Attached files

file filename
EX-23.2 - EX-23.2 - CONSENT OF ERNST & YOUNG LLP - WildHorse Resource Development Corpwrd-ex232_8.htm
EX-99.1 - EX-99.1 REPORT OF CAWLEY, GILLESPIE AND ASSOCIATES, INC. - WildHorse Resource Development Corpwrd-ex991_198.htm
EX-32.1 - EX-32.1 - CERTIFICATIONS OF CEO AND CFO - WildHorse Resource Development Corpwrd-ex321_39.htm
EX-31.2 - EX-31.2 - CERTIFICATION OF CHIEF FINANCIAL OFFICER - WildHorse Resource Development Corpwrd-ex312_38.htm
EX-31.1 - EX-31.1- CERTIFICATION OF CHIEF EXECUTIVE OFFICER - WildHorse Resource Development Corpwrd-ex311_40.htm
EX-23.3 - EX-23.3 - CONSENT OF CAWLEY, GILLESPIE AND ASSOCIATES, INC. - WildHorse Resource Development Corpwrd-ex233_10.htm
EX-23.1 - EX-23.1 - CONSENT OF KPMG - WildHorse Resource Development Corpwrd-ex231_6.htm
EX-21.1 - EX-21.1 - SUBSIDIARIES OF WILDHORSE RESOURCE DEVELOPMENT CORPORATION - WildHorse Resource Development Corpwrd-ex211_7.htm
EX-4.6 - EX-4.6 - SECOND SUPPLEMENTAL INDENTURE - WildHorse Resource Development Corpwrd-ex46_52.htm

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

Form 10-K

 

(Mark One)

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

For the fiscal year ended December 31, 2017

OR

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

Commission File Number: 001-37964

 

WildHorse Resource Development Corporation

(Exact name of Registrant as specified in its Charter)

 

 

Delaware

 

81-3470246

(State or other jurisdiction of incorporation or organization)

 

(I.R.S. Employer Identification No.)

 

 

 

9805 Katy Freeway, Suite 400, Houston, TX

 

77024

(Address of principal executive offices)

 

(Zip Code)

 

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

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

 

Common Stock, par value $0.01 per share

 

New York Stock Exchange

(Title of each class)

 

(Name of each exchange on which registered)

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

 

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

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

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

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

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

 

Large accelerated filer

 

 

Accelerated filer

 

 

 

 

 

 

Non-accelerated filer

(Do not check if a small reporting company)

 

Small reporting company

 

 

 

 

 

 

 

 

 

 

Emerging growth company

 

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

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

The aggregate market value of the 21,438,051 shares of voting stock held by non-affiliates of the registrant, based upon the closing sale price of the registrant’s common stock on June 30, 2017, the last business day of the registrant’s most recently completed second fiscal quarter, of $12.37 per share as reported on the New York Stock Exchange was $265.2 million.  Shares of common stock held by each director and executive officer and by each person who owns 10 percent or more of the outstanding common stock or who is otherwise believed by the registrant to be in a control position have been excluded.  This determination of affiliate status is limited to this calculation and is not intended to be determinative for any other purpose.

As of February 28, 2018, the registrant had 101,304 ,079 shares of common stock, $0.01 par value outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

The Company’s definitive proxy statement relating to the annual meeting of shareholders (to be held May 17, 2018) will be filed with the Securities and Exchange Commission within 120 days after the close of the Company’s fiscal year ended December 31, 2017 and is incorporated by reference in Part III to the extent described herein.

 

 

 


 

WILDHORSE RESOURCE DEVELOPMENT CORPORATION

TABLE OF CONTENTS

 

 

 

 

 

Page

 

 

PART I

 

 

Item 1.

 

Business

 

10

Item 1A.

 

Risk Factors

 

31

Item 1B.

 

Unresolved Staff Comments

 

52

Item 2.

 

Properties

 

52

Item 3.

 

Legal Proceedings

 

52

Item 4.

 

Mine Safety Disclosures

 

52

 

 

 

 

 

 

 

PART II

 

 

Item 5.

 

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

 

53

Item 6.

 

Selected Financial Data

 

55

Item 7.

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

57

Item 7A.

 

Quantitative and Qualitative Disclosures About Market Risk

 

75

Item 8.

 

Financial Statements and Supplementary Data

 

78

Item 9.

 

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

 

78

Item 9A.

 

Controls and Procedures

 

79

Item 9B.

 

Other Information

 

79

 

 

 

 

 

 

 

PART III

 

 

Item 10.

 

Directors, Executive Officers and Corporate Governance

 

80

Item 11.

 

Executive Compensation

 

80

Item 12.

 

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

 

80

Item 13.

 

Certain Relationships and Related Transactions, and Director Independence

 

80

Item 14.

 

Principal Accounting Fees and Services

 

80

 

 

 

 

 

 

 

PART IV

 

 

Item 15.

 

Exhibits and Financial Statement Schedules

 

81

Item 16.

 

Form 10-K Summary

 

84

 

 

 

 


 

GLOSSARY OF OIL AND NATURAL GAS TERMS

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

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 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.

2


 

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 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.

3


 

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.

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).

4


 

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

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

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

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

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

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

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

Unproved properties: Properties with no proved reserves.

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

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

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

WTI: West Texas Intermediate.


