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EX-32.1 - EX-32.1 - WildHorse Resource Development Corpwrd-20180630ex321a92877.htm
EX-31.2 - EX-31.2 - WildHorse Resource Development Corpwrd-20180630ex312c1ca36.htm
EX-31.1 - EX-31.1 - WildHorse Resource Development Corpwrd-20180630ex311d05026.htm
EX-4.6 - EX-4.6 - WildHorse Resource Development Corpwrd-20180630ex4699ec0a9.htm

 

 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

 

Washington, D.C. 20549

 


Form 10-Q

 


 

(Mark One)

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

For the quarterly period ended June 30, 2018

OR

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

For the transition period from            to          .

Commission File Number: 001-37964

 


WildHorse Resource Development Corporation

(Exact name of Registrant as specified in its Charter)

 


 

 

 

 

Delaware

 

81-3470246

( State or other jurisdiction of
incorporation or organization)

 

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

 

 

 

9805 Katy Freeway, Suite 400, Houston, TX

 

77024

(Address of principal executive offices)

 

(Zip Code)

 

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

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

 

 

 

 

Common Stock, par value $0.01 per share

 

New York Stock Exchange

(Title of each class)

 

(Name of each exchange on which registered)

 

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

 


 

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

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

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

 

 

 

 

 

 

Large accelerated filer

 

Accelerated filer

 

 

 

 

 

Non-accelerated filer

(Do not check if a smaller reporting company)

Smaller reporting company

 

 

 

 

 

 

 

 

Emerging growth company

 

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

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

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

 

 

 

 


 

WILDHORSE RESOURCE DEVELOPMENT CORPORATION

TABLE OF CONTENTS

 

 

 

 

 

 

Page

 

 

 

 

Glossary of Oil and Natural Gas Terms

2

 

Commonly Used Defined Terms

6

 

Cautionary Note Regarding Forward-Looking Statements

7

 

 

 

 

PART I—FINANCIAL INFORMATION

9

Item 1. 

Financial Statements

9

 

Unaudited Condensed Consolidated Balance Sheets as of June 30, 2018 and December 31, 2017

9

 

Unaudited Statements of Condensed Consolidated Operations for the Three and Six Months Ended June 30, 2018 and 2017

10

 

Unaudited Statements of Condensed Consolidated Cash Flows for the Six Months Ended June 30, 2018 and 2017

11

 

Unaudited Condensed Consolidated Statement of Changes in Stockholders’ Equity for the Six Months Ended June 30, 2018

12

 

Note 1 – Organization and Basis of Presentation

13

 

Note 2 – Summary of Significant Accounting Policies

14

 

Note 3 – Acquisitions and Divestitures

19

 

Note 4 – Fair Value Measurements of Financial Instruments

21

 

Note 5 – Risk Management and Derivative Instruments

23

 

Note 6 – Accounts Receivable

25

 

Note 7 – Accrued Liabilities

25

 

Note 8 – Asset Retirement Obligations

26

 

Note 9 – Long Term Debt

26

 

Note 10 – Preferred Stock

28

 

Note 11 – Equity

29

 

Note 12 – Earnings Per Share

29

 

Note 13 – Long Term Incentive Plans

30

 

Note 14 – Incentive Units

30

 

Note 15 – Related Party Transactions

31

 

Note 16 – Segment Disclosures

32

 

Note 17 – Income Taxes

33

 

Note 18 – Commitments and Contingencies

33

 

Note 19 – Subsequent Events

34

 

 

 

Item 2. 

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

35

Item 3. 

Quantitative and Qualitative Disclosures About Market Risk

49

Item 4. 

Controls and Procedures

50

 

 

 

 

PART II—OTHER INFORMATION

51

Item 1. 

Legal Proceedings

51

Item 1A. 

Risk Factors

51

Item 2. 

Unregistered Sales Of Equity Securities and Use of Proceeds

51

Item 3. 

Defaults Upon Senior Securities

52

Item 4. 

Mine Safety Disclosures

52

Item 5. 

Other Information

52

Item 6. 

