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EX-95.1 - EX-95.1 - WildHorse Resource Development Corpwrd-20180930ex951401d33.htm
EX-32.1 - EX-32.1 - WildHorse Resource Development Corpwrd-20180930ex3219016c3.htm
EX-31.2 - EX-31.2 - WildHorse Resource Development Corpwrd-20180930ex3122c7766.htm
EX-31.1 - EX-31.1 - WildHorse Resource Development Corpwrd-20180930ex311d9f73b.htm
EX-10.1 - EX-10.1 - WildHorse Resource Development Corpwrd-20180930ex101057c23.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 September 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 every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the Registrant was required to submit such files).    Yes      No  

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

 

 

 

 

 

 

Large accelerated filer

 

Accelerated filer

 

 

 

 

 

Non-accelerated filer

 

Smaller reporting company

 

 

 

 

 

 

 

 

Emerging growth company

 

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

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

As of October 31, 2018, the registrant had 101,995,729 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 September 30, 2018 and December 31, 2017

9

 

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

10

 

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

11

 

Unaudited Condensed Consolidated Statements of Changes in Stockholders’ Equity for the Nine Months Ended September 30, 2018 and 2017

12

 

Note 1 – Organization and Basis of Presentation

13

 

Note 2 – Summary of Significant Accounting Policies

15

 

Note 3 – Acquisitions and Divestitures

21

 

Note 4 – Fair Value Measurements of Financial Instruments

23

 

Note 5 – Risk Management and Derivative Instruments

25

 

Note 6 – Accounts Receivable

27

 

Note 7 – Accrued Liabilities

27

 

Note 8 – Asset Retirement Obligations

27

 

Note 9 – Long Term Debt

28

 

Note 10 – Preferred Stock

30

 

Note 11 – Equity

31

 

Note 12 – Earnings Per Share

31

 

Note 13 – Long Term Incentive Plans

32

 

Note 14 – Incentive Units

32

 

Note 15 – Related Party Transactions

33

 

Note 16 – Segment Disclosures

34

 

Note 17 – Income Taxes

35

 

Note 18 – Commitments and Contingencies

36

 

Note 19 – Subsequent Events

37

 

 

 

Item 2. 

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

38

Item 3. 

Quantitative and Qualitative Disclosures About Market Risk

54

Item 4. 

Controls and Procedures

55

 

 

 

 

PART II—OTHER INFORMATION

55

Item 1. 

Legal Proceedings

55

Item 1A. 

Risk Factors

55

Item 2. 

Unregistered Sales Of Equity Securities and Use of Proceeds

57

Item 3. 

Defaults Upon Senior Securities

58

Item 4. 

Mine Safety Disclosures

58

Item 5. 

Other Information

58

Item 6. 

Exhibits

58

 

 

 

 

Signatures

61

 

 

 

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;

·

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

·

“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 and in the Giddings Austin Chalk Trend 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

6


 

stock, par value $0.01 per share, designated as “Series A Perpetual Convertible Preferred Stock” (the “Preferred Stock”).

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, including matters relating to our merger with Chesapeake, 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 merger with Chesapeake;

·

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;

7


 

·

uncertainty regarding our future operating results; and

·

plans, objectives, expectations and intentions contained in this Quarterly 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, the possibility that the proposed merger with Chesapeake does not close when expected or at all because required regulatory, shareholder or other approvals are not received or other conditions to the closing are not satisfied on a timely basis or at all, the risk that regulatory approvals required for the proposed merger are not obtained or are obtained subject to conditions that are not anticipated, potential adverse reactions or changes to business or employee relationships, including those resulting from the announcement or completion of the proposed merger, uncertainties as to the timing of the proposed merger; competitive responses to the proposed merger, the possibility that the anticipated benefits of the proposed merger are not realized when expected or at all, including as a result of the impact of, or problems arising from, the integration of the two companies, the possibility that the proposed merger may be more expensive to complete than anticipated, including as a result of unexpected factors or events, diversion of management’s attention from ongoing business operations and opportunities, the ability of Chesapeake to complete the acquisition and integration of WRD successfully, litigation relating to the proposed merger, other factors that may affect future results of WRD and Chesapeake and the other risks described under “Part II—Item 1A. Risk Factors” of this Quarterly Report and “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)

