424B3

Terms of the New 6.875% Senior Notes due 2025 Offered in the Exchange Offer:

You should carefully consider the risk factors beginning on page 7 of this prospectus before participating in the exchange offer.

We are not asking you for a proxy and you are requested not to send us a proxy.

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

This prospectus is part of a registration statement we filed with the Securities and Exchange Commission. In making your investment decision, you should rely only on the information contained in this prospectus and in the accompanying letter of transmittal. We have not authorized anyone to provide you with any other information. We are not making an offer to sell these securities or soliciting an offer to buy these securities in any jurisdiction where an offer or solicitation is not authorized or in which the person making that offer or solicitation is not qualified to do so or to anyone whom it is unlawful to make an offer or solicitation. You should not assume that the information contained in this prospectus is accurate as of any date other than its respective date.

This prospectus refers to important business and financial information about WildHorse Resource Development Corporation that is not included or delivered with this prospectus. Such information is available without charge to holders of old notes upon written or oral request made to the office of WildHorse Resource Development Corporation, 9805 Katy Freeway, Suite 400, Houston, Texas 77024 (Telephone: (713) 568-4910). To obtain timely delivery of any requested information, holders of old notes must make any request no later than November 3, 2017 which is five business days prior to the expiration of the exchange offer.

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

The information in this prospectus includes “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 prospectus, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this prospectus, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on management’s current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading “Risk Factors” included in this prospectus.

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

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

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

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

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

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 elsewhere in this prospectus (i)(a) as of, and for the year ended, December 31, 2016, and (b) as of December 31, 2015, and for the period from February 17, 2015 (the inception of common control) to December 31, 2015, have been derived from the combined financial position and results attributable to our predecessor and Esquisto for periods prior to our initial public offering, (ii)(a) for the period from January 1, 2015 to February 16, 2015, and (b) as of, and for the year ended December 31, 2014, have been derived from the financial position and results attributable to our predecessor and (iii) for the six months ended June 30, 2016 have been derived from the combined financial position and results attributable to our predecessor and Esquisto; furthermore, the results of Acquisition Co. are reflected in the financial data presented herein beginning on December 19, 2016. For periods after the completion of our initial public offering, our consolidated financial statements include our accounts and those of our subsidiaries.

The comparability of the results of operations among the periods presented is impacted by (i) combining the financial position and results of operations of Esquisto with the predecessor beginning February 17, 2015; (ii) public company expenses incurred in connection with our initial public offering, the Corporate Reorganization and incremental general and administrative expenses as a result of being a publicly traded company; (iii) Esquisto’s third-party acquisition of certain oil and natural gas producing properties, undeveloped acreage and water assets located in the Eagle Ford in July 2015 for a purchase price of $103.0 million, net of customary post-closing adjustments; (iv) the Burleson North Acquisition for a final purchase price of $385.9 million, net of customary post-closing adjustments; (v) increases in our drilling programs; and (vi) the issuance of the old notes on February 1, 2017. As a result of these factors, the consolidated and combined historical results of operations and period-to-period comparisons of these results and certain financial data included in this prospectus may not be comparable or indicative of future results.

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

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

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

PROSPECTUS SUMMARY

This summary highlights information contained elsewhere in this prospectus. You should read the entire prospectus carefully before making an investment decision, including the information under the headings “Risk Factors,” “Cautionary Statement Regarding Forward-Looking Statements” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the historical and unaudited pro forma financial statements and the related notes thereto appearing elsewhere in this prospectus. Certain commonly used terms are defined in “Commonly Used Defined Terms” or in the glossary included in this prospectus as Annex B.

Unless context otherwise requires, in this prospectus, we refer to (i) the notes to be issued in the exchange offer as the “new notes,”(ii) the notes issued on February 1 and September 19, 2017 collectively as the “old notes,” (iii) the new notes and the old notes collectively as the “notes” or the “2025 Senior Notes” and (iv) the indenture governing the notes, dated February 1, 2017, as supplemented, among the Company, the subsidiary guarantors named therein and U.S. Bank National Association, as trustee, as the “indenture.”

WildHorse Resource Development Corporation

WildHorse Resource Development Corporation is a Delaware corporation, the common shares of which are listed on the New York Stock Exchange (“NYSE”) under the symbol “WRD.” We are an independent oil and natural gas company focused on the acquisition, exploitation, development and production of oil, natural gas and NGL resources.

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

Risk Factors

Investing in the notes involves substantial risks. You should carefully consider all the information contained in this prospectus prior to participating in the exchange offer. In particular, we urge you to consider carefully the factors set forth under “Risk Factors” beginning on page 7 of this prospectus.

The Exchange Offer

On February 1 and September 19, 2017, we completed private offerings of the old notes. In connection with each offering, we entered into a registration rights agreement with the initial purchasers in which we agreed to deliver to you this prospectus and to use our reasonable best efforts to complete the exchange offer on or prior to February 1, 2018 (such agreements together, the “registration rights agreement”).

Exchange Offer

We are offering to exchange the new notes for the old notes.

Expiration Date

The exchange offer will expire at 5:00 p.m., New York City time, on November 13, 2017, unless we decide to extend it.

Condition to the Exchange Offer

The registration rights agreement does not require us to accept old notes for exchange if the exchange offer, or the making of any exchange by a holder of the old notes, would violate any applicable law or interpretation of the staff of the Securities and Exchange Commission. The exchange offer is not conditioned on a minimum aggregate principal amount of old notes being tendered.

Procedures for Tendering Old Notes

To participate in the exchange offer, you must follow the procedures established by The Depository Trust Company, which we call “DTC,” for tendering notes held in book-entry form. These procedures, which we call “ATOP,” require that (i) the exchange agent receive, prior to the expiration date of the exchange offer, a computer generated message known as an “agent’s message” that is transmitted through DTC’s automated tender offer program, and (ii) DTC confirms that:

•

DTC has received your instructions to exchange your notes, and

•

you agree to be bound by the terms of the letter of transmittal.

For more information on tendering your old notes, please refer to the section in this prospectus entitled “Exchange Offer—Terms of the Exchange Offer,” “—Procedures for Tendering,” and “Description of Notes—Book-Entry, Delivery and Form.”

Guaranteed Delivery Procedures

None.

Withdrawal of Tenders

You may withdraw your tender of old notes at any time prior to the expiration date. To withdraw, you must submit a notice of withdrawal to the exchange agent using ATOP procedures before 5:00 p.m., New York City time, on the expiration date of the exchange offer. Please refer to the section in this prospectus entitled “Exchange Offer—Withdrawal of Tenders.”

Acceptance of Old Notes and Delivery of New Notes

If you fulfill all conditions required for proper acceptance of old notes, we will accept any and all old notes that you properly tender in the exchange offer on or before 5:00 p.m., New York City time, on

the expiration date. We will return any old notes that we do not accept for exchange to you without expense promptly after the expiration date and acceptance of the old notes for exchange. Please refer to the section in this prospectus entitled “Exchange Offer—Terms of the Exchange Offer.”

Fees and Expenses

We will bear the expenses related to the exchange offer. Please refer to the section in this prospectus entitled “Exchange Offer—Fees and Expenses.”

Use of Proceeds

The issuance of the new notes will not provide us with any new proceeds. We are making this exchange offer solely to satisfy our obligations under the registration rights agreement.

Consequences of Failure to Exchange Old Notes

If you do not exchange your old notes in this exchange offer, you will no longer be able to require us to register the old notes under the Securities Act except in limited circumstances provided under the registration rights agreement. In addition, you will not be able to resell, offer to resell or otherwise transfer the old notes unless we have registered the old notes under the Securities Act, or unless you resell, offer to resell or otherwise transfer them under an exemption from the registration requirements of, or in a transaction not subject to, the Securities Act.

U.S. Federal Income Tax Considerations

The exchange of new notes for old notes in the exchange offer will not be a taxable event for U.S. federal income tax purposes. Please read “Material United States Federal Income Tax Consequences.”

Exchange Agent

We have appointed U.S. Bank National Association as exchange agent for the exchange offer. You should direct questions and requests for assistance, as well as requests for additional copies of this prospectus or the letter of transmittal, to the exchange agent addressed as follows: U.S. Bank National Association, Global Corporate Trust Services, Attn: Specialized Finance, 111 Fillmore Ave. East, EP-MN-WS-2N, St. Paul, MN 55107. Eligible institutions may make requests by calling (800) 934-6802.

Terms of the New Notes

The new notes will be identical to the old notes except that the new notes are registered under the Securities Act and will not have restrictions on transfer, registration rights or provisions for additional interest. The new notes will evidence the same debt as the old notes, and the same indenture will govern the new notes and the old notes.

The following summary contains basic information about the new notes and is not intended to be complete. It does not contain all information that is important to you. For a more complete understanding of the new notes, please refer to the section of this document entitled “Description of Notes.”

Issuer

WildHorse Resource Development Corporation.

Notes Offered

$500,000,000 aggregate principal amount of 6.875% Senior Notes due 2025, registered under the Securities Act. The old notes and the new notes will be treated as a single class of securities under the indenture, including, without limitation, for purposes of waivers, amendments, redemptions and offers to purchase.

Maturity

February 1, 2025.

Interest

6.875% per year (calculated using a 360-day year).

Interest Payment Dates

February 1 and August 1 of each year. Interest on each new note will accrue from the last interest payment date on which interest was paid on the old note tendered in exchange thereof, or, if no interest has been paid on the old note, from the date of the original issue of the old note.

Ranking

Like the old notes, the new notes are our unsecured senior obligations. Accordingly, they rank:

•

equally in right of payment with all of our existing and future senior unsecured indebtedness;

•

effectively junior in right of payment to all of our existing and future secured indebtedness, including indebtedness under our revolving credit facility, to the extent of the value of the assets securing such indebtedness;

•

structurally junior to all indebtedness and other liabilities of any future non-guarantor subsidiaries; and

•

senior in right of payment to all of our future subordinated indebtedness.

Guarantees

All of our existing and certain of our future subsidiaries will fully and unconditionally and jointly and severally guarantee the new notes. If we cannot make payments on the new notes when they are due, the guarantors must make them instead. Please read “Description of Notes—Note Guarantees.”

Each guarantee will rank:

•

equally in right of payment with all of the applicable guarantor’s existing and future senior unsecured indebtedness;

•

effectively junior in right of payment to the applicable guarantor’s existing and future secured indebtedness, including its guarantee of indebtedness under our revolving credit facility, to the extent of the value of the assets securing such indebtedness; and

•

senior in right of payment to any future subordinated indebtedness of the guarantor.

Optional Redemption

The issuer will have the option to redeem all or a portion of the new notes, on any one or more occasions, on or after February 1, 2020, at the redemption prices described in this prospectus under the heading “Description of Notes—Optional Redemption,” together with any accrued and unpaid interest, if any, to the date of redemption. Prior to February 1, 2020, the issuer may, on any one or more occasions, redeem up to 35% of the aggregate principal amount of the new notes, in an amount not greater than the net cash proceeds of one or more equity offerings, at a redemption price of 106.875% of the principal amount thereof, plus any accrued and unpaid interest, if any, to the date of redemption, if at least 65% of the aggregate principal amount of the new notes remains outstanding immediately after such redemption and the redemption occurs within 180 days after the closing date of such equity offering. Further, prior to February 1, 2020, we may redeem all or a portion of the new notes, on any one or more occasions, at a redemption price equal to 100% of the principal amount of the new notes redeemed, plus the “make-whole” premium as of, and accrued interest and unpaid interest, if any, to the date of the redemption. Please read “Description of Notes—Optional Redemption.”

Change of Control

If certain change of control events occur, the holders of the new notes may have the right to require us to repurchase all or a portion of the new notes for cash at a price equal to 101% of the aggregate principal amount of such notes, plus accrued and unpaid interest, if any, to the date of repurchase.

Certain Covenants

The indenture governing the new notes contains covenants that limit, among other things, our ability and the ability of our restricted subsidiaries to:

•

pay dividends on, purchase or redeem our common stock or purchase or redeem subordinated debt;

•

make certain investments;

•

incur or guarantee additional indebtedness or issue certain types of preferred equity securities;

•

create or incur certain secured debt;

•

sell assets;

•

consolidate, merge or transfer all or substantially all of our assets;

•

enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us;

•

engage in transactions with affiliates; and

•

create unrestricted subsidiaries.

These covenants are subject to a number of important qualifications and limitations. In addition, most of the covenants will be terminated if the new notes are assigned an investment grade rating in the future and no default exists under the indenture governing the new notes. See “Description of Notes.”

Transfer Restrictions; Absence of a Public Market for the New Notes

The new notes generally will be freely transferable, but will also be new securities for which there will not initially be a market. There can be no assurance as to the development, maintenance or liquidity of any market for the new notes.

We do not intend to apply for a listing of the new notes on any securities exchange or any automated dealer quotation system.

Risk Factors

Investing in the new notes involves risks. See “Risk Factors” beginning on page 7 for a discussion of certain factors you should consider in evaluating whether or not to tender your old notes.

Investing in our notes involves risk. Before making an investment decision, you should carefully consider the risk factors discussed in this prospectus, together with all of the other information included in this prospectus or to which we refer you. If any of these risks were to occur, our business, financial condition or results of operations could be adversely affected. Additional risks and uncertainties not presently known to us or not believed by us to be material may also negatively impact us. Also, please read “Cautionary Statement Regarding Forward-Looking Statements” in this prospectus.

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

The prices we receive for our oil, natural gas and NGL production heavily influence our revenue, profitability, access to capital, future rate of growth and the carrying value of our properties. Oil, natural gas and NGLs are commodities, and their prices may fluctuate widely in response to market uncertainty and to relatively minor changes in the supply of and demand for oil, natural gas and NGLs. Historically, oil, natural gas and NGL prices have been volatile. For example, during the period from January 1, 2014 through September 25, 2017, the WTI spot price for oil declined from a high of $107.95 per Bbl on June 20, 2014 to a low of $26.19 per Bbl on February 11, 2016, and the Henry Hub spot price for natural gas has declined from a high of $8.15 per MMBtu on February 10, 2014 to a low of $1.49 per MMBtu on March 4, 2016. Likewise, NGLs, which are made up of ethane, propane, isobutane, normal butane and natural gasoline, each of which have different uses and different pricing characteristics, have suffered significant recent declines in realized prices. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control, which include the following:

In the second half of 2014, oil prices began a rapid and significant decline as the global oil supply began to outpace demand. During 2015 and 2016 and thus far in 2017, the global oil supply has continued to outpace demand, resulting in persistently low realized prices for oil production. In general, this imbalance between supply and demand reflects the significant supply growth achieved in the United States as a result of shale drilling and oil production increases by certain other countries, including Russia and Saudi Arabia, as part of an effort to retain market share, combined with only modest demand growth in the United States and less-than-expected demand in other parts of the world, particularly in Europe and China. Although there has been a dramatic decrease in drilling activity in the industry, oil storage levels in the United States remain at historically high levels. Until supply and demand balance and the overhang in storage levels begins to decline, prices will likely remain under pressure. The U.S. dollar has also strengthened relative to other leading currencies, which has caused oil prices to weaken, as they are U.S. dollar-denominated. In addition, the lifting of economic sanctions on Iran has resulted in increasing supplies of oil from Iran, adding further downward pressure to oil prices. NGL prices generally correlate to the price of oil. Also adversely affecting the price for NGLs is the supply of NGLs in the United States, which has continued to grow due to an increase in industry participants targeting projects that produce NGLs in recent years. Prices for domestic natural gas began to decline during the third quarter of 2014 and remained weak throughout 2015 and 2016 and thus far in 2017. The declines in natural gas prices are primarily due to an imbalance between supply and demand across North America. The continued duration and magnitude of these commodity price declines cannot be accurately predicted. Compared to 2014, our realized oil price for 2015 fell 51% to $44.41 per barrel, our realized oil price for the year ended December 31, 2016 further decreased to $41.09 per barrel and our realized oil price for the six months ended June 30, 2017 was $48.05 per barrel. Similarly, our realized natural gas price for 2015 decreased 41% to $2.60 per Mcf and our realized price for NGLs declined 49% to $12.22 per barrel. For the year ended December 31, 2016, our realized price for natural gas was $2.44 per Mcf and our realized price for NGLs was $12.28 per barrel. For the six months ended June 30, 2017, our realized price for natural gas was $3.12 per Mcf, and our realized price for NGLs was $16.62 per barrel.

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

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

The oil and natural gas industry is capital-intensive. We make and expect to continue to make substantial capital expenditures related to our development projects and acquisitions. Our 2017 capital budget is $550 million to $675 million. We expect to fund our capital expenditures with cash generated by operations, cash on hand, borrowings under our revolving credit facility and proceeds from the offering of the old notes. However, our financing needs may require us to alter or increase our capitalization substantially through the issuance of debt or equity securities or the sale of assets. The issuance of additional indebtedness would require that an additional portion of our cash flow from operations be used for the payment of interest and principal on our indebtedness, thereby further reducing our ability to use cash flow from operations to fund working capital, capital expenditures and acquisitions. The issuance of additional equity securities would be dilutive to our existing stockholders. The actual amount and timing of our future capital expenditures may differ materially from

our estimates as a result of, among other things: commodity prices; actual drilling results; the availability of drilling rigs and other services and equipment; and regulatory, technological and competitive developments. A reduction in commodity prices from current levels may result in a decrease in our actual capital expenditures, which would negatively impact our ability to grow production.

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

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

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

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

In addition, certain of the new techniques we are adopting may cause irregularities or interruptions in production due to offset wells being shut in and the time required to drill and complete multiple wells before any such wells begin producing. Furthermore, the results of drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer and emerging formations and areas have limited or no production history and, consequently,

we are more limited in assessing future drilling results in these areas. If our drilling results are less than anticipated, the return on our investment for a particular project may not be as attractive as we anticipated, and we could incur material write-downs of unevaluated properties and the value of our undeveloped acreage could decline in the future.

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

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

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

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

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 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 notes and our other indebtedness.

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

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

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, borrow more money or raise equity. We may not be able to refinance our debt, sell assets, borrow more money or raise equity on terms acceptable to us, if at all. For example, our existing and future debt agreements will require that we satisfy certain conditions, including coverage and leverage ratios, to borrow money. Our existing and future debt agreements will also restrict the payment of dividends and distributions by certain of our subsidiaries to us, which could affect our access to cash. In addition, our ability to comply with the financial and other restrictive covenants in our indebtedness will be affected by the levels of cash flow from our operations and future events and circumstances beyond our control. Failure to comply with these covenants would result in an event of default under our indebtedness, and such an event of default could adversely affect our business, financial condition and results of operations.

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.

Our revolving credit facility 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. On April 4, 2017, our revolving credit facility borrowing base was increased to $450.0 million in connection with the semi-annual borrowing redetermination by the lenders and the borrowing base further increased to $650.0 million upon the closing of the Acquisition. In connection with the consummation of the offering of 2025 Senior Notes on September 19, 2017, the borrowing base was automatically reduced to $612.5 million. The next scheduled borrowing base redetermination is set for October 2017.

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

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

We enter into derivative instrument contracts for a portion of our oil and natural gas production. As of August 9, 2017, we had entered into swaps, collars and deferred premium puts through 2020 covering a total of 15,340 MBbl of our projected oil production and 31,175,408 MMBtu of our projected natural gas production. Accordingly, our earnings may fluctuate significantly as a result of changes in fair value of our derivative instruments.

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

The use of derivatives may, in some cases, require the posting of cash collateral with counterparties. If we enter into derivative instruments that require cash collateral and commodity prices or interest rates change in a manner adverse to us, our cash otherwise available for use in our operations would be reduced, which could limit our ability to make future capital expenditures and make payments on our indebtedness, and which could also limit the size of our borrowing base. Future collateral requirements will depend on arrangements with our

counterparties, oil, natural gas and NGL prices and interest rates. In addition, derivative arrangements could limit the benefit we would receive from increases in the prices for oil, natural gas and NGLs or from reductions in interest rates, which could have a material adverse effect on our financial condition. In addition, our revolving credit facility limits our ability to enter into commodity hedges covering greater than 100% of our reasonably anticipated projected proved production for the first two years of the facility and 75% of reasonably anticipated projected proved production for the following three years.

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

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

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

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

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 prospectus is the current market value of our estimated reserves. Actual future prices and costs may differ materially from those used in the present value estimate. For example, our estimated proved reserves as of December 31, 2016 and related standardized measure were calculated under SEC rules using twelve-month trailing average benchmark prices of $42.75 per barrel of oil (WTI) and $2.48 per MMBtu of natural gas (Henry Hub spot), which, for certain periods in 2016, were substantially higher than the available spot prices. If spot prices are below such calculated amounts, using more recent prices in estimating proved reserves may result in a reduction in proved reserve volumes due to economic limits.

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

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

Properties we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties that we acquire or obtain protection from sellers against such liabilities.

Acquiring oil and natural gas properties requires us to assess reservoir and infrastructure characteristics, including recoverable reserves, future oil and gas prices and their applicable differentials, development and operating costs, and potential liabilities, including environmental liabilities. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Such assessments are inexact and inherently uncertain. For these reasons, the properties we have acquired or will acquire in the future in connection with the acquisitions or otherwise may not produce as expected. In connection with the assessments, we perform a review of the subject properties, but such a review may not reveal all existing or potential problems. In the course of our due diligence, we may not review every well, pipeline or associated facility. We cannot necessarily observe structural and environmental problems, such as groundwater contamination, when a review is performed. We may be unable to obtain contractual indemnities from the seller for liabilities created prior to our purchase of the property. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.

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

As of December 31, 2016, we have identified 4,548 potential drilling locations on our acreage. We do not expect to operate 1,798 of such locations, and there is no assurance that we will operate all of our other drilling locations. In addition, unless we are successful in increasing our working interest in our other drilling locations through acreage exchanges and consolidation efforts, we will not be the operator with respect to these other identified horizontal drilling locations. We have limited ability to exercise influence over the operations of the drilling locations operated by our partners, and there is the risk that our partners may at any time have economic, business or legal interests or goals that are inconsistent with ours. Furthermore, the success and timing of development activities operated by our partners will depend on a number of factors that will be largely outside of our control, including:

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

Further, we may be liable for certain financial obligations of the operator of a well in which we own a working interest to the extent such operator becomes insolvent and cannot satisfy such obligations. Similarly, we may be liable for certain obligations of our contractors to the extent such contractor becomes insolvent and cannot satisfy their obligations. The satisfaction of such obligations could have a material adverse effect on our financial condition.

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

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

As of December 31, 2016, we had identified 3,135 gross horizontal drilling locations on our Eagle Ford Acreage and 1,413 gross horizontal drilling locations on our North Louisiana Acreage. As a result of the limitations described in this prospectus, we may be unable to drill many of our identified locations. In addition, we will require significant additional capital over a prolonged period in order to pursue the development of these locations, and we may not be able to raise or generate the capital required to do so. See “ —Our development projects and acquisitions require substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms, which could lead to a decline in our ability to access or grow production and reserves.” Any drilling activities we are able to conduct on these locations may not be successful, may not result in production or additions to our estimated proved reserves and could result in a downward revision of our estimated proved reserves, which could have a material adverse effect on the borrowing base under our revolving credit facility or our future business and results of operations. Additionally, if we curtail our drilling program, we may lose a portion of our acreage through lease expirations and may be required to reduce our estimated proved reserves, which could reduce the borrowing base under our revolving credit facility.

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

As of December 31, 2016, approximately 48% of our total net acreage was held by production. The leases for our net acreage not held by production will expire at the end of their primary term unless production is established in paying quantities under the units containing these leases or the leases are renewed. For example, as of December 31, 2016, 29% and 18% of our net undeveloped acreage was set to expire in 2017 and 2018, respectively. If our leases expire and we are unable to renew the leases, we will lose our right to develop the

related properties. Although we intend to extend substantially all of our net acreage associated with identified drilling locations through a combination of development drilling, the payment of pre-agreed leasehold extension and renewal payments pursuant to an option to extend or the negotiation of lease extensions, we may not be successful in extending our leases. Additionally, where we do not have options to extend a lease, we may not be successful in negotiating extensions or renewals or any payments related to such extensions or renewals may be more than anticipated. Please see “Business—Reserve Data—Undeveloped Acreage Expirations” for more information regarding acreage expirations and our plans for extending and renewing our acreage. Our ability to drill and develop our acreage and establish production to maintain our leases depends on a number of uncertainties, including oil, natural gas and NGL prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors.

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

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

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

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

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

All of our producing properties are geographically concentrated in the Eagle Ford and in North Louisiana. At December 31, 2016, all of our total estimated proved reserves were attributable to properties located in these areas. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in these areas caused by governmental regulation, processing or transportation capacity constraints, market limitations, availability of equipment and personnel, water shortages or other drought related conditions or interruption of the processing or transportation of oil, natural gas or NGLs.

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

The marketability of our oil and natural gas production depends in part upon the availability, proximity and capacity of transportation facilities owned by third parties. Our oil production is transported from the wellhead to our tank batteries by our gathering systems. The oil is then transported by the purchaser by truck to a transportation facility. Our natural gas production is generally transported by our or third-party gathering lines from the wellhead to a gas processing facility or transmission pipeline. We do not control these trucks and other third-party transportation facilities and our access to them may be limited or denied. Insufficient production from

our wells to support the construction of pipeline facilities by our purchasers or a significant disruption in the availability of our or third-party transportation facilities or other production facilities could adversely impact our ability to deliver to market or produce our oil and natural gas and thereby cause a significant interruption in our operations. If, in the future, we are unable, for any sustained period, to implement acceptable delivery or transportation arrangements or encounter production related difficulties, we may be required to shut in or curtail production. Any such shut-in or curtailment, or an inability to obtain favorable terms for delivery of the oil and natural gas produced from our fields, would materially and adversely affect our financial condition and results of operations.

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

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

The development of our estimated PUDs 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, 2016, approximately 69% 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, 2016 are approximately $1.10 billion over the next five years. We expect to fund these expenditures through cash generated by operations, borrowings under our revolving credit facility and other sources of capital. Our ability to fund these expenditures is subject to a number of risks. See “—Our development projects and acquisitions require substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms, which could lead to a decline in our ability to access or grow production and reserves.” Delays in the development of our reserves, increases in costs to drill and develop such reserves or decreases in commodity prices will reduce the value of our estimated PUDs and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our PUDs as unproved reserves. Furthermore, there is no certainty that we will be able to convert our PUDs to developed reserves or that our undeveloped reserves will be economically viable or technically feasible to produce.

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

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

Accounting rules require that we periodically review the carrying value of our properties for possible impairment. Based on prevailing commodity prices and specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write-down the carrying value of our properties. A write-down constitutes a non-cash impairment charge to earnings. Commodity prices have declined significantly since 2014. On September 25, 2017, the WTI spot price for crude oil was $51.85 per barrel and the Henry Hub spot price for natural gas was $2.96 per MMBtu, representing decreases of 52% and 64%, respectively, from the high of $107.95 per barrel of oil and $8.15 per MMBtu for natural gas during 2014.

Likewise, NGLs have suffered significant recent declines in realized prices. Lower commodity prices in the future could result in impairments of our properties, which could have a material adverse effect on our results of operations for the periods in which such charges are taken. As a result of lower commodity prices, we recorded $24.7 million and $9.3 million of impairment expense during the years ended December 31, 2014 and 2015. We could experience further material write-downs as a result of lower commodity prices or other factors, including low production results or high lease operating expenses, capital expenditures or transportation fees.

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

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

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

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

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

We normally sell our production to a relatively small number of customers, as is customary in our business. For the years ended December 31, 2016 and 2015, there were three purchasers who accounted for an aggregate 82% and 72%, respectively, of WHR II’s and Esquisto’s total revenue on a combined basis. During such years, no other purchaser accounted for 10% or more of WHR II’s and Esquisto’s revenue on a combined basis. The loss of any such greater than 10% purchaser as a purchaser could adversely affect our revenues in the short term.

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

Our operations are subject to stringent and complex federal, state and local laws and regulations governing the discharge of materials into the environment and protection of environment and natural resources (including threatened and endangered species and their habitat), and health and safety aspects of our operations or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations applicable to our operations, including the acquisition of a permit or other approval before conducting regulated activities; the restriction of types, quantities and concentration of materials that can be released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands, seismically active areas and other protected areas; the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from our operations. Numerous governmental authorities, such as the EPA and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them. Such enforcement actions often involve difficult and costly compliance measures or corrective actions. Failure to comply with these laws and regulations

may result in the assessment of sanctions, including administrative, civil or criminal penalties, natural resource damages, the imposition of investigatory or remedial obligations, and the issuance of orders limiting or prohibiting some or all of our operations. In addition, we may experience delays in obtaining, or be unable to obtain, required permits, which may delay or interrupt our operations and limit our growth and revenue.

Certain environmental laws impose strict liability (i.e., no showing of “fault” is required) as well as joint and several liability for costs required to remediate and restore sites where hazardous substances, hydrocarbons or solid wastes have been stored or released. We may be required to remediate contaminated properties currently or formerly owned or operated by us or facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In connection with certain acquisitions, we could acquire, or be required to provide indemnification against, environmental liabilities that could expose us to material losses. In certain instances, citizen groups also have the ability to bring legal proceedings against us if we are not in compliance with environmental laws, or to challenge our ability to receive environmental permits that we need to operate. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. Our insurance may not cover all environmental risks and costs or may not provide sufficient coverage if an environmental claim is made against us. Moreover, public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stringent environmental legislation and regulations applied to the crude oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability.

To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements, our business, prospects, financial condition or results of operations could be materially adversely affected.

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

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

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

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:

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

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

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

In addition, we have grown rapidly over the last several years. Our management believes that our future success depends on our ability to manage the rapid growth that we have experienced and the demands from increased responsibility on management personnel. Prior to our initial public offering, WHR II and Esquisto had separate management teams and going forward, we will have one management team. Additionally, the following factors could present difficulties:

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

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

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

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

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

The success of completed acquisitions will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions. No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations.

In addition, our revolving credit facility imposes certain limitations on our ability to enter into mergers or combination transactions and to incur certain indebtedness, which could indirectly limit our ability to acquire assets and businesses.

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

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

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

The demand for drilling rigs, pipe and other equipment and supplies, as well as for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry, can fluctuate significantly, often in correlation with oil, natural gas and NGL prices, causing periodic shortages of supplies and needed personnel. Our operations are concentrated in areas in which oilfield activity levels had increased rapidly, and as a result, demand for such drilling rigs, equipment and personnel, as well as access to transportation, processing and refining facilities in these areas, had increased, as did the costs for those items. However, beginning in the second half of 2014, commodity prices began to decline and the demand for goods and services subsided due to reduced activity. To the extent that commodity prices improve in the future, the demand for and prices of these goods and services are likely to increase and we could encounter delays in or an inability to secure the personnel, equipment, power, services, resources and facilities access necessary for us to resume or increase our development activities, which

could result in production volumes being below our forecasted volumes. In addition, any such negative effect on production volumes, or significant increases in costs, could have a material adverse effect on our cash flow and profitability. Furthermore, if we are unable to secure a sufficient number of drilling rigs at reasonable costs, we may not be able to drill all of our acreage before our leases expire.

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

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

A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.

Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by the FERC, as a natural gas company under the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress. If the FERC were to consider the status of an individual facility and determine that the facility and/or services provided by it are not exempt from FERC regulation, the rates for, and terms and conditions of services provided by such facility would be subject to regulation by the FERC. Such regulation could decrease revenues, increase operating costs, and depending upon the facility in question, could adversely affect our results of operations and cash flows. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA, this could result in the imposition of civil penalties as well as a requirement to disgorge charges collected for such service in excess of the cost-based rate established by the FERC.

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

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

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

sanctions may be insufficient, and judgments and estimates to determine accruals or range of losses related to legal and other proceedings could change from one period to the next, and such changes could be material.

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

The EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and natural gas production sources in the United States on an annual basis, which include certain of our operations. In June 2016, the EPA published performance standards that establish new controls for emissions of methane from new, modified or reconstructed sources in the oil and natural gas sector, including production, processing, transmission and storage activities. Compliance will require enhanced record-keeping practices, the purchase of new equipment and could result in the increased frequency of maintenance and repair activities to address emissions leakage at well sites and compressor stations, and also may require additional personnel time to support these activities or the engagement of third party contractors to assist with and verify compliance. Several states and industry groups have filed suit before the D.C. Circuit challenging the EPA’s implementation of the methane rule and legal authority to issue the methane rule. However, in April 2017, the EPA announced that it will review the rule for new, modified, and reconstructed sources and will initiate proceedings to potentially revise or rescind portions of the methane rule. Additionally, the EPA previously issued a stay of the June 3, 2017 compliance date applicable to fugitive emissions monitoring requirements for 90 days. However, on July 31, 2017 the D.C. Circuit issued an order carrying the methane rule back into effect. The court’s decision does not limit the EPA’s ability to reconsider the methane rule pursuant to notice and comment rulemaking. The D.C. Circuit’s decision on whether to rehear the case en banc is still pending. Additionally, in 2015, EPA published a rule, known as the Clean Power Plan, to limit GHG emissions from electric power plants. In February 2016, the Supreme Court stayed the implementation of the Clean Power Plan while legal challenges to the rule proceed. Depending on the ultimate outcome of those challenges, and how various states choose to implement this rule, it may alter the power generation mix between natural gas, coal, oil, and alternative energy sources, which would ultimately affect the demand for natural gas and oil in electric generation.

While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs. Cap and trade programs typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. In addition, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues. For example, in April 2016, the United States signed the Paris Agreement, which requires member nations to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. The Paris Agreement, which entered into force in November 2016, includes pledges to voluntarily limit or reduce future emissions. However, in June 2017, the President stated that the United States would withdraw from the Paris Agreement, but may enter into a future international agreement related to GHGs. The Paris Agreement provides for a four-year exit process beginning

when it took effect in November 2016, resulting in an effective exit date of November 2020. The United States’ adherence to the exit process is uncertain and/or the terms on which the United States may reenter the Paris Agreement or a separately negotiated agreement are unclear at this time.

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

Finally, increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have a material adverse effect on our operations.

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

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

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

Certain governmental reviews are either underway or have been conducted that focus on environmental aspects of hydraulic fracturing practices. For example, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The EPA report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits.

example, in May 2013, the Railroad Commission issued a “well integrity rule,” which updates the requirements for drilling, putting pipe down and cementing wells. The rule also includes new testing and reporting requirements, such as (i) the requirement to submit cementing reports after well completion or after cessation of drilling, whichever is later, and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. The well integrity rule took effect in January 2014.

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

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

State and federal regulatory agencies have recently focused on a possible connection between the hydraulic fracturing related activities, particularly the underground injection of wastewater into disposal wells, and the increased occurrence of seismic activity, and regulatory agencies at all levels are continuing to study the possible linkage between oil and gas activity and induced seismicity. For example, in 2015, the United States Geological Study identified eight states, including Texas, with areas of increased rates of induced seismicity that could be attributed to fluid injection or oil and gas extraction.

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

We dispose of large volumes of produced water gathered from our drilling and production operations by injecting it into wells pursuant to permits issued to us by governmental authorities overseeing such disposal activities. While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change, which could result in the imposition of more stringent operating constraints or new monitoring and reporting requirements, owing to, among other things, concerns of the public or governmental authorities regarding such gathering or disposal activities. The adoption and implementation of any new laws or regulations that restrict our ability to use hydraulic fracturing or dispose of produced water gathered from our drilling and production activities by limiting volumes, disposal rates, disposal well locations or otherwise, or requiring us to shut down disposal wells, could have a material adverse effect on our business, financial condition and results of operations.

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

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

NGP and their affiliates are not limited in their ability to compete with us, which could cause conflicts of interest and limit our ability to acquire additional assets or businesses.

Our governing documents provide that NGP and their respective affiliates (including NGP and its affiliates’ portfolio investments) are not restricted from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, NGP and their respective affiliates may acquire, develop or dispose of additional oil and natural gas properties or other assets in the future, without any obligation to offer us the opportunity to purchase or develop any of those assets. NGP are established participants in the oil and natural gas industry, and have resources greater than ours, which factors may make it more difficult for us to compete with them with respect to commercial activities as well as for potential acquisitions. As a result, competition from these affiliates could adversely impact our results of operations.

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

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

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, limit our ability to pursue acquisition opportunities, reduce cash flow used for drilling and place us at a competitive disadvantage. Recent and continuing disruptions and volatility in the global financial markets may lead to a contraction in credit availability impacting our ability to finance our operations. A significant reduction in cash flows from operations or the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.

Certain U.S. federal income tax deductions currently available with respect to natural gas and oil exploration and development may be eliminated as a result of future legislation.

In past years, legislation has been proposed that would, if enacted into law, make significant changes to U.S. tax laws, including to certain key U.S. federal income tax provisions currently available to oil and gas

exploration and production companies. Such legislative changes have included, but not been limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. Congress could consider, and could include, some or all of these proposals as part of tax reform legislation, to accompany lower federal income tax rates. Moreover, other more general features of tax reform legislation, including changes to cost recovery rules and to the deductibility of interest expense, may be developed that also would change the taxation of oil and gas companies. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could take effect. The passage of any legislation as a result of these proposals or any similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that currently are available with respect to oil and gas development, or increase costs, and any such changes could have an adverse effect on our financial position, results of operations and cash flows.

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

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

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

Oil and natural gas operations in our operating areas may be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife. Such restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay our operations or materially increase our operating and capital costs. Permanent restrictions imposed to protect threatened or endangered species or their habitat could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. The designation of previously unprotected species in areas where we operate as threatened or endangered could cause us to incur increased costs arising from species protection measures or could result in limitations on our activities that could have a material and adverse impact on our ability to develop and produce our reserves.

The enactment of derivatives legislation could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

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

The Dodd-Frank Act and CFTC rules also will require us, in connection with certain derivatives activities, to comply with clearing and trade-execution requirements (or to take steps to qualify for an exemption to such

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

It is not possible at this time to predict with certainty the full effects of the Dodd-Frank Act and CFTC rules on us or the timing of such effects. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, and reduce our ability to monetize or restructure our existing derivative contracts. If we reduce our use of derivatives as a result of the Dodd-Frank Act and CFTC rules, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures.

Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil, natural gas and NGL prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil, natural gas and NGL. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and CFTC rules is to lower commodity prices. Any of these consequences could have a material and adverse effect on us, our financial condition or our results of operations. In addition, the European Union and other non-U.S. jurisdictions are implementing regulations with respect to the derivatives market. To the extent we transact with counterparties in foreign jurisdictions, we may become subject to such regulations, the impact of which is not clear at this time.

We may not be able to keep pace with technological developments in our industry.

The oil and natural gas industry is characterized by rapid and significant technological advancement and the introduction of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or may be forced by competitive pressures to implement those new technologies at substantial costs. In addition, other oil and natural gas companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and that may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures or implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete, our business, financial condition or results of operations could be materially and adversely affected.

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

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

Our implementation of various procedures and controls to monitor and mitigate such security threats and to increase security for our information, systems, facilities and infrastructure may result in increased costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. If any of these security breaches were to occur, they could lead to losses of, or damage

to, sensitive information or facilities, infrastructure and systems essential to our business and operations, as well as data corruption, communication interruptions or other disruptions to our operations, which, in turn, could have a material adverse effect on our business, financial position, results of operations and cash flows.

If you do not properly tender your old notes, you will continue to hold unregistered old notes and your ability to transfer old notes will remain restricted and may be adversely affected.

We will only issue new notes in exchange for old notes that you timely and properly tender. Therefore, you should allow sufficient time to ensure timely delivery of the old notes, and you should carefully follow the instructions on how to tender your old notes. Neither we nor the exchange agent is required to tell you of any defects or irregularities with respect to your tender of old notes.

If you do not exchange your old notes for new notes pursuant to the exchange offer, the old notes you hold will continue to be subject to the existing transfer restrictions. In general, you may not offer or sell the old notes except under an exemption from, or in a transaction not subject to, the Securities Act and applicable state securities laws. We do not plan to register old notes under the Securities Act unless the registration rights agreement requires us to do so. Further, if you continue to hold any old notes after the exchange offer is consummated, you may have trouble selling them because there will be fewer of these notes outstanding.

We are not obligated to complete the exchange offer under certain circumstances. See “Exchange Offer—Conditions to the Exchange Offer.” Even if the exchange offer is completed, it may not be completed on the schedule described in this prospectus. Accordingly, holders participating in the exchange offer may have to wait longer than expected to receive their new notes, during which time those holders of old notes will not be able to effect transfers of their old notes tendered in the exchange offer.

You may be required to deliver prospectuses and comply with other requirements in connection with any resale of the new notes.

If you tender your old notes for the purpose of participating in a distribution of the new notes, you will be required to comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale of the new notes. In addition, if you are a broker-dealer that receives new notes for your own account in exchange for old notes that you acquired as a result of market-making activities or any other trading activities, you will be required to acknowledge that you will deliver a prospectus in connection with any resale of such new notes.

Our leverage and debt service obligations may adversely affect our financial condition, results of operations, business prospects and our ability to make payments on the notes.

We have a substantial amount of indebtedness, and we and our subsidiaries may be able to incur substantial additional indebtedness in the future, subject to restrictions in our debt agreements. As of June 30, 2017, we had approximately $502.1 million of available borrowing capacity under our revolving credit facility. The terms and conditions governing our indebtedness will:

Our ability to meet our expenses and current and future 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 current and future debt and meet our other obligations. If we do not have enough money, we may be required to refinance all or part of our existing debt, sell assets, borrow more money or raise equity, and we may be unable to make desirable capital expenditures, which could put us at a competitive disadvantage relative to other less leveraged competitors that have more cash flow to devote to their operations. We may not be able to refinance our debt, sell assets, borrow more money or raise equity on terms acceptable to us, if at all. For example, our existing and future debt agreements will require that we satisfy certain conditions, including coverage and leverage ratios, to borrow money. Our existing and future debt agreements may 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.

The notes and the guarantees are unsecured and effectively subordinated to our and the guarantors’ existing and future secured indebtedness and structurally subordinated to indebtedness of any future non-guarantor subsidiaries.

The new notes and the guarantees, like the old notes and guarantees, are general unsecured senior obligations ranking effectively junior in right of payment to all of our existing and future secured debt and that of each guarantor, including obligations under our revolving credit facility, to the extent of the value of the assets securing such debt. As of June 30, 2017, we had approximately $502.1 million of available borrowing capacity under our revolving credit facility.

If we or a guarantor is declared bankrupt, becomes insolvent or is liquidated or reorganized, any secured debt of ours or of the guarantor will be entitled to be paid in full from the assets securing that debt before any payment may be made with respect to the notes or the affected guarantees. Holders of the notes will participate ratably with all holders of our other unsecured indebtedness that does not rank junior to the notes, including all of our other general creditors, based upon the respective amounts owed to each holder or creditor, in any proceeds from our remaining assets. In any of the foregoing events, we cannot assure you that there will be sufficient assets to pay amounts due on the notes. As a result, holders of the notes would likely receive less, ratably, than holders of secured indebtedness.

The notes are also structurally subordinated to any indebtedness and other liabilities of any subsidiaries that in the future do not guarantee the notes. The indenture governing the notes will permit us to form or acquire additional subsidiaries that are not guarantors of the notes in certain circumstances, and will allow us to release subsidiary guarantees in certain circumstances.

Holders of the notes will have no claim as a creditor against any of our non-guarantor subsidiaries.

Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly

Borrowings under our senior secured revolving credit facility bear interest at variable rates and expose us to interest rate risk. If interest rates increase and we are unable to effectively hedge our interest rate risk, our debt service obligations on the variable rate indebtedness would increase even if the amount borrowed remained the same, and our net income and cash available for servicing our indebtedness would decrease. If interest rates on our revolving credit facility increased by 1%, cash interest expense for the year ended December 31, 2016 would have increased by approximately $0.1 million.

Upon the occurrence of certain change of control events, we would be required to offer to repurchase all or any part of the notes then outstanding for cash at 101% of the principal amount plus accrued and unpaid interest, if any. The source of funds for any repurchase required as a result of any change of control will be our available cash or cash generated from our operations or other sources, including:

We cannot assure you that sufficient funds would be available at the time of any change of control to repurchase your notes after first repaying any of our other senior debt that may exist at the time. In addition, restrictions under our revolving credit facility may not allow such repurchases and additional credit facilities we enter into in the future also may prohibit such repurchases. Additionally, using available cash to fund the potential consequences of a change of control may impair our ability to obtain additional financing in the future, which could negatively impact our ability to conduct our business operations.

A subsidiary guarantee could be voided if it constitutes a fraudulent transfer under U.S. bankruptcy or similar state law, which would prevent the holders of the notes from relying on the subsidiary guarantor to satisfy claims.

Under U.S. bankruptcy law and comparable provisions of state fraudulent transfer laws, any guarantee of the notes can be voided, or claims under the guarantee may be subordinated to all other debts of the guarantor if, among other things, the guarantor, at the time it incurred the indebtedness evidenced by its guarantee or, in some states, when payments become due under the guarantee, received less than reasonably equivalent value or fair consideration for the incurrence of the guarantee and:

A court may find that a guarantor did not receive reasonably equivalent value or fair consideration for its guarantee if such guarantor did not substantially benefit directly or indirectly from the issuance of the guarantee. If a court were to void a guarantee, you would no longer have a claim against that guarantor. Absent further findings from the court, you would, however, retain your claim against the remaining entities. Sufficient funds to repay the notes may not be available from other sources, if any. In addition, the court might direct you to repay any amounts that you already received from such guarantor.

The measures of insolvency for purposes of fraudulent transfer laws vary depending upon the governing law. Generally, a guarantor would be considered insolvent if:

A guarantee may also be voided, without regard to the above factors, if a court finds that the guarantor entered into the guarantee with the actual intent to hinder, delay or defraud its creditors.

The indenture contains a provision intended to limit each guarantor’s liability to the maximum amount that it could incur without causing the incurrence of obligations under its guarantee to be a fraudulent transfer. Such provision may not be effective to protect the guarantee from being voided under fraudulent transfer law.

Your ability to transfer the notes may be limited by the absence of an active trading market, and there is no assurance that any active trading market will develop for the notes.

The old notes have not been registered under the Securities Act, and may not be resold by purchasers thereof unless the old notes are subsequently registered or an exemption from the registration requirements of the Securities Act is available. However, we cannot assure you that, even following registration or exchange of the old notes for new notes, that an active trading market for the old notes or the new notes will exist, and we will have no obligation to create such a market. At the time of the private placement of the old notes, the initial purchasers advised us that they intended to make a market in the old notes and, if issued, the new notes. The initial purchasers are not obligated, however, to make a market in the old notes or the new notes and any market-making may be discontinued at any time in their sole discretion. No assurance can be given as to the liquidity of or trading market for the old notes or the new notes.

The liquidity of any trading market for the notes and the market price quoted for the notes will depend upon the number of holders of the notes, the overall market for high yield securities, our financial performance or prospects or the prospects for companies in our industry generally, the interest of securities dealers in making a market in the notes and other factors.

Many of the covenants in the indenture governing the notes will terminate if the notes are rated investment grade by Standard & Poor’s Global Ratings (“Standard and Poor’s) and Moody’s Investors Service, Inc. (“Moody’s”).

Many of the covenants in the indenture governing the notes will terminate if the notes are rated investment grade by Standard & Poor’s and Moody’s provided at such time no default has occurred and is continuing. The termination of these covenants would allow us to engage in certain transactions that would not have been permitted while these covenants were in force. However, there can be no assurance that these covenants will be terminated and while in place, they will restrict, among other things, our ability to pay dividends on our common stock, incur debt and to enter into certain other transactions. See “Description of Notes—Certain Covenants.”

Because we are a holding company, we are financially dependent on receiving distributions from our subsidiaries.

We are a holding company and our assets consist of the equity interests in our operating subsidiaries. Our rights and the rights of our creditors, including the holders of the notes, to participate in the distribution of assets of any entity in which we own an equity interest will be subject to prior claims of the entity’s creditors upon the entity’s liquidation or reorganization. However, we may ourselves be a creditor with recognized claims against such entity, but our claims would still be subject to the prior claims of any secured creditor of such entity and of any holder of indebtedness of such entity that is senior to that held by us. Accordingly, a holder of our debt securities, including holders of the notes, may be deemed to be effectively subordinated to those claims.

At the closing of the offerings of the old notes, we entered into the registration rights agreement pursuant to which we agreed to use our reasonable best efforts, for the benefit of the holders of the old notes, at our cost, to do the following:

Upon the SEC’s declaring the exchange offer registration statement effective, we agreed to offer the new notes in exchange for surrender of the old notes. We agreed to use reasonable best efforts to cause the exchange offer registration statement to be effective continuously, to keep the exchange offer open for a period of not less than 20 business days and to use reasonable best efforts to cause the exchange offer to be commenced promptly after the exchange offer registration statement is declared effective by the SEC.

For each old note surrendered to us pursuant to the exchange offer, the holder of such old note will receive a new note having a principal amount equal to that of the surrendered old note. Interest on each new note will accrue from the last interest payment date, August 1, 2017. The registration rights agreement also obligates us to include in the prospectus for the exchange offer certain information necessary to allow a broker-dealer who holds old notes that were acquired for its own account as a result of market-making activities or other ordinary course trading activities (other than old notes acquired directly from us or one of our affiliates) to exchange such old notes pursuant to the exchange offer and to satisfy the prospectus delivery requirements in connection with resales of new notes received by such broker-dealer in the exchange offer. We agreed to amend or supplement the prospectus contained in the exchange offer registration statement for a period of 180 days after the last exchange date, which period may be extended under certain circumstances.

The preceding agreement is needed because any broker-dealer who acquires old notes for its own account as a result of market-making activities or other trading activities is required to deliver a prospectus meeting the requirements of the Securities Act. This prospectus covers the offer and sale of the new notes pursuant to the exchange offer and the resale of new notes received in the exchange offer by any broker-dealer who held old notes acquired for its own account as a result of market-making activities or other trading activities other than old notes acquired directly from us or one of our affiliates.

Based on interpretations by the staff of the SEC set forth in no-action letters issued to third parties, we believe that the new notes issued pursuant to the exchange offer would in general be freely tradable after the exchange offer without further registration under the Securities Act. However, any purchaser of old notes who is an “affiliate” of ours or who intends to participate in the exchange offer for the purpose of distributing the related new notes:

Each holder of the old notes (other than certain specified holders) who desires to exchange old notes for the new notes in the exchange offer will be required to make the representations described below under “—Procedures for Tendering—Your Representations to Us.”

We further agreed to file with the SEC a shelf registration statement to register for public resale of old notes held by any holder who provides us with certain information for inclusion in the shelf registration statement if:

We have agreed, at our expense, (a) as promptly as practicable (but in no event more than 20 days after such filing obligation arises) to file a shelf registration statement, (b) to use our reasonable best efforts to cause the shelf registration statement to be declared effective (unless it becomes effective automatically upon filing) under the Securities Act by the 90^th day after the filing of such shelf registration statement is required under the registration rights agreement and (c) to keep effective the shelf registration statement until one year after its effective date (or such shorter period that will terminate when all the notes covered thereby have been sold pursuant thereto or in certain other circumstances).

If (a) the exchange offer is not consummated on or before to the 365th calendar day following the date of issuance of the old notes or (b) a shelf registration statement applicable to the notes is not declared effective or does not automatically become effective when required (each such event referred to in clauses (a) through (b) above, a “Registration Default”), we will pay liquidated damages in the form of additional interest in cash to each holder of notes in an amount equal to 0.25% per annum of the aggregate principal amount of notes for the 90-day period immediately following the occurrence of the Registration Default until such time as no Registration Default is in effect, which rate shall increase by 0.25% per annum for each subsequent 90-day period during which such Registration Default continues up to a maximum of 0.5% per annum. Following the cure of all Registration Defaults, such additional interest will cease to accrue and the interest rate on the notes will revert to the original rate; provided, however, that, if after the date such additional interest ceases to accrue, a different Registration Default occurs, such additional interest may again commence accruing pursuant to the foregoing provisions. All references herein to “interest” include any additional interest payable pursuant to this paragraph.

Holders of the old notes will be required to make certain representations to us (as described in the registration rights agreement) in order to participate in the exchange offer and may be required to deliver information to be used in connection with the shelf registration statement in order to have their old notes included in the shelf registration statement.

This summary of the material provisions of the registration rights agreement does not purport to be complete and is subject to, and is qualified in its entirety by reference to, all the provisions of the registration rights agreement, copies of which are filed as exhibits to the registration statement, which includes this prospectus.

Except as set forth above, after consummation of the exchange offer, holders of old notes which are the subject of the exchange offer have no registration or exchange rights under the registration rights agreement. See “—Consequences of Failure to Exchange.”

Subject to the terms and conditions described in this prospectus and in the letter of transmittal, we will accept for exchange any old notes properly tendered and not withdrawn prior to 5:00 p.m., New York City time, on the expiration date. We will issue new notes in principal amount equal to the principal amount of old notes surrendered in the exchange offer. Old notes may be tendered only for new notes and only in minimum denominations of $2,000 and integral multiples of $1,000 in excess thereof.

The exchange offer is not conditioned upon any minimum aggregate principal amount of old notes being tendered for exchange.

As of the date of this prospectus, $500,000,000 in aggregate principal amount of the old notes is outstanding. This prospectus and the letter of transmittal are being sent to all registered holders of old notes. There will be no fixed record date for determining registered holders of old notes entitled to participate in the exchange offer.

We intend to conduct the exchange offer in accordance with the provisions of the registration rights agreement, the applicable requirements of the Securities Act and the Exchange Act and the rules and regulations of the SEC. Old notes that the holders thereof do not tender for exchange in the exchange offer will remain outstanding and continue to accrue interest. These old notes will continue to be entitled to the rights and benefits such holders have under the indenture relating to the notes and the registration rights agreement.

We will be deemed to have accepted for exchange properly tendered old notes when we have given oral or written notice of the acceptance to the exchange agent and complied with the applicable provisions of the registration rights agreement. The exchange agent will act as agent for the tendering holders for the purposes of receiving the new notes from us.

If you tender old notes in the exchange offer, you will not be required to pay brokerage commissions or fees or, subject to the letter of transmittal, transfer taxes with respect to the exchange of old notes. We will pay all charges and expenses, other than certain applicable taxes described below, in connection with the exchange offer. It is important that you read the section labeled “—Fees and Expenses” for more details regarding fees and expenses incurred in the exchange offer.

We will return any old notes that we do not accept for exchange for any reason without expense to their tendering holder promptly after the expiration or termination of the exchange offer.

The exchange offer will expire at 5:00 p.m., New York City time, on November 13, 2017, unless, in our sole discretion, we extend it.

We expressly reserve the right, at any time or various times, to extend the period of time during which the exchange offer is open. We may delay acceptance of any old notes by giving oral or written notice of such extension to their holders. During any such extensions, all old notes previously tendered will remain subject to the exchange offer, and we may accept them for exchange.