Exhibits

52

 

 

 

 

Signatures

54

 

 

 

i


 

GLOSSARY OF OIL AND NATURAL GAS TERMS

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

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

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

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

Bcf: One billion cubic feet of natural gas.

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

Boe/d: One Boe per day.

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

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

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

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

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

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

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

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

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

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

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

2


 

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

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

Exploratory well: A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.

Field: An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations. For a complete definition of field, refer to the SEC’s Regulation S-X, Rule 4-10(a)(15).

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

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

Generation 3: With respect to our Eagle Ford Acreage, a slickwater fracking technique using approximately 3,700 pounds per foot of sand and 75 Bbls per foot of fluid, with 150 foot stages and nine clusters per stage at 90 barrels per minute.

Gross acres or gross wells: The total acres or wells, as the case may be, in which a working interest is owned.

Held by production: Acreage covered by a mineral lease that perpetuates a company’s right to operate a property as long as the property produces a minimum paying quantity of oil or natural gas.

Horizontal drilling:  A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.

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

MBoe:  One thousand Boe.

Mcf: One thousand cubic feet of natural gas.

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

MMBoe: One million Boe.

MMBtu: One million British thermal units.

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

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

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

NYMEX: The New York Mercantile Exchange.

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

3


 

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

Play: A geographic area with hydrocarbon potential.

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

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

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

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

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

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

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

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

Proved properties: Properties with proved reserves.

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

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

4


 

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

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

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

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

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

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

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

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

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

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

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

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

Unproved properties: Properties with no proved reserves.

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

5


 

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

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

WTI: West Texas Intermediate.

COMMONLY USED DEFINED TERMS

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

·

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

·

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

·

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

·

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

·

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

·

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

·

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

·

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

·

“Eagle Ford Acreage” refers to our acreage in the northern area of the Eagle Ford Shale in Southeast Texas;

·

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

·

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

·

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

6


 

FORWARD–LOOKING STATEMENTS

This Quarterly Report on Form 10-Q (“Quarterly Report”) contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”).  All statements, other than statements of historical fact included in this Quarterly Report, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Quarterly Report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on management’s current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under “Part I—Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2017 (“2017 Form 10-K”) and “Part II—Item 1A. Risk Factors” appearing within this Quarterly Report and elsewhere in this Quarterly Report.

Forward-looking statements may include statements about:

·

our business strategy;

·

our estimated proved, probable and possible reserves;

·

our drilling prospects, inventories, projects and programs;

·

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

·

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

·

our realized oil, natural gas and NGL prices;

·

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

·

our hedging strategy and results;

·

our future drilling plans;

·

competition and government regulations;

·

our ability to obtain permits and governmental approvals;

·

pending legal or environmental matters;

·

our marketing of oil, natural gas and NGLs;

·

our leasehold or business acquisitions;

·

costs of developing our properties;

·

general economic conditions;

·

credit markets;

·

uncertainty regarding our future operating results; and

·

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

7


 

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the development, production, gathering and sale of oil and natural gas. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures and the other risks described under “Part I—Item 1A. Risk Factors” of our 2017 Form 10-K.

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

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

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

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

8


 

PART I—FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS.

WILDHORSE RESOURCE DEVELOPMENT CORPORATION

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except outstanding shares)

 

 

 

 

 

 

 

 

 

 

June 30, 

 

December 31, 

 

    

2018

    

2017

ASSETS

 

 

 

 

 

 

Current Assets:

 

 

 

 

 

 

Cash and cash equivalents

 

$

19,139

 

$

226

Accounts receivable, net

 

 

109,017

 

 

84,103

Derivative instruments

 

 

 —

 

 

2,336

Prepaid expenses and other current assets

 

 

4,669

 

 

3,290

Total current assets

 

 

132,825

 

 

89,955

Property and equipment:

 

 

 

 

 

 

Oil and gas properties

 

 

3,007,462

 

 

2,999,728

Other property and equipment

 

 

53,124

 

 

53,003

Accumulated depreciation, depletion and amortization

 

 

(351,248)

 

 

(368,245)

