S-1 1 d299355ds1.htm S-1 S-1
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As filed with the Securities and Exchange Commission on April 10, 2017.

Registration No. 333-            

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

Form S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

 

 

VINE RESOURCES INC.

(Exact name of registrant as specified in its charter)

 

 

 

Delaware   1311  

81-4833927

(State or other jurisdiction of

incorporation or organization)

 

(Primary Standard Industrial

Classification Code Number)

 

(I.R.S. Employer

Identification No.)

5800 Granite Parkway, Suite 550

Plano, Texas 75024

(469) 606-0540

(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)

 

 

Eric D. Marsh

Chairman and Chief Executive Officer

5800 Granite Parkway, Suite 550

Plano, Texas 75024

(469) 606-0540

(Name, address, including zip code, and telephone number, including area code, of agent for service)

 

 

Copies to:

 

Matthew R. Pacey

Justin F. Hoffman

Kirkland & Ellis LLP

600 Travis Street, Suite 3300

Houston, Texas 77002

(713) 835-3600

 

Alan Beck

Thomas G. Zentner

Vinson & Elkins L.L.P.

1001 Fannin, Suite 2500

Houston, Texas 77002

(713) 758-2222

 

 

Approximate date of commencement of proposed sale of the securities to the public:

As soon as practicable after the effective date of this Registration Statement.

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box:  ☐

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ☐

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ☐

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

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 7(a)(2)(B) of the Securities Act. ☒

 

CALCULATION OF REGISTRATION FEE

 

 

Title of Each Class of

Securities to be Registered

 

Proposed

Maximum

Offering Price(1)(2)

  Amount of
Registration Fee(3)

Class A Common Stock, par value $0.01 per share

  $500,000,000   $57,950

 

 

(1) Includes Class A common stock issuable upon exercise of the underwriters’ option to purchase additional Class A common stock.
(2) Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o) under the Securities Act of 1933, as amended (the “Securities Act”).
(3) To be paid in connection with the initial filing of the registration statement.

 

 

The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933, as amended, or until this registration statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

 

 

 


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The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state or jurisdiction where the offer or sale is not permitted.

 

Subject to Completion, dated April 10, 2017

PROSPECTUS

            Shares

 

 

LOGO

 

Vine Resources Inc.

Class A Common Stock

 

 

This is the initial public offering of the common stock of Vine Resources Inc., a Delaware corporation. We are offering              shares of our Class A common stock. No public market currently exists for our Class A common stock.

We have applied to list our Class A common stock on the New York Stock Exchange under the symbol “VRI.”

We anticipate that the initial public offering price will be between $        and $        per share.

 

 

Investing in our Class A common stock involves risks, including those described under “Risk Factors” beginning on page 21 of this prospectus.

 

     Per
share
     Total  

Price to the public

   $                   $               

Underwriting discounts and commissions(1)

   $                   $               

Proceeds to us (before expenses)

   $                   $               

 

  (1) The underwriters will also be reimbursed for certain expenses incurred in the offering. “Underwriting” contains additional information regarding underwriter compensation.

We are an “emerging growth company” as that term is used in the Jumpstart Our Business Startups Act of 2012, and as such, we have elected to take advantage of certain reduced public company reporting requirements for this prospectus and future filings. “Risk Factors” and “Prospectus Summary — Emerging Growth Company Status” contain additional information about our status as an emerging growth company.

We have granted the underwriters the option to purchase up to         additional shares of Class A common stock on the same terms and conditions set forth above if the underwriters sell more than          shares of Class A common stock in this offering.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed on the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.

The underwriters expect to deliver the shares on or about                     , 2017.

 

 

Joint Book-Running Managers

 

Credit Suisse   Morgan Stanley

Prospectus dated                     , 2017


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LOGO


Table of Contents

TABLE OF CONTENTS

 

    Page  

PROSPECTUS SUMMARY

    1  

RISK FACTORS

    21  

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

    45  

USE OF PROCEEDS

    47  

DIVIDEND POLICY

    48  

CAPITALIZATION

    49  

DILUTION

    50  

SELECTED HISTORICAL AND UNAUDITED PRO FORMA FINANCIAL INFORMATION

    51  

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

    53  

BUSINESS

    73  

MANAGEMENT

    95  

EXECUTIVE COMPENSATION

    99  

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

    106  

CORPORATE REORGANIZATION

    108  

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

    113  

DESCRIPTION OF CAPITAL STOCK

    120  

SHARES ELIGIBLE FOR FUTURE SALE

    128  

MATERIAL U.S. FEDERAL INCOME TAX CONSIDERATIONS FOR NON-U.S. HOLDERS

    130  

UNDERWRITING

    134  

LEGAL MATTERS

    141  

EXPERTS

    141  

WHERE YOU CAN FIND MORE INFORMATION

    141  

INDEX TO FINANCIAL STATEMENTS

    F-1  

 

 

You should rely only on the information contained in this prospectus and any free writing prospectus prepared by us or on behalf of us or to the information which we have referred you. Neither we nor the underwriters have authorized anyone to provide you with information different from that contained in this prospectus and any free writing prospectus. We take no responsibility for, and can provide no assurance as to the reliability of, any other information that others may give you. We and the underwriters are offering to sell shares of Class A common stock and seeking offers to buy shares of Class A common stock only in jurisdictions where offers and sales are permitted. The information in this prospectus is accurate only as of the date of this prospectus, regardless of the time of delivery of this prospectus or any sale of the Class A common stock. Our business, financial condition, results of operations and prospects may have changed since that date. We will update this prospectus as required by law, including with respect to any material change affecting us or our business prior to the completion of this offering.

This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements” contain additional information regarding these risks.

Through and including              (the 25th day after the date of this prospectus), all dealers effecting transactions in our shares, whether or not participating in this offering, may be required to deliver a prospectus. This requirement is in addition to the dealers’ obligation to deliver a prospectus when acting as an underwriter and with respect to an unsold allotment or subscription.

 

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Commonly Used Defined Terms

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

 

    “Blackstone” refers, collectively, to investment funds affiliated with or managed by The Blackstone Group L.P.;

 

    “Existing Owners” refers, collectively, to Blackstone and the Management Members that own equity interests in Vine Oil & Gas LP prior to the completion of our corporate reorganization and in us indirectly through Vine Investment and Vine Investment II as of and following the completion of our corporate reorganization;

 

    “GEP” means GEP Haynesville LLC, a subsidiary of GeoSouthern Energy Corp.;

 

    “JOA” means the Definitive Agreement for the Division of Operatorship for Blacksmith – Magnolia Area of Interest, dated November 1, 2012;

 

    “Management Member” refers to our individual officers and employees who, together with Blackstone, held equity in Vine Oil & Gas LP immediately prior to the corporate reorganization;

 

    “RBL” means the Company’s revolving credit facility, dated as of November 25, 2014, by and among the Company, HSBC Bank USA, National Association, as Administrative Agent, Collateral Agent, Swingline Lender and as Issuing Bank and the banks, financial institutions and other lending institutions from time to time party thereto, as amended;

 

    “Shell” means affiliates of Royal Dutch Shell plc;

 

    “Shell Acquisition” means the acquisition of natural gas properties in the Haynesville Basin of Northwest Louisiana in November 2014 from affiliates of Royal Dutch Shell plc;

 

    “Superpriority” means the Company’s superpriority facility, dated as of February 7, 2017, by and among the Company, HSBC Bank USA, National Association, as Administrative Agent, Swingline Lender and as Issuing Bank and the banks, financial institutions and other lending institutions from time to time party thereto, as amended;

 

    “TLB” or “Term Loan B” means the Company’s second lien term loan, dated November 25, 2014, by and among the Company, Morgan Stanley Senior Funding, Inc., as Administrative Agent and Collateral Agent and the banks, financial institutions and other lending institutions from time to time party thereto, as amended;

 

    “TLC” or “Term Loan C” means the Company’s third lien term loan, dated November 25, 2014, by and among the Company, Morgan Stanley Senior Funding, Inc., as Administrative Agent and Collateral Agent and the banks, financial institutions and other lending institutions from time to time party thereto, as amended;

 

    “Vine,” “we,” “our,” “us” or like terms refer collectively to Vine Oil & Gas LP, our predecessor and its consolidated subsidiaries before the completion of our corporate reorganization described in “Corporate Reorganization” (except as otherwise disclosed) and to Vine Resources Inc. and its consolidated subsidiaries, as of and following the completion of our corporate reorganization;

 

    “Vine Investment” refers to Vine Investment LLC, a Delaware limited liability company formed on December 30, 2016 by the Existing Owners to hold equity interests in us following the corporate reorganization;

 

    “Vine Investment II” refers to Vine Investment II LLC, a Delaware limited liability company formed on March 1, 2017 by the Existing Owners to hold equity interests in us following the corporate reorganization;

 

    “Vine Units” means units representing limited liability company interests in Vine Resources Holdings LLC issued pursuant to the VRH LLC Agreement;

 

    “Von Gonten” means W.D.Von Gonten & Co., our independent reserve engineer; and

 

    “VRH LLC Agreement” means the amended and restated limited liability company agreement of Vine Resources Holdings LLC.

 

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Glossary of Oil and Natural Gas Terms

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

 

    “ARO” means asset retirement obligation;

 

    “Bcf” means one billion cubic feet of natural gas;

 

    “Bcfd” means one billion cubic feet of natural gas per day;

 

    “Btu” means one British thermal unit, the quantity of heat required to raise the temperature of a one-pound mass of water by one degree of Fahrenheit;

 

    “Basin” means a large natural depression on the earth’s surface in which sediments generally brought by water accumulate;

 

    “CapEx” means capital expenditures;

 

    “Completion” means the process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency;

 

    “D&C costs” means drilling and completion costs;

 

    “Developed acreage” means the number of acres that are allocated or assignable to productive wells or wells capable of production;

 

    “Estimated ultimate recovery” or “EUR” means the sum of reserves remaining as of a given date and cumulative production as of that date. As used in this prospectus, EUR includes only proved reserves and is based on our reserve estimates;

 

    “Exploratory well” means a well drilled to find and produce natural gas or oil reserves not classified as proved, to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir or to extend a known reservoir;

 

    “FERC” means the Federal Energy Regulatory Commission;

 

    “Field” means 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;

 

    “Formation” means a layer of rock which has distinct characteristics that differs from nearby rock;

 

    “Henry Hub” means the distribution hub on the natural gas pipeline system in Erath, Louisiana, owned by Sabine Pipe Line LLC, a subsidiary of EnLink Midstream Partners LP who purchased the asset from Chevron Corporation in 2014;

 

    “Horizontal drilling” means 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;

 

    “Identified drilling locations” means total gross (net) resource play locations that we may be able to drill on our existing acreage. A portion of our identified drilling locations constitute estimated locations based on our acreage and spacing assumptions, as described in “Business — Our Operations —Reserve Data —Drilling Locations”. Actual drilling activities may change depending on the availability of capital, regulatory approvals, seasonal restrictions, natural gas and oil prices, costs, drilling results and other factors;

 

    “IDC” means intangible drilling cost;

 

    “Invested capital” means the future capital expenditures required to drill and complete a single well. When used in this prospectus in connection with descriptions of our rate of return, the calculation of “invested capital” assumes such capital expenditures are incurred in period one (with revenue and operating costs recognized until the economic end of a well’s life, at which time abandonment costs are recognized);

 

    “LNG” means liquid natural gas;

 

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    “Mcf” means one thousand cubic feet of natural gas;

 

    “MMBtu” means one million Btu;

 

    “MMcf” means one million cubic feet of natural gas;

 

    “Net acres” means the percentage of total acres an owner has out of a particular number of acres, or a specified tract. An owner who has 50% interest in 100 acres owns 50 net acres;

 

    “NYMEX” means the New York Mercantile Exchange, a commodity futures exchange owned and operated by CME Group of Chicago;

 

    “Productive well” means 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” means 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 developed reserves” means reserves that can be expected to be recovered through existing wells with existing equipment and operating methods;

 

    “Proved reserves” means the estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions;

 

    “Proved undeveloped reserves” or “PUDs” means 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;

 

    “Recompletion” means the process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production;

 

    “Reservoir” means 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 separate from other reservoirs;

 

    “Spacing” means 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;

 

    “Standardized measure” means 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 natural gas and oil properties. Future net cash inflows after income taxes are discounted using a 10% annual discount rate;

 

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

 

    “Unit” means the joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement;

 

    “Wellbore” means the hole drilled by the bit that is equipped for natural gas production on a completed well. Also called well or borehole; and

 

    “Working interest” means the right granted to the lessee of a property to explore for and to 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.

 

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In addition, unless otherwise indicated, the reserve and operational data presented in this prospectus is that of our predecessor as of the dates and for the periods presented. Unless another date is specified or the context otherwise requires, all acreage, well count, hedging and drilling location data presented in this prospectus is as of December 31, 2016. Unless otherwise noted, references to production volumes refer to sales volumes reflective of our net interest.

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

Presentation of Financial and Operating Data

Unless otherwise indicated, the summary historical consolidated financial information presented in this prospectus is that of our predecessor. Additional information may be found under “Corporate Reorganization” and the unaudited pro forma financial statements included elsewhere in this prospectus.

Industry and Market Data

The market data and certain other statistical information used throughout this prospectus are based on independent industry publications, government publications and other published independent sources. Although we believe these third-party sources are reliable as of their respective dates, neither we nor the underwriters have independently verified the accuracy or completeness of this information. The industry in which we operate is subject to a high degree of uncertainty and risk due to a variety of factors, including those described in the section entitled “Risk Factors.” These and other factors could cause results to differ materially from those expressed in these publications.

Trademarks and Trade Names

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

 

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PROSPECTUS SUMMARY

This summary provides a brief overview of information contained elsewhere in this prospectus. Readers should consider this entire prospectus and other referenced documents before making an investment decision. Other material information can be found under “Risk Factors”, “Cautionary Statement Regarding Forward-Looking Statements” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the historical financial statements and the related notes to those financial statements contained elsewhere in this prospectus. Where applicable, we have assumed an initial public offering price of $        per share (the midpoint of the price range set forth on the cover page of this prospectus).

Unless otherwise indicated, the information presented in this prospectus assumes that the underwriters’ option to purchase additional shares of Class A common stock is not exercised. Unless otherwise indicated, the estimated reserve information presented in this prospectus were prepared by our independent reserve engineer as of December 31, 2016 based on the SEC’s reserve pricing rule, as more fully described in “— Reserve and Operating Data.” Certain operational terms used in this prospectus are defined in the “Glossary of Oil and Natural Gas Terms”, and “Commonly Used Defined Terms”.

Our Company

We are a pure play natural gas company focused solely on the development of natural gas properties in the stacked Haynesville and Mid-Bossier shale plays in the Haynesville Basin of Northwest Louisiana. The Haynesville and Mid-Bossier shales are among the highest quality, highest return dry gas resource plays in North America with approximately 489 Tcf of natural gas in place in the Haynesville play, according to the Oil & Gas Journal. The Haynesville Basin has re-emerged in recent years as a result of material increases in well economics driven by advances in enhanced drilling and completion techniques. This has led to higher recoveries on a per lateral foot basis through more frac stages and greater proppant usage combined with a steady reduction in well costs. The Mid-Bossier shale overlays the Haynesville shale and, while earlier in its development life cycle than the Haynesville shale, has demonstrated similar characteristics and well results. Both plays demonstrate high-quality petrophysical characteristics, such as being over-pressured and having high porosity, permeability and thickness. Both plays also exhibit consistent and predictable geology and high EURs relative to D&C costs. In addition, due to significant development activity in the Haynesville Basin beginning in 2008, production and decline rates are predictable, and low-cost midstream infrastructure is currently in place with underutilized capacity. As a result of these factors, as well as our proximity to Henry Hub and other premium Gulf Coast markets, LNG export facilities and other end-users, we believe we benefit from low breakeven costs relative to other North American natural gas plays, such as those in Appalachia and the Rockies.

We first entered the Haynesville Basin in 2014 following our acquisition of assets from Shell, which we refer to as the Shell Acquisition, and as of December 31, 2016, have approximately 95,000 net surface acres in what we believe to be the core of the Haynesville and Mid-Bossier plays. Approximately 90% of our acreage is held by production, providing us with the flexibility to control the pace of development without the threat of lease expiration, and which enables us to capitalize on advancements in drilling and completion technologies and natural gas price movements. Our assets are located almost entirely in Red River, DeSoto and Sabine parishes of Northwest Louisiana, which based on RS Energy Group, have consistently demonstrated higher EURs relative to D&C costs than the Haynesville and Mid-Bossier plays in Texas and other parishes in Louisiana. Over 60% of our acreage is prospective for dual-zone development, providing us with over 1,700 gross horizontal drilling locations. Utilizing eight gross rigs and assuming six wells per 640-acre section, we have over 22 years of organic development opportunities.

 



 

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The following table provides a summary of our inventory of identified drilling locations as of December 31, 2016, including lateral length and drilling location data in each play.

 

Gross Identified Drilling Locations(1)   Standard Lateral(2)     Long Lateral(2)     Total  

Haynesville

    643       182       825  

Mid-Bossier

    596       303       899  
 

 

 

   

 

 

   

 

 

 

Total

    1,239       485       1,724  
 

 

 

   

 

 

   

 

 

 

 

(1) “Business — Our Operations — Drilling Locations” contains a description of our methodology used to determine gross identified drilling locations.
(2) Our typical standard lateral is approximately 4,600 ft and our typical long lateral is approximately 7,500 ft. We classify wells with lateral lengths of less than 5,000 ft as standard laterals and greater than 5,000 ft as long laterals.

Substantially all of our leasehold acreage is held through at least one developed well per section, which maintains all the leasehold position in that section while preserving the ability to drill additional wells in that section. Our acreage has been well delineated by over 500 gross horizontal wells drilled on our acreage in Sabine, Red River and DeSoto parishes, providing us with confidence that our inventory is low-risk and repeatable and able to continue to generate consistent economic returns. In addition, more than 1,000 wells have been drilled on or within one mile of our acreage. The majority of our acreage overlays portions of the Haynesville and Mid-Bossier reservoirs with highly attractive geologic parameters, including high permeability and low clay content which yield strong recoveries, both key advantages when compared with other parishes in Louisiana and portions of East Texas. Our production has grown at a compounded annual growth rate of approximately 48% from third quarter 2015 to fourth quarter 2016 as a result of the 47 wells we have brought online since the Shell Acquisition. For 2016, our average net daily production was 218 MMcfd.

 

 

LOGO

 

(1) The first new Vine-developed well was brought online in September 2015. Compound annual growth rate, or CAGR, represents a calculation of the average annual compounded growth rate of our average daily production from the third quarter of 2015 to the fourth quarter of 2016. The calculation assumes that the growth rate derived from the calculation is even across the periods covered by the calculation and does not take into account any fluctuations in our production for any periods other than the two periods used to calculate the CAGR. Accordingly, the use of CAGR may have limitations.

In addition, we may have opportunities to enhance existing wells as they age through recompletions that utilize current completion technologies in existing wells that have been historically understimulated.

Northwest Louisiana’s extensive legacy midstream infrastructure provides access to substantial gathering capacity, including our third party gatherer’s approximately 500 miles of pipeline and related processing plants with a design capacity of approximately 2.8 Bcfd. We sell our gas at the tailgate of these three processing plants attached to our gatherer’s system and, as a result, incur and hold no direct firm-transportation cost or

 



 

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commitments. Additionally, our proximity to Henry Hub and other premium Gulf Coast markets, LNG export facilities and other end-users results in low transportation costs that provide a competitive advantage compared to other North American dry gas plays such as those in Appalachia and the Rockies. As illustrated in the chart below, our basis differentials have averaged less than $0.10/Mcf over the last two years. We believe these low basis differentials and our long-term access to underutilized midstream infrastructure support the efficient development of our reserves and should enhance our returns.

 

 

LOGO

Our management team has extensive experience in the Haynesville and Mid-Bossier shale plays and a proven track record of implementing large-scale, technically driven development programs to target best-in-class returns in some of the most prominent resource plays across the United States. Many members of our management team have experience working in the Haynesville since its inception as a commercial play and have contributed directly to the technical advancement of the play. Since the Shell Acquisition, our management team has instituted several measures designed to enhance well EURs, including:

 

    adopting enhanced completion technologies and strategies (such as increasing the length of laterals in a typical well, increasing the number of frac stages, increasing the amount of proppant pumped per foot of lateral and reducing cluster spacing);

 

    managing production rates to preserve downhole pressure;

 

    optimizing our simultaneous development footprint through dual-zone bi-directional well pads;

 

    adjusting well spacing and development patterns to enhance inventory and per well reserves; and

 

    improving wellbore landing accuracy.

Our average D&C costs for standard lateral wells brought online in the fourth quarter of 2016 were $1,400 per lateral foot, compared with $1,900 per lateral foot for our wells brought online in 2015, despite an increase of over 50% in the number of frac stages per well brought online during this period. We drilled our first long lateral in the fourth quarter of 2015 and have since increasingly used long laterals to bolster our capital efficiency by allowing us to develop the gas in place while reducing the number of vertical wellbores and associated D&C costs. Our average D&C costs for long lateral wells brought online in the fourth quarter of 2016 were $1,300 per lateral foot.

 



 

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Using the assumptions regarding well costs, operating costs and type curves from our 2016 reserve report, we believe that the gas price necessary to yield a 10% rate of return on invested capital to be below $2.05 for our standard laterals and below $1.80 for the long laterals that we expect to develop over the next 5 years. We believe that these results yield some of the lowest breakeven costs among North American gas plays.

Our 2017 CapEx forecast is approximately $320 million, which is almost entirely allocated to the development of 44 gross (20 net) operated wells and the development of 30 gross (13 net) non-operated wells utilizing 8 to 9 gross rigs. Additionally, our 2017 CapEx forecast includes six gross refracs on older producing wells to capitalize on our knowledge of our 2015 refrac program and our current completion design to significantly improve sectional production. Our forecasted gross well cost assumptions for 2017 reflected an average cost of $7.9 million for our standard laterals and $10.7 million for our long laterals, with long laterals comprising 40% of the 2017 program, and reflect further evolution from our 2016 completion design, which we hope will yield further EUR increases. We believe we can execute our stated growth strategy in future periods with similar levels of CapEx. We also believe that following this offering we could accelerate our development plan and still maintain considerable liquidity and financial flexibility.

History of the Haynesville and Mid-Bossier Shales and of Our Acreage

The Haynesville Shale and the overlying Mid-Bossier Shale were deposited in a Jurassic basin that covers more than 11,000 square miles and includes eight parishes in North Louisiana and eight counties in East Texas, collectively called the Haynesville Basin. These shales were deposited in a deep, restricted basin that preserved the rich organic content and through subsequent burial developed strong reservoir properties, including becoming over-pressured and preserving porosity and permeability. Within our North Louisiana acreage, the Haynesville ranges from 11,500 to over 13,500 ft deep and can be as thick as 200 ft. The Mid-Bossier overlays the Haynesville and ranges from 11,000 to 13,000 ft deep and can be as thick as 350 ft.

Although this area has seen almost continuous drilling since oil and gas was discovered in the early 1900’s, the prospectivity of the Haynesville play was not widely recognized until 2005. During this time, Encana and other operators acquired significant acreage in North Louisiana in an attempt to extend the East Texas Bossier play. Encana drilled and tested Haynesville discovery wells during 2005 and 2006 and subsequently entered into a joint venture with Shell for the development of this acreage position. We purchased Shell’s portion of this acreage in 2014 and GEP purchased the Encana portion during 2015. We continue to be party to the JOA with GEP with respect to the operation and development of the combined acreage. We believe GEP’s primary asset is its acreage in the play, and we expect them to be focused on optimizing development through successful coordination of their development activities and field operations with us, including data sharing.

In 2010, at the height of activity in the basin, 180 rigs were active in the Haynesville Basin as producers were drilling wells to preserve leasehold positions, resulting in the development of significant oilfield services and midstream infrastructure that remains available to accommodate additional volumes arising from current and future drilling activity. The basin experienced a peak production of 10.6 Bcfd in 2011, compared to 6.0 Bcfd in December of 2016, according to the U.S. EIA. Furthermore, the basin is well positioned to capitalize on the emergence of LNG and other export facilities and increasing demand from a southern migration of the U.S. population, the growing petrochemical capacity in the Gulf Coast region and the retirement of certain coal-fired electricity generation.

Since the peak Haynesville production in 2011, our industry has made significant advances in drilling and completion technology and techniques, including longer laterals, geo-steering techniques and changes in completion intensity and design. These trends have resulted in increased EURs per lateral foot with more recent

 



 

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wells trending even higher. We believe our EURs per lateral foot compare favorably with the most prolific basins in North America. At the same time, our average drilling time and well costs have decreased, which combine to yield enhanced economics for development of natural gas reserves in our basin.

Additionally, in 2011, the Louisiana Office of Conservation began to allow cross-unit horizontal drilling, allowing operators the ability to drill across section lines and more efficiently develop acreage. We believe our large and relatively contiguous position within the Haynesville and a streamlined regulatory approval process provides us with an opportunity to capitalize on a development plan that features multi-section lateral lengths.

Although the industry had identified the Mid-Bossier play as resource potential, it had not yet been commercialized in 2012 when falling natural gas prices caused exploration and development in the basin to decrease dramatically. As the Haynesville shale play has been increasingly targeted for development in the last few years, the shallower Mid-Bossier shale play has also experienced increased development activity, and from initial well results, we continue to believe there could be substantial resource potential in the play. 

Business Strategy

Our strategy is to draw upon our management team’s experience in developing natural gas resources to economically grow our production, reserves and cash flow and thus enhance the value of our assets. Our strategy has the following principal elements:

 

    Grow Production, Reserves and Cash Flow Through the Development of Our Pure Play Haynesville Basin Inventory. We have assembled a drilling inventory of more than 1,700 gross locations across our acreage in the Haynesville and Mid-Bossier shale plays. The concentration and scale of our core leasehold positions, coupled with our technical understanding of the reservoirs, allows us to efficiently develop our acreage, increase sectional recoveries over time and allocate capital to enhance the value of our resource base. We believe that our extensive inventory of low-risk drilling locations, combined with our operating expertise and completion design evolution, will enable us to continue to deliver significant production, reserves and cash flow growth and enhance shareholder value.

 

    Maximize Returns by Developing Industry-Leading Drilling and Completion Technologies and Practices. We continue to develop and apply industry-leading practices to lower D&C costs and maximize the recovery factor of gas in place. We have captured significant improvements in our drilling efficiency over time, reducing our cycle time from spud to rig release for our standard lateral by approximately 25% from the fourth quarter of 2015 through the fourth quarter of 2016. These cycle time reductions contribute to lower well costs because approximately 60% of our drilling costs are directly correlated to the number of days required to drill a well. We have also employed enhanced completion techniques (through longer horizontal wellbore laterals, increased frac stages, more proppant loading and reduced cluster spacing) and other drilling-related efficiencies (through dual-zone bi-directional well pads, well spacing and development patterns) to yield increased EURs. Certain of these measures also help increase our capital efficiency by allowing us to develop more reserves per lateral foot while also reducing the number of vertical wellbores and associated development, equipping and abandonment costs.

 

   

Leverage Our Deep Experience in and Ongoing Focus on the Haynesville Basin to Maximize Returns. Eric D. Marsh, our Chief Executive Officer, and other key members of our management participated in the early development of the Haynesville Basin. At the peak of Haynesville activity levels in 2011 and 2012, our core management team operated a 20-plus rig program and oversaw the drilling and completions of hundreds of Haynesville wells. Through their experience, they developed an expertise that allows for continued advancement of industry-leading well completion techniques and drilling and development efficiencies. During 2016, we were among the top two most active operators

 



 

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in the region based on number of the Haynesville and Mid-Bossier wells drilled and completed. Our singular focus on the Haynesville Basin positions us to continue to be a leader in advancing technical aspects of its future development.

 

    Enhance Returns by Focusing on Capital and Operating Cost Efficiencies. We maintain a disciplined, return-focused approach to capital allocation. We have reduced our average cost per well in the Haynesville by approximately 20% from the fourth quarter of 2015 through year end 2016 through substantial reductions in cycle times, utilization of new downhole technologies and management-negotiated cost reductions for oil field products and services. We have continued to develop new techniques and practices to lower D&C costs while increasing our EURs. We expect to mitigate future service cost increases by generating additional operational improvements and efficiencies, including drilling wells from common pad sites, shared use of pre-existing central facilities and other economies of scale. While our industry has benefited from reduced oilfield service pricing during the recent downturn, we believe up to 50% of our reductions to well costs are related to more permanent changes to well design and operational efficiencies that should endure cyclicality in commodity prices. Additionally, we have reduced lease operating expenses through strategic alliances with our key vendors (including reductions in chemical and water costs), cost reductions from our partners related to our non-operated assets and overall service cost reductions. These operating cost reductions are the result of a range of operational improvements, including the addition of a centralized command center which governs substantially all day-to-day well operations and permits more efficient labor deployment. Our command center is designed to be scalable and should yield lower unit costs in the future as new wells come online.

 

    Maintain a Disciplined Financial Strategy While Growing Our Business Organically and Through Opportunistic Acquisitions. We intend to fund our organic growth predominantly with internally generated cash flows while maintaining ample liquidity to weather commodity cycles. We will seek to preserve future cash flows and liquidity levels through a multi-year commodity hedge program with multiple counterparties. Our debt agreements permit us to hedge up to 85% of expected production. We intend to utilize this flexibility to actively hedge the revenue expected to be generated by future development. To further reduce volatility in our cash flows and returns, we will also seek to enter into contracts for oilfield services to be no longer than the periods covered by our commodity hedges. In addition to reducing leverage through the use of proceeds of this transaction, we will endeavor to reduce our leverage over time through the generation of excess cash flows from operations and may consider acquisitions that meet our financial strategy and operational objectives.

Business Strengths

We have a number of strengths that we believe will help us successfully execute our business strategy and enhance shareholder value, including:

 

    Large, Contiguous Acreage Position Concentrated in the Core of the Basin. We own extensive and contiguous acreage positions in what we believe to be the core of the Haynesville and Mid-Bossier shale plays. Through the Shell Acquisition, we entered the Haynesville Basin ahead of renewed industry interest, development and acquisition activity in the region in 2015 and 2016. At that time, we recognized the value in large, contiguous acreage blocks and were successful in acquiring some of the highest quality, most concentrated assets in the basin. Since the Shell Acquisition, we have further delineated our acreage position using industry-leading drilling and completion techniques that have yielded industry-leading well results that we believe will have some of the highest EURs per lateral foot in the basin. Our highly concentrated and contiguous acreage position promotes more efficient development through the ability to deploy longer laterals across adjacent acreage positions, the ability to utilize multi-zone bi-directional well pads and other efficiencies.

 



 

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    More Than 22 Years of High Quality, Low Risk, Drilling Inventory which is 90% Held by Production. Our drilling inventory as of December 31, 2016 consisted of more than 1,700 gross identified drilling locations in both the Haynesville and Mid-Bossier shale plays, which included 485 locations where we intend to utilize longer laterals. Assuming an eight gross drilling rig program, we expect our inventory life of undrilled wells to be greater than 22 years. We have been able to consistently achieve higher returns on our wells with longer laterals including those with lateral lengths in excess of 7,500 ft (significantly longer than a typical standard lateral of 4,600 ft). We may also be able to add horizontal drilling locations across the majority of our acreage position in the future through downspacing. In addition, we may have opportunities to extend the economic life of existing wells as they age through recompletions that utilize current completion technologies in existing wells that have been historically understimulated. We consider our inventory of drilling locations to be low risk because it is in areas where we (and other producers) have extensive drilling and production experience. Because approximately 90% of our acreage is held by production, we have more flexibility than many other operators to control the pace of development without the threat of lease expiration.

 

    High Caliber and Seasoned Management and Technical Team. Our senior management team has substantial experience in the Haynesville Basin and has collectively operated large development programs that helped commercialize the Haynesville shale, as well as other plays, obtained market-leading D&C costs, decreased operating costs and generated increased EURs. Additionally, we have assembled a strong technical supporting staff of petroleum engineers and geologists that have extensive Haynesville and Mid-Bossier shale experience. We believe our team’s expertise will continue to drive drilling, completion and operational improvements that result in increasing EURs and capital efficiency. Furthermore, our management team’s operational and financial discipline, as well as their extensive experience in leadership roles at public companies, gives us confidence of our ability to maintain a well-run public company platform and to successfully navigate the challenges of our cyclical industry.

 

    Close Proximity to Premium Markets through Available Midstream Infrastructure. Our acreage position is in close proximity to premium markets along the Gulf Coast, which results in low basis differentials as compared to other plays, such as the Marcellus, Utica, Permian and Rockies. We believe this allows producers in our basin to benefit from better unit economics and to level the playing field with respect to our marginally higher Haynesville well costs when compared to other basins. Low-cost legacy gathering infrastructure with a design capacity of 2.8 Bcfd is in place across our acreage to support our development program with minimal incremental capital. We are not party to any transportation contracts or similar commitments and the minimum volume commitments in our gathering contracts materially decrease in August 2019 and further decrease in April 2020 before they completely expire in January 2021, at which point the gathering rate in place through 2025 at approximately $0.31 per MMbtu is highly competitive. Because our only production is dry gas, we also have minimal cost to process our gas to meet pipeline specifications, which, based on current natural gas liquids pricing, may give us an economic advantage as compared to wet gas plays.

 

   

Low Operating Cost Structure with Significant Control Across Our Acreage Position Through Our JOA. We have implemented several initiatives to enhance and manage our base production in the region. In early 2015, we established an advanced technology 24-hour automated command center from which we can remotely control the majority of field-wide operations from a single location. We developed a field-wide infrastructure capable of bringing new wells online by adding limited additional fixed lease operating costs. The automated process reduces manpower needs and allows operators to focus on production efficiency, by, among other things, efficiently deploying labor through a centralized operating center. As we continue to bring new wells online, we expect our unit costs will continue to decline. We continue to increase margins through operational efficiencies, more effective chemical solutions and improved maintenance programs. We have significant control across our

 



 

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acreage position through our JOA with GEP, which grants us and them the ability to propose drilling on acreage operated by the other party.

 

    Significant Liquidity and Financial Flexibility. Upon completion of this offering and the application of net proceeds therefrom, we will have approximately $          million of liquidity which includes availability under our RBL and cash on hand. Our RBL has a $350 million floor, which should provide us with sufficient liquidity to manage future commodity cycles. As we continue converting our large inventory of undeveloped drilling locations to producing wells, we expect our cash flow and borrowing base to grow, thereby further enhancing our liquidity and financial strength. We believe this ample liquidity should provide us with sufficient capital to grow our production, increase shareholder value and weather any future industry downturn. Our RBL, maturing in November 2019, is our earliest stated debt maturity, but we can extend the maturity to November 2021 through two payments of a 25 basis point extension fee. In addition, we have built a hedge portfolio that extends into 2019 to protect us against downward movements of natural gas pricing and to support the achievement of our stated growth objectives. We also have interest rate swaps that protect our cash flows on floating rate debt against LIBOR increases. We evaluate and utilize swaps and collars to provide certainty of cash flows and to establish a minimum targeted return on our invested capital.

Risk Factors

An investment in our Class A common stock involves a number of risks. Potential investors should carefully consider, in addition to the other information contained in this prospectus, the risks described in “Risk Factors” before investing in our Class A common stock. These risks could materially affect our business, financial condition and results of operations and cause the trading price of our Class A common stock to decline. In reviewing this prospectus, we stress that past experience is no indication of future performance, and “Cautionary Statement Regarding Forward-Looking Statements” contains a discussion of what types of statements are forward-looking statements, as well as the significance of such statements in the context of this prospectus.

Corporate Reorganization

Vine Resources Inc. is a Delaware corporation that was formed for the purpose of making this offering. Following this offering and the transactions related thereto, Vine Resources Inc. will be a holding company whose sole material asset will consist of membership interests in Vine Resources Holdings LLC. Vine Resources Holdings LLC will own all of the outstanding limited partnership interests in Vine Oil & Gas LP, the operating subsidiary through which we operate our assets, and all of the outstanding equity in Vine Oil & Gas GP LLC, the general partner of Vine Oil & Gas LP. After the consummation of the transactions contemplated by this prospectus, Vine Resources Inc. will be the sole managing member of Vine Resources Holdings LLC and will control and be responsible for all operational, management and administrative decisions relating to Vine Resources Holdings LLC’s business and will consolidate the financial results of Vine Resources Holdings LLC and its subsidiaries.