 

 

 

 

 

 

 

 

 

 

September 30, 

 

December 31, 

 

    

2018

    

2017

ASSETS

 

 

 

 

 

 

Current Assets:

 

 

 

 

 

 

Cash and cash equivalents

 

$

1,745

 

$

226

Accounts receivable, net

 

 

111,354

 

 

84,103

Derivative instruments

 

 

 —

 

 

2,336

Prepaid expenses and other current assets

 

 

5,734

 

 

3,290

Total current assets

 

 

118,833

 

 

89,955

Property and equipment:

 

 

 

 

 

 

Oil and gas properties

 

 

3,271,422

 

 

2,999,728

Other property and equipment

 

 

79,120

 

 

53,003

Accumulated depreciation, depletion and amortization

 

 

(426,373)

 

 

(368,245)

Total property and equipment, net

 

 

2,924,169

 

 

2,684,486

Other noncurrent assets:

 

 

 

 

 

 

Derivative instruments

 

 

574

 

 

86

Debt issuance costs

 

 

3,301

 

 

3,573

Other

 

 

17,575

 

 

 —

Total assets

 

$

3,064,452

 

$

2,778,100

LIABILITIES AND EQUITY

 

 

 

 

 

 

Current liabilities:

 

 

 

 

 

 

Accounts payable

 

$

66,423

 

$

53,005

Accrued liabilities

 

 

169,665

 

 

199,952

Derivative instruments

 

 

131,539

 

 

58,074

Total current liabilities

 

 

367,627

 

 

311,031

Noncurrent liabilities:

 

 

 

 

 

 

Long-term debt

 

 

1,085,997

 

 

770,596

Asset retirement obligations

 

 

7,899

 

 

14,467

Deferred tax liabilities

 

 

44,141

 

 

71,470

Derivative instruments

 

 

81,736

 

 

18,676

Other

 

 

762

 

 

1,085

Total noncurrent liabilities

 

 

1,220,535

 

 

876,294

Total liabilities

 

 

1,588,162

 

 

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 September 30, 2018 and December 31, 2017, respectively, (involuntary liquidation preference of $450,389 and $448,146 at September 30, 2018 and December 31, 2017, respectively)

 

 

447,726

 

 

445,483

 

 

 

 

 

 

 

Stockholders’ equity:

 

 

 

 

 

 

Common stock, $0.01 par value 500,000,000 shares authorized; 101,996,754 shares and 101,137,277 shares issued and outstanding at September 30, 2018 and December 31, 2017 respectively

 

 

1,020

 

 

1,012

Additional paid-in capital

 

 

1,146,149

 

 

1,118,507

Accumulated earnings (deficit)

 

 

(118,605)

 

 

25,773

Total stockholders’ equity

 

 

1,028,564

 

 

1,145,292

Total liabilities and equity

 

$

3,064,452

 

$

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 September 30, 

 

For the Nine Months Ended September 30, 

 

 

    

2018

    

2017

    

2018

    

2017

    

Revenues and other income:

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil sales

 

$

236,040

 

$

100,391

 

$

625,811

 

$

192,431

 

Natural gas sales

 

 

9,298

 

 

14,906

 

 

45,034

 

 

40,328

 

NGL sales

 

 

13,883

 

 

6,881

 

 

30,999

 

 

12,948

 

Other income

 

 

269

 

 

308

 

 

1,816

 

 

1,244

 

Total revenues and other income

 

 

259,490

 

 

122,486

 

 

703,660

 

 

246,951

 

Operating expenses:

 

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating expenses

 

 

14,221

 

 

12,435

 

 

42,736

 

 

26,200

 

Gathering, processing and transportation

 

 

3,225

 

 

3,761

 

 

5,053

 

 

7,403

 

Taxes other than income tax

 

 

14,193

 

 

6,047

 

 

38,753

 