Total property and equipment, net

 

 

2,709,338

 

 

2,684,486

Other noncurrent assets:

 

 

 

 

 

 

Derivative instruments

 

 

491

 

 

86

Debt issuance costs

 

 

3,618

 

 

3,573

Other

 

 

13,256

 

 

 —

Total assets

 

$

2,859,528

 

$

2,778,100

LIABILITIES AND EQUITY

 

 

 

 

 

 

Current liabilities:

 

 

 

 

 

 

Accounts payable

 

$

65,710

 

$

53,005

Accrued liabilities

 

 

193,552

 

 

199,952

Derivative instruments

 

 

107,206

 

 

58,074

Total current liabilities

 

 

366,468

 

 

311,031

Noncurrent liabilities:

 

 

 

 

 

 

Long-term debt

 

 

935,609

 

 

770,596

Asset retirement obligations

 

 

7,518

 

 

14,467

Deferred tax liabilities

 

 

20,612

 

 

71,470

Derivative instruments

 

 

61,866

 

 

18,676

Other noncurrent liabilities

 

 

874

 

 

1,085

Total noncurrent liabilities

 

 

1,026,479

 

 

876,294

Total liabilities

 

 

1,392,947

 

 

1,187,325

Commitments and contingencies (Note 18)

 

 

 

 

 

 

 

 

 

 

 

 

 

Preferred Stock, $0.01 par value: 50,000,000 shares authorized

 

 

 

 

 

 

Series A perpetual convertible preferred stock, $0.01 par value: 500,000 shares authorized; 435,000 shares issued and outstanding at June 30, 2018 and December 31, 2017, respectively, (involuntary liquidation preference of $450,389 and $448,146 at June 30, 2018 and December 31, 2017, respectively)

 

 

447,726

 

 

445,483

 

 

 

 

 

 

 

Stockholders’ equity:

 

 

 

 

 

 

Common stock, $0.01 par value 500,000,000 shares authorized; 102,007,516 shares and 101,137,277 shares issued and outstanding at June 30, 2018 and December 31, 2017 respectively

 

 

1,020

 

 

1,012

Additional paid-in capital

 

 

1,141,140

 

 

1,118,507

Accumulated earnings (deficit)

 

 

(123,305)

 

 

25,773

Total stockholders’ equity

 

 

1,018,855

 

 

1,145,292

Total liabilities and equity

 

$

2,859,528

 

$

2,778,100

See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements

9


 

WILDHORSE RESOURCE DEVELOPMENT CORPORATION

UNAUDITED STATEMENTS OF CONDENSED CONSOLIDATED OPERATIONS

(In thousands, except per share amounts)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Three Months Ended

June 30, 

 

For the Six Months Ended June 30, 

 

 

    

2018

    

2017

    

2018

    

2017

    

Revenues and other income:

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil sales

 

$

207,392

 

$

52,963

 

$

389,771

 

$

92,040

 

Natural gas sales

 

 

8,106

 

 

13,277

 

 

35,736

 

 

25,422

 

NGL sales

 

 

9,668

 

 

3,404

 

 

17,116

 

 

6,067

 

Other income

 

 

247

 

 

529

 

 

1,547

 

 

936

 

Total revenues and other income

 

 

225,413

 

 

70,173

 

 

444,170

 

 

124,465

 

Operating expenses:

 

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating expenses

 

 

12,088

 

 

6,837

 

 

28,515

 

 

13,765

 

Gathering, processing and transportation

 

 

476

 

 

1,942

 

 

1,828

 

 

3,642

 

Taxes other than income tax

 

 

12,779

 

 

4,509

 

 

24,560

 

 

8,408

 

Depreciation, depletion and amortization

 

 

70,694

 

 

33,229

 

 

130,577

 

 

59,672

 

Impairment of NLA Disposal Group (Note 3)

 

 

 —

 

 

 —

 

 

214,274

 

 

 —

 

(Gain) loss on sale of properties

 

 

(3,167)

 

 

 —

 

 

(3,167)

 

 

 —

 

General and administrative expenses

 

 