In connection with this offering, (a) the Existing Owners will contribute all of their equity interests in Vine Oil & Gas LP and Vine Oil & Gas GP LLC to Vine Resources Holdings LLC in exchange for newly issued equity in Vine Resources Holdings LLC (the “LLC Interests”), (b) the Existing Owners will contribute a portion of their LLC Interests to Vine Investment II in exchange for newly issued equity interests in Vine Investment II and Vine Investment II will exchange the LLC Interests for Class A common stock, (c) Vine Resources Inc. will contribute the net proceeds of this offering to Vine Resources Holdings LLC in exchange for newly-issued managing units in Vine Resources Holdings LLC and (d) the Existing Owners will exchange the remaining portion of their LLC Interests for a new class of equity in Vine Resources Holdings LLC, the Vine Units, receive newly issued Class B common stock of Vine Resources Inc. with no economic rights, and will contribute all of their Vine Units and Class B common stock to Vine Investment in exchange for newly issued equity interests in

 



 

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Vine Investment. After giving effect to these transactions and the offering contemplated by this prospectus, Vine Resources Inc. will own an approximate     % interest in Vine Resources Holdings LLC (or     % if the underwriters’ option to purchase additional shares is exercised in full), Vine Investment will own an approximate     % interest in Vine Resources Holdings LLC (or     % if the underwriters’ option to purchase additional shares is exercised in full), and Vine Investment II will own an approximate     % interest in Vine Resources Inc. (or     % if the underwriters’ option to purchase additional shares is exercised in full). “Security Ownership of Certain Beneficial Owners and Management” contains more information.

Each share of Class B common stock will entitle its holder (the “Vine Unit Holders”) to one vote on all matters to be voted on by shareholders. Holders of Class A common stock and Class B common stock will vote together as a single class on all matters presented to our shareholders for their vote or approval, except as otherwise required by applicable law or by our certificate of incorporation. We do not intend to list Class B common stock on any stock exchange.

We will enter into a Tax Receivable Agreement with Vine Investment. This agreement generally provides for the payment by Vine Resources Inc. to Vine Investment of 85% of the net cash savings, if any, in U.S. federal, state and local income tax or franchise tax that Vine Resources Inc. actually realizes (or is deemed to realize in certain circumstances) in periods after this offering as a result of (i) the tax basis increases resulting from the exchange of Vine Units by Vine Investment for shares of Class A common stock pursuant to the exchange agreement and (ii) imputed interest deemed to be paid by us as a result of, and additional tax basis arising from, any payments we make under the Tax Receivable Agreement. Vine Resources Inc. will retain the benefit of the remaining 15% of these cash savings. If we experience a change of control (as defined under the Tax Receivable Agreement, which includes certain mergers, asset sales and other forms of business combinations) or the Tax Receivable Agreement terminates early (at our election or as a result of our breach), we could be required to make a substantial, immediate lump-sum payment. “Certain Relationships and Related Party Transactions—Tax Receivable Agreement” contains more information.

 



 

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The following diagrams indicate our current ownership structure and our simplified ownership structure immediately following this offering and the transactions related thereto (assuming that the underwriters’ option to purchase additional shares is not exercised):

Simplified Current Ownership Structure

LOGO

 

 



 

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Simplified Ownership Structure After Giving Effect to this Offering

LOGO

Our Principal Stockholders

Following the completion of this offering and our corporate reorganization, Blackstone and Management Members will in the aggregate own 100% of our Class B common stock through Vine Investment, representing

 



 

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approximately     % of the voting power of Vine Resources Inc., (    % if the underwriters’ option to purchase additional shares is exercised in full), and         % of our Class A common stock through Vine Investment II, representing         % of the voting power of Vine Resources Inc., (        % if the underwriters’ option to purchase additional shares is exercised in full). Vine Investment and Vine Investment II are controlled by Blackstone, our private equity sponsor.

Blackstone is one of the world’s leading investment firms. Blackstone’s asset management businesses, with over $360 billion in assets under management, include investment vehicles focused on private equity, real estate, public debt and equity, non-investment grade credit, real assets and secondary funds, all on a global basis. Blackstone has committed and invested $13.6 billion and 32 energy private equity transactions throughout the energy and natural resources value chain on a global basis, primarily through Blackstone Energy Partners L.P., Blackstone Energy Partners II L.P., Blackstone Capital Partners VI L.P. and Blackstone Capital Partners VII L.P. Investments in oil and natural gas assets represent a substantial portion of this activity and include leading independent onshore and offshore exploration and production companies in North America and globally.

Emerging Growth Company Status

We are an “emerging growth company” as defined in the JOBS Act. For as long as we are an emerging growth company, unlike other public companies that don’t meet those qualifications, we are not required to:

 

    provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of SOX;

 

    provide more than two years of audited financial statements and related management’s discussion and analysis of financial condition and results of operations in a registration statement on Form S-1;

 

    comply with any new requirements adopted by PCAOB requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer;

 

    provide certain disclosure regarding executive compensation required of larger public companies or hold shareholder advisory votes on executive compensation required by the Dodd-Frank Act; or

 

    obtain shareholder approval of any golden parachute payments not previously approved.

We will cease to be an “emerging growth company” upon the earliest of:

 

    the last day of the year in which we have $1 billion or more in annual revenue;

 

    the date on which we become a “large accelerated filer” (which means the year-end at which the total market value of our common equity securities held by non-affiliates is $700 million or more as of June 30);

 

    the date on which we issue more than $1 billion of non-convertible debt securities over a three-year period; and

 

    the last day of the year following the fifth anniversary of our initial public offering.

In addition, Section 107 of the JOBS Act provides that an emerging growth company can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act of 1933, as amended (the “Securities Act”), for complying with new or revised accounting standards, but we have irrevocably opted out of the extended transition period and, as a result, we will adopt new or revised accounting standards on the relevant dates in which adoption of such standards is required for other public companies.

 



 

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Corporate Information

Our principal executive offices are located at 5800 Granite Parkway, Suite 550, Plano, Texas 75024, and our telephone number at that address is (469) 606-0540. Our website is located at www.vineres.com. We expect to make our periodic reports and other information filed with or furnished to the SEC available free of charge through our website as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on, or otherwise accessible through, our website or any other website is not incorporated by reference herein and does not constitute a part of this prospectus.

 



 

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The Offering

 

Class A common stock offered by us

                 shares (or                  shares, if the underwriters exercise in full their option to purchase additional shares).

 

Class A common stock to be outstanding after the offering

                 shares (or                  shares, if the underwriters exercise in full their option to purchase additional shares).

 

Option to purchase additional shares

We have granted the underwriters a 30 day option to purchase up to an aggregate of                  additional shares of our Class A common stock.

 

Class B common stock to be outstanding immediately after completion of this offering

                 shares, or one share for each Vine Unit held by the Vine Unit Holders immediately following this offering. Class B shares are non-economic. When a Vine Unit is exchanged for a share of Class A common stock, a corresponding share of Class B common stock will be cancelled.

 

Use of proceeds

We expect to receive approximately $         million of net proceeds (assuming the midpoint of the price range set forth on the cover of this prospectus) from the sale of the Class A common stock offered by us (or approximately $         million, if the underwriters exercise in full their option to purchase additional shares) after deducting underwriting discounts and commissions and estimated offering expenses payable by us. Each $1.00 change in the public offering price would change our net proceeds by approximately $        million.

 

  We intend to use the net proceeds from this offering to repay indebtedness and to provide liquidity for general corporate purposes. “Use of Proceeds” contains additional information regarding our intended use of proceeds from this offering.

 

Conflicts of Interest

Because affiliates of Credit Suisse Securities (USA) LLC and Morgan Stanley & Co. LLC are lenders under the RBL, and each will receive 5% or more of the net proceeds of this offering to the extent proceeds from this offering are used to repay amounts outstanding thereunder, each of these underwriters is deemed to have a conflict of interest within the meaning of Rule 5121 of the Financial Industry Regulatory Authority, Inc. (“FINRA”) Rules. Accordingly, this offering is being conducted in accordance with FINRA Rule 5121, which requires, among other things, that a “qualified independent underwriter” participate in the preparation of, and exercise the usual standards of “due diligence” with respect to, the registration statement and this prospectus.              has agreed to

 



 

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act as a qualified independent underwriter for this offering.              will not receive any additional fees for serving as a qualified independent underwriter in connection with this offering. We have agreed to indemnify              against liabilities incurred in connection with acting as a qualified independent underwriter, including liabilities under the Securities Act. “Underwriting—Certain Relationships” contains additional information.

 

Voting Power of Class A common stock after giving effect to this offering

     % or (or 100% if all outstanding Vine Units held by the Vine Unit Holders are exchanged, along with a corresponding number of shares of our Class B common stock, for newly-issued shares of Class A common stock on a one-for-one basis).

 

Voting Power of Class B common stock after giving effect to this offering

     % or (or 0% if all outstanding Vine Units held by the Vine Unit Holders are exchanged, along with a corresponding number of shares of our Class B common stock, for newly-issued shares of Class A common stock on a one-for-one basis).

 

Voting rights

Vine Investment, an entity that will be owned by the Existing Owners, will hold all of the outstanding shares of our Class B common stock. Each share of Class B common stock will entitle its holder to one vote on all matters to be voted on by shareholders generally. Vine Investment II, an entity that will be owned by the Existing Owners, will hold     % of the outstanding shares of our Class A common stock. The Class A common stock will be voting stock and entitle each holder to one vote per share of Class A common stock. “Description of Capital Stock” contains more information.

 

Dividend policy

We do not anticipate paying any cash dividends to holders of our Class A common stock. In addition, our existing debt instruments place certain restrictions on our ability to pay cash dividends to the holders of our Class A common stock. “Dividend Policy” includes additional information.

 

Risk factors

The “Risk Factors” section beginning on page 21 contains additional information that should be carefully read and considered before deciding to invest in our common stock.

 

Listing and trading symbol

We have applied to list our common stock on the New York Stock Exchange (the “NYSE”) under the symbol “VRI.”

 

Exchange rights of holders of Vine Units

Prior to the completion of this offering we will enter into an exchange agreement with Vine Investment so that it may (subject to the terms of the exchange agreement) exchange its Vine Units for shares of Class A common stock of Vine Resources Inc. on a one-for-one basis,

 



 

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subject to customary conversion rate adjustments for stock splits, stock dividends and reclassifications (the “Exchange Right”) or cash at our election (the “Cash Option”). “Certain Relationships and Related Party Transactions—Exchange Agreement” contains more information.

 

Tax receivable agreement

Future exchanges of Vine Units for shares of Class A common stock are expected to result in increases in the tax basis of the tangible and intangible assets of Vine Resources Holdings LLC. The anticipated basis adjustments are expected to increase (for tax purposes) our depreciation and depletion deductions and may also decrease our gains (or increase our losses) on future dispositions of certain capital assets to the extent tax basis is allocated to those capital assets. Such increased deductions and losses and reduced gains may reduce the amount of tax that we would otherwise be required to pay in the future. Prior to the completion of this offering, we will enter into a tax receivable agreement with Vine Investment that provides for the payment by Vine Resources Inc. to exchanging holders of Vine Units of 85% of the benefits, if any, that Vine Resources Inc. actually or is deemed to realize as a result of (i) the tax basis increases resulting from the exchange of Vine Units by Vine Investment for shares of Class A common stock (or cash pursuant to the Cash Option) pursuant to the Exchange Right and (ii) imputed interest deemed to be paid by us as a result of, and additional tax basis arising from, any payments we make under the Tax Receivable Agreement. If we experience a change of control (as defined under the Tax Receivable Agreement, which includes certain mergers, asset sales and other forms of business combinations) or the Tax Receivable Agreement terminates early (at our election or as a result of our breach), we could be required to make a substantial, immediate lump-sum payment. “Certain Relationships and Related Party Transactions—Tax Receivable Agreement” contains more information.

The information above excludes             shares of Class A common stock reserved for issuance under our long-term incentive plan that we intend to adopt in connection with the completion of this offering.

In addition, it does not give effect to the grant of an aggregate of approximately                 restricted stock units (based on the midpoint of the price range set forth on the cover page of this prospectus) that our board of directors has agreed to make to certain of our directors, officers and employees in connection with the completion of this offering.

 



 

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Summary Historical and Unaudited Pro Forma Financial Information

The following table shows summary historical financial information of our predecessor, and summary unaudited pro forma financial information for the periods and as of the dates indicated. The summary historical financial information as of December 31, 2016 and 2015, and for the years then ended, was derived from the audited historical financial statements of our predecessor included elsewhere in this prospectus.

The summary unaudited pro forma income statement for 2016 has been prepared to give pro forma effect to (i) the reorganization transactions described under “Corporate Reorganization”, (ii) the closing and funding of the Superpriority and (iii) this offering and the application of the net proceeds from this offering as if they had been completed as of January 1, 2016. The summary unaudited pro forma balance sheet information has been prepared to give pro forma effect to those transactions as if they had been completed as of December 31, 2016. This information is subject to and gives effect to the assumptions and adjustments described in the notes accompanying the unaudited pro forma financial statements included elsewhere in this prospectus. The summary unaudited pro forma financial information is presented for informational purposes only and should not be considered indicative of actual results of operations that would have been achieved had the reorganization transactions and this offering been consummated on the dates indicated, and do not purport to be indicative of statements of financial position or results of operations as of any future date or for any future period.

 



 

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“Use of Proceeds,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” the historical financial statements and the unaudited pro forma financial statements included elsewhere in this prospectus contain additional information to be read in conjunction with the following table.

 

    Predecessor     Vine Resources Inc.
Pro Forma
 
    Years Ended December 31,     Year Ended December 31,  
    2016     2015           2016        
    (in thousands, except per share data)  

Statement of operations information:

     

Natural gas sales

  $ 184,490     $ 154,005     $           

Realized gain on commodity derivatives

    63,803       30,038    

Unrealized gain (loss) on commodity derivatives

    (144,634     91,008    
 

 

 

   

 

 

   

 

 

 

Total revenue

    103,659       275,051    

Lease operating

    23,071       26,190    

Gathering and treating

    26,817       24,085    

Production and ad valorem taxes

    9,088       13,109    

General and administrative

    3,812       9,349    

Depreciation, depletion and accretion

    115,755       118,217    

Exploration

    2,072       2,056    

Acquisition-related

    —         207    
 

 

 

   

 

 

   

 

 

 

Total operating expenses

    180,615       193,213    
 

 

 

   

 

 

   

 

 

 

Operating income

    (76,956     81,838    
 

 

 

   

 

 

   

 

 

 

Interest expense

    (84,423     (87,911  

Income tax provision

    (217     —      
 

 

 

   

 

 

   

 

 

 

Net income

  $ (161,596   $ (6,073   $  
 

 

 

   

 

 

   

 

 

 

Less net income attributable to non-controlling interest

     
 

 

 

   

 

 

   

 

 

 

Net income attributable to Vine Resources Inc.

     
 

 

 

   

 

 

   

 

 

 

Balance sheet information (end of period):

     

Cash and cash equivalents

  $ 19,204     $ 15,367    

Total natural gas properties, net

    1,374,668       1,320,288    

Total assets

    1,504,963       1,523,316    

Total debt

    978,372       839,825    

Total partners’ capital/stockholders’ equity

    285,547       446,310    

Net cash provided by (used in):

     

Operating activities

  $ 30,948     $ (27,026  

Investing activities

    (155,387     (103,496  

Financing activities

    128,276       29,910    

Other financial information:

     

Adjusted EBITDAX(1)

  $ 177,945     $ 110,052     $  

Earnings (loss) per share — basic

     

Earnings (loss) per share — diluted

     

 

(1) Adjusted EBITDAX is not a financial measure calculated in accordance with GAAP, but we believe it provides important perspective regarding our operating results. “— Non-GAAP Financial Measure” below contains a description of Adjusted EBITDAX and a reconciliation to our net income.

 



 

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Non-GAAP Financial Measure

We define Adjusted EBITDAX as our net income before interest expense, income taxes, depreciation, depletion and amortization, exploration expense and impairment of oil and gas properties, unrealized earnings on derivatives and other non-cash operating items.

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

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

 

     Predecessor     Vine Resources Inc.
Pro Forma
 
     Years Ended December 31,    

Year Ended December 31,

 
           2016                 2015                 2016        
     (in thousands)  

Net income

   $ (161,596   $ (6,073   $           

Interest expense

     84,423       87,911    

Income tax provision

     217       —      

Depletion, depreciation and accretion

     115,755       118,217    

Unrealized (gain) loss on commodity derivatives

     144,634       (91,008  

Exploration

     2,072       2,056    

Non-cash G&A

     (265     833    

Non-cash volumetric and production adjustment to gas gathering liability

     (7,295     (1,884  
  

 

 

   

 

 

   

 

 

 

Adjusted EBITDAX

   $ 177,945     $ 110,052     $  
  

 

 

   

 

 

   

 

 

 

 



 

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Summary Reserve, Production and Operating Data

Summary Reserve Data

The following table summarizes estimated proved reserves as of December 31, 2016 based on a report prepared by Von Gonten, our independent reserve engineer. All of these reserve estimates were prepared in accordance with the SEC’s rule regarding reserve reporting currently in effect.

The information in the following table does not give any effect to or reflect our commodity hedge portfolio. “Business — Our Operations — Reserve Data” contains additional information about our reserves.

 

     SEC Pricing(2)     Strip Pricing(3)  

2016 Estimated proved reserves:(1)

    

Natural gas (MMcf)

     1,518,339       1,574,350  

Total proved developed reserves (MMcf)

     207,883       234,099  

Percent proved developed

     14     15

Total proved undeveloped reserves (MMcf)

     1,310,456       1,340,251  

 

(1) Our reserve information reflects an assumed 30-year reserve life.
(2) Our estimated proved reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance. As of December 31, 2016, the SEC Price Deck was $2.49/MMBtu (Henry Hub Price) for natural gas. In determining our reserves, the SEC Price Deck was adjusted for basis differentials and other factors affecting the prices we receive, which yielded a price of $2.35 per Mcf.
(3) Our estimated net proved NYMEX reserves were prepared on the same basis as our SEC reserves, except for the use of pricing based on closing monthly futures prices as reported on the NYMEX for oil and natural gas on January 4, 2017 rather than using the average of the first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance. Prices were in each case adjusted for basis differentials and other factors affecting the prices we receive. Our NYMEX reserves were determined using index prices for natural gas, without giving effect to derivative transactions. “Business — Our Operations — Reserve Data — Adjusted Index Prices Used in Reserve Calculations” contains the adjusted realized prices under strip pricing. Actual future prices may vary significantly from the NYMEX prices on January 4, 2017; therefore, actual volumes of reserves recovered and the value generated may be more or less than the estimated amounts. “Risk Factors — Risks Related to Our Business — Natural gas prices are volatile. A reduction or sustained decline in prices may adversely affect our business, financial condition or results of operations and our ability to meet our financial commitments” and “Risk Factors — Risks Related to Our Business — Reserve estimates depend on many assumptions that may turn out to be inaccurate” contain more information regarding the uncertainty associated with price and reserve estimates.

Select Production and Operating Statistics

 

     Years Ended December 31,  
           2016                  2015        

Production data:

     

Natural gas (MMcf)

     79,893        63,362  

Average daily production (MMcfd)

     218        174  

Average sales prices per Mcf:

     

Before effects of derivatives

   $ 2.31      $ 2.43  

After effects of realized derivatives

   $ 3.11      $ 2.91  

Costs per Mcf:

     

Lease operating

   $ 0.29      $ 0.41  

Gathering and treating

   $ 0.34      $ 0.38  

Production and ad valorem taxes

   $ 0.11      $ 0.21  

Depreciation, depletion and accretion

   $ 1.45      $ 1.87  

General and administrative

   $ 0.05      $ 0.15  

 



 

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RISK FACTORS

Investing in our Class A common stock involves risks. The information in this prospectus should be considered carefully, including the matters addressed under “Cautionary Statement Regarding Forward-Looking Statements,” and the following risks before making an investment decision. The risks and uncertainties described below are not the only ones we face. Additional risks not presently known to us or that we currently deem immaterial may also materially affect our business. The occurrence of any of the following risks or additional risks and uncertainties that are currently immaterial or unknown could materially and adversely affect our business, financial condition, liquidity, results of operations, cash flows or prospects. The trading price of our Class A common stock could decline due to any of these risks, and you may lose all or part of your investment.

Risks Related to Our Business

Natural gas prices are volatile. A reduction or sustained decline in prices may adversely affect our business, financial condition or results of operations and our ability to meet our financial commitments.

Prevailing natural gas prices heavily influence our revenue, profitability, access to capital, growth rate and value of our properties. Further, although we do not produce oil, to the extent oil prices rise considerably, the cost of services we incur may also increase. As a commodity, gas prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the natural gas market has been volatile. Prices for domestic natural gas began to decline during the third quarter of 2014 and have been pressured since then, despite a modest recovery in oil prices. Spot prices for Henry Hub generally ranged from $2.00 per MMBtu to $4.00 per MMBtu over the period from 2014 to 2017. Our revenue, profitability and future growth are highly dependent on the prices we receive for our natural gas production, and the levels of our production, depend on numerous factors beyond our control. These factors include the following:

 

    worldwide and regional economic conditions impacting the global supply of and demand for natural gas;

 

    the actions of OPEC, its members and other state-controlled oil companies relating to oil price and production controls;

 

    the level of global exploration and production;

 

    the level of global inventories;

 

    prevailing prices on local price indexes in the areas in which we operate and expectations about future commodity prices;

 

    extent of natural gas production associated with increased oil production;

 

    the proximity, capacity, cost and availability of gathering and transportation facilities;

 

    localized and global supply and demand fundamentals and transportation availability;

 

    weather conditions across North America and, increasingly due to LNG, across the globe;

 

    technological advances affecting energy consumption;

 

    speculative trading in natural gas markets;

 

    end-user conservation trends;

 

    petrochemical, fertilizer, ethanol, transportation supply and demand balance;

 

    the price and availability of alternative fuels;

 

    domestic, local and foreign governmental regulation and taxes; and

 

    liquefied petroleum products supply and demand balances.

 

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If commodity prices decrease or we experience negative basis differentials, our cash flows and refinancing ability will be reduced. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our reserves as existing reserves are depleted. Lower commodity prices may also reduce the amount of natural gas that we can produce economically. Additionally, a significant portion of our projects could become uneconomic and require us to abandon or postpone our planned drilling, which could result in downward adjustments to our estimated proved reserves. As a result, a reduction or sustained decline in natural gas prices may materially and adversely affect our financial condition, results of operations, liquidity and our ability to finance CapEx.

We may be unable to obtain required capital or financing on satisfactory terms, which could lead to a decline in our production and natural gas reserves.

Our industry is capital intensive, requiring substantial CapEx to develop and acquire natural gas reserves. The actual amount and timing of our future CapEx may differ materially from our estimates as a result of, among other things, natural gas prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments. A reduction or sustained decline in natural gas prices from current levels may force us to reduce our CapEx, which would negatively impact our ability to grow production. We intend to finance our CapEx through cash flow from operations and through available capacity under our RBL; however, our financing needs may require us to alter or increase our capitalization substantially through the issuance of debt or equity securities or the sale of assets. The issuance of additional indebtedness requires compliance with the terms of our existing indebtedness and would require us to incur additional interest and principal, which may affect our ability to fund working capital, CapEx and acquisitions.

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

 

    our proved reserves;

 

    the volume of natural gas we are able to produce from existing wells;

 

    the prices at which our production is sold;

 

    our ability to acquire, locate and produce new reserves;

 

    the extent and levels of our derivative activities;

 

    the levels of our operating expenses; and

 

    our ability to access the capital markets.

If our cash flow decreases as a result of lower natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to fund our planned CapEx or operations. If additional capital is needed, we may not be able to obtain financing on terms acceptable to us, if at all.

Our business strategy includes continued use of advancements in horizontal drilling and completion techniques, which involve risks and uncertainties in their application.

Our current and future operations involve utilizing some of the latest drilling and completion techniques. While drilling and completing our wells, we face risks associated with:

 

    effectively controlling downhole pressure;

 

    landing and maintaining our wellbore in the desired drilling zone;

 

    running our casing the entire length of the wellbore;

 

    deploying tools and other equipment consistently downhole;

 

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    stimulating the formation with the planned number of stages; and

 

    cleaning out the wellbore after final fracture stimulation.

In addition, some of the techniques may cause irregularities or interruptions in existing production due to offset wells being shut in. The development of new formations is more uncertain initially than in proven areas that are more developed and have a longer history of established production. Newer or emerging formations and areas have limited or no production history and, consequently, we are more limited in assessing future drilling results in these areas. If our actual results are less than anticipated, it may trigger reduced cash flow and impairment of our properties.

Our industry requires us to navigate many uncertainties that could adversely affect our financial condition and results of operations.

Our financial condition and results of operations depend on the success of our development and acquisition activities, which are subject to numerous risks beyond our control, including the risk that development will not result in commercially viable production or uneconomic results or that various characteristics of the drilling process or the well will cause us to abandon the well prior to fully producing commercially viable quantities.

Our decisions to purchase, explore or develop properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. “— Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions could materially affect the quantities and present value of our reserves” contains additional information regarding this risk. In addition, our actual development cost for a well could significantly exceed planned levels.

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

 

    reductions or sustained declines in natural gas prices;

 

    regulatory compliance, including limitations on wastewater disposal, discharge of greenhouse gases and hydraulic fracturing;

 

    geological formation irregularities and pressures

 

    shortages of or delays in obtaining equipment, supplies and qualified personnel;

 

    equipment failures, accidents or other unexpected operational events;

 

    gathering facilities’ capacity or delays in construction of new gathering facilities;

 

    capacity on transmission pipelines or our inability to make our gas meet quality specifications for such pipeline;

 

    environmental hazards, such as natural gas leaks, pipeline and tank ruptures and unauthorized discharges of brine and other fluids, toxic gases or other pollutants;

 

    natural disasters including regional flooding;

 

    availability of financing at acceptable terms; and

 

    title issues.

Any of these risks can cause substantial losses, including personal injury or loss of life, damage to property, reserves and equipment, pollution, environmental contamination and regulatory penalties.

 

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Our gathering contracts require fees on minimum volumes regardless of throughput.

Our gathering contracts require delivery of minimum volumes of gas for each annual contract period and require settlement payments for any shortfalls in the gathered volumes. The minimum volume commitments in our gathering contracts step down from 705,000 MMbtud in 2016 to 377,000 MMbtud in August 2019 and to 95,000 MMbtud in April 2020 before expiring in January 2021. As of December 31, 2016, our expected annual future cash obligation under these agreements is $75-80 million. The fees we are required to pay under these gathering contracts may have a material adverse effect on our liquidity and results of operations.

Our revenue will ultimately depend on our ability to transport our gas to various sales points.

We do not own or control third-party transportation facilities and our access to them may be limited or denied, because we do not have contracts for firm transportation. We currently sell our gas at the tailgate of our gatherer’s treating plants. The purchasers of our gas are typically parties who hold firm transportation and who, after taking possession of our gas, use it to fulfill their volume commitments. Today, there is ample transportation capacity, and there are ample holders of firm transportation who are willing to engage in the types of arrangements we use. If demand for transportation surged or if parties holding firm transport satisfied volume commitments with their own or others’ gas, we may be unable to sell our gas, which would materially and adversely affect our financial condition and results of operations.

We may be unable to generate sufficient cash to service all of our indebtedness and financial commitments.

Our ability to make scheduled payments on or to refinance our indebtedness and financial commitments depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. We may be unable to generate sufficient cash flow to permit us to pay the principal, premium, if any, and interest on our indebtedness.

If our cash flows and capital resources are insufficient to fund debt and other obligations, we may be forced to reduce or delay CapEx, sell assets, seek additional capital or restructure our indebtedness. Our ability to restructure or refinance indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our operations. The terms of existing or future debt instruments may restrict us from adopting some of these alternatives. In addition, any failure to service our debt would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. If we face substantial liquidity problems, we might be required to sell assets to meet debt and other obligations. Our debt restricts our ability to dispose of assets and dictates our use of the proceeds from such disposition. We may not be able to consummate dispositions, and the proceeds of any such disposition may be inadequate to meet obligations.

We may be unable to access adequate funding as a result of a decrease in borrowing base due to an unwillingness or inability on the part of lending counterparties to meet their funding obligations and the inability of other lenders to provide additional funding to cover a defaulting lender’s portion. As a result, we may be unable to execute our development plan, make acquisitions or otherwise conduct operations, which would have a material adverse effect on our financial condition and results of operations.

Restrictions associated with our debt agreements could limit our growth and our ability to engage in certain activities.

Our debt agreements contain a number of significant covenants that may limit our ability to, among other things:

 

    incur additional indebtedness;

 

    sell assets;

 

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    make loans to or investments in others;

 

    enter into mergers;

 

    make certain payments;

 

    hedge future production or interest rates;

 

    incur liens;

 

    pay dividends, and

 

    engage in certain other transactions without the prior consent of the lenders.

In addition, our RBL requires us to maintain certain financial ratios. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants impose on us.

If we fail to comply with the restrictions and covenants in our debt agreements, there could be an event of default under the terms of such agreements, which could result in an acceleration of payment.

A breach of any covenant in any of our debt agreements would result in a default under the applicable agreement after any applicable grace periods. A default could result in acceleration of the indebtedness which would have a material adverse effect on us. If an acceleration occurs, it would likely accelerate all of our indebtedness through cross-default provisions and we would likely be unable to make all of the required payments to refinance such indebtedness. Even if new financing were available at that time, it may not be on terms that are acceptable to us.

Reserve estimates depend on many assumptions that may turn out to be inaccurate.

The process of estimating natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of our reserves.

In order to prepare reserve estimates, we project production rates, timing and pace of development. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as D&C costs, operating costs, and production and ad valorem taxes.

Actual future production revenue, taxes, development costs and operating expenses will vary from our estimates. In addition, we may adjust reserve estimates to reflect production history, changes in existing commodity prices and other factors, many of which are beyond our control.

We do not believe that the present value of future net revenue from our reserves calculated in accordance with the method prescribed by the SEC is the current market value of our reserves. We generally base the estimated value of our properties on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in current estimates.

We will not be the operator on a substantial portion of our existing and future producing locations.

Of our future drilling locations, we do not expect to operate approximately half of such locations almost all of which we expect GEP to operate. Our JOA with GEP provides for our ability to propose wells on acreage operated by them; however, we still have lesser rights than we would have if we were the operator, and there is risk that our partners may have economic, business or legal interests or goals that are inconsistent with ours.

 

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Furthermore, the development activities conducted by GEP will depend on a number of factors that will be largely outside of our control, including:

 

    their desired timing for CapEx;

 

    their expertise and financial resources;

 

    their selection of technology and the application thereof;

 

    their production rate; and

 

    their management of the asset and its future value.

These factors, to the extent not aligned with our objectives, could adversely impact the expected rate and success of our development.

We participate with third parties who may have economic, business or legal interests or goals that are inconsistent with ours.

We own less than 100% of the working interest in the areas where we conduct operations, and other parties own the remaining portion of the working interest. Our JOA with GEP provides that either we or GEP may propose wells on acreage operated by the other party; however, in the event that either party does not consent to such a proposal, the proposing party is permitted to drill the well at their cost. If we choose not to participate on a well proposed by GEP and they proceed to drill that well, we would be excluded from the costs and economic benefits of that well, likely for its entire life. This could cause a material change in the value of the assets we own and could yield recognition of impairments and forgone rights of ownership. Furthermore, with respect to GEP’s operated properties, we generally have lesser rights than we would have if we were the operator, and there is a risk that our partners may have economic, business or legal interests or goals that are inconsistent with ours.

Our identified drilling locations are scheduled out over many years, making them susceptible to uncertainties regarding the timing or likelihood of their development. In addition, we may lack sufficient capital necessary to develop our identified drilling locations.

We have a multi-year development plan. These to-be-developed locations represent a significant part of our growth strategy. Our ability to develop these locations depends on a number of uncertainties, including natural gas prices, the availability and cost of capital, drilling and production costs, availability of services and equipment, gathering system and pipeline transportation constraints, regulatory approvals and other factors. In addition, we will require significant capital over a prolonged period in order to develop these locations, and we may not be able to raise, generate or maintain the capital required to do so. Because of these uncertainties, we cannot be certain that all identified locations may be developed successfully.

All of our producing properties are located in the Haynesville and Mid-Bossier shale in Northwest Louisiana, making us vulnerable to risks associated with operating in only one geographic area.

As a result of our geographic concentration, an adverse development in the industry in our operating area could have a greater impact on our financial condition and results of operations than if we were more geographically diverse. We may also be disproportionately exposed to the impact of regional supply and demand factors, impact of governmental regulation, or midstream capacity constraints. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.

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

The existence of a material title deficiency can render a lease worthless. In the course of acquiring the rights to develop natural gas, it is standard procedure for us and the lessor to execute a lease agreement with payment

 

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subject to title verification. In most cases, we incur the expense of retaining lawyers to verify the rightful owners of the gas interests prior to payment of such lease bonus to the lessor. There is no certainty, however, that a lessor has valid title to their lease’s gas interests. In those cases, such leases are generally voided and payment is not remitted to the lessor. As such, title failures may result in fewer net acres to us. Prior to the drilling of a natural gas well, however, it is the normal practice in our industry for the person or company acting as the operator of the well to obtain a preliminary title review to ensure there are no obvious defects in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct defects in the marketability of the title, and such curative work entails expense. Our failure to cure any title defects may delay or prevent us from utilizing the associated mineral interest, which may adversely impact our ability in the future to increase production and reserves. Accordingly, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss.

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

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

The credit risk of financial institutions could adversely affect us.

We have entered into transactions with counterparties in the financial services industry, including commercial banks, investment banks, insurance companies and other institutions. These transactions expose us to credit risk in the event of default of our counterparty. Deterioration in the credit markets may impact the credit ratings of our current and potential counterparties and affect their ability to fulfill their existing obligations to us and their willingness to enter into future transactions with us. We have exposure to financial institutions in the form of derivative transactions in connection with our hedges and insurance companies in the form of claims under our policies. In addition, if any lender under the RBL is unable to fund its commitment, our liquidity will be reduced by an amount up to the aggregate amount of such lender’s commitment under the RBL.

The failure of our hedge counterparties, significant customers or working interest holders to meet their obligations to us may adversely affect our financial results.

Our hedging transactions expose us to the risk that a counterparty fails to perform under a derivative contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the derivative contract and we may not be able to realize the benefit of the derivative contract. Any default by the counterparty to these derivative contracts when they become due would have a material adverse effect on our financial condition and results of operations.

We also face credit risk through joint interest receivables and the sale of our natural gas production, which totaled approximately 30 purchasers during 2016. Joint interest receivables arise from billing entities who own partial interest in the wells we operate. We are also subject to credit risk due to concentration of our natural gas receivables with several significant customers. We do not require our customers to post collateral. The inability or failure of our significant customers or working interest holders to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.

 

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We may not be able to enter into commodity derivatives on favorable terms or at all.

We enter into financial commodity derivative contracts to mitigate financial risk caused by changes to market factors. However, we currently rely on less than ten counterparties with whom we have negotiated operative hedging documents. We have, at times, been unable to secure sufficient capacity with these counterparties, even when markets reached a level at which we would have been willing to transact. If we are unable to maintain sufficient hedging capacity with our counterparties, we could have greater exposure to changes in commodity prices and LIBOR, which could have a material adverse impact on our business, financial condition and results of operations.

Our operations are subject to stringent environmental laws and regulations that may expose us to significant costs and liabilities that could exceed current expectations.

