S-1/A 1 d151897ds1a.htm S-1/A S-1/A
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As filed with the Securities and Exchange Commission on March 9, 2021.

Registration No. 333-253366

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

Amendment No. 3

to

Form S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

 

 

VINE ENERGY 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

Michael W. Rigdon

Kirkland & Ellis LLP

609 Main Street, Suite 4700

Houston, Texas 77002

(713) 836-3600

  

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, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer      Accelerated filer  
Non-accelerated filer      Smaller reporting company  
     Emerging growth company  

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 7(a)(2)(B) of the Securities Act.  ☐

 

 

CALCULATION OF REGISTRATION FEE

 

 

Title of Each Class of
Securities to be Registered
  Amount to be
Registered(1)
  Proposed Maximum
Offering Price Per
Share(2)
  Proposed Maximum
Aggregate Offering
Price(1) (2)
  Amount of
Registration Fee(3)

Class A Common Stock, par value $0.01 per share

  21,562,500   $19.00   409,687,500   $44,696.91

 

 

 

(1)

Estimated pursuant to Rule 457(a) under the Securities Act of 1933, as amended. Includes 2,812,500 additional shares of Class A common stock that the underwriters have the option to purchase.

(2)

Estimated solely for the purpose of calculating the registration fee.

(3)

The Registrant previously paid $10,910.00 of the total registration fee in connection with the previously filing of this 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. The prospectus is not an offer to sell these securities nor a solicitation of an offer to buy these securities in any jurisdiction where the offer and sale is not permitted.

 

Subject to Completion, dated March 9, 2021

PROSPECTUS

18,750,000 Shares

 

LOGO

Vine Energy Inc.

Class A Common Stock

 

 

This is the initial public offering of the common stock of Vine Energy Inc., a Delaware corporation. We are offering 18,750,000 shares of our Class A common stock. No public market currently exists for our Class A common stock.

We intend to list our Class A common stock on the New York Stock Exchange under the symbol “VEI.”

We anticipate that the initial public offering price will be between $16.00 and $19.00 per share.

Holders of shares of our Class A common stock and Class B common stock are entitled to one vote for each share of Class A common stock and Class B common stock, respectively, held of record on all matters on which stockholders are entitled to vote generally. See “Description of Capital Stock.”

After the completion of this offering, affiliates of The Blackstone Group L.P. will beneficially own approximately 73.0% of the combined voting power of our Class A and Class B common stock. As a result, we will be a “controlled company” within the meaning of the New York Stock Exchange rules. See “Management—Status as a Controlled Company.”

 

 

Investing in our Class A common stock involves risks, including those described under “Risk Factors” beginning on page 30 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 (Conflicts of Interest)” 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 2,812,500 additional shares of Class A common stock on the same terms and conditions set forth above if the underwriters sell more than 18,750,000 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                 , 2021.

 

 

 

Citigroup    Credit Suisse    Morgan Stanley

 

 

 

BofA Securities    Barclays    RBC Capital Markets

 

 

 

   Blackstone   
Capital One Securities    KeyBanc Capital Markets    MUFG
CastleOak Securities, L.P.   Drexel Hamilton        Ramirez & Co., Inc.    Stern

Prospectus dated                 , 2021


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LOGO

Cutaway view showing co-development of the Haynesville and overlying Mid-Bossier. Multiple wells are drilled from each surface location to increase drilling efficiency and the laterals are spaced to optimize recovery.


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TABLE OF CONTENTS

 

     Page  

PROSPECTUS SUMMARY

     1  

RISK FACTORS

     30  

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

     55  

USE OF PROCEEDS

     57  

DIVIDEND POLICY

     58  

CAPITALIZATION

     59  

DILUTION

     60  

SUMMARY HISTORICAL AND UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL INFORMATION

     61  

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

     63  

BUSINESS

     86  

MANAGEMENT

     122  

EXECUTIVE COMPENSATION

     127  

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

     135  

CORPORATE REORGANIZATION

     139  

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

     144  

DESCRIPTION OF CAPITAL STOCK

     151  

SHARES ELIGIBLE FOR FUTURE SALE

     159  

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

     161  

UNDERWRITING (CONFLICTS OF INTEREST)

     165  

LEGAL MATTERS

     172  

EXPERTS

     172  

WHERE YOU CAN FIND MORE INFORMATION

     172  

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                 , 2021 (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:

 

   

“8.75% Notes” means the 8.75% Senior Notes due 2023 issued by Vine Oil & Gas LP and Vine Oil & Gas Finance Corp. pursuant to that certain indenture dated as of October 18, 2017, by and among Vine Oil & Gas LP, Vine Oil & Gas Finance Corp., the subsidiary guarantors named therein and Wilmington Trust, National Association, as trustee;

 

   

“9.75% Notes” means the 9.75% Senior Notes due 2023 issued by Vine Oil & Gas LP and Vine Oil & Gas Finance Corp. pursuant to that certain indenture dated as of October 3, 2018, by and among Vine Oil & Gas LP, Vine Oil & Gas Finance Corp., the subsidiary guarantors named therein and Wilmington Trust, National Association, as trustee;

 

   

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

 

   

“Blocker Entities” refers to the entities that are taxable as corporations for U.S. federal income tax purposes through which certain of the Existing Owners indirectly hold LLC Interests;

 

   

“Brix” refers to Brix Oil & Gas Holdings LP and its consolidated subsidiaries;

 

   

“Brix Companies” refers to Brix and Harvest on a combined basis as acquired by Vine Oil & Gas prior to the IPO;

 

   

“Brix Credit Facility” refers to that certain Senior Secured Credit Agreement dated as of March 20, 2018 by and among Brix Operating LLC, the lenders from time to time party thereto, and Macquarie Investments US Inc., as administrative agent, as amended from time to time;

 

   

“Brix GP” refers to Brix Oil & Gas Holdings GP LLC;

 

   

“Brix Investment” refers to Brix Investment LLC, a Delaware limited liability company formed by certain Existing Owners of Brix to hold equity interests in us following the corporate reorganization;

 

   

“Brix Investment II” refers to Brix Investment II LLC, a Delaware limited liability company formed by certain Existing Owners of Brix to hold equity interests in us following the corporate reorganization;

 

   

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

 

   

“GAAP” means generally accepted accounting principles in the United States;

 

   

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

 

   

“Harvest” means Harvest Royalties Holdings LP and its consolidated subsidiaries;

 

   

“Harvest GP” means Harvest Royalties Holdings GP LLC;

 

   

“Harvest Investment” refers to Harvest Investment LLC, a Delaware limited liability company formed by certain Existing Owners of Harvest to hold equity interests in us following the corporate reorganization;

 

   

“Harvest Investment II” refers to Harvest Investment II LLC, a Delaware limited liability company formed by certain Existing Owners of Harvest to hold equity interests in us following the corporate reorganization;

 

   

“IPO” means the initial public offering of the common stock of Vine Energy Inc.;

 

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

 

   

“Levered free cash flow” means a non-GAAP financial measure, defined as the amount of money the company has remaining after paying its financial obligations related to investing activities prior to considering any funds received from or paid for financing activities and calculated as net cash provided by operating activities less net cash used in investing activities;

 

   

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

 

   

“RBL” means Vine Oil & Gas LP’s revolving credit facility, dated as of November 25, 2014, by and among Vine Oil & Gas LP, 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;

 

   

“Second Lien Credit Agreement” means that certain credit agreement entered into in December 2020 with Morgan Stanley Senior Funding, Inc. as administrative agent and collateral agent, and certain other banks, financial institutions and other lending institutions from time to time party thereto, pursuant to which we were provided with the Second Lien Term Loan;

 

   

“Second Lien Term Loan” means Vine Oil & Gas LP’s $150 million second lien term loan facility, dated as of December 30, 2020, by and among Vine Oil & Gas LP, Morgan Stanley Senior Funding, Inc., as administrative agent and collateral agent, and the several lenders party thereto, issued at 97.25% of face value on December 30, 2020;

 

   

“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 Shell;

 

   

“Superpriority Facility” means Vine Oil & Gas LP’s superpriority facility, dated as of February 7, 2017, by and among Vine Oil & Gas LP, 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;

 

   

“Tax Receivable Agreement” means that tax receivable agreement to be entered into in connection with the closing of this offering, by and among Vine Investment, Brix Investment, Harvest Investment, Vine Investment II, Brix Investment II, Harvest Investment II, Vine Holdings, Vine Energy and certain others from time to time a party thereto;

 

   

“Third Lien Credit Agreement” means that certain credit agreement entered into in December 2019 with Blackstone Holdings Finance Co LLC, as administrative agent and collateral agent and certain other banks, financial institutions and other lending institutions from time to time party thereto;

 

   

“VEH LLC Agreement” means the amended and restated limited liability company agreement of Vine Holdings;

 

   

“Vine,” “we,” “us,” “our” or the “company” or other like terms, prior to the corporate reorganization described in this prospectus (unless otherwise disclosed), refer collectively to Vine Oil & Gas, Brix and Harvest on a combined basis and together with their consolidated subsidiaries, and following the corporate reorganization described in this prospectus, to Vine Energy;

 

   

“Vine Energy” refers to Vine Energy Inc. and its consolidated subsidiaries (including, for the avoidance of doubt, the Blocker Entities following the corporate reorganization), unless otherwise required by context;

 

   

“Vine Energy Investment Vehicles” refers to Vine Investment, Brix Investment and Harvest Investment, collectively;

 

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“Vine Energy Investment II Vehicles” refers to Vine Investment II, Brix Investment II and Harvest Investment II, collectively;

 

   

“Vine Holdings” refers to Vine Energy Holdings LLC;

 

   

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

 

   

“Vine Oil & Gas” refers to Vine Oil & Gas Parent LP and its consolidated subsidiaries;

 

   

“Vine Oil & Gas GP” refers to Vine Oil & Gas Parent GP LLC;

 

   

“Vine Unit Holder” means a holder of Vine Units (other than Vine Energy) and a corresponding number of shares of Class B common stock;

 

   

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

 

   

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

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;

 

   

“Basin” refers to a geographic area containing specific geologic intervals;

 

   

“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 Fahrenheit;

 

   

“CapEx” means capital expenditures;

 

   

“Completion” means all the post-drilling and post-casing processes to allow the well to flow hydrocarbons;

 

   

“D&C” 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;

 

   

“Drilling” means any activity related to drilling pad make-ready costs, rig mobilization and creating a wellbore in order to facilitate the ultimate production of hydrocarbons;

 

   

“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;

 

   

“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;

 

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“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;

 

   

“Horizontal drilling” means a drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled horizontally within a specified interval;

 

   

“IDC” means intangible drilling cost;

 

   

“Drilling locations” means total gross locations that may be able to be drilled on our existing acreage. A portion of our drilling locations constitute estimated locations based on our acreage and spacing assumptions, as described in “Business—Our Operations—Reserve Data—Drilling Locations”;

 

   

“Invested capital” means the CapEx required to drill, complete and equip with facilities a single well;

 

   

“LNG” means liquified natural gas;

 

   

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

 

   

“MMBtu” means one million Btu;

 

   

“MMBtud” means one MMBtu per day;

 

   

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

 

   

“MMcfd” means one MMcf per day;

 

   

“MT” means one metric ton;

 

   

“NGL” means natural gas liquids;

 

   

“Net acres” means the percentage of total acres an owner owns or has leased 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;

 

   

“Possible reserves” means those additional reserves which analysis of geoscience and engineering data suggest are less likely to be recoverable than probable reserves. The total quantities ultimately recovered from the project have a low probability to exceed the sum of proved plus probable plus possible reserves (“3P”), which is equivalent to the high estimate scenario. In this context, when probabilistic methods are used, there should be at least a 10% probability that the actual quantities recovered will equal or exceed the 3P estimate;

 

   

“Probable reserves” means those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than proved reserves but more certain to be recovered than possible reserves. It is equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated proved plus probable reserves (“2P”). In this context, when probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the 2P estimate;

 

   

“Productive well” means a well that is capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses;

 

   

“Proved developed reserves” means reserves that can be expected to be recovered through existing wells with existing equipment and operating methods, according to the SEC or Society of Petroleum Engineers definitions of proved reserves;

 

   

“Proved reserves” means the reserves 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 undrilled well locations on existing acreage or from existing wells where a relatively major expenditure is required for recompletion within the five year development window, according to the SEC or Society of Petroleum Engineers definition of PUD;

 

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“Recompletion” means the process of re-entering an existing wellbore and mechanically re- invigorating the wellbore to establish or increase existing production and reserves;

 

   

“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 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;

 

   

“Tcf” means one trillion cubic feet;

 

   

“TWh” means terawatt hours;

 

   

“Undeveloped acreage” means acreage under lease on which wells have not been drilled or completed such that there is not production of commercial quantities of hydrocarbons;

 

   

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

 

   

“Weighted average rate of return” means the weighted average single well internal rate of returns on D&C capital realized at a noted price for our remaining core inventory. The single well return calculation is based on our reserve type curves and internal cost estimates and is weighed based on the remaining footage associated with our core drilling locations for each category of lateral lengths;

 

   

“Wellbore” or “well” means a drilled hole that is equipped for natural gas production; 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.

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 accounting predecessor, Vine Oil & Gas. The pro forma financial information presented in this prospectus treats the combination of Vine Oil & Gas, Brix and Harvest in connection with our corporate reorganization as an acquisition in a business combination of Brix and Harvest by Vine Oil & Gas. Please see “Corporate Reorganization” and “Unaudited Pro Forma Condensed Combined Financial Statements” included elsewhere in this prospectus.

In addition, unless otherwise indicated, the reserve and operational data presented in this prospectus is that of Vine Oil & Gas, Brix and Harvest on a combined basis as of the dates and for the periods presented.

 

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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. These sources include an article entitled Study Forecasts Gradual Haynesville Production Recovery Before Final Decline, dated December 2015, by The Oil & Gas Journal, reports entitled Haynesville Inventory, dated April 2020, and Enverus Gas Plays and Market Outlook, dated October 2020, by Enverus, reports entitled World Energy Outlook 2020, dated October 2020, and Global EV Outlook 2020, dated June 2020, by IEA (as defined below), reports entitled Annual Energy Outlook 2020, dated January 2020, and U.S. Energy-Related Carbon Dioxide Emissions, 2019, dated September 2019, by EIA (as defined below), presentations entitled North America Gas Market Outlook, dated July 2020 and North America Energy Markets, dated November 2020, by Wood Mackenzie, and Rig Count by Baker Hughes, dated November 2020. 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 $17.50 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 was prepared by our independent reserve engineer as of December 31, 2020 based on the SEC’s reserve pricing rule and NYMEX forward strip pricing, as more fully described in “ —Reserve and Operating Data,” and is presented as of the dates and for the periods indicated. 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 an energy 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.

Natural gas demand has significantly grown as a percentage of North America’s energy mix over the last ten years, having increased 38% from 86 Bcfd to 119 Bcfd and growing from 27% to 37% of the energy mix due to ample domestic supply, reliability of supply, significant supporting in-place infrastructure, low carbon intensity and low prices. In particular, demand for exported LNG has contributed to approximately 21% of that increase, with continued growth in LNG exports anticipated according to Wood Mackenzie. We believe natural gas will continue to be instrumental as a low carbon intensity source for meeting growing energy demand.

We believe the Haynesville will be particularly critical to meeting future natural gas demand. 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, according to The Oil & Gas Journal. The Haynesville is among the oldest and most delineated shale plays in North America and its well economics have continued to improve in recent years as a result of advances in enhanced drilling and completion techniques, combined with predictable production profiles and well cost reductions. These advances have driven both higher and more capital efficient reserve recoveries on a per lateral foot basis, primarily as a consequence of optimized fracture stage lengths and increased proppant and water loading.

The Mid-Bossier shale overlays the Haynesville shale and demonstrates similar characteristics and well results. Additionally, the Haynesville and Mid-Bossier shales possess 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. These plays are at 10,500 to 13,500 ft in depth with formation temperatures ranging from 300 to 375° F, resulting in near pipeline quality natural gas requiring little additional processing, which contributes to relatively low operating costs. Lastly, due to significant historical development activity in the Haynesville beginning in 2008, which resulted in approximately 5,700 wells drilled through December 31, 2020, production and decline rates are predictable, and low-cost and sufficient midstream infrastructure is already in place. We therefore believe the Haynesville is one of the lowest-cost, lowest-risk natural gas plays in North America. As a consequence of these factors, as well as our proximity to Henry Hub and other premium Gulf Coast markets, LNG export facilities and other end-users, the play



 

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benefits from low breakeven costs, higher cash margins and higher pricing netbacks relative to other North American natural gas plays, such as those in Appalachia and the Rockies.

In contrast to the Haynesville, other sources of natural gas supply, including associated gas from oil-prone drilling and natural gas from the Appalachian region, are facing headwinds in the form of reduced activity and infrastructure constraints. Associated natural gas from oil-prone drilling was the largest contributor to natural gas supply growth from 2011 to 2019. However, due to the significant oil price shock brought on by the COVID-19 pandemic, the number of rigs drilling for oil in North America fell 59% in 2020, which is expected to result in a significant decline in future natural gas supply. While the Marcellus and Utica shales in the northeast United States currently account for approximately 30% of North American natural gas supply, there is limited pipeline capacity available to transport natural gas out of the area. Additionally, the demanding regulatory environment in the Northeast has limited new gas pipeline infrastructure. As such, we believe the Haynesville will be further relied upon to meet natural gas demand growth driven by increasing electricity demand associated with the global economic recovery, coupled with the continued increase in global LNG cargoes.

We first entered the Haynesville in 2014 following the Shell Acquisition and have actively acquired additional proximate acreage. We have approximately 125,000 net surface acres centered in what we believe to be the core of the Haynesville. Over 90% of our acreage is held-by-production and we operate over 90% of our future drilling locations with an average working interest of 83%. Approximately 84% of our acreage is prospective for dual-zone development, providing us with approximately 900 drilling locations among Vine, Brix and Harvest. Utilizing an average of 4 gross rigs, which we believe is sufficient to maintain production, we have approximately 25 years of development opportunities. We are not subject to any material minimum volume commitments in our gathering agreements, and have no firm transportation commitments, which provides us with the flexibility to match an optimal development pace to the prevailing natural gas price and hedging environment at any given time. This, coupled with the extensive midstream infrastructure and low basis differentials in the Haynesville, contributes to lower break-even costs. Research from Enverus projects that the average Haynesville Basin core well generates a 31% rate of return using a NYMEX gas price of $2.75 per MMBtu, which Enverus ranks as the highest among notable shale plays in North America. Moreover, based on the location of our acreage, which is in some of the most prospective parts of the Haynesville, we believe our weighted average rate of return based on internal cost assumptions for our remaining core drilling locations is 85% at a NYMEX gas price of $2.75 per MMBtu. As of December 31, 2020, we had approximately 370 net producing wells. Our assets are located almost entirely in Red River, DeSoto and Sabine parishes of Northwest Louisiana, which, according to Enverus, have consistently demonstrated higher EURs relative to drilling and completion costs than the Haynesville in Texas and other parishes in Louisiana.

The following table provides a summary of our inventory of drilling locations as of December 31, 2020, including average lateral length and drilling location data in each play.

Drilling Locations (1) (2)

 

     Short
Lateral
     Long
Lateral
        
Length    <5,300 ft      >5,300 ft      Total  

Haynesville

     226        147        373  

Mid-Bossier

     212        293        505  
  

 

 

    

 

 

    

 

 

 

Total Core

     438        440        878  
  

 

 

    

 

 

    

 

 

 

Total Non-Core

     44        10        54  
  

 

 

    

 

 

    

 

 

 

Total Drilling Locations

     482        450        932  
  

 

 

    

 

 

    

 

 

 


 

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(1)

“Business—Our Operations—Reserve Data and Presentation—Drilling Locations” contains a description of our methodology used to determine gross drilling locations. We exclude drilling locations where our working interest is less than 20%.

(2)

932 gross drilling locations reflecting an average working interest of approximately 83% or 776 net drilling locations.

We describe the progression of our well completions as Vintages with our most recent wells described as Vintage 5. The characteristics of our Vintage 5 wells include 100-mesh sand completions, decreased cluster spacing, optimized proppant and water loading and refined stage lengths. We intend to continue employing longer laterals to develop certain areas within our asset base in order to increase capital efficiency. The shift to a higher concentration of longer laterals is a strategy we believe reflects our recent success in drilling long laterals of up to 10,000 ft. We expect this will increase our capital efficiency by allowing us to develop the gas in place using fewer wellbores and lower development costs, resulting in lower breakeven prices and higher returns.

Substantially all of our leasehold acreage is not subject to expiry because we have at least one developed well in each section, which, through continuous production of gas, maintains the leasehold position in that section and provides us with flexibility to conduct our remaining development. Our acreage has been delineated by over 700 gross horizontal wells drilled across our position in Sabine, Red River and DeSoto parishes, providing us with confidence that our inventory of drilling locations is low-risk and repeatable and that we can continue to generate consistent economic returns; of these 700 wells, over 280 wells have been brought online under our ownership or participation since our development program began in 2015, providing us with a significant amount of well performance data and associated learnings. In addition to the 700 wells drilled on our acreage, approximately 1,000 wells have been drilled by other operators within one mile of our position, further enhancing the delineation and confidence in our acreage. The company also holds license to almost 400 square miles of 3D and 50 miles of 2D seismic data. We are the leader of Mid-Bossier development, accounting for 36% of all Mid-Bossier wells brought online from 2017 to 2020, which is more than any other single operator.

All of the company’s acreage is underlaid by Northwest Louisiana’s extensive legacy midstream infrastructure, which includes access to sufficient gathering capacity to accommodate our future growth, including our primary third-party gatherer’s approximately 500 miles of pipeline and related treating plants. Their system is currently operating at an approximate 90% utilization rate and has multiple offload points where we can transfer volumes to other area gatherers at equivalent rates. This significant pre-existing area midstream infrastructure provides access to other area gatherers, and we utilize their capacity on both a firm and interruptible basis and expect to continue to do so in the future. We sell our gas at the tailgates of the treating plants attached to our gatherers’ systems and, as a result, incur and hold no direct firm-transportation cost or commitments. Furthermore, approximately 1.0 Bcfd of additional transportation capacity came online in mid-2020 through the DTE Energy (LEAP) project and another approximately 1.0 Bcfd is expected by mid-year 2021 with the Enterprise Product Partners (Acadian) project. Our proximity and sales to Henry Hub and other premium Gulf Coast markets, LNG export facilities and other end-users results in our netbacks reflecting low transportation costs, which is a significant competitive advantage compared to other North American dry gas plays such as those in Appalachia and the Rockies. As a result of these takeaway and sales dynamics, our basis differentials have remained tightly banded since our inception, ranging from $0.01 to $0.26 per MMBtu; over this same period, basis differentials in Appalachia and the Rockies have ranged from $0.27 to $1.54 and $0.12 to $0.96 per MMBtu, respectively. Further, in 2020, Vine Oil & Gas sold approximately 62% of its total gas production through firm sales contracts, with approximately 37% of total production being sold at specified differentials from Henry Hub, providing additional support to our realized pricing. We believe these attractive relative realizations and our long-term access to growing demand (e.g. LNG, chemical, refinery) on the Gulf Coast support our development plan and ability to generate levered free cash flow in various commodity price environments.



 

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A transition to cleaner sources of energy is underway across the globe as demand for renewables and natural gas is projected to increase at a more rapid pace than demand for higher emission energy sources like coal and oil. According to the International Energy Agency (“IEA”) global natural gas demand is projected to grow 15% between 2019 and 2030, resulting in an increase of approximately 17 Tcf of demand. Much of this growth, approximately 8 Tcf, is in the industrial sector, with growth in power generation, buildings, transportation and other sectors comprising the balance. Additionally, global natural gas consumed for energy and feedstock uses in industry is expected to grow 25% between 2019 and 2030, while coal and oil are projected to decline.

With respect to domestic electricity generation, the U.S. Energy Information Agency (“EIA”) projects that between 2019 and 2050, electricity generation will increase approximately 30% from 4,127 billion kilowatt hours to 5,414 billion kilowatt hours. In 2019, natural gas represented 37% of this fuel mix while renewables represented 19% with the balance comprised of coal at 24% and nuclear at 19%. By 2050, the EIA predicts that natural gas will remain a relatively constant 36% of this growing market, while renewables will increase to 38% and coal and nuclear will decrease to 13% and 12%, respectively. Renewables like wind and solar, which are intermittent by nature, require non-intermittent back up capacity such as natural gas, to provide a consistent level of electricity generation. More globally, the International Energy Agency (“IEA”) predicts that global demand from electric vehicles will increase from 69 TWh in 2019 to 551 TWh by 2030, representing a compound annual growth rate (“CAGR”) of 21%. We believe that increasing demand for electricity from lower emissions sources, like renewables and natural gas, demonstrate how natural gas will play a critical role in this transition to a cleaner energy future.