In order to extend the exchange offer, we will notify the exchange agent orally or in writing of any extension. We will notify the registered holders of old notes of the extension no later than 9:00 a.m., New York City time, on the business day after the previously scheduled expiration date.

If any of the conditions described below under “—Conditions to the Exchange Offer” have not been satisfied, we reserve the right, in our sole discretion:

by giving oral or written notice of such delay, extension or termination to the exchange agent. Subject to the terms of the registration rights agreement, we also reserve the right to amend the terms of the exchange offer in any manner.

Any such delay in acceptance, extension, termination or amendment will be followed promptly by oral or written notice thereof to the registered holders of old notes. If we amend the exchange offer in a manner that we determine to constitute a material change, we will promptly disclose such amendment by means of a prospectus supplement. The supplement will be distributed to the registered holders of the old notes. Depending upon the significance of the amendment and the manner of disclosure to the registered holders, we may extend the exchange offer. In the event of a material change in the exchange offer, including the waiver by us of a material condition, we will extend the exchange offer period if necessary so that at least five business days remain in the exchange offer following notice of the material change.

We will not be required to accept for exchange, or exchange any new notes for, any old notes if the exchange offer, or the making of any exchange by a holder of old notes, would violate applicable law or any applicable interpretation of the staff of the SEC. Similarly, we may terminate the exchange offer as provided in this prospectus before accepting old notes for exchange in the event of such a potential violation.

In addition, we will not be obligated to accept for exchange the old notes of any holder that has not made to us the representations described under “—Purpose and Effect of the Exchange Offer,” “—Procedures for Tendering” and “Plan of Distribution” and such other representations as may be reasonably necessary under applicable SEC rules, regulations or interpretations to allow us to use an appropriate form to register the new notes under the Securities Act.

We expressly reserve the right to amend or terminate the exchange offer, and to reject for exchange any old notes not previously accepted for exchange, upon the occurrence of any of the conditions to the exchange offer specified above. We will give prompt oral or written notice of any extension, amendment, non-acceptance or termination to the holders of the old notes as promptly as practicable.

These conditions are for our sole benefit, and we may assert them or waive them in whole or in part at any time or at various times in our sole discretion. If we fail at any time to exercise any of these rights, this failure will not mean that we have waived our rights. Each such right will be deemed an ongoing right that we may assert at any time or at various times.

In addition, we will not accept for exchange any old notes tendered, and will not issue new notes in exchange for any such old notes, if at such time any stop order has been threatened or is in effect with respect to the registration statement of which this prospectus constitutes a part or the qualification of the indenture relating to the notes under the Trust Indenture Act of 1939 (the “Trust Indenture Act”).

In order to participate in the exchange offer, you must properly tender your old notes to the exchange agent as described below. It is your responsibility to properly tender your notes. We have the right to waive any defects. However, we are not required to waive defects and are not required to notify you of defects in your tender.

If you have any questions or need help in exchanging your notes, please call the exchange agent, whose address and phone number are set forth in “Prospectus Summary—The Exchange Offer—Exchange Agent.”

All of the old notes were issued in book-entry form, and all of the old notes are currently represented by global certificates held for the account of DTC. We have confirmed with DTC that the old notes may be tendered using the ATOP instituted by DTC. The exchange agent will establish an account with DTC for purposes of the exchange offer promptly after the commencement of the exchange offer and DTC participants may electronically transmit their acceptance of the exchange offer by causing DTC to transfer their old notes to the exchange agent

using the ATOP procedures. In connection with the transfer, DTC will send an “agent’s message” to the exchange agent. The agent’s message will state that DTC has received instructions from the participant to tender old notes and that the participant agrees to be bound by the terms of the letter of transmittal.

By using the ATOP procedures to exchange old notes, you will not be required to deliver a letter of transmittal to the exchange agent. However, you will be bound by its terms just as if you had signed it.

We will determine in our sole discretion all questions as to the validity, form, eligibility, time of receipt, acceptance of tendered old notes and withdrawal of tendered old notes. Our determination will be final and binding. We reserve the absolute right to reject any old notes not properly tendered or any old notes our acceptance of which would, in the opinion of our counsel, be unlawful. We also reserve the right to waive any defect, irregularities or conditions of tender as to particular old notes. Our interpretation of the terms and conditions of the exchange offer, including the instructions in the letter of transmittal, will be final and binding on all parties. Unless waived, all defects or irregularities in connection with tenders of old notes must be cured within such time as we shall determine. Although we intend to notify holders of defects or irregularities with respect to tenders of old notes, neither we, the exchange agent nor any other person will incur any liability for failure to give such notification. Tenders of old notes will not be deemed made until such defects or irregularities have been cured or waived. Any old notes received by the exchange agent that are not properly tendered and as to which the defects or irregularities have not been cured or waived will be returned to the tendering holder, unless otherwise provided in the letter of transmittal, promptly following the expiration date.

In all cases, we will issue new notes for old notes that we have accepted for exchange under the exchange offer only after the exchange agent timely receives:

If we do not accept any tendered old notes for exchange or if old notes are submitted for a greater principal amount than the holder desires to exchange, the unaccepted or non-exchanged old notes will be returned without expense to their tendering holder. Such non-exchanged old notes will be credited to an account maintained with DTC. These actions will occur promptly after the expiration or termination of the exchange offer.

By agreeing to be bound by the letter of transmittal, you will represent to us that, among other things:

Except as otherwise provided in this prospectus, you may withdraw your tender at any time prior to 5:00 p.m., New York City time, on the expiration date. For a withdrawal to be effective you must comply with the appropriate procedures of DTC’s ATOP system. Any notice of withdrawal must specify the name and number of the account at DTC to be credited with withdrawn old notes and otherwise comply with the procedures of DTC.

We will determine all questions as to the validity, form, eligibility and time of receipt of notice of withdrawal. Our determination shall be final and binding on all parties. We will deem any old notes so withdrawn not to have been validly tendered for exchange for purposes of the exchange offer.

Any old notes that have been tendered for exchange but are not exchanged for any reason will be credited to an account maintained with DTC for the old notes. This crediting will take place as soon as practicable after withdrawal, rejection of tender or termination of the exchange offer. You may retender properly withdrawn old notes by following the procedures described under “—Procedures for Tendering” above at any time prior to 5:00 p.m., New York City time, on the expiration date.

We will bear the expenses of soliciting tenders. The principal solicitation is being made by mail; however, we may make additional solicitation by facsimile, telephone, electronic mail or in person by our officers and regular employees and those of our affiliates.

We have not retained any dealer-manager in connection with the exchange offer and will not make any payments to broker-dealers or others soliciting acceptances of the exchange offer. We will, however, pay the exchange agent reasonable and customary fees for its services and reimburse it for its related reasonable out-of-pocket expenses.

We will pay the cash expenses to be incurred in connection with the exchange offer. They include:

We will pay all transfer taxes, if any, applicable to the exchange of old notes under the exchange offer. The tendering holder, however, will be required to pay any transfer taxes, whether imposed on the registered holder or any other person, if a transfer tax is imposed for any reason other than the exchange of old notes under the exchange offer.

If you do not exchange new notes for your old notes under the exchange offer, you will remain subject to the existing restrictions on transfer of the old notes. In general, you may not offer or sell the old notes unless the offer or sale is either registered under the Securities Act or exempt from the registration under the Securities Act and applicable state securities laws. Except as required by the registration rights agreement, we do not intend to register resales of the old notes under the Securities Act.

We will record the new notes in our accounting records at the same carrying value as the old notes. This carrying value is the aggregate principal amount of the old notes less any bond discount, as reflected in our accounting records on the date of exchange. Accordingly, we will not recognize any gain or loss for accounting purposes in connection with the exchange offer.

Participation in the exchange offer is voluntary, and you should carefully consider whether to accept. You are urged to consult your financial and tax advisors in making your own decision on what action to take.

We may in the future seek to acquire untendered old notes in open market or privately negotiated transactions, through subsequent exchange offers or otherwise. We have no present plans to acquire any old notes that are not tendered in the exchange offer or to file a registration statement to permit resales of any untendered old notes.

The exchange offer is intended to satisfy our obligations under the registration rights agreement. We will not receive any proceeds from the issuance of the new notes in the exchange offer. In consideration for issuing the new notes as contemplated by this prospectus, we will receive old notes in a like principal amount. The form and terms of the new notes are identical in all respects to the form and terms of the old notes, except the new notes will be registered under the Securities Act and will not contain restrictions on transfer, registration rights or provisions for additional interest. Old notes surrendered in exchange for the new notes will be retired and cancelled and will not be reissued. Accordingly, the issuance of the new notes will not result in any change in outstanding indebtedness.

The following selected financial data should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated and combined financial statements and notes thereto includes elsewhere in this prospectus.

Basis of Presentation. The selected financial data of our predecessor was retrospectively recast due to common control considerations. Because WHR II, Esquisto and Acquisition Co. were under the common control of NGP, the sale and contribution of the respective ownership interests were accounted for as a combination of entities under common control, whereby the assets and liabilities sold and contributed were recorded based on historical cost. As such, the selected financial data presented below (i)(a) as of, and for the year ended, December 31, 2016, and (b) as of December 31, 2015, and for the period from February 17, 2015 (the inception of common control) to December 31, 2015, have been derived from the combined financial position and results attributable to our predecessor and Esquisto for periods prior to our initial public offering, (ii)(a) for the period from January 1, 2015 to February 16, 2015, and (b) as of, and for the year ended December 31, 2014, have been derived from the financial position and results attributable to our predecessor and (iii) for the six months ended June 30, 2016 have been derived from the combined financial position and results attributable to our predecessor and Esquisto. Furthermore, the results of Acquisition Co. are reflected in the financial data presented herein beginning on December 19, 2016. For periods after the completion of our initial public offering, our consolidated financial statements include our accounts and those of our subsidiaries.

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

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

The following table sets forth our ratios of consolidated earnings to fixed charges for the periods presented:

For the purpose of computing the ratio of earnings to fixed charges, the term “earnings” is the amount resulting from adding and subtracting the following items (as applicable). Add the following: (i) pre-tax income from continuing operations before adjustment for income or loss from equity investees; (ii) fixed charges; (iii) amortization of capitalized interest; (iv) distributed income of equity investees; and (v) your share of pre-tax losses of equity investees for which charges arising from guarantees are included in fixed charges. From the total of the added items, subtract the following: (i) interest capitalized; (ii) preference security dividend requirements of consolidated subsidiaries; and (iii) the noncontrolling interest in pre-tax income of subsidiaries that have not incurred fixed charges.

The term “fixed charges” means the sum of the following: (i) interest expensed and capitalized, (ii) amortized premiums, discounts and capitalized expenses related to indebtedness, (iii) an estimate of the interest within rental expense, and (iv) preference security dividend requirements of consolidated subsidiaries.

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 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” and “Cautionary Statement Regarding Forward-Looking Statements” contained herein. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.

The Company is a Delaware corporation, the common stock, par value $0.01 per share, of which is listed on the NYSE under the symbol “WRD.”

We operate in one reportable segment engaged in the acquisition, exploitation, development and production of oil, natural gas and NGL resources. Our assets are characterized by concentrated acreage positions in Southeast Texas and North Louisiana with multiple producing stratigraphic horizons, or stacked pay zones, and attractive single-well rates of return. In Southeast Texas, we primarily operate in Burleson, Lee and Washington Counties where we primarily target the Eagle Ford Shale. In North Louisiana, we operate in and around the highly prolific Terryville Complex, where we primarily target the over-pressured Cotton Valley play.

As of December 31, 2016, we had assembled a total leasehold position of approximately 467,319 gross (371,198 net) acres across our expanding acreage, including approximately 321,661 gross (262,742 net) acres in the Eagle Ford and approximately 145,658 gross (108,455 net) acres in North Louisiana. We have identified a total of approximately 4,548 gross (2,350 net) drilling locations across our acreage as of December 31, 2016.

In September 2017, we completed a private placement of $150.0 million aggregate principal amount of the 2025 Senior Notes. Such 2025 Senior Notes, issued at 98.26% of par, mature on February 1, 2025 and are fully and unconditionally guaranteed on a joint and several basis by all of our existing and certain future subsidiaries (subject to customary release provisions) and are treated as a single class of securities with the previously issued 2025 Senior Notes. The 2025 Senior Notes are governed by the indenture. The 2025 Senior Notes accrue interest at 6.875% per annum and payable semi-annually in arrears on February 1 and August 1 of each year. We used the net proceeds to repay borrowings outstanding under our revolving credit facility and for general corporate purposes.

On May 10, 2017, we, through our new wholly owned subsidiary, WHR Eagle Ford LLC (“WHR EF”), entered into a Purchase and Sale Agreement (the “First Acquisition Agreement”) by and among WHR EF, as purchaser, and Anadarko E&P Onshore LLC (“APC”), Admiral A Holding L.P., TE Admiral A Holding L.P. and Aurora C-I Holding L.P. (collectively, “KKR” and, together with APC, the “First Sellers”), as sellers, to acquire

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

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

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

The Preferred Stock ranks senior to our common stock with respect to dividend rights and with respect to rights on liquidation, winding-up and dissolution. The Preferred Stock has an initial Accreted Value (as defined in the Certificate of Designations of the 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 will, among other things, increase the number of shares of common stock issuable upon conversion of each share of Preferred Stock. The Preferred Stock also participates in dividends and distributions on our common stock on an as-converted basis. If at any time following December 30, 2019, the closing sale price of our common stock equals or exceeds 130% of the Conversion Price for at least 25 consecutive trading days, our obligation to pay dividends on the Preferred Stock shall terminate permanently.

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

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

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

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

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

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

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

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

In February 2017, we announced multiple transactions to acquire certain oil and natural gas producing and non-producing properties from third-parties in Burleson County, Texas for an aggregate price of approximately $14.9 million, subject to customary post-closing adjustments. One transaction closed in February 2017 and the

remaining transactions closed in April 2017. In addition to the transactions we previously announced, on May 17, 2017 we entered into an agreement to acquire unproved oil and natural gas properties from a third party in Burleson County, Texas. On June 27, 2017, we closed this transaction for $2.2 million.

Our revenues are largely derived from the sale of our oil and natural gas production, the sale of NGLs that are extracted from our natural gas during processing, and the gathering charge paid by certain third parties for their share of volumes that run through our gathering system. Production revenues are derived entirely from the continental United States.

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

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

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

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

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 natural gas and crude oil properties are capitalized. Costs to drill and develop development wells and costs to drill and develop exploratory wells that find proved reserves are also capitalized. Costs to drill exploratory wells that do not find proved reserves, delay rentals and geological and geophysical costs are expensed.

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

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

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.

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

Our estimates of proved reserves are based on the quantities of oil, natural gas and NGLs, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Reserves and economic evaluation of all of our properties are prepared on a well-by-well basis. The accuracy of reserve estimates is a function of the:

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

We intend to have our independent reserve engineer audit our internally prepared reserve report as of December 31 for each year.

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

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

Our derivative instruments are not designated as hedges for accounting purposes. Accordingly, changes in fair value are recognized in our consolidated and combined statements of operations in the period of change. Gains and losses on derivatives and premiums paid for put options are included in cash flows from operating activities.

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

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

In estimating the fair values of assets acquired and liabilities assumed in a business combination, we make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved and unproved oil and gas properties. If sufficient market data is not available regarding the fair values of proved and unproved properties, we must prepare estimates. To estimate the fair values of these properties, we prepare estimates of oil, natural gas and NGL reserves. We estimate future prices to apply to the estimated reserves quantities acquired and estimate future operating and development costs to arrive at estimates of future net cash flows. For estimated proved reserves, the future net cash flows are discounted using a market-based weighted average cost of capital rate determined appropriate at the time of the acquisition. The market-based weighted average cost of capital rate is subjected to additional project-specific risking factors. To compensate for the inherent risk of estimating and valuing unproved reserves, when a discounted cash flow model is used, the discounted future net cash flows of probable and possible reserves are reduced by additional risk factors. In some instances, market comparable information of recent transactions is used to estimate fair value of unproved acreage.

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

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

Revenues from the sale of oil, natural gas and NGLs are recognized when the product is delivered at a fixed or determinable price, title has transferred, and collectability is reasonably assured and evidenced by a contract. We recognize revenues from the sale of oil, natural gas and NGLs using the sales method of accounting, whereby revenue is recorded based on our share of volume sold, regardless of whether we have taken our proportional share of volume produced. These differences result in gas imbalances. We record a liability to the extent there are not sufficient reserves to cover an over delivered gas imbalance. No receivables are recorded for those wells on which the Company has taken less than its proportionate share of production. We receive payment approximately one month after delivery for operated wells and up to three months after delivery for non-operated wells. At the end of each month, we estimate the amount of production delivered to purchasers and the price we will receive. Variances between our estimates and the actual amounts received are recorded in the month payment is received. A 10% change in our December 31, 2016, 2015 and 2014 revenue accrual would have impacted total operating revenues by approximately $1.7 million, $1.2 million and $0.8 million for the years ended December 31, 2016, 2015 and 2014, respectively.

The governing documents of WHR II provided for the issuance of incentive units. WHR II granted incentive units to certain of its members who were key employees at the time of grant. Holders of incentive units would have been entitled to distributions ranging from 20% to 40% when declared, but only after cumulative distribution thresholds (payouts) had been achieved. Payouts were generally triggered after the recovery of specified members’ capital contributions plus a rate of return. The incentive units were being accounted for as liability-classified awards as achievement of the payout conditions required settlement of such awards by transferring cash to the incentive unit holder. Compensation cost was recognized only if the performance condition was probable of being satisfied at each reporting date. The payment likelihood related to the WHR II incentive units was not deemed probable for the year ended December 31, 2016, 2015 and 2014, respectively. As such, no compensation expense was recognized by our predecessor.

In connection with the Corporate Reorganization, the WHR II incentive units were transferred to WildHorse Investment Holdings in exchange for substantially similar incentive units in WildHorse Investment Holdings, which became responsible for making all payments, distributions and settlements relating to the exchanged incentive units. While any such payments, distributions and settlements will not involve any cash payments by us, we will recognize non-cash compensation expense within G&A expenses, which may be material, in the period in which the applicable performance conditions are probable of being satisfied. We will receive a deemed capital contribution with respect to such compensation expense.

Holdings and Acquisition Co. Holdings. The WildHorse Holdings incentive units, Esquisto Holdings incentive units and Acquisition Co. Holdings incentive units will each vest in three equal annual installments beginning on the first anniversary of the applicable date of grant. The incentive units are entitled to a portion of future distributions by each of WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings in excess of the value of our common stock held by each of WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings based upon the initial public offering price of such common stock plus a 5% internal rate of return. WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings will be responsible for making all payments, distributions and settlements to all award recipients relating to the WildHorse Holdings incentive units, Esquisto Holdings incentive units and Acquisition Co. Holdings incentive units, respectively. While any such payments, distributions and settlements are not expected to involve any cash payment by us, we expect to recognize non-cash compensation expense within G&A expenses, which may be material, in the period in which the applicable performance conditions are probable of being satisfied. We will receive a deemed capital contribution with respect to such compensation expense.

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

The results of operations of our predecessor were retrospectively recast due to common control considerations. Because WHR II, Esquisto and Acquisition Co. were under the common control of NGP, the sale and contribution of the respective ownership interests were accounted for as a combination of entities under common control, whereby the assets and liabilities sold and contributed were recorded based on historical cost. As such, the results of operations presented below (i) for the three and six months ended June 30, 2016 have been derived from the combined results attributable to our predecessor and Esquisto, (ii) for the year ended December 31, 2016 and for the period from February 17, 2015 (the inception of common control) to December 31, 2015 have been derived from the combined results attributable to our predecessor and Esquisto for periods prior to our initial public offering and (iii) for the period from January 1, 2015 to February 16, 2015 and for the year ended December 31, 2014 have been derived from the results attributable to our predecessor. For periods after the completion of our initial public offering, our consolidated financial statements include our accounts and those of our subsidiaries.

Factors Affecting the Comparability of the Combined Historical Financial Results

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

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

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

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

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

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

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

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

Year Ended December 31, 2016 Compared to Year Ended December 31, 2015 and Year Ended December 31, 2015 Compared to the Year Ended December 31, 2014

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

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

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

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

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

Based on our current oil and natural gas price expectations, we believe our cash flows provided by operating activities and availability under our revolving credit facility will provide us with the financial flexibility and wherewithal to meet our cash requirements, including normal operating needs, and pursue our currently planned development drilling activities for the next 12 months. However, future cash flows are subject to a number of variables, including the level of our oil and natural gas production and the prices we receive for our oil and natural gas production, and significant additional capital expenditures will be required to more fully develop our properties and acquire additional properties. We cannot assure you that operations and other needed capital will be available on acceptable terms, or at all.

As of June 30, 2017, we had $14.6 million of cash and cash equivalents and $502.1 million of available borrowings under our revolving credit facility. As of June 30, 2017, we had a working capital deficit of $63.3 million primarily due to the accrual of capital expenditures. As of June 30, 2017, the borrowing base under our revolving credit facility was increased to $650.0 million. In connection with the consummation of the offering of 2025 Senior Notes on September 19, 2017, the borrowing base was automatically reduced to

$612.5 million. The borrowing base under our revolving credit facility is subject to redetermination on at least a semi-annual basis based on an engineering report with respect to our estimated oil and natural gas reserves, which will take into account the prevailing oil and natural gas prices at such time, as adjusted for the impact of our commodity derivative contracts. Unanimous approval by the lenders is required for any increase to the borrowing base. The next scheduled borrowing base redetermination is set for October 2017. A continuing decline in oil and natural gas prices could result in a reduction of our borrowing base under our revolving credit facility and could trigger mandatory principal repayments. On April 27, 2017, standby letters of credit of $1.9 million were issued to the Railroad Commission of Texas under our revolving credit facility.

We are authorized to issue up to 50,000,000 shares of preferred stock. On June 30, 2017, we issued 435,000 shares of preferred stock in connection with the Acquisition. See “—Recent Developments—Preferred Stock Issuance” of this prospectus for additional information regarding our preferred stock issuance.

We established a 2017 drilling and completion capital expenditure budget of $550.0 million to $675.0 million. For the six months ended June 30, 2017, our drilling and completion expenditures were approximately $267.6 million primarily related to the development of our Eagle Ford properties. In 2017, we expect to drill 90 to 110 gross wells and complete 80 to 100 gross wells across our acreage. We expect to fund our capital expenditures with cash generated by operations, cash on hand, borrowings under our revolving credit facility and proceeds from our offerings of 2025 Senior Notes. The amount, timing and allocation of capital expenditures is largely discretionary and within our control, and our 2017 capital budget may be adjusted as business conditions warrant. Please see “Risk Factors—Risks Related to Our Business—Our development projects and acquisitions require substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms, which could lead to a decline in our ability to access or grow production and reserves.” Commodity prices declined significantly since June 2014 and have remained low thus far in 2017. If oil or natural gas prices remain at current levels or decline to levels below our acceptable levels, or costs increase to levels above our acceptable levels, we could choose to defer a significant portion of our budgeted capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity and prioritize capital projects that we believe will have the highest expected rates of return and potential to generate near-term cash flow. We routinely monitor and adjust our capital expenditures in response to changes in commodity prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in drilling activities, contractual obligations, internally generated cash flow and other factors both within and outside our control. Any reduction in our capital expenditure budget could have the effect of delaying or limiting our development program, which would negatively impact our ability to grow production and could materially and adversely affect our future business, financial condition, results of operations or liquidity.

We intend to fund our 2017 capital expenditures and our cash requirements, including normal cash operating needs, debt service obligations and commitments and contingencies through December 31, 2017, with borrowings under our revolving credit facility, our operating cash flow, cash on hand and proceeds from our offerings of 2025 Senior Notes. However, to the extent that we consider market conditions favorable, we may access the capital markets to raise capital from time to time to fund acquisitions, pay down our revolving credit facility balance and for general working capital purposes.

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

Revolving Credit Facility. In December 2016, we, as borrower, and certain of our current and future subsidiaries, as guarantors, entered into a five-year, $1.0 billion senior secured revolving credit facility. In April 2017, our revolving credit facility borrowing base was increased from $362.5 million to $450.0 million in connection with the semi-annual borrowing redetermination by our lenders. Our revolving credit facility is reserve-based, and thus our borrowing base is primarily based on the estimated value of our oil. NGL and natural gas properties and our commodity derivative contracts as determined by our lenders in their sole discretion consistent with their normal and customary oil and gas lending practices semi-annually.” On June 30, 2017, the Company, each of the Company’s wholly owned subsidiaries (each as a guarantor), the Administrative Agent, and the lenders party thereto entered into the Amendment to the Credit Agreement.

In connection with the consummation of the offering of 2025 Senior Notes on September 19, 2017, the borrowing base was automatically reduced to $612.5 million.

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

See “Note 9—Long Term Debt” of the Notes to the Company’s Unaudited Condensed Consolidated and Combined Financial Statements with respect to the period ended June 30, 2017 included herein for additional information regarding our revolving credit facility.

In February 2017, we completed a private placement of $350.0 million aggregate principal amount of the 2025 Senior Notes, issued at 99.244% of par. In addition, 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. The 2025 Senior Notes are treated as a single class of debt securities, mature on February 1, 2025 and are fully and unconditionally guaranteed on a joint and several basis by all of our existing and certain future subsidiaries (subject to customary release provisions). The 2025 Senior Notes are governed by the indenture and accrue interest at 6.875% per annum and payable semi-annually in arrears on February 1 and August 1 of each year. We used the net proceeds to repay the borrowings outstanding under our revolving credit facility and for general corporate purposes, including funding our 2017 capital expenditures. On August 1, 2017, we made a $12.0 million interest payment on such 2025 Senior Notes.

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

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

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

The following table summarizes our cash flows from operating, investing and financing activities for the periods indicated. Our predecessor’s cash flows were retrospectively revised due to common control considerations. As such, the cash flows for the six months ended June 30, 2016 have been derived from the combined financial position and results attributable to the predecessor and the previous owner. The cash flows for years ended 2016, 2015 and 2014 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 Unaudited Statements of Condensed Consolidated and Combined Cash Flows contained herein.

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

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

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

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

$73.4 million during 2016, of which $58.5 million was attributable to Esquisto’s drilling and completion activities in the Eagle Ford and $14.9 million was attributable to our predecessor’s drilling and completion activities in North Louisiana.

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

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

Operating Activities. Net cash provided by operating activities was $22.3 million for 2016, compared to $50.1 million of net cash provided by operating activities for 2015. Production increased 1.5 MMBoe (approximately 40%) and average realized sales prices increased to $23.67 per Boe for 2016 compared to $22.65 per Boe during 2015 as previously discussed above under “Results of Operations.” Higher G&A expenses also contributed to the period-to-period decrease in net cash provided by operating activities. Net cash provided by operating activities included $4.9 million of cash receipts on derivative instruments during 2016 compared to $11.5 million during 2015. There was a $50.7 million decrease in cash flow attributable to the timing of cash receipts and disbursements related to operating activities during 2016 compared to 2015.

Investing Activities. During 2016 and 2015, cash flows used in investing activities were $567.5 million and $443.6 million, respectively. Acquisitions of oil and gas properties were $436.1 million during 2016. We closed the Burleson North Acquisition in December 2016 for $389.8 million. Acquisitions of oil and gas properties were $165.8 million during 2015. In July 2015, Esquisto acquired oil and natural gas producing properties, undeveloped acreage and water assets for a total purchase price of $103.0 million. 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. Additions to oil and gas properties were $253.9 million during 2015, of which $130.0 million was attributable to Esquisto’s drilling and completion activities in the Eagle Ford and $123.9 million was attributable to our predecessor’s drilling and completion activities in North Louisiana.

Financing Activities. 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.

Net cash provided by financing activities of $424.5 million during 2015 was primarily attributable to capital contributions of $125.1 million and $208.4 million from our predecessor and previous owner, respectively. Net borrowings under our revolving credit facilities were $89.9 million during 2015. Amounts borrowed under our predecessor and previous owner credit facilities were primarily used for additions to oil and natural gas properties and working capital. Debt issuance costs were $0.9 million.

Operating Activities. Net cash provided by operating activities was $50.1 million for 2015, compared to $25.7 million of net cash provided by operating activities for 2014. The change in operating cash flow was primarily the result of the significant decrease in commodity prices and higher G&A expense, largely offset by higher realized hedging gains, higher production and changes in working capital. Average realized sales prices decreased to $22.65 per Boe for 2015 compared to $27.78 per Boe during 2014 while production increased 2.2 MMBoe, or 132%, over the same time period as a result of acquisitions during 2015.

Investing Activities. During 2015 and 2014, cash flows used in investing activities were $443.6 million and $129.0 million, respectively. The increase for 2015 compared to the prior year is primarily due to $419.8 million in acquisitions and additions for 2015 compared to $128.7 million in additions for 2014.

Financing Activities. Net cash provided by financing activities of $424.5 million during 2015 was primarily attributable to capital contributions of $125.1 million and $208.4 million from our predecessor and previous owner, respectively. Net borrowings under our revolving credit facilities were $89.9 million during 2015. Amounts borrowed under our predecessor and previous owner credit facilities were primarily used for additions to oil and natural gas properties and working capital. Net cash provided by financing activities of $114.6 million during 2014 was primarily attributable to capital contributions of $97.5 million from our predecessor and net borrowings from WHR II’s revolving credit facility.

In the table below, we set forth our contractual obligations as of December 31, 2016. 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.

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

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

Leases. In February 2016, the FASB issued a revision to its lease accounting guidance. The FASB retained a dual model, requiring leases to be classified as either direct financing or operating leases. The classification will be based on criteria that are similar to the current lease accounting treatment. The revised guidance requires lessees to recognize a right-of-use asset and lease liability for all leasing transactions regardless of classification. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize lease assets and lease liabilities. If a lessee makes this election, it should recognize lease expense for such leases generally on a straight-line basis over the lease term. The amendments are effective for financial statements issued for annual periods beginning after December 15, 2018 and interim periods within those fiscal years. Although early adoption is permitted for all entities as of the beginning of an interim or annual reporting period, the Company will apply the revised lease rules for our interim and annual reporting periods starting January 1, 2019 using the required modified retrospective approach, including applicable practical expedients related to leases commenced before the effective date. As the Company is the lessee under various agreements for office space, compressors and equipment currently accounted for as operating leases, the new rules will increase reported assets and liabilities. The full quantitative impacts of the new standard are dependent on the leases in force at the time of adoption and, as a result, the evaluation of the effect of the new standards will extend over future periods.

revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, the standard provides a five-step analysis of transactions to determine when and how revenue is recognized. In August 2015, the FASB issued an accounting standards update that formally delayed the effective date of its new revenue recognition standard. The new standard is effective for fiscal years, and interim periods within those years, beginning after December 15, 2017. Although early adoption was permitted, the Company decided not to early adopt. The new guidance will be applicable to us beginning on January 1, 2018. The standard permits the use of either the retrospective or cumulative effect transition method. The Company has not yet selected a transition method. We do not currently expect that adoption of the new revenue recognition standard will materially impact revenue recognition for many types of our arrangements. Documentation of our revenue streams and related contract reviews is currently underway and expected to be completed by the end of September. During the fourth quarter, we plan to update our existing business process and internal control documentation for any new or revised processes and controls.

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

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.

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

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

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

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

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

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

In addition, our derivative contracts expose us to credit risk in the event of nonperformance by counterparties. While we do not require counterparties to our derivative contracts to post collateral, we do evaluate the credit standing of such counterparties as we deem appropriate. Each of the counterparties to our derivative contracts currently in place has an investment grade rating. See “Note 5—Risk Management and Derivative Instruments” of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included in this prospectus for additional information regarding credit risk associated with our derivative instruments.

The Company is a Delaware corporation, the common stock, par value $0.01 per share, of which are listed on the NYSE under the symbol WRD.

Our predecessor was formed in 2013. We operate in one reportable segment engaged in the acquisition, exploitation, development and production of oil, natural gas and NGL resources. Our assets are characterized by concentrated acreage positions in Southeast Texas and North Louisiana with multiple producing stratigraphic horizons, or stacked pay zones, and attractive single-well rates of return. In Southeast Texas, we primarily operate in Burleson, Lee and Washington Counties where we primarily target the Eagle Ford Shale. In North Louisiana, we operate in and around the highly prolific Terryville Complex, where we primarily target the overpressured Cotton Valley play.

As of December 31, 2016, we had assembled a total leasehold position of approximately 467,319 gross (371,198 net) acres across our expanding acreage, including approximately 321,661 gross (262,742 net) acres in the Eagle Ford and approximately 145,658 gross (108,455 net) acres in North Louisiana. As of December 31, 2016, we had identified a total of approximately 4,548 gross (2,350 net) drilling locations across our acreage. For the year ended December 31, 2016, approximately 60%, 34% and 5% of our revenues were attributable to oil, natural gas and NGLs, respectively.

The Eagle Ford Shale is one of the most active unconventional shale trends in North America. According to weekly rig count metrics published by Baker Hughes, the Eagle Ford Shale has consistently been one of the most active basins in the United States since 2011 and currently has the second highest rig count of all major U.S. basins. The Eagle Ford Shale trends across Texas from the Mexican border north into East Texas and is roughly 50 miles wide and 400 miles long. The Eagle Ford Shale rests between the Austin Chalk and the Buda Lime at a depth of approximately 4,000 to 14,000 feet. As of December 31, 2016, there were approximately 35,227 producing wells in the Eagle Ford with total production of 2.0 MMBoe/d in December 2016.

We currently target a portion of the Eagle Ford Shale at depths between 7,000 feet and 12,200 feet primarily in Burleson, Lee and Washington Counties, Texas. This portion of the Eagle Ford Shale averages 125 feet in thickness and contains 70% carbonate. We believe that the elevated carbonate percentages are in large part responsible for the brittleness of the Eagle Ford and successful completions which exhibit high productivity when fractured. The overall clay content of the Eagle Ford increases regionally as it continues northeast into Brazos, Grimes and Madison Counties, Texas.

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

We entered the Eagle Ford with the goal of redeveloping the area with horizontal drilling and modern completion techniques. Since that time, we have completed multiple bolt-on acquisitions and in-fill leases to build our current position in the Eagle Ford. We divide our Burleson County acreage into sub-regions, which we

refer to as Burleson Main, Burleson North, Burleson West and Burleson South, based on our assessment of depth and reservoir characteristics, such as gas to oil ratio, pressure and clay content. All of our drilling activity has historically been focused in our Burleson Main area. As of December 31, 2016, we have identified a substantial inventory of 3,135 gross drilling locations within our Eagle Ford Acreage, consisting of 2,676 gross drilling locations in Burleson County, Texas, 423 gross drilling locations in Lee County, Texas, and 36 gross drilling locations in Washington County, Texas. The wells in our Eagle Ford Acreage have shown a strong track record of increasing EURs and a decreasing trend in drilling and completion capital costs.

As of December 31, 2016, our Eagle Ford position included approximately 262,742 net acres. Also, as of December 31, 2016, approximately 49% of our Eagle Ford Acreage was held by production, with an average working interest of 82%, and, as of December 31, 2016, 24% of our 104.7 MMBoe of proved reserves were developed, 93% of which were liquids.

Within our North Louisiana Acreage we primarily target the overpressured Cotton Valley formation in the Terryville Complex. The Cotton Valley formation, extending across East Texas, North Louisiana and Southern Arkansas, has been under development since the 1930s and is characterized by thick, multi-zone natural gas and oil reservoirs with well-known geologic characteristics and long-lived, predictable production profiles. Over 23,000 vertical and horizontal wells have been completed throughout the trend. In 2005, operators started redeveloping the Cotton Valley using horizontal drilling and advanced hydraulic fracturing techniques. Through December 31, 2016, operators have drilled over 1,100 horizontal Cotton Valley wells. Some large, analogous redevelopment projects in the Terryville Complex include the Terryville play in Lincoln Parish, the Nan-Su-Gail area in Freestone County, East Texas and the Carthage Complex in Panola County, East Texas.

Our North Louisiana Acreage spans across the Webster, Claiborne, Bienville, Lincoln, Jackson and Ouachita Parishes, focusing on the Bear Creek field and the RCT and Weyerhaeuser Areas, where we are targeting overpressured Cotton Valley opportunities in multiple zones. We believe the Terryville Complex, which has been producing since 1954, is one of North America’s most prolific liquids rich natural gas plays, characterized by high recoveries relative to drilling and completion costs, high initial production rates with high liquids yields, long reserve life, multiple stacked pay zones, available infrastructure and a large number of service providers. The RCT Area is a direct offset of the Terryville Field and is part of the same Terryville Complex trend. Our drilling activity is expected to focus on producing natural gas from the overpressured Cotton Valley formation in the Terryville Complex where we intend to target the Upper and Lower Red and Upper Deep Pink intervals.

As of December 31, 2016, our North Louisiana Acreage included approximately 108,455 net acres. Also, as of December 31, 2016, 46% of our acreage was then held by production, with an average working interest of 74%, and 46% of our 48 MMBoe of proved reserves were developed, 98% of which were natural gas. As of December 31, 2016, we had drilled and completed 13 wells, acquired 605 wells and participated in two non-operated wells resulting in a total 2016 net production of approximately 7.8 MBoe/d (3% oil, 95% natural gas and 2% NGLs), including non-operated production.

Our estimated proved reserves of were prepared by our internal reserve engineers and audited by Cawley, Gillespie and Associates, Inc. (“Cawley”), our independent reserve engineers. As of December 31, 2016, we had 152.5 MMBoe of estimated proved reserves. As of this date, our proved reserves were 35.5% natural gas and 64.5% oil and NGLs. The following table provides summary information regarding our estimated proved reserves data and our average net daily production by area based on our reserve reports as of December 31, 2016:

To achieve our objectives of growing reserves, production and cash flows in a disciplined manner, we intend to execute the following business strategies:

Grow production, reserves and cash flow through the development of our extensive drilling inventory. We believe our extensive inventory of drilling locations in the Eagle Ford and the overpressured Cotton Valley formation in and around the Terryville Complex, combined with our operating expertise, will enable us to continue to deliver accretive production, reserves and cash flow growth. As of December 31, 2016, we had identified a total of approximately 4,548 gross (2,350 net) drilling locations across our acreage, with further upside potential given the multiple stacked pay zones across much of our acreage in addition to potential downspacing. We will continue to closely monitor offset operators as they delineate adjoining acreage and zones, providing us further data to optimize our development plan over time. We believe the location, concentration and scale of our core leasehold positions, coupled with our technical understanding of the reservoirs will allow us to efficiently develop our core areas and to allocate capital to maximize the value of our resource base.

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

In our Eagle Ford Acreage, we have reduced our drilling and completion costs per completed lateral foot by approximately 67%, from $2,958 per foot for our wells completed using Generation 1 hydraulic fracturing design to approximately $989 per foot for our wells completed using Generation 3 hydraulic fracturing design. Additionally, as we have transitioned our completion techniques in our Eagle Ford Acreage from Generation 1 to Generation 3 hydraulic fracturing designs, we have increased EURs by approximately 28% per completed lateral foot from an average of 76 Boe per foot to 97 Boe per foot. In our North Louisiana Acreage, we have reduced our drilling and completion costs per completed lateral foot by approximately 17%, from approximately $1,878 per foot for the year ended December 31, 2015 to approximately $1,559 per foot for the year ended December 31, 2016. Our drilling and completion cost reductions coupled with our completion design improvements are generating enhanced single-well recoveries and attractive returns in the current commodity environment, and we believe we can further optimize our results through these and other technologies across our acreage position.

Capture additional horizontal development opportunities on current acreage. Our existing asset base provides numerous opportunities for our management team to increase our inventory beyond our currently identified drilling locations. Based on results from our horizontal drilling program and those of offset operators, including offset production trends, mud logs, 2-D and 3-D seismic, well data analysis and geologic trend mapping, we believe our acreage has multiple productive zones providing significant upside potential to our current inventory of identified drilling locations. We have excluded from our identified drilling locations potential opportunities associated with downspacing and with additional horizontal drilling locations in (i) the Austin Chalk trend in Burleson County, (ii) the Eagle Ford Shale in Washington County, (iii) the Buda, Woodbine, Georgetown and Pecan Gap zones that are present across much of our Eagle Ford Acreage and (iv) additional Cotton Valley intervals across our North Louisiana Acreage.

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

Maintain a disciplined, growth-oriented financial strategy. We prudently manage our liquidity and leverage levels by monitoring cash flow, capital spending and debt capacity, which, being a two-basin company, we believe will allow us to strategically deploy capital among projects across our acreage. As of June 30, 2017, we had approximately $502.1 million of available borrowing capacity under our revolving credit facility, including $14.6 million in cash and cash equivalents. We intend to fund our growth primarily with internally generated cash flows while maintaining ample liquidity and access to the capital markets, which we believe will allow us to accelerate our development program and maximize the present value of our resource potential. Consistent with our disciplined approach to financial management, we have an active commodity hedging program that seeks to reduce our exposure to downside commodity price fluctuations, enabling us to protect cash flows and maintain liquidity to fund our capital program and investment opportunities.

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

Extensive, contiguous acreage position in two of North America’s leading oil and gas plays. We own an extensive and substantially contiguous acreage position targeting two of the premier plays in North America, the Eagle Ford Shale and the overpressured Cotton Valley formation in and around the Terryville Complex. As of December 31, 2016, we had approximately 467,319 gross (371,198 net) acres and 152.5 MMBoe of proved reserves (57.4% oil, 35.5% natural gas and 7.1% NGLs) across our acreage. We believe that our recent well results demonstrate that many of the wells on our high-quality acreage are capable of producing single-well rates of return that are competitive with many of the top performing basins in the United States. Furthermore, the location of our acreage provides us with lower operating costs and better realized pricing than other companies operating in different basins around the country due to our acreage’s proximity to the end markets for oil, natural gas and NGLs.

Multi-year inventory of drilling opportunities across our acreage position. As of December 31, 2016, we had identified approximately 4,548 gross (2,350 net) drilling locations across our acreage position, providing us with approximately 45 years of drilling inventory based on our 2017 drilling program. On our Eagle Ford Acreage, our horizontal drilling locations target the Eagle Ford Shale in Burleson and Lee Counties and the Austin Chalk in Washington County, and on our North Louisiana Acreage, our horizontal drilling locations target the Upper Red, Lower Red and Upper Deep Pink zones in the RCT Area and Weyerhaeuser Area in the overpressured Cotton Valley formation in the Terryville Complex. In addition, we believe our acreage position includes a number of additional areas and zones that are prospective for hydrocarbons. For example, we believe we may identify additional horizontal drilling locations in (i) the Austin Chalk trend in Burleson County, (ii) the Eagle Ford Shale in Washington County, (iii) the Buda, Woodbine, Georgetown and Pecan Gap zones that are present across much of our Eagle Ford Acreage and (iv) additional Cotton Valley intervals across our North Louisiana Acreage. Furthermore, we also believe that we may add horizontal drilling locations across our entire acreage position through downspacing.

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

Management and technical teams with substantial technical and operational expertise. Our management and technical teams have significant industry experience and a long history of collaboration in the identification, execution and integration of acquisitions and in cost-efficient management of profitable, large-scale drilling programs. Additionally, we have substantial expertise in advanced drilling and completion technologies and decades of collective experience in operating in the Eagle Ford and North Louisiana. Mr. Graham, our Chief Executive Officer, and Mr. Bahr, our President, co-founded one of the predecessors to, and Mr. Graham served as Chief Executive Officer of, Memorial Resource Development Corp. (“MRD”), which pioneered the horizontal redevelopment of the Terryville Complex, participating in the drilling of MRD’s initial 55 horizontal wells. Further, our management team has a significant economic interest in us directly and through its equity interests in each of WildHorse Holdings and Esquisto Holdings. We believe our management team is motivated to use its experience in identifying and creating value across our acreage and drilling highly productive wells to deliver attractive returns and maintain safe and reliable operations.

Geographically advantaged assets with significant midstream infrastructure to service our production. Our acreage position is in close proximity to end markets for oil, natural gas and NGLs, providing us with a regional price advantage. For example, low oil and natural gas basis differentials along the Gulf Coast represent a

competitive advantage when compared to other plays, such as the Marcellus, Utica, Permian and DJ. Recently developed and low-cost legacy infrastructure is in place across significant portions of our acreage to support our development program. In addition, we own and operate a large portion of our necessary midstream infrastructure which provides us with improved netbacks. On our Eagle Ford Acreage, we own substantial fresh water supply and storage and are in the process of developing a saltwater disposal well. On our North Louisiana Acreage, we own and operate a gathering system with capacity of approximately 250 MMcf/d as of December 31, 2016, as well as two saltwater disposal wells. Our midstream infrastructure allows us to realize lower operating costs and provides us with increased flexibility in our development program. In addition, while not currently contemplated, our midstream infrastructure could prove to be a future source of additional capital if monetized at an attractive valuation.

As of June 30, 2017, WildHorse Holdings, Esquisto Holdings, Acquisition Co. Holdings, NGP XI US Holdings, L.P. (“NGP XI”), and management directly own 21.0%, 38.3%, 2.5%, 49.8% and 2.6%, respectively, of our common stock. WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings are controlled by NGP. As of June 30, 2017, NGP and its affiliates (through WildHorse Holdings, Esquisto Holdings, Acquisition Co. Holdings and NGP XI) beneficially owned approximately 70.8% of our common stock. The Carlyle Investor owns all 435,000 shares of the Preferred Stock.

Our reserve estimates as of December 31, 2016 included in this prospectus are based on evaluations prepared by our management and audited by the independent petroleum engineering firm of Cawley in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Evaluation Engineers and definitions and guidelines established by the SEC. Our independent reserve engineers were selected for their historical experience and geographic expertise in engineering similar resources.

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

Our internal staff of petroleum engineers and geoscience professionals works closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of data furnished to our independent reserve engineers in their reserve auditing process. Periodically, our technical team meets with the independent reserve engineers to review properties and discuss methods and assumptions used by us to prepare reserve estimates.

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

For the year ended December 31, 2016, our reserve estimates and related reports were prepared internally and reviewed and approved by Jason Pearce. Mr. Pearce is our Senior Vice President, Reserves and has approximately 18 years of experience in oil and gas operations, reservoir engineering, reserve management, unconventional reservoir characterization and strategic planning. Cawley performed audits of our internally prepared reserves estimates on our proved reserves as of December 31, 2016. Our proved reserves are, in the aggregate, reasonable and within the established audit tolerance guidelines of 10%. The reports of Cawley contain further discussion of the reserves estimates and its audit procedure.

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

The following table presents the estimated net proved oil and natural gas reserves as of December 31, 2016, based on our audited reserve reports.

As of December 31, 2016, we had 105.2 MMBoe of proved undeveloped reserves consisting of 68.3 MBbls of oil, 179.2 MMcf of natural gas and 7.1 MBbls of NGLs. None of our PUDs as of December 31, 2016 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.

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.

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, 2016, 2015 and 2014:

Historically, commodity prices have been extremely volatile and we expect this volatility to continue for the foreseeable future. For example, for the three years ended December 31, 2016, the NYMEX-WTI oil spot price ranged from a high of $107.95 per Bbl to a low of $26.19 per Bbl, while the NYMEX-Henry Hub natural gas spot price ranged from a high of $8.15 per MMBtu to a low of $1.49 per MMBtu. For the year ended December 31, 2016, the West Texas Intermediate posted price ranged from a high of $54.01 per Bbl on December 28, 2016 to a low of $26.19 per Bbl on February 11, 2016 and the Henry Hub spot market price ranged from a high of $3.80 per MMBtu on December 7, 2016 to a low of $1.49 per MMBtu on March 4, 2016. NGL prices have also suffered significant recent declines. The continuation of low prices for oil or natural gas could materially and adversely affect our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce and our access to capital.

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

For a description of ours, our predecessor’s and the previous owners’ combined historical production, revenues and average sales prices and unit costs, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations.”

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, 2016, 2015 and 2014, respectively:

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, 2016.

The following table sets forth certain information regarding the total developed and undeveloped acreage in which we owned an interest as of December 31, 2016. Approximately 49% of our net Eagle Ford Acreage and 46% of our net North Louisiana Acreage was held by production at December 31, 2016.

Included in our North Louisiana Acreage in the table above are approximately 12,848 net acres we have the right to lease pursuant to an oil and gas lease option agreement with affiliates of Weyerhaeuser Company (“Weyerhaeuser”). Pursuant to that agreement, we have the right, upon notice to Weyerhaeuser, to lease acreage in exchange for a specified bonus payment. Upon such notice and our payment of the applicable bonus payment, Weyerhaeuser is obligated under the option agreement to enter into a three-year lease with us for the acreage we specify in the notice. The purchase price of this option was $0.5 million, and in addition, we also made a prepayment of $0.4 million as an initial lease bonus for 1,285 unspecified net acres associated with leases under the option. In October 2016, we made a payment of $1.5 million to extend the option for one year, as further described below.

The following table sets forth the number of total net undeveloped acres as of December 31, 2016 across our Eagle Ford and North Louisiana Acreage that will expire in 2017, 2018, 2019, 2020 and 2021, 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.

We intend to extend substantially all of the net acreage associated with our drilling locations through a combination of development drilling and leasehold extension and renewal payments. Of the 49,016 net acres expiring in 2017 across our Eagle Ford Acreage, we have the option to extend or renew the leases covering 17,251 net acres and have budgeted approximately $9.9 million in 2017 to execute extensions and renewals. With respect to the remaining 31,765 net acres for which we do not have an option to extend or renew in the Eagle Ford, 3,716 net acres are associated with 30 gross (20.6 net) wells of proved undeveloped reserves where the leases covering such expected wells will expire prior to our expected drilling date though we expect to extend or renew such leases. Further, with respect to the total remaining 28,049 net acres for which we do not have an option to extend or renew in the Eagle Ford, we intend to retain substantially all such acreage by negotiating lease extensions or renewals or drilling wells. Of the 42,971 net acres expiring in 2017 across our North Louisiana Acreage, we have the option to extend 22,762 of the 26,560 net acres in the RCT and Weyerhaeuser

Areas, and we have budgeted approximately $14.2 million in 2017 to execute such extensions and renewals. In October 2016, we executed a second amendment to an option for an oil and gas lease agreement with affiliates of Weyerhaeuser to extend our option to lease approximately 12,848 net acres to October 2017, which we refer to in this prospectus as our “Weyerhaeuser Area.” Upon notice and payment of the applicable lease bonus payment, we can enter into a three-year lease covering all such acreage. With respect to the remaining 3,798 net acres for which we do not have an option to extend or renew, we have not assigned any proved undeveloped reserves to such locations, although we intend to retain substantially all such acreage by negotiating lease extensions or renewals or drilling wells. We also have 16,411 net acres in our North Louisiana Acreage expiring in 2017 other areas. We plan to extend or renew approximately 1,211 net acres for an estimated cost of approximately $0.7 million and intend to let the remainder of this acreage expire. Accordingly, we have not assigned any drilling locations to such acreage. Please see “Risk Factors—Risks Related to Our Business—Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage or the leases are renewed.”

The following table describes the development and exploratory wells drilled on our acreage during the years ended December 31, 2016, 2015 and 2014. At December 31, 2016, 5.0 gross (4.1 net) wells were in various stages of completion.

All wells drilled were productive wells, except for one development well drilled in our North Louisiana Acreage during the year ended December 31, 2014 and one exploratory well drilled in our North Louisiana Acreage during the year ended December 31, 2015, each of which was not productive.

In July 2015, we reduced our drilling program in our North Louisiana Acreage to one rig in response to low commodity prices and continued operating a one-rig drilling program through February 2016. Similarly, in early October 2015, we reduced our drilling program in our Eagle Ford Acreage to one rig, which we ran until February 2016, at which point we ceased drilling due to the commodity price environment. We are currently running a seven-rig program, which we are utilizing on a well-to-well basis. We are not currently a party to any long-term drilling rig contracts.

We have no commitments to deliver a fixed and determinable quantity of our oil or natural gas production to customers in the near future under our existing contracts.

We were assigned a firm gas transportation service agreement with Regency Intrastate Gas LLC (“RIGS”) as a result of our predecessor’s property acquisition on August 8, 2013. Under the terms of the agreement, we are obligated to pay total daily transportation fees not to exceed $0.30 per MMBtu per day for quantities of 40,000 MMBtu per day to RIGS until March 5, 2019.

We have leased or acquired approximately 467,319 gross (371,198 net) acres where we had a weighted-average working interest of approximately 79%, as of December 31, 2016. As operator of a majority of our acreage, we design and manage the development of a well and supervise operation and maintenance activities on a day-to-day basis. Independent contractors engaged by us provide all the equipment and personnel associated with these activities. We employ petroleum engineers, geologists and land professionals who work to improve production rates, increase reserves and lower the cost of operating our oil and natural gas properties.

We maintain active development of our infrastructure to reduce lease operating costs and support our drilling schedule and production growth. Our production facilities are located near the producing well and consist of storage tanks, two-phase and three-phase separation equipment, flowlines, metering equipment and safety systems. Predominate artificial lift methods include foamer, gas, plunger and rod lift.

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

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

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 2016 or 2015, and 10% or more of our predecessors’ revenue during 2014.

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

No other purchaser accounted for 10% or more of our revenue on a combined basis in the years ended December 31, 2016 or 2015 or of our predecessors’ revenue in the year ended December 31, 2014. The loss of any such purchaser could adversely affect our revenues in the short term. However, based on the current demand for oil and natural gas and the availability of other purchasers, we believe that the loss of any such purchaser as a purchaser would not have a material adverse effect on our financial condition and results of operations because crude oil and natural gas are fungible products with well-established markets and numerous purchasers.

The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our larger or more integrated competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties.

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

Weather conditions can affect the demand for, and prices of, oil and natural gas. 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.

As is customary in the oil and natural gas industry, we initially conduct only a cursory review of the title to our properties in connection with acquisition of leasehold acreage. At such time as we determine to conduct drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects prior to commencement of drilling operations. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. We have obtained title opinions on substantially all of our producing properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and natural gas industry.

Prior to completing an acquisition of producing oil and natural gas leases, we perform title reviews on the most significant leases and, depending on the materiality of properties, we may obtain a title opinion, obtain an updated title review or opinion or review previously obtained title opinions. Our oil and natural gas properties are subject to customary royalty and other interests, liens for current taxes and other burdens which we believe do not materially interfere with the use of or affect our carrying value of the properties.

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

The typical oil and natural gas lease agreement covering our properties provides for the payment of royalties to the mineral owner for all oil and natural gas produced from any wells drilled on the leased premises. The lessor royalties and other leasehold burdens on our properties generally range from approximately 20% to 30%.

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

venting or flaring of natural gas, and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells.

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

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

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

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

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

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

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

Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates and regulations regarding access are equally applicable to all comparable shippers, we believe that the regulation of oil

transportation will not affect our operations in any way that is of material difference from those of our competitors who are similarly situated.