Our operations are subject to stringent and complex federal, state and local laws and regulations governing the release, disposal or discharge of materials into the environment, health and safety aspects of our operations, or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations applicable to our operations including the acquisition of a permit before conducting regulated drilling activities; the restriction of types, quantities and concentration of materials that can be released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from our operations. Numerous governmental authorities, such as the U.S. Environmental Protection Agency (“EPA”), and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them. Such enforcement actions often involve taking difficult and costly compliance measures or corrective actions. We may be required to make significant capital and operating expenditures or perform remedial or other corrective actions at our wells and properties to comply with the requirements of these environmental laws and regulations or the terms or conditions of permits issued pursuant to such requirements. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, the imposition of investigatory or remedial obligations, and the issuance of orders limiting or prohibiting some or all of our operations. In addition, we may experience delays in obtaining or be unable to obtain required permits, which may delay or interrupt our operations and limit our growth and revenue.

There is inherent risk of incurring significant environmental costs and liabilities in the performance of our operations due to our handling of petroleum hydrocarbons, other hazardous substances and wastes, as a result of air emissions and wastewater discharges related to our operations, and because of historical operations and waste disposal practices. Spills or other releases of regulated substances, including such spills and releases that occur in the future, could expose us to material losses, expenditures and liabilities under applicable environmental laws and regulations. Under certain of such laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination, regardless of whether we were responsible for the release or contamination and even if our operations met previous standards in the industry at the time they were conducted. In connection with certain acquisitions, we could acquire, or be required to provide indemnification against, environmental liabilities that could expose us to material losses. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. Our insurance may not cover all environmental risks and costs or may not provide sufficient coverage if an environmental claim is made against us. Moreover, public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stringent environmental legislation and regulations applied to the crude oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly well drilling, construction, completion or water management activities or waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our industry in general in addition to our own results of

 

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operations, competitive position or financial condition. For example, the EPA has designated energy extraction as one of six national enforcement initiatives for 2014 to 2016 and 2017 to 2019, and has indicated that the agency will direct resources towards addressing incidences of noncompliance from natural gas extraction and production activities. Also, in May 2016, the EPA finalized rules regarding criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting requirements. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements, our business, prospects, financial condition or results of operations could be materially adversely affected.

Federal and state legislative and regulatory initiatives regarding hydraulic fracturing as well as governmental reviews of such activities could increase our costs of doing business, result in additional operating restrictions or delays, limit the areas in which we can operate and reduce our natural gas production, which could adversely impact our production and business.

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. Hydraulic fracturing involves the injection of water, sand or alternative proppant and chemicals under pressure into target geological formations to fracture the surrounding rock and stimulate production. We regularly use hydraulic fracturing as part of our operations. Recently, there has been increased public concern regarding an alleged potential for hydraulic fracturing to adversely affect drinking water supplies, and proposals have been made to enact separate federal, state and local legislation that would increase the regulatory burden imposed on hydraulic fracturing.

At present, hydraulic fracturing is regulated primarily at the state level, typically by state oil and natural gas commissions and similar agencies. Along with several other states, Louisiana (where we conduct operations) has adopted laws and proposed regulations that require oil and natural gas operators to disclose chemical ingredients and water volumes used to hydraulically fracture wells, in addition to more stringent well construction and monitoring requirements. In addition, local governments may also adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular or prohibit the performance of well drilling in general or hydraulic fracturing in particular. If new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

In addition, EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance in February 2014 addressing the performance of such activities using diesel fuels in those states where EPA is the permitting authority. In May 2014, the EPA issued an Advance Notice of Proposed Rulemaking to collect data on chemicals used in hydraulic fracturing operations under Section 8 of the Toxic Substances Control Act. Further, the EPA finalized regulations under the federal Clean Water Act (“CWA”) in June 2016 prohibiting wastewater discharges from hydraulic fracturing and certain other natural gas operations to publicly-owned wastewater treatment plants. Also, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain circumstances. In addition, the federal Bureau of Land Management (“BLM”) finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal and American Indian lands; however, the U.S. District Court of Wyoming struck down this rule in June 2016. An appeal of this decision is pending. On March 15, 2017, the BLM filed a motion in the appeal, requesting the court to hold the case in abeyance pending rescission of the rule.

 

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Federal and state legislative and regulatory initiatives relating to pipeline safety that require the use of new or more stringent safety controls or result in more stringent enforcement of applicable legal requirements could subject us to increased capital costs, operational delays and costs of operation.

Pursuant to the authority under the Natural Gas Pipeline Safety Act (“NGPSA”) and the Hazardous Liquid Pipeline Safety Act (“HLPSA”), as amended by the Pipeline Safety Improvement Act of 2002, the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“2011 Pipeline Safety Act”) and the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (“2016 Pipeline Safety Act”), the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) has promulgated regulations requiring pipeline operators to develop and implement integrity management programs for certain gas and hazardous liquid pipelines that, in the event of a pipeline leak or rupture could affect “high consequence areas,” which are areas where a release could have the most significant adverse consequences, including high-population areas, certain drinking water sources and unusually sensitive ecological areas. These regulations require operators of covered pipelines to:

 

    perform ongoing assessments of pipeline integrity;

 

    identify and characterize applicable threats to pipeline segments that could impact a high consequence area;

 

    improve data collection, integration and analysis;

 

    repair and remediate the pipeline as necessary; and

 

    implement preventive and mitigating actions.

In addition, states have adopted regulations similar to existing PHMSA regulations for certain intrastate gas and hazardous liquid pipelines. At this time, we cannot predict the ultimate cost of compliance with applicable pipeline integrity management regulations, as the cost will vary significantly depending on the number and extent of any repairs found to be necessary as a result of pipeline integrity testing, but the results of these tests could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the safe and reliable operation of our pipelines.

The 2016 Pipeline Safety Act is the most recent federal legislation to amend the NGPSA and HLPSA pipeline safety laws, requiring increased safety measures for gas and hazardous liquids pipelines. The 2016 Pipeline Safety Act extends PHMSA’s statutory mandate through 2019 and, among other things, requires PHMSA to complete certain of its outstanding mandates under the 2011 Pipeline Safety Act and to develop new safety standards for natural gas storage facilities by June 2018. The 2016 Pipeline Safety Act also empowers PHMSA to address imminent hazards by imposing emergency restrictions, prohibitions and safety measures on owners and operators of gas or hazardous liquid pipeline facilities without prior notice or an opportunity for a hearing. Changes to pipeline safety laws by Congress and regulations by PHMSA or states that result in more stringent or costly safety standards could have a significant adverse effect on us and similarly situated midstream operators.

For example, in March of 2015, PHMSA finalized new rules applicable to gas and hazardous liquid pipelines that, among other changes, impose new post-construction inspections, welding, gas component pressure testing requirements, as well as requirements for calculating pressure reductions for immediate repairs on liquid pipelines. Also, in March 2016 PHMSA published a proposed rulemaking that would expand integrity management requirements and impose new pressure testing requirements on currently regulated pipelines. The proposal would also significantly expand the regulation of gathering lines, subjecting previously unregulated pipelines to requirements regarding damage prevention, corrosion control, public education programs, maximum allowable operating pressure limits, and other requirements. The safety enhancement requirements and other provisions of the 2016 Pipeline Safety Act as well as any implementation of PHMSA, rules thereunder could require us to install new or modified safety controls, pursue additional capital projects, or conduct maintenance

 

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programs on an accelerated basis, any or all of which tasks could result in our incurring increased operating costs that could have a material adverse effect on our results of operations or financial position.

Moreover, effective October 2013, PHMSA adopted new rules increasing the maximum administrative civil penalties for violation of the pipeline safety laws and regulations that occur after January 3, 2012 to $200,000 per violation per day and up to $2 million for a related series of violations. Federal and state legislative and regulatory initiatives relating to pipeline safety that require the use of new or more stringent safety controls or result in more stringent enforcement of applicable legal requirements could subject us to increased capital costs, operational delays and costs of operation.

We are subject to risks associated with climate change.

The EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, establish Prevention of Significant Deterioration, or PSD, construction and Title V operating permit reviews for certain large stationary sources. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established on a case-by-case basis. EPA rulemakings related to GHG emissions could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and gas production sources in the United States on an annual basis, which include certain of our operations. Recently, in December 2015, the EPA finalized rules that added new sources to the scope of the greenhouse gases monitoring and reporting rule. These new sources include gathering and boosting facilities as well as completions and workovers from hydraulically fractured oil wells. The revisions also include the addition of well identification reporting requirements for certain facilities. Furthermore, in May 2016, the EPA finalized rules that establish new controls for emissions of methane from new, modified or reconstructed sources in the oil and natural gas source category, including production, processing, transmission and storage activities. The rule includes first-time standards to address emissions of methane from equipment and processes across the source category, including hydraulically fractured oil and natural gas well completions. The BLM has also proposed rules to reduce methane emissions from venting, flaring, and leaking on public lands. As a result of this continued regulatory focus, future federal GHG regulations of the oil and gas industry remain a possibility.

In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of GHGs and a number of states have already taken legal measures to reduce emissions of GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Internationally, in December 2015, the United States was one of many countries at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France that prepared an agreement requiring member countries to review and “represent a progression” in their nationally determined contributions which set GHG emissions reduction goals every five years. However, the GHG emission reductions called for by this Paris agreement are not binding and future participation in the agreement by the United States at this time remains uncertain. The adoption of legislation or regulatory programs to reduce emissions of GHGs could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.

 

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

Our operations are subject to risks associated with the energy industry, including the possibility of:

 

    environmental hazards, such as uncontrollable releases of natural gas, brine, well fluids, toxic gas or other pollution into the environment;

 

    abnormally pressured formations;

 

    mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse;

 

    fires, explosions and ruptures of pipelines;

 

    personal injuries and death;

 

    natural disasters; and

 

    terrorist attacks targeting natural gas and oil related facilities and infrastructure.

Any of these risks could adversely affect our operations and result in substantial loss to us for:

 

    injury or loss of life;

 

    damage to and destruction of property, natural resources and equipment;

 

    pollution and other environmental damage;

 

    regulatory investigations and penalties;

 

    suspension of our operations; and

 

    repair and remediation costs.

In accordance with what we believe to be customary industry practice, we maintain insurance against some, but not all, of our business risks. Our insurance may not be adequate to cover any losses or liabilities we may suffer. Also, insurance may no longer be available to us or, and if it is, its availability may be at premium levels that do not justify its purchase. The occurrence of a significant uninsured claim or a claim in excess of the insurance coverage limits we maintain could have an adverse effect on our ability to conduct normal business operations and on our financial condition, results of operations or cash flows. In addition, we may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial condition. We may also be liable for environmental damage caused by previous owners of properties purchased by us, which liabilities may not be covered by insurance.

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

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

Although we believe that the vast majority of our identified development locations are technically proved, any unsuccessful development in commercially viable quantities will adversely affect our results of operations and financial condition. The use of micro-seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether natural gas will be present or, if present, whether natural gas will be present in commercial quantities. We can provide no assurance that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects. Further, our drilling operations may be curtailed, delayed or cancelled as a result of numerous factors, including:

 

    unexpected drilling conditions;

 

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    title problems;

 

    pressure or lost circulation in formations;

 

    equipment failure or accidents;

 

    adverse weather conditions;

 

    compliance with environmental and other governmental or contractual requirements; and

 

    increase in the cost of, or shortages or delays in the availability of, electricity, supplies, materials, drilling or workover rigs, equipment and services.

In the future, we may make acquisitions of businesses that we believe complement or expand our current business. We may not be able to identify attractive acquisition opportunities, or if we do, we may be unable to complete the acquisition or do so on commercially acceptable terms.

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

In addition, our debt agreements impose certain limitations on our ability to enter into mergers or combination transactions and limit our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions.

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

The demand for qualified and experienced field and technical personnel to conduct our operations can fluctuate significantly, often in correlation with hydrocarbon prices. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. Furthermore, it is possible that oil prices may increase without a corresponding increase in natural gas prices, which could lead to increased demand and prices for supplies and personnel, and necessary equipment and services may become unavailable to us at economical prices. Any shortages in available human capital could delay or cause us to incur significant expenditures that are not provided for in our capital budget, which could have a material adverse effect on our business, financial condition or results of operations.

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

Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing natural gas and securing trained personnel. Also, there is substantial competition for capital available for investment in our industry. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to pay more for productive natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel has increased may increase

 

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substantially in the future. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business.

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

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

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

Our predecessor was organized as a Delaware limited partnership on May 28, 2014. As a result, our company has only limited historical financial and operating information available upon which to base your evaluation of our performance.

Events of force majeure may limit our ability to operate our business and could adversely affect our operating results.

The weather, unforeseen events, or other events of force majeure in the areas in which we operate could cause disruptions and, in some cases, suspension of our operations. This suspension could result from a direct impact to our properties or result from an indirect impact by a disruption or suspension of the operations of those upon whom we rely for gathering and transportation. If disruption or suspension were to persist for a long period, our results of operations would be materially impacted.

Increases in interest rates could adversely affect our business.

We require continued access to capital. Our business and operating results can be harmed by factors such as the availability, terms of and cost of capital, increases in interest rates or a reduction in credit rating. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flow used for drilling and place us at a competitive disadvantage. Recent and continuing disruptions and volatility in the global energy capital markets may lead to a contraction in credit availability impacting our ability to finance our operations. A significant reduction in cash flows from operations or the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.

If commodity prices decrease and our assets’ fair value is less than their carrying value, we will recognize impairments.

We periodically review the carrying value of our assets for possible impairment. Natural gas prices are a critical component to our fair value estimate of our natural gas properties. If these prices decline, we will record an impairment, which is a non-cash charge to earnings, if we determine that an asset’s carrying value exceeds its estimated fair value. Impairment expense may have a material adverse effect on our earnings.

The enactment of derivatives legislation and related regulations have had an adverse effect on our ability to use derivatives to hedge risks associated with our business.

The Dodd-Frank Act, enacted on July 21, 2010, establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The Dodd-Frank Act requires the Commodity Futures Trading Commission (“CFTC”) and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. Although the CFTC has finalized some regulations, including critical rulemakings on the definition of “swap,” “swap dealer,” and “major swap participant,” others remain to be finalized and it is not possible at this time to predict when this will be accomplished.

 

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The Dodd-Frank Act authorized the CFTC to establish rules and regulations setting position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. The CFTC’s initial position limits rules were vacated by the U.S. District Court for the District of Columbia in September 2012. However, on November 5, 2013, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this time.

The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing. The CFTC has not yet proposed rules designating any other classes of swaps, including physical commodity swaps, for mandatory clearing. In addition, certain banking regulators and the CFTC have recently adopted final rules establishing minimum margin requirements for uncleared swaps. Although we expect to qualify for the end-user exception from the mandatory clearing, trade execution and margin requirements for swaps entered to hedge our commercial risks, the application of such requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. If any of our swaps do not qualify for the commercial end-user exception, posting of collateral could impact liquidity and reduce our cash available for CapEx, therefore reducing our ability to execute hedges to reduce risk and protect cash flows.

The Dodd-Frank Act and regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, and reduce our ability to monetize or restructure our existing derivative contracts. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund CapEx.

Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenue could therefore be adversely affected if a consequence of the Dodd-Frank Act and regulations is lower commodity prices.

In addition, the European Union and other non-U.S. jurisdictions are implementing regulations with respect to the derivatives market. To the extent we transact with counterparties in foreign jurisdictions, we may become subject to such regulations, the impact of which is not clear at this time.

Future legislation may result in the elimination of certain U.S. federal income tax deductions currently available with respect to natural gas exploration and production. Additionally, future federal or state legislation may impose new or increased taxes or fees on natural gas extraction.

In past years, legislation has been proposed that, if enacted into law, would make significant changes to U.S. federal and state income tax laws, including to certain key U.S. federal income tax incentives currently available to energy companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance; (ii) the elimination of current deductions for IDC; (iii) the elimination of the deduction for certain U.S. production activities; and (iv) an extension of the amortization period for geological and geophysical expenditures. Congress could consider any or all of these proposals as part of tax reform legislation. Moreover, other features of tax reform legislation could include changes to cost recovery rules and to the deductibility of interest expense, which could adversely affect us. It is unclear when or if any of these or similar changes will be enacted. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal and state income tax laws could eliminate or postpone the underlying tax deductions and any such change could negatively affect our financial condition and results of operations.

 

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Risks Related to the Offering and our Class A Common Stock

We are a holding company. Our sole material asset after completion of this offering will be our equity interest in Vine Resources Holdings LLC and we are accordingly dependent upon distributions from Vine Resources Holdings LLC to pay taxes, make payments under the Tax Receivable Agreement and cover our corporate and other overhead expenses.

We are a holding company and will have no material assets other than our equity interest in Vine Resources Holdings LLC. “Corporate Reorganization” contains more information. We have no independent means of generating revenue. To the extent Vine Resources Holdings LLC has available cash, we intend to cause Vine Resources Holdings LLC to generally make pro rata distributions to its unitholders, including us, in an amount sufficient to cover all applicable taxes at assumed tax rates and payments under the Tax Receivable Agreement we will enter into with Vine Resources Holdings LLC and the Vine Unit Holders, and to reimburse us for our corporate and other overhead expenses. We are limited, however, in our ability to cause Vine Resources Holdings LLC and its subsidiaries to make these and other distributions to us due to the restrictions under our credit facilities. To the extent that we need funds and Vine Resources Holdings LLC or its subsidiaries are restricted from making such distributions under applicable law or regulation or under the terms of their financing arrangements, or are otherwise unable to provide such funds, it could materially adversely affect our liquidity and financial condition.

The requirements of being a public company, including compliance with the reporting requirements of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and the requirements of the Sarbanes-Oxley Act, may strain our resources, increase our costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner.

As a public company, we will need to comply with new laws, regulations and requirements, certain corporate governance provisions of SOX, related regulations of the SEC and the requirements of the NYSE, with which we were not required to comply as a private company. Complying with these statutes, regulations and requirements will occupy a significant amount of our time and will significantly increase our costs and expenses. We will need to:

 

    institute a more comprehensive compliance function to test and conclude on the sufficiency of our internal controls around financial reporting;

 

    comply with rules promulgated by the NYSE;

 

    prepare and distribute periodic public reports;

 

    establish new internal policies, such as those relating to insider trading; and

 

    involve and retain to a greater degree outside professionals in the above activities.

Furthermore, while we generally must comply with Section 404 of the SOX for our year ended December 31, 2016, we are not required to have our independent registered public accounting firm attest to the effectiveness of our internal controls until our first annual report subsequent to our ceasing to be an “emerging growth company.” We may not be required to have our independent registered public accounting firm attest to the effectiveness of our internal controls until as late as our annual report for the year ending December 31, 2022. At any time, we may conclude that our internal controls, once tested, are not operating as designed or that the system of internal controls does not address all relevant financial statement risks. Once required to attest to control effectiveness, our independent registered public accounting firm may issue a report that concludes it does not believe our internal controls over financial reporting are effective. Compliance with SOX requirements may strain our resources, increase our costs and distract management; and we may be unable to comply with these requirements in a timely or cost-effective manner.

There is no existing market for our Class A common stock, and we do not know if one will develop.

Prior to this offering, there has not been a public market for our Class A common stock. We cannot predict the extent to which investor interest in our company will lead to the development of an active trading market on

 

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the stock exchange on which we list our Class A common stock or otherwise or how liquid that market might become. If an active trading market does not develop, anyone purchasing our Class A common stock may have difficulty selling it. The initial public offering price for the Class A common stock was determined by negotiations between us and the representatives of the underwriters and may not be indicative of prices that will prevail in the open market following this offering. Consequently, purchasers of our Class A common stock may be unable to sell it at prices equal to or greater than the price paid.

The stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our Class A common stock. Securities class action litigation has often been instituted against companies following periods of volatility in the overall market and in the market price of a company’s securities. Such litigation, if instituted against us, could result in very substantial costs, divert our management’s attention and resources and harm our business, operating results and financial condition.

Vine Investment and Vine Investment II will collectively hold a substantial majority of our common stock.

Holders of Class A common stock and Class B common stock will vote together as a single class on all matters presented to our shareholders for their vote or approval, except as otherwise required by applicable law or our certificate of incorporation. Upon completion of this offering (assuming no exercise of the underwriters’ option to purchase additional shares), Vine Investment II will own approximately     % of our Class A common stock and Vine Investment will own 100% of our Class B common stock (representing     % of our combined economic interest and voting power).

Although the Existing Owners, through this ownership in Vine Investment and Vine Investment II, are entitled to act separately in their own respective interests with respect to their stock in us, the Existing Owners will together have the ability to elect all of the members of our board of directors, and thereby to control our management and affairs. In addition, they will be able to determine the outcome of all matters requiring shareholder approval, including mergers and other material transactions, and will be able to cause or prevent a change in the composition of our board of directors or a change of control of our company that could deprive our shareholders of an opportunity to receive a premium for their Class A common stock as part of a sale of our company. The existence of significant shareholders may also have the effect of deterring hostile takeovers, delaying or preventing changes in control or changes in management, or limiting the ability of our other shareholders to approve transactions that they may deem to be in the best interests of our company.

So long as the Existing Owners continue to control a significant amount of our common stock, the Existing Owners will, through their ownership interests in Vine Investment, be able to strongly influence all matters requiring stockholder approval, regardless of whether or not other stockholders believe that a potential transaction is in their own best interests. In any of these matters, the interests of the Existing Owners may differ or conflict with the interests of our other stockholders. Moreover, this concentration of stock ownership may also adversely affect the trading price of our Class A common stock to the extent investors perceive a disadvantage in owning stock of a company with a controlling stockholder.

Conflicts of interest could arise in the future between us and Blackstone and its affiliates, including their portfolio companies concerning conflicts over our operations or business opportunities.

Blackstone is a private equity investment fund, and has investments in other companies in the energy industry. As a result, Blackstone may, from time to time, acquire interests in businesses that directly or indirectly compete with our business, as well as businesses that are our customers or suppliers. As such, Blackstone or its portfolio companies may acquire or seek to acquire the same assets that we seek to acquire and, as a result, those acquisition opportunities may not be available to us or may be more expensive for us to pursue. Any actual or perceived conflicts of interest with respect to the foregoing could have an adverse impact on the trading price of our Class A common stock.

 

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Our amended and restated certificate of incorporation and amended and restated bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our Class A common stock.

Our amended and restated certificate of incorporation authorizes our board of directors to issue preferred stock without stockholder approval. If our board of directors elects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our amended and restated certificate of incorporation and amended and restated bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders, including:

 

    limitations on the removal of directors;

 

    limitations on the ability of our stockholders to call special meetings;

 

    establishing advance notice provisions for stockholder proposals and nominations for elections to the board of directors to be acted upon at meetings of stockholders;

 

    the requirement that the affirmative vote of holders representing at least 66  23% of the voting power of all outstanding shares of capital stock (or a majority of the voting power of all outstanding shares of capital stock if Blackstone beneficially owns at least 30% of the voting power of all such outstanding shares) be obtained to amend our amended and restated bylaws, to remove directors or to amend our certificate of incorporation;

 

    providing that the Board of Directors is expressly authorized to adopt, or to alter or repeal our bylaws; and

 

    establishing advance notice and certain information requirements for nominations for election to our Board of Directors or for proposing matters that can be acted upon by stockholders at stockholder meetings.

In addition, certain change of control events have the effect of accelerating the payment due under our Tax Receivable Agreement, which could be substantial and accordingly serve as a disincentive to a potential acquirer of our company. “—In certain cases, payments under the Tax Receivable Agreement may be accelerated and/or significantly exceed the actual benefits, if any, we realize in respect of the tax attributes subject to the Tax Receivable Agreement” contains more information.

Investors in this offering will experience immediate and substantial dilution of $         per share.

Based on an assumed initial public offering price of $         per share (the midpoint of the range set forth on the cover of this prospectus), purchasers of our Class A common stock in this offering will experience an immediate and substantial dilution of $         per share in the as adjusted net tangible book value per share of Class A common stock from the initial public offering price, and our as adjusted net tangible book value as of December 31, 2016 on a pro forma basis would be $         per share. This dilution is due in large part to earlier investors having paid substantially less than the initial public offering price when they purchased their shares. “Dilution” contains additional information.

We do not intend to pay dividends on our Class A common stock and our debt instruments place certain restrictions on our ability to do so.

We do not plan to declare dividends on shares of our Class A common stock in the foreseeable future. Additionally, our debt agreements place certain restrictions on our ability to pay cash dividends. Consequently, to achieve a return on any investment in us, it might require a sale of our Class A common stock at a price greater than cost. There is no guarantee that the price of our Class A common stock that will prevail in the market will ever exceed the price paid in this offering.

 

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Future sales of our Class A common stock in the public market could reduce our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.

Subject to certain limitations and exceptions, the Vine Unit Holders may exchange their Vine Units (together with shares of Class B common stock) for shares of Class A common stock (on a one-for-one basis, subject to conversion rate adjustments for stock splits, stock dividends and reclassification and other similar transactions) and then sell those shares of Class A common stock. Additionally, we may issue additional shares of Class A common stock or convertible securities in subsequent public offerings. After the completion of this offering, we will have                  outstanding shares of Class A common stock and                  outstanding shares of Class B common stock. This number includes                  shares of Class A common stock that we are selling in this offering and the                  shares of Class A common stock that we may sell in this offering if the underwriters’ option to purchase additional shares is fully exercised, which may be resold immediately in the public market. Following the completion of this offering, the Existing Owners, through Vine Investment and Vine Investment II, will own                  shares of Class A common stock and                  shares of Class B common stock, representing approximately     % (or     % if the underwriters’ option to purchase additional shares is exercised in full) of our total outstanding common stock. All such shares are restricted from immediate resale under the federal securities laws and are subject to the lock-up agreements between such parties and the underwriters described in “Underwriting,” but may be sold into the market in the future. Vine Investment and Vine Investment II will be party to a registration rights agreement with us that will require us to effect the registration of their shares in certain circumstances no earlier than the expiration of the lock-up period contained in the underwriting agreement entered into in connection with this offering. “Shares Eligible for Future Sale” and “Certain Relationships and Related Party Transactions—Registration Rights Agreement” contain more information.

We cannot predict the size of future issuances of our common stock or securities convertible into common stock or the effect, if any, that future issuances and sales of shares of our Class A common stock will have on the market price of our Class A common stock. Sales of substantial amounts of our Class A common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our Class A common stock.

The underwriters of this offering may waive or release parties to the lock-up agreements entered into in connection with this offering, which could adversely affect the price of our Class A common stock.

We, Vine Investment, Vine Investment II and all of our directors and executive officers have entered into lock-up agreements with respect to their Class A common stock, pursuant to which we and they are subject to certain resale restrictions for a period of 180 days following the effectiveness date of the registration statement of which this prospectus forms a part. The underwriters, at any time and without notice, may release all or any portion of the Class A common stock subject to the foregoing lock-up agreements. If the restrictions under the lock-up agreements are waived, then Class A common stock will be available for sale into the public markets, which could cause the market price of our Class A common stock to decline and impair our ability to raise capital. “Underwriting” provides additional information regarding the lock-up agreements.

We will be required to make payments under the Tax Receivable Agreement for certain tax benefits we may claim, and the amounts of such payments could be significant.

We will enter into a Tax Receivable Agreement with Vine Investment. This agreement generally provides for the payment by us to Vine Investment of 85% of the net cash savings, if any, in U.S. federal, state and local income tax or franchise tax that we actually realize (or are deemed to realize in certain circumstances) in periods after this offering as a result of (i) the tax basis increases resulting from the exchange of Vine Units by such Vine Investment for shares of Class A common stock pursuant to the Exchange Right and (ii) imputed interest deemed to be paid by us as a result of, and additional tax basis arising from, any payments we make under the Tax Receivable Agreement. In addition, payments we make under the Tax Receivable Agreement will be increased by any interest accrued from the due date (without extensions) of the corresponding tax return.

 

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The payment obligations under the Tax Receivable Agreement are our obligations and not obligations of Vine Resources Holdings LLC. For purposes of the Tax Receivable Agreement, cash savings in tax generally are calculated by comparing our actual tax liability to the amount we would have been required to pay had we not been able to utilize any of the tax benefits subject to the Tax Receivable Agreement. The amounts payable, as well as the timing of any payments, under the Tax Receivable Agreement are dependent upon significant future events and assumptions, including the timing of the exchanges of Vine Units, the price of our Class A common stock at the time of each exchange, the extent to which such exchanges are taxable transactions, the amount of the exchanging Vine Unit Holder’s tax basis in its Vine Units at the time of the relevant exchange, the depreciation periods that apply to the increase in tax basis, the amount and timing of taxable income we generate in the future, the U.S. federal income tax rate then applicable, and the portion of Vine Resources Inc.’s payments under the Tax Receivable Agreement that constitute imputed interest or give rise to depreciable or amortizable tax basis. The term of the Tax Receivable Agreement will commence upon the completion of this offering and will continue until all such tax benefits have been utilized or expired, unless we exercise our right to terminate the Tax Receivable Agreement by making the termination payment specified in the agreement. In the event that the Tax Receivable Agreement is not terminated, the payments under the Tax Receivable Agreement are anticipated to commence in 2029 (with respect to the tax year 2028) and to continue for approximately 14 years.

The actual increase in tax basis, as well as the amount and timing of any payments under the Tax Receivable Agreement, will vary depending upon a number of factors, including the timing of the exchanges of Vine Units, the price of Class A common stock at the time of each exchange, the extent to which such exchanges are taxable, the amount and timing of the taxable income we generate in the future and the tax rate then applicable, and the portion of our payments under the Tax Receivable Agreement constituting imputed interest or depletable, depreciable or amortizable basis. We expect that the payments that we will be required to make under the Tax Receivable Agreement could be substantial.

The payments under the Tax Receivable Agreement will not be conditioned upon a holder of rights under the Tax Receivable Agreement having a continued ownership interest in us. “Certain Relationships and Related Party Transactions—Tax Receivable Agreement contains more information.”

In certain cases, payments under the Tax Receivable Agreement may be accelerated and/or significantly exceed the actual benefits we realize, if any, in respect of the tax attributes subject to the Tax Receivable Agreement.

If we experience a change of control (as defined under the Tax Receivable Agreement, which includes certain mergers, asset sales and other forms of business combinations) or the Tax Receivable Agreement terminates early (at our election or as a result of our breach), we could be required to make a substantial, immediate lump-sum payment. This payment would equal the present value of hypothetical future payments that could be required under the Tax Receivable Agreement. The calculation of the hypothetical future payments will be based upon certain assumptions and deemed events set forth in the Tax Receivable Agreement, including (i) the sufficiency of taxable income to fully utilize the tax benefits, (ii) any Vine Units (other than those held by us) outstanding on the termination date are exchanged on the termination date and (iii) certain loss carryovers will be utilized on a pro rata basis from the date of the termination date through the scheduled expiration date under applicable tax law of such loss carryovers. Our ability to generate net taxable income is subject to substantial uncertainty. Accordingly, as a result of the assumptions, the required lump-sum payment may be significantly in advance of and could materially exceed, the realized future tax benefits to which the payment relates.

As a result of either an early termination or a change of control, we could be required to make payments under the Tax Receivable Agreement that exceed our actual cash tax savings under the Tax Receivable Agreement. Consequently, our obligations under the Tax Receivable Agreement could have a substantial negative impact on our liquidity and could have the effect of delaying, deferring or preventing certain mergers, asset sales, other forms of business combinations or other changes of control. For example, assuming no material changes in the relevant tax law, we expect that if we experienced a change of control or the Tax Receivable

 

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Agreement were terminated immediately after this offering, the estimated lump-sum payment would be approximately $350 million (calculated using a discount rate equal to one-year LIBOR plus 100 basis points, applied against an undiscounted liability of approximately $450 million). There can be no assurance that we will be able to finance our obligations under the Tax Receivable Agreement.

In the event that our payment obligations under the Tax Receivable Agreement are accelerated upon certain mergers, other forms of business combinations or other changes of control, the consideration payable to holders of our Class A common stock could be substantially reduced.

If we experience a change of control (as defined under the Tax Receivable Agreement), our obligation to make a substantial, immediate lump-sum payment could result in holders of our Class A common stock receiving substantially less consideration in connection with a change of control transaction than they would receive in the absence of such obligation. Further, holders of rights under the Tax Receivable Agreement may not have an equity interest in us or Vine Resources Holdings LLC. Accordingly, the interests of holders of rights under the Tax Receivable Agreement may conflict with those of the holders of our Class A common stock. Please read “Risk Factors—In certain cases, payments under the Tax Receivable Agreement may be accelerated and/or significantly exceed the actual benefits we realize, if any, in respect of the tax attributes subject to the Tax Receivable Agreement” and ‘‘Certain Relationships and Related Party Transactions—Tax Receivable Agreement.”

We will not be reimbursed for any payments made under the Tax Receivable Agreement in the event that any tax benefits are subsequently disallowed.

Payments under the Tax Receivable Agreement will be based on the tax reporting positions that we will determine. The holders of rights under the Tax Receivable Agreement will not reimburse us for any payments previously made under the Tax Receivable Agreement if such basis increases or other benefits are subsequently disallowed, except that excess payments made to any such holder will be netted against payments otherwise to be made, if any, to such holder after our determination of such excess. As a result, in such circumstances, we could make payments that are greater than our actual cash tax savings, if any, and may not be able to recoup those payments, which could adversely affect our liquidity.

Sales or redemptions of 50% or more of Vine Units during any twelve-month period will result in a termination of Vine Resources Holdings LLC for federal income tax purposes.

Sales or exchanges of 50% or more of the Vine Units during any twelve-month period will result in a termination of Vine Resources Holdings LLC for federal income tax purposes. Vine Resources Holdings LLC will be considered to have constructively terminated for U.S. federal income tax purposes if there is a sale or exchange of 50% or more of the capital and profits of the company within a twelve-month period. A constructive termination of Vine Resources Holdings LLC could result in a significant deferral of depreciation deductions allocable to us in computing our taxable income.

If Vine Resources Holdings LLC were to become a publicly traded partnership taxable as a corporation for U.S. federal income tax purposes, we and Vine Resources Holdings LLC might be subject to potentially significant tax inefficiencies, and we would not be able to recover payments previously made by us under the Tax Receivable Agreement even if the corresponding tax benefits were subsequently determined to have been unavailable due to such status.

We intend to operate such that Vine Resources Holdings LLC does not become a publicly traded partnership taxable as a corporation for U.S. federal income tax purposes. A “publicly traded partnership” is a partnership the interests of which are traded on an established securities market or are readily tradable on a secondary market or the substantial equivalent thereof. Under certain circumstances, exchanges of Vine Resources Holdings LLC pursuant to the Exchange Right or other transfers of Vine Units could cause Vine Resources Holdings LLC to be

 

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treated as a publicly traded partnership. Applicable U.S. Treasury regulations provide for certain safe harbors from treatment as a publicly traded partnership, and we intend to operate such that exchanges or other transfers of Vine Units qualify for one or more such safe harbors.

If Vine Resources Holdings LLC were to become a publicly traded partnership, significant tax inefficiencies might result for us and for Vine Resources Holdings LLC, including as a result of our inability to file a consolidated U.S. federal income tax return with Vine Resources Holdings LLC. In addition, we would no longer have the benefit of certain increases in tax basis covered under the Tax Receivable Agreement, and we would not be able to recover any payments previously made by us under the Tax Receivable Agreement, even if the corresponding tax benefits (including any claimed increase in the tax basis of Vine Resources Holdings LLC’s assets) were subsequently determined to have been unavailable.

In certain circumstances, Vine Resources Holdings LLC will be required to make tax distributions to the Vine Unit Holders, including us, and the tax distributions that Vine Resources Holdings LLC will be required to make may be substantial. To the extent we receive tax distributions in excess of our tax liabilities and obligations to make payments under the Tax Receivable Agreement and do not distribute such cash balances as dividends on our Class A common stock, the Existing Owners could benefit from such accumulated cash balances if they exercise their Exchange Right.