 

14,455

 

Depreciation, depletion and amortization

 

 

74,842

 

 

51,843

 

 

205,419

 

 

111,515

 

Impairment of NLA Disposal Group (Note 3)

 

 

 —

 

 

 —

 

 

214,274

 

 

 —

 

(Gain) loss on sale of properties

 

 

217

 

 

 —

 

 

(2,950)

 

 

 —

 

General and administrative expenses

 

 

16,033

 

 

11,043

 

 

41,677

 

 

28,574

 

Incentive unit compensation expense

 

 

 —

 

 

 —

 

 

13,776

 

 

 —

 

Exploration expense

 

 

13,814

 

 

4,749

 

 

19,891

 

 

17,868

 

Other operating (income) expense

 

 

169

 

 

 9

 

 

938

 

 

53

 

Total operating expense

 

 

136,714

 

 

89,887

 

 

579,567

 

 

206,068

 

Income (loss) from operations

 

 

122,776

 

 

32,599

 

 

124,093

 

 

40,883

 

Other income (expense):

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest expense, net

 

 

(15,718)

 

 

(8,749)

 

 

(43,027)

 

 

(20,953)

 

Gain (loss) on derivative instruments

 

 

(76,358)

 

 

(40,288)

 

 

(227,533)

 

 

37,119

 

Other income (expense)

 

 

(122)

 

 

(12)

 

 

(272)

 

 

12

 

Total other income (expense)

 

 

(92,198)

 

 

(49,049)

 

 

(270,832)

 

 

16,178

 

Income (loss) before income taxes

 

 

30,578

 

 

(16,450)

 

 

(146,739)

 

 

57,061

 

Income tax benefit (expense)

 

 

(19,055)

 

 

5,646

 

 

28,394

 

 

(21,247)

 

Net income (loss) available to WRD

 

 

11,523

 

 

(10,804)

 

 

(118,345)

 

 

35,814

 

Preferred stock dividends

 

 

6,756

 

 

6,450

 

 

22,106

 

 

6,523

 

Undistributed earnings allocated to participating securities

 

 

1,233

 

 

 —

 

 

 —

 

 

3,234

 

Net income (loss) available to common stockholders

 

$

3,534

 

$

(17,254)

 

$

(140,451)

 

$

26,057

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Earnings per common share:

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic

 

$

0.04

 

$

(0.17)

 

$

(1.41)

 

$

0.27

 

Diluted

 

$

0.04

 

$

(0.17)

 

$

(1.41)

 

$

0.27

 

Weighted-average common shares outstanding:

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic

 

 

99,639

 

 

99,142

 

 

99,433

 

 

95,369

 

Diluted

 

 

99,639

 

 

99,142

 

 

99,433

 

 

95,369

 

 

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 Nine Months Ended September 30, 

 

 

    

2018

    

2017

    

Cash flows from operating activities:

 

 

 

 

 

 

 

Net income (loss)

 

$

(118,345)

 

$

35,814

 

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

 

 

 

 

 

 

 

Depreciation, depletion and amortization

 

 

205,419

 

 

111,515

 

Impairments of unproved properties

 

 

8,226

 

 

13,910

 

Impairment of NLA Disposal Group

 

 

214,274

 

 

 —

 

Amortization of debt issuance cost

 

 

2,184

 

 

1,962

 

Accretion of senior notes discount

 

 

108

 

 

197

 

(Gain) loss on derivative instruments

 

 

227,533

 

 

(37,119)

 

Cash settlements on derivative instruments

 

 

(81,177)

 

 

6,895

 

Deferred income tax expense (benefit)

 

 

(27,396)

 

 

20,263

 

Debt extinguishment expense

 

 

 —

 

 

(11)

 

Amortization of equity awards

 

 

11,988

 

 

4,217

 

Incentive unit compensation expense

 

 

13,776

 

 

 —

 

(Gain) loss on sale of properties

 

 

(2,950)

 

 

 —

 

Loss on equity investment

 

 

103

 

 

 

 

Consideration paid to customers, net of amortization

 

 