12,917

 

 

10,049

 

 

25,644

 

 

17,531

 

Incentive unit compensation expense

 

 

13,776

 

 

 —

 

 

13,776

 

 

 —

 

Exploration expense

 

 

4,369

 

 

11,504

 

 

6,077

 

 

13,119

 

Other operating (income) expense

 

 

111

 

 

25

 

 

769

 

 

44

 

Total operating expense

 

 

124,043

 

 

68,095

 

 

442,853

 

 

116,181

 

Income (loss) from operations

 

 

101,370

 

 

2,078

 

 

1,317

 

 

8,284

 

Other income (expense):

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest expense, net

 

 

(14,002)

 

 

(6,633)

 

 

(27,309)

 

 

(12,204)

 

Gain (loss) on derivative instruments

 

 

(110,805)

 

 

46,116

 

 

(151,175)

 

 

77,407

 

Other income (expense)

 

 

(13)

 

 

(2)

 

 

(150)

 

 

24

 

Total other income (expense)

 

 

(124,820)

 

 

39,481

 

 

(178,634)

 

 

65,227

 

Income (loss) before income taxes

 

 

(23,450)

 

 

41,559

 

 

(177,317)

 

 

73,511

 

Income tax benefit (expense)

 

 

9,356

 

 

(15,193)

 

 

47,449

 

 

(26,893)

 

Net income (loss) available to WRD

 

 

(14,094)

 

 

26,366

 

 

(129,868)

 

 

46,618

 

Preferred stock dividends

 

 

7,961

 

 

73

 

 

15,350

 

 

73

 

Undistributed earnings allocated to participating securities

 

 

 —

 

 

387

 

 

 —

 

 

434

 

Net income (loss) available to common stockholders

 

$

(22,055)

 

$

25,906

 

$

(145,218)

 

$

46,111

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Earnings per common share:

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic

 

$

(0.22)

 

$

0.28

 

$

(1.46)

 

$

0.49

 

Diluted

 

$

(0.22)

 

$

0.28

 

$

(1.46)

 

$

0.49

 

Weighted-average common shares outstanding:

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic

 

 

99,411

 

 

93,685

 

 

99,328

 

 

93,452

 

Diluted

 

 

99,411

 

 

93,685

 

 

99,328

 

 

93,452

 

 

See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements

10


 

WILDHORSE RESOURCE DEVELOPMENT CORPORATION

UNAUDITED STATEMENTS OF CONDENSED CONSOLIDATED CASH FLOWS

(In thousands)

 

 

 

 

 

 

 

 

 

 

 

For the Six Months Ended June 30, 

 

 

    

2018

    

2017

    

Cash flows from operating activities:

 

 

 

 

 

 

 

Net income (loss)

 

$

(129,868)

 

$

46,618

 

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

 

 

 

 

 

 

 

Depreciation, depletion and amortization

 

 

130,249

 

 

59,367

 

Accretion of asset retirement obligations

 

 

328

 

 

305

 

Impairments of unproved properties

 

 

5,866

 

 

10,663

 

Impairment of NLA Disposal Group

 

 

214,274

 

 

 —

 

Amortization of debt issuance cost

 

 

1,421

 

 

1,277

 

Accretion of senior notes discount

 

 

105

 

 

105

 

(Gain) loss on derivative instruments

 

 

151,175

 

 

(77,407)

 

Cash settlements on derivative instruments

 

 

(50,054)

 

 

1,093

 

Deferred income tax expense (benefit)

 

 

(50,925)

 

 

26,893

 

Debt extinguishment expense

 

 

 —

 

 

(11)

 

Amortization of equity awards

 

 

6,991

 

 

1,803

 

Incentive unit compensation expense

 

 

13,776

 

 

 —

 

(Gain) loss on sale of properties

 

 

(3,167)

 

 

 —

 

Consideration paid to customers, net of amortization

 

 

(1,328)

 

 

 —

 

Changes in operating assets and liabilities

 

 

 

 

 

 

 

Decrease (increase) in accounts receivable

 

 

(18,321)

 

 