Vine Resources Holdings LLC will be treated as a partnership for U.S. federal income tax purposes and, as such, is not subject to U.S. federal income tax. Instead, taxable income will be allocated to the Vine Unit Holders, including us. Pursuant to the VRH LLC Agreement, Vine Resources Holdings LLC will generally make pro rata cash distributions, or tax distributions, to the Vine Unit Holders, including us, calculated using an assumed tax rate, to allow each of the Vine Unit Holders to pay its respective taxes on such holder’s allocable share of Vine Resources Holdings LLC’s taxable income; such tax distributions will be calculated after taking into account certain other distributions or payments received by the Vine Unit Holders from Vine Resources Holdings LLC or Vine Resources Inc.

Funds used by Vine Resources Holdings LLC to satisfy its tax distribution obligations will not be available for reinvestment in our business. Moreover, the tax distributions that Vine Resources Holdings LLC will be required to make may be substantial, and may exceed (as a percentage of Vine Resources Holdings LLC’s income) the overall effective tax rate applicable to a similarly situated corporate taxpayer. In addition, because these payments will be calculated with reference to an assumed tax rate, and because of the disproportionate allocation of net taxable income, these payments will likely significantly exceed the actual tax liability for many of the Vine Unit Holders that is attributable to Vine Resources Holdings LLC.

As a result of potential differences in the amount of net taxable income allocable to us and to the other Vine Unit Holders, as well as the use of an assumed tax rate in calculating Vine Resources Holdings LLC’s tax distribution obligations, we may receive distributions significantly in excess of our tax liabilities and obligations to make payments under the Tax Receivable Agreement. If we do not distribute such cash balances as dividends on our Class A common stock, the Existing Owners could benefit from any value attributable to such accumulated cash balances as a result of their ownership of Class A common stock following an exchange of their Vine Units pursuant to the Exchange Right or their receipt of an equivalent amount of cash.

We expect to be a “controlled company” within the meaning of the NYSE rules and, as a result, will qualify for and could rely on exemptions from certain corporate governance requirements.

Upon completion of this offering, Vine Investment will beneficially control a majority of the combined voting power of all classes of our outstanding voting stock. In connection with the completion of this offering, we will enter into a stockholders’ agreement, pursuant to which Blackstone, through its ownership interests in Vine Investment and Vine Investment II, will have certain rights with respect to the election of directors. “Certain Relationships and Related Party Transactions — Stockholders’ Agreement” contains additional

 

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information regarding these risks. As a result, we expect to be a controlled company within the meaning of the NYSE corporate governance standards. Under the NYSE rules, a company of which more than 50% of the voting power is held by another person or group of persons acting together is a controlled company and may elect not to comply with certain NYSE corporate governance requirements, including the requirements that:

 

    a majority of the board of directors consist of independent directors;

 

    the nominating and governance committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities;

 

    the compensation committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities; and

 

    there be an annual performance evaluation of the nominating and governance and compensation committees.

These requirements will not apply to us as long as we remain a controlled company. Following this offering, we may utilize some or all of these exemptions. Accordingly, you may not have the same protections afforded to stockholders of companies that are subject to all of the corporate governance requirements of the NYSE. “Management” contains additional information regarding these risks.

For as long as we are an emerging growth company, we will not be required to comply with certain reporting requirements, including disclosure about our executive compensation, that apply to other public companies.

We are classified as an “emerging growth company” under the JOBS Act. In addition, we have reduced SOX compliance requirements, as discussed elsewhere, for as long as we are an emerging growth company, which may be up to five full fiscal years, unlike other public companies, we will not be required to, among other things, (i) comply with any new requirements adopted by the PCAOB requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer, (ii) provide certain disclosure regarding executive compensation required of larger public companies or (iii) hold nonbinding advisory votes on executive compensation. We may remain an emerging growth company for up to five years, subject to requirements discussed elsewhere.

We may issue preferred stock whose terms could adversely affect the voting power or value of our Class A common stock.

Our certificate of incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our common stock respecting dividends and distributions, as our board of directors may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the Class A common stock.

If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our Class A common stock or if our operating results do not meet their expectations, our stock price could decline.

The trading market for our Class A common stock will be influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of our company or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in

 

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turn could cause our stock price or trading volume to decline. Moreover, if one or more of the analysts who cover our company downgrades our Class A common stock or if our operating results do not meet their expectations, our stock price could decline.

Our amended and restated certificate of incorporation will designate the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.

Our amended and restated certificate of incorporation will provide that unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our stockholders, (iii) any action asserting a claim arising pursuant to any provision of the Delaware General Corporation Law (the “DGCL”), our amended and restated certificate of incorporation or our bylaws, or (iv) any action asserting a claim against us that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein. This choice of forum may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our amended and restated certificate of incorporation inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our financial condition or results of operations.

 

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

The information in this prospectus includes “forward-looking statements.” All statements, other than statements of historical fact included in this prospectus, regarding our strategy, future operations, financial position, estimated revenue and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this prospectus, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our 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 “Risk Factors.” These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events.

Forward-looking statements may include statements about our:

 

    business strategy;

 

    reserves;

 

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

 

    realized natural gas prices;

 

    timing and amount of future production of natural gas;

 

    hedging strategy and results;

 

    future drilling plans;

 

    competition and government regulations;

 

    pending legal or environmental matters;

 

    marketing of natural gas;

 

    leasehold or business acquisitions;

 

    general economic conditions;

 

    credit markets;

 

    uncertainty regarding our future operating results; and

 

    plans, objectives, expectations and intentions contained in this prospectus 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 exploration for and development, production and sale of natural gas. These risks include, but are not limited to, commodity price volatility, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under “Risk Factors.”

Reserve engineering is a process of estimating underground accumulations of natural gas and oil 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 drilling. Accordingly, reserve estimates may differ significantly from the quantities of natural gas and oil that are ultimately recovered.

 

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

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

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

 

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USE OF PROCEEDS

We expect to receive approximately $          million of net proceeds (assuming the midpoint of the price range set forth on the cover of this prospectus) from the sale of the Class A common stock offered by us after deducting underwriting discounts and commissions and estimated offering expenses payable by us.

We intend to use $354 million net proceeds from this offering to repay all of our outstanding indebtedness under the TLC with any excess proceeds above the $354 million redemption price being used to pay down our RBL.

As of December 31, 2016, we had $278.3 million of outstanding borrowings under the RBL. The RBL matures November 2019, but in connection with a 25 basis point payment for each annual extension, is extendable by us for up to two years and bears interest at a variable rate based on LIBOR, plus an additional margin of 1.50% to 2.50% (based upon usage), which was 2.25% per annum at December 31, 2016.

The $350 million TLC matures in May 2022 and bears interest at LIBOR (floored at 1%), plus an additional margin of 9.000%. The current rate was 10% per annum at December 31, 2016. Affiliates of Credit Suisse Securities (USA) LLC and Morgan Stanley & Co. LLC are lenders under the RBL and, to the extent proceeds from this offering are used to repay amounts outstanding thereunder, will receive a portion of the proceeds from this offering. Accordingly, this offering is being made in compliance with FINRA Rule 5121. “Underwriting—Conflicts of Interest” contains more information. Additionally, Blackstone owns a portion of the indebtedness under the TLC and will receive a substantial portion of proceeds from this offering pursuant to the retirement of the TLC. “Certain Relationships and Related Party Transactions—Blackstone” contains more information.

A $1.00 change in the assumed initial public offering price of $        per share would cause the net proceeds from this offering, after deducting the underwriting discounts and commissions and estimated offering expenses, received by us to change, respectively, by $          million, assuming no change to the number of shares offered by us, as set forth on the cover page of this prospectus. If the proceeds increase for any reason, we would use the additional net proceeds to repay additional amounts outstanding under the RBL. If the proceeds decrease for any reason, then we expect that we would first reduce net proceeds directed to repay additional amounts outstanding under the RBL.

 

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DIVIDEND POLICY

Our debt agreements place restrictions on our ability to pay cash dividends. We do not expect to declare or pay cash dividends to holders of our Class A common stock for the foreseeable future. In addition, our existing debt instruments place certain restrictions on our ability to pay cash dividends to the holders of our Class A common stock. We currently intend to retain future operating cash flow to repay debt or finance the growth of our business. Our future dividend policy is within the discretion of our board of directors and will depend upon then-existing conditions, including our results of operations, financial condition, capital requirements, investment opportunities, statutory restrictions on our ability to pay dividends and other factors our board of directors may deem relevant.

 

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CAPITALIZATION

The following table sets forth our cash position and capitalization as of December 31, 2016:

 

    on an actual basis for our predecessor; and

 

    on an as adjusted basis to give effect to the transactions described under “Corporate Reorganization,” entry into the Superpriority facility, application of proceeds to repay outstanding borrowings under our TLC and RBL and this share offering at an assumed IPO price of $        per share (the midpoint of the range set forth on the cover of this prospectus), including the application of the net proceeds as set forth under “Use of Proceeds.”

The information set forth in the table below is illustrative only and will be adjusted based on the actual initial public offering price and other final terms of this offering. This table should be read in conjunction with, and is qualified in its entirety by reference to, “Use of Proceeds” and our financial statements and related notes appearing elsewhere in this prospectus.

 

     As of December 31, 2016  
     Actual      As Adjusted  
     (In thousands, except share
counts and par value)
 

Cash and cash equivalents

   $ 19,204      $               
  

 

 

    

 

 

 

Long-term debt:

     

Superpriority Facility(1)

   $ —       

RBL Credit Facility(2)

     278,276     

Term Loan B

     400,000     

Term Loan C

     350,000     
  

 

 

    

 

 

 

Total indebtedness

   $ 1,028,276      $  
  

 

 

    

 

 

 

Partners’ capital/stockholders’ equity:

     

Partners’ capital

     285,547     

Class A Common stock — $0.01 par value; no shares authorized, issued or outstanding, actual;                  shares authorized,                  shares issued and outstanding, as adjusted

     —       

Class B Common stock — $0.01 par value; no shares authorized, issued or outstanding, actual;                  shares authorized,                  shares issued and outstanding, as adjusted

     —       

Additional paid in capital

     —       

Non-controlling interest

     —       

Retained earnings

     —       
  

 

 

    

 

 

 

Total partners’ capital/stockholders’ equity

   $ 285,547      $  
  

 

 

    

 

 

 

Total capitalization

   $ 1,313,823      $  
  

 

 

    

 

 

 

 

(1) We entered into the Superpriority facility in February 2017. After giving effect to the consummation of the reorganization transactions described under “Corporate Reorganization,” the entry into the Superpriority facility and incurrence of borrowings thereunder and the application of the net proceeds of this offering, we expect to have $          million of available borrowing capacity under our RBL.
(2) At December 31, 2016, we had outstanding borrowings under the RBL of $278.3 million and $37.8 million of outstanding letters of credit, which yield $33.9 million of remaining capacity under the RBL. After giving effect to the consummation of the reorganization transactions described under “Corporate Reorganization,” our incurrence of borrowings under our Superpriority and the application of the net proceeds of this offering, we expect to have $          million of available borrowing capacity under our RBL.

 

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DILUTION

Purchasers of our Class A common stock in this offering will experience immediate and substantial dilution in the net tangible book value per share of the Class A common stock for accounting purposes. Our net tangible book value as of December 31, 2016, after giving effect to the transactions described under “Corporate Reorganization,” was $        , or $        per share. Pro forma net tangible book value per share is determined by dividing our pro forma tangible net worth (tangible assets less total liabilities) by the total number of outstanding shares of Class A common stock that will be outstanding immediately prior to the closing of this offering after giving effect to our corporate reorganization. Assuming an IPO price of $        per share (the midpoint of the price range set forth on the cover page of this prospectus), after giving effect to the receipt of the estimated net proceeds (after deducting estimated underwriting discounts and commissions and estimated offering expenses), our adjusted pro forma net tangible book value as of December 31, 2016 would have been approximately $          million, or $        per share. This represents an immediate increase in the net tangible book value of $        per share to our existing stockholders and an immediate dilution (i.e., the difference between the offering price and the adjusted pro forma net tangible book value after this offering) to new investors purchasing shares in this offering of $        per share. The following table illustrates the per share dilution to new investors purchasing shares in this offering (assuming that 100% of our Class B common stock has been exchanged for Class A common stock):

 

IPO price per share

      $               

Pro forma net tangible book value per share as of December 31, 2016 (after giving effect to our corporate reorganization)

   $                  

Increase per share attributable to new investors in this offering

     
  

 

 

    

As adjusted pro forma net tangible book value per share after giving effect to our corporate reorganization and this offering

     
     

 

 

 

Dilution in pro forma net tangible book value per share to new investors in this offering

      $  
     

 

 

 

A $1.00 change in the assumed initial public offering price of $        per share, which is the midpoint of the price range set forth on the cover page of this prospectus, would change our as adjusted pro forma net tangible book value per share after the offering by $        and change the dilution to new investors in this offering by $        per share, assuming the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same, after deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us. The following table summarizes, on an adjusted pro forma basis as of December 31, 2016, the total number of shares of Class A common stock owned by existing stockholders (assuming that 100% of our Class B common stock has been exchanged for Class A common stock) and to be owned by new investors, the total consideration paid, and the average price per share paid by our existing stockholders and to be paid by new investors in this offering at our initial public offering price of $        per share, calculated before deduction of estimated underwriting discounts and commissions:

 

     Shares Acquired     Total Consideration     Average
Price Per
Share
 
       Amount
(in thousands)
     Percent    
     Number      Percent         

Vine Investment

               $                            $               

Vine Investment II

               $                            $               

New investors in this offering

               $                            $               

Total

               $                            $               

The above tables and discussion are based on the number of shares of our Class A common stock to be outstanding as of the closing of this offering. If the underwriters’ option to purchase additional shares is exercised in full, the number of shares held by new investors will be increased to                 , or approximately     % of the total number of shares of Class A common stock.

 

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SELECTED HISTORICAL AND UNAUDITED PRO FORMA FINANCIAL INFORMATION

The following table shows selected historical financial information of our predecessor, and selected unaudited pro forma financial information for the periods and as of the dates indicated. The selected historical financial information as of December 31, 2016 and 2015, and for the years then ended, was derived from the audited historical financial statements of our predecessor included elsewhere in this prospectus.

The selected unaudited pro forma income statement for 2016 has been prepared to give pro forma effect to (i) the reorganization transactions described under “Corporate Reorganization” and (ii) this offering and the application of the net proceeds from this offering as if they had been completed as of January 1, 2016. The selected unaudited pro forma balance sheet information has been prepared to give pro forma effect to those transactions as if they had been completed as of December 31, 2016. This information is subject to and gives effect to the assumptions and adjustments described in the notes accompanying the unaudited pro forma financial statements included elsewhere in this prospectus. The selected unaudited pro forma financial information is presented for informational purposes only and should not be considered indicative of actual results of operations that would have been achieved had the reorganization transactions and this offering been consummated on the dates indicated, and do not purport to be indicative of statements of financial position or results of operations as of any future date or for any future period.

 

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    Predecessor     Vine Resources Inc.
Pro Forma
 
    Years Ended December 31,    

Year ended December 31,

 
    2016     2015     2016  
    (in thousands, except per share data)  

Statement of operations information:

     

Natural gas sales

  $ 184,490     $ 154,005     $                   

Realized gain on commodity derivatives

    63,803       30,038    

Unrealized gain (loss) on commodity derivatives

    (144,634     91,008    
 

 

 

   

 

 

   

 

 

 

Total revenue

    103,659       275,051    

Lease operating

    23,071       26,190    

Gathering and treating

    26,817       24,085    

Production and ad valorem taxes

    9,088       13,109    

General and administrative

    3,812       9,349    

Depreciation, depletion and accretion

    115,755       118,217    

Exploration

    2,072       2,056    

Acquisition-related

    —         207    
 

 

 

   

 

 

   

 

 

 

Total operating expenses

    180,615       193,213    
 

 

 

   

 

 

   

 

 

 

Operating income

    (76,956     81,838    
 

 

 

   

 

 

   

 

 

 

Interest expense

    (84,423     (87,911  

Income tax provision

    (217     —      
 

 

 

   

 

 

   

 

 

 

Net income

  $ (161,596   $ (6,073   $  
 

 

 

   

 

 

   

 

 

 

Less net income attributable to non-controlling interest

     
 

 

 

   

 

 

   

 

 

 

Net income attributable to Vine Resources Inc.

  $ (161,596   $ (6,073  
 

 

 

   

 

 

   

 

 

 

Balance sheet information (end of period):

     

Cash and cash equivalents

  $ 19,204     $ 15,367    

Total natural gas properties, net

    1,374,668       1,320,288    

Total assets

    1,504,963       1,523,316    

Total debt

    978,372       839,825    

Total partners’ capital/stockholders’ equity

    285,547       446,310    

Net cash provided by (used in):

     

Operating activities

  $ 30,948     $ (27,026  

Investing activities

    (155,387     (103,496  

Financing activities

    128,276       29,910    

Other financial information:

     

Adjusted EBITDAX(1)

  $ 177,945     $ 110,052     $  

Earnings (loss) per share — basic

     

Earnings (loss) per share — diluted

     

 

(1) Adjusted EBITDAX is not a financial measure calculated in accordance with GAAP, but we believe it provides important perspective regarding our operating results. “Prospectus Summary — Non-GAAP Financial Measure” contains a description of Adjusted EBITDAX and a reconciliation to our net income.

 

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

The following should be read in conjunction with our financial statements and related notes appearing elsewhere in this prospectus. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expectations. We caution that assumptions, expectations, projections, intentions or beliefs about future events may vary materially from actual results. Some of the key factors which could cause actual results to vary from our expectations include changes in natural gas prices, the timing of planned CapEx, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below and elsewhere in this prospectus, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. “Cautionary Statement Regarding Forward-Looking Statements” and “Risk Factors” (included elsewhere in this prospectus) contain important information. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.

Overview

We are a pure play natural gas company focused on the development of natural gas properties in the stacked Haynesville and Mid-Bossier shale plays in the Haynesville Basin of Northwest Louisiana. We first entered the Haynesville Basin in 2014 following our acquisition of assets from Shell which we refer to as the Shell Acquisition, and as of December 31, 2016, have approximately 95,000 net surface acres in what we believe to be the core of the Haynesville and Mid-Bossier plays. Approximately 90% of our acreage is held by production, providing us with the flexibility to control the pace of development without the threat of lease expiration. Our assets are located almost entirely in Red River, DeSoto and Sabine parishes of Northwest Louisiana. Over 60% of our acreage is prospective for dual-zone development, providing us with over 1,700 horizontal drilling locations. Utilizing eight gross rigs and assuming six wells per 640-acre section, we have over 22 years of organic development opportunities. For 2016, our annual average net daily production was 218 MMcfd.

Market Conditions and Operational Trends

The oil and gas industry is cyclical and commodity prices are highly volatile. Since the second half of 2014, commodity prices have declined and remained pressured throughout 2016. Spot prices for Henry Hub generally ranged from $2.00 per MMBtu to $4.00 per MMBtu over the period from 2014 to 2017. We expect that this market will continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control, some of which are discussed in “Risk Factors.” We believe our derivative portfolio helps mitigate the risks of this volatility.

Lower natural gas prices not only reduce our revenue and cash flows, but also may limit the amount of natural gas that we can develop economically and therefore potentially lower our proved reserves. Lower commodity prices in the future could also result in impairments of our natural gas properties. The occurrence of any of the foregoing could materially and adversely affect our future business, financial condition, results of operations, operating cash flows, liquidity or ability to finance planned CapEx. Alternatively, natural gas prices may increase, which would result in significant losses being incurred on our derivatives, which could cause us to experience lower cash receipts than had we not been hedged.

Additionally, the oil and gas industry is subject to a number of operational trends, some of which are particularly prominent in the Haynesville Basin. Oil and gas companies are increasingly utilizing new techniques to lower D&C costs and increase the efficiency of operations, including using more proppant per lateral foot, increasing use of longer laterals, increased stages per lateral foot and increased automation to reduce drilling time

 

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and costs. Furthermore, our industry, and the Haynesville Basin in particular, has benefited from reduced oilfield service pricing over the past two years as demand for such services has waned in response to lower oil and gas prices.

Evaluating Our Operations

We use the following metrics to assess the performance of our natural gas operations:

 

    reserve and production levels;

 

    realized prices on the sale of our production, including derivative effects;

 

    lease operating expenses;

 

    Adjusted EBITDAX; and

 

    D&C costs per well and overall CapEx levels.

Production Levels and Sources of Revenue

We derive our revenue from the sale of our natural gas production and sales volumes directly impact our results of operations. As reservoir pressures decline, production from a given well or formation decreases. Growth in our future production and reserves will depend on our continued ability to add proved reserves in excess of our production. Accordingly, we plan to maintain our focus on adding reserves through organic drill-bit growth as well as opportunistically through acquisitions. Our ability to add reserves through development projects and acquisitions is dependent on many factors, including our ability to raise capital, obtain regulatory approvals, procure drilling rigs and personnel and successfully identify and consummate acquisitions.

Increases or decreases in our revenue, profitability and future production growth are highly dependent on the commodity prices we receive. Natural gas prices are market driven and have been historically volatile, and we expect that future prices will continue to fluctuate due to supply and demand factors, seasonality and geopolitical and economic factors. “— Market Conditions and Operational Trends” above contains additional information regarding the current commodity price environment.

 

     Years Ended
December 31,
 
     2016      2015  

NYMEX Henry Hub High

   $ 3.23      $ 3.19  

NYMEX Henry Hub Low

   $ 1.71      $ 2.03  

Differential to Average NYMEX Henry Hub(1)

   $ (0.07    $ (0.09

 

(1) Our differential is calculated by comparing the average NYMEX Henry Hub price to our volume weighted average realized price per MMBtu.

We sell our gas to many creditworthy purchasers and we do not believe the loss of any customer would have a material adverse effect on our business, as other customers or markets are currently accessible to us.

Principal Components of our Cost Structure

Lease operating expense. Lease operating expenses (“LOE”) are the costs incurred in the operation of producing properties, including workover costs. Expenses for utilities, direct labor, chemicals, water disposal, materials and supplies comprise the most significant portion of our LOE. Certain items, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges, but can fluctuate depending on activities performed during a specific period. For instance, repairs to our well equipment or surface facilities result in increased LOE in periods during which they are performed. Certain of our operating

 

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cost components are variable and change in correlation to our production levels. For example, the disposal of produced water usually increases in connection with increased production. Also, we monitor our LOE in absolute dollar terms and on a per Mcf basis to assess our performance and to determine if any wells or properties should be shut in, repaired or recompleted.

Gathering and treating. These are costs incurred to gather and move our gas to third party treating facilities and to treat the gas to meet pipeline specification. Such costs include the fees paid to third parties who operate low- and high-pressure gathering systems that gather our natural gas.

Production and ad valorem taxes. Production taxes are paid on produced natural gas based on rates established by the state of Louisiana and the amount of gas produced. In general, the production taxes we pay correlate to the changes in natural gas revenue, although Louisiana sets rates annually each July. We are also subject to ad valorem taxes in the parishes where our production is located. Ad valorem taxes are assessed based on a formula developed by the parishes based upon well cost and value of equipment.

General and administrative. General and administrative (“G&A”) expenses are costs incurred for overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, IT expenses, legal, audit and other fees for professional services.

Depreciation, depletion and accretion. Depreciation, depletion and accretion (“DD&A”) includes the systematic expensing of the capitalized costs incurred to acquire and develop natural gas. As a “successful efforts” company, we capitalize all costs associated with our acquisition and successful development efforts and allocate these costs to each unit of production using the units of production method. We recognize accretion expense for the impact of increasing the gas gathering liability to its estimated settlement value. We also recognize accretion expense for the impact of increasing the discounted ARO to its estimated settlement value.

Exploration expense. These costs include seismic, geologic and geophysical studies, as well as the results of unsuccessful drilling.

Interest expense. We have financed a portion of our working capital requirements and property acquisitions with borrowings under our RBL, TLB and TLC. As a result, we incur interest expense that is affected by fluctuations in interest rates and, in the case of the RBL, based on outstanding borrowings. We will likely continue to incur increased levels of interest expense as we continue to grow; although we expect that we would see an immediate reduction in cash interest expense following the completion of this offering. Additionally, we capitalize interest expense attributable to significant investments in unproved properties that are not being depleted.

Adjusted EBITDAX

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

 

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D&C Costs and CapEx

We evaluate our D&C costs by considering the absolute cost to drill and complete a well, as well as the cost on a per lateral foot basis. Moreover, we evaluate the level of reserves developed per dollar spent in connection with that development to measure our capital efficiency. So long as these metrics continue to meet our expectations, we expect our overall CapEx levels to support an approximate eight gross drilling rig program. Our capital efficiency is one of the key metrics we use to manage our business.

Factors That Significantly Affect Comparability of Our Financial Condition and Results of Operations

Our historical financial condition and results of operations for the periods presented may not be comparable, either from period to period or going forward, for the following reasons:

Public Company Expenses. Upon completion of this offering, we expect to incur direct, incremental G&A expenses as a result of being a publicly-traded corporation, including costs associated with Exchange Act compliance, tax return preparation, PCAOB support fees, SOX compliance costs, investor relations activities, listing fees, registrar and transfer agent fees, stock-based compensation, incremental director and officer liability insurance costs and independent director compensation. We estimate these direct, incremental G&A expenses could total approximately $2 to 4 million per year. These direct, incremental G&A expenses are not included in our historical results of operations.

Corporate Reorganization. The historical consolidated financial statements included in this prospectus are based on the financial statements of our predecessor, prior to our reorganization in connection with this offering as described in “Corporate Reorganization.” As a result, the historical financial data may not yield an accurate indication of what our actual results would have been if those transactions had been completed at the beginning of the periods presented or of what our future results of operations are likely to be. Certain of our management compensation is treated as a liability award under GAAP. If, by virtue of this offering or subsequent offerings, our outstanding Class A Units vest as a result of the change of control provisions of such units, we could have an immediate recognition of compensation expense arising from them.

Interest Expense. Following this offering, we expect to materially reduce our indebtedness. Depending on our use of proceeds, we expect our cash interest expense to decrease through the repayment of debt. In connection with the use of proceeds of this offering, we expect to recognize losses on early extinguishment of our debt associated with unamortized discounts and deferred finance costs, which will be recognized as a non-cash increase to interest expense in the period of repayment.

Income Taxes. Our predecessor is a limited partnership not subject to federal income taxes. Accordingly, no provision for federal income taxes has been provided for in our historical results of operations because taxable income was passed through to our partners. Although we are a corporation under the Internal Revenue Code, we do not expect to report any income tax benefit or expense prior to the consummation of this offering.

Results of Operations

For 2016, we had the following financial and operational highlights:

 

    brought online 39 new gross wells (20 net);

 

    grew production by 26% compared to 2015; and

 

    lowered unit lease operating expenses by $0.12 per Mcf compared to 2015.

 

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The following table sets forth selected operating data for 2016 and 2015.

 

     Years Ended December 31,  
     2016      2015  
     (in thousands, except per Mcf)  

Production:

         

Total (MMcf)

     79,893          63,362    

Average Daily (MMcfd)

     218          174    
           Per Mcf            Per Mcf  

Revenue:

         

Natural gas sales

   $ 184,490     $ 2.31      $ 154,005     $ 2.43  

Realized gain on commodity derivatives

     63,803       0.80        30,038       0.47  

Unrealized gain (loss) on commodity derivatives

     (144,634        91,008    
  

 

 

      

 

 

   

Total revenue

     103,659          275,051    

Operating expenses:

         

Lease operating

     23,071       0.29        26,190       0.41  

Gathering and treating

     26,817       0.34        24,085       0.38  

Production and ad valorem taxes

     9,088       0.11        13,109       0.21  

General and administrative

     3,812       0.05        9,349       0.15  

Depletion, depreciation and accretion

     115,755       1.45        118,217       1.87  

Exploration

     2,072          2,056    

Acquisition-related

     —            207    
  

 

 

      

 

 

   

Total operating expenses

     180,615          193,213    
  

 

 

      

 

 

   

Operating income

     (76,956        81,838    
  

 

 

      

 

 

   

Interest expense

     (84,423        (87,911  

Income tax provision

     (217           
  

 

 

      

 

 

   

Net income

   $ (161,596      $ (6,073  
  

 

 

      

 

 

   

Interest expense

     84,423          87,911    

Income tax provision

     217          —      

Depreciation, depletion and accretion

     115,755          118,217    

Unrealized (gain) loss on commodity derivatives

     144,634          (91,008  

Exploration

     2,072          2,056    

Non-cash G&A

     (265        833    

Non-cash volumetric and production adjustment to gas gathering liability

     (7,295        (1,884  
  

 

 

      

 

 

   

Adjusted EBITDAX(1)

   $ 177,945        $ 110,052    
  

 

 

      

 

 

   

 

(1) Adjusted EBITDAX is not a financial measure calculated in accordance with GAAP, but we believe it provides important perspective regarding our operating results. “Prospectus Summary — Non-GAAP Financial Measure” contains a description of Adjusted EBITDAX and a reconciliation to our net income.

 

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Revenue

Natural Gas Sales and Realized Commodity Derivatives

The following table summarizes the changes in our natural gas sales and realized derivative effects (in thousands):

 

2015

   $  184,043  

Volume increases

     40,170  

Price decreases

     (9,685

Realized derivative increase

     33,765  
  

 

 

 

2016

   $ 248,293  
  

 

 

 

The 26% increase in natural gas volume for 2016 compared to 2015 was primarily the result of additional producing wells, as well as production increases from ongoing well maintenance projects and effects of passive fracturing stimulations.

Since commodity prices were below the weighted average floor prices of our portfolio, we realized a net gain on our natural gas derivatives during the 2016. The average prices of natural gas in our commodity derivative contracts for both 2016 and 2015 was $3.458 per MMBtu. Additionally, our total volumes hedged for the 2016 was 92% higher than total volumes hedged for 2015.

As we continue to develop our assets, we would expect our production to increase. Also, the forward curve for natural gas currently reflects higher prices than prevailed in 2015 and 2016. Thus, we expect our revenue to increase from amounts we reported in 2015 and 2016.

Unrealized Gain (Loss) On Commodity Derivatives

We had an unrealized loss on our commodity derivative contracts for 2016 primarily due to the increase in NYMEX natural gas futures prices at December 31, 2016 relative to December 31, 2015. The unrealized gain for 2015 was primarily due to the decrease in NYMEX natural gas futures prices at December 31, 2015 relative to December 31, 2014. For example, the 2017 futures price was $3.61 at December 31, 2016, up from $2.79 at December 31, 2015, causing the value of our derivative portfolio to decline.

Operating Expenses

Lease Operating

LOE for 2016 decreased in the aggregate from 2015 primarily due to negotiated price reductions under strategic alliances with our key chemical and water disposal vendors, cost reductions on GEP-operated properties and overall service cost reductions due to the reduced capital activity in the Haynesville Basin. On a unit basis, LOE decreased 29%, which was attributable to the factors described above as well as the impact of fixed LOE over a greater amount of production.

We expect that our LOE will increase in the future as additional wells are brought online, but we expect that the unit cost will reduce as the fixed portion of LOE is not expected to be as elastic as the production increases.

 

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Gathering and Treating

 

     Years Ended December 31,  
     2016      2015  
     (in thousands)      Per Mcf      (in thousands)      Per Mcf  

Gathering and treating

   $ 19,559      $ 0.25      $ 17,458      $ 0.28  

Fuel

     6,177        0.08        5,253        0.08  

Other

     1,081        0.01        1,374        0.02  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 26,817      $ 0.34      $ 24,085      $ 0.38  
  

 

 

    

 

 

    

 

 

    

 

 

 

Gathering and treating expense on a per unit basis for 2016 compared to 2015 decreased $0.06 due to non-cash adjustments to our gathering shortfall liability, offset by $0.01 due to increased interconnect charges associated with new wells coming online and $0.01 due to an annual price increase.

Excluding the impact of any non-cash adjustments to our gathering shortfall liability, we expect gathering and treating expense to increase in the future as our production increases. We also expect that unit costs may increase in correlation with improved natural gas pricing, as the fuel component of gathering and treating expense typically fluctuates relative to fluctuating gas price.

Production and Ad Valorem Taxes

 

     Years Ended December 31,  
     2016      2015  
     (in thousands)      Per Mcf      (in thousands)      Per Mcf  

Production taxes

   $ 4,860      $ 0.06      $ 8,644      $ 0.14  

Ad valorem taxes

     4,228        0.05        4,465        0.07  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 9,088      $ 0.11      $ 13,109      $ 0.21  
  

 

 

    

 

 

    

 

 

    

 

 

 

Production taxes for 2016 decreased 44% in the aggregate relative to 2015, which was primarily attributable to lower severance tax rates in Louisiana. Louisiana resets its severance tax rate annually in July, based on prevailing gas prices in the preceding year. We currently benefit from a severance tax holiday program, enacted by Louisiana, which provides new wells with an exemption from severance taxes for the earlier of two years from the date of first production or until wells reach payout. Each July, the state of Louisiana resets its severance tax rates, and in July 2015 it lowered the prevailing rate for wells that do not receive exemptions from $0.163 to $0.158 and again to $0.098 in July 2016.

We expect our ad valorem expense to increase in the future as we develop our assets and increase the number of producing wells on which such taxes are levied. We expect these new wells will continue to qualify for early life severance tax exemptions, and we expect our severance costs will increase in absolute terms but decrease on a per unit basis in 2017.

 

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G&A 

 

     Years Ended December 31,  
             2016                      2015          
     (in thousands)  

Wages and benefits

   $ 13,255      $ 8,794  

Professional services

     2,038        2,768  

Monitoring fee

     1,763        1,619  

Other

     4,634        4,381  
  

 

 

    

 

 

 

Total gross G&A expense

   $ 21,690      $ 17,562  

Less:

     

Allocations to affiliates

     (5,004      —  

Gain on inventory

     (1,098      —  

Recoveries

     (11,776      (8,213
  

 

 

    

 

 

 

Net G&A expense

   $ 3,812      $ 9,349  
  

 

 

    

 

 

 

The decrease in G&A expense for 2016 compared to 2015 was primarily due to the allocation of a material portion of our G&A to affiliates that were created in 2016, and billed pursuant to the MSA, as well as the recognition of gains on inventory transactions during 2016. “Certain Relationships and Related Party Transactions — Historical Transactions with Affiliates — Management Services Agreement and — Other Historical Arrangements” contain additional information regarding the MSA.

We expect our future G&A may increase as we grow our staffing to accommodate higher production volumes and expand our technical capabilities. Moreover, following our IPO, we would expect material cost increases associated with being a public company. These effects will be mitigated by additional recoveries associated with our expanded operated well count.

DD&A

 

     Years Ended December 31,  
     2016      2015  
     (in thousands)      Per Mcf      (in thousands)      Per Mcf  

Depletion

   $ 99,963      $ 1.25      $ 100,614      $ 1.59  

Depreciation

     1,876        0.02        1,148        0.02  

Accretion

     13,916        0.18        16,455        0.26  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 115,755      $ 1.45      $ 118,217      $ 1.87  
  

 

 

    

 

 

    

 

 

    

 

 

 

The per unit basis decease in depletion expense for 2016 compared to 2015 is primarily attributable to a decrease in the depletion rate, which is due to growth in reserves used to determine depletion.

We are party to gathering contracts that require delivery of minimum volumes of gas for each annual contract period and require settlement payments for any shortfalls in the gathered volumes. We recorded a discounted liability for the expected volume shortfall over the remaining contract period based on our acquisition date reserve report. As the remaining liability decreases through the passage of time and funding of the shortfall, the liability subject to accretion and resulting accretion expense recognized each period thereafter will also decline.

We expect our DD&A to increase in the future as we increase our production and incur CapEx to develop our assets and convert undeveloped reserves to developed.

 

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Exploration

Exploration expense, which includes seismic, geologic and geophysical studies, was mostly unchanged for 2016 compared to 2015.