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

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

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

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

Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. Although FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering function or a jurisdictional transmission function,

FERC’s determinations as to the classification of facilities are done on a case-by-case basis. To the extent that FERC issues an order that reclassifies certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, and depending on the scope of that decision, our costs of getting gas to point of sale locations may increase. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress. State regulation of natural gas gathering facilities generally includes various occupational safety, environmental and, in some circumstances, nondiscriminatory-take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.

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

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

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

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

On January 3, 2012, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, or the Pipeline Safety Act, was signed into law. In addition to reauthorizing the PSIA through 2015, the Pipeline Safety Act

expanded the DOT’s authority under the PSIA and requires the DOT to evaluate whether integrity management programs should be expanded beyond high consequence areas, authorizes the DOT to promulgate regulations requiring the use of automatic and remote-controlled shut-off valves for new or replaced pipelines, and requires the DOT to promulgate regulations requiring the use of excess flow values where feasible. In addition, new pipeline safety legislation, the “Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016” (the “PIPES Act”), was signed into law in June 2016. The PIPES Act provides PHMSA with additional authority to address imminent hazards by imposing emergency restrictions, prohibitions, and safety measures on owners and operators of gas or hazardous liquids pipeline facilities. The Act also directs PHMSA to issue minimum safety standards for natural gas storage facilities by June 2018, and calls for a review, study, and analysis of a number of issues related to pipeline management and safety.

PHMSA has also proposed additional regulations for gas pipeline safety. For example, in March 2016 PHMSA proposed a rule that would explain integrity management requirements beyond “High Consequence Areas” to apply to gas pipelines in newly defined “Moderate Consequence Areas.” Many gas pipelines that were in place before 1970, and thus grandfathered from certain pressure testing obligations, would be required to be pressure tested to determine their maximum allowable operating pressures. Many gathering lines in rural areas that are currently not regulated at the federal level would also be covered by this proposal. Any new or amended pipeline safety regulations may require us to incur additional capital expenditures and may increase our operating costs. We cannot predict what future action the DOT will take, but we do not believe that any regulatory changes will affect us in a way that materially differs from the way they will affect other natural gas gatherers with which we compete.

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

Our oil and natural gas development operations are subject to numerous stringent federal, regional, state and local statutes and regulations governing occupational safety and health, the discharge of materials into the environment or otherwise relating to environmental protection, some of which carry substantial administrative, civil and criminal penalties for failure to comply. These laws and regulations may require the acquisition of a permit before drilling or other regulated activity commences; restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling, production and transporting through pipelines; govern the sourcing and disposal of water used in the drilling and completion process; limit or prohibit drilling activities in certain areas and on certain lands lying within wilderness, wetlands, frontier, seismically active areas and other protected areas; require some form of remedial action to prevent or mitigate pollution from former operations such as plugging abandoned wells or closing earthen pits; establish specific safety and health criteria addressing worker protection; and impose substantial liabilities for pollution resulting from operations or failure to comply with regulatory filings. In addition, these laws and regulations may restrict the rate of production.

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

The Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (“CERCLA”), also known as the “Superfund” law, and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the current and past owner or operator of the disposal site or the site where the release occurred and persons that disposed or arranged for the disposal of the hazardous substances at the site where the release occurred. Under CERCLA, such persons may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We are able to control directly the operation of only those wells with respect to which we act as operator. Notwithstanding our lack of direct control over wells operated by others, the failure of an operator other than us to comply with applicable environmental regulations may, in certain circumstances, be attributed to us. We generate materials in the course of our operations that may be regulated as hazardous substances but we are unaware of any liabilities for which we may be held responsible that would materially and adversely affect us.

The Resource Conservation and Recovery Act (“RCRA”) and analogous state laws, impose detailed requirements for the generation, handling, storage, treatment and disposal of nonhazardous and hazardous solid wastes. RCRA specifically excludes drilling fluids, produced waters and other wastes associated with the development or production of crude oil, natural gas or geothermal energy from regulation as hazardous wastes. However, these wastes may be regulated by the EPA or state agencies under RCRA’s less stringent nonhazardous solid waste provisions, state laws or other federal laws. Moreover, it is possible that these particular oil and natural gas development and production wastes now classified as nonhazardous solid wastes could be classified as hazardous wastes in the future. For example, from time to time various environmental groups have challenged the EPA’s exemption of certain oil and gas wastes from RCRA. A loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in an increase in our costs to manage and dispose of generated wastes, which could have a material adverse effect on our results of operations and financial position. In addition, in the course of our operations, we generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste compressor oils that may be regulated as hazardous wastes if such wastes have hazardous characteristics. Although the costs of managing hazardous waste may be significant, we do not believe that our costs in this regard are materially more burdensome than those for similarly situated companies.

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

The Clean Water Act and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other oil and natural gas wastes, into or near navigable waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a

permit issued by the EPA or the state. The discharge of dredge and fill material in regulated waters, including wetlands, is also prohibited, unless authorized by a permit issued by the U.S. Army Corps of Engineers (the “Corps”). In September 2015, the EPA and the Corps issued new rules defining the scope of the EPA’s and the Corps’ jurisdiction under the Clean Water Act with respect to certain types of waterbodies and classifying these waterbodies as regulated wetlands. The rule has been challenged in court on the grounds that it unlawfully expands the reach of the Clean Water Act, and implementation of the rule has been stayed pending resolution of the court challenge. In February 2017, President Trump issued an executive order directing the EPA and the Corps to review the rule and to publish a proposed rule rescinding or revising the rule. In June 2017, pursuant to the executive order, the EPA and Corps formally proposed to rescind the rule. Repeal of or revisions to the rule will require the EPA and the Corps to initiate a rulemaking, which is subject to public notice and comment, as well as judicial challenges. At present we cannot predict the outcome of the pending litigation or any revisions to the rule. To the extent the rule expands the scope of the Clean Water Act’s jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. Obtaining permits has the potential to delay the development of oil and natural gas projects. These laws and any implementing regulations provide for administrative, civil and criminal penalties for any unauthorized discharges of oil and other substances in reportable quantities and may impose substantial potential liability for the costs of removal, remediation and damages.

Pursuant to these laws and regulations, we may be required to obtain and maintain approvals or permits for the discharge of wastewater or storm water and are required to develop and implement spill prevention, control and countermeasure plans, also referred to as “SPCC plans,” in connection with on-site storage of significant quantities of oil. We are currently undertaking a review of recently acquired oil properties to determine the need for new or updated SPCC plans and, where necessary, we will be developing or upgrading such plans and implementing the physical and operation controls imposed by these plans, the costs of which are not expected to be material.

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

The federal Clean Air Act and comparable state laws restrict the emission of air pollutants from many sources (e.g., compressor stations), through the imposition of air emissions standards, construction and operating permitting programs and other compliance requirements. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. For example, in October 2015, the EPA lowered the National Ambient Air Quality Standard (“NAAQS”) for ozone from 75 to 70 parts per billion.

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

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

In response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment, the EPA has adopted regulations pursuant to the federal Clean Air Act to reduce GHG emissions from various sources. For example, the EPA requires certain large stationary sources to obtain preconstruction and operating permits for pollutants regulated under the Prevention of Significant Deterioration and Title V programs of the Clean Air Act. Facilities required to obtain preconstruction permits for such pollutants are also required to meet “best available control technology” standards that are being established by the states. These regulatory requirements could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. The EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and natural gas production sources in the United States on an annual basis, which include certain of our operations. In June 2016, the EPA published performance standards that establish new controls for emissions of methane from new, modified or reconstructed sources in the oil and natural gas sector, including production, processing, transmission and storage activities. Compliance will require enhanced record-keeping practices, the purchase of new equipment, and increased frequency of maintenance and repair activities to address emissions leakage at certain well sites and compressor stations, and also may require hiring additional personnel to support these activities or the engagement of third party contractors to assist with and verify compliance. Several states and industry groups have filed suit before the D.C. Circuit challenging the EPA’s implementation of the methane rule and legal authority to issue the methane rule. However, in April 2017, the EPA announced that it will review the rule for new, modified, and reconstructed sources and will initiate proceedings to potentially revise or rescind portions of the methane rule. Additionally, the EPA previously issued a stay of the June 3, 2017 compliance date applicable to fugitive emissions monitoring requirements for 90 days. However, on July 31, 2017 the D.C. Circuit issued an order carrying the methane rule back into effect. The court’s decision does not limit the EPA’s ability to reconsider the methane rule pursuant to notice and comment rulemaking. The D.C. Circuit’s decision on whether to rehear the case en banc is still pending. The new rule will, and proposed rules could, result in increased compliance costs on our operations. The EPA has also announced that it intends to impose methane emission standards for existing sources but, to date, has not yet issued a proposal. And in 2015, EPA published a rule, known as the Clean Power Plan, to limit GHGs from electric power plants. In February 2016, the Supreme Court stayed the implementation of the Clean Power Plan while legal challenges to the rule proceed. Depending on the ultimate outcome of those challenges, and how various states choose to implement this rule, it may alter the power generation mix between natural gas, coal, oil, and alternative energy sources, which would ultimately affect the demand for natural gas and oil in electric generation.

programs typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. In addition, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues. For example, in April 2016, the United States signed the Paris Agreement, which requires member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. The Paris Agreement entered into force in November 2016 and includes pledges to voluntarily limit or reduce future emissions. However, in June 2017, the President stated that the United States would withdraw from the Paris Agreement, but may enter into a future international agreement related to GHGs. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, resulting in an effective exit date of November 2020. The United States’ adherence to the exit process is uncertain and/or the terms on which the United States may reenter the Paris Agreement or a separately negotiated agreement are unclear at this time. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations, as well as delay or restrict our ability to permit GHG emissions from new or modified sources. Substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas we produce and lower the value of our reserves.

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

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

Certain governmental reviews are either underway or have been conducted that focus on the environmental aspects of hydraulic fracturing practices. For example, in December 2016, the EPA released its final report on the

potential impacts of hydraulic fracturing on drinking water resources. The EPA report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits.

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

The Endangered Species Act (“ESA”) and (in some cases) comparable state laws were established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. We may conduct operations on oil and natural gas leases in areas where certain species that are or could be listed as threatened or endangered are known to exist. The U.S. Fish and Wildlife Service may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to land use and may materially delay or prohibit land access for oil and natural gas development. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia in September 2011, the U.S. Fish and Wildlife Service is required to make a determination on listing of more than 250 species as endangered or threatened under the ESA by no later than completion of the agency’s 2017 fiscal year. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The federal government in the past has pursued enforcement actions against oil and natural gas companies under the Migratory Bird Treaty Act after dead migratory birds were found near reserve pits associated with drilling activities. The identification or designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures or could result in limitations on our development activities that could have an adverse impact on our ability to develop and produce reserves. If we were to have a portion of our leases designated as critical or suitable habitat, it could adversely impact the value of our leases.

We are subject to the requirements of the Occupational Safety and Health Act (“OSHA”) and comparable state statutes whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the Emergency Planning and Community Right-to-Know Act and comparable state statutes and any implementing regulations require that we organize and/or disclose information about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governmental authorities and citizens.

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.

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.

As of December 31, 2016, we had 85 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.

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

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

Our principal executive office is located at 9805 Katy Freeway, Suite 400, Houston, Texas 77024. Our main telephone number is (713) 568-4910.

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

We are currently considered an “emerging growth company,” within the meaning of the Securities Act, for purposes of the SEC’s executive compensation disclosure rules. In accordance with such rules, we are required to provide a Summary Compensation Table and an Outstanding Equity Awards at Fiscal Year-End table, as well as limited narrative disclosures regarding executive compensation for our last completed fiscal year. Further, our reporting obligations extend only to our “named executive officers,” who are the individuals who served as our principal executive officer and our two other most highly compensated officers who served as executive officers during the last completed fiscal year. This executive compensation disclosure provides an overview of the 2016 executive compensation program for our named executive officers identified below. For 2016, our named executive officers were:

We employ a compensation philosophy that emphasizes pay-for-performance, based on a combination of our performance and the individual’s impact on our performance, which results in the majority of each officer’s compensation being placed at risk. The compensation of our executive and non-executive officers includes a significant component of incentive compensation based on our performance. The performance metrics governing incentive compensation are not tied in any way to the performance of any other entities. We believe this pay-for-performance approach generally aligns the interests of our executive officers with that of our stockholders, and at the same time enables us to maintain a lower level of base overhead in the event our operating and financial performance fails to meet expectations.

Our executive compensation is designed to attract and retain individuals with the background and skills necessary to successfully execute our business model in a demanding environment, to motivate those individuals to reach near-term and long-term goals in a way that aligns their interest with that of our stockholders, and to reward success in reaching such goals. We use three primary elements of compensation to fulfill that design—salary, cash bonus and long-term equity incentive awards. Cash bonuses and equity incentives (as opposed to salary) represent the performance driven elements. They are also flexible in application and can be tailored to meet our objectives. The determination of specific individuals’ cash bonuses reflects their relative contribution to achieving or exceeding annual goals, and the determination of specific individuals’ long-term incentive awards is based on their expected contribution in respect of longer term performance objectives.

We do not have a defined benefit or pension plan for our executive officers because we believe such plans primarily reward longevity rather than performance. We provide a basic benefits package generally to all employees, which includes a 401(k) plan and health, disability and life insurance.

We were formed in August 2016 and did not incur any cost or liability with respect to compensation, management incentive or retirement benefits for our executive officers for any prior periods prior to our formation. Accordingly, the following table presents the executive compensation awarded to, earned by or paid to our named executive officers for all of 2016 (and with respect to Jay C. Graham, for the fiscal year ended December 31, 2015), including amounts paid by our predecessor prior to our formation.

The following table reflects all equity awards granted to our named executive officers that were outstanding as of December 31, 2016.

In 2014, Mr. Graham received an award of WHR II Incentive Units pursuant to the WHR II LLC Agreement. In connection with our initial public offering, the WHR II Incentive Units were exchanged for the WildHorse Investment Incentive Units pursuant to the Limited Liability Company Agreement of WildHorse Investment (as amended from time to time, the “WildHorse Investment LLC Agreement”). The WildHorse Investment Incentive Units represent actual (non-voting) equity interests in WildHorse Investment. The WildHorse Investment Incentive Units are divided into five tiers. Tier I and Tier II incentive units each vest in three equal annual installments beginning on the original date of grant applicable to the WHR II Incentive Units. A potential payout for each tier of WildHorse Investment Incentive Units will occur when a specified level of cumulative cash distributions has been received by the capital interest holding members of WildHorse Investment. The assets of WildHorse Investment consist only of the equity interests in WildHorse Holdings that it received in connection with our initial public offering. Further, the assets of WildHorse Holdings consist only of the shares of our common stock that it received in connection with our initial public offering. Accordingly, we expect that the only event that would cause cash distributions to the capital interest holding members of WildHorse Investment would either be (i) sales of our common stock by WildHorse Holdings or (ii) in-kind distributions of shares of our common stock by WildHorse Holdings to its members (including WildHorse Investment).

While any payments, distributions and settlements made by WildHorse Investment with respect to the WildHorse Investment Incentive Units will not involve any cash payment by us, we will recognize non-cash compensation expense within general and administrative expenses, which may be material, in the period in which the applicable performance conditions are probable of being satisfied. We will receive a deemed capital

contribution with respect to such compensation expense. Because we will not be a party to the limited liability company agreement of WildHorse Investment, we cannot be certain that the terms of the WildHorse Investment Incentive Units will remain the same in the future.

WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings Incentive Units

In connection with our initial public offering, our named executive officers were granted awards of WildHorse Holdings Incentive Units, Esquisto Holdings Incentive Units and Acquisition Co. Holdings Incentive Units pursuant to the limited liability company agreements of WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings, respectively. The WildHorse Holdings Incentive Units, Esquisto Holdings Incentive Units and Acquisition Co. Holdings Incentive Units represent actual (non-voting) equity interests in WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings. The WildHorse Holdings Incentive Units, Esquisto Holdings Incentive Units and Acquisition Co. Holdings Incentive Units are divided into two tiers. Tier I incentive units and Tier II incentive units each vest in three equal annual installments beginning on the first anniversary of the applicable date of grant. A potential payout for each tier of WildHorse Holdings Incentive Units, Esquisto Holdings Incentive Units or Acquisition Co. Holdings Incentive Units, as applicable, will occur when a specified level of cumulative cash distributions has been received by the capital interest holding members of WildHorse Holdings, Esquisto Holdings or Acquisition Co. Holdings, respectively. The assets of each of WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings consist only of the shares of our common stock that each received in connection with our initial public offering. Accordingly, we expect that the only event that would cause cash distributions to the capital interest holding members of WildHorse Holdings, Esquisto Holdings or Acquisition Co. Holdings, as applicable, would be the sale of our common stock by WildHorse Holdings, Esquisto Holdings or Acquisition Co. Holdings, respectively.

While any payments, distributions and settlements made by WildHorse Holdings, Esquisto Holdings or Acquisition Co. Holdings with respect to the WildHorse Holdings Incentive Units, Esquisto Holdings Incentive Units or Acquisition Co. Holdings Incentive Units, as applicable, will not involve any cash payment by us, we will recognize non-cash compensation expense within general and administrative expenses, which may be material, in the period in which the applicable performance conditions are probable of being satisfied. We will receive a deemed capital contribution with respect to such compensation expense. Because we will not be a party to the limited liability company agreements of WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings, we cannot be certain that the terms of the WildHorse Holdings Incentive Units, Esquisto Holdings Incentive Units and Acquisition Co. Holdings Incentive Units will remain the same in the future.

In connection with our initial public offering, on December 19, 2016, Messrs. Cozby and Roane were granted awards of restricted stock pursuant to the WRD Plan. Messrs. Cozby and Roane each received an award of 166,667 shares of restricted stock. The restricted stock awards generally vest in equal one-third installments on each of the first three anniversaries of the date of grant.

We do not currently maintain any employment agreements with our executive officers. However, we believe that it is important to provide our named executive officers with certain severance and change in control payments or benefits in order to establish a stable work environment for the individuals responsible for our day to day management. As such, we adopted the Executive Change in Control and Severance Plan (the “CIC Plan”) in connection with our initial public offering.

The CIC Plan provides certain severance and change in control benefits to our named executive officers and certain other executives who are selected by our board of directors, or a committee thereof (as applicable, the “Committee”). Upon the occurrence of a “change in control” (as defined below), all outstanding unvested equity

awards held by a participant will immediately become fully vested. Further, if a participant’s employment with us is terminated:

For purposes of the CIC Plan, a “change in control” generally means the occurrence of any of the following events:

The CIC Plan does not provide a tax gross-up provision for federal excise taxes that may be imposed under section 4999 of the Code. Instead, the CIC Plan includes a modified cutback provision, which states that, if amounts payable to a plan participant under the CIC Plan (together with any other amounts that are payable by us as a result of a change in control (the “Payments”) exceed the amount allowed under section 280G of the Code for such participant, thereby subjecting the participant to an excise tax under section 4999 of the Code, then the Payments will either be: (i) reduced to the level at which no excise tax applies, such that the full amount of the Payments would be equal to $1 less than three times the participant’s “base amount,” which is generally the average W-2 earnings for the five calendar years immediately preceding the date of termination, or (ii) paid in full, which would subject the participant to the excise tax. We will determine, in good faith, which alternative produces the best net after tax position for a participant.

The CIC Plan may be amended or terminated by resolution of two-thirds of the Board, except that (i) no amendment adopted within one year prior to a change in control may adversely affect any participant without his or her consent, (ii) no amendment may be made at the request of a third party that takes steps to effectuate a change in control or otherwise in connection with a change in control and (iii) no amendment may be made within two years following the occurrence of a change in control that would adversely affect any individual who is a participant on the change in control date.

We have not maintained, and do not currently intend to maintain, a defined benefit pension plan or nonqualified deferred compensation plan. Instead, our employees, including our named executive officers, may participate in a retirement plan sponsored by WildHorse Resources Management Company, our wholly owned subsidiary, intended to provide benefits under section 401(k) of the Code (the “401(k) Plan”) pursuant to which employees are allowed to contribute a portion of their base compensation to a tax-qualified retirement account. We provide matching contributions equal to 100% of the first 6% of employees’ eligible compensation contributed to the 401(k) Plan up to a statutory limit, which was $18,000 for the calendar years 2015 and 2016. Employees are immediately 100% vested in the matching contributions made to their 401(k) Plan account and are always 100% vested in the employee contributions they make to their 401(k) Plan account. Employees may generally receive a distribution of the vested portion of their 401(k) Plan account upon (i) a termination of employment, (ii) normal retirement, (iii) disability or (iv) death.

Our supplemental insider trading policy prohibits employees, officers and directors from engaging in hedging transactions and certain transactions involving derivatives in the Company’s securities, such as short selling, transactions in debt that may be convertible into Company common stock, trading in Company-based option contracts, transactions in straddles or collars, and writing puts or calls.

Our supplemental insider trading policy also prohibits the purchasing by employees, officers and directors of the Company’s securities on margin or pledging the Company’s securities as collateral for a loan, without the prior consent of the Board.

The following table sets forth the beneficial ownership of our common stock owned as of September 29, 2017 by:

Except as otherwise noted, the person or entities listed below have sole voting and investment power with respect to all shares of our common stock beneficially owned by them, except to the extent this power may be shared with a spouse. All information with respect to beneficial ownership has been furnished by the respective 5% or more stockholders, directors, director nominees or named executive officers, as the case may be. Unless otherwise noted, the mailing address of each listed beneficial owner is c/o 9805 Katy Freeway, Suite 400, Houston, TX 77024.

Each of the members of WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings, including our executive officers, will have an indirect interest in the shares of common stock sold by WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings.

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 matters impacting the Preferred Stock. However, the Preferred Stock is not entitled to vote with the common stock on an as-converted basis, is not convertible into our common stock and is not entitled to the board election rights described below until the Requisite Approvals Notice Date.

In connection with our initial public offering, we engaged in reorganization events and transactions with certain affiliates and our existing equity holders. Pursuant to a contribution agreement, (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 Resources II, LLC (“Esquisto II”) exchanged all of their interests in Esquisto II 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 II to Esquisto Holdings and the owner of WHE Holdings contributed all of its interests in Acquisition Co. to WHE Holdings and (iii) WildHorse Holdings, Esquisto Holdings and WHE Holdings contributed all of the interests in WHR II, Esquisto II and Acquisition Co., respectively, to us in exchange for 21,200,084 shares, 38,755,330 shares and 2,563,266 shares, respectively, of our common stock. We refer to these reorganization transactions as the “Corporate Reorganization.” As a result of the Corporate Reorganization, WHR II, Esquisto II and Acquisition Co. became direct, wholly owned subsidiaries of WildHorse Resource Development Corporation.

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

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

additive to and not intended to limit in any way the rights that WildHorse Holdings, Esquisto Holdings, Acquisition Co. Holdings and NGP XI or any of their affiliates may have to nominate, elect or remove our directors under our certificate of incorporation, bylaws or the DGCL.

As conditions to closing of the Acquisition, on June 30, 2017, the Company amended and restated its existing registration rights agreement (the “A&R Registration Rights Agreement”) with WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings (collectively, the “Sponsoring Holders”), NGP XI, Jay C. Graham and Anthony Bahr (together with KKR, the Carlyle Investor, the Sponsoring Holders and their permitted transferees, the “Holders”) in order to grant certain registration rights to KKR and the Carlyle Investor. Pursuant to the A&R Registration Rights Agreement, we have agreed to register the sale of shares of our common stock under the circumstances described below.

At any time after (i), for the Sponsoring Holders, the 180 lock-up period, related to our initial public offering, or (ii) for the Carlyle Investor, the first anniversary of the date of the A&R Registration Rights Agreement, and subject to the limitations set forth below, each of the Sponsoring Holders and the Carlyle Investor (or its permitted transferees) has 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 are not obligated to effect a demand registration within 90 days after the closing of any underwritten offering of shares of our common stock. Further, we are not obligated to effect more than a total of four demand registrations for each of WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings, and more than a total of six demand registration for the Carlyle Investor.

Subject to certain exceptions, we are also not 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. Once we are eligible to effect a registration on Form S-3, any such demand registration may be for a shelf registration statement. We will be required to use reasonable best efforts to maintain the effectiveness of any such registration statement until all such securities registered for resale thereunder cease to be registrable securities under such agreement.

In addition, each of the Sponsoring Holders (or its permitted transferees) has 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.

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 of the Holders (or its permitted transferees) of such proposal to allow them to include a specified number of their shares of our common stock in that registration statement or underwritten offering, as applicable. KKR was made a Holder under the A&R Registration Rights Agreement for purposes of obtaining such piggyback rights.

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.

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

Upon the closing of our initial public offering, we entered into a transition services agreement with CH4 Energy IV, LLC, PetroMax and Crossing Rocks Energy, LLC (collectively, the “Service Providers”), pursuant to which the Service Providers agreed to provide certain engineering, land, operating and financial services to us for six months relating to our Eagle Ford Acreage. In exchange for such services, we agreed to pay a monthly management fee to the Service Providers. NGP and certain former management members of Esquisto own the Service Providers. During the three and six months ended June 30, 2017, we paid the Service Providers $0.1 million.

Mr. Grant E. Sims has served as a member of our board of directors since February 2017. Mr. Sims has served as a director and Chief Executive Officer of the general partner of Genesis Energy Partners, L.P. (“Genesis”) since August 2006 and Chairman of the board of directors of the general partner since October 2012. Genesis is one of our purchasers of hydrocarbons and other liquids. During the three and six months ended June 30, 2017, we received $0.6 million and $1.5 million, respectively, from Genesis. During the fiscal year ended December 31, 2016, WildHorse received disbursements from Genesis of approximately $2.8 million, which is less than 1% of Genesis’ revenue for 2016. Mr. Graham’s sister-in-law, Erica Casias, is a non-officer employee of the Company since April 2010. Ms. Casias received total compensation from WildHorse in 2016 of approximately $124,000. In addition, Mr. Brannon’s son, Richard D. Brannon, Jr., who had been an employee of CH4 Energy, joined WildHorse as a non-officer employee in connection with our initial public offering in December 2016. Mr. Brannon’s son received total compensation from WildHorse in 2016 of approximately $5,700.

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

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

Highmark Energy Operating, LLC. During the three and six months ended June 30, 2017, we, respectively, had net disbursements of less than $0.1 million to and net receipts of $0.1 million from Highmark Energy Operating, LLC (“Highmark”), a NGP affiliated company, for non-operated working interests in oil and natural gas properties we operate. During the year ended December 31, 2016, we received net payments of $0.2 million from Highmark.

Cretic Energy Services, LLC. During the year ended December 31, 2016, we made payments of $0.4 million to Cretic Energy Services, LLC, a NGP affiliated company, for services related to our drilling and completion activities. We recorded payments of $0.1 million for both the three and six months ended June 30, 2017.

PennTex Midstream Partners, LP. During the year ended December 31, 2016, we made net payments of $0.2 million to PennTex Midstream Partners, LP (“PennTex”) for the gathering, processing and transportation of natural gas and NGLs. PennTex was a NGP affiliated company until October 31, 2016. Our related party relationship ceased in the fall of 2016 when a third-party acquired controlling interests in PennTex.

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

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

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

Memorial Resource Development Corp. During the year ended December 31, 2016, we paid net payments of $0.1 million to MRD for non-operated working interests in oil and gas properties we operate. MRD was an NGP affiliated company until it was acquired by Range Resources Corporation in September 2016.

WHR II and WHR. During 2014 and 2015, WHR II issued promissory notes in favor of WHR II’s management to fund future capital commitments. As of December 31, 2015 and 2014, promissory note advances outstanding to WHR II’s management were $2.4 million and $1.7 million, respectively. Promissory note advances carry an interest rate of 2.5%. In 2015 and 2014 $0.1 million and $0.2 million in interest was accrued to the promissory notes, respectively. In 2015 and 2014, management paid $0.1 million and $0.3 million of promissory note interest, respectively. These promissory notes have been repaid and terminated.

WHR II and WHR, an entity formerly under common control with WHR II, entered into a Management Agreement in August 2013 pursuant to which WHR provided certain administrative and land services to WHR II. Further, on August 8, 2013, WHR II and WHR entered into an Asset and Cost Sharing Agreement where, among other things, WHR II and WHR agreed to share certain general and administrative costs. As a result of these agreements, WHR II made net payments of $5.0 million to WHR in 2014.

On June 18, 2014, (i) the Management Agreement and the Asset Cost Sharing Agreement were terminated, (ii) WHR II purchased WHRM from WHR for $0.2 million and (iii) WHR II, through WHRM, began providing accounting and operating transition services to WHR, including administrative and land services, pursuant to the Management Services Agreement.

As a result of the Management Services Agreement, WHR II made $57.6 million in net payments to WHR in 2015 but received net payments of $53.0 million from WHR and its affiliates in 2014. WHR II was owed $0.0 million and $1.6 million, net, as of December 31, 2015 and 2014, respectively. On February 25, 2015, the Management Services Agreement was terminated effective March 1, 2015.

WHR ceased being a related party in September 2016 when its parent company was acquired by a third party. During both the three and six months ended June 30, 2016, we paid net payments of less than $0.1 million to WHR’s parent company for non-operated working interests in oil and natural gas properties we operate.

During the year ended December 31, 2015, WHR II made payments of $1.0 million to Cretic Energy Services, LLC, a NGP affiliated company, for services related to drilling and completion activities.

Notes payable to members. During 2015 and 2014, Esquisto accrued $4.3 million and $2.1 million, respectively, as general and administrative expenses payable to its members, who historically have managed Esquisto. These liabilities have been recorded on the accompanying balance sheets as long-term notes payable to members. During the three and six months ended June 30, 2016, Esquisto accrued $1.1 million and $2.1 million, respectively, as general and administrative expenses payable to its members. In connection with our initial public

offering, the Esquisto notes payable to its members were paid off. Certain CH4 Energy entities received $3.6 million; Garland Exploration, LLC received $5.5 million; and Crossing Rocks Energy, LLC received $1.3 million. These entities are NGP affiliated companies.

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

Operator. Esquisto paid Petromax Operating Company, Inc. (“Petromax”), who was the operator of the majority of Esquisto’s wells, $981,000 and $218,000 during 2015 and 2014, respectively, and $0.3 million and $0.6 million during the three and six months ended June 30, 2016, respectively, for overhead charges on drilling and producing wells at market rates as set forth in joint operating agreements and in accordance with an operating agreement between Petromax and Esquisto. Petromax is owned 33.3% by Mike Hoover, the former Chief Operating Officer of Esquisto, who also indirectly owned one of the former members of Esquisto.

We maintain a policy for approval of related party transactions. The policy and procedures for reviewing related party transactions are not formally stated, but are derived from the Code of Business Conduct and Ethics and the charter of the Audit Committee. Under its charter, the Audit Committee is responsible for reviewing all material facts of all related party transactions, including transactions for which disclosure would be required under Item 404(a) of Regulation S-K. A “Related Party Transaction” is a transaction, arrangement or relationship in which we or any of our subsidiaries was, is or will be a participant, the amount of which involved exceeds $120,000, and in which any Related Person had, has or will have a direct or indirect material interest. A “Related Person” means:

You can find the definitions of certain terms used in this description under the subheading “—Certain Definitions.” In this description, the “Company” refers only to WildHorse Resource Development Corporation and not to any of its Subsidiaries. References to the “notes” in this section of the prospectus include both the notes issued on February 1 and September 19, 2017, which we collectively refer to as the old notes, and the new notes offered hereby, unless the context otherwise requires.

The Company will issue the new notes and issued the old notes under an indenture dated February 1, 2017, as supplemented, among itself, the Guarantors and U.S. Bank National Association, as trustee, which we refer to herein as the “indenture.” The terms of the notes include those stated in the indenture and those made part of the indenture by reference to the Trust Indenture Act.

The following description is a summary of the material provisions of the indenture. It does not restate the indenture in its entirety. We urge you to read the indenture because it, and not this description, defines your rights as holders of the notes. A copy of the indenture is filed as an exhibit to the registration statement of which this prospectus is a part. Certain defined terms used in this description but not defined below under “—Certain Definitions” have the meanings assigned to them in the indenture.

The registered holder of a note will be treated as the owner of it for all purposes. Only registered holders have rights under the indenture and all references to “holders” in this description are to registered holders of notes.

If the exchange offer contemplated by this prospectus is consummated, holders of old notes who do not exchange those notes for new notes in the exchange offer will vote together will holders of new notes for all relevant purposes under the indenture. In that regard, the indenture requires that certain actions by the holders thereunder must be taken, and certain rights must be exercised, by specified minimum percentages of the aggregate principal amount of the outstanding securities issued under the indenture. In determining whether holders of the requisite percentage in principal amount have given any notice, consent or waiver or taken any other action permitted under the indenture, any old notes that remain outstanding after the exchange offer will be aggregated with the new notes and the holders of such old notes and the new notes will vote together as a single class for all such purposes. Accordingly, all references herein to specified percentages in aggregate principal amount of the notes outstanding shall be deemed to mean, at any time after the exchange offer is consummated, such percentages in aggregate principal amount of the old notes and the new notes then outstanding.

However, the new notes, like the old notes, will be structurally subordinated to the Indebtedness and other obligations of the Subsidiaries of the Company that are not Guarantors, including the Company’s Unrestricted Subsidiaries. See “Risk Factors—Risks Related to the Notes—The notes and the guarantees are unsecured and effectively subordinated to our and the guarantors’ existing and future secured indebtedness and structurally subordinated to indebtedness of any future non-guarantor subsidiaries.”

Initially, the new notes, like the old notes, will be guaranteed by all of the Company’s Restricted Subsidiaries. In the future, other Restricted Subsidiaries of the Company that are not Guarantors may be required to guarantee the notes under the circumstances described below under “—Certain Covenants—Additional Note Guarantees.”

Accordingly, the notes are structurally subordinated to the Indebtedness and other obligations of the Subsidiaries of the Company that are not Guarantors. See “Risk Factors—Risks Related to the Notes—The notes and the guarantees are unsecured and effectively subordinated to our and the guarantors’ existing and future secured indebtedness and structurally subordinated to indebtedness of any future non-guarantor subsidiaries.” Currently, all of the Company’s Subsidiaries are “Restricted Subsidiaries.” However, under the circumstances described below under the caption “—Certain Covenants—Designation of Restricted and Unrestricted Subsidiaries,” the Company is permitted to designate certain of its Subsidiaries as “Unrestricted Subsidiaries.” The Company’s Unrestricted Subsidiaries are not subject to many of the restrictive covenants in the indenture and will not guarantee the notes.

The Company has issued $500 million in aggregate principal amount of old notes. In addition to the new notes offered hereby, the Company may issue additional notes under the indenture from time to time. Any such issuance of additional notes is subject to all of the covenants in the indenture, including the covenant described below under the caption “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock.” The old notes, the new notes and any additional notes subsequently issued under the indenture, together with any Exchange Notes, will be treated as a single class for all purposes under the indenture, including, without limitation, waivers, amendments, redemptions and offers to purchase; provided, however, that if any such additional notes are not fungible with the notes, such additional notes shall have a different CUSIP number (or other applicable identifying number). Unless expressly stated or the context requires otherwise, references to “notes” for all purposes of the indenture and this “Description of Notes” section include any additional notes actually issued. The Company may issue notes only in denominations of $2,000 and integral multiples of $1,000 in excess of $2,000. The notes will mature on February 1, 2025.

Interest on the notes accrues at the rate of 6.875% per annum and are payable semi-annually in arrears on February 1 and August 1. The Company makes each interest payment to the holders of record on the immediately preceding January 15 and July 15.

Interest on the new notes will accrue from August 1, 2017, the most recent interest payment date, or, if interest has already been paid on the old notes, from the date it was most recently paid. Interest is computed on the basis of a 360-day year comprised of twelve 30-day months.

If an interest payment date falls on a day that is not a Business Day, the interest payment to be made on such interest payment date will be made, without penalty, on the next succeeding Business Day with the same force and effect as if made on such interest payment date.

The Company will pay principal of, and interest and premium, if any, on notes in global form registered in the name of Cede & Co., the nominee of DTC, in immediately available funds, directly to DTC. If a holder of

certificated notes has given wire transfer instructions to the Company, the Company will pay all principal of, and interest and premium, if any, on, that holder’s notes in accordance with those instructions. All other payments on the certificated notes will be made at the office or agency of the paying agent and registrar within the City and State of New York unless the Company elects to make interest payments by check mailed to the noteholders at their addresses set forth in the register of holders.

The trustee currently acts as paying agent and registrar. The Company may change the paying agent or registrar without prior notice to the holders of the notes, and the Company or any of its Subsidiaries may act as paying agent or registrar.

A holder may transfer or exchange notes in accordance with the provisions of the indenture. The registrar and the trustee may require a holder, among other things, to furnish appropriate endorsements and transfer documents in connection with a transfer of notes. Holders are required to pay all taxes due on transfer. The Company will not be required to transfer or exchange any note selected for redemption. Also, the Company will not be required to transfer or exchange any note for a period of 15 days before a selection of notes to be redeemed or between a record date and the next succeeding interest payment date.

Like the old notes, the new notes will be guaranteed by all of the Company’s Restricted Subsidiaries. In the future, other Restricted Subsidiaries of the Company that are not Guarantors may be required to guarantee the notes under the circumstances described below under “—Certain Covenants—Additional Note Guarantees.” These Note Guarantees are joint and several obligations of the Guarantors. The obligations of each Guarantor under its Note Guarantee are limited as necessary to prevent that Note Guarantee from constituting a fraudulent conveyance under applicable law, although this limitation may not be effective to prevent the Note Guarantees from being voided in bankruptcy. See “Risk Factors—Risks Relating to the Notes—A subsidiary guarantee could be voided if it constitutes a fraudulent transfer under U.S. bankruptcy or similar state law, which would prevent the holders of the notes from relying on the subsidiary guarantor to satisfy claims.” A Guarantor may not sell or otherwise dispose of, in one or a series of related transactions, all or substantially all of its properties or assets to, or consolidate with or merge with or into (whether or not such Guarantor is the surviving Person) another Person, other than the Company or another Guarantor, unless:

(1) immediately after giving effect to such transaction or series of transactions, no Default or Event of Default exists; and

(a) the Person acquiring the properties or assets in any such sale or other disposition or the Person formed by or surviving any such consolidation or merger (if other than the Guarantor) unconditionally assumes all the obligations of that Guarantor under its Note Guarantee and the indenture pursuant to a supplemental indenture or other agreement in form reasonably satisfactory to the trustee; or

(b) such transaction or series of transactions does not violate the covenant described under the caption “—Repurchase at the Option of Holders—Asset Sales.”

(1) in connection with any sale or other disposition of all or substantially all of the properties or assets of that Guarantor, by way of merger, consolidation or otherwise, to a Person that is not (either before or after giving effect to such transaction) the Company or a Restricted Subsidiary of the Company, if the sale or other disposition does not violate the covenant described under the caption “—Repurchase at the Option of Holders—Asset Sales”;

(2) in connection with any sale or other disposition of the Capital Stock of that Guarantor to a Person that is not (either before or after giving effect to such transaction) the Company or a Restricted Subsidiary of the Company, if the sale or other disposition does not violate the covenant described under the caption “— Repurchase at the Option of Holders—Asset Sales” and the Guarantor ceases to be a Restricted Subsidiary of the Company as a result of the sale or other disposition;

(3) if the Company designates such Guarantor to be an Unrestricted Subsidiary in accordance with the applicable provisions of the indenture;

(4) upon legal defeasance or covenant defeasance as provided below under the caption “—Legal Defeasance and Covenant Defeasance” or upon satisfaction and discharge of the indenture as provided below under the caption “—Satisfaction and Discharge”;

(5) upon the liquidation or dissolution of such Guarantor provided no Default or Event of Default has occurred that is continuing;

(6) upon such Guarantor consolidating with, merging into or transferring all of its properties or assets to the Company or another Guarantor, and as a result of, or in connection with, such transaction such Guarantor dissolving or otherwise ceasing to exist; or

(7) at such time as such Guarantor ceases to guarantee or otherwise be an obligor with respect to any other Indebtedness of the Company or any other Guarantor in excess of the De Minimis Guaranteed Amount, provided no Event of Default has occurred that is continuing.

At any time prior to February 1, 2020, the Company may on any one or more occasions redeem up to 35% of the aggregate principal amount of notes (including, without limitation, the old notes, the new notes and additional notes, if any) issued under the indenture, in an amount not greater than the net cash proceeds of one or more Equity Offerings by the Company, upon notice as provided in the indenture, at a redemption price equal to 106.875% of the principal amount of the notes redeemed, plus accrued and unpaid interest, if any, to the date of redemption (subject to the rights of holders of notes on the relevant record date to receive interest on the relevant interest payment date); provided that:

(1) at least 65% of the aggregate principal amount of notes (including, without limitation, the old notes, the new notes and additional notes, if any) originally issued under the indenture (excluding notes held by the Company and its Subsidiaries) remains outstanding immediately after the occurrence of such redemption; and

(2) the redemption occurs within 180 days of the date of the closing of such Equity Offering.

At any time prior to February 1, 2020, the Company may on any one or more occasions redeem all or a part of the notes, upon notice as provided in the indenture, at a redemption price equal to 100% of the principal amount of the notes redeemed, plus the Applicable Premium as of, and accrued and unpaid interest to, the date of redemption, subject to the rights of holders of notes on the relevant record date to receive interest due on the relevant interest payment date.

Except pursuant to the preceding paragraphs and the penultimate paragraph under “—Repurchase at the Option of Holders—Change of Control,” the notes will not be redeemable at the Company’s option prior to February 1, 2020.

On or after February 1, 2020, the Company may on any one or more occasions redeem all or a part of the notes, upon notice as provided in the indenture, at the redemption prices (expressed as percentages of principal

amount) set forth below, plus accrued and unpaid interest, if any, on the notes redeemed to the applicable date of redemption, subject to the rights of holders of notes on the relevant record date to receive interest on the relevant interest payment date, if redeemed during the twelve-month period beginning on February 1 of the years indicated below:

The Company is not required to make mandatory redemption or sinking fund payments with respect to the notes. The Company may at any time and from time to time purchase notes in the open market or otherwise, in each case without any restriction under the indenture.

If less than all of the notes are to be redeemed at any time, the trustee will select notes for redemption on a pro rata basis (or, in the case of notes issued in global form as discussed under “—Book-Entry, Delivery and Form,” based on a method as DTC or its nominee or successor may require or, where such nominee or successor is the trustee, a method that most nearly approximates pro rata selection as the trustee deems fair and appropriate) unless otherwise required by law or applicable stock exchange or depositary requirements.

The unredeemed portion of any note shall be in authorized denominations. Notices of redemption will be mailed by first class mail (or sent electronically if DTC is the recipient) at least 30 but not more than 60 days before the redemption date to each holder of notes to be redeemed at its registered address, except that redemption notices may be given more than 60 days prior to a redemption date if the notice is issued in connection with a defeasance or covenant defeasance of the notes or a satisfaction and discharge of the indenture. The notice of redemption with respect to the redemption described in the second paragraph under the heading “Optional Redemption” need not set forth the Applicable Premium but only the manner of calculation thereof. The Company will notify the trustee of the Applicable Premium with respect to any such redemption promptly after the calculation, and the trustee shall not be responsible for such calculation. Notices of redemption, including, without limitation, upon an Equity Offering, may, at the Company’s discretion, be subject to one or more conditions precedent, including, without limitation, completion of the related Equity Offering. If a redemption is subject to the satisfaction of one or more conditions precedent, the related notice shall describe each such condition, and if applicable, shall state that, in the Company’s discretion, the date of redemption may be delayed until such time as any or all such conditions shall be satisfied or waived (provided that in no event shall such date of redemption be delayed to a date later than 60 days after the date on which such notice was sent), or such redemption may not occur and such notice may be rescinded in the event that any or all such conditions shall not have been satisfied or waived by the Company by the date of redemption, or by the date of redemption as so delayed.

If any note is to be redeemed in part only, the notice of redemption that relates to that note will state the portion of the principal amount of that note that is to be redeemed. A new note in principal amount equal to the unredeemed portion of the original note will be issued in the name of the holder of notes upon cancellation of the original note.

Notes or portions thereof called for redemption will become due on the date fixed for redemption, subject to satisfaction of any conditions to such redemption. Unless the Company defaults in the payment of the redemption price, interest will cease to accrue on the notes or portions thereof called for redemption on the applicable redemption date.

If a Change of Control occurs, each holder of notes will have the right to require the Company to repurchase all or any part (equal to $2,000 or an integral multiple of $1,000 in excess thereof) of that holder’s notes pursuant to a cash tender offer (“Change of Control Offer”) on the terms set forth in the indenture. In the Change of Control Offer, the Company will offer a payment in cash (“Change of Control Payment”) equal to 101% of the aggregate principal amount of notes repurchased, plus accrued and unpaid interest on the notes repurchased to the date of purchase (the “Change of Control Purchase Date”), subject to the rights of holders of notes on the relevant record date to receive interest due on the relevant interest payment date. Within 30 days following any Change of Control, the Company will send a notice to each holder describing the transaction or transactions that constitute the Change of Control and offering to repurchase notes properly tendered prior to the expiration date specified in the notice, which date will be no earlier than 30 days and no later than 60 days from the date such notice is sent, pursuant to the procedures required by the indenture and described in such notice. The Company will comply with the requirements of Rule 14e-1 under the Exchange Act and any other securities laws and regulations thereunder to the extent those laws and regulations are applicable in connection with the repurchase of the notes as a result of a Change of Control. To the extent that the provisions of any securities laws or regulations conflict with the Change of Control provisions of the indenture, the Company will comply with the applicable securities laws and regulations and will not be deemed to have breached its obligations under the Change of Control provisions of the indenture by virtue of such compliance.

Promptly following the expiration of the Change of Control Offer, the Company will, to the extent lawful, accept for payment all notes or portions of notes properly tendered pursuant to the Change of Control Offer. Promptly after such acceptance, the Company will, on the Change of Control Purchase Date:

(1) deposit with the paying agent an amount equal to the Change of Control Payment in respect of all notes or portions of notes properly tendered; and

(2) deliver or cause to be delivered to the trustee the notes properly accepted together with an officers’ certificate stating the aggregate principal amount of notes or portions of notes being purchased by the Company.

The paying agent will promptly mail to each holder of notes properly tendered the Change of Control Payment for such notes (or, if all the notes are then in global form, make such payment through the facilities of DTC, and the trustee will promptly authenticate and mail to each holder of certificated notes a new note equal in principal amount to any unpurchased portion of the notes surrendered, if any. The Company will publicly announce the results of the Change of Control Offer on or as soon as practicable after the Change of Control Purchase Date.

The provisions described above that require the Company to make a Change of Control Offer following a Change of Control will be applicable whether or not any other provisions of the indenture are applicable. Except as described above with respect to a Change of Control, the indenture does not contain provisions that permit the holders of the notes to require that the Company repurchase or redeem the notes in the event of a takeover, recapitalization or similar transaction.

The Company will not be required to make a Change of Control Offer upon a Change of Control if (1) a third party makes the Change of Control Offer in the manner, at the time and otherwise in compliance with the requirements set forth in the indenture applicable to a Change of Control Offer made by the Company and purchases all notes properly tendered and not withdrawn under the Change of Control Offer, (2) notice of redemption of all outstanding notes has been given pursuant to the indenture as described above under the caption “—Optional Redemption,” unless and until there is a default in payment of the applicable redemption price or (3) in connection with or in contemplation of any Change of Control, the Company has made an offer to purchase (an “Alternate Offer”) any and all notes validly tendered at a cash price equal to or higher than the

Change of Control Payment and has purchased all notes properly tendered in accordance with the terms of such Alternate Offer. Notwithstanding anything to the contrary contained in the indenture, a Change of Control Offer may be made in advance of a Change of Control, or conditioned upon the consummation of such Change of Control, if a definitive agreement is in place for the Change of Control at the time the Change of Control Offer is made.

The definition of Change of Control includes a phrase relating to the direct or indirect sale, lease, transfer, conveyance or other disposition of “all or substantially all” of the properties or assets of the Company and its Subsidiaries taken as a whole. Although there is a limited body of case law interpreting the phrase “substantially all,” there is no precise established definition of the phrase under applicable law. Accordingly, the ability of a holder of notes to require the Company to repurchase its notes as a result of a sale, lease, transfer, conveyance or other disposition of less than all of the properties or assets of the Company and its Subsidiaries taken as a whole to another Person or group may be uncertain.

In the event that upon consummation of a Change of Control Offer or Alternate Offer less than 10% of the aggregate principal amount of the notes (including, without limitation, additional notes, if any) that were originally issued are held by holders other than the Company or Affiliates thereof, the Company will have the right, upon not less than 30 nor more than 60 days prior notice, given not more than 30 days following the purchase pursuant to the Change of Control Offer described above, to redeem all of the notes that remain outstanding following such purchase at a redemption price equal to the Change of Control Payment plus, to the extent not included in the Change of Control Payment, accrued and unpaid interest, if any, on the notes that remain outstanding, to the date of redemption, subject to the rights of holders of notes on the relevant record date to receive interest on the relevant interest payment date.

The provisions under the indenture relative to the Company’s obligation to make an offer to repurchase the notes as a result of a Change of Control may be waived or modified or terminated with the consent of the holders of a majority in principal amount of the notes then outstanding (including consents obtained in connection with a tender offer or exchange offer for the notes) prior to the occurrence of such Change of Control.

The Company will not, and will not permit any of its Restricted Subsidiaries to, consummate an Asset Sale unless:

(1) the Company (or a Restricted Subsidiary, as the case may be) receives consideration at the time of the Asset Sale at least equal to the Fair Market Value (measured as of the date of the definitive agreement with respect to such Asset Sale) of the assets or Equity Interests issued or sold or otherwise disposed of; and

(2) at least 75% of the aggregate consideration received in the Asset Sale by the Company or a Restricted Subsidiary and all other Asset Sales since the date of the indenture is in the form of cash or Cash Equivalents.

For purposes of this provision, each of the following will be deemed to be cash:

(a) any liabilities, as shown on the Company’s most recent consolidated balance sheet, of the Company or any Restricted Subsidiary (other than contingent liabilities and liabilities that are by their terms subordinated to the notes or any Note Guarantee) that are assumed by the transferee of any such assets pursuant to a novation or indemnity agreement that releases the Company or such Restricted Subsidiary from or indemnifies against further liability (or in lieu of such absence of liability, the acquiring Person or its parent company agrees to indemnify and hold the Company or such Restricted Subsidiary harmless from and against any loss, liability or cost in respect of such assumed liabilities accompanied by the posting of a letter of credit (issued by a commercial bank that has an Investment Grade Rating) in favor of the Company or such Restricted Subsidiary for the full amount of such liabilities and for so long as such liabilities remain outstanding unless such indemnifying party (or its

long term debt securities) shall have an Investment Grade Rating (with no indication of a negative outlook or credit watch with negative implications, in any case, that contemplates such indemnifying party (or its long term debt securities) failing to have an Investment Grade Rating) at the time the indemnity is entered into);

(b) with respect to any Asset Sale of Oil and Gas Properties by the Company or any of its Restricted Subsidiaries where the Company or such Restricted Subsidiary retains an interest in such property, the costs and expenses of the Company or such Restricted Subsidiary related to the exploration, development, completion or production of such properties and activities related thereto that the transferee (or an Affiliate thereof) agrees to pay;

(c) any securities, notes or other obligations received by the Company or any Restricted Subsidiary from such transferee that are, within 180 days of the Asset Sale, converted by the Company or such Restricted Subsidiary into cash, to the extent of the cash received in that conversion;

(e) any Designated Non-cash Consideration received by the Company or such Restricted Subsidiary in such Asset Sale having an aggregate Fair Market Value, taken together with all other Designated Non-cash Consideration received pursuant to this clause (e), not to exceed an amount equal to 5.0% of the Company’s Adjusted Consolidated Net Tangible Assets (determined at the time of receipt of such Designated Non-cash Consideration), with the Fair Market Value of each item of Designated Non-cash Consideration being measured at the time received and without giving effect to subsequent changes in value.

Within 360 days after the receipt of any Net Proceeds from an Asset Sale, the Company (or any Restricted Subsidiary) may apply such Net Proceeds at its option to any combination of the following:

(3) to make capital expenditures in respect of the Company’s or any Restricted Subsidiaries’ Oil and Gas Business.

The requirement of clause (2) or (3) of the preceding paragraph shall be deemed to be satisfied if a bona fide binding contract committing to make the investment, acquisition or expenditure referred to therein is entered into by the Company (or any Restricted Subsidiary) with a Person other than a Restricted Subsidiary within the time period specified in the preceding paragraph and such Net Proceeds are subsequently applied in accordance with such contract within six months following the date such agreement is entered into.

Pending the final application of any Net Proceeds, the Company (or any Restricted Subsidiary) may temporarily reduce Indebtedness under any Credit Facility or otherwise expend or invest the Net Proceeds in any manner that is not prohibited by the indenture.

Any Net Proceeds from Asset Sales that are not applied or invested as provided in the second paragraph of this covenant will constitute “Excess Proceeds.” When the aggregate amount of Excess Proceeds exceeds $25.0 million, within five days thereof, the Company will make an offer (an “Asset Sale Offer”) to all holders of notes and all holders of other Indebtedness that is pari passu with the notes containing provisions similar to those set forth in the indenture with respect to offers to purchase, prepay or redeem with the proceeds of sales of assets to purchase, prepay or redeem, on a pro rata basis (based on principal amounts of notes and pari passu Indebtedness (or, in the case of pari passu Indebtedness issued with significant original issue discount, based on the accreted value thereof) tendered), the maximum principal amount of notes and such other pari passu Indebtedness (plus all accrued interest on the Indebtedness and the amount of all fees and expenses, including premiums, incurred in connection therewith) that may be purchased, prepaid or redeemed out of the Excess Proceeds. The offer price in any Asset Sale Offer will be equal to 100% of the principal amount, plus accrued

and unpaid interest, if any, to the date of purchase, prepayment or redemption, subject to the rights of holders of notes on the relevant record date to receive interest due on the relevant interest payment date, and will be payable in cash. If any Excess Proceeds remain after consummation of an Asset Sale Offer, the Company or any Restricted Subsidiary may use those Excess Proceeds for any purpose not otherwise prohibited by the indenture. If the aggregate principal amount of notes tendered in such Asset Sale Offer exceeds the amount of Excess Proceeds allocated to the purchase of notes, the trustee will select the notes to be purchased on a pro rata basis (except that any notes represented by a note in global form will be selected by such method as DTC or its nominee or successor may require or, where such nominee or successor is the trustee, a method that most nearly approximates pro rata selection as the trustee deems fair and appropriate), based on the principal amounts tendered (with such adjustments as may be deemed appropriate by the Company so that only notes in denominations of $2,000, and any integral multiple of $1,000 in excess thereof, will be purchased). Upon completion of each Asset Sale Offer, the amount of Excess Proceeds will be reset at zero. The Company may satisfy the foregoing obligation with respect to any Excess Proceeds by making an Asset Sale Offer prior to the expiration of the relevant 360 day period or with respect to Excess Proceeds of $25.0 million or less.