North America has become increasingly dependent on natural gas for its energy consumption needs, and the EIA credits the increasing use of natural gas in domestic power generation as the leading factor in the 15% decrease in domestic energy related CO2 emissions from 2007 to 2019. Additionally, domestic LNG exports, which began in 2016, have increased to current levels of approximately 10 Bcfd. We believe the export of LNG to global markets will allow economies in Asia, Europe and Latin America to be less dependent on higher emission fuels as has been the case in North America.

Due to the composition of our production stream, which is essentially all dry gas (i.e. methane), we do not produce any associated oil or natural gas liquids. We also produce small amounts of water, CO2 and other byproducts. Since our production is not burdened with having to separate, store or transport oil or natural gas liquids, we do not have any direct emissions related to these processes. Moreover, by utilizing industry leading technology, we seek to measure and reduce our emissions and consider doing so a core competency of our business. We measure the quantity of greenhouse gas emissions in metric tons of CO2 equivalent, or “CO2e,” and the intensity of our emissions in CO2e per Bcf of production. We also measure methane emissions as a percentage of production or methane intensity. We have adopted operational practices specifically designed to reduce our emission footprint, including installation of intermittant and no-bleed control valves, utilization of bi-fuel drilling and completion equipment, proactive Leak Detection and Repair (“LDAR”) wellsite surveys to reduce fugitive emissions, and the onsite generation of solar power to operate certain equipment. While from 2017 to 2020 our annual production increased 153.5% from 128.8 Bcf to 326.5 Bcf, our CO2e emissions rate decreased by 35% from 686 mT CO2e/Bcf to 444 mT CO2e/Bcf and our methane intensity decreased by 77% from 0.061% to 0.014% of production, below BP by comparison, an industry leader at 0.14% of production across its more diverse asset base. Given the low emissions nature of our natural gas production and the additional active mitigation measures we implement, we believe we have one of the lowest emission levels per Bcf of annual production of any domestic onshore oil and gas company.

Our management team has extensive experience in the Haynesville and Mid-Bossier 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 North America. Many members of our management team have extensive experience working in the Haynesville since its inception as a commercial play and have directly contributed to its



 

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technical advancement. Since the Shell Acquisition, our management team has been at the forefront of developing the technology to enhance well EUR and economics for both Haynesville and Mid-Bossier wells, including;

 

   

increasing lateral length;

 

   

optimizing fracture stage lengths;

 

   

optimizing the amount and intensity of proppant and fluid pumped per foot of lateral;

 

   

reducing cluster spacing;

 

   

managing production rates to preserve downhole pressure;

 

   

adjusting well spacing and development patterns; and

 

   

improving wellbore landing accuracy.

Successful implementation of these measures has resulted in superior well performance relative to that of other major operators in the basin as seen in the charts below.

 

LOGO

 

Note:

Vine and third-party data sourced from Enverus. Includes horizontal wells targeting the Haynesville and Mid-Bossier with initial production between 2017 to 2020, normalized to a 7,500’ lateral.

 

(1)

Haynesville peers include Aethon Energy Management LLC, BPX Energy Inc., Castleton Commodities International LLC, Chesapeake Energy Corporation, EnSight IV Energy Partners, LLC, Exco Resources, Inc., Exxon Mobil Corporation, GeoSouthern Haynesville, Goodrich Petroleum Corporation, Indigo Natural Resources, LLC, Rockcliff Energy LLC, Sabine Oil & Gas Corporation.

(2)

Mid-Bossier peers include Aethon Energy Management LLC, BPX Energy Inc., Comstock Resources Inc., Exxon Mobil Corporation, GeoSouthern Haynesville, and Indigo Natural Resources, LLC.

To maximize gas recovery from our wells, we manage the downhole pressure drop after initial flowback which results in a flat early-time production profile. The flat production profile is 5 to 18 months for both our Haynesville and Mid-Bossier wells. After the flat production period, our wells enter an exponential decline period followed by a hyperbolic decline and a final exponential terminal decline.

We believe that the gas price necessary to yield a 10% rate of return on invested capital (“Breakeven PV-10”) to be $1.91 per MMBtu NYMEX on average for our remaining core drilling locations. Additionally, and based on internal estimates, we believe the gas price necessary to yield a Breakeven PV-10 for our remaining Haynesville and Mid-Bossier drilling locations to be $1.90 and $1.93 per MMBtu, respectively. These results demonstrate basin leading breakevens based on estimates from Enverus, which indicate Haynesville and Mid-



 

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Bossier breakevens for our peers range from $2.05 to $2.54 and $1.93 to $2.74 per MMBtu, respectively. Furthermore, our wells generally achieve payout of our drilling and completion costs within 12 to 16 months, which allows for efficient recycling of cash flow and provides significant excess cash flow beyond payout and, what we believe to be, industry leading returns on investment.

History of the Haynesville and Our Acreage

The Haynesville shale and the overlying Mid-Bossier shale were deposited in a Jurassic basin that covers more than 9,000 square miles and includes eight parishes in North Louisiana and eight counties in East Texas, collectively called the Haynesville. 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 acreage position, the Haynesville ranges from 11,500 ft 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 ft 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 1900s, the prospectivity of the Haynesville was not widely recognized until 2005. During this time, Encana and other operators acquired significant acreage in North Louisiana 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. During this time, certain members of our management team were part of, and integral to, the Encana team. We purchased Shell’s interest in this acreage during 2014 and GEP purchased the Encana portion during 2015.

In 2010, at the height of its activity, over 200 rigs were active in the Haynesville as producers drilled wells to preserve leasehold positions, creating significant oilfield services and midstream infrastructure that remains today to accommodate the current development activity and contribute to the low basis differentials in the basin. Furthermore, the basin is well positioned to capitalize on LNG demand, growing population centers in the southern United States, expanding petrochemical capacity in the Gulf Coast region, and the retirement of selected coal-fired electricity plants.

Since peak activity in 2010, our industry has made significant advances in drilling and completion technology and techniques, including long lateral development, geo-steering techniques and changes in completion intensity and design. These trends have resulted in increased EURs per lateral foot, a trend which continues with our most recent well design. We believe our EURs per lateral foot and the resulting Breakeven PV-10 levels compare favorably with the most prolific basins in North America. At the same time, our average drilling and completion times and well costs have decreased, which have yielded enhanced economics for development of our reserves.

In January 2011, Louisiana began allowing cross-unit horizontal drilling. Prior to this rule change, lateral lengths could not exceed 5,000 feet in length. With this change in regulation, operators can now develop wells that cross section lines and more efficiently develop the acreage using long laterals. We believe our large and relatively contiguous position combined with a streamlined regulatory approval process provides us with an opportunity to capitalize on a development plan that features multi-section lateral lengths.

We believe that we have been instrumental in the revitalization of the Haynesville since entering the basin in 2014 through the purchase of Shell’s interest. Since we began our drilling program in 2015, we have participated in over 280 wells, and been at the forefront of advancements in drilling and completion optimization techniques such as increasing lateral lengths, proppant concentration, water intensity, cluster spacing and reservoir pressure drawn-down management. Enverus projects that the current number of rigs running in the Haynesville will increase from the current figure of approximately 43 rigs up to 50 rigs over the next 12 to 18 months, which compares to 2020 average rigs of 37.



 

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Business Strategy

Our strategy is to draw upon our management team’s experience in developing natural gas resources to generate levered free cash flow while achieving modest growth in our production and reserves and thus enhance our value. Our strategy has the following principal elements:

 

   

Optimize Return-On-Capital Through Focus on Profitably Increasing Well Recoveries While Minimizing Costs. Since 2017, we have drilled, on average, longer-lateral wells and further optimized our completion design, resulting in increased EURs compared to our prior drilling programs. From our initial Vintage 1 wells drilled in 2015 to our Vintage 5 wells in 2019 and 2020, EURs have increased from 1.4 Bcf per 1,000 lateral feet to 2.1 Bcf per 1,000 lateral feet. Simultaneous with recovery improvements, D&C costs per lateral foot have declined while lateral lengths have increased, indicating both capital efficiency gains and improvements in per Mcf economics. Our capital program in 2018 was concentrated on the evaluation of well density and key elements of our completion design, and, based on successful tests, our 2019 and 2020 capital program focused on longer lateral development, completion optimization and cycle time improvements. We focus on developing the maximum recovery of gas and economic value for every section we operate by adjusting the number of wells per section as market conditions change. We look for opportunities to reduce capital costs based on market conditions and we are focused on locking in reduced costs as a result of recent industry-wide decreases in demand for oilfield services. Additionally, we continue to rely on strategic alliances with third parties to reduce lease operating expenses for items such as chemicals and self-source higher cost services like water disposal to lower our overall operating costs.

 

   

Generate Levered Free Cash Flow While Delivering Modest Production Growth. We maintain a disciplined, cash flow-focused approach to capital allocation. Based on our year-end 2020 reserves, we had a drilling inventory of approximately 900 drilling locations among Vine, Brix and Harvest, or approximately 25 years of development opportunities utilizing an average of 4 gross rigs, which we believe would be sufficient to maintain production. Our remaining drilling inventory has an average payback period of approximately 14 and 24 months at an assumed NYMEX gas price of $2.75 and $2.25 per MMBtu, respectively. The concentration, delineation and scale of our core leasehold positions, coupled with our technical understanding of the reservoirs, allows us to efficiently develop our acreage to generate levered free cash flow, increase sectional recoveries over time and 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 levered free cash flow while modestly growing production and reserves.

 

   

Leverage our Deep Experience in the Haynesville to Develop Industry-Leading Business Practices and Technology. Eric D. Marsh, our President and Chief Executive Officer, and other key members of our management participated in the early development of the Haynesville. Through their experience, they developed expertise that allows for continued advancement of industry-leading well completion techniques and drilling and development efficiencies. We continue to develop and apply industry-leading practices to manage D&C costs and maximize the recovery factor of gas in place. We have also realized significant improvements in our development efficiency over time, including a reduction in drilling and completion days, which contribute to lower well costs. We employ enhanced completion techniques through increased fracture stages, optimized proppant loading and pumping intensity and reduced cluster spacing and drilling-related efficiencies through multi-well pads and longer laterals. These measures have allowed us to lower D&C costs per lateral foot while yielding increased EURs, thereby improving our capital efficiency and returns, while also reducing the number of short laterals and associated surface equipment required to develop our resource.

 

   

Maintain a Disciplined Financial Strategy. We intend to fund our operations predominantly with internally generated cash flows while maintaining ample liquidity to weather commodity cycles. We target spending approximately 65% to 75% of our operating cash flow on CapEx to maintain or modestly increase production, with the remaining amount being available, initially, for debt repayment. We seek to protect



 

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future cash flows and liquidity levels through a multi-year commodity hedge program and through physical firm sales agreements with multiple credit-worthy counterparties. We expect that our new credit agreement that we will enter into contemporaneously with the closing of this offering will give us significant flexibility to hedge a large percentage of our total expected production. To further reduce volatility in our cash flows and returns, we will also seek to enter into contracts for oilfield services that are no longer than the periods covered by our commodity hedges. In addition, pro forma for this offering, we anticipate that our total net debt to Adjusted EBITDAX ratio for the year-ended December 31, 2020 will be approximately 2.0x, which is among the lowest for publicly traded gas-focused upstream companies. We intend to target modest financial leverage of total net debt to Adjusted EBITDAX of 1.0x to 1.5x and use levered free cash flow to further reduce outstanding debt. While we will prioritize debt paydown as the primary use of levered free cash flow until our targeted leverage ratios are met, we may evaluate potential acquisition opportunities that are highly strategic to us, but we will pursue them only to the extent they are accretive and meet our financial strategy and operational objectives. Adjusted EBITDAX is not a financial measure calculated in accordance with GAAP. We believe that Adjusted EBITDAX provides important information regarding our operating results. “—Non-GAAP Financial Measures” contains a description of this measure and a reconciliation to the most directly comparable GAAP measure.

 

   

Steward the Health and Safety of our Employees, our Community and the Environment. Since peaking in 2007 at 6,003 MMmt, the EIA reports that total domestic energy sector related CO2 emissions have declined by 14.5% (873 MMmt) by 2019 and they cite the increasing use of natural gas in power generation as a key driver of this trend. While we believe the lower carbon intensity of using natural gas as opposed to coal in electric power generation in and of itself contributes meaningfully to lower CO2 emissions, we further believe that the benefits of natural gas are enhanced by reducing production related CO2, methane and other emissions. To that end, minimizing production related emissions is a core competency of our business and we continually seek to identify, accurately measure and reduce emission related to our business. From 2017 to 2020, our CO2e per Bcf of production declined 35% from 686 mT CO2e/Bcf to 444 mT CO2e/Bcf while our methane intensity decreased 77% from 0.061% to 0.014% of production, below BP by comparison, an industry leader at 0.14% of production across its more diverse asset base. In addition, we emphasize rigorous health and safety protocols in all aspects of our business and have demonstrated strong safety performance. Our total recordable incident frequency rate averaged 0.31 from 2017 through 2020 and 0.09 for 2020, both of which are well below the American Exploration and Production Council 2019 average of 0.47 and the U.S. Bureau of Labor Statistics E&P Support Activities Benchmark of 0.60.

Business Strengths

We have a number of strengths that we believe will help us successfully execute our business strategy and generate levered free cash flow, including:

 

   

We Believe we are Among the Most Economic Natural Gas Producers in North America. We own leases across an extensive, largely contiguous and fully delineated acreage position spanning approximately 125,000 net surface acres and approximately 230,000 net effective acres centered in what we believe to be the core of the Haynesville and Mid-Bossier. Our highly concentrated acreage position promotes more efficient development through the drilling of longer laterals, the ability to utilize multi-zone bi-directional well pads and limited need for additional gathering expansion. Longer laterals are significantly more capital efficient with a 10,000 ft lateral having up to four times the PV-10 at a $2.75 NYMEX price per MMBtu, but less than two times the cost, when compared to our standard lateral. Research from Enverus projects that the average Haynesville Basin core well generates a 31% rate of return using a NYMEX gas price of $2.75 per MMBtu, which Enverus ranks as the highest among notable shale plays in North America. Moreover, based on the location of our acreage, which is in some of the most prospective parts of the Haynesville, we believe our weighted average rate of return based on internal cost assumptions for our remaining core drilling locations is 85% at a NYMEX gas price of $2.75 per MMBtu. Additionally, given the high initial



 

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productivity of our wells, we typically recover approximately 45% of a well’s EUR in the first 12 months of production. As of December 31, 2020, our drilling inventory consisted of approximately 900 drilling locations among Vine, Brix and Harvest in both the Haynesville and Mid-Bossier, which included approximately 450 drilling locations where we intend to utilize laterals 5,300 ft or greater. Utilizing an average of 4 gross rigs among Vine, Brix and Harvest, which we believe is sufficient to maintain production, we believe we have approximately 25 years of development opportunities. Our average production for the quarter ended December 31, 2020 was 944 MMcfd. We consider our drilling inventory to be low risk because it is located in areas where we (and other producers) have extensive drilling and production experience with production results exhibiting higher repeatability versus other natural gas plays. There have been over 700 gross horizontal wells drilled across our position, of which we participated in over 280 since 2015, providing us substantial well performance data. In addition to the over 700 wells drilled on our acreage, more than 1,000 wells have been drilled within one mile of our position, further supporting our economic expectations.

 

   

High-Margin, Low Operating Cost Structure that Generates Significant Levered Free Cash Flow. Our free cash flow is primarily attributable to our industry-leading operating margins and low operating costs. For the year-ended December 31, 2020 and pro forma for the reorganization transactions, we achieved a 72.2% operating margin, which we calculate by dividing our Adjusted EBITDAX by our revenues, which are inclusive of natural gas sales and realized gains and losses on commodity derivatives. In the year-ended December 31, 2020 and pro forma for the reorganization transactions, our lease operating expense of $0.20 per Mcf and our general and administrative expense of $0.05 per Mcf were among the lowest in our peer group. We have implemented several initiatives to enhance and manage our production in the region and reduce operating costs. In early 2015, we established a technologically advanced 24-hour automated command center from which we can remotely control most field-wide production operations from a single location, allowing us to remotely bring wells online and manage existing production. This level of automation reduces manpower needs and allows operators to focus on production efficiency, by, among other things, efficiently deploying labor through a centralized operating center. Moreover, we have significantly reduced our operating cost per unit by vertically integrating through the drilling and operation of our own produced water disposal wells. 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 gas treating solutions and improved maintenance programs. In drilling locations where our working interest exceeds 20%, we hold an approximate 83% working interest and operate over 90% of such wells. We believe this gives us a high degree of control over our development program, allowing us to be responsive to changes in the commodity price environment. Levered free cash flow is not a financial measure calculated in accordance with GAAP, but we believe it provides an important perspective regarding our operating cash flow. “–Non-GAAP Financial Measures” below contains a description of levered free cash flow and a reconciliation to net cash provided by operating activities.

 

   

Close Proximity to Premium Markets and Ample Available Midstream Infrastructure. Our acreage position is in close proximity to premium markets and LNG facilities along the Gulf Coast, which results in lower and less volatile basis differentials and higher netbacks compared to other plays, including gas plays such as the Marcellus, Utica and those in the Rockies. As a result of these attractive takeaway and sales dynamics, our basis differentials have remained tightly banded since our inception, ranging from $0.01 to $0.26 per MMBtu; over this same period, basis differentials in Appalachia and the Rockies have ranged from $0.27 to $1.54 and $0.12 to $0.96 per MMBtu, respectively. We believe this allows producers in our basin to benefit from better unit economics. Low-cost legacy gathering infrastructure is in place across our acreage to support our development program. Our gathering cost for the year-ended December 31, 2020 was $0.31 per Mcfe, which compares favorably to $1.20 per Mcfe reported by publicly traded Appalachian-focused natural gas producers for the comparable period. Further, we are not party to any transportation contracts or similar commitments and our small amount of minimum volume commitments in our gathering contracts are well covered by current production volumes. Because we only produce dry gas, we have



 

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minimal cost to treat our gas to meet pipeline specifications, which may give us an economic advantage over wet gas plays during periods of low pricing for NGLs, as is currently taking place. Additionally, we do not have any of the emissions related to wet gas separation, storage or transportation.

 

   

Well Capitalized Balance Sheet that Provides Flexibility to Execute our Business Plan. Pro forma for this offering, we anticipate total net debt to Adjusted EBITDAX for the year-ended December 31, 2020 of approximately 2.0x, which would be among the lowest for publicly traded gas-focused upstream companies. Contemporaneously with the closing of this offering, we expect to enter into a new reserve-based lending facility led by Citibank. This facility is expected to have a total facility size of $750 million, a borrowing base of $350 million and available capacity of $316 million (after giving effect to $25 million of letters of credit to be issued at closing) based on projected as adjusted borrowings of approximately $9 million pro forma for this offering, resulting in projected liquidity of approximately $350 million as of December 31, 2020. Finally, we maintain an active hedge program and as of December 31, 2020 have hedged an average of 819 Bbtud, 492 Bbtud and 186 Bbtud for 2021, 2022 and 2023, respectively, at weighted average swap prices of $2.56 per MMBtu, $2.55 per MMBtu and $2.49 per MMBtu, respectively. Moreover, our Second Lien Term Loan requires us to have 70% of our total expected production hedged 24 months forward. We believe our balance sheet and hedge program provide ample liquidity in the event of an adverse commodity price environment to enable us to continue to generate levered free cash flow.

 

   

High Caliber and Experienced Management and Technical Team. Our senior management team has substantial experience in the Haynesville, as well as other premier North American resource plays, and has collectively operated large development programs that helped commercialize the Haynesville, attained 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 experience. We believe our team’s expertise will continue to drive drilling, completion and operational improvements that result in improved recoveries and capital efficiency. Furthermore, our management team’s operational and financial discipline, as well as its extensive experience in leadership roles at public companies, gives us confidence in our ability to successfully manage a public company platform.

 

   

Leader in Environmental, Governance and Societal Responsibilities of the Natural Gas Production Sector. According to the EIA, since it began tracking CO2 emissions in 1990, the increased market share of natural gas in electrical power generation has been a leading driver in reducing energy sector CO2 emissions. Not only do we produce the fuel that is the cornerstone of this accomplishment, we invest significantly in the human capital, equipment and technology that allows us to produce natural gas safely, efficiently and with minimal related emissions. While emissions reductions is a focus for all of our employees, we have 5 employees specifically dedicated to environmental, health and safety matters, including emissions reductions. For example, our sustainability efforts include 100% green completions, 100% non-potable water usage, and 100% solar-generated wellsite electricity. Additionally, we have peer leading CO2 emissions at 2.6 mT per MBOE per well and methane intensity of only 0.014% of gas produced. Additionally, we and our employees make commitments of financial resources and time to assist underserved members in the communities where we operate and our employees live. Moreover, we value diversity in our work force, including our executive leadership team, which is relatively evenly split 60% / 40% between men and women.

Recent Developments

The outbreak of COVID-19 has significantly decreased the demand for hydrocarbons, particularly oil. As a result of the COVID-19 pandemic or other adverse public health developments, including voluntary and mandatory quarantines, travel restrictions, and other restrictions, our operations, and those of our subcontractors and customers, have experienced, and are anticipated to continue to experience, delays or disruptions and temporary suspensions of operations.



 

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Reduction in oil and gas activity as a result of the COVID-19 pandemic has resulted in a decrease of associated gas production as fewer oil wells are drilled in the Permian Basin and other liquids-weighted basins, which has led to a contraction in domestic gas supply. Lower levels of supply have pushed current and forecasted gas prices higher, which has had a positive impact on our results of operations and cash flows. We expect that the reduction in drilling activity and rig counts may contribute to a shortage in the supply of natural gas in the future, which could result in higher gas prices. As a result, although gas prices were on average lower in 2020 than 2019, gas prices trended higher after the effects of the COVID-19 pandemic began to take hold and slow oil production towards the middle of 2020. As the factors described above reduced the supply of oil and gas, gas prices increased towards the end of 2020 as compared to the prices in the months prior to and during the beginning of the COVID-19 pandemic. For reference, the Henry Hub spot price for natural gas averaged $2.22 per MMBtu from August 2019 to March 2020, $1.72 per MMBtu from April 2020 to June 2020, $2.32 per MMBtu for the remaining six months of 2020 exiting the year at $2.90 per MMBtu in December 2020 and $2.69 per MMBtu from January 2021 to March 2021. However, because of our obligation to hedge 70% of our production for the next 24 months, we will be limited in the benefit we would otherwise realize from any such price increases. To the extent, however, that natural gas prices decrease, these lower 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 fund planned CapEx. Alternatively, natural gas prices may increase, which while increasing revenue and cash flows, would result in significant losses being incurred on our derivatives.

We are taking precautions as an organization to protect our employees and community during this time. Vine has undertaken a number of proactive measures to reduce the spread of the virus and maintain the safety and health of its workforce, including, among other things, implementing comprehensive screening at operational bases throughout the organization.

Concurrently, deterioration of production agreements between key global oil producers has led to an increase in supply. In addition to the effects of the COVID-19 pandemic, the confluence of these factors has caused significant volatility in oil and gas prices. In response, many producers in North America have significantly reduced drilling activity. The land rig count in North America fell from 771 in mid-March of 2020 to 244 in mid-August of 2020 and has recovered slightly to 373 by January of 2021.

The reduction in activity has resulted in a decrease of associated gas production as fewer oil wells are drilled in the Permian Basin and other liquids-weighted basins, which has led to a contraction in domestic gas supply. Lower levels of supply have pushed current and forecasted gas prices higher. We expect that the reduction in drilling activity and rig counts may contribute to a shortage in the supply of natural gas in the future, which could result in higher gas prices.

The significant reduction in drilling and completion activity has also reduced demand for oilfield services and providers of these services have reduced their pricing as a result. Coupled with the improvement in drilling and completion cycle times achieved by our operational staff of approximately 14-19% in 2020, we have seen our well costs fall approximately 20% from an average of $1,521 per lateral foot in the first half of 2019 to $1,241 per lateral foot for the second half of 2020, as illustrated in the table below. We expect, given the trajectory of demand reduction for oilfield services, along with our continued realization of operational efficiencies, that D&C costs will continue to decrease. In addition, we have undertaken several initiatives to



 

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optimize our operating cost structure in order to be well positioned to operate through periods of market and commodity price volatility. These actions include entering into term contracts with key vendors at attractive rates and continued operational efficiencies.