Interest Expense

 

     Years Ended
December 31,
 
     2016      2015  
     (in thousands)  

Interest costs on debt outstanding

   $ 73,946      $ 70,568  

Plus:

     

Realized loss on interest rate swaps

     4,936        2,502  

Fees paid on letters of credit outstanding

     671        641  

Non-cash interest

     11,086        21,394  
  

 

 

    

 

 

 

Total interest costs incurred

   $ 90,639      $ 95,105  

Less: Interest capitalized

     (6,216      (7,194
  

 

 

    

 

 

 

Interest expense

   $ 84,423      $ 87,911  
  

 

 

    

 

 

 

The increase in interest cost is attributable to additional borrowings on the RBL and realized loss on interest rate swaps. Non-cash interest expense includes amortization of deferred financing costs, original issue discount and unrealized loss on interest rate derivatives. 2015 non-cash interest includes a $6.2 million write-off of original issue discount and deferred debt issuance costs associated with a pay down on the TLB of $100 million.

Significant Fourth Quarter Adjustments

We recorded an adjustment to our results in the fourth quarter of 2016 to reduce the projected bonus by $0.5 million based on our failure to attain expected payout levels.

Capital Resources and Liquidity

Our development activities require us to make significant operating and capital expenditures. Historically, post-Shell Acquisition sources of liquidity have been borrowings under our RBL and cash flows from operations and in 2017 through the Superpriority. To date, our primary use of capital has been for the development of natural gas properties.

Our future success in growing reserves and production will be highly dependent on the availability of capital resources. For 2017, we forecast investing $315 million of our $320 million CapEx for drilling and completion, compared with our 2016 CapEx of $155.4 million. This increase results from our plan to run up to 9 gross drilling rigs in 2017 compared with an average of under 5 rigs in 2016. Additionally, our 2017 CapEx program includes six gross refracs on older producing wells. Our new refracs are expected to capitalize on our knowledge of our 2015 refrac program and our current completion design to significantly improve sectional production. Our gross well cost assumptions for 2017 reflect an average cost of $7.9 million for our standard laterals and $10.7 million for our long laterals, which reflects continued evolution of completion design, which we hope will yield EUR increases.

After giving effect to this offering and the closing of the Superpriority, we expect to fund our 2017 and beyond CapEx through 2017 with cash generated by operations, cash on hand and available capacity under our RBL. Following the completion of this offering, we estimate that we will have cash on hand of $          million and availability under our RBL of approximately $         million. Our capital forecast, including the amount,

 

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timing and allocation of CapEx, is largely discretionary and within our control but may change. If natural gas prices decline to levels below our acceptable return levels, or our costs increase to levels above our acceptable return levels, we could choose to defer a significant portion of our forecasted CapEx until later periods to achieve the desired balance between sources and uses of liquidity and prioritize capital projects that we believe will accomplish our strategic objectives. Any reduction in our CapEx could have the effect of delaying or limiting our development program, which would negatively impact our ability to grow production and operating cash flow.

Following the completion of this offering, we expect that our overall borrowing costs will be lower through reductions in outstanding debt. Even though we believe lower borrowing costs will give us greater flexibility in funding our CapEx going forward, we do not expect to rely on borrowings to fund such expenditures in a meaningfully more significant way following this offering than we have historically.

After giving effect to this offering, we believe that operating cash flow and our available capacity under our RBL should be sufficient to fully fund our CapEx forecast for 2017 and meet our cash requirements, including normal operating needs, debt service obligations and commitments and contingencies. However, we may access the capital markets to raise capital from time to time to the extent that we consider market conditions favorable.

Cash Flow Activity

Our financial condition and results of operations, including our liquidity and profitability, are significantly affected by the prices that we realize for our natural gas and the volumes of natural gas that we produce. Natural gas is a commodity product for which established trading markets exist. Accordingly, our operating cash flow is sensitive to a number of variables, the most significant of which are the volatility of natural gas prices and production levels both regionally and across North America, the availability and price of alternative fuels, infrastructure capacity to reach markets, costs of operations and other variable factors. We monitor factors that we believe could be likely to influence price movements including new or expanded natural gas markets, gas imports, LNG and other exports and industry CapEx levels.

Our produced volumes have a high correlation to our level of CapEx and our ability to fund it through operating cash flow, borrowings and other sources may be affected by multiple factors discussed further herein.

The following summarizes our cash flow activity:

 

     For the Years Ended
December 31
 
     2016      2015  
     (in thousands)  

Operating cash flow

   $ 30,948      $ (27,026

Investing cash flow

     (155,387      (103,496

Financing cash flow

     128,276        29,910  

Net change in cash

   $ 3,837      $ (100,612

Operating Cash Flow

Cash flow from operating activities for 2016 increased from 2015 primarily due to increased production and, via hedging, a higher realized price, plus the effects of lower cash operating costs, offset by higher cash interest expense due to higher average outstanding debt during 2016. Our operating cash flow is significantly impacted by a number of industry factors, but also on the cash settlement of our gas gathering liability over the remaining term of the underlying minimum volume commitments.

 

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Investing and Financing Cash Flow

The change in investing cash flow in 2016 compared to 2015 was attributable to the increase in our capital plan. In executing that plan, our capital spending exceeded our operating cash flows by a greater percentage in 2016 compared to 2015. This resulted in the need to increase our borrowings under the RBL. For 2015, we drew a net amount of $124.3 million on our RBL to repay $100.0 million of TLB principal and fund $20.0 million in modification fees. We utilized cash on hand to fund the excess for these transactions.

Our CapEx in 2016 includes our net costs of joint participation with GEP in an average 4.8 gross rig program compared with an average 1.8 gross rig program in 2015. During 2017, we expect our CapEx to be $320 million, which we expect will require additional net RBL borrowings of approximately $140 million before giving effect to the use of proceeds of this offering. During February 2017, we completed the placement of the $150 million Superpriority, which we used the proceeds of $130 million to repay $105 million of outstanding borrowings under the RBL and to retain as cash on hand, thereby creating additional liquidity thereunder. On a pro forma basis, we estimate our liquidity to be approximately $180 million at December 31, 2016. Assuming a similar capital program beyond 2017, we would expect that growth in production and revenue will cause our deficit spending to decrease until 2020, when we expect to be free cash flow positive.

Derivative Activities

Natural gas prices are inherently volatile and unpredictable. Accordingly, to achieve more predictable cash flow and reduce our exposure to adverse fluctuations in commodity prices, we have historically utilized commodity derivatives, such as swaps and collars, to hedge price risk associated with our anticipated production and to underpin our development program. This helps reduce potential negative effects of reductions in gas prices but also reduces our ability to benefit from increases in gas prices. In certain circumstances, where we have unrealized gains in our derivative portfolio, we may choose to restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of our existing positions.

A swap has an established fixed price. When the settlement price is below the fixed price, the counterparty pays us an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. When the settlement price is above the fixed price, we pay our counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume.

A put option has an established floor price. The buyer of that put option pays the seller a premium to enter into the put option. When the settlement price is below the floor price, the seller pays the buyer an amount equal to the difference between the settlement price and the strike price multiplied by the hedged contract volume. When the settlement price is above the floor price, the put option expires worthless.

A call option has an established ceiling price. The buyer of the call option pays the seller a premium to enter into the call option. When the settlement price is above the ceiling price, the seller pays the buyer an amount equal to the difference between the settlement price and the strike price multiplied by the hedged contract volume. When the settlement price is below the ceiling price, the call option expires worthless.

A put option and a call option may be combined to create a collar. A collar requires the seller to pay the buyer if the settlement price is above the ceiling price and requires the buyer to pay the seller if the settlement price is below the floor price.

 

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Our commodity derivatives allow us to mitigate the potential effects of the variability in operating cash flow thereby providing increased certainty of cash flows to support our capital program and to service our debt. We believe the RBL affords us greater flexibility to hedge than similar agreements of our peers because it allows us to hedge up to 85% of expected production. Typically, credit documents limit borrowers to hedging only production from already developed reserves. Our derivatives provide only partial price protection against declines in natural gas prices and partially limit our potential gains from future increases in prices. The following table summarizes our derivatives as of December 31, 2016.

 

Period

   Natural Gas Volume
(MMBtud)
     Weighted Average
Swap Price
 

First Quarter of 2017

     232,500      $ 3.40  

Second Quarter of 2017

     262,500      $ 3.38  

Third Quarter of 2017

     312,500      $ 3.36  

Fourth Quarter of 2017

     332,500      $ 3.38  

First Quarter of 2018

     240,000      $ 3.33  

Second Quarter of 2018

     120,000      $ 3.17  

Additionally, we use interest rate derivatives to hedge the risks associated with fluctuating interest rates under our debt agreements. In June 2015, we entered into two interest rate derivatives, which swapped $750.0 million of our variable rate debt based on one-month LIBOR into fixed rate debt.

The following summarizes our interest rate derivatives as of December 31, 2016:

 

Notional Principal

Amount

   Fixed Rate     Effective Date      Maturity Date  

$400.0 million

     1.784     June 30, 2015        June 30, 2019  

$350.0 million

     1.495     July 6, 2015        June 30, 2018  

We expect to continue to use commodity derivatives to hedge our price risk in the future, though the notional and pricing levels will be dependent upon prevailing conditions, including available capacity of our counterparties. We have entered into agreements with seven potential counterparties to provide us with hedge capacity. In two cases, these agreements also allow us to hedge our physical gas sales at fixed prices.

Debt Agreements

Superpriority Facility

In February 2017, we entered into an incremental agreement evidencing the Superpriority facility. Upon the execution of the Superpriority agreement, we drew $150 million aggregate principal, and in connection therewith, we incurred discounts and up-front fees totaling $19.5 million. We used the proceeds to reduce our outstanding RBL borrowings by $105 million, retaining the remainder for working capital purposes. Concurrent with the incurrence of the Superpriority, we amended the RBL to reflect the changes associated with the priority position of the Superpriority described below.

The Superpriority has a face amount of $150 million which is not subject to redetermination. The terms of the Superpriority closely resemble the RBL in respect of interest rate, covenants, restrictions, maturity and extensions. Collateral provisions are similar to the RBL, however the Superpriority has a priority in right of repayment and to the proceeds of collateral in the event of default. The Superpriority also has priority in the event of disposal of properties that collateralize the facility and places limitations on certain types of restricted payments. Although the Superpriority is prepayable at any time without penalty, any repayment would be a permanent reduction to the exposure and loss of liquidity.

RBL Facility

In November 2014, in connection with the Shell Acquisition, we entered into the RBL with HSBC Bank USA, National Association, as Administrative Agent, Collateral Agent, Swingline Lender and an Issuing Bank

 

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and the banks, financial institutions and other lending institutions from time to time party thereto. The RBL was amended in January 2015.

As amended, our RBL has a face value of $375 million and our borrowing base is the greater of (a) $350 million plus the aggregate principal amount of outstanding Superpriority loans (the “Fixed Amount”) and (b) an amount based on the PV-9 value of the proved oil and gas reserves (the “Variable Amount”). The Fixed Amount is only subject to redeterminations in connection with certain significant asset dispositions. The Variable Amount is subject to semi-annual redeterminations and additional redeterminations at our option, subject to certain limitations, as well as adjustments in connection with certain asset dispositions, terminations of hedge positions, casualty events, and future debt incurrences. Any increase in the borrowing base requires the consent of the lenders holding not less than 90% of the commitments.

The RBL requires that we provide a first priority security interest in our oil and gas properties (such that those properties subject to the security interest represent at least 80% of the total value of the proved oil and gas properties) and all of our personal property assets. The RBL is scheduled to mature in November 2019, but we have the option to extend the maturity for two one-year terms by payment of a 25 basis point fee for each extension. The ultimate extended maturity date must be at least 180 days in advance of any maturity of junior debt.

The RBL includes usual and customary covenants for facilities of its type and size. The covenants cover matters such as mandatory reserve reports, the responsible operation and maintenance of properties, certifications of compliance, required disclosures to the lenders, notices under other material instruments, and notices of sales of oil and gas properties. It also places limitation on the incurrence of additional indebtedness, restricted payments, distributions, investments outside of the ordinary course of business and limitations on the amount of commodity and interest rate hedges that can be put in place.

The RBL also contains a financial maintenance covenant limiting us to a maximum ratio of RBL debt to consolidated trailing twelve month EBITDAX of 3:1 measured quarterly, with a step down to 2.5:1 beginning in the second quarter of 2018.

The RBL bears interest based on LIBOR plus an additional margin, based on the percentage of the borrowing base being utilized, ranging from 1.50% to 2.50%. There is also a commitment fee that ranges between 0.375% and 0.50% on the undrawn borrowing base amounts. The RBL may be prepaid without a premium. Interest on outstanding facility debt was LIBOR+2.25% at December 31, 2016.

Term Loan B

In November 2014, in connection with the Shell Acquisition, we entered into the TLB with Morgan Stanley Senior Funding, Inc., as Administrative Agent and Collateral Agent and the banks, financial institutions and other lending institutions from time to time party thereto. The TLB was amended in January 2015.

As amended, the TLB consists of $400 million second lien senior secured term loans with our interest based on LIBOR (with a 1% floor) plus 6.875%. The TLB may be prepaid without a premium.

The TLB requires that we provide the lenders a second priority security interest of at least 80% of our oil and gas properties and all of our personal property assets, subject to certain exceptions. Incurrence of additional debt outside of the TLB is significantly restricted. The maturity date of the TLB is November 2021.

The TLB includes usual and customary covenants for facilities of its type and size. The covenants cover matters such as mandatory reserve reports, the responsible operation and maintenance of properties, certifications of compliance, required disclosures to the lenders, notices under other material instruments, notices of sales of oil and gas properties, incurrence of additional indebtedness, restricted payments and distributions, certain investments outside of the ordinary course of business, limits on the amount of hedges that can be put in place, and events of default. The TLB is not subject to any financial maintenance covenants.

 

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Term Loan C

In November 2014, in connection with the Shell Acquisition, we entered into the TLC with Morgan Stanley Senior Funding, Inc., as Administrative Agent and Collateral Agent and the banks, financial institutions and other lending institutions from time to time party thereto. The TLC was amended in January 2015.

As amended, the TLC is comprised of $350 million third lien senior secured term loans with our interest based on LIBOR (with a 1% floor) plus 9.000%. The TLC may be prepaid at a 1% prepayment premium, and after November 2017, with no prepayment premium.

The TLC requires that we provide the lenders a third priority security interest in at least 80% of our oil and gas properties and all of our personal property assets, subject to certain exceptions. Incurrence of additional debt outside of the TLC is significantly restricted. The scheduled maturity of the TLC is May 2022.

The TLC includes the usual and customary covenants for facilities of its type and size. The covenants cover matters such as mandatory reserve reports, the responsible operation and maintenance of properties, certifications of compliance, required disclosures to the lenders, notices under other material instruments, notices of sales of oil and gas properties, incurrence of additional indebtedness, restricted payments and distributions, certain investments outside of the ordinary course of business, limits on the amount of hedges that can be put in place, and events of default. The TLC is not subject to any financial maintenance covenants.

Summary of Outstanding Debt at December 31, 2016

 

    Priority on Collateral and Structural Seniority(1)
    Highest Priority   ½————————————————————— ¾   Lowest Priority
    Superpriority   RBL   TLB   TLC

Face amount

  $150 million   $350 million   $400 million   $350 million

Amount outstanding

  $0   $278 million   $400 million   $350 million

Scheduled maturity date

  November 2019 (2)   November 2019 (2)   November 2021   May 2022

Springing maturity date

  November 2021 (2)   November 2021 (2)   N/A   N/A

Interest rate on outstanding borrowings at December 31, 2016

  N/A   ~3.0%   7 7/8%   10%

Base interest rate options

  ABR and LIBOR

+ spread (3)

  ABR and LIBOR

+ spread (3)

  ABR floor of 2% and LIBOR
floor of 1% + 6 7/8%
  ABR floor of 2% and LIBOR
floor of 1% + 9%

Financial maintenance covenants

  – Maximum senior secured
debt leverage ratio of 3.0x
through March 2018 and 2.5x
thereafter
  – Maximum senior secured
debt leverage ratio of 3.0x
through March 2018 and 2.5x
thereafter
  N/A   N/A

Significant restrictive covenants

  – Incurrence of debt

– Incurrence of liens

– Payment of dividends

– Equity purchases

– Asset sales

– Limitations on derivatives &
investments

– Affiliate transactions

  – Incurrence of debt

– Incurrence of liens

– Payment of dividends

– Equity purchases

– Asset sales

– Limitations on derivatives &
investments

– Affiliate transactions

  – Incurrence of debt

– Incurrence of liens

– Payment of dividends

– Equity purchases

– Asset sales

– Limitations on derivatives &
investments

– Affiliate transactions

  – Incurrence of debt

– Incurrence of liens

– Payment of dividends

– Equity purchases

– Asset sales

– Limitations on derivatives &
investments

– Affiliate transactions

Optional redemption

  Any time at par   Any time at par   Any time at par   101% of par until
November 25, 2017; at par
thereafter

Change of control

  Event of default   Event of default   Event of default   Event of default

 

(1) The information presented in this table is qualified in all respects by reference to the full text of the covenants, provisions and related definitions contained in the documents governing the various components of our debt.
(2) Maturity may be extended for two one-year terms by payment of a 25 basis point fee for each extension; provided that the maturity may not be later than 180 days prior to the TLB maturity date.
(3) The spread applicable to a LIBOR loan ranges from 1.50% to 2.50% and the spread applicable to an ABR loan, should we elect to convert from a LIBOR loan, ranges from 0.50% to 1.50%, in each case based on borrowing base utilization. For ease of disclosure, we have presented information in the above table assuming LIBOR-only borrowings, which is the only mechanism we have ever used, although we are permitted to make ABR borrowings.

 

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Contractual Obligations(1)

 

    For the Year Ended December 31, 2016  
    ($USD in Thousands)  
    2017     2018     2019     2020     2021     Thereafter     Total  

RBL Principal & Extension(2)

  $     $     $ 638     $ 638     $ 278,276     $     $ 279,552  

RBL Interest(5)

    9,435       11,054       12,069       12,844       13,223             58,625  

TLB Principal

                            400,000             400,000  

TLB Interest(5)

    31,540       33,867       35,326       36,439       33,231             170,403  

TLC Principal

                                  350,000       350,000  

TLC Interest(5)

    35,035       37,071       38,347       39,322       39,845       16,129       205,749  

Gathering Commitment(3)

    74,589       77,164       67,426       21,449       869             241,497  

LC Fees & Payments(4)

    1,098       1,520       1,660       1,766       1,824             7,868  

Other

    892       880       883       896       911       1,286       5,748  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

  $ 152,589     $ 161,556     $ 156,349     $ 113,354     $ 768,179     $ 367,415     $ 1,719,442  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(1) We are party to four drilling rig contracts, none of which had an original term beyond one year, and as a result, are not reflected in this table.
(2) The RBL matures in November 2019; however, we have the option to extend its maturity for two one-year terms by payment of a 25 basis point fee for each extension. The information included in the table assumes each extension occurs.
(3) Our gathering contracts require fees to be paid on minimum volumes of committed gas regardless of throughput. The minimum volume commitments in our gathering contracts step down from 705,000 MMbtud in 2017 to 377,000 MMbtud in August 2019 and to 95,000 MMbtud in April 2020 before expiring in January 2021.
(4) Related to $37.8 million in outstanding letters of credit outstanding as of December 31, 2016.
(5) This debt bears interest at LIBOR plus a borrowing spread. In determining future interest, we used outstanding amounts at December 31, 2016 and used the forward curve for LIBOR to project the interest obligations in those future periods.

Critical Accounting Estimates

Our financial statements are prepared in accordance with GAAP. In connection with preparing of our financial statements, we are required to make assumptions and estimates about future events, and apply judgments that affect the reported amounts of assets, liabilities, revenue, expense and the related disclosures. We base our assumptions, estimates and judgments on historical experience, current trends and other factors that management believes to be relevant at the time we prepare our consolidated financial statements. On a regular basis, management reviews the accounting policies, assumptions, estimates and judgments to ensure that our financial statements are presented fairly and in accordance with GAAP. However, because future events and their effects cannot be determined with certainty, actual results could differ materially from our assumptions and estimates.

Our significant accounting policies are discussed in our audited financial statements included elsewhere in this prospectus. Management believes that the following accounting estimates are those most critical to fully understanding and evaluating our reported financial results, and they require management’s most difficult, subjective or complex judgments, resulting from the need to make estimates about the effect of matters that are inherently uncertain.

Gathering Liability

Policy Description

We are party to gathering contracts that require delivery of minimum volumes regardless of throughput for each annual contract period. These gathering contracts require annual settlement payments for any shortfalls in the gathered volumes.

Judgments and Assumptions

Our obligation for the gathering contracts was initially measured at fair value as of the acquisition date and represented the expected volume shortfall over the remaining contract period. The fair value was determined using estimated future development pace, future production volumes, future inflation factors, and our weighted average cost of capital. We recognize accretion expense for the impact of increasing the discounted liability to its estimated settlement value. At each reporting period, the difference, if any, between the estimated payments at

 

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inception and actual current contract period payments expected to be required are recorded to gathering and treating expense. If our development plan changes or if production deviates from our initial estimation, the amount of the adjustments to the gas gathering liability recorded to gathering and treating expense could be material. For example, if our forecasted volumes were to decrease, we would need to increase the liability via additional gathering and treating expense. Conversely, if our forecasted volumes were to increase, we would reduce the liability via a reduction to gathering and treating expense.

Natural Gas Reserves

Policy Description

Proved natural gas reserves are the estimated quantities of natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. In calculating cash inflows for reserves, we use an unweighted average of the preceding 12-month first-day-of-the-month prices for determination of proved reserve values and for annual proved reserve disclosures. We assume continued use of technologies with demonstrated success of yielding expected results, including the use of drilling results, well performance, well logs, seismic data, geological maps, well stimulation techniques, well test data and reservoir simulation modeling.

In calculating cash outflows for reserves, we use well costs and operating costs prevailing during the preceding year, but more heavily weighted toward recent demonstration levels, which are then held constant into future periods. Our estimates of proved reserves are determined and reassessed at least annually using available geological and reservoir data as well as production performance data. Revisions may result from changes in, among other things, reservoir performance, prices, economic conditions and governmental policies.

We limit our future development program to only those wells that we expect to be developed within five years of their initial recognition. Additional information regarding our proved natural gas reserves may be found under “Reserve Data” found elsewhere in this prospectus.

Judgments and Assumptions

All of the reserve information in this prospectus is based on estimates. Estimates of natural gas reserves are prepared in accordance with guidelines established by the SEC. Reservoir engineering is a subjective process of estimating recoverable underground accumulations of natural gas. There are numerous uncertainties inherent in estimating recoverable quantities of proved natural gas reserves. Uncertainties include the projection of future production rates and the expected timing of development expenditures. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, proved reserve estimates may be different from the quantities of natural gas that are ultimately recovered.

The passage of time provides more qualitative information regarding estimates of reserves, and revisions are made to prior estimates to reflect updated information. If future significant revisions are necessary that reduce previously estimated reserve quantities, it could result in impairments. In addition to using estimates of proved reserves to assess for impairment, we also rely heavily on them in the calculation of depletion expense. For example, if estimates of proved reserves decline, the depletion rate and resulting expense will increase, resulting in a decrease in net income. A decline in estimates of proved reserves could also cause us to perform an impairment analysis to determine whether the carrying amount of oil and natural gas properties exceeds fair value, which would result in an impairment charge, reducing net income.

Successful Efforts Method of Accounting for Natural Gas Properties

Policy Description

We use the successful efforts method of accounting for natural gas activities. Costs to acquire mineral interests in natural gas properties are capitalized as unproved properties whereas costs to drill and equip wells that result in proved reserves are capitalized as proved properties. Costs to drill wells that do not identify proved reserves as well as geological and geophysical costs are expensed.

 

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Our proved natural gas properties are recorded at cost. We evaluate our properties for impairment annually in the fourth quarter or when events or changes in circumstances indicate that a decline in the recoverability of their carrying value may have occurred. We estimate the expected future cash flows of our natural gas properties and compare these undiscounted cash flows to the carrying amount of the natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will write down the carrying amount of the natural gas properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future operating and CapEx, and discount rates.

Judgments and Assumptions

Our impairment analysis requires us to apply judgment in identifying impairment indicators and estimating future cash flows of our natural gas properties. If actual results are not consistent with our assumptions and estimates or our assumptions and estimates change due to new information, we may be exposed to an impairment charge.

Key assumptions used to determine the undiscounted future cash flows include estimates of future production, timing of new wells coming on line, differentials, net estimated operating costs, anticipated CapEx, and future commodity prices. Our discussion of the judgments inherent in reserve estimation above has information with direct bearing on the judgments surrounding our depletion calculation and impairment analysis. However, in conducting our impairment analysis, we also replace pricing assumptions with future price estimates and we include values for our probable and possible reserves in determining fair value.

Lower net undiscounted cash flows can result in the carrying amount of the natural gas properties exceeding the net undiscounted cash flows, which results in an impairment expense. Changes in forward commodity prices and differentials, changes in capital and operating expenses, and changes in production among other items can result in lower net undiscounted cash flows. Forward commodity prices can change quickly and unexpectedly as, for example, a result of global supply fluctuations or warmer than anticipated weather, which can negatively impact forward commodity prices, which could significantly lower undiscounted net cash flows.

Similarly, future capital and lease operating costs are uncertain and can change quickly based on regional oil and natural gas drilling activity, steel and other raw material prices, transportation costs and regulatory requirements, among other factors. Increased capital and lease operating costs would result in lower net undiscounted cash flows. Production estimates are determined based on field activities and future drilling plans. Drilling and field activities require significant judgments in the evaluation of all available geological, geophysical, engineering and economic data. As such, actual results may materially differ from predicted results, which could lower production and net undiscounted cash flows.

Unproved property costs consist of costs to acquire undeveloped leases. We evaluate unproved properties for impairment based on remaining lease term, nearby drilling results, reservoir performance, seismic interpretation or future plans to develop acreage.

Derivatives

Policy Description

We enter into derivatives to mitigate risk associated with the prices received from our natural gas production. We also utilize interest rate derivatives to hedge the risk associated with interest rates on our outstanding debt.

Our derivatives are not designated as hedges for accounting purposes. Accordingly, changes in their fair value are recognized in income in the period of change. As the derivative cash flows are considered an integral part of our operations, they are classified as cash flows from operating activities. All derivatives instruments are recognized as either an asset or liability on the balance sheet measured at their fair value determined by reference to published future market prices and interest rates.

 

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Judgments and Assumptions

The estimates of the fair values of our commodity and interest rate derivatives require substantial judgment. Valuations are based upon multiple factors such as futures prices, volatility data from major natural gas trading points, length of time to maturity, credit risks and interest rates. We compare our estimates of fair value for these instruments with valuations obtained from independent third parties and counterparty valuation confirmations. The values we report in our financial statements change as these estimates are revised to reflect actual results. Future changes to forecasted or realized commodity prices could result in significantly different values and realized cash flows for such instruments.

Asset Retirement Obligations

Policy Description

We record the fair value of the liability for ARO in the period in which it is legally or contractually incurred. Upon initial recognition of the ARO, an asset retirement cost is capitalized by increasing the carrying amount of the asset by the same amount as the liability. In periods subsequent to initial measurement, the asset retirement cost is recognized as expense through depletion or depreciation over the asset’s useful life. Changes in the liability for ARO are recognized for (i) the passage of time and (ii) revisions to either the timing or the amount of estimated cash flows. Accretion expense is recognized for the impacts of increasing the discounted liability to its estimated settlement value.

Judgments and Assumptions

The estimates of our future ARO require substantial judgment. We estimate the future costs associated with our retirement obligations, the expected remaining life of the related asset and our credit-adjusted-risk-free interest rate. As revisions to these estimates occur, we may have significant changes to the related asset and its ARO.

If future abandonment cost estimates were to exceed current estimates, or if assets had shortened lives compared to current estimates, we would expect to increase the recorded liability for ARO, which would trigger recognition of additional expense and a reduction to our net income.

JOBS Act

The JOBS Act permits us, as an “emerging growth company,” to take advantage of an extended transition period to comply with new or revised accounting standards applicable to public companies. Prior to the effectiveness of our registration statement, we will determine whether to opt out of the extended transition period.

Recent Accounting Pronouncements

Our audited financial statements found elsewhere in this prospectus contain a description of recent accounting pronouncements.

Internal Controls and Procedures

We are not currently required to comply with the SEC’s rules implementing Section 404 of SOX, and are therefore not required to make a formal assessment of the effectiveness of our internal control over financial reporting for that purpose. Upon becoming a public company, we will be required to comply with the SEC’s rules implementing Section 302 of SOX, which will require certifications in our quarterly and annual reports and provision of an annual management report on the effectiveness of our internal control over financial reporting. We will not be required to have our independent registered accounting firm make its first assessment of our internal control over financial reporting under Section 404 until our first annual report subsequent to our ceasing to be an “emerging growth company”.

 

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Quantitative and Qualitative Disclosure about Market Risk

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risk. The term “market risk” refers to the risk of loss arising from adverse changes in natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for hedging purposes, rather than for speculative trading.

Commodity Price Risk and Hedges

Our major market risk exposure is in the pricing that we receive for our natural gas production. Natural gas is a commodity and, therefore, its price is subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the natural gas market has been volatile. Prices for domestic natural gas began to decline during the third quarter of 2014 and have been pressured since then, despite a modest recovery in oil prices. Spot prices for Henry Hub generally ranged from $2.00 per MMBtu to $4.00 per MMBtu over the period from 2014 to 2017. Our revenue, profitability and future growth are highly dependent on the prices we receive for our natural gas production, and the levels of our production, depend on numerous factors beyond our control, some of which are discussed in “Risk Factors — Risks Related to Our Business — Natural gas prices are volatile. A reduction or sustained decline in prices may adversely affect our business, financial condition or results of operations and our ability to meet our financial commitments”.

A $0.10 per Mcf change in our realized natural gas price would have resulted in an $1.7 million change in our natural gas revenue for 2016, after giving effect to our commodity derivative contracts. Our sole sources of cash are our production of natural gas and the related hedging.

Due to natural gas volatility, we have historically used, and we expect to continue to use, derivatives, such as swaps and collars, to hedge price risk associated with our anticipated production. Our derivatives allow us to reduce, but not eliminate, the potential effects of the variability in cash flow from operations due to fluctuations in oil and natural gas prices and provide increased certainty of cash flows for our drilling program and debt service requirements. These instruments provide only partial price protection against declines in oil and natural gas prices and may partially limit our potential gains from future increases in prices.

“Risk Factors” contains additional information regarding the volumes of our production covered by derivatives and the associated risks.

Interest Rate Risk

At December 31, 2016, we had almost $1 billion of debt outstanding which bears interest at a floating rate, including $750 million of term loans with a LIBOR floor of 1%.

Through interest rate derivatives, we have attempted to mitigate our exposure to changes in interest rates. We have entered into various fixed interest rate swaps which hedge our exposure to LIBOR variations on our debt. At December 31, 2016, we had interest rate swaps outstanding for a notional amount of $750 million with fixed pay rates ranging from 1.495% to 1.784% and terms expiring from June 30, 2018 to June 30, 2019.

Counterparty and Customer Credit Risk

Our derivatives expose us to credit risk in the event of nonperformance by counterparties. While we do not require our counterparties to our derivatives to post collateral, our counterparties have principally been lenders under the RBL, which allows for right-of-offset in the event that they do not perform. Recently, we have been utilizing other counterparties who have investment grade credit ratings and whom we will continue to evaluate creditworthiness over the terms of the derivatives.

Our principal exposures to credit risk are through receivables resulting from joint interest receivables and receivables from the sale of our natural gas production. The inability or failure of our significant customers to

 

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meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. However, we believe the credit quality of our customers is high.

We sell our production to various types of customers, but generally to trading houses and large physical consumers of natural gas. We extend and monitor credit based on an evaluation of their financial conditions and publicly available credit ratings. The future availability of a ready market for natural gas depends on numerous factors outside of our control, none of which can be predicted with certainty. For 2016, we had three customers that exceeded 10% of total natural gas revenue. We do not believe the loss of any single purchaser would materially impact our operating results because of gas fungibility, the depth of Gulf Coast markets and presence of numerous purchasers.

Accounts receivable from joint interest billings arise from costs that we incur as operator that are attributable to outside working interests. We generally have the right to offset cash we receive for any production that we market on behalf of such outside working interests in the event they do not pay their portion of the costs we incur on their behalf.

Inflation

Inflation in the U.S. has been relatively low in recent years and did not have a material impact on our results of operations for 2016. Although the impact of inflation has been insignificant in recent years, it could cause upward pressure on the cost of oilfield services, equipment and G&A.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements.

 

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BUSINESS

Our Company

We are a pure play natural gas company focused solely on the development of natural gas properties in the stacked Haynesville and Mid-Bossier shale plays in the Haynesville Basin of Northwest Louisiana. The Haynesville and Mid-Bossier shales are among the highest quality, highest return dry gas resource plays in North America with approximately 489 Tcf of natural gas in place in the Haynesville play, according to the Oil & Gas Journal. The Haynesville Basin has re-emerged in recent years as a result of material increases in well economics driven by advances in enhanced drilling and completion techniques. This has led to higher recoveries on a per lateral foot basis through more frac stages and greater proppant usage combined with a steady reduction in well costs. The Mid-Bossier shale overlays the Haynesville shale and, while earlier in its development life cycle than the Haynesville shale, has demonstrated similar characteristics and well results. Both plays demonstrate high-quality petrophysical characteristics, such as being over-pressured and having high porosity, permeability and thickness. Both plays also exhibit consistent and predictable geology and high EURs relative to D&C costs. In addition, due to significant development activity in the Haynesville Basin beginning in 2008, production and decline rates are predictable, and low-cost midstream infrastructure is currently in place with underutilized capacity. As a result of these factors, as well as our proximity to Henry Hub and other premium Gulf Coast markets, LNG export facilities and other end-users, we believe we benefit from low breakeven costs relative to other North American natural gas plays, such as those in Appalachia and the Rockies.

We first entered the Haynesville Basin in 2014 following our acquisition of assets from Shell, which we refer to as the Shell Acquisition, and as of December 31, 2016, have approximately 95,000 net surface acres in what we believe to be the core of the Haynesville and Mid-Bossier plays. Approximately 90% of our acreage is held by production, providing us with the flexibility to control the pace of development without the threat of lease expiration, and which enables us to capitalize on advancements in drilling and completion technologies and natural gas price movements. Our assets are located almost entirely in Red River, DeSoto and Sabine parishes of Northwest Louisiana, which based on RS Energy Group, have consistently demonstrated higher EURs relative to D&C costs than the Haynesville and Mid-Bossier plays in Texas and other parishes in Louisiana. Over 60% of our acreage is prospective for dual-zone development, providing us with over 1,700 gross horizontal drilling locations. Utilizing eight gross rigs and assuming six wells per 640-acre section, we have over 22 years of organic development opportunities.

The following table provides a summary of our inventory of identified drilling locations as of December 31, 2016, including lateral length and drilling location data in each play.

 

     Standard Lateral(2)      Long Lateral(2)      Total  

Gross Identified Drilling Locations(1)

        

Haynesville

     643        182        825  

Mid-Bossier

     596        303        899  
  

 

 

    

 

 

    

 

 

 

Total

     1,239        485        1,724  
  

 

 

    

 

 

    

 

 

 

 

(1) “— Our Operations — Drilling Locations” contains a description of our methodology used to determine gross identified drilling locations.
(2) Our typical standard lateral is approximately 4,600 ft and our typical long lateral is approximately 7,500 ft. We classify wells with lateral lengths of less than 5,000 ft as standard laterals and greater than 5,000 ft as long laterals.

Substantially all of our leasehold acreage is held through at least one developed well per section, which maintains all the leasehold position in that section while preserving the ability to drill additional wells in that section. Our acreage has been well delineated by over 500 gross horizontal wells drilled on our acreage in Sabine, Red River and DeSoto parishes, providing us with confidence that our inventory is low-risk and repeatable and able to continue to generate consistent economic returns. In addition, more than 1,000 wells have been drilled on or within one mile of our acreage. The majority of our acreage overlays portions of the Haynesville and Mid-Bossier reservoirs with highly attractive geologic parameters, including high permeability and low clay content which yield strong recoveries, both key advantages when compared with other parishes in Louisiana and portions of East Texas. Our production has grown at a compounded annual growth rate of

 

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approximately 48% from third quarter 2015 to fourth quarter 2016 as a result of the 47 wells we have brought online since the Shell Acquisition. For 2016, our average net daily production was 218 MMcfd.