The provisions under the indenture relative to the Company’s obligation to make an offer to repurchase the notes as a result of an Asset Sale may be waived or modified with the written consent of a majority in principal amount of the outstanding notes.

The Company will comply with the requirements of Rule 14e-1 under the Exchange Act and any other securities laws and regulations thereunder to the extent those laws and regulations are applicable in connection with each repurchase of notes pursuant to an Asset Sale Offer. To the extent that the provisions of any securities laws or regulations conflict with the “Asset Sales” provisions of the indenture, the Company will comply with the applicable securities laws and regulations and will not be deemed to have breached its obligations under the “Asset Sales” provisions of the indenture by virtue of such compliance.

(1) the notes are rated Baa3 or better by Moody’s and BBB- or better by S&P (or, if either such entity ceases to rate the notes for reasons outside of the control of the Company, the equivalent investment grade credit rating from any other “nationally recognized statistical rating organization” within the meaning of Section 3(a)(62) of the Exchange Act selected by the Company as a replacement agency);

(3) the Company has delivered to the trustee an officers’ certificate certifying to the foregoing provisions of this paragraph,

then, the Company and its Restricted Subsidiaries will no longer be subject to the provisions of the indenture described below under the following captions in this description of notes:

(e) “—Certain Covenants—Dividend and Other Payment Restrictions Affecting Restricted Subsidiaries”;

(f) clause (4) of the covenant described below under the caption “—Certain Covenants—Merger, Consolidation or Sale of Assets”;

(h) “—Certain Covenants—Designation of Restricted and Unrestricted Subsidiaries.”

There can be no assurance that the notes will ever be rated as investment grade or, if such rating is achieved, that such rating will be maintained.

The Company will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly:

(1) declare or pay any dividend or make any other payment or distribution on account of the Company’s or any of its Restricted Subsidiaries’ Equity Interests (including, without limitation, any payment in connection with any merger or consolidation involving the Company or any of its Restricted Subsidiaries) or to the direct or indirect holders of the Company’s or any of its Restricted Subsidiaries’ Equity Interests in their capacity as such (other than dividends or distributions payable in Equity Interests (other than Disqualified Stock) of the Company and other than dividends or distributions payable to the Company or a Restricted Subsidiary of the Company);

(2) repurchase, redeem or otherwise acquire or retire for value (including, without limitation, in connection with any merger or consolidation involving the Company) any Equity Interests of the Company or any direct or indirect parent of the Company other than through the exchange therefor solely of Equity Interests (other than Disqualified Stock) of the Company and other than any acquisition or retirement for value from, or payment to, the Company or any Restricted Subsidiary of the Company;

(3) make any payment on or with respect to, or repurchase, redeem, defease or otherwise acquire or retire for value any Indebtedness of the Company or any Guarantor that is contractually subordinated to the notes or to any Note Guarantee (excluding (a) any intercompany Indebtedness between or among the Company and any of its Restricted Subsidiaries and (b) the repurchase or other acquisition or retirement for value of any such Indebtedness in anticipation of satisfying a sinking fund or other payment obligation due within one year of the date of such repurchase or other acquisition or retirement for value), except a payment of interest or principal at the Stated Maturity thereof; or

(4) make any Restricted Investment (all such payments and other actions set forth in these clauses (1) through (4) being collectively referred to as “Restricted Payments”),

(a) no Default (except a Reporting Default) or Event of Default has occurred and is continuing or would occur as a consequence of such Restricted Payment;

(b) the Company would, at the time of such Restricted Payment and after giving pro forma effect thereto as if such Restricted Payment had been made at the beginning of the applicable four-quarter period, have been permitted to incur at least $1.00 of additional Indebtedness pursuant to the Fixed Charge Coverage Ratio test set forth in the first paragraph of the covenant described below under the caption “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock”; and

(c) such Restricted Payment, together with the aggregate amount of all other Restricted Payments made by the Company and its Restricted Subsidiaries since the date of the Indenture (excluding Restricted Payments permitted by clauses (2) through (12) of the next succeeding paragraph), is less than the sum, without duplication, of:

(i) 50% of the Consolidated Net Income of the Company for the period (taken as one accounting period) from January 1, 2017 to the end of the Company’s most recently ended fiscal quarter for which internal financial statements are available at the time of such Restricted Payment (or, if such Consolidated Net Income for such period is a deficit, less 100% of such deficit); plus

(ii) 100% of the aggregate net cash proceeds and the Fair Market Value of any Capital Stock of Persons engaged primarily in the Oil and Gas Business or any other assets that are used or useful in the Oil and Gas Business other than cash, in each case received by the Company since the date of the Indenture as a contribution to its common equity capital or from the issue or sale of Equity Interests of the Company (other than Disqualified Stock) or received by the Company from the issue or sale of convertible or exchangeable Disqualified Stock or convertible or exchangeable debt securities of the Company that have been converted into or exchanged for such Equity Interests since the date of the Indenture or from the issue or sale of options, warrants or rights to purchase such Equity Interests that have been exercised for such Equity Interests since the date of the Indenture (other than, in either case, Equity Interests (or Disqualified Stock or debt securities) sold to a Restricted Subsidiary of the Company or to an employee stock ownership plan, option plan or similar trust to the extent such sale to an employee stock ownership plan, option plan or similar trust is financed by loans from or Guaranteed by the Company or any Restricted Subsidiary (unless such loans have been repaid with cash on or prior to the date of determination)); plus

(iii) to the extent not already included in Consolidated Net Income for such period, if any Restricted Investment that was made by the Company or any of its Restricted Subsidiaries after the date of the Indenture is sold (other than to the Company or any Restricted Subsidiary of the Company) or otherwise cancelled, liquidated or repaid, 100% of the aggregate cash, and the Fair Market Value of any property other than cash, constituting the return of capital to the Company or any of its Restricted Subsidiaries with respect to such Restricted Investment resulting from such sale, cancellation, liquidation or repayment (less any out-of-pocket costs incurred in connection with any such sale); plus

(iv) the amount by which Indebtedness of the Company or its Restricted Subsidiaries is reduced on the Company’s balance sheet upon the conversion or exchange (other than by a Restricted Subsidiary of the Company) subsequent to the date of the Indenture of any such Indebtedness of the Company or its Restricted Subsidiaries convertible or exchangeable for Equity Interests (other than Disqualified Stock) of the Company (less the amount of any cash, or the Fair Market Value of any other property (other than such Equity Interests), distributed by the Company upon such conversion or exchange and excluding the net cash proceeds from the conversion or exchange financed, directly or indirectly, using funds borrowed from the Company or any Restricted Subsidiary), together with the net proceeds, if any, received by the Company or any of its Restricted Subsidiaries upon such conversion or exchange; plus

(v) to the extent that any Unrestricted Subsidiary of the Company designated as such after the date of the Indenture is redesignated as a Restricted Subsidiary pursuant to the terms of the indenture or is merged or consolidated with or into, or transfers or otherwise disposes of all of substantially all of its properties or assets to or is liquidated into, the Company or a Restricted Subsidiary after the date of the Indenture, the lesser of, as of the date of such redesignation, merger, consolidation, transfer, disposition or liquidation, (A) the Fair Market Value of the Company’s Restricted Investment in such Subsidiary (or of the properties or assets disposed of, as applicable) as of the date of such redesignation, merger, consolidation, transfer, disposition or liquidation and (B) such Fair Market Value as of the date on which such Subsidiary was originally designated as an Unrestricted Subsidiary after the date of the Indenture; plus

(vi) the amount equal to the net reduction in Restricted Investments made since the date of the Indenture resulting from dividends, distributions, redemptions or repurchases, proceeds of sales or other dispositions thereof, interest payments, repayments of loans or advances, releases of guarantees or other transfers of assets (including transfers as a result of a merger or liquidation), in each case to the Company or any of its Restricted Subsidiaries from any Person (including, without limitation, Unrestricted Subsidiaries) in respect of Restricted Investments; plus

(vii) to the extent not included in clause (vi), any dividends received in cash by the Company or any of its Restricted Subsidiaries since the date of the Indenture from an Unrestricted Subsidiary, to the extent such dividends were not otherwise included in the Consolidated Net Income of the Company for such period.

(1) the payment of any dividend or the consummation of any irrevocable redemption within 60 days after the date of declaration of the dividend or giving of the redemption notice, as the case may be, if at the date of declaration or notice, the dividend or redemption payment would have complied with the provisions of the indenture;

(2) the making of any Restricted Payment in exchange for, or out of or with the net cash proceeds of the substantially concurrent sale (other than to a Subsidiary of the Company) of, Equity Interests of the Company (other than Disqualified Stock) or from the substantially concurrent contribution of common equity capital to the Company; provided that the amount of any such net cash proceeds that are utilized for any such Restricted Payment will not be considered to be net proceeds of Equity Interests for purposes of clause (c)(ii) of the preceding paragraph and will not be considered to be net cash proceeds from an Equity Offering for purposes of the “Optional Redemption” provisions of the indenture;

(3) the payment of any dividend (or, in the case of any partnership or limited liability company, any similar distribution) by a Restricted Subsidiary of the Company to the holders of its Equity Interests on a pro rata basis (or a basis more favorable to the Company);

(4) the repurchase, redemption, defeasance, satisfaction and discharge or other acquisition or retirement for value of Indebtedness of the Company or any Guarantor that is contractually subordinated to the notes or to any Note Guarantee or any Disqualified Stock of the Company out or with the net cash proceeds from a substantially concurrent incurrence of, or in exchange for, Permitted Refinancing Indebtedness;

(5) the repurchase, redemption or other acquisition or retirement for value of any Equity Interests of the Company or any Restricted Subsidiary of the Company held by any current or former officer, director or employee of the Company or any of its Restricted Subsidiaries pursuant to any equity subscription agreement, equity option agreement, unitholders’ agreement or similar agreement; provided that the aggregate price paid for all such repurchased, redeemed, acquired or retired Equity Interests may not exceed $5.0 million in any calendar year (with any portion of such $5.0 million amount that is unused in any calendar year to be carried forward to successive calendar years and added to such amount), plus (a) the cash proceeds received by the Company or any of its Restricted Subsidiaries from sales of Equity Interests of the Company to employees or directors of the Company that occur after the date of the Indenture (to the extent the cash proceeds from the sale of such Equity Interests have not otherwise been applied to the payment of Restricted Payments by virtue of clause (c)(ii) of the preceding paragraph), plus (b) the cash proceeds of key man life insurance policies received by the Company or any of its Restricted Subsidiaries after the date of the Indenture, less (c) the amount of payments previously effected by using amounts specified in the foregoing clauses (a) and (b);

(6) loans or advances to employees of the Company or employees or directors of any Subsidiary of the Company, in each case as permitted by Section 402 of the Sarbanes-Oxley Act of 2002, the proceeds of which are used to purchase Capital Stock of the Company, or to refinance loans or advances made pursuant to this clause (6), in an aggregate amount not in excess of $2.0 million at any one time outstanding;

(7) the repurchase or other acquisition or retirement for value of Equity Interests deemed to occur upon the exercise, conversion or exchange of units or other equity options, warrants, incentives or other rights to acquire Equity Interests to the extent such Equity Interests represent a portion of the exercise, conversion or exchange price of those unit or other equity options or other rights and any repurchase or other acquisition or retirement for value of Equity Interests made in lieu of withholding taxes in connection with any exercise, conversion or exchange of units or other equity options, warrants, incentives or other rights to acquire Equity Interests;

(8) the repurchase, redemption or other acquisition or retirement for value of Equity Interests of the Company or any Restricted Subsidiary of the Company representing fractional units of such Equity Interests in connection with a merger or consolidation involving the Company or such Restricted Subsidiary or any other transaction permitted by the indenture;

(9) the declaration and payment of regularly scheduled or accrued dividends to holders of any class or series of Disqualified Stock of the Company or any Preferred Stock of any Restricted Subsidiary of the Company issued in accordance with the covenant described below under the caption “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock”;

(10) payments of cash, dividends, distributions, advances or other Restricted Payments by the Company or any of its Restricted Subsidiaries to allow the payment of cash in lieu of the issuance of fractional units upon (i) the exercise of options or warrants, incentives or other rights to acquire Equity Interests or (ii) the exercise, conversion or exchange of Equity Interests of any such Person;

(11) the purchase, redemption or other acquisition or retirement for value of Indebtedness that is subordinated or junior in right of payment to the notes or any Note Guarantee at a purchase price not greater than (i) 101% of the principal amount of such subordinated or junior Indebtedness in the event of a Change of Control or (ii) 100% of the principal amount of such subordinated or junior Indebtedness in the event of an Asset Sale, in each case, plus accrued and unpaid interest thereon, in connection with any change of control offer or prepayment offer required by the terms of such Indebtedness, but only if:

(a) in the case of a Change of Control, the Company has first complied with and fully satisfied its obligations described under the caption “—Repurchase at the Option of Holders—Change of Control”; or

(b) in the case of an Asset Sale, the Company has complied with and fully satisfied its obligations in accordance with the covenant described under the caption “—Repurchase at the Option of Holders—Asset Sales”; and

(12) any Restricted Payment, which when combined with the outstanding amount of all other Restricted Payments effected pursuant to this clause (12), does not exceed $25.0 million at any one time outstanding.

The amount of all Restricted Payments (other than cash) will be the Fair Market Value, on the date of the Restricted Payment, of the Restricted Investment proposed to be made or the asset(s) or securities proposed to be transferred or issued by the Company or any of its Restricted Subsidiaries, as the case may be, pursuant to the Restricted Payment, except that the Fair Market Value of any non-cash dividend paid within 60 days after the date of declaration will be determined as of such date of declaration. The Fair Market Value of any Restricted Investment, assets or securities that are required to be valued by this covenant will be determined in accordance with the definition of that term. For purposes of determining compliance with this “Restricted Payments” covenant, in the event that a Restricted Payment (or payment or other transaction that, except for being a Permitted Investment or Permitted Payment, would constitute a Restricted Payment) meets the criteria of more than one of the categories of Restricted Payments described in the preceding clauses (1) through (12) of this covenant, or is permitted pursuant to the first paragraph of this covenant or is a Permitted Investment or Permitted Payment, the Company will be permitted to classify (or later classify or reclassify in whole or in part in its sole discretion) such Restricted Payment or other such transaction (or portion thereof) on the date made or later reclassify such Restricted Payment or other such transaction (or portion thereof) in any manner that complies with this covenant. “Permitted Payment” means any transaction expressly excluded from clauses (1), (2) and (3) of the first paragraph of this covenant.

For purposes of this covenant and the definition of “Permitted Investments,” a contribution, sale or incurrence will be deemed to be “substantially concurrent” if the related Restricted Payment or purchase, repurchase, redemption, defeasance, satisfaction and discharge, retirement or other acquisition for value or payment of principal or acquisition of assets or Capital Stock occurs no later than 180 days after such contribution, sale or incurrence.

The Company will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, create, incur, issue, assume, Guarantee or otherwise become directly or indirectly liable, contingently or otherwise, with respect to (collectively, “incur”) any Indebtedness (including Acquired Debt), and the Company will not issue any Disqualified Stock and will not permit any of its Restricted Subsidiaries to issue any Preferred Stock; provided, however, that the Company may incur Indebtedness (including Acquired Debt) or issue Disqualified Stock, and the Company’s Restricted Subsidiaries may incur Indebtedness (including Acquired Debt) or issue Preferred Stock, if the Fixed Charge Coverage Ratio for the Company’s most recently ended four full fiscal quarters for which internal financial statements are available immediately preceding the date on which such additional Indebtedness is incurred or such Disqualified Stock or such Preferred Stock is issued, as the case may be, would have been at least 2.0 to 1.0, determined on a pro forma basis (including a pro forma application of the net proceeds therefrom), as if the additional Indebtedness had been incurred or the Disqualified Stock or the Preferred Stock had been issued, as the case may be, at the beginning of such four-quarter period.

The first paragraph of this covenant will not prohibit the incurrence of any of the following items of Indebtedness or issuances of Disqualified Stock or Preferred Stock, as applicable (collectively, “Permitted Debt”):

(1) the incurrence by the Company or any Restricted Subsidiary (whether as borrower or guarantor) of Indebtedness and letters of credit under one or more Credit Facilities in an aggregate principal amount at any one time outstanding under this clause (1) (with letters of credit being deemed to have a principal amount equal to the maximum potential liability of the Company and its Restricted Subsidiaries thereunder) not to exceed the greatest of (i) $450.0 million, (ii) the Borrowing Base and (iii) $250.0 million plus 35.0% of Adjusted Consolidated Net Tangible Assets determined on the date of such incurrence;

(2) the incurrence by the Company and its Restricted Subsidiaries of the Existing Indebtedness;

(3) the incurrence by the Company and the Guarantors of Indebtedness represented by (a) the old notes that were issued on February 1, 2017; (b) the Exchange Notes issued pursuant to any registration rights agreement; and (c) any Note Guarantees;

(4) the incurrence by the Company or any of its Restricted Subsidiaries of Indebtedness represented by Capital Lease Obligations, mortgage financings or purchase money obligations or other Indebtedness, in each case, incurred for the purpose of financing all or any part of the purchase price or other acquisition cost or cost of design, construction, installation, development, repair or improvement of property, plant or equipment used in the business of the Company or any of its Restricted Subsidiaries (together with improvements, additions, accessions and contractual rights relating primarily thereto), and any Permitted Refinancing Indebtedness incurred to renew, refund, refinance, replace, defease or discharge any Indebtedness incurred pursuant to this clause (4), in an aggregate principal amount, when taken together with the outstanding amount of all other Indebtedness or Permitted Refinancing Indebtedness incurred pursuant to this clause (4), not to exceed the greater of (a) $50.0 million and (b) 5.0% of Adjusted Consolidated Net Tangible Assets determined at the date of such incurrence;

(5) the incurrence by the Company or any of its Restricted Subsidiaries of Permitted Refinancing Indebtedness in exchange for, or the net proceeds of which are used to renew, refund, refinance, replace, defease or discharge any Indebtedness (other than intercompany Indebtedness) or Disqualified Stock or Preferred Stock that was permitted by the indenture to be incurred under the first paragraph of this covenant or clause (2), (3), (5), (15) or (17) of this paragraph;

(6) the incurrence by the Company or any of its Restricted Subsidiaries of intercompany Indebtedness between or among the Company and any of its Restricted Subsidiaries; provided, however, that:

(a) if the Company or any Guarantor is the obligor on such Indebtedness and the payee is not the Company or a Guarantor, such Indebtedness must be unsecured and expressly subordinated to the prior payment in full in cash of all Obligations then due with respect to the notes, in the case of the Company, or the Note Guarantee, in the case of a Guarantor; and

(b) (i) any subsequent issuance or transfer of Equity Interests that results in any such Indebtedness being held by a Person other than the Company or a Restricted Subsidiary of the Company and (ii) any sale or other transfer of any such Indebtedness to a Person that is not either the Company or a Restricted Subsidiary of the Company,

will be deemed, in each case, to constitute an incurrence of such Indebtedness by the Company or such Restricted Subsidiary, as the case may be, that was not permitted by this clause (6);

(7) the issuance by any of the Company’s Restricted Subsidiaries to the Company or to any of its Restricted Subsidiaries of any Preferred Stock; provided, however, that:

(a) any subsequent issuance or transfer of Equity Interests that results in any such Preferred Stock being held by a Person other than the Company or a Restricted Subsidiary of the Company; and

(b) any sale or other transfer of any such Preferred Stock to a Person that is not either the Company or a Restricted Subsidiary of the Company,

will be deemed, in each case, to constitute an issuance of such Preferred Stock by such Restricted Subsidiary that was not permitted by this clause (7);

(8) the incurrence by the Company or any of its Restricted Subsidiaries of Hedging Obligations;

(9) the Guarantee by the Company or any of the Guarantors of Indebtedness of the Company or a Restricted Subsidiary of the Company to the extent that the guaranteed Indebtedness was permitted to be incurred by another provision of this covenant; provided that if the Indebtedness being guaranteed is subordinated to or pari passu with the notes, then the Guarantee must be subordinated or pari passu, as applicable, to the same extent as the Indebtedness guaranteed, and if the Guarantee is by a Restricted Subsidiary that is not a Guarantor, the Indebtedness guaranteed could have otherwise been incurred by such Restricted Subsidiary under this covenant;

(10) the incurrence by the Company or any of its Restricted Subsidiaries of Indebtedness in respect of self-insurance obligations or bid, plugging and abandonment, appeal, reimbursement, performance, surety and similar bonds and completion guarantees issued or provided by, or for the account of, the Company or a Restricted Subsidiary in the ordinary course of business and any Guarantees or obligations with respect to letters of credit functioning as or supporting any of the foregoing bonds or obligations and workers’ compensation claims in the ordinary course of business;

(11) the incurrence by the Company or any of its Restricted Subsidiaries of Indebtedness arising from the honoring by a bank or other financial institution of a check, draft or similar instrument inadvertently drawn against insufficient funds, so long as such Indebtedness is covered within five Business Days;

(12) the incurrence by the Company or any of its Restricted Subsidiaries of in-kind obligations relating to net oil or natural gas balancing positions arising in the ordinary course of business;

(13) the incurrence of any obligation arising from agreements of the Company or any Restricted Subsidiary of the Company providing for indemnification, guarantees (other than guarantees of Indebtedness), adjustment of purchase price, holdbacks, earn outs or similar obligations, in each case, incurred or assumed in connection with the disposition or acquisition of any business, assets or Capital Stock of a Restricted Subsidiary in a transaction permitted by the indenture, provided such obligation is not reflected on the face of the balance sheet of the Company or any Restricted Subsidiary;

(14) the pledge of (or a Guaranty limited in recourse solely to) Equity Interests in an Unrestricted Subsidiary or Joint Venture held by the Company or a Restricted Subsidiary to secure Indebtedness of such Unrestricted Subsidiary or Joint Venture and solely to the extent such Indebtedness constitutes Non-Recourse Debt;

(15) the incurrence by the Company or its Restricted Subsidiaries of Permitted Acquisition Indebtedness;

(16) the incurrence by the Company or its Restricted Subsidiaries of Indebtedness consisting of the financing of insurance premiums in customary amounts consistent with the operations and business of the Company and the Restricted Subsidiaries; and

(17) the incurrence by the Company or any Restricted Subsidiary of additional Indebtedness or the issuance by the Company of any Disqualified Stock or by any Restricted Subsidiary of Preferred Stock in an aggregate principal amount, when taken together with the outstanding amount of all other Indebtedness incurred or Disqualified Stock or Preferred Stock issued pursuant to this clause (17), not to exceed the greater of (i) $50.0 million and (ii) 5.0% of Adjusted Consolidated Net Tangible Assets determined on the date of such incurrence or issuance.

Indebtedness permitted by this covenant need not be permitted solely by reference to one provision permitting such Indebtedness or Disqualified Stock or Preferred Stock but may be permitted in part by one such provision and in part by one or more other provisions of this covenant permitting such Indebtedness or Disqualified Stock or Preferred Stock. For purposes of determining compliance with this “Incurrence of Indebtedness and Issuance of Preferred Stock” covenant, in the event that an item of Indebtedness or Disqualified Stock or Preferred Stock meets the criteria of more than one of the categories of Permitted Debt described in clauses (1) through (17) above, or is entitled to be incurred pursuant to the first paragraph of this covenant, the Company will be permitted to divide, classify and reclassify such item of Indebtedness or Disqualified Stock or Preferred Stock on the date of its incurrence or issuance, or later redivide or reclassify all or a portion of such item of Indebtedness or Disqualified Stock or Preferred Stock, in any manner (including by dividing and classifying such item of Indebtedness or Disqualified Stock or Preferred Stock in more than one type of Indebtedness or Disqualified Stock or Preferred Stock permitted under such covenant) that complies with this covenant.

The dollar equivalent principal amount of any Indebtedness denominated in a foreign currency and incurred pursuant to any dollar-denominated restriction on the incurrence of Indebtedness shall be calculated based on the relevant exchange rates in effect at the time of incurrence, in the case of term Indebtedness, or first committed, in the case of revolving credit Indebtedness; provided that if such Indebtedness is incurred to refinance other Indebtedness denominated in a foreign currency, and such refinancing would cause the applicable U.S. dollar-denominated restriction to be exceeded if calculated at the relevant currency exchange rate in effect on the date of such refinancing, such U.S. dollar-denominated restriction shall be deemed not to have been exceeded so long as the principal amount of such refinancing Indebtedness does not exceed the principal amount of such Indebtedness being refinanced. Notwithstanding any other provision of this covenant, the maximum amount of Indebtedness that the Company and the Restricted Subsidiaries may incur pursuant to this covenant shall not be deemed to be exceeded solely as a result of fluctuations in the exchange rates of currencies. The principal amount of any Indebtedness incurred to refinance other Indebtedness, if incurred in a different currency from the Indebtedness being refinanced, shall be calculated based on the currency exchange rate applicable to the currencies in which such Permitted Refinancing Indebtedness is denominated that is in effect on the date of such refinancing.

The accrual of interest or Preferred Stock dividends, the accretion or amortization of original issue discount, the payment of interest on any Indebtedness not secured by a Lien or on the notes in the form of additional Indebtedness with the same term and the payment of dividends on Preferred Stock or Disqualified Stock in the form of additional securities of the same class of Preferred Stock or Disqualified Stock will not be deemed to be an incurrence of Indebtedness or an issuance of Preferred Stock or Disqualified Stock for purposes of this covenant; provided that the amount thereof is included in Fixed Charges of the Company as accrued to the extent required by the definition of such term. For purposes of this covenant, (i) the accrual of an obligation to pay a premium in respect of Indebtedness or Disqualified Stock or Preferred Stock arising in connection with the issuance of a notice of redemption or making of a mandatory offer to purchase such Indebtedness or Disqualified Stock or Preferred Stock, and (ii) unrealized losses or charges in respect of Hedging Agreements (including those resulting from the application of FASB ASC Topic No. 815, Derivatives and Hedging) will, in the case of (i) or

(ii), not be deemed to be an incurrence of Indebtedness or Disqualified Stock or Preferred Stock. Further, the accounting reclassification of any obligation or Disqualified Stock or Preferred Stock of the Company or any of its Restricted Subsidiaries as Indebtedness or Disqualified Stock or Preferred Stock will not be deemed an incurrence of Indebtedness or issuance of Disqualified Stock or Preferred Stock for purposes of this covenant.

The “amount” or “principal amount” of any Indebtedness or Preferred Stock or Disqualified Stock outstanding at any time of determination as used herein shall be as set forth below or, if not set forth below, determined in accordance with GAAP:

(1) the accreted value of the Indebtedness, in the case of any Indebtedness issued with original issue discount;

(2) the principal amount of the Indebtedness, in the case of any other Indebtedness;

(3) in respect of Indebtedness of another Person secured by a Lien on the assets of the specified Person, the lesser of:

(4) in the case of any Capital Lease Obligation, the amount determined in accordance with the definition thereof;

(5) in the case of any Preferred Stock, (x) if other than Disqualified Stock, the greater of its voluntary or involuntary liquidation preference and its maximum fixed redemption price or repurchase price or (y) if Disqualified Stock, as specified in the definition thereof;

(6) in the case of any Interest Rate Agreements included in the definition of “Permitted Debt,” zero;

(7) in the case of all other unconditional obligations, the amount of the liability thereof determined in accordance with GAAP; and

(8) in the case of all other contingent obligations, the maximum liability at such date of such Person.

For purposes of determining any particular amount of Indebtedness, (i) guarantees of, or obligations in respect of letters of credit relating to, Indebtedness otherwise included in the determination of such amount shall not also be included and (ii) if obligations in respect of letters of credit are incurred pursuant to a Credit Facility and are being treated as incurred pursuant to clause (1) of the definition of “Permitted Debt” and the letters of credit relate to other Indebtedness, then the amount of such other Indebtedness equal to the face amount of such letters of credit shall not be included. If Indebtedness is secured by a letter of credit that serves only to secure such Indebtedness, then the total amount deemed incurred shall be equal to the greater of (x) the principal of such Indebtedness and (y) the amount that may be drawn under such letter of credit.

The Company will not and will not permit any of its Restricted Subsidiaries to, directly or indirectly, create, incur, assume or otherwise cause or suffer to exist or become effective any Lien of any kind (other than Permitted Liens) securing Indebtedness upon any of their property or assets, now owned or hereafter acquired, unless the notes or any Note Guarantee of such Restricted Subsidiary, as applicable, are secured on an equal and ratable basis with the Indebtedness so secured (or, in the case of Indebtedness subordinated to the notes or any Note Guarantee, prior or senior thereto, with the same relative priority as the notes or Note Guarantee shall have with respect to such subordinated Indebtedness) until such time as such Indebtedness is no longer secured by a Lien. Any Lien created for the benefit of the holders of the notes pursuant to the preceding sentence shall provide by its terms that such Lien shall be automatically and unconditionally released and discharged upon the release and discharge of the initial Lien, provided no Event of Default has occurred and is continuing at the time of such release and discharge.

The Company will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, create or permit to exist or become effective any consensual encumbrance or restriction on the ability of any Restricted Subsidiary to:

(1) pay dividends or make any other distributions on its Capital Stock to the Company or any of its Restricted Subsidiaries, or pay any indebtedness owed to the Company or any of its Restricted Subsidiaries; provided that (i) the priority that any series of Preferred Stock of a Restricted Subsidiary has in receiving dividends or liquidating distributions before dividends or liquidating distributions are paid in respect of common stock of such Restricted Subsidiary shall not constitute a restriction on the ability to pay or make dividends or distributions on Capital Stock for purposes of this covenant and (ii) the subordination of indebtedness owed to the Company or any Restricted Subsidiary to other indebtedness incurred by any Restricted Subsidiary shall not be deemed a restriction on the ability to pay indebtedness;

(2) make loans or advances to the Company or any of its Restricted Subsidiaries (it being understood that the subordination of loans or advances made to the Company or any Restricted Subsidiary to other Indebtedness incurred by the Company or any Restricted Subsidiary shall not be deemed a restriction on the ability to make loans or advances); or

(3) sell, lease or transfer any of its properties or assets to the Company or any of its Restricted Subsidiaries.

However, the preceding restrictions will not apply to encumbrances or restrictions existing under or by reason of:

(1) agreements governing Existing Indebtedness and the Credit Agreement as in effect on the date of the indenture and any amendments, restatements, modifications, renewals, supplements, refundings, replacements or refinancings of those agreements; provided that the amendments, restatements, modifications, renewals, supplements, refundings, replacements or refinancings are not materially more restrictive, taken as a whole, with respect to such dividend and other payment restrictions than those contained in those agreements on the date of the indenture, as determined in good faith by the Company;

(3) agreements governing other Indebtedness permitted to be incurred under the provisions of the covenant described above under the caption “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock” and any amendments, restatements, modifications, renewals, supplements, refundings, replacements or refinancings of those agreements; provided that the restrictions therein are not materially more restrictive, taken as a whole, than those contained in the indenture, the notes and the Note Guarantees or the Credit Agreement as in effect on the date of the indenture, as determined in good faith by the Company;

(4) applicable law, rule, regulation, order, approval, license, permit or similar restriction;

(5) any instrument governing Indebtedness or Capital Stock or other agreement of a Person acquired (including by merger or consolidation), or the assets of which are acquired, by the Company or any of its Restricted Subsidiaries as in effect at the time of such acquisition (except to the extent such Indebtedness or Capital Stock or other agreement was incurred in connection with or in contemplation of such acquisition), which encumbrance or restriction is not applicable to any Person, or the properties or assets of any Person, other than the Person, or the property or assets of the Person, so acquired; provided that, in the case of Indebtedness, such Indebtedness was permitted by the terms of the indenture to be incurred;

(6) customary non-assignment provisions in Hydrocarbon purchase and sale or exchange agreements or similar operational agreements or in licenses, easements or leases, in each case, entered into in the ordinary course of business;

(7) purchase money obligations for property acquired in the ordinary course of business and Capital Lease Obligations that impose restrictions on the property purchased or leased of the nature described in clause (3) of the preceding paragraph;

(8) any agreement for the sale or other disposition of a Restricted Subsidiary that restricts distributions by that Restricted Subsidiary pending its sale or other disposition;

(9) Permitted Refinancing Indebtedness; provided that the restrictions contained in the agreements governing such Permitted Refinancing Indebtedness are not materially more restrictive, taken as a whole, than those contained in the agreements governing the Indebtedness being refinanced, as determined in good faith by the Company;

(10) Liens permitted to be incurred under the provisions of the covenant described above under the caption “—Certain Covenants—Liens” that limit the right of the debtor to dispose of the assets subject to such Liens;

(11) provisions limiting the disposition or distribution of assets or property in joint venture agreements, asset sale agreements, sale-leaseback agreements, stock sale agreements, shareholders’ agreements, partnership agreements and other similar agreements (including agreements entered into in connection with a Restricted Investment) entered into with the approval of the Board of Directors of the Company or in the ordinary course of business, which limitation is applicable only to the assets or property that is the subject of such agreements;

(12) any agreement or instrument relating to any property or assets acquired after the date of the indenture, so long as such encumbrance or restriction relates only to the property or assets so acquired and is not and was not created in anticipation of such acquisition;

(13) encumbrances or restrictions on cash, Cash Equivalents or other deposits or net worth requirements imposed by customers or lessors under contracts or leases entered into in the ordinary course of business;

(14) any Preferred Stock issued by a Restricted Subsidiary of the Company; provided that issuance of such Preferred Stock is permitted pursuant to the covenant described above under the caption “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock” and the terms of such Preferred Stock do not expressly restrict the ability of a Restricted Subsidiary of the Company to pay dividends or make any other distributions on its Equity Interests (other than requirements to pay dividends or liquidation preferences on such Preferred Stock prior to paying any dividends or making any other distributions on such other Equity Interests);

(15) any encumbrance or restriction contained in the terms of any Indebtedness or any agreement pursuant to which such Indebtedness was incurred if (x) either (a) the encumbrance or restriction applies only in the event of a payment default or a default with respect to a financial covenant in such Indebtedness or agreement or (b) any such encumbrance or restriction will not materially affect the Company’s ability to make principal or interest payments on the notes, as determined in good faith by the Company and (y) the encumbrance or restriction is not materially more disadvantageous to the Holders than is customary in comparable financings or agreements, as determined in good faith by the Company;

(16) Oil and Gas Hedging Contracts or Interest Rate Agreements permitted from time to time under the indenture;

(17) encumbrances and restrictions contained in contracts entered into in the ordinary course of business, not relating to any Indebtedness, and that do not, taken as a whole, detract from the value of, or from the ability of the Company and its Restricted Subsidiaries to realize the value of, property or assets of the Company or any Restricted Subsidiary in any manner material to the Company or any Restricted Subsidiary, as determined in good faith by the Company; provided that such encumbrances or restrictions will not materially affect the Company’s ability to make principal or interest payments on the notes, as determined in good faith by the Company;

(18) customary encumbrances and restrictions contained in agreements of the types described in the definition of “Permitted Business Investments”; or

In each case set forth above, notwithstanding any stated limitation on the assets or property that may be subject to such encumbrance or restriction, an encumbrance or restriction on a specified asset or property or group or type of assets or property may also apply to all improvements, additions, accessions and contractual rights relating primarily thereto and all proceeds thereof (including dividends, distributions and increases in respect thereof).

The Company will not, directly or indirectly: (x) consolidate or merge with or into another Person (whether or not the Company is the survivor), or (y) sell, assign, transfer, convey, lease or otherwise dispose of all or substantially all of its properties or assets, in one or more related transactions, to another Person, unless:

(1) either: (a) the Company is the surviving Person; or (b) the Person formed by or surviving any such consolidation or merger (if other than the Company) or to which such sale, assignment, transfer, conveyance, lease or other disposition has been made is a Person organized or existing under the laws of the United States, any state of the United States or the District of Columbia; provided, however, that at any time such surviving Person is a limited liability company or limited partnership, there shall be a co-issuer of the notes that is a corporation organized or existing under the laws of the United States, any state of the United States or the District of Columbia;

(2) the Person formed by or surviving any such consolidation or merger (if other than the Company) or the Person to which such sale, assignment, transfer, conveyance, lease or other disposition has been made assumes all the obligations of the Company under the notes and the indenture pursuant to a supplemental indenture or other agreement in a form reasonably satisfactory to the trustee;

(4) immediately after giving effect to such transaction and any related financing transaction on a pro forma basis as if the same had occurred at the beginning of the applicable four-quarter period, either (i) the Company or the Person formed by or surviving any such consolidation or merger (if other than the Company), or to which such sale, assignment, transfer, conveyance, lease or other disposition has been made, would be permitted to incur at least $1.00 of additional Indebtedness pursuant to the Fixed Charge Coverage Ratio test set forth in the first paragraph of the covenant described above under the caption “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock” or (ii) the Fixed Charge Coverage Ratio of the Company or the Person formed by or surviving any such consolidation or merger (if other than the Company), or to which such sale, assignment, transfer, conveyance, lease or other disposition has been made, is equal to or greater than the Fixed Charge Coverage Ratio of the Company immediately prior to such transaction; and

(5) the Company has delivered to the trustee an officers’ certificate and an opinion of counsel, each stating that such consolidation, merger or disposition and such supplemental indenture, if any, comply with the indenture.

Notwithstanding the restrictions described in the foregoing clause (4), (i) any Restricted Subsidiary of the Company may consolidate with or merge into the Company and (ii) the Company may consolidate with or merge into or dispose all or substantially all of its properties or assets to any Guarantor; and the Company, in the case of (i) or (ii), will not be required to comply with the preceding clause (4) in connection with any such consolidation, merger or disposition.

Notwithstanding the second preceding paragraph, the Company may reorganize as any other form of entity in accordance with the following procedures provided that:

(1) the reorganization involves the conversion (by merger, sale, contribution or exchange of assets or otherwise) of the Company into a form of entity other than a corporation formed under Delaware law;

(2) the entity so formed by or resulting from such reorganization is an entity organized or existing under the laws of the United States, any state thereof or the District of Columbia;

(3) the entity so formed by or resulting from such reorganization assumes all the obligations of the Company under the notes and the indenture pursuant to a supplemental indenture or other agreement in a form reasonably satisfactory to the trustee;

(4) immediately after such reorganization no Default (other than a Reporting Default) or Event of Default exists; and

(5) such reorganization is not materially adverse to the holders or Beneficial Owners of the notes (for purposes of this clause (5) a reorganization will not be considered materially adverse to the holders or Beneficial Owners of the notes solely because the successor or survivor of such reorganization (a) is subject to federal or state income taxation as an entity or (b) is considered to be an “includible corporation” of an affiliated group of corporations within the meaning of Section 1504(b) of the Code or any similar state or local law).

For purposes of the foregoing, the transfer (by lease, assignment, sale or otherwise, in a single transaction or series of transactions) of all or substantially all of the properties or assets of one or more Restricted Subsidiaries of the Company, the Capital Stock of which constitutes all or substantially all of the properties or assets of the Company, shall be deemed to be the transfer of all or substantially all of the properties or assets of the Company.

Upon any consolidation or merger or any sale, assignment, transfer, conveyance, lease or other disposition of all or substantially all of the properties or assets of the Company in accordance with the foregoing in which the Company is not the surviving entity, the surviving Person formed by such consolidation or into or with which the Company is merged or to which such sale, assignment, transfer, conveyance, lease or other disposition is made shall succeed to, and be substituted for, and may exercise every right and power of, the Company under the indenture and the notes with the same effect as if such surviving Person had been named as the Company in the indenture and the notes, and thereafter (except in the case of a lease of all or substantially all of the Company’s properties or assets), the Company will be relieved of all obligations and covenants under the indenture and the notes.

Although there is a limited body of case law interpreting the phrase “substantially all,” there is no precise established definition of the phrase under applicable law. Accordingly, in certain circumstances there may be a degree of uncertainty as to whether a particular transaction would involve “all or substantially all” of the properties or assets of a Person.

The Company will not, and will not permit any of its Restricted Subsidiaries to, make any payment to, or sell, lease, transfer or otherwise dispose of any of its properties or assets to, or purchase any property or assets from, or enter into or make or amend any transaction, contract, agreement, understanding, loan, advance or Guarantee with, or for the benefit of, any Affiliate of the Company (each, an “Affiliate Transaction”) involving aggregate consideration to or from the Company or a Restricted Subsidiary in excess of $2.0 million, unless:

(1) the Affiliate Transaction is on terms that are no less favorable to the Company or the relevant Restricted Subsidiary than those that could have been obtained in a comparable transaction by the Company or such Restricted Subsidiary with an unrelated Person or, if, as determined in good faith by the Company, no comparable transaction is available with which to compare such Affiliate Transaction, such Affiliate Transaction is otherwise fair to the Company or the relevant Restricted Subsidiary from a financial point of view; and

(a) with respect to any Affiliate Transaction or series of related Affiliate Transactions involving aggregate consideration in excess of $20.0 million, an officers’ certificate certifying that such Affiliate Transaction or series of related Affiliate Transactions complies with this covenant; and

(b) with respect to any Affiliate Transaction or series of related Affiliate Transactions involving aggregate consideration in excess of $40.0 million, an officers’ certificate certifying that such Affiliate Transaction or series of related Affiliate Transactions complies with this covenant and that such Affiliate Transaction or series of related Affiliate Transactions has been approved by a majority of the members of the Board of Directors of the Company and by a majority of the disinterested members of the Board of Directors of the Company, if any.

The following items will not be deemed to be Affiliate Transactions and, therefore, will not be subject to the provisions of the prior paragraph:

(1) any employment agreement, employee benefit plan, officer or director indemnification agreement or any similar arrangement entered into by the Company or any of its Restricted Subsidiaries in the ordinary course of business and payments pursuant thereto;

(2) transactions between or among the Company and/or its Restricted Subsidiaries;

(3) transactions with a Person (other than an Unrestricted Subsidiary of the Company) that is an Affiliate of the Company solely because the Company owns, directly or through a Restricted Subsidiary, an Equity Interest in, or controls, such Person;

(4) payment of reasonable and customary fees and reimbursement of expenses (pursuant to indemnity agreements or otherwise) of, or provision of directors’ and officers’ liability insurance, compensation, indemnification and other benefits to, officers, directors, employees or consultants of the Company or any of its Subsidiaries;

(5) any issuance of Equity Interests (other than Disqualified Stock) of the Company to Affiliates of the Company;

(6) any Restricted Payments or Permitted Investments or Permitted Payments that are permitted by the provisions of the indenture described above under the caption “—Certain Covenants—Restricted Payments”;

(7) transactions between the Company or any of its Restricted Subsidiaries and any Person that would not otherwise constitute an Affiliate Transaction except for the fact that one director of such other Person is also a director of the Company or such Restricted Subsidiary, as applicable; provided that such director abstains from voting as a director of the Company or such Restricted Subsidiary, as applicable, on any matter involving such other Person;

(8) any transaction in which the Company or any of its Restricted Subsidiaries, as the case may be, delivers to the trustee a letter from an accounting, appraisal, advisory or investment banking firm of national standing stating that such transaction is fair to the Company or such Restricted Subsidiary from a financial point of view or that such transaction meets the requirements of clause (1) of the preceding paragraph;

(9) (a) guarantees by the Company or any of its Restricted Subsidiaries of performance of obligations of the Company’s Unrestricted Subsidiaries in the ordinary course of business, except for guarantees of Indebtedness in respect of borrowed money, and (b) pledges by the Company or any Restricted Subsidiary of the Company of (or any Guarantee by the Company or any Restricted Subsidiary limited in recourse solely to) Equity Interests in Unrestricted Subsidiaries for the benefit of lenders or other creditors of the Company’s Unrestricted Subsidiaries;

(10) transactions with Unrestricted Subsidiaries, customers, clients, suppliers or purchasers or sellers of goods or services, or lessors or lessees of property, in each case in the ordinary course of business and otherwise in compliance with the terms of the indenture which are, in the aggregate (taking into account all the costs and benefits associated with such transactions), not materially less favorable to the Company and its Restricted Subsidiaries than those that would have been obtained in a comparable transaction by the Company or such Restricted Subsidiary with an unrelated person or are on terms at least as favorable as might reasonably have been obtained at such time from an unaffiliated party, in each case, as determined in good faith by the Company;

(11) transactions (other than purchases or sales of assets) effected in accordance with the terms of (a) any other agreements with Affiliates of the Company that are described in the offering memorandum dated January 27, 2017 and identified in the indenture, in each case as such agreements were in effect on the date of the indenture, (b) any amendment or replacement of any of such agreements or (c) any agreement entered into after the date of the indenture that is similar to any such agreements, so long as, in the case of clause (b) or (c), the terms of any such amendment or replacement agreement or future agreement, taken as a whole, are no less advantageous to the Company or no less favorable to the holders in any material respect than the agreement so amended or replaced or the similar such agreement, respectively, as determined in good faith by the Company;

(12) in the case of contracts for exploring for, producing, marketing, storing or otherwise handling Hydrocarbons, or activities or services reasonably related or ancillary thereto, or other operational contracts, any such contracts entered into in the ordinary course of business and otherwise in compliance with the terms of the indenture which are fair to the Company and its Restricted Subsidiaries, or are on terms at least as favorable as might reasonably have been obtained at such time from an unaffiliated party, in each case, as determined in good faith by the Company; and

(13) loans or advances to employees in the ordinary course of business not to exceed $2.0 million in the aggregate at any one time outstanding.

If, after the date of the indenture, any Restricted Subsidiary of the Company that is not already a Guarantor Guarantees or otherwise becomes an obligor with respect to any other Indebtedness of the Company or any Guarantor in excess of the De Minimis Guaranteed Amount, then such Restricted Subsidiary will become a Guarantor by executing a supplemental indenture and delivering it to the trustee within 20 Business Days of the date on which it Guaranteed or became an obligor with respect to such Indebtedness; provided, however, that the preceding shall not apply to Subsidiaries of the Company that have properly been designated as Unrestricted Subsidiaries in accordance with the indenture for so long as they continue to constitute Unrestricted Subsidiaries. Notwithstanding the preceding, any Note Guarantee of a Restricted Subsidiary that was incurred pursuant to this paragraph shall be subject to all limitations and provisions described under the caption “Note Guarantees” and provide by its terms that it shall be automatically and unconditionally released at such time as such Guarantor ceases to Guarantee or otherwise be an obligor with respect to any other Indebtedness of the Company or any other Guarantor in excess of the De Minimis Guaranteed Amount, provided no Event of Default has occurred and is continuing at the time of such release.

The Board of Directors of the Company may designate any Restricted Subsidiary to be an Unrestricted Subsidiary if that designation would not cause a Default. If a Restricted Subsidiary is designated as an Unrestricted Subsidiary, the aggregate Fair Market Value of all outstanding Investments owned by the Company and its Restricted Subsidiaries in the Subsidiary designated as an Unrestricted Subsidiary will be deemed to either be an Investment made as a “Restricted Payment” as of the time of the designation that will reduce the amount available for Restricted Payments under the covenant described above under the caption “—Certain Covenants—Restricted Payments” or represent a Permitted Investment under one or more clauses of the definition of Permitted Investments, as determined in good faith by the Company. That designation will only be permitted if the Investment would be permitted at that time and if the Subsidiary so designated otherwise meets the definition of an Unrestricted Subsidiary.

Any designation of a Subsidiary of the Company as an Unrestricted Subsidiary will be evidenced to the trustee by filing with the trustee a certified copy of a resolution of the Board of Directors of the Company giving

effect to such designation and an officers’ certificate certifying that such designation complied with the preceding conditions and was permitted by the covenant described above under the caption “—Certain Covenants—Restricted Payments.” If, at any time, any Unrestricted Subsidiary would fail to meet the preceding requirements as an Unrestricted Subsidiary, it will thereafter cease to be an Unrestricted Subsidiary for purposes of the indenture and any Indebtedness of such Subsidiary will be deemed to be incurred by a Restricted Subsidiary of the Company as of such date and, if such Indebtedness is not permitted to be incurred as of such date under the covenant described under the caption “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock,” the Company will be in default of such covenant.

The Board of Directors of the Company may at any time designate any Unrestricted Subsidiary to be a Restricted Subsidiary of the Company; provided that such designation will be deemed to be an incurrence of Indebtedness by a Restricted Subsidiary of the Company of any outstanding Indebtedness of such Unrestricted Subsidiary, and such designation will only be permitted if (1) such Indebtedness is permitted under the covenant described under the caption “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock,” either as “Permitted Debt” or pursuant to the first paragraph of such covenant with the Fixed Charge Coverage Ratio calculated on a pro forma basis as if such designation had occurred at the beginning of the applicable reference period; and (2) no Default or Event of Default would be in existence following such designation.

Whether or not required by the rules and regulations of the SEC, so long as any notes are outstanding, the Company will furnish to the holders of notes or cause the trustee to furnish to the holders of notes (or file with the SEC for public availability), within the time periods specified in the SEC’s rules and regulations applicable to a non-accelerated filer, after giving effect to all applicable extensions and cure periods:

(1) all quarterly and annual reports that would be required to be filed with the SEC on Forms 10-Q and 10-K if the Company were required to file such reports, including a “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and, with respect to the annual report only, a report on the Company’s consolidated financial statements by the Company’s certified independent accountants; and

(2) all current reports that would be required to be filed with the SEC on Form 8-K if the Company were required to file such reports.

The availability of the foregoing reports on the SEC’s EDGAR filing system will be deemed to satisfy the foregoing delivery requirements. All such reports will be prepared in all material respects in accordance with all of the rules and regulations applicable to such reports.

If the Company has designated as an Unrestricted Subsidiary any of its Subsidiaries that is a Significant Subsidiary (or that, taken together with other Unrestricted Subsidiaries, would be a Significant Subsidiary), then the quarterly and annual financial information required by the second preceding paragraph will include, to the extent material, a reasonably detailed presentation, either on the face of the financial statements or in the footnotes thereto, and in Management’s Discussion and Analysis of Financial Condition and Results of Operations, of the financial condition and results of operations of the Company and its Restricted Subsidiaries separate from the financial condition and results of operations of the Unrestricted Subsidiaries of the Company.

This covenant does not impose any duty on the Company under the Sarbanes Oxley Act of 2002 and the related SEC rules that would not otherwise be applicable.

Any and all Defaults or Events of Default arising from a failure to furnish or file in a timely manner a report or information required by this covenant shall be deemed cured (and the Company shall be deemed to be in compliance with this covenant) upon furnishing or filing such report or information as contemplated by this

covenant (but without regard to the date on which such report or information is so furnished or filed); provided that such cure shall not otherwise affect the rights of the holders under “—Events of Defaults and Remedies” if the principal, interest and premium, if any, have been accelerated in accordance with the terms of the indenture and such acceleration has not been rescinded or cancelled prior to such cure.

In addition, for so long as the notes remain outstanding, the Company will furnish to the holders and Beneficial Owners of the notes and to securities analysts and prospective investors in the notes, upon their request, the information required to be delivered pursuant to Rule 144A(d)(4) under the Securities Act.

The Company will be deemed to have furnished to the holders and Beneficial Owners of the notes and to securities analysts and prospective investors the reports referred to in clauses (1) and (2) of the first paragraph of this covenant or the information referred to in the immediately preceding paragraph of this covenant if the Company has posted such reports or information on the Company Website. For purposes of this covenant, the term “Company Website” means the collection of web pages that may be accessed on the World Wide Web using the URL address http://www.wildhorserd.com or such other address as the Company may from time to time maintain for public information.

(2) default in the payment when due (at Stated Maturity, upon redemption or otherwise) of the principal of, or premium, if any, on, the notes;

(3) failure by the Company for 30 days after written notice has been given, by certified mail, (1) to the Company by the trustee or (2) to the Company and the trustee by the holders of at least 25% in aggregate principal amount of the notes then outstanding to comply with its obligations to offer to repurchase or repurchase notes described under the captions (a) “—Repurchase at the Option of Holders—Change of Control” or (b) “—Repurchase at the Option of Holders—Asset Sales”;

(4) failure by the Company to comply with the provisions described under the caption “—Certain Covenants—Merger, Consolidation or Sale of Assets”;

(5) failure by the Company for 180 days after written notice has been given, by certified mail, (1) to the Company by the trustee or (2) to the Company and the trustee by the holders of at least 25% in aggregate principal amount of the notes then outstanding to comply with the provisions described under “—Certain Covenants—Reports”;

(6) failure by the Company for 60 days after written notice has been given, by certified mail, (1) to the Company by the trustee or (2) to the Company and the trustee by the holders of at least 25% in aggregate principal amount of the notes then outstanding to comply with any of the other agreements in the indenture;

(7) default under any mortgage, indenture or instrument under which there is issued or by which there is secured or evidenced any Indebtedness for money borrowed by the Company or any of its Restricted Subsidiaries (or the payment of which is guaranteed by the Company or any of its Restricted Subsidiaries), whether such Indebtedness or Guarantee now exists, or is created after the date of the indenture, if that default:

(a) is caused by a failure to pay principal of, and interest and premium, if any, on, such Indebtedness prior to the expiration of the grace period provided in such Indebtedness on the date of such default (a “Payment Default”); or

(b) results in the acceleration of such Indebtedness prior to its express maturity,

and, in each case, the principal amount of any such Indebtedness, together with the principal amount of any other such Indebtedness under which there has been a Payment Default or the maturity of which

has been so accelerated, aggregates $25.0 million or more; provided, however, if, prior to any acceleration of the notes, (i) any such Payment Default is cured or waived, (ii) any such acceleration is rescinded, or (iii) such Indebtedness is repaid during the 60 day period commencing upon the end of any applicable grace period for such Payment Default or the occurrence of such acceleration, as the case may be, any Default or Event of Default (but not any acceleration of the notes) caused by such Payment Default or acceleration shall be automatically rescinded, so long as such rescission does not conflict with any judgment, decree or applicable law;

(8) failure by the Company or any of its Restricted Subsidiaries to pay final judgments entered by a court or courts of competent jurisdiction aggregating in excess of $25.0 million (to the extent not covered by insurance by a reputable and creditworthy insurer as to which the insurer has not disclaimed coverage), which judgments are not paid, discharged or stayed, for a period of 60 days;

(9) except as permitted by the indenture, any Note Guarantee is held in any judicial proceeding to be unenforceable or invalid or ceases for any reason to be in full force and effect, or any Guarantor, or any Person acting on behalf of any Guarantor, denies or disaffirms its obligations under its Note Guarantee, except, in each case, by reason of the release of such Note Guarantee in accordance with the indenture; and

(10) certain events of bankruptcy or insolvency described in the indenture with respect to the Company or any of its Restricted Subsidiaries that is a Significant Subsidiary or any group of its Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary.

