prepared using constant prices and costs, and conforms to Item 1202(a)(8) of Regulation S-K and other rules of the Securities and Exchange Commission (“SEC”). This report was prepared for the inclusion as an exhibit in a filing made with the SEC. The results of this evaluation are presented in the accompanying tabulation, with a composite summary of the values presented below:

		Proved
		Developed	Proved	Proved	Total
		Producing	Developed	Undeveloped	Proved
Net Reserves
Oil	- Mbbl	66,398.3	66,398.3	218,868.5	285,266.8
Gas	- MMcf	88,936.0	88,936.0	289,236.5	378,172.6
NGL	- Mbbl	14,135.1	14,135.1	43,619.9	57,755.1
Net Revenue
Oil	- M$	4,446,185.0	4,446,185.0	14,683,408.0	19,129,598.0
Gas	- M$	201,311.4	201,311.4	677,668.9	878,980.4
NGL	- M$	279,619.9	279,619.9	981,307.9	1,260,927.9
Severance Taxes	- M$	230,713.3	230,713.3	771,715.2	1,002,428.4
Ad Valorem Taxes	- M$	30,996.3	30,996.3	102,766.4	133,762.7
Operating Expenses	- M$	1,109,582.1	1,109,582.1	875,229.8	1,984,812.3
3rd Party COPAS	- M$	4,880.0	4,880.0	0.0	4,880.0
Other Deductions	- M$	78,132.6	78,132.6	236,188.1	314,320.3
Investments	- M$	81,676.8	81,676.8	5,086,593.5	5,168,270.5
Net Operating Income  (BFIT)	- M$	3,391,135.0	3,391,135.0	9,269,894.0	12,661,033.0
Discounted @ 10%	- M$	1,978,017.1	1,978,017.1	3,111,900.5	5,089,917.5

Brazos Valley Longhorn, L.L.C. Interests

February 26, 2019

Page 2

The discounted future net cash flow shown above should not be construed to represent an estimate of the fair market value of the reserves by Cawley, Gillespie & Associates, Inc. (“CG&A”).

Future revenue is prior to deducting state production taxes and ad valorem taxes. Future net cash flow is after deducting these taxes, future capital costs and operating expenses, but before consideration of federal income taxes.  In accordance with SEC guidelines, the future net cash flow has been discounted at an annual rate of ten percent to determine its “present worth”. The present worth is shown to indicate the effect of time on the value of money and should not be construed as being the fair market value of the reserves.

The oil reserves include oil and condensate.  Oil volumes and NGL volumes are expressed in barrels (42 U.S. gallons).  Gas volumes are expressed in thousands of standard cubic feet (Mcf) at contract temperature and pressure base.

Hydrocarbon Pricing

As requested for SEC purposes, the base oil and gas prices calculated for December 31, 2018 were $65.56/BBL and $3.100/MMBTU, respectively. As specified by the SEC, a company must use a 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. The base oil price is based upon WTI-Cushing spot prices (Bloomberg) during 2018 and the base gas price is based upon Henry Hub spot prices (Platts Gas Daily) during 2018. NGL prices were adjusted on a per-property basis and averaged 32.6% of the net oil price on a composite basis.

The base prices were adjusted for differentials on a per-property basis, which may include local basis differential, treating cost, transportation, gas shrinkage, gas heating value (BTU content) and/or crude quality and gravity corrections. After these adjustments, the net realized prices for the SEC price case over the life of the proved properties was estimated to be $67.06 per barrel for oil, $2.32 per MCF for natural gas and $21.83 per barrel for NGL. All economic factors were held constant in accordance with SEC guidelines.

Capital, Expenses and Taxes

Capital expenditures, lease operating expenses and ad valorem tax values were forecast as provided by BVL LLC.  As you explained, the capital costs were based on the most current estimates, lease operating expenses were based on the analysis of historical actual expenses, operating overhead is included for non-operated properties and no credit or deduction is made for producing overhead paid to the company by other owners of the operated properties. Capital costs and lease operating expenses were held constant in accordance with SEC guidelines.  Severance tax rates were applied at normal state percentages of oil and gas revenue. Severance Tax rates in certain instances, where authorized by taxing authorities, have severance tax abatements and were provided by your office and applied when appropriate.

SEC Conformance and Regulations

The reserve classifications and the economic considerations used herein conform to the criteria of the SEC as defined in pages 3 and 4 of the Appendix.  The reserves and economics are predicated on regulatory agency classifications, rules, policies, laws, taxes and royalties currently in effect except as noted herein. Federal, state, and local laws and regulations, which are currently in effect and that govern the development and production of oil and natural gas, have been considered in the evaluation of proved reserves for this report. The possible effects of changes in legislation or other Federal or State restrictive actions which could affect the reserves and economics have not been considered.  These possible changes could have an effect on the reserves and economics. However, we do not anticipate nor are we aware of any legislative changes or restrictive regulatory actions that may impact the recovery of reserves.

This evaluation includes 887 proved undeveloped locations, 875 of which are commercial using required SEC pricing. Each of these commercial drilling locations proposed as part of BVL LLC’s development plans conforms to the proved undeveloped standards as set forth by the SEC. In our opinion, BVL LLC has indicated it has every intent to complete this development plan as scheduled.  Furthermore, BVL LLC has demonstrated that it has adequate company staffing, financial backing and prior development success to ensure this development plan will be fully executed.

Reserve Estimation Methods

The methods employed in estimating reserves are described on page 2 of the Appendix. Reserves for proved developed producing wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to similar production, both of which are considered to provide a relatively high degree of accuracy.

Brazos Valley Longhorn, L.L.C. Interests

February 26, 2019

Page 3

Non-producing reserve estimates, for both developed and undeveloped properties, were forecast using either volumetric or analogy methods, or a combination of both. These methods provide a relatively high degree of accuracy for predicting proved developed non-producing and proved undeveloped reserves. The assumptions, data, methods and procedures used herein are appropriate for the purpose served by this report.

Miscellaneous

An on-site field inspection of the properties has not been performed nor has the mechanical operation or condition of the wells and their related facilities been examined, nor have the wells been tested by Cawley, Gillespie & Associates, Inc.  Possible environmental liability related to the properties has not been investigated nor considered.  Further, the net cost of plugging and the salvage value of equipment at abandonment have been included herein.

The reserve estimates and forecasts were based upon interpretations of data furnished by BVL LLC and available from our files.  Ownership information and economic factors such as liquid and gas prices, price differentials and expenses were furnished by BVL LLC.  To some extent, information from public records was used to check and/or supplement these data.  The basic engineering and geological data were utilized subject to third party reservations and qualifications.  Nothing has come to our attention, however, that would cause us to believe that we are not justified in relying on such data. All estimates represent our best judgment based on the data available at the time of preparation. Due to inherent uncertainties in future production rates, commodity prices and geologic conditions, it should be realized that the reserve estimates, the reserves actually recovered, the revenue derived therefrom and the actual cost incurred could be more or less than the estimated amounts.

Cawley, Gillespie & Associates, Inc. is a Texas Registered Engineering Firm (F-693), made up of independent registered professional engineers and geologists that have provided petroleum consulting services to the oil and gas industry for over 50 years.  This evaluation was supervised by W. Todd Brooker, President at Cawley, Gillespie & Associates, Inc. and a State of Texas Licensed Professional Engineer (License #83462). We do not own an interest in the properties or BVL LLC and are not employed on a contingent basis.  We have used all methods and procedures that we consider necessary under the circumstances to prepare this report. Our work-papers and related data utilized in the preparation of these estimates are available in our office.

Yours very truly,

CAWLEY, GILLESPIE & ASSOCIATES, INC.

TEXAS REGISTERED ENGINEERING FIRM F-693

W. TODD BROOKER, P.E.
PRESIDENT

ROBERT P. BERGERON, JR., P.E.
RESERVOIR ENGINEER

APPENDIX

Explanatory Comments for Individual Tables

HEADINGS

Table Number

Effective Date of the Evaluation

Identity of Interest Evaluated

Reserve Classification and Development Status

Operator – Property Name

Field (Reservoir) Names – County, State

FORECAST

(Columns)

(1) (11) (21)            Calendar or Fiscal years/months commencing on effective date.

(2) (3) (4)                Gross Production (8/8th) for the years/months which are economical. These are expressed as thousands of barrels (Mbbl) and millions of cubic feet (MMcf) of gas at standard conditions. Total future production, cumulative production to effective date, and ultimate recovery at the effective date are shown following the annual/monthly forecasts.

(5) (6) (7)                Net Production accruable to evaluated interest is calculated by multiplying the revenue interest times the gross production. These values take into account changes in interest and gas shrinkage.

(8)                           Average (volume weighted) gross liquid price per barrel before deducting production-severance taxes.

(9)                           Average (volume weighted) gross gas price per Mcf before deducting production-severance taxes.

(10)                         Average (volume weighted) gross NGL price per barrel before deducting production-severance taxes.

(12)                         Revenue derived from oil sales -- column (5) times column (8).

(13)                         Revenue derived from gas sales -- column (6) times column (9).

(14)                         Revenue derived from NGL sales -- column (7) times column (10).

(15)                         Revenue derived from hedge positions.

(16)                         Revenue not derived from column (12) through column (15); may include electrical sales revenue and saltwater disposal revenue.

(17)                         Total Revenue – sum of column (12) through column (16).

(18)                         Production-Severance taxes deducted from gross oil, gas and NGL revenue.

(19)                         Ad Valorem taxes.

(20)                         $/BOE6 – is the total of column (22), column (25), column (26), and column (27) divided by Barrels of Oil Equivalent (“BOE”). BOE is net oil production column (5) plus net gas production column (6) converted to oil at six Mcf gas per one bbl oil plus net NGL production column (7) converted to oil at one bbl NGL per 0.65 bbls of oil.

(22)                         Operating Expenses are direct operating expenses to the evaluated working interest and may include combined fixed rate administrative overhead charges for operated oil and gas producers known as COPAS.

(23)                         Average gross wells.

(24)                         Average net wells are gross wells times working interest.

(25)                         Work-over Expenses are non-direct operating expenses and may include maintenance, well service, compressor, tubing, and pump repair.

(26)                         3rd Party COPAS are combined fixed rate administrative overhead charges for non-operated oil and gas producers.

(27)                         Other Deductions may include compression-gathering expenses, transportation costs and water disposal costs.

(28)                         Investments, if any, include re-completions, future drilling costs, pumping units, etc. and may include either tangible or intangible or both, and the costs for plugging and the salvage value of equipment at abandonment may be shown as negative investments at end of life.

(29) (30)                  Future Net Cash Flow is column (17) less the total of column (18), column (19), column (22), column (25), column (26), column (27), and column (28). The data in column (29) are accumulated in column (30). Federal income taxes have not been considered.

(31)                         Cumulative Discounted Cash Flow is calculated by discounting monthly cash flows at the specified annual rates.

MISCELLANEOUS

DCF Profile                   The cumulative cash flow discounted at six different interest rates are shown at the bottom of columns (30-31). Interest has been compounded monthly. The DCF’s for the “Without Hedge” case may be shown to the left of the main DCF profile.

Life                                The economic life of the appraised property is noted in the lower right-hand corner of the table.

Footnotes                       Comments regarding the evaluation may be shown in the lower left-hand footnotes.

Price Deck                     A table of oil and gas prices, price caps and escalation rates may be shown in the lower middle footnotes.

Cawley, Gillespie & Associates, Inc. Appendix Page 1

APPENDIX

Methods Employed in the Estimation of Reserves

The four methods customarily employed in the estimation of reserves are (1) production performance, (2) material balance, (3) volumetric and (4) analogy. Most estimates, although based primarily on one method, utilize other methods depending on the nature and extent of the data available and the characteristics of the reservoirs.

Basic information includes production, pressure, geological and laboratory data. However, a large variation exists in the quality, quantity and types of information available on individual properties. Operators are generally required by regulatory authorities to file monthly production reports and may be required to measure and report periodically such data as well pressures, gas-oil ratios, well tests, etc. As a general rule, an operator has complete discretion in obtaining and/or making available geological and engineering data. The resulting lack of uniformity in data renders impossible the application of identical methods to all properties, and may result in significant differences in the accuracy and reliability of estimates.

A brief discussion of each method, its basis, data requirements, applicability and generalization as to its relative degree of accuracy follows:

Production performance. This method employs graphical analyses of production data on the premise that all factors which have controlled the performance to date will continue to control and that historical trends can be extrapolated to predict future performance. The only information required is production history. Capacity production can usually be analyzed from graphs of rates versus time or cumulative production. This procedure is referred to as "decline curve" analysis. Both capacity and restricted production can, in some cases, be analyzed from graphs of producing rate relationships of the various production components. Reserve estimates obtained by this method are generally considered to have a relatively high degree of accuracy with the degree of accuracy increasing as production history accumulates.

Material balance. This method employs the analysis of the relationship of production and pressure performance on the premise that the reservoir volume and its initial hydrocarbon content are fixed and that this initial hydrocarbon volume and recoveries therefrom can be estimated by analyzing changes in pressure with respect to production relationships. This method requires reliable pressure and temperature data, production data, fluid analyses and knowledge of the nature of the reservoir. The material balance method is applicable to all reservoirs, but the time and expense required for its use is dependent on the nature of the reservoir and its fluids. Reserves for depletion type reservoirs can be estimated from graphs of pressures corrected for compressibility versus cumulative production, requiring only data that are usually available. Estimates for other reservoir types require extensive data and involve complex calculations most suited to computer models which makes this method generally applicable only to reservoirs where there is economic justification for its use. Reserve estimates obtained by this method are generally considered to have a degree of accuracy that is directly related to the complexity of the reservoir and the quality and quantity of data available.

Volumetric. This method employs analyses of physical measurements of rock and fluid properties to calculate the volume of hydrocarbons in-place. The data required are well information sufficient to determine reservoir subsurface datum, thickness, storage volume, fluid content and location. The volumetric method is most applicable to reservoirs which are not susceptible to analysis by production performance or material balance methods. These are most commonly newly developed and/or no-pressure depleting reservoirs. The amount of hydrocarbons in-place that can be recovered is not an integral part of the volumetric calculations but is an estimate inferred by other methods and a knowledge of the nature of the reservoir. Reserve estimates obtained by this method are generally considered to have a low degree of accuracy; but the degree of accuracy can be relatively high where rock quality and subsurface control is good and the nature of the reservoir is uncomplicated.

Analogy. This method which employs experience and judgment to estimate reserves, is based on observations of similar situations and includes consideration of theoretical performance. The analogy method is a common approach used for “resource plays,” where an abundance of wells with similar production profiles facilitates the reliable estimation of future reserves with a relatively high degree of accuracy. The analogy method is applicable where the data are insufficient or so inconclusive that reliable reserve estimates cannot be made by other methods. Reserve estimates obtained by this method are generally considered to have a relatively low degree of accuracy.

Much of the information used in the estimation of reserves is itself arrived at by the use of estimates. These estimates are subject to continuing change as additional information becomes available. Reserve estimates which presently appear to be correct may be found to contain substantial errors as time passes and new information is obtained about well and reservoir performance.

Cawley, Gillespie & Associates, Inc. Appendix Page 2

APPENDIX

Reserve Definitions and Classifications

The Securities and Exchange Commission, in SX Reg. 210.4-10 dated November 18, 1981, as amended on September 19, 1989 and January 1, 2010, requires adherence to the following definitions of oil and gas reserves:

"(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, 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.

"(i)       The area of a reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

"(ii)       In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

"(iii)      Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

"(iv)      Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

"(v)       Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

"(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

“(i)       Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

“(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.

"(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category 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.

“(i)       Reserves on undrilled acreage shall be 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.

“(ii)      Undrilled locations can be 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.

“(iii)     Under no circumstances shall estimates for undeveloped reserves be 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, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

Cawley, Gillespie & Associates, Inc. Appendix Page 3

"(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

“(i)       When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the    sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

“(ii)       Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

“(iii)      Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery  of the hydrocarbons in place than assumed for proved reserves.

“(iv)       See also guidelines in paragraphs (17)(iv) and (17)(vi) of this section (below).

"(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

“(i)       When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

“(ii)       Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

“(iii)       Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

“(iv)       The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

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

“(vi)       Pursuant to paragraph (22)(iii) of this section (above), where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.”

Instruction 4 of Item 2(b) of Securities and Exchange Commission Regulation S-K was revised January 1, 2010 to state that "a registrant engaged in oil and gas producing activities shall provide the information required by Subpart 1200 of Regulation S–K." This is relevant in that Instruction 2 to paragraph (a)(2) states: “The registrant is permitted, but not required, to disclose probable or possible reserves pursuant to paragraphs (a)(2)(iv) through (a)(2)(vii) of this Item.”

"(26) Reserves.  Reserves are estimated remaining quantities of oil and 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 gas or related substances to market, and all permits and financing required to implement the project.

“Note to paragraph (26): 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).”

Cawley, Gillespie & Associates, Inc. Appendix Page 4

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Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2018	Mar. 04, 2019	Jun. 30, 2018
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2018
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	FY
Trading Symbol	WRD
Entity Registrant Name	Brazos Valley Longhorn, L.L.C.
Entity Central Index Key	0001681714
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		0
Entity Public Float			$ 0

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CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Current Assets:
Cash and cash equivalents	$ 14,947	$ 226
Accounts receivable, net	91,558	84,103
Derivative instruments	54,131	2,336
Prepaid expenses and other current assets	7,851	3,290
Total current assets	168,487	89,955
Property and equipment:
Oil and gas properties	3,457,897	2,999,728
Other property and equipment	107,279	53,003
Accumulated depreciation, depletion and amortization	(518,054)	(368,245)
Total property and equipment, net	3,047,122	2,684,486
Other noncurrent assets:
Derivative instruments	18,579	86
Debt issuance costs	3,592	3,573
Other	17,250
Total assets	3,255,030	2,778,100
Current liabilities:
Accounts payable	76,189	53,005
Accrued liabilities	124,633	199,952
Derivative instruments	508	58,074
Total current liabilities	201,330	311,031
Noncurrent liabilities:
Long-term debt	1,191,376	770,596
Asset retirement obligations	8,226	14,467
Deferred tax liabilities	112,731	71,470
Derivative instruments		18,676
Other	2,233	1,085
Total noncurrent liabilities	1,314,566	876,294
Total liabilities	1,515,896	1,187,325
Commitments and contingencies (Note 18)
Stockholders' equity:
Common stock, $0.01 par value 500,000,000 shares authorized; 101,793,855 shares and 101,137,277 shares issued and outstanding at December 31, 2018 and December 31, 2017, respectively	1,018	1,012
Additional paid-in capital	1,153,617	1,118,507
Accumulated earnings	136,773	25,773
Total stockholders' equity	1,291,408	1,145,292
Total liabilities and equity	3,255,030	2,778,100
Preferred Stock
Temporary equity
Preferred stock
Series A Perpetual Convertible Preferred Stock
Temporary equity
Preferred stock	$ 447,726	$ 445,483

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CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	500,000,000	500,000,000
Common stock, shares issued	101,793,855	101,137,277
Common stock, shares outstanding	101,793,855	101,137,277
Preferred Stock
Preferred stock, par value	$ 0.01	$ 0.01
Preferred stock, shares authorized	50,000,000	50,000,000
Series A Perpetual Convertible Preferred Stock
Preferred stock, par value	$ 0.01	$ 0.01
Preferred stock, shares authorized	500,000	500,000
Preferred stock, shares issued	435,000	435,000
Preferred stock, shares outstanding	435,000	435,000
Preferred stock, involuntary liquidation preference	$ 450,389	$ 448,146

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STATEMENTS OF CONSOLIDATED AND COMBINED OPERATIONS - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Revenues and other income:
Other Income	$ 2,052	$ 1,431	$ 2,131
Total operating revenues and other income	947,386	427,187	127,342
Operating expenses:
Lease operating expenses	61,620	39,770	12,320
Gathering, processing and transportation	9,856	11,897	6,581
Taxes other than income tax	52,410	24,158	6,814
Depreciation, depletion and amortization	296,685	168,250	81,757
Impairment of NLA Disposal Group (Note 3)	214,274
Gain on sale of properties	(2,781)		43
General and administrative expenses	65,710	40,663	23,973
Incentive unit compensation expense	13,776
Exploration expense	22,483	36,911	12,026
Other operating expense	1,064	73	99
Total operating expenses	735,097	321,722	143,570
Income (loss) from operations	212,289	105,465	(16,228)
Other income (expense):
Interest expense, net	(60,119)	(31,934)	(7,834)
Gain (loss) on derivative instruments	35,393	(55,483)	(26,771)
North Louisiana settlement (Note 18)		(7,000)
Other income (expense)	(859)	8	(1,818)
Total other expense	(25,585)	(94,409)	(36,423)
Income (loss) before income taxes	186,704	11,056	(52,651)
Income tax benefit (expense)	(40,196)	38,824	5,575
Net income (loss)	146,508	49,880	(47,076)
Net loss attributable to previous owners			(2,681)
Net loss attributable to predecessor			(33,998)
Net income (loss) available to WRD	146,508	49,880	(10,397)
Preferred stock dividends	28,862	13,146
Undistributed earnings allocated to participating securities	30,344	5,612
Net income (loss) available to common stockholders	$ 87,302	$ 31,122	$ (10,397)
Earnings per common share:
Basic	$ 0.88	$ 0.32	$ (0.11)
Diluted	$ 0.88	$ 0.32	$ (0.11)
Weighted-average common shares outstanding:
Basic	99,498	96,324	91,327
Diluted	99,498	96,324	91,327
Oil sales
Revenues and other income:
Revenues	$ 843,244	$ 342,868	$ 75,938
Natural gas sales
Revenues and other income:
Revenues	60,129	59,924	43,487
Natural gas liquid sales
Revenues and other income:
Revenues	$ 41,961	$ 22,964	$ 5,786

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STATEMENTS OF CONSOLIDATED AND COMBINED CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Cash flows from operating activities:
Net income (loss)	$ 146,508	$ 49,880	$ (47,076)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	296,685	168,250	81,757
Impairments of unproved properties	10,504	20,834	3,051
Impairment of NLA Disposal Group	214,274
Amortization of debt issuance cost	3,098	2,575	479
Accretion of senior note discount	132	342
(Gain) loss on derivative instruments	(35,393)	55,483	26,771
Cash settlements on derivative instruments	(113,637)	1,517	4,975
Deferred income tax expense (benefit)	41,193	(39,831)	(5,575)
Debt extinguishment benefit		(11)	1,667
Amortization of equity awards	19,468	6,644	68
Incentive unit compensation expense	13,776
(Gain) loss on sale of properties	(2,781)		43
Loss on equity investment	676
Consideration paid to customers, net of amortization	(1,817)
Changes in operating assets and liabilities:
Increase in accounts receivable	(8,206)	(56,828)	(16,300)
Increase in prepaid expenses	(576)	(390)	(448)
Increase in inventories	(1,056)	(648)
(Decrease) increase in accounts payable and accrued liabilities	33,678	69,555	(27,150)
Net cash provided by operating activities	616,526	277,372	22,262
Cash flows from investing activities:
Acquisitions of oil and gas properties	(53,814)	(551,242)	(436,072)
Additions to oil and gas properties	(1,051,891)	(700,546)	(125,837)
Additions to and acquisitions of other property and equipment	(83,597)	(15,959)	(5,403)
Contribution to equity method investee	(10,177)
Sales of other property and equipment			102
Proceeds from NLA Divestiture	207,924
Net cash used in investing activities	(991,555)	(1,267,747)	(567,210)
Cash flows from financing activities:
Advances on revolving credit facilities	1,085,000	513,500	383,450
Payments on revolving credit facilities	(867,353)	(469,897)	(378,700)
Debt issuance cost	(4,736)	(15,279)	(3,607)
Termination of second lien			(225)
Proceeds from senior notes offering	204,000	494,744
Proceeds from the issuance of preferred stock		435,000
Proceeds from the issuance of common stock		34,457	412,500
Preferred stock dividends	(20,267)
Previous owner and predecessor contributions			110,280
Repurchase of vested restricted stock	(6,894)	(564)
Net cash provided by financing activities	389,750	986,600	505,272
Net change in cash, cash equivalents and restricted cash	14,721	(3,775)	(39,676)
Cash, cash equivalents and restricted cash, beginning of period	226	4,001	43,677
Cash, cash equivalents and restricted cash, end of period	14,947	226	4,001
Convertible Preferred Stock
Cash flows from financing activities:
Cost incurred in conjunction with the issuance of stock		(2,663)
Common Stock
Cash flows from financing activities:
Cost incurred in conjunction with the issuance of stock	$ 0	$ (2,698)	$ (18,426)

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CONSOLIDATED AND COMBINED STATEMENT OF CHANGES IN EQUITY - USD ($) $ in Thousands	Common Stock	Additional Paid in Capital	Accumulated Earnings (Deficit)	Total
Balance (Predecessor) at Dec. 31, 2015				$ 274,133
Balance (Previous Owner) at Dec. 31, 2015				374,556
Balance at Dec. 31, 2015				648,689
Capital contributions | Predecessor				10,837
Capital contributions | Previous Owner				97,000
Capital contributions				107,837
Property contributions | Previous Owner				329
Property contributions				329
Net income (loss) | Predecessor				(33,998)
Net income (loss) | Previous Owner				(2,681)
Net income (loss)			$ (10,397)	(47,076)
Proceeds from issuance of common stock	$ 275	$ 412,225		412,500
Costs incurred in connection with issuance of common stock		(19,252)		(19,252)
Notes receivable from members | Predecessor				(132)
Notes receivable from members				(132)
Dissolution of notes receivable from members. | Predecessor				2,575
Dissolution of notes receivable from members.				2,575
Amortization of equity awards	4	64		68
Issuance of shares in connection with Corporate Reorganization | Predecessor				(253,415)
Issuance of shares in connection with Corporate Reorganization | Previous Owner				(469,204)
Issuance of shares in connection with Corporate Reorganization	625	721,994
Issuance of shares in connection with acquisition of properties	13	19,613		19,626
Tax related effects in connection with Corporate Reorganization and initial public offering		(117,276)		(117,276)
Balance at Dec. 31, 2016	917	1,017,368	(10,397)	1,007,888
Net income (loss)			49,880	49,880
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	17	6,627		6,644
Issuance of shares in connection with acquisition of properties	55	60,699		60,754
Deferred tax adjustment related to initial public offering		1,251		1,251
Preferred stock paid-in-kind dividend			(13,146)	(13,146)
Repurchase of vested restricted common stock			(564)	(564)
Balance at Dec. 31, 2017	1,012	1,118,507	25,773	1,145,292
Net income (loss)			146,508	146,508
Amortization of equity awards	10	19,462		19,472
Preferred stock cash dividend			(20,267)	(20,267)
Preferred stock paid-in-kind dividend			(2,243)	(2,243)
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)	(1,872)
Repurchase of vested restricted common stock	(4)		(6,890)	(6,894)
Contribution related to incentive unit compensation expense		13,776		13,776
Balance at Dec. 31, 2018	$ 1,018	$ 1,153,617	136,773	1,291,408
Cumulative effect of accounting change (Note 2)			$ 243	$ 243

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Organization and Basis of Presentation

12 Months Ended

Dec. 31, 2018

Organization Consolidation And Presentation Of Financial Statements [Abstract]

Organization and Basis of Presentation

Note 1. Organization and Basis of Presentation

Merger with Chesapeake Energy Corporation

In February 2019, we were acquired by Chesapeake for approximately 717.3 million shares of Chesapeake common stock and $381.1 million in cash. Immediately following the completion of the acquisition, WildHorse Development merged with and into Brazos Valley Longhorn, L.L.C., a newly formed Delaware limited liability company and wholly owned subsidiary of Chesapeake.