5


 

Commonly Used Defined Terms

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

 

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

 

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

 

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

 

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

 

“Esquisto I” refers to Esquisto Resources, LLC;

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

6


 

 

“Terryville Complex” refers to the play located primarily in Lincoln Parish, Louisiana, and northern Jackson Parish, Louisiana;

 

“RCT Area” refers to our Ruston-Choudrant-Tremont acreage within the Terryville Complex located primarily in Lincoln Parish, Louisiana;

 

“Weyerhaeuser Area” refers to the acreage that we have the right to lease within the Terryville Complex located in northern Jackson Parish, Louisiana, which acreage is included in our North Louisiana acreage in this Annual Report (see “Business—Development of Proved Undeveloped Reserves—Acreage);

 

“Eagle Ford Acreage” refers to our acreage in the northern area of the Eagle Ford Shale in East Texas, which has historically been owned and operated by Esquisto;

 

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

 

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

 

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

 

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

 

 

 

7


 

FORWARD–LOOKING STATEMENTS

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

Forward-looking statements may include statements about:

 

our business strategy;

 

our estimated proved, probable and possible reserves;

 

our drilling prospects, inventories, projects and programs;

 

our ability to replace the reserves we produce through drilling and property acquisitions;

 

our financial strategy, liquidity and capital required for our development program;

 

our realized oil, natural gas and NGL prices;

 

the timing and amount of our future production of oil, natural gas and NGLs;

 

our hedging strategy and results;

 

our future drilling plans;

 

competition and government regulations;

 

our ability to obtain permits and governmental approvals;

 

pending legal or environmental matters;

 

our marketing of oil, natural gas and NGLs;

 

our leasehold or business acquisitions;

 

costs of developing our properties;

 

general economic conditions;

 

credit markets;

 

uncertainty regarding our future operating results;

 

the consummation of the NLA Divestiture (as defined below); and

 

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

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

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

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

 

8


 

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

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

9


 

PART I

ITEM 1.

BUSINESS

Overview

WildHorse Resource Development Corporation (the “Company”) is a Delaware corporation, the common stock, par value $0.01 per share, of which are listed on the New York Stock Exchange (“NYSE”) under the symbol “WRD.”  We completed our initial public offering on December 19, 2016.

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 East Texas and North Louisiana with multiple producing stratigraphic horizons, or stacked pay zones, and attractive single-well rates of return. In East Texas, we primarily operate in Burleson, Lee and Washington Counties where we primarily target the Eagle Ford Shale. In North Louisiana, we have historically operated in and around the highly prolific Terryville Complex, where we primarily targeted the overpressured Cotton Valley play. Following the NLA Divestiture (as defined below), our operations will be focused exclusively in East Texas, though all references to our assets and operations in this Annual Report do not give effect to the NLA Divestiture unless otherwise specified.

As of December 31, 2017, we had assembled a total leasehold position of approximately 585,941 gross (477,153 net) acres across our expanding acreage, including approximately 460,000 gross (387,091 net) acres in the Eagle Ford and approximately 125,941 gross (90,062 net) acres in North Louisiana. We have identified a total of approximately 6,069 gross (3,739 net) drilling locations across our acreage. For the year ended December 31, 2017, approximately 80%, 14% and 5% of our revenues were attributable to oil, natural gas and NGLs, respectively.

Recent Developments

Acquisition of Lee County Properties

On March 1, 2018, we through our wholly owned subsidiary WHR Eagle Ford LLC (“WHR EF”), closed on our acquisition of producing and non-producing properties in Lee County, Texas for approximately $18.6 million from an undisclosed seller. The properties consist of approximately 17,500 net acres immediately contiguous to our existing Eagle Ford properties and one operated (four non-operated) producing horizontal wells.

Pending Divestiture of North Louisiana Assets

        On February 12, 2018, WHR II entered into a Purchase and Sale Agreement with Tanos Energy Holdings III, LLC (“Tanos”) for the sale of all of our producing and non-producing oil and natural gas properties (including Oakfield), primarily located in Webster, Claiborne, Lincoln, Jackson and Ouachita Parishes, Louisiana (“NLA Assets”) for a total sales price of approximately $217.0 million (the “NLA Divestiture”), subject to customary purchase price adjustments.  The NLA Assets consist of all of our assets in our North Louisiana Acreage.  In addition, WRD could receive contingent payments of up to $35.0 million based on the number of wells spud over the next four years.  The effective date of the proposed sale is January 1, 2018, and we expect to close the transaction by the end of March 2018. The NLA Assets include approximately 90,000 net acres.  As of December 31, 2017, estimated proved reserves from these properties were approximately 68.7 MMBoe, or 15% of our estimated year-end 2017 proved reserves. The sale includes approximately 620 gross (356.8 net) wells that produced approximately 7.2 MBoe/d (96% gas) for the year ended December 31, 2017.  Our well count on these properties consisted of 473 gross (346.1 net) operated wells and 147 gross (10.7 net) non-operated wells.

        The sales price is subject to adjustments for (i) operating expenses, capital expenditures and revenues between the effective date and the closing date, (ii) title, casualty and environmental defects, and (iii) other purchase price adjustments customary in oil and gas purchase and sale agreements. Pursuant to the terms of the Purchase and Sale Agreement, Tanos paid WHR II a deposit of $21.7 million at signing, which amount will be applied to the sales price if the transaction closes.

        The completion of the NLA Divestiture is subject to customary closing conditions. The parties may terminate the Purchase and Sale Agreement by mutual written consent or if certain closing conditions have not been satisfied, if total adjustments to the sales price exceed 20% of the sales price, or approximately $43 million, or the transaction has not closed on or before April 30, 2018. If one or more of the closing conditions are not satisfied, or if the transaction is otherwise terminated, the divestiture may not be completed. There can be no assurance that we will sell the NLA Assets on the terms or timing described or at all. If the NLA Divestiture closes, we intend to use the net proceeds to repay amounts outstanding under our credit facility and for general corporate purposes. Please see Item 1A “Risk Factors—Risks Related to our Business—Our pending NLA Divestiture may not be consummated.”

Development of In-field Sand Mine

On February 12, 2018, we announced that Burleson Sand LLC, a wholly owned subsidiary had previously acquired surface and sand rights on approximately 727 acres in Burleson County, Texas to construct and operate an in-field sand mine.  We expect that the

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total capital expenditure for the full development of the sand mine will be approximately $65.0 - $75.0 million in 2018, which includes the property acquisition and third-party engineering studies.

North Louisiana Settlement

On February 1, 2018, we settled a dispute related to a possible area of mutual interest (“AMI”) associated with our North Louisiana properties with a third party.  This settlement is referred to as the “North Louisiana Settlement.”  See Note 21 under “Item 8. Financial Statements and Supplementary Data” for additional information regarding the North Louisiana Settlement.