In the case of an Event of Default arising from certain events of bankruptcy or insolvency, with respect to the Company, any Restricted Subsidiary of the Company that is a Significant Subsidiary or any group of Restricted Subsidiaries of the Company that, taken together, would constitute a Significant Subsidiary, all outstanding notes will become due and payable immediately without further action or notice. If any other Event of Default occurs and is continuing, the trustee or the holders of at least 25% in aggregate principal amount of the then outstanding notes may declare all the notes to be due and payable immediately.

Holders of the notes may not enforce the indenture or the notes except as provided in the indenture. Subject to certain limitations, holders of a majority in aggregate principal amount of the then outstanding notes may direct the trustee in its exercise of any trust or power. The trustee may withhold from holders of the notes notice of any continuing Default or Event of Default if it determines that withholding notice is in their interest, except a Default or Event of Default relating to the payment of principal of, or interest or premium, if any, on, the notes.

The holders of a majority in aggregate principal amount of the then outstanding notes by written notice to the trustee may, on behalf of the holders of all of the notes, rescind an acceleration or waive any existing Default or Event of Default and its consequences under the indenture, if the rescission would not conflict with any judgment or decree, except a continuing Default or Event of Default in the payment of principal of, or interest or premium, if any, on, the notes.

The Company is required to deliver to the trustee annually an officers’ certificate regarding compliance with the indenture. Upon any Officer of the Company becoming aware of any Default or Event of Default, the Company is required to deliver to the trustee a statement specifying such Default or Event of Default within 30 days after such Officer becomes aware of the occurrence and continuance of such Default or Event of Default, unless such Default or Event of Default has been cured before the end of the 30-day period.

No past, present or future director, officer, partner, employee, incorporator, member, manager, stockholder, unitholder or other owner of the Capital Stock of the Company or any Guarantor, as such, will have any liability for any obligations of the Company or the Guarantors under the notes, the indenture or the Note Guarantees or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each holder of notes by accepting a note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the notes.

The Company may at any time, at the option of its Board of Directors evidenced by a resolution set forth in an officers’ certificate, elect to have all of its obligations discharged with respect to the outstanding notes and all obligations of the Guarantors discharged with respect to their Note Guarantees (“Legal Defeasance”) except for:

(1) the rights of holders of outstanding notes to receive payments in respect of the principal of, or interest or premium, if any, on, such notes when such payments are due from the trust referred to below;

(2) the Company’s obligations with respect to the notes concerning issuing temporary notes, registration of notes, mutilated, destroyed, lost or stolen notes and the maintenance of an office or agency for payment and money for security payments held in trust;

(3) the rights, powers, trusts, duties and immunities of the trustee under the indenture, and the Company’s and the Guarantors’ obligations in connection therewith; and

In addition, the Company may, at its option and at any time, elect to have its obligations and the obligations of the Guarantors released with respect to (x) all of the covenants that are described under “—Certain Covenants” and under “—Repurchase at the Option of Holders” (other than the covenant described in the first paragraph under “—Certain Covenants—Merger, Consolidation or Sale of Assets,” except to the extent described below), including the Company’s obligation to make Change of Control Offers and Asset Sale Offers, and (y) the limitations described in clause (4) of the first paragraph under “—Certain Covenants—Merger, Consolidation or Sale of Assets” (“Covenant Defeasance”) and thereafter any omission to comply with those covenants or limitations will not constitute a Default or Event of Default with respect to the notes. In the event Covenant Defeasance occurs, all Events of Default described under “—Events of Default and Remedies” (except those relating to payments on the notes or bankruptcy or insolvency events as to the Company) will no longer constitute an Event of Default with respect to the notes.

(1) the Company must irrevocably deposit with the trustee, in trust, for the benefit of the holders of the notes, cash in U.S. dollars, non-callable Government Securities, or a combination thereof, in amounts as will be sufficient, in the opinion of a nationally recognized investment bank, appraisal firm or firm of independent public accountants, to pay the principal of, and interest and premium, if any, on, the outstanding notes on the stated date for payment thereof or on the applicable redemption date, as the case may be, and the Company must specify whether the notes are being defeased to such stated date for payment or to a particular redemption date;

(2) in the case of Legal Defeasance, the Company must deliver to the trustee an opinion of counsel reasonably acceptable to the trustee confirming that

(a) the Company has received from, or there has been published by, the Internal Revenue Service a ruling or

(b) since the date of the indenture, there has been a change in the applicable federal income tax law, in either case to the effect that, and based thereon such opinion of counsel will confirm that, the holders of the outstanding notes will not recognize income, gain or loss for federal income tax purposes as a result of such Legal Defeasance and will be subject to federal income tax on the same amounts, in the same manner and at the same times as would have been the case if such Legal Defeasance had not occurred;

(3) in the case of Covenant Defeasance, the Company must deliver to the trustee an opinion of counsel reasonably acceptable to the trustee confirming that the holders of the outstanding notes will not recognize income, gain or loss for federal income tax purposes as a result of such Covenant Defeasance and will be subject to federal income tax on the same amounts, in the same manner and at the same times as would have been the case if such Covenant Defeasance had not occurred;

(4) the Company must deliver to the trustee an officer’s certificate stating that no Default or Event of Default has occurred and is continuing on the date of such deposit (other than a Default or Event of Default resulting from the borrowing of funds to be applied to such deposit (and any similar concurrent deposit relating to other Indebtedness), and the granting of Liens to secure such borrowings, all or a portion of which are to be applied to such deposit);

(5) the Company must deliver to the trustee an officer’s certificate stating that such Legal Defeasance or Covenant Defeasance will not result in a breach or violation of, or constitute a default under, any material agreement or instrument (other than the indenture and the agreements governing any other Indebtedness being defeased, discharged or replaced) to which the Company or any Guarantor is a party or by which the Company or any Guarantor is bound;

(6) the Company must deliver to the trustee an officers’ certificate stating that the deposit was not made by the Company with the intent of preferring the holders of notes over the other creditors of the Company with the intent of defeating, hindering, delaying or defrauding any creditors of the Company or others; and

(7) the Company must deliver to the trustee an officers’ certificate and an opinion of counsel, each stating that all conditions precedent relating to the Legal Defeasance or the Covenant Defeasance, as the case may be, have been complied with.

Except as provided in the next two succeeding paragraphs, the indenture, the notes or the Note Guarantees may be amended or supplemented with the consent of the holders of a majority in aggregate principal amount of the then outstanding notes voting as a single class (including, without limitation, consents obtained in connection with a tender offer or exchange offer for, or purchase of, the notes), and any existing Default or Event of Default (other than a Default or Event of Default in the payment of the principal of, or interest or premium, if any, on, the notes, except a payment default resulting from an acceleration that has been rescinded) or compliance with any provision of the indenture, the notes or the Note Guarantees may be waived with the consent of the holders of a majority in aggregate principal amount of the then outstanding notes (including, without limitation, additional notes, if any) voting as a single class (including, without limitation, consents obtained in connection with a purchase of, or tender offer or exchange offer for, notes).

Without the consent of each holder of notes affected, an amendment, supplement or waiver may not (with respect to any notes held by a non-consenting holder):

(1) reduce the principal amount of notes whose holders must consent to an amendment, supplement or waiver;

(2) reduce the principal of or change the fixed maturity of any note or alter or waive any of the provisions with respect to the redemption of the notes (except provisions related to minimum required notice of optional redemption and those provisions relating to the covenants described above under the caption “Repurchase at the Option of Holders”);

(3) reduce the rate of or change the time for payment of interest, including default interest, on any note;

(4) waive a Default or Event of Default in the payment of principal of, or interest or premium, if any, on, the notes (except (i) a payment required by one of the covenants described above under the caption “—Repurchase at the Option of Holders” or (ii) a rescission of acceleration of the notes by the holders of a majority in aggregate principal amount of the then outstanding notes and a waiver of the payment default that resulted from such acceleration);

(6) make any change in the provisions of the indenture relating to waivers of past Defaults or the rights of holders of notes to receive payments of principal of, or interest or premium, if any, on, the notes (other

than a payment required by one of the covenants described above under the caption “—Repurchase at the Option of Holders”);

(7) waive a redemption payment with respect to any note (other than a payment required by one of the covenants described above under the caption “—Repurchase at the Option of Holders”);

(8) release any Guarantor from any of its obligations under its Note Guarantee or the indenture, except in accordance with the terms of the indenture; or

(9) make any change in the preceding amendment, supplement and waiver provisions.

Notwithstanding the preceding, without the consent of any holder of notes, the Company, the Guarantors and the trustee may amend or supplement the indenture, the notes or the Note Guarantees:

(2) to provide for uncertificated notes in addition to or in place of certificated notes;

(3) to provide for the assumption of the Company’s or a Guarantor’s obligations to holders of notes and Note Guarantees in the case of a merger or consolidation or sale of all or substantially all of the Company’s or such Guarantor’s properties or assets, as applicable;

(4) to make any change that would provide any additional rights or benefits to the holders of notes or that does not adversely affect the legal rights under the indenture of any holder;

(5) to comply with requirements of the SEC in order to effect or maintain the qualification of the indenture under the Trust Indenture Act;

(6) to conform the text of the indenture, the notes or the Note Guarantees to any provision of the “Description of Notes” section of the Company’s offering memorandum dated January 27, 2017 relating to the issuance of the old notes on February 1, 2017;

(7) to provide for the issuance of additional notes in accordance with the limitations set forth in the indenture as of the date of the indenture;

(8) to secure the notes or the Note Guarantees pursuant to the requirements of the covenant described above under the subheading “—Certain Covenants—Liens”;

(9) to add any additional Guarantor or to evidence the release of any Guarantor from its Note Guarantee, in each case as provided in the indenture;

(10) to evidence or provide for the acceptance of appointment under the indenture of a successor trustee; or

(11) to provide for the reorganization of the Company as any other form of entity in accordance with the third paragraph of “—Certain Covenants—Merger, Consolidation or Sale of Assets.”

The consent of the holders is not necessary under the indenture to approve the particular form of any proposed amendment, supplement or waiver. It is sufficient if such consent approves the substance of the proposed amendment, supplement or waiver. After an amendment, supplement or waiver under the indenture requiring the approval of the holders becomes effective, the Company will mail to the holders a notice briefly describing the amendment, supplement or waiver. However, the failure to give such notice, or any defect in the notice, will not impair or affect the validity of the amendment, supplement or waiver.

The indenture will be discharged and will cease to be of further effect as to all notes issued thereunder (except as to surviving rights of registration of transfer or exchange of the notes and as otherwise specified in the indenture), when:

(a) all notes that have been authenticated, except lost, stolen or destroyed notes that have been replaced or paid and notes for whose payment money has been deposited in trust and thereafter repaid to the Company, have been delivered to the trustee for cancellation; or

(b) all notes that have not been delivered to the trustee for cancellation have become due and payable or will become due and payable within one year by reason of the mailing of a notice of redemption or otherwise and either the Company or any Guarantor has irrevocably deposited or caused to be deposited with the trustee as trust funds in trust solely for the benefit of the holders, cash in U.S. dollars, non-callable Government Securities, or a combination thereof, in such amounts as will be sufficient, without consideration of any reinvestment of interest, to pay and discharge the entire Indebtedness on the notes not delivered to the trustee for cancellation for principal of, or interest or premium, if any, on, the notes to the date of Stated Maturity or redemption;

(2) the Company has paid or caused to be paid all other sums payable by the Company under the indenture; and

(3) if applicable, the Company has delivered irrevocable instructions to the trustee to apply the deposited money toward the payment of the notes at Stated Maturity or on the redemption date, as the case may be.

In addition, the Company must deliver an officers’ certificate and an opinion of counsel to the trustee stating that all conditions precedent to satisfaction and discharge have been satisfied.

If the trustee becomes a creditor of the Company or any Guarantor, the indenture limits the right of the trustee to obtain payment of claims in certain cases, or to realize on certain property received in respect of any such claim as security or otherwise. The trustee is permitted to engage in other transactions; however, if it acquires any conflicting interest (as defined in the Trust Indenture Act) after a Default has occurred and is continuing it must eliminate such conflict within 90 days, apply to the SEC for permission to continue as trustee (if the indenture has been qualified under the Trust Indenture Act) or resign.

The holders of a majority in aggregate principal amount of the then outstanding notes have the right to direct the time, method and place of conducting any proceeding for exercising any remedy available to the trustee, subject to certain exceptions. In case an Event of Default has occurred and is continuing, the trustee is required, in the exercise of its powers, to use the degree of care of a prudent man in the conduct of his own affairs. Subject to such provisions, the trustee is under no obligation to exercise any of its rights or powers under the indenture at the request of any holder of notes, unless such holder has offered to the trustee reasonable indemnity or security satisfactory to it against any loss, liability or expense.

The indenture, the notes and the Note Guarantees will be governed by, and construed in accordance with, the laws of the State of New York.

The new notes will be issued initially only in the form of one or more global notes (collectively, the “Global Notes”). The Global Notes will be deposited upon issuance with the trustee as custodian for DTC and registered in the name of DTC’s nominee, Cede & Co., in each case for credit to an account of a direct or indirect participant in DTC as described below. Beneficial interests in the Global Notes may be held through the Euroclear System (“Euroclear”) and Clearstream Banking, S.A. (“Clearstream”) (as indirect participants in DTC).

The Global Notes may be transferred, in whole but not in part, only to another nominee of DTC or to a successor of DTC or its nominee. Beneficial interests in the Global Notes may not be exchanged for notes in registered, certificated form (“Certificated Notes”) except in the limited circumstances described below. See “—Exchange of Global Notes for Certificated Notes.” In addition, transfers of beneficial interests in the Global Notes will be subject to the applicable rules and procedures of DTC and its direct or indirect participants (including, if applicable, those of Euroclear and Clearstream), which may change from time to time.

The following description of the operations and procedures of DTC, Euroclear and Clearstream are provided solely as a matter of convenience. These operations and procedures are solely within the control of the respective settlement systems and are subject to changes by them. The Company takes no responsibility for these operations and procedures and urges investors to contact the system or their participants directly to discuss these matters.

DTC has advised the Company that DTC is a limited-purpose trust company created to hold securities for its participating organizations (collectively, the “Participants”) and to facilitate the clearance and settlement of transactions in those securities between Participants through electronic book-entry changes in accounts of its Participants. The Participants include securities brokers and dealers (including the initial purchasers), banks, trust companies, clearing corporations and certain other organizations. Access to DTC’s system is also available to other entities such as banks, brokers, dealers and trust companies that clear through or maintain a custodial relationship with a Participant, either directly or indirectly (collectively, the “Indirect Participants”). Persons who are not Participants may beneficially own securities held by or on behalf of DTC only through the Participants or the Indirect Participants. The ownership interests in, and transfers of ownership interests in, each security held by or on behalf of DTC are recorded on the records of the Participants and Indirect Participants.

DTC has also advised the Company that, pursuant to procedures established by it:

(1) upon deposit of the Global Notes, DTC will credit the accounts of the Participants designated by the exchange agent with portions of the principal amount of the Global Notes; and

(2) ownership of these interests in the Global Notes will be shown on, and the transfer of ownership of these interests will be effected only through, records maintained by DTC (with respect to the Participants) or by the Participants and the Indirect Participants (with respect to other owners of beneficial interests in the Global Notes).

Investors in the Global Notes who are Participants in DTC’s system may hold their interests therein directly through DTC. Investors in the Global Notes who are not Participants may hold their interests therein indirectly through organizations (including Euroclear and Clearstream) which are Participants in such system. Euroclear and Clearstream may hold interests in the Global Notes on behalf of their participants through customers’ securities accounts in their respective names on the books of their depositories, which are Euroclear Bank S.A./ N.V, as operator of Euroclear, and Citibank, N.A., as operator of Clearstream. All interests in a Global Note, including those held through Euroclear or Clearstream, may be subject to the procedures and requirements of DTC. Those interests held through Euroclear or Clearstream may also be subject to the procedures and requirements of such systems.

The laws of some jurisdictions may require that certain Persons take physical delivery in definitive form of securities that they own. Consequently, the ability to transfer beneficial interests in a Global Note to such Persons will be limited to that extent. Because DTC can act only on behalf of Participants, which in turn act on behalf of the Indirect Participants, the ability of a Person having beneficial interests in a Global Note to pledge such interests to Persons that do not participate in the DTC system, or otherwise take actions in respect of such interests, may be affected by the lack of a physical certificate evidencing such interests.

Except as described below, owners of beneficial interests in the Global Notes will not have notes registered in their names, will not receive physical delivery of Certificated Notes and will not be considered the registered owners or “holders” thereof under the indenture for any purpose.

Payments in respect of the principal of, and interest and premium, if any, on, a Global Note registered in the name of DTC or its nominee will be payable to DTC in its capacity as the registered holder under the indenture. Under the terms of the indenture, the Company, the Guarantors and the trustee will treat the Persons in whose names the notes, including the Global Notes, are registered as the owners of the notes for the purpose of receiving payments and for all other purposes. Consequently, neither the Company, the Guarantors, the trustee nor any agent of the Company, the Guarantors or the trustee has or will have any responsibility or liability for:

(1) any aspect of DTC’s records or any Participant’s or Indirect Participant’s records relating to or payments made on account of beneficial ownership interests in the Global Notes or for maintaining, supervising or reviewing any of DTC’s records or any Participant’s or Indirect Participant’s records relating to the beneficial ownership interests in the Global Notes; or

(2) any other matter relating to the actions and practices of DTC or any of its Participants or Indirect Participants.

DTC has advised the Company that its current practice, at the due date of any payment in respect of securities such as the notes, is to credit the accounts of the relevant Participants with the payment on the payment date unless DTC has reason to believe that it will not receive payment on such payment date. Each relevant Participant is credited with an amount proportionate to its beneficial ownership of an interest in the principal amount of the relevant security as shown on the records of DTC. Payments by the Participants and the Indirect Participants to the beneficial owners of notes will be governed by standing instructions and customary practices and will be the responsibility of the Participants or the Indirect Participants and will not be the responsibility of DTC, the trustee, the Company or the Guarantors. Neither the Company, the Guarantors nor the trustee will be liable for any delay by DTC, its nominee or any Participant or Indirect Participant in identifying the beneficial owners of the notes, and the Company, the Guarantors and the trustee may conclusively rely on and will be protected in relying on instructions from DTC or its nominee for all purposes.

Transfers between the Participants will be effected in accordance with DTC’s procedures, and will be settled in same-day funds, and transfers between participants in Euroclear and Clearstream will be effected in accordance with their respective rules and operating procedures.

Cross-market transfers between the Participants, on the one hand, and Euroclear or Clearstream participants, on the other hand, will be effected through DTC in accordance with DTC’s rules on behalf of Euroclear or Clearstream, as the case may be, by their respective depositaries; however, such cross-market transactions will require delivery of instructions to Euroclear or Clearstream, as the case may be, by the counterparty in such system in accordance with the rules and procedures and within the established deadlines (Brussels time) of such system. Euroclear or Clearstream, as the case may be, will, if the transaction meets its settlement requirements, deliver instructions to its depositary to take action to effect final settlement on its behalf by delivering or receiving interests in the relevant Global Note in DTC, and making or receiving payment in accordance with normal procedures for same-day funds settlement applicable to DTC. Euroclear participants and Clearstream participants may not deliver instructions directly to the depositaries for Euroclear or Clearstream.

DTC has advised the Company that it will take any action permitted to be taken by a holder of notes only at the direction of one or more Participants to whose account DTC has credited the interests in the Global Notes and only in respect of such portion of the aggregate principal amount of the notes as to which such Participant or Participants has or have given such direction. However, if there is an Event of Default under the notes, DTC reserves the right to exchange the Global Notes for Certificated Notes, and to distribute such notes to its Participants.

Although DTC, Euroclear and Clearstream have agreed to the foregoing procedures to facilitate transfers of interests in the Global Notes among participants in DTC, Euroclear and Clearstream, they are under no obligation to perform or to continue to perform such procedures, and may discontinue such procedures at anytime. None of the Company, the Guarantors, the trustee or any of their respective agents will have any responsibility for the performance by DTC, Euroclear or Clearstream or their respective participants or indirect participants of their respective obligations under the rules and procedures governing their operations.

A Global Note is exchangeable for Certificated Notes in minimum denominations of $2,000 and in integral multiples of $1,000 in excess of $2,000, if:

(1) DTC (a) notifies the Company that it is unwilling or unable to continue as depositary for the Global Note or (b) has ceased to be a clearing agency registered under the Exchange Act and, in either event, the Company fails to appoint a successor depositary within 90 days;

(2) the Company, at its option but subject to DTC’s requirements, notifies the trustee in writing that they elect to cause the issuance of the Certificated Notes; or

(3) there has occurred and is continuing an Event of Default, and DTC notifies the trustee of its decision to exchange such Global Note for Certificated Notes.

In addition, beneficial interests in a Global Note may be exchanged for Certificated Notes upon prior written notice given to the trustee by or on behalf of DTC in accordance with the indenture. In all cases, Certificated Notes delivered in exchange for any Global Note or beneficial interests in Global Notes will be registered in the names, and issued in any approved denominations, requested by or on behalf of DTC (in accordance with its customary procedures).

Neither the Company, the Guarantors nor the trustee will be liable for any delay by DTC, its nominee or any Participant or Indirect Participant in identifying the beneficial owners of interests in Global Notes, and the Company, the Guarantors and the trustee may conclusively rely on, and will be protected in relying on, instructions from DTC or its nominee for all purposes, including, without limitation, with respect to the registration and delivery, and the respective principal amounts, of the Certificated Notes to be issued.

Certificated Notes may not be exchanged for beneficial interests in any Global Note, except in the limited circumstances provided in the indenture.

The Company makes payments in respect of the notes represented by the Global Notes (including principal, interest and premium, if any) by wire transfer of immediately available funds to the accounts specified by DTC or its nominee. The Company makes all payments of principal, interest and premium, if any, with respect to Certificated Notes in the manner described above under “—Methods of Receiving Payments on the Notes.” The notes represented by the Global Notes are eligible to trade in DTC’s Same-Day Funds Settlement System, and

any permitted secondary market trading activity in such notes will, therefore, be required by DTC to be settled in immediately available funds. The Company expects that secondary trading in any Certificated Notes will also be settled in immediately available funds.

Because of time zone differences, the securities account of a Euroclear or Clearstream participant purchasing an interest in a Global Note from a Participant will be credited, and any such crediting will be reported to the relevant Euroclear or Clearstream participant, during the securities settlement processing day (which must be a business day for Euroclear and Clearstream) immediately following the settlement date of DTC. DTC has advised the Company that cash received in Euroclear or Clearstream as a result of sales of interests in a Global Note by or through a Euroclear or Clearstream participant to a Participant will be received with value on the settlement date of DTC but will be available in the relevant Euroclear or Clearstream cash account only as of the business day for Euroclear or Clearstream following DTC’s settlement date.

Set forth below are certain defined terms used in the indenture. Reference is made to the indenture for a full disclosure of all defined terms used therein, as well as any other capitalized terms used herein for which no definition is provided.

(1) Indebtedness of any other Person existing at the time such other Person is merged with or into or became a Subsidiary of such specified Person, whether or not such Indebtedness is incurred in connection with, or in contemplation of, such other Person merging with or into, or becoming a Restricted Subsidiary of, such specified Person; and

(2) Indebtedness secured by a Lien encumbering any asset acquired by such specified Person.

(1) any assets used or useful in the Oil and Gas Business, other than Indebtedness or Capital Stock;

(2) the Capital Stock of a Person that becomes a Restricted Subsidiary as a result of the acquisition of such Capital Stock by the Company or any of its Restricted Subsidiaries; or

(3) Capital Stock constituting a minority interest in any Person that at such time is a Restricted Subsidiary;

provided, however, that any such Restricted Subsidiary described in clause (2) or (3) is primarily engaged in the Oil and Gas Business.

“Adjusted Consolidated Net Tangible Assets” means (without duplication), as of the date of determination,

(a) the discounted future net revenues from proved oil and natural gas reserves of the Company and its Restricted Subsidiaries calculated in accordance with SEC guidelines before any state or federal income taxes, as estimated in a reserve report prepared as of the end of either the Company’s most recently completed fiscal year (or, if such date of determination is within 45 days after the end of such most recently completed fiscal year and no reserve report as of the end of such fiscal year has at the time been prepared or audited by independent petroleum engineers, the Company’s second preceding fiscal year) or, at the Company’s option, the Company’s most recently completed fiscal quarter for which internal financial statements are available, which reserve report is prepared or audited by independent petroleum engineers as to proved reserves accounting for at least 80% of all such discounted future net revenues and by the Company’s petroleum engineers with respect to any other

proved reserves covered by such report, as increased by, as of the date of determination, the estimated discounted future net revenues calculated in accordance with SEC guidelines from:

(i) estimated proved oil and natural gas reserves of the Company and its Restricted Subsidiaries acquired since the date of such year-end or quarterly reserve report, and

(ii) estimated proved oil and natural gas reserves of the Company and its Restricted Subsidiaries attributable to extensions, discoveries and other additions and upward revisions of estimates of proved oil and natural gas reserves (including previously estimated development costs incurred during the period and the accretion of discount since the prior period end) since the date of such year-end or quarterly reserve report due to exploration, development or exploitation, production or other activities which would, in accordance with standard industry practice, cause such revisions, and decreased by, as of the date of determination, the estimated discounted future net revenue attributable to:

(iii) estimated proved oil and natural gas reserves of the Company and its Restricted Subsidiaries reflected in such reserve report produced or disposed of since the date of such year-end or quarterly reserve report, and

(iv) reductions in estimated proved oil and natural gas reserves of the Company and its Restricted Subsidiaries reflected in such reserve report attributable to downward revisions of estimates of proved oil and natural gas reserves since such year-end or quarterly reserve report due to changes in geological conditions or other factors which would, in accordance with standard industry practice, cause such revisions;

in the case of the preceding clauses (i) through (iv), calculated on a pre-tax basis in accordance with SEC guidelines (utilizing the prices utilized in the Company’s year-end or quarterly reserve report, as applicable) and estimated by the Company’s petroleum engineers or, at the Company’s election, any independent petroleum engineers engaged by the Company for that purpose;

(b) the capitalized costs that are attributable to oil and natural gas properties of the Company and its Restricted Subsidiaries to which no proved oil and natural gas reserves are attributable, based on the Company’s books and records as of a date no earlier than the last day of the Company’s most recent quarterly or annual period for which internal financial statements are available;

(c) the Consolidated Net Working Capital of the Company and its Restricted Subsidiaries as of a date no earlier than the last day of the Company’s most recent quarterly or annual period for which internal financial statements are available; and

(ii) the appraised value, as estimated by independent appraisers, of other tangible assets (including Investments in unconsolidated Subsidiaries),

in each case, of the Company and its Restricted Subsidiaries as of a date no earlier than the last day of the date of the Company’s most recent quarterly or annual period for which internal financial statements are available; provided that if no such appraisal has been performed, the Company shall not be required to obtain such an appraisal and only clause (d)(i) of this definition shall apply,

minus, to the extent not otherwise taken into account in the immediately preceding clause (1),

(b) any net natural gas balancing liabilities of the Company and its Restricted Subsidiaries as of the last day of the Company’s most recent annual or quarterly period for which internal financial

statements are available to the extent not deducted in calculating Consolidated Net Working Capital of the Company and its Restricted Subsidiaries in accordance with clause (1)(c) of this definition;

(c) to the extent included in clause (1)(a) above, the discounted future net revenues, calculated in accordance with SEC guidelines (utilizing the prices utilized in the Company’s year-end or quarterly reserve report), attributable to reserves that are required to be delivered to third parties to fully satisfy the obligations of the Company and its Restricted Subsidiaries with respect to Volumetric Production Payments on the schedules specified with respect thereto, and

(d) the discounted future net revenues, calculated in accordance with SEC guidelines, attributable to reserves subject to Dollar-Denominated Production Payments that, based on the estimates of production and price assumptions included in determining the discounted future net revenues specified in clause (1)(a) above, would be necessary to fully satisfy the payment obligations of the Company and its Restricted Subsidiaries with respect to Dollar-Denominated Production Payments on the schedules specified with respect thereto.

If the Company changes its method of accounting from the successful efforts method to the full cost method or a similar method of accounting, Adjusted Consolidated Net Tangible Assets will continue to be calculated as if the Company were still using the successful efforts method of accounting.

“Affiliate” of any specified Person means any other Person directly or indirectly controlling or controlled by or under direct or indirect common control with such specified Person. For purposes of this definition, “control,” as used with respect to any Person, means the possession, directly or indirectly, of the power to direct or cause the direction of the management or policies of such Person, whether through the ownership of voting securities, by agreement or otherwise. For purposes of this definition, the terms “controlling,” “controlled by” and “under common control with” have correlative meanings.

“Applicable Premium” means, with respect to any note on any redemption date, the greater of:

(a) the present value at such redemption date of (i) the redemption price of the note at February 1, 2020 (such redemption price being set forth in the table appearing above under the caption “—Optional Redemption”) plus (ii) all required interest payments due on the note through February 1, 2020 (in each case, excluding accrued but unpaid interest to the redemption date), computed using a discount rate equal to the Treasury Rate as of such redemption date plus 50 basis points discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months), over

“as determined in good faith by the Company” means a determination made in good faith by the Board of Directors of the Company or any Officer of the Company involved in or otherwise familiar with the transaction for which such determination is being made, any such determination being conclusive for all purposes under the indenture.

(1) the sale, lease (other than operating leases entered into in the ordinary course of business), conveyance or other disposition of any assets or rights by the Company or any of the Company’s Restricted Subsidiaries; and

(2) the issuance of Equity Interests by any of the Company’s Restricted Subsidiaries or the sale by the Company or any of the Company’s Restricted Subsidiaries of Equity Interests in any of the Company’s Subsidiaries (in either case other than Preferred Stock of any Restricted Subsidiary issued in compliance

with the covenant described above under the caption “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock,” and directors’ qualifying shares or shares required by applicable law to be held by a Person other than the Company or a Restricted Subsidiary);

provided that, in the case of (1) or (2), the sale, assignment, transfer, conveyance, lease or other disposition of all or substantially all of the properties or assets of the Company and its Subsidiaries (including by way of a merger or consolidation) will be governed by the provisions of the indenture described above under the caption “—Repurchase at the Option of Holders—Change of Control” and/or the provisions described above under the caption “—Certain Covenants—Merger, Consolidation or Sale of Assets” and not by the provisions of the Asset Sales covenant.

Notwithstanding the preceding, none of the following items will be deemed to be an Asset Sale:

(1) any single transaction or series of related transactions that involves assets or Equity Interests having a Fair Market Value of less than $15.0 million;

(2) a transfer of assets between or among the Company and its Restricted Subsidiaries;

(3) an issuance or sale of Equity Interests by a Restricted Subsidiary of the Company to the Company or to a Restricted Subsidiary of the Company;

(4) the sale, lease or other disposition of products, services, inventory or accounts receivable in the ordinary course of business and any sale or other disposition of surplus, damaged, worn-out or obsolete assets (including the abandonment or other disposition of intellectual property that is, in the reasonable judgment of the Company, no longer economically practicable to maintain or useful in the conduct of the business of the Company and its Restricted Subsidiaries taken as whole);

(5) the abandonment, farm-out, lease or sublease of developed or undeveloped oil or natural gas properties, or the forfeiture of such properties, owned or held by the Company or any of its Restricted Subsidiaries in the ordinary course of business;

(6) licenses and sublicenses by the Company or any of its Restricted Subsidiaries of software, intellectual property or other general intangibles in the ordinary course of business;

(7) any surrender or waiver of contract rights or settlement, release, recovery on or surrender of contract, tort or other claims;

(8) the granting, creation or incurrence of Liens not prohibited by the covenant described above under the caption “—Certain Covenants—Liens” and dispositions in connection with such Liens and the exercise by any Person in whose favor such Lien is granted of any of its rights in respect of such Lien;

(9) the sale or other disposition of cash or Cash Equivalents or other financial instruments (other than Oil and Gas Hedging Contracts);

(10) a disposition of assets that constitutes (or results in by virtue of the consideration received for such disposition) either a Restricted Payment that does not violate the covenant described above under the caption “—Certain Covenants—Restricted Payments” or a Permitted Investment or a Permitted Payment;

(11) a sale or other disposition of Hydrocarbons or other mineral products in the ordinary course of business;

(13) dispositions of crude oil and natural gas properties (whether or not in the ordinary course of business); provided that at the time of any such disposition such properties do not have associated with them any proved reserves;

(14) any Production Payments and Reserve Sales; provided that any such Production Payments and Reserve Sales, other than incentive compensation programs on terms that are customary in the Oil and Gas

Business for geologists, geophysicists and other providers of technical services to the Company or a Restricted Subsidiary, shall have been created, incurred, issued, assumed or Guaranteed in connection with the financing of, and within 60 days after the acquisition of, the property that is subject thereto;

(15) the disposition of assets or Equity Interests received in settlement of debts owing to a Person as a result of foreclosure, perfection or enforcement of any Lien or debt, which debts were owing to such Person; and

(16) any sale of Equity Interests in, or Indebtedness or other securities of, an Unrestricted Subsidiary.

“Asset Swap” means any substantially contemporaneous (and in any event occurring within 180 days of each other) purchase and sale or exchange of any assets or properties used or useful in the Oil and Gas Business between the Company or any of its Restricted Subsidiaries and another Person; provided, that the Fair Market Value of the properties or assets traded or exchanged by the Company or such Restricted Subsidiary (together with any cash or Cash Equivalents) is reasonably equivalent to the Fair Market Value of the properties or assets (together with any cash or Cash Equivalents) to be received by the Company or such Restricted Subsidiary, and provided further, that any net cash or Cash Equivalents received must be applied in accordance with the provisions described above under the caption “—Repurchase at the Option of Holders—Asset Sales” if then in effect as if the Asset Swap were an Asset Sale.

“Attributable Debt” in respect of a sale and leaseback transaction means, at the time of determination, the present value of the obligation of the lessee for net rental payments during the remaining term of the lease included in such sale and leaseback transaction including any period for which such lease has been extended or may, at the option of the lessor, be extended. Such present value shall be calculated using a discount rate equal to the rate of interest implicit in such transaction, determined in accordance with GAAP; provided, however, that if such sale and leaseback transaction results in a Capital Lease Obligation, the amount of Indebtedness represented thereby will be determined in accordance with the definition of “Capital Lease Obligation.”

“Beneficial Owner” has the meaning assigned to such term in Rule 13d-3 and Rule 13d-5 under the Exchange Act, except that in calculating the beneficial ownership of any particular “person” (as that term is used in Section 13(d)(3) of the Exchange Act), such “person” will be deemed to have beneficial ownership of all securities that such “person” has the right to acquire within one year by conversion or exercise of other securities, whether such right is currently exercisable or is exercisable only after the passage of time. The terms “Beneficially Owns” and “Beneficially Owned” have a corresponding meaning. For purposes of this definition, a Person shall be deemed not to Beneficially Own securities that are the subject of a stock purchase agreement, merger agreement, amalgamation agreement, arrangement agreement or similar agreement until consummation of the transactions or, as applicable, series of related transactions contemplated thereby.

(1) with respect to a corporation, the board of directors of the corporation or any committee thereof duly authorized to act on behalf of such board;

(2) with respect to a limited partnership, the board of directors of the general partner of the partnership;

(3) with respect to a limited liability company, the managing member or members or any controlling committee of managing members thereof; and

(4) with respect to any other Person, the board or committee of such Person serving a similar function.

“Borrowing Base” means the maximum amount determined or re-determined by the lenders under the Credit Agreement as the aggregate lending value to be ascribed to the Oil and Gas Properties of the Company and its Restricted Subsidiaries against which such lenders are prepared to provide loans, letters of credit or other Indebtedness to the Company and the Restricted Subsidiaries under the Credit Agreement, using their customary practices and standards for determining reserve based loans and which are generally applied by commercial

lenders to borrowers in the Oil and Gas Business, as determined semi-annually during each year and/or on such other occasions as may be provided for by the Credit Agreement, and which is based upon, inter alia, the review by such lenders of the hydrocarbon reserves, royalty interests and assets and liabilities of the Company and the Restricted Subsidiaries.

“Capital Lease Obligation” means, at the time any determination is to be made, the amount of the liability in respect of a capital lease that would at that time be required to be capitalized on a balance sheet prepared in accordance with GAAP, with the amount of Indebtedness represented by such obligation being the capitalized amount of such obligation determined in accordance with GAAP, and the Stated Maturity thereof being the date of the last payment of rent or any other amount due under such lease prior to the first date upon which such lease may be prepaid by the lessee without payment of a penalty. Notwithstanding the foregoing, any lease (whether entered into before or after the date of the indenture) that would have been classified as an operating lease pursuant to GAAP as in effect on the date of the indenture will be deemed not to represent a Capital Lease Obligation. For purposes of the covenant described above under the caption “—Certain Covenants—Liens,” a Capital Lease Obligation will be deemed to be secured by a Lien on the property being leased.

(2) in the case of an association or business entity, any and all shares, interests, participations, rights or other equivalents (however designated) of corporate stock;

(3) in the case of a partnership or limited liability company, partnership interests (whether general or limited) or membership interests; and

(4) any other interest or participation that confers on a Person the right to receive a share of the profits and losses of, or distributions of assets of, the issuing Person,

but excluding from all of the foregoing any debt securities exercisable for, exchangeable for or convertible into Capital Stock, whether or not such debt securities include any right of participation with Capital Stock.

(2) securities issued or directly and fully guaranteed or insured by the United States government or any agency or instrumentality of the United States government (provided that the full faith and credit of the United States is pledged in support of those securities) having maturities of not more than one year from the date of acquisition;

(3) marketable general obligations issued by any state of the United States of America or any political subdivision of any such state or any public instrumentality thereof maturing within one year from the date of acquisition thereof and, at the time of acquisition thereof, having a credit rating of “A” or better from either S&P or Moody’s;

(4) certificates of deposit, demand deposits and eurodollar time deposits with maturities of one year or less from the date of acquisition, bankers’ acceptances with maturities not exceeding six months and overnight bank deposits, in each case, with any domestic commercial bank having capital and surplus in excess of $500.0 million or that is a lender under the Credit Agreement;

(5) repurchase obligations with a term of not more than seven days for underlying securities of the types described in clauses (2), (3) and (4) above entered into with any financial institution meeting the qualifications specified in clause (4) above;

(6) commercial paper having one of the two highest ratings obtainable from Moody’s or S&P and, in each case, maturing within one year after the date of acquisition;

(7) money market funds at least 95% of the assets of which constitute Cash Equivalents of the kinds described in clauses (1) through (6) of this definition;

(8) with respect to any Foreign Subsidiary of the Company, investments denominated in local currency that are similar to the items specified in clauses (1) through (7) above; and

(9) marketable short-term money market and similar securities having a rating of at least P-2 or A-2 from either Moody’s or S&P, respectively, and in each case maturing within 24 months after the date of the creation thereof.

“Cash Management Obligations” means, with respect to any Person, any obligations of such Person to any lender in respect of treasury management arrangements, depositary or other cash management services, including any treasury management line of credit.

(1) the direct or indirect sale, lease, transfer, conveyance or other disposition (other than by way of merger or consolidation), in one or a series of related transactions, of all or substantially all of the properties or assets of the Company (including Equity Interests of Restricted Subsidiaries) and its Subsidiaries taken as a whole to any Person (including any “person” (as that term is used in Section 13(d)(3) of the Exchange Act)) other than any Permitted Holder, in each case which occurrence is followed by a Rating Decline within 90 days thereafter;

(2) the adoption of a plan relating to the liquidation or dissolution of the Company; or

(3) the consummation of any transaction (including, without limitation, any merger or consolidation) the result of which is that any “person” (as defined above), other than any Permitted Holder, becomes the Beneficial Owner, directly or indirectly, of more than 50% of the Voting Stock of the Company, measured by voting power rather than number of shares, units or the like, which occurrence is followed by a Rating Decline within 90 days thereafter; provided that a transaction in which the Company becomes a Subsidiary of another Person shall not constitute a Change of Control if, immediately following such transaction, the “persons” (as defined above) who were Beneficial Owners of the Voting Stock of the Company immediately prior to such transaction Beneficially Own, directly or indirectly through one or more intermediaries, 50% or more of the total voting power of the Voting Stock of such other Person of whom the Company has become a Subsidiary.

“Code” means the Internal Revenue Code of 1986, as amended from time to time, and any successor statute or statutes thereto.

“Consolidated Cash Flow” means, with respect to any specified Person for any period, the Consolidated Net Income of such Person for such period plus, without duplication:

(1) an amount equal to any extraordinary expenses or loss plus any net loss realized by such Person or any of its Restricted Subsidiaries in connection with an Asset Sale, to the extent such expenses or losses were deducted in computing such Consolidated Net Income; plus

(2) provision for taxes based on income or profits (including state franchise taxes accounted for as income taxes in accordance with GAAP) of such Person and its Restricted Subsidiaries for such period, to the extent that such provision for taxes was deducted in computing such Consolidated Net Income; plus

(3) the Fixed Charges of such Person and its Restricted Subsidiaries for such period, to the extent that such Fixed Charges were deducted in computing such Consolidated Net Income; plus

(4) depreciation, depletion, amortization (including amortization of intangibles but excluding amortization of prepaid cash expenses that were paid in a prior period), impairment, abandonment expense,

non-cash equity based compensation expense and other non-cash charges and expenses (excluding any such non-cash charge or expense to the extent that it represents an accrual of or reserve for cash charges or expenses in any future period or amortization of a prepaid cash charge or expense that was paid in a prior period) of such Person and its Restricted Subsidiaries for such period to the extent that such depreciation, depletion, amortization, impairment, abandonment expense and other non-cash charges or expenses were deducted in computing such Consolidated Net Income; plus

(5) if such Person accounts for its oil and gas operations using successful efforts or a similar method of accounting, consolidated exploration expense of such Person and its Restricted Subsidiaries; minus

(6) non-cash items increasing such Consolidated Net Income for such period, other than the accrual of revenue in the ordinary course of business; and minus

(7) to the extent increasing such Consolidated Net Income for such period, the sum of (a) the amount of deferred revenues that are amortized during such period and are attributable to reserves that are subject to Volumetric Production Payments and (b) amounts recorded in accordance with GAAP as repayments of principal and interest pursuant to Dollar-Denominated Production Payments, in each case, on a consolidated basis and determined in accordance with GAAP.

“Consolidated Net Income” means, with respect to any specified Person for any period, the aggregate of the net income (loss) of such Person and its Restricted Subsidiaries for such period, on a consolidated basis determined in accordance with GAAP and without any reduction in respect of Preferred Stock dividends; provided that:

(1) the net income (or loss) of any Person that is not a Restricted Subsidiary or that is accounted for by the equity method of accounting will be included, but only to the extent of, in the case of net income, the amount of dividends or distributions paid in cash to the specified Person or a Restricted Subsidiary of the Person, or, in the case of net loss, the amount of cash that has been contributed by the specified Person or Restricted Subsidiary to fund such loss;

(2) the net income of any Restricted Subsidiary of such Person (other than a Guarantor) will be excluded to the extent that the declaration or payment of dividends or similar distributions by that Restricted Subsidiary of that net income is not at the date of determination permitted, directly or indirectly, by operation of the terms of its charter, or any judgment, decree, order, statute, rule or governmental regulation applicable to that Restricted Subsidiary or its stockholders, partners or members or any other loan instrument, agreement or other contractual restriction;

(3) the cumulative effect of a change in accounting principles will be excluded;

(4) any gain (loss), net of taxes (less all fees and expenses relating thereto), realized upon the sale or other disposition of any property, plant or equipment of such Person or its consolidated Restricted Subsidiaries (including pursuant to any sale or leaseback transaction) which is not sold or otherwise disposed of in the ordinary course of business and any gain (loss) realized upon the sale or other disposition of any Capital Stock of any Person, together with any related provision for taxes on any such gain, will be excluded;

(5) to the extent deducted in the calculation of Consolidated Net Income, any non-cash or other charges relating to any premium or penalty paid, write off of deferred financing costs or other financial recapitalization charges in connection with redeeming or retiring any Indebtedness prior to its Stated Maturity will be excluded;

(6) any “ceiling limitation” on Oil and Gas Properties or other asset impairment writedowns on Oil and Gas Properties or other non-current assets under GAAP or SEC guidelines will be excluded; and

(7) any unrealized non-cash gains or losses or charges in respect of Hedging Obligations (including those resulting from the application of FASB ASC 815) will be excluded.

“Consolidated Net Working Capital” means (a) all current assets of the Company and its Restricted Subsidiaries except current assets from Oil and Gas Hedging Contracts, less (b) all current liabilities of the Company and its Restricted Subsidiaries, except (i) current liabilities included in Indebtedness, (ii) current liabilities associated with future abandonment or asset retirement obligations relating to oil and natural gas properties and (iii) any current liabilities from Oil and Gas Hedging Contracts, in each case as set forth in the consolidated financial statements of the Company prepared in accordance with GAAP (excluding any adjustments made pursuant to FASB ASC 815).

“continuing” means, with respect to any Default or Event of Default, that such Default or Event of Default has not been cured or waived.

“Credit Agreement” means that certain Credit Agreement, dated as of December 19, 2016, by and among the Company, as borrower, Wells Fargo Bank, National Association, as administrative agent, and the other financial institutions party thereto, including any related notes, Guarantees, collateral documents, instruments and agreements executed in connection therewith, and, in each case, as amended, restated, modified, renewed, refunded, replaced in any manner (whether upon or after termination or otherwise) or refinanced (including by means of sales of debt securities to institutional investors) in whole or in part from time to time.

“Credit Facilities” means one or more debt facilities (including, without limitation, the Credit Agreement), indentures or commercial paper facilities, in each case, with banks or other lenders or investors providing for revolving credit loans, term loans, capital market financings, debt securities, receivables financing (including through the sale of receivables to such lenders or to special purpose entities formed to borrow from such lenders against such receivables), letters of credit, debt issuances or other borrowings, in each case, as amended, restated, modified, renewed, refunded, replaced in any manner (whether upon or after termination or otherwise) or refinanced (including refinancing with any capital markets transaction or otherwise by means of sales of debt securities to institutional investors) in whole or in part from time to time.

“Customary Recourse Exceptions” means, with respect to any Non-Recourse Debt of an Unrestricted Subsidiary, exclusions from the exculpation provisions with respect to such Non-Recourse Debt for the voluntary bankruptcy of such Unrestricted Subsidiary, fraud, misapplication of cash, environmental claims, waste, willful destruction and other circumstances customarily excluded by lenders from exculpation provisions or included in separate indemnification agreements in non-recourse financings.

“Default” means any event that is, or with the passage of time or the giving of notice or both would be, an Event of Default.

“De Minimis Guaranteed Amount” means a principal amount of Indebtedness that does not exceed $5.0 million.

“Designated Non-cash Consideration” means the Fair Market Value of non-cash consideration received by the Company or a Restricted Subsidiary in connection with an Asset Sale that is so designated as Designated Non-cash Consideration, less the amount of cash or Cash Equivalents received in connection with a subsequent sale of or collection on such Designated Non-cash Consideration.

“Disqualified Stock” means any Capital Stock that, by its terms (or by the terms of any security into which it is convertible, or for which it is exchangeable, in each case, at the option of the holder of the Capital Stock), or upon the happening of any event, matures or is mandatorily redeemable, pursuant to a sinking fund obligation or otherwise, or redeemable at the option of the holder of the Capital Stock (other than in exchange for Capital Stock of the Company (other than Disqualified Stock)), in whole or in part, on or prior to the date that is 91 days after the earlier of (a) the date on which no notes are outstanding and (b) the date on which the notes mature; provided that only the portion of Capital Stock which is mandatorily redeemable or matures or is redeemable at the option of the holder thereof prior to such date will be deemed to be Disqualified Stock; provided further that

any Capital Stock issued pursuant to any plan of the Company or any of its Affiliates for the benefit of one or more employees will not constitute Disqualified Stock solely because it may be required to be repurchased by the Company or any of its Affiliates in order to satisfy applicable contractual, statutory or regulatory obligations. Notwithstanding the preceding sentence, any Capital Stock that would constitute Disqualified Stock solely because the holders of the Capital Stock have the right to require the Company to repurchase or redeem such Capital Stock upon the occurrence of a change of control or an asset sale will not constitute Disqualified Stock if (x) the terms of such Capital Stock provide that the Company may not repurchase or redeem any such Capital Stock pursuant to such provisions unless such repurchase or redemption complies with the covenant described above under the caption “—Certain Covenants—Restricted Payments,” or (y) the terms of such Capital Stock provide that the Company may not repurchase or redeem any such Capital Stock pursuant to such provisions prior to the Company’s purchase of the notes as is required to be purchased pursuant to the provisions of the indenture. The amount (or principal amount) of Disqualified Stock deemed to be outstanding at any time for purposes of the indenture will be the maximum amount that the Company and its Restricted Subsidiaries may become obligated to pay upon the maturity of, or pursuant to any mandatory redemption provisions of, such Disqualified Stock, exclusive of accrued dividends.

“Dollar-Denominated Production Payments” means production payment obligations recorded as liabilities in accordance with GAAP, together with all undertakings and obligations in connection therewith.

“Domestic Subsidiary” means any Restricted Subsidiary of the Company that was formed under the laws of the United States or any state of the United States or the District of Columbia.

“Equity Interests” of any Person means (1) any and all Capital Stock of such Person and (2) all rights to purchase, warrants or options (whether or not currently exercisable), participations or other equivalents of or interests in (however designated) such Capital Stock of such Person, but excluding from all of the foregoing any debt securities exercisable for, exchangeable for or convertible into Equity Interests, regardless of whether such debt securities include any right of participation with Equity Interests.

“Equity Offering” means a sale of Equity Interests of the Company (other than Disqualified Stock and other than to a Subsidiary of the Company) made for cash or any cash contribution to the capital of the Company in respect of Equity Interests (other than Disqualified Stock), in each case after the date of the indenture.

“Exchange Notes” means the notes issued in an Exchange Offer pursuant to the indenture. Such term includes the new notes.

“Exchange Offer” has the meaning set forth for such term in the applicable registration rights agreement.

“Existing Indebtedness” means all Indebtedness of the Company and its Subsidiaries (other than Indebtedness under the Credit Agreement) in existence on the date of the indenture, until such amounts are repaid.

“Fair Market Value” means the value that would be paid by a willing buyer to an unaffiliated willing seller in a transaction not involving distress or necessity of either party.

“Fixed Charge Coverage Ratio” means with respect to any specified Person for any four-quarter reference period, the ratio of the Consolidated Cash Flow of such Person for such period to the Fixed Charges of such Person for such period. In the event that the specified Person or any of its Restricted Subsidiaries incurs, assumes, Guarantees, repays, repurchases, redeems, defeases or otherwise discharges any Indebtedness (other than ordinary working capital borrowings) or issues, repurchases or redeems Preferred Stock subsequent to the commencement of the period for which the Fixed Charge Coverage Ratio is being calculated and on or prior to the date on which the event for which the calculation of the Fixed Charge Coverage Ratio is made (the “Calculation Date”), then the Fixed Charge Coverage Ratio will be calculated giving pro forma effect to such

incurrence, assumption, Guarantee, repayment, repurchase, redemption, defeasance or other discharge of Indebtedness, or such issuance, repurchase or redemption of Preferred Stock, and the use of the proceeds therefrom, as if the same had occurred at the beginning of the applicable four-quarter reference period (except that in making such computation, the amount of Indebtedness under any revolving Credit Facility outstanding on the date of such determination will be deemed to be (i) the average daily balance of such Indebtedness during such four fiscal quarters or such shorter period for which such Credit Facility was outstanding or (ii) if such revolving Credit Facility was created after the end of such four fiscal quarters, the average daily balance of such Indebtedness during the period from the date of creation of such revolving Credit Facility to the date of such determination). If any Indebtedness bears a floating rate of interest and is being given pro forma effect, the interest expense on such Indebtedness will be calculated as if the average rate in effect from the beginning of such period to the Calculation Date had been the applicable rate for the entire period (taking into account any interest Hedging Obligation applicable to such Indebtedness, but if the remaining term of such interest Hedging Obligation is less than twelve months, then such interest Hedging Obligation shall only be taken into account for that portion of the period equal to the remaining term thereof). If any Indebtedness that is being given pro forma effect bears an interest rate at the option of such Person, the interest rate shall be calculated by applying such option rate chosen by such Person. Interest on Indebtedness that may optionally be determined at an interest rate based upon a factor of a prime or similar rate, a Eurocurrency interbank offered rate, or other rate, shall be deemed to have been based upon the rate actually chosen, or if none, then based upon such optional rate chosen as such Person may designate. Interest on any Indebtedness under a revolving Credit Facility will be calculated based upon the average daily balance of such Indebtedness during the applicable period.

(1) acquisitions or Investments that have been made, or contributions received, by the specified Person or any of its Restricted Subsidiaries, including through mergers, consolidations or otherwise (including acquisitions or Investments or contributions of assets used or useful in the Oil and Gas Business), or any Person or any of its Restricted Subsidiaries acquired by the specified Person or any of its Restricted Subsidiaries, and including all related financing transactions and including increases in ownership of Restricted Subsidiaries, during the four-quarter reference period or subsequent to such four-quarter reference period and on or prior to the Calculation Date, or that are to be made on the Calculation Date, will be given pro forma effect as if they had occurred on the first day of the four-quarter reference period;

(2) the Consolidated Cash Flow attributable to discontinued operations, as determined in accordance with GAAP, and operations or businesses or Investments (or ownership interests therein) disposed of on or prior to the Calculation Date, will be excluded;

(3) the Fixed Charges attributable to discontinued operations, as determined in accordance with GAAP, and operations or businesses or Investments (or ownership interests therein) disposed of on or prior to the Calculation Date, will be excluded, but only to the extent that the obligations giving rise to such Fixed Charges will not be obligations of the specified Person or any of its Restricted Subsidiaries following the Calculation Date;

(4) any Person that is to be a Restricted Subsidiary of the specified Person immediately following the Calculation Date will be deemed to have been a Restricted Subsidiary at all times during such four-quarter reference period;

(5) any Person that is not to be a Restricted Subsidiary of the specified Person immediately following the Calculation Date will be deemed not to have been a Restricted Subsidiary at any time during such four-quarter reference period;

(6) interest income reasonably anticipated by such Person to be received during the applicable four-quarter reference period from cash or Cash Equivalents held by such Person or any Restricted Subsidiary of such Person, which cash or Cash Equivalents exist on the Calculation Date or will exist as a result of the transaction giving rise to the need to calculate the Fixed Charge Coverage Ratio, will be included; and

(7) if, since the beginning of such four-quarter reference period, any Person (that subsequently became a Restricted Subsidiary or was merged or consolidated with or into such Person or any of its Restricted Subsidiaries since the beginning of such four-quarter reference period) disposed of any operations or businesses or Investments (or ownership interests therein) or made any acquisition or Investment or received any contribution that would have required an adjustment pursuant to clause (1), (2) or (3) above if made by such Person or any of its Restricted Subsidiaries during such four-quarter reference period, Consolidated Cash Flow and Fixed Charges for such period will be calculated after giving pro forma effect thereto as if such disposition or acquisition, contribution or Investment had occurred on the first day of such four-quarter reference period.