(1,806)

 

 

 —

 

Changes in operating assets and liabilities

 

 

 

 

 

 

 

Decrease (increase) in accounts receivable

 

 

(23,492)

 

 

(42,081)

 

Decrease (increase) in prepaid expenses

 

 

(503)

 

 

(1,245)

 

Decrease (increase) in inventories

 

 

648

 

 

 —

 

(Decrease) increase in accounts payable and accrued liabilities

 

 

18,784

 

 

28,875

 

Net cash flow provided by operating activities

 

 

447,374

 

 

143,192

 

Cash flows from investing activities:

 

 

 

 

 

 

 

Acquisitions of oil and gas properties

 

 

(53,188)

 

 

(549,033)

 

Additions to oil and gas properties

 

 

(824,656)

 

 

(443,210)

 

Additions to and acquisitions of other property and equipment

 

 

(57,987)

 

 

(10,070)

 

Construction deposits

 

 

(1,714)

 

 

 —

 

Contribution to equity method investee

 

 

(10,177)

 

 

 —

 

Proceeds from NLA Divestiture

 

 

206,406

 

 

 —

 

Net cash used in investing activities

 

 

(741,316)

 

 

(1,002,313)

 

Cash flows from financing activities:

 

 

 

 

 

 

 

Advances on revolving credit facilities

 

 

842,000

 

 

363,500

 

Payments on revolving credit facilities

 

 

(729,353)

 

 

(447,765)

 

Debt issuance cost

 

 

(3,502)

 

 

(13,545)

 

Proceeds from senior notes offering

 

 

204,000

 

 

494,744

 

Proceeds from the issuance of preferred stock

 

 

 —

 

 

435,000

 

Costs incurred in conjunction with the issuance of preferred stock

 

 

 —

 

 

(2,662)

 

Proceeds from issuance of common stock

 

 

 —

 

 

34,457

 

Cost incurred in conjunction with issuance of common stock

 

 

 —

 

 

(2,698)

 

Preferred stock dividends

 

 

(13,512)

 

 

 —

 

Repurchase of vested restricted stock

 

 

(4,172)

 

 

 —

 

Net cash provided by financing activities

 

 

295,461

 

 

861,031

 

Net change in cash, cash equivalents and restricted cash

 

 

1,519

 

 

1,910

 

Cash, cash equivalents and restricted cash, beginning of period

 

 

226

 

 

4,001

 

Cash, cash equivalents and restricted cash, end of period

 

$

1,745

 

$

5,911

 

 

See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements

11


 

 

WILDHORSE RESOURCE DEVELOPMENT CORPORATION

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF
CHANGES IN STOCKHOLDERS’ EQUITY

(In thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Nine Months Ended September 30, 2018

 

    

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)

 

 

 —

 

 

 —

 

 

241

 

 

241

Net income (loss)

 

 

 —

 

 

 —

 

 

(115,774)

 

 

(115,774)

Preferred stock paid-in-kind dividend

 

 

 —

 

 

 —

 

 

(2,243)

 

 

(2,243)

Accrued preferred stock cash dividend

 

 

 —

 

 

 —

 

 

(4,480)

 

 

(4,480)

Beneficial conversion feature of preferred stock

 

 

 —

 

 

1,872

 

 

 —

 

 

1,872

Amortization of beneficial conversion feature

 

 

 —

 

 

 —

 

 

(668)

 

 

(668)

Repurchase of vested restricted common stock

 

 

 —

 

 

 —

 

 

(69)

 

 

(69)

Amortization of equity awards

 

 

 1

 

 

3,155

 

 

 —

 

 

3,156

March 31, 2018

 

 

1,013

 

 

1,123,534

 

 

(97,220)

 

 

1,027,327

Cumulative effect of accounting change (Note 2)

 

 

 —

 

 

 —

 

 

 2

 

 

 2

Net income (loss)

 

 

 —

 

 

 —

 

 

(14,094)

 

 

(14,094)

Preferred stock cash dividend

 

 

 —

 

 

 —

 

 

(6,756)

 

 