Tax Reform Legislation

On December 22, 2017, the United States ("U.S.") government enacted Public Law No. 115-97, commonly referred to as the Tax Cuts and Jobs Act (the “Tax Act”), which made significant changes to U.S. federal income tax law. We expect that certain aspects of these changes will positively impact our future after-tax earnings primarily due to the lower federal statutory income tax rate. We were required to recognize the effect of this rate change on our deferred tax assets and liabilities in 2017, the period the tax rate change was enacted. Key aspects of the Tax Act include, but are not limited to, (i) establishing a flat corporate income tax rate of 21% to replace previous rates that ranged from 15% to 35% and eliminating the corporate alternative minimum tax (“AMT”); (ii) reducing the maximum deduction for net operating loss (“NOL”) carryforwards arising in tax years beginning after December 31, 2017 to 80% of the taxpayer’s taxable income, allowing any NOLs generated in tax years beginning after December 31, 2017 to be carried forward indefinitely, and generally repealing carrybacks; (iii) limiting the deduction for net interest expense; (iv) allowing businesses to immediately expense the cost of new investments in certain qualified depreciable assets acquired after September 27,  2017 (with a phase-down of such expensing starting in 2023); and (v) repealing the Section 199 domestic production deduction beginning in 2018.; The Tax Act did not include any changes with respect to the current option to expense Intangible Drilling Costs or the Percentage Depletion deduction. See Note 17 under “Item 8. Financial Statements and Supplementary Data” for additional information regarding our income taxes.

2017 Developments

APC/KKR Acquisition

On May 10, 2017, we, through our wholly owned subsidiary, WHR EF,  entered into a Purchase and Sale Agreement (the “First Acquisition Agreement”) by and among WHR EF, as purchaser, and Anadarko E&P Onshore LLC (“APC”), 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, 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. 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, by and among us and KKR.

Preferred Stock Issuance

We partially funded the Acquisition through the issuance of 435,000 shares of Preferred Stock in exchange for $435.0 million on June 30, 2017, pursuant to a Preferred Stock Purchase Agreement (the “Preferred Stock Purchase Agreement”), by and among us and CP VI Eagle Holdings, L.P. (the “Carlyle Investor”), an affiliate of The Carlyle Group, L.P.  See Note 10 under “Item 8. Financial Statements and Supplementary Data” for additional information regarding our preferred stock issuance.

Amendments 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”).

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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.  The Third Amendment, among other things, modified the Credit Agreement to (i) increase the aggregate maximum credit amount to $2.0 billion from $1.0 billion, (ii) increase the borrowing base from $612.5 million to $875.0 million and (iii) add additional lenders.

2025 Senior Notes Offering

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, which resulted in net proceeds of approximately $144.7 million. The notes issued in September 2017 are treated as a single class of debt securities with the 2025 Senior Notes issued in February 2017.   The 2025 Senior Notes will mature on February 1, 2025 and interest is payable on February 1 and August 1 of each year.  The 2025 Senior Notes are fully and unconditionally guaranteed on a joint and several basis by all of our existing and certain future subsidiaries (subject to customary release provisions).  We have no material assets or operations that are independent of our existing subsidiaries.   There are no restrictions on our ability to obtain funds from our subsidiaries through dividends or loans.  The net proceeds from each of the offerings of the 2025 Senior Notes were used to repay borrowings outstanding under our revolving credit facility and for general corporate purposes.

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

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

Exercise of Underwriters’ Over-allotment Option

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.

Our Properties

Eagle Ford Acreage

The Eagle Ford Shale is one of the most active unconventional shale trends in North America. According to weekly rig count metrics published by Baker Hughes, the Eagle Ford Shale has consistently been one of the most active basins in the United States since 2011 and currently has the second highest rig count of all major U.S. basins.  The Eagle Ford Shale trends across Texas from the Mexican border north into East Texas and is roughly 50 miles wide and 400 miles long. The Eagle Ford Shale rests between the Austin Chalk and the Buda Lime at a depth of approximately 4,000 to 14,000 feet. As of December 31, 2017, there were approximately 36,000 producing wells in the Eagle Ford with an average production of 2.1 MMBoe/d in December 2017.

We currently target a portion of the Eagle Ford Shale at depths between 6,000 feet and 13,000 feet primarily in Burleson, Lee, Brazos and Washington Counties, Texas. This portion of the Eagle Ford Shale averages 125 feet in thickness and contains 70% carbonate. We believe that the elevated carbonate percentages are in large part responsible for the brittleness of the Eagle Ford and successful completions which exhibit high productivity when fractured. The overall clay content of the Eagle Ford increases regionally as it continues progressively northeast into Brazos, Grimes and Madison Counties, Texas.

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

We entered the Eagle Ford with the goal of redeveloping the area with horizontal drilling and modern completion techniques. Since that time, we have completed multiple bolt-on acquisitions and in-fill leases to build our current position in the Eagle Ford.  We have identified a substantial inventory of 4,675 gross drilling locations within our Eagle Ford Acreage across Burleson, Brazos, Lee, Robertson and Washington Counties.  The wells in our Eagle Ford Acreage have shown a strong track record of increasing EURs and a decreasing trend in drilling and completion capital costs.  

As of December 31, 2017, our Eagle Ford position included approximately 387,091 net acres. Also, as of December 31, 2017, approximately 69% of our Eagle Ford Acreage was held by production, with an average working interest of 84%, and, as of December 31, 2017, 22% of our 385.6 MMBoe of proved reserves were developed, 88% of which were liquids. Since January 2014, we and our previous owner have drilled and completed 125 wells, acquired 878 wells and participated in 26 wells resulting in total net production of approximately 23.5 MBoe/d (76% oil, 10% natural gas and 14% NGLs), including non-operated production.

