UNITED STATES SECURITIES AND EXCHANGE COMMISSION

 

Washington, D.C. 20549

 

Form 10-Q

 

(Mark One)

For the quarterly period ended September 30, 2017

OR

For the transition period from            to          .

Commission File Number: 001-37964

 

WildHorse Resource Development Corporation

(Exact name of Registrant as specified in its Charter)

 

 

 

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

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

 

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

 

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

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

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

 

 

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

 

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

 

As of October 31, 2017, the registrant had 101,171,233 shares of common stock, $0.01 par value outstanding.

 

 

 

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WILDHORSE RESOURCE DEVELOPMENT CORPORATION

TABLE OF CONTENTS

 

 

 

 

 

 

 

 

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GLOSSARY OF OIL AND NATURAL GAS TERMS

The following are abbreviations and definitions of commonly used in the oil and natural gas industry:

3-D seismic: Geophysical data that depict the subsurface strata in three dimensions. 3-D seismic typically provides a more detailed and accurate interpretation of the subsurface strata than 2-D, or two-dimensional, seismic.

Basin: A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.

Bbl: One stock tank barrel of 42 U.S. gallons liquid volume used herein in reference to crude oil, condensate or NGLs.

Bcf: One billion cubic feet of natural gas.

Boe: One barrel of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil. This is an energy content correlation and does not reflect a value or price relationship between the commodities.

Boe/d: One Boe per day.

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

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

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

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

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

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

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

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

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

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

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

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.

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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.

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

MBoe:  One thousand Boe.

Mcf: One thousand cubic feet of natural gas.

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

MMBoe: One million Boe.

MMBtu: One million British thermal units.

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

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

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

NYMEX: The New York Mercantile Exchange.

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

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

Play: A geographic area with hydrocarbon potential.

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

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

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

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

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

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

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

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

Proved properties: Properties with proved reserves.

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

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

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

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

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

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.

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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.

Unproved properties: Properties with no proved reserves.

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

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

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

WTI: West Texas Intermediate.

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COMMONLY USED DEFINED TERMS

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

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FORWARD–LOOKING STATEMENTS

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

Forward-looking statements may include statements about:

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

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

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

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

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

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PART I—FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS.

WILDHORSE RESOURCE DEVELOPMENT CORPORATION

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except outstanding shares)

 

See Accompanying Notes to Unaudited Condensed Consolidated and Combined Financial Statements

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WILDHORSE RESOURCE DEVELOPMENT CORPORATION

UNAUDITED STATEMENTS OF CONDENSED CONSOLIDATED AND COMBINED OPERATIONS

(In thousands, except per share amounts)

 

See Accompanying Notes to Unaudited Condensed Consolidated and Combined Financial Statements

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WILDHORSE RESOURCE DEVELOPMENT CORPORATION

UNAUDITED STATEMENTS OF CONDENSED CONSOLIDATED AND COMBINED CASH FLOWS

(In thousands)

 

See Accompanying Notes to Unaudited Condensed Consolidated and Combined Financial Statements

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WILDHORSE RESOURCE DEVELOPMENT CORPORATION

UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF

CHANGES IN STOCKHOLDERS’ EQUITY

(In thousands)

 

See Accompanying Notes to Unaudited Condensed Consolidated and Combined Financial Statements

 

 

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WILDHORSE RESOURCE DEVELOPMENT CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Note 1. Organization and Basis of Presentation

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

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

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

Basis of Presentation

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

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

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

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WILDHORSE RESOURCE DEVELOPMENT CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Use of Estimates in the Preparation of Financial Statements

Preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about carrying values of assets and liabilities that are not readily apparent from other sources. We evaluate the estimates and assumptions on a regular basis; however, actual results may differ from these estimates and assumptions used in the preparation of the financial statements. Significant estimates with regard to these financial statements include (1) the estimate of proved oil, natural gas and NGL reserves and related present value estimates of future net cash flows therefrom; (2) depreciation, depletion and amortization expense; (3) valuation of accounts receivable; (4) accrued capital expenditures and liabilities; (5) asset retirement obligations (“ARO”); (6) environmental remediation costs; (7) valuation of derivative instruments; (8) incentive unit compensation cost; (9) contingent liabilities and (10) impairment expense. Although management believes these estimates are reasonable, changes in facts and circumstances or discovery of new information may result in revised estimates, and such revisions could be material.