(6,756)

Accrued preferred stock cash dividend

 

 

 —

 

 

 —

 

 

 1

 

 

 1

Amortization of beneficial conversion feature

 

 

 —

 

 

 —

 

 

(1,204)

 

 

(1,204)

Contribution related to incentive unit compensation expense

 

 

 —

 

 

13,776

 

 

 —

 

 

13,776

Repurchase of vested restricted common stock

 

 

(2)

 

 

 —

 

 

(4,034)

 

 

(4,036)

Amortization of equity awards

 

 

 9

 

 

3,830

 

 

 —

 

 

3,839

June 30, 2018

 

 

1,020

 

 

1,141,140

 

 

(123,305)

 

 

1,018,855

Net income (loss)

 

 

 —

 

 

 —

 

 

11,523

 

 

11,523

Preferred stock cash dividend

 

 

 —

 

 

 —

 

 

(6,756)

 

 

(6,756)

Contribution related to incentive unit compensation expense

 

 

 —

 

 

 —

 

 

 —

 

 

 —

Repurchase of vested restricted common stock

 

 

 —

 

 

 —

 

 

(67)

 

 

(67)

Amortization of equity awards

 

 

 —

 

 

5,009

 

 

 —

 

 

5,009

September 30, 2018

 

$

1,020

 

$

1,146,149

 

$

(118,605)

 

$

1,028,564

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Nine Months Ended September 30, 2017

 

    

Common
Stock

    

Additional
Paid in
Capital

    

Accumulated
Earnings
(Deficit)

    

Total

December 31, 2016

 

$

917

 

$

1,017,368

 

$

(10,397)

 

$

1,007,888

Net income (loss)

 

 

 —

 

 

 —

 

 

20,252

 

 

20,252

Proceeds from issuance of common stock

 

 

23

 

 

34,434

 

 

 —

 

 

34,457

Costs incurred in connection with issuance of common stock

 

 

 —

 

 

(1,872)

 

 

 —

 

 

(1,872)

Amortization of equity awards

 

 

 —

 

 

495

 

 

 —

 

 

495

March 31, 2017

 

 

940

 

 

1,050,425

 

 

9,855

 

 

1,061,220

Net income (loss)

 

 

 —

 

 

 —

 

 

26,366

 

 

26,366

Issuance of common stock in connection with the Acquisition

 

 

55

 

 

60,699

 

 

 —

 

 

60,754

Accrual of preferred stock paid-in-kind dividend

 

 

 —

 

 

 —

 

 

(73)

 

 

(73)

Amortization of equity awards

 

 

16

 

 

1,292

 

 

 —

 

 

1,308

June 30, 2017

 

 

1,011

 

 

1,112,416

 

 

36,148

 

 

1,149,575

Net income (loss)

 

 

 —

 

 

 —

 

 

(10,804)

 

 

(10,804)

Accrual of preferred stock paid-in-kind dividend

 

 

 —

 

 

 —

 

 

(6,450)

 

 

(6,450)

Amortization of equity awards

 

 

 1

 

 

2,413

 

 

 —

 

 

2,414

September 30, 2017

 

$

1,012

 

$

1,114,829

 

$

18,894

 

$

1,134,735

See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements

 

12


 

Table of Contents

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”), Burleson Sand LLC (“Burleson Sand”) and WHCC Infrastructure LLC (“WHCC”) are wholly owned subsidiaries of the Company as of September 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.

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) 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.

13


 

Table of Contents

WILDHORSE RESOURCE DEVELOPMENT CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Investment in Unconsolidated Affiliate

 

WHCC and an undisclosed joint venture partner (“JV Partner”) each made an approximate $10.2 million cash capital contribution for a 50% membership interest in JWH Midstream LLC (“JWH”) during July 2018.  JWH used the capital contributions to finance the acquisition of a holding company from a third party that had an existing lease with the Port of Corpus Christi Authority (“Port”) for approximately 55 acres of land on the north side of the Corpus Christi Ship Channel in the Inner Harbor. WHCC’s 50% membership interest in JWH is subject to a call and put option. 