 

LOGO

Recent Debt Transactions

On December 30, 2020, we entered into the Second Lien Term Loan and used the proceeds, along with cash on hand, to repay the aggregate principal amount of loans outstanding under the Superpriority Facility in connection with the entry into the amendment to and extension of the RBL. The Second Lien Term Loan has a total facility size of $150 million and was fully drawn at closing.

The maturity of the RBL was extended to January 15, 2023 and availability under the facility was reduced from $350 million to $300 million and will reduce further on a quarterly basis to $100 million at December 31, 2022. Other than these quarterly reductions in availability, there are no borrowing base redeterminations. The pricing grid was increased by 1.00% to LIBOR + 2.50% to 3.50% based on utilization. We intend to use the net proceeds from this offering and borrowings under the New RBL to repay in full and terminate each of the RBL and the Brix Credit Facility.

The Second Lien Term Loan bears interest at a rate equal to LIBOR, with a floor of 0.75%, plus 8.75% per annum, payable monthly, and matures on the earlier to occur of (a) December 30, 2025 and (b) 90 days prior to the maturity of the 9.75% Notes or 8.75% Notes, to the extent specified amounts of such indebtedness remain outstanding. The Second Lien Term Loan is redeemable beginning June 30, 2022 at 102% of par value, stepping down to 101% of par value on June 30, 2023 and at par value on June 30, 2024 and thereafter.

The Second Lien Term Loan is secured on a junior lien basis by all of our assets and stock and the subsidiaries that secure the RBL.

The Second Lien Term Loan provides for a quarterly Consolidated Total Net Leverage Ratio financial maintenance covenant of 4.00x, stepping down to 3.50x with the quarter ended June 30, 2021 and thereafter, similar to the RBL. The Second Lien Term Loan also contains customary incurrence-based covenants for issuances of this type, including restrictions on the incurrence of liens, indebtedness, asset dispositions, fundamental changes, transactions with affiliates, restricted payments and other customary covenants, along with the requirement to maintain liquidity of no less than $40 million, tested quarterly.

In December 2019, we entered into the Third Lien Credit Agreement with Blackstone Holdings Finance Co LLC, as administrative agent and collateral agent and certain other banks, financial institutions and other lending institutions from time to time party thereto. At that time, the Third Lien Credit Agreement was secured on a second lien basis, but was subordinated to a third lien in December 2020 in connection with the entry into the Second Lien Credit Agreement. The Third Lien Credit Agreement provides for a revolving credit facility in an amount up to $330 million, and bears interest at a rate of LIBOR plus 9.75% per annum. In addition, a commitment fee of 0.424% per annum is charged on the unutilized balance of the committed borrowing base and is included in interest expense. The Third Lien Credit Agreement matures on March 15, 2023. We expect to terminate our Third Lien Credit Facility in connection with this offering.



 

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New RBL

Contemporaneously with the closing of this offering, we expect to enter into a new reserve-based lending facility (the “New RBL”) led by Citibank. This facility is expected to have a total facility size of $750 million, a borrowing base of $350 million and available capacity of $316 million (after giving effect to $25 million of letters of credit to be issued at closing) based on projected as adjusted borrowings of approximately $9 million pro forma for this offering, resulting in projected liquidity of approximately $350 million as of December 31, 2020. The New RBL will contain various conditions precedent, including the requirement to terminate the Third Lien Credit Agreement.

The New RBL will bear interest at a rate equal to LIBOR plus an additional margin, based on the percentage of the revolving commitment being utilized, ranging from 3.00% to 4.00%, with a LIBOR ‘floor’ of 0.50%. The New RBL matures on the earlier to occur of (a) 45 months after the closing of this offering, (b) 91 days prior to the maturity of the Second Lien Term Loan, to the extent any of such indebtedness remains outstanding, and (c) 91 days prior to the maturity of the 9.75% Notes or 8.75% Notes, to the extent specified amounts of such indebtedness remain outstanding. There will also be a commitment fee of 0.50% on the undrawn borrowing base amounts. The New RBL will be secured on a senior basis by substantially all of our assets and stock and guaranteed by the subsidiaries that secure and guarantee the Second Lien Term Loan.

The New RBL will provide for a quarterly Consolidated Total Net Leverage Ratio financial maintenance covenant of 3.25x beginning with the quarter ended June 30, 2021, a quarterly Current Ratio maintenance covenant of 1.00x beginning with the quarter ended June 30, 2021 and a $100 million weekly minimum liquidity covenant that is applicable starting 180 days prior to the maturity of the indebtedness under the Second Lien Term Loan, the 9.75% Notes or the 8.75% Notes, to the extent any of such indebtedness is outstanding. The New RBL will also contain customary incurrence-based covenants for facilities of this type, including restrictions on the incurrence of liens, indebtedness, asset dispositions, fundamental changes, transactions with affiliates, restricted payments and other customary covenants.

The credit agreement governing the New RBL will also contain customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control.

2021 CapEx and Financing Activities

We expect our 2021 capital program to be approximately $340 to $350 million of which $310 to $320 million is allocated for D&C operations. The remaining $30 million of our capital program is designated for non-D&C items. We plan to fund our 2021 CapEx through cash flow from operations, proceeds from this offering and borrowings under our New RBL. Further, we intend to monitor conditions in the debt capital markets and may determine to issue long-term debt securities, including potentially in the near term, to fund a portion of our 2021 CapEx or refinance a portion of our existing indebtedness. We cannot predict with certainty the timing, amount and terms of any future issuances of any such debt securities.

Corporate Reorganization

Vine Energy is a Delaware corporation that was formed for the purpose of making this offering. Following this offering and the transactions related thereto, Vine Energy will be a holding company whose sole material asset will consist of membership interests in Vine Holdings. Vine Holdings will own all of the outstanding limited partnership interests in each of Vine Oil & Gas, Brix and Harvest, the operating subsidiaries through which we operate our assets, and all of the outstanding equity in each of Vine Oil & Gas GP, Brix GP and Harvest GP, the general partners of Vine Oil & Gas, Brix and Harvest, respectively. After the consummation of the transactions contemplated by this prospectus, Vine Energy will be the managing member of Vine Holdings



 

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and will control and be responsible for all operational, management and administrative decisions relating to Vine Holdings’ business and will consolidate the financial results of Vine Holdings and its subsidiaries.

In connection with this offering, (a) the Existing Owners who directly hold equity interests in Vine Oil & Gas, Vine Oil & Gas GP, Brix, Brix GP, Harvest and Harvest GP will contribute all of such equity interests to Vine Holdings in exchange for newly issued equity in Vine Holdings (the “LLC Interests”), (b) certain of the Existing Owners will contribute a portion of their LLC Interests directly or indirectly, by contribution of Blocker Entities holding LLC Interests, to Vine Energy in exchange for newly issued Class A common stock and will contribute such Class A common stock received to Vine Investment II, Brix Investment II, Harvest Investment II, Vine Investment, Brix Investment or Harvest Investment, as applicable, (c) certain of the Existing Owners will exchange the remaining portion of their LLC Interests for newly issued Vine Units and subscribe for newly issued Class B common stock of Vine Energy with no economic rights or value and will contribute such Vine Units and Class B common stock to Vine Investment, Brix Investment and Harvest Investment, as applicable, and (d) Vine Energy will contribute the net proceeds of this offering to Vine Holdings in exchange for newly issued Vine Units and a managing member interest in Vine Holdings. After giving effect to these transactions and the offering contemplated by this prospectus, (i) Vine Energy will own an approximate 50.5% interest in Vine Holdings (or 52.4% if the underwriters’ option to purchase additional shares is exercised in full), (ii) Vine Investment will own an approximate 25.2% interest in Vine Holdings and 0.1% interest in Vine Energy (or 24.2% and 0.1% if the underwriters’ option to purchase additional shares is exercised in full), (iii) Brix Investment will own an approximate 24.0% interest in Vine Holdings and 0.1% interest in Vine Energy (or 23.1% and 0.1% if the underwriters’ option to purchase additional shares is exercised in full), (iv) Harvest Investment will own an approximate 0.3% interest in Vine Holdings and less than 0.1% interest in Vine Energy (or 0.3% and less than 0.1% if the underwriters’ option to purchase additional shares is exercised in full), (v) Vine Investment II will own an approximate 13.7% interest in Vine Energy (or 13.1% if the underwriters’ option to purchase additional shares is exercised in full), (vi) Brix Investment II will own an approximate 9.4% interest in Vine Energy (or 9.1% if the underwriters’ option to purchase additional shares is exercised in full), and (vii) Harvest Investment II will own an approximate 0.2% interest in Vine Energy (or 0.2% 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. 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, Brix Investment, Harvest Investment, Vine Investment II, Brix Investment II and Harvest Investment II. This agreement generally provides for the payment by Vine Energy to Vine Investment, Brix Investment, Harvest Investment, Vine Investment II, Brix Investment II and Harvest Investment II, respectively, of 85% of the net cash savings, if any, in U.S. federal, state and local income tax that Vine Energy (a) actually realizes with respect to taxable periods ending after December 31, 2025 or (b) is deemed to realize in the event of a change of control (as defined under the Tax Receivable Agreement, which includes certain mergers, asset sales and other forms of business combinations and certain changes to the composition of the Vine Energy board) or the Tax Receivable Agreement terminates early (at our election or as a result of our breach) with respect to any taxable periods ending on or after such change of control or early termination event, in each case, as a result of (i) the tax basis increases resulting from the exchange of Vine Units and the corresponding surrender of an equivalent number of shares of Class B common stock by Vine Investment, Brix Investment and Harvest Investment, respectively, for a number of shares of Class A common stock on a one-for-one basis or, at our option, the receipt of an equivalent amount of cash pursuant to the exchange agreement, (ii) certain existing net operating loss carryforwards, disallowed interest expense carryforwards under Section 163(j) of the Code, and tax credit carryforwards attributable to the Blocker Entities previously owned by certain of the Existing Owners, and (iii) imputed interest deemed to be paid by us as a result



 

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of, and additional tax basis arising from, any payments we make under the Tax Receivable Agreement. Vine Energy will retain the benefit of the remaining 15% of these cash savings, if any. If we experience a change of control or the Tax Receivable Agreement terminates early, we could be required to make a substantial, immediate lump-sum payment. 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 $211 million (calculated using a discount rate equal to a per annum rate of LIBOR plus 100 basis points, applied against an undiscounted liability of approximately $244 million). “Certain Relationships and Related Party Transactions—Tax Receivable Agreement” contains more information.

The following diagrams indicate our simplified 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

 

(1)

Blackstone owns 99.3% of Vine Oil & Gas GP, 97.0% of Brix GP and 94.2% of Harvest GP. Blackstone holds its ownership in Vine Oil & Gas through funds separate from the funds in which it holds its ownership in Brix and Harvest, which are not consolidated by a common parent. Therefore, Vine Oil & Gas is not considered under common control with Brix GP and Harvest GP for financial reporting purposes.

(2)

Certain Management Members own 0.7% of Vine Oil & Gas GP, 3.0% of Brix GP and 5.8% of Harvest GP.



 

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Simplified Ownership Structure After Giving Effect to this Offering

 

 

LOGO

 

(1)

Includes Vine Investment, Brix Investment and Harvest Investment.

(2)

Includes Vine Investment II, Brix Investment II and Harvest Investment II.

(3)

Vine Holdings owns 100% of Brix GP, Harvest GP and Vine Oil & Gas GP. Brix GP is the general partner of Brix, Harvest GP is the general partner of Harvest and Vine Oil & Gas GP is the general partner of Vine Oil & Gas.

Our Principal Stockholders

Following the completion of this offering and our corporate reorganization, Blackstone and Management Members will in the aggregate own 0.3% of our Class A common stock and 100% of our Class B common stock through the Vine Energy Investment Vehicles, representing approximately 49.7% of the voting power of Vine Energy (47.7% if the underwriters’ option to purchase additional shares is exercised in full), and 46.1% of our Class A common stock through the Vine Energy Investment II Vehicles, representing 23.3% of the voting power



 

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of Vine Energy (22.4% if the underwriters’ option to purchase additional shares is exercised in full). The Vine Energy Investment Vehicles and the Vine Energy Investment II Vehicles are controlled by Blackstone, our private equity sponsor.

Blackstone is one of the world’s leading investment firms. Blackstone seeks to create positive economic impact and long-term value for its investors, the companies it invests in, and the communities in which it works. Blackstone does this by using extraordinary people and flexible capital to help companies solve problems.

Blackstone’s asset management businesses, with $619 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 Energy Partners is Blackstone’s energy-focused private equity business, with a successful record built on our industry expertise and partnerships with exceptional management teams. Blackstone private equity has invested more than $18 billion of equity globally across a broad range of sectors within the energy industry.

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 do not 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 $1.07 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. We have elected to take advantage of this extended transition period, which means that the financial statements included in this prospectus, as well as any financial statements that we file or furnish in the future, will not be subject to all new or revised accounting standards generally applicable to public companies for the transition period for so long as we remain an emerging growth company.



 

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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.vineog.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

18,750,000 shares (or 21,562,500 shares, if the underwriters exercise in full their option to purchase additional shares).

 

Class A common stock to be outstanding after the offering

34,995,149 shares (or 37,807,649 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 2,812,500 additional shares of our Class A common stock.

 

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

34,289,108 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 surrendered.

 

Use of proceeds

We expect to receive approximately $303.3 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 $349.5 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 $17.6 million.

 

  We intend to use the net proceeds from this offering and borrowings under our New RBL to repay in full and terminate each of the RBL and the Brix Credit Facility. “Use of Proceeds” contains additional information regarding our intended use of proceeds from this offering.
 

 

Conflicts of Interest

Each of Credit Suisse Securities (USA) LLC and Morgan Stanley & Co. LLC is a lender under the RBL and, as such, is expected to receive in excess of 5% of the offering proceeds. Furthermore, affiliates of Blackstone Securities Partners L.P. will own in excess of 10% of our issued and outstanding Class A common stock. Because each of Credit Suisse Securities (USA) LLC, Morgan Stanley & Co. LLC and Blackstone Securities Partners L.P. is an underwriter in this offering, it is deemed to have a “conflict of interest” under Rule 5121 (“Rule 5121”) of the Financial Industry Regulatory Authority, Inc. (“FINRA”). Accordingly, this offering is being made in compliance with the requirements of Rule 5121. Due to certain of these conflicts of interest, Rule 5121 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. Citigroup Global Markets Inc. has agreed to act as a qualified independent underwriter for this offering. Citigroup Global Markets Inc. will not receive any



 

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additional fees for serving as a qualified independent underwriter in connection with this offering. We have agreed to indemnify Citigroup Global Markets Inc. against liabilities incurred in connection with acting as a qualified independent underwriter, including liabilities under the Securities Act.

 

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

50.5% 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

49.5% 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

The Vine Energy Investment Vehicles, which 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. After giving effect to the shares issued pursuant to this offering, Vine Energy Investment II Vehicles, which will be owned by the Existing Owners, will hold 46.1% (or 42.7% if the underwriters’ option is exercised in full) 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 currently do not pay a cash dividend to holders of our Class A common stock and certain of our debt agreements place certain restrictions on our ability to pay cash dividends on our Class A common stock. “Dividend Policy” includes additional information. However to the extent our free cash flow generation results in a decrease in our overall leverage in the future, we may revisit our dividend policy and declare cash dividends on our Class A common stock.

 

Listing and trading symbol

We intend to list our Class A common stock on the New York Stock Exchange (the “NYSE”) under the symbol “VEI.”

 

Exchange rights of Vine Unit Holders

In connection with the completion of this offering, we will enter into an exchange agreement with the entities that comprise the Vine Energy Investment Vehicles and Vine Holdings so that the Vine Energy Investment Vehicles may (subject to the terms of the exchange agreement) exchange their Vine Units, along with surrendering a corresponding number of shares of our Class B common stock, for shares of Class A common stock of Vine Energy on a one-for-one basis, subject to customary conversion rate adjustments for stock splits, stock dividends and reclassifications, or,



 

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at our option, an equivalent amount of cash (the “Exchange Right”). “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 Holdings. The anticipated basis adjustments are expected to increase (for tax purposes) our depreciation, depletion and amortization 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. In addition, we have acquired certain tax attributes attributable to the Blocker Entities previously owned by certain of the Existing Owners. Such increased deductions and losses and reduced gains, as well as such tax attributes, 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, Brix Investment, Harvest Investment, Vine Investment II, Brix Investment II and Harvest Investment II. This agreement generally provides for the payment by Vine Energy to Vine Investment, Brix Investment, Harvest Investment, Vine Investment II, Brix Investment II and Harvest Investment II, respectively, of 85% of the net cash savings, if any, in U.S. federal, state and local income tax that Vine Energy (a) actually realizes with respect to taxable periods ending after December 31, 2025 or (b) is deemed to realize in the event of a change of control (as defined under the Tax Receivable Agreement, which includes certain mergers, asset sales and other forms of business combinations and certain changes to the composition of the Vine Energy board) or the Tax Receivable Agreement terminates early (at our election or as a result of our breach) with respect to any taxable periods ending on or after such change of control or early termination event, in each case, as a result of (i) the tax basis increases resulting from the exchange of Vine Units and the corresponding surrender of an equivalent number of shares of Class B common stock by Vine Investment, Brix Investment and Harvest Investment, respectively, for a number of shares of Class A common stock on a one-for-one basis or, at our option, the receipt of an equivalent amount of cash pursuant to the exchange agreement, (ii) certain existing net operating loss carryforwards, disallowed interest expense carryforwards under Section 163(j) of the Code, and tax credit carryforwards attributable to the Blocker Entities previously owned by certain of the Existing Owners, and (iii) 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 Energy will retain the benefit of the remaining 15% of these cash savings, if any. If we experience a change of control or the Tax Receivable Agreement terminates early, 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 information above excludes 5,462,740 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.

Summary of Risk Factors

An investment in our securities involves a high degree of risk. The occurrence of one or more of the events or circumstances described in the section titled “Risk Factors,” alone or in combination with other events or circumstances, may materially adversely affect our business, financial condition and operating results. In that event, the trading price of our securities could decline, and you could lose all or part of your investment. Such risks include, but are not limited to:

 

   

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.

 

   

Past performance by our management team or their respective affiliates may not be indicative of future performance of an investment in us.

 

   

The widespread outbreak of an illness, pandemic or any other public health crisis may have material adverse effects on our business, financial position, results of operations and/or cash flows.

 

   

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

 

   

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

 

   

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

 

   

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

 

   

Our 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 drilling locations.

 

   

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

 

   

Federal and state legislative and regulatory initiatives regarding hydraulic fracturing and related activities, 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.

 

   

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.

 

   

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 hedging activities could result in financial losses or reduce our income.

 

   

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

 

   

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.



 

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If Vine Holdings were to become a publicly traded partnership taxable as a corporation for U.S. federal income tax purposes, we and Vine Holdings 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.

 

   

In certain circumstances, Vine Holdings will be required to make tax distributions to us and the Vine Unit Holders, and the tax distributions that Vine Holdings will be required to make may be substantial.

 

   

The Vine Energy Investment Vehicles and the Vine Energy Investment II Vehicles will collectively hold a substantial majority of our common stock.

 

   

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.



 

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Summary Historical and Unaudited Pro Forma Condensed Combined Financial Information

The following table shows summary historical financial information of our accounting predecessor, Vine Oil & Gas, and summary unaudited pro forma condensed combined financial information for the periods and as of the dates indicated.

The summary historical financial information as of and for the years ended December 31, 2020 and 2019 was derived from the audited historical financial statements of our predecessor, Vine Oil & Gas, included elsewhere in this prospectus.

The summary unaudited pro forma condensed combined statements of operations data for the year ended December 31, 2020 been prepared to give pro forma effect to (i) the reorganization transactions described under “Corporate Reorganization,” including the business combination of Brix and Harvest with Vine Oil & Gas, and (ii) this offering and the application of the net proceeds from this offering, as if the reorganization and offering transactions had been completed on January 1, 2020. The summary unaudited pro forma condensed combined balance sheet as of December 31, 2020 has been prepared to give pro forma effect to these transactions as if they had been completed on December 31, 2020. This information is subject to and gives effect to the assumptions and adjustments described in the notes accompanying the unaudited pro forma condensed combined financial statements included elsewhere in this prospectus. The summary unaudited pro forma condensed combined 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 and this offering been consummated on the dates indicated, and do not purport to be indicative of our 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,” “Corporate Reorganization,” “Unaudited Pro Forma Condensed Combined Financial Statements,” and the historical financial statements included elsewhere in this prospectus contain additional information to be read in conjunction with the following information.

 

    Vine Oil & Gas     Vine Pro Forma  
    As of and for the
Year Ended
December 31,
    As of and for the
Year Ended
December 31, 2020
 
    2020     2019  
    (in thousands, except share and per share
data)
 

Statements of Operations Information:

     

Revenue:

     

Natural gas sales

  $ 418,877     $ 445,589     $ 571,144  

Realized gain on commodity derivatives

    123,875       39,679       161,918  

Unrealized gain (loss) on commodity derivatives

    (164,077     101,239       (204,552
 

 

 

   

 

 

   

 

 

 

Total revenue

    378,675       586,507       528,510  

Operating Expenses:

     

Lease operating

    47,911       46,247       65,639  

Gathering and treating

    76,770       37,955       101,974  

Production and ad valorem taxes

    15,620       18,539       18,335  

General and administrative

    7,448       7,842       15,014  

Monitoring fee

    7,541       7,011       —    

Depletion, depreciation and accretion

    347,652       327,659       392,141  

Exploration

    167       886       193  

Strategic

    2,182       853       2,284  

Severance

    326       —         447  

Write-off of deferred IPO expenses

    5,787       2,825       5,787  
 

 

 

   

 

 

   

 

 

 

Total operating expenses

    511,404       449,817       601,814  
 

 

 

   

 

 

   

 

 

 

Operating Income

    (132,729     136,690       (73,304

Interest expense

    (119,248     (112,198     (121,128
 

 

 

   

 

 

   

 

 

 

Income Before Income Taxes

    (251,977     24,492       (194,432

Income tax provision

    (217     (496     (217
 

 

 

   

 

 

   

 

 

 

Net Income

  $ (252,194   $ 23,996     $ (194,649
 

 

 

   

 

 

   

 

 

 

Net income attributable to non-controlling interests

        (96,333
     

 

 

 

Net Income Attributable to Vine Energy Inc.

      $ (98,316
     

 

 

 

Net Income per Share:

     

Basic

      $ (2.81
     

 

 

 

Diluted

      $ (2.81
     

 

 

 

Weighted Average Shares Outstanding:

     

Basic

        34,995,149  
     

 

 

 

Diluted

        34,995,149  
     

 

 

 

Balance Sheet Information:

     

Cash and cash equivalents

  $ 15,517     $ 18,286     $ 33,177  

Total natural gas properties, net

    1,342,354       1,435,976       1,873,982  

Total assets

    1,467,763       1,658,100       2,036,019  

Total debt

    1,224,741       1,218,558       1,050,235  

Total equity(1)

    10,061       292,255       717,992  

Statements of Cash Flows Information:

     

Net cash provided by operating activities

  $ 295,174     $ 270,699    

Net cash used in investing activities

    (252,378     (281,193  

Net cash provided by (used in) financing activities

    (45,565     7,750    

Other Financial Information:

     

Adjusted EBITDAX(2)

  $ 384,713     $ 338,571     $ 529,351  

Levered free cash flow(2)

  $ 42,796     $ (10,494  

 

(1)

Pro forma total equity as of December 31, 2020 includes $354.5 million of non-controlling interests related to the Vine Energy Investment Vehicles.

(2)

Adjusted EBITDAX and levered free cash flow are not financial measures calculated in accordance with GAAP. We believe these measures provide important perspective regarding our operating results and liquidity, as applicable. “Prospectus Summary—Non-GAAP Financial Measures” contains a description of each of these measures and a reconciliation to the most directly comparable GAAP measure.



 

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Non-GAAP Financial Measures

Adjusted EBITDAX

We define Adjusted EBITDAX as our net income before interest expense, income taxes, depreciation, depletion and accretion, unrealized gains and losses on commodity derivatives, exploration expense, strategic expense, 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 to reflect the substantial variance in practice from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net 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.