(22,307)

 

Decrease (increase) in prepaid expenses

 

 

(831)

 

 

(1,760)

 

Decrease (increase) in inventories

 

 

648

 

 

 —

 

(Decrease) increase in accounts payable and accrued liabilities

 

 

21,168

 

 

25,395

 

Net cash flow provided by operating activities

 

 

291,507

 

 

72,034

 

Cash flows from investing activities:

 

 

 

 

 

 

 

Acquisitions of oil and gas properties

 

 

(19,914)

 

 

(547,389)

 

Additions to oil and gas properties

 

 

(578,669)

 

 

(211,263)

 

Additions to and acquisitions of other property and equipment

 

 

(25,010)

 

 

(6,189)

 

Construction deposits

 

 

(7,948)

 

 

 —

 

Proceeds from NLA Divestiture

 

 

206,406

 

 

 —

 

Net cash used in investing activities

 

 

(425,135)

 

 

(764,841)

 

Cash flows from financing activities:

 

 

 

 

 

 

 

Advances on revolving credit facilities

 

 

530,000

 

 

161,500

 

Payments on revolving credit facilities

 

 

(567,353)

 

 

(258,250)

 

Debt issuance cost

 

 

(3,246)

 

 

(10,756)

 

Proceeds from senior notes offering

 

 

204,000

 

 

347,354

 

Proceeds from the issuance of preferred stock

 

 

 —

 

 

435,000

 

Costs incurred in conjunction with the issuance of preferred stock

 

 

 —

 

 

(2,416)

 

Proceeds from issuance of common stock

 

 

 —

 

 

34,457

 

Cost incurred in conjunction with issuance of common stock

 

 

 —

 

 

(2,097)

 

Cost incurred in conjunction with the initial public offering

 

 

 —

 

 

(601)

 

Preferred stock dividends

 

 

(6,756)

 

 

 —

 

Repurchase of vested restricted stock

 

 

(4,104)

 

 

 —

 

Net cash provided by financing activities

 

 

152,541

 

 

704,191

 

Net change in cash, cash equivalents and restricted cash

 

 

18,913

 

 

11,384

 

Cash, cash equivalents and restricted cash, beginning of period

 

 

226

 

 

4,001

 

Cash, cash equivalents and restricted cash, end of period

 

$

19,139

 

$

15,385

 

 

See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements

 

11


 

WILDHORSE RESOURCE DEVELOPMENT CORPORATION

UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF
CHANGES IN STOCKHOLDERS’ EQUITY

(In thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Stockholders’ Equity

 

 

 

 

    

Common
Stock

    

Additional
Paid in
Capital

    

Accumulated
Earnings
(Deficit)

    

Total

December 31, 2017

 

 

1,012

 

 

1,118,507

 

 

25,773

 

 

1,145,292

Cumulative effect of accounting change (Note 2)

 

 

 —

 

 

 —

 

 

243

 

 

243

Net income (loss)

 

 

 —

 

 

 —

 

 

(129,868)

 

 

(129,868)

Preferred stock paid-in-kind dividend

 

 

 —

 

 

 —

 

 

(2,243)

 

 

(2,243)

Preferred stock cash dividend

 

 

 —

 

 

 —

 

 

(6,756)

 

 

(6,756)

Accrued preferred stock cash dividend

 

 

 —

 

 

 —

 

 

(4,479)

 

 

(4,479)

Beneficial conversion feature of preferred stock

 

 

 —

 

 

1,872

 

 

 —

 

 

1,872

Amortization of beneficial conversion feature

 

 

 —

 

 

 —

 

 

(1,872)

 

 

(1,872)

Contribution related to incentive unit compensation expense

 

 

 —

 

 

13,776

 

 

 —

 

 

13,776

Repurchase of vested restricted common stock

 

 

(2)

 

 

 —

 

 

(4,103)

 

 

(4,105)

Amortization of equity awards

 

 

10

 

 

6,985

 

 

 —

 

 

6,995

June 30, 2018

 

$

1,020

 

$

1,141,140

 

$

(123,305)

 