 

The call option gives JV Partner the right, but not the obligation, to purchase WHCC’s membership interest after December 1, 2018 in the event that WHCC and JV Partner have not entered into definitive documentation regarding a proposed joint venture terminal development plan on or before December 1, 2018.  The put option gives WHCC the right, but not the obligation, to require JV Partner to purchase WHCC’s membership interest after June 1, 2019 in the event that WHCC and JV Partner have not entered into definitive documentation regarding a proposed joint venture terminal development plan on or before June 1, 2019.  The predetermined sales price of WHCC’s membership interest will be equal to aggregate capital contributions made by WHCC to JWH, less any distributions made by JWH to WHCC, plus a rate of return equal to three percent.  We determined that the call and put options did not meet the definition of a derivative.

 

A $47.5 million irrevocable standby letter of credit was issued on July 27, 2018 under the Company’s revolving credit facility in favor of the Port to cover future minimum annual wharfage fee payment deficits under the lease. The Port requires that either a guaranty or letter of credit be in place for the first 10 years of the 20-year lease. Until the proposed marine terminal is built and operational, the letter of credit cannot be drawn upon by the Port.  If the put or call option is exercised, JV Partner is contractually required to take all actions, including but not limited to, providing a letter of credit or similar guarantee to the Port, as necessary to have WRD fully released from its letter of credit.

 

We determined that JWH is a variable interest entity (“VIE”) due to our disproportionate obligation to absorb losses compared to our voting rights and substantially all of JWH’s current activities involve us.  We are exposed to losses above and beyond our 50% membership interest in JWH since we provided the Port with the irrevocable standby letter of credit naming the Port as beneficiary. A reporting entity is the primary beneficiary of a VIE and must consolidate it when that party has a variable interest, or combination of variable interests, that provides it with a controlling financial interest. A party is deemed to have a controlling financial interest if it meets both of the power and losses/benefits criteria. The power criterion is the ability to direct the activities of the VIE that most significantly impact its economic performance. The losses/benefits criterion is the obligation to absorb losses from, or right to receive benefits from, the VIE that could potentially be significant to the VIE. The VIE model requires an ongoing reconsideration of whether a reporting entity is the primary beneficiary of a VIE due to changes in facts and circumstances. The Company has determined it is not the primary beneficiary.  On the basis of governing provisions set forth in JWH’s limited liability agreement, all decisions regarding activities requires joint or unanimous consent. The power to direct activities that most significantly impact JWH’s economic performance is shared. Our maximum exposure to loss cannot be quantified, but would be limited to our investment and any amounts withdrawn by the Port under the standby letter of credit previously discussed.

 

Our investment in JWH is being accounted as an equity method investee.  Investments in a limited liability company that maintains a specific ownership account for each investor should generally be accounted for under the equity method of accounting unless the investment is so minor that the member may have virtually no influence over the company’s operating and financial policies. In practice, investments of more than 3 to 5 percent are viewed as more than minor. Our $10.1 million investment in JWH is reflected on our balance sheet under other noncurrent assets as a component of the “Other” financial statement line item.   Equity losses of $0.1 million for the three and nine months ended September 30, 2018 is reflected on our income statement under other income (expense) as a component of the “Other income (expense)” financial statement line item.

 

14


 

Table of Contents

WILDHORSE RESOURCE DEVELOPMENT CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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.

Oil and Gas Properties

 

Significant costs associated with development wells in progress or awaiting completion are excluded from depletion until the well is completed.  Effective July 1, 2018, we lowered our significance threshold and as a result, we excluded capitalized costs of $60.9 million at September 30, 2018.

Supplemental Cash Flow Information

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

 

 

 

 

 

 

 

 

 

 

 

For the Nine Months Ended September 30, 

 

 

    

2018

    

2017

    

Supplemental cash flows:

 

 

 

 

 

 

 

Cash paid for interest, net of capitalized interest

 

$

45,496

 

$

13,465

 

Noncash investing activities:

 

 

 

 

 

 

 

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

 

 

(45,838)

 

 

95,292

 

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

 

 

(1,780)

 

 

7,990

 

 

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

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transition under a retrospective approach for each period presented. If it is impracticable to apply the amendments retrospectively for some of the issues, the amendments for those issues would be applied prospectively as of the earliest date practicable. The Company adopted this guidance on January 1, 2018 and it did not have a material impact on our consolidated financial statements.