Initial Public Offering and Corporate Reorganization

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

The Company was formed in August 2016 to serve as a holding company for the assets of WHR II and Esquisto. We did not have any operations until we completed our initial public offering on December 19, 2016. In connection with our initial public offering and Corporate Reorganization (defined below), our accounting predecessor, WHR II was contributed to us. In addition to WHR II, we received Esquisto and Acquisition Co. We are an independent oil and natural gas company focused on the acquisition, exploration, development and production of oil, natural gas and NGL resources.

WHR II, Esquisto II, Acquisition Co., WHR Eagle Ford LLC (“WHR EF”), Burleson Sand LLC (“Burleson Sand”) and WHCC Infrastructure LLC (“WHCC”) are wholly owned subsidiaries of the Company as of December 31, 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.

The Company issued and sold to the public in its initial public offering 27,500,000 shares of common stock. The gross proceeds from the sale of the common stock were $412.5 million, net of underwriting discounts of $14.1 million and other offering costs of $5.0 million. The net proceeds from our initial public offering were $393.4 million. Debt issuance costs of $2.9 million related to the establishment of the Company's revolving credit facility were also incurred in conjunction with our initial public offering.

Contemporaneously with our initial public offering, (i) the owners of WHR II exchanged all of their interests in WHR II for equivalent interests in WildHorse Investment Holdings and the owners of Esquisto exchanged all of their interests in Esquisto for equivalent interests in Esquisto Investment Holdings, (ii) WildHorse Investment Holdings contributed all of the interests in WHR II to WildHorse Holdings, Esquisto Investment Holdings contributed all of the interests in Esquisto to Esquisto Holdings and the owner of Acquisition Co. contributed all of its interests in Acquisition Co. to Acquisition Co. Holdings and (iii) WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings contributed all of the interests in WHR II, Esquisto and Acquisition Co., respectively, to us in exchange for shares of our common stock. We refer to these reorganization transactions as the “Corporate Reorganization.” As a result of the Corporate Reorganization, WHR II, Esquisto and Acquisition Co. became direct, wholly owned subsidiaries of WildHorse Resource Development Corporation.

Basis of Presentation

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

Our consolidated and combined 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 consolidated and combined statements of cash flows. Restricted cash is now being included in cash and cash equivalents when reconciling the beginning of period and end of period totals due to the adoption of a new accounting standard.

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

Investment in Unconsolidated 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. In December 2018, we accrued an additional $1.9 million capital contribution which was funded in January 2019.   

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.  We have incurred letter of credit fees of approximately $0.4 million.

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 $11.5 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 $0.7 million for the year ended December 31, 2018 is reflected on our income statement under other income (expense) as a component of the “Other income (expense)” financial statement line item.

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2018

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

Note 2. Summary of Significant Accounting Policies

Use of Estimates in the Preparation of Financial Statements

Preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about carrying values of assets and liabilities that are not readily apparent from other sources. We evaluate the estimates and assumptions on a regular basis; however, actual results may differ from these estimates and assumptions used in the preparation of the financial statements. Significant estimates with regard to these financial statements include (1) the estimate of proved oil, natural gas and NGL reserves and related present value estimates of future net cash flows therefrom; (2) depreciation, depletion and amortization expense; (3) valuation of accounts receivable; (4) accrued capital expenditures and liabilities; (5) asset retirement obligations; (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.

Cash and Cash Equivalents

We consider all highly liquid investment instruments purchased with original maturities of three months or less to be cash equivalents for purposes of the Consolidated and Combined Statements of Cash Flows and other statements. These investments are carried at cost, which approximates fair value. In case a book overdraft exists at the end of a period, we reclassify the negative cash amount to accounts payable.

Restricted Cash

Historically, restricted cash consisted of certificates of deposit in place to collateralize letters of credit. The letters of credit were required as part of normal business operations. The certificates of deposit were in place for a period greater than 12 months and were considered noncurrent. We had no restricted cash at December 31, 2018 and 2017.

Oil and Gas Properties

We use the successful efforts method of accounting for crude oil and natural gas producing activities. Costs to acquire mineral interests in natural gas and crude oil properties are capitalized. Significant costs associated with development wells in progress or awaiting completion are excluded from depletion until the well is completed.  We have excluded capitalized costs of $98.1 million at December 31, 2018. Costs to drill exploratory wells that do not find proved reserves, delay rentals and geological and geophysical costs are expensed.

The following table reflects the net changes in capitalized exploratory well costs for the periods indicated (in thousands):

	For Year Ended December 31,
	2018		2017		2016
Balance, beginning of period	$	—	$	7,064	$	15,198
Additions to capitalized exploratory well costs pending the determination of proved reserves		—		—		60,847
Reclassifications to wells, facilities and equipment based on the determination of proved reserves		—		(7,064)		(68,981)
Capitalized exploratory well costs charged to expense		—		—		—
Balance, end of period	$	—	$	—	$	7,064

We acquire leases on acreage not associated with proved reserves or held by production with the expectation of ultimately assigning proved reserves and holding the leases with production. The costs of acquiring these leases, including primarily brokerage costs and amounts paid to lessors, are capitalized and excluded from current amortization pending evaluation. When proved reserves are assigned, the leasehold costs associated with those leases are depleted as producing oil and gas properties. Costs associated with leases not held by production are impaired when events and circumstances indicate that carrying value of the properties is not recoverable. We recorded impairment of $10.5 million, $20.8 million and $3.1 million as exploration expense for unproved oil and gas properties for the years ended December 31, 2018, 2017 and 2016, respectively.

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

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

Oil and Gas Reserves

The estimates of proved crude oil, natural gas, and natural gas liquids reserves utilized in the preparation of the financial statements are estimated in accordance with guidelines established by the Securities and Exchange Commission (“SEC”) and the Financial Accounting Standards Board (“FASB”), which require that reserve estimates be prepared under existing economic and operating conditions using a 12‑month average price with no provision for price and cost escalations in future years except by contractual arrangements. Our proved reserves are prepared by Cawley, Gillespie & Associates, Inc. ("CG&A"), a third-party independent reserve engineer.

We emphasize that reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. It is possible that, because of changes in market conditions or the inherent imprecision of these reserve estimates, the estimates of future cash inflows, future gross revenues, the amount of natural gas, crude oil and natural gas liquids reserves, the remaining estimated lives of the natural gas and crude oil properties, or any combination of the above may be increased or reduced. See Note 20—“Supplemental Oil and Gas Information (Unaudited)” for further information.

Other Property and Equipment

Other property and equipment includes our sand mine, saltwater disposal wells, Burleson water assets, leasehold improvements, office furniture, automobiles, computer equipment, software, pipelines, office buildings and land. Other property and equipment is depreciated using a straight-line method over the expected useful lives of the respective assets. Leasehold improvements are amortized over the remaining term of the lease and land is not depreciated or amortized.

Capitalized Interest

We capitalize interest costs to oil and gas properties on expenditures made in connection with certain projects such as drilling and completion of new oil and natural gas wells and major facility installations. Interest is capitalized only for the period that such activities are in progress. Interest is capitalized using a weighted average interest rate based on our outstanding borrowings. For the year ended December 31, 2018, 2017 and 2016, we recorded $5.9 million, $3.1 million and $0.1 million in capitalized interest, respectively.

Properties Acquired in Asset Acquisitions and Business Combinations

For asset acquisitions, the purchase price recorded at cost and is allocated to identifiable assets on a relative fair value basis.  Therefore, we would need to determine the fair value of the assets at acquisition.

Assets and liabilities acquired in a business combination are required to be recorded at fair value. If sufficient market data is not available, we determine the fair values of proved and unproved properties acquired in transactions accounted for as business combinations by preparing our own estimates of crude oil and natural gas reserves. To compensate for the inherent risk of estimating and valuing unproved reserves, discounted future net cash flows of probable and possible reserves are reduced by additional risk-weighting factors. See Note 3—“Acquisitions and Divestitures.”

Asset Retirement Obligations

We recognize a liability equal to the fair value of the estimated cost to plug and abandon our natural gas and crude oil wells and associated equipment. The liability and the associated increase in the related long-lived asset are recorded in the period in which the related assets are placed in service or acquired. The liability is accreted to its expected future cost each period and the capitalized cost is depleted using the units-of-production method of the related asset. The accretion expense is included in depreciation, depletion and amortization expense.

The fair value of the estimated cost is based on historical experience, managements' expertise and third-party proposals for plugging and abandoning wells. The estimated remaining lives of the wells is based on reserve life estimates and federal and state regulatory requirements. At the time the related long-lived asset is placed in service, the estimated cost is adjusted for inflation based on the remaining life, then discounted using a credit-adjusted risk-free rate to determine the fair value.

Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs, including non-operated plug and abandonment expense, changes in the remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements. At the time of abandonment, we recognize a gain or loss on abandonment to the extent that actual costs do not equal the estimated costs.

Environmental Costs

As an owner or lessee and operator of oil and gas properties, we are subject to various federal, state and local laws and regulations relating to discharge of materials into, and protection of, the environment. Environmental expenditures that relate to an existing condition caused by past operations and that do not have future economic benefit are expensed. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable and the costs can be reasonably estimated.

Revenue 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.

Natural 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, the Company 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 the Company 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).  Our performance obligation under these contracts is to sell the extracted NGLs and residue gas.  We recognize revenue at a point in time (at the plant tailgate) when we have fulfilled our performance obligation.  Prior to the adoption of the new revenue standard, we did not recognize the volumes retained by our customer as an expense and we reported revenues net of the volumes they retained.

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.

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 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.

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 December 31, 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 -"Acquisitions and Divestitures"), 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.

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 Year Ended December 31, 2018
	As Reported		Without ASC 606		Increase/-
	Under ASC 606		Adoption		Decrease
Revenues:
Oil sales	$	843,244	$	843,329	$	(85)
Natural gas sales		60,129		64,896		(4,767)
NGL sales		41,961		51,052		(9,091)
Other Income		2,052		1,861		191
Operating expenses:
Lease operating expenses		61,620		63,043		(1,423)
Gathering, processing and transportation		9,856		22,703		(12,847)
Depreciation, depletion and amortization		296,685		297,295		(610)
Other operating expense		1,064		459		605
Income before income taxes		186,704		186,180		524
Income tax expense		(40,196)		(40,083)		(113)
Net income		146,508		146,097		411

	At December 31, 2018
	As Reported		Without ASC 606		Increase/-
	Under ASC 606		Adoption		Decrease
Assets:
Oil and gas properties	$	3,457,897	$	3,463,857	$	(5,960)
Accumulated depreciation, depletion and amortization		(518,054)		(519,035)		981
Other non-current assets		17,250		11,439		5,811
Liabilities:
Deferred tax liabilities		112,731		112,551		180
Stockholders' Equity
Accumulated earnings		136,773		137,785		(1,012)

	For the Year Ended December 31, 2018
	As Reported		Without ASC 606		Increase/-
	Under ASC 606		Adoption		Decrease
Cash flows from operating activities:
Net income	$	146,508	$	146,097	$	411
Depreciation, depletion and amortization		296,685		297,295		(610)
Deferred income tax expense		41,193		41,080		113
Consideration paid to customers, net of amortization		(1,817)		—		(1,817)
Cash flows from investing activities:
Additions to oil and gas properties		(1,051,891)		(1,053,811)		1,920

Incentive Units

For details regarding incentive units, please see “Note 14. Incentive Units.”

Accounts Receivable

We grant credit to creditworthy independent and major natural gas and crude oil marketing companies for the sale of crude oil, natural gas and natural gas liquids. In addition, we grant credit to our oil and gas working interest partners. Receivables from our working interest partners are generally secured by the underlying ownership interests in the properties.

Accounts receivable balances primarily relate to joint interest billings and oil and gas sales, net of our interest. The accounts receivable balance generally includes one month of accrued revenues for operated oil properties, two months of accrued revenues for operated natural gas properties and three months of accrued revenues for non-operated properties net of any collections related to those periods. The accounts receivable balance also includes other miscellaneous balances.

Accounts receivable are recorded at the amount we expect to collect. We use the specific identification method of providing allowances for doubtful accounts. We recorded a provision for uncollectible accounts of $0.2 million and $0.1 million at December 31, 2018 and 2017, respectively.

Derivative Instruments

We periodically enter into derivative contracts to manage our exposure to commodity price risk. These derivative contracts, which are placed with major financial institutions that we believe have minimal credit risks, take the form of variable to fixed price commodity swaps, basis swaps, collars and deferred purchased puts. The natural gas reference price, upon which the commodity derivative contracts are based, reflects market indices that have a high degree of historical correlation with actual prices received for natural gas sales.

All derivative instruments are recorded on the balance sheet as either an asset or liability measured at fair value. Derivative instruments are netted when the right to net exists under a master netting agreement, future liabilities and assets correspond to the same commodity type and future cash flows have the same balance sheet current or non-current classification. Changes in fair value are recognized currently in earnings. Realized and unrealized gains and losses from our oil, gas and natural gas liquids derivatives are recorded as a component of “Other income (expense)” on our Statements of Consolidated and Combined Operations. We compute the fair value of the unrealized gains and losses of our derivative instruments using forward prices and dealer quotes provided by a third party.

For our forward commodity contracts that meet the definition of a derivative, we have elected the normal purchases and normal sales scope exclusion, because we believe it is probable that physical delivery of the product will occur under the contract and we do not intend on net settling the contract. Therefore, all activity under these contracts was recorded as revenue in our consolidated financial statements.

See Note 5—“Risk Management and Derivative and Other Financial Instruments” for additional information regarding our derivative instruments.

Corporate Lease Expenses

We record escalating lease expenses for our corporate office over the life of the lease on a straight-line basis.

Debt Issuance Costs

Debt issuance costs associated with line-of-credit arrangements, including arrangements with no outstanding borrowings, are classified as an asset, and amortized over the term of the arrangements. Debt issuance costs related to term loans and senior notes are presented as a direct deduction from the carrying amount of the associated debt liability and amortized over the term of the associated debt using the effective yield method.

Fair Value Measurements

Accounting guidance for fair value measurements establishes a fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three levels. The fair value hierarchy gives the highest priority to quoted market prices (unadjusted) in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Level 2 inputs are inputs, other than quoted prices included within Level 1, which are observable for the asset or liability, either directly or indirectly. We use Level 1 inputs when available as Level 1 inputs generally provide the most reliable evidence of fair value. See Note 4—“Fair Value Measurements of Financial Instruments.”

Income Taxes

We are a corporation subject to federal and certain state income taxes. Prior to our initial public offering, we were primarily organized as pass-through entities for federal income tax purposes and were not subject to federal income taxes.

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 carry forwards. 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 and Combined 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.

Commitments and Contingencies

Accruals for loss contingencies arising from claims, assessments, litigation, environmental and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. These accruals are adjusted as additional information becomes available or circumstances change.

Supplemental Cash Flow Information

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

	For Year Ended December 31,
	2018		2017		2016
Supplemental cash flows:
Cash paid for interest, net of capitalized interest	$	48,717	$	12,246	$	7,152
Noncash investing activities:
Increase (decrease) in capital expenditures in accounts payables and accrued liabilities		(82,358)		134,589		(4,492)
(Increase) decrease in accounts receivable related to capital expenditures and acquisitions		(1,247)		(847)		(5,175)

Due to Hurricane Harvey, the Internal Revenue Service (“IRS”) granted relief to affected taxpayers by allowing taxpayers to defer the deadline for tax return filings and payment of estimated taxes to January 31, 2018. The Company paid $2.3 million related to its 2017 estimated alternative minimum tax to the IRS on January 31, 2018.

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. The Company adopted this guidance on January 1, 2018 on a prospective basis 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 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, which requires classification of leases as finance or operating. The classification is 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. The new standard is effective for financial statements issued for annual periods beginning after December 15, 2018 and interim periods within those fiscal years. 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 adopted the standard using the effective date method on January 1, 2019.

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 old 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 has made this accounting policy election beginning January 1, 2019.

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 has made this accounting policy election for all classes of assets beginning January 1, 2019.

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 has made this accounting policy election beginning January 1, 2019.

The Company is a lessee under various agreements for office space, compressors and other equipment.  Though we are finalizing the implementation of certain processes to monitor and track all lease information, we anticipate leases as recognized under the new standard will create right-of-use assets and initial lease liabilities between $35 million and $65 million on our consolidated balance sheet.

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.  

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Acquisitions and Divestitures

12 Months Ended

Dec. 31, 2018

Business Combinations [Abstract]

Acquisitions and Divestitures

Note 3. Acquisitions and Divestitures

We account for third-party acquisitions under the acquisition method. The assets acquired and the liabilities assumed have been measured at fair value based on various estimates. These estimates are based on key assumptions related to the business combination, including reviews of publicly disclosed information for other acquisitions in the industry, historical experience of the companies, data that was available through the public domain and due diligence reviews of the acquired businesses. Acquisition-related transaction costs and acquisition-related restructuring charges are not included as components of consideration transferred but are accounted for as expenses in the period in which the costs are incurred.

Acquisition-related costs

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

For the Year Ended December 31,
	2018	2017		2016
$	1,117	$	4,348	$	553

2018 Acquisitions

Eagle Ford Shale Acquisitions. During the year ended December 31, 2018, we closed on multiple transactions to acquire certain acreage and associated production from third parties for approximately $53.8 million.   These transactions were accounted for as asset acquisitions since substantially all the fair value was concentrated in a group of similar assets.  As such, an additional $1.5 million of acquisition costs were capitalized as part of these acquisitions.  We assigned $48.0 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 $66.1 million at December 31, 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 APC and KKR (together with APC, the “First Sellers”), as sellers, to acquire certain acreage and associated production in Burleson, Brazos, Lee, Milam, Robertson and Washington Counties, Texas (the “Purchase”). Also on May 10, 2017, WHR EF entered into a Purchase and Sale Agreement (together, with the First Acquisition Agreement, the “Acquisition Agreements”), by and among WHR EF, as purchaser, and APC and Anadarko Energy Services Company (together, with APC, the “APC Subs” and, together with the First Sellers, the “Sellers”), as sellers, to acquire certain acreage and associated production in Burleson, Brazos, Lee, Milam, Robertson and Washington Counties, Texas (together, with the Purchase, the “Acquisition”).

On  June 30, 2017, we completed the Acquisition. The aggregate purchase price for the Acquisition, as described in the Acquisition Agreements, consisted of an aggregate of approximately $533.6 million of cash to the APC Subs and approximately 5.5 million shares of our common stock valued at approximately $60.8 million to KKR (collectively, the “Adjusted Purchase Price”). The common stock portion of the Adjusted Purchase Price payable to KKR was issued pursuant to a Stock Issuance Agreement that was executed on May 10, 2017, by and among us and KKR. For the year ended December 31, 2017, revenues of $42.6 million were recorded in the statement of operations, which generated $11.1 million of income subsequent to the closing date.

The following table summarizes the fair value assessment of the assets acquired and liabilities assumed as of the closing 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 year ended December 31, 2017 and 2016 as though the Acquisition had been completed on January 1, 2016 (in thousands, except per share amounts). The unaudited pro forma financial information was derived from the historical combined statements of operations of the predecessor and previous owners and adjusted to include: (i) the revenues and direct operating expenses associated with oil and natural gas properties acquired, (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 the Year Ended December 31,
	2017		2016
Revenues	$	475,396	$	226,502
Net income (loss)	$	71,287	$	(11,290)
Earnings per share (basic and diluted)	$	0.51	$	(0.10)

Burleson 2017 Acquisitions. During the year ended December 31, 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 $19.7 million, of which $11.6 million was allocated to unproved oil and natural gas properties.

2016 Acquisitions

Burleson North Acquisition. On December 19, 2016, in connection with our initial public offering, we completed an acquisition of approximately 158,000 net acres of oil and natural gas properties adjacent to our existing Eagle Ford Acreage (the “Burleson North Acquisition”). Funds wired on December 19, 2016 were $389.8 million. During the three months ended March 31, 2017, we received a post-closing receipt of $3.9 million. We allocated $162.9 million of the purchase price to unproved oil and natural gas properties.  For the year ended December 31, 2016, revenues of $2.0 million were recorded in the statement of operations and generated a loss of approximately $0.4 million subsequent to the closing date.

The following table summarizes the fair value assessment of the assets acquired and liabilities assumed as of the acquisition date after customary post-closing adjustments (in thousands):

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

Rosewood Acquisition. On December 19, 2016, we acquired from certain third parties approximately 7,500 net acres, consisting primarily of additional working interests in our Eagle Ford Acreage in Lee County (the “Rosewood Acquisition”). The closing of the acquisition occurred contemporaneously with the closing of our initial public offering, and we issued 1,308,427 shares to such third parties as consideration. We allocated $18.3 million of the purchase price to unproved oil and natural gas properties with the remainder allocated to proved oil and natural gas properties.

November Acquisition. On November 8, 2016, Esquisto acquired from certain third parties approximately 4,900 net acres and nine producing wells in Burleson County for approximately $30.0 million (the “November Acquisition”), of which $29.4 million of the purchase price was allocated to unproved oil and natural gas properties with the remainder allocated to proved oil and natural gas properties.

The following table summarizes the fair value assessment of the assets acquired and liabilities assumed as of the acquisition date for the November Acquisition and Rosewood Acquisition (in thousands):

		Rosewood Acquisition		November Acquisition
Oil and gas properties	$	19,626	$	29,973

The following unaudited pro forma combined results of operations are provided for the years ended December 31, 2016 as though the Burleson North Acquisition had been completed on January 1, 2015. The unaudited pro forma financial information was derived from the historical combined statements of operations of the Company, the predecessor and previous owners and adjusted to include: (i) the revenues and direct operating expenses associated with oil and gas properties acquired and (ii) depletion expense applied to the adjusted basis of the properties acquired. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of expected future results of operations.

	For Year Ended December 31,
	2016
Revenues	$	176,082
Net loss	$	(34,894)
Basic and diluted earnings per unit		n/a

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 final purchase price adjustments of $4.8 million, the final sales price of $211.2 million has been fully collected at December 31, 2018. The Company has paid $3.8 million in expenses related to the divestiture and has received $0.4 million in contingent payments from Tanos.

In addition, the Company could receive contingent payments of up to $35.0 million, based on the number of wells spud on such properties over the next three 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. We received $0.4 million in contingent payments 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 customary preliminary purchase price adjustments, we recorded an impairment charge of $214.3 million during the first quarter of 2018 to adjust the carrying amount of the disposal group (“NLA Disposal Group”) to its 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 years ended December 31, 2018 and 2017, the NLA Disposal Group had pre-tax losses of $202.7 million and $5.9 million, respectively.

During the year ended December 31, 2018, we recognized a gain of $2.8 million. We received a $4.8 million final settlement payment from Tanos in October 2018.  We provided Tanos with transitional accounting and land services during the three months ended June 30, 2018 and recognized $0.9 million of fees as a reduction to our general and administrative expenses.

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Fair Value Measurements of Financial Instruments

12 Months Ended

Dec. 31, 2018

Fair Value Disclosures [Abstract]

Fair Value Measurements of Financial Instruments

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). The characteristics of fair value amounts classified within each level of the hierarchy are described as follows:

Level 1 — Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. An active market is one in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 — Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. At December 31, 2018 and 2017, all of the derivative instruments reflected on the accompanying balance sheets were considered Level 2.

Level 3 — Measure based on prices or valuation models that require inputs that are both significant to the fair value measurement and are less observable from objective sources (i.e., supported by little or no market activity).

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 December 31, 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 December 31, 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.

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

	Fair Value Measurements at December 31, 2018
	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	$	—	$	72,710	$	—	$	72,710
Liabilities:
Commodity derivatives	$	—	$	508	$	—	$	508

	Fair Value Measurements at December 31, 2017
	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 gas properties. We did not record impairments on proved properties for the year ended December 31, 2018, 2017 and 2016.

· Unproved oil and natural gas properties and other assets are reviewed for impairment based on passage of time or geologic factors.  Information such as remaining lease terms, drilling results, reservoir performance, seismic interpretation or future plans to develop acreage is also considered.  When unproved properties are deemed to be impaired, the expense is recorded as a component of exploration expenses.  For the years ended December 31, 2018, 2017 and 2016, we recorded $10.5 million, $20.8 million and $3.1 million of impairments of unproved properties, respectively.