 

LOGO

 

(1) The first new Vine-developed well was brought online in September 2015. Compound annual growth rate, or CAGR, represents a calculation of the average annual compounded growth rate of our average daily production from the third quarter of 2015 to the fourth quarter of 2016. The calculation assumes that the growth rate derived from the calculation is even across the periods covered by the calculation and does not take into account any fluctuations in our production for any periods other than the two periods used to calculate the CAGR. Accordingly, the use of CAGR may have limitations.

In addition, we may have opportunities to extend the economic life of existing wells as they age through recompletions that utilize current completion technologies in existing wells that have been historically understimulated.

Northwest Louisiana’s extensive legacy midstream infrastructure provides access to substantial gathering capacity, including our third party gatherer’s approximately 500 miles of pipeline and related processing plants with a design capacity of approximately 2.8 Bcfd. We sell our gas at the tailgate of these three processing plants attached to our gatherer’s system and, as a result, incur and hold no direct firm-transportation cost or commitments. Additionally, our proximity to Henry Hub and other premium Gulf Coast markets, LNG export facilities and other end-users results in low transportation costs that provide a competitive advantage compared to other North American dry gas plays such as those in Appalachia and the Rockies. As illustrated in the chart below, our basis differentials have averaged less than $0.10/Mcf over the last two years. We believe these low basis differentials and our long-term access to underutilized midstream infrastructure support the efficient development of our reserves and should enhance our returns.

 

 

LOGO

 

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Our management team has extensive experience in the Haynesville and Mid-Bossier shale plays and a proven track record of implementing large-scale, technically driven development programs to target best-in-class returns in some of the most prominent resource plays across the United States. Many members of our management team have experience working in the Haynesville since its inception as a commercial play and have contributed directly to the technical advancement of the play. Since the Shell Acquisition, our management team has instituted several measures designed to enhance well EURs, including:

 

    adopting enhanced completion technologies and strategies (such as increasing the length of laterals in a typical well, increasing the number of frac stages, increasing the amount of proppant pumped per foot of lateral and reducing cluster spacing);

 

    managing production rates to preserve downhole pressure;

 

    optimizing our simultaneous development footprint through dual-zone bi-directional well pads;

 

    adjusting well spacing and development patterns to enhance inventory and per well reserves; and

 

    improving wellbore landing accuracy.

Our average D&C costs for standard lateral wells brought online in the fourth quarter of 2016 were $1,400 per lateral foot, compared with $1,900 per lateral foot for our wells brought online in 2015, despite an increase of over 50% in the number of frac stages per well brought online during this period. We drilled our first long lateral in the fourth quarter of 2015 and have since increasingly used long laterals to bolster our capital efficiency by allowing us to develop the gas in place while reducing the number of vertical wellbores and associated D&C costs. Our average D&C costs for long lateral wells brought online in the fourth quarter of 2016 were $1,300 per lateral foot.

Using the assumptions regarding well costs, operating costs and type curves from our 2016 reserve report, we believe that the gas price necessary to yield a 10% rate of return on invested capital to be below $2.05 for our standard laterals and below $1.80 for the long laterals that we expect to develop over the next 5 years. We believe that these results yield some of the lowest breakeven costs among North American gas plays.

Our 2017 CapEx forecast is approximately $320 million, which is almost entirely allocated to the development of 44 gross (20 net) operated wells and the development of 30 gross (13 net) non-operated wells utilizing 8 to 9 gross rigs. Additionally, our 2017 CapEx forecast includes six gross refracs on older producing wells to capitalize on our knowledge of our 2015 refrac program and our current completion design to significantly improve sectional production. Our forecasted gross well cost assumptions for 2017 reflected an average cost of $7.9 million for our standard laterals and $10.7 million for our long laterals, with long laterals comprising 40% of the 2017 program, and reflect further evolution from our 2016 completion design, which we hope will yield further EUR increases. We believe we can execute our stated growth strategy in future periods with similar levels of CapEx. We also believe that following this offering we could accelerate our development plan and still maintain considerable liquidity and financial flexibility.

Business Strategy

Our strategy is to draw upon our management team’s experience in developing natural gas resources to economically grow our production, reserves and cash flow and thus enhance the value of our assets. Our strategy has the following principal elements:

 

   

Grow Production, Reserves and Cash Flow Through the Development of Our Pure Play Haynesville Basin Inventory. We have assembled a drilling inventory of more than 1,700 gross locations across our acreage in the Haynesville and Mid-Bossier shale plays. The concentration and scale of our core leasehold positions, coupled with our technical understanding of the reservoirs, allows us to efficiently develop our acreage, increase sectional recoveries over time and allocate capital to enhance the value of our resource base. We believe that our extensive inventory of low-risk drilling locations, combined

 

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with our operating expertise and completion design evolution, will enable us to continue to deliver significant production, reserves and cash flow growth and enhance shareholder value.

 

    Maximize Returns by Developing Industry-Leading Drilling and Completion Technologies and Practices. We continue to develop and apply industry-leading practices to lower D&C costs and maximize the recovery factor of gas in place. We have captured significant improvements in our drilling efficiency over time, reducing our cycle time from spud to rig release for our standard lateral by approximately 25% from the fourth quarter of 2015 through the fourth quarter of 2016. These cycle time reductions contribute to lower well costs because approximately 60% of our drilling costs are directly correlated to the number of days required to drill a well. We have also employed enhanced completion techniques (through longer horizontal wellbore laterals, increased frac stages, more proppant loading and reduced cluster spacing) and other drilling-related efficiencies (through dual-zone bi-directional well pads, well spacing and development patterns) to yield increased EURs. Certain of these measures also help increase our capital efficiency by allowing us to develop more reserves per lateral foot while also reducing the number of vertical wellbores and associated development, equipping and abandonment costs.

 

    Leverage Our Deep Experience in and Ongoing Focus on the Haynesville Basin to Maximize Returns. Eric D. Marsh, our Chief Executive Officer, and other key members of our management participated in the early development of the Haynesville Basin. At the peak of Haynesville activity levels in 2011 and 2012, our core management team operated a 20-plus rig program and oversaw the drilling and completions of hundreds of wells. Through their experience, they developed an expertise that allows for continued advancement of industry-leading well completion techniques and drilling and development efficiencies. During 2016, we were among the top two most active operators in the region based on number of the Haynesville and Mid-Bossier wells drilled and completed. Our singular focus on the Haynesville Basin positions us to continue to be a leader in advancing technical aspects of its future development.

 

    Enhance Returns by Focusing on Capital and Operating Cost Efficiencies. We maintain a disciplined, return-focused approach to capital allocation. We have reduced our average cost per well in the Haynesville by approximately 20% from the fourth quarter of 2015 through year end 2016 through substantial reductions in cycle times, utilization of new downhole technologies and management-negotiated cost reductions for oil field products and services. We have continued to develop new techniques and practices to lower D&C costs while increasing our EURs. We expect to mitigate future service cost increases by generating additional operational improvements and efficiencies, including drilling wells from common pad sites, shared use of pre-existing central facilities and other economies of scale. While our industry has benefited from reduced oilfield service pricing during the recent downturn, we believe up to 50% of our reductions to well costs are related to more permanent changes to well design and operational efficiencies that should endure cyclicality in commodity prices. Additionally, we have reduced lease operating expenses through strategic alliances with our key vendors (including reductions in chemical and water costs), cost reductions from our partners related to our non-operated assets and overall service cost reductions. These operating cost reductions are the result of a range of operational improvements, including the addition of a centralized command center which governs substantially all day-to-day well operations and permits more efficient labor deployment. Our command center is designed to be scalable and should yield lower unit costs in the future as new wells come online.

 

   

Maintain a Disciplined Financial Strategy While Growing Our Business Organically and Through Opportunistic Acquisitions. We intend to fund our organic growth predominantly with internally generated cash flows while maintaining ample liquidity to weather commodity cycles. We will seek to preserve future cash flows and liquidity levels through a multi-year commodity hedge program with multiple counterparties. Our debt agreements permit us to hedge up to 85% of expected production. We intend to utilize this flexibility to actively hedge the revenue expected to be generated by future development. To further reduce volatility in our cash flows and returns, we will also seek to enter into

 

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contracts for oilfield services to be no longer than the periods covered by our commodity hedges. In addition to reducing leverage through the use of proceeds of this transaction, we will endeavor to reduce our leverage over time through the generation of excess cash flows from operations and may consider acquisitions that meet our financial strategy and operational objectives.

Business Strengths

We have a number of strengths that we believe will help us successfully execute our business strategy and enhance shareholder value, including:

 

    Large, Contiguous Acreage Position Concentrated in the Core of the Basin. We own extensive and contiguous acreage positions in what we believe to be the core of the Haynesville and Mid-Bossier shale plays. Through the Shell Acquisition, we entered the Haynesville Basin ahead of renewed industry interest, development and acquisition activity in the region in 2015 and 2016. At that time, we recognized the value in large, contiguous acreage blocks and were successful in acquiring some of the highest quality, most concentrated assets in the basin. Since the Shell Acquisition, we have further delineated our acreage position using industry-leading drilling and completion techniques that have yielded industry-leading well results that we believe will have some of the highest EURs per lateral foot in the basin. Our highly concentrated and contiguous acreage position promotes more efficient development through the ability to deploy longer laterals across adjacent acreage positions, the ability to utilize multi-zone bi-directional well pads and other efficiencies.

 

    More Than 22 Years of High Quality, Low Risk, Drilling Inventory which is 90% Held by Production. Our drilling inventory as of December 31, 2016 consisted of more than 1,700 gross identified drilling locations in both the Haynesville and Mid-Bossier shale plays, which included 485 locations where we intend to utilize longer laterals. Assuming an eight gross drilling rig program, we expect our inventory life of undrilled wells to be greater than 22 years. We have been able to consistently achieve higher returns on our wells with longer laterals, including those with lateral lengths in excess of 7,500 ft (significantly longer than a typical standard lateral of 4,600 ft). We may also be able to add horizontal drilling locations across the majority of our acreage position in the future through downspacing. In addition, we may have opportunities to extend the economic life of existing wells as they age through recompletions that utilize current completion technologies in existing wells that have been historically understimulated. We consider our inventory of drilling locations to be low risk because it is in areas where we (and other producers) have extensive drilling and production experience. Because approximately 90% of our acreage is held by production, we have more flexibility than many other operators to control the pace of development without the threat of lease expiration.

 

    High Caliber and Seasoned Management and Technical Team. Our senior management team has substantial experience in the Haynesville Basin and has collectively operated large development programs that helped commercialize the Haynesville shale, as well as other plays, obtained market-leading D&C costs, decreased operating costs and generated increased EURs. Additionally, we have assembled a strong technical staff of petroleum engineers and geologists that have extensive Haynesville and Mid-Bossier shale experience. We believe our team’s expertise will continue to drive drilling, completion and operational improvements that result in increasing EURs and capital efficiency. Furthermore, our management team’s operational and financial discipline, as well as their extensive experience in leadership roles at public companies, gives us confidence of our ability to maintain a well-run public company platform and to successfully navigate the challenges of our cyclical industry.

 

   

Close Proximity to Premium Markets through Available Midstream Infrastructure. Our acreage position is in close proximity to premium markets along the Gulf Coast, which results in low basis differentials as compared to other plays, such as the Marcellus, Utica, Permian and Rockies. We believe this allows producers in our basin to benefit from better unit economics and to level the playing field with respect to our marginally higher Haynesville well costs when compared to other basins. Low-cost legacy gathering infrastructure with a design capacity of 2.8 Bcfd is in place across our

 

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acreage to support our development program with minimal incremental capital. We are not party to any transportation contracts or similar commitments and the minimum volume commitments in our gathering contracts materially decrease in August 2019 and further decrease in April 2020 before they completely expire in January 2021, at which point the gathering rate in place through 2025 at approximately $0.31 per MMbtu is highly competitive. Because our only production is dry gas, we also have minimal cost to process our gas to meet pipeline specifications, which, based on current natural gas liquids pricing, may give us an economic advantage as compared to wet gas plays.

 

    Low Operating Cost Structure with Significant Control Across Our Acreage Position Through Our JOA. We have implemented several initiatives to enhance and manage our base production in the region. In early 2015, we established an advanced technology 24-hour automated command center from which we can remotely control the majority of field-wide operations from a single location. We developed a field-wide infrastructure capable of bringing new wells online by adding limited additional fixed lease operating costs. The automated process reduces manpower needs and allows operators to focus on production efficiency, by, among other things, efficiently deploying labor through a centralized operating center. As we continue to bring new wells online, we expect our unit costs will continue to decline. We continue to increase margins through operational efficiencies, more effective chemical solutions and improved maintenance programs. We have significant control across our acreage position through our JOA with GEP, which grants us and them the ability to propose drilling on acreage operated by the other party.

 

    Significant Liquidity and Financial Flexibility. Upon completion of this offering and the application of net proceeds therefrom, we will have approximately $          million of liquidity which includes availability under our RBL and cash on hand. Our RBL has a $350 million floor, which should provide us with sufficient liquidity to manage future commodity cycles. As we continue converting our large inventory of undeveloped drilling locations to producing wells, we expect our cash flow and borrowing base to grow, thereby further enhancing our liquidity and financial strength. We believe this ample liquidity should provide us with sufficient capital to grow our production, increase shareholder value and weather any future industry downturn. Our RBL, maturing in November 2019, is our earliest stated debt maturity, but we can extend the maturity to November 2021 through two payments of a 25 basis point extension fee. In addition, we have built a hedge portfolio that extends into 2019 to protect us against downward movements of natural gas pricing and to support the achievement of our stated growth objectives. We also have interest rate swaps that protect our cash flows on floating rate debt against LIBOR increases. We evaluate and utilize swaps and collars to provide certainty of cash flows and to establish a minimum targeted return on our invested capital.

History of the Haynesville and Mid-Bossier Shales and of Our Acreage

The Haynesville Shale and the overlying Mid-Bossier Shale were deposited in a Jurassic basin that covers more than 11,000 square miles and includes eight parishes in North Louisiana and eight counties in East Texas, collectively called the Haynesville Basin. These shales were deposited in a deep, restricted basin that preserved the rich organic content and through subsequent burial developed strong reservoir properties, including becoming over-pressured and preserving porosity and permeability. Within our North Louisiana acreage, the Haynesville ranges from 11,500 to over 13,500 ft deep and can be as thick as 200 ft. The Mid-Bossier overlays the Haynesville and ranges from 11,000 to 13,000 ft deep and can be as thick as 350 ft.

Although this area has seen almost continuous drilling since oil and gas was discovered in the early 1900’s, the prospectivity of the Haynesville play was not widely recognized until 2005. During this time, Encana and other operators acquired significant acreage in North Louisiana in an attempt to extend the East Texas Bossier play. Encana drilled and tested Haynesville discovery wells during 2005 and 2006 and subsequently entered into a joint venture with Shell for the development of this acreage position. We purchased Shell’s portion of this acreage in 2014 and GEP purchased the Encana portion during 2015. We continue to be party to the JOA with GEP with respect to the operation and development of the combined acreage. We believe GEP’s primary asset is

 

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its acreage in the play, and we expect them to be focused on optimizing development through successful coordination of their development activities and field operations with us, including data sharing.

Our JOA with GEP remains in effect until the parties, or their respective successors no longer have a joint interest in any of the leases or when all of the leases subject to the JOA have been developed. Additionally the JOA remains in effect while there are producing wells on the acreage. Under the JOA, each party has the right to propose wells on the other party’s acreage and operate any new well that the other party non-consents. Furthermore, the JOA contains other customary rights for a joint operating agreement such as sharing access to the books, records, reports and data related to the acreage subject to the JOA.

In 2010, at the height of activity in the basin, 180 rigs were active in the Haynesville Basin as producers were drilling wells to preserve leasehold positions, resulting in the development of significant oilfield services and midstream infrastructure that remains available to accommodate additional volumes arising from current and future drilling activity. The basin experienced a peak production of 10.6 Bcfd in 2011, compared to 6.0 Bcfd in December of 2016, according to the U.S. EIA. Furthermore, the basin is well positioned to capitalize on the emergence of LNG and other export facilities and increasing demand from a southern migration of the U.S. population, the growing petrochemical capacity in the Gulf Coast region and the retirement of certain coal-fired electricity generation.

Since the peak Haynesville production in 2011, our industry has made significant advances in drilling and completion technology and techniques, including longer laterals, geo-steering techniques and changes in completion intensity and design. These trends have resulted in increased EURs per lateral foot with more recent wells trending even higher. We believe our EURs per lateral foot compare favorably with the most prolific basins in North America. At the same time, our average drilling time and well costs have decreased, which combine to yield enhanced economics for development of natural gas reserves in our basin.

Additionally, in 2011, the Louisiana Office of Conservation began to allow cross-unit horizontal drilling, allowing operators the ability to drill across section lines and more efficiently develop acreage. We believe our large and relatively contiguous position within the Haynesville and a streamlined regulatory approval process provides us with an opportunity to capitalize on a development plan that features multi-section lateral lengths.

Although the industry had identified the Mid-Bossier play as resource potential, it had not yet been commercialized in 2012 when falling natural gas prices caused exploration and development in the basin to decrease dramatically. As the Haynesville shale play has been increasingly targeted for development in the last few years, the shallower Mid-Bossier shale play has also experienced increased development activity, and from initial well results, we continue to believe there could be substantial resource potential in the play.

Our Operations

Reserve Data

The information with respect to our estimated reserves has been prepared in accordance with the rules and regulations of the SEC.

Reserves Presentation

Our estimated proved reserves as of December 31, 2016 are based on valuations prepared by our independent reserve engineer assuming a 30-year reserve life. Copies of the summary reports of our reserve engineers as of December 31, 2016 are filed as exhibits to the registration statement of which this prospectus forms a part. “Preparation of Reserve Estimates” contains additional definitions of proved reserves and the technologies and economic data used in their estimation.

 

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     SEC Pricing(2)     Strip Pricing(3)  

2016 Estimated proved reserves:(1)

    

Natural gas (MMcf)

     1,518,339       1,574,350  

Total proved developed reserves (MMcf)

     207,883       234,099  

Percent proved developed

     14     15

Total proved undeveloped reserves (MMcf)

     1,310,456       1,340,251  

 

(1) Our reserve information reflects an assumed 30-year reserve life.
(2) Our estimated proved reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance. As of December 31, 2016, the SEC Price Deck was $2.49/MMBtu (Henry Hub Price) for natural gas. In determining our reserves, the SEC Price Deck was adjusted for basis differentials and other factors affecting the prices we receive, which yielded a price of $2.35 per Mcf.
(3) Our estimated net proved NYMEX reserves were prepared on the same basis as our SEC reserves, except for the use of pricing based on closing monthly futures prices as reported on the NYMEX for oil and natural gas on January 4, 2017 rather than using the average of the first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance. Prices were in each case adjusted for basis differentials and other factors affecting the prices we receive. Our NYMEX reserves were determined using index prices for natural gas, without giving effect to derivative transactions. “—Adjusted Index Prices Used in Reserve Calculations” contains the adjusted realized prices under strip pricing. Actual future prices may vary significantly from the NYMEX prices on January 4, 2017; therefore, actual volumes of reserves recovered and value generated may be more or less than the estimated amounts. “Risk Factors — Risks Related to Our Business — Natural gas prices are volatile. A reduction or sustained decline in prices may adversely affect our business, financial condition or results of operations and our ability to meet our financial commitments” and “Risk Factors — Risks Related to Our Business — Reserve estimates depend on many assumptions that may turn out to be inaccurate” contain more information regarding the uncertainty associated with price and reserve estimates.

Adjusted Index Prices Used in Reserve Calculations

The following tables show our index prices used in our reserve calculations as of the dates indicated under both SEC pricing and strip pricing:

 

     December 31, 2016  

SEC Pricing:

  

Natural gas (per MMBtu)

   $ 2.49  

Strip Pricing:(1)

  

Natural gas (per MMBtu)

   $ 3.61  

 

  (1) Strip pricing is as of January 4, 2017. The following table shows the price levels used to determine the average index price under strip pricing based on NYMEX pricing. These price levels have not been adjusted for basis differentials and other factors affecting the prices we receive. Actual future prices may vary significantly from the NYMEX prices on January 4, 2017; therefore, actual volumes of reserves recovered and value generated may be more or less than the estimated amounts. “Risk Factors — Risks Related to Our Business — Natural gas prices are volatile. A reduction or sustained decline in prices may adversely affect our business, financial condition or results of operations and our ability to meet our financial commitments” and “Risk Factors — Risks Related to Our Business — Reserve estimates depend on many assumptions that may turn out to be inaccurate” contain more information regarding the uncertainty associated with price and reserve estimates.

 

        2017             2018             2019             2020             2021         Thereafter  

Natural gas (per MMBtu)

  $ 3.32     $ 3.03     $ 2.85     $ 2.86     $ 2.89     $ 3.73  

Proved Undeveloped Reserves (in MMcf)

 

Proved undeveloped reserves at December 31, 2015

     1,161,921  

Conversions into proved developed reserves(1)

     (133,609

Extensions and discoveries(2)

     215,512  

Revisions(3)

     66,632  
  

 

 

 

Proved undeveloped reserves at December 31, 2016

     1,310,456  
  

 

 

 

 

(1) Conversion of proved undeveloped locations during 2016.

 

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(2) Extensions and discoveries represent extensions to reserves attributable to additional gross locations to be developed by 2021 (as that year entered the 5-year development window) and reflect updated expected future rig count.
(3) Associated with type curve improvements and well performance (10,669 MMcf), lease expirations (-7,855 MMcf), working interest adjustments (24,224 MMcf), the updating of gas prices to year end 2016 (-22,196 MMcf) and the updating of economic assumptions (61,790 MMcf).

Extensions and discoveries principally represent extensions to reserves attributable to additional gross locations to be developed by 2021 (as that year now enters the 5-year development window) and reflect updated future rig count. These locations reside within the five year development window, which permits their recognition as proved undeveloped reserves based upon their continuing satisfaction of the engineering requirements for recognition as proved reserves. Extensions and discoveries to proved undeveloped reserves included positive changes for the development plan of 70,475 MMcf. During 2016, we incurred costs of approximately $135 million to convert 133,609 MMcf of proved undeveloped reserves to proved developed reserves. We began our development program during April 2015 and had an annualized gross rig count of only 1.8 rigs in 2015. This initial development resulted in only limited conversion of proved undeveloped reserves to proved developed reserves. As a consequence, we also incurred only a fraction of the CapEx that we expected to incur in 2016 and beyond, which further increases our rig count and the subsequent conversion of proved undeveloped reserves to proved developed reserves. In November 2015, we increased to a 4 rig program and moved to an 8 rig program in December 2016. After the completion of this offering, we believe we will have adequate liquidity to fund our CapEx through availability under our credit facility, cash on hand and cash flow from operations.

As of December 31, 2016, we had no proved undeveloped reserves that were forecasted to be developed beyond five years from the date of their initial recognition.

Estimated future development costs relating to the development of our proved undeveloped reserves at December 31, 2016 are approximately $1.3 billion over the next five years, which we expect to finance through operating cash flow and available capacity under our RBL. Based on our reserve report as of December 31, 2016, we had 445 and 2 identified drilling locations in the Haynesville Shale and Mid-Bossier Shale, respectively, associated with proved undeveloped reserves. The Haynesville wells are prioritized accordingly to drill the deepest target first, while we continue to assess the development of the shallower Mid-Bossier formation. “Risk Factors” contains additional information regarding the risks associated with development of our reserves.

Preparation of Reserve Estimates

Our reserve estimates as of December 31, 2016 included in this prospectus are based on a report prepared by Von Gonten, our independent reserve engineer, in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC in effect at such time. A copy of the report is included as an exhibit to the registration statement containing this prospectus. Von Gonten provides a variety of services to the oil and gas industry, including field studies, oil and gas reserve estimations, appraisals of oil and gas properties and reserve reports for their clients. Von Gonten is a Texas Registered Engineering Firm.

Proved reserves are reserves which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expires, unless evidence indicates that renewal is reasonably certain. Our proved reserves were estimated assuming a 30-year reserve life. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil or natural gas actually recovered will equal or exceed the estimate. The technical and economic data used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps, well-test data, production data (including flow rates), well data (including lateral lengths), historical price and cost information, and property ownership interests. Our independent reserve engineer uses this technical data, together with standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, and analogy. The proved developed reserves and EURs are

 

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estimated using performance analysis and volumetric analysis. The estimates of the proved developed reserves and EURs are used to estimate the proved undeveloped reserves for each proved undeveloped location (utilizing type curves, statistical analysis, and analogy). Proved undeveloped locations that are more than one offset from a proved developed well utilized reliable technologies to confirm reasonable certainty. The reliable technologies that were utilized in estimating these reserves include log data, performance data, log cross sections, seismic data, core data, and statistical analysis.

Internal Controls

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

Von Gonten is an independent petroleum engineering and geological services firm. John M. Parker is the technical person primarily responsible for preparing our estimates. Mr. Parker has worked at Von Gonten for 4 years as a senior reservoir engineer overseeing several unconventional resources plays including the Haynesville and Mid-Bossier, but has over 25 years of experience in all major producing basins, both domestically and internationally, while working for several private and public oil and gas companies both as a staff engineer and in senior management. Mr. Parker holds Bachelor of Science degrees in both Petroleum Geology and Petroleum Engineering from the University of Kansas. Mr. Parker meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.

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

For all of our properties, our internally prepared reserve estimates and the reserve reports prepared by Von Gonten, are reviewed and approved by our Reserve Manager, Phuong Le. She has been with us since our formation and has over 15 years of experience in reservoir engineering and reserve management.

Drilling Locations

We have 447 gross proved undeveloped horizontal drilling locations as of December 31, 2016. On our acreage, we have over 1,700 estimated drilling locations based on our well spacing assumptions and upon the evaluation of our horizontal drilling results and those of other operators in our area, combined with our interpretation of available geologic and engineering data. In addition, in evaluating the prospectivity of our horizontal acreage, we have reviewed available open-hole and mud log evaluations, core analysis and drill cuttings analysis. The drilling locations that we actually drill will depend on the review of prospectively available geologic and engineering data and on availability of capital, regulatory approvals, commodity prices, costs, results drilling other wells and other factors. Any drilling activities we are able to conduct on these identified locations may not be successful and may not result in our ability to add additional proved reserves to our existing proved reserves. Further, to the extent the drilling locations are associated with acreage operated by others, we may be dependent upon their capital allocation, development pace and development success.

To date, our shorter laterals have had lengths of 4,600 feet while our longer laterals have extended to more than 8,600 feet. Where our combined acreage with GEP and the geologic data support it, we plan to drill wells

 

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with lateral lengths of up to 10,000 ft, but in our 2016 reserve report we only reflect wells with lateral lengths of up to 7,500 feet based on our demonstrated results. We believe our development plan underlying our reserve report is reasonable, though we expect those same reserves may be developed using longer laterals of up to 10,000 feet. As of December 31, 2016, we had identified approximately 485 long laterals as part of our more than 1,700 locations. Our horizontal drilling location count generally implies six wells per 640 acre section in the primary target play, with six wells per 640 acre section in the secondary play, if applicable, based on standard lateral lengths.

Production, Revenue, Price and Production Costs

The following table sets forth information regarding our production, revenue and realized prices, and production costs for 2016 and 2015. Our MD&A contains additional information regarding our production, revenue, price and production cost history.

 

     Years Ended December 31,  
     2016      2015  

Production data:

     

Natural gas (MMcf)

     79,893        63,362  

Average daily production (MMcfd)

     218        174  

Average sales prices per Mcf:

     

Before effects of derivatives

   $ 2.31      $ 2.43  

After effects of realized derivatives

   $ 3.11      $ 2.91  

Costs per Mcf:

     

Lease operating

   $ 0.29      $ 0.41  

Gathering and treating

   $ 0.34      $ 0.38  

Production and ad valorem taxes

   $ 0.11      $ 0.21  

Depreciation, depletion and accretion

   $ 1.45      $ 1.87  

General and administrative

   $ 0.05      $ 0.15  

Productive Wells as of December 31, 2016

 

     Productive Wells      Average
Working
Interest
 
     Gross      Net     

Natural gas wells operated by Vine or GEP

     450        228.4        50.8

Natural gas wells operated by others

     41        3.6        8.8
  

 

 

    

 

 

    

Total

     491        232.0        47.3
  

 

 

    

 

 

    

Acreage as of December 31, 2016

 

Undeveloped acres(1)

     71,021  

Developed acres

     23,873  
  

 

 

 

Total

     94,894  
  

 

 

 

 

(1) Approximately 90% of our leasehold acreage is held by production through at least one developed well per section, with only 8,986 acres being subject to expiration.

 

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Undeveloped Acreage Expirations

The following table sets forth when our acreage would expire if production is not established prior to the expiration dates. We have not recognized any reserves on acreage where expiration precedes development. In addition, we do not anticipate material delay rental or lease extension payments in connection with such acreage.

 

     Acres  

2017

     6,908  

2018

     185  

2019

     —    

2020

     1,325  

2021 and thereafter

     568  
  

 

 

 

Total

     8,986  
  

 

 

 

Drilling Activity

 

     Year Ended
December 31, 2016
     Year Ended
December 31, 2015
 
     Productive Wells      Productive Wells  
           Gross                  Net                  Gross                  Net        

Mid-Bossier:

           

Development

     5.0        2.6        1.0        0.5  

Exploratory

     —          —          —          —    
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

     5.0        2.6        1.0        0.5  
  

 

 

    

 

 

    

 

 

    

 

 

 

Haynesville Shale:

           

Development

     35.0        17.7        12.0        6.5  

Exploratory

     —          —          —          —    
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

     35.0        17.7        12.0        6.5  
  

 

 

    

 

 

    

 

 

    

 

 

 

As of December 31, 2016, we had four wells that were actively being drilled, four wells that had been partially drilled but not being actively drilled, four wells that have been fully drilled but awaiting completion and two wells that were actively being completed.

Major Customers

In 2016, we sold over 55% of natural gas production to affiliates of Royal Dutch Shell, 20% to Enterprise Products Operating LLC, and 14% to Chesapeake Energy Marketing, LLC. During such period, no other purchaser accounted for more than 10% of our natural gas revenue. Although a substantial portion of production is purchased by these customers, we do not believe the loss of them or any other party would have a material adverse effect on our business, as other customers or markets would be accessible to us. However, there is no guarantee that we will be able to enter into an agreement with a new customer on terms as favorable.

Title to Properties

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

 

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

We believe that we have satisfactory title to all of our material assets, and we believe that such title is not subject to liens or encumbrances that will materially detract from the value of these properties or from our interest in these properties or materially interfere with our use of these properties in the operation of our business. In addition, we believe that we have obtained sufficient rights-of-way grants and permits from public authorities and private parties for us to operate our business in all material respects as described in this prospectus.

Seasonality

Demand for natural gas generally decreases during the spring and fall months and increases during the summer and winter months. However, seasonal anomalies and consumers procurement initiatives can also lessen seasonal demand fluctuations. Seasonal anomalies can increase competition for equipment, supplies and personnel can lead to shortages and increase costs or delay our operations.

Competition

Our industry is intensely competitive, and we compete with other companies that have greater resources than we do. Many of these companies not only explore for and produce natural gas, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for properties or define, evaluate, bid for and purchase a greater number of properties than we can. They may also be able to expend greater resources to attract qualified personnel. In addition, these companies may have a greater ability to conduct exploration during periods of low natural gas market prices. Our larger competitors may be able to absorb the existing and evolved laws and regulations more easily than we can, which would adversely affect our competitiveness. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in eventually bidding or consummating transactions.

There is also competition between natural gas producers and other related and unrelated industries. Furthermore, competitive conditions may be substantially affected by energy legislation or regulation enacted by governments of the United States and other jurisdictions. It is not possible to predict the nature of any such legislation or regulation which may ultimately be adopted or its effects upon our future operations. Such laws and regulations may substantially increase the costs of capitalizing on oil and gas opportunities. Our larger competitors may be able to absorb the burden of existing, and any changes to governmental regulations more easily than we can, which would adversely affect our competitive position.

Regulation of the Natural Gas Industry

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

 

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as well as regulations that generally prohibit the venting or flaring of natural gas, and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells.

Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on our industry increases our cost of doing business and affects profitability. Although we believe we are in substantial compliance with all applicable laws and regulations, such laws and regulations are frequently amended or reinterpreted. Therefore, we cannot to predict the future costs or impact of compliance. Additional proposals and proceedings that affect the natural gas industry are regularly considered by Congress, states, FERC and the courts, or whether any such proposals may become effective.

We believe we are in substantial compliance with currently applicable laws and regulations and that continued substantial compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations. However, current regulatory requirements may change, currently unforeseen environmental incidents may occur or past non-compliance with environmental laws or regulations may be discovered.

Regulation of Production

The production of natural gas is subject to regulation under a wide range of local, state and federal requirements with mandate permits for drilling operations, drilling bonds and reports concerning operations. Our properties have regulations governing conservation matters, including provisions for the unitization or pooling of natural gas and oil properties, the establishment of maximum allowable rates of production, the regulation of well spacing or density, and plugging and abandonment of wells. The effect of these regulations may limit the amount of natural gas that we can produce from our wells and to limit the number of wells we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing or density.

The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations, but may be better equipped to comply with them.

Regulation of Transportation and Sales of Natural Gas

Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated by agencies of the U.S. federal government, primarily FERC. FERC regulates interstate natural gas transportation rates and service conditions, which affects the marketing of natural gas that we produce, as well as the revenue we receive for sales of our natural gas. Since 1985, FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services.

In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the Natural Gas Policy Act (“NGPA”), and culminated in adoption of the Natural Gas Wellhead Decontrol Act in 1993, which removed controls affecting wellhead sales of natural gas. The transportation and sale for resale of natural gas in interstate commerce is regulated primarily under the NGA, and by regulations and orders promulgated under the NGA by FERC. In certain limited circumstances, intrastate transportation and wholesale sales of natural gas may also be affected directly or indirectly by laws enacted by Congress and by FERC regulations.

Beginning in 1992, FERC issued a series of orders to implement its open access policies. As a result, the interstate pipelines’ traditional role as wholesalers of natural gas has been greatly reduced and replaced by a

 

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structure under which pipelines provide transportation and storage service on an open access basis to others who buy and sell natural gas. Although FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.

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

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

We cannot accurately predict whether FERC’s actions will achieve the goal of increasing competition in markets in which our natural gas is sold. Additional proposals and proceedings that might affect the natural gas industry are pending before FERC and the courts. The natural gas industry historically has been very heavily regulated. Therefore, we cannot provide any assurance that the less stringent regulatory approach recently established by FERC will continue. However, we do not believe that any action taken will affect us in a way that materially differs from the way it affects other natural gas producers.

Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Although its policy is still in flux, FERC has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of getting gas to point of sale locations. State regulation of natural gas gathering facilities generally include various safety, environmental and, in some circumstances, nondiscriminatory-take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.

Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas

 

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company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress.

Our sales of natural gas are also subject to requirements under the Commodity Exchange Act (“CEA”), and regulations promulgated thereunder by the Commodity Futures Trading Commission (“CFTC”). The CEA prohibits any person from manipulating or attempting to manipulate the price of any commodity in interstate commerce or futures on such commodity. The CEA also prohibits knowingly delivering or causing to be delivered false or misleading or knowingly inaccurate reports concerning market information or conditions that affect or tend to affect the price of a commodity.