Levered Free Cash Flow

We define levered free cash flow as the amount of money we have remaining after paying our financial obligations related to investing activities prior to considering any funds received from or paid for financing activities. We calculate levered free cash flow as operating cash flow less investing cash flow.



 

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We believe that levered free cash flow is a useful performance measure as it provides the amount of cash we generated after capital expenditures and any proceeds received from asset sales, prior to any proceeds received from or used in financing activities. While levered free cash flow is not a GAAP measure, it is derived from two GAAP measures, operating cash flow and investing cash flow but should not be considered as an alternative to, or more meaningful than, operating cash flow or investing cash flow determined in accordance with GAAP. Our computation of levered free cash flow may not be identical to other similarly titled measures of other companies.

 

    Vine Oil & Gas     Vine Pro Forma
 
    For the Year Ended
December 31,
    For the
Year Ended
December 31,
2020
 
    2020     2019  
    (in thousands)  

Net income

  $ (252,194   $ 23,996     $ (194,649

Interest expense

    119,248       112,198       121,128  

Income tax provision

    217       496       217  

Depletion, depreciation and accretion

    347,652       327,659       392,141  

Unrealized gain (loss) on commodity derivatives

    164,077       (101,239     204,552  

Exploration

    167       886       193  

Non-cash G&A

    (182     (18     (182

Strategic

    2,182       853       2,284  

Non-cash write-off of deferred IPO expenses

    5,787       2,825       5,787  

Severance

    326       —         447  

Non-cash volumetric and production adjustment to gas gathering liability

    (2,567     (29,085     (2,567
 

 

 

   

 

 

   

 

 

 

Adjusted EBITDAX

  $ 384,713     $ 338,571     $ 529,351  
 

 

 

   

 

 

   

 

 

 

Operating cash flow

  $ 295,174     $ 270,699    

Investing cash flow

    (252,378     (281,193  
 

 

 

   

 

 

   

Levered free cash flow

  $ 42,796     $ (10,494  
 

 

 

   

 

 

   


 

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Summary Reserve, Production and Operating Data

Summary Reserve Data

The following tables summarize estimated proved reserves based on reports 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, except that the table which provides our reserves at “strip pricing” uses pricing based on NYMEX futures prices. The information in the following tables does not give any effect to or reflect our commodity hedge portfolio. “Business—Our Operations—Reserve Data” contains additional information about our reserves.

Summary of Proved Reserves as of December 31, 2020 Based on SEC Pricing

The following table provides the estimated proved reserves of Vine Oil & Gas, Brix and Harvest on a combined basis as of December 31, 2020 based on SEC pricing.

 

     Vine Oil & Gas     Vine Pro Forma  
     At December 31,
2020(1)(2)
    At December 31,
2020(1)(2)
 

Natural gas (MMcf)

     1,802,118       2,313,499  

Total proved developed reserves (MMcf)

     446,243       590,160  

Percent proved developed

     25     26

Total proved undeveloped reserves (MMcf)

     1,355,875       1,723,339  

 

(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, 2020, the SEC Price Deck was $1.99 per 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 $1.73 per Mcf. “Business—Our Operations—Reserve Data—Adjusted Index Prices Used in Reserves Calculations” below contains the adjusted realized prices under strip pricing.

Sensitivity of Proved Reserves Based on Future Strip Pricing

The following table provides our estimated proved reserves of Vine Oil & Gas, Brix and Harvest on a combined basis as of December 31, 2020, using NYMEX strip prices as of market close on December 31, 2020. We have included this reserve sensitivity in order to provide a measure that is more reflective of the fair value of our assets and the cash flows that we expect to generate from those assets. The historical 12-month pricing average in our 2020 disclosures above does not reflect the prevailing gas futures. We believe that the forward-looking nature of strip pricing provides investors with a more meaningful measure of value and enhances their ability to make decisions regarding their investment in us. In addition, we believe strip pricing provides relevant and useful information because it is widely used by investors in our industry as a basis for comparing the relative size and value of our proved reserves to our peers and in particular addresses the impact of differentials compared with our peers. Our estimated net proved reserves based on NYMEX futures were otherwise prepared on the same basis as our SEC reserves for the comparable period.



 

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Actual future prices may vary significantly from the NYMEX prices on December 31, 2020. Actual revenue and value generated may be more or less than the amounts disclosed. “Risk Factors” contains more information regarding the uncertainty associated with price and reserve estimates.

 

     Vine Oil & Gas     Vine Pro Forma  
     Strip Pricing(1)     Strip Pricing(1)  

Estimated proved reserves at NYMEX Strip Pricing

    

Natural gas (MMcf)

     2,364,510       3,151,073  

Total proved developed reserves (MMcf)

     491,769       643,352  

Percent proved developed

     21     20

Total proved undeveloped reserves (MMcf)

     1,872,741       2,507,721  

 

(1)

Prices were in each case adjusted for basis differentials and other factors affecting the prices we receive. Our NYMEX futures based 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.

Select Production and Operating Statistics

The following table sets forth information regarding production, revenues and realized prices, and production costs for the years ended December 31, 2020 and 2019, for Vine Oil & Gas and on a pro forma basis giving effect to the reorganization and business combination transactions described under “Corporate Reorganization.” For additional information on price calculations, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

 

     Vine Oil & Gas      Vine Pro Forma  
     Year Ended
December 31,
     Year Ended
December 31,
 
     2020      2019      2020  

Production data:

        

Natural gas (MMcf)

     240,869        200,214        326,510  

Average daily production (MMcfd)

     658        549        892  

Average sales prices per Mcf:

        

Before effects of realized derivatives

   $ 1.74      $ 2.23      $ 1.75  

After effects of realized derivatives

   $ 2.25      $ 2.42      $ 2.25  

Costs per Mcf:

        

Lease operating

   $ 0.20      $ 0.23      $ 0.20  

Gathering and treating

     0.32        0.19        0.31  

Production and ad valorem taxes

     0.06        0.09        0.06  

Depreciation, depletion and accretion

     1.44        1.64        1.20  

General and administrative

     0.03        0.04        0.05  

Monitoring fee

     0.03        0.04        —    

Exploration

     —          —          —    

Strategic

     0.01        —          0.01  

Write-off of deferred IPO costs

     0.02        0.01        0.02  
  

 

 

    

 

 

    

 

 

 

Total

   $ 2.11      $ 2.24      $ 1.85  
  

 

 

    

 

 

    

 

 

 


 

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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 have been pressured. 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, including the economic impacts of the COVID-19 virus;

 

   

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 oil and gas 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.

If commodity prices decrease or we experience widening of basis differentials, our cash flows and refinancing ability will be reduced. We may be unable to obtain needed capital or financing on satisfactory terms,

 

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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.

Our business and operations have been adversely affected by, and are expected to continue to be adversely affected by, the COVID-19 pandemic, and may be adversely affected by other similar outbreaks.

As a result of the COVID-19 pandemic or other adverse public health developments, including voluntary and mandatory quarantines, travel restrictions, and other restrictions, our operations, and those of our subcontractors and customers, have and are anticipated to continue to experience delays or disruptions and temporary suspensions of operations. In addition, our financial condition and results of operations have been and are likely to continue to be adversely affected by the COVID-19 pandemic.

The rapid development and fluidity of this situation precludes any prediction as to the ultimate adverse impact of COVID-19 on our business, which will depend on numerous evolving factors and future developments that we are not able to predict, including the length of time that the pandemic continues, its effect on the demand for natural gas, the response of the overall economy and the financial markets as well as the effect of governmental actions taken in response to the pandemic.

The timeline and potential magnitude of the COVID-19 outbreak are currently unknown. The continuation or amplification of this virus could continue to more broadly affect the United States and global economy, including our business and operations, and the demand for oil and gas. For example, the outbreak of coronavirus has resulted in a widespread health crisis that will adversely affect the economies and financial markets of many countries, resulting in an economic downturn that may affect our operating results. Other contagious diseases in the human population could have similar adverse effects. In addition, the effects of COVID-19 and concerns regarding its global spread have negatively impacted the domestic and international demand for crude oil and natural gas, which has contributed to price volatility. As the potential impact from COVID-19 is difficult to predict, the extent to which it will negatively affect our operating results, or the duration of any potential business disruption is uncertain. The magnitude and duration of any impact will depend on future developments and new information that may emerge regarding the severity and duration of COVID-19 and the actions taken by authorities to contain it or treat its impact, all of which are beyond our control.

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 New 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 many factors, including:

 

   

our proved reserves;

 

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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 D&C techniques, which involve risks and uncertainties in their application.

Our current and future operations involve utilizing some of the latest D&C techniques. While developing our wells, we face risks associated with:

 

   

effectively controlling downhole pressure;

 

   

landing and maintaining our wellbore at the desired depth in the desired drilling zone;

 

   

running our casing the entire length of the wellbore;

 

   

deploying tools and other equipment consistently downhole;

 

   

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. 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” 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, disrupt, delay or cancel our scheduled drilling projects and ongoing operations, 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;

 

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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;

 

   

stockholder activism or activities by others to restrict exploration, development and production of oil and natural gas;

 

   

natural disasters including regional flooding and hurricanes;

 

   

adverse weather conditions;

 

   

compliance with environmental and other governmental or contractual requirements;

 

   

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.

Our operations are concentrated in the Haynesville Basin of Northwest Louisiana, making us vulnerable to risks associated with operating in a limited geographic area.

All of our producing properties are geographically concentrated in the north western Haynesville Basin. As a result, we may be disproportionately exposed to various factors, including, among others: (i) the impact of regional supply and demand factors, (ii) delays or interruptions of production from wells in such areas caused by governmental regulation, (iii) processing or transportation capacity constraints, (iv) market limitations, (v) availability of equipment and personnel, (vi) water shortages or other drought related conditions or (vii) interruption of the processing or transportation natural gas. This concentration in a limited geographic area also increases our exposure to changes in local laws and regulations, certain lease stipulations designed to protect wildlife and unexpected events that may occur in the regions such as natural disasters, seismic events, industrial accidents or labor difficulties. Any one of these factors has the potential to cause producing wells to be shut-in, delay operations, decrease cash flows, increase operating and capital costs and prevent development of lease inventory before expirations. Any of the risks described above could have a material adverse effect on our business, financial condition, results of operations and cash flow.

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 (i.e. gas transport pipelines) 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.

 

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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 including 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 or convey assets;

 

   

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 and our Second Lien Credit Facility requires us and our New RBL will require 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 representation, warranty or 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

 

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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.

Our 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 drilling locations.

We have a multi-year development plan. These to-be-developed drilling locations represent a significant part of our growth strategy. Our ability to develop these drilling 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 drilling 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 drilling locations may be developed successfully.

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, we typically execute a lease agreement with payment to the lessor subject to title verification. In many 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.

 

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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. If any lender under the RBL or the New 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 or the New RBL, respectively.

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. 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.

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. This helps reduce potential negative effects of reductions in gas prices but also reduces our ability to benefit from increases in gas prices. Moreover, our Second Lien Term Loan requires us to have 70% of our total expected production hedged 24 months forward. However, we currently rely on fewer 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 interest rates, which could have a material adverse impact on our business, financial condition and results of operations.

Increased attention to environmental, social and governance (“ESG”) matters may impact our business.

Increasing attention to climate change, increasing societal expectations on companies to address climate change, increasing investor and societal expectations regarding voluntary ESG disclosures, and potential

 

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increasing consumer demand for alternative forms of energy may result in increased costs, reduced demand for our products, reduced profits, increased investigations and litigation, and negative impacts on our access to capital markets. Increasing attention to climate change, for example, may result in demand shifts for oil and natural gas products and additional governmental investigations and private litigation against the company. To the extent that societal pressures or political or other factors are involved, it is possible that such liability could be imposed without regard to the company’s causation of or contribution to the asserted damage, or to other mitigating factors.

In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Such ratings are used by some investors to inform their investment and voting decisions. Unfavorable ESG ratings and recent activism directed at shifting funding away from companies with energy-related assets could lead to increased negative investor sentiment toward the company and our industry and to the diversion of investment to other industries, which could have a negative impact on our stock price and our access to and costs of capital. Also, institutional lenders may, of their own accord, elect not to provide funding for fossil fuel energy companies based on climate change related concerns, which could affect our access to capital for potential growth projects.

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 development 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, habitat of protected species, 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 the ownership or operation of our oil and gas properties. Numerous governmental authorities 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. “Business—Regulation of Environmental and Occupational Safety and Health Matters” contains further description of the laws and regulations that affect us.

There is inherent risk of incurring significant environmental costs and liabilities in the performance of our operations due to our handling of petroleum hydrocarbons and 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 hazardous 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

 

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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 operations, competitive position or financial condition. To the extent laws are enacted or other governmental action is taken that restricts development 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 and related activities, 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 we use to stimulate production of natural gas. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure to fracture the surrounding rock and stimulate production. There has been increased public concern regarding an alleged potential for hydraulic fracturing to adversely affect drinking water supplies and increase seismicity, 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 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 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. At the federal level, the United States Environmental Protection Agency (“EPA”) has conducted investigations that focus on potential impacts of hydraulic fracturing on drinking water resources and asserted federal regulatory authority over various activities associated with hydraulic fracturing by issuing various guidance, notices, rules and regulations.

In addition, hydraulic fracturing operations require the use of a significant amount of water. The inability to locate sufficient amounts of water, or dispose of or recycle water used in drilling and production operations, could adversely impact our operations. Moreover, new environmental initiatives and regulations could include restrictions on the ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the development or production of natural gas.

Finally, in some instances, the operation of underground injection wells for the disposal of waste has been alleged to cause earthquakes. In Oklahoma, for example, such issues have led to orders prohibiting continued injection or the suspension of drilling in certain wells identified as possible sources of seismic activity. Such concerns also have resulted in stricter regulatory requirements in some jurisdictions relating to the location and operation of underground injection wells. Although our operations are not located in those jurisdictions, any future orders or regulations addressing concerns about seismic activity from well injection in jurisdictions where we operate could affect our operations.

 

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If new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process and disposal activities are adopted in areas where we operate, we could incur potentially significant added costs or permitting requirements 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. “Business—Regulation of Environmental and Occupational Safety and Health Matters—Hydraulic Fracturing” contains further description of the laws and regulations relating to hydraulic fracturing that affect us.

Federal and state legislative and regulatory initiatives relating to pipeline safety could subject us to increased operational delays and costs or reduced prices.

Pursuant to federal legislative authority governing pipeline safety matters, 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 may impact operators of pipelines downstream from the sales points for our product.

In addition, states have adopted regulations similar to existing PHMSA regulations for certain intrastate gas and hazardous liquid pipelines which may be more stringent than the federal requirements. These federal and state legislative and regulatory initiatives relating to pipeline safety could subject us to increased operational delays and transportation costs due to constraints on available pipeline capacity, or reduce the price purchasers are willing to pay for our product.

We are subject to risks associated with climate change.

Climate change continues to attract considerable public and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of greenhouse gases (“GHGs”). These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources. At the federal level, no comprehensive climate change legislation has been implemented to date. The EPA has, however, adopted rules that establish permitting reviews for GHG emissions from potential major sources of certain principal pollutant emissions, which reviews could require meeting “best available control technology” standards for air emissions, as well as monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources and, together with the National Highways Transportation Safety Administration, implement GHG emissions limits on vehicles manufactured for operation in the United States. The regulation of methane emissions from the oil and gas sector has been subject to uncertainty in recent years. Prior standards were rescinded during the Trump Administration; however, the current administration has called for the reinstatement or issuance of methane emissions standards for new, modified, and existing oil and gas facilities. On an international level, the United States was one of 175 countries to sign the Paris Agreement, which requires member countries to set their own GHG emission reduction goals beginning in 2020. Although the United States had withdrawn from the Paris Agreement, the current administration has recommitted the United States to the agreement and directed the federal government to begin formulating the United States’ nationally determined emissions reduction goal under the agreement. The impacts of this order, and any legislation or regulation promulgated to fulfill the United States’ commitments under the Paris Agreement, are uncertain.

Forced emissions reductions could increase our operating costs and CapEx. Such programs could also adversely affect the demand for natural gas by increasing the cost of consuming natural gas. Additionally, on January 27, 2021, the current administration called for substantial action on climate change, including, among other things, the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry, and increased emphasis on climate-related risks across agencies and economic sectors. Incentives to conserve energy or use alternative energy sources as a means of addressing climate change could also adversely affect the demand for natural gas. Additionally, various state and local governments have brought suit against various oil and natural gas companies alleging damages related to climate

 

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change or failure to properly disclose adverse climate impacts to their investors and consumers. Moreover, parties concerned about the potential effects of climate change have directed their attention at sources of funding for energy companies, which has resulted in certain financial institutions, funds and other sources of capital, restricting or eliminating their investment in oil and natural gas activities. There is also a risk that financial institutions will be required to adopt policies that have the effect of gradually curtailing the funding provided to the fossil fuel sector. Recently, the Federal Reserve announced that it has joined the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector. Consequently, legislation, regulation, market changes, and/or future litigation related to climate change could have an adverse effect on our business. Further, most 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 hurricanes, storms, floods and other climatic events. If any such effects were to occur, they could adversely affect or delay demand for the natural gas we produce or cause us to incur significant costs in preparing for or responding to those effects. “Business— Regulation of Environmental and Occupational Safety and Health Matters—Climate Change” contains further description of the risks associated with climate change.

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 and natural resources damages;

 

   

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 costs 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 that are not covered by insurance.

 

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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 drilling locations are technically proved, any inability to develop commercially viable quantities will adversely affect our results of operations and financial condition. The use of 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 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.

In the future, we may make acquisitions that we believe complement or expand our current business. We may not be able to identify attractive acquisition opportunities or complete any such acquisition on commercially acceptable terms.

The success of any completed acquisition will depend on our ability to integrate effectively the acquisition into our existing operations. The process of integrating acquisitions 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.

We can provide no assurance 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 acquisitions 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 periods of high demand will exist in the future or their timing and duration. 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

 

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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 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. 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.

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 or 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 could have an adverse effect on our ability to use derivatives to hedge risks associated with our business.

Title VII of the Dodd-Frank Act established federal oversight and regulation of the derivatives market and of companies like us that participate in that market. The Dodd-Frank Act requires the Commodity Futures Trading Commission (“CFTC”) to promulgate rules and regulations implementing mandates of the Dodd-Frank Act with respect to over-the-counter derivatives of the types we use to hedge our exposure to commodity price volatility. Although the CFTC has issued final regulations in certain areas, in other areas, final regulations and the scope of relevant definitions and/or exemptions still remain to be finalized.

 

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The CFTC issued a final rule on October 15, 2020, imposing position limits for certain futures and option contracts in various commodities (including oil and natural gas) and for swaps that are their economic equivalents. The compliance dates for these limits are delayed until January 1, 2022 and in some cases, January 1, 2023. Under this rule, certain types of hedging transactions are exempt from these limits on the size of positions that may be held, provided that such hedging transactions satisfy the CFTC’s requirements for certain enumerated “bona fide hedging” transactions or positions.

The CFTC has also adopted a final rule regarding aggregation of positions, under which a party that controls the trading of, or owns 10% or more of the equity interests in, another party will have to aggregate the positions of the controlled or owned party with its own positions for purposes of determining compliance with position limits unless an exemption applies. The CFTC’s aggregation rules are now in effect, though CFTC staff have granted relief—until August 12, 2022—from various conditions and requirements in the final aggregation rules. With the implementation of the final aggregation rules and upon the effectiveness of the final CFTC position limits rule, our ability to execute our hedging strategies described herein could be limited.”

On January 24, 2020, U.S. banking regulators published a new approach for calculating the quantum of exposure of derivative contracts under their regulatory capital rules. This approach to measuring exposure is referred to as the standardized approach for counterparty credit risk or SA-CCR. It requires certain financial institutions to comply with significantly increased capital requirements for over-the-counter commodity derivatives beginning on January 1, 2022. In addition, on September 15, 2020, the CFTC issued a final rule regarding the capital a swap dealer or major swap participant is required to set aside with respect to its swap business, which has a compliance date of October 6, 2021. These two sets of regulations and the increased capital requirements they place on certain financial institutions may reduce the number of products and counterparties in the over-the-counter derivatives market available to us and could result in significant additional costs being passed through to end-users like us.

The Volcker Rule provisions of the Dodd-Frank Act may require banks that engage in financial derivative transactions to spin off some of their derivatives activities to separate entities that may not be as creditworthy as our current bank counterparties. Other banks may elect to cease their business as hedge providers, thereby reducing the liquidity of the financial derivatives and the ability of entities like us, as commercial end-users, to hedge or mitigate our exposure to commodity price volatility using over-the-counter financial derivatives.

The legislation and regulations specifically noted above and others yet to be introduced could increase our costs or reduce our opportunities with respect to the use of derivative transactions to hedge or mitigate our exposure to commodity price volatility and other commercial risks affecting our business, which could adversely affect our business, financial condition and results of operations.

Our hedging activities could result in financial losses or reduce our income, or if gas prices increase, we will not benefit from such increases with respect to any gas volumes we had hedged.

To achieve a more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of natural gas, as well as interest rates, we have, and may in the future, enter into derivative arrangements for a portion of our natural gas production and our debt that could result in both realized and unrealized hedging losses. We typically utilize financial instruments to hedge commodity price exposure to declining prices on our natural gas.

Our Second Lien Term Loan requires that we hedge 70% of our production for the next 24 months. By virtue of this hedging requirement, we are impacted less by gas price volatility during this time frame than future periods where a smaller percentage of our production is subject to derivative contracts. However, if gas prices increase, we will not benefit from such increases with respect to the volumes of gas that we have hedged to the extent such volumes are hedged at a price lower than the increased strip price. While such hedges reduce our exposure to downside risk, they also decrease our ability to benefit from the upside of price increases.

 

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Our production may be significantly higher or lower than we estimate at the time we enter into hedging transactions for such period. If the actual amount is higher than we estimate, we will have greater commodity price exposure than we intended. If the actual amount is lower than the nominal amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale or purchase of the underlying physical commodity, resulting in a substantial diminution of our liquidity. As a result of these factors, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows.

Our business could be negatively affected by security threats, including cybersecurity threats and other disruptions.

As an oil and gas producer, we face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the security of our facilities and infrastructure or third-party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. The potential for such security threats has subjected our operations to increased risks that could have a material adverse effect on our business. In particular, our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our information facilities and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. If any of these security breaches were to occur, they could lead to losses of sensitive information, critical infrastructure or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations or cash flows. Cybersecurity attacks in particular are becoming more sophisticated and include, but are not limited to, malicious software, attempts to gain unauthorized access to data and systems and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, and corruption of data. These events could lead to financial losses from remedial actions, loss of business or potential liability.

Changes to applicable U.S. tax laws and regulations or exposure to additional income tax liabilities could adversely affect our business and future profitability.

We will have no material assets other than our equity interest in Vine Holdings, which holds, directly or indirectly, all of the operating assets of our business. Vine Holdings generally will not be subject to U.S. federal income tax, but may be subject to certain U.S. state and local taxes. We are a domestic corporation that will be subject to U.S. corporate income tax on our earnings, including our allocable share of the income of Vine Holdings. Existing U.S. tax laws and regulations could be interpreted, changed or modified, including possibly with retroactive effect, in a manner that would be adverse to us. Further, new U.S. laws and policy relating to taxes could have an adverse effect on our business and future profitability.

For example, the new administration has set forth several tax proposals that would, if enacted, make significant changes to U.S. tax laws. Such proposals include, but are not limited to, (i) an increase in the U.S. income tax rate applicable to corporations (including us) from 21% to 28%, (ii) the elimination of certain subsidies current tax law grants to oil and gas producers, (iii) an increase in the maximum U.S. federal income tax rate applicable to individuals and (iv) an increase in the U.S. federal income tax rate for long term capital gain for certain taxpayers with income in excess of a threshold amount. Congress may consider, and could include, some or all of these proposals in connection with tax reform to be undertaken by the current administration. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could take effect. The passage of any legislation as a result of these proposals and other similar changes in U.S. federal income tax laws could adversely affect our business and future profitability or the liquidity of our Class A common stock.

 

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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 Holdings and we are accordingly dependent upon distributions from Vine Holdings 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 Holdings. “Corporate Reorganization” contains more information. We have no independent means of generating revenue. To the extent Vine Holdings has available cash, we intend to cause Vine Holdings (i) to generally make pro rata distributions to its unitholders, including us, in an amount at least sufficient to allow us to pay our taxes and make payments under the Tax Receivable Agreement, and (ii) to reimburse us for our corporate and other overhead expenses through non-pro rata payments that are not treated as distributions under the VEH LLC Agreement. To the extent that we are unable to make payments under the Tax Receivable Agreement for any reason, such payments will be deferred and will accrue interest until paid. We are limited, however, in our ability to cause Vine Holdings 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 Holdings 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 (“SOX”), 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, 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, 2027. 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.