Note 2. Summary of Significant Accounting Policies

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

Supplemental Cash Flow Information

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

 

 

On June 30, 2017, we issued approximately 5.5 million shares of our common stock valued at approximately $60.8 million to KKR in connection with the consummation of the Acquisition.  See Note 3 for additional information regarding this issuance.

New Accounting Standards

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

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

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WILDHORSE RESOURCE DEVELOPMENT CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

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 selected the cumulative effect 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.  Though we have not quantified the impact, we believe that the new standard will require that fees incurred under some of our natural gas processing contracts be reported as a deduction to revenue earned under those contracts, instead of being presented as gathering, processing and transportation costs on our statement of operations. Documentation of our revenue streams and related contract reviews is substantially complete.  During the fourth quarter, we plan to finalize our contract review and 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.

Note 3. Acquisitions and Divestitures

Acquisition-related costs

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

 

2017 Acquisitions

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

On June 30, 2017, we completed the Acquisition. The aggregate purchase price for the Acquisition, which is subject to customary adjustments as provided in the Acquisition Agreements, consisted of approximately $533.6 million of cash to the APC Subs and approximately 5.5 million shares of our common stock valued at approximately $60.8 million to KKR (collectively, the “Adjusted Purchase Price”). The common stock consideration price payable to KKR was issued pursuant to a Stock Issuance Agreement that was executed on May 10, 2017 (the “Stock Issuance Agreement”), by and among us and KKR.  Post-acquisition, our earnings included $19.6 million of revenues and generated $5.0 million of income related to properties obtained in the Acquisition.

 

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WILDHORSE RESOURCE DEVELOPMENT CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

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

 

Supplemental Pro forma Information.  The following unaudited pro forma combined results of operations are provided for the three months and nine months ended September 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, (ii) depletion expense applied to the adjusted basis of the properties acquired and (iii) interest expense on additional borrowings necessary to finance the Acquisition. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the Acquisition occurred on the basis assumed above, nor is such information indicative of expected future results of operations.

 

 

Burleson 2017 Acquisitions. During the nine months ended September 30, 2017, we closed on multiple transactions to acquire oil and natural gas producing and non-producing properties from third parties in Burleson County, Texas for approximately $19.3 million, of which $11.6 million was allocated to unproved oil and natural gas properties.  

2016 Acquisitions

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

 

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Supplemental Pro forma Information.  The following unaudited pro forma combined results of operations are provided for the three months and nine months ended September 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.

 

 

Note 4. Fair Value Measurements of Financial Instruments

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

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The carrying values of cash and cash equivalents, restricted cash, accounts receivables, accounts payables (including accrued liabilities) and amounts outstanding under long-term debt agreements with variable rates included in the accompanying balance sheets approximated fair value at September 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 September 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 September 30, 2017 and December 31, 2016 for each of the fair value hierarchy levels:

 

 

 

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

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

Note 5. Risk Management and Derivative Instruments

We have entered into certain derivative arrangements with respect to portions of our oil and natural gas production to reduce our sensitivity to volatile commodity prices. None of our derivative instruments are designated as cash flow hedges. We believe that these derivative arrangements, although not free of risk, allow us to achieve more predictable cash flows and to reduce exposure to commodity price fluctuations. However, derivative arrangements limit the benefit of increases in the prices of oil and natural gas sales. Moreover, our derivative arrangements apply only to a portion of our production and provide only partial protection against declines in commodity prices. Such arrangements may expose us to risk of financial loss in certain circumstances. We continuously reevaluate our risk management program in light of changes in production, market conditions, commodity price forecasts, capital spending, interest rate forecasts and debt service requirements.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Commodity Derivatives

We have fixed price commodity swaps, basis swaps, collars and deferred purchased puts to accomplish our hedging strategy. Through our basis swap instruments, we receive a fixed price differential and pay a variable price differential to the contract counterparty.  Collars consist of a sold call and a purchased put that establish a ceiling and floor price for expected future oil and natural gas sales. We recognize all derivative instruments at fair value; however, certain of our derivative instruments have a deferred premium. The deferred premium is factored into the fair value measurement and where the Company agrees to defer the premium paid or received until the time of settlement. Cash received on settled derivative positions during the three and nine months ended September 30, 2017 is net of deferred premiums of $1.5 million and $2.1 million, respectively.