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

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

Regulation of Environmental and Occupational Safety and Health Matters

General

Our operations are subject to numerous federal, regional, state, local, and other laws and regulations governing occupational health and safety, the release, discharge or disposal of materials into the environment or otherwise relating to environmental protection. Applicable U.S. federal environmental laws include, but are not limited to, the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), the Clean Water Act (“CWA”) and the Clean Air Act (“CAA”). In addition, state and local laws and regulations set forth specific standards for drilling wells, the maintenance of bonding requirements in order to drill or operate wells, the spacing and location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells, and the prevention and cleanup of pollutants and other matters. These laws and regulations may, among other things, require the acquisition of permits to conduct exploration, drilling and production operations; govern the amounts and types of substances that may be released into the environment in connection with oil and gas drilling and production; limit or prohibit construction or drilling activities in sensitive areas such as wetlands, wilderness areas or areas inhabited by endangered or threatened species; impose specific health and safety criteria addressing worker protection; require investigatory and remedial actions to mitigate pollution conditions caused by our operations or attributable to former operations; and impose obligations to reclaim and abandon well sites and pits. We maintain insurance against costs of clean-up operations, but we are not fully insured against all such risks. Additionally, Congress and federal and state agencies frequently revise environmental laws and regulations, and any changes that result in delay or more stringent and costly permitting, waste handling, disposal and clean-up requirements for the oil and gas industry could have a significant impact on our operating costs. Although future environmental obligations are not expected to have a material impact on the results of our operations or financial condition, there can be no assurance that future developments, such as increasingly stringent environmental laws or enforcement thereof, will not cause us to incur material environmental liabilities or costs.

 

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Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal fines and penalties, loss of leases, the imposition of investigatory or remedial obligations and the issuance of orders enjoining some or all of our operations in affected areas. These laws and regulations may also restrict the rate of natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability. The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus, any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly well drilling, construction, completion or water management activities or waste handling, storage, transport, disposal, or remediation requirements could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our results of operations and financial position. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we cannot be sure that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons. Although we believe that we are in substantial compliance with applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on us, there can be no assurance that this will continue in the future.

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

Hazardous Substances and Wastes

CERCLA, also known as the “Superfund law,” imposes cleanup obligations, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that transported or disposed or arranged for the transport or disposal of the hazardous substances found at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA and any state analogs may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file corresponding common law claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. While petroleum and crude oil fractions are not considered hazardous substances under CERCLA and its analog because of the so-called “petroleum exclusion,” adulterated petroleum products containing other hazardous substances have been treated as hazardous substances in the past.

We also generate solid and hazardous wastes that may be subject to the requirements of the Resource Conservation and Recovery Act, as amended (“RCRA”), and comparable state statutes. RCRA regulates the generation, storage, treatment, transport and disposal of wastes. RCRA specifically excludes from the definition of hazardous waste “drilling fluids, produced waters and other wastes associated with the exploration, development or production of crude oil, natural gas or geothermal energy.” However, legislation has been proposed from time to time and environmental groups have filed lawsuits that, if successful, could result in the reclassification of certain natural gas exploration and production wastes as “hazardous wastes,” which would make such wastes subject to much more stringent handling, disposal and clean-up requirements. For example, following the filing of a lawsuit in the U.S. District Court for the District of Columbia in May 2016 by several non-governmental environmental groups against the EPA for the agency’s failure to timely assess its RCRA Subtitle D criteria regulations for oil and gas wastes, EPA and the environmental groups entered into an agreement that was finalized in a consent decree issued by the District Court on December 28, 2016. Under the decree, the EPA is required to propose no later than March 15, 2019, a rulemaking for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or sign a determination that revision of the regulations is not necessary. If EPA proposes a rulemaking for revised oil and gas waste regulations, the Consent Decree

 

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requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021. Any such changes in applicable laws and regulations could have a material adverse effect on its CapEx and operating expenses. Moreover, some ordinary industrial wastes which we generate, such as paint wastes, waste solvents, laboratory wastes and waste oils, may be regulated as hazardous wastes if they are determined to have hazardous characteristics.

Some of our leases may have had prior owners who commenced exploration and production of natural gas operations on these sites. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us on or under other locations where such wastes have been taken for disposal. In addition, a portion of these properties may have been operated by third parties whose treatment and disposal or release of wastes was not under our control. These properties and the wastes disposed thereon may be subject to CERCLA, RCRA, and/or analogous state laws. Under such laws, we could be required to remove or remediate previously disposed wastes (including waste disposed of or released by prior owners or operators) or property contamination (including groundwater contamination by prior owners or operators), or to perform remedial plugging or closure operations to prevent future contamination.

Water Discharges

The Federal Water Pollution Control Act, as amended, also known as the CWA and its state analogues impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of certain substances, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA, the Army Corps of Engineers (the “Corps”) or an analogous state agency. The CWA and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. In September 2015, EPA and the Corps issued new rules defining the scope of the EPA’s and the Corps’ jurisdiction over wetlands. The rule has been challenged in court on the grounds that it unlawfully expands the reach of CWA programs, and implementation of the rule has been stayed pending resolution of the court challenge. In February 2017, President Trump issued an executive order directing the EPA and Corps to review and, consistent with applicable law, initiate rulemaking to rescind or revise the rule. To the extent this rule or a revised rule expands the scope of the CWA’s jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas.

The process for obtaining permits has the potential to delay our operations. Spill prevention, control and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of navigable waters by a petroleum hydrocarbon tank spill, rupture or leak. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. Federal and state regulatory agencies can impose administrative, civil and criminal penalties as well as other enforcement mechanisms for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.

The Oil Pollution Act of 1990, as amended, or the OPA, which amends the CWA, establishes strict liability for owners and operators of facilities that are the site of a release of oil into waters of the U.S. The OPA and its associated regulations impose a variety of requirements on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills. A “responsible party” under the OPA includes owners and operators of certain onshore facilities from which a release may affect waters of the U.S. The OPA assigns joint and several, strict liability, without regard to fault, to each liable party for all containment and oil removal costs and a variety of public and private damages including, but not limited to, the costs of responding to a release of oil, natural resource damages, and economic damages suffered by persons adversely affected by an oil spill.

 

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Hydraulic Fracturing

Hydraulic fracturing is an essential and common practice in the natural gas industry used to stimulate production of natural gas and/or oil from low permeability subsurface rock formations. Hydraulic fracturing involves using water, sand, and certain chemicals to fracture the hydrocarbon-bearing rock formation to allow flow of hydrocarbons into the wellbore. We regularly perform hydraulic fracturing as part of our operations. While hydraulic fracturing has historically been regulated by state oil and natural gas commissions, the practice has become increasingly controversial in certain parts of the country, resulting in increased scrutiny and regulation. For example, the EPA has asserted federal regulatory authority over certain hydraulic-fracturing activities under the SDWA involving the use of diesel fuels and published permitting guidance in February 2014 addressing the use of diesel in fracturing operations. Also, in May 2014 the EPA issued an Advanced Notice of Proposed Rulemaking to collect data on chemicals used in hydraulic fracturing operations under Section 8 of the Toxic Substances Control Act. Further, the EPA finalized regulations under the CWA in June 2016 prohibiting wastewater discharges from hydraulic fracturing and certain other natural gas operations to publicly owned wastewater treatment plants. Also, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain circumstances. The draft report is expected to be finalized after a public comment period and a formal review by the EPA’s Science Advisory Board. Finally, the BLM finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal and American Indian lands, though the U.S. District Court of Wyoming struck down this rule in June 2016. An appeal of this decision is pending. On March 15, 2017, the BLM filed a motion in the appeal, requesting the court to hold the case in abeyance pending rescission of the rule.

Along with several other states, Louisiana has adopted laws and proposed regulations that require oil and natural gas operators to disclose chemical ingredients and water volumes used to hydraulically fracture wells, in addition to more stringent well construction and monitoring requirements. In addition, local governments may also adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular or prohibit the performance of well drilling in general or hydraulic fracturing in particular. If new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

If hydraulic fracturing is further regulated at the federal state, or local level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential legislation or regulation governing hydraulic fracturing, and any of the above risks could impair our ability to manage our business and have a material adverse effect on our operations, cash flows and financial position.

Air Emissions

The CAA and comparable state laws restrict the emission of air pollutants from many sources, including compressor stations, through the issuance of permits and the imposition of other requirements. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. The need to obtain permits has the potential to delay the development of natural gas projects. Over the next several

 

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years, we may be required to incur certain CapEx for air pollution control equipment or other air emissions related issues. For example, in May 2016, the EPA finalized rules regarding criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting requirements. In addition, in October 2015, the EPA lowered the National Ambient Air Quality Standard (“NAAQS”) for ozone from 75 to 70 parts per billion. State implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant. The EPA has also adopted new rules under the CAA that require the reduction of volatile organic compound emissions from certain fractured and refractured natural gas wells for which well completion operations are conducted and further require that most wells use reduced emission completions, also known as “green completions.” These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors, and from pneumatic controllers and storage vessels. Compliance with these and other air pollution control and permitting requirements has the potential to delay the development of oil and natural gas projects and increase our costs of development, which costs could be significant.

Climate Change

In response to findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the CAA that, among other things, establish prevention of significant deterioration (“PSD”) pre-construction and Title V operating permit reviews for certain large stationary sources. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established on a case-by-case basis. EPA rulemakings related to GHG emissions could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and gas production sources in the United States on an annual basis, which include certain of our operations. Recently, in December 2015, the EPA finalized rules that added new sources to the scope of the greenhouse gases monitoring and reporting rule. These new sources include gathering and boosting facilities as well as completions and workovers from hydraulically fractured oil wells. The revisions also include the addition of well identification reporting requirements for certain facilities. Furthermore, in May 2016, the EPA finalized rules that establish new controls for emissions of methane from new, modified or reconstructed sources in the oil and natural gas source category, including production, processing, transmission and storage activities. The rule includes first-time standards to address emissions of methane from equipment and processes across the source category, including hydraulically fractured oil and natural gas well completions. The EPA had also announced in November 2016 that it intended to impose methane emission standards for existing sources as well but, in March 2017, the EPA announced that it was withdrawing an Information Collection Request that it had previously issued so that the agency could further assess the information that it was collecting through the request, consequently, to date, has not yet issued a proposal. The BLM has also proposed rules governing the emission of methane from oil and gas activities on federal lands. Several states, including Louisiana, are pursuing similar measures to regulate emissions of methane from new and existing sources within the oil and natural gas source category. Compliance with these rules will require enhanced record-keeping practices, the purchase of new equipment, such as optical gas imaging instruments to detect leaks, and increased frequency of maintenance and repair activities to address emissions leakage. These rules will also likely require additional personnel time to support these activities or the engagement of third party contractors to assist with and verify compliance. These new and proposed rules could result in increased compliance costs on our operations.

While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in

 

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return for emitting those GHGs. Although it is not possible at this time to estimate how potential future laws or regulations addressing GHG emissions would impact our business, either directly or indirectly, any future federal, state or local laws or implementing regulations that may be adopted to address GHG emissions in areas where we operate could require us or our customers to incur increased operating costs. Regulation of GHGs could also result in a reduction in demand for and production of oil and natural gas, which would result in a decrease in demand for our services and adversely affect our financial position and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. If any such effects were to occur, they could adversely affect or delay demand for the oil or natural gas produced by our customers or otherwise cause us to incur significant costs in preparing for or responding to those effects.

National Environmental Policy Act

Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. The process involves the preparation of either an environmental assessment or environmental impact statement depending on whether the specific circumstances surrounding the proposed federal action will have a significant impact on the human environment. The NEPA process involves public input through comments which can alter the nature of a proposed project either by limiting the scope of the project or requiring resource-specific mitigation. NEPA decisions can be appealed through the court system by process participants. This process may result in delaying the permitting and development of projects, increase the costs of permitting and developing some facilities and could result in certain instances in the cancellation of existing leases.

Endangered Species Act and Migratory Bird Treaty Act

The Endangered Species Act (“ESA”) restricts activities that may affect endangered or threatened species of their habitats. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. While some of our operations may be located in areas that are designated as habitats for endangered or threatened species or that may attract migratory birds we believe that we are in substantial compliance with the ESA and the Migratory Bird Treaty Act, and we are not aware of any proposed ESA listings that will materially affect our operations. On February 11, 2016, the U.S. Fish and Wildlife Service published a final policy which alters how it identifies critical habitat for endangered and threatened species. A critical habitat designation could result in further material restrictions to federal and private land use and could delay or prohibit land access or development. Moreover, the U.S. Fish and Wildlife Service continues its six-year effort to make listing decisions and critical habitat designations where necessary for over 250 species before the end of the agency’s 2017 fiscal year, as required under a 2011 settlement approved by the U.S. District Court for the District of Columbia, and many hundreds of additional anticipated listing decisions have already been identified beyond those recognized in the 2011 settlement. However, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected states.

Worker Health and Safety

We are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act, as amended, (“OSHA”), and comparable state statutes, whose purpose is to protect the safety and health of workers. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require maintenance of information about hazardous materials used or produced in operations and provision of this information to employees, state and local government authorities and citizens. Other OSHA standards regulate specific worker safety aspects of our operations. Failure to comply with OSHA requirements can lead to the imposition of penalties. In December 2015, the U.S. Departments of Justice and Labor announced a plan to more frequently and effectively prosecute worker health and safety violations, including enhanced penalties.

 

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Employees

As of December 31, 2016, we had 84 full-time employees.

Legal Proceedings

We are party to various legal proceedings and claims in the ordinary course of our business. We believe these matters will not have a material adverse effect on our consolidated financial position, results of operations or liquidity.

 

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MANAGEMENT

Directors and Executive Officers

The following table sets forth the names, ages and titles of our directors and executive officers as of December 31, 2016:

 

Name

  

Age

    

Title

Eric D. Marsh

     57      President, Chief Executive Officer and Chairman of the Board

John C. Regan

     47      Chief Financial Officer

Brian D. Dutton

     42      Chief Accounting Officer

David I. Foley

     49      Director

Angelo G. Acconcia

     37      Director

Gary D. Levin

     34      Director

Adam M. Jenkins

     33      Director

Charles M. Sledge

     51      Director Nominee

Set forth below are the backgrounds of our directors and executive officers as of December 31, 2016.

Eric D. Marsh became our President and Chief Executive Officer in May 2014. From October 2013 to May 2014, Mr. Marsh provided consulting services in the energy industry. Previously, Mr. Marsh served as Senior Vice President of Encana’s USA Division after being promoted to that position in 2011. From November 2009 to October 2013, Mr. Marsh also served as an Executive Vice President at Encana, leading the Natural Gas Economy team, a fundamentals team that was responsible for understanding supply and demand relationships for natural gas in North America. Prior to 2009, Mr. Marsh held various management positions at Encana’s Bighorn Business Unit and Encana’s South Rockies Business Unit. Mr. Marsh currently serves as a director of Huntley & Huntley Energy Exploration, LLC. Mr. Marsh sits on the Governor’s Task Force for the State of Wyoming Engineering Development and has served on both the University of Wyoming Foundation and the University of Wyoming Engineering Accreditation Board.

John C. Regan became our Executive Vice President and Chief Financial Officer in January 2015. He had previously been the Senior Vice President and Chief Financial Officer of Quicksilver Resources from April 2012 through December 2014, after having served as their Chief Accounting Officer beginning in September 2007. Mr. Regan is a Certified Public Accountant with more than 25 years of combined public accounting, corporate finance and financial reporting experience. Mr. Regan was also employed by Flowserve Corporation where he held various management positions of increasing responsibility from 2002 to 2007, including Vice President of Finance and by PricewaterhouseCoopers where his roles included being a senior manager specializing in the energy segment of their audit practice during his employment from 1994 to 2002.

Brian D. Dutton became our Chief Accounting Officer in February 2015. Mr. Dutton is a Certified Public Accountant with more than 18 years of combined public accounting and financial reporting experience. He had previously been the Vice President of Finance and Accounting of Silver Creek Oil & Gas from July 2012 through January 2015. Mr. Dutton was also employed by Quicksilver Resources where he held various positions in accounting and finance from 2008 to July 2012. He began his finance career with PricewaterhouseCoopers in 1998.

David I. Foley has served on our board since May 2014. Mr. Foley is a Senior Managing Director in the Private Equity Group at Blackstone and Chief Executive Officer of Blackstone Energy Partners. Mr. Foley leads Blackstone’s private equity investment activities in the energy and natural resources sector on a global basis. Since joining Blackstone in 1995, Mr. Foley has been responsible for building the Blackstone energy and natural resources practice and has been involved in every private equity energy deal that the firm has invested in. Mr. Foley currently serves as a director of Kosmos Energy, Cheniere Energy Inc., and several privately-held energy companies in which Blackstone is an equity investor. Because of his broad knowledge of the industry and oil and gas investments, we believe Mr. Foley is well qualified to serve on our board of directors.

 

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Angelo G. Acconcia has served on our board since May 2014. Mr. Acconcia is a Senior Managing Director in the Private Equity Group at Blackstone. Mr. Acconcia leads Blackstone’s private equity investment activities in the oil & gas sector on a global basis. Since joining Blackstone in August 2004, Mr. Acconcia has been involved in the execution of numerous Blackstone investments, including Graham Packaging, Ondeo Nalco, TRW Automotive and Texas Genco. Mr. Acconcia has either led or played a critical role in every one of Blackstone’s North American oil and gas investments, including Alta Energy, Beacon Offshore Energy, GeoSouthern Energy, Guidon Energy, Hunter Oil & Gas, Kosmos Energy, LLOG Bluewater, OSUM Oil Sands, Primexx, Royal Resources, Gavilan Resources and Vine Resources, among others. From August 2002 until August 2004, Mr. Acconcia worked at Morgan Stanley & Company’s Investment Banking Division in the Global Energy and Mergers and Acquisitions departments in both the U.S. and Canada. Because of his broad knowledge of the industry and oil and gas investments, we believe Mr. Acconcia is well qualified to serve on our board of directors.

Gary D. Levin has served on our board since May 2014. Mr. Levin is a Managing Director in the Private Equity Group at Blackstone. Since joining Blackstone in October 2011, Mr. Levin has been involved with Blackstone’s investments in Alta Energy, Beacon Offshore Energy, GeoSouthern Energy, Kosmos Energy, LLOG Bluewater, OSUM Oil Sands, Gavilan Resources and Vine Resources, among others. From January 2007 until September 2011, Mr. Levin was a Vice President at Pine Brook Partners, where he was involved in the evaluation and execution of numerous private equity investments into oil and gas companies. From June 2004 until December 2006, Mr. Levin worked for Warburg Pincus, where he focused on investments across the energy sector. Because of his broad knowledge of the industry and oil and gas investments, we believe Mr. Levin is well qualified to serve on our board of directors.

Adam M. Jenkins has served on our board since May 2014. Mr. Jenkins is a Principal in the Private Equity Group at Blackstone. Since joining Blackstone in July 2013, Mr. Jenkins has been involved with Blackstone’s investments in Beacon Offshore Energy, Kosmos Energy, LLOG Bluewater, Royal Resources, Siccar Point Energy, and Vine Resources, among others. From August 2011 until June 2013, Mr. Jenkins was an Associate at WL Ross & Co. From July 2006 until July 2008, he worked at Lazard, where he focused on mergers and acquisitions advisory to consumer goods companies. He is a member of the New York State Bar. Because of his broad knowledge of the industry and oil and gas investments, we believe Mr. Jenkins is well qualified to serve on our board of directors.

Charles M. Sledge has been nominated to serve as a member of our board of directors, effective upon completion of this offering. Mr. Sledge previously served as Senior Vice President and Chief Financial Officer of Cameron International Corporation, an oilfield services company, from November 2008 until its acquisition by Schlumberger in April 2016 after previously having been its Vice President and Chief Financial Officer and its Corporate Controller. Mr. Sledge also served as Senior Vice President of Finance and Treasurer of Stage Stores, Inc. from 1999 to 2001 after having served as its Vice President, Controller from 1996 to 1999. Mr. Sledge serves on the board of directors of Stone Energy Corporation and Templar Energy LLC. Because of his broad financial knowledge as well as knowledge of the industry and oil and gas investments, we believe Mr. Sledge is well qualified to serve on our board of directors.

Board of Directors

Upon the closing of this offering, it is anticipated that we will have six directors.

Our board of directors has determined that Messrs. Foley, Acconcia, Levin, Jenkins and Sledge are independent under NYSE listing standards.

In connection with this offering, we will enter into a stockholders’ agreement with Blackstone, which will provide Blackstone with the right to designate up to five nominees to our board of directors so long as it and its affiliates collectively beneficially own more than 50% of the outstanding shares of our common stock. Under the stockholders’ agreement, Blackstone will also have the right to designate a certain number of nominees to our

 

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board of directors so long as it and its affiliates collectively beneficially own more than 5% of the outstanding shares of our common stock. Our board of directors will be divided into three classes of directors, with each class as equal in number as possible, serving staggered three-year terms, and such directors will be removable only for “cause.”

In evaluating director candidate’s qualifications, we will assess whether a candidate possesses the integrity, judgment, knowledge, experience, skills and expertise that are likely to enhance our ability to manage and direct our affairs and business, including the ability of our board’s committees. Our directors hold office until the earlier of their death, resignation, retirement, disqualification or removal or until their successors have been duly elected and qualified.

Status as a Controlled Company

Because Vine Investment will own a majority of our outstanding common stock following the completion of this offering, we expect to be a controlled company under NYSE corporate governance standards. A controlled company need not comply with the applicable corporate governance rules that its board of directors have a majority of independent directors and independent compensation and nominating and governance committees. Notwithstanding our status as a controlled company, we will remain subject to the applicable corporate governance standard that requires us to have an audit committee composed entirely of independent directors. As a result, our audit committee must have at least one independent director by the date our Class A common stock is listed on the NYSE, as applicable, at least two independent directors within 90 days of the listing date and at least three independent directors within one year of the listing date.

While these exemptions will apply to us as long as we remain a controlled company, we expect that our board of directors will nonetheless consist of a majority of independent directors within the meaning of the NYSE listing standards currently in effect.

Committees of the Board of Directors

Upon the conclusion of this offering, we intend to have an audit committee of our board of directors, and may have such other committees as the board of directors shall determine from time to time. We anticipate that each of the standing committees of the board of directors will have the composition and responsibilities described below.

Audit Committee

We will establish an audit committee prior to the completion of this offering. Following completion of this offering, our audit committee will consist of Mr. Sledge. As required by the rules of the SEC and listing standards of the NYSE, the audit committee will consist solely of independent directors, subject to the phase-in exceptions. Those rules permit us to have an audit committee that has one independent member at the date our common stock is first listed on the NYSE, a majority of independent members within 90 days thereafter and all independent members within one year thereafter. SEC rules also require that a public company disclose whether or not its audit committee has an “audit committee financial expert” which is defined as a person whose experience yields the attributes outlined in such rules. Mr. Sledge will satisfy this requirement.

This committee will oversee, review, act on and report on various auditing and accounting matters to our board of directors, including: the selection of our independent accountants, the scope of our annual audits, fees to be paid to them, their performance and our accounting practices. In addition, the audit committee will oversee our compliance programs relating to legal and regulatory requirements. We expect to adopt an audit committee charter defining the committee’s primary duties in a manner consistent with the rules of the SEC and applicable stock exchange or market standards, including SOX.

 

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Compensation Committee

Because we will be a “controlled company” within the meaning of the NYSE corporate governance standards, we will not be required to have a compensation committee.

If and when we are no longer a “controlled company” within the meaning of the NYSE corporate governance standards, we will be required to establish a compensation committee prior to the completion of this offering. We anticipate that such a compensation committee would consist of three directors who will be “independent” under the rules of the SEC. This committee would establish salaries, incentives and other forms of compensation for officers and other employees. Any compensation committee would also administer our incentive compensation and benefit plans. Upon formation of a compensation committee, we would expect to adopt a compensation committee charter defining the committee’s primary duties in a manner consistent with the rules of the SEC, the PCAOB and applicable stock exchange or market standards.

Nominating and Corporate Governance Committee

Because we will be a “controlled company” within the meaning of the NYSE corporate governance standards, we will not be required to, and do not currently expect to, have a nominating and corporate governance committee.

If and when we are no longer a “controlled company” within the meaning of the NYSE corporate governance standards, we will be required to establish a nominating and corporate governance committee shortly after the completion of this offering. We anticipate that such a nominating and corporate governance committee would consist of three directors who will be “independent” under the rules of the SEC. This committee would identify, evaluate and recommend qualified nominees to serve on our board of directors, develop and oversee our internal corporate governance processes and maintain a management succession plan. Upon formation of a compensation committee, we would expect to adopt a nominating and corporate governance committee charter defining the committee’s primary duties in a manner consistent with the rules of the SEC and applicable stock exchange or market standards.

Compensation Committee Interlocks and Insider Participation

Because we will be a “controlled company” within the meaning of the NYSE corporate governance standards, we will not be required to, and do not currently expect to, have a compensation committee. None of our executive officers serve on the board of directors or compensation committee of another public company that has an executive officer that serves on our board or compensation committee. No member of our board is an executive officer of another public company in which one of our executive officers serves as a member of the board of directors or compensation committee of that company.

Code of Business Conduct and Ethics

Prior to the completion of this offering, our board of directors will adopt amendments to our existing code of business conduct and ethics applicable to our employees, directors and officers, that will comply with applicable U.S. federal securities laws and the corporate governance rules of the NYSE. Any waiver of this code may be made only by our board of directors and will be promptly disclosed as required by applicable U.S. federal securities laws and the corporate governance rules of the NYSE.

Corporate Governance Guidelines

Prior to the completion of this offering, our board of directors will adopt corporate governance guidelines in accordance with the corporate governance rules of the NYSE.

 

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EXECUTIVE COMPENSATION

We are an “emerging growth company,” within the meaning of the Securities Act. As such, we are providing our Summary Compensation Table, Outstanding Equity Awards at Fiscal Year-End and limited narrative disclosures regarding executive compensation for only the last two completed fiscal years. Further, our reporting requirements extend only to our “named executive officers” as defined in the Securities Act. For 2016, our named executive officers (“NEOs”) were:

 

Name

   Principal Position

Eric D. Marsh

   President, Chief Executive Officer & Chairman of the Board

John C. Regan

   Chief Financial Officer & Executive Vice President

Brian D. Dutton

   Chief Accounting Officer

Summary Compensation Table

The following table summarizes information relating to compensation earned and accrued for employment:

 

Name

   Year      Salary
($)(1)
    Bonus
($)(2)
     All Other
Compensation

($)(3)
    Total
($)
 

Eric D. Marsh

     2016        350,000       931,000        27,763 (4)      1,308,763  
     2015        350,000       931,000        30,742 (4)      1,311,742  
            

John C. Regan

     2016        330,000       166,250        22,539       518,789  
     2015        330,000       166,250        57,719       553,969  
            

Brian D. Dutton

     2016        211,150       84,248        28,755       324,153  
     2015        175,104 (5)      69,866        55,185       300,155  

 

(1) A portion of these amounts are charged to Brix Oil & Gas Holdings LP and Harvest Royalties Holdings LP as general and administrative expenses based on time spent by our NEOs providing services to such entities pursuant to separate management services agreements.
(2) The amounts reported reflect amounts earned for company performance for the respective year under our discretionary annual cash bonus program which were paid during the first quarter of 2016 and 2017.
(3) Amounts reported include company contributions under our 401(k) plan, company paid insurance premiums, any relocation expenses and any sign on bonuses.
(4) Amounts reported include monitoring fees under the Advisory Agreement. “Certain Relationships and Related Party Transactions” contains more information regarding the Advisory Agreement.
(5) Mr. Dutton joined the Company in February 2015, so the amount included for 2015 reflects a pro-rated annual base salary for the months of service to the Company.

 

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Outstanding Equity Awards at 2016 Fiscal Year-End

The following table reflects information regarding outstanding Class A units, the only incentive awards held by our NEOs, as of December 31, 2016. Vine Oil & Gas LP is currently responsible for making all payments, distributions and settlements to all award recipients relating to the Class A units and following the consummation of this offering, Vine Investment and Vine Investment II will be responsible for making all payments, distributions and settlements to all award recipients relating to the Class A units. “—Narrative Disclosures—Incentive Units” contains additional information on such units prior to and following the consummation of this offering.

 

Name

   Number of
Securities
Unexercised,
Exercisable

(#)(1)
     Number of
Securities
Unexercised,
Unexercisable

(#)(1)
     Exercise
Price ($)
   Expiration
Date

Eric D. Marsh

     16        24      N/A    N/A

John C. Regan

     4        6      N/A    N/A

Brian D. Dutton

     0.8        1.2      N/A    N/A

 

(1) We believe that these awards are most similar economically to stock options, and as such we report them as “options” under the definition provided in Item 402(a)(6)(i) of Regulation S-K as an instrument with an “option-like feature.” Awards reflected as “Unexercisable” are Class A units that have not yet vested or are not yet probable to vest. The Class A units vest in five equal installments beginning on the later of the grant date or the Shell Acquisition. Awards reflected as “Exercisable” are Class A units that have vested, but are not yet exercisable and have not yet been settled.

Employment Agreements

We have entered into employment agreements with Messrs. Marsh and Regan. The description of the employment agreements set forth below is a summary of the material features of the agreements regarding potential payments upon termination or a change of control. This summary, however, does not purport to be a complete description of all the provisions of the agreements that we have entered into with the executives. This summary is qualified in its entirety by reference to the employment agreements, which have been filed as exhibits to this registration statement.

In May 2014 we entered into an employment agreement with Mr. Marsh. The agreement had an initial two-year term, and an indefinite extension until otherwise terminated upon the consummation of the Shell Acquisition. The agreement provided Mr. Marsh with an annual base salary of $350,000 during the term and eligibility to earn a targeted annual bonus of two times his base salary. Effective January 1, 2017, Mr. Marsh’s agreement was amended to increase his base salary to $570,000 with an annual bonus target of 100% of his base salary. Mr. Marsh’s employment agreement now has an indefinite term unless otherwise terminated earlier.

In January 2015 we entered into an employment agreement with Mr. Regan. The agreement initially had a two-year term that automatically renews for successive one-year periods until terminated by either party at least 60 days prior to a renewal date. The agreement provided Mr. Regan with an annual base salary of $330,000 during the term and eligibility to earn an annual target bonus of $125,000. Effective January 1, 2017, Mr. Regan’s agreement was amended to increase his base salary to $385,000 and an annual bonus target of 40% of his base salary.

Under the terms of both employment agreements, each will be entitled to receive the following amounts upon a termination by the company for “cause” (as such term is defined below) or upon voluntary termination without “good reason” (as such term is defined below): (a) payment of all accrued and unpaid base salary to the date of termination, (b) reimbursement of all incurred but unreimbursed business expenses and (c) benefits entitled under the terms of any applicable benefit plan or program (together the “Accrued Obligations”). If the termination is due to death or disability, by the company without cause or by the executive with good reason, he will also be entitled to a severance payment equal to the sum of their annual base salary and pro-rated annual

 

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bonus (provided, that Mr. Regan’s bonus shall not be pro-rated) on the date of termination, payable in ratable installments in accordance with regular payroll practices.

“Good Reason” means (a) a material diminution in the executive’s base salary; (b) a material diminution in the executive’s authority, duties, or responsibilities; (c) the involuntary relocation of the geographic location of the executive’s principal place of employment by more than 50 miles from the location of the executive’s principal place of employment as of the effective date of the employment agreement; or (d) a material breach by us of the employment agreement.

“Cause” means (a) act(s) of gross negligence or willful misconduct by the executive in the course of employment, (b) willful failure or refusal to perform in any material respect the executive’s duties or responsibilities, (c) misappropriation (or attempted misappropriation) by the executive of any assets or business opportunities of us, (d) embezzlement or fraud committed (or attempted) by the executive, or at his direction, (e) conviction of, or the plea of guilty or nolo contendere or the equivalent in respect to, any felony or a misdemeanor involving an act of dishonesty, moral turpitude, deceit, or fraud, (f) material breach by the executive of the employment agreement or (g) breach by the executive of the non-interference agreement.

Base Salary

Each NEO’s base salary is a fixed component of compensation for each year for performing specific job duties and functions. Historically, the board of managers of Vine Oil & Gas LP established the annualized base salary for each of the NEOs at a level necessary to retain their services and reviewed such annualized base salary at the end of each year, with adjustments implemented at the beginning of the next year. The establishment and adjustment of the annualized base salary for each NEO has generally been based on factors including but not limited to: (i) any increase or decrease in responsibility, (ii) job performance and (iii) the level of compensation paid to executives of other peer companies, as estimated based on publicly available information and the experience of the board of managers of our predecessor.

Annual Bonus

Historically, we have maintained a discretionary bonus program. Following year end, our board of managers has previously determined the amount, if any, of the discretionary annual bonuses awarded to each of our NEOs after careful review of our performance over the course of the preceding year. Principal determinants in this subjective assessment have included, but were not limited to, natural gas production, well costs, capital efficiency, and adjusted EBITDAX. Other qualitative factors such as safety performance and advancement of strategic objectives also influence the calculation.

For both 2016 and 2015, based on company performance, our board of managers approved a payout for Messrs. Marsh, Dutton and Regan of 133% of their respective bonus targets.

Class A Units

In 2014 Mr. Marsh and in 2015 Messrs. Regan and Dutton each received an award of Class A units in Vine Oil & Gas LP pursuant to the Vine Oil & Gas LP Class A Unit Incentive Plan. The Class A units are profits interests that represent actual (non-voting) equity interests in Vine Oil & Gas LP meant to enable certain employees to share in Blackstone’s financial success after Blackstone receives a certain level of return on its investment. The Class A units entitle unitholders to an increasing percentage of future distributions, but only after all invested capital has received cumulative cash distributions of a certain multiple return.

Upon the consummation of this offering and the related reorganization (i) the Class A units in Vine Oil & Gas LP will be converted into units in Vine Investment and Vine Investment II and (ii) Vine Investment and Vine Investment II will hold shares of Class A common stock. Vine Oil & Gas LP is currently responsible for making

 

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all payments, distributions and settlements to all award recipients relating to the Class A units and following the consummation of this offering, Vine Investment and Vine Investment II will be responsible for making all payments, distributions and settlements to all award recipients relating to the Class A units. The below description of the Class A units reflects the terms of the Class A units as such units will exist in Vine Investment and Vine Investment II upon consummation of this offering.

The Class A units vest in five equal installments beginning on the later of the grant date or the Shell Acquisition, although such vesting will be fully accelerated upon the occurrence of a “Change of Control” (as defined below). If employment is terminated due to death or disability, any Class A units that would have become vested on the next vesting date shall automatically vest. If employment is terminated for any other reason, all unvested Class A units are forfeited at the time of termination (except with respect to Mr. Marsh, whose unvested Class A units will fully vest in the event he is terminated without cause or if he resigns with good reason, in each case, within one year of this offering). If employment is terminated due to death or disability, or by us without cause or by the employee with good reason, Vine Investment and Vine Investment II each have the right but not the obligation (except that Vine Investment and Vine Investment II have an obligation to repurchase vested units with respect to Mr. Marsh in the event of his death or disability) to repurchase all vested Class A units held by the executive at their fair market value. Prior to the fourth anniversary of this offering (except with respect to Mr. Marsh) if employment or service is terminated for any reason other than due to death or disability, or by us without cause or by the employee with good reason, Vine Investment and Vine Investment II each have the right but not the obligation to repurchase all vested Class A units held by the executive at the lesser of (1) capital contributions made by the unitholder in respect of the Class A unit less distributions made to the unitholder in respect of the Class A unit and (2) fair market value. Since all of the Class A units issued by Vine Investment and Vine Investment II were made without a capital contribution, the repurchase under these circumstances would be at $0 which would allow Vine Investment and Vine Investment II to cancel the award (except with respect to Mr. Marsh) without making payment to the holder for either vested or unvested portions. Following the fourth anniversary of this offering (or at any time following this offering with respect to Mr. Marsh), if employment or service is terminated by an executive without good reason, Vine Investment and Vine Investment II will have the right but not the obligation to repurchase all vested Class A units held by the executive for a percentage of fair market value.

We do not expect that this offering will result in a Change of Control for the Class A units. A “Change of Control” occurs if:

 

  a) more than 50% of the Class B units of Vine Oil & Gas LP (and after the consummation of this offering and the reorganization, Vine Investment and Vine Investment II) are acquired by an unaffiliated entity; or

 

  b) substantially all of Vine Oil & Gas LP’s (and after the consummation of this offering and the reorganization, Vine Investment and Vine Investment II) outstanding interests are sold or exchanged in a single transaction, or a series of related transactions, to any unaffiliated entity.

