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0000950123-17-000067.txt : 20170410 0000950123-17-000067.hdr.sgml : 20170410 20170106164517 ACCESSION NUMBER: 0000950123-17-000067 CONFORMED SUBMISSION TYPE: DRS PUBLIC DOCUMENT COUNT: 6 FILED AS OF DATE: 20170106 20170410 DATE AS OF CHANGE: 20170203 FILER: COMPANY DATA: COMPANY CONFORMED NAME: VINE RESOURCES INC. CENTRAL INDEX KEY: 0001693853 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 000000000 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: DRS SEC ACT: 1933 Act SEC FILE NUMBER: 377-01462 FILM NUMBER: 17514751 BUSINESS ADDRESS: STREET 1: 500 GRANITE PARKWAY, SUITE 550 CITY: PLANO STATE: TX ZIP: 75024 BUSINESS PHONE: (469) 606-0540 MAIL ADDRESS: STREET 1: 500 GRANITE PARKWAY, SUITE 550 CITY: PLANO STATE: TX ZIP: 75024 DRS 1 filename1.htm DRS

As confidentially submitted with the Securities and Exchange Commission on January 6, 2017

Registration No. 333-

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Confidential Draft Submission No. 1

Form S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

VINE RESOURCES INC.

(Exact name of registrant as specified in its charter)

Delaware

1311

81-4833927

(State or other jurisdiction of

incorporation or organization)

(Primary Standard Industrial

Classification Code Number)

(I.R.S. Employer

Identification No.)

5800 Granite Parkway, Suite 550

Plano, Texas 75024

(469) 606-0540

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

Eric D. Marsh

President and Chief Executive Officer

5800 Granite Parkway, Suite 550

Plano, Texas 75024

(469) 606-0540

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

Copies to:

Matthew R. Pacey

Justin F. Hoffman

Kirkland & Ellis LLP

600 Travis Street, Suite 3300

Houston, Texas 77002

(713) 835-3600

Alan Beck

Thomas G. Zentner

Vinson & Elkins L.L.P.

1001 Fannin, Suite 2500

Houston, Texas 77002

(713) 758-2222

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

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

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

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

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

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

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

CALCULATION OF REGISTRATION FEE



Title of Each Class of Securities to be Registered	Proposed Maximum Offering Price⁽¹⁾⁽²⁾	Amount of Registration Fee⁽³⁾
Common Stock, par value $0.01 per share	$	$

(1)	Includes common stock issuable upon exercise of the underwriters’ option to purchase additional common stock.

(2)	Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o) under the Securities Act of 1933, as amended (the “Securities Act”).

(3)	To be paid in connection with the initial filing of the registration statement.

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

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

Subject to Completion, dated , 2017

PROSPECTUS

Shares

LOGO

Vine Resources Inc.

Common Stock

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

We intend to apply to list our common stock on the New York Stock Exchange under the symbol “VRI.”

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

Investing in our common stock involves risks, including those described under “Risk Factors” beginning on page 17 of this prospectus.


	Per share	Total
Price to the public	$	$
Underwriting discounts and commissions	$	$
Proceeds to us (before expenses)	$	$

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

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

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

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

Joint Book-Running Managers

Prospectus dated , 2017

TABLE OF CONTENTS


	Page
PROSPECTUS SUMMARY		1
RISK FACTORS		17
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS		37
USE OF PROCEEDS		39
DIVIDEND POLICY		40
CAPITALIZATION		41
DILUTION		42
SELECTED HISTORICAL AND UNAUDITED PRO FORMA FINANCIAL INFORMATION		43
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		45
BUSINESS		64
MANAGEMENT		84
EXECUTIVE COMPENSATION		88
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT		89
CORPORATE REORGANIZATION		91
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS		92
DESCRIPTION OF CAPITAL STOCK		94
SHARES ELIGIBLE FOR FUTURE SALE		98
MATERIAL U.S. FEDERAL INCOME TAX CONSIDERATIONS FOR NON-U.S. HOLDERS		100
UNDERWRITING		104
LEGAL MATTERS		110
EXPERTS		110
WHERE YOU CAN FIND MORE INFORMATION		110
INDEX TO FINANCIAL STATEMENTS		F-1
ANNEX A: GLOSSARY OF OIL AND NATURAL GAS TERMS		A-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 common stock and seeking offers to buy shares of 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 common stock. Our business, financial condition, results of operations and prospects may have changed since that date. We will update this prospectus as required by law, including with respect to any material change affecting us or our business prior to the completion of this offering.

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

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

Commonly Used Defined Terms

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

•

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

•

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

•

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

•

“Management Member” refers to our individual officers and employees and other individuals who, together with Blackstone, initially formed Vine Oil & Gas LP;

•

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

•

“Shell” means affiliates of Royal Dutch Shell plc;

•

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

•

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

•

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

•

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

•

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

•

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

We have also included a glossary of some of the oil and natural gas industry terms used in this prospectus in Annex A to this prospectus.

Presentation of Financial and Operating Data

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

In addition, unless otherwise indicated, the reserve and operational data presented in this prospectus is that of our predecessor as of the dates and for the periods presented. Unless another date is specified or the context otherwise requires, all acreage, well count, hedging and drilling location data presented in this prospectus is as of September 30, 2016. Unless otherwise noted, references to production volumes refer to sales