Derivative instruments are netted when the right to net exists under a master netting agreement, future liabilities and assets correspond to the same commodity type and future cash flows have the same balance sheet current or non-current classification. We have exposure to financial institutions in the form of derivative transactions. These transactions are with counterparties in the financial services industry, certain of which are also lenders under 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 September 30, 2017 we had net derivative assets of $7.5 million. Had certain counterparties failed completely to perform according to the terms of existing contracts, we would have the right to offset $9.1 million against amounts outstanding under our revolving credit facility, thereby eliminating any credit exposure.

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

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

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

  

Balance Sheet Presentation

The following table summarizes both: (i) the gross fair value of derivative instruments by the appropriate balance sheet classification even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the balance sheet and (ii) the net recorded fair value as reflected on the balance sheet at September 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. 

 

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

(Gains) & Losses on Derivatives

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

 

 

Note 6. Accounts Receivable

Accounts receivable consist of the following (in thousands):

 

 

Note 7. Accrued Liabilities

Accrued liabilities consist of the following (in thousands):

 

 

Note 8. Asset Retirement Obligations

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

 

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

 

Note 9. Long Term Debt

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

 

 

On September 29, 2017, we cancelled our standby letters of credit of $1.9 million, which had reduced the available borrowing capacity under our revolving credit facility. 

Borrowing Base

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

 

 

  Amendment to Credit Agreement

On June 30, 2017, the Company, each of the Company’s wholly owned subsidiaries (each as a guarantor), Wells Fargo Bank National Association, as administrative agent (the “Administrative Agent”), and the lenders party thereto entered into a Second Amendment (the “Second 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 Second Amendment, among other things, modified the Credit Agreement to (i) permit the Company to enter into the Acquisition, and the Preferred Stock Purchase Agreement, and perform its obligations under and in connection therewith, including the issuance of the Preferred Stock (see Note 10), (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.

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

2025 Senior Notes

On February 1, 2017, we completed a private placement of $350.0 million aggregate principal amount of 6.875% senior unsecured notes due 2025 (the “2025 Senior Notes”).  The 2025 Senior Notes were issued at a price of 99.244% of par and resulted in net proceeds of approximately $338.6 million.  In addition, on September 19, 2017, we completed another private placement of $150.0 million aggregate principal amount of the 2025 Senior Notes issued at 98.26% of par and resulted in net proceeds of $144.7 million. The September 2017 issuance is treated as a single class of debt with the other outstanding 2025 Senior Notes.   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

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

fully and unconditionally guaranteed on a joint and several basis by all of our existing and certain future subsidiaries (subject to customary release provisions).  We have no material assets or operations which are independent of our existing subsidiaries.   There are no restrictions on the ability of the Company to obtain funds from its subsidiaries through dividends or loans.  The net proceeds from 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.

In connection with the issuance and sale of the 2025 Senior Notes in each of February and September of 2017, the Company and our subsidiary guarantors entered into a registration rights agreement (the “Registration Rights Agreements”) with a representative of the initial purchasers of the 2025 Senior Notes, dated February 1, 2017 and September 19, 2017, respectively. Pursuant to the Registration Rights Agreements, we agreed to file a registration statement with the Securities and Exchange Commission (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.