North Louisiana Acreage

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

Our North Louisiana Acreage spans across the Webster, Claiborne, Bienville, Lincoln, Jackson and Ouachita Parishes, focusing on the Bear Creek field and the RCT and Weyerhaeuser Areas, where we are targeting overpressured Cotton Valley opportunities in multiple zones. We believe the Terryville Complex, which has been producing since 1954, is one of North America’s most prolific liquids rich natural gas plays, characterized by high recoveries relative to drilling and completion costs, high initial production rates with high liquids yields, long reserve life, multiple stacked pay zones, available infrastructure and a large number of service providers. The RCT Area is a direct offset of the Terryville Field and is part of the same Terryville Complex trend. Following the NLA Divestiture, we do not expect to continue operating in this area.

As of December 31, 2017, our North Louisiana Acreage included approximately 90,000 net acres. Also, as of December 31, 2017, 58% of our acreage was then held by production, with an average working interest of 72%, and 41% of our 68.7 MMBoe of proved reserves were developed, 97% of which were natural gas. Since the inception of our predecessor, we had drilled and completed 18 wells, acquired 597 wells and participated in 5 non-operated wells resulting in a total 2017 net production of approximately 7.2 MBoe/d (2% oil, 96% natural gas and 2% NGLs), including non-operated production. 

On February 12, 2018, WHR II entered into a Purchase and Sale Agreement with Tanos for the sale of the NLA Assets for a total sales price of approximately $217.0 million before customary adjustments. The NLA Divestiture is expected to close by the end of March 2018.

 

 

 

 

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Reserve Summary

Our estimated proved reserves of were prepared by our internal reserve engineers and audited by Cawley, Gillespie and Associates, Inc. (“Cawley”), our independent reserve engineers.  As of December 31, 2017, we had 454.3 MMBoe of estimated proved reserves.  As of this date, our proved reserves were 75% oil and NGLs and 25% natural gas.  The following table provides summary information regarding our estimated proved reserves data and our average net daily production by area based on our reserve reports as of December 31, 2017:

 

Region

 

Proved Total

(MMBoe) (1)

 

 

% Oil &

Liquids

 

 

% Developed

 

 

Average Net

Daily

Production

(MBoe/d) (2)

 

Eagle Ford

 

 

385.6

 

 

 

87.8

%

 

 

22.4

%

 

 

36.0

 

North Louisiana

 

 

68.7

 

 

 

2.3

%

 

 

41.0

%

 

 

9.9

 

Total

 

 

454.3

 

 

 

 

 

 

 

 

 

 

 

45.9

 

 

(1)

Our estimated net proved reserves as of December 31, 2017 were determined using average first-day-of-the month prices for the prior 12 months in accordance with SEC rules. For oil and NGL volumes, the average WTI posted price of $51.34 per barrel as of December 31, 2017 was adjusted for quality, transportation fees and a regional price differential. For natural gas volumes, the average Henry Hub spot price of $2.976 per MMBtu as of December 31, 2017 was adjusted for energy content, transportation fees and a regional price differential. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of our properties are $49.80 per barrel of oil, $16.27 per barrel of NGL and $2.849 per Mcf of natural gas as of December 31, 2017.

(2)

Represents average daily net production for the three months ended December 31, 2017.

Business Strategies

To achieve our primary objective of delivering shareholder value, we intend to execute the following business strategies:

Grow production, reserves and cash flow through the development of our extensive drilling inventory. We believe our extensive inventory of drilling locations in the Eagle Ford and Austin Chalk formations following the consummation of the NLA Divestiture, combined with our operating expertise, will enable us to continue to deliver accretive production, reserves and cash flow growth and create shareholder value. We have identified a total of approximately 4,675 gross (3,097 net) drilling locations across our Eagle Ford acreage, with further upside potential given the multiple stacked pay zones across much of our acreage in addition to potential downspacing. We will continue to closely monitor offset operators as they delineate adjoining acreage and zones, providing us further data to optimize our development plan over time. We believe the location, concentration and scale of our core leasehold positions, coupled with our technical understanding of the reservoirs will allow us to efficiently develop our core areas and to allocate capital to maximize the value of our resource base.

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

 

minimizing the costs of drilling and completing horizontal wells through our knowledge of the target formations, pad drilling and reduced drilling times;

 

maximizing EURs through advanced drilling, completion and production techniques, such as by optimizing lateral lengths, the number of hydraulic fracturing stages and perforation intervals, water and proppant volumes, fluid chemistry, choke management and the strategic use of artificial lift techniques;

 

maximizing our cash flows by targeting specific areas within our balanced portfolio of oil and natural gas drilling opportunities based on the existing commodity price environment; and

 

minimizing operating costs through our experience in efficient well management.

In our Eagle Ford Acreage, we have reduced our drilling and completion costs per completed lateral foot by approximately 66%, from $2,958 per foot for our wells completed using Generation 1 hydraulic fracturing design to approximately $1,000 per foot for our wells completed using Generation 3 hydraulic fracturing design. Additionally, as we have transitioned our completion techniques in our Eagle Ford Acreage from Generation 1 to Generation 3 hydraulic fracturing designs, we have increased EURs by approximately 29% per completed lateral foot from an average of 76 Boe per foot to 99 Boe per foot. Our drilling and completion cost reductions coupled with our completion design improvements are generating enhanced single-well recoveries and attractive returns in the current commodity environment, and we believe we can further optimize our results through these and other technologies across our acreage position.

Capture additional horizontal development opportunities on current acreage. Our existing asset base provides numerous opportunities for our management team to create shareholder value by increasing our inventory beyond our currently identified drilling locations. Based on results from our horizontal drilling program and those of offset operators, including offset production trends, mud

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logs, 2-D and 3-D seismic, well data analysis and geologic trend mapping, we believe our acreage has multiple productive zones providing significant upside potential to our current inventory of identified drilling locations. We have excluded from our identified drilling locations potential opportunities associated with downspacing and with additional horizontal drilling locations in (i) the Austin Chalk trend in Burleson County, (ii) the Eagle Ford Shale in Washington County and (iii) the Buda, Woodbine, Georgetown and Pecan Gap zones that are present across much of our Eagle Ford Acreage.