The Vine Energy Investment Vehicles and the Vine Energy Investment II Vehicles 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), the Vine Energy Investment Vehicles will own approximately 0.3% of our Class A common stock and 100% of our Class B common stock and the Vine Energy Investment II Vehicles will own approximately 46.1% of our Class A common stock (representing 73.0% of our combined economic interest and voting power).

Although the Existing Owners, through their ownership in the Vine Energy Investment Vehicles and the Vine Energy Investment II Vehicles, 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 the Vine Energy Investment Vehicles and the Vine Energy Investment II Vehicles, 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

 

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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. For additional discussion of potential conflicts of interest of which our stockholders should be aware and a discussion of our related party transactions policy, see “Certain Relationships and Related Party Transactions.”

Certain of our directors have significant duties with, and spend significant time serving, entities that may compete with us in seeking acquisitions and business opportunities and, accordingly, may have conflicts of interest in allocating time or pursuing business opportunities.

Certain of our directors, who are responsible for managing the direction of our operations and acquisition activities, hold positions of responsibility with other entities (including Vine-affiliated entities) that are in the business of identifying and acquiring oil and natural gas properties. The existing positions held by these directors may give rise to fiduciary or other duties that are in conflict with the duties they owe to us. These directors may become aware of business opportunities that may be appropriate for presentation to us as well as to the other entities with which they are or may become affiliated. Due to these existing and potential future affiliations, they may present potential business opportunities to other entities prior to presenting them to us, which could cause additional conflicts of interest. They may also decide that certain opportunities are more appropriate for other entities with which they are affiliated, and as a result, they may elect not to present those opportunities to us. These conflicts may not be resolved in our favor. For additional discussion of our management’s business affiliations and the potential conflicts of interest of which our stockholders should be aware, see “Certain Relationships and Related Party Transactions.”

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:

 

   

providing for a classified Board of Directors;

 

   

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 2/3% 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.

 

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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 $7.14 per share.

Based on an assumed initial public offering price of $17.50 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 $7.14 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, 2020 on a pro forma basis would be $10.36 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.

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, assuming the underwriters’ option to purchase additional shares is fully exercised, we will have 37,807,649 outstanding shares of Class A common stock and 34,289,108 outstanding shares of Class B common stock. This number includes 18,750,000 shares of Class A common stock that we are selling in this offering and the 2,812,500 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 the Vine Energy Investment Vehicles and the Vine Energy Investment II Vehicles, will own 16,245,149 shares of Class A common stock and 34,289,108 shares of Class B common stock, representing approximately 73.0% (or 70.1% 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 (Conflicts of Interest)” but may be sold into the market in the future.

The Vine Energy Investment Vehicles and the Vine Energy Investment II Vehicles 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.

 

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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 representatives of 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, the Vine Energy Investment Vehicles, the Vine Energy Investment II Vehicles 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 representatives of 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 (Conflicts of Interest)” 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, Brix Investment, Harvest Investment, Vine Investment II, Brix Investment II and Harvest Investment II. This agreement generally provides for the payment by us to Vine Investment, Brix Investment, Harvest Investment, Vine Investment II, Brix Investment II and Harvest Investment II, respectively, of 85% of the net cash savings, if any, in U.S. federal, state and local income tax that Vine Energy (a) actually realizes with respect to taxable periods ending after December 31, 2025 or (b) is deemed to realize in the event of a change of control (as defined under the Tax Receivable Agreement, which includes certain mergers, asset sales and other forms of business combinations and certain changes to the composition of the Vine Energy board) or the Tax Receivable Agreement terminates early (at our election or as a result of our breach) with respect to any taxable periods ending on or after such change of control or early termination event, in each case, as a result of (i) the tax basis increases resulting from the exchange of Vine Units and the corresponding surrender of an equivalent number of shares of Class B common stock by Vine Investment, Brix Investment and Harvest Investment, respectively, for a number of shares of Class A common stock on a one-for-one basis or, at our option, the receipt of an equivalent amount of cash pursuant to the exchange agreement, (ii) certain existing net operating loss carryforwards, disallowed interest expense carryforwards under Section 163(j) of the Code, and tax credit carryforwards attributable to the Blocker Entities previously owned by certain of the Existing Owners, and (iii) 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 Energy will retain the benefit of the remaining 15% of these cash savings, if any. If we experience a change of control or the Tax Receivable Agreement terminates early, 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 payment obligations under the Tax Receivable Agreement are our obligations and not obligations of Vine Holdings. 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 future events and assumptions, including the timing of the exchanges of Vine Units along with surrendering a corresponding number of our Class B common stock, 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

 

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basis in its Vine Units at the time of the relevant exchange, the depreciation, depletion and amortization 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 Energy’s payments under the Tax Receivable Agreement that constitute imputed interest or give rise to depreciable, depletable 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 and all required payments are made, unless we exercise our right to terminate the Tax Receivable Agreement (or the Tax Receivable Agreement is terminated due to other circumstances, including our breach of a material obligation thereunder or certain mergers or other changes of control) 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 not anticipated to commence until 2028 at the earliest (with respect to the tax year 2026).

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 depreciable, depletable or amortizable tax 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 or Vine Holdings. In addition, certain rights under the Tax Receivable Agreement (including the right to receive payments) will be transferable in connection with transfers permitted thereunder. “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 and certain changes to the composition of the Vine Energy board) 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) the utilization of certain 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 Agreement were terminated immediately after this offering, the estimated lump-sum payment would be approximately $211 million (calculated using a discount rate equal to a per annum rate of LIBOR plus 100 basis points, applied against an undiscounted liability of approximately $244 million). There can be no assurance that we will be able to finance our obligations under the Tax Receivable Agreement.

 

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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 Holdings. 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, and the IRS or another tax authority may challenge all or part of the tax basis increases upon which payments under the Tax Receivable Agreement are based, as well as other related tax positions that we take, and a court could sustain such challenge. 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.

If Vine Holdings were to become a publicly traded partnership taxable as a corporation for U.S. federal income tax purposes, we and Vine Holdings 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 Holdings 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 Units pursuant to the Exchange Right or other transfers of Vine Units could cause Vine Holdings to be 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 Holdings were to become a publicly traded partnership, significant tax inefficiencies might result for us and for Vine Holdings, including as a result of our inability to file a consolidated U.S. federal income tax return with Vine Holdings. 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 Holdings’ assets) were subsequently determined to have been unavailable.

 

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In certain circumstances, Vine Holdings will be required to make tax distributions to us and the Vine Unit Holders, and the tax distributions that Vine Holdings will be required to make may be substantial.

Vine Holdings 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, and us. Pursuant to the VEH LLC Agreement, Vine Holdings will generally make pro rata cash distributions, or tax distributions, to us and the Vine Unit Holders, calculated using our estimated effective tax rate and taking into account our payment obligations under the Tax Receivable Agreement.

Funds used by Vine Holdings to satisfy its tax distribution obligations will not be available for reinvestment in our business. Moreover, the tax distributions that Vine Holdings will be required to make may be substantial, and may exceed (as a percentage of Vine Holdings’ income) the overall effective tax rate applicable to a similarly situated corporate taxpayer.

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, the Vine Energy Investment Vehicles and the Vine Energy Investment II Vehicles will collectively 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 the Vine Energy Investment Vehicles and the Vine Energy Investment II Vehicles, will have certain rights with respect to the election of directors. “Certain Relationships and Related Party Transactions—Stockholders’ Agreement” contains additional 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.

 

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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 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.

Because we have elected to take advantage of the extended transition period pursuant to Section 107 of the JOBS Act, our financial statements may not be comparable to those of other public companies.

Section 107 of the JOBS Act provides that an emerging growth company can use the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accounting standards. This permits an emerging growth company to delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. We are choosing to take advantage of this extended transition period and, as a result, we will comply with new or revised accounting standards on the relevant dates on which adoption of such standards is required for private companies. Accordingly, our financial statements may not be comparable to companies that comply with public company effective dates, and our stockholders and potential investors may have difficulty in analyzing our operating results by comparing us to such companies.

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. Notwithstanding the foregoing sentence, the federal district courts of the United States of America shall be the exclusive forum for the resolution of any complaint asserting a cause of action arising under U.S. federal securities laws, including the Securities Act and the Exchange Act. This choice of forum may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes

 

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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;

 

   

our reserves;

 

   

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

 

   

our realized or expected natural gas prices;

 

   

our timing and amount of future production of natural gas;

 

   

our hedging strategy and results;

 

   

our future drilling plans and cost estimates;

 

   

our competition and government regulations;

 

   

our pending legal or environmental matters;

 

   

our ability to make business acquisitions;

 

   

the impact of the COVID-19 pandemic and its effect on our business and financial condition;

 

   

general economic conditions;

 

   

credit markets;

 

   

our future operating results; and

 

   

our future plans, objectives, expectations and intentions.

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 method 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 previous estimates. 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 $303.3 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 the net proceeds from this offering and borrowings under the New RBL to repay in full and terminate each of the RBL and the Brix Credit Facility.

As of December 31, 2020, we had $190.0 million of outstanding borrowings under the RBL. The RBL was extended in December 2020 to mature in January 2023. The RBL bears interest based on LIBOR plus an additional margin, based on the percentage of the revolving commitment being utilized, ranging from 2.50% to 3.50%.

As of December 31, 2020, we had $125.0 million of outstanding borrowings under the Brix Credit Facility. The Brix Credit Facility matures in March of 2023 and bears interest based on LIBOR plus an additional margin of 7.25%.

A $1.00 change in the assumed initial public offering price of $17.50 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 $17.6 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, first, borrow less under the New RBL and, second, provide additional liquidity for general corporate purposes. If the proceeds decrease for any reason, then we expect that we would increase borrowings under the New RBL to repay in full and terminate the RBL and the Brix Credit Facility.

 

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DIVIDEND POLICY

We currently do not pay a cash dividend to holders of our Class A common stock. 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. In addition, our existing debt agreements place and are expected to place certain restrictions on our ability to pay cash dividends to the holders of our Class A common stock. However to the extent our free cash flow generation results in a decrease in our overall leverage in the future, we may revisit our dividend policy and declare cash dividends on our Class A common stock.

 

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CAPITALIZATION

The following table sets forth our cash position and capitalization as of December 31, 2020:

 

   

on an actual basis for our predecessor, Vine Oil & Gas;

 

   

on an as adjusted basis to give effect to the reorganization and business combination transactions described under “Corporate Reorganization”; and

 

   

on an as further adjusted basis for this share offering at an assumed IPO price of $17.50 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,” and the entry into the New RBL.

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, 2020  
     Actual      As Adjusted     As Further Adjusted  
     (in thousands, except shares and par value)  

Cash and cash equivalents

   $ 15,517      $ 33,177     $ 33,177  
  

 

 

    

 

 

   

 

 

 

Long-term debt:(1)

       

Vine Oil & Gas New RBL(2)

   $ —        $ —       $ 9,063  

Vine Oil & Gas RBL Credit Facility(3)

     190,000        190,000       —    

Vine Oil & Gas Second Lien Term Loan

     150,000        150,000       150,000  

Vine Oil & Gas Third Lien Credit Facility

     —          —         —    

Vine Oil & Gas 8.75% Notes

     530,000        530,000       530,000  

Vine Oil & Gas 9.75% Notes

     380,000        380,000       380,000  

Brix Credit Facility(4)

     —          125,000       —    
  

 

 

    

 

 

   

 

 

 

Total Indebtedness

   $ 1,250,000      $ 1,375,000     $ 1,069,063  
  

 

 

    

 

 

   

 

 

 

Partners’ capital/stockholders’ equity:

       

Partners’ capital

   $ 10,061      $ —       $ —    

Class A Common stock—$0.01 par value; no shares authorized, issued or outstanding, actual; 350,000,000 shares authorized, 16,245,149 shares issued and outstanding, as adjusted; 34,995,149 shares issued and outstanding, as further adjusted

     —          162       350  

Class B Common stock—$0.01 par value; no shares authorized, issued or outstanding, actual; 150,000,000 shares authorized, 34,289,108 shares issued and outstanding, as adjusted; 34,289,108 shares issued and outstanding, as further adjusted

     —          343       343  

Additional paid in capital

     —          213,181       367,566  

Retained earnings

     —          (300     (4,811
  

 

 

    

 

 

   

 

 

 

Total partners’ capital/stockholders’ equity

   $ 10,061      $ 213,386     $ 363,448  

Non-controlling interest

     —          208,880       354,544  
  

 

 

    

 

 

   

 

 

 

Total equity

   $ 10,061      $ 422,266     $ 717,992  
  

 

 

    

 

 

   

 

 

 

Total capitalization

   $ 1,260,061      $ 1,797,266     $ 1,787,055  
  

 

 

    

 

 

   

 

 

 

 

(1)

All outstanding amounts of indebtedness shown at principal amount.

(2)

After giving effect to the consummation of the reorganization and business combination transactions described under “Corporate Reorganization,” and the application of the net proceeds of this offering, we expect to have available capacity of $316 million (after giving effect to approximately $25 million of letters of credit to be issued at closing) based on projected as adjusted borrowings of approximately $9 million pro forma for this offering, resulting in projected liquidity of approximately $350 million as of December 31, 2020 under the New RBL facility.

(3)

At March 8, 2021, Vine Oil & Gas had outstanding borrowings under the RBL of $200.0 million and $24.9 million of outstanding letters of credit, resulting in $75.1 million of remaining capacity under the RBL.

(4)

As of March 8, 2021, Brix had outstanding borrowings under the Brix Credit Facility of $125.0 million and no outstanding letters of credit.

 

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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, 2020, after giving effect to the transactions described under “Corporate Reorganization,” was $422.3 million, or $8.36 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 $17.50 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, 2020 would have been approximately $718.0 million, or $10.36 per share. This represents an immediate increase in the net tangible book value of $2.01 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 $7.14 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

      $ 17.50  

Pro forma net tangible book value per share as of December 31, 2020 (after giving effect to our corporate reorganization)

   $ 8.36     
  

 

 

    

Increase in pro forma net tangible book value per share of Class A common stock attributable to investors in this offering

     2.01     
     

As adjusted pro forma net tangible book value per share of Class A common stock after our corporate reorganization and this offering

        10.36  
     

 

 

 

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

      $ 7.14  
     

 

 

 

A $1.00 change in the assumed initial public offering price of $17.50 per share, which is the midpoint of the price range set forth on the cover page of this prospectus, would increase our as adjusted pro forma net tangible book value per share after the offering by $0.25 and increase the dilution to new investors in this offering by $0.75 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, 2020, 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 $17.50 per share, calculated before deduction of estimated underwriting discounts and commissions:

 

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

Vine Energy Investment Vehicles

     34,403,394        49.7   $ 401,092        43.7   $ 11.66  

Vine Energy Investment II Vehicles

     16,130,863        23.3     188,062        20.5   $ 11.66  

New investors in this offering

     18,750,000        27.0     328,125        35.8   $ 17.50  
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

 

Total

     69,284,257        100   $ 917,279        100   $ 13.24  

The above tables and discussion are based on the number of shares of our Class A common stock and Class B 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 21,562,500, or approximately 29.9% of the total number of shares of Class A common stock.

 

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SUMMARY HISTORICAL AND UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL INFORMATION

The following table shows summary historical financial information of our accounting predecessor, Vine Oil & Gas, and summary unaudited pro forma condensed combined financial information for the periods and as of the dates indicated.

The summary historical financial information as of and for the years ended December 31, 2020 and 2019 was derived from the audited historical financial statements of our predecessor, Vine Oil & Gas, included elsewhere in this prospectus.

The summary unaudited pro forma condensed combined statements of operations data for the year ended December 31, 2020 been prepared to give pro forma effect to (i) the reorganization transactions described under “Corporate Reorganization,” including the acquisition by Vine Oil & Gas of the Brix Companies, and (ii) this offering and the application of the net proceeds from this offering, as if the reorganization and offering transactions had been completed on January 1, 2020. The summary unaudited pro forma condensed combined balance sheet as of December 31, 2020 has been prepared to give pro forma effect to these transactions as if they had been completed on December 31, 2020. This information is subject to and gives effect to the assumptions and adjustments described in the notes accompanying the unaudited pro forma condensed combined financial statements included elsewhere in this prospectus. The summary unaudited pro forma condensed combined 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 and this offering been consummated on the dates indicated, and do not purport to be indicative of our 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,” “Corporate Reorganization,” “Unaudited Pro Forma Condensed Combined Financial Statements,” and the historical financial statements included elsewhere in this prospectus contain additional information to be read in conjunction with the following information.

    Vine Oil & Gas     Vine Pro Forma  
    As of and for the
Year Ended

December 31,
    As of and for the
Year Ended
December 31, 2020
 
    2020     2019  
    (in thousands, except share and per share
data)
 

Statements of Operations Information:

     

Revenue:

     

Natural gas sales

  $ 418,877     $ 445,589     $ 571,144  

Realized gain on commodity derivatives

    123,875       39,679       161,918  

Unrealized gain (loss) on commodity derivatives

    (164,077     101,239       (204,552
 

 

 

   

 

 

   

 

 

 

Total revenue

    378,675       586,507       528,510  

Operating Expenses:

     

Lease operating

    47,911       46,247       65,639  

Gathering and treating

    76,770       37,955       101,974  

Production and ad valorem taxes

    15,620       18,539       18,335  

General and administrative

    7,448       7,842       15,014  

Monitoring fee

    7,541       7,011       —    

Depletion, depreciation and accretion

    347,652       327,659       392,141  

Exploration

    167       886       193  

Strategic

    2,182       853       2,284  

Severance

    326       —         447  

Write-off of deferred IPO expenses

    5,787       2,825       5,787  
 

 

 

   

 

 

   

 

 

 

Total operating expenses

    511,404       449,817       601,814  
 

 

 

   

 

 

   

 

 

 

Operating Income

    (132,729     136,690       (73,304

Interest expense

    (119,248     (112,198     (121,128
 

 

 

   

 

 

   

 

 

 

Income Before Income Taxes

    (251,977     24,492       (194,432

Income tax provision

    (217     (496     (217
 

 

 

   

 

 

   

 

 

 

Net Income

  $ (252,194   $ 23,996     $ (194,649
 

 

 

   

 

 

   

 

 

 

Net income attributable to non-controlling interests

        (96,333
     

 

 

 

Net Income Attributable to Vine Energy Inc.

      $ (98,316
     

 

 

 

Net Income per Share:

     

Basic

      $ (2.81
     

 

 

 

Diluted

      $ (2.81
     

 

 

 

Weighted Average Shares Outstanding:

     

Basic

        34,995,149  
     

 

 

 

Diluted

        34,995,149  
     

 

 

 

Balance Sheet Information:

     

Cash and cash equivalents

  $ 15,517     $ 18,286     $ 33,177  

Total natural gas properties, net

    1,342,354       1,435,976       1,873,982  

Total assets

    1,467,763       1,658,100       2,036,019  

Total debt

    1,224,741       1,218,558       1,050,235  

Total equity(1)

    10,061       292,255       717,992  

Statements of Cash Flows Information:

     

Net cash provided by operating activities

  $ 295,174     $ 270,699    

Net cash used in investing activities

    (252,378     (281,193  

Net cash provided by (used in) financing activities

    (45,565     7,750    

Other Financial Information:

     

Adjusted EBITDAX(2)

  $ 384,713     $ 338,571     $ 529,351  

Levered free cash flow(2)

  $ 42,796     $ (10,494  

 

(1)

Pro forma total equity as of December 31, 2020 includes $354.5 million of non-controlling interests related to the Vine Energy Investment Vehicles.

(2)

Adjusted EBITDAX and levered free cash flow are not financial measures calculated in accordance with GAAP. We believe these measures provide important perspective regarding our operating results and liquidity, as applicable. “Prospectus Summary—Non-GAAP Financial Measures” contains a description of each of these measures and a reconciliation to the most directly comparable GAAP measure.

 

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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 that could cause actual results to vary from our expectations include 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. Unless otherwise indicated, the historical financial information presented in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” speaks only with respect to our predecessor, Vine Oil & Gas, and does not give pro forma effect to our corporate reorganization described in “Corporate Reorganization.”

Overview

Vine Oil & Gas is 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. As of December 31, 2020, we have approximately 100,000 net surface acres centered in what we believe to be the core of the Haynesville and Mid-Bossier plays. Over 90% of our acreage is held by production, and we operate approximately 95% of our future drilling locations. As of December 31, 2020, we had approximately 330 net producing wells. Our assets are located almost entirely in Red River, DeSoto and Sabine parishes of Northwest Louisiana, which according to Enverus, have consistently demonstrated higher EURs relative to drilling and completion (“D&C”) costs than the Haynesville and Mid-Bossier plays in Texas and other parishes in Louisiana. Approximately 85% of our acreage is prospective for dual-zone development, providing us with approximately 800 drilling locations. Utilizing an average of 4 gross rigs, we have approximately 22 years of development opportunities.

Market Conditions and Operational Trends

The oil and gas industry is cyclical and commodity prices are highly volatile. Spot prices for Henry Hub generally ranged from $1.50 per MMBtu to $4.75 per MMBtu since 2014. 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. We use our derivative portfolio and firm sales contracts to mitigate the risks of price volatility.

Our Second Lien Term Loan requires that we hedge 70% of our production for the next 24 months. By virtue of this hedging requirement, we are impacted less by gas price volatility during this time frame than future periods where a smaller percentage of our production is subject to derivative contracts. We believe our balance sheet and hedge program provide ample liquidity in the event of an adverse commodity price environment to enable us to continue to generate levered free cash flow.

Reduction in oil and gas activity has resulted in a decrease of associated gas production as fewer oil wells are drilled in the Permian Basin and other liquids-weighted basins, which has led to a contraction in domestic gas supply. Lower levels of supply have pushed current and forecasted gas prices higher. We expect that the reduction in drilling activity and rig counts may contribute to a shortage in the supply of natural gas in the future, which could result in higher gas prices.

To the extent, however, that natural gas prices decrease, these lower 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

 

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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 fund planned CapEx. Alternatively, natural gas prices may increase, which while increasing revenue and cash flows would result in significant losses being incurred on our derivatives.

We believe domestic gas macro fundamentals are positively disposed in the near-to-intermediate term as lower oil-focused drilling activity will lead to lower associated gas production resulting in a tighter market and higher prices than current levels.

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

Historically, we have seen inflationary pressure on certain service costs; however, we have been able to partially mitigate these cost increases through improved cycle times, longer laterals and other efficiencies. In 2020, we saw reduced service costs due to the recent industry downturn and expect these costs to continue for the remainder of 2021.

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;

 

   

D&C costs per well and per lateral foot drilled and overall CapEx levels; and

 

   

levered free cash flow.

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 with a well’s age, production from a given well 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 gas prices, capital availability, regulatory approvals and ability to procure equipment, services, and personnel and successfully execute the development program or 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. We believe that higher volumes of natural gas will be produced or sold in the Gulf Coast region, but we also expect that higher demand from industrial expansion and export growth will cause the Gulf Coast markets to stabilize and our differentials to NYMEX will remain close to the current range and significantly better than differentials other basins have experienced. To mitigate the variability in differentials, we have entered into multiple physical firm sales contracts at fixed differentials to NYMEX.

 

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The following table summarizes the changes in commodity prices:

 

     For the Year
Ended
December 31,
 
     2020      2019  
     ($ / MMBtu)  

NYMEX Henry Hub High

   $ 3.00      $ 3.64  

NYMEX Henry Hub Low

   $ 1.50      $ 2.14  

Differential to Average NYMEX Henry Hub(1)

   $ (0.19    $ (0.19

 

(1)

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

We utilize an unaffiliated third party to market a portion of our gas production to various purchasers, which consist of credit-worthy counterparties, including utilities, LNG producers, industrial consumers, major corporations and super majors, in our industry. This third party collects directly from the purchasers and remits to us the total of all amounts collected on our behalf less their fee for making such sales. Additionally, we sell a portion of our gas to purchasers who remit directly to us under firm sales contracts. 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, gas treatment, 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 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. These costs are generally determined on a MMBtu basis as specified in the underlying contract.