$

1,018,855

 

See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements

 

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WILDHORSE RESOURCE DEVELOPMENT CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 1. Organization and Basis of Presentation

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

Reference to “WHR II” refers to WildHorse Resources II, LLC, together with its consolidated subsidiaries. Reference to “Esquisto II” refers to Esquisto Resources II, LLC.  Reference to “Acquisition Co.” refers to WHE AcqCo., LLC. Reference to “WildHorse Investment Holdings” refers to WildHorse Investment Holdings, LLC.    Reference to “WildHorse Holdings” refers to WHR Holdings, LLC.  Reference to “Esquisto Holdings” refers to Esquisto Holdings, LLC. Reference to “Acquisition Co. Holdings” refers to WHE AcqCo Holdings, LLC. Reference to “NGP” refers to Natural Gas Partners, a family of private equity investment funds organized to make direct equity investments in the energy industry, including the funds invested in WHR II, Esquisto II and Acquisition Co.

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

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

Basis of Presentation

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

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

Use of Estimates in the Preparation of Financial Statements

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

We evaluate the estimates and assumptions on a regular basis; however, actual results may differ from these estimates and assumptions used in the preparation of the financial statements. Significant estimates with regard to these financial statements include (1) the estimate of proved oil, natural gas and NGL reserves and related present value estimates of future net cash flows therefrom; (2) depreciation, depletion and amortization expense; (3) valuation of accounts receivable; (4) accrued capital expenditures and liabilities; (5) asset retirement obligations; (6) deferred income taxes; (7)

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WILDHORSE RESOURCE DEVELOPMENT CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

Note 2. Summary of Significant Accounting Policies

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

Supplemental Cash Flow Information

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

 

 

 

 

 

 

 

 

 

 

 

For the Six Months Ended June 30, 

 

 

    

2018

    

2017

    

Supplemental cash flows:

 

 

 

 

 

 

 

Cash paid for interest, net of capitalized interest

 

$

22,487

 

$

306

 

Noncash investing activities:

 

 

 

 

 

 

 

Increase (decrease) in capital expenditures in accounts payables and accrued liabilities

 

 

(23,993)

 

 

82,295

 

(Increase) decrease in accounts receivable related to capital expenditures and acquisitions

 

 

(3,027)

 

 

(8,687)

 

 

New Accounting Standards

Definition of a Business

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

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

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

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

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

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WILDHORSE RESOURCE DEVELOPMENT CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

date practicable. The Company adopted this guidance on January 1, 2018 and it did not have a material impact on our consolidated financial statements.

Leases

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

Revenue from Contracts with Customers

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

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

Crude oil sales contracts

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

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WILDHORSE RESOURCE DEVELOPMENT CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

that crude oil.   Sales of crude oil are presented on the “Oil sales” line item of our statement of operations.  The adoption of the new revenue standard did not result in any material changes to the accounting or presentation of oil sales.

Natural gas sales contracts

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

For the other portion of our natural gas sales contracts, our contracts are structured such that both the customer and WildHorse have shared contractual control over the natural gas.  Contractual terms dictate that payment to us is based on actual extracted volumes of NGLs/residue gas.  Further, the contracts stipulate that a portion of that processed gas is retained by our customer as compensation for their services, thereby incentivizing the customer to process our gas and operate their facilities efficiently in our best interest.  Under these contracts, the value associated with the volumes our customer retains and any charges assessed by our customer are recognized on our “Gathering, processing and transportation” expense line item.  This is because the gas is contractually controlled jointly by both us and our customer until our performance obligation is fulfilled at the tailgate of our customer’s plant (once processing has been completed).  Our performance obligation under these contracts is to sell the extracted NGLs and residue gas.  We recognize revenue at a point in time (at the plant tailgate) when we have fulfilled our performance obligation.  Prior to the adoption of the new revenue standard, we did not recognize the volumes retained by our customer as an expense and we reported revenues net of the volumes they retained.