For purposes of this definition, whenever pro forma effect is to be given to any calculation under this definition, the pro forma calculations will be determined in good faith by a responsible financial or accounting Officer of the Company, which determination shall be conclusive for all purposes under the indenture; provided that such Officer may in such Officer’s discretion include any reasonably identifiable and factually supportable pro forma changes to Consolidated Cash Flow or Fixed Charges, including any pro forma expense and cost reductions or synergies that have occurred or are reasonably expected to occur within the 12 months immediately following the Calculation Date (regardless of whether those cost savings or operating improvements could then be reflected in pro forma financial statements in accordance with Regulation S-X promulgated under the Securities Act or any other regulation or policy of the SEC related thereto).

“Fixed Charges” means, with respect to any specified Person for any period, the sum, without duplication, of:

(1) the consolidated interest expense (less interest income) of such Person and its Restricted Subsidiaries for such period, whether paid or accrued (excluding (i) any interest attributable to Dollar-Denominated Production Payments, (ii) write-off of deferred financing costs and (iii) accretion of interest charges on future plugging and abandonment obligations, future retirement benefits and other obligations that do not constitute Indebtedness, but including, without limitation, amortization of debt issuance costs and original issue discount, non-cash interest payments, the interest component of all payments associated with Capital Lease Obligations, imputed interest with respect to Attributable Debt, commissions, discounts and other fees and charges incurred in respect of letter of credit or bankers’ acceptance financings), and net of the effect of all payments made or received pursuant to Hedging Obligations in respect of interest rates; plus

(2) the consolidated interest expense of such Person and its Restricted Subsidiaries that was capitalized during such period; plus

(3) any interest on Indebtedness of another Person (other than Non-Recourse Debt of any Unrestricted Subsidiary or Joint Venture incurred pursuant to clause (14) of the covenant described under the caption “Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock”) that is Guaranteed by such Person or one of its Restricted Subsidiaries or secured by a Lien on assets of such Person or one of its Restricted Subsidiaries, whether or not such Guarantee or Lien is called upon; plus

(4) all dividends, whether paid or accrued and whether or not in cash, on any series of Disqualified Stock of such Person or any series of Preferred Stock of its Restricted Subsidiaries, other than dividends on Equity Interests payable solely in Equity Interests of such Person (other than Disqualified Stock) or to such Person or a Restricted Subsidiary of such Person, in each case, on a consolidated basis and determined in accordance with GAAP.

“Foreign Subsidiary” means any Restricted Subsidiary of the Company that is not a Domestic Subsidiary.

“GAAP” means generally accepted accounting principles in the United States, which are in effect from time to time. All ratio computations based on GAAP contained in the indenture will be computed in conformity with GAAP.

“Guarantee” means a guarantee other than by endorsement of negotiable instruments for collection in the ordinary course of business, direct or indirect, in any manner including, without limitation, by way of a pledge of assets or through letters of credit or reimbursement agreements in respect thereof, of all or any part of any Indebtedness (whether arising by virtue of partnership arrangements, or by agreements to keep-well, to purchase assets, goods, securities or services, to take or pay or to maintain financial statement conditions or otherwise). When used as a verb, “Guarantee” has a correlative meaning.

“Guarantors” means any Subsidiary of the Company that Guarantees the notes in accordance with the provisions of the indenture, and their respective successors and assigns, in each case, until the Note Guarantee of such Person has been released in accordance with the provisions of the indenture.

“Hedging Obligations” means, with respect to any specified Person, the obligations of such Person under any (a) Interest Rate Agreement and (b) Oil and Gas Hedging Contract.

“Hydrocarbons” means oil, natural gas, casing head gas, drip gasoline, natural gasoline, condensate, distillate, liquid hydrocarbons, gaseous hydrocarbons and all constituents, elements or compounds thereof and products refined or processed therefrom.

“Indebtedness” means, with respect to any specified Person, any indebtedness of such Person (excluding accrued expenses and Trade Payables), whether or not contingent:

(2) (a) evidenced by bonds, notes, debentures or similar instruments or (b) constituting letters of credit (or reimbursement agreements in respect thereof) (other than obligations with respect to letters of credit securing obligations (other than obligations described in clauses (1), (2)(a), (3), (4) or (6) of this definition) entered into in the ordinary course of business of such Person to the extent such letters of credit are not drawn upon or, if and to the extent drawn upon, such drawing is reimbursed no later than the tenth Business Day following payment on the letter of credit);

(4) representing Capital Lease Obligations or Attributable Debt in respect of sale and leaseback transactions;

(5) representing the balance deferred and unpaid of the purchase price of any property or services due more than six months after such property is acquired or such services are completed; or

if and to the extent any of the preceding items (other than letters of credit, Attributable Debt and Hedging Obligations) would appear as a liability upon a balance sheet of the specified Person prepared in accordance with GAAP. In addition, the term “Indebtedness” includes all Indebtedness of others secured by a Lien on any asset of the specified Person (whether or not such Indebtedness is assumed by the specified Person) and, to the extent not otherwise included, the Guarantee by the specified Person of any Indebtedness of any other Person (including, with respect to any Production Payment, any warranties or guarantees of production or payment by such Person with respect to such Production Payment, but excluding other contractual obligations of such Person with respect to such Production Payment). Subject to the preceding sentence, neither Dollar-Denominated Production Payments nor Volumetric Production Payments shall be deemed to be Indebtedness.

In addition, “Indebtedness” of any Person shall include Indebtedness described in the preceding paragraph that would not appear as a liability on the balance sheet of such Person if:

(1) such Indebtedness is the obligation of a partnership that is a Joint Venture;

(2) such Person or a Restricted Subsidiary of such Person is a general partner of the Joint Venture (a “Joint Venture General Partner”); and

(3) there is recourse, by contract or operation of law, with respect to the payment of such Indebtedness to property or assets of such Person or a Restricted Subsidiary of such Person; and then such Indebtedness shall be included in an amount not to exceed:

(a) the lesser of (i) the net assets of the Joint Venture General Partner and (ii) the amount of such obligations to the extent that there is recourse, by contract or operation of law, to the property or assets of such Person or a Restricted Subsidiary of such Person; or

(b) if less than the amount determined pursuant to clause (a) immediately above, the actual amount of such Indebtedness that is recourse to such Person or a Restricted Subsidiary of such Person, if the Indebtedness is evidenced by a writing and is for a determinable amount and the related interest expense shall be included in Fixed Charges to the extent actually paid by such Person or its Restricted Subsidiaries.

Notwithstanding the foregoing, the following shall not in any event constitute “Indebtedness”:

(1) any indebtedness which has been defeased or discharged in accordance with GAAP or defeased or discharged pursuant to the deposit of cash or Cash Equivalents (in an amount sufficient to satisfy all such indebtedness at maturity or redemption, as applicable, and all payments of interest and premium, if any) in a trust or account created or pledged for the sole benefit of the holders of such indebtedness, and subject to no other Liens, and the other applicable terms of the instrument governing such indebtedness;

(2) any obligation of a Person in respect of a farm-in agreement or similar arrangement whereby such Person agrees to pay all or a share of the drilling, completion or other expenses of an exploratory or development well (which agreement may be subject to a maximum payment obligations, after which expenses are shared in accordance with the working or participation interest therein or in accordance with the agreement of the parties) or perform the drilling, completion or other operation on such well in exchange for an ownership interest in an oil or gas property;

(3) any unrealized losses or charges in respect of Interest Rate Agreements or Oil and Gas Hedging Contracts (including those resulting from the application of FASB ASC 815);

(4) all contracts and other obligations, agreements, instruments or arrangements described in clauses (10), (18) and (19) of the definition of “Permitted Liens”; and

“Interest Rate Agreement” means any interest rate swap agreement (whether from fixed to floating or from floating to fixed), interest rate cap agreement, interest rate collar agreement or other similar agreement or arrangement designed to protect the Company or any of its Restricted Subsidiaries against fluctuations in interest rates and is not for speculative purposes.

“Investment Grade Rating” means a rating equal to or higher than Baa3 (or the equivalent) by Moody’s or BBB- (or the equivalent) by S&P (or, if either such entity ceases to rate the notes for reasons outside of the control of the Company, the equivalent investment grade credit rating from any other “nationally recognized statistical rating organization” within the meaning of Section 3(a)(62) of the Exchange Act selected by the Company as a replacement agency).

“Investments” means, with respect to any Person, all direct or indirect investments by such Person in other Persons (including Affiliates) in the forms of loans (including Guarantees), advances or capital contributions, and purchases or other acquisitions for consideration of Indebtedness, Equity Interests or other securities, together with all items that are or would be classified as investments on a balance sheet prepared in accordance with GAAP (excluding, in each case, (1) commission, travel and similar advances to officers and employees made in

the ordinary course of business, (2) any interest in an oil or natural gas leasehold to the extent constituting a security under applicable law and (3) advances to customers in the ordinary course of business that are recorded as accounts receivable on the balance sheet of the lender, prepaid expenses or deposits and extensions of trade credit on commercially reasonable terms in accordance with normal trade practices). If the Company or any Restricted Subsidiary of the Company sells or otherwise disposes of any Equity Interests of any direct or indirect Restricted Subsidiary of the Company such that, after giving effect to any such sale or disposition, such Person is no longer a Restricted Subsidiary of the Company (other than the sale of all of the outstanding Capital Stock of such Subsidiary), the Company will be deemed to have made an Investment on the date of any such sale or disposition equal to the Fair Market Value of the Company’s Investments in such Subsidiary that were not sold or disposed of in an amount determined as provided in the penultimate paragraph of the covenant described above under the caption “—Certain Covenants—Restricted Payments.” The acquisition by the Company or any Restricted Subsidiary of the Company of a Person that holds an Investment in a third Person will be deemed to be an Investment by the Company or such Restricted Subsidiary in such third Person in an amount equal to the Fair Market Value of the Investments held by the acquired Person in such third Person in an amount determined as provided in the final paragraph of the covenant described above under the caption “—Certain Covenants—Restricted Payments.” Except as otherwise provided in the indenture, the amount of an Investment will be determined at the time the Investment is made and without giving effect to subsequent changes in value or write-ups, write-downs or write-offs with respect to such Investment.

“Joint Venture” means any Person that is not a direct or indirect Subsidiary of the Company in which the Company or any of its Restricted Subsidiaries makes any Investment.

“Legal Holiday” means a Saturday, a Sunday or a day on which banking institutions in the City of Houston, Texas or the City of New York, New York are authorized by law, regulation or executive order to remain closed.

“Lien” means, with respect to any asset, any mortgage, lien, pledge, charge, security interest or encumbrance of any kind in respect of such asset, whether or not filed, recorded or otherwise perfected under applicable law, including any conditional sale or other title retention agreement, any lease in the nature thereof, any option or other agreement to sell or give a security interest in and any filing of or agreement to give any financing statement under the Uniform Commercial Code (or equivalent statutes) of any jurisdiction other than a precautionary financing statement respecting a lease not intended as a security agreement.

“Midstream Assets” means (i) assets other than cash and Cash Equivalents used primarily for gathering, transmission, compression, storage, processing, marketing, fractionation, dehydration, stabilization or treatment of Hydrocarbons, carbon dioxide or water and (ii) Equity Interests of any Person whose assets consist, in all material respects, of assets referred to in clause (i).

“Midstream Business” means the gathering, marketing, treating, processing, storage, selling, transporting transmission, compression, fractionation, dehydration, stabilization or treatment of Hydrocarbons, carbon dioxide or water.

“Moody’s” means Moody’s Investors Service, Inc. and any successor to the ratings business thereof.

“Net Proceeds” means the aggregate cash proceeds and Cash Equivalents received by the Company or any of its Restricted Subsidiaries in respect of any Asset Sale (including, without limitation, any cash or Cash Equivalents received upon the sale or other disposition of any non-cash consideration received in any Asset Sale but excluding any non-cash consideration deemed to be cash or Cash Equivalents for purposes of the “Asset Sales” provisions of the indenture), net of (i) the costs relating to such Asset Sale, including, without limitation, legal, title and recording expenses, accounting and investment banking fees, and sales commissions, (ii) distributions and other payments required to be made to minority interest holders in Subsidiaries or joint ventures as a result of such Asset Sale, (iii) any relocation expenses and severance and associated costs, expenses and charges of personnel relating to the assets subject to or incurred as a result of the Asset Sale, (iv) taxes paid

or payable as a result of the Asset Sale, in each case, after taking into account any available tax credits or deductions and any tax sharing arrangements, (v) amounts required to be applied to the repayment of Indebtedness (other than revolving credit Indebtedness under a Credit Facility that is secured by a Lien on the asset or assets that were the subject of such Asset Sale), and (vi) any reserve for adjustment or indemnification obligations in respect of the sale price of such asset or assets established in accordance with GAAP.

“Non-Recourse Debt” means, with respect to Indebtedness of any Unrestricted Subsidiary or Joint Venture, Indebtedness:

(1) as to which neither the Company nor any of its Restricted Subsidiaries (a) provides credit support of any kind (including any undertaking, agreement or instrument that would constitute Indebtedness) or (b) is directly or indirectly liable as a guarantor or otherwise, except for Customary Recourse Exceptions and except by the pledge of (or a Guaranty limited in recourse solely to) the Equity Interests of such Unrestricted Subsidiary or Joint Venture; and

(2) as to which the lenders will not have any recourse to the Capital Stock or assets of the Company or any of its Restricted Subsidiaries (other than the Equity Interests of such Unrestricted Subsidiary or Joint Venture), except for Customary Recourse Exceptions.

“Note Guarantee” means the Guarantee by each Guarantor of the Company’s obligations under the indenture and the notes, as provided in the indenture.

“Obligations” means any principal, interest, penalties, fees, indemnifications, reimbursements, damages and other liabilities payable under the documentation governing any Indebtedness.

“Officer” means, with respect to any Person, the Chairman of the Board, the Chief Executive Officer, the President, the Chief Operating Officer, the Chief Financial Officer, the Chief Accounting Officer, the Treasurer, any Assistant Treasurer, the Controller, the Secretary, any Assistant Secretary or any Vice President of such Person (or, if such Person is a limited partnership, the Chairman of the Board, the Chief Executive Officer, the President, the Chief Operating Officer, the Chief Financial Officer, the Chief Accounting Officer, the Treasurer, any Assistant Treasurer, the Controller, the Secretary, any Assistant Secretary or any Vice President of such Person’s general partner).

“Oil and Gas Business” means (i) the acquisition, exploration, development, production, operation and disposition of interests in oil, gas and other Hydrocarbon properties, (ii) the gathering, marketing, treating, processing, storage, selling and transporting of any production from such interests or properties, (iii) any business relating to exploration for or development, production, treatment, processing, storage, transportation or marketing of oil, gas and other minerals and products produced in association therewith and (iv) any activity that, as determined in good faith by the Company, arises from, relates to or is ancillary, complementary or incidental to or necessary or appropriate for the activities described in clauses (i) through (iii) of this definition.

“Oil and Gas Hedging Contracts” means any puts, cap transactions, floor transactions, collar transactions, forward contract, commodity swap agreement, commodity option agreement or other similar agreement or arrangement in respect of Hydrocarbons to be purchased, used, produced, processed or sold by the Company or any of its Restricted Subsidiary that are customary in the Oil and Gas Business and designed to protect against or manage price risks, basis risks or other risks encountered in the Oil and Gas Business and not for speculative purposes.

“Oil and Gas Properties” means all properties, including equity or other ownership interest therein, owned by such Person or any of its Restricted Subsidiaries which contain or are believed to contain “proved oil and gas reserves” as defined in Rule 4-10 of Regulation S-X of the Securities Act.

“Permitted Acquisition Indebtedness” means Indebtedness or Disqualified Stock or Preferred Stock of the Company or any of its Restricted Subsidiaries to the extent such Indebtedness or Disqualified Stock or Preferred

Stock was Indebtedness or Disqualified Stock or Preferred Stock of any other Person existing at the time (a) such Person became a Restricted Subsidiary of the Company or (b) such Person was merged or consolidated with or into the Company or any of its Restricted Subsidiaries, and in each case was not incurred in contemplation of the foregoing, provided that on the date such Person became a Restricted Subsidiary or the date such Person was merged or consolidated with or into the Company or any of its Restricted Subsidiaries, as applicable, either of:

(1) immediately after giving effect to such transaction and any related financing transaction on a pro forma basis as if the same had occurred at the beginning of the applicable four-quarter period, the Company or such Person (if the Company is not the survivor in the transaction) would be permitted to incur at least $1.00 of additional Indebtedness pursuant to the Fixed Charge Coverage Ratio test set forth in the first paragraph of the covenant described above under the caption “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock”; or

(2) immediately after giving effect to such transaction and any related financing transaction on a pro forma basis as if the same had occurred at the beginning of the applicable four-quarter period, the Fixed Charge Coverage Ratio of the Company or such Person (if the Company is not the survivor in the transaction) is equal to or greater than the Fixed Charge Coverage Ratio of the Company immediately prior to such transaction.

“Permitted Business Investments” means Investments made in the ordinary course of, or of a nature that is or shall have become customary in, the Oil and Gas Business as a means of actively exploiting, exploring for, acquiring, developing, processing, gathering, marketing or transporting oil and natural gas through agreements, transactions, interests or arrangements which permit one to share risks or costs, comply with regulatory requirements regarding local ownership or satisfy other objectives customarily achieved through the conduct of Oil and Gas Business jointly with third parties, including, without limitation, (i) ownership interests in oil, natural gas, other Hydrocarbon properties or any interest therein or gathering, transportation, processing, storage or related systems, (ii) entry into and Investments and expenditures in the form of or pursuant to operating agreements, processing agreements, farm-in agreements, farm-out agreements, development agreements, area of mutual interest agreements, unitization agreements, pooling agreements, joint bidding agreements, service contracts, joint venture agreements, partnership agreements (whether general or limited), subscription agreements, stock purchase agreements and other similar or customary agreements, (iii) working interests, royalty interests, mineral leases, production sharing agreements, production sales and marketing agreements, oil or gas leases, overriding royalty agreements, net profits agreements, production payment agreements or royalty trust agreements, (iv) Investments of operating funds on behalf of co-owners of properties used in the Oil and Gas Business of the Company or its Restricted Subsidiaries pursuant to joint operating agreements, and (v) direct or indirect ownership interests in drilling rigs, fracturing units and other related equipment.

“Permitted Holders” means each of (i) WHR Holdings, LLC, Esquisto Holdings, LLC and WHE AcqCo Holdings, LLC, (ii) NGP Energy Capital Management, L.L.C., NGP IX US Holdings, L.P., NGP X US Holdings, L.P. and NGP XI US Holdings, L.P. and (iii) any affiliated funds or investment vehicles managed by any of the persons described in clauses (i) and (ii) above, and any general partner, managing member, principal or managing director of any of the persons described in clauses (i) and (ii) above.

(1) any Investment in the Company (including, without limitation, through the purchase of any notes) or in a Restricted Subsidiary of the Company;

(3) any Investment by the Company or any Restricted Subsidiary of the Company in a Person, if as a result of such Investment:

(b) such Person is merged, consolidated or amalgamated with or into, or transfers or conveys substantially all of its properties or assets to, or is liquidated into, the Company or a Restricted Subsidiary of the Company;

(4) any Investment made as a result of the receipt of non-cash consideration from an Asset Sale or Asset Swap that was made pursuant to and in compliance with the covenant described above under the caption “—Repurchase at the Option of Holders—Asset Sales”;

(5) any acquisition of assets or Capital Stock solely in exchange for the issuance of, or with or out of the net cash proceeds of the substantially concurrent (a) contribution (other than from a Restricted Subsidiary) to the equity capital of the Company in respect of, or (b) sale (other than to a Restricted Subsidiary) of, Equity Interests (other than Disqualified Stock) of the Company, provided that in each such case, the amount of such issuance, contribution or sale will be disregarded for purposes of clause (c)(ii) under the caption “—Certain Covenants—Restricted Payments”;

(6) any Investments received in compromise or resolution of (a) obligations of trade creditors or customers that were incurred in the ordinary course of business of the Company or any of its Restricted Subsidiaries, including pursuant to any plan of reorganization or similar arrangement upon the bankruptcy or insolvency of any trade creditor or customer; or (b) litigation, arbitration or other disputes;

(8) Investments in any Person to the extent such Investments consist of prepaid expenses, negotiable instruments held for collection and lease, utility and workers’ compensation, performance and other deposits made in the ordinary course of business by the Company or any of its Restricted Subsidiaries;

(9) relocation allowances for, and loans or advances to, officers, directors or employees made in the ordinary course of business of the Company or any Restricted Subsidiary of the Company;

(11) any Guarantee of Indebtedness of (a) the Company or a Restricted Subsidiary or (b) any Person that is not an Affiliate of the Company, in each case permitted to be incurred by the covenant described above under the caption “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock”;

(12) any Investment existing on, or made pursuant to binding commitments existing on, the date of the indenture and any Investment consisting of an extension, modification or renewal of any Investment existing on, or made pursuant to a binding commitment existing on, the date of the indenture; provided that the amount of any such Investment may be increased (a) as required by the terms of such Investment as in existence on the date of the indenture or (b) as otherwise permitted under the indenture;

(13) Investments acquired after the date of the indenture as a result of the acquisition by the Company or any Restricted Subsidiary of the Company of another Person, including by way of a merger or consolidation with or into the Company or any of its Restricted Subsidiaries in a transaction that is not prohibited by the covenant described above under the caption “—Certain Covenants—Merger, Consolidation or Sale of Assets” after the date of the indenture to the extent that such Investments were not made in contemplation of such acquisition, merger or consolidation and were in existence on the date of such acquisition, merger or consolidation;

(14) Permitted Business Investments or Permitted Midstream Business Investments;

(15) Investments received as a result of a foreclosure by, or other transfer of title to, the Company or any of its Restricted Subsidiaries with respect to any secured Investment in default;

(16) receivables owing to the Company or any Restricted Subsidiary created or acquired in the ordinary course of business and payable or dischargeable in accordance with customary trade terms; provided, however, that such trade terms may include such concessionary trade terms as the Company or any such Restricted Subsidiary deems reasonable under the circumstances;

(17) Investments consisting of Oil and Gas Hedging Contracts or Interest Rate Agreements permitted under the covenant described above under the caption “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock”;

(18) Guarantees or other Investments arising from the incurrence of Indebtedness by the Company or any Restricted Subsidiary with respect to Indebtedness of any Unrestricted Subsidiary or Joint Venture permitted under clause (14) of the covenant described above under the caption “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock”;

(19) Guarantees of performance or other obligations (other than Indebtedness) arising in the ordinary course in the Oil and Gas Business, including obligations under oil and natural gas exploration, development, joint operating, and related agreements and licenses, concessions or operating leases related to the Oil and Gas Business;

(20) advances and prepayments for asset purchases in the ordinary course of business in the Oil and Gas Business of the Company or any Restricted Subsidiary; and

(21) any Investment in any Person having an aggregate Fair Market Value (measured on the date such Investment was made and without giving effect to subsequent changes in value) that, when taken together with the Fair Market Value (as so measured) of all other Investments made pursuant to this clause (21) that are at the time outstanding, that does not exceed the greater of (a) $50.0 million and (b) 5.0% of Adjusted Consolidated Net Tangible Assets determined at the time such Investment is made; provided, however, that if any Investment pursuant to this clause (21) is made in any Person that is not a Restricted Subsidiary of the Company at the date of the making of such Investment and such Person becomes a Restricted Subsidiary of the Company after such date, such Investment shall thereafter be deemed to have been made pursuant to clause (1) above and shall cease to have been made pursuant to this clause (21) for so long as such Person continues to be a Restricted Subsidiary of the Company (unless the Company otherwise classifies such Investment in compliance with the indenture).

With respect to any Investment, the Company may, in its sole discretion, classify all or any portion of any Investment in one or more of the above clauses so that the entire Investment is a Permitted Investment.

(1) Liens on assets of the Company or any Restricted Subsidiary securing Indebtedness under Credit Facilities that was permitted by the terms of the indenture to be incurred pursuant to clause (1) of the second paragraph under “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock”;

(3) Liens on property of a Person existing at the time such Person becomes a Restricted Subsidiary of the Company or is merged with or into or consolidated with the Company or any Restricted Subsidiary of the Company; provided that such Liens do not extend to any other property owned by such Person or any of its Restricted Subsidiaries;

(4) Liens on property (including Capital Stock) existing at the time of acquisition of the property by the Company or any Subsidiary of the Company; provided that such Liens do not extend to any property other than that acquired;

(5) pledges or deposits or other Liens to secure the performance of statutory obligations, insurance, surety or appeal bonds, workers’ compensation, unemployment and similar obligations, bid, leases (including, without limitation, statutory and common law landlord’s liens), government contracts, plugging and abandonment obligations and performance bonds or other obligations of a like nature incurred in the ordinary course of business (including Liens to secure letters of credit issued to assure payment of such obligations);

(6) Liens securing Indebtedness represented by Capital Lease Obligations, mortgage financings or purchase money obligations or other Indebtedness, in each case, incurred for the purpose of financing all or

any part of the purchase price or other acquisition cost or cost of design, construction, installation, development, repair or improvement of property, plant or equipment used in the business of the Company or any of its Restricted Subsidiaries and acquired or designed, constructed, installed, developed, repaired or improved in the ordinary course of business; provided that (a) such Liens are in favor of the seller or other transferor of such asset or property, in favor of the Person or Persons designing, constructing, installing, developing, repairing or improving such asset or property, or in favor of the Person or Persons that provided the funding for the acquisition, design, construction, installation, development, repair or improvement cost, as the case may be, of such asset or property, (b) such Liens are created no later than 360 days after the acquisition, design, construction, installation, development, repair or improvement, (c) the aggregate principal amount of the Indebtedness secured by such Liens is otherwise permitted to be incurred under the indenture and does not exceed the greater of (i) the cost of the asset or property so acquired, designed, constructed, installed, developed, repaired or improved plus related financing costs and (ii) the fair market value of the asset or property so acquired, designed, constructed, installed, developed, repaired or improved, measured at the date of such acquisition, or the date of completion of such design, construction, installation, development, repair or improvement plus related financing costs, and (d) such Liens are limited to the asset or property so acquired, designed, constructed, installed, developed, repaired or improved (together with improvements, additions, accessions and contractual rights relating primarily thereto and all proceeds thereof (including dividends, distributions and increases in respect thereof));

(7) Liens existing on the date of the indenture (other than Liens securing Indebtedness under the Credit Agreement);

(8) Liens created for the benefit of (or to secure) the notes (or the Note Guarantees) or to secure other obligations under the indenture;

(9) Liens on and pledges of the Equity Interests of any Unrestricted Subsidiary or any Joint Venture owned by the Company or any Restricted Subsidiary of the Company to the extent securing Non-Recourse Debt or other Indebtedness of such Unrestricted Subsidiary or Joint Venture;

(11) Liens reserved in oil and natural gas mineral leases for bonus or rental payments and for compliance with the terms of such leases;

(12) Liens to secure any Indebtedness incurred to refinance or replace Indebtedness secured by any Lien described under clauses (3), (4), (6), (7), (8) and (22) of this definition permitted to be incurred under the indenture; provided, however, that:

(a) the new Lien is limited to all or part of the same property and assets that secured or, except in the case of Indebtedness secured by any Lien described under clauses (3), (4) or (6) of this definition, under the written agreements pursuant to which the original Lien arose, could secure the original Lien (plus improvements and accessions to, such property or proceeds or distributions thereof); and

(b) the Indebtedness secured by the new Lien is not increased to any amount greater than the sum of (x) the outstanding principal amount, or, if greater, committed amount, of the Indebtedness exchanged, renewed, refunded, refinanced, replaced, defeased or discharged with such Permitted Refinancing Indebtedness and (y) an amount necessary to pay any fees and expenses, including premiums, related to such exchange, renewal, refunding, refinancing, replacement, defeasance or discharge;

(13) Liens on insurance policies and proceeds thereof, or other deposits, to secure insurance premium financings;

(14) filing of Uniform Commercial Code financing statements as a precautionary measure in connection with operating leases;

(15) bankers’ Liens, rights of setoff, rights of revocation, refund or chargeback with respect to money or instruments of the Company or any Restricted Subsidiary, Liens arising out of judgments or awards not

constituting an Event of Default and notices of lis pendens and associated rights related to litigation being contested in good faith by appropriate proceedings and for which adequate reserves have been made;

(16) Liens on cash, Cash Equivalents or other property arising in connection with the defeasance, discharge or redemption of Indebtedness;

(17) Liens on specific items of inventory or other goods (and the proceeds thereof) of any Person securing such Person’s obligations in respect of bankers’ acceptances issued or created in the ordinary course of business for the account of such Person to facilitate the purchase, shipment or storage of such inventory or other goods;

(18) Liens in respect of Production Payments and Reserve Sales; provided that such Liens are limited to the property that is subject to such Production Payments and Reserve Sales;

(19) Liens arising under oil and natural gas leases or subleases, overriding royalty interests, assignments, farm-out agreements, farm-in agreements, division orders, contracts for the sale, purchase, exchange, transportation, gathering or processing of Hydrocarbons, unitizations and pooling designations, declarations, orders and agreements, development agreements, joint venture agreements, partnership agreements, operating agreements, royalties, working interests, net profits interests, joint interest billing arrangements, participation agreements, production sales contracts, production payment agreements, royalty trust agreements, incentive compensation programs for geologists, geophysicists and other providers of technical services to the Company or a Restricted Subsidiary, area of mutual interest agreements, gas balancing or deferred production agreements, injection, repressuring and recycling agreements, salt water or other disposal agreements, seismic or geophysical permits or agreements, licenses, sublicenses and other agreements which are customary in the Oil and Gas Business; provided, however, in all instances that such Liens are limited to the assets that are the subject of the relevant agreement, program, order or contract;

(20) Liens to secure performance of Hedging Obligations of the Company or any of its Restricted Subsidiaries entered into in the ordinary course of business and not for speculative purposes;

(21) Liens arising under the indenture in favor of the trustee for its own benefit and similar Liens in favor of other trustees, agents and representatives arising under instruments governing Indebtedness permitted to be incurred under the indenture; provided, however, that such Liens are solely for the benefit of the trustees, agents or representatives in their capacities as such and not for the benefit of the holders of such Indebtedness;

(22) any Lien incurred by the Company or any Restricted Subsidiary of the Company with respect to Indebtedness in aggregate principal amount that, when taken together with the aggregate principal amount of all other Indebtedness secured by Liens incurred pursuant to this clause (22) then outstanding, together with all other then outstanding Indebtedness secured by Liens incurred pursuant to clause (12) of this definition that had previously refinanced or replaced Indebtedness secured by Liens incurred under this clause (22), does not exceed the greater of (a) $50.0 million and (b) 5.0% of Adjusted Consolidated Net Tangible Assets determined at the time such Lien is incurred;

(23) leases and subleases of real property which do not materially interfere with the ordinary conduct of the business of the Company or the Restricted Subsidiaries;

(a) taxes, assessments or governmental charges or claims that are not yet delinquent or which are being contested in good faith by appropriate proceedings promptly instituted and diligently conducted; provided that any reserve or other appropriate provision as will be required in conformity with GAAP will have been made therefor,

(b) good faith deposits in connection with tenders, leases and contracts (other than contracts for the payment of Indebtedness),

(c) survey exceptions, zoning restrictions, easements, licenses, reservations, title defects, rights of others for rights of way, utilities, sewers, electric lines, telephone or telegraph lines, and other similar

purposes, provisions, covenants, conditions, waivers, restrictions on the use of property or minor irregularities of title (and with respect to leasehold interests, mortgages, obligations, Liens and other encumbrances incurred, created, assumed or permitted to exist and arising by, through or under a landlord or owner of the leased property, with or without consent of the lessee), none of which materially impairs the use of any parcel of property material to the operation of the business of the Company or the Restricted Subsidiaries or the value of such property for the purpose of such business,

(d) operation of law or contract in favor of mechanics, carriers, warehousemen, landlords, materialmen, laborers, employees, suppliers and similar persons, incurred in the ordinary course of business, to the extent such Liens relate only to the tangible property of the lessee which is located on such property, for sums which are not yet delinquent or are being contested in good faith by negotiations or by appropriate proceedings which suspend the collection thereof; if such reserve or other appropriate provision, if any, as shall be required by GAAP shall have been made in respect thereof, or

(25) Liens on any specific property or any interest therein, construction thereon or improvement thereto to secure all or any part of the costs incurred for surveying, exploration, drilling, extraction, development, operation, production, construction, alteration, repair or improvement of, in, from, under or on such property and the plugging and abandonment of wells located thereon (it being understood that, in the case of oil and gas producing properties, or any interest therein, costs incurred for development and production shall include costs incurred for all facilities relating to such properties or to projects, ventures or other arrangements of which such properties form a part or which relate to such properties or interests and costs incurred for processing, gathering, marketing, refining and storage of such production), in each case that do not secure Indebtedness for borrowed money.

In each case set forth above, notwithstanding any stated limitation on the assets that may be subject to such Lien, a Permitted Lien on a specified asset or group or type of assets shall also include any Lien on all improvements, additions, accessions and contractual rights relating primarily thereto and all proceeds thereof (including dividends, distributions and increases in respect thereof).

“Permitted Midstream Business Investments” means Investments by the Company or any of its Restricted Subsidiaries in any Person (including in any Unrestricted Subsidiary or Joint Venture) consisting of a capital contribution, or arising from the receipt of non-cash consideration from a transfer, to such Person of Midstream Assets; provided that:

(1) at the time of any such Investment and immediately thereafter, the Company would be permitted to incur at least $1.00 of additional Indebtedness pursuant to the Fixed Charge Coverage Ratio set forth in the first paragraph of the covenant described above under the caption “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock”;

(2) if such Person has outstanding Indebtedness at the time of any such Investment, either (a) all such Indebtedness is Non-Recourse Debt or (b) any such Indebtedness of such Person that is not Non-Recourse Debt could, at the time such Investment is made, be incurred at that time by the Company and its Restricted Subsidiaries pursuant to the Fixed Charge Coverage Ratio test set forth in the first paragraph of the covenant described above under the caption “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock”; and

(3) such Person is not engaged, in any material respect, in any business other than a Midstream Business.

“Permitted Refinancing Indebtedness” means any Indebtedness or Disqualified Stock or Preferred Stock of the Company or any of its Restricted Subsidiaries issued in exchange for, or the net proceeds of which are used to renew, refund, refinance, replace, defease or discharge other Indebtedness or Disqualified Stock or Preferred

Stock of the Company or any of its Restricted Subsidiaries (other than intercompany Indebtedness); provided that:

(1) the principal amount (or accreted value, if applicable) of such Permitted Refinancing Indebtedness does not exceed the principal amount of the Indebtedness or Disqualified Stock or Preferred Stock exchanged, renewed, refunded, refinanced, replaced, defeased or discharged (plus all accrued interest on the Indebtedness and all accrued dividends on the Disqualified Stock or Preferred Stock and the amount of all fees and expenses, including premiums, incurred in connection therewith);

(2) such Permitted Refinancing Indebtedness has a final maturity date that is either (a) no earlier than the final maturity date of, and has a Weighted Average Life to Maturity equal to or greater than the Weighted Average Life to Maturity of, the Indebtedness or Disqualified Stock or Preferred Stock being exchanged, renewed, refunded, refinanced, replaced, defeased or discharged or (b) more than 90 days after the final maturity date of the notes;

(3) if the Indebtedness being exchanged, renewed, refunded, refinanced, replaced, defeased or discharged is subordinated in right of payment to the notes or the Note Guarantees, such Permitted Refinancing Indebtedness is subordinated in right of payment to the notes or the Note Guarantees, as applicable, on terms at least as favorable to the holders of notes as those contained in the documentation governing (or shall be Capital Stock of the obligor on) the Indebtedness being exchanged, renewed, refunded, refinanced, replaced, defeased or discharged, as determined in good faith by the Company;

(4) such Indebtedness is not incurred by a Restricted Subsidiary of the Company (other than a Guarantor) if the Company or a Guarantor is the issuer or other obligor on the Indebtedness being exchanged, renewed, refunded, refinanced, replaced, defeased or discharged;

(5) if any Preferred Stock being exchanged, renewed, refunded, refinanced, replaced, defeased or discharged was Disqualified Stock of the Company, the Permitted Refinancing Indebtedness shall be Disqualified Stock of the Company; and

(6) if any Preferred Stock being exchanged, renewed, refunded, refinanced, replaced, defeased or discharged was Preferred Stock of a Restricted Subsidiary, the Permitted Refinancing Indebtedness shall be Preferred Stock of such Restricted Subsidiary.

“Person” means any individual, corporation, partnership, joint venture, association, joint-stock company, trust, unincorporated organization, limited liability company or government or other entity.

“Preferred Stock” means, with respect to any Person, any and all preferred or preference stock or other similar Equity Interests (however designated) of such Person whether outstanding or issued after the date of the indenture.

“Production Payments” means Dollar-Denominated Production Payments and Volumetric Production Payments, collectively.

“Production Payments and Reserve Sales” means the grant or transfer by the Company or any of its Restricted Subsidiaries to any Person of a royalty, overriding royalty, net profits interest, Production Payment, partnership or other interest in Oil and Gas Properties, reserves or the right to receive all or a portion of the production or the proceeds from the sale of production attributable to such properties where the holder of such interest has recourse solely to such production or proceeds of production, subject to the obligation of the grantor or transferor to operate and maintain, or cause the subject interests to be operated and maintained, in a reasonably prudent manner or other customary standard or subject to the obligation of the grantor or transferor to indemnify for environmental, title or other matters customary in the Oil and Gas Business, including any such grants or transfers pursuant to incentive compensation programs on terms that are reasonably customary in the Oil and Gas Business for geologists, geophysicists or other providers of technical services to the Company or any of its Restricted Subsidiaries.

(1) with respect to S&P, any of the following categories: AAA, AA, A, BBB, BB, B, CCC, CC, C and D (or equivalent successor categories); and

(2) with respect to Moody’s, any of the following categories: Aaa, Aa, A, Baa, Ba, B, Caa, Ca, C and D (or equivalent successor categories).

“Rating Decline” means a decrease in the rating of the notes by either Moody’s or S&P by one or more gradations (including gradations within Rating Categories as well as between Rating Categories). In determining whether the rating of the notes has decreased by one or more gradations, gradations within Rating Categories, namely + or - for S&P, and 1, 2, and 3 for Moody’s, will be taken into account; for example, in the case of S&P, a rating decline either from BB+ to BB or BB- to B+ will constitute a decrease of one gradation.

“Reporting Default” means a Default described in clause (5) under “—Events of Default and Remedies.”

“Restricted Investment” means an Investment other than a Permitted Investment.

“Restricted Subsidiary” of a Person means any Subsidiary of the referent Person that is not an Unrestricted Subsidiary. Except where expressly stated otherwise, all references to Restricted Subsidiaries refer to Restricted Subsidiaries of the Company.

“S&P” means Standard & Poor’s Ratings Services and any successor to the ratings business thereof.

(1) all Indebtedness of the Company or any of its Restricted Subsidiaries outstanding under Credit Facilities and all obligations under Hedging Obligations with respect thereto;

(2) any other Indebtedness of the Company or any of its Restricted Subsidiaries permitted to be incurred under the terms of the indenture, unless the instrument under which such Indebtedness is incurred expressly provides that it is subordinated in right of payment to the notes or any Note Guarantee; and

(3) all Obligations with respect to the items listed in the preceding clauses (1) and (2).

Notwithstanding anything to the contrary in the preceding sentence, Senior Debt will not include:

(1) any intercompany Indebtedness of the Company or any of its Restricted Subsidiaries to the Company or any Affiliate;

“Significant Subsidiary” means any Restricted Subsidiary that would be a “significant subsidiary” as defined in Article 1, Rule 1-02 of Regulation S-X, promulgated pursuant to the Securities Act, as such Regulation is in effect on the date of the indenture.

“Stated Maturity” means, with respect to any installment of interest or principal on any series of Indebtedness, the date on which the payment of interest or principal was scheduled to be paid in the original documentation governing such Indebtedness, and will not include any contingent obligations to repay, redeem or repurchase any such interest or principal prior to the date originally scheduled for the payment thereof.

(1) any corporation, association or other business entity (other than a partnership or limited liability company) of which more than 50% of the total voting power of its Voting Stock is at the time owned or controlled, directly or indirectly, by that Person or one or more of the other Subsidiaries of that Person (or a combination thereof); and

(2) any partnership or limited liability company of which (a) more than 50% of the capital accounts, distribution rights, total equity and voting interests or general or limited partnership interests, as applicable, are owned or controlled, directly or indirectly, by such Person or one or more of the other Subsidiaries of that Person or a combination thereof, whether in the form of membership, general, special or limited partnership interests or otherwise, or (b) such Person or any Subsidiary of such Person is the sole or controlling general partner or manager or managing member of, or otherwise controls, such entity.

“Trade Payables” means, as to any Person, (a) accounts payable or other obligations of such Person created or assumed by such Person in the ordinary course of business in connection with the obtaining of goods or services and (b) obligations arising under contracts for the exploration, development, drilling, completion and plugging and abandonment of wells or for the construction, repair or maintenance of related infrastructure or facilities.

“Treasury Rate” means, as of any redemption date, the yield to maturity as of such redemption date of the most recently issued United States Treasury securities with a constant maturity (as compiled and published in the most recent Federal Reserve Statistical Release H.15 (519) that has become publicly available at least two Business Days prior to the redemption date (or, if such Statistical Release is no longer published, any publicly available source of similar market data)) most nearly equal to the period from the redemption date to February 1, 2020; provided, however, that if the period from the redemption date to February 1, 2020, is less than one year, the weekly average yield on actually traded United States Treasury securities adjusted to a constant maturity of one year will be used. The Company will (a) calculate the Treasury Rate on the second Business Day preceding the applicable redemption date and (b) prior to such redemption date file with the trustee an officers’ certificate setting forth the Applicable Premium and the Treasury Rate and showing the calculation of each in reasonable detail.

“Unrestricted Subsidiary” means any Subsidiary of the Company (including any newly acquired or newly formed Subsidiary or a Person becoming a Subsidiary through merger or consolidation or Investment therein) that is designated (or deemed designated) by the Company’s Board of Directors as an Unrestricted Subsidiary pursuant to a resolution of the Board of Directors, but only to the extent that such Subsidiary:

(1) has no Indebtedness other than Non-Recourse Debt owing to any Person other than the Company or any of its Restricted Subsidiaries (other than any Guarantee of the notes or the Note Guarantees or any Indebtedness that would be released upon such designation);

(2) except as permitted by the covenant described above under the caption “—Certain Covenants—Transactions with Affiliates,” is not party to any agreement, contract, arrangement or understanding with the Company or any Restricted Subsidiary of the Company unless the terms of any such agreement, contract, arrangement or understanding, together with the terms of all other agreements, contracts, arrangements and understandings with such Unrestricted Subsidiary, taken as a whole, are no less favorable to the Company or such Restricted Subsidiary than those that might be obtained at the time from Persons who are not Affiliates of the Company, as determined in good faith by the Company;

(3) is a Person with respect to which neither the Company nor any of its Restricted Subsidiaries has any direct or indirect obligation (a) to subscribe for additional Equity Interests or (b) to maintain or preserve such Person’s financial condition; and

(4) has not Guaranteed or otherwise become an obligor on any Indebtedness of the Company or any of its Restricted Subsidiaries, except to the extent such Guarantee or obligation would be released upon such

designation and except for (x) any Non-Recourse Debt with respect to which the Company or any Restricted Subsidiary has pledged (or provided a Guaranty limited in recourse solely to) Equity Interests in such Subsidiary or (y) any Guarantee of the notes and the Note Guarantees,

except, in the case of (1), (2), (3) or (4), for any such Indebtedness that is subject to a Guarantee by or other obligation of, or any agreement, contract, arrangement or understanding with, or any equity subscription or credit support obligation of, the Company or Restricted Subsidiary that constitutes an Investment in such Subsidiary that has been effected as a Restricted Payment or Permitted Investment that complies with the covenant described above under the caption “—Certain Covenants—Restricted Payments.”

All Subsidiaries of an Unrestricted Subsidiary shall also be Unrestricted Subsidiaries.

“Volumetric Production Payments” means production payment obligations recorded as deferred revenue in accordance with GAAP, together with all undertakings and obligations in connection therewith.

“Voting Stock” of any specified Person as of any date means the Capital Stock of such Person entitling the holders thereof (whether at all times or only so long as no senior class of Capital Stock has voting power by reason of any contingency) to vote in the election of members of the Board of Directors of such Person; provided that with respect to a limited partnership or other entity which does not have a Board of Directors, Voting Stock means the Capital Stock of the general partner of such limited partnership or other business entity with the ultimate authority to manage the business and operations of such Person.

“Weighted Average Life to Maturity” means, when applied to any Indebtedness (or Disqualified Stock or Preferred Stock) at any date, the number of years obtained by dividing:

(1) the sum of the products obtained by multiplying (a) the amount of each then remaining installment, sinking fund, serial maturity or other required payments of principal or (with respect to Preferred Stock) redemption or similar payment, including payment at final maturity, in respect of the Indebtedness (or Disqualified Stock or Preferred Stock), by (b) the number of years (calculated to the nearest one-twelfth) that will elapse between such date and the making of such payment; by

(2) the then outstanding principal amount of such Indebtedness (or Disqualified Stock or Preferred Stock).

“Wholly Owned Restricted Subsidiary” means a Restricted Subsidiary all the Capital Stock of which (other than directors’ qualifying shares) is owned by the Company or another Wholly Owned Restricted Subsidiary.

You may transfer new notes issued under the exchange offer in exchange for the old notes if:

Each broker-dealer that receives new notes for its own account pursuant to the exchange offer in exchange for old notes that were acquired by such broker-dealer as a result of market-making or other trading activities must acknowledge that it will deliver a prospectus in connection with any resale of such new notes. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of new notes received in exchange for old notes where such old notes were acquired as a result of market-making activities or other trading activities. We and the subsidiary guarantors have agreed that, starting on the expiration date of the exchange offer and ending on the close of business 180 days after the date of such expiration date, we will make this prospectus, as amended or supplemented, available to any broker-dealer for use in connection with any such resale.

If you wish to exchange new notes for your old notes in the exchange offer, you will be required to make representations to us as described in “Exchange Offer—Purpose and Effect of the Exchange Offer” and “—Procedures for Tendering—Your Representations to Us” in this prospectus and in the letter of transmittal. In addition, if you are a broker-dealer who receives new notes for your own account in exchange for old notes that were acquired by you as a result of market-making activities or other trading activities, you will be required to acknowledge that you will deliver a prospectus in connection with any resale by you of such new notes.

We will not receive any proceeds from any sale of new notes by broker-dealers. New notes received by broker-dealers for their own account pursuant to the exchange offer may be sold from time to time on one or more transactions in any of the following ways:

Any such resale may be made directly to purchasers or to or through brokers or dealers who may receive compensation in the form of commissions or concessions from any such broker-dealer or the purchasers of any such new notes.

Any broker-dealer that resells new notes that were received by it for its own account pursuant to the exchange offer in exchange for old notes that were acquired by such broker-dealer as a result of market-making or other trading activities may be deemed to be an “underwriter” within the meaning of the Securities Act. The letter of transmittal states that by acknowledging that it will deliver and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act. We agreed to permit the use of this prospectus for a period of up to 180 days after the completion of the exchange offer by such broker-dealers to satisfy this prospectus delivery requirement. Furthermore, we agree to amend or supplement this prospectus during such period if so requested in order to expedite or facilitate the disposition of any new notes by broker-dealers.

We have agreed to pay all expenses incident to the exchange offer other than fees and expenses of counsel to the holders and brokerage commissions and transfer taxes, if any, and will indemnify the holders of the old notes (including any broker-dealers) against certain liabilities, including liabilities under the Securities Act.

The following discussion is a summary of the material U.S. federal income tax considerations relevant to the exchange of old notes for new notes, but does not purport to be a complete analysis of all potential tax effects. The discussion is based upon the Internal Revenue Code of 1986, as amended, or the Code, Treasury Regulations, Internal Revenue Service rulings and pronouncements and judicial decisions now in effect, all of which may be subject to change at any time by legislative, judicial or administrative action. These changes may be applied retroactively in a manner that could adversely affect a holder of new notes. We cannot assure you that the Internal Revenue Service will not challenge one or more of the tax consequences described in this discussion, and we have not obtained, nor do we intend to obtain, a ruling from the Internal Revenue Service or an opinion of counsel with respect to the U.S. federal income tax consequences described herein. Some holders, including financial institutions, insurance companies, regulated investment companies, tax-exempt organizations, dealers in securities or currencies, persons whose functional currency is not the U.S. dollar or persons who hold the notes as part of a hedge, conversion transaction, straddle or other risk reduction transaction may be subject to special rules not discussed below.

We recommend that each holder consult its own tax advisor as to the particular tax consequences of exchanging such holder’s old notes for new notes, including the applicability and effect of any foreign, state, local or other tax laws or U.S. federal estate or gift tax considerations.

We believe that the exchange of old notes for new notes will not be an exchange or otherwise a taxable event to a holder for U.S. federal income tax purposes. Accordingly, a holder will not recognize gain or loss upon receipt of a new note in exchange for an old note in the exchange, and the holder’s basis and holding period in the new note will be the same as its basis and holding period in the corresponding old note immediately before the exchange.

The validity of the new notes offered in this exchange offer will be passed upon for us by Vinson & Elkins L.L.P., Houston, Texas.

The consolidated financial statements of WildHorse Resource Development Corporation as of December 31, 2016 and 2015, and for the years in the three-year period ended December 31, 2016, included in this prospectus, have been audited by KPMG LLP, an independent registered public accounting firm, as set forth in their report appearing elsewhere herein, and are included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

The consolidated financial statements of Esquisto Resources II, LLC and Subsidiary at December 31, 2015, and for the period from February 17, 2015 to December 31, 2015 (not presented separately herein), have been audited by Ernst & Young LLP, independent registered public accounting firm, as set forth in their report thereon appearing elsewhere herein, and in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

The statements of revenues and direct operating expenses of Anadarko Petroleum Corporation’s Eaglebine and Northstars Properties acquired by WHR Eagle Ford LLC, a subsidiary of WildHorse Resource Development Corporation, for the years ended December 31, 2016, 2015, and 2014, included in this prospectus, have been audited by KPMG LLP, independent auditors, as stated in their report appearing herein. The audit report contains an emphasis of matter paragraph relating to financial presentation and required supplemental information.

The statements of revenues and direct operating expenses of the oil and natural gas properties of Admiral A. Holding, L.P., TE Admiral A. Holding L.P., and Aurora C-I Holding L.P., under common control of KKR EIGF LLC, for the period from September 11, 2014 through December 31, 2014, and for the years ended December 31, 2015 and 2016, included in this Prospectus, have been audited by Deloitte & Touche LLP, independent auditors, as stated in their report (which report expresses an unmodified opinion and includes an emphasis-of-matter paragraph relating to financial presentation and an other matter paragraph relating to required supplemental information) appearing herein, and are included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

The statements of revenues and direct operating expenses, which comprise the revenues and direct operating expenses of certain oil and gas properties of Clayton Williams Energy, Inc. contracted to be acquired by Acquisition Co. for the nine months ended September 30, 2016 and the years ended December 31, 2015 and 2014, included in this prospectus, have been audited by KPMG LLP, independent auditors, as stated in their report appearing herein. The audit report contains an other matter paragraph relating to Supplementary Oil and Gas Disclosures presented as required supplemental information to the financial statements.

Estimates of WildHorse’s oil and natural gas reserves and related future net cash flows related to WildHorse’s properties as of December 31, 2016, included herein were based upon the proved reserves estimates prepared by WildHorse and audited by independent petroleum engineers, Cawley, Gillespie & Associates.

We have audited the accompanying consolidated balance sheet of WildHorse Resource Development Corporation and subsidiaries as of December 31, 2016, the consolidated and combined balance sheet of WildHorse Resource Development Corporation as of December 31, 2015, and 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, 2016. 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 did not audit the financial statements of Esquisto Resources II, LLC, a wholly owned subsidiary, for the period from February 17, 2015 to December 31, 2015. Esquisto Resources II, LLC’s financial statements reflect total assets constituting 56 percent and total revenues constituting 53 percent in 2015, of the related combined totals. Those statements were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for Esquisto Resources II, LLC for the period from February 17, 2015 to December 31, 2015, is based solely on the report of the other auditors.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits and the report of the other auditors provide a reasonable basis for our opinion.

In our opinion, based on our audits and the report of the other auditors, the consolidated and combined financial statements referred to above present fairly, in all material respects, the financial position of WildHorse Resource Development Corporation and subsidiaries as of December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2016, in conformity with U.S. generally accepted accounting principles.

As discussed in Note 1 to the consolidated and combined financial statements, the balance sheet as of December 31, 2015, and the related 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, have been prepared on a combined basis of accounting.

We have audited the accompanying consolidated balance sheet of Esquisto Resources II, LLC and Subsidiaries (the Company) as of December 31, 2015, and the related consolidated statement of operations, changes in members’ equity, and cash flows for the period from February 17, 2015 to December 31, 2015 (not presented separately herein). These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, 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. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Esquisto Resources II, LLC and Subsidiaries at December 31, 2015, and the consolidated results of their operations and their cash flows for the period from February 17, 2015 to December 31, 2015, in conformity with U.S. generally accepted accounting principles.

WildHorse Resource Development Corporation (the “Company”) is a publicly traded Delaware corporation, the common shares of which are listed on the New York Stock Exchange (“NYSE”) under the symbol “WRD.” Unless the context requires otherwise, references to “we,” “us,” “our,” “WRD,” or “the Company” are intended to mean the business and operations of WildHorse Resource Development Corporation and its consolidated subsidiaries.

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 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). Reference “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, exploitation, development and production of oil, natural gas and NGL resources.

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. WHR II has two wholly owned subsidiaries—WildHorse Resources Management

Company, LLC (“WHRM”) and Oakfield Energy LLC (“Oakfield”). Esquisto has two wholly owned subsidiaries—Petromax E&P Burleson, LLC and Burleson Water Resources, LLC. WHRM is the named operator for all oil and gas properties owned by us.

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, and (b) as of December 31, 2015, and for the period from February 17, 2015 (the inception of common control) to December 31, 2015, have been derived from the combined financial position and results attributable to our predecessor and Esquisto for periods prior to our initial public offering and (ii) (a) for the period from January 1, 2015 to February 16, 2015 and (b) for the year ended December 31, 2014, have been derived from the results attributable to our predecessor. 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.