Production and ad valorem taxes. Production taxes are paid on produced natural gas based on rates established by Louisiana and the amount of gas produced. We currently benefit from a severance tax holiday program, enacted by the State of 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 the well reaches payout. In general, the production taxes we pay correlate to the changes in natural gas revenue, although Louisiana sets rates annually each July. Effective July 1, 2020 through June 30, 2021, the production tax rate on non-exempt production is $0.0934 per Mcf. We are also subject to ad valorem taxes in the parishes where our production is located. Ad valorem taxes are assessed according to 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. G&A expenses are offset by recoveries for overhead that are billed

 

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to our joint-interest partners as outlined in the JOA or other similar documents. As the Vine Energy Investment Vehicles and Vine Energy Investment II Vehicles sell their ownership of common stock in the future, we will recognize non-cash compensation charges to the extent distributions are made by those investment vehicles to any Management Members.

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 discounted gas gathering liability as time passes. 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, drilling of test wells in new areas of the basin as well as the results of any unsuccessful drilling.

Interest expense. We have financed a portion of our working capital requirements and property acquisitions with borrowings under our debt instruments. As a result, we incur interest expense that is affected by fluctuations in interest rates and, in the case of the RBL, New RBL and Second Lien Term Loan, based on outstanding borrowings. Our 8.75% Notes and 9.75% Notes have fixed interest rates. We expect that we would see an immediate reduction in cash interest expense following the completion of this offering and could see further reductions in cash interest expense as we use free cash flow to lower debt.

Strategic expense. These costs include amounts paid to external parties for potential acquisitions or other projects.

IPO related costs. The costs we have incurred related to this offering have been captured on our balance sheet in prepaid and other assets. Upon completion of this offering, these costs will be offset against proceeds received.

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 determined our adjustments from net income to arrive at Adjusted EBITDAX to reflect the substantial variance in practice 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 differ from other similarly titled measures of other companies.

Levered Free Cash Flow

We define levered free cash flow as the amount of money we have remaining after paying our financial obligations related to investing activities prior to considering any funds received from or paid for financing activities. We calculate levered free cash flow as net cash provided by operating activities less net cash used in investing activities.

We believe that levered free cash flow is a useful performance measure as it provides the amount of cash we generated after capital expenditures and any proceeds received from asset sales, prior to any proceeds received

 

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from or used in financing activities. While levered free cash flow is a non-GAAP measure, it is derived from two GAAP measures, operating cash flow and investing cash flow but should not be considered as an alternative to, or more meaningful than, net cash provided by operating activities or net cash used in investing activities determined in accordance with GAAP. Our computation of levered free cash flow may differ from other similarly titled measures of other companies.

 

     Vine Oil & Gas     Vine Pro Forma
 
     For the Year Ended
December 31,
    For the Year
Ended
December 31,
2020
 
     2020     2019  
     (in thousands)  

Net income

   $ (252,194   $ 23,996     $ (194,649

Interest expense

     119,248       112,198       121,128  

Income tax provision

     217       496       217  

Depletion, depreciation and accretion

     347,652       327,659       392,141  

Unrealized (gain) loss on commodity derivatives

     164,077       (101,239     204,552  

Exploration

     167       886       193  

Non-cash G&A

     (182     (18     (182

Strategic

     2,182       853       2,284  

Non-cash write-off of deferred IPO costs

     5,787       2,825       5,787  

Severance

     326       —         447  

Non-cash volumetric and production adjustment to gas gathering liability

     (2,567     (29,085     (2,567
  

 

 

   

 

 

   

 

 

 

Adjusted EBITDAX

   $ 384,713     $ 338,571     $ 529,351  
  

 

 

   

 

 

   

 

 

 

Operating cash flow

   $ 295,174     $ 270,699    

Investing cash flow

     (252,378     (281,193  
  

 

 

   

 

 

   

Levered free cash flow

     42,796       (10,494  
  

 

 

   

 

 

   

Drilling and Completion Costs and Capital Expenditures

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 average 3-4 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 publicly traded, including costs associated with Exchange Act compliance, tax compliance, 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 $10 million to $12 million per year, which are not included in our historical results of operations. We anticipate these effects will be mitigated by additional recoveries associated with our expanded operated well count and the elimination of our monitoring fee paid to our existing owners.

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

 

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as described in “Corporate Reorganization.” Our 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. Most of our compensation expense for Class A Units is treated as a liability award under GAAP. If, by virtue of this offering or future events, our outstanding Class A Units vest as a result of the change of control provisions of such units and a payment to the Class A unitholders becomes probable, we could have an immediate recognition of compensation expense arising from them.

Monitoring fee. Monitoring fees are paid pursuant to a management and consulting agreement with Blackstone and our CEO, of which over 99% is attributable to Blackstone. Our monitoring fee will be eliminated upon completion of this offering.

Interest Expense. In connection with this offering, we expect to materially reduce our indebtedness. Depending on our use of proceeds, we expect an immediate reduction in cash interest expense and could see further reductions in cash interest expense as we use free cash flow to lower debt.

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.

 

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Results of Operations for Vine Oil & Gas

 

     For the Year Ended December 31,  
     2020     2019  
     (in thousands, except per Mcf)  

Production:

        

Total (MMcf)

     240,869         200,214    

Average Daily (MMcfd)

     658         549    
        
           Per Mcf           Per Mcf  

Revenue:

        

Natural gas sales

   $ 418,877     $ 1.74     $ 445,589     $ 2.23  

Realized gain on commodity derivatives

     123,875       0.51       39,679       0.20  

Unrealized (loss) gain on commodity derivatives

     (164,077     (0.68     101,239       0.51  
  

 

 

   

 

 

   

 

 

   

 

 

 

Total revenue

     378,675       1.57       586,507       2.93  

Operating Expenses:

        

Lease operating

     47,911       0.20       46,247       0.23  

Gathering and treating

     76,770       0.32       37,955       0.19  

Production and ad valorem taxes

     15,620       0.06       18,539       0.09  

General and administrative

     7,448       0.03       7,842       0.04  

Monitoring fee

     7,541       0.03       7,011       0.04  

Depreciation, depletion and accretion

     347,652       1.44       327,659       1.64  

Exploration

     167       0.00       886       0.00  

Strategic

     2,182       0.01       853       0.00  

Severance

     326       0.00       —         —    

Write-off of deferred IPO costs

     5,787       0.02       2,825       0.01  
  

 

 

   

 

 

   

 

 

   

 

 

 

Total operating expenses

     511,404       2.11       449,817       2.25  
  

 

 

     

 

 

   

Operating income

     (132,729       136,690    
  

 

 

     

 

 

   

Interest expense

     (119,248       (112,198  

Income tax provision

     (217       (496  
  

 

 

     

 

 

   

Total other expenses

     (119,465       (112,694  
  

 

 

     

 

 

   

Net income

   $ (252,194     $ 23,996    
  

 

 

     

 

 

   

Interest expense

     119,248         112,198    

Income tax provision

     217         496    

Depreciation, depletion and accretion

     347,652         327,659    

Unrealized loss (gain) on commodity derivatives

     164,077         (101,239  

Exploration

     167         886    

Non-cash G&A

     (182       (18  

Strategic

     2,182         853    

Severance

     326         —      

Non-cash write-off of deferred IPO costs

     5,787         2,825    

Non-cash volumetric and production adjustment to gas gathering liability

     (2,567       (29,085  
  

 

 

     

 

 

   

Adjusted EBITDAX

   $ 384,713       $ 338,571    
  

 

 

     

 

 

   

 

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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):

 

2019

   $ 485,268  

Volume

     90,481  

Price

     (117,193

Realized derivative

     84,196  
  

 

 

 

2020

   $ 542,752  
  

 

 

 

The increase in natural gas volume for 2020 was primarily the result of additional producing wells. The price decrease for 2020 was driven by the decline in the Henry Hub price upon which our sales price is generally determined.

Since commodity prices were below the weighted average floor prices of our derivative portfolio, we realized a net gain on our natural gas derivatives during 2020. The average prices of natural gas in our commodity derivative contracts for 2020 and 2019 were $2.71 and $2.86 per MMBtu, respectively. Additionally, our total volumes hedged for 2020 and 2019 were each approximately 90% of net gas produced.

As our production volumes fluctuate, we would expect our revenue to also fluctuate, depending on prevailing natural gas prices.

Unrealized Gain (Loss) On Commodity Derivatives

We had an unrealized loss on our commodity derivative contracts in 2020 and an unrealized gain in 2019. The unrealized loss in 2020 is primarily related to an increase in the NYMEX natural gas futures as well as a decline in our average hedge price from December 31, 2019 while the unrealized gain in 2019 was primarily related to the decrease in NYMEX natural gas futures relative to December 31, 2018.

Operating Expenses

Lease Operating

LOE for 2020 compared to 2019 was down $0.03 per Mcf primarily due to reduced costs for gas treatment and water disposal. After a spike in our gas treatment and water disposal costs in 2019, we started to realize gas treatment cost savings following the replacement of individual well gas treatment equipment with a more efficient, multi-well amine treating facilities that were brought online in 2020. We also developed our third saltwater disposal facility and brought online two saltwater gathering lines resulting in decreased rates on water hauling and disposal costs and direct control over the majority of our water volumes.

We expect that our LOE will increase in the future as additional wells are brought online but may decrease on a unit cost basis as production increases since a portion of our LOE is fixed.

Gathering and Treating

 

     For the Year Ended December 31,  
     2020      2019  
     (in thousands)      Per Mcf      (in thousands)      Per Mcf  

Gathering — Cash

   $ 78,578      $ 0.33      $ 66,181      $ 0.33  

Gathering — noncash

     (2,567      (0.01      (29,085      (0.15

Other

     759        —          859        —    
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 76,770      $ 0.32      $ 37,955      $ 0.19  
  

 

 

    

 

 

    

 

 

    

 

 

 

 

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Gathering and treating expense increased in 2020 on an absolute and unit cost basis. Our cash gathering fees increased $12.4 million due to higher volumes but were flat on a per Mcf basis in 2020. On a per Mcf basis, non-cash gathering expenses decreased because we met all obligations on our gas gathering liability in the first quarter of 2020 and consequently recorded the last non-cash gains at that time with no payments required in 2019 or 2020 on our minimum volume gathering commitment.

Production and Ad Valorem Taxes

 

     For the Year Ended December 31,  
     2020      2019  
     (in thousands)      Per Mcf      (in thousands)      Per Mcf  

Production taxes

   $ 9,957      $ 0.04      $ 13,292      $ 0.06  

Ad valorem taxes

     5,663        0.02        5,247        0.03  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 15,620      $ 0.06      $ 18,539      $ 0.09  
  

 

 

    

 

 

    

 

 

    

 

 

 

Production and ad valorem taxes decreased $2.9 million in 2020 compared to 2019. Production taxes were down $0.02 per Mcf primarily because the state of Louisiana dropped the severance tax rate from $.125 per Mcf to $.0934 per Mcf in the third quarter of 2020. Additionally, the increased production volume in 2020 is production tax exempt whereas 2019 included production volumes where more wells had met payout and no longer qualified for the production tax exemptions.

We expect our production and ad valorem tax 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 production tax exemptions, and we expect our production tax costs will increase in absolute terms as wells meet payout and are no longer production tax exempt. Production taxes are paid on produced natural gas based on rates established annually by the state of Louisiana.

G&A

 

     For the Year Ended December 31,  
             2020                      2019          
     (in thousands)  

Wages and benefits

   $ 25,091      $ 23,301  

Professional services

     2,924        2,498  

Licenses, fees and other

     7,504        7,287  
  

 

 

    

 

 

 

Total gross G&A expense

     35,519        33,086  

Less:

     

Allocations to affiliates

     (9,108      (8,722

Recoveries

     (18,963      (16,522
  

 

 

    

 

 

 

Net G&A expense

   $ 7,448      $ 7,842  
  

 

 

    

 

 

 

The increase in gross G&A expense for 2020 was primarily due to increased headcount in the Plano office and related compensation as well as increased professional services. While net G&A expense in 2020 decreased relative to 2019, as recoveries were higher in 2020 and were attributable to increased producing well count and inflationary rate adjustments.

Write-off of Deferred IPO Costs

In conjunction with a possible initial public offering (“IPO”), costs incurred related to the IPO such as legal, audit, tax and other professional services are capitalized as deferred equity issuance costs in other non-current

 

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assets. In the first quarter of 2020, we wrote-off deferred IPO costs related to years that will no longer be presented in any future potential filings. In the fourth quarter of 2020, we incurred new costs related to a possible IPO and included them in prepaid and other assets.

Monitoring Fee

The increase in monitoring fee for 2020 is due to higher Adjusted EBITDAX with payments pursuant to a management and consulting agreement with Blackstone and our CEO. The monitoring fee is based on Adjusted EBITDAX, and we anticipate monitoring fees will increase in the future if we generate more Adjusted EBITDAX. The monitoring fee will cease upon completion of this offering.

Strategic

These costs include amounts paid to external parties for potential acquisitions or other projects.

DD&A

 

     For the Year Ended December 31,  
     2020      2019  
     (in thousands)      Per Mcf      (in thousands)      Per Mcf  

Depletion

   $ 340,423      $ 1.41      $ 319,456      $ 1.60  

Depreciation

     5,351        0.02        4,405        0.02  

Accretion

     1,878        0.01        3,798        0.02  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 347,652      $ 1.44      $ 327,659      $ 1.64  
  

 

 

    

 

 

    

 

 

    

 

 

 

The increase in DD&A in 2020 is due to increased production. The increase in deprecation is primarily associated with the new saltwater disposal facilities and lower allocation of depreciation to affiliates in 2020. The decrease in accretion expense is related to the extinguishment of the gas gathering liability.

The per MCF decrease in depletion expense for 2020 is attributable to a lower depletion rate primarily due to higher December 31, 2019 proved reserves. We expect our depletion rate will fluctuate in the future based on levels of CapEx incurred to develop our assets and changes in proved reserve levels.

Interest Expense

 

     For the Year Ended December 31,  
             2020                      2019          
     (in thousands)  

Cash interest:

     

Interest costs and unutilized fees

   $ 96,190      $ 98,869  

Realized gain on interest rate swaps

     —          (1,404

Letter of credit fees and other

     943        875  
  

 

 

    

 

 

 

Total cash interest

     97,133        98,340  

Non-cash interest:

     

Non-cash interest

     17,606        12,384  

Non-cash loss on extinguishment of Superpriority Facility

     4,509        —    

Unrealized loss on interest rate swaps

     —          1,474  
  

 

 

    

 

 

 

Total non-cash interest

     22,115        13,858  
  

 

 

    

 

 

 

Total interest expense

   $ 119,248      $ 112,198  
  

 

 

    

 

 

 

 

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The decrease in cash interest costs on debt outstanding for 2020 is attributable to LIBOR decreases on the Superpriority Facility and RBL and unutilized commitment fees on the Second Lien Credit Facility and higher borrowings on the RBL. Non-cash interest on debt outstanding includes amortization of deferred financing costs and original issue discount and is higher for 2020 due to additional amortization related to the First Lien extension, addition of the Second Lien in the fourth quarter of 2020, a non-cash loss on extinguishment of $4.5 million related to the write-off of remaining deferred financing costs and discount on the Superpriority loan.

Our interest rate swap expired in June 2019.

Capital Resources and Liquidity

Our development activities require us to make significant operating and capital expenditures. Our primary use of capital has historically been for the development of natural gas properties. In addition, we regularly evaluate our capital structure and opportunities to manage our liabilities, as well as other strategic transactions that we believe to be credit accretive.

We expect the 2021 capital program of our predecessor, Vine Oil & Gas LP, to be approximately $230 to $240 million of which $210 to $220 million is allocated for D&C operations. The remaining $20 million of its capital program is designated for non-D&C items. We expect our 2021 capital program for Vine Energy Inc. and its subsidiaries following this offering and the combinations to be approximately $340 to $350 million of which $310 to $320 million is allocated for D&C operations. The remaining $30 million of its capital program is designated for non-D&C items.

We plan to fund our 2021 CapEx through cash flow from operations, excess proceeds from this offering (if any) and borrowings under our New RBL. Further, we intend to monitor conditions in the debt capital markets and may determine to issue long-term debt securities, including potentially in the near term, to fund a portion of our 2021 CapEx or refinance a portion of our existing indebtedness. We cannot predict with certainty the timing, amount and terms of any future issuances of any such debt securities.

In July 2020, a committee of independent members from Vine’s Board of Managers approved a $30 million distribution to Vine Oil & Gas Parent LP, a wholly owned subsidiary of Blackstone and certain members of management. The distribution was made immediately following such approval with funds originating from a first lien RBL draw made at the end of June 2020.

On December 30, 2020, we entered into an extension and amendment of our RBL Credit Facility and a new second lien term loan to repay the aggregate principal amount of loans under the Superpriority Facility resulting in the following:

 

   

the maturity of the RBL was extended to January 15, 2023 and the borrowing base of the facility was reduced from $350 million to $300 million and will reduce further on a quarterly basis to $100 million at December 31, 2022. Other than the quarterly reductions, there are no borrowing base redeterminations. The pricing grid was increased by 1.00% to LIBOR + 2.50% to 3.50% based on utilization.

 

   

entered into the Second Lien Term Loan whereby the proceeds were used to repay the aggregate principal amount of loans of $150 million outstanding under the Superpriority Facility in connection with the entry into the amendment to and extension of the RBL. The Second Lien Term Loan was fully drawn at closing in the amount of $150 million. The Second Lien Term Loan bears interest at a rate equal to a LIBOR floor of 0.75% plus 8.75% per annum, payable monthly, and matures on the earlier to occur of (a) December 30, 2025 and (b) 90 days prior to the maturity of the 9.75% Notes or 8.75% Notes, to the extent specified amounts of such indebtedness remain outstanding. The Second Lien Term Loan is redeemable beginning June 30, 2022 at 102% of par value, stepping down to 101% of par value on June 30, 2023 and at par value on June 30, 2024 and thereafter. The Second Lien Term Loan is secured on a junior lien basis by all our assets and stock and the subsidiaries that secure the RBL and, upon closing of the offering, the New RBL.

 

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the Company’s existing $280 million second lien revolving credit agreement, dated December 30, 2019, was subordinated to a third lien in connection with the entry into the Second Lien Term Loan. The Third Lien Credit Agreement provides for a revolving credit facility in an amount up to $330 million, and bears interest rate of LIBOR plus 9.75% per annum. The Third Lien Credit Agreement matures on March 15, 2023 and was undrawn at December 31, 2020.

With consideration of the executed transactions above, we believe we have sufficient liquidity to fund future operations and to meet obligations as they become due for at least one year following the date that these consolidated financial statements are issued.

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 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 Year Ended December 31,  
              2020                        2019           
     (in thousands)  

Operating cash flow

   $ 295,174      $ 270,699  

Investing cash flow

     (252,378      (281,193

Financing cash flow

     (45,565      7,750  
  

 

 

    

 

 

 

Net change in cash

   $ (2,769)      $ (2,744
  

 

 

    

 

 

 

2020 Compared to 2019

Operating Cash Flow

Cash flow from operating activities for 2020 was higher than 2019 primarily due to higher production levels of 658 MMcfd in 2020 as compared to 549 MMcfd in 2019 and working capital changes offset by lower natural gas prices.

Investing Cash Flow

Our cash flow used in investing activities in 2020 was lower than 2019 primarily due to a higher capital program in 2019 offset by $5.8 million in proceeds from the sale of certain pipeline assets.

Financing Cash Flow

Cash flow used in financing activities in 2020 increased as we made a $30 million distribution to Vine Oil and Gas Parent LP and paid $15.6 million of deferred financing costs compared to 2019 where we had net borrowings of $10 million on our RBL and $2.2 million of deferred financing costs.

 

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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 use commodity derivatives, such as swaps, 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 utilize their value to further our strategic pursuits.

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. Our Second Lien Term Loan requires us to have 70% of our total expected production hedged 24 months forward.

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 New RBL will afford us greater flexibility to hedge than similar agreements of our peers because it is expected to allow us to hedge a large percentage of our total 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, 2020:

 

Natural Gas Swaps

 

Period

   Natural Gas
Volume

(MMBtud)
     Weighted Average
Swap Price

($ / MMBtu)
 

2021

     

First Quarter

     515,000      $ 2.70  

Second Quarter

     610,890      $ 2.53  

Third Quarter

     637,522      $ 2.53  

Fourth Quarter

     648,370      $ 2.54  

2022

     

First Quarter

     639,833      $ 2.55  

Second Quarter

     119,780      $ 2.57  

Third Quarter

     156,522      $ 2.56  

Fourth Quarter

     363,109      $ 2.53  

 

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Natural Gas Swaps

 

Period

   Natural Gas
Volume

(MMBtud)
     Weighted Average
Swap Price

($ / MMBtu)
 

2023

     

First Quarter

     445,333      $ 2.50  

Fourth Quarter

     101,087      $ 2.54  

2024

     

First Quarter

     300,000      $ 2.54  

Fourth Quarter

     70,761      $ 2.58  

2025

     

First Quarter

     137,667      $ 2.58  

 

Natural Gas Calls

 

Period

   Natural Gas
Volume

(MMBtud)
     Weighted Average
Swap Price

($ / MMBtu)
 

2021

     

First Quarter

     (85,000    $ 3.19  

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.

Our current derivative portfolio cannot protect us from the risk of a potential widening of differentials between our sales price and NYMEX. We have entered into agreements with multiple potential counterparties to also allow us to hedge our physical gas sales at fixed prices. In 2020, approximately 62% of our 2020 basis was effectively fixed at approximately $0.18 under NYMEX by virtue of our physical, firm sales agreements with multiple credit-worthy counterparties.

Debt Agreements

Vine Oil & Gas 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 and the banks, financial institutions and other lending institutions from time to time party thereto. The RBL was amended in January 2015, October 2017 and most recently in December 2020.

As amended, our RBL has a total current revolving commitment of $300 million, with such commitment being subject to periodic scheduled reductions until January 15, 2023 (the commitment as subject to these reduction from time to time, the “Loan Limit”). In addition to the periodic reductions referenced above, the Loan Limit is also subject to adjustments in connection with certain asset dispositions. 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 85% 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 January 2023.

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.

 

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The RBL also contains a financial maintenance covenant limiting us to a consolidated total net leverage to consolidated trailing twelve month EBITDAX ratio of 4.00:1.00 on or prior to March 31, 2021 and 3.50:1.00 thereafter, measured quarterly.

The RBL bears interest based on LIBOR plus an additional margin, based on the percentage of the revolving commitment being utilized, ranging from 2.50% to 3.50%. 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. Should the RBL remain outstanding as of January 1, 2023, we will be required to pay a ‘deferred extension fee’ of $1 million to the pro rata account of each lender.

We intend to use the net proceeds of this offering and borrowings under the New RBL to repay in full and terminate the RBL.

Second Lien Credit Agreement

In December 2020, we entered into the Second Lien Credit Agreement with Morgan Stanley Senior Funding, Inc. as administrative agent and collateral agent, and certain other banks, financial institutions and other lending institutions from time to time party thereto, pursuant to which we were provided with the Second Lien Term Loan.

The Second Lien Term Loan was fully drawn in December 2020 in an amount of $150 million, and bears interest at a rate equal to a LIBOR plus 8.75% per annum, payable quarterly, maturing on the earlier to occur of (a) December 30, 2025 and (b) 90 days prior to the maturity of the 9.75% Notes or 8.75% Notes, to the extent specified amounts of such indebtedness remain outstanding. If redeemed prior to June 30, 2022, the Second Lien Term Loan is subject to a make-whole premium of the applicable treasury rate plus 0.50% of the amount of interest and any call premium which would have otherwise been payable had the Second Lien Term Loan been redeemed on June 30, 2022. The Second Lien Term Loan is redeemable beginning June 30, 2022 at 102% of par value, stepping down to 101% of par value on June 30, 2023 and at par value on June 30, 2024 and thereafter. The Second Lien Term Loan also provides for a quarterly consolidated total net leverage ratio financial maintenance covenant of 4.00x, stepping down to 3.50x with the quarter ended June 30, 2021 and thereafter, similar to the RBL.

The Second Lien Term Loan contains customary incurrence-based covenants for facilities of this type, including restrictions on the incurrence of liens, indebtedness, asset dispositions, fundamental changes, transactions with affiliates, restricted payments and other customary covenants. For example, our Second Lien Term Loan requires us to have 70% of our total expected production hedged 24 months forward, along with the requirement to maintain liquidity of no less than $40 million, tested quarterly, and is secured on a second lien basis by all of our assets and stock and the subsidiaries that secure the RBL.