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

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Risk Management and Derivative and Other Financial Instruments

12 Months Ended

Dec. 31, 2018

Derivative Instruments And Hedging Activities Disclosure

Risk Management and Derivative Instruments

Note 5. Risk Management and Derivative and Other Financial 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, historically, used fixed price commodity swaps, basis swaps, collars 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. Collars consist of a sold call and a purchased put that establish a ceiling and floor price for expected future oil and natural gas sales. We recognize all derivative instruments at fair value; however, certain of our derivative instruments have a deferred premium. The deferred premium is factored into the fair value measurement and where the Company agrees to defer the premium paid or received until the time of settlement. Cash received on settled derivative positions during the years ended December 31, 2018 and 2017 is net of deferred premiums of $9.3 million and $6.3 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, certain of which are also lenders under the 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 December 31, 2018 we had net derivative assets of $72.2 million. Had certain counterparties failed completely to perform according to the terms of existing contracts, we would have the right to offset $72.2 million against amounts outstanding under our revolving credit facility, thereby eliminating any credit exposure.

The following derivative contracts were in place at December 31, 2018:

	2019		2020
Crude Oil Derivative Contracts:
Fixed price swap contracts:
Volume (Bbls)		6,652,369		4,511,681
Weighted-average fixed price	$	54.45	$	53.49
Put options:
Volume (Bbls)		1,749,757		—
Weighted-average floor price	$	53.83	$	—
Weighted-average put premium	$	(5.43)	$	—
Natural Gas Derivative Contracts:
Fixed price swap contracts:
Volume (MMBtu)		6,425,146		4,846,020
Weighted-average fixed price	$	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 December 31, 2018 and 2017. There was no cash collateral received or pledged associated with our derivative instruments since the counterparties to our derivative contracts are lenders under our collective credit agreements.

		Asset Derivatives				Liability Derivatives
		(in thousands)				(in thousands)
Type	Balance Sheet Location	2018		2017		2018		2017
Commodity contracts	Short-term derivative instruments	$	54,131	$	2,336	$	508	$	58,074
Netting arrangements	Short-term derivative instruments		—		—		—		—
Net recorded fair value		$	54,131	$	2,336	$	508	$	58,074
Commodity contacts	Long-term derivative instruments	$	18,579	$	86	$	—	$	18,676
Netting arrangements	Long-term derivative instruments		—		—		—		—
Net recorded fair value		$	18,579	$	86	$	—	$	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 Statements of Combined and Consolidated Financial Statements. The following table details the gains and losses related to derivative instruments for the years ending December 31, 2018, 2017 and 2016 (in thousands):

	Statements of	For the Year Ended December 31,
	Operations Location	2018		2017		2016
Commodity derivative contracts	Gain (loss) on derivative instruments	$	35,393	$	(55,483)	$	(26,771)

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Accounts Receivable

12 Months Ended

Dec. 31, 2018

Receivables [Abstract]

Accounts Receivable

Note 6. Accounts Receivable

Accounts receivable consist of the following (in thousands):

	At December 31,
	2018		2017
Oil, gas and NGL sales	$	70,900	$	67,584
Joint interest billings		17,491		9,467
Severance tax		1,352		171
Derivative receivable		308		—
North Louisiana Settlement receivable		—		5,955
Environmental remediation		1,511		—
Other current receivables		196		1,026
Allowance for doubtful accounts		(200)		(100)
Total	$	91,558	$	84,103

The following table presents our allowance for doubtful accounts activity for the periods indicated (in thousands):

	2018		2017		2016
Balance at beginning of period	$	100	$	100	$	50
Charged to costs and expenses		100		—		50
Balance at end of period	$	200	$	100	$	100

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Accrued Liabilities

12 Months Ended

Dec. 31, 2018

Payables And Accruals [Abstract]

Accrued Liabilities

Note 7. Accrued Liabilities

Accrued liabilities consist of the following (in thousands):

	At December 31,
	2018		2017
Capital expenditures	$	80,897	$	162,260
Preferred stock cash dividends		4,479		—
Deferred rent		—		410
Lease operating expense		6,604		5,796
General and administrative		4,335		1,642
Severance and ad valorem taxes		5,283		3,463
Interest expense		20,122		17,177
Derivative payable		1,746		5,281
Income taxes		—		991
Other accrued liabilities		1,167		2,932
Total	$	124,633	$	199,952

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Asset Retirement Obligations

12 Months Ended

Dec. 31, 2018

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

Note 8. Asset Retirement Obligations

The following table presents the changes in the asset retirement obligations for the year ended December 31, 2018 and 2017 (in thousands):

	For the Year Ended December 31,
	2018		2017
Asset retirement obligations at beginning of period	$	14,557	$	11,033
Accretion expense		573		713
Liabilities incurred		743		3,137
Liabilities settled		—		—
Revisions		70		(326)
Disposition of wells and gathering system		(7,627)		—
Asset retirement obligations at end of period		8,316		14,557
Less: current portion		90		90
Asset retirement obligations – long-term	$	8,226	$	14,467

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Long Term Debt

12 Months Ended

Dec. 31, 2018

Debt Disclosure [Abstract]

Long Term Debt

Note 9. Long Term Debt

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

	At December 31,
Debt Obligation	2018		2017
WRD revolving credit facility	$	504,000	$	286,353
2025 Senior Notes (as defined below) (1)		700,000		500,000
Unamortized net discounts - 2025 Senior Notes		(782)		(4,914)
Unamortized debt issuance costs - 2025 Senior Notes		(11,842)		(10,843)
Total long-term debt	$	1,191,376	$	770,596

(1) The estimated fair value of this fixed-rate debt was $661.5 million and $511.3 million at December 31, 2018 and 2017, respectively. The estimated fair values are based on quoted market prices and is 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):

	December 31,
Credit Facility	2018
WRD revolving credit facility	$	1,300,000

Revolving Credit Facility

On December 19, 2016 after the closing of our initial public offering, 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, which had an initial borrowing base of $450.0 million but was automatically reduced to $362.5 million in connection with the consummation of our 2025 Senior Notes (defined below) offering on February 1, 2017.

On June 30, 2017, the Company, each of the Company's wholly owned subsidiaries (each as a guarantor), Wells Fargo Bank National Association, as administrative agent (the “Administrative Agent”), and the lenders party thereto entered into a Second Amendment to the Credit Agreement (the “Second Amendment”) 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 Second Amendment, among other things, modified the Credit Agreement to (i) permit the Company to enter into the Acquisition, and the Preferred Stock Purchase Agreement, and perform its obligations under and in connection therewith, including the issuance of the Preferred Stock (see Note 10-"Preferred Stock"), (ii) increase the Company's borrowing base and elected commitment amount from $450 million to $650 million, (iii) increase the annual cap on certain restricted payments from $50 million to $75 million, and (iv) modify the definition of net debt so that certain contingent obligations, accounts payable, obligations to make deliveries in respect of advance payments, take or pay obligations, disqualified capital stock and obligations in respect of production payments are excluded from net debt for purposes of the Company's leverage covenant.

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

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 to the Credit Agreement (the “Fourth Amendment”).  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 a Fifth Amendment to the Credit Agreement (the “Fifth Amendment”).  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

Our revolving credit facility is reserve-based, and thus our borrowing base is primarily based on the estimated value of our oil and natural gas properties and our commodity derivative contracts as determined by our lenders in their sole discretion consistent with their normal and customary oil and gas lending practices semi-annually (in the case of scheduled redeterminations), from time to time at our election in connection with material acquisitions, or no more frequently than twice in any fiscal year at the request of the required lenders or us (in the case of interim redeterminations), in each case based on engineering reports with respect to our estimated oil, NGL and natural gas reserves, and our commodity derivative contracts. Unanimous approval by the lenders is required for any increase to the borrowing base pursuant to a redetermination, while only required lender approval is required to maintain or decrease the borrowing base pursuant to a redetermination. The borrowing base may also automatically decrease upon the issuance of certain debt, including senior notes, the sale or other disposition of certain assets and the early termination of certain swap agreements. In the future, we may be unable to access sufficient capital under the Credit Agreement as a result of (i) a decrease in our borrowing base due to a borrowing base redetermination or (ii) an unwillingness or inability on the part of our lenders to meet their funding obligations.

A decline in commodity prices could result in a redetermination that lowers our borrowing base and, in such case, we could be required to repay any indebtedness in excess of the borrowing base, or we could be required to pledge other oil and natural gas properties as additional collateral. If a redetermination of our borrowing base results in our borrowing base being less than our aggregate elected commitments, our aggregate elected commitments will be automatically reduced to the amount of such reduced borrowing base. We do not anticipate having any substantial unpledged properties, and we may not have the financial resources in the future to make any mandatory principal prepayments required under the Credit Agreement.

Borrowings under our revolving credit facility are secured by liens on substantially all of our properties, but in any event, not less than 85% (or 75% with respect to certain properties prior to February 2, 2017) of the total value, as determined by the administrative agent, of the proved reserves attributable to our oil and natural gas properties using a discount rate of 9%, all of our equity interests in any future guarantor subsidiaries and all of our other assets including personal property but excluding equity interests in and assets of unrestricted subsidiaries.

Additionally, borrowings under our revolving credit facility will bear interest, at our option, at either: (i) the Alternate Base Rate, which is based on the greatest of (x) the prime rate as determined by the Administrative Agent, (y) the federal funds effective rate plus 0.50%, and (z) the adjusted LIBOR for a one month interest period plus 1.0%, in each case, plus a margin that varies per annum according to the total commitments usage (which is the ratio of outstanding borrowings and letters of credit to the least of the total commitments, the borrowing base and the aggregate elected commitments then in effect), (ii) the adjusted LIBOR plus a margin that varies per annum according to the total commitment usage or (iii) the applicable LIBOR market index rate plus a margin that varies per annum according to the total commitment usage. The unused portion of the total commitments are subject to a commitment fee that varies per annum according to our total commitments usage.

The Credit Agreement requires us to maintain (x) a ratio of total debt to EBITDAX (as defined under our revolving credit facility) of not more than 4.00 to 1.00 and (y) a ratio of current assets (including availability under the facility) to current liabilities of not less than 1.00 to 1.00.

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

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

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

2025 Senior Notes

On February 1, 2017, we completed a private placement of $350.0 million aggregate principal amount of 6.875% senior unsecured notes due 2025 (the “2025 Senior Notes”).  The 2025 Senior Notes were issued at a price of 99.244% of par and resulted in net proceeds of approximately $338.6 million.  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.

The indenture governing the 2025 Senior Notes (the "2025 Indenture") contains customary reporting covenants (including furnishing quarterly and annual reports to the holders of the 2025 Senior Notes) and restrictive covenants that, among other things, restrict the ability of the Company and its subsidiaries to: (i) pay dividends on, purchase or redeem the Company's equity interests or purchase or redeem subordinated debt; (ii) make certain investments; (iii) incur or guarantee additional indebtedness or issue certain types of equity securities; (iv) create or incur certain secured debt; (v) sell assets; (vi) consolidate, merge or transfer all or substantially all of the Company's assets; (vii) enter into agreements that restrict distributions or other payments from the Company's restricted subsidiaries to the Company; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries. These covenants are subject to a number of important qualifications and limitations. In addition, most of the covenants will be terminated before the 2025 Senior Notes mature if at any time no default or event of default exists under the 2025 Indenture and the 2025 Senior Notes receive an investment grade rating from both of two specified ratings agencies. The 2025 Indenture also contains customary events of default.

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 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.

Pursuant to a registration rights agreement entered into in connection with the issuance of the April Notes, we agreed to file a registration statement with the SEC so that holders of the April Notes could exchange the unregistered April Notes for registered notes that have substantially identical terms. In addition, we agreed to exchange the unregistered guarantees related to the April Notes for registered guarantees having substantially identical terms. On September 24, 2018, 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.

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 and combined variable-rate debt obligations for the periods presented:

	At December 31,
Credit Facility	2018		2017		2016
WRD revolving credit facility	4.06	%	3.60	%	3.52	%
WHR II revolving credit facility terminated December 2016	n/a		n/a		3.03	%
Esquisto - revolving credit facility terminated December 2016	n/a		n/a		2.84	%
Esquisto - revolving credit facility terminated January 2016	n/a		n/a		2.97	%
Esquisto - Second lien terminated in January 2016	n/a		n/a		9.50	%

Unamortized Deferred Financing Costs

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

	At December 31,
	2018		2017
WRD revolving credit facility
Current	$	1,823	$	1,203
Long-term		3,592		3,573
6.875% senior unsecured notes, due February 2025		11,842		10,843
Total	$	17,257	$	15,619

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Preferred Stock

12 Months Ended

Dec. 31, 2018

Temporary Equity [Abstract]

Preferred Stock

Note 10. Preferred Stock

Preferred Stock Issuance

We partially funded the Acquisition through the issuance of 435,000 shares of Preferred Stock in exchange for $435.0 million on June 30, 2017, pursuant to a Preferred Stock Purchase Agreement (the “Preferred Stock Purchase Agreement”), by and among us and CP VI Eagle Holdings, L.P. (the “Carlyle Investor”), an affiliate of The Carlyle Group, L.P.

	Series A Perpetual
	Convertible Preferred
	Stock
	(in thousands)
Balance at December 31, 2016	$	—
Issue of preferred stock in connection with the Acquisition		435,000
Costs incurred related to the issuance of preferred stock		(2,663)
Accrual of preferred stock paid-in-kind dividend		13,146
Balance at December 31, 2017		445,483
Paid-in-kind dividend		2,243
Beneficial conversion feature ("BCF")		(1,872)
Amortization of BCF		1,872
Balance at December 31, 2018	$	447,726

The Preferred Stock ranks senior to our common stock with respect to dividend rights and with respect to rights on liquidation, winding-up and dissolution. The Preferred Stock had an initial Accreted Value (as defined in the Certificate of Designations 6.00% Series A Perpetual Convertible Preferred Stock (the “Certificate”)) of $1,000 per share and is entitled to a dividend at a rate of 6% per annum on the Accreted Value payable in cash if, as and when declared by our board of directors. If a cash dividend is not declared and paid in respect of any dividend payment period, then the Accreted Value of each outstanding share of Preferred Stock will automatically be increased by the amount of the dividend otherwise payable for such dividend payment period. Any increase in the Accreted Value, among other things, increases the number of shares of common stock issuable upon conversion of each share of Preferred Stock. With respect to each of the quarterly periods from issuance until January 31, 2018, our board of directors elected to pay the dividend on the preferred stock by increasing the Accreted Value rather than paying cash. As such, as of January 31, 2018, the Accreted Value was $1,024 per share. The Preferred Stock also participates in dividends and distributions on our common stock on an as-converted basis. If at any time following December 30, 2019, the closing sale price of our common stock equals or exceeds 130% of the Conversion Price (as defined below) for at least 25 consecutive trading days, our obligation to pay dividends on the Preferred Stock shall terminate permanently.

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

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

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

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

Until conversion, the holders of the Preferred Stock vote together with our common stock on an as-converted basis and also have rights to vote as a separate class on certain customary matters impacting the Preferred Stock.

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

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

On October 31, 2017, an aggregate quarterly dividend of $6.558 million was paid by an automatic increase to the Accreted Value of each such share of Preferred Stock as of the date of issuance. The declared dividend was for the period beginning on August 1, 2017 to October 31, 2017 and was paid to holders of record on October 15, 2017.

On January 31, 2018, an aggregate quarterly dividend of $6.656 million was paid by an automatic increase to the Accreted Value of each such share of Preferred Stock as of the date of issuance. The declared dividend was for the period beginning on 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 beneficial conversion feature that was amortized over the earliest Preferred Stock conversion period as additional dividends. The table below summarizes the quarterly cash dividends paid to holders of record at the dates indicated of our preferred stock:

	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
October 15, 2018	August 1, 2018	October 31, 2018	$	6.756	October 31, 2018

Subsequent Event.On January 31, 2019, an aggregate quarterly cash dividend of $6.831 million was paid to holders of record as of January 15, 2019 for the period from November 1, 2018 to February 1, 2019.  In connection with the Merger and in accordance with the voting agreement with Carlyle, all the Company's preferred stock was converted into the Company's common stock prior to the effective time of the Merger.

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Equity

12 Months Ended

Dec. 31, 2018

Equity [Abstract]

Equity

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 shares issued since December 31, 2016:

Balance, December 31, 2016	91,680,441
Common stock issued	7,815,225
Restricted common shares issued	1,676,284
Restricted common shares forfeited	(717)
Repurchase of vested restricted shares (2)	(33,956)
Balance, December 31, 2017	101,137,277
Restricted common shares issued	1,076,165
Restricted common shares forfeited	(63,768)
Repurchase of vested restricted shares (2)	(355,819)
Balance, December 31, 2018	101,793,855

(1) We were incorporated in August 2016 under the laws of the State of Delaware.

(2) Restricted common shares are generally net-settled by 2016 LTIP participants to cover the required withholding tax upon vesting of restricted stock awards. Participants surrendered shares with value equivalent to the employee's minimum statutory obligation for the applicable income and other employment taxes. Total payments remitted for the employees' tax obligations to the appropriate taxing authorities were approximately $6.9 million and $0.6 million for the years ended December 31, 2018 and 2017, respectively. These net-settlements had the effect of shares repurchased by the Company as they reduced the number of shares that would have otherwise been outstanding as a result of the vesting and did not represent an expense to the Company.

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

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

See “Note 13—Long Term Incentive Plans” for additional information regarding the shares of restricted common stock that were granted during the years ended December 31, 2018 and 2017. Restricted shares of common stock are considered issued and outstanding on the grant date of the restricted stock award.

Dividend Policy

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

Predecessor Equity

The predecessor received capital contributions of $10.8 million from its members during the year ended December 31, 2016, respectively. Promissory note advances were available to management to fund future capital commitments and carried an interest rate of 2.5%.

The table below summarizes advances and payments of the promissory note advances for the year ended December 31, 2016 (in thousands):

	Principal		Interest		Total
Balance, December 31, 2015	$	2,367	$	76	$	2,443
Advances		101		—		101
Payments		(20)		—		(20)
Accrued Interest		—		51		51
Dissolution		(2,448)		(127)		(2,575)
Balance, December 31, 2016	$	—	$	—	$	—

On November, 9, 2016, the management members conveyed to the predecessor certain ownership interests in the predecessor in exchange for the discharge in full and the termination of all the promissory note advances then outstanding. The promissory note advances and the related accrued interest receivable are presented in the balance sheet as a deduction from predecessor equity.

Previous Owner Equity

The previous owner received capital contributions of $97.0 million from its members during the year ended December 31, 2016. As a result of the Corporate Reorganization (as discussed in Note 1) and common control accounting, Esquisto's net assets were recorded at NGP's historical cost basis.

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Earnings Per Share

12 Months Ended

Dec. 31, 2018

Earnings Per Share [Abstract]

Earnings Per Share

Note 12. Earnings Per Share

The following sets forth the calculation of earnings (loss) per share, or EPS, for the years ended December 31, 2018, 2017 and 2016 (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 Year Ended December 31,
	2018 (1)		2017 (2)		2016 (3)
Numerator:
Net income (loss) available to WRD	$	146,508	$	49,880	$	(10,397)
Less: Preferred stock dividends		28,862		13,146		—
Less: Undistributed earnings allocated to participating securities		30,344		5,612		—
Net income (loss) available to common stockholders	$	87,302	$	31,122	$	(10,397)
Denominator:
Weighted-average common shares outstanding (in thousands)		99,498		96,324		91,327
Basic EPS	$	0.88	$	0.32	$	(0.11)
Diluted EPS	$	0.88	$	0.32	$	(0.11)

(1) The Company used the two-class method for both basic and diluted EPS.  For the year ended December 31, 2018, 775 incremental restricted shares were excluded in the calculation of diluted EPS due to their antidilutive effect under the treasury stock method.  For the for the year ended December 31, 2018, 32,363 shares were excluded from the calculation of diluted EPS due to their antidilutive effect under the if-converted method.

(2) The Company used the two-class method for both basic and diluted EPS.  For the year ended December 31, 2017, 628 incremental restricted shares were excluded in the calculation of diluted EPS due to their antidilutive effect under the treasury stock method.  For the year ended December 31, 2017, 16,008 shares were excluded from the calculation of diluted EPS due to their antidilutive effect under the if-converted method.

(3) The Company used the two-class method for both basic and diluted EPS. For the year ended December 31, 2016, restricted shares were excluded from the calculation of diluted EPS due to their antidilutive effect as we were in a loss position for the period.

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Long Term Incentive Plans

12 Months Ended

Dec. 31, 2018

Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]

Long Term Incentive Plans

Note 13. Long Term Incentive Plans

In connection with the initial public offering, our Board 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 share awards granted under the 2016 LTIP for the periods presented:

		Weighted-Average
	Number of	Grant Date Fair
	Shares	Value per Share (1)
Restricted common shares outstanding at January 1, 2016	—	$	—
Granted (2)	353,334	$	14.50
Restricted common stock outstanding at December 31, 2016	353,334	$	14.50
Granted (2)	1,676,284	$	13.88
Forfeited	(717)	$	13.94
Vested	(131,111)	$	14.50
Restricted common stock outstanding at December 31, 2017	1,897,790	$	13.95
Granted (2)	1,076,165	$	25.57
Forfeited	(63,768)	$	16.45
Vested	(1,069,933)	$	15.66
Restricted common stock outstanding at December 31, 2018	1,840,254	$	19.66

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

(2) The aggregate grant date fair value of restricted common share awards granted in 2017 was $23.3 million based on grant date market price ranging from $10.91 to $14.22 per share. The aggregate grant date fair value of restricted common share awards granted in 2018 was $27.5 million based on grant date market price ranging from $18.14 to $27.07 per share. Our awards have contractual vesting periods between one and three years.

For the year ended December 31, 2018, 2017 and 2016, we recorded $19.5 million, $6.6 million and less than $0.1 million of recognized compensation expense associated, respectively, with these awards. Unrecognized compensation cost associated with the restricted common share awards was an aggregate of $28.7 million at December 31, 2018. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 2.0 years. We elect to account for forfeitures on share-based payments by recognizing forfeitures of awards as they occur.

Subsequent event. In January 2019, all outstanding shares granted under the 2016 LTIP were supervested.  On February 1, 2019, the shares were converted to common shares of Chesapeake using the conversion method elected by the shareholder as outlined in the merger agreement.

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Incentive Units

12 Months Ended

Dec. 31, 2018

Compensation Related Costs [Abstract]

Incentive Units

Note 14. Incentive Units

Prior to December 31, 2018, certain officers and employees were granted awards of incentive units in WildHorse Investment Holdings and WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings (the “LLCs”). 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 December 31, 2018. 

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).

Subsequent event. In connection with the Merger, all unvested incentive units became fully vested in accordance with their terms and will remain outstanding following the effective time of the merger. See “Note 1—Organization and Basis of Presentation” for information regarding our merger with Chesapeake.

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Related Party Transactions

12 Months Ended

Dec. 31, 2018

Related Party Transactions [Abstract]

Related Party Transactions

Note 15. Related Party Transactions

Corporate Reorganization

As described in Note 1, in connection with our initial public offering, we completed certain reorganization transactions pursuant to which we acquired all of the interests in WHR II, Esquisto and Acquisition Co. owned by WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings, respectively, in exchange for 21,200,084 shares, 38,755,330 shares and 2,563,266 shares, respectively, of our common stock.

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. We received $1.2 million and $2.2 million for the years ended December 31, 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 the year ended December 31, 2018, we had disbursements of $0.1 million to Archrock.

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 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 year ended December 31, 2017, we had disbursements of $0.2 million related to director and advisory fees and reimbursement of initial public offering costs. We did not have any related party payments or receipts for the year ended December 31, 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 year ended December 31, 2018 we had disbursements of $0.2 million to certain CH4 Energy entities for office rental and parking payments. During the year ended December 31, 2017 we had disbursements of $0.5 million to certain CH4 Energy entities, of which $0.3 million was a reimbursement of landman services and expenses incurred in 2016 that CH4 Energy entities had paid on our behalf and $0.2 million was related to office rental and parking payments.   Additionally, the Company acquired incremental leasehold interests from CH4 Energy entities for $0.1 million during the year ended December 31, 2017 in connection with the Corporate Reorganization.

Cretic Energy Services, LLC. During the year ended December 31, 2017, we had disbursements of $0.2 million to Cretic Energy Services, LLC, an NGP affiliated company, for services related to our drilling and completion activities. We did not have any related party payments for the year ended December 31, 2018.

Related Party Agreements

Registration Rights Agreement. We are parties to an amended and restated registration rights agreement with WildHorse Investment Holdings, Esquisto Investment Holdings, WildHorse Holdings, Esquisto Holdings, Acquisition Co. Holdings, NGP XI US Holdings, L.P. (“NGP XI”), Jay Graham and Anthony Bahr (collectively, the “Sponsor Group”), CP VI Eagle Holdings, L.P. (the “Carlyle Investor”), and EIGF Aggregator LLC, TE Admiral A Holding L.P. and Aurora C‑1 Holding L.P. (collectively, “KKR”). Pursuant to the amended and restated registration rights agreement, we have agreed to register the sale of shares of our common stock under certain circumstances.

Demand rights. Subject to the limitations set forth below, at any time after (i) for the Sponsor Group, the 180 day lock-up period, related to our initial public offering, or (ii) for the Carlyle Investor, June 30, 2018, and subject to the limitations set forth below, each member of the Sponsor Group and the Carlyle Investor (or its permitted transferees) have the right to require us by written notice to prepare and file a registration statement registering the offer and sale of a certain number of its shares of our common stock. Generally, we are required to provide notice of the request to certain other holders of our common stock who may, in certain circumstances, participate in the registration. Subject to certain exceptions, we will not be obligated to effect a demand registration within 90 days after the closing of any underwritten offering of shares of our common stock. Further, we are not obligated to effect more than a total of four demand registrations for each of WildHorse Holdings, Esquisto Holdings and WHE Holdings, and more than a total of six demand registrations for the Carlyle Investor.

Subject to certain exceptions, we are also not be obligated to effect any demand registration in which the anticipated aggregate offering price for our common stock included in such offering is less than $75 million. We have in effect a registration on Form S‑3, therefore, any such demand registration would be for a shelf registration statement. We will be required to use reasonable best efforts to maintain the effectiveness of any such registration statement until the earlier of (i) 180 days (or two years in the case of a shelf registration statement) after the effective date thereof or (ii) the date on which all shares covered by such registration statement have been sold (subject to certain extensions).