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

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 (“GAAP”).

Preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about carrying values of assets and liabilities that are not readily apparent from other sources. We evaluate the estimates and assumptions on a regular basis; however, actual results may differ from these estimates and assumptions used in the preparation of the financial statements. Significant estimates with regard to these financial statements include (1) the estimate of proved oil and gas reserves and related present value estimates of future net cash flows therefrom; (2) depreciation, depletion and amortization expense; (3) valuation of accounts receivable; (4) accrued capital expenditures and liabilities; (5) asset retirement obligations; (6) environmental remediation costs; (7) valuation of derivative instruments; (8) contingent liabilities and (9) 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.

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 consists of certificates of deposit in place to collateralize letters of credit. The letters of credit are required as part of normal business operations. The certificates of deposit will be in place for a period greater than 12 months and are considered noncurrent.

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

Proved oil and gas properties are reviewed for impairment when events and circumstances indicate a potential decline in the fair value of such properties below the carrying value, such as a downward revision of the reserve estimates or lower commodity prices. We estimate the undiscounted future cash flows expected in connection with the properties and compare such future cash flows to the carrying amounts of the properties to determine if the carrying amounts are recoverable. If the carrying value of the properties is determined to not be recoverable based on the undiscounted cash flows, an impairment charge is recognized by comparing the carrying value to the estimated fair value of the properties. The factors used to determine fair value include, but are not limited to, estimates of proved and probable reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. We recorded impairment expense of $9.3 million and $24.7 million to proved oil and gas properties for the year ended December 31, 2015 and 2014, respectively. The impairment resulted from lower projected oil and gas prices and a drop in projected remaining reserves in East Texas and our non-core fields.

The estimates of proved natural gas, crude oil and natural gas liquids reserves utilized in the preparation of the financial statements are estimated in accordance with guidelines established by the Securities and Exchange Commission (“SEC”) and the Financial Accounting Standards Board (“FASB”), which require that reserve estimates be prepared under existing economic and operating conditions using a 12-month average price with no provision for price and cost escalations in future years except by contractual arrangements. Proved reserves are, with respect to WHR II, prepared by WHR II and audited by Cawley, Gillespie & Associates, Inc. (“Cawley”), its independent reserve engineer. With respect to Esquisto, the proved reserves were prepared by Cawley, its independent reserve engineer, for 2015. Esquisto’s proved reserves for 2016 were internally prepared and audited by Cawley.

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 19—“Supplemental Oil and Gas Information (Unaudited)” for further information.

In 2015, our Oakfield subsidiary constructed and began operating a 15.2 mile 16” natural gas gathering system in order to provide sufficient, cost effective access to major markets for our existing and expected future production from new horizontal wells in North Louisiana. The wells are charged a fee for gathering services based on their throughput volumes and gas quality. In 2016, only wells operated by us were connected to the system. We are depreciating the Oakfield gathering assets on a straight-line basis over the current expected reserve life of wells connected to the system.

Other property and equipment includes our natural gas gathering system, leasehold improvements, office furniture, automobiles, computer equipment, software, pipelines, office buildings and land. Other property and equipment is depreciated using a straight-line method over the expected useful lives of the respective assets. Leasehold improvements are amortized over the remaining term of the lease and land is not depreciated or amortized.

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, 2016, 2015 and 2014, we recorded $0.1 million, $0.8 million $0.2 million in capitalized interest, respectively.

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.”

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.

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.

We recognize revenues from the sale of oil, natural gas and NGLs using the sales method of accounting, whereby revenue is recorded based on our share of volume sold, regardless of whether we have taken our proportional share of volume produced. These differences result in gas imbalances. We record a liability to the extent there are not sufficient reserves to cover an over delivered gas imbalance. No receivables are recorded for those wells on which the Company has taken less than its proportionate share of production. We receive payment approximately one month after delivery for operated wells and up to three months after delivery for non-operated wells. At the end of each month, we estimate the amount of production delivered to purchasers and the price we will receive. Variances between our estimates and the actual amounts received are recorded in the month payment is received. No receivables are recorded for those wells on which we have taken less than our proportionate share of production.

For details regarding incentive units issued by our predecessor, please see “Note 13. Incentive Units.”

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 two months of accrued revenues for operated properties and three months of accrued revenues for non-operated properties net of any collections related to those periods. The accounts receivable balance also includes other miscellaneous balances.

Accounts receivable are recorded at the amount we expect to collect. We use the specific identification method of providing allowances for doubtful accounts. We recorded a provision for uncollectible accounts of $0.1 million at both December 31, 2016 and 2015.

We periodically enter into derivative contracts to manage our exposure to commodity price risk. These derivative contracts, which are placed with major financial institutions that we believe have minimal credit risks, take the form of variable to fixed price swaps collars and 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.

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

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.

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.”

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.

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.

Definition of a Business. In January 2017, the FASB issued an accounting standards update to clarify the definition of a business. The definition of a business affects many areas of accounting including acquisitions, disposals, goodwill, and consolidation. The amendments are intended to help companies and other organizations evaluate whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The amendments provide a more robust framework to use in determining when a set of assets and activities is a business. The amendments are effective for annual periods beginning after December 15, 2017, including interim periods within those periods. Early adoption is permitted and the guidance is to be applied on a prospective basis to purchases or disposals of a business or an asset. The Company is currently evaluating the impact of this standard on its 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. Early adoption is permitted, including adoption in an interim period. The new guidance requires transition under a retrospective approach for each period presented. The Company is currently assessing the impact the adoption of this new guidance will have on our consolidated financial statements and related disclosures.

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. Early adoption is permitted, including adoption in an interim period. 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 is currently assessing the impact the adoption of this new guidance will have on our consolidated financial statements and related disclosures.

Improvements to Employee Share-Based Payment Accounting. In March 2016, the FASB issued an accounting standards update to simplify the guidance on employee share-based payment accounting. The update involves several aspects of accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification in the statement of cash flows. Entities will no longer record excess tax benefits and certain tax deficiencies in equity. Instead, they will

record all excess tax benefits and tax deficiencies as income tax expense or benefit in the income statement. In addition, the new guidance eliminates the requirement that excess tax benefits be realized before entities can recognize them and requires entities to present excess tax benefits as an operating activity on the statement of cash flows rather than as a financing activity. Furthermore, the new guidance will increase the amount an employer can withhold to cover income taxes on awards and still qualify for the exception to liability classification for shares used to satisfy the employer’s statutory income tax withholding obligation. The new guidance requires an entity to classify the cash paid to a tax authority when shares are withheld to satisfy its statutory income tax withholding obligation as a financing activity on the statement of cash flows. In addition, entities will now have to elect whether to account for forfeitures on share-based payments by: (i) recognizing forfeitures of awards as they occur or (ii) estimating the number of awards expected to be forfeited and adjusting the estimate when it is likely to change, as is currently required. For the amendments that change the recognition and measurement of share-based payment awards, the new guidance requires transition under a modified retrospective approach, with a cumulative-effect adjustment made to retained earnings as of the beginning of the fiscal period in which the guidance is adopted. Prospective application is required for the accounting for excess tax benefits and tax deficiencies. This new standard will be effective for annual periods beginning after December 15, 2016. Early adoption is permitted. The Company adopted this guidance as of January 1, 2017 and it did not have a material impact on our consolidated financial statements. We elected to account for forfeitures on share-based payments by recognizing forfeitures of awards as they occur.

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

Transition will require application of the new guidance at the beginning of the earliest comparative period presented. We are currently evaluating the standard and the impact on our financial statements and related footnote disclosures.

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

Simplifying the Accounting for Measurement-Period Adjustments. In September 2015, the FASB issued an accounting standards update that eliminates the requirement that an acquirer in a business combination account for measurement-period adjustments retrospectively. Instead, an acquirer will recognize a measurement-period adjustment during the period in which it determines the amount of the adjustment. Disclosure of the effect on

earnings of any amounts an acquirer would have recorded in previous periods if the accounting had been completed at the acquisition date is required. The disclosure is required for each affected income statement line item, and may be presented separately on the face of the income statement or in the notes to the financial statements. The new guidance should be applied prospectively to adjustments to provisional amounts that occur after the effective date and is effective for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. The impact of adopting this guidance was not material to our financial statements and related disclosures.

Presentation of Debt Issuance Cost. In April 2015, the FASB issued an accounting standards update that requires debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the carrying value of that debt liability, consistent with debt discounts. The guidance is effective retrospectively for fiscal years, and interim periods within those years, beginning after December 15, 2015. In August 2015, the FASB issued an accounting standards update that incorporates SEC guidance clarifying that the SEC would not object to debt issuance costs related to line-of-credit arrangements being deferred and presented as an asset that is subsequently amortized over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The impact of adopting this guidance was not material to our financial statements and related disclosures.

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

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

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 gas properties adjacent to our existing Eagle Ford acreage at an aggregate purchase price of $389.8 million in cash (the “Burleson North Acquisition”), after preliminary customary post-closing adjustments. We allocated $163.8 million of the purchase price to unproved oil and natural gas properties. 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 preliminary fair value assessment of the assets acquired and liabilities assumed as of the acquisition date (in thousands):

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):

The following unaudited pro forma combined results of operations are provided for the years ended December 31, 2016 and 2015 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.

Comstock Acquisition. In July 2015, Esquisto acquired oil and natural gas producing properties, undeveloped acreage and water assets from a wholly owned subsidiary of Comstock Resources, Inc. for a total purchase price of $103.0 million, net of customary post-closing adjustments.

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

On February 7, 2014, the predecessor acquired certain oil and gas properties in east Texas for cash consideration of $16.0 million, net of customary post-closing adjustments. The purchase price was primarily allocated to oil and gas properties.

On June 3, 2014, the predecessor acquired oil and gas producing properties and leases in north Louisiana for cash consideration of $37.1 million, net of customary post-closing adjustments. Assumed liabilities included suspended amounts payable to royalty and other working interest owners. The purchase price was primarily allocated to oil and gas properties.

On October 13, 2014, the predecessor acquired oil and gas producing properties and leases in north Louisiana for cash consideration of $12.8 million, net of customary post-closing adjustments. Assumed liabilities include suspended amounts payable to royalty and other working interest owners. The purchase price was primarily allocated to oil and gas properties.

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, 2016 and 2015, 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).

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, 2016 and December 31, 2015. 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, 2016 and December 31, 2015 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, 2016 and December 31, 2015 for each of the fair value hierarchy levels:

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:

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.

We have fixed price commodity swaps, collars and deferred purchased puts to accomplish our hedging strategy. Collars consist of a sold call and a purchased put that establishes a ceiling and floor price for expected future oil and natural gas sales. Derivative instruments are netted when the right to net exists under a master netting agreement, future liabilities and assets correspond to the same commodity type and future cash flows have the same balance sheet current or non-current classification. We have exposure to financial institutions in the form of derivative transactions. These transactions are with counterparties in the financial services industry, specifically with members of our bank group. These transactions could expose us to credit risk in the event of default of our counterparties. We have master netting agreements for our derivative transactions with our counterparties and although we do not require collateral, we believe our counterparty risk is low because of the credit worthiness of our counterparties. See Note 4—“Fair Value Measurements of Financial Instruments” for further information.

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, 2016 and 2015. 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.

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, 2016, 2015 and 2014:

The following table presents our allowance for doubtful accounts activity for the periods indicated:

The following table presents the changes in the asset retirement obligations for the years ended December 31, 2016, 2015 and 2014:

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.

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 will also automatically decrease upon the issuance of certain debt, including 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.

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

Additionally, borrowings under our revolving credit facility will bear interest, at our option, at either (i) the greatest of (x) the prime rate as determined by the administrative agent, (y) the federal funds effective rate plus 0.50%, and (z) the adjusted LIBOR for a one month interest period plus 1.0%, in each case, plus a margin that varies from 1.25% to 2.25% 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 2.25% to 3.25% per annum according to the total commitment usage or (iii) the applicable LIBOR market index rate plus a margin that varies from 2.25% to 3.25% per annum according to the total commitment usage. The unused portion of the total commitments are subject to a commitment fee that varies from 0.375% to 0.50% per annum according to our total commitments usage.

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

Events of default under our revolving credit facility 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 our revolving credit facility, together with accrued interest, fees and other obligations under the credit agreement, could be declared immediately due and payable.

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

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

Esquisto retired and terminated one of their revolving credit facilities and second lien loan in January 2016 in connection with the merger of Esquisto I and Esquisto II.

Subsequent Event. 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 are fully and unconditionally guaranteed on a joint and several basis by all of our existing and certain future subsidiaries. The consummation of our 2025 Senior Notes offering automatically reduced the borrowing base of our revolving credit facility by $87.5 million. See Note 20 for additional information regarding the 2025 Senior Notes.

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

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

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 for the year ended December 31, 2016:

See Note 12 for additional information regarding restricted common shares that were granted in connection with our initial public offering. Restricted shares of common stock are considered issued and outstanding on the grant date of restricted stock award.

Our amended and restated certificate of incorporation will authorize our board of directors, subject to any limitations prescribed by law, without further stockholder approval, to establish and to issue from time to time one or more classes or series of preferred stock, par value $0.01 per share, covering up to an aggregate of 50,000,000 shares of preferred stock. Each class or series of preferred stock will have the powers, preferences, rights, qualifications, limitations and restrictions determined by the board of directors, which may include, among others, dividend rights, liquidation preferences, voting rights, conversion rights, preemptive rights and redemption rights. Except as provided by law or in a preferred stock designation, the holders of preferred stock will not be entitled to vote at or receive notice of any meeting of stockholders. There are no shares issued and outstanding as of December 31, 2016.

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

The predecessor received capital contributions of $10.8 million, $125.9 million and $89.4 million from its members during the year ended December 31, 2016, 2015 and 2014, 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 years ended December 31, 2016, 2015 and 2014:

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.

The previous owner’s received capital contributions of $97.0 million and $208.4 million from its members during the year ended December 31, 2016 and for the period of February 17, 2015 to December 31, 2015, respectively. During the period from February 17, 2015 to December 31, 2015, Esquisto received property contributions of $40.1 million from its members that primarily consisted of developed and undeveloped properties in the East Texas Eagle Ford, Austin Chalk and Pecan Gap formations in Lee County, Washington County and Brazos County, Texas. On February 17, 2015, NGP acquired a controlling interest in Esquisto from an Esquisto member not affiliated with NGP. NGP’s basis exceeded the net book value by $16.1 million associated with this transaction. In May 2015, NGP acquired additional interests in Esquisto from another Esquisto member not affiliated with NGP. NGP’s basis exceeded the net book value by $26.6 million associated with this transaction. 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.

The following sets forth the calculation of earnings (loss) per share, or EPS, for the year ending December 31, 2016 (in thousands, except per share amounts):

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. As of December 31, 2016, we had granted 353,334 restricted shares to certain officers and directors.

The following table summarizes information regarding restricted common share awards granted under the 2016 LTIP for the periods presented:

For the year ended December 31, 2016, we recorded $0.1 million of recognized compensation expense associated with these awards. Unrecognized compensation cost associated with the restricted common share awards was an aggregate of $5.0 million at December 31, 2016. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 2.86 years.

specified members’ capital contributions plus a rate of return. The incentive units were being accounted for as liability-classified awards as achievement of the payout conditions required settlement of such awards by transferring cash to the incentive unit holder. Compensation cost was recognized only if the performance condition was probable of being satisfied at each reporting date. The payment likelihood related to the WHR II incentive units was not deemed probable for the year ended December 31, 2016, 2015 and 2014, respectively. As such, no compensation expense was recognized by our predecessor.

In connection with the Corporate Reorganization, the WHR II incentive units were transferred to WildHorse Investment Holdings in exchange for substantially similar incentive units in WildHorse Investment Holdings, who became responsible for making all payments, distributions and settlements relating to the exchanged incentive units. While any such payments, distributions and settlements will not involve any cash payments by us, we will recognize non-cash compensation expense within general and administrative expenses, which may be material, in the period in which the applicable performance conditions are probable of being satisfied. We will receive a deemed capital contribution with respect to such compensation expense.

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

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.

(“Genesis”) since August 2006 and Chairman of the Board of the general partner since October 2012. Genesis is one of our purchasers of hydrocarbons and other liquids. During the fiscal year ended December 31, 2016, we received $2.8 million from Genesis. In addition, Mr. Richard D. Brannon’s son who had been an employee of a CH4 Energy entity (an NGP affiliated company), joined the Company as a non-officer employee in connection with our initial public offering in December 2016. Mr. Brannon’s son received total compensation from us in 2016 of less than $0.1 million.

Our chief executive officer’s sister-in-law is a non-officer employee of the Company and received total compensation from us of approximately $0.1 million for each of the years ended December 31, 2016, 2015, and 2014, respectively.

Highmark Energy Operating, LLC. During the year ended December 31, 2016, 2015 and 2014, we received net payments of $0.2 million, $0.4 million and $0.1 million, respectively, from Highmark Energy Operating, LLC, a NGP affiliated company, for non-operated working interests in oil and gas properties we operate.

Cretic Energy Services, LLC. During the year ended December 31, 2016, 2015 and 2014, we made payments of $0.4 million, $1.0 million and $6.5 million, respectively, to Cretic Energy Services, LLC, a NGP affiliated company, for services related to our drilling and completion activities.

Multi-Shot, LLC. During the year ended December 31, 2015 and 2014, we made payments of $0.1 million and $0.1 million, respectively, to Multi-Shot, LLC, a NGP affiliated company, for services related to our drilling and completion activities.

PennTex Midstream Partners, LP. During the year ended December 31, 2016, we made net payments of $0.2 million to PennTex Midstream Partners, LP (“PennTex”), a NGP affiliated company, for the gathering, processing and transportation of natural gas and NGLs. During the year ended December 31, 2015 and 2014, we received net payments of $0.1 million and $0.1 million, respectively. Energy Transfer Partners, L.P. acquired ownership in the general partner of PennTex on November 1, 2016. PennTex became a controlled subsidiary of Energy Transfer Partners, L.P. effective November 1, 2016. As such, as of the date of these financial statements, PennTex was no longer a related party.

Promissory Notes. WHR II issued promissory notes in favor of certain members of WHR II’s management to fund future capital commitments These promissory notes have been repaid and terminated. See Note 10 for additional information.

WildHorse Resources, LLC. WHR II and WildHorse Resources, LLC (“WHR”), an entity formerly under common control with WHR II, entered into a management services agreement in August 2013 pursuant to which WHR provided certain administrative and land services to WHR II. As operator, WHR received operated and non-operated revenues on behalf of WHR II and billed and received joint interest billings. In addition, WHR paid for lease operating expenses and drilling costs on behalf of WHR II. On August 8, 2013, an asset and cost sharing agreement between WHR and WHR II was executed. As part of the agreement, shared WHR costs were allocated between WHR and WHR II in accordance with a sharing ratio. The sharing ratio was based on the previous quarter’s capital expenditures and number of operated wells. Company specific costs were billed directly to the appropriate entity. As a result of these agreements, WHR II made net payments of $5.0 million to WHR in 2014.

A management services agreement was executed on August 8, 2013, where WHRM began providing general, administrative and employee services to WHR II as well as WHR. WHRM shared costs were also subject to the same sharing ratio as the asset and cost sharing agreement between WHR and WHR II. As a result of this agreement, we made net payments of $6.0 million to WHRM in 2014.

On June 18, 2014, (i) the management agreement and the asset cost sharing agreement were terminated, (ii) WHR II purchased WHRM from WHR for $0.2 million and (iii) WHR II, through WHRM, began providing accounting and operating transition services to WHR, including administrative and land services, pursuant to the management services agreement. As a result of the management services agreement, WHR II made $57.6 million in net payments to WHR in 2015 but received net payments of $53.0 million from WHR and its affiliates in 2014. WHR II was owed $1.6 million, net, as of December 31, 2015. On February 25, 2015, the management services agreement was terminated effective March 1, 2015.

During the year ended December 31, 2016, we paid net payments of $0.1 million to WHR’s parent company for non-operated working interests in oil and gas properties we operate. WHR ceased being a related party in September 2016 when its parent company was acquired by a third party.

NGP X US Holdings LP. Our predecessor paid NGP X US Holdings LP. (“NGP X”) $0.1 million during each year ended December 31, 2016, 2015, and 2014 for director fees. In addition, we reimbursed NGP X $0.8 million for certain of our initial public offering related expenses during the year ended December 31, 2016.

Notes payable to members. During the period from February 17, 2015 to December 31, 2015, Esquisto accrued $3.6 million, as general and administrative expenses payable to its members. Esquisto owed $6.4 million as of December 31, 2015, to its members for general and administrative expenses incurred on its behalf. During the year ended December 31, 2016, Esquisto accrued $4.0 million, as general and administrative expenses payable to its members.

These notes were payable to members by December 31, 2022 and bore interest after a year at the Applicable Federal Rate compounded annually paid at maturity. In connection with our initial public offering, the Esquisto notes payable to its members were paid off. Certain CH4 Energy entities received $3.6 million. These CH4 Energy entities are NGP affiliated companies and Mr. Brannon is President of these entities. Garland Exploration, LLC and Crossing Rocks Energy, LLC (“Crossing Rocks”) received $5.5 million and $1.3 million, respectively. These entities are also NGP affiliated companies.

Services provided by member. Esquisto paid Calbri Energy, Inc. (“Calbri”), a less than 1% former owner, $0.4 million for the period from February 17, 2015 to December 31, 2015, for completion consulting services. During the year ended December 31, 2016, Esquisto paid Calbri $0.4 million for completion consulting services.

Operator. Esquisto paid Petromax Operating Company, Inc. (“Petromax”), who was the operator of the majority of Esquisto’s wells, $1.3 million during the year ended December 31, 2016 and $0.9 million during the period from February 17, 2015 to December 31, 2015 for overhead charges on drilling and producing wells at market rates as set forth in joint operating agreements and in accordance with an operating agreement between Petromax and Esquisto. Petromax is owned 33.3% by Mike Hoover, the former Chief Operating Officer of Esquisto, who also indirectly owned one of the former members of Esquisto.

Registration Rights Agreement. In connection with the closing of our initial public offering, we entered into a registration rights agreement with WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings. Pursuant to the registration rights agreement, we have agreed to register the sale of shares of our common stock under certain circumstances.

Demand Rights. At any time after the 180 day lock-up period, related to our initial public offering and subject to the limitations set forth below, each of the holders (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 Acquisition Co. Holdings.

We are also not obligated to effect any demand registration in which the anticipated aggregate offering price for our common stock included in such offering is less than $30 million. Once we are eligible to effect a registration on Form S-3, any such demand registration may be for a shelf registration statement. We will be required to use reasonable best efforts to maintain the effectiveness of any such registration statement until the earlier of (i) 180 days (or two years in the case of a shelf registration statement) after the effective date thereof or (ii) the date on which all shares covered by such registration statement have been sold (subject to certain extensions).

In addition, each of the holders (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, NGP XI US Holdings, L.P. (“NGP XI”), Mr. Graham and Mr. Bahr (or its permitted transferees) of such proposal to allow them to include a specified number of their shares of our common stock in that registration statement or underwritten offering, as applicable.

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:

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.

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

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

The following table presents a reconciliation of net income (loss) to Adjusted EBITDAX:

The actual income tax benefit (expense) differs from the expected amount computed by applying the federal statutory corporate tax rate of 35% as follows:

The Company recorded a deferred tax liability of approximately $117.3 million through stockholders’ equity in connection with its initial public offering and the related restructuring transactions. The tax basis of its assets and liabilities was unchanged as a result of its initial public offering and the related restructuring transactions, which is reported as a transaction among stockholders for financial reporting purposes.

Uncertain Income Tax Position. The Company must recognize the tax effects of any uncertain tax positions it may adopt, 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, 2016 and expects no significant change to the unrecognized tax benefits over the next twelve months ending December 31, 2017.

Tax Audits and Settlements. Generally, the Company’s income tax years 2013 through 2016 remain open and subject to examination by Federal tax authorities or the tax authorities in Louisiana and Texas and certain other small state taxing jurisdictions where the Company conducts 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, 2016, the Company had federal net operating loss carryforwards of approximately $6.5 million, which would expire in 2036. The Company also had state tax carryforwards of approximately $2.0 million, which would expire in 2036. A valuation allowance of $0.2 million was established on pre-contribution tax attributes based upon management’s evaluation that the attributes will not be fully realized.

We are party to various ongoing and threatened legal actions relating to our entitled ownership interests in certain properties. We evaluate the merits of existing and potential claims and accrue a liability for any that meet the recognition criteria and can be reasonably estimated. We did not recognize any liability as of December 31, 2016 and 2015. Our estimates are based on information known about the matters and the input of attorneys experienced in contesting, litigating, and settling similar matters. Actual amounts could differ from our estimates and other claims could be asserted.

From time to time, we could be liable for environmental claims arising in the ordinary course of business. At December 31, 2016 and 2015, no environmental obligations were recognized.

WHR II was assigned a firm gas transportation service agreement with Regency Intrastate Gas LLC (the “Transporter”) as a result of our property acquisition on August 8, 2013. Under the terms of the agreement, we are obligated to pay total daily transportation fees not to exceed $0.30 per MMBtu per day for quantities of 40,000 MMBtu per day to the Transporter until March 5, 2019.

Our minimum commitments to the Transporter as of December 31, 2016 is as follows (in thousands):

We currently lease corporate office space through May 31, 2021. Total general and administrative rent expense for the year ended December 31, 2016, 2015 and 2014 was $0.9 million, $0.8 million and $0.4 million, respectively. WHRM entered into the office lease agreement in 2013 that has escalating payments between July 2014 and May 2021. The average annual lease payment is $1.2 million over the life of the lease.

We have entered into drilling services agreements with varying terms. We have entered into compressor and equipment rental agreements with various terms. The compressor and equipment rental agreements expire at various times with the latest expiring in March 2017. Most of these agreements contain 30 day termination clauses. Total compressor and equipment rental expense incurred in 2016, 2015 and 2014 was $0.6 million, $1.0 million and $0.7 million, respectively.

The following tables present selected quarterly financial data for the periods indicated. 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.

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.

Proved reserves are, with respect to WHR II, prepared by WHR II and audited by Cawley, its independent reserve engineer. With respect to Esquisto, the proved reserves were prepared by Cawley, its independent reserve engineer, for 2015. Esquisto’s proved reserves for 2016 were internally prepared and audited by Cawley. All proved reserves are located in the United States and all prices are held constant in accordance with SEC rules.

The following tables set forth estimates of the net reserves as of December 31, 2016, 2015 and 2014, respectively:

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

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.

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, 2016:

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.

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:

In February 2017, we announced multiple transactions to acquire certain oil and natural gas producing and non-producing properties from third-parties in Burleson County, TX for an aggregate price of approximately $15.6 million, subject to customary post-closing adjustments. One transaction closed in February 2017 and the remaining transactions are expected to close in April 2017.

On February 1, 2017, we completed our private placement of $350 million in aggregate principal amount of our 6.875% Senior Notes due 2025. The 2025 Senior Notes were issued at a price of 99.244% of par and resulted in net proceeds of approximately $340.4 million. The 2025 Senior Notes will mature on February 1, 2025 and interest is payable on February 1 and August 1 of each year. We intend to use the net proceeds from the 2025 Senior Notes offering to repay borrowings outstanding under our revolving credit facility and for general corporate purposes.

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

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

On January 17, 2017, we also 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.

See Accompanying Notes to Unaudited Condensed Consolidated and Combined Financial Statements

UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

See Accompanying Notes to Unaudited Condensed Consolidated and Combined Financial Statements

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

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

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

the combined financial position and results attributable to our predecessor and Esquisto. For periods after the completion of our initial public offering, our consolidated financial statements include our accounts and those of our subsidiaries.

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

Preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about carrying values of assets and liabilities that are not readily apparent from other sources. We evaluate the estimates and assumptions on a regular basis; however, actual results may differ from these estimates and assumptions used in the preparation of the financial statements. Significant estimates with regard to these financial statements include (1) the estimate of proved oil, natural gas and NGL reserves and related present value estimates of future net cash flows therefrom; (2) depreciation, depletion and amortization expense; (3) valuation of accounts receivable; (4) accrued capital expenditures and liabilities; (5) asset retirement obligations (“ARO”); (6) environmental remediation costs; (7) valuation of derivative instruments; (8) incentive unit compensation cost; (9) contingent liabilities and (10) impairment expense. Although management believes these estimates are reasonable, changes in facts and circumstances or discovery of new information may result in revised estimates, and such revisions could be material.

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

Revenue from Contracts with Customers. In May 2014, the FASB issued a comprehensive new revenue recognition standard for contracts with customers that will supersede most current revenue recognition guidance, including industry-specific guidance. The core principle of this standard is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, the standard provides a five-step analysis of transactions to determine when and how revenue is recognized. In August 2015, the FASB issued an accounting standards update that formally delayed the effective date of its new revenue recognition standard. The new standard is effective for fiscal years, and interim periods within those years, beginning after December 15, 2017. Although early adoption was permitted, the Company decided not to early adopt. The new guidance will be applicable to us beginning on January 1, 2018. The standard permits the use of either the retrospective or cumulative effect transition method. The Company has not yet selected a transition method. We do not currently expect that adoption of the new revenue recognition standard will materially impact revenue recognition for many types of our arrangements. Documentation of our revenue streams and related contract reviews is currently underway and expected to be completed by the end of September. During the fourth quarter, we plan to update our existing business process and internal control documentation for any new or revised processes and controls.

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

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

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

Supplemental Pro forma Information. The following unaudited pro forma combined results of operations are provided for the three months and six months ended June 30, 2017 and 2016 as though the Acquisition had been

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

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

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

Supplemental Pro forma Information. The following unaudited pro forma combined results of operations are provided for the three months and six months ended June 30, 2016 as though the Burleson North Acquisition had

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

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

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

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

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

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:

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

Derivative instruments are netted when the right to net exists under a master netting agreement, future liabilities and assets correspond to the same commodity type and future cash flows have the same balance sheet current or non-current classification. We have exposure to financial institutions in the form of derivative transactions. These transactions are with counterparties in the financial services industry, specifically only lenders under our revolving credit facility, which could expose us to credit risk in the event of default of our counterparties. We have master netting agreements for our derivative transactions with our counterparties and although we do not require collateral, we believe our counterparty risk is low because of the credit worthiness of our counterparties. Master netting agreements are used to mitigate risk of loss due to default with counterparties on derivative instruments by providing us and each of our counterparties with rights of set-off upon the occurrence of defined acts of default by either us or our counterparty to a derivative or other financial instrument, whereby the party not in default may set-off all liabilities owed to the defaulting party against all net derivative and other financial asset receivables from the defaulting party. At June 30, 2017 we had net derivative assets of $51.8 million. As a result, had certain counterparties failed completely to perform according to the terms of existing contracts, we would have the right to offset $43.7 million against amounts outstanding under our revolving credit facility, thereby reducing our maximum credit exposure to approximately $8.1 million which was with one counterparty.

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

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

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

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

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

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

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):

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

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

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

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

Registration Rights Agreement, we agreed to file a registration statement with the SEC so that holders of the 2025 Senior Notes can exchange the 2025 Senior Notes for registered notes that have substantially identical terms. In addition, we have agreed to exchange the guarantees related to the 2025 Senior Notes for registered guarantees having substantially the same terms as the original guarantees. The Company and the guarantors will use commercially reasonable best efforts to cause the exchange to be consummated within 365 days after the issuance of the 2025 Senior Notes. The Company and the guarantors are required to pay additional interest if they fail to comply with their obligations to register the 2025 Senior Notes within the specified time periods.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

PennTex Midstream Partners, LP. During both the three and six months ended June 30, 2016, we made net payments of less than $0.1 million and $0.1 million to PennTex Midstream Partners, LP (“PennTex”), a former

NGP affiliated company, for the gathering, processing and transportation of natural gas and NGLs. Our related party relationship ceased in the fall of 2016 when a third-party acquired controlling interests in PennTex.

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

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

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

Operator. Esquisto paid Petromax Operating Company, Inc. (“Petromax”), who was the operator of the majority of Esquisto’s wells, $0.3 million and $0.6 million during the three and six months ended June 30, 2016, respectively, for overhead charges on drilling and producing wells at market rates as set forth in joint operating agreements and in accordance with an operating agreement between Petromax and Esquisto. Petromax is owned 33.3% by Mike Hoover, the former Chief Operating Officer of Esquisto, who also indirectly owned one of the former members of Esquisto.

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

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

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

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

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

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

We are party to various ongoing and potential legal actions relating to our entitled ownership interests in certain properties. We evaluate the merits of existing and potential claims and accrue a liability for any that meet the recognition criteria and can be reasonably estimated. We did not recognize any liability as of June 30, 2017 and December 31, 2016. Our estimates are based on information known about the matters and the input of attorneys experienced in contesting, litigating, and settling similar matters. Actual amounts could differ from our estimates and other claims could be asserted.

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

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

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

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

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

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

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

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

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

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

Our predecessor’s financial statements were retrospectively recast due to common control considerations. Because WHR II, Esquisto I, Esquisto II 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.

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

Pursuant to the Acquisition Agreements, on June 30, 2017, we acquired oil and gas working interests covering approximately 111,000 aggregate net acres and the associated production therefrom. The aggregate purchase price for the assets, as described in the Acquisition Agreements, subject to customary adjustments as provided in the Acquisition Agreements, consisted of an aggregate of approximately $533.6 million of cash to the APC Subs and approximately 5.5 million shares of our common stock valued at approximately $60.8 million to KKR (in the aggregate, the “Adjusted Purchase Price”). The common stock consideration price payable to KKR issued pursuant to a Stock Issuance Agreement that was executed, on May 10, 2017 (the “Stock Issuance Agreement”), by and among us and KKR. We and KKR made customary representations, warranties and covenants in the Stock Issuance Agreement. The closing of the common stock issuance was conditioned upon and occurred simultaneous with the closing of the Acquisition. WHR EF and the Sellers made customary representations, warranties and covenants in the Acquisition Agreements. The Sellers made certain additional customary covenants, including, among others, covenants to conduct its business in the ordinary course between the execution of the Acquisition Agreements and the closing of the Acquisition and not to engage in certain kinds of transactions during that period, subject to certain exceptions. The Sellers agreed not to take certain specified actions without our consent during the time between execution of the Acquisition Agreements and the closing of the Acquisition.

An affiliate of The Carlyle Group, L.P. (“Carlyle”) agreed to purchase $435 million of Preferred Stock from WRD. The remainder of the acquisition price was funded by borrowings under WRD’s revolving credit facility. The unaudited pro forma combined statements of operations of the Company include pro forma adjustments to give effect to the following as if they had occurred on the dates indicated:

The unaudited pro forma combined statements of operations of the Company are based on (i) the audited financial statements of the Company for the year ended December 31, 2016, included elsewhere in this prospectus; (ii) the unaudited financial statements of the Company for the six months ended June 30, 2017, included elsewhere in this prospectus; (iii) the audited historical statements of revenues and direct operating expenses of the Burleson North Acquisition for the nine months ended September 30, 2016, included elsewhere in this prospectus; (iv) the audited and unaudited historical statements of revenues and direct operating expenses of the APC Acquisition for the year ended December 31, 2016 and the three months ended March 31, 2017, included elsewhere in this prospectus; (v) the audited and unaudited historical statements of revenues and direct operating expenses of the KKR Acquisition for the year ended December 31, 2016 and the three months ended March 31, 2017, included elsewhere in this prospectus; and (vi) certain pro forma adjustments reflected in the pro forma financial statements below.

The pro forma data presented reflects events directly attributable to the above described transactions and certain assumptions that the Company believes are reasonable. The pro forma adjustments are based on currently available information and certain estimates and assumptions. Therefore, the actual adjustments may differ from the pro forma adjustments. However, management believes that the pro forma assumptions provide a reasonable basis for presenting the significant effects of the transactions as contemplated and that the pro forma adjustments give appropriate effect to those assumptions and are properly applied in the unaudited pro forma combined financial statements.

The unaudited pro forma combined financial statements and related notes are presented for illustrative purposes only. If the Burleson North Acquisition or the Acquisition and the related financing transactions contemplated herein had occurred in the past, the Company’s operating results might have been materially different from those presented in the unaudited pro forma combined financial statements. The unaudited pro forma combined financial statements should not be relied upon as an indication of operating results that the Company would have achieved if the acquisitions and other transactions contemplated herein had taken place on the specified date. In addition, future results may vary significantly from the results reflected in the unaudited pro forma statements of operations and should not be relied on as an indication of the future results of the Company.

The unaudited pro forma combined financial statements should be read in conjunction with the notes thereto and with the audited and unaudited historical financial statements and related notes of the Company, as well as the other audited and unaudited historical statements of revenues and direct operating expenses included elsewhere in this prospectus.

The accompanying notes are an integral part of these unaudited pro forma combined financial statements.

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

The unaudited pro forma combined financial information has been derived from the Company’s historical consolidated and combined financial statements. The unaudited pro forma combined statements of operations for the six months ended June 30, 2017 and the year ended December 31, 2016 each give effect to the Acquisition as if it had been completed on January 1, 2016. The unaudited pro forma combined statement of operations for the year ended December 31, 2016 also gives effect to the Burleson North Acquisition as if it had been completed on January 1, 2016.

The unaudited pro forma combined financial statements reflect pro forma adjustments that are described in Note 3 below and are based on available and certain assumptions that the Company believes are reasonable. However, actual results may differ from those reflected in these statements. In our opinion, all adjustments that are necessary to present fairly the pro forma information have been made. The following unaudited pro forma combined statements do not purport to represent what the financial position or results of operations would have been if the transaction had actually occurred on the dates indicated above, nor are they indicative of our future financial position or results of operations. These unaudited pro forma combined financial statements should be read in conjunction with the historical financial statements and our related notes for the periods presented.

We account for third-party acquisitions, including the Acquisition, under the acquisition method. The assets acquired and the liabilities assumed in the Acquisition have been measured at fair value based on various estimates. These estimates are based on key assumptions related to the business combination, including reviews of publicly disclosed information for other acquisitions in the industry, historical experience of the companies, data that was available through the public domain and due diligence reviews of the acquiree businesses. 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.

The allocation of the preliminary purchase price to the fair values of assets acquired and liabilities assumed includes pro forma adjustments to reflect the fair values of the Acquisition’s assets and liabilities at the time of the completion of the Acquisition. The final allocation of the purchase price could differ materially from the preliminary allocation. As such, we expect to finalize the allocation of the purchase price as soon as practicable.

The following pro forma adjustments have been applied to the Company’s historical combined statement of operations to depict the Company’s combined statements of operations as if the Burleson North Acquisition and the Acquisition had occurred on January 1, 2016. No further pro forma balance sheet information is required, since the acquisition is fully reflected in the Company’s historical balance sheet. The pro forma adjustments are based on currently available information and assumptions that management believes to be appropriate in the circumstances.

The following adjustments were made in the preparation of the unaudited pro forma combined statements of operations for the six months ended June 30, 2017 and year ended December 31, 2016:

The following sets forth the calculation of earnings (loss) per share (“EPS”), for the year ended December 31, 2016 and the six months ended June 30, 2017 (in thousands, except per share amounts). In the calculation of basic net income (loss) per share attributable to common stockholders, participating securities are allocated earnings based on actual dividend distributions received plus a proportionate share of undistributed net income attributable to common stockholders, if any, after recognizing distributed earnings. The Company’s participating securities do not participate in undistributed net losses because they are not contractually obligated to do so.

Our consolidated historical proved reserves as of December 31, 2016 were prepared by our internal engineers and audited by Cawley, Gillespie and Associates, Inc. (“Cawley”), our independent reserve engineers. APC’s proved reserves as of December 31, 2016 were prepared by their internal reservoir engineers. KKR’s proved reserves as of December 31, 2016 were prepared by their internal reservoir engineers. All proved reserves are located in the United States and all prices were determined and held constant in accordance with SEC rules.

The following tables set forth estimates of the quantities of oil, natural gas and NGL reserves as of December 31, 2016:

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

Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves

As required by the Financial Accounting Standards Board 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 pro forma standard measure of discounted future net cash flows in as follows:

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

The following is a pro forma summary of the changes in the standardized measure of discounted future net cash flows for the proved oil and natural gas reserves during the year ended December 31, 2016:

We have audited the accompanying Statements of Revenue and Direct Operating Expenses (the “Statements”) of Anadarko Petroleum Corporation’s Eaglebine and Northstars Properties (the “Properties”) for the years ended December 31, 2016, 2015, and 2014, and the related notes to the Statements.

Management is responsible for the preparation and fair presentation of these Statements in accordance with U.S. generally accepted accounting principles; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of Statements that are free from material misstatement, whether due to fraud or error.

Our responsibility is to express an opinion on these Statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the Statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the Statements. The procedures selected depend on the auditors’ judgment, including the assessment of the risks of material misstatement of the Statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the Statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the Statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

In our opinion, the Statements referred to above present fairly, in all material respects, the revenues and direct operating expenses of the Properties for the years ended December 31, 2016, 2015, and 2014, in accordance with U.S. generally accepted accounting principles.

As described in Note 2, the accompanying Statements of Revenues and Direct Operating Expenses were prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission and are not intended to be a complete presentation of the operations of the Properties. Our opinion is not modified with respect to this matter.

Accounting principles generally accepted in the United States of America require that the supplemental information relating to oil and natural gas producing activities be presented to supplement the basic financial

statements. Such information, although not a part of the basic financial statements, is required by the United States Financial Accounting Standards Board, who as described in Accounting Standards Codification Topic 932-235-50, considers the supplemental information to be an essential part of financial reporting for placing the basic financial statements in an appropriate operational, economic, or historical context. We have applied certain limited procedures to the required supplementary information in accordance with auditing standards generally accepted in the United States of America, which consisted of inquiries of management about the methods of preparing the information and comparing the information for consistency with management’s responses to our inquiries, the basic financial statements, and other knowledge we obtained during our audit of the basic financial statements. We do not express an opinion or provide any assurance on the information because the limited procedures do not provide us with sufficient evidence to express an opinion or provide any assurance.

Anadarko Petroleum Corporation (the “Company”) holds an interest in approximately 202,000 gross acres in Austin, Brazos, Burleson, Fayette, Lee, Milam, Robertson, and Washington Counties, Texas. The Company’s interest includes, among other formations, approximately 78,400 net acres in the Eagle Ford formation, and approximately 158,000 net acres among the Austin Chalk, Buda, Georgetown, and deeper formations. The Company participates in a total of 551 active wells, of which 80 are currently completed in the Eagle Ford formation (collectively with the net acres described above, the “Eaglebine and Northstars Properties”).

On May 10, 2017, the Company entered into a definitive agreement pursuant to two purchase and sale agreements to sell the Company’s interest in the Eaglebine and Northstars Properties to a third party.

Basis of Presentation The accompanying Statements of Revenues and Direct Operating Expenses for the Eaglebine and Northstars Properties (the “Statements”) include revenues from the sale of oil, condensate, natural gas, and natural-gas liquids (NGLs) and direct operating expenses for the three months ended March 31, 2017 and 2016, and the years ended December 31, 2016, 2015, and 2014. Revenues and direct operating expenses included in the Statements represent the Company’s interest in the Eaglebine and Northstars Properties and are presented on the accrual basis of accounting. During the periods presented, the Eaglebine and Northstars Properties were not accounted for or operated as a separate division or entity by the Company. Accordingly, complete financial statements under U.S. generally accepted accounting principles are not available or practicable to produce for the Eaglebine and Northstars Properties. The Statements are not intended to be a complete presentation of the results of operations of the Eaglebine and Northstars Properties and may not be representative of future operations as they do not include indirect general and administrative expenses; interest expense; depreciation, depletion, and amortization; provision for income taxes; and certain other revenues and expenses not directly associated with revenues from the sale of oil, condensate, natural-gas, and NGLs.

Use of Estimates Accounting principles generally accepted in the United States of America require management to make estimates and assumptions that affect the amounts reported in the Statements. These estimates and assumptions are based on management’s best estimates and judgment. Actual results may differ from those estimates.

Revenues The Company’s oil and condensate production from the Eaglebine and Northstars Properties is sold to third-party marketers, gatherers, and refiners. Natural-gas and NGLs production is primarily sold to the Company’s marketing affiliate. The Company recognizes sales revenues for oil and condensate, natural gas, and NGLs based on the amount of each product sold to purchasers when delivery to the purchaser has occurred and title has transferred.

Direct Operating Expenses Direct operating expenses are recognized when incurred and include (a) lease operating expenses, which consist of gathering and processing, salaries and wages, water costs, lease and well repairs and maintenance, utilities and other direct operating expenses; (b) production taxes; and (c) ad valorem taxes.

New Accounting Standards Issued but Not Yet Adopted The Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2014-09, Revenue from Contracts with Customers (Topic 606), which supersedes current revenue recognition requirements and industry- specific guidance. The codification was amended through additional ASUs and, as amended, requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity

NOTES TO THE STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES (Continued)

expects to be entitled to in exchange for those goods or services. The Company is required to adopt the new standard in the first quarter of 2018 using one of two retrospective application methods. The Company is continuing to evaluate the provisions of this ASU and is therefore unable to disclose the impact that adopting ASU 2014-09 may have on the Statements for the Eaglebine and Northstars Properties.

A substantial majority of the Eaglebine and Northstars Properties’ natural gas and NGLs is sold to the Company’s marketing affiliate.

Sales to individual customers that exceeded 10% of total revenues related to the Eaglebine and Northstars Properties in each of the periods presented are as follows:

There were no sales to other customers that exceeded 10% of total revenues in any of the periods presented.

The Company is subject to legal proceedings, claims, and liabilities that arise in the ordinary course of business as well as various environmental-remediation and reclamation obligations arising from federal, state, and local laws and regulations. The Company does not believe that the liability with respect to these actions will have a material adverse effect on the operations or financial results related to the Company’s interest in the Eaglebine and Northstars Properties.

The Company has evaluated subsequent events through June 9, 2017, the date the Statements were available to be issued, and has concluded there are no material subsequent events that would require recognition or disclosure in these financial statements.

The unaudited supplemental information on oil and gas exploration and production activities related to the Eaglebine and Northstars Properties for 2016, 2015, and 2014 has been presented in accordance with FASB

NOTES TO THE STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES (Continued)

Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas and the Securities and Exchange Commission’s final rule, Modernization of Oil and Gas Reporting. The Oil and Gas Reserves and the Standardized Measure of Discounted Future Net Cash Flows represent Anadarko’s interest in the Eaglebine and Northstars Properties.

The following reserves disclosures relate to the Eaglebine and Northstars Properties and reflect estimates of proved reserves, proved developed reserves, and proved undeveloped reserves, net of third-party royalty interests, of oil, condensate, natural gas, and NGLs owned at each year end and changes in proved reserves during each of the years presented. Oil, condensate, and NGLs volumes are presented in thousands of barrels (MBbls) and natural-gas volumes are presented in millions of cubic feet (MMcf) at a pressure base of 14.73 pounds per square inch. Total volumes are presented in thousands of barrels of oil equivalent (MBOE). For this computation, one barrel is the equivalent of 6,000 cubic feet of natural gas. Shrinkage associated with NGLs has been deducted from the natural-gas reserves volumes.

The Company’s estimates of proved reserves are made using available geological and reservoir data as well as production performance data. These estimates are reviewed annually by internal reservoir engineers and revised, either upward or downward, as warranted by additional data. The results of infill drilling are treated as positive revisions due to increases to expected recovery. Other revisions are due to changes in, among other things, development plans, reservoir performance, commodity prices, economic conditions, and governmental restrictions.

The prices below were used to compute the information presented in the following tables and are adjusted only for fixed and determinable amounts under provisions in existing contracts. Oil and condensate and NGLs prices are presented as price per barrel (Bbl). Gas prices are presented as price per million British thermal units (MMBtu).

NOTES TO THE STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES (Continued)

Estimates of future net cash flows from proved reserves are computed based on the average beginning-of-the-month prices during the 12-month period for the year. Estimated future net cash flows for all periods presented are reduced by estimated future development, production, and abandonment and dismantlement costs based on existing costs, assuming continuation of existing economic conditions. These estimates also include assumptions about the timing of future production of proved reserves, and timing of future development, production costs, and abandonment and dismantlement.

The present value of future net cash flows is not an estimate of the fair value of the Eaglebine and Northstars Properties’ oil and gas properties. An estimate of fair value would also take into account, among other things, anticipated changes in future prices and costs, the expected recovery of reserves in excess of proved reserves, and a discount factor more representative of the time value of money and the risks inherent in producing oil and natural gas. Significant changes in estimated reserves volumes or commodity prices could have a material effect on the results of operations of the Eaglebine and Northstars Properties.

NOTES TO THE STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES (Continued)

The standardized measure of discounted future net cash flows related to the proved oil and gas reserves of the Eaglebine and Northstars Properties is presented below and excludes income taxes as income tax expense is excluded from the Statements.

Changes in the standardized measure of discounted future net cash flows before income taxes related to the proved oil and gas reserves of the Eaglebine and Northstars Properties are as follows:

We have audited the accompanying statements of revenue and direct operating expenses of the oil and natural gas properties (the “Properties”) expected to be acquired by WHR Eagle Ford LLC, a subsidiary of WildHorse Resource Development Corporation, from Admiral A. Holding, L.P., TE Admiral A. Holding L.P., and Aurora C-I Holding L.P. (collectively, the “Partnerships”), under common control of KKR EIGF LLC (the “Company”), in accordance with the definitive purchase and sale agreement dated May 10, 2017, for the period from September 11, 2014 through December 31, 2014, and for the years ended December 31, 2015 and 2016.

Management’s Responsibility for the Statements of Revenue and Direct Operating Expenses

Management is responsible for the preparation and fair presentation of the statements of revenue and direct operating expenses in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of the statements of revenue and direct operating expenses that are free from material misstatement, whether due to fraud or error.

Our responsibility is to express an opinion on the statements of revenue and direct operating expenses based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the statements of revenue and direct operating expenses are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the statements of revenue and direct operating expenses. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the Company’s preparation and fair presentation of the statements of revenue and direct operating expenses in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the statements of revenue and direct operating expenses.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

In our opinion, the statements of revenue and direct operating expenses referred to above present fairly, in all material respects, the revenues and direct operating expenses of the Properties for the period from September 11, 2014 to December 31, 2014, and for the years ended December 31, 2015 and 2016, in accordance with accounting principles generally accepted in the United States of America.

As discussed in Note 2 to the statements of revenue and direct operating expenses, the accompanying statements of revenue and direct operating expenses have been prepared for the purposes of presenting the revenues and direct operating expenses of the Properties, and are not intended to be a complete presentation of the financial position, results of operations or cash flows of the Properties. Our opinion is not modified with respect to this matter.

Accounting principles generally accepted in the United States of America require that the Supplemental Oil, Natural Gas, and NGL Information be presented to supplement the statements of revenue over direct operating expenses. Such information, although not a part of the statements of revenue over direct operating expenses, is required by the Financial Accounting Standards Board who considers it to be an essential part of financial reporting for placing the statements of revenue over direct operating expenses in an appropriate operational, economic, or historical context. We have applied certain limited procedures to the required supplementary information in accordance with auditing standards generally accepted in the United States of America, which consisted of inquiries of management about the methods of preparing the information and comparing the information for consistency with management’s responses to our inquiries, the statements of revenue over direct operating expenses, and other knowledge we obtained during our audit of the statements of revenue over direct operating expenses. We do not express an opinion or provide any assurance on the information because the limited procedures do not provide us with sufficient evidence to express an opinion or provide any assurance.

See accompanying notes to the Statements of Revenues and Direct Operating Expenses.

NOTES TO THE STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES OF THE AURORA ACQUIRED PROPERTIES (AS DESCRIBED IN NOTE 1)

On September 11, 2014, Admiral A Holdings L.P., TE Admiral A Holdings L.P. and Aurora C-I Holding L.P. (together “Aurora”) acquired working interests in certain oil and natural gas properties located in the Eaglebine play in Texas. On May 10, 2017, WHR Eagle Ford LLC, a wholly-owned subsidiary of WildHorse Resource Development Corporation (“WildHorse”), entered into a purchase and sale agreement with Aurora to acquire all of Aurora’s working interests in the Eaglebine properties (the “Acquired Properties”).

Basis of Presentation—Aurora did not prepare separate stand-alone historical financial statements for the Acquired Properties during the periods presented. Accordingly, complete financial statements under U.S. generally accepted accounting principles are not available or practicable to produce for the Acquired Properties. The Statements of Revenues and Direct Operating Expenses are not intended to be a complete presentation of the results of operations of the Acquired Properties and may not be representative of future operations as they do not include indirect general and administrative expenses, interest expense, depreciation, depletion, and amortization, income taxes, effects of hedging transactions, impairment expenses, exploration expenses, and other income and expenses not directly attributable to oil, natural gas, and natural gas liquids (“NGL”) revenue.

Use of Estimates—Accounting principles generally accepted in the United States of America require management to make estimates and assumptions that affect the amounts reported in the Statements. These estimates and assumptions are based on management’s best estimates and judgment. Actual results may differ from those estimates.

Revenue Recognition—Oil, natural gas, and NGL revenues are recognized when production is sold to a purchaser at fixed or determinable prices, when delivery has occurred and title has transferred and collectability of the revenue is reasonably assured. Aurora follows the sales method of accounting for natural gas revenues. Under this method of accounting, revenues are recognized based on volumes sold, which may differ from the volume which are entitled based on Aurora’s working interest. There were no material gas imbalances during the periods presented.

Direct Operating Expenses—Direct operating expenses are recognized when incurred and include (a) lease operating expenses, which consist of gathering and processing expenses, lifting costs, lease and well repairs and maintenance, and other field expenses; and (b) production and other taxes, which consist of severance and ad valorem taxes.

The activity of the Acquired Properties may become subject to potential claims and litigation in the normal course of operations. While the ultimate impact of any proceedings cannot be predicted with certainty, Aurora management is currently not aware of any legal or other contingencies that would have a material effect on the Statements of Revenues and Direct Operating Expenses.

The Statements of Revenues and Direct Operating Expense were issued on June 27, 2017, and all subsequent events through June 27, 2017 were considered for purposes of analysis and disclosure.

NOTES TO THE STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES OF THE AURORA ACQUIRED PROPERTIES (AS DESCRIBED IN NOTE 1) (Continued)

The following tables present the changes in estimated proved and estimated proved developed reserves, the standardized measure of discounted future net cash flows and changes therein relating to estimated proved oil, natural gas, and NGL reserves for the periods presented. We caution that there are many uncertainties inherent in estimating proved reserve quantities and in projecting future production rates and the timing of development. Accordingly, these estimates are expected to change as further information becomes available. Material revisions of reserve estimates may occur in the future, development and production of the oil, natural gas and NGL reserves may not occur in the periods assumed, and actual prices realized incurred may vary significantly from those used in these estimates. The estimates of our proved reserves for the periods presented have been prepared internally by qualified engineers.