Residue gas contracts

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

Performance obligations fulfilled in a prior period

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

Disaggregation of revenue

The new revenue standard requires that we disaggregate revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors.  Our statement of operations disaggregates revenue to reflect pricing realities present in our contracts with our

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WILDHORSE RESOURCE DEVELOPMENT CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

Contributions in aid of construction

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

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

 

 

 

 

 

 

 

 

 

 

 

 

 

At December 31, 

 

Adjustments for

 

At January 1,

 

    

2017

    

ASC 606

    

2018

Assets:

 

 

 

 

 

 

 

 

 

Oil and gas properties

 

$

2,999,728

 

$

(4,041)

 

$

2,995,687

Accumulated depreciation, depletion and amortization

 

 

(368,245)

 

 

371

 

 

(367,874)

Other non-current assets

 

 

 

 

3,978

 

 

3,978

Liabilities:

 

 

 

 

 

 

 

 

 

Deferred tax liabilities

 

$

71,470

 

$

67

 

$

71,537

Stockholders’ Equity:

 

 

 

 

 

 

 

 

 

Accumulated earnings (deficit)

 

$

25,773

 

$

243

 

$

26,016

 

Other topics

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

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

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

Other Income - During the period, we owned the Oakfield gathering system, substantial fresh water supply and storage, a saltwater disposal well and several compressors.  Though the Oakfield gathering system, saltwater disposal well and compressors were sold to Tanos Energy Holdings III, LLC (“Tanos”) as part of the NLA Divestiture (see Note 3), these assets were used during the period in the operations of our wells.  Non-operators who own a portion of our wells are billed for the use of these assets, utilizing rates based on industry-accepted joint interest accounting rules and market conditions.  We report income from this source as “Other income” on our statement of operations in accordance with

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Table of Contents

WILDHORSE RESOURCE DEVELOPMENT CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Three Months Ended June 30, 2018

 

For the Six Months Ended June 30, 2018

 

 

 As Reported

 

Without ASC 606

 

Increase/-

 

 As Reported

 

Without ASC 606

 

Increase/-

 

    

 Under ASC 606

    

Adoption

    

Decrease

    

 Under ASC 606

    

Adoption

    

Decrease

Revenues:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil sales

 

$

207,392

 

$

207,421

 

$

(29)

 

$

389,771

 

$

389,800

 

$

(29)

Natural gas sales

 

 

8,106

 

 

9,540

 

 

(1,434)

 

 

35,736

 

 

37,975

 

 

(2,239)

NGL sales

 

 

9,668

 

 

12,193

 

 

(2,525)

 

 

17,116

 

 

21,601

 

 

(4,485)

Other Income

 

 

247

 

 

304

 

 

(57)

 

 

1,547

 

 

1,738

 

 

(191)

Operating expenses:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating expenses

 

 

12,088

 

 

12,395

 

 

(307)

 

 

28,515

 

 

28,816

 

 

(301)

Gathering, processing and transportation

 

 

476

 

 

4,022

 

 

(3,546)

 

 

1,828

 

 

8,120

 

 

(6,292)

Depreciation, depletion and amortization

 

 

70,694

 

 

70,849

 

 

(155)

 

 

130,577

 

 

130,866

 

 

(289)

Other operating (income) expense

 

 

111

 

 

282

 

 

(171)

 

 

769

 

 

1,080

 

 

(311)

Income (loss) before income taxes

 

 

(23,450)

 

 

(23,583)

 

 

133

 

 

(177,317)

 

 

(177,565)

 

 

248

Income tax benefit (expense)

 

 

9,356

 

 

9,383

 

 

(27)

 

 

47,449

 

 

47,503

 

 

(54)

Net income (loss)

 

 

(14,094)

 

 

(14,200)

 

 

106

 

 

(129,868)

 

 

(130,062)

 

 

194

 

 

 

 

 

 

 

 

 

 

 

 

 

 

At June 30, 2018

 

 

 As Reported

 

 Without ASC 606

 

Increase/-

 

    

 Under ASC 606

    

Adoption

    

Decrease

Assets:

 

 

 

 

 

 

 

 

 

Oil and gas properties

 

$

3,007,462

 

$

3,012,871

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