Weighted-Average Interest Rates

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

 

 

Unamortized Debt Issuance Costs

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

 

 

Note 10. Preferred Stock

Preferred Stock Issuance

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

 

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WILDHORSE RESOURCE DEVELOPMENT CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

 

The Preferred Stock ranks senior to our common stock with respect to dividend rights and with respect to rights on liquidation, winding-up and dissolution. The Preferred Stock has an initial Accreted Value (as defined in the Certificate of Designations 6.00% Series A Perpetual Convertible Preferred Stock (the “Certificate”)) of $1,000 per share and is entitled to a dividend at a rate of 6% per annum on the Accreted Value payable in cash if, as and when declared by our board of directors. If a cash dividend is not declared and paid in respect of any dividend payment period, then the Accreted Value of each outstanding share of Preferred Stock will automatically be increased by the amount of the dividend otherwise payable for such dividend payment period. Any increase in the Accreted Value will, among other things, increase the number of shares of common stock issuable upon conversion of each share of Preferred Stock. The Preferred Stock also participates in dividends and distributions on our common stock on an as-converted basis. If at any time following December 30, 2019, the closing sale price of our common stock equals or exceeds 130% of the Conversion Price (as defined below) for at least 25 consecutive trading days, our obligation to pay dividends on the Preferred Stock shall terminate permanently.

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

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

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

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

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

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

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Preferred Stock Dividend – Payment In Kind

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

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

 

Note 11. Equity

Common Stock

The Company’s authorized capital stock includes 500,000,000 shares of common stock, $0.01 par value per share. The following is a summary of the changes in our common stock issued for the nine months ended September 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 during the nine months ended September 30, 2017. Restricted shares of common stock are considered issued and outstanding on the grant date of the restricted stock award.

Previous Owner Equity

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

Predecessor Equity

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

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Note 12. Earnings Per Share

The following sets forth the calculation of earnings (loss) per share, or EPS, for the three and nine months ended September 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.  

 

 

Note 13. Long Term Incentive Plans

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

 

 

For the three and nine months ended September 30, 2017, we recorded $2.4 million and $4.2 million of recognized compensation expense, respectively, associated with these awards.  Unrecognized compensation cost associated with the restricted common stock awards was an aggregate of $24.1 million at September 30, 2017.  We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 2.58 years.

Note 14. Incentive Units

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

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WILDHORSE RESOURCE DEVELOPMENT CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

In connection with the Corporate Reorganization, the WHR II incentive units were transferred to WildHorse Investment Holdings in exchange for substantially similar 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 September 30, 2017.  As such, no compensation expense was recognized by us.  Unrecognized compensation costs associated with these incentive units was $21.8 million at September 30, 2017.

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

 

 

Note 15. Related Party Transactions

Board of Directors Relationships

Mr. Grant E. Sims has served as a member of our board of directors since February 2017. Mr. Sims has served as a director and Chief Executive Officer of the general partner of Genesis Energy Partners, L.P. (“Genesis”) since August 2006 and Chairman of the board of directors of the general partner since October 2012. Genesis is one of our purchasers of hydrocarbons and other liquids. During the three and nine months ended September 30, 2017, we received $0.5 million and $1.9 million, respectively, from Genesis.  

NGP Affiliated Companies

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

NGP ECM.  During the three and nine months ended September 30, 2017, we had net disbursements of less than $0.1 million and $0.1 million, respectively, related to expense reimbursements associated with their services as directors of WRD.  During the three and nine months ended September 30, 2016, our predecessor paid less than $0.1 million and $0.1 million, respectively, for director fees.

Highmark Energy Operating, LLC.  During both the three and nine months ended September 30, 2017, we had net disbursements of less than $0.1 million to 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 nine months ended September 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 nine months ended September 30, 2017, we made payments of $0.1 million and $0.2 million, respectively, to Cretic Energy Services, LLC, a NGP affiliated company, for services related to our drilling and completion activities. We recorded payments of $0.4 million for the nine months ended September 30, 2016 and no transactions for the three months ended September 30, 2016.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

PennTex Midstream Partners, LP. During the three and nine months ended September 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 the three and nine months ended September 30, 2016, we paid net payments of less than $0.1 million and $0.1 million, respectively, 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, one of our directors, is President of these entities.  During both the three and nine months ended September 30, 2017 we had net disbursements of $0.1 million 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 nine months ended September 30, 2016.

Garland Exploration LLC.  During the nine months ended September 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 nine months ended September 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 nine months ended September 30, 2016. 

Previous Owner Related Party Transactions

Notes payable to members.  During the three and nine months ended September 30, 2016, Esquisto accrued $1.1 million and $3.2 million, respectively, as general and administrative expenses payable to its members. In connection with our initial public offering, the Esquisto notes payable to its members were paid off.