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

Maintain a disciplined, growth-oriented financial strategy. We prudently manage our liquidity and leverage levels by monitoring cash flow, capital spending and debt capacity. We had approximately $588.6 million of available borrowing capacity under our revolving credit facility as of December 31, 2017. We intend to fund our growth primarily with internally generated cash flows and borrowings under our revolving credit facility while maintaining ample liquidity and access to the capital markets, which we believe will allow us to accelerate our development program and maximize the present value of our resource potential. Consistent with our disciplined approach to financial management, we have an active commodity hedging program that seeks to reduce our exposure to downside commodity price fluctuations, enabling us to protect cash flows and maintain liquidity to fund our capital program and investment opportunities.

Business Strengths

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

Extensive, contiguous acreage position in one of North America’s leading oil and gas plays. We own an extensive and substantially contiguous acreage position targeting one of the premier plays in North America, the Eagle Ford Shale formation. As of December 31, 2017, we had approximately 585,941 gross (477,153 net) acres and we had 454.3 MMBoe of proved reserves (62% oil, 25% natural gas and 13% NGLs) across our acreage. In February 2018, WHR II entered into a Purchase and Sale Agreement for the sale of the NLA Assets.  We believe that our recent well results demonstrate that many of the wells on our high-quality acreage are capable of producing single-well rates of return that are competitive with many of the top performing basins in the United States. Furthermore, the location of our acreage provides us with lower operating costs and better realized pricing than other companies operating in different basins around the country due to our acreage’s proximity to the end markets for oil, natural gas and NGLs.

Multi-year inventory of drilling opportunities across our acreage position. We have identified approximately 4,675 gross (3,097 net) drilling locations across our Eagle Ford Acreage, providing us with approximately 44.5 years gross (29.5 years net) of drilling inventory based on our 2018 drilling program. On our Eagle Ford Acreage, our horizontal drilling locations target the Eagle Ford Shale in Burleson and Lee Counties and the Austin Chalk in Washington County. In addition, we believe our acreage position includes a number of additional areas and zones that are prospective for hydrocarbons. For example, we believe we may identify additional horizontal drilling locations in (i) the Austin Chalk trend in Burleson County, (ii) the Eagle Ford Shale in Washington County and (iii) the Buda, Woodbine, Georgetown and Pecan Gap zones that are present across much of our Eagle Ford Acreage. Furthermore, we also believe that we may add horizontal drilling locations across our entire acreage position through downspacing.

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

Management and technical teams with substantial technical and operational expertise. Our management and technical teams have significant industry experience and a long history of collaboration in the identification, execution and integration of acquisitions and in cost-efficient management of profitable, large-scale drilling programs. Additionally, we have substantial expertise in advanced drilling and completion technologies and decades of collective experience in operating in the Eagle Ford. Mr. Graham, our Chief Executive Officer, and Mr. Bahr, our President, co-founded one of the predecessors to, and Mr. Graham served as Chief Executive

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Officer of, Memorial Resource Development Corp. (“MRD”), which pioneered the horizontal redevelopment of the Terryville Complex, participating in the drilling of MRD’s initial 55 horizontal wells. Further, our management team has a proven track record of returning value to shareholders and a significant economic interest in us directly and through its equity interests in each of WildHorse Holdings and Esquisto Holdings.  We believe our management team is motivated to use its experience in identifying and creating value across our acreage and drilling highly productive wells to deliver attractive returns, maintain safe and reliable operations and create shareholder value.

Geographically advantaged assets with significant midstream infrastructure to service our production. Our acreage position is in close proximity to end markets for oil, natural gas and NGLs, providing us with a regional price advantage. For example, low oil and natural gas basis differentials along the Gulf Coast represent a competitive advantage when compared to other plays, such as the Bakken, Marcellus, Utica, Permian and DJ. Recently developed and low-cost legacy infrastructure is in place across significant portions of our acreage to support our development program. In addition, we own and operate a large portion of our necessary midstream infrastructure which provides us with improved netbacks. On our Eagle Ford Acreage, we own substantial fresh water supply and storage, developed saltwater disposal wells and are in the process of developing an in-field sand mine. Our midstream infrastructure allows us to realize lower operating costs and provides us with increased flexibility in our development program. In addition, while not currently contemplated, our midstream infrastructure could prove to be a future source of additional capital if monetized at an attractive valuation.

Our Principal Stockholders

WildHorse Holdings, Esquisto Holdings, Acquisition Co. Holdings, NGP XI US Holdings, L.P. (“NGP XI”), and management directly own 21.0%, 38.3%, 2.5%, 8.9% and 2.6%, respectively, of our common stock. WildHorse Holdings, Esquisto Holdings and Acquisition Co. Holdings are controlled by NGP.  Carlyle beneficially owned 435,000 shares of Preferred Stock, which, based on the conversion rate as of December 31, 2017, represented approximately 24.3% of our common stock on an as converted basis.  NGP and its affiliates (through WildHorse Holdings, Esquisto Holdings, Acquisition Co. Holdings and NGP XI) beneficially own approximately 70.7% of our common stock.  Based solely on the Schedule 13G filed on February 5, 2018 with the SEC by KKR, KKR owned approximately 5.5% of our common stock as of June 30, 2017.

Reserve Data

Preparation of Reserve Estimates

Our reserve estimates as of December 31, 2017 included in this Annual Report are based on evaluations prepared by our management and audited by the independent petroleum engineering firm of Cawley in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Evaluation Engineers and definitions and guidelines established by the SEC. Our independent reserve engineers were selected for their historical experience and geographic expertise in engineering similar resources.

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

Internal Controls

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

Reserve engineering is and must be recognized as a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data

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and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil, natural gas and NGLs that are ultimately recovered. Estimates of economically recoverable oil, natural gas and NGLs and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs.  Please read “Item 1A. Risk Factors” appearing elsewhere in this Annual Report.