In addition, each member of the Sponsor Group (or its permitted transferees) have the right to require us, subject to certain limitations, to effect a distribution of any or all of its shares of our common stock by means of an underwritten offering. In general, any demand for an underwritten offering (other than the first requested underwritten offering made in respect of a prior demand registration and other than a requested underwritten offering made concurrently with a demand registration) shall constitute a demand request subject to the limitations set forth above.

Piggyback Rights. Subject to certain exceptions, if at any time we propose to register an offering of common stock or conduct an underwritten offering, whether or not for our own account, then we must notify each Holder (or its permitted transferees), NGP XI, Mr. Graham, Mr. Bahr, the Carlyle Investor and KKR of such proposal to allow them to include a specified number of their shares of our common stock in that registration statement or underwritten offering, as applicable. KKR was made a Holder under the amended and restated registration rights agreement for purposes of obtaining such piggyback rights; however, as of December 31, 2018, they no longer own any of our common stock.

Conditions and Limitations; Expenses. These registration rights are subject to certain conditions and limitations, including the right of the underwriters to limit the number of shares to be included in a registration and our right to delay or withdraw a registration statement under certain circumstances. We will generally pay all registration expenses in connection with our obligations under the registration rights agreement, regardless of whether a registration statement is filed or becomes effective.

Stockholders' Agreement. In connection with our initial public offering, we entered into a stockholders' agreement with WildHorse Holdings, Esquisto Holdings, and Acquisition Co. Holdings. Among other things, the stockholders' agreement provides the right to designate nominees to our board of directors as follows:

· so long as WildHorse Holdings, Esquisto Holdings, Acquisition Co. Holdings and their affiliates, including NGP XI, collectively own greater than 50% of our common stock, WildHorse Holdings and Esquisto Holdings can each nominate up to three nominees to our board of directors;

· so long as WildHorse Holdings, Esquisto Holdings, Acquisition Co. Holdings and their affiliates, including NGP XI, collectively own at least 35% of our common stock but less than 50% of our common stock, WildHorse Holdings and Esquisto Holdings can each nominate two nominees to our board of directors;

· so long as WildHorse Holdings, Esquisto Holdings, Acquisition Co. Holdings and their affiliates, including NGP XI, collectively own at least 15% of our common stock but less than 35% of our common stock, WildHorse Holdings and Esquisto Holdings can each nominate one nominee to our board of directors and can nominate a third nominee by agreement between them;

· so long as WildHorse Holdings, Esquisto Holdings, Acquisition Co. Holdings and their affiliates, including NGP XI, collectively own at least 5% of our common stock but less than 15% of our common stock, WildHorse Holdings and Esquisto Holdings can each nominate one nominee to our board of directors; and

· once WildHorse Holdings, Esquisto Holdings, Acquisition Co. Holdings and their affiliates, including NGP XI, collectively own less 5% of our common stock, WildHorse Holdings and Esquisto Holdings will not have any board designation rights.

Pursuant to the stockholders' agreement we are required to take all necessary actions, to the fullest extent permitted by applicable law (including with respect to any fiduciary duties under Delaware law), to cause the election of the nominees designated by WildHorse Holdings and Esquisto Holdings.

In addition, the stockholders' agreement provides that for so long as WildHorse Holdings, Esquisto Holdings, Acquisition Co. Holdings and their affiliates, including NGP XI, own at least 15% of the outstanding shares of our common stock, WildHorse Holdings and Esquisto Holdings will have the right to cause any committee of our board of directors to include in its membership at least one director designated by WildHorse Holdings or Esquisto Holdings, except to the extent that such membership would violate applicable securities laws or stock exchange rules. The rights granted to WildHorse Holdings and Esquisto Holdings to designate directors are additive to and not intended to limit in any way the rights that WildHorse Holdings, Esquisto Holdings, Acquisition Co. or any of their affiliates, including NGP XI, may have to nominate, elect or remove our directors under our certificate of incorporation, bylaws or the Delaware General Corporation Law.

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Segment Disclosures

12 Months Ended

Dec. 31, 2018

Segment Reporting [Abstract]

Segment Disclosures

Note 16. Segment Disclosures

Our chief executive officer has been identified as our chief operating decision maker (“CODM”).  As of December 31, 2018, we identified one operating segment and one reportable segment—the Eagle Ford—that is engaged in the acquisition, exploration, 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-"Acquisitions and Divestitures" 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.

Major Customers

The following table sets forth the percentage of our revenues attributed to our customers who have accounted for 10% or more of our revenues during 2018, 2017 or 2016.

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

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Income Taxes

12 Months Ended

Dec. 31, 2018

Income Tax Disclosure [Abstract]

Income Taxes

Note 17. Income Taxes

The components of income tax expense (benefit) are as follows (in thousands):

	For the Year Ended December 31,
	2018		2017		2016
Current income taxes:
Federal	$	(997)	$	997	$	—
State		—		10		—
Total current income tax expense (benefit)		(997)		1,007		—
Deferred income taxes:
Federal		43,143		(40,529)		(5,737)
State		(1,950)		698		162
Total deferred income tax expense (benefit)		41,193		(39,831)		(5,575)
Total income tax expense (benefit)	$	40,196	$	(38,824)	$	(5,575)

The actual income tax expense (benefit) differs from the expected amount computed by applying the federal statutory corporate tax rate of 21%,  35% and 35% for 2018, 2017 and 2016, respectively, as follows:

	For the Year Ended December 31,
	2018		2017		2016
Expected tax expense (benefit) at federal statutory rate	$	39,208	$	3,870	$	(18,428)
State income tax expense (benefit), net of federal benefit		(3,360)		460		105
Pass-through entities (1)		—		—		12,499
Incentive unit compensation		2,893		—		—
Stock-based compensation		(1,070)		—		—
Valuation allowance		1,820		—		234
Change in tax rate (2)		—		(43,431)		—
Change in prior period estimates		24		315		—
Other		681		(38)		15
Total income tax expense (benefit)	$	40,196	$	(38,824)	$	(5,575)

(1) Our predecessor was a pass-through entity for federal income tax purposes.

(2) The federal corporate income tax rate was reduced from 35% to 21% as a result of the Tax Act.

The components of net deferred income tax liabilities are as follows:

Components of net deferred income tax liabilities:	2018		2017
Deferred income tax assets:
Net operating loss Carryforwards	$	47,609	$	29,866
Disallowed interest carryforwards		9,992		—
Minimum tax credit Carryforward		—		997
Asset retirement obligation		1,796		3,311
Derivatives		—		16,903
Other		3,860		2,153
Total deferred income tax assets		63,257		53,230
Valuation allowance		(1,820)		—
Net deferred income tax assets		61,437		53,230
Deferred income tax liabilities:
Property, plant and equipment		158,868		124,700
Derivatives		15,300		—
Total deferred income tax liabilities		174,168		124,700
Net deferred income tax liabilities	$	112,731	$	71,470

Uncertain Income Tax Position.  The Company must recognize the tax effects of any uncertain tax positions it may have if the position taken by us is more likely than not sustainable based on its technical merits. For those benefits to be recognized, an income tax position must be more likely than not to be sustained upon examination by taxing authorities. The Company had no unrecognized tax benefits as of December 31, 2018 and expects no significant change to the unrecognized tax benefits over the next twelve months ending December 31, 2019.

Tax Audits and Settlements. Generally, the Company's income tax years 2015 through 2018 remain open and subject to examination by federal and various state tax authorities which include Louisiana and Texas and certain other state taxing jurisdictions where the Company previously had operations. In certain jurisdictions the Company operates through more than one legal entity, each of which may have different open years subject to examination.

Tax Attribute Carryforwards and Valuation Allowance.  As of December 31, 2018, the Company had federal net operating loss (NOL) carryforwards of approximately $218.0 million. The federal NOL carryforwards generated prior to 2018 expire in 2036 and 2037. The 2018 federal NOL carryforward of $65.9 million has no expiration. The Company also had state tax carryforwards of approximately $28.8 million, which expire in 2036 through 2038. In addition, the Company had disallowed business interest carryforward of approximately $47.6 million, which can be carried forward indefinitely. The Company recorded a valuation allowance of approximately $1.8 million against its deferred tax assets related to state tax attributes due to the NLA Divestiture.  The Company recorded no other valuation allowance based upon management's evaluation that it is more likely than not that the Company will realize its deferred tax assets.

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2018

Commitments And Contingencies Disclosure [Abstract]

Commitments and Contingencies

Note 18. Commitments and Contingencies

Litigation & Environmental

We are party to various ongoing and potential legal actions relating to our entitled ownership interests in certain properties. We evaluate the merits of existing and potential claims and accrue a liability for any that meet the recognition criteria and can be reasonably estimated. We did not recognize any liability as of December 31, 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.

On February 1, 2018, we settled a dispute related to a possible area of mutual interest (“AMI”) associated with our North Louisiana assets with a third party.  Pursuant to such settlement, the third party agreed to pay the actual net costs attributable to interests in certain leases and/or wells it elected to acquire.  We agreed to provide the third party with a $7.0 million credit towards purchasing the interests selected by the third party, which is reflected in the accompanying statements of operations for the year ended December 31, 2017 as “North Louisiana Settlement.”  The settlement loss was partially offset by a tax benefit of $1.6 million.  A settlement receivable of $5.9 million from the third party was collected by us during 2018.

In January 2019, putative class action lawsuits in U.S. District Courts for the District of Delaware and Southern District of New York were filed against us and other defendants. The lawsuits generally allege various violations of the Securities Exchange Act of 1934 in connection with the disclosure contained in the joint proxy statement/prospectus filed in connection with the Merger. The lawsuits seek rescission of the Merger or rescissory damages and, in each case, attorney's fees, costs and interest. We intend to vigorously defend these claims.

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 December 31, 2018 and at December 31, 2017.

Lease Obligations

We executed two office leases during the year ended December 31, 2018.  In June 2018, we executed a new lease for corporate office space that has escalating payments.  The commencement date was December 1, 2018 and the lease terminates on December 31, 2026.  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. Total office lease expense for the year ended December 31, 2018, 2017 and 2016 was $0.8 million, $1.0 million and $0.9 million.

In 2017, we entered into two dedicated fracturing fleet services agreements to complete wells in a timely manner following conclusion of drilling operations in the Eagle Ford Shale.

On March 15, 2017, we entered into a 20 month dedicated fracturing fleet services agreement. The agreement may be extended for an additional twelve months. We have agreed to pay a fixed monthly service fee of $2.7 million that covers equipment and personnel costs. In addition to the fixed monthly service charge, we have agreed to pay a fixed fee for each stage completed in excess of 360 stages per calendar quarter. We have also agreed to pay a pass through fee for the cost of chemicals and fuel plus 10%. We have the right to terminate the contract with appropriate notice; however, an early termination fee of approximately $1.4 million times the number of months remaining under the initial term of the contract would be payable on such termination date.  Our obligations under the contract ended in December 2018.

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

We have entered into drilling services agreements with varying terms, all of which have contractual terms of less than one year.

We have entered into compressor rental agreements, which have contractual terms of 13 months or less, after which they can be terminated with notice.  Total compressor and equipment rental expense incurred in 2018, 2017 and 2016 was $5.4 million, $2.0 million and $0.6 million, respectively.

The table below reflects our minimum commitments as of December 31, 2018:

	2019		2020		2021		2022		2023
Office Leases	$	2,399	$	2,435	$	2,398	$	2,216	$	2,251
Dedicated Fracturing Fleet Services Agreement		21,000		—		—		—		—
Sand Mine Equipment		5,055		3,436		—		—		—
Compressors		4,143		3,991		3,859		2,724		902
Total	$	32,597	$	9,862	$	6,257	$	4,940	$	3,153

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 years ended December 31, 2018 and 2017, respectively.

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Quarterly Financial Information (Unaudited)

12 Months Ended

Dec. 31, 2018

Quarterly Financial Information Disclosure [Abstract]

Quarterly Financial Information (Unaudited)

Note 19. Quarterly Financial Information (Unaudited)

The following tables present selected quarterly financial data for the periods indicated (in thousands except per share amounts). Earnings per share are computed independently for each of the quarters presented and the sum of the quarterly earnings per share may not necessarily equal the total for the year.

	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter (1)
For the Year Ended December 31, 2018
Revenues	$	218,757	$	225,413	$	259,490	$	243,726
Operating income (loss)		(100,053)		101,370		122,776	$	88,196
Net income (loss) available to WRD		(115,774)		(14,094)		11,523	$	264,853
Preferred stock dividends		7,389		7,961		6,756		6,756
Net income (loss) available to common stockholders		(123,163)		(22,055)		3,534		228,986
Basic earnings (loss) per share	$	(1.24)	$	(0.22)	$	0.04	$	1.92
Diluted earnings (loss) per share	$	(1.24)	$	(0.22)	$	0.04	$	1.92
For the Year Ended December 31, 2017
Revenues	$	54,292	$	70,173	$	122,486	$	180,236
Operating income		6,206		2,078		32,599	$	64,582
Net income (loss)		20,252		26,366		(10,804)	$	14,066
Preferred stock dividends		—		73		6,450		6,623
Net income (loss) available to common stockholders		20,252		25,906		(17,254)		2,218
Basic earnings (loss) per share	$	0.22	$	0.28	$	(0.17)	$	0.06
Diluted earnings (loss) per share	$	0.22	$	0.28	$	(0.17)	$	0.06

(1) Net income for the three months ended December 31, 2017 includes a deferred tax benefit of $43.4 million as a result of the re-measurement of our deferred tax assets and liabilities as a result of the Tax Act.

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Supplemental Oil and Gas Information

12 Months Ended

Dec. 31, 2018

Extractive Industries

Supplemental Oil and Gas Information

Note 20. Supplemental Oil and Gas Information (Unaudited)

Oil and Natural Gas Reserves

Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.

Proved reserves are those quantities of oil and natural gas that 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.

Our proved reserves are prepared CG&A, a third-party independent reserve. All proved reserves are located in the United States and all prices are held constant in accordance with SEC rules.

	For the Year Ended December 31,
	2018		2017		2016
Oil ($/Bbl)
West Texas Intermediate (1)	$	65.56	$	51.34	$	42.75
NGL ($/Bbl)
West Texas Intermediate (1)	$	65.56	$	51.34	$	42.75
Natural Gas ($/Mmbtu)
Henry Hub (2)	$	3.10	$	2.98	$	2.48

(1) The unweighted average West Texas Intermediate price was adjusted by lease for quality, transportation fees, and a regional price differential.

(2) The unweighted average Henry Hub price was adjusted by lease for energy content, compression charges, transportation fees, and regional price differentials.

The following tables set forth estimates of the net reserves as of December 31, 2018, 2017 and 2016, respectively:

	For the Year Ended December 31, 2018
	Oil (MBbls)	Gas (MMcf)	NGL (MBbls)	Equivalent (MBoe)
Proved developed and undeveloped reserves:
Beginning of the year	282,798	683,808	57,550	454,315
Extensions, discoveries and additions	81,174	129,962	16,377	119,211
Purchase of minerals in place	520	727	116	757
Sales of minerals in place	(1,272)	(393,057)	(398)	(67,180)
Production	(12,585)	(21,531)	(2,143)	(18,316)
Revision of previous estimates	(65,369)	(21,736)	(13,747)	(82,737)
End of year	285,266	378,173	57,755	406,050
Proved developed reserves:
Beginning of year	65,023	221,517	12,553	114,495
End of year	66,398	88,936	14,135	95,356
Proved undeveloped reserves:
Beginning of year	217,775	462,291	44,997	339,820
End of year	218,868	289,237	43,620	310,694

	For the Year Ended December 31, 2017
	Oil (MBbls)	Gas (MMcf)	NGL (MBbls)	Equivalent (MBoe)
Proved developed and undeveloped reserves:
Beginning of the year	87,447	325,102	10,874	152,505
Extensions, discoveries and additions	93,454	279,368	22,545	162,559
Purchase of minerals in place	59,169	28,106	6,740	70,593
Production	(6,606)	(20,463)	(1,206)	(11,222)
Revision of previous estimates	49,334	71,695	18,597	79,880
End of year	282,798	683,808	57,550	454,315
Proved developed reserves:
Beginning of year	19,192	145,880	3,765	47,270
End of year	65,023	221,517	12,553	114,495
Proved undeveloped reserves:
Beginning of year	68,255	179,222	7,109	105,235
End of year	217,775	462,291	44,997	339,820

	For the Year Ended December 31, 2016
	Oil (MBbls)	Gas (MMcf)	NGL (MBbls)	Equivalent (MBoe)
Proved developed and undeveloped reserves:
Beginning of the year	36,650	344,959	8,897	103,040
Extensions, discoveries and additions	18,870	32,782	2,606	26,940
Purchase of minerals in place	26,835	13,545	1,823	30,916
Production	(1,848)	(17,820)	(471)	(5,289)
Revision of previous estimates	6,940	(48,364)	(1,981)	(3,102)
End of year	87,447	325,102	10,874	152,505
Proved developed reserves:
Beginning of year	7,503	142,990	2,235	33,570
End of year	19,192	145,880	3,765	47,270
Proved undeveloped reserves:
Beginning of year	29,147	201,969	6,662	69,470
End of year	68,255	179,222	7,109	105,235

Noteworthy amounts included in the categories of proved reserve changes in the above tables include:

· During 2018, extensions, discoveries and additions increased proved reserves by 119,211 MBoe. These increases were partially offset by sales of minerals in place related to the North Louisiana Divestiture, which reduced proved reserves by 67,180 Mboe and production reducing proved reserves by 18,316 MBoe. We also had downward revisions of 82,737 Mboe, of which 86,953 MBoe were performance related partially offset by 4,216 MBoe related to commodity price increases.

· During 2017, extensions, discoveries and additions increased proved reserves by 20,313 MBoe and 142,246 MBoe related to North Louisiana and Eagle Ford Shale, respectively.

· During 2017, purchases of minerals in place of 70,593 MBoe was attributable to the Acquisition.

· During 2017, we had upward revisions of 79,880 MBoe, of which 7,461 MBoe related to commodity price changes and 72,419 MBoe was performance related.

· During 2016, extensions, discoveries and additions increased proved reserves by 4,131 MBoe and 22,809 MBoe related to drilling in the RCT field in North Louisiana and Eagle Ford Shale, respectively.

· During 2016, purchase of minerals in place of 30,916 MBoe was primarily attributable to the Burleson North Acquisition.

· During 2016, we had downward revisions of proved reserves of 3,102 MBoe, of which 711 MBoe related to commodity price changes and 2,391 MBoe was performance related.

See Note 3-"Acquisitions and Divestitures" for additional information on acquisitions and divestitures.

A variety of methodologies are used to determine our proved reserve estimates. The principal methodologies employed are reservoir simulation, decline curve analysis, volumetric, material balance, advance production type curve matching, petro-physics/log analysis and analogy. Some combination of these methods is used to determine reserve estimates in substantially all of our fields.

Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves

As required by the FASB and SEC, the standardized measure of discounted future net cash flows presented below is computed by applying first-day-of-the-month average prices, year-end costs and legislated tax rates and a discount factor of 10 percent to proved reserves. We do not believe the standardized measure provides a reliable estimate of the Company's expected future cash flows to be obtained from the development and production of its oil and gas properties or of the value of its proved oil and gas reserves. The standardized measure is prepared on the basis of certain prescribed assumptions including first-day-of-the-month average prices, which represent discrete points in time and therefore may cause significant variability in cash flows from year to year as prices change.

The standardized measure of discounted future net cash flows is as follows (in thousands):

	For the Year Ended December 31,
	2018		2017		2016
Future cash inflows	$	21,269,502	$	16,967,369	$	4,434,117
Future production costs		(3,440,203)		(3,305,941)		(1,220,067)
Future development costs		(5,168,271)		(4,008,916)		(1,146,632)
Future income tax expense		(2,398,612)		(1,814,510)		(442,285)
Future net cash flows for estimated timing of cash flows		10,262,416		7,838,002		1,625,133
10% annual discount for estimated timing of cash flows		(6,144,980)		(4,994,097)		(1,082,092)
Standardized measure of discounted future net cash flows	$	4,117,436	$	2,843,905	$	543,041

Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves

The following is a summary of the changes in the standardized measure of discounted future net cash flows for the proved oil and natural gas reserves during each of the years in the three-year period ended December 31, 2018 (in thousands):

	For the Year Ended December 31,
	2018		2017		2016
Beginning of year	$	2,843,905	$	543,041	$	451,930
Sale of oil and natural gas produced, net of production costs		(822,471)		(351,031)		(104,596)
Purchase of minerals in place		4,313		507,095		188,317
Sales of minerals in place		(319,858)		—		—
Extensions and discoveries		1,829,564		1,595,385		168,796
Changes in income taxes, net		(277,050)		(488,484)		(206,817)
Changes in prices and costs		1,380,323		398,713		(57,034)
Previously estimated development costs incurred		67,575		49,977		15,067
Net changes in future development costs		(13,317)		(87,375)		11,985
Revisions of previous quantities		(1,057,523)		653,567		3,943
Accretion of discount		323,927		74,999		103,000
Change in production rates and other		158,048		(51,982)		(31,550)
End of year	$	4,117,436	$	2,843,905	$	543,041

Capitalized Costs Relating to Oil and Natural Gas Producing Activities

The total amount of capitalized costs relating to oil and natural gas producing activities and the total amount of related accumulated depreciation, depletion and amortization is as follows at the dates indicated (in thousands).

	For the Year Ended December 31,
	2018		2017		2016
Evaluated oil and natural gas properties	$	2,764,875	$	2,265,525	$	1,144,857
Unevaluated oil and natural gas properties		693,023		734,203		428,991
Accumulated depletion, depreciation and amortization		(498,811)		(362,406)		(196,567)
Total	$	2,959,087	$	2,637,322	$	1,377,281

Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities

Costs incurred in property acquisition, exploration and development activities were as follows for the periods indicated:

	For the Year Ended December 31,
	2018		2017		2016
Property acquisition costs, proved	$	4,422	$	269,429	$	230,910
Property acquisition costs, unproved		85,863		386,515		235,652
Exploration and extension well costs		11,979		16,076		72,875
Development		927,985		795,273		63,006
Total	$	1,030,249	$	1,467,293	$	602,443

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Subsequent Events

12 Months Ended

Dec. 31, 2018

Subsequent Events [Abstract]

Subsequent Events

Note 21. Subsequent Events

Quarterly Preferred Stock Dividend

Merger with Chesapeake

In February 2019, we were acquired by Chesapeake for approximately 717.3 million shares of Chesapeake common stock and $381.1 million in cash. Immediately following the completion of the acquisition, WildHorse Development merged with and into Brazos Valley Longhorn, L.L.C., a newly formed Delaware limited liability company and wholly owned subsidiary of Chesapeake. Following the completion of the Merger on February 1, 2019, Brazos Valley Longhorn, L.L.C., as successor to WildHorse Development, was a wholly owned subsidiary of Chesapeake.

On February 1, 2019, we paid our financial advisors $23.1 million of advisory fees, which were contingent upon the closing of the merger with Chesapeake.  The contingent fee was not deemed probable at December 31, 2018.

On February 1, 2019, Brazos Valley Longhorn, L.L.C., as successor by merger to WildHorse, entered into a sixth amendment (the "Sixth Amendment") to its Credit Agreement. Among other things, the Sixth Amendment (i) amended the merger covenant and the definition of change of control to permit the WildHorse Merger and (ii) permits borrowings under the Credit Agreement to be used to redeem or repurchase the 2025 Senior Notes so long as certain conditions are met.

On February 1, 2019, Brazos Valley Longhorn, L.L.C., as successor by merger to WildHorse, and Brazos Valley Longhorn Finance Corp., a Delaware corporation ("BVL Finance Corp.") and wholly owned subsidiary of the Company, entered into a fourth supplemental indenture (the "Fourth Supplemental Indenture") to the 2025 Indenture. Pursuant to the Fourth Supplemental Indenture, (i) the Brazos Valley Longhorn, L.L.C. assumed the rights and obligations of WildHorse as issuer under the 2025 Indenture and (ii) BVL Finance Corp. was named as a co-issuer of the 2025 Senior Notes under the 2025 Indenture.

If the 2025 Senior Notes are downgraded within 90 days after the consummation of the WildHorse Merger (which constitutes a "Change of Control" under the 2025 Indenture), the 2025 Indenture requires the Company (or a third party, in certain circumstances) to make an offer to repurchase the 2025 Senior Notes at 101% of their principal amount, plus accrued and unpaid interest, within 30 days of such downgrade. If any holder of 2025 Senior Notes accepts such offer, the Company may (subject to the terms and conditions thereof) fund the purchase price with loans under the Credit Agreement, use cash on hand, issue debt securities or use other sources of liquidity to fund such repurchase.

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2018

Accounting Policies [Abstract]

Initial Public Offering and Corporate Reorganization

Initial Public Offering and Corporate Reorganization

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

The Company was formed in August 2016 to serve as a holding company for the assets of WHR II and Esquisto. We did not have any operations until we completed our initial public offering on December 19, 2016. In connection with our initial public offering and Corporate Reorganization (defined below), our accounting predecessor, WHR II was contributed to us. In addition to WHR II, we received Esquisto and Acquisition Co. We are an independent oil and natural gas company focused on the acquisition, exploration, development and production of oil, natural gas and NGL resources.

WHR II, Esquisto II, Acquisition Co., WHR Eagle Ford LLC (“WHR EF”), Burleson Sand LLC (“Burleson Sand”) and WHCC Infrastructure LLC (“WHCC”) are wholly owned subsidiaries of the Company as of December 31, 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.

The Company issued and sold to the public in its initial public offering 27,500,000 shares of common stock. The gross proceeds from the sale of the common stock were $412.5 million, net of underwriting discounts of $14.1 million and other offering costs of $5.0 million. The net proceeds from our initial public offering were $393.4 million. Debt issuance costs of $2.9 million related to the establishment of the Company's revolving credit facility were also incurred in conjunction with our initial public offering.