Services provided by member.  Esquisto paid Calbri Energy, Inc. (“Calbri”), a less than 1% former owner, $0.6 million and $0.8 million for the three and nine months ended September 30, 2016, respectively, for completion consulting services.  

Operator. Esquisto paid PetroMax Operating Co., Inc. (“Petromax”), who was the operator of the majority of Esquisto’s wells, $0.3 million and $0.9 million during the three and nine months ended September 30, 2016, respectively, for overhead charges on drilling and producing wells at market rates as set forth in joint operating agreements and in accordance with an operating agreement between Petromax and Esquisto. Petromax is owned 33.3% by Mike Hoover, the former Chief Operating Officer of Esquisto, who also indirectly owned one of the former members of Esquisto.  

Related Party Agreements

Stockholders’ Agreement

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

Registration Rights Agreement

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

Transition Services Agreement

Upon the closing of our initial public offering, we entered into a transition services agreement with CH4 Energy IV, LLC, Petromax and Crossing Rocks Energy, LLC (collectively, the “Service Providers”), pursuant to which the Service Providers agreed to

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WILDHORSE RESOURCE DEVELOPMENT CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

provide certain engineering, land, operating and financial services to us for six months relating to our Eagle Ford Acreage. In exchange for such services, we agreed to pay a monthly management fee to the Service Providers.  NGP and certain former management members of Esquisto own the Service Providers.  The transition service agreement was terminated on March 31, 2017 and we, therefore, did not have any payments during the three months ended September 30, 2017.  During the nine months ended September 30, 2017, we paid the Service Providers $0.1 million.

Note 16. Segment Disclosures

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

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

 

 

Note 17. Income Taxes

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

The Company recorded an income tax benefit of $5.6 million and expense of $21.2 million for the three and nine months ended September 30, 2017, respectively, compared to income tax expense of $0.2 million and $0.5 million for the three and nine months ended September 30, 2016, respectively. The tax benefit of $5.6 million was primarily a result of the pretax loss reported for the three months ended September 30, 2017.  The increase in income tax expense for the nine months ended September 30, 2017 was primarily a result of being a corporation subject to federal and state income taxes subsequent to our initial public offering. The effective tax rates for the three and nine months ended September 30, 2017 were 34.3% and 37.2%, respectively, compared to approximately 6.1% and (1.6)% for the three and nine months ended September 30, 2016, respectively. The effective tax rate differed from the statutory federal income tax rate during the three and nine months ended September 30, 2017 primarily due to the impact of state income tax as well as a result of changes in estimates related to a prior-period tax provision.  The effective tax rate differed from the statutory federal income tax rate during the three and nine months ended September 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 September 30, 2017 and expects no significant change to the unrecognized tax benefits in the next twelve months.

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WILDHORSE RESOURCE DEVELOPMENT CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Note 18. Commitments and Contingencies

Litigation & Environmental

We are party to various ongoing and potential legal actions relating to our entitled ownership interests in certain properties. We evaluate the merits of existing and potential claims and accrue a liability for any that meet the recognition criteria and can be reasonably estimated. We did not recognize any liability as of September 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 September 30, 2017 and December 31, 2016.

Firm Gas Transportation Service Agreement

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

Letters of Credit and Certificate of Deposit

In accordance with state regulatory requirements, we had standby letters of credit that were cash collateralized by certificates of deposits at both September 30, 2017 and December 31, 2016.  The fair value of the certificates of deposits were $0.5 million and $0.9 million at September 30, 2017 and December 31, 2016, respectively, and were recorded on our balance sheet as restricted cash.  Additionally, we cancelled a standby letter of credit of $1.9 million on September 29, 2017 (see Note 9) and replaced it with a surety bond.

Dedicated Fracturing Fleet Services Agreements

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

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

Interruptible Water Availability Agreement

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

 

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WILDHORSE RESOURCE DEVELOPMENT CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

 

Note 19. Subsequent Events

Third Amendment to the Credit Agreement

Please see Note 9 for information regarding the Third Amendment to the Credit Agreement, dated as of October 4, 2017, including information regarding the redetermination of our borrowing base.