For the year ended December 31, 2017, our reserve estimates and related reports were prepared internally and reviewed and approved by Jason Pearce.  Mr. Pearce is our Senior Vice President, Reserves and has approximately 19 years of experience in oil and gas operations, reservoir engineering, reserve management, unconventional reservoir characterization and strategic planning.  Cawley performed audits of our internally prepared reserves estimates on our proved reserves as of December 31, 2017. Our proved reserves are, in the aggregate, reasonable and within the established audit tolerance guidelines of 10%. The report of Cawley contains further discussion of the reserves estimates and its audit procedure.

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

Estimated Proved Reserves

The following table presents the estimated net proved oil and natural gas reserves as of December 31, 2017, based on our audited reserve report.

 

 

 

Oil

(MBbls)

 

 

Natural Gas

(MMcf)

 

 

NGLs

(MBbls)

 

 

Total

(MBoe)

 

Estimated Proved Reserves

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Proved Developed

 

 

65,023

 

 

 

221,517

 

 

 

12,553

 

 

 

114,495

 

Total Proved Undeveloped

 

 

217,775

 

 

 

462,291

 

 

 

44,996

 

 

 

339,820

 

Total Proved Reserves

 

 

282,798

 

 

 

683,808

 

 

 

57,549

 

 

 

454,315

 

Development of Proved Undeveloped Reserves

As of December 31, 2017, we had 339.8 MMBoe of proved undeveloped reserves consisting of 217.8 MMBbls of oil, 462.3 MMcf of natural gas and 45.0 MBbls of NGLs, compared to 105.2 MMBoe of proved undeveloped reserves at December 31, 2016, consisting of 68.3 MMbbls of oil, 179.2 MMcf of natural gas and 7.1 MBbls of NGLs.  None of our PUDs as of December 31, 2017 are scheduled to be developed on a date more than five years from the date the reserves were initially booked to PUDs. PUDs will be converted from undeveloped to developed as the applicable wells begin production.

Our PUDs changed during 2017 as a result of:

 

upward performance and price revisions of 73.4 MMBoe;

 

acquisitions of 49.5 MMBoe;

 

reserve additions of 116.8 MMBoe; and

 

transfers to proved developed producing of 5.0 MMBoe

We estimate that we incurred $91.9 million of costs to convert proved undeveloped reserves from 13 locations into proved developed reserves in 2017.

Reconciliation of PV-10 to Standardized Measure

PV-10 is a non-GAAP financial measure and differs from the Standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. PV-10 is a computation of the Standardized Measure of discounted future net cash flows on a pre-tax basis. PV-10 is equal to the Standardized measure of discounted future net cash flows at the applicable date, before deducting future income taxes, discounted at 10 percent. We believe that the presentation of PV-10 is relevant and useful to

17


 

investors because it presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies without regard to the specific tax characteristics of such entities. We use this measure when assessing the potential return on investment related to our oil and natural gas properties. PV-10, however, is not a substitute for the Standardized measure of discounted future net cash flows. Our PV-10 measure and the Standardized measure of discounted future net cash flows do not purport to represent the fair value of our oil and natural gas reserves.

The following table provides a reconciliation of PV-10 of our proved reserves to the Standardized measure of discounted future net cash flows at December 31, 2017, 2016 and 2015:

 

 

 

At December 31,

 

 

 

2017

 

 

2016

 

 

2015

 

 

 

(in thousands)

 

PV-10

 

$

3,539,337

 

 

$

749,988

 

 

$

457,861

 

Less: present value of future income taxes discounted at 10%

 

 

(695,432

)

 

 

(206,947

)

 

 

(5,931

)

Standardized measure

 

$

2,843,905

 

 

$

543,041

 

 

$

451,930

 

 

Reserves Sensitivity

Historically, commodity prices have been extremely volatile and we expect this volatility to continue for the foreseeable future. For example, for the three years ended December 31, 2017, the NYMEX-WTI oil spot price ranged from a high of $61.36 per Bbl to a low of $26.19 per Bbl, while the NYMEX-Henry Hub natural gas spot price ranged from a high of $3.80 per MMBtu to a low of $1.49 per MMBtu. For the year ended December 31, 2017, the West Texas Intermediate posted price ranged from a high of $60.46 per Bbl on December 29, 2017 to a low of $42.48 per Bbl on June 21, 2017 and the Henry Hub spot market price ranged from a high of $3.71 per MMBtu on January 2, 2017 to a low of $2.44 per MMBtu on February 27, 2017. The continuation of low prices for oil or natural gas could materially and adversely affect our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce and our access to capital.

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

 

 

 

Base Case (1)

 

 

Case A (2)

 

 

Case B (2)

 

Crude oil price ($/Bbl)

 

$

51.34

 

 

$

55.75

 

 

$

60.00

 

Natural gas price ($/Mcf)

 

$

2.98

 

 

$

2.93

 

 

$

2.88

 

NGL price ($/Bbl)

 

$

51.34

 

 

$

55.75

 

 

$

60.00

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Capital expenditure increase

 

n/a

 

 

Flat

 

 

 

5

%

Operating expenditure increase

 

n/a

 

 

Flat

 

 

 

5

%

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved developed reserves (MMBoe)

 

 

114.5

 

 

 

115.3

 

 

 

115.3

 

Proved undeveloped reserves (MMBoe)

 

 

339.8

 

 

 

339.3

 

 

 

339.3

 

Total proved reserves (MMBoe)

 

 

454.3

 

 

 

454.6

 

 

 

454.6

 

PV-10 value (in thousands) (3)

 

$

3,539,337

 

 

$

4,104,991

 

 

$

4,454,357

 

Less: present value of future income taxes discounted at 10% (in thousands)

 

 

(695,432

)

 

 

(811,607

)

 

 

(890,810

)

Standardized measure (in thousands)

 

$

2,843,905

 

 

$

3,293,384

 

 

$

3,563,547

 

 

(1)

SEC pricing as of December 31, 2017 before adjustment for market differentials.

(2)

Prices represent potential SEC pricing based on different pricing assumptions before adjustments for market differentials.

(3)

PV-10 is a non-GAAP financial measure.  For a definition of PV-10, see “—Reconciliation of PV-10 to Standard Measure.”