Following the closing of this offering, we expect that our NEOs will no longer receive awards of Class A units or other equity based compensation from Vine Oil & Gas LP, Vine Investment or Vine Investment II. We do expect our NEOs to receive long-term incentive compensation pursuant to the long-term incentive plan that our board of directors has adopted in connection with the offering.

Director Compensation

We were formed in December 2016. We have recognized no obligations with respect to director compensation for any periods prior to or following the formation. Individuals serving on the board of managers of Vine Oil & Gas LP did not receive compensation in 2015 or 2016.

 

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We also believe that the compensation package for our non-employee directors should include equity-based awards to align their interest with our stockholders.

Following the completion of this offering, we expect to provide our non-employee directors (other than directors who are employees of Blackstone) with an annual compensation package comprised of a cash element and an equity-based award element. We expect our non-employee directors (other than directors who are employees of Blackstone) to each receive:

 

    a quarterly cash retainer of $37,500; and

 

    an annual Class A stock grant with a grant date fair market value of $50,000.

We also expect that all members of our board of directors will be reimbursed for certain reasonable expenses in connection with their services to us.

We are reviewing the landscape of non-employee director compensation and intend to implement a non-employee director compensation program in connection with this offering. Directors who are also our employees will not receive any additional compensation for their service on our board of directors.

Long-Term Incentive Plan

We anticipate that our board of directors will adopt the Vine Resources Inc. 2017 Long-Term Incentive Plan (the “Plan”), pursuant to which employees, consultants, and directors of our company and its affiliates performing services for us, including our named executive officers, will be eligible to receive awards. We anticipate that the Plan will provide for the grant of stock options, stock appreciation rights, restricted stock, restricted stock units, bonus stock, dividend equivalents, other stock-based awards, substitute awards, annual incentive awards, and performance awards intended to align the interests of participants with those of our stockholders. The following description of the Plan is based on the form we anticipate will be adopted, but since the Plan has not yet been adopted, the provisions remain subject to change. As a result, the following description is qualified in its entirety by reference to the final Plan once adopted, a copy of which in substantial form has been filed as an exhibit to this registration statement.

Administration. We anticipate that the Plan will be administered by our board of directors, or the compensation committee of our board of directors once established (the “Plan Administrator”). The Plan Administrator will have the authority to, among other things, designate eligible persons as participants under the Plan, determine the type of awards to be granted, determine the number of shares of our Class A common stock to be covered by awards, determine the terms and conditions applicable to awards and interpret and administer the Plan. The Plan Administrator may terminate or amend the Plan at any time with respect to any shares of our Class A common stock for which a grant has not yet been made. The Plan Administrator also has the right to alter or amend the Plan or any part of the Plan from time to time, including increasing the number of shares of our common stock that may be granted, subject to applicable shareholder approval. However, no change in any outstanding award may be made that would materially and adversely affect the rights of the participant under the award without the consent of the participant.

Number of Shares. Subject to adjustment in the event of any distribution, recapitalization, split, merger, consolidation or similar corporate event, we anticipate that the number of our Class A common shares available for delivery pursuant to awards granted under the Plan will not exceed             . Shares subject to awards under the Plan that are canceled, forfeited, exchanged, settled in cash or otherwise terminated, including shares withheld to satisfy exercise prices or tax withholding obligations, will again be available for awards under the Plan. The shares of our common stock to be delivered under the Plan will be made available from authorized but unissued shares, shares held in treasury, or previously issued shares reacquired by us, including by purchase on the open market.

 

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Stock Options. A stock option, or option, is a right to purchase shares of our Class A common stock at a specified price during specified time periods. We anticipate that options which vest over time will have an exercise price no less than the fair market value of our Class A common stock on the date of grant. Options granted under the Plan can be either incentive options (within the meaning of section 422 of the Code), which have certain tax advantages for recipients, or non-qualified options. No option will have a term that exceeds ten years.

Stock Appreciation Rights. A stock appreciation right is an award that, upon exercise, entitles a participant to receive the excess of the fair market value of our common stock on the exercise date over the grant price established for the stock appreciation right on the date of grant. Such excess will be paid in a form (e.g., cash or shares of our Class A common stock) determined by the Plan Administrator. It is anticipated that stock appreciation rights will vest over time and have a grant price that may not be less than the fair market value of our common stock on the date of grant.

Restricted Stock. A restricted stock grant is an award of Class A common stock that vests over a period of time and, during such time, is subject to transfer limitations and other restrictions imposed by the Plan Administrator, in its discretion. Except as otherwise provided under the terms of the Plan or an award agreement, during the vesting period, a participant will have rights as a stockholder, including the right to vote the Class A common stock subject to the award and to receive cash dividends thereon (which may, if required by the Plan Administrator, be subjected to the same vesting terms that apply to the underlying award of restricted stock).

Restricted Stock Units. A restricted stock unit is a notional share that entitles the grantee to receive shares of our common stock, cash or a combination thereof, as determined by the Plan Administrator, at or some future date following the vesting of the restricted stock unit.

Bonus Stock Awards. A bonus stock award is a transfer of unrestricted shares of our Class A common stock on terms and conditions determined by the Plan Administrator. The Plan Administrator will determine any terms and conditions applicable to grants of Class A common stock, including performance criteria, if any, associated with a bonus stock award.

Dividend Equivalents. Dividend equivalents entitle a participant to receive cash, Class A common stock, other awards, or other property equal in value to dividends paid with respect to a specified number of shares of our common stock, or other periodic payments at the discretion of the Plan Administrator. Dividend equivalents may be granted on a free-standing basis or in connection with another award (other than an award of restricted stock or a bonus stock award).

Other Stock-Based Awards. Other stock-based awards are award denominated in or payable in, valued in whole or in part by reference to, or otherwise based on or related to, the value of our Class A common stock.

Substitute Awards. Substitute awards may be granted under the Plan in substitution for similar awards held for individuals who become eligible persons as a result of a merger, consolidation, or acquisition of another entity (or the assets of another entity) by or with us or one of our affiliates.

Performance Awards and Annual Incentive Awards. A performance award is a right to receive all or part of an award granted under the Plan based upon performance conditions specified by the Plan Administrator. The Plan Administrator will determine the period over which certain specified company or individual goals or objectives must be met. An annual incentive award is an award based on a performance period of the fiscal year and is also conditioned on one or more performance standards. The performance or annual incentive award may be paid in cash, Class A common stock, other awards or other property, in the discretion of the Plan Administrator.

One or more of the following business criteria as applied to us may be used by the Plan Administrator in establishing performance conditions for performance awards granted to covered employees that are intended to

 

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satisfy the requirements for “performance-based compensation” within the meaning of section 162(m) of the Code: (1) earnings per share; (2) revenues; (3) cash flow; (4) cash flow from operations; (5) cash flow return; (6) return on net assets; (7) return on assets; (8) return on investment; (9) return on capital; (10) return on equity; (11) economic value added; (12) operating margin; (13) contribution margin; (14) net income; (15) net income per share; (16) pretax earnings; (17) pretax earnings before interest, depreciation and amortization; (18) pretax operating earnings after interest expense and before incentives, service fees, and extraordinary or special items; (19) total stockholder return; (20) debt reduction or management; (21) market share; (22) change in the Fair Market Value of the Stock; (23) operating income; (24) enterprise value; (25) reserve volumes or value; (26) production volumes; (27) finding and development costs or production costs per mcf; (28) lease operating expenses (29) well costs; (30) capital efficiency; (31) number of drilling locations; and (32) any of the above goals determined on a basic or adjusted basis, or on an absolute or relative basis, as compared to the performance of a published or special index deemed applicable by the Plan Administrator, including but not limited to, the Standard & Poor’s 500 Stock Index or a group of comparable companies.

 

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth the beneficial ownership of our Class A common stock and Class B common stock (assuming the underwriters do not exercise their option to purchase additional common stock) that, upon the consummation of our corporate reorganization in connection with the completion of this offering, will be owned by:

 

    each person known to us to beneficially own more than 5% of any class of our outstanding common stock;

 

    each of our Named Executive Officers;

 

    each member of our board of directors; and

 

    all of our directors and executive officers as a group.

Except as otherwise noted, the person or entities listed below have sole voting and investment power with respect to all shares of our Class A common stock beneficially owned by them, except to the extent this power may be shared with a spouse. All information with respect to beneficial ownership has been furnished by the directors or Named Executive Officers, as the case may be. Unless otherwise noted, the mailing address of each listed beneficial owner is c/o Vine Resources Inc., 5800 Granite Parkway, Suite 550, Plano, Texas 75024.

Prior to the completion of our corporate reorganization (which will occur in connection with the completion of this offering), the ownership interests of our directors and executive officers are represented by limited partnership interests in Vine Oil & Gas LP.

To the extent that the underwriters sell more than              shares of Class A common stock, the underwriters have the option to purchase up to an additional              shares from us.

 

     Shares of Class A
Common

Stock Beneficially Owned
     Shares of Class B
Common

Stock Beneficially Owned
     Total
Common
Stock
Beneficially
Owned
 

Name of Beneficial Owner(1)

   Number      Percentage      Number      Percentage      Percentage  

5% Shareholders:

              

Vine Investment(2)

              

Vine Investment II(3)

              

Named Executive Officers and Directors:

              

Eric D. Marsh

              

John C. Regan

              

Brian D. Dutton

              

David I. Foley(4)

              

Angelo G. Acconcia(4)

              

Gary D. Levin(4)

              

Adam M. Jenkins(4)

              

Charles M. Sledge

              

Executive Officers and Directors as a Group (     persons)

              

 

* Less than 1%.
(1) Does not include an aggregate of              shares of restricted stock units (based on the midpoint of the price range set forth on the cover page of this prospectus) that our board of directors has offered to grant to our executive officers and directors in connection with the completion of this offering.
(2)

Vine Investment is owned by Vine Oil & Gas Holdings LLC (“Holdings”), Vintner Resources, LLC, which is controlled by Eric D. Marsh, our Chief Executive Officer, and certain members of management. Certain members of our management team and certain of our employees also own incentive units in Vine Investment. “Executive Compensation—Outstanding Equity Awards at 2016 Fiscal Year-

 

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  End” contains additional information on the incentive units. Holdings is owned by Blackstone Capital Partners VI-Q L.P. (“BCP VI-Q”), Blackstone Energy Partners Q L.P. (“BEP Q”), Blackstone Family Investment Partnership VI-ESC L.P. (“BFIP VI”), Blackstone Energy Family Investment Partnership ESC L.P. (“BEFIP ESC”) and Blackstone Energy Family Investment Partnership SMD L.P. (“BEFIP SMD”). The general partner of BCP VI-Q is Blackstone Management Associates VI L.L.C. The sole member of Blackstone Management Associates VI L.L.C. is BMA VI L.L.C. The general partner of BEP Q is Blackstone Energy Management Associates L.L.C. The sole member of Blackstone Energy Management Associates L.L.C. is Blackstone EMA L.L.C. The general partner of BFIP VI is BCP VI Side-by-Side GP L.L.C. The general partner of BEFIP ESC is BEP Side-by-Side GP L.L.C. The general partner of BEFIP SMD is Blackstone Family GP L.L.C., which is in turn, wholly-owned by Blackstone’s senior managing directors and controlled by its founder, Stephen A. Schwarzman. Blackstone Holdings III L.P. is the managing member of each of BMA VI L.L.C. and Blackstone EMA L.L.C. and the sole member of each of BCP VI Side-by-Side GP L.L.C. and BEP Side-by-Side GP L.L.C. The general partner of Blackstone Holdings III L.P. is Blackstone Holdings III GP L.P. The general partner of Blackstone Holdings III GP L.P. is Blackstone Holdings III GP Management L.L.C. The sole member of Blackstone Holdings III GP Management L.L.C. is The Blackstone Group L.P. The general partner of The Blackstone Group L.P. is Blackstone Group Management L.L.C. Blackstone Group Management L.L.C. is wholly-owned by Blackstone’s senior managing directors and controlled by its founder, Stephen A. Schwarzman. Each of the Blackstone entities described in this footnote and Stephen A. Schwarzman may be deemed to beneficially own the shares directly or indirectly controlled by such Blackstone entities or him, but each disclaims beneficial ownership of such shares. The address of each of the foregoing entities is 345 Park Avenue, 31st Floor, New York, New York 10154, provided that the address for Vintner Resources is 5800 Granite Parkway, Plano, Texas 75024.
(3) Vine Investment II LLC is owned by Vine TE-892 Holdings I LP, Vine TE-892 Holdings II LP, Vintner Resources, LLC, which is controlled by Eric D. Marsh, our Chief Executive Officer, and certain members of management. The general partner of Vine TE-892 Holdings I LP is Blackstone Energy Management Associates L.L.C. The sole member of Blackstone Energy Management Associates L.L.C. is Blackstone EMA L.L.C. The general partner of Vine TE-892 Holdings II LP is Blackstone Management Associates VI L.L.C. The sole member of Blackstone Management Associates VI L.L.C. is BMA VI L.L.C. Blackstone Holdings III L.P. is the managing member of each of BMA VI L.L.C. and Blackstone EMA L.L.C. The general partner of Blackstone Holdings III L.P. is Blackstone Holdings III GP L.P. The general partner of Blackstone Holdings III GP L.P. is Blackstone Holdings III GP Management L.L.C. The sole member of Blackstone Holdings III GP Management L.L.C. is The Blackstone Group L.P. The general partner of The Blackstone Group L.P. is Blackstone Group Management L.L.C. Blackstone Group Management L.L.C. is wholly-owned by Blackstone’s senior managing directors and controlled by its founder, Stephen A. Schwarzman. Each of the Blackstone entities described in this footnote and Stephen A. Schwarzman may be deemed to beneficially own the shares directly or indirectly controlled by such Blackstone entities or him, but each disclaims beneficial ownership of such shares. The address of each of the foregoing entities is 345 Park Avenue, 31st Floor, New York, New York 10154 provided that the address for Vintner Resources is 5800 Granite Parkway, Plano, Texas 75024.
(4) Messrs. Foley, Acconcia, Levin and Jenkins are each employees of Blackstone, but each disclaims beneficial ownership of the shares beneficially owned by Blackstone. The address for Messrs. Foley, Acconcia, Levin and Jenkins is c/o The Blackstone Group L.P., 345 Park Avenue, New York, New York 10154.

 

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CORPORATE REORGANIZATION

Vine Resources Inc. is a Delaware corporation that was formed for the purpose of making this offering. Following this offering and the transactions related thereto, Vine Resources Inc. will be a holding company whose sole material asset will consist of membership interests in Vine Resources Holdings LLC. Vine Resources Holdings LLC will own all of the outstanding limited partnership interests in Vine Oil & Gas LP, the operating subsidiary through which we operate our assets, and all of the outstanding equity in Vine Oil & Gas GP LLC, the general partner of Vine Oil & Gas LP. After the consummation of the transactions contemplated by this prospectus, Vine Resources Inc. will be the managing member of Vine Resources Holdings LLC and will be responsible for all operational, management and administrative decisions relating to Vine Resources Holdings LLC’s business and will consolidate the financial results of Vine Resources Holdings LLC and its subsidiaries.

In connection with this offering, (a) the Existing Owners will contribute all of their equity interests in Vine Oil & Gas LP and Vine Oil & Gas GP LLC to Vine Resources Holdings LLC in exchange for LLC Interests, (b) the Existing Owners will contribute a portion of their LLC Interests to Vine Investment II in exchange for newly issued equity interests in Vine Investment II and Vine Investment II will exchange the LLC Interests for Class A common stock, (c) Vine Resources Inc. will contribute the net proceeds of this offering to Vine Resources Holdings LLC in exchange for newly-research managing units in Vine Resources Holdings LLC, (d) the Existing Owners will exchange the remaining portion of their LLC Interests for Vine Units, receive newly issued Class B common stock with no economic rights in Vine Resources Inc., and will contribute all of their Vine Units and Class B common stock to Vine Investment in exchange for newly issued equity interests in Vine Investment. After giving effect to these transactions and the offering contemplated by this prospectus, Vine Resources Inc. will own an approximate     % interest in Vine Resources Holdings LLC (or     % if the underwriters’ option to purchase additional shares is exercised in full), Vine Investment will own an approximate     % interest in Vine Resources Holdings LLC (or     % if the underwriters’ option to purchase additional shares is exercised in full), and Vine Investment II will own an approximate     % interest in Vine Resources Inc. (or     % if the underwriters’ option to purchase additional shares is exercised in full).

Each share of Class B common stock will entitle its holder to one vote on all matters to be voted on by shareholders generally. Holders of Class A common stock and Class B common stock will vote together as a single class on all matters presented to our shareholders for their vote or approval, except as otherwise required by applicable law or by our certificate of incorporation. We do not intend to list Class B common stock on any stock exchange.

We will enter into a Tax Receivable Agreement with Vine Investment. This agreement generally provides for the payment by Vine Resources Inc. to Vine Investment of 85% of the net cash savings, if any, in U.S. federal, state and local income tax or franchise tax that Vine Resources Inc. actually realizes (or is deemed to realize in certain circumstances) in periods after this offering as a result of (i) the tax basis increases resulting from the exchange of Vine Units by Vine Investment for shares of Class A common stock pursuant to the Exchange Right (or resulting from an exchange of Vine Units for cash pursuant to the Cash Option) and (ii) imputed interest deemed to be paid by us as a result of, and additional tax basis arising from, any payments we make under the Tax Receivable Agreement. Vine Resources Inc. will retain the benefit of the remaining 15% of these cash savings. If we experience a change of control (as defined under the Tax Receivable Agreement, which includes certain mergers, asset sales and other forms of business combinations) or the Tax Receivable Agreement terminates early (at our election or as a result of our breach), we could be required to make a substantial, immediate lump-sum payment. “Certain Relationships and Related Party Transactions—Tax Receivable Agreement” contains more information.

 

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The following diagrams indicate our current ownership structure and our simplified ownership structure immediately following this offering and the transactions related thereto (assuming that the underwriters’ option to purchase additional shares is not exercised):

Simplified Current Ownership Structure

LOGO

 

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Simplified Ownership Structure After Giving Effect to this Offering

 

LOGO

Offering

Only Class A common stock will be sold to investors pursuant to this offering. Immediately following this offering, there will be              shares of Class A common stock issued and outstanding and              shares of Class A common stock reserved for exchanges of Vine Units and shares of Class B common stock pursuant to the VRH LLC Agreement. We estimate that our net proceeds from this offering, after deducting estimated

 

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underwriting discounts and commissions and other offering related expenses, will be approximately $             million. We intend to contribute all of the net proceeds of this offering to Vine Resources Holding LLC in exchange for Vine Units. Vine Resources Holding LLC will use (i) approximately $        million to repay our indebtedness and (ii) the remaining balance of the net proceeds for general corporate purposes. “Use of Proceeds” contains more information.

As a result of the corporate reorganization and the offering described above (and prior to any exchanges of Vine Units):

 

    the investors in this offering will collectively own              shares of Class A common stock (or              shares of Class A common stock if the underwriters exercise in full their option to purchase additional shares of Class A common stock);

 

    Vine Resources Inc. will hold             Vine Units;

 

    Vine Investment will hold              shares of Class B common stock and a corresponding number of Vine Units;

 

    Vine Investment II will hold              shares of Class A common stock;

 

    the investors in this offering will collectively hold         % of the voting power in us; and

 

    assuming no exercise of the underwriters’ option to purchase additional shares, Vine Investment will hold     % of the voting power in us (or         % if the underwriters exercise in full their option to purchase additional shares of Class A common stock).

Holding Company Structure

Our post-offering organizational structure will allow the Vine Unit Holders to retain their equity ownership in Vine Resources Holdings LLC, a partnership for U.S. federal income tax purposes. Investors in this offering will, by contrast, hold their equity ownership in the form of shares of Class A common stock in us, and we are classified as a domestic corporation for U.S. federal income tax purposes. We believe that the Vine Unit Holders find it advantageous to hold their equity interests in an entity that is not taxable as a corporation for U.S. federal income tax purposes. The Vine Unit Holders will generally incur U.S. federal, state and local income taxes on their proportionate share of any taxable income of Vine Resources Holdings LLC.

In addition, pursuant to our certificate of incorporation and the VRH LLC Agreement, our capital structure and the capital structure of Vine Resources Holdings LLC will generally replicate one another and will provide for customary antidilution mechanisms in order to maintain the one-for-one exchange ratio between the Vine Units and our Class A common stock, among other things.

The holders of Vine Units, including us, will generally incur U.S. federal, state and local income taxes on their proportionate share of any taxable income of Vine Resources Holdings LLC and will be allocated their proportionate share of any taxable loss of Vine Resources Holdings LLC. The VRH LLC Agreement will provide, to the extent cash is available, for distributions pro rata to the holders of Vine Units if we, as the managing member of Vine Resources Holdings LLC, determine that the taxable income of Vine Resources Holdings LLC will give rise to taxable income for a unitholder. Generally, these tax distributions will be computed based on our estimate of the taxable income of Vine Resources Holdings LLC that is allocable to a holder of Vine Units, multiplied by an assumed tax rate equal to the highest effective marginal combined U.S. federal, state and local income tax rate prescribed for an individual (or, if higher, a corporation) resident in New York, New York (taking into account the character of the allocated income and the deductibility of state and local income tax for federal income tax purposes).

We may accumulate cash balances in future years resulting from distributions from Vine Resources Holdings LLC exceeding our tax liabilities and our obligations to make payments under the Tax Receivable

 

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Agreement. To the extent we do not distribute such cash balances as a dividend on our Class A common stock and instead decide to hold or recontribute such cash balances to Vine Resources Holdings LLC for use in our operations, Vine Unit Holders who exchange their Vine Units for Class A common stock in the future could also benefit from any value attributable to any such accumulated cash balances.

We will enter into a Tax Receivable Agreement with Vine Investment. This agreement generally will provide for the payment by Vine Resources Inc. to Vine Investment of 85% of the net cash savings, if any, in U.S. federal, state and local income tax or franchise tax that Vine Resources Inc. actually realizes (or is deemed to realize in certain circumstances) in periods after this offering as a result of (i) the tax basis increases resulting from the exchange of Vine Units by Vine Investment for shares of Class A common stock pursuant to the Exchange Right (or resulting from an exchange of Vine Units for cash pursuant to the Cash Option) and (ii) imputed interest deemed to be paid by us as a result of, and additional tax basis arising from, any payments we make under the Tax Receivable Agreement. Vine Resources Inc. will retain the benefit of the remaining 15% of these cash savings. If we experience a change of control (as defined under the Tax Receivable Agreement, which includes certain mergers, asset sales and other forms of business combinations) or the Tax Receivable Agreement terminates early (at our election or as a result of our breach), we could be required to make a substantial, immediate lump-sum payment. “Certain Relationships and Related Party Transactions—Tax Receivable Agreement” contains additional information.

 

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Corporate Reorganization

In connection with our corporate reorganization, we will engage in transactions with certain affiliates and our existing equity holders. “Corporate Reorganization” contains a description of these transactions.

VRH LLC Agreement

Under the VRH LLC Agreement, we will have the right to determine when distributions will be made to the holders of Vine Units and the amount of any such distributions. Following this offering, if we authorize a distribution, such distribution will be made to the holders of Vine Units on a pro rata basis in accordance with their respective percentage ownership of Vine Units.

The holders of Vine Units, including us, will generally incur U.S. federal, state and local income taxes on their proportionate share of any taxable income of Vine Resources Holdings LLC and will be allocated their proportionate share of any taxable loss of Vine Resources Holdings LLC. Net profits and net losses of Vine Resources Holdings LLC generally will be allocated to holders of Vine Units on a pro rata basis in accordance with their respective percentage ownership of Vine Units, except that certain non-pro rata adjustments will be required to be made to reflect built-in gains and losses and tax depletion and depreciation with respect to such built-in gains and losses. The VRH LLC Agreement will provide, to the extent cash is available, for distributions to the holders of Vine Units if we, as the managing member of Vine Resources Holdings LLC, determine that the taxable income of Vine Resources Holdings LLC will give rise to taxable income for a unitholder. Generally, these tax distributions will be computed based on our estimate of the taxable income of Vine Resources Holdings LLC that is allocable to a holder of Vine Units, multiplied by an assumed tax rate equal to the highest effective marginal combined U.S. federal, state and local income tax rate prescribed for an individual (or, if higher, a corporation) resident in New York, New York (taking into account the character of the allocated income and the deductibility of state and local income tax for federal income tax purposes). In addition, if the cumulative amount of U.S. federal, state and local taxes payable by us exceeds the amount of the tax distribution to us, Vine Resources Holdings LLC will make advances to us in an amount necessary to enable us to fully pay these tax liabilities. Such advances will be repayable, without interest, solely from (i.e., by offset against) future distributions by Vine Resources Holdings LLC to us.

The VRH LLC Agreement will provide that, except as otherwise determined by us, at any time we issue a share of our Class A common stock or any other equity security, the net proceeds received by us with respect to such issuance, if any, shall be concurrently invested in Vine Resources Holdings LLC, and Vine Resources Holdings LLC shall issue to us one Vine Unit or other economically equivalent equity interest. Conversely, if at any time, any shares of our Class A common stock are redeemed, repurchased or otherwise acquired, Vine Resources Holdings LLC shall redeem, repurchase or otherwise acquire an equal number of Vine Units held by us, upon the same terms and for the same price, as the shares of our Class A common stock are redeemed, repurchased or otherwise acquired.

Under the VRH LLC Agreement, the members have agreed that Blackstone and/or one or more of its affiliates will be permitted to engage in business activities or invest in or acquire businesses which may compete with our business or do business with any client of ours.

Vine Resources Holdings LLC will be dissolved only upon the first to occur of (i) the sale of substantially all of its assets, (ii) approval of its dissolution by the managing member, and a vote in favor of dissolution by at least two-thirds of the holders of its Class B units or (iii) entry of a judicial order to dissolve the company. Upon dissolution, Vine Resources Holdings LLC will be liquidated and the proceeds from any liquidation will be applied and distributed in the following manner: (a) first, to creditors (including to the extent permitted by law, creditors who are members) in satisfaction of the liabilities of Vine Resources Holdings LLC, (b) second, to establish cash reserves for contingent or unforeseen liabilities and (c) third, to the members in proportion to the number of Vine Units owned by each of them.

 

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Exchange Agreement

We will enter into an exchange agreement with the holders of Vine Units pursuant to which each holder of Vine Units (and certain permitted transferees thereof) may, subject to the terms of the exchange agreement, exchange their Vine Units for shares of Class A common stock of Vine Resources Inc. on a one-for-one basis, subject to customary conversion rate adjustments for stock splits, stock dividends and reclassifications. At our election and pursuant to the Cash Option, we may give the exchanging Vine Unit Holders cash in an amount equal to the value of such Class A common stock instead of shares of Class A common stock. The exchange agreement also provides that a holder of Vine Units will not have the right to exchange Vine Units if Vine Resources Inc. determines that such exchange would be prohibited by law or regulation or would violate other agreements with Vine Resources Inc. or its subsidiaries to which such holder may be subject. Vine Resources Inc. may impose additional restrictions on any exchange that it determines to be necessary or advisable so that we are not treated as a “publicly traded partnership” for U.S. federal income tax purposes. As a holder exchanges Vine Units for shares of Class A common stock, the number of Vine Units held by Vine Resources Inc. is correspondingly increased as it acquires the exchanged Vine Units. In accordance with the exchange agreement, any holder who surrenders all of its Vine Units for exchange must concurrently surrender all shares of Class B common stock held by it (including fractions thereof) to Vine Resources Inc.

Tax Receivable Agreement

As described in “—VRH LLC Agreement” above, the Vine Unit Holders (and their permitted transferees) may exchange their Vine Units (together with a corresponding number of shares of Class B common stock) for shares of Class A common stock (on a one-for-one basis, subject to conversion rate adjustments for stock splits, stock dividends and reclassification and other similar transactions or, at our election, for cash). Vine Resources Holdings LLC intends to make an election under Section 754 of the Code that will be effective for the taxable year that includes this offering and each taxable year in which an exchange of Vine Units for shares of Class A common stock pursuant to the Exchange Right (or resulting from an exchange of Vine Units for cash pursuant to the Cash Option) occurs. Pursuant to the Section 754 election, each future exchange of Vine Units for Class A common stock (as well as any exchange of Vine Units for cash) is expected to result in an adjustment to the tax basis of the tangible and intangible assets of Vine Resources Holdings LLC, and these adjustments will be allocated to us. Adjustments to the tax basis of the tangible and intangible assets of Vine Resources Holdings LLC described above would not have been available absent these exchanges of Vine Units. The anticipated basis adjustments are expected to increase (for tax purposes) our depreciation and depletion deductions and may also decrease our gains (or increase our losses) on future dispositions of certain capital assets to the extent tax basis is allocated to those capital assets. Such increased deductions and losses and reduced gains may reduce the amount of tax that we would otherwise be required to pay in the future.

We will enter into a Tax Receivable Agreement with Vine Investment. This agreement generally will provide for the payment by us to Vine Investment of 85% of the net cash savings, if any, in U.S. federal, state and local income tax or franchise tax that we actually realize (or are deemed to realize in certain circumstances) in periods after this offering as a result of (i) the tax basis increases resulting from the exchange of Vine Units by such Vine Investment for shares of Class A common stock pursuant to the Exchange Right (or resulting from an exchange of Vine Units for cash pursuant to the Cash Option) and (ii) imputed interest deemed to be paid by us as a result of, and additional tax basis arising from, any payments we make under the Tax Receivable Agreement.

The payment obligations under the Tax Receivable Agreement are our obligations and not obligations of Vine Resources Holdings LLC, and we expect that the payments we will make under the Tax Receivable Agreement will be substantial. For purposes of the Tax Receivable Agreement, cash savings in tax generally will be calculated by comparing our actual tax liability to the amount we would have been required to pay had we not been able to utilize any of the tax benefits subject to the Tax Receivable Agreement. The amounts payable, as well as the timing of any payments, under the Tax Receivable Agreement are dependent upon significant future events and assumptions, including the timing of the exchanges of Vine Units, the price of our Class A common

 

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stock at the time of each exchange, the extent to which such exchanges are taxable transactions, the amount of the exchanging unit holder’s tax basis in its Vine Units at the time of the relevant exchange, the depreciation periods that apply to the increase in tax basis, the amount and timing of taxable income we generate in the future, the U.S. federal income tax rate then applicable, and the portion of Vine Resources Inc.’s payments under the Tax Receivable Agreement that constitute imputed interest or give rise to depreciable or amortizable tax basis. The term of the Tax Receivable Agreement will commence upon the completion of this offering and will continue until all such tax benefits have been utilized or have expired, unless we exercises our right to terminate the Tax Receivable Agreement. In the event that the Tax Receivable Agreement is not terminated, the payments under the Tax Receivable Agreement are anticipated to commence in 2029 (with respect to the tax year 2028) and to continue for approximately 14 years.

Estimating the amount of payments that may be made under the Tax Receivable Agreement is by its nature imprecise, insofar as the calculation of amounts payable depends on a variety of factors. The actual increase in tax basis, as well as the amount and timing of any payments under the Tax Receivable Agreement, will vary depending upon a number of factors, including the timing of the exchanges, the price of Class A common stock at the time of each exchange, the extent to which such exchanges are taxable, the amount and timing of the taxable income we generate in the future and the tax rate then applicable, and the portion of our payments under the Tax Receivable Agreement constituting imputed interest or depreciable or amortizable basis. We expect that the payments that we will be required to make under the Tax Receivable Agreement could be substantial. Assuming no material changes in the relevant tax law, we expect that if we experienced a change of control or the Tax Receivable Agreement were terminated immediately after this offering, the estimated lump-sum payment would be approximately $350 million (calculated using a discount rate equal to one-year LIBOR plus 100 basis points, applied against an undiscounted liability of approximately $450 million). The foregoing amounts are merely estimates and the actual payments could differ materially. It is possible that future transactions or events could increase or decrease the actual tax benefits realized and the corresponding Tax Receivable Agreement payments as compared to these estimates. Moreover, there may be a negative impact on our liquidity if, as a result of timing discrepancies or otherwise, (i) the payments under the Tax Receivable Agreement exceed the actual benefits we realize in respect of the tax attributes subject to the Tax Receivable Agreement and/or (ii) distributions to us by Vine Resources Holding LLC are not sufficient to permit us to make payments under the Tax Receivable Agreement after we have paid our taxes and other obligations. The payments under the Tax Receivable Agreement will not be conditioned upon a holder of rights under the Tax Receivable Agreement having a continued ownership interest in either Vine Resources Holding LLC or us.

In addition, although we are not aware of any issue that would cause the Internal Revenue Service (“IRS”), to challenge potential tax basis increases or other tax benefits covered under the Tax Receivable Agreement, the holders of rights under the Tax Receivable Agreement will not reimburse us for any payments previously made under the Tax Receivable Agreement if such basis increases or other benefits are subsequently disallowed, except that excess payments made to any such holder will be netted against payments otherwise to be made, if any, to such holder after our determination of such excess. As a result, in such circumstances, we could make payments that are greater than our actual cash tax savings, if any, and may not be able to recoup those payments, which could adversely affect our liquidity.

The Tax Receivable Agreement will provide that in the event that we breach any of our material obligations under it, whether as a result of our failure to make any payment when due (including in cases where we elect to terminate the Tax Receivable Agreement early, the Tax Receivable Agreement is terminated early due to certain mergers or other changes of control or we have available cash but fail to make payments when due under circumstances where we do not have the right to elect to defer the payment, as described below), failure to honor any other material obligation under it or by operation of law as a result of the rejection of the Tax Receivable Agreement in a case commenced under the United States Bankruptcy Code or otherwise, then all our payment and other obligations under the Tax Receivable Agreement will be accelerated and will become due and payable applying the same assumptions described above. Such payments could be substantial and could exceed our actual cash tax savings under the Tax Receivable Agreement.

 

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Additionally, if we experience a change of control (as defined under the Tax Receivable Agreement, which includes certain mergers, asset sales and other forms of business combinations) or the Tax Receivable Agreement terminates early (at our election or as a result of our breach), we could be required to make a substantial, immediate lump-sum payment. This payment would equal the present value of hypothetical future payments that could be required to be paid under the Tax Receivable Agreement (calculated using a discount rate equal to one-year LIBOR plus 100 basis points). The calculation of the hypothetical future payments will be based upon certain assumptions and deemed events set forth in the Tax Receivable Agreement, including (i) the sufficiency of taxable income to fully utilize the tax benefits, (ii) any Vine Units (other than those held by us) outstanding on the termination date are exchanged on the termination date and (iii) certain loss carryovers will be utilized on a pro rata basis from the date of the termination date through the scheduled expiration date under applicable tax law of such loss carryovers.

Any payment upon a change of control or early termination may be made significantly in advance of the actual realization of the future tax benefits to which the payment obligation relates. Because of the deductions and other tax incentives available to us with respect to our industry, we do not expect to have taxable income in 2017, and our ability to generate taxable income in the future is subject to substantial uncertainty. Accordingly, our ability to use the tax benefits covered by the Tax Receivable Agreement may be significantly delayed, and such tax benefits may expire before we are able to utilize them. Except in the event of a change of control transaction or an early termination, we will not be obligated to make a payment under the Tax Receivable Agreement with respect to any tax benefits that we are unable to utilize. However, if we experience a change of control or the Tax Receivable Agreement is terminated early, the assumptions required to be made under the Tax Receivable Agreement in calculating our obligation include the sufficiency of taxable income to fully utilize the tax benefits covered by the Tax Receivable Agreement. As a result, in these circumstances, we could be required to make an immediate lump-sum payment under the Tax Receivable Agreement even though our ability to recognize any related realized cash tax savings is uncertain. Accordingly, the immediate lump-sum payment could significantly exceed our actual cash tax savings to which such payment relates. Vine Investment will not reimburse us for any portion of such payment if we are unable to utilize any of the tax benefits that give rise to such payment.

In these situations, our obligations under the Tax Receivable Agreement could have a substantial negative impact on our liquidity and could have the effect of delaying, deferring or preventing certain mergers, asset sales, or other forms of business combinations or changes of control. For example, if we experienced a cha