Third Lien Credit Agreement

In December 2019, we entered into the Third Lien Credit Agreement with Blackstone Holdings Finance Co LLC, as administrative agent and collateral agent and certain other banks, financial institutions and other lending institutions from time to time party thereto. At that time, the Third Lien Credit Agreement was secured on a second lien basis, but was subordinated to a third lien in December 2020 in connection with the entry into the Second Lien Credit Agreement. We expect to terminate the Third Lien Credit Facility in connection with this offering.

The Third Lien Credit Agreement provides for a revolving credit facility in an amount up to $330 million, and bears interest at a rate of LIBOR plus 9.75% per annum. The Third Lien Credit Agreement matures on March 15, 2023 and was undrawn at December 31, 2020.

 

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The Third Lien Credit Agreement contains customary incurrence-based covenants for facilities of this type, including restrictions on the incurrence of liens, indebtedness, asset dispositions, fundamental changes, transactions with affiliates, restricted payments and other customary covenants, and is secured on a third lien basis by all of our assets and stock and the subsidiaries that secure the RBL and will secure the New RBL, as applicable.

Vine Oil & Gas 8.75% Notes

In October 2017, we issued $530 million aggregate principal amount of the 8.75% Notes at 99% of par, and in connection therewith, we incurred discounts and upfront fees totaling $17.9 million. Aggregate net proceeds from the issuance of the 8.75% Notes of approximately $512 million were used to repay borrowings outstanding on the RBL and Term Loan B (“TLB”) in the amount of $95.0 million and $61.4 million, respectively, and to repurchase in full our $350 million Term Loan C (“TLC”) for $353.5 million. Interest is accrued and paid semi-annually on April 15 and October 15.

The 8.75% Notes are guaranteed on a senior unsecured basis by all our subsidiaries. We may redeem the 8.75% Notes at a redemption price (plus accrued and unpaid interest) equal to 106.563% of the principal amount through October 2021, 104.375% of the principal amount from October 2021 through April 2022 and 100% of the principal amount thereafter. The 8.75% Notes mature in April 2023 and bear interest at 8.75%.

Vine Oil & Gas 9.75% Notes

In October 2018, we issued $380 million aggregate principal amount of 9.75% Notes due 2023 at par, and in connection therewith, we incurred upfront fees totaling $7.8 million. Aggregate net proceeds from the issuance of the 9.75% Notes were $372.2 million and were used to repay borrowings and accrued and unpaid interest in full on the TLB in the amount of $339.0 million. Interest is accrued and paid semi-annually on April 15 and October 15.

The 9.75% Notes are guaranteed on a senior unsecured basis by all our subsidiaries. The 9.75% Notes mature in April 2023 and bear interest at 9.75%. We may redeem the 9.75% Notes at a redemption price (plus accrued and unpaid interest) equal to 107.313% of the principal amount through October 2021, 104.875% of the principal amount from October 2021 through April 2022 and 100% of the principal amount thereafter.

Summary of Outstanding Debt at December 31, 2020 (1)

 

    

Highest Priority

            

Lowest Priority

    

RBL

 

  

Second Lien Term

Loan

  

Third Lien Credit Facility

  

9.75%
(Unsecured)

  

8.75%
(Unsecured)

Face amount

   $ 300 million    $150 million    $330 million    $380 million    $530 million

Amount outstanding

   $ 190 million    $150 million    $0    $380 million    $530 million

Scheduled maturity date

   January 2023    December 30, 2025 or 90 days prior to the maturity of the 9.75% Notes or 8.75% Notes    March 15, 2023    April 2023    April 2023

Interest rate

   LIBOR+2.5-3.5%    LIBOR + 8.75%    LIBOR + 9.75%    9.75%    8.75%

Base interest rate options

   ABR and LIBOR + spread    ABR and LIBOR + spread    ABR and LIBOR + spread    N/A    N/A

Financial maintenance covenants

   – Maximum consolidated total net leverage ratio of 4.0x    – Maximum consolidated total net leverage ratio of 4.0x    - LTM Leverage minimum of $0    N/A    N/A

 

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Highest Priority

            

Lowest Priority

    

RBL

 

  

Second Lien Term

Loan

  

Third Lien Credit
Facility

  

9.75%
(Unsecured)

  

8.75%
(Unsecured)

   decreasing to 3.5x effective April 2021   

decreasing to 3.5x effective April 2021

 

- Minimum liquidity of $40 million tested quarterly

  

 

-Maximum consolidated total net leverage ratio of 4.0x decreasing to 3.5x effective April 2021

 

- Maximum secured leverage ratios of 4.0x decreasing to 3.5x effective April 2021

     

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

 

– Excess cash cap

  

– 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 ability to make investments

 

– Affiliate transactions

  

– Incurrence of debt

 

– Incurrence of liens

 

– Payment of dividends

 

– Equity purchases

 

– Asset sales

 

–Limitations on ability to make investments

 

– Affiliate transactions

Optional redemption

   Any time at par    Make-whole through June 2022; 102% through June 2023; 101% through June 2024; thereafter at par    Any time at par    After October 2020 through October 2021 at 107.313%; thereafter through April 2022 at 104.875%; thereafter at par    After October 2020 through October 2021 at 106.563%; thereafter through April 2022 at 104.375%; thereafter at par

Change of control

   Event of default    Event of default    Event of default    If accompanied by Ratings Decline, Investor put at 101% of par    If accompanied by Ratings Decline, Investor put at 101% of par

 

(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.

 

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Contractual Obligations

 

     As of December 31, 2020 (in thousands)  
     2021      2022      2023      2024      2025      Total  

RBL Principal(1)

   $ —        $ 90,000      $ 100,000      $ —        $ —        $ 190,000  

RBL Interest(2)

     6,823        6,293        127        —          —          13,243  

2nd Lien Term Loan

     —          —          —          —          150,000        150,000  

2nd Lien Interest(2)

     14,448        14,448        14,448        14,448        14,448        72,240  

3rd Lien Interest(3)

     1,419        1,419        288        —          —          3,126  

8.75% Notes Principal

     —          —          530,000        —          —          530,000  

8.75% Notes Interest

     46,375        46,375        13,341        —          —          106,091  

9.75% Notes Principal

     —          —          380,000        —          —          380,000  

9.75% Notes Interest

     37,050        37,050        10,658        —          —          84,758  

LC Fees & Payments(4)

     847        863        653        653        653        3,669  

Drilling Rig(5)

     6,513        4,173        —          —          —          10,686  

Other

     1,054        1,087        932        —          —          3,073  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 114,529      $ 201,708      $ 1,050,447      $ 15,101      $ 165,101      $ 1,546,886  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1)

On December 30, 2020, the maturity of the RBL was extended to January 15, 2023 and availability under the facility was reduced from $350 million to $300 million and will reduce further on a quarterly basis to $100 million at December 31, 2022.

(2)

This debt bears interest at LIBOR plus a borrowing spread. In determining future interest, we used outstanding amounts at December 31, 2020 and used the forward curve for LIBOR to project the interest obligations in those future periods.

(3)

Includes payment of the commitment fee pursuant to the Third Lien Credit Agreement.

(4)

Related to $24.9 million in outstanding letters of credit outstanding as of December 31, 2020.

(5)

We are party to four drilling rig contracts, only one of which had an original term beyond one year, and as a result, only one is reflected in this table.

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 some 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.

 

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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 as time passes. At each reporting period, the difference, if any, between the estimated payments at 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 actual production volumes were to increase, we would reduce the liability via a reduction to gathering and treating expense when the excess gas is produced. We met all obligations on our gas gathering liability in the first quarter of 2020 and consequently recorded the last non-cash gains to fully amortize the gas gathering liability.

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

 

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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.

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.

 

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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 derivative 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.

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. We have elected to

 

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take advantage of this extended transition period, which means that the financial statements included in this prospectus, as well as any financial statements that we file or furnish in the future, will not be subject to all new or revised accounting standards generally applicable to public companies for the transition period for so long as we remain an emerging growth company.

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 with respect to 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 after we cease being an “emerging growth company”.

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 $1.50 per MMBtu to $4.75 per MMBtu since 2014. 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 a $4.9 million change in our natural gas revenue for 2020, 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. This helps reduce potential negative effects of reductions in gas prices but also reduces our ability to benefit from increases in gas prices. 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. Moreover, our Second Lien Term Loan requires us to have 70% of our total expected production hedged 24 months forward.

 

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

Interest Rate Risk

At December 31, 2020, Vine had $340 million of debt outstanding, which bears interest at a floating rate.

Based on the $340 million in floating rate debt we had outstanding as of December 31, 2020, a 50 basis point increase or decrease in interest rate would have resulted in an increase or decrease, respectively, of approximately $1.7 million in interest expense per year. We do not currently have any derivative arrangements to protect against fluctuations in interest rates applicable to our variable rate indebtedness but may enter into such derivative arrangements in the future. To the extent we enter into any such interest rate derivative arrangement, we would subject to risk for financial loss. For more information, please see “Risk Factors—Risks Related to Our Business—Our derivative activities could result in financial losses or reduce our income.”

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 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 2020, we had five 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 in 2020. 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 an energy 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.

Natural gas demand has significantly grown as a percentage of North America’s energy mix over the last ten years, having increased 38% from 86 Bcfd to 119 Bcfd and growing from 27% to 37% of the energy mix due to ample domestic supply, reliability of supply, significant supporting in-place infrastructure, low carbon intensity and low prices. In particular, demand for exported LNG has contributed to approximately 21% of that increase, with continued growth in LNG exports anticipated according to Wood Mackenzie. We believe natural gas will continue to be instrumental as a low carbon intensity source for meeting growing energy demand.

We believe the Haynesville will be particularly critical to meeting future natural gas demand. 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, according to The Oil & Gas Journal. The Haynesville is among the oldest and most delineated shale plays in North America and its well economics have continued to improve in recent years as a result of advances in enhanced drilling and completion techniques, combined with predictable production profiles and well cost reductions. These advances have driven both higher and more capital efficient reserve recoveries on a per lateral foot basis, primarily as a consequence of optimized fracture stage lengths and increased proppant and water loading.

The Mid-Bossier shale overlays the Haynesville shale and demonstrates similar characteristics and well results. Additionally, the Haynesville and Mid-Bossier shales possess 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. These plays are at 10,500 to 13,500 ft in depth with formation temperatures ranging from 300 to 375° F, resulting in near pipeline quality natural gas requiring little additional processing, which contributes to relatively low operating costs. Lastly, due to significant historical development activity in the Haynesville beginning in 2008, which resulted in approximately 5,700 wells drilled through December 31, 2020, production and decline rates are predictable, and low-cost and sufficient midstream infrastructure is already in place. We therefore believe the Haynesville is one of the lowest-cost, lowest-risk natural gas plays in North America. As a consequence of these factors, as well as our proximity to Henry Hub and other premium Gulf Coast markets, LNG export facilities and other end-users, the play benefits from low breakeven costs, higher cash margins and higher pricing netbacks relative to other North American natural gas plays, such as those in Appalachia and the Rockies.

In contrast to the Haynesville, other sources of natural gas supply, including associated gas from oil-prone drilling and natural gas from the Appalachian region, are facing headwinds in the form of reduced activity and infrastructure constraints. Associated natural gas from oil-prone drilling was the largest contributor to natural gas supply growth from 2011 to 2019. However, due to the significant oil price shock brought on by the COVID-19 pandemic, the number of rigs drilling for oil in North America fell 59% in 2020, which is expected to result in a significant decline in future natural gas supply. While the Marcellus and Utica shales in the northeast United States currently account for approximately 30% of North American natural gas supply, there is limited pipeline capacity available to transport natural gas out of the area. Additionally, the demanding regulatory environment in the Northeast has limited new gas pipeline infrastructure. As such, we believe the Haynesville will be further relied upon to meet natural gas demand growth driven by increasing electricity demand associated with the global economic recovery, coupled with the continued increase in global LNG cargoes.

We first entered the Haynesville in 2014 following the Shell Acquisition and have actively acquired additional proximate acreage. We have approximately 125,000 net surface acres centered in what we believe to be the core of the Haynesville. Over 90% of our acreage is held-by-production and we operate over 90% of our

 

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future drilling locations with an average working interest of 83%. Approximately 84% of our acreage is prospective for dual-zone development, providing us with approximately 900 drilling locations among Vine, Brix and Harvest. Utilizing an average of 4 gross rigs, which we believe is sufficient to maintain production, we have approximately 25 years of development opportunities. We are not subject to any material minimum volume commitments in our gathering agreements, and have no firm transportation commitments, which provides us with the flexibility to match an optimal development pace to the prevailing natural gas price and hedging environment at any given time. This, coupled with the extensive midstream infrastructure and low basis differentials in the Haynesville, contributes to lower break-even costs. Research from Enverus projects that the average Haynesville Basin core well generates a 31% rate of return using a NYMEX gas price of $2.75 per MMBtu, which Enverus ranks as the highest among notable shale plays in North America. Moreover, based on the location of our acreage, which is in some of the most prospective parts of the Haynesville, we believe our weighted average rate of return based on internal cost assumptions for our remaining core drilling locations is 85% at a NYMEX gas price of $2.75 per MMBtu. As of December 31, 2020, we had approximately 370 net producing wells. Our assets are located almost entirely in Red River, DeSoto and Sabine parishes of Northwest Louisiana, which, according to Enverus, have consistently demonstrated higher EURs relative to drilling and completion costs than the Haynesville in Texas and other parishes in Louisiana.

The following table provides a summary of our inventory of drilling locations as of December 31, 2020, including average lateral length and drilling location data in each play.

Drilling Locations (1) (2)

 

     Short Lateral      Long Lateral         
Length    <5,300 ft      >5,300 ft      Total  
        

Haynesville

     226        147        373  

Mid-Bossier

     212        293        505  
  

 

 

    

 

 

    

 

 

 

Total Core

     438        440        878  
  

 

 

    

 

 

    

 

 

 

Total Non-Core

     44        10        54  
  

 

 

    

 

 

    

 

 

 

Total Drilling Locations

     482        450        932  
  

 

 

    

 

 

    

 

 

 

 

(1)

“Business—Our Operations—Reserve Data and Presentation—Drilling Locations” contains a description of our methodology used to determine gross drilling locations. We exclude drilling locations where our working interest is less than 20%.

(2)

932 gross drilling locations reflecting an average working interest of approximately 83% or 776 net drilling locations.

We describe the progression of our well completions as Vintages with our most recent wells described as Vintage 5. The characteristics of our Vintage 5 wells include 100-mesh sand completions, decreased cluster spacing, optimized proppant and water loading and refined stage lengths. We intend to continue employing longer laterals to develop certain areas within our asset base in order to increase capital efficiency. The shift to a higher concentration of longer laterals is a strategy we believe reflects our recent success in drilling long laterals of up to 10,000 ft. We expect this will increase our capital efficiency by allowing us to develop the gas in place using fewer wellbores and lower development costs, resulting in lower breakeven prices and higher returns.

Substantially all of our leasehold acreage is not subject to expiry because we have at least one developed well in each section, which, through continuous production of gas, maintains the leasehold position in that section and provides us with flexibility to conduct our remaining development. Our acreage has been delineated by over 700 gross horizontal wells drilled across our position in Sabine, Red River and DeSoto parishes, providing us with confidence that our inventory of drilling locations is low-risk and repeatable and that we can continue to generate consistent economic returns; of these 700 wells, over 280 wells have been brought online

 

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under our ownership or participation since our development program began in 2015, providing us with a significant amount of well performance data and associated learnings. In addition to the 700 wells drilled on our acreage, approximately 1,000 wells have been drilled by other operators within one mile of our position, further enhancing the delineation and confidence in our acreage. The company also holds license to almost 400 square miles of 3D and 50 miles of 2D seismic data. We are the leader of Mid-Bossier development, accounting for 36% of all Mid-Bossier wells brought online from 2017 to 2020, which is more than any other single operator.

All of the company’s acreage is underlaid by Northwest Louisiana’s extensive legacy midstream infrastructure, which includes access to sufficient gathering capacity to accommodate our future growth, including our primary third-party gatherer’s approximately 500 miles of pipeline and related treating plants. Their system is currently operating at an approximate 90% utilization rate and has multiple offload points where we can transfer volumes to other area gatherers at equivalent rates. This significant pre-existing area midstream infrastructure provides access to other area gatherers, and we utilize their capacity on both a firm and interruptible basis and expect to continue to do so in the future. We sell our gas at the tailgates of the treating plants attached to our gatherers’ systems and, as a result, incur and hold no direct firm-transportation cost or commitments. Furthermore, approximately 1.0 Bcfd of additional transportation capacity came online in mid-2020 through the DTE Energy (LEAP) project and another approximately 1.0 Bcfd is expected by mid-year 2021 with the Enterprise Product Partners (Acadian) project. Our proximity and sales to Henry Hub and other premium Gulf Coast markets, LNG export facilities and other end-users results in our netbacks reflecting low transportation costs, which is a significant competitive advantage compared to other North American dry gas plays such as those in Appalachia and the Rockies. As a result of these takeaway and sales dynamics, our basis differentials have remained tightly banded since our inception, ranging from $0.01 to $0.26 per MMBtu; over this same period, basis differentials in Appalachia and the Rockies have ranged from $0.27 to $1.54 and $0.12 to $0.96 per MMBtu, respectively. Further, in 2020, Vine Oil & Gas sold approximately 62% of its total gas production through firm sales contracts, with approximately 37% of total production being sold at specified differentials from Henry Hub, providing additional support to our realized pricing. We believe these attractive relative realizations and our long-term access to growing demand (e.g. LNG, chemical, refinery) on the Gulf Coast support our development plan and ability to generate levered free cash flow in various commodity price environments.

A transition to cleaner sources of energy is underway across the globe as demand for renewables and natural gas is projected to increase at a more rapid pace than demand for higher emission energy sources like coal and oil. According to the IEA global natural gas demand is projected to grow 15% between 2019 and 2030, resulting in an increase of approximately 17 Tcf of demand. Much of this growth, approximately 8 Tcf, is in the industrial sector, with growth in power generation, buildings, transportation and other sectors comprising the balance. Additionally, global natural gas consumed for energy and feedstock uses in industry is expected to grow 25% between 2019 and 2030, while coal and oil are projected to decline.

With respect to domestic electricity generation, the EIA projects that between 2019 and 2050, electricity generation will increase approximately 30% from 4,127 billion kilowatt hours to 5,414 billion kilowatt hours. In 2019, natural gas represented 37% of this fuel mix while renewables represented 19% with the balance comprised of coal at 24% and nuclear at 19%. By 2050, the EIA predicts that natural gas will remain a relatively constant 36% of this growing market, while renewables will increase to 38% and coal and nuclear will decrease to 13% and 12%, respectively. Renewables like wind and solar, which are intermittent by nature, require non-intermittent back up capacity such as natural gas, to provide a consistent level of electricity generation. More globally, the IEA predicts that global demand from electric vehicles will increase from 69 TWh in 2019 to 551 TWh by 2030, representing a CAGR of 21%. We believe that increasing demand for electricity from lower emissions sources, like renewables and natural gas, demonstrate how natural gas will play a critical role in this transition to a cleaner energy future.

North America has become increasingly dependent on natural gas for its energy consumption needs, and the EIA credits the increasing use of natural gas in domestic power generation as the leading factor in the 15%

 

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decrease in domestic energy related CO2 emissions from 2007 to 2019. Additionally, domestic LNG exports, which began in 2016, have increased to current levels of approximately 10 Bcfd. We believe the export of LNG to global markets will allow economies in Asia, Europe and Latin America to be less dependent on higher emission fuels as has been the case in North America.

Due to the composition of our production stream, which is essentially all dry gas (i.e. methane), we do not produce any associated oil or natural gas liquids. We also produce small amounts of water, CO2 and other byproducts. Since our production is not burdened with having to separate, store or transport oil or natural gas liquids, we do not have any direct emissions related to these processes. Moreover, by utilizing industry leading technology, we seek to measure and reduce our emissions and consider doing so a core competency of our business. We measure the quantity of greenhouse gas emissions in CO2e and the intensity of our emissions in CO2e per Bcf of production. We also measure methane emissions as a percentage of production or methane intensity. We have adopted operational practices specifically designed to reduce our emission footprint, including installation of intermittant and no-bleed control valves, utilization of bi-fuel drilling and completion equipment, proactive LDAR wellsite surveys to reduce fugitive emissions, and the onsite generation of solar power to operate certain equipment. While from 2017 to 2020 our annual production increased 153.5% from 128.8 Bcf to 326.5 Bcf, our CO2e emissions rate decreased by 35% from 686 mT CO2e/Bcf to 444 mT CO2e/Bcf and our methane intensity decreased by 77% from 0.061% to 0.014% of production, below BP by comparison, an industry leader at 0.14% of production across its more diverse asset base. Given the low emissions nature of our natural gas production and the additional active mitigation measures we implement, we believe we have one of the lowest emission levels per Bcf of annual production of any domestic onshore oil and gas company.

Our management team has extensive experience in the Haynesville and Mid-Bossier 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 North America. Many members of our management team have extensive experience working in the Haynesville since its inception as a commercial play and have directly contributed to its technical advancement. Since the Shell Acquisition, our management team has been at the forefront of developing the technology to enhance well EURs and economics for both Haynesville and Mid-Bossier wells, including;

 

   

increasing lateral length;

 

   

optimizing fracture stage lengths;

 

   

optimizing the amount and intensity of proppant and fluid pumped per foot of lateral;

 

   

reducing cluster spacing;

 

   

managing production rates to preserve downhole pressure;

 

   

adjusting well spacing and development patterns; and

 

   

improving wellbore landing accuracy.

 

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Successful implementation of these measures has resulted in superior well performance relative to that of other major operators in the basin as seen in the charts below.

 

LOGO

 

Note:

Vine and third-party data sourced from Enverus. Includes horizontal wells targeting the Haynesville and Mid-Bossier with initial production between 2017 to 2020, normalized to a 7,500’ lateral.

 

(1)

Haynesville peers include Aethon Energy Management LLC, BPX Energy Inc., Castleton Commodities International LLC, Chesapeake Energy Corporation, EnSight IV Energy Partners, LLC, Exco Resources, Inc., Exxon Mobil Corporation, GeoSouthern Haynesville, Goodrich Petroleum Corporation, Indigo Natural Resources, LLC, Rockcliff Energy LLC, Sabine Oil & Gas Corporation.

(2)

Mid-Bossier peers include Aethon Energy Management LLC, BPX Energy Inc., Comstock Resources Inc., Exxon Mobil Corporation, GeoSouthern Haynesville, and Indigo Natural Resources, LLC.

To maximize gas recovery from our wells, we manage the downhole pressure drop after initial flowback which results in a flat early-time production profile. The flat production profile is 5 to 18 months for both our Haynesville and Mid-Bossier wells. After the flat production period, our wells enter an exponential decline period followed by a hyperbolic decline and a final exponential terminal decline.

We believe that the gas price necessary to yield a Breakeven PV-10 to be $1.91 per MMBtu NYMEX on average for our remaining core drilling locations. Additionally, and based on internal estimates, we believe the gas price necessary to yield a Breakeven PV-10 for our remaining Haynesville and Mid-Bossier drilling locations to be $1.90 and $1.93 per MMBtu, respectively. These results demonstrate basin leading breakevens based on estimates from Enverus, which indicate Haynesville and Mid-Bossier breakevens for our peers range from $2.05 to $2.54 and $1.93 to $2.74 per MMBtu, respectively. Furthermore, our wells generally achieve payout of our drilling and completion costs within 12 to 16 months, which allows for efficient recycling of cash flow and provides significant excess cash flow beyond payout and, what we believe to be, industry leading returns on investment.

History of the Haynesville and Our Acreage

The Haynesville shale and the overlying Mid-Bossier shale were deposited in a Jurassic basin that covers more than 9,000 square miles and includes eight parishes in North Louisiana and eight counties in East Texas, collectively called the Haynesville. 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 acreage position, the Haynesville ranges from 11,500 ft 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 ft 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 1900s, the prospectivity of the Haynesville was not widely recognized until 2005. During this time, Encana and other

 

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operators acquired significant acreage in North Louisiana 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. During this time, certain members of our management team were part of, and integral to, the Encana team. We purchased Shell’s interest in this acreage during 2014 and GEP purchased the Encana portion during 2015.

In 2010, at the height of its activity, over 200 rigs were active in the Haynesville as producers drilled wells to preserve leasehold positions, creating significant oilfield services and midstream infrastructure that remains today to accommodate the current development activity and contribute to the low basis differentials in the basin. Furthermore, the basin is well positioned to capitalize on LNG demand, growing population centers in the southern United States, expanding petrochemical capacity in the Gulf Coast region, and the retirement of selected coal-fired electricity plants.