 

 

18


 

Production, Revenue and Price History

For a description of ours, our predecessor’s and the previous owners’ combined historical production, revenues and average sales prices and unit costs, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations.”  For certain financial information about our operations, see “Item 6. Selected Financial Data” and “Item 8. Financial Statements and Supplementary Data.”

The following tables summarize our average net production, average unhedged sales prices by product and average production costs by geographic region for the years ended December 31, 2017, 2016 and 2015, respectively:

 

 

 

Year Ended December 31, 2017

 

 

 

 

 

 

 

Oil

 

 

Natural Gas

 

 

NGLs

 

 

Total

 

 

 

 

 

 

 

Production

Volumes

 

 

Average

Sales

Price

 

 

Production

Volumes

 

 

Average

Sales

Price

 

 

Production

Volumes

 

 

Average

Sales

Price

 

 

Production

Volumes

 

 

Average

Sales

Price

 

 

Lease

Operating

Expense

 

 

 

(MBbls)

 

 

($/Bbl)

 

 

(MMcf)

 

 

($/Mcf)

 

 

(MBbls)

 

 

($/Bbl)

 

 

(MBoe)

 

 

($/MBoe)

 

 

($/MBoe)

 

Eagle Ford

 

 

6,541

 

 

$

51.94

 

 

 

5,275

 

 

$

2.60

 

 

 

1,158

 

 

$

18.93

 

 

 

8,578

 

 

$

43.76

 

 

$

3.70

 

North Louisiana

 

 

65

 

 

$

48.05

 

 

 

15,188

 

 

$

3.04

 

 

 

48

 

 

$

21.74

 

 

 

2,644

 

 

$

19.05

 

 

$

3.03

 

Total

 

 

6,606

 

 

 

 

 

 

 

20,463

 

 

 

 

 

 

 

1,206

 

 

 

 

 

 

 

11,222

 

 

 

 

 

 

$

3.54

 

Average net production (MBoe/d)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

30.7

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31, 2016

 

 

 

Oil

 

 

Natural Gas

 

 

NGLs

 

 

Total

 

 

 

 

 

 

 

Production

Volumes

 

 

Average

Sales

Price

 

 

Production

Volumes

 

 

Average

Sales

Price

 

 

Production

Volumes

 

 

Average

Sales

Price

 

 

Production

Volumes

 

 

Average

Sales

Price

 

 

Lease

Operating

Expense

 

 

 

(MBbls)

 

 

($/Bbl)

 

 

(MMcf)

 

 

($/Mcf)

 

 

(MBbls)

 

 

($/Bbl)

 

 

(MBoe)

 

 

($/MBoe)

 

 

($/MBoe)

 

Eagle Ford

 

 

1,765

 

 

$

41.21

 

 

 

1,750

 

 

$

2.20

 

 

 

404

 

 

$

11.74

 

 

 

2,461

 

 

$

33.05

 

 

$

2.42

 

North Louisiana

 

 

83

 

 

$

38.70

 

 

 

16,070

 

 

$

2.47

 

 

 

67

 

 

$

15.54

 

 

 

2,828

 

 

$

15.52

 

 

$

2.25

 

Total

 

 

1,848

 

 

 

 

 

 

 

17,820

 

 

 

 

 

 

 

471

 

 

 

 

 

 

 

5,289

 

 

 

 

 

 

$

2.33

 

Average net production (MBoe/d)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

14.5

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31, 2015

 

 

 

Oil

 

 

Natural Gas

 

 

NGLs

 

 

Total

 

 

 

 

 

 

 

Production

Volumes

 

 

Average

Sales

Price

 

 

Production

Volumes

 

 

Average

Sales

Price

 

 

Production

Volumes

 

 

Average

Sales

Price

 

 

Production

Volumes

 

 

Average

Sales

Price

 

 

Lease

Operating

Expense

 

 

 

(MBbls)

 

 

($/Bbl)

 

 

(MMcf)

 

 

($/Mcf)

 

 

(MBbls)

 

 

($/Bbl)

 

 

(MBoe)

 

 

($/MBoe)

 

 

($/MBoe)

 

Eagle Ford

 

 

895

 

 

$

44.45

 

 

 

1,210

 

 

$

2.34

 

 

 

248

 

 

$

11.38

 

 

 

1,345

 

 

$

33.78

 

 

$

4.05

 

North Louisiana

 

 

73

 

 

$

43.98

 

 

 

13,637

 

 

$

2.63

 

 

 

103

 

 

$

14.24

 

 

 

2,449

 

 

$

16.54

 

 

$

3.51

 

Total

 

 

968

 

 

 

 

 

 

 

14,847

 

 

 

 

 

 

 

351

 

 

 

 

 

 

 

3,794

 

 

 

 

 

 

$

3.70

 

Average net production (MBoe/d)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

10.4

 

 

 

 

 

 

 

 

 

Productive Wells

Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we own an interest, and net wells are the sum of our fractional working interests owned in gross wells. The following table sets forth information relating to the productive wells in which we owned a working interest as of December 31, 2017.

 

 

 

Oil

 

 

Natural Gas

 

 

 

Gross

Wells

 

 

Net

Wells

 

 

Average

Working

Interest

 

 

Gross

Wells

 

 

Net

Wells

 

 

Average

Working

Interest

 

Eagle Ford Acreage

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operated

 

 

830.0

 

 

 

796.8

 

 

 

96.0

%

 

 

47.0

 

 

 

41.1

 

 

 

87.4

%

Non-operated

 

 

125.0

 

 

 

26.7

 

 

 

21.4

%

 

 

27.0

 

 

 

6.6

 

 

 

24.4

%

North Louisiana Acreage

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operated

 

 

7.0

 

 

 

4.8

 

 

 

68.6

%

 

 

466.0

 

 

 

341.3

 

 

 

73.2

%

Non-operated

 

 

1.0

 

 

 

0.1

 

 

 

10.0

%

 

 

146.0

 

 

 

10.6

 

 

 

7.3

%

Total

 

 

963.0

 

 

 

828.4

 

 

 

86.0

%

 

 

686.0

 

 

 

399.6

 

 

 

58.3

%

 

19


 

Acreage

The following table sets forth certain information regarding the total developed and undeveloped acreage in which we owned an interest as of December 31, 2017.