October Preferred Stock Dividend – Payment In Kind

Please see Note 10 for information regarding the declared aggregate quarterly dividend on our Preferred Stock.

Exchange Offer

The Company’s Registration Statement on Form S-4 registering an aggregate of $500.0 million of 2025 Senior Notes to be offered in exchange for the currently outstanding 2025 Senior Notes, which have not been registered under the Securities Act, was declared effective on October 12, 2017. The exchange offer for the 2025 Senior Notes commenced on October 13, 2017 and is expected to expire on November 13, 2017.

 

 

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

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

Overview

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

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

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

Recent Developments

APC/KKR Acquisition

On May 10, 2017, we, through our new wholly owned subsidiary, WHR Eagle Ford LLC (“WHR EF”),  entered into a Purchase and Sale Agreement (the “First Acquisition Agreement”) by and among WHR EF, as purchaser, and Anadarko E&P Onshore LLC (“APC”), Admiral A Holding L.P., TE Admiral A Holding L.P. and Aurora C-I Holding L.P. (collectively, “KKR” and, together with APC, the “First Sellers”), as sellers, to acquire certain 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 of approximately 111,000 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 portion of the Purchase price payable to KKR was issued pursuant to a Stock Issuance Agreement that was executed, on May 10, 2017 (the “Stock Issuance Agreement”), by and among us and KKR.

Preferred Stock Issuance

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

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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 6.00% Series A Perpetual Convertible Preferred Stock (the “Certificate”)) of $1,000 per share and is entitled to a dividend at a rate of 6% per annum on the Accreted Value payable in cash if, as and when declared by our board of directors. If a cash dividend is not declared and paid in respect of any dividend payment period, then the Accreted Value of each outstanding share of Preferred Stock will automatically be increased by the amount of the dividend otherwise payable for such dividend payment period. Any increase in the Accreted Value 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.

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

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Amendment to Credit Agreement

On June 30, 2017, the Company, each of the Company’s wholly owned subsidiaries (each as a guarantor), Wells Fargo Bank, National Association, as administrative agent (the “Administrative Agent”), and the lenders party thereto entered into a second amendment (the “Second 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 Second Amendment, among other things, modified the Credit Agreement to (a) permit the Company to enter into the Acquisition, and the Preferred Stock Purchase Agreement, and perform its obligations under and in connection therewith, including the issuance of the Preferred Stock, (b) increase the Company’s borrowing base and elected commitment amount from $450 million to $650 million, (c) increase the annual cap on certain restricted payments from $50 million to $75 million, and (d) modify the definition of net debt so that certain contingent obligations, accounts payable, obligations to make deliveries in respect of advance payments, take or pay obligations, disqualified capital stock and obligations in respect of production payments are excluded from net debt for purposes of the Company’s leverage covenant.

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

2025 Senior Notes

On February 1, 2017, we completed a private placement of $350.0 million aggregate principal amount of 6.875% senior unsecured notes due 2025 (the “2025 Senior Notes”).  The 2025 Senior Notes were issued at a price of 99.244% of par and resulted in net proceeds of approximately $338.6 million.  In addition, on September 19, 2017, we completed a private placement of $150.0 million aggregate principal amount of the 2025 Senior Notes issued at 98.26% of par and resulted in net proceeds of $144.7 million. The September 2017 issuance is treated as a single class of debt with the other outstanding 2025 Senior Notes.   The 2025 Senior Notes will mature on February 1, 2025 and interest is payable on February 1 and August 1 of each year.  The 2025 Senior Notes are fully and unconditionally guaranteed on a joint and several basis by all of our existing and certain future subsidiaries (subject to customary release provisions).  We have no material assets or operations which are independent of our existing subsidiaries.   There are no restrictions on the ability of the Company to obtain funds from its subsidiaries through dividends or loans.  The net proceeds from the 2025 Senior Notes were used to repay borrowings outstanding under our revolving credit facility and for general corporate purposes.

Eagle Ford Acquisitions

During the nine months ended September 30, 2017, we closed on multiple transactions to acquire oil and natural gas producing and non-producing properties from third parties in Burleson County, Texas for approximately $19.3 million, of which $11.6 million was allocated to unproved oil and natural gas properties.  