The estimated proved and estimated proved developed reserves for the periods presented are as follows:

As specified by the SEC, estimated future net cash flows utilize prices for oil, natural gas, and NGL that are the arithmetical average prices during the year determined using the price on the first day of each month.

The present value of future net cash flows does not purport to be an estimate of the fair market value of the Acquired Properties. An estimate of fair value would also take into account, among other things, anticipated changes in future prices and costs, the expected recovery of reserves in excess of proved reserves and a discount factor more representative of the time value of money and the risks inherent in producing oil and natural gas.

NOTES TO THE STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES OF THE AURORA ACQUIRED PROPERTIES (AS DESCRIBED IN NOTE 1) (Continued)

The standardized measure of discounted future net cash flows relating to estimated proved oil, natural gas, and NGL reserves for the periods presented are as follows:

The principal sources of changes in the standardized measure of discounted future net cash flows for the periods presented are as follows:

We have audited the accompanying statements of revenues and direct operating expenses (the “financial statements”), which comprise the revenues and direct operating expenses of certain oil and gas properties of Clayton Williams Energy, Inc. contracted to be acquired by WHE AcqCo., LLC (the “Burleson North Properties working interest”) for the nine month period ended September 30, 2016 and the years ended December 31, 2015 and 2014, and the related notes to the financial statements.

Management is responsible for the preparation and fair presentation of these financial statements in conformity with U.S. generally accepted accounting principles; this includes the design, implementation and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free of material misstatement, whether due to fraud or error.

Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditors’ judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

The accompanying financial statements referred to above were prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission. The financial statements are not intended to be a complete presentation of the operations of the Burleson North Properties working interest.

In our opinion, the financial statements referred to above present fairly, in all material respects, the revenues and direct operating expenses of the Burleson North Properties working interest for the nine month period ended September 30, 2016 and the years ended December 31, 2015 and 2014 in accordance with U.S. generally accepted accounting principles.

U.S. generally accepted accounting principles require that the Supplementary Oil and Gas Disclosures contained herein be presented to supplement the basic financial statements. Such information, although not a part of the basic financial statements, is required by the Financial Accounting Standards Board who considers it to be

an essential part of financial reporting for placing the basic financial statements in an appropriate operational, economic, or historical context. We have applied certain limited procedures to the required supplementary information in accordance with auditing standards generally accepted in the United States of America, which consisted of inquiries of management about the methods of preparing the information and comparing the information for consistency with management’s responses to our inquiries, the basic financial statements, and other knowledge we obtained during our audit of the basic financial statements. We do not express an opinion or provide any assurance on the information because the limited procedures do not provide us with sufficient evidence to express an opinion or provide any assurance.

See accompanying notes to the Statements of Revenues and Direct Operating Expenses.

On October 24, 2016, WHE AcqCo., LLC (“WHE AcqCo”) entered into a purchase and sale agreement (the “PSA”) to acquire from Clayton Williams Energy, Inc. (“CWEI”) its working interests in certain producing oil and gas properties and undeveloped acreage in the Eagleford and Austin Chalk trends in East Texas (the “Burleson North Properties working interest”) for a total of $400.0 million in cash, subject to customary purchase price adjustments. The PSA contains customary representations and warranties, covenants, indemnification provisions and conditions to closing. The transaction is expected to close in December 2016 and is effective as of October 1, 2016.

The accompanying audited statements include revenues from oil (including condensate and gas liquids) and gas production and direct operating expenses associated with the Burleson North Properties working interest and were derived from CWEI’s consolidated historical accounting records. The accompanying statements vary from a complete income statement in accordance with accounting principles generally accepted in the United States of America in that they do not reflect certain indirect expenses that were incurred in connection with the ownership and operation of the Burleson North Properties working interest including, but not limited to, general and administrative expenses, interest expense and state income tax expense. These costs were not separately allocated to the Burleson North Properties working interest in the accounting records of CWEI. In addition, these allocations, if made using historical general and administrative structures and tax burdens, would not produce allocations that would be indicative of the historical performance of the Burleson North Properties working interest had it been a WHE AcqCo property due to the differing size, structure, operations and accounting policies of CWEI and WHE AcqCo. The accompanying statements also do not include provisions for depreciation, depletion, amortization and accretion, as such amounts would not be indicative of the costs that WHE AcqCo will incur upon the allocation of the purchase price paid for the Burleson North Properties working interest. Furthermore, no balance sheet has been presented for the Burleson North Properties working interest because the acquired properties were not accounted for as a separate subsidiary or division of CWEI and complete financial statements are not available, nor has information about the Burleson North Properties working interest’s operating, investing and financing cash flows been provided for similar reasons. Accordingly, the historical Statements of Revenues and Direct Operating Expenses of the Burleson North Properties working interest are presented in lieu of the full financial statements required under Item 3-05 of Securities and Exchange Commission (“SEC”) Regulation S-X.

These Statements of Revenues and Direct Operating Expenses are not indicative of the results of operations for the Burleson North Properties working interest on a go forward basis.

Use of Estimates—The Statements of Revenues and Direct Operating Expenses are derived from the historical operating statements of CWEI. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America require management to make estimates and assumptions that affect the reported amounts of revenues and direct operating expenses during the respective reporting periods. Actual results could be different from those estimates.

Revenue Recognition—Total revenues in the accompanying statements include the sale of crude oil, natural gas and natural gas liquids, net of royalties. CWEI recognizes revenues when the significant risks and rewards of ownership have been transferred, which is when title passes to the customer. Oil and gas revenues included in these statements are recorded on the sales method, under which revenues are based on the oil, natural gas liquids and natural gas delivered rather than the net revenue interest share of oil and gas produced. There were no significant imbalances with other revenue interest owners during the period from January 1, 2016 to September 30, 2016 and the years ended December 31, 2015 and 2014.

Burleson North Properties Working Interest (as described in Note 1) (Continued)

During the period from January 1, 2016 to September 30, 2016, two customers accounted for approximately 46% and 45% of the Burleson North Properties working interest’s total revenues, respectively. During 2015, these two customers accounted for approximately 58% and 36% of the Burleson North Properties working interest’s total revenues, respectively. During 2014, these two customers accounted for approximately 28% and 64% of the Burleson North Properties working interest’s total revenues, respectively. During such periods, no other purchaser accounted for more than 10% of the total revenues. The loss of any single significant customer or contract could have a material adverse short-term effect; however, it is not likely that the loss of any single significant customer or contract would materially affect the Burleson North Properties working interest in the long-term as such purchasers could be replaced by other purchasers under contracts with similar terms and conditions.

Direct Operating Expenses—Direct operating expenses are recognized when incurred and consist of direct expenses of operating the Burleson North Properties working interest. The direct operating expenses include lease operating, production taxes, processing and transportation expenses. Lease operating expenses include lifting costs, well repair expenses, facility maintenance expenses, well workover costs, and other field related expenses. Lease operating expenses also include expenses directly associated with support personnel, support services, equipment, and facilities directly related to oil and gas production activities.

The activities of the Burleson North Properties working interest may become subject to potential claims and litigation in the normal course of operations. CWEI does not believe that any liability resulting from any pending or threatened litigation will have a material adverse effect on the operations or financial results of the Burleson North Properties working interest.

CWEI has evaluated events through November 10, 2016, the date the Statements of Revenues and Direct Operating Expenses were available to be issued, and are not aware of any events that have occurred that require adjustments to or disclosure in the financial statements.

Burleson North Properties Working Interest (as described in Note 1) (Continued)

The following unaudited supplemental reserve information summarizes the net proved reserves of oil and gas and the standardized measure thereof attributable to the Burleson North Properties working interest as of September 30, 2016 and December 31, 2015 and 2014 and for the period from January 1, 2016 to September 30, 2016 and the years ended December 31, 2015 and 2014 attributable to the Burleson North Properties working interest. All of the reserves are located in the United States. The reserve disclosures are based on reserve studies prepared in accordance with the guidelines established by the SEC.

There are numerous uncertainties inherent in estimating quantities and values of proved reserves and in projecting future rates of production and the amount and timing of development expenditures, including many factors beyond the property owner’s control. Reserve engineering is a subjective process of estimating the recovery from underground accumulations of oil and gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Because all reserve estimates are to some degree subjective, the quantities of oil and gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and gas sales prices may each differ from those assumed in these estimates. In addition, the different reserve engineers may make different estimates of reserve quantities and cash flows based upon the same available data. The standardized measure shown below represents estimates only and should not be construed as the current market value of the estimated oil and gas reserves attributable to the Burleson North Properties working interest. In this regard, the information set forth in the following tables includes revisions of reserve estimates attributable to proved properties included in the preceding year’s estimates. Such revisions reflect additional information from subsequent development activities, production history of the Burleson North Properties working interest and any adjustments in the projected economic life of such property resulting from changes in product prices.

In December 2008, the SEC issued its final rule, Modernization of Oil and Gas Reporting, which was first effective for reporting reserve information as of December 31, 2009. In January 2010, the Financial Accounting Standards Board issued its authoritative guidance on extractive activities for oil and gas to align its requirements with the SEC’s final rule. Under the SEC’s final rule, prior period reserves were not restated.

Burleson North Properties Working Interest (as described in Note 1) (Continued)

The following table sets forth certain data pertaining to the Burleson North Properties working interest’s proved developed reserves as of September 30, 2016 and December 31, 2015 and 2014 and for the period from January 1, 2016 to September 30, 2016 and the years ended

The changes in proved reserves during 2016, 2015 and 2014 are comprised of the following items:

Revision of previous estimates. Revision of previous estimates for all periods can be primarily attributed to changes in commodity prices whereby when increased, it increases the estimated useful life of the wells and when decreased, it decreases the estimated useful life of the wells, thereby increasing or decreasing the ultimate recoverable reserves, respectively.

Burleson North Properties Working Interest (as described in Note 1) (Continued)

Extensions and discoveries. Extensions and discoveries during 2015 and 2014 are the result of drilling in the Eagleford trend where nine wells were added in 2015 and 25 wells were added in 2014, and the addition of one Austin Chalk well in 2015.

The Standardized Measure of Discounted Future Net Cash Flows (excluding income tax expense) relating to proved crude oil and gas reserves is presented below:

The Standardized Measure of Discounted Future Net Cash Flows (discounted at 10%) from production of proved reserves was developed as follows:

Burleson North Properties Working Interest (as described in Note 1) (Continued)

As described in Note 1, these Statements of Revenue and Direct Operating Expenses do not include income tax expense or balance sheet information, therefore income tax and capital expenditure estimates were omitted from the Standardized Measure of Discounted Future Net Cash Flows calculation. The principal sources of changes in the Standardized Measure of Discounted Future Net Cash Flows for each of the periods presented below are as follows:

If you wish to exchange old 6.875% Senior Notes due 2025 for an equal aggregate principal amount at maturity of new 6.875% Senior Notes due 2025 pursuant to the exchange offer, you must validly tender (and not withdraw) old notes to the exchange agent prior to the expiration date.

The undersigned hereby acknowledges receipt and review of the prospectus, dated October 12, 2017 (the “Prospectus”), of WildHorse Resource Development Corporation (the “Issuer”), and this letter of transmittal (the “Letter of Transmittal”), which together describe the Issuer’s offer (the “Exchange Offer”) to exchange its 6.875% Senior Notes due 2025 (the “new notes”) that have been registered under the Securities Act, as amended (the “Securities Act”), for a like principal amount of its issued and outstanding 6.875% Senior Notes due 2025 (the “old notes”). Capitalized terms used but not defined herein have the respective meaning given to them in the Prospectus.

The Issuer reserves the right, at any time or from time to time, to extend the Exchange Offer at its discretion, in which event the term “Expiration Date” shall mean the latest time date to which the Exchange Offer is extended. The Issuer shall notify the Exchange Agent and each registered holder of the old notes of any extension by oral or written notice prior to 9:00 a.m., New York City time, on the next business day after the previously scheduled Expiration Date.

This Letter of Transmittal is to be used by holders of the old notes. Tender of old notes is to be made according to the Automated Tender Offer Program (“ATOP”) of the Depository Trust Company (“DTC”) pursuant to the procedures set forth in the prospectus under the caption “Exchange Offer—Procedures for Tendering.” DTC participants that are accepting the Exchange Offer must transmit their acceptance to DTC, which will verify the acceptance and execute a book-entry delivery to the Exchange Agent’s DTC account. DTC will then send a computer generated message known as an “agent’s message” to the exchange agent for its acceptance. For you to validly tender your old notes in the Exchange Offer the Exchange Agent must receive prior to the Expiration Date, an agent’s message under the ATOP procedures that confirms that:

BY USING THE ATOP PROCEDURES TO TENDER OLD NOTES, YOU WILL NOT BE REQUIRED TO DELIVER THIS LETTER OF TRANSMITTAL TO THE EXCHANGE AGENT. HOWEVER, YOU WILL BE BOUND BY ITS TERMS, AND YOU WILL BE DEEMED TO HAVE MADE THE ACKNOWLEDGMENTS AND THE REPRESENTATIONS AND WARRANTIES IT CONTAINS, JUST AS IF YOU HAD SIGNED IT.

1. By tendering old notes in the Exchange Offer, you acknowledge receipt of the Prospectus and this Letter of Transmittal.

2. By tendering old notes in the Exchange Offer, you represent and warrant that you have full authority to tender the old notes described above and will, upon request, execute and deliver any additional documents deemed by the Issuer to be necessary or desirable to complete the tender of old notes.

3. You understand that the tender of the old notes pursuant to all of the procedures set forth in the Prospectus will constitute an agreement between you and the Issuer as to the terms and conditions set forth in the Prospectus.

4. By tendering old notes in the Exchange Offer, you acknowledge that the Exchange Offer is being made in reliance upon interpretations contained in no-action letters issued to third parties by the staff of the Securities and Exchange Commission (the “SEC”), including Exxon Capital Holdings Corp., SEC No-Action Letter (available April 13, 1988), Morgan Stanley & Co., Inc., SEC No-Action Letter (available June 5, 1991) and Shearman & Sterling, SEC No-Action Letter (available July 2, 1993), that the new notes issued in exchange for the old notes pursuant to the Exchange Offer may be offered for resale, resold and otherwise transferred by holders thereof without compliance with the registration and prospectus delivery provisions of the Securities Act (other than a broker-dealer who purchased old notes exchanged for such new notes directly from the Issuer to resell pursuant to Rule 144A or any other available exemption under the Securities Act of 1933, as amended (the “Securities Act”) and any such holder that is an “affiliate” of the Issuer within the meaning of Rule 405 under the Securities Act), provided that such new notes are acquired in the ordinary course of such holders’ business and such holders are not participating in, and have no arrangement with any other person to participate in, the distribution of such new notes.

5. By tendering old notes in the Exchange Offer, you hereby represent and warrant that:

You may, if you are unable to make all of the representations and warranties contained in Item 5 above and as otherwise permitted in the Registration Rights Agreement (as defined below), elect to have your old notes registered in the shelf registration statement described in the Registration Rights Agreements, dated February 1, 2017 and September 19, 2017 (the “Registration Rights Agreement”), by and among the Issuer and the Initial Purchasers (as defined therein). Such election may be made by notifying the Issuer in writing at 9805 Katy Freeway, Suite 400, Houston, TX 77024, Attention: Kyle N. Roane, Executive Vice President, General Counsel and Corporate Secretary. By making such election, you agree, as a holder of old notes participating in a shelf

registration, to indemnify and hold harmless the Issuer, each of the directors of the Issuer, each of the officers of the Issuer who signs such shelf registration statement, each person who controls the Issuer within the meaning of either the Securities Act or the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and the respective officers, directors, partners, employees, representatives and agents of each such person, from and against any and all losses, claims, damages or liabilities caused by any untrue statement or alleged untrue statement of a material fact contained in any shelf registration statement or prospectus, or in any supplement thereto or amendment thereof, or caused by the omission or alleged omission to state therein a material fact required to be stated therein or necessary to make the statements therein, in the light of the circumstances under which they were made, not misleading; but only with respect to information relating to you furnished in writing by or on behalf of you expressly for use in a shelf registration statement, a prospectus or any amendments or supplements thereto. Any such indemnification shall be governed by the terms and subject to the conditions set forth in the Registration Rights Agreement, including, without limitation, the provisions regarding notice, retention of counsel, contribution and payment of expenses set forth therein. The above summary of the indemnification provision of the Registration Rights Agreement is not intended to be exhaustive and is qualified in its entirety by the Registration Rights Agreement.

6. If you are a broker-dealer that will receive new notes for your own account in exchange for old notes that were acquired as a result of market-making activities or other trading activities, you acknowledge by tendering old notes in the Exchange Offer, that you will deliver a prospectus in connection with any resale of such new notes; however, by so acknowledging and by delivering a prospectus, you will not be deemed to admit that you are an “underwriter” within the meaning of the Securities Act.

7. If you are a broker-dealer and old notes held for your own account were not acquired as a result of market-making or other trading activities, such old notes cannot be exchanged pursuant to the Exchange Offer.

8. Any of your obligations hereunder shall be binding upon your successors, assigns, executors, administrators, trustees in bankruptcy and legal and personal representatives.

Any confirmation of a book-entry transfer to the Exchange Agent’s account at DTC of old notes tendered by book-entry transfer (a “Book-Entry Confirmation”), as well as Agent’s Message and any other documents required by this Letter of Transmittal, must be received by the Exchange Agent at its address set forth herein prior to 5:00 p.m., New York City time, on the Expiration Date.

Tenders of old notes will be accepted only in minimum denominations of $2,000 and integral multiples of $1,000 in excess thereof. The entire principal amount of old notes delivered to the Exchange Agent will be deemed to have been tendered unless otherwise communicated to the Exchange Agent. If the entire principal amount of all old notes is not tendered, then old notes for the principal amount of old notes not tendered and new notes issued in exchange for any old notes accepted will be delivered to the holder via the facilities of DTC promptly after the old notes are accepted for exchange.

All questions as to the validity, form, eligibility (including time of receipt), acceptance, and withdrawal of tendered old notes will be determined by the Issuer, in its sole discretion, which determination will be final and binding. The Issuer reserves the absolute right to reject any or all tenders not in proper form or the acceptance for exchange of which may, in the opinion of counsel for the Issuer, be unlawful. The Issuer also reserves the absolute right to waive any of the conditions of the Exchange Offer or any defect or irregularity in the tender of any old notes. The Issuer’s interpretation of the terms and conditions of the Exchange Offer (including the instructions on the Letter of Transmittal) will be final and binding on all parties. Unless waived, any defects or irregularities in connection with tenders of old notes must be cured within such time as the Issuers shall determine. Although the Issuer intends to notify holders of defects or irregularities with respect to tenders of old notes, neither the Issuer, the Exchange Agent, nor any other person shall be under any duty to give notification of any defects or irregularities in tenders or incur any liability for failure to give such notification. Tenders of old notes will not be deemed to have been made until such defects or irregularities have been cured or waived. Any old notes received by the Exchange Agent that are not properly tendered and as to which the defects or irregularities have not been cured or waived will be returned by the Exchange Agent to the tendering holders, unless otherwise provided in the Letter of Transmittal, promptly following the Expiration Date.

The Issuer reserves the absolute right to waive, in whole or part, up to the expiration of the Exchange Offer, any of the conditions to the Exchange Offer set forth in the Prospectus or in this Letter of Transmittal.

No alternative, conditional, irregular or contingent tender of old notes will be accepted.

Requests for assistance or for additional copies of the Prospectus or this Letter of Transmittal may be directed to the Exchange Agent at the address or telephone number set forth on the cover page of this Letter of Transmittal. Holders may also contact their broker, dealer, commercial bank, trust company or other nominee for assistance concerning the Exchange Offer.

Tenders may be withdrawn only pursuant to the limited withdrawal rights set forth in the Prospectus under the caption “Exchange Offer—Withdrawal of Tenders.”

IMPORTANT: BY USING THE ATOP PROCEDURES TO TENDER OLD NOTES, YOU WILL NOT BE REQUIRED TO DELIVER THIS LETTER OF TRANSMITTAL TO THE EXCHANGE AGENT. HOWEVER, YOU WILL BE BOUND BY ITS TERMS, AND YOU WILL BE DEEMED TO HAVE MADE THE ACKNOWLEDGMENTS AND THE REPRESENTATIONS AND WARRANTIES IT CONTAINS, JUST AS IF YOU HAD SIGNED IT.

The following are abbreviations and definitions of commonly used in the oil and natural gas industry:

3-D seismic: Geophysical data that depict the subsurface strata in three dimensions. 3-D seismic typically provides a more detailed and accurate interpretation of the subsurface strata than 2-D, or two-dimensional, seismic.

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

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

Boe: One barrel of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil. This is an energy content correlation and does not reflect a value or price relationship between the commodities.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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.

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

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

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

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

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

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

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

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

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

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

Proved reserves: Those quantities of oil, natural gas and NGLs, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date

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

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

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

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

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

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

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

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

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

Royalty: An interest in an oil and natural gas lease that gives the owner the right to receive a portion of the production from the leased acreage (or of the proceeds from the sale thereof), but does not require the owner to

pay any portion of the production or development costs on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

Service well: A well drilled or completed for the purpose of supporting production in an existing field.

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

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

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

Stratigraphic test well: A drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as “exploratory type” if not drilled in a known area or “development type” if drilled in a known area.

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

Unit: The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.

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

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

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

At your request, Cawley, Gillespie & Associates, Inc. (“CG&A”) prepared this report on January 25, 2017 for WildHorse Resources II, LLC, a wholly owned subsidiary of WildHorse Resource Development Corporation (“WildHorse”) for the purpose of confirming WildHorse’s in-house reserve estimates and economic forecasts attributable to the subject interests. CG&A audited over 90% of WildHorse’s estimated reserves, which are located in various gas and oil properties in Louisiana, Texas and Arkansas. This report was prepared for public disclosure by WildHorse or its affiliates in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations. This evaluation, effective December 31, 2016, 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”). A composite summary of the results of this audit are presented in the table below with respect to proved reserves of the interests of WildHorse:

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 properties.

In this audit, the base oil and gas prices calculated for December 31, 2016 were $42.75/BBL and $2.481/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 during 2016 and the base gas price is based upon Henry Hub spot prices during 2016. Prices were not escalated.

The base prices were adjusted for differentials on a by area basis, which may include local basis differentials, 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 $39.07 per barrel of oil, $2.530 per MCF of gas and $13.77 per barrel of NGL. All economic factors were held constant in accordance with SEC guidelines.

Ownership was accepted as furnished and has not been independently confirmed. Oil and gas price differentials, gas shrinkage, ad valorem taxes, lease operating expenses and investments were calculated and prepared by WildHorse and were accepted as furnished. All economic parameters, including lease operating expenses and investments, were held constant (not escalated) throughout the life of these properties.

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. However, the impact of possible changes to legislation or regulations to future operating expenses and investment costs have not been included in the evaluation. 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.

The reserve classifications and the economic considerations used herein for the SEC pricing scenario 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. 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. However, we do not anticipate nor are we aware of any legislative changes or restrictive regulatory actions that may impact the recovery of reserves.

The methods employed in estimating reserves are described in 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 offset production, both of which are considered to provide a relatively high degree of accuracy.

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 for WildHorse’s properties. The assumptions, data, methods and procedures used herein are appropriate for the purpose served by this report.

Please be advised that, based upon the foregoing, in our opinion the above-described estimates of the direct interests of WildHorse’s proved reserves are, in the aggregate, reasonable and have been prepared in accordance with generally accepted petroleum engineering and evaluation principles as set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information promulgated by the Society of Petroleum Engineers. In aggregate, CG&A reserve estimates are within 10% of WildHorse Resources’ in-house reserve estimates shown in the tables above for WildHorses’s properties.

It should be understood that our above-described audit does not constitute a complete reserve study of the oil and gas properties of the direct interests of WildHorse Resources II, LLC, a wholly owned subsidiary of WildHorse. The estimates and forecasts were based upon interpretations of data furnished by WildHorse and available from our files. 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.

Gillespie & Associates, Inc. Possible environmental liability related to the properties has not been investigated or considered. The estimated net cost of plugging and the salvage value of equipment at abandonment has been included.

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. The lead evaluator preparing this report was W. Todd Brooker, P.E., Senior Vice 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 WildHorse 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.

This letter is for the use of WildHorse Resources II, LLC, a wholly owned subsidiary of WildHorse. This letter should not be used, circulated, or quoted for any other purpose without the express written consent of Cawley, Gillespie & Associates, Inc. or except as required by law.

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 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.

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.

“(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).”

At your request, Cawley, Gillespie & Associates, Inc. (“CG&A”) prepared this report on January 26, 2017 for Esquisto Resources II, LLC, WHE AcqCo., LLC, and Petromax E&P Burleson, LLC all of which are wholly owned subsidiaries of WildHorse Resource Development Corporation (“WildHorse”) for the purpose of confirming WildHorse’s in-house reserve estimates and economic forecasts attributable to the subject interests. CG&A audited 100% of the subject interests estimated reserves, which are located in various gas and oil properties in East Texas. This report was prepared for public disclosure by WildHorse or its affiliates in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations. This evaluation, effective December 31, 2016, 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).

A composite summary of the results of this audit are presented in the table below with respect to the total proved reserves of the interests of WildHorse:

The base prices were adjusted for differentials on a by area basis, which may include local basis differentials, 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 $40.34 per barrel for oil, $10.77 per barrel for NGL, and $1.788 per MCF for gas. All economic factors were held constant in accordance with SEC guidelines.

to the Estimating and Auditing of Oil and Gas Reserve Information promulgated by the Society of Petroleum Engineers. In aggregate, CG&A reserve estimates are within 10% of WildHorse’s in-house reserve estimates shown in the tables above for WildHorses’s properties.

It should be understood that our above-described audit does not constitute a complete reserve study of the oil and gas properties of the direct interests of Esquisto Resources II, LLC, WHE AcqCo., LLC, and Petromax E&P Burleson, LLC all of which are wholly owned subsidiaries of WildHorse. The estimates and forecasts were based upon interpretations of data furnished by WildHorse and available from our files. 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.

An on-site field inspection of the properties has not been performed nor have 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 or considered. The estimated net cost of plugging and the salvage value of equipment at abandonment has been included.

This letter is for the use of Esquisto Resources II, LLC, WHE AcqCo., LLC, and Petromax E&P Burleson, LLC all of which are wholly owned subsidiaries of WildHorse relating to information of the interests of WildHorse. This letter should not be used, circulated, or quoted for any other purpose without the express written consent of Cawley, Gillespie & Associates, Inc. or except as required by law.

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

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.

“(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.

“(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.

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.”


COMMONLY USED DEFINED TERMS			ii
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS			iv
PROSPECTUS SUMMARY			1
RISK FACTORS			7
EXCHANGE OFFER			34
USE OF PROCEEDS			41
SELECTED FINANCIAL DATA			42
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			45
BUSINESS			74
EXECUTIVE COMPENSATION			99
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT			107
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS			112
DESCRIPTION OF NOTES			118
PLAN OF DISTRIBUTION			177
MATERIAL UNITED STATES FEDERAL INCOME TAX CONSEQUENCES			178
LEGAL MATTERS			179
EXPERTS			179
INDEX TO FINANCIAL STATEMENTS			F-1

Annex A—Letter of Transmittal			A-1
Annex B—Glossary of Oil and Natural Gas Terms			B-1
Annex C—Cawley, Gillespie & Associates, Inc. Audit Letter of WildHorse Resources II, LLC at December 31, 2016			C-1
Annex D—Cawley, Gillespie & Associates, Inc. Audit Letter of Esquisto Resources II, LLC, WHE AcqCo., LLC and Petromax E&P Burleson at December 31, 2016			D-1


	For the Six Months Ended June 30,						For the Year Ended December 31,
	2017			2016			2016			2015			2014
	(In thousands, except per share data)
Revenues:
Oil sales	$	92,040		$	31,936		$	75,938		$	42,971		$	2,780
Natural gas sales		25,422			19,439			43,487			38,665			41,694
NGL sales		6,067			2,170			5,786			4,295			989
Other income		936			1,297			2,131			404			—

Total revenues		124,465			54,842			127,342			86,335			45,463

Operating expenses:
Lease operating expenses		13,765			5,062			12,320			14,053			9,428
Gathering, processing and transportation		3,642			3,474			6,581			5,300			3,953
Gathering system operating expense		44			118			99			914			—
Taxes other than income tax		8,408			3,257			6,814			5,510			2,584
Cost of oil sales		—			—			—			—			687
Depreciation, depletion and amortization		59,672			41,986			81,757			56,244			15,297
Impairment of proved oil and gas properties		—			—			—			9,312			24,721
General and administrative expenses		17,531			9,132			23,973			15,903			5,838
Exploration expense		13,119			7,523			12,026			18,299			1,597

Total operating expenses		116,181			70,552			143,570			125,535			64,105

Income (loss) from operations		8,284			(15,710	)		(16,228	)		(39,200	)		(18,642	)
Other income (expense):
Interest expense		(12,204	)		(3,753	)		(7,834	)		(6,943	)		(2,680	)
Debt extinguishment costs		11			(358	)		(1,667	)		—			—
Gain (loss) on derivative instruments		77,407			(12,364	)		(26,771	)		13,854			6,514
Other income (expense)		13			(62	)		(151	)		(147	)		213

Total other income (expense)		65,227			(16,537	)		(36,423	)		6,764			4,047

Income (loss) before income taxes		73,511			(32,247	)		(52,651	)		(32,436	)		(14,595	)
Income tax benefit (expense)		(26,893	)		(250	)		5,575			(604	)		158

Net income (loss)	$	46,618		$	(32,497	)	$	(47,076	)	$	(33,040	)	$	(14,437	)
Net income (loss) attributable to previous owners		—			(7,782	)		(2,681	)		(3,085	)		—
Net income (loss) attributable to predecessor		—			(24,715	)		(33,998	)		(29,955	)		(14,437	)

Net income (loss) available to WildHorse Resource Development Corporation	$	46,618			—		$	(10,397	)	$	—		$	—
Preferred stock dividends		73			—			—			—			—
Undistributed earnings allocated to participating securities		434			—			—			—			—

Net income (loss) available to common stockholders	$	46,111		$	—		$	(10,397	)	$	—		$	—

Net income (loss) per common share:
Basic and diluted	$	0.49			n/a		$	(0.11	)		n/a			n/a
Weighted-average common shares outstanding:
Basic and diluted		93,452			n/a			91,327			n/a			n/a
Cash Flow Data:
Net cash provided by operating activities	$	72,034		$	17,313		$	22,262		$	50,096		$	25,660
Net cash used in investing activities	$	(764,707	)	$	(80,516	)	$	(567,545	)	$	(443,639	)	$	(128,967	)
Net cash provided by financing activities	$	704,191		$	25,575		$	505,272		$	424,481		$	114,589


	For the Six Months Ended June 30,				For the Year Ended December 31,
	2017		2016		2016		2015		2014
	(In thousands, except per share data)
Other Financial Data:
Adjusted EBITDAX(1)	$	86,964	$	39,421	$	84,317	$	55,858	$	21,277
Balance Sheet Data (at period end):
Cash and cash equivalents	$	14,633	$	5,498	$	3,115	$	43,126	$	12,188
Total assets	$	2,373,550	$	938,390	$	1,442,281	$	966,365	$	335,722
Total liabilities	$	791,318	$	283,588	$	434,393	$	317,676	$	156,731
Perpetual convertible preferred stock	$	432,657	$	—	$	—	$	—	$	—
Predecessor and Previous owner equity	$	—	$	654,802	$	—	$	648,689	$	178,992
Stockholders’ equity	$	1,149,575		n/a	$	1,007,888		n/a		n/a
Total liabilities and stockholders’ equity	$	1,940,893	$	938,390	$	1,442,281	$	966,365	$	335,722


	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2017			2016			2017			2016
	(In thousands, except per share data)						(In thousands, except per share data)
Revenues:
Oil sales	$	52,963		$	18,683		$	92,040		$	31,936
Natural gas sales		13,277			9,233			25,422			19,439
NGL sales		3,404			1,225			6,067			2,170
Other income		529			574			936			1,297

Total operating revenues		70,173			29,715			124,465			54,842

Operating expenses:
Lease operating expenses		6,837			2,302			13,765			5,062
Gathering, processing and transportation		1,942			1,583			3,642			3,474
Gathering system operating expense		25			64			44			118
Taxes other than income tax		4,509			1,785			8,408			3,257
Depreciation, depletion and amortization		33,229			19,923			59,672			41,986
General and administrative		10,049			4,683			17,531			9,132
Exploration expense		11,504			80			13,119			7,523

Total operating expense		68,095			30,420			116,181			70,552

Income (loss) from operations		2,078			(705	)		8,284			(15,710	)
Other income (expense):
Interest expense, net		(6,633	)		(1,781	)		(12,204	)		(3,753	)
Debt extinguishment costs		—			—			11			(358	)
Gain (loss) on derivative instruments		46,116			(15,610	)		77,407			(12,364	)
Other income (expense)		(2	)		(74	)		13			(62	)

Total other income (expense)		39,481			(17,465	)		65,227			(16,537	)

Income (loss) before income taxes		41,559			(18,170	)		73,511			(32,247	)
Income tax benefit (expense)		(15,193	)		(111	)		(26,893	)		(250	)

Net income (loss)		26,366			(18,281	)		46,618			(32,497	)
Net income (loss) attributable to previous owners		—			(5,265	)		—			(7,782	)
Net income (loss) attributable to predecessor		—			(13,016	)		—			(24,715	)

Net income (loss) available to WildHorse Resource Development Corporation		26,366			—			46,618			—
Preferred stock dividends		73			—			73			—
Undistributed earnings allocated to participating securities		387			—			434			—

Net income (loss) available to common stockholders	$	25,906		$	—		$	46,111		$	—


	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2017		2016		2017		2016
	(In thousands, except per share data)				(In thousands, except per share data)
Net income (loss) per common share:
Basic and diluted	$	0.28		n/a	$	0.49		n/a
Weighted-average common shares outstanding:
Basic and diluted		93,685		n/a		93,452		n/a
Oil and natural gas revenue:
Natural gas	$	13,277	$	9,233	$	25,422	$	19,439
Crude oil		52,963		18,683		92,040		31,936
Natural gas liquids		3,404		1,225		6,067		2,170

Total oil and natural gas revenue	$	69,644	$	29,141	$	123,529	$	53,545

Production volumes:
Natural gas (MMcf)		4,299		4,739		8,148		9,540
Oil (MBbls)		1,133		434		1,916		880
NGLs (MBbls)		205		104		365		215

Total (MBoe)		2,054		1,328		3,639		2,685

Average sales price:
Natural gas (per Mcf)	$	3.09	$	1.95	$	3.12	$	2.04
Oil (per Bbl)		46.77		43.07		48.05		36.30
NGLs (per Bbl)		16.59		11.74		16.62		10.08

Total (per Boe)	$	33.90	$	21.94	$	33.95	$	19.94

Average production volumes:
Natural gas (MMcf/d)		47.2		52.1		45.0		52.4
Oil (MBbls/d)		12.5		4.8		10.6		4.8
NGLs (MBbls/d)		2.3		1.1		2.0		1.2

Average net production (MBoe/d)		22.6		14.6		20.1		14.8

Average unit costs per Boe:
Lease operating expenses	$	3.33	$	1.73	$	3.78	$	1.89
Gathering, processing and transportation	$	0.95	$	1.19	$	1.00	$	1.29
Taxes other than income tax	$	2.20	$	1.34	$	2.31	$	1.21
General and administrative expenses	$	4.89	$	3.53	$	4.82	$	3.40
Depletion, depreciation and amortization	$	16.18	$	15.00	$	16.40	$	15.64


	For the Six Months Ended June 30, 2017			For the Years Ended December 31,
	For the Six Months Ended June 30, 2017			2016			2015			2014
	(in thousands)
Adjusted EBITDAX reconciliation to net (loss) income:
Net income (loss)	$	46,618		$	(47,076	)	$	(33,040	)	$	(14,437	)
Interest expense, net		12,204			7,834			6,943			2,680
Income tax (benefit) expense		26,893			(5,575	)		604			(158	)
Depreciation, depletion and amortization		59,672			81,757			56,244			15,297
Exploration expense		13,119			12,026			18,299			1,597
Impairment of proved oil and gas properties		—			—			9,312			24,721
(Gain) loss on derivative instruments		(77,407	)		26,771			(13,854	)		(6,514	)
Cash settlements received (paid) on derivative instruments		1,093			4,975			11,517			(2,712	)
Stock-based compensation		1,803			68			—			—
Acquisition related costs		2,798			553			593			1,450
(Gain) loss on sale of properties		—			43			—			—
Debt extinguishment costs		(11	)		1,667			—			—
Initial public offering costs		182			1,560			—			—
Non-cash liability amortization		—			(286	)		(760	)		(647	)

Total Adjusted EBITDAX	$	86,946		$	84,317		$	55,858		$	21,277


	For the Six Months Ended June 30,						For the Year Ended December 31,
	2017			2016			2016			2015			2014
Net cash provided by operating activities	$	72,034		$	17,313		$	22,262		$	50,096		$	25,660
Net cash used in investing activities	$	(764,707	)	$	(80,516	)	$	(567,545	)	$	(443,639	)	$	(128,967	)
Net cash provided by financing activities	$	704,191		$	25,575		$	505,272		$	424,481		$	114,589


Contractual Obligation	Total		Payment or Settlement due by Period
Contractual Obligation	Total		2017		2018-2019		2020-2021		Thereafter
			(In thousands)
Revolving credit facility(1)	$	242,750	$	—	$	—	$	242,750	$	—
Estimated interest payments(2)		42,464		8,545		17,090		16,829		—
Office lease		5,630		1,235		2,541		1,854		—
Gas transportation agreement(3)		9,528		4,380		5,148		—		—
Compressor and equipment(4)		1,599		1,599		—		—		—
Right-of-way		2,000		40		80		80		1,800

Total	$	303,971	$	15,799	$	24,859	$	261,513	$	1,800


	June 30, 2017
	Carrying Amount		Estimated Fair Value
2025 Senior Notes, fixed-rate due February 2025(1)	$	339,033	$	328,125


Region	Proved Total (MMBoe)		% Oil & Liquids		% Developed		Average Net Daily Production (MBoe/d)
Eagle Ford		104.7		92.8%		24.3%		6.7
North Louisiana		47.8		2.5%		45.7%		7.8

Total		152.5						14.5


	Oil (MBbls)		Natural Gas (MMcf)		NGLs (MBbls)		Total (MBoe)
Estimated Proved Reserves
Total Proved Developed		19,192		145,880		3,765		47,270
Total Proved Undeveloped		68,255		179,222		7,109		105,235

Total Proved Reserves		87,447		325,102		10,874		152,505


	For the Year Ending December 31,
	2016			2015			2014
	(in thousands)
PV-10	$	749,988		$	451,861		$	230,201
Less: present value of future income taxes discounted at 10%		(206,947	)		(5,931	)		(302	)

Standardized measure	$	543,041		$	445,930		$	229,899


	Base Case(1)			Case A(2)			Case B(2)
Crude oil price ($/Bbl)	$	42.75		$	48.00		$	55.00
Natural gas price ($/Mcf)	$	2.481		$	2.93		$	3.43
NGL price ($/Bbl)	$	42.75		$	48.00		$	55.00
Capital expenditure increase		n/a			Flat			5%
Operating expenditure increase		n/a			Flat			5%
Proved developed reserves (MMBoe)		47,270			49,166			51,211
Proved undeveloped reserves (MMBoe)		105,235			109,827			116,824

Total proved reserves (MMBoe)		152,505			158,993			168,035

PV-10 value (in thousands)(3)	$	749,988		$	1,036,433		$	1,484,776
Less: present value of future income taxes discounted at 10% (in thousands)		(206,947	)		(292,641	)		(455,182	)

Standardized measure (in thousands)	$	543,041		$	743,792		$	1,029,594


	Year Ended December 31, 2016
	Oil				Natural Gas				NGLs				Total
	Production Volumes		Average Sales Price		Production Volumes		Average Sales Price		Production Volumes		Average Sales Price		Production Volumes		Average Sales Price		Lease Operating Expense
	(MBbls)		($/Bbl)		(MMcf)		($/Mcf)		(MBbls)		($/Bbl)		(MBoe)		($/ MBoe)		($/MBoe)
Eagle Ford		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


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

Total		968				14,847				351				3,794			$	3.70

Average net production (MBoe/d)														10.4


	Oil						Natural Gas
	Gross		Net		Average Working Interest		Gross		Net		Average Working Interest
Eagle Ford Acreage
Operated		359.00		337.44		93.99%		36.00		30.25		84.03%
Non-operated		61.00		16.16		26.49%		4.00		0.36		9.00%
North Louisiana Acreage
Operated		7.00		4.78		68.29%		428.00		316.03		73.84%
Non-operated		1.00		0.11		11.00%		92.00		10.22		11.11%

Total		428.00		358.49		83.76%		560.00		356.86		63.73%


Region	Developed Acres(1)				Undeveloped Acres				Total Acres
	Gross(2)		Net(3)		Gross(2)		Net(3)		Gross(2)		Net(3)
Eagle Ford Acreage		10,752		8,325		310,909		254,418		321,661		262,743
North Louisiana Acreage		80,759		49,450		64,899		59,005		145,658		108,455

Total		91,511		57,775		375,808		313,423		467,319		371,198


Region	2017		2018		2019		2020		2021
Eagle Ford Acreage		49,016		45,889		31,334		4,618		100
North Louisiana Acreage		42,971		11,445		1,784		1,326		1

Total		91,987		57,334		33,118		5,944		101


	Year Ended December 31,
	2016				2015				2014
	Gross		Net		Gross		Net		Gross		Net
Eagle Ford Acreage
*Development wells*:
Productive		20.00		16.06		18.00		17.84		—		—
Dry		—		—		—		—		—		—
*Exploratory wells*:
Productive		—		—		—		—		—		—
Dry		—		—		—		—		—		—
North Louisiana Acreage
*Development wells*:
Productive		4.00		1.78		6.00		4.51		3.00		2.95
Dry		—		—		—		—		—		—
*Exploratory wells*:
Productive		—		—		3.00		2.70		—		—
Dry		—		—		—		—		—		—
Total wells
*Development wells*:
Productive		24.00		17.84		24.00		22.35		3.00		2.95
Dry		—		—		—		—		—		—

Total development wells		24.00		17.84		24.00		22.35		3.00		2.95

*Exploratory wells*:
Productive		—		—		3.00		2.70		—		—
Dry		—		—		—		—		—		—

Total exploratory wells		—		—		3.00		2.70		—		—

Total		24.00		17.84		27.00		25.05		3.00		2.95


Major Customers	Years Ending December 31,
Major Customers	2016(1)			2015(1)			2014
Energy Transfer Equity, L.P. and subsidiaries		63	%		36	%		10	%
Royal Dutch Shell plc and subsidiaries		12	%		20	%		41	%
Cima Energy LTD		15	%		16	%		n/a
BP Corporation North America		n/a			n/a			31	%


Name		Principal Position
Jay C. Graham		Chief Executive Officer
Andrew J. Cozby		Executive Vice President and Chief Financial Officer
Kyle N. Roane		Executive Vice President, General Counsel and Corporate Secretary


Name and Principal Position(1)	Year		Salary ($)		Bonus ($)(2)		Stock Awards ($)(3)		Option Awards ($)(4)		All Other Compensation ($)(5)		Total ($)
Jay C. Graham		2016	$	93,750	$	500,000	$	—	$	—	$	18,607	$	612,357
Chief Executive Officer		2015		266,667		—		—				15,540		282,207

Andrew J. Cozby		2016	$	100,737	$	75,000	$	2,416,672	$	—	$	—	$	2,592,409
Executive Vice President and Chief Financial Officer

Kyle N. Roane		2016	$	100,737	$	75,000	$	2,416,672	$	—	$	—	$	2,592,409
Executive Vice President, General Counsel and Corporate Secretary


	Shares Beneficially Owned					Shares of Preferred Stock
Name of Beneficial Owner	Shares of Common Stock		Percentage(10)			Shares of Preferred Stock
5% Stockholders:
WHR Holdings, LLC(1)		21,200,084		21.0	%		—
Esquisto Holdings, LLC(2)		38,755,330		38.3	%		—
WHE AcqCo Holdings, LLC(3)		2,563,266		2.5	%		—
NGP XI US Holdings, L.P.(2)(3)(4)		50,318,596		49.8	%		—
Boston Partners(5)		4,663,707		4.6	%		—
CP VI Eagle Holdings, L.P.(6)		—		—			435,000
Investment funds associated with KKR & Co. L.P.(7)		5,518,125		5.5	%		—
Directors and Named Executive Officers:
Jay C. Graham(8)(9)		843,076		*			—
Anthony Bahr(8)		894,602		*			—
Andrew J. Cozby(8)		310,139		*			—
Kyle N. Roane(8)		310,139		*			—
Richard D. Brannon(8)		10,000		*			—
Jonathan M. Clarkson(8)		16,000		*			—
Scott A. Gieselman		—		—			—
David W. Hayes		—		—			—
Grant E. Sims(8)		10,000		*			—
Tony R. Weber		—		—			—
Brian A. Bernasek		—		—			—
Martin W. Sumner		—		—			—
Directors and Executive Officers as a Group (14 Persons)		2,661,162		2.6	%		—


Year	Percentage
2020		105.156	%
2021		103.438	%
2022		101.719	%
2023 and thereafter		100.000	%


	Page
WildHorse Resource Development Corporation
Consolidated and Combined Financial Statements
Reports of Independent Registered Public Accounting Firms		F-2
Consolidated and Combined Balance Sheets as of December 31, 2016 and 2015		F-4
Statements of Consolidated and Combined Operations for the Years Ended December 31, 2016, 2015 and 2014		F-5
Statements of Consolidated and Combined Cash Flows for the Years Ended December 31, 2016, 2015, and 2014		F-6
Statements of Consolidated and Combined Statement of Changes in Equity for the Years Ended December 31, 2016, 2015, and 2014		F-7
Notes to Consolidated and Combined Financial Statements		F-8
Unaudited Condensed Consolidated Financial Statements
Unaudited Condensed Consolidated Balance Sheets as of June 30, 2017 and December 31, 2016		F-47
Unaudited Statements of Condensed Consolidated and Combined Operations for the Three Months and Six Months Ended June 30, 2017 and 2016		F-48
Unaudited Statements of Condensed Consolidated and Combined Cash Flows for the Three Months and Six Months Ended June 30, 2017 and 2016		F-49
Unaudited Condensed Consolidated Statement of Changes in Stockholders’ Equity for the Six Months Ended June 30, 2017		F-50
Notes to Condensed Consolidated and Combined Financial Statements		F-51
Unaudited Pro Forma Combined Financial Statements
Introduction		F-73
Unaudited Pro Forma Combined Statement of Operations for the Year Ended December 31, 2016		F-75
Unaudited Pro Forma Combined Statement of Operations for the Six Months Ended June 30, 2017		F-76
Notes to Unaudited Pro Forma Combined Financial Statements		F-77

Anadarko Eaglebine and Northstars Properties
Audited and Unaudited Statements of Revenues and Direct Operating Expenses
Independent Auditors’ Report		F-86
Statements of Revenues and Direct Operating Expenses for the Years Ended December 31, 2016, 2015 and 2014 (audited) and the Three Months Ended March 31, 2017 and 2016 (unaudited)		F-88
Notes to the Statements of Revenues and Direct Operating Expenses		F-89

KKR Eaglebine Properties
Audited and Unaudited Statements of Revenues and Direct Operating Expenses
Independent Auditors’ Report		F-94
Statements of Revenues and Direct Operating Expenses for the Years Ended December 31, 2016 and 2015 (audited), the period from September 11, 2014 to December 31, 2014 (audited) and the Three Months Ended March 31, 2017 and 2016 (unaudited)		F-96
Notes to the Statements of Revenues and Direct Operating Expenses		F-97

Burleson North Assets
Audited Statements of Revenues and Direct Operating Expenses
Independent Auditors’ Report		F-100
Statements of Revenues and Direct Operating Expenses for the Period From January 1, 2016 to September 30, 2016 and the Years Ended December 31, 2015 and 2014		F-102
Notes to the Statements of Revenues and Direct Operating Expenses		F-103


	December 31,			December 31,
	2016			2015
ASSETS
Current Assets:
Cash and cash equivalents	$	3,115		$	43,126
Accounts receivable, net		26,428			13,737
Short-term derivative instruments		—			7,076
Prepaid expenses and other current assets		1,633			2,830

Total current assets		31,176			66,769
Property and equipment:
Oil and gas properties		1,573,848			983,972
Other property and equipment		34,344			30,609
Accumulated depreciation, depletion and amortization		(200,293	)		(118,943	)

Total property and equipment, net		1,407,899			895,638
Other noncurrent assets:
Restricted cash		886			551
Long-term derivative instruments		—			2,440
Debt issuance costs		2,320			967

Total assets	$	1,442,281		$	966,365

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	21,014		$	34,843
Accrued liabilities		23,371			28,782
Short-term derivative instruments		14,087			—
Asset retirement obligations		90			90

Total current liabilities		58,562			63,715
Noncurrent liabilities:
Long-term debt		242,750			237,857
Asset retirement obligations		10,943			6,930
Notes payable to members (Note 14)		—			6,438
Deferred tax liabilities		112,552			852
Long-term derivative instruments		8,091			—
Other noncurrent liabilities		1,495			1,884

Total noncurrent liabilities		375,831			253,961

Total liabilities		434,393			317,676
Commitments and contingencies
Equity:
Stockholders’ equity:
Preferred stock, $0.01 par value: 50,000,000 shares authorized; no shares issued and outstanding		—			—
Common stock, $0.01 par value 500,000,000 shares authorized; 91,680,441 shares issued and outstanding at December 31, 2016		917			—
Additional paid-in capital		1,017,368			—
Accumulated earnings (deficit)		(10,397	)		—

Total stockholders’ equity		1,007,888			—
Predecessor		—			274,133
Previous owner		—			374,556

Total equity		1,007,888			648,689

Total liabilities and equity		1,442,281			966,365


	For Year Ended December 31,
	2016			2015			2014
Revenues:
Oil sales	$	75,938		$	42,971		$	2,780
Natural gas sales		43,487			38,665			41,694
NGL sales		5,786			4,295			989
Other income		2,131			404			—

Total operating revenues		127,342			86,335			45,463

Operating expenses:
Lease operating expenses		12,320			14,053			9,428
Gathering, processing and transportation		6,581			5,300			3,953
Gathering system operating expense		99			914			—
Taxes other than income tax		6,814			5,510			2,584
Cost of oil sales		—			—			687
Depreciation, depletion and amortization		81,757			56,244			15,297
Impairment of proved oil and gas properties		—			9,312			24,721
General and administrative		23,973			15,903			5,838
Exploration expense		12,026			18,299			1,597

Total operating expense		143,570			125,535			64,105

Income (loss) from operations		(16,228	)		(39,200	)		(18,642	)
Other income (expense):
Interest expense, net		(7,834	)		(6,943	)		(2,680	)
Debt extinguishment costs		(1,667	)		—			—
Gain (loss) on derivative instruments		(26,771	)		13,854			6,514
Other income (expense)		(151	)		(147	)		213

Total other income (expense)		(36,423	)		6,764			4,047

Income (loss) before income taxes		(52,651	)		(32,436	)		(14,595	)
Income tax benefit (expense)		5,575			(604	)		158

Net income (loss)		(47,076	)		(33,040	)		(14,437	)
Net income (loss) attributable to previous owners		(2,681	)		(3,085	)		—
Net income (loss) attributable to predecessor		(33,998	)		(29,955	)		(14,437	)

Net income (loss) available to WildHorse Resources	$	(10,397	)	$	—		$	—

Earnings per common share:
Basic	$	(0.11	)		n/a			n/a

Diluted	$	(0.11	)		n/a			n/a

Weighted-average common shares outstanding:
Basic		91,327			n/a			n/a

Diluted		91,327			n/a			n/a


	Stockholders’ Equity
	Common Stock		Additional Paid in Capital			Accumulated Earnings (deficit)			Predecessor			Previous Owner			Total
Balance, December 31, 2013	$	—	$	—		$	—		$	95,882		$	—		$	95,882
Capital contributions		—		—			—			89,437			—			89,437
Notes receivable from members, net		—		—			—			8,109			—			8,109
Net income (loss)		—		—			—			(14,437	)		—			(14,437	)

December 31, 2014	$	—	$	—		$	—		$	178,991		$	—		$	178,991
Balance at inception of common control (February 17, 2015)		—		—			—			—			86,478			86,478
Capital contributions		—		—			—			125,850			208,376			334,226
Property contributions		—		—			—			—			40,116			40,116
Common control step up in basis (Note 10)		—		—			—			—			42,671			42,671
Notes receivable from members, net		—		—			—			(753	)		—			(753	)
Net income (loss)		—		—			—			(29,955	)		(3,085	)		(33,040	)

December 31, 2015		—		—			—			274,133			374,556			648,689
Capital contributions		—		—			—			10,837			97,000			107,837
Property contributions		—		—			—			—			329			329
Net income (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


	Preliminary Purchase Price
Oil and gas properties	$	396,481
Other property and equipment		478
Accounts receivable		3,160
Asset retirement obligations		(3,101	)
Accrued liabilities		(7,206	)

Total identifiable net assets	$	389,812


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


	Comstock Acquisition
Oil and gas properties	$	102,628
Other property and equipment		500
Asset retirement obligations		(112	)

Total identifiable net assets	$	103,016


	Fair Value Measurements at December 31, 2016 Using
	Quoted Prices in Active Market (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Fair Value
	(In thousands)
Assets:
Commodity derivatives	$	—	$	7	$	—	$	—
Liabilities:
Commodity derivatives	$	—	$	22,185	$	—	$	22,185


		Asset Derivatives						Liability Derivatives
Type	Balance Sheet Location	2016			2015			2016			2015
Commodity contracts	Short-term derivative instruments	$	4		$	7,108		$	14,091		$	32
Netting arrangements	Short-term derivative instruments		(4	)		(32	)		(4	)		(32	)

Net recorded fair value		$	—		$	7,076		$	14,087		$	—


Commodity contacts	Long-term derivative instruments	$	3		$	2,656		$	8,094		$	216
Netting arrangements	Long-term derivative instruments		(3	)		(216	)		(3	)		(216	)

Net recorded fair value		$	—		$	2,440		$	8,091		$	—


	Statements of Operations Location	For the Year Ended December 31,
	Statements of Operations Location	2016		2015			2014
Commodity derivative contracts	(Gain) loss on commodity derivatives	$	26,771	$	(13,854	)	$	(6,514	)


	At December 31,
	2016			2015
Oil, gas and NGL sales	$	13,390		$	9,412
Joint interest billings		7,898			3,455
Severance tax		392			531
Other current receivables(1)		4,848			389
Allowance for doubtful accounts		(100	)		(50	)

Total	$	26,428		$	13,737