Leases

In February 2016, the FASB issued a revision to its lease accounting guidance. The FASB retained a dual model, which requires classification of leases as finance or operating. The classification  is based on criteria that are similar to the current lease accounting guidance. The revised guidance requires lessees to recognize a right-of-use asset and lease liability for all leasing transactions regardless of classification. The new standard is effective for financial statements issued for annual periods beginning after December 15, 2018 and interim periods within those fiscal years. 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 required to use a modified retrospective approach, where the date of initial application to existing leases would be to the beginning of the earliest period presented in the annual financial statements where we first apply the new standard (i.e. financial statements as of and for the year ending December 31, 2019).  Under this method therefore, leases commencing as early as January 1, 2017 would be impacted by the new standard and comparative periods presented in those financials would likely be adjusted (“the comparative method”).  In July 2018, the FASB issued targeted improvements to the new leasing standard, which now allows entities the option to use the January 1, 2019 effective date as the date of initial application (“the effective date method”).  As a result, comparative periods will not require adjustment because only contracts existing as of January 1, 2019 are within the scope of the new standard.  The Company currently intends to adopt the standard using the effective date method.

Further, the new standard allows lessees to adopt a package of practical expedients upon transition to the new standard, whereby contracts existing as of January 1, 2019 will not require reassessment under the new definition of a lease or new lease classification criteria.  Therefore, a contract existing on January 1, 2019 that did not meet the definition of a lease under the current standard, will not be accounted for or reported as a lease under the new standard.  Effectively, the current identification and classification will remain for those leases (under the new standard) unless those leases are modified or require reassessment under the new standard.   The Company currently intends to make this accounting policy election upon adoption.

For leases with a term of 12 months or less (i.e. a short-term lease), a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize right-of-use assets and lease liabilities. If a lessee makes this election, it should generally recognize lease expense for such leases on a straight-line basis over the lease term and short-term lease costs must be disclosed for each period.  The Company currently intends to make this accounting policy election for most or all classes of assets.

The new standard provides a scope exclusion for the rights to use land easements related to oil and gas activities, for which many of our land easement will qualify.  Additionally, the standard allows a practical expedient not to reassess whether land easements existing on January 1, 2019 meet the definition of a lease under the new standard if they were not accounted for as leases under the current standard.  The Company currently intends to make this accounting policy election upon adoption.

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.   Though the full quantitative impacts of the new standard are dependent on the leases in force at the time of adoption, we have determined that the adoption of the standard will result in a material increase to our assets and liabilities due to the recognition on our balance sheet of our office leases and certain equipment.  As we complete our evaluation, we will determine all contracts that are impacted throughout our various disciplines.

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Revenue from Contracts with Customers

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

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

Crude oil sales contracts

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

Natural gas sales contracts

Our natural gas contracts stipulate that we deliver unprocessed natural gas to a contractually specified delivery point. Once the natural gas enters our customer’s facilities, it may be compressed, dehydrated, treated, separated into residue gas (predominately methane) and NGLs, or otherwise processed.  For a majority of our natural gas sales contracts, 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). 

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

Residue gas contracts

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

Performance obligations fulfilled in a prior period

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

Disaggregation of revenue

The new revenue standard requires that we disaggregate revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors.  Our statement of operations disaggregates revenue to reflect pricing realities present in our contracts with our customers.  The terms of our natural gas sales contracts stipulate that the pricing we receive for our unprocessed natural gas will be based on the volumes of lower value natural gas and higher value NGLs present in the unprocessed natural gas we deliver.  Fees assessed by our customers (that reduce revenue) are allocated between gas and NGLs on a volumetric basis or based upon the nature of the fee.

Contributions in aid of construction

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

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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)