 

Region

 

Developed Acres(1)

 

 

Undeveloped Acres

 

 

Total Acres

 

 

 

Gross (2)

 

 

Net (3)

 

 

Gross (2)

 

 

Net (3)

 

 

Gross (2)

 

 

Net (3)

 

Eagle Ford Acreage

 

 

24,040

 

 

 

21,028

 

 

 

435,960

 

 

 

366,063

 

 

 

460,000

 

 

 

387,091

 

North Louisiana Acreage

 

 

83,580

 

 

 

51,899

 

 

 

42,361

 

 

 

38,163

 

 

 

125,941

 

 

 

90,062

 

Total

 

 

107,620

 

 

 

72,927

 

 

 

478,321

 

 

 

404,226

 

 

 

585,941

 

 

 

477,153

 

 

(1)

Developed acres are acres spaced or assigned to productive wells or wells capable of production.

(2)

A gross acre is an acre in which we own a working interest. The number of gross acres is the total number of acres in which we own a working interest.

(3)

A net acre is deemed to exist when the sum of our fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

Approximately 69% of our net Eagle Ford Acreage and 58% of our net North Louisiana Acreage was held by production at December 31, 2017.  Included in our North Louisiana Acreage in the table above are approximately 12,848 net acres we have the right to lease pursuant to an oil and gas lease option agreement with affiliates of Weyerhaeuser Company (“Weyerhaeuser”). Pursuant to that agreement, we have the right, upon notice to Weyerhaeuser, to lease acreage in exchange for a specified bonus payment. Upon such notice and our payment of the applicable bonus payment, Weyerhaeuser is obligated under the option agreement to enter into a three-year lease with us for the acreage we specify in the notice. The purchase price of this option was $0.5 million, and in addition, we also made a prepayment of $0.4 million as an initial lease bonus for 1,285 unspecified net acres associated with leases under the option. In October 2016, we made a payment of $1.5 million to extend the option for one year.  In January 2018, we exercised our option to lease approximately 12,848 net acres from Weyerhaeuser and paid $3.9 million.  On February 12, 2018, WHR II entered into a Purchase and Sale Agreement with Tanos for the sale of the NLA Assets, which include the recently leased acreage from Weyerhaeuser, for a total sales price of approximately $217.0 million. The transaction is expected to close by the end of March 2018.

Undeveloped Acreage Expirations

The following table sets forth the number of total net undeveloped acres as of December 31, 2017 across our Eagle Ford and North Louisiana Acreage that will expire in 2018, 2019, 2020, 2021 and 2022, unless production is established within the spacing units covering the acreage prior to the expiration dates or unless such leasehold rights are extended or renewed.

 

Region

 

2018

 

 

2019

 

 

2020

 

 

2021

 

 

2022

 

Eagle Ford Acreage

 

 

31,447

 

 

 

30,920

 

 

 

20,445

 

 

 

2,774

 

 

 

109

 

North Louisiana Acreage

 

 

23,694

 

 

 

11,700

 

 

 

2,583

 

 

 

6

 

 

 

 

Total

 

 

55,141

 

 

 

42,620

 

 

 

23,028

 

 

 

2,780

 

 

 

109

 

 

We intend to extend substantially all of the net acreage associated with our drilling locations through a combination of development drilling and leasehold extension and renewal payments. Of the 31,447 net acres expiring in 2018 across our Eagle Ford Acreage, we have the option to extend or renew the leases covering 13,124 net acres and have budgeted approximately $4.2 million in 2018 to execute extensions and renewals. With respect to the remaining 18,323 net acres for which we do not have an option to extend or renew in the Eagle Ford, 3,105 net acres are associated with 42 gross (30.0 net) wells of proved undeveloped reserves where the leases covering such expected wells will expire prior to our expected drilling date though we expect to extend or renew such leases. Further, with respect to the total remaining 18,323 net acres for which we do not have an option to extend or renew in the Eagle Ford, we intend to retain substantially all such acreage by negotiating lease extensions or renewals or drilling wells. Of the 23,694 net acres expiring in 2018 across our North Louisiana Acreage, we have the option to extend 19,101 of the 23,694 net acres in the RCT, Athens and Weyerhaeuser Areas, and we have budgeted approximately $6.8 million in 2018 to execute such extensions. As of December 31, 2017, 12,848 of the 23,694 net acres were related to the Weyerhaeuser Area.  In January 2018, we exercised our option to lease approximately 12,848 net acres from Weyerhaeuser for approximately $3.9 million.  We plan, in the event the NLA Divestiture is not consummated, to amend and extend or obtain new leases for the remaining approximately 4,593 net acres for an estimated cost of approximately $5.3 million. Please see Item 1A “Risk Factors—Risks Related to Our Business—Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage or the leases are renewed.”

Drilling Activities

The following table summarizes our approximate gross and net interest in wells completed during the periods indicated (including both operated and non-operated wells), regardless of when drilling was initiated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation among the number of productive wells drilled, quantities of reserves found or economic value. A dry well is a well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion. A productive well is a well that is not a dry well. Completion refers to installation of permanent

20


 

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

 

 

 

Year Ended December 31,

 

 

 

2017

 

 

2016

 

 

2015

 

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

Eagle Ford Acreage

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Development wells:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Productive

 

 

85.00

 

 

 

83.99

 

 

 

20.00

 

 

 

16.06

 

 

 

18.00

 

 

 

17.84

 

Dry

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Exploratory wells:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Productive

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Dry

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

North Louisiana Acreage

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Development wells:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Productive

 

 

11.00

 

 

 

6.94

 

 

 

4.00

 

 

 

1.78

 

 

 

6.00

 

 

 

4.51

 

Dry

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Exploratory wells:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Productive