Sources of Our Revenues

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

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

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Principal Components of Cost Structure

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

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.

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Critical Accounting Policies and Estimates

Preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about carrying values of assets and liabilities that are not readily apparent from other sources.

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

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

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Results of Operations

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

Factors Affecting the Comparability of the Combined Historical Financial Results

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

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.

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

  

 

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

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

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Nine Months Ended September 30, 2017 Compared to the Nine Months Ended September 30, 2016

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

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Calculation of Adjusted EBITDAX

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

We define Adjusted EBITDAX as Net income (loss):

Plus:

Less:

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

Reconciliation of Net Income to Adjusted EBITDAX

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

  

Liquidity and Capital Resources

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

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

As of September 30, 2017, we had $5.4 million of cash and cash equivalents and $454.0 million of available borrowings under our revolving credit facility. As of September 30, 2017, we had a working capital deficit of $99.1 million primarily due to the accrual of capital expenditures. As of September 30, 2017, the borrowing base under our Credit Agreement was $612.5 million and we had outstanding borrowings of $158.5 million.

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On October 4, 2017, the Company, each of the Company’s wholly owned subsidiaries (each as a guarantor), the Administrative Agent, and the lenders party thereto entered into the Third Amendment to the Credit Agreement, which, among other things, increased the borrowing base from $612.5 million to $875.0 million. The borrowing base under our revolving credit facility is subject to redetermination on at least a semi-annual basis based on an engineering report with respect to our estimated oil and natural gas reserves, which will take into account the prevailing oil and natural gas prices at such time, as adjusted for the impact of our commodity derivative contracts. Unanimous approval by the lenders is required for any increase to the borrowing base.  The next scheduled borrowing base redetermination is set for April 2018. 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.

Preferred Stock

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

Capital Expenditure Budget

We established a 2017 drilling and completion capital expenditure budget of $550.0 million to $675.0 million. For the nine months ended September 30, 2017, our drilling and completion expenditures were approximately $481.8 million primarily related to the development of our Eagle Ford properties.

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 Second Amendment to the Credit Agreement.

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

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

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 September 30, 2017.

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

2025 Senior Notes

In February 2017, we completed a private placement of $350.0 million of the 2025 Senior Notes, issued at 99.244% of par and resulted in net proceeds of $338.6 million.  In addition, in September 2017, we completed another private placement of $150.0 million

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aggregate principal amount of the 2025 Senior Notes issued at 98.26% of par and resulted in net proceeds of $144.7 million. We used the net proceeds from both issuances to repay the borrowings outstanding under our revolving credit facility and for general corporate purposes, including funding a portion of our 2017 capital expenditures. The September 2017 issuance is treated as a single class of debt with the February 2017 issuance.  The 2025 Senior Notes are governed by an indenture dated as of February 1, 2017, mature on February 1, 2025 and are fully and unconditionally guaranteed on a joint and several basis by all of our existing and certain future subsidiaries (subject to customary release provisions).  We have no material assets or operations that are independent of our existing subsidiaries.   There are no restrictions on the ability of the Company to obtain funds from its subsidiaries through dividends or loans.  The 2025 Senior Notes accrue interest at 6.875% per annum and payable semi-annually in arrears on February 1 and August 1 of each year.  On August 1, 2017, we made a $12.0 million interest payment on the 2025 Senior Notes.

See “Note 9—Long Term Debt” of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under “Item 1. Financial Statements” of this Quarterly Report for additional information regarding the 2025 Senior Notes.

Commodity Derivative Contracts

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

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

Counterparty Exposure

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

Cash Flows from Operating, Investing and Financing Activities

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

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

  

Nine Months Ended September 30, 2017 Compared to the Nine Months Ended September 30, 2016

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

Operating Activities. Net cash provided by operating activities was $143.2 million for 2017, compared to $24.3 million of net cash provided by operating activities for 2016. Production increased 3.0 MMBoe (approximately 76%) and average realized sales prices increased to $35.08 per Boe for 2017 compared to $21.74 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 also impacted by higher G&A expenses and LOE due to the growth of the Company.  Net cash provided by operating activities included $6.9 million of cash receipts on derivative instruments during 2017 compared to $6.1 million in cash receipts during 2016.  There was a $9.2 million increase in cash flow attributable to the timing of cash receipts and disbursements related to operating activities during 2017 compared to 2016.  