Since peak activity in 2010, our industry has made significant advances in drilling and completion technology and techniques, including long lateral development, geo-steering techniques and changes in completion intensity and design. These trends have resulted in increased EURs per lateral foot, a trend which continues with our most recent well design. We believe our EURs per lateral foot and the resulting Breakeven PV-10 levels compare favorably with the most prolific basins in North America. At the same time, our average drilling and completion times and well costs have decreased, which have yielded enhanced economics for development of our reserves.

In January 2011, Louisiana began allowing cross-unit horizontal drilling. Prior to this rule change, lateral lengths could not exceed 5,000 feet in length. With this change in regulation, operators can now develop wells that cross section lines and more efficiently develop the acreage using long laterals. We believe our large and relatively contiguous position combined with a streamlined regulatory approval process provides us with an opportunity to capitalize on a development plan that features multi-section lateral lengths.

We believe that we have been instrumental in the revitalization of the Haynesville since entering the basin in 2014 through the purchase of Shell’s interest. Since we began our drilling program in 2015, we have participated in over 280 wells, and been at the forefront of advancements in drilling and completion optimization techniques such as increasing lateral lengths, proppant concentration, water intensity, cluster spacing and reservoir pressure drawn-down management. Enverus projects that the current number of rigs running in the Haynesville will increase from the current figure of approximately 43 rigs up to 50 rigs over the next 12 to 18 months, which compares to 2020 average rigs of 37.

Business Strategy

Our strategy is to draw upon our management team’s experience in developing natural gas resources to generate levered free cash flow while achieving modest growth in our production and reserves and thus enhance our value. Our strategy has the following principal elements:

 

 

Optimize Return-On-Capital Through Focus on Profitably Increasing Well Recoveries While Minimizing Costs. Since 2017, we have drilled, on average, longer-lateral wells and further optimized our completion design, resulting in increased EURs compared to our prior drilling programs. From our initial Vintage 1 wells drilled in 2015 to our Vintage 5 wells in 2019 and 2020, EURs have increased from 1.4 Bcf per 1,000 lateral feet to 2.1 Bcf per 1,000 lateral feet. Simultaneous with recovery improvements, D&C costs per lateral foot have declined while lateral lengths have increased, indicating both capital efficiency gains and improvements in per Mcf economics. Our capital program in 2018 was concentrated on the evaluation of well density and key elements of our completion design, and, based on successful tests, our 2019 and 2020 capital program focused on longer lateral development, completion optimization and cycle time improvements. We focus on developing the maximum recovery of gas and economic value for every section we operate by adjusting the number of wells per section as market conditions change. We look for opportunities to reduce capital costs based on market conditions and we are focused on locking in reduced costs as a result of recent industry-wide decreases in demand for oilfield services. Additionally, we continue to rely on strategic alliances with third

 

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parties to reduce lease operating expenses for items such as chemicals and self-source higher cost services like water disposal to lower our overall operating costs.

 

 

Generate Levered Free Cash Flow While Delivering Modest Production Growth. We maintain a disciplined, cash flow-focused approach to capital allocation. Based on our year-end 2020 reserves, we had a drilling inventory of approximately 900 drilling locations among Vine, Brix and Harvest, or approximately 25 years of development opportunities utilizing an average of 4 gross rigs, which we believe would be sufficient to maintain production. Our remaining drilling inventory has an average payback period of approximately 14 and 24 months at an assumed NYMEX gas price of $2.75 and $2.25 per MMBtu, respectively. The concentration, delineation and scale of our core leasehold positions, coupled with our technical understanding of the reservoirs, allows us to efficiently develop our acreage to generate levered free cash flow, increase sectional recoveries over time and 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 levered free cash flow while modestly growing production and reserves.

 

 

Leverage our Deep Experience in the Haynesville to Develop Industry-Leading Business Practices and Technology. Eric D. Marsh, our President and Chief Executive Officer, and other key members of our management participated in the early development of the Haynesville. Through their experience, they developed expertise that allows for continued advancement of industry-leading well completion techniques and drilling and development efficiencies. We continue to develop and apply industry-leading practices to manage D&C costs and maximize the recovery factor of gas in place. We have also realized significant improvements in our development efficiency over time, including a reduction in drilling and completion days, which contribute to lower well costs. We employ enhanced completion techniques through increased fracture stages, optimized proppant loading and pumping intensity and reduced cluster spacing and drilling-related efficiencies through multi-well pads and longer laterals. These measures have allowed us to lower D&C costs per lateral foot while yielding increased EURs, thereby improving our capital efficiency and returns, while also reducing the number of short laterals and associated surface equipment required to develop our resource.

 

 

Maintain a Disciplined Financial Strategy. We intend to fund our operations predominantly with internally generated cash flows while maintaining ample liquidity to weather commodity cycles. We target spending approximately 65% to 75% of our operating cash flow on CapEx to maintain or modestly increase production, with the remaining amount being available, initially, for debt repayment. We seek to protect future cash flows and liquidity levels through a multi-year commodity hedge program and through physical firm sales agreements with multiple credit-worthy counterparties. We expect that our new credit agreement that we will enter into contemporaneously with the closing of this offering will give us significant flexibility to hedge a large percentage of our total expected production. To further reduce volatility in our cash flows and returns, we will also seek to enter into contracts for oilfield services that are no longer than the periods covered by our commodity hedges. In addition, pro forma for this offering, we anticipate that our total net debt to Adjusted EBITDAX ratio for the year-ended December 31, 2020 will be approximately 2.0x, which is among the lowest for publicly traded gas-focused upstream companies. We intend to target modest financial leverage of total net debt to Adjusted EBITDAX of 1.0x to 1.5x and use levered free cash flow to further reduce outstanding debt. While we will prioritize debt paydown as the primary use of levered free cash flow until our targeted leverage ratios are met, we may evaluate potential acquisition opportunities that are highly strategic to us, but we will pursue them only to the extent they are accretive and meet our financial strategy and operational objectives. Adjusted EBITDAX is not a financial measure calculated in accordance with GAAP. We believe that Adjusted EBITDAX provides important information regarding our operating results. “Prospectus Summary—Non-GAAP Financial Measures” contains a description of each of this measure and a reconciliation to the most directly comparable GAAP measure.

 

 

Steward the Health and Safety of our Employees, our Community and the Environment. Since peaking in 2007 at 6,003 MMmt, the EIA reports that total domestic energy sector related CO2 emissions have declined by 14.5% (873 MMmt) by 2019 and they cite the increasing use of natural gas in power generation as a key driver of this trend. While we believe the lower carbon intensity of using natural gas as opposed to coal in

 

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electric power generation in and of itself contributes meaningfully to lower CO2 emissions, we further believe that the benefits of natural gas are enhanced by reducing production related CO2, methane and other emissions. To that end, minimizing production related emissions is a core competency of our business and we continually seek to identify, accurately measure and reduce emission related to our business. From 2017 to 2020, our CO2e per Bcf of production declined 35% from 686 mT CO2e/Bcf to 444 mT CO2e/Bcf while our methane intensity decreased 77% from 0.061% to 0.014% of production, below BP by comparison, an industry leader at 0.14% of production across its more diverse asset base. In addition, we emphasize rigorous health and safety protocols in all aspects of our business and have demonstrated strong safety performance. Our total recordable incident frequency rate averaged 0.31 from 2017 through 2020 and 0.09 for 2020, both of which are well below the American Exploration and Production Council 2019 average of 0.47 and the U.S. Bureau of Labor Statistics E&P Support Activities Benchmark of 0.60.

Business Strengths

We have a number of strengths that we believe will help us successfully execute our business strategy and generate levered free cash flow, including:

 

 

We Believe we are Among the Most Economic Natural Gas Producers in North America. We own leases across an extensive, largely contiguous and fully delineated acreage position spanning approximately 125,000 net surface acres and approximately 230,000 net effective acres centered in what we believe to be the core of the Haynesville and Mid-Bossier. Our highly concentrated acreage position promotes more efficient development through the drilling of longer laterals, the ability to utilize multi-zone bi-directional well pads and limited need for additional gathering expansion. Longer laterals are significantly more capital efficient with a 10,000 ft lateral having up to four times the PV-10 at a $2.75 NYMEX price per MMBtu, but less than two times the cost, when compared to our standard lateral. Research from Enverus projects that the average Haynesville Basin core well generates a 31% rate of return using a NYMEX gas price of $2.75 per MMBtu, which Enverus ranks as the highest among notable shale plays in North America. Moreover, based on the location of our acreage, which is in some of the most prospective parts of the Haynesville, we believe our weighted average rate of return based on internal cost assumptions for our remaining core drilling locations is 85% at a NYMEX gas price of $2.75 per MMBtu. Additionally, given the high initial productivity of our wells, we typically recover approximately 45% of a well’s EUR in the first 12 months of production. As of December 31, 2020, our drilling inventory consisted of approximately 900 drilling locations among Vine, Brix and Harvest in both the Haynesville and Mid-Bossier, which included approximately 450 drilling locations where we intend to utilize laterals 5,300 ft or greater. Utilizing an average of 4 gross rigs among Vine, Brix and Harvest, which we believe is sufficient to maintain production, we believe we have approximately 25 years of development opportunities. Our average production for the quarter ended December 31, 2020 was 944 MMcfd. We consider our drilling inventory to be low risk because it is located in areas where we (and other producers) have extensive drilling and production experience with production results exhibiting higher repeatability versus other natural gas plays. There have been over 700 gross horizontal wells drilled across our position, of which we participated in over 280 since 2015, providing us substantial well performance data. In addition to the over 700 wells drilled on our acreage, more than 1,000 wells have been drilled within one mile of our position, further supporting our economic expectations.

 

 

High-Margin, Low Operating Cost Structure that Generates Significant Levered Free Cash Flow. Our free cash flow is primarily attributable to our industry-leading operating margins and low operating costs. For the year-ended December 31, 2020 and pro forma for the reorganization transactions, we achieved a 72.2% operating margin, which we calculate by dividing our Adjusted EBITDAX by our revenues, which are inclusive of natural gas sales and realized gains and losses on commodity derivatives. In the year-ended December 31, 2020 and pro forma for the reorganization transactions, our lease operating expense of $0.20 per Mcf and our general and administrative expense of $0.05 per Mcf were among the lowest in our peer group. We have implemented several initiatives to enhance and manage our production in the region and reduce operating costs. In early 2015, we established a technologically advanced 24-hour automated command center from which we can remotely control most field-wide production operations from a single location, allowing us

 

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to remotely bring wells online and manage existing production. This level of automation reduces manpower needs and allows operators to focus on production efficiency, by, among other things, efficiently deploying labor through a centralized operating center. Moreover, we have significantly reduced our operating cost per unit by vertically integrating through the drilling and operation of our own produced water disposal wells. 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 gas treating solutions and improved maintenance programs. In drilling locations where our working interest exceeds 20%, we hold an approximate 83% working interest and operate over 90% of such wells. We believe this gives us a high degree of control over our development program, allowing us to be responsive to changes in the commodity price environment. Levered free cash flow is not a financial measure calculated in accordance with GAAP, but we believe it provides important information regarding our operating cash flow. “Prospectus Summary—Non-GAAP Financial Measures” above contains a description of levered free cash flow and a reconciliation to net cash provided by operating activities.

 

 

Close Proximity to Premium Markets and Ample Available Midstream Infrastructure. Our acreage position is in close proximity to premium markets and LNG facilities along the Gulf Coast, which results in lower and less volatile basis differentials and higher netbacks compared to other plays, including gas plays such as the Marcellus, Utica and those in the Rockies. As a result of these attractive takeaway and sales dynamics, our basis differentials have remained tightly banded since our inception, ranging from $0.01 to $0.26 per MMBtu; over this same period, basis differentials in Appalachia and the Rockies have ranged from $0.27 to $1.54 and $0.12 to $0.96 per MMBtu, respectively. We believe this allows producers in our basin to benefit from better unit economics. Low-cost legacy gathering infrastructure is in place across our acreage to support our development program. Our gathering cost for the year-ended December 31, 2020 was $0.31 per Mcfe, which compares favorably to $1.20 per Mcfe reported by publicly traded Appalachian-focused natural gas producers for the comparable period. Further, we are not party to any transportation contracts or similar commitments and our small amount of minimum volume commitments in our gathering contracts are well covered by current production volumes. Because we only produce dry gas, we have minimal cost to treat our gas to meet pipeline specifications, which may give us an economic advantage over wet gas plays during periods of low pricing for NGLs, as is currently taking place. Additionally, we do not have any of the emissions related to wet gas separation, storage or transportation.

 

 

Well Capitalized Balance Sheet that Provides Flexibility to Execute our Business Plan. Pro forma for this offering, we anticipate total net debt to Adjusted EBITDAX for the year-ended December 31, 2020 of approximately 2.0x, which would be among the lowest for publicly traded gas-focused upstream companies. Contemporaneously with the closing of this offering, we expect to enter into a new reserve-based lending facility led by Citibank. This facility is expected to have a total facility size of $750 million, a borrowing base of $350 million and available capacity of $316 million (after giving effect to $25 million of letters of credit to be issued at closing) based on projected as adjusted borrowings of approximately $9 million pro forma for this offering, resulting in projected liquidity of approximately $350 million as of December 31, 2020. Finally, we maintain an active hedge program and as of December 31, 2020 have hedged an average of 819 Bbtud, 492 Bbtud and 186 Bbtud for 2021, 2022 and 2023, respectively, at weighted average swap prices of $2.56 per MMBtu, $2.55 per MMBtu and $2.49 per MMBtu, respectively. Moreover, our Second Lien Term Loan requires us to have 70% of our total expected production hedged 24 months forward. We believe our balance sheet and hedge program provide ample liquidity in the event of an adverse commodity price environment to enable us to continue to generate levered free cash flow.

 

 

High Caliber and Experienced Management and Technical Team. Our senior management team has substantial experience in the Haynesville, as well as other premier North American resource plays, and has collectively operated large development programs that helped commercialize the Haynesville attained 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 experience. We believe our team’s expertise will continue to drive drilling, completion and operational improvements that result in improved recoveries and capital efficiency. Furthermore, our

 

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management team’s operational and financial discipline, as well as its extensive experience in leadership roles at public companies, gives us confidence in our ability to successfully manage a public company platform.

 

 

Leader in Environmental, Governance and Societal Responsibilities of the Natural Gas Production Sector. According to the EIA, since it began tracking CO2 emissions in 1990, the increased market share of natural gas in electrical power generation has been a leading driver in reducing energy sector CO2 emissions. Not only do we produce the fuel that is the cornerstone of this accomplishment, we invest significantly in the human capital, equipment and technology that allows us to produce natural gas safely, efficiently and with minimal related emissions. While emissions reductions is a focus for all of our employees, we have 5 employees specifically dedicated to environmental, health and safety matters, including emissions reductions. For example, our sustainability efforts include 100% green completions, 100% non-potable water usage, and 100% solar-generated wellsite electricity. Additionally, we have peer leading CO2 emissions at 2.6 mT per MBOE per well and methane intensity of only 0.014% of gas produced. Additionally, we and our employees make commitments of financial resources and time to assist underserved members in the communities where we operate and our employees live. Moreover, we value diversity in our work force, including our executive leadership team, which is relatively evenly split 60% / 40% between men and women.

Recent Developments

The outbreak of COVID-19 has significantly decreased the demand for hydrocarbons, particularly oil. As a result of the COVID-19 pandemic or other adverse public health developments, including voluntary and mandatory quarantines, travel restrictions, and other restrictions, our operations, and those of our subcontractors and customers, have experienced, and are anticipated to continue to experience, delays or disruptions and temporary suspensions of operations.

Reduction in oil and gas activity as a result of the COVID-19 pandemic has resulted in a decrease of associated gas production as fewer oil wells are drilled in the Permian Basin and other liquids-weighted basins, which has led to a contraction in domestic gas supply. Lower levels of supply have pushed current and forecasted gas prices higher, which has had a positive impact on our results of operations and cash flows. We expect that the reduction in drilling activity and rig counts may contribute to a shortage in the supply of natural gas in the future, which could result in higher gas prices. As a result, although gas prices were on average lower in 2020 than 2019, gas prices trended higher after the effects of the COVID-19 pandemic began to take hold and slow oil production towards the middle of 2020. As the factors described above reduced the supply of oil and gas, gas prices increased towards the end of 2020 as compared to the prices in the months prior to and during the beginning of the COVID-19 pandemic. For reference, the Henry Hub spot price for natural gas averaged $2.22 per MMBtu from August 2019 to March 2020, $1.72 per MMBtu from April 2020 to June 2020, $2.32 per MMBtu for the remaining six months of 2020 exiting the year at $2.90 per MMBtu in December 2020 and $2.69 per MMBtu from January 2021 to March 2021. However, because of our obligation to hedge 70% of our production for the next 24 months, we will be limited in the benefit we would otherwise realize from any such price increases. To the extent, however, that natural gas prices decrease, these lower 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 fund planned CapEx. Alternatively, natural gas prices may increase, which while increasing revenue and cash flows would result in significant losses being incurred on our derivatives.

We are taking precautions as an organization to protect our employees and community during this time. Vine has undertaken a number of proactive measures to reduce the spread of the virus and maintain the safety and health of its workforce, including, among other things, implementing comprehensive screening at operational bases throughout the organization.

 

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Concurrently, deterioration of production agreements between key global oil producers has led to an increase in supply. In addition to the effects of the COVID-19 pandemic, the confluence of these factors has caused significant volatility in oil and gas prices. In response, many producers in North America have significantly reduced drilling activity. The land rig count in North America fell from 771 in mid-March of 2020 to 244 in mid-August of 2020 and has recovered slightly to 373 by January of 2021.

The reduction in activity has resulted in a decrease of associated gas production as fewer oil wells are drilled in the Permian Basin and other liquids-weighted basins, which has led to a contraction in domestic gas supply. Lower levels of supply have pushed current and forecasted gas prices higher. We expect that the reduction in drilling activity and rig counts may contribute to a shortage in the supply of natural gas in the future, which could result in higher gas prices.

The significant reduction in drilling and completion activity has also reduced demand for oilfield services and providers of these services have reduced their pricing as a result. Coupled with the improvement in drilling and completion. cycle times achieved by our operational staff of approximately 14-19% in 2020, we have seen our well costs fall approximately 20% from an average of $1,521 per lateral foot in the first half of 2019 to $1,241 per lateral foot for the second half of, 2020, as illustrated in the table below. We expect, given the trajectory of demand reduction for oilfield services, along with our continued realization of operational efficiencies, that D&C costs will continue to decrease. In addition, we have undertaken several initiatives to optimize our operating cost structure in order to be well positioned to operate through periods of market and commodity price volatility. These actions include entering into term contracts with key vendors at attractive rates and continued operational efficiencies.

 

LOGO

Recent Debt Transactions

On December 30, 2020, we entered into the Second Lien Term Loan and used the proceeds, along with cash on hand, to repay the aggregate principal amount of loans outstanding under the Superpriority Facility in connection with the entry into the amendment to and extension of the RBL. The Second Lien Term Loan has a total facility size of $150 million and was fully drawn at closing.

The maturity of the RBL was extended to January 15, 2023 and availability under the facility was reduced from $350 million to $300 million and will reduce further on a quarterly basis to $100 million at December 31, 2022. Other than these quarterly reductions in availability, there are no borrowing base redeterminations. The pricing grid was increased by 1.00% to LIBOR + 2.50% to 3.50% based on utilization. We intend to use the net proceeds from this offering and borrowings under the New RBL to repay in full and terminate each of the RBL and the Brix Credit Facility.

The Second Lien Term Loan bears interest at a rate equal to LIBOR, with a floor of 0.75%, plus 8.75% per annum, payable monthly, and matures on the earlier to occur of (a) December 30, 2025 and (b) 90 days prior to the maturity of the 9.75% Notes or 8.75% Notes, to the extent specified amounts of such indebtedness remain outstanding. The Second Lien Term Loan is redeemable beginning June 30, 2022 at 102% of par value, stepping down to 101% of par value on June 30, 2023 and at par value on June 30, 2024 and thereafter.

The Second Lien Term Loan is secured on a junior lien basis by all of our assets and stock and the subsidiaries that secure the RBL.

 

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The Second Lien Term Loan provides for a quarterly Consolidated Total Net Leverage Ratio financial maintenance covenant of 4.00x, stepping down to 3.50x with the quarter ended June 30, 2021 and thereafter, similar to the RBL. The Second Lien Term Loan also contains customary incurrence-based covenants for issuances of this type, including restrictions on the incurrence of liens, indebtedness, asset dispositions, fundamental changes, transactions with affiliates, restricted payments and other customary covenants, along with the requirement to maintain liquidity of no less than $40 million, tested quarterly.

In December 2019, we entered into the Third Lien Credit Agreement with Blackstone Holdings Finance Co LLC, as administrative agent and collateral agent and certain other banks, financial institutions and other lending institutions from time to time party thereto. At that time, the Third Lien Credit Agreement was secured on a second lien basis, but was subordinated to a third lien in December 2020 in connection with the entry into the Second Lien Credit Agreement. The Third Lien Credit Agreement provides for a revolving credit facility in an amount up to $330 million, and bears interest at a rate of LIBOR plus 9.75% per annum. In addition, a commitment fee of 0.424% per annum is charged on the unutilized balance of the committed borrowing base and is included in interest expense. The Third Lien Credit Agreement matures on March 15, 2023. We expect to terminate our Third Lien Credit Facility in connection with this offering.

New RBL

Contemporaneously with the closing of this offering, we expect to enter into the New RBL led by Citibank. This facility is expected to have a total facility size of $750 million, a borrowing base of $350 million and available capacity of $316 million (after giving effect to approximately $25 million of letters of credit to be issued at closing) based on projected as adjusted borrowings of approximately $9 million pro forma for this offering, resulting in projected liquidity of approximately $350 million as of December 31, 2020. The New RBL will contain various conditions precedent, including the requirement to terminate the Third Lien Credit Agreement.

The New RBL will bear interest at a rate equal to LIBOR plus an additional margin, based on the percentage of the revolving commitment being utilized, ranging from 3.00% to 4.00%, with a LIBOR ‘floor’ of 0.50%. The New RBL matures on the earlier to occur of (a) 45 months after the closing of this offering, (b) 91 days prior to the maturity of the Second Lien Term Loan, to the extent any of such indebtedness remains outstanding, and (c) 91 days prior to the maturity of the 9.75% Notes or 8.75% Notes, to the extent specified amounts of such indebtedness remain outstanding. There will also be a commitment fee of 0.50% on the undrawn borrowing base amounts. The New RBL will be secured on a senior basis by substantially all of our assets and stock and guaranteed by the subsidiaries that secure and guarantee the Second Lien Term Loan.

The New RBL will provide for a quarterly Consolidated Total Net Leverage Ratio financial maintenance covenant of 3.25x beginning with the quarter ended June 30, 2021, a quarterly Current Ratio maintenance covenant of 1.00x beginning with the quarter ended June 30, 2021 and a $100 million weekly minimum liquidity covenant that is applicable starting 180 days prior to the maturity of the indebtedness under the Second Lien Term Loan, the 9.75% Notes or the 8.75% Notes, to the extent any of such indebtedness is outstanding. The New RBL will also contain customary incurrence-based covenants for facilities of this type, including restrictions on the incurrence of liens, indebtedness, asset dispositions, fundamental changes, transactions with affiliates, restricted payments and other customary covenants.

The credit agreement governing the New RBL will also contain customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control.

 

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2021 CapEx and Financing Activities

We expect our 2021 capital program to be approximately $340 to $350 million of which $310 to $320 million is allocated for D&C operations. The remaining $30 million of our capital program is designated for non-D&C items. We plan to fund our 2021 CapEx through cash flow from operations, proceeds from this offering and borrowings under our New RBL. Further, we intend to monitor conditions in the debt capital markets and may determine to issue long-term debt securities, including potentially in the near term, to fund a portion of our 2021 CapEx or refinance a portion of our existing indebtedness. We cannot predict with certainty the timing, amount and terms of any future issuances of any such debt securities.

Our Operations

Reserve Data and Presentation

The information with respect to our estimated reserves has been prepared in accordance with the rules and regulations of the SEC, except that the table which provides our reserves at “strip pricing” uses pricing based on NYMEX futures prices for natural gas as explained below. Our estimated proved reserves as of December 31, 2020 and December 31, 2019 are based on valuations prepared by our independent reserve engineer assuming a