Contemporaneously with our initial public offering, (i) the owners of WHR II exchanged all of their interests in WHR II for equivalent interests in WildHorse Investment Holdings and the owners of Esquisto exchanged all of their interests in Esquisto for equivalent interests in Esquisto Investment Holdings, (ii) WildHorse Investment Holdings contributed all of the interests in WHR II to WildHorse Holdings, Esquisto Investment Holdings contributed all of the interests in Esquisto to Esquisto Holdings and the owner of Acquisition Co. contributed all of its interests in Acquisition Co. to Acquisition Co. Holdings and (iii) WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings contributed all of the interests in WHR II, Esquisto and Acquisition Co., respectively, to us in exchange for shares of our common stock. We refer to these reorganization transactions as the “Corporate Reorganization.” As a result of the Corporate Reorganization, WHR II, Esquisto and Acquisition Co. became direct, wholly owned subsidiaries of WildHorse Resource Development Corporation.

Basis of Presentation

Basis of Presentation

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

Our consolidated and combined 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 consolidated and combined statements of cash flows. Restricted cash is now being included in cash and cash equivalents when reconciling the beginning of period and end of period totals due to the adoption of a new accounting standard.

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

Use of Estimates in the Preparation of Financial Statements

Use of Estimates in the Preparation of Financial Statements

Preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about carrying values of assets and liabilities that are not readily apparent from other sources. We evaluate the estimates and assumptions on a regular basis; however, actual results may differ from these estimates and assumptions used in the preparation of the financial statements. Significant estimates with regard to these financial statements include (1) the estimate of proved oil, natural gas and NGL reserves and related present value estimates of future net cash flows therefrom; (2) depreciation, depletion and amortization expense; (3) valuation of accounts receivable; (4) accrued capital expenditures and liabilities; (5) asset retirement obligations; (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.

Cash and Cash Equivalents

Cash and Cash Equivalents

We consider all highly liquid investment instruments purchased with original maturities of three months or less to be cash equivalents for purposes of the Consolidated and Combined Statements of Cash Flows and other statements. These investments are carried at cost, which approximates fair value. In case a book overdraft exists at the end of a period, we reclassify the negative cash amount to accounts payable.

Restricted Cash

Restricted Cash

Historically, restricted cash consisted of certificates of deposit in place to collateralize letters of credit. The letters of credit were required as part of normal business operations. The certificates of deposit were in place for a period greater than 12 months and were considered noncurrent. We had no restricted cash at December 31, 2018 and 2017.

Oil and Gas Properties

Oil and Gas Properties

We use the successful efforts method of accounting for crude oil and natural gas producing activities. Costs to acquire mineral interests in natural gas and crude oil properties are capitalized. Significant costs associated with development wells in progress or awaiting completion are excluded from depletion until the well is completed.  We have excluded capitalized costs of $98.1 million at December 31, 2018. Costs to drill exploratory wells that do not find proved reserves, delay rentals and geological and geophysical costs are expensed.

The following table reflects the net changes in capitalized exploratory well costs for the periods indicated (in thousands):

	For Year Ended December 31,
	2018		2017		2016
Balance, beginning of period	$	—	$	7,064	$	15,198
Additions to capitalized exploratory well costs pending the determination of proved reserves		—		—		60,847
Reclassifications to wells, facilities and equipment based on the determination of proved reserves		—		(7,064)		(68,981)
Capitalized exploratory well costs charged to expense		—		—		—
Balance, end of period	$	—	$	—	$	7,064

We acquire leases on acreage not associated with proved reserves or held by production with the expectation of ultimately assigning proved reserves and holding the leases with production. The costs of acquiring these leases, including primarily brokerage costs and amounts paid to lessors, are capitalized and excluded from current amortization pending evaluation. When proved reserves are assigned, the leasehold costs associated with those leases are depleted as producing oil and gas properties. Costs associated with leases not held by production are impaired when events and circumstances indicate that carrying value of the properties is not recoverable. We recorded impairment of $10.5 million, $20.8 million and $3.1 million as exploration expense for unproved oil and gas properties for the years ended December 31, 2018, 2017 and 2016, respectively.

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

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

Oil and Gas Reserves

Oil and Gas Reserves

The estimates of proved crude oil, natural gas, and natural gas liquids reserves utilized in the preparation of the financial statements are estimated in accordance with guidelines established by the Securities and Exchange Commission (“SEC”) and the Financial Accounting Standards Board (“FASB”), which require that reserve estimates be prepared under existing economic and operating conditions using a 12‑month average price with no provision for price and cost escalations in future years except by contractual arrangements. Our proved reserves are prepared by Cawley, Gillespie & Associates, Inc. ("CG&A"), a third-party independent reserve engineer.

We emphasize that reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. It is possible that, because of changes in market conditions or the inherent imprecision of these reserve estimates, the estimates of future cash inflows, future gross revenues, the amount of natural gas, crude oil and natural gas liquids reserves, the remaining estimated lives of the natural gas and crude oil properties, or any combination of the above may be increased or reduced. See Note 20—“Supplemental Oil and Gas Information (Unaudited)” for further information.

Other Property and Equipment

Other Property and Equipment

Other property and equipment includes our sand mine, saltwater disposal wells, Burleson water assets, leasehold improvements, office furniture, automobiles, computer equipment, software, pipelines, office buildings and land. Other property and equipment is depreciated using a straight-line method over the expected useful lives of the respective assets. Leasehold improvements are amortized over the remaining term of the lease and land is not depreciated or amortized.

Capitalized Interest

Capitalized Interest

We capitalize interest costs to oil and gas properties on expenditures made in connection with certain projects such as drilling and completion of new oil and natural gas wells and major facility installations. Interest is capitalized only for the period that such activities are in progress. Interest is capitalized using a weighted average interest rate based on our outstanding borrowings. For the year ended December 31, 2018, 2017 and 2016, we recorded $5.9 million, $3.1 million and $0.1 million in capitalized interest, respectively.

Properties Acquired in Business Combinations

Properties Acquired in Asset Acquisitions and Business Combinations

For asset acquisitions, the purchase price recorded at cost and is allocated to identifiable assets on a relative fair value basis.  Therefore, we would need to determine the fair value of the assets at acquisition.

Assets and liabilities acquired in a business combination are required to be recorded at fair value. If sufficient market data is not available, we determine the fair values of proved and unproved properties acquired in transactions accounted for as business combinations by preparing our own estimates of crude oil and natural gas reserves. To compensate for the inherent risk of estimating and valuing unproved reserves, discounted future net cash flows of probable and possible reserves are reduced by additional risk-weighting factors. See Note 3—“Acquisitions and Divestitures.”

Asset Retirement Obligations

Asset Retirement Obligations

We recognize a liability equal to the fair value of the estimated cost to plug and abandon our natural gas and crude oil wells and associated equipment. The liability and the associated increase in the related long-lived asset are recorded in the period in which the related assets are placed in service or acquired. The liability is accreted to its expected future cost each period and the capitalized cost is depleted using the units-of-production method of the related asset. The accretion expense is included in depreciation, depletion and amortization expense.

The fair value of the estimated cost is based on historical experience, managements' expertise and third-party proposals for plugging and abandoning wells. The estimated remaining lives of the wells is based on reserve life estimates and federal and state regulatory requirements. At the time the related long-lived asset is placed in service, the estimated cost is adjusted for inflation based on the remaining life, then discounted using a credit-adjusted risk-free rate to determine the fair value.

Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs, including non-operated plug and abandonment expense, changes in the remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements. At the time of abandonment, we recognize a gain or loss on abandonment to the extent that actual costs do not equal the estimated costs

Environmental Costs

Environmental Costs

As an owner or lessee and operator of oil and gas properties, we are subject to various federal, state and local laws and regulations relating to discharge of materials into, and protection of, the environment. Environmental expenditures that relate to an existing condition caused by past operations and that do not have future economic benefit are expensed. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable and the costs can be reasonably estimated.

Revenue Recognition and Oil and Gas Imbalances

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.

Natural 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, the Company 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 the Company 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).  Our performance obligation under these contracts is to sell the extracted NGLs and residue gas.  We recognize revenue at a point in time (at the plant tailgate) when we have fulfilled our performance obligation.  Prior to the adoption of the new revenue standard, we did not recognize the volumes retained by our customer as an expense and we reported revenues net of the volumes they retained.

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.

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 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.

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 December 31, 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 -"Acquisitions and Divestitures"), 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.

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 Year Ended December 31, 2018
	As Reported		Without ASC 606		Increase/-
	Under ASC 606		Adoption		Decrease
Revenues:
Oil sales	$	843,244	$	843,329	$	(85)
Natural gas sales		60,129		64,896		(4,767)
NGL sales		41,961		51,052		(9,091)
Other Income		2,052		1,861		191
Operating expenses:
Lease operating expenses		61,620		63,043		(1,423)
Gathering, processing and transportation		9,856		22,703		(12,847)
Depreciation, depletion and amortization		296,685		297,295		(610)
Other operating expense		1,064		459		605
Income before income taxes		186,704		186,180		524
Income tax expense		(40,196)		(40,083)		(113)
Net income		146,508		146,097		411

	At December 31, 2018
	As Reported		Without ASC 606		Increase/-
	Under ASC 606		Adoption		Decrease
Assets:
Oil and gas properties	$	3,457,897	$	3,463,857	$	(5,960)
Accumulated depreciation, depletion and amortization		(518,054)		(519,035)		981
Other non-current assets		17,250		11,439		5,811
Liabilities:
Deferred tax liabilities		112,731		112,551		180
Stockholders' Equity
Accumulated earnings		136,773		137,785		(1,012)

	For the Year Ended December 31, 2018
	As Reported		Without ASC 606		Increase/-
	Under ASC 606		Adoption		Decrease
Cash flows from operating activities:
Net income	$	146,508	$	146,097	$	411
Depreciation, depletion and amortization		296,685		297,295		(610)
Deferred income tax expense		41,193		41,080		113
Consideration paid to customers, net of amortization		(1,817)		—		(1,817)
Cash flows from investing activities:
Additions to oil and gas properties		(1,051,891)		(1,053,811)		1,920

Incentive Units

Incentive Units

For details regarding incentive units, please see “Note 14. Incentive Units.”

Accounts Receivable

Accounts Receivable

We grant credit to creditworthy independent and major natural gas and crude oil marketing companies for the sale of crude oil, natural gas and natural gas liquids. In addition, we grant credit to our oil and gas working interest partners. Receivables from our working interest partners are generally secured by the underlying ownership interests in the properties.

Accounts receivable balances primarily relate to joint interest billings and oil and gas sales, net of our interest. The accounts receivable balance generally includes one month of accrued revenues for operated oil properties, two months of accrued revenues for operated natural gas properties and three months of accrued revenues for non-operated properties net of any collections related to those periods. The accounts receivable balance also includes other miscellaneous balances.

Accounts receivable are recorded at the amount we expect to collect. We use the specific identification method of providing allowances for doubtful accounts. We recorded a provision for uncollectible accounts of $0.2 million and $0.1 million at December 31, 2018 and 2017, respectively.

Derivative Instruments

Derivative Instruments

We periodically enter into derivative contracts to manage our exposure to commodity price risk. These derivative contracts, which are placed with major financial institutions that we believe have minimal credit risks, take the form of variable to fixed price commodity swaps, basis swaps, collars and deferred purchased puts. The natural gas reference price, upon which the commodity derivative contracts are based, reflects market indices that have a high degree of historical correlation with actual prices received for natural gas sales.

All derivative instruments are recorded on the balance sheet as either an asset or liability measured at fair value. Derivative instruments are netted when the right to net exists under a master netting agreement, future liabilities and assets correspond to the same commodity type and future cash flows have the same balance sheet current or non-current classification. Changes in fair value are recognized currently in earnings. Realized and unrealized gains and losses from our oil, gas and natural gas liquids derivatives are recorded as a component of “Other income (expense)” on our Statements of Consolidated and Combined Operations. We compute the fair value of the unrealized gains and losses of our derivative instruments using forward prices and dealer quotes provided by a third party.

For our forward commodity contracts that meet the definition of a derivative, we have elected the normal purchases and normal sales scope exclusion, because we believe it is probable that physical delivery of the product will occur under the contract and we do not intend on net settling the contract. Therefore, all activity under these contracts was recorded as revenue in our consolidated financial statements.

See Note 5—“Risk Management and Derivative and Other Financial Instruments” for additional information regarding our derivative instruments.

Corporate Lease Expenses

Corporate Lease Expenses

We record escalating lease expenses for our corporate office over the life of the lease on a straight-line basis.

Debt Issuance Costs

Debt Issuance Costs

Debt issuance costs associated with line-of-credit arrangements, including arrangements with no outstanding borrowings, are classified as an asset, and amortized over the term of the arrangements. Debt issuance costs related to term loans and senior notes are presented as a direct deduction from the carrying amount of the associated debt liability and amortized over the term of the associated debt using the effective yield method.

Fair Value Measurements

Fair Value Measurements

Accounting guidance for fair value measurements establishes a fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three levels. The fair value hierarchy gives the highest priority to quoted market prices (unadjusted) in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Level 2 inputs are inputs, other than quoted prices included within Level 1, which are observable for the asset or liability, either directly or indirectly. We use Level 1 inputs when available as Level 1 inputs generally provide the most reliable evidence of fair value. See Note 4—“Fair Value Measurements of Financial Instruments.”

Income Taxes

Income Taxes

We are a corporation subject to federal and certain state income taxes. Prior to our initial public offering, we were primarily organized as pass-through entities for federal income tax purposes and were not subject to federal income taxes.

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 carry forwards. 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 and Combined 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.

Commitments and Contingencies

Commitments and Contingencies

Accruals for loss contingencies arising from claims, assessments, litigation, environmental and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. These accruals are adjusted as additional information becomes available or circumstances change.

Supplemental Cash Flow Information

Supplemental Cash Flow Information

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

	For Year Ended December 31,
	2018		2017		2016
Supplemental cash flows:
Cash paid for interest, net of capitalized interest	$	48,717	$	12,246	$	7,152
Noncash investing activities:
Increase (decrease) in capital expenditures in accounts payables and accrued liabilities		(82,358)		134,589		(4,492)
(Increase) decrease in accounts receivable related to capital expenditures and acquisitions		(1,247)		(847)		(5,175)

Due to Hurricane Harvey, the Internal Revenue Service (“IRS”) granted relief to affected taxpayers by allowing taxpayers to defer the deadline for tax return filings and payment of estimated taxes to January 31, 2018. The Company paid $2.3 million related to its 2017 estimated alternative minimum tax to the IRS on January 31, 2018.

New Accounting Standards

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. The Company adopted this guidance on January 1, 2018 on a prospective basis 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 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, which requires classification of leases as finance or operating. The classification is 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. The new standard is effective for financial statements issued for annual periods beginning after December 15, 2018 and interim periods within those fiscal years. 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 adopted the standard using the effective date method on January 1, 2019.

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 old 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 has made this accounting policy election beginning January 1, 2019.

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 has made this accounting policy election for all classes of assets beginning January 1, 2019.

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 has made this accounting policy election beginning January 1, 2019.

The Company is a lessee under various agreements for office space, compressors and other equipment.  Though we are finalizing the implementation of certain processes to monitor and track all lease information, we anticipate leases as recognized under the new standard will create right-of-use assets and initial lease liabilities between $35 million and $65 million on our consolidated balance sheet.

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

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Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2018

Impact of adoption of revenue standard

Schedule of Net Changes Capitalized Exploratory Costs

The following table reflects the net changes in capitalized exploratory well costs for the periods indicated (in thousands):

	For Year Ended December 31,
	2018		2017		2016
Balance, beginning of period	$	—	$	7,064	$	15,198
Additions to capitalized exploratory well costs pending the determination of proved reserves		—		—		60,847
Reclassifications to wells, facilities and equipment based on the determination of proved reserves		—		(7,064)		(68,981)
Capitalized exploratory well costs charged to expense		—		—		—
Balance, end of period	$	—	$	—	$	7,064

Schedule of Supplemental Cash Flow Information

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

	For Year Ended December 31,
	2018		2017		2016
Supplemental cash flows:
Cash paid for interest, net of capitalized interest	$	48,717	$	12,246	$	7,152
Noncash investing activities:
Increase (decrease) in capital expenditures in accounts payables and accrued liabilities		(82,358)		134,589		(4,492)
(Increase) decrease in accounts receivable related to capital expenditures and acquisitions		(1,247)		(847)		(5,175)

Accounting Standards Update 2014-09

Impact of adoption of revenue standard

Summary of Impact of Adoption of Accounting Standards

XBRL-Only Content Section

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

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 Year Ended December 31, 2018
	As Reported		Without ASC 606		Increase/-
	Under ASC 606		Adoption		Decrease
Revenues:
Oil sales	$	843,244	$	843,329	$	(85)
Natural gas sales		60,129		64,896		(4,767)
NGL sales		41,961		51,052		(9,091)
Other Income		2,052		1,861		191
Operating expenses:
Lease operating expenses		61,620		63,043		(1,423)
Gathering, processing and transportation		9,856		22,703		(12,847)
Depreciation, depletion and amortization		296,685		297,295		(610)
Other operating expense		1,064		459		605
Income before income taxes		186,704		186,180		524
Income tax expense		(40,196)		(40,083)		(113)
Net income		146,508		146,097		411

	At December 31, 2018
	As Reported		Without ASC 606		Increase/-
	Under ASC 606		Adoption		Decrease
Assets:
Oil and gas properties	$	3,457,897	$	3,463,857	$	(5,960)
Accumulated depreciation, depletion and amortization		(518,054)		(519,035)		981
Other non-current assets		17,250		11,439		5,811
Liabilities:
Deferred tax liabilities		112,731		112,551		180
Stockholders' Equity
Accumulated earnings		136,773		137,785		(1,012)

	For the Year Ended December 31, 2018
	As Reported		Without ASC 606		Increase/-
	Under ASC 606		Adoption		Decrease
Cash flows from operating activities:
Net income	$	146,508	$	146,097	$	411
Depreciation, depletion and amortization		296,685		297,295		(610)
Deferred income tax expense		41,193		41,080		113
Consideration paid to customers, net of amortization		(1,817)		—		(1,817)
Cash flows from investing activities:
Additions to oil and gas properties		(1,051,891)		(1,053,811)		1,920

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Acquisitions and Divestitures (Tables)

12 Months Ended

Dec. 31, 2018

Schedule of Acquisition-Related Costs Included in General and Administrative Expenses

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

For the Year Ended December 31,
	2018	2017		2016
$	1,117	$	4,348	$	553

APC/KKR Acquisitions

Summary of Fair Value of Assets Acquired and Liabilities Assumed

The following table summarizes the fair value assessment of the assets acquired and liabilities assumed as of the closing 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

Summary of Unaudited Pro Forma Financial Information

	For the Year Ended December 31,
	2017		2016
Revenues	$	475,396	$	226,502
Net income (loss)	$	71,287	$	(11,290)
Earnings per share (basic and diluted)	$	0.51	$	(0.10)

Burleson North Acquisition

Summary of Fair Value of Assets Acquired and Liabilities Assumed

The following table summarizes the fair value assessment of the assets acquired and liabilities assumed as of the acquisition date after customary post-closing adjustments (in thousands):

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

Summary of Unaudited Pro Forma Financial Information

	For Year Ended December 31,
	2016
Revenues	$	176,082
Net loss	$	(34,894)
Basic and diluted earnings per unit		n/a

November and Rosewood Acquisitions

Summary of Fair Value of Assets Acquired and Liabilities Assumed

The following table summarizes the fair value assessment of the assets acquired and liabilities assumed as of the acquisition date for the November Acquisition and Rosewood Acquisition (in thousands):

		Rosewood Acquisition		November Acquisition
Oil and gas properties	$	19,626	$	29,973

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Fair Value Measurements of Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2018

Fair Value Disclosures [Abstract]

Assets and Liabilities Measured at Fair Value on Recurring Basis

	Fair Value Measurements at December 31, 2018
	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	$	—	$	72,710	$	—	$	72,710
Liabilities:
Commodity derivatives	$	—	$	508	$	—	$	508

	Fair Value Measurements at December 31, 2017
	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

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Risk Management and Derivative and Other Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2018

Derivative Instruments And Hedging Activities Disclosure

Schedule of Derivative Contracts

The following derivative contracts were in place at December 31, 2018:

	2019		2020
Crude Oil Derivative Contracts:
Fixed price swap contracts:
Volume (Bbls)		6,652,369		4,511,681
Weighted-average fixed price	$	54.45	$	53.49
Put options:
Volume (Bbls)		1,749,757		—
Weighted-average floor price	$	53.83	$	—
Weighted-average put premium	$	(5.43)	$	—
Natural Gas Derivative Contracts:
Fixed price swap contracts:
Volume (MMBtu)		6,425,146		4,846,020
Weighted-average fixed price	$	2.79	$	2.76

Summary of Gross Fair Value and Net Recorded Fair Value of Derivative Instruments by Appropriate Balance Sheet Classification

		Asset Derivatives				Liability Derivatives
		(in thousands)				(in thousands)
Type	Balance Sheet Location	2018		2017		2018		2017
Commodity contracts	Short-term derivative instruments	$	54,131	$	2,336	$	508	$	58,074
Netting arrangements	Short-term derivative instruments		—		—		—		—
Net recorded fair value		$	54,131	$	2,336	$	508	$	58,074
Commodity contacts	Long-term derivative instruments	$	18,579	$	86	$	—	$	18,676
Netting arrangements	Long-term derivative instruments		—		—		—		—
Net recorded fair value		$	18,579	$	86	$	—	$	18,676

Schedule of Gains and Losses Related to Derivative Instruments

The following table details the gains and losses related to derivative instruments for the years ending December 31, 2018, 2017 and 2016 (in thousands):

	Statements of	For the Year Ended December 31,
	Operations Location	2018		2017		2016
Commodity derivative contracts	Gain (loss) on derivative instruments	$	35,393	$	(55,483)	$	(26,771)

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Accounts Receivable (Tables)

12 Months Ended

Dec. 31, 2018

Receivables [Abstract]

Schedule of Accounts Receivable

Accounts receivable consist of the following (in thousands):

	At December 31,
	2018		2017
Oil, gas and NGL sales	$	70,900	$	67,584
Joint interest billings		17,491		9,467
Severance tax		1,352		171
Derivative receivable		308		—
North Louisiana Settlement receivable		—		5,955
Environmental remediation		1,511		—
Other current receivables		196		1,026
Allowance for doubtful accounts		(200)		(100)
Total	$	91,558	$	84,103

Schedule of Allowance for Doubtful Accounts Activity

The following table presents our allowance for doubtful accounts activity for the periods indicated (in thousands):

	2018		2017		2016
Balance at beginning of period	$	100	$	100	$	50
Charged to costs and expenses		100		—		50
Balance at end of period	$	200	$	100	$	100

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Accrued Liabilities (Tables)

12 Months Ended

Dec. 31, 2018

Payables And Accruals [Abstract]

Schedule of Accrued Liabilities

Accrued liabilities consist of the following (in thousands):

	At December 31,
	2018		2017
Capital expenditures	$	80,897	$	162,260
Preferred stock cash dividends		4,479		—
Deferred rent		—		410
Lease operating expense		6,604		5,796
General and administrative		4,335		1,642
Severance and ad valorem taxes		5,283		3,463
Interest expense		20,122		17,177
Derivative payable		1,746		5,281
Income taxes		—		991
Other accrued liabilities		1,167		2,932
Total	$	124,633	$	199,952

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Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2018

Asset Retirement Obligation Disclosure [Abstract]

Summary of Changes in Asset Retirement Obligations

The following table presents the changes in the asset retirement obligations for the year ended December 31, 2018 and 2017 (in thousands):

	For the Year Ended December 31,
	2018		2017
Asset retirement obligations at beginning of period	$	14,557	$	11,033
Accretion expense		573		713
Liabilities incurred		743		3,137
Liabilities settled		—		—
Revisions		70		(326)
Disposition of wells and gathering system		(7,627)		—
Asset retirement obligations at end of period		8,316		14,557
Less: current portion		90		90
Asset retirement obligations – long-term	$	8,226	$	14,467

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Long Term Debt (Tables)

12 Months Ended

Dec. 31, 2018

Debt Disclosure [Abstract]

Schedule of Debt Obligations

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

	At December 31,
Debt Obligation	2018		2017
WRD revolving credit facility	$	504,000	$	286,353
2025 Senior Notes (as defined below) (1)		700,000		500,000
Unamortized net discounts - 2025 Senior Notes		(782)		(4,914)
Unamortized debt issuance costs - 2025 Senior Notes		(11,842)		(10,843)
Total long-term debt	$	1,191,376	$	770,596

The estimated fair value of this fixed-rate debt was $661.5 million and $511.3 million at December 31, 2018 and 2017, respectively. The estimated fair values are based on quoted market prices and is classified as Level 2 within the fair value hierarchy.

Schedule of Borrowing Base Revolving Credit Facility

The borrowing base for our revolving credit facility was the following at the date indicated (in thousands):

	December 31,
Credit Facility	2018
WRD revolving credit facility	$	1,300,000

Schedule of Debt Instrument Pricing Based on Borrowing Base Utilization

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

Summary of Weighted-Average Interest Rates Paid on Variable-Rate Debt Obligations

	At December 31,
Credit Facility	2018		2017		2016
WRD revolving credit facility	4.06	%	3.60	%	3.52	%
WHR II revolving credit facility terminated December 2016	n/a		n/a		3.03	%
Esquisto - revolving credit facility terminated December 2016	n/a		n/a		2.84	%
Esquisto - revolving credit facility terminated January 2016	n/a		n/a		2.97	%
Esquisto - Second lien terminated in January 2016	n/a		n/a		9.50	%

Summary of Unamortized Deferred Financing Costs Associated with Consolidated Debt Obligations

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

	At December 31,
	2018		2017
WRD revolving credit facility
Current	$	1,823	$	1,203
Long-term		3,592		3,573
6.875% senior unsecured notes, due February 2025		11,842		10,843
Total	$	17,257	$	15,619

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Preferred Stock (Tables)

12 Months Ended

Dec. 31, 2018

Temporary Equity [Abstract]

Schedule of Preferred Stock

	Series A Perpetual
	Convertible Preferred
	Stock
	(in thousands)
Balance at December 31, 2016	$	—
Issue of preferred stock in connection with the Acquisition		435,000
Costs incurred related to the issuance of preferred stock		(2,663)
Accrual of preferred stock paid-in-kind dividend		13,146
Balance at December 31, 2017		445,483
Paid-in-kind dividend		2,243
Beneficial conversion feature ("BCF")		(1,872)
Amortization of BCF		1,872
Balance at December 31, 2018	$	447,726

Schedule of Preferred Stock Dividends

	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
October 15, 2018	August 1, 2018	October 31, 2018	$	6.756	October 31, 2018

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Equity (Tables)

12 Months Ended

Dec. 31, 2018

Equity [Abstract]

Summary of Changes in Common Shares Issued

Balance, December 31, 2016	91,680,441
Common stock issued	7,815,225
Restricted common shares issued	1,676,284
Restricted common shares forfeited	(717)
Repurchase of vested restricted shares (2)	(33,956)
Balance, December 31, 2017	101,137,277
Restricted common shares issued	1,076,165
Restricted common shares forfeited	(63,768)
Repurchase of vested restricted shares (2)	(355,819)
Balance, December 31, 2018	101,793,855

(1) We were incorporated in August 2016 under the laws of the State of Delaware.

(2) Restricted common shares are generally net-settled by 2016 LTIP participants to cover the required withholding tax upon vesting of restricted stock awards. Participants surrendered shares with value equivalent to the employee's minimum statutory obligation for the applicable income and other employment taxes. Total payments remitted for the employees' tax obligations to the appropriate taxing authorities were approximately $6.9 million and $0.6 million for the years ended December 31, 2018 and 2017, respectively. These net-settlements had the effect of shares repurchased by the Company as they reduced the number of shares that would have otherwise been outstanding as a result of the vesting and did not represent an expense to the Company.

Schedule Of Advances And Payments Of Promissory Note Advances Table [Text Block]

The table below summarizes advances and payments of the promissory note advances for the year ended December 31, 2016 (in thousands):

	Principal		Interest		Total
Balance, December 31, 2015	$	2,367	$	76	$	2,443
Advances		101		—		101
Payments		(20)		—		(20)
Accrued Interest		—		51		51
Dissolution		(2,448)		(127)		(2,575)
Balance, December 31, 2016	$	—	$	—	$	—

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Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2018

Earnings Per Share [Abstract]

Schedule of Calculation of Earnings (Loss) Per Share

	For the Year Ended December 31,
	2018 (1)		2017 (2)		2016 (3)
Numerator:
Net income (loss) available to WRD	$	146,508	$	49,880	$	(10,397)
Less: Preferred stock dividends		28,862		13,146		—
Less: Undistributed earnings allocated to participating securities		30,344		5,612		—
Net income (loss) available to common stockholders	$	87,302	$	31,122	$	(10,397)
Denominator:
Weighted-average common shares outstanding (in thousands)		99,498		96,324		91,327
Basic EPS	$	0.88	$	0.32	$	(0.11)
Diluted EPS	$	0.88	$	0.32	$	(0.11)

(1) The Company used the two-class method for both basic and diluted EPS.  For the year ended December 31, 2018, 775 incremental restricted shares were excluded in the calculation of diluted EPS due to their antidilutive effect under the treasury stock method.  For the for the year ended December 31, 2018, 32,363 shares were excluded from the calculation of diluted EPS due to their antidilutive effect under the if-converted method.

(2) The Company used the two-class method for both basic and diluted EPS.  For the year ended December 31, 2017, 628 incremental restricted shares were excluded in the calculation of diluted EPS due to their antidilutive effect under the treasury stock method.  For the year ended December 31, 2017, 16,008 shares were excluded from the calculation of diluted EPS due to their antidilutive effect under the if-converted method.

The Company used the two-class method for both basic and diluted EPS. For the year ended December 31, 2016, restricted shares were excluded from the calculation of diluted EPS due to their antidilutive effect as we were in a loss position for the period

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Long Term Incentive Plans (Tables)

12 Months Ended

Dec. 31, 2018

Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]

Summary of Restricted Common Stock Awards Granted Under 2016 LTIP

		Weighted-Average
	Number of	Grant Date Fair
	Shares	Value per Share (1)
Restricted common shares outstanding at January 1, 2016	—	$	—
Granted (2)	353,334	$	14.50
Restricted common stock outstanding at December 31, 2016	353,334	$	14.50
Granted (2)	1,676,284	$	13.88
Forfeited	(717)	$	13.94
Vested	(131,111)	$	14.50
Restricted common stock outstanding at December 31, 2017	1,897,790	$	13.95
Granted (2)	1,076,165	$	25.57
Forfeited	(63,768)	$	16.45
Vested	(1,069,933)	$	15.66
Restricted common stock outstanding at December 31, 2018	1,840,254	$	19.66

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

The aggregate grant date fair value of restricted common share awards granted in 2017 was $23.3 million based on grant date market price ranging from $10.91 to $14.22 per share. The aggregate grant date fair value of restricted common share awards granted in 2018 was $27.5 million based on grant date market price ranging from $18.14 to $27.07 per share. Our awards have contractual vesting periods between one and three years.

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Segment Disclosures (Tables)

12 Months Ended

Dec. 31, 2018

Segment Reporting [Abstract]

Summary of Major Customers

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

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2018

Income Tax Disclosure [Abstract]

Components of Income Tax Benefit (Expense)

The components of income tax expense (benefit) are as follows (in thousands):

	For the Year Ended December 31,
	2018		2017		2016
Current income taxes:
Federal	$	(997)	$	997	$	—
State		—		10		—
Total current income tax expense (benefit)		(997)		1,007		—
Deferred income taxes:
Federal		43,143		(40,529)		(5,737)
State		(1,950)		698		162
Total deferred income tax expense (benefit)		41,193		(39,831)		(5,575)
Total income tax expense (benefit)	$	40,196	$	(38,824)	$	(5,575)

Schedule of Effective Income Tax Rate Reconciliation

	For the Year Ended December 31,
	2018		2017		2016
Expected tax expense (benefit) at federal statutory rate	$	39,208	$	3,870	$	(18,428)
State income tax expense (benefit), net of federal benefit		(3,360)		460		105
Pass-through entities (1)		—		—		12,499
Incentive unit compensation		2,893		—		—
Stock-based compensation		(1,070)		—		—
Valuation allowance		1,820		—		234
Change in tax rate (2)		—		(43,431)		—
Change in prior period estimates		24		315		—
Other		681		(38)		15
Total income tax expense (benefit)	$	40,196	$	(38,824)	$	(5,575)

(1) Our predecessor was a pass-through entity for federal income tax purposes.

(2) The federal corporate income tax rate was reduced from 35% to 21% as a result of the Tax Act.

Components of Net Deferred Income Tax Liabilities

Components of net deferred income tax liabilities:	2018		2017
Deferred income tax assets:
Net operating loss Carryforwards	$	47,609	$	29,866
Disallowed interest carryforwards		9,992		—
Minimum tax credit Carryforward		—		997
Asset retirement obligation		1,796		3,311
Derivatives		—		16,903
Other		3,860		2,153
Total deferred income tax assets		63,257		53,230
Valuation allowance		(1,820)		—
Net deferred income tax assets		61,437		53,230
Deferred income tax liabilities:
Property, plant and equipment		158,868		124,700
Derivatives		15,300		—
Total deferred income tax liabilities		174,168		124,700
Net deferred income tax liabilities	$	112,731	$	71,470

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2018

Commitments And Contingencies Disclosure [Abstract]

Summary of Minimum Commitments of Lease Obligations

The table below reflects our minimum commitments as of December 31, 2018:

	2019		2020		2021		2022		2023
Office Leases	$	2,399	$	2,435	$	2,398	$	2,216	$	2,251
Dedicated Fracturing Fleet Services Agreement		21,000		—		—		—		—
Sand Mine Equipment		5,055		3,436		—		—		—
Compressors		4,143		3,991		3,859		2,724		902
Total	$	32,597	$	9,862	$	6,257	$	4,940	$	3,153

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Quarterly Financial Information (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2018

Quarterly Financial Information Disclosure [Abstract]

Quarterly Financial Data

	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter (1)
For the Year Ended December 31, 2018
Revenues	$	218,757	$	225,413	$	259,490	$	243,726
Operating income (loss)		(100,053)		101,370		122,776	$	88,196
Net income (loss) available to WRD		(115,774)		(14,094)		11,523	$	264,853
Preferred stock dividends		7,389		7,961		6,756		6,756
Net income (loss) available to common stockholders		(123,163)		(22,055)		3,534		228,986
Basic earnings (loss) per share	$	(1.24)	$	(0.22)	$	0.04	$	1.92
Diluted earnings (loss) per share	$	(1.24)	$	(0.22)	$	0.04	$	1.92
For the Year Ended December 31, 2017
Revenues	$	54,292	$	70,173	$	122,486	$	180,236
Operating income		6,206		2,078		32,599	$	64,582
Net income (loss)		20,252		26,366		(10,804)	$	14,066
Preferred stock dividends		—		73		6,450		6,623
Net income (loss) available to common stockholders		20,252		25,906		(17,254)		2,218
Basic earnings (loss) per share	$	0.22	$	0.28	$	(0.17)	$	0.06
Diluted earnings (loss) per share	$	0.22	$	0.28	$	(0.17)	$	0.06

Net income for the three months ended December 31, 2017 includes a deferred tax benefit of $43.4 million as a result of the re-measurement of our deferred tax assets and liabilities as a result of the Tax Act.

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Supplemental Oil and Gas Information (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2018

Extractive Industries

Weighted Average Benchmark Product Prices

	For the Year Ended December 31,
	2018		2017		2016
Oil ($/Bbl)
West Texas Intermediate (1)	$	65.56	$	51.34	$	42.75
NGL ($/Bbl)
West Texas Intermediate (1)	$	65.56	$	51.34	$	42.75
Natural Gas ($/Mmbtu)
Henry Hub (2)	$	3.10	$	2.98	$	2.48

(1) The unweighted average West Texas Intermediate price was adjusted by lease for quality, transportation fees, and a regional price differential.

The unweighted average Henry Hub price was adjusted by lease for energy content, compression charges, transportation fees, and regional price differentials.

Summary of changes in quantities of proved oil and natural gas reserves

The following tables set forth estimates of the net reserves as of December 31, 2018, 2017 and 2016, respectively:

	For the Year Ended December 31, 2018
	Oil (MBbls)	Gas (MMcf)	NGL (MBbls)	Equivalent (MBoe)
Proved developed and undeveloped reserves:
Beginning of the year	282,798	683,808	57,550	454,315
Extensions, discoveries and additions	81,174	129,962	16,377	119,211
Purchase of minerals in place	520	727	116	757
Sales of minerals in place	(1,272)	(393,057)	(398)	(67,180)
Production	(12,585)	(21,531)	(2,143)	(18,316)
Revision of previous estimates	(65,369)	(21,736)	(13,747)	(82,737)
End of year	285,266	378,173	57,755	406,050
Proved developed reserves:
Beginning of year	65,023	221,517	12,553	114,495
End of year	66,398	88,936	14,135	95,356
Proved undeveloped reserves:
Beginning of year	217,775	462,291	44,997	339,820
End of year	218,868	289,237	43,620	310,694

	For the Year Ended December 31, 2017
	Oil (MBbls)	Gas (MMcf)	NGL (MBbls)	Equivalent (MBoe)
Proved developed and undeveloped reserves:
Beginning of the year	87,447	325,102	10,874	152,505
Extensions, discoveries and additions	93,454	279,368	22,545	162,559
Purchase of minerals in place	59,169	28,106	6,740	70,593
Production	(6,606)	(20,463)	(1,206)	(11,222)
Revision of previous estimates	49,334	71,695	18,597	79,880
End of year	282,798	683,808	57,550	454,315
Proved developed reserves:
Beginning of year	19,192	145,880	3,765	47,270
End of year	65,023	221,517	12,553	114,495
Proved undeveloped reserves:
Beginning of year	68,255	179,222	7,109	105,235
End of year	217,775	462,291	44,997	339,820

	For the Year Ended December 31, 2016
	Oil (MBbls)	Gas (MMcf)	NGL (MBbls)	Equivalent (MBoe)
Proved developed and undeveloped reserves:
Beginning of the year	36,650	344,959	8,897	103,040
Extensions, discoveries and additions	18,870	32,782	2,606	26,940
Purchase of minerals in place	26,835	13,545	1,823	30,916
Production	(1,848)	(17,820)	(471)	(5,289)
Revision of previous estimates	6,940	(48,364)	(1,981)	(3,102)
End of year	87,447	325,102	10,874	152,505
Proved developed reserves:
Beginning of year	7,503	142,990	2,235	33,570
End of year	19,192	145,880	3,765	47,270
Proved undeveloped reserves:
Beginning of year	29,147	201,969	6,662	69,470
End of year	68,255	179,222	7,109	105,235

Standardized Measure of Discounted Future Net Cash Flows

The standardized measure of discounted future net cash flows is as follows (in thousands):

	For the Year Ended December 31,
	2018		2017		2016
Future cash inflows	$	21,269,502	$	16,967,369	$	4,434,117
Future production costs		(3,440,203)		(3,305,941)		(1,220,067)
Future development costs		(5,168,271)		(4,008,916)		(1,146,632)
Future income tax expense		(2,398,612)		(1,814,510)		(442,285)
Future net cash flows for estimated timing of cash flows		10,262,416		7,838,002		1,625,133
10% annual discount for estimated timing of cash flows		(6,144,980)		(4,994,097)		(1,082,092)
Standardized measure of discounted future net cash flows	$	4,117,436	$	2,843,905	$	543,041

Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves

The following is a summary of the changes in the standardized measure of discounted future net cash flows for the proved oil and natural gas reserves during each of the years in the three-year period ended December 31, 2018 (in thousands):

	For the Year Ended December 31,
	2018		2017		2016
Beginning of year	$	2,843,905	$	543,041	$	451,930
Sale of oil and natural gas produced, net of production costs		(822,471)		(351,031)		(104,596)
Purchase of minerals in place		4,313		507,095		188,317
Sales of minerals in place		(319,858)		—		—
Extensions and discoveries		1,829,564		1,595,385		168,796
Changes in income taxes, net		(277,050)		(488,484)		(206,817)
Changes in prices and costs		1,380,323		398,713		(57,034)
Previously estimated development costs incurred		67,575		49,977		15,067
Net changes in future development costs		(13,317)		(87,375)		11,985
Revisions of previous quantities		(1,057,523)		653,567		3,943
Accretion of discount		323,927		74,999		103,000
Change in production rates and other		158,048		(51,982)		(31,550)
End of year	$	4,117,436	$	2,843,905	$	543,041

Capitalized Costs Relating to Oil and Natural Gas Producing Activities

The total amount of capitalized costs relating to oil and natural gas producing activities and the total amount of related accumulated depreciation, depletion and amortization is as follows at the dates indicated (in thousands).

	For the Year Ended December 31,
	2018		2017		2016
Evaluated oil and natural gas properties	$	2,764,875	$	2,265,525	$	1,144,857
Unevaluated oil and natural gas properties		693,023		734,203		428,991
Accumulated depletion, depreciation and amortization		(498,811)		(362,406)		(196,567)
Total	$	2,959,087	$	2,637,322	$	1,377,281

Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities

	For the Year Ended December 31,
	2018		2017		2016
Property acquisition costs, proved	$	4,422	$	269,429	$	230,910
Property acquisition costs, unproved		85,863		386,515		235,652
Exploration and extension well costs		11,979		16,076		72,875
Development		927,985		795,273		63,006
Total	$	1,030,249	$	1,467,293	$	602,443

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Organization and Basis of Presentation - Additional Information (Details) $ in Millions	1 Months Ended	12 Months Ended
	Feb. 28, 2019 USD ($) shares	Dec. 31, 2016 USD ($) shares	Dec. 31, 2018 subsidiary
Organization And basis of presentation
Issued and sold of initial public offering | shares		27,500,000
Gross proceeds from the sale of the common stock		$ 412.5
Underwriting discounts and commissions		14.1
Other offering costs		5.0
Net proceeds from initial public offering		393.4
Debt issuance cost		$ 2.9
Chesapeake | Wildhorse Resource Development Corporation | Subsequent Event
Organization And basis of presentation
Business acquisition, shares issued | shares	717,300,000
Cash paid	$ 381.1
Esquisto II
Organization And basis of presentation
Number of wholly owned subsidiaries | subsidiary			2

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Organization and Basis of Presentation - Investment in Unconsolidated Affiliate (Details) $ in Thousands		1 Months Ended	12 Months Ended
	Jul. 27, 2018 USD ($)	Jul. 31, 2018 USD ($)	Dec. 31, 2018 USD ($)
Investment in unconsolidated affiliate
Cash capital contribution			$ 10,177
Line of Credit Facility, Collateral Fees		$0.4
Minimum range of investment value the entity deems as more than minor			more than 3 to 5 percent
Loss on equity investment			$ 676
Other income (expense)
Investment in unconsolidated affiliate
Loss on equity investment			700
Port of Corpus Christi Authority
Investment in unconsolidated affiliate
Lease term		20 years
Irrevocable Standby Letter of Credit
Investment in unconsolidated affiliate
Letter of credit outstanding	$ 47,500
Irrevocable Standby Letter of Credit | Port of Corpus Christi Authority
Investment in unconsolidated affiliate
Term of letter of credit	10 years
JWH
Investment in unconsolidated affiliate
Accrued capital contribution			1,900
JWH | Other
Investment in unconsolidated affiliate
Equity method investment			$ 11,500
WHCC | JWH
Investment in unconsolidated affiliate
Membership percentage		50.00%
WHCC | JWH
Investment in unconsolidated affiliate
Cash capital contribution		$ 10,200
Joint Venture Partner | JWH
Investment in unconsolidated affiliate
Membership percentage		50.00%
Joint Venture Partner | JWH
Investment in unconsolidated affiliate
Cash capital contribution		$ 10,200
JWH
Investment in unconsolidated affiliate
Number of leased acres for construction and operation of marine terminal facility		55

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Summary of Significant Accounting Policies - Oil and Gas Properties (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Restricted cash
Restricted cash	$ 0.0	$ 0.0
Oil and gas properties
Capital costs excluded from depletion	$ 98.1

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Summary of Significant Accounting Policies - Schedule of Net changes Capitalized Exploratory Costs (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Extractive Industries
Balance, beginning of period	$ 7,064	$ 15,198
Additions to capitalized exploratory well costs pending the determination of proved reserves		60,847
Reclassifications to wells, facilities and equipment based on the determination of proved reserves	$ (7,064)	(68,981)
Balance, end of period		$ 7,064

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Summary of Significant Accounting Policies - Additional Information (Details) - USD ($) $ in Millions		12 Months Ended
	Jan. 31, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Significant accounting policies
Capitalized interest		$ 5.9	$ 3.1	$ 0.1
Provision for uncollectible accounts		0.2	0.1
Internal Revenue Service ("IRS")
Significant accounting policies
Estimated minimum tax paid	$ 2.3
Unproved Oil and Gas Properties
Significant accounting policies
Impairment of oil and natural gas properties		$ 10.5	$ 20.8	$ 3.1

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Summary of Significant Accounting Policies - Summary of Impact of Adoption of Accounting Standards on Condensed Consolidated Balance Sheet (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Jan. 02, 2018	Jan. 01, 2018	Dec. 31, 2017
ASSETS
Oil and gas properties	$ 3,457,897	$ 2,995,687		$ 2,999,728
Accumulated depreciation, depletion and amortization	(518,054)	(367,874)		(368,245)
Other non-current assets	17,250	3,978
Liabilities:
Deferred tax liabilities	112,731	71,537		71,470
Stockholders' equity:
Accumulated earnings	136,773	$ 26,016		$ 25,773
Contract with customers assets and liabilities
Contract assets	0
Performance obligation
Unsatisfied performance obligations	0
Adjustments for ASC 606 | Accounting Standards Update 2014-09
ASSETS
Oil and gas properties	(5,960)		$ (4,041)
Accumulated depreciation, depletion and amortization	981		371
Other non-current assets	5,811		3,978
Liabilities:
Deferred tax liabilities	180		67
Stockholders' equity:
Accumulated earnings	(1,012)		$ 243
Calculated under Revenue Guidance in Effect before Topic 606 | Accounting Standards Update 2014-09
ASSETS
Oil and gas properties	3,463,857
Accumulated depreciation, depletion and amortization	(519,035)
Other non-current assets	11,439
Liabilities:
Deferred tax liabilities	112,551
Stockholders' equity:
Accumulated earnings	$ 137,785

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Summary of Significant Accounting Policies - Summary of Impact of Adoption of Accounting Standards on Consolidated Income Statement (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Revenues
Other income	$ 2,052	$ 1,431	$ 2,131
Operating expenses:
Lease operating expenses	61,620	39,770	12,320
Gathering, processing and transportation	9,856	11,897	6,581
Depreciation, depletion and amortization	296,685	168,250	81,757
Other operating expense	1,064	73	99
Income before income taxes	186,704	11,056	(52,651)
Income tax expense	(40,196)	38,824	5,575
Net income	146,508	49,880	(10,397)
Oil sales
Revenues
Revenues	843,244	342,868	75,938
Natural gas sales
Revenues
Revenues	60,129	59,924	43,487
Natural gas liquid sales
Revenues
Revenues	41,961	$ 22,964	$ 5,786
Calculated under Revenue Guidance in Effect before Topic 606 | Accounting Standards Update 2014-09
Revenues
Other income	1,861
Operating expenses:
Lease operating expenses	63,043
Gathering, processing and transportation	22,703
Depreciation, depletion and amortization	297,295
Other operating expense	459
Income before income taxes	186,180
Income tax expense	(40,083)
Net income	146,097
Calculated under Revenue Guidance in Effect before Topic 606 | Accounting Standards Update 2014-09 | Oil sales
Revenues
Revenues	843,329
Calculated under Revenue Guidance in Effect before Topic 606 | Accounting Standards Update 2014-09 | Natural gas sales
Revenues
Revenues	64,896
Calculated under Revenue Guidance in Effect before Topic 606 | Accounting Standards Update 2014-09 | Natural gas liquid sales
Revenues
Revenues	51,052
Adjustments for ASC 606 | Accounting Standards Update 2014-09
Revenues
Other income	191
Operating expenses:
Lease operating expenses	(1,423)
Gathering, processing and transportation	(12,847)
Depreciation, depletion and amortization	(610)
Other operating expense	605
Income before income taxes	524
Income tax expense	(113)
Net income	411
Adjustments for ASC 606 | Accounting Standards Update 2014-09 | Oil sales
Revenues
Revenues	(85)
Adjustments for ASC 606 | Accounting Standards Update 2014-09 | Natural gas sales
Revenues
Revenues	(4,767)
Adjustments for ASC 606 | Accounting Standards Update 2014-09 | Natural gas liquid sales
Revenues
Revenues	$ (9,091)

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Summary of Significant Accounting Policies - Summary of Impact of Adoption of Accounting Standards on Condensed Consolidated Cash Flows (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Cash flows from operating activities:
Net income (loss)	$ 264,853	$ 11,523	$ (14,094)	$ (115,774)	$ 14,066	$ (10,804)	$ 26,366	$ 20,252	$ 146,508	$ 49,880	$ (47,076)
Depreciation, depletion and amortization									296,685	168,250	81,757
Deferred income tax expense									41,193	(39,831)	(5,575)
Consideration paid to customers, net of amortization									(1,817)
Cash flows from investing activities:
Additions to oil and gas properties									(1,051,891)	$ (700,546)	$ (125,837)
Calculated under Revenue Guidance in Effect before Topic 606 | Accounting Standards Update 2014-09
Cash flows from operating activities:
Net income (loss)									146,097
Depreciation, depletion and amortization									297,295
Deferred income tax expense									41,080
Cash flows from investing activities:
Additions to oil and gas properties									(1,053,811)
Adjustments for ASC 606 | Accounting Standards Update 2014-09
Cash flows from operating activities:
Net income (loss)									411
Depreciation, depletion and amortization									(610)
Deferred income tax expense									113
Consideration paid to customers, net of amortization									(1,817)
Cash flows from investing activities:
Additions to oil and gas properties									$ 1,920

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Summary of Significant Accounting Policies - Schedule of Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Supplemental cash flows:
Cash paid for interest, net of capitalized interest	$ 48,717	$ 12,246	$ 7,152
Noncash investing activities:
Increase (decrease) in capital expenditures in accounts payables and accrued liabilities	(82,358)	134,589	(4,492)
(Increase) decrease in accounts receivable related to capital expenditures and acquisitions	$ (1,247)	$ (847)	$ (5,175)

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Summary of Significant Accounting Policies - Leases (Details) - Accounting Standards Update 2016-02 - Proforma Adjustment $ in Millions	Dec. 31, 2018 USD ($)
Minimum
New accounting pronouncements - Leases
Operating Lease, Right-of-Use Asset	$ 35.0
Maximum
New accounting pronouncements - Leases
Operating Lease, Right-of-Use Asset	$ 65.0

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Acquisitions and Divestitures - Schedule of Acquisition-Related Costs Included in General and Administrative Expenses (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Business Combinations [Abstract]
Acquisition-related costs	$ 1,117	$ 4,348	$ 553

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Acquisitions and Divestitures - Additional Information (Details) $ in Thousands						1 Months Ended	3 Months Ended			12 Months Ended
	Mar. 29, 2018 USD ($)	Jan. 04, 2018 USD ($) a	Jun. 30, 2017 USD ($) shares	Dec. 19, 2016 USD ($) a shares	Nov. 08, 2016 USD ($) a item	Oct. 31, 2018 USD ($)	Jun. 30, 2018 USD ($)	Mar. 31, 2018 USD ($)	Mar. 31, 2017 USD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Sep. 30, 2018 USD ($)
Business Acquisitions
Acquisitions of oil and gas properties										$ 53,814	$ 551,242	$ 436,072
Payments to acquire other property, plant and equipment										83,597	15,959	5,403
Capitalized assets										107,279	53,003
Divestitures
Impairment of NLA Disposal Group								$ 214,300		214,274
Pre-tax loss of NLA Disposal Group										202,700	5,900
NLA Assets | Disposal Group, Disposed of by Sale, Not Discontinued Operations
Divestitures
Proceeds from divestiture before final purchase price adjustments	$ 206,400
Final purchase price adjustments						$ 4,800				4,800
Final proceeds from divestiture										211,200
Divestiture related costs										3,800
Contingent consideration arrangement divestiture										$ 35,000			$ 35,000
Period of time over which contingent payments will be determined										3 years
Payments received on contingent consideration arrangements										$ 400
Gain on sale of NLA Disposal Group										2,800
Fee revenue from transitional accounting and land service provided							$ 900
Sand Mine
Business Acquisitions
Capitalized sand assets										66,100
Eagle Ford Acquisitions
Business Acquisitions
Acquisitions of oil and gas properties										53,800
Capitalized transaction costs										1,500
Purchase price allocated to unproved oil and natural gas properties										$ 48,000
APC/KKR Acquisitions
Business Acquisitions
Payments to acquire oil and natural gas properties			$ 533,002
Business acquisition, value of shares issued			$ 60,754
Business acquisition, date of acquisition agreement			May 10, 2017
Business acquisition, date of completion			Jun. 30, 2017
Revenues related to properties obtained in the Acquisition											42,600
Income/loss related to properties obtained in the Acquisition											11,100
APC Subs
Business Acquisitions
Payments to acquire oil and natural gas properties			$ 533,600
KKR
Business Acquisitions
Business acquisition, value of shares issued			$ 60,800
Business acquisition, shares issued | shares			5,518,125
Third Parties Acquisition | Burleson County, TX
Business Acquisitions
Payments to acquire oil and natural gas properties											19,700
Purchase price allocated to unproved oil and natural gas properties											$ 11,600
Burleson North Acquisition
Business Acquisitions
Payments to acquire oil and natural gas properties				$ 389,800
Purchase price allocated to unproved oil and natural gas properties				$ 162,900
Business acquisition, post-closing receipt									$ 3,900
Revenues related to properties obtained in the Acquisition												2,000
Income/loss related to properties obtained in the Acquisition												$ 400
Area of oil and natural gas properties acquired | a				158,000
Rosewood Acquisition
Business Acquisitions
Purchase price allocated to unproved oil and natural gas properties				$ 18,300
Area Of Land | a				7,500
Business acquisition, shares issued | shares				1,308,427
Burleson Sand | Sand Mine
Business Acquisitions
Surface and sand rights acquired | a		727
Payments to acquire other property, plant and equipment		$ 9,000
Esquisto II | November Acquisition
Business Acquisitions
Payments to acquire oil and natural gas properties					$ 30,000
Purchase price allocated to unproved oil and natural gas properties					$ 29,400
Area Of Land | a					4,900
Number of oil and gas producing wells | item					9

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Acquisitions and Divestitures - Summary of Fair Value of Assets Acquired and Liabilities Assumed (Details) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 19, 2016	Nov. 08, 2016
APC/KKR Acquisitions
Business Acquisitions
Cash paid	$ 533,002
Common stock, Purchase price	60,754
Total consideration, Purchase price	593,756
Final Purchase Price Allocation
Proved oil and gas properties, Purchase price	264,467
Unproved oil and gas properties, Purchase price	333,778
Accounts receivable, Purchase Price	60
Asset retirement obligations, Purchase Price	(2,500)
Accrued liabilities, Purchase Price	(2,049)
Total identifiable net assets, Purchase Price	$ 593,756
Burleson North Acquisition
Business Acquisitions
Cash paid		$ 389,800
Burleson North Acquisition | Final Purchase Price Allocation
Business Acquisitions
Oil and natural gas properties, Purchase Price		395,591
Other property and equipment, Purchase Price		478
Final Purchase Price Allocation
Accounts receivable, Purchase Price		1,257
Accounts payable, Purchase Price		(1,816)
Asset retirement obligations, Purchase Price		(3,101)
Accrued liabilities, Purchase Price		(6,503)
Total identifiable net assets, Purchase Price		385,906
Rosewood Acquisition
Business Acquisitions
Oil and natural gas properties, Purchase Price		$ 19,626
November Acquisition
Business Acquisitions
Oil and natural gas properties, Purchase Price			$ 29,973

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Acquisitions and Divestitures - Summary of Unaudited Pro Forma Financial Information (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
APC/KKR Acquisitions
Business Acquisitions
Revenues	$ 475,396	$ 226,502
Net loss	$ 71,287	$ (11,290)
Earnings per share (basic and diluted)	$ 0.51	$ (0.10)
Burleson North Acquisition
Business Acquisitions
Revenues		$ 176,082
Net loss		$ (34,894)

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Fair Value Measurements of Financial Instruments - Assets and Liabilities Measured at Fair Value on Recurring Basis (Details) - Fair Value, Measurements, Recurring - Commodity Contract - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Assets:
Fair value of derivative asset	$ 72,710	$ 2,422
Liabilities:
Fair value of derivative liability	508	76,750
Significant Other Observable Inputs (Level 2)
Assets:
Fair value of derivative asset	72,710	2,422
Liabilities:
Fair value of derivative liability	$ 508	$ 76,750

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Fair Value Measurements of Financial Instruments - Additional Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Proved Oil and Gas Properties
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment of oil and natural gas properties	$ 0	$ 0	$ 0
Unproved Oil and Gas Properties
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment of oil and natural gas properties	$ 10,500	$ 20,800	$ 3,100

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Risk Management and Derivative Instruments - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Derivative Instruments And Hedging Activities Disclosure
Derivative instruments designated as cash flow hedges	$ 0.0
Deferred premiums	9.3	$ 6.3
Derivative assets	72.2
Derivative liability, right to offset amount	72.2
Cash collateral received or pledged	$ 0.0

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Risk Management and Derivative Instruments - Schedule of Derivative Contracts (Details)	12 Months Ended
	Dec. 31, 2018 MMBTU $ / bbl bbl
Crude Oil Derivative Contracts Fixed Price Swap 2019
Derivative [Line Items]
Volume (Bbls) | bbl	6,652,369
Weighted-average fixed price	54.45
Crude Oil Derivative Contracts Put Options 2019
Derivative [Line Items]
Volume (Bbls) | bbl	1,749,757
Weighted-average floor price	53.83
Weighted-average put premium	(5.43)
Crude Oil Derivative Contracts Fixed Price Swap 2020
Derivative [Line Items]
Volume (Bbls) | bbl	4,511,681
Weighted-average fixed price	53.49
Natural Gas Derivative Contracts Fixed Price Swap 2019
Derivative [Line Items]
Volume (MMBtu) | MMBTU	6,425,146
Weighted-average fixed price	2.79
Natural Gas Derivative Contracts Fixed Price Swap 2020
Derivative [Line Items]
Volume (MMBtu) | MMBTU	4,846,020
Weighted-average fixed price	2.76

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Risk Management and Derivative Instruments - Summary of Gross Fair Value and Net Recorded Fair Value of Derivative Instruments by Appropriate Balance Sheet Classification (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Derivative [Line Items]
Asset Derivatives, Net recorded fair value	$ 72,200
Short-term Derivative Instruments | Commodity Contract
Derivative [Line Items]
Asset Derivatives, Gross fair value	54,131	$ 2,336
Asset Derivatives, Net recorded fair value	54,131	2,336
Liability Derivatives, Gross fair value	508	58,074
Liability Derivatives, Net recorded fair value	508	58,074
Long-term Derivative Instruments | Commodity Contract
Derivative [Line Items]
Asset Derivatives, Gross fair value	18,579	86
Asset Derivatives, Net recorded fair value	18,579	86
Liability Derivatives, Gross fair value	0	18,676
Liability Derivatives, Net recorded fair value	$ 0	$ 18,676

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Risk Management and Derivative Instruments - Schedule of Gains and Losses Related to Derivative Instruments (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Commodity Contract
Derivative Instruments Gain Loss [Line Items]
Gain (loss) on derivative instruments	$ 35,393	$ (55,483)	$ (26,771)

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Accounts Receivable - Schedule of Accounts Receivable (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Receivables [Abstract]
Oil, natural gas and NGL sales	$ 70,900	$ 67,584
Joint interest billings	17,491	9,467
Severance tax	1,352	171
Derivative receivable	308
North Louisiana Settlement receivable		5,955
Environmental remediation	1,511
Other current receivables	196	1,026
Allowance for doubtful accounts	(200)	(100)	$ (100)	$ (50)
Total	$ 91,558	$ 84,103

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Accounts Receivable - Schedule of Accounts Notes Loans and Financing Receivable (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2016
Accounts Notes Loans And Financing Receivable Gross Allowance And Net [Abstract]
Balance at beginning of period	$ 100	$ 50
Charged to costs and expenses	100	50
Balance at end of period	$ 200	$ 100

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Accrued Liabilities - Schedule of Accrued Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Payables And Accruals [Abstract]
Capital expenditures	$ 80,897	$ 162,260
Preferred stock cash dividends	4,479
Deferred rent		410
Lease operating expense	6,604	5,796
General and administrative	4,335	1,642
Severance and ad valorem taxes	5,283	3,463
Interest expense	20,122	17,177
Derivative payable	1,746	5,281
Income taxes		991
Other accrued liabilities	1,167	2,932
Total	$ 124,633	$ 199,952

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Asset Retirement Obligations - Summary of Changes in Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations at beginning of period	$ 14,557	$ 11,033
Accretion expense	573	713
Liabilities incurred	743	3,137
Revisions	70	(326)
Disposition of wells and gathering system	(7,627)
Asset retirement obligations at end of period	8,316	14,557
Less: current portion	90	90
Asset retirement obligations - long-term	$ 8,226	$ 14,467

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Long Term Debt - Schedule of Debt Obligations (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Debt Instrument
Unamortized debt issuance costs	$ (17,257)	$ (15,619)
Total long-term debt	1,191,376	770,596
6.875% Senior Unsecured Notes, Due February 2025
Debt Instrument
Long-term debt, gross	700,000	500,000
Unamortized discounts	(782)	(4,914)
Unamortized debt issuance costs	(11,842)	(10,843)
WRD Revolving Credit Facility
Debt Instrument
Long-term debt, gross	$ 504,000	$ 286,353

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Long Term Debt - Schedule of Debt Obligations Additional Information (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
6.875% Senior Unsecured Notes, Due February 2025 | Significant Other Observable Inputs (Level 2) | Estimated Fair Value
Debt Instrument
Estimated fair value of fixed rate debt	$ 661.5	$ 511.3

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Long Term Debt - Schedule of Borrowing Base Revolving Credit Facility (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Oct. 15, 2018	Mar. 23, 2018	Mar. 22, 2018	Oct. 04, 2017	Oct. 03, 2017	Jun. 30, 2017	Jun. 29, 2017	Feb. 01, 2017	Dec. 19, 2016
Line Of Credit Facility
WRD revolving credit facility							$ 650,000	$ 450,000
WRD Revolving Credit Facility
Line Of Credit Facility
WRD revolving credit facility	$ 1,300,000	$ 1,300,000	$ 1,050,000	$ 875,000	$ 875,000	$ 612,500			$ 362,500	$ 450,000

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Long Term Debt - Amendment to the Credit Agreement (Details) - WRD Revolving Credit Facility		12 Months Ended
	Oct. 15, 2018	Dec. 31, 2018
LIBOR
Debt Instrument
Variable margin rate		1.00%
Greater than or equal to 90%
Debt Instrument
Commitment fee	0.50%
Greater than or equal to 90% | LIBOR
Debt Instrument
Variable margin rate	2.50%
Greater than or equal to 90% | Base Rate
Debt Instrument
Variable margin rate	1.50%
Greater than or equal to 75% but less than 90%
Debt Instrument
Commitment fee	0.50%
Greater than or equal to 75% but less than 90% | LIBOR
Debt Instrument
Variable margin rate	2.25%
Greater than or equal to 75% but less than 90% | Base Rate
Debt Instrument
Variable margin rate	1.25%
Greater than or equal to 50% but less than 75%
Debt Instrument
Commitment fee	0.50%
Greater than or equal to 50% but less than 75% | LIBOR
Debt Instrument
Variable margin rate	2.00%
Greater than or equal to 50% but less than 75% | Base Rate
Debt Instrument
Variable margin rate	1.00%
Greater than or equal to 25% but less than 50%
Debt Instrument
Commitment fee	0.375%
Greater than or equal to 25% but less than 50% | LIBOR
Debt Instrument
Variable margin rate	1.75%
Greater than or equal to 25% but less than 50% | Base Rate
Debt Instrument
Variable margin rate	0.75%
Less than 25%
Debt Instrument
Commitment fee	0.375%
Less than 25% | LIBOR
Debt Instrument
Variable margin rate	1.50%
Less than 25% | Base Rate
Debt Instrument
Variable margin rate	0.50%

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Long Term Debt - Additional Information (Details) $ in Thousands						12 Months Ended
	Oct. 15, 2018 USD ($)	Apr. 20, 2018 USD ($)	Sep. 19, 2017 USD ($)	Feb. 01, 2017 USD ($)	Dec. 19, 2016 USD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Mar. 23, 2018 USD ($)	Mar. 22, 2018 USD ($)	Nov. 20, 2017	Oct. 04, 2017 USD ($)	Oct. 03, 2017 USD ($)	Jun. 30, 2017 USD ($)	Jun. 29, 2017 USD ($)
Debt Instrument
WRD revolving credit facility													$ 650,000	$ 450,000
Restricted Payment													$ 75,000	$ 50,000
Proceeds from senior notes offering						$ 204,000	$ 494,744
6.875% Senior Unsecured Notes, Due February 2025
Debt Instrument
Debt instrument interest rate percentage										6.875%
Debt instrument maturity date						Feb. 01, 2025
6.875% Senior Unsecured Notes, Due February 2025 | Private Placement
Debt Instrument
Aggregate principal amount		$ 200,000	$ 150,000	$ 350,000
Debt instrument interest rate percentage				6.875%
Issue price of notes as a percentage of par value		102.00%	98.26%	99.244%
Proceeds from senior notes offering		$ 201,000	$ 144,700	$ 338,600
Debt instrument maturity date							Feb. 01, 2025
Debt instrument redemption price percentage				106.875%
Debt instrument, redemption description						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.
Maximum | 6.875% Senior Unsecured Notes, Due February 2025 | Private Placement
Debt Instrument
Debt instrument redemption percentage of principal amount				35.00%
WRD Revolving Credit Facility
Debt Instrument
Line of credit expiration period					5 years
Aggregate maximum credit amount					$ 1,000,000						$ 2,000,000	$ 1,000,000
WRD revolving credit facility	$ 1,300,000			$ 362,500	$ 450,000	$ 1,300,000		$ 1,050,000	$ 875,000		$ 875,000	$ 612,500
Decrease in pricing grid	0.25%
Debt issuance date					Dec. 19, 2016
Secured Credit Facility, discount rate						9.00%
Interest description						borrowings under our revolving credit facility will bear interest, at our option, at either: (i) the Alternate Base Rate, which is based on the greatest of (x) the prime rate as determined by the Administrative Agent, (y) the federal funds effective rate plus 0.50%, and (z) the adjusted LIBOR for a one month interest period plus 1.0%, in each case, plus a margin that varies per annum according to the total commitments usage (which is the ratio of outstanding borrowings and letters of credit to the least of the total commitments, the borrowing base and the aggregate elected commitments then in effect), (ii) the adjusted LIBOR plus a margin that varies per annum according to the total commitment usage or (iii) the applicable LIBOR market index rate plus a margin that varies per annum according to the total commitment usage.
WRD Revolving Credit Facility | Federal Funds Effective Swap Rate
Debt Instrument
Interest rate spread						0.50%
WRD Revolving Credit Facility | LIBOR
Debt Instrument
Interest rate spread						1.00%
WRD Revolving Credit Facility | Minimum
Debt Instrument
Secured Credit Facility lien percentage					85.00%
Ratio of current assets to current liabilities							1.00
WRD Revolving Credit Facility | Maximum
Debt Instrument
Ratio of total debt to EBITDAX							4.00
WRD Revolving Credit Facility | Certain Properties Prior to February 2, 2017
Debt Instrument
Secured Credit Facility lien percentage					75.00%

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Long Term Debt - Summary of Weighted-Average Interest Rates Paid On Variable-Rate Debt Obligations (Details)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
WRD Revolving Credit Facility
Line Of Credit Facility
Revolving credit facility, weighted-average interest rates	4.06%	3.60%	3.52%
WHR II Revolving Credit Facility Terminated December 2016
Line Of Credit Facility
Revolving credit facility, weighted-average interest rates			3.03%
Esquisto - Revolving Credit Facility Terminated December 2016
Line Of Credit Facility
Revolving credit facility, weighted-average interest rates			2.84%
Esquisto - Revolving Credit Facility Terminated January 2016
Line Of Credit Facility
Revolving credit facility, weighted-average interest rates			2.97%
Esquisto - Second Lien Terminated In January 2016
Line Of Credit Facility
Revolving credit facility, weighted-average interest rates			9.50%

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Long Term Debt - Summary of Unamortized Deferred Financing Costs Associated with Consolidated Debt Obligations (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Debt Instrument
Long-term	$ 3,592	$ 3,573
Unamortized deferred financing costs	17,257	15,619
6.875% Senior Unsecured Notes, Due February 2025
Debt Instrument
Unamortized deferred financing costs	11,842	10,843
WRD Revolving Credit Facility
Debt Instrument
Current	1,823	1,203
Long-term	$ 3,592	$ 3,573

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Preferred Stock - Additional Information (Details) $ / shares in Units, $ in Thousands				1 Months Ended	12 Months Ended
	Jan. 31, 2018 USD ($) $ / shares	Oct. 31, 2017 USD ($)	Jul. 31, 2017 USD ($) $ / shares	Jun. 30, 2017 USD ($) $ / shares shares	Dec. 31, 2018 director $ / shares	Dec. 31, 2017 USD ($)
Temporary Equity
Proceeds from the issuance of preferred stock						$ 435,000
June 30, 2018 Anniversary
Temporary Equity
Conversion of stock, conversion price | $ / shares					$ 13.90
Redeemable Convertible Preferred Stock
Temporary Equity
Quarterly dividend, amount	$ 6,656	$ 6,558
Dividend, record date	Jan. 15, 2018	Oct. 15, 2017
Dividend, date paid	Jan. 31, 2018	Oct. 31, 2017
Beneficial conversion feature	$ 1,900
Redeemable Convertible Preferred Stock | Dividend Payment In Kind
Temporary Equity
Preferred equity, initial accreted value, per share | $ / shares			$ 1,000
Quarterly dividend announced date			Jul. 31, 2017
Quarterly dividend, amount			$ 2,175
Dividend, record date			Jul. 15, 2017
Preferred Stock Purchase Agreement | 10% Ownership of Outstanding Common Stock
Temporary Equity
Number of directors entitled to be elected upon holding of outstanding common stock | director					2
Preferred Stock Purchase Agreement | Carlyle | 5% Ownership of Outstanding Common Stock
Temporary Equity
Number of directors entitled to be elected upon holding of outstanding common stock | director					1
Preferred Stock Purchase Agreement | Minimum | Carlyle | 10% Ownership of Outstanding Common Stock
Temporary Equity
Holding percentage of outstanding common stock to elect director					10.00%
Preferred Stock Purchase Agreement | Minimum | Carlyle | 5% Ownership of Outstanding Common Stock
Temporary Equity
Holding percentage of outstanding common stock to elect director					5.00%
Preferred Stock Purchase Agreement | Redeemable Convertible Preferred Stock
Temporary Equity
Proceeds from the issuance of preferred stock				$ 435,000
Preferred stock, shares issued | shares				435,000
Preferred equity, initial accreted value, per share | $ / shares	$ 1,024			$ 1,000
Preferred stock, dividend rate percentage					6.00%
Preferred stock redemption date					Jun. 30, 2022
Preferred Stock Purchase Agreement | Redeemable Convertible Preferred Stock | December 30, 2019 Anniversary
Temporary Equity
Percentage of preferred stock conversion price					130.00%
Number of trading days required for conversion					25 days
Preferred Stock Purchase Agreement | Redeemable Convertible Preferred Stock | June 30, 2021 Anniversary
Temporary Equity
Percentage of preferred stock conversion price					140.00%
Number of trading days required for conversion					25 days
Preferred Stock Purchase Agreement | Redeemable Convertible Preferred Stock | June 30, 2023 Anniversary
Temporary Equity
Multiple percentage on preferred stock accreted value					112.00%
Preferred Stock Purchase Agreement | Redeemable Convertible Preferred Stock | June 30, 2024 Anniversary
Temporary Equity
Multiple percentage on preferred stock accreted value					109.00%
Preferred Stock Purchase Agreement | Redeemable Convertible Preferred Stock | After June 30, 2024 Anniversary
Temporary Equity
Multiple percentage on preferred stock accreted value					106.00%

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Preferred Stock - Schedule of Preferred Stock (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Changes in common shares
Paid-in-kind dividend	$ 2,243	$ 13,146
Beneficial conversion feature of preferred stock	(1,872)
Amortized beneficial conversion feature	1,872
Preferred Stock Purchase Agreement | Redeemable Convertible Preferred Stock
Changes in common shares
Beginning Balance	445,483	0
Issuance of preferred stock in connection with the Acquisition		435,000
Costs incurred related to the issuance of preferred stock		(2,663)
Accrual of preferred stock paid-in-kind dividend		13,146
Paid-in-kind dividend	2,243
Beneficial conversion feature of preferred stock	(1,872)
Amortized beneficial conversion feature	1,872
Ending Balance	$ 447,726	$ 445,483

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Preferred Stock - Quarterly cash dividends (Details) - USD ($)					1 Months Ended			12 Months Ended
	Jan. 31, 2019	Jan. 31, 2018	Oct. 31, 2017	Jul. 31, 2017	Oct. 31, 2018	Jul. 31, 2018	Apr. 30, 2018	Dec. 31, 2018
Temporary Equity
Amortized beneficial conversion feature								$ 1,872,000
Preferred stock dividend paid								$ 20,267,000
Redeemable Convertible Preferred Stock
Temporary Equity
Quarterly dividend, amount		$ 6,656,000	$ 6,558,000
Beneficial conversion feature		$ 1,900,000
Dividend, date paid		Jan. 31, 2018	Oct. 31, 2017
Dividend, record date		Jan. 15, 2018	Oct. 15, 2017
Redeemable Convertible Preferred Stock | Dividend Payment In Kind
Temporary Equity
Quarterly dividend announced date				Jul. 31, 2017
Quarterly dividend, amount				$ 2,175,000
Dividend, record date				Jul. 15, 2017
Redeemable Convertible Preferred Stock | Cash Dividend
Temporary Equity
Preferred stock dividend paid					$ 6.756	$ 6.756	$ 6.756
Dividend, date paid					Oct. 31, 2018	Jul. 31, 2018	Apr. 30, 2018
Dividend, record date					Oct. 15, 2018	Jul. 15, 2018	Apr. 15, 2018
Redeemable Convertible Preferred Stock | Cash Dividend | Subsequent Event
Temporary Equity
Preferred stock dividend paid	$ 6.831
Dividend, date paid	Jan. 31, 2019
Dividend, record date	Jan. 15, 2019

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Equity - Additional Information (Details) - USD ($) $ / shares in Units, $ in Thousands			12 Months Ended
	Jun. 30, 2017	Jan. 17, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2018
Changes in common shares
Common stock, shares authorized			500,000,000		500,000,000
Common stock, par value			$ 0.01		$ 0.01
Issued and sold of initial public offering				27,500,000
Common stock offering price		$ 15.00
Proceeds from exercise of over-allotment		$ 32,600
Capital contributions				$ 107,837
Previous Owner
Changes in common shares
Capital contributions				97,000
Predecessor
Changes in common shares
Capital contributions				$ 10,837
Promissory note advances to fund future capital commitments and carried an interest rate				2.50%
KKR
Changes in common shares
Business acquisition, shares issued	5,518,125
Business acquisition, value of shares issued	$ 60,800
Common Stock
Changes in common shares
Issued and sold of initial public offering		2,297,100	7,815,225

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Equity - Summary of Changes in Common Shares Issued (Details) - USD ($) $ in Thousands			12 Months Ended
	Jan. 17, 2017	Dec. 19, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Changes in common shares
Common stock issued					27,500,000
Payments for employee withholding taxes			$ 6,894	$ 564
Rosewood Acquisition
Changes in common shares
Shares of common stock issued with corporate reorganization and acquisition		1,308,427
Common Stock
Changes in common shares
Balance, Beginning of Period			101,137,277	91,680,441
Common stock issued	2,297,100			7,815,225
Restricted common stock issued			1,076,165	1,676,284
Restricted common stock forfeited			(63,768)	(717)
Repurchase of vested restricted shares			(355,819)	(33,956)
Balance, End of Period			101,793,855	101,137,277	91,680,441

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Equity - Summary of Advances and Payments of Promissory Note Advances (Details) - Predecessor	12 Months Ended
	Dec. 31, 2016 USD ($)
Changes in common shares
Beginning balance	$ 2,443
Advances	101
Payments	(20)
Accrued Interest	51
Dissolution	(2,575)
Principal
Changes in common shares
Beginning balance	2,367
Advances	101
Payments	(20)
Dissolution	(2,448)
Interest
Changes in common shares
Beginning balance	76
Advances	0
Accrued Interest	51
Dissolution	$ (127)

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Earnings Per Share - Schedule of Calculation of Earnings (Loss) Per Share, or EPS (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Numerator:
Net income (loss) available to WRD									$ 146,508	$ 49,880	$ (10,397)
Less: Preferred stock dividends	$ 6,756	$ 6,756	$ 7,961	$ 7,389	$ 6,623	$ 6,450	$ 73	$ 0	28,862	13,146
Less: Undistributed earnings allocated to participating securities									30,344	5,612
Net income (loss) available to common stockholders	$ 228,986	$ 3,534	$ (22,055)	$ (123,163)	$ 2,218	$ (17,254)	$ 25,906	$ 20,252	$ 87,302	$ 31,122	$ (10,397)
Denominator:
Weighted-average common shares outstanding									99,498	96,324	91,327
Basic	$ 1.92	$ 0.04	$ (0.22)	$ (1.24)	$ 0.06	$ (0.17)	$ 0.28	$ 0.22	$ 0.88	$ 0.32	$ (0.11)
Diluted	$ 1.92	$ 0.04	$ (0.22)	$ (1.24)	$ 0.06	$ (0.17)	$ 0.28	$ 0.22	$ 0.88	$ 0.32	$ (0.11)

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Earnings Per Share - Schedule of Calculation of Earnings (Loss) Per Share, or EPS Additional Information (Details) - shares shares in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Antidilutive Securities Excluded From Computation Of Earnings Per Share
Shares excluded in calculation of diluted EPS	32,363	16,008
Restricted Stock
Antidilutive Securities Excluded From Computation Of Earnings Per Share
Shares excluded in calculation of diluted EPS	775	628

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Long Term Incentive Plans - Additional Information (Details) - 2016 Long-Term Incentive Plan - Restricted Stock - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Share Based Compensation Arrangement By Share Based Payment Award
Aggregate grant date fair value	$ 27.5	$ 23.3
Grant date market price	$ 25.57	$ 13.88	$ 14.50
Common stock authorized for issuance under plan	9,512,500
Recognized compensation expense	$ 19.5	$ 6.6
Unrecognized compensation cost	$ 28.7
Unrecognized compensation cost, weighted-average period	2 years
Minimum
Share Based Compensation Arrangement By Share Based Payment Award
Grant date market price	$ 18.14	$ 10.91
Vesting period	1 year
Maximum
Share Based Compensation Arrangement By Share Based Payment Award
Grant date market price	$ 27.07	$ 14.22
Vesting period	3 years
Recognized compensation expense			$ 0.1

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Long Term Incentive Plans - Summary of Restricted Common Stock Awards Granted Under 2016 LTIP (Details) - 2016 Long-Term Incentive Plan - Restricted Stock - $ / shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Number of Shares
Restricted common shares outstanding, Beginning Balance	1,897,790	353,334
Restricted commons shares, Granted	1,076,165	1,676,284	353,334
Restricted commons shares, Forfeited	(63,768)	(717)
Restricted commons shares, Vested	(1,069,933)	(131,111)
Restricted common shares outstanding, Ending Balance	1,840,254	1,897,790	353,334
Weighted Average Grant Date Fair Value per Share
Restricted common stock outstanding, Weighted-Average Grant Date Fair Value per Share, Beginning Balance	$ 13.95	$ 14.50
Restricted common shares, Granted, Weighted-Average Grant Date Fair Value per Share	25.57	13.88	$ 14.50
Restricted common shares, Forfeited, Weighted-Average Grant Date Fair Value per Share	16.45	13.94
Restricted common shares, Vested, Weighted-Average Grant Date Fair Value per Share	15.66	14.50
Restricted common stock outstanding, Weighted-Average Grant Date Fair Value per Share, Ending Balance	$ 19.66	$ 13.95	$ 14.50

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Incentive Units - Additional Information (Detail) - USD ($) $ in Thousands		12 Months Ended
	May 14, 2018	Dec. 31, 2018
Share Based Compensation Arrangement By Share Based Payment Award
Incentive unit compensation expense		$ 13,776
Contribution related to incentive unit compensation expense		$ 13,776
Esquisto Holdings | Incentive Award Units
Share Based Compensation Arrangement By Share Based Payment Award
Stock distribution	500,932

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Related Party Transactions - Additional Information (Details) $ in Millions		12 Months Ended
	Jan. 17, 2017 shares	Dec. 31, 2018 USD ($) director	Dec. 31, 2017 USD ($) shares	Dec. 31, 2016 USD ($) shares	Jun. 30, 2017 shares
Related Party Transactions
Issued and sold of initial public offering | shares				27,500,000
Initial offering lock-up period		180 days
Anticipated aggregate common stock offering price		$ 75.0
Common Stock
Related Party Transactions
Issued and sold of initial public offering | shares	2,297,100		7,815,225
Carlyle Group, L.P.
Related Party Transactions
Percentage of carried interest income to be allocated to Partnership for future interests in future carry funds		55.00%
WildHorse Holdings, Esquisto Holdings, and Acquisition Co. Holdings | Wildhorse Resource Development Corporation | Minimum
Related Party Transactions
Common stock ownership percentage		15.00%
WildHorse Holdings, Esquisto Holdings, and Acquisition Co. Holdings | Wildhorse Resource Development Corporation | Stockholders Agreement One | Minimum
Related Party Transactions
Common stock ownership percentage		50.00%
WildHorse Holdings, Esquisto Holdings, and Acquisition Co. Holdings | Wildhorse Resource Development Corporation | Stockholders Agreement Two | Minimum
Related Party Transactions
Common stock ownership percentage		35.00%
WildHorse Holdings, Esquisto Holdings, and Acquisition Co. Holdings | Wildhorse Resource Development Corporation | Stockholders Agreement Two | Maximum
Related Party Transactions
Common stock ownership percentage		50.00%
WildHorse Holdings, Esquisto Holdings, and Acquisition Co. Holdings | Wildhorse Resource Development Corporation | Stockholders Agreement Three | Minimum
Related Party Transactions
Common stock ownership percentage		15.00%
WildHorse Holdings, Esquisto Holdings, and Acquisition Co. Holdings | Wildhorse Resource Development Corporation | Stockholders Agreement Three | Maximum
Related Party Transactions
Common stock ownership percentage		35.00%
WildHorse Holdings, Esquisto Holdings, and Acquisition Co. Holdings | Wildhorse Resource Development Corporation | Stockholders Agreement Four | Minimum
Related Party Transactions
Common stock ownership percentage		5.00%
WildHorse Holdings, Esquisto Holdings, and Acquisition Co. Holdings | Wildhorse Resource Development Corporation | Stockholders Agreement Four | Maximum
Related Party Transactions
Common stock ownership percentage		15.00%
WildHorse Holdings, Esquisto Holdings, and Acquisition Co. Holdings | Wildhorse Resource Development Corporation | Stockholders Agreement Five | Maximum
Related Party Transactions
Common stock ownership percentage		5.00%
Genesis Energy Partners, L.P
Related Party Transactions
Proceeds from sale of hydrocarbons and other liquids		$ 1.2	$ 2.2
Cretic Energy Services, LLC | Drilling and Completion Activities
Related Party Transactions
Payments made to related party		0.0	0.2
Affiliate of Carlyle Group
Related Party Transactions
Preferred stock, shares issued | shares					435,000
CH4 Energy
Related Party Transactions
Payments made to related party		0.2	0.5
CH4 Energy | Corporate Reorganization
Related Party Transactions
Leasehold Interests		0.1
CH4 Energy | Office Rental and Parking
Related Party Transactions
Payments made to related party			0.2
CH4 Energy | Landman Services and Expenses Incurred in 2016
Related Party Transactions
Payments made to related party				$ 0.3
Archrock Inc.
Related Party Transactions
Payments made to related party		$ 0.1
NGP ECM | Director and Advisory Fees and Reimbursement of IPO Costs | Maximum
Related Party Transactions
Related party payments (receipts), net			$ 0.2
NGP ECM | NGP X US Holdings
Related Party Transactions
Percentage of carried interest income to be allocated to Partnership for future interests in future carry funds		40.00%
NGP ECM | NGP XI
Related Party Transactions
Percentage of carried interest income to be allocated to Partnership for future interests in future carry funds		47.50%
WHR II | Corporate Reorganization | Common Stock
Related Party Transactions
Issued and sold of initial public offering | shares				21,200,084
Esquisto Holdings | Corporate Reorganization | Common Stock
Related Party Transactions
Issued and sold of initial public offering | shares				38,755,330
Acquisitions Co. | Corporate Reorganization | Common Stock
Related Party Transactions
Issued and sold of initial public offering | shares				2,563,266
Wild Horse Holdings And Esquisto Holdings
Related Party Transactions
Number of Board of Directors nominees each | director		1
Wild Horse Holdings And Esquisto Holdings | Stockholders Agreement One
Related Party Transactions
Number of Board of Directors nominees each | director		3
Wild Horse Holdings And Esquisto Holdings | Stockholders Agreement Two
Related Party Transactions
Number of Board of Directors nominees each | director		2
Wild Horse Holdings And Esquisto Holdings | Stockholders Agreement Three
Related Party Transactions
Number of Board of Directors nominees each | director		1
Wild Horse Holdings And Esquisto Holdings | Stockholders Agreement Four
Related Party Transactions
Number of Board of Directors nominees each | director		1

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Segment Disclosures - Additional Information (Details) - segment		12 Months Ended
	Mar. 29, 2018	Dec. 31, 2018
Segment Reporting [Abstract]
Number of operating segments	2	1
Number of reportable segments	1	1

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Segment Disclosures - Major Customers (Details) - Customer Concentration Risk - Sales Revenue, Segment	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Energy Transfer Equity LP. and Subsidiaries
Concentration risk percentage	49.00%	56.00%	63.00%
Koch Industries, Inc.
Concentration risk percentage	19.00%	4.00%
Royal Dutch Shell Plc and Subsidiaries
Concentration risk percentage	18.00%	21.00%	12.00%
Cima Energy Ltd.
Concentration risk percentage			15.00%

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Income Taxes - Additional Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Tax Contingency [Line Items]
Federal statutory tax rate	21.00%	35.00%	35.00%
Liability for unrecognized tax benefits	$ 0
Disallowed business interest deduction carryforward	47,600
Valuation allowance	1,820
Domestic Tax Authority [Member]
Income Tax Contingency [Line Items]
Income tax operating loss carry forward	218,000
Portion of income tax operating loss carry forward with no expiration	$ 65,900
Domestic Tax Authority [Member] | Earliest Tax Year
Income Tax Contingency [Line Items]
Income tax operating loss carry forward expiration year	Dec. 31, 2036
Domestic Tax Authority [Member] | Latest Tax Year
Income Tax Contingency [Line Items]
Income tax operating loss carry forward expiration year	Dec. 31, 2037
State and Local Jurisdiction [Member]
Income Tax Contingency [Line Items]
Income tax operating loss carry forward	$ 28,800
Valuation allowance	$ 1,800
State and Local Jurisdiction [Member] | Earliest Tax Year
Income Tax Contingency [Line Items]
Income tax operating loss carry forward expiration year	Dec. 31, 2036
State and Local Jurisdiction [Member] | Latest Tax Year
Income Tax Contingency [Line Items]
Income tax operating loss carry forward expiration year	Dec. 31, 2038

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Income Taxes - Components of Income Tax Benefit (Expense) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Current income taxes:
Federal	$ (997)	$ 997
State		10
Total current income tax expense (benefit)	(997)	1,007
Deferred income taxes:
Federal	43,143	(40,529)	$ (5,737)
State	(1,950)	698	162
Total deferred income tax expense (benefit)	41,193	(39,831)	(5,575)
Total income tax expense (benefit)	$ 40,196	$ (38,824)	$ (5,575)

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Income Taxes - Schedule of Effective Income Tax Rate Reconciliation (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income tax expense benefit continuing operations income tax reconciliation
Expected tax expense (benefit) at federal statutory rate		$ 39,208	$ 3,870	$ (18,428)
State income tax expense (benefit), net of federal benefit		(3,360)	460	105
Pass-through entities				12,499
Incentive unit compensation		2,893
Stock-based compensation		(1,070)
Valuation allowance		1,820		234
Change in tax rate	$ (43,400)		(43,431)
Change in prior period estimates		24	315
Other		681	(38)	15
Total income tax expense (benefit)		$ 40,196	$ (38,824)	$ (5,575)
Federal statutory tax rate		21.00%	35.00%	35.00%

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Income Taxes - Components of Net Deferred Income Tax Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Deferred income tax assets:
Net operating loss carryforwards	$ 47,609	$ 29,866
Disallowed business interest deduction carryforward	9,992
Minimum tax credit carryforward		997
Asset retirement obligation	1,796	3,311
Derivatives		16,903
Other	3,860	2,153
Total deferred income tax assets	63,257	53,230
Valuation allowance	(1,820)
Net deferred income tax assets	61,437	53,230
Deferred income tax liabilities:
Property, plant and equipment	158,868	124,700
Derivatives	15,300
Total deferred income tax liabilities	174,168	124,700
Net deferred income tax liabilities	$ 112,731	$ 71,470

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Commitments and Contingencies - Additional Information (Details) $ in Thousands				12 Months Ended
	Aug. 02, 2018 director	Jun. 01, 2017 USD ($) item	Mar. 15, 2017 USD ($) item	Dec. 31, 2018 USD ($) lease acre ft	Dec. 31, 2017 USD ($) agreement	Dec. 31, 2016 USD ($)
Commitments and contingencies
North Louisiana Settlement					$ (7,000)
Income tax benefit (expense)				$ (40,196)	38,824	$ 5,575
North Louisiana Settlement receivable					$ 5,955
Dedicated Fracturing Fleet Services Agreements
Commitments and contingencies
Number of agreements entered for completion of wells and drilling operations | agreement					2
Term of agreement for completion of wells and drilling operations		23 months	20 months
Additional term of agreement for completion of wells and drilling operations		12 months	12 months
Fixed monthly service fee for cost of equipment and personnel		$ 2,800	$ 2,700
Minimum number of stages to be completed for milestone payments | item		115	360
Percentage of amount payable in excess of chemicals and fuel cost		10.00%	10.00%
Early termination fee, description					approximately $1.4 million times the number of months remaining under the initial term of the contract would be payable on such termination date
Early termination fee, approximate multiplier to number of months remaining under initial contract term		$ 1,400	$ 1,400
Interruptible Water Availability Agreement
Commitments and contingencies
Interruptible water availability agreement, start date				Feb. 01, 2017
Interruptible water availability agreement, end date				Dec. 31, 2021
Aggregate of acre-feet of water per year | acre ft				6,978
Agreement payment				$ 500	$ 400
Office Leases
Commitments and contingencies
Rent expense				$ 800	1,000	900
Period after which lease can be terminated penalty-free				2 years
Number of leases executed | lease				2
Compressors
Commitments and contingencies
Rent expense				$ 5,400	2,000	$ 600
Maximum | Drilling Services Agreements
Commitments and contingencies
Term of agreement for completion of wells and drilling operations				1 year
Maximum | Compressors
Commitments and contingencies
Lease term				13 months
Klein v. Graham, et al
Commitments and contingencies
Number of directors named in legal action | director	7
Number of former directors named in a legal action | director	1
North Louisiana Settlement
Commitments and contingencies
North Louisiana Settlement					7,000
Income tax benefit (expense)					$ 1,600
Settlement receivable collected				$ 5,900

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Commitments and Contingencies - Schedule of Future Minimum Lease Obligation (Detail) $ in Thousands	Dec. 31, 2018 USD ($)
Operating Leased Assets
Operating Leases, Future Minimum Payments, Due 2019	$ 32,597
Operating Leases, Future Minimum Payments, Due 2020	9,862
Operating Leases, Future Minimum Payments, Due 2021	6,257
Operating Leases, Future Minimum Payments, Due 2022	4,940
Operating Leases, Future Minimum Payments, Due 2023	3,153
Office Lease
Operating Leased Assets
Operating Leases, Future Minimum Payments, Due 2019	2,399
Operating Leases, Future Minimum Payments, Due 2020	2,435
Operating Leases, Future Minimum Payments, Due 2021	2,398
Operating Leases, Future Minimum Payments, Due 2022	2,216
Operating Leases, Future Minimum Payments, Due 2023	2,251
Dedicated Fracturing Fleet Services Agreements
Operating Leased Assets
Operating Leases, Future Minimum Payments, Due 2019	21,000
Sand Mine Equipment
Operating Leased Assets
Operating Leases, Future Minimum Payments, Due 2019	5,055
Operating Leases, Future Minimum Payments, Due 2020	3,436
Compressors
Operating Leased Assets
Operating Leases, Future Minimum Payments, Due 2019	4,143
Operating Leases, Future Minimum Payments, Due 2020	3,991
Operating Leases, Future Minimum Payments, Due 2021	3,859
Operating Leases, Future Minimum Payments, Due 2022	2,724
Operating Leases, Future Minimum Payments, Due 2023	$ 902

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Quarterly Financial accounting (Detail) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Revenues	$ 243,726	$ 259,490	$ 225,413	$ 218,757	$ 180,236	$ 122,486	$ 70,173	$ 54,292	$ 947,386	$ 427,187	$ 127,342
Operating income (loss)	88,196	122,776	101,370	(100,053)	64,582	32,599	2,078	6,206	212,289	105,465	(16,228)
Net income (loss)	264,853	11,523	(14,094)	(115,774)	14,066	(10,804)	26,366	20,252	146,508	49,880	(47,076)
Preferred stock dividends	6,756	6,756	7,961	7,389	6,623	6,450	73	0	28,862	13,146
Net income (loss) available to common stockholders	$ 228,986	$ 3,534	$ (22,055)	$ (123,163)	$ 2,218	$ (17,254)	$ 25,906	$ 20,252	$ 87,302	$ 31,122	$ (10,397)
Basic earnings (loss) per share	$ 1.92	$ 0.04	$ (0.22)	$ (1.24)	$ 0.06	$ (0.17)	$ 0.28	$ 0.22	$ 0.88	$ 0.32	$ (0.11)
Diluted earnings (loss) per share	$ 1.92	$ 0.04	$ (0.22)	$ (1.24)	$ 0.06	$ (0.17)	$ 0.28	$ 0.22	$ 0.88	$ 0.32	$ (0.11)
Deferred tax benefit - change in tax rate					$ 43,400					$ 43,431

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Supplemental Oil and Gas Information - Proved Reserves, Prices (Detail)	12 Months Ended
	Dec. 31, 2018 $ / MMBTU $ / bbl	Dec. 31, 2017 $ / MMBTU $ / bbl	Dec. 31, 2016 $ / MMBTU $ / bbl
Oil
Price of oil and gas	65.56	51.34	42.75
Natural gas liquid sales
Price of oil and gas	65.56	51.34	42.75
Natural Gas
Price of oil and gas | $ / MMBTU	3.10	2.98	2.48

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Supplemental Oil and Gas Information - Estimates of Net Reserves (Detail)	12 Months Ended
	Dec. 31, 2018 MBoe MMcf MBbls	Dec. 31, 2017 MBoe MMcf MBbls	Dec. 31, 2016 MBoe MMcf MBbls
Reserve Quantities
Beginning of the year | MBoe	454,315	152,505	103,040
Extensions, discoveries and additions | MBoe	119,211	162,559	26,940
Purchase of minerals in place | MBoe	757	70,593	30,916
Sales of minerals in place | MBoe	(67,180)
Production | MBoe	(18,316)	(11,222)	(5,289)
Revision of previous estimates | MBoe	(82,737)	79,880	(3,102)
End of year | MBoe	406,050	454,315	152,505
Proved developed reserves, Beginning of year | MBoe	114,495	47,270	33,570
Proved developed reserves, End of year | MBoe	95,356	114,495	47,270
Proved undeveloped reserves, Beginning of year | MBoe	339,820	105,235	69,470
Proved undeveloped reserves, End of year | MBoe	310,694	339,820	105,235
Oil
Reserve Quantities
Beginning of the year	282,798	87,447	36,650
Extensions, discoveries and additions	81,174	93,454	18,870
Purchase of minerals in place	520	59,169	26,835
Sales of minerals in place	(1,272)
Production	(12,585)	(6,606)	(1,848)
Revision of previous estimates	(65,369)	49,334	6,940
End of year	285,266	282,798	87,447
Proved developed reserves, Beginning of year	65,023	19,192	7,503
Proved developed reserves, End of year	66,398	65,023	19,192
Proved undeveloped reserves, Beginning of year	217,775	68,255	29,147
Proved undeveloped reserves, End of year	218,868	217,775	68,255
Natural Gas
Reserve Quantities
Beginning of the year | MMcf	683,808	325,102	344,959
Extensions, discoveries and additions | MMcf	129,962	279,368	32,782
Purchase of minerals in place | MMcf	727	28,106	13,545
Sales of minerals in place | MMcf	(393,057)
Production | MMcf	(21,531)	(20,463)	(17,820)
Revision of previous estimates | MMcf	(21,736)	71,695	(48,364)
End of year | MMcf	378,173	683,808	325,102
Proved developed reserves, Beginning of year | MMcf	221,517	145,880	142,990
Proved developed reserves, End of year | MMcf	88,936	221,517	145,880
Proved undeveloped reserves, Beginning of year | MMcf	462,291	179,222	201,969
Proved undeveloped reserves, End of year | MMcf	289,237	462,291	179,222
Natural gas liquid sales
Reserve Quantities
Beginning of the year	57,550	10,874	8,897
Extensions, discoveries and additions	16,377	22,545	2,606
Purchase of minerals in place	116	6,740	1,823
Sales of minerals in place	(398)
Production	(2,143)	(1,206)	(471)
Revision of previous estimates	(13,747)	18,597	(1,981)
End of year	57,755	57,550	10,874
Proved developed reserves, Beginning of year	12,553	3,765	2,235
Proved developed reserves, End of year	14,135	12,553	3,765
Proved undeveloped reserves, Beginning of year	44,997	7,109	6,662
Proved undeveloped reserves, End of year	43,620	44,997	7,109

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Supplemental Oil and Gas Information - Categorical Information on Estimates of Net Reserves (Detail) - MBoe	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Reserve Quantities
Extensions, discoveries and additions	119,211	162,559	26,940
Sales of minerals in place	(67,180)
Production	18,316	11,222	5,289
Purchase of minerals in place	757	70,593	30,916
Revision of previous estimates	(82,737)	79,880	(3,102)
Commodity Price Changes
Reserve Quantities
Revision of previous estimates	4,216	7,461	(711)
Performance Related
Reserve Quantities
Revision of previous estimates	(86,953)	72,419	(2,391)
North Louisiana
Reserve Quantities
Extensions, discoveries and additions		20,313
Sales of minerals in place	(67,180)
Production	18,316
Eagle Ford
Reserve Quantities
Extensions, discoveries and additions		142,246	22,809
RCT field in Louisiana
Reserve Quantities
Extensions, discoveries and additions			4,131
APC/KKR Acquisitions
Reserve Quantities
Purchase of minerals in place		70,593
Burleson North Acquisition
Reserve Quantities
Purchase of minerals in place			30,916

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Supplemental Oil and Gas Information (Unaudited) - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2018
Extractive Industries
Additional Information Necessary to Prevent Disclosure of Discounts Future Net Cash Flows from Being Misleading	As required by the FASB and SEC, the standardized measure of discounted future net cash flows presented below is computed by applying first-day-of-the-month average prices, year-end costs and legislated tax rates and a discount factor of 10 percent to proved reserves

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Supplemental Oil and Gas Information - Standardized Measure of Discounted Future Net Cash Flows (Detail) - USD ($)	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Oil And Gas Exploration And Production Industries Disclosures
Future cash inflows	$ 21,269,502	$ 16,967,369	$ 4,434,117
Future production costs	(3,440,203)	(3,305,941)	(1,220,067)
Future development costs	(5,168,271)	(4,008,916)	(1,146,632)
Future income tax expense	(2,398,612)	(1,814,510)	(442,285)
Future net cash flows for estimated timing of cash flows	10,262,416	7,838,002	1,625,133
10% annual discount for estimated timing of cash flows	(6,144,980)	(4,994,097)	(1,082,092)
Standardized measure of discounted future net cash flows	$ 4,117,436	$ 2,843,905	$ 543,041	$ 451,930

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Supplemental Oil and Gas Information - Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Principal Sources Of Change In Standardized Measure Of Discounted Future Net Cash Flow Relating To Proved Oil And Gas Reserves
Beginning of year	$ 2,843,905	$ 543,041	$ 451,930
Sale of oil and natural gas produced, net of production costs	(822,471)	(351,031)	(104,596)
Purchase of minerals in place	4,313	507,095	188,317
Sales of minerals in place	(319,858)
Extensions and discoveries	1,829,564	1,595,385	168,796
Changes in income taxes, net	(277,050)	(488,484)	(206,817)
Changes in prices and costs	1,380,323	398,713	(57,034)
Previously estimated development costs incurred	67,575	49,977	15,067
Net changes in future development costs	(13,317)	(87,375)	11,985
Revisions of previous quantities	(1,057,523)	653,567	3,943
Accretion of discount	323,927	74,999	103,000
Change in production rates and other	158,048	(51,982)	(31,550)
End of year	$ 4,117,436	$ 2,843,905	$ 543,041

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Supplemental Oil and Gas Information - Capitalized Costs Relating to Oil and Natural Gas Producing Activities (Detail) - USD ($)	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area
Accumulated depletion, depreciation and amortization	$ (498,811)	$ (362,406)	$ (196,567)
Total	2,959,087	2,637,322	1,377,281
Evaluated
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area
Evaluated/Unevaluated oil and natural gas properties	2,764,875	2,265,525	1,144,857
Unevaluated
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area
Evaluated/Unevaluated oil and natural gas properties	$ 693,023	$ 734,203	$ 428,991

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Supplemental Oil and Gas Information - Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Oil And Gas Exploration And Production Industries Disclosures
Property acquisition costs, proved	$ 4,422	$ 269,429	$ 230,910
Property acquisition costs, unproved	85,863	386,515	235,652
Exploration and extension well costs	11,979	16,076	72,875
Development	927,985	795,273	63,006
Total	$ 1,030,249	$ 1,467,293	$ 602,443

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Subsequent Events (Details) - Subsequent Event - USD ($) shares in Millions, $ in Millions		1 Months Ended
	Feb. 01, 2019	Feb. 28, 2019
Subsequent Events
Financial advisory fees	$ 23.1
WRD Revolving Credit Facility | 6.875% Senior Unsecured Notes, Due February 2025
Subsequent Events
Period after the consumation of the merger during which, if the senior notes are downgraded, constitutes a change in control	90 days
Percent of principal amount that is required to be offered to repurchase the notes	101.00%
Period after downgrade of notes that an offer to repurchase must be made	30 days
Chesapeake | Wildhorse Resource Development Corporation
Subsequent Events
Business acquisition, shares issued		717.3
Cash paid		$ 381.1