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Investing Activities. During 2017 and 2016, cash flows used in investing activities were $1.0 billion and $98.8 million, respectively.  Acquisitions of oil and gas properties were $549.0 million and $10.9 million during 2017 and 2016, respectively. See “—Recent Developments” for additional information on the Acquisition.  Additions to oil and gas properties were $443.2 million during 2017 primarily related to our land leasing activities and drilling and completion activities in the Eagle Ford.  Additions to oil and gas properties were $84.8 million during 2016, of which $69.9 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.  Additions to and acquisitions of other property and equipment were $10.1 million during 2017 primarily related to Oakfield and Burleson Water infrastructure projects and $3.0 million during 2016.  

Financing Activities. Net cash provided by financing activities during 2017 of $861.0 million was primarily attributable to $432.3 million in net proceeds from the issuance of our Preferred Stock, $494.7 million in proceeds from the issuance of our 2025 Senior Notes, $363.5 million in advances on our revolving credit facilities and $34.5 million from the partial exercise of the underwriters’ over-allotment option in connection with our initial public offering. These cash inflows were offset by payments under our revolving credit facilities of $447.8 million during 2017, debt issuance costs of $13.5 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 primarily pay down our revolver.  Amounts borrowed under our revolver funded our lease acquisition and drilling programs, activities related to Oakfield and Burleson Water infrastructure projects and our working capital needs.

Net cash provided by financing activities of $32.9 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 $4.5 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 $0.7 million. Costs associated with Esquisto’s termination of its second lien were $0.2 million.

Contractual Obligations

During the nine months ended September 30, 2017, there were no significant changes in our consolidated contractual obligations from those reported in our 2016 Form 10-K filed except for the additions of two long-term dedicated fracturing fleet services agreements and an interruptible water availability agreement all of which were entered into as part of our ordinary course of business. For more information see “Note 18—Commitments and Contingencies” of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under “Item 1. Financial Statements” of this Quarterly Report. Additionally, we had $158.5 million outstanding under our revolving credit facility at September 30, 2017 compared to $242.8 million at December 31, 2016. As previously discussed, our 2025 Senior Notes were issued in February 2017 and September 2017. See “Note 9—Long Term Debt” of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under “Item 1. Financial Statements” of this Quarterly Report for additional information on our indebtedness.

Off–Balance Sheet Arrangements

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

Recently Issued Accounting Pronouncements

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

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Commodity Price Risk

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

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 September 30, 2017, see “Note 5—Risk Management and Derivative Instruments” of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under “Item 1. Financial Statements” of this Quarterly Report.

Interest Rate Risk

At September 30, 2017, we had $158.5 million outstanding under our revolving credit facility. We do not currently have any derivative arrangements to protect against fluctuations in interest rates applicable to indebtedness we may incur but may enter into such derivative arrangements in the future. To the extent we enter into any such interest rate derivative arrangement, we would be subject to risk for financial loss.

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

  

Counterparty and Customer Credit Risk

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

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

In addition, our derivative contracts expose us to credit risk in the event of nonperformance by counterparties. While we do not require counterparties to our derivative contracts to post collateral, we do evaluate the credit standing of such counterparties as we deem appropriate. Each of the counterparties to our derivative contracts currently in place has an investment grade rating. See “Note 5—Risk Management and Derivative Instruments” of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under “Item 1. Financial Statements” of this Quarterly Report for additional information regarding credit risk associated with our derivative instruments.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures.

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

 

 

 

 

 

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Changes in Internal Controls Over Financial Reporting

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

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

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PART II—OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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

ITEM 1A.  RISK FACTORS

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

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

We did not have any sales of unregistered securities during the three months ended September 30, 2017.

None.

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

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5. OTHER INFORMATION

None.

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ITEM 6. EXHIBITS

 

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SIGNATURES

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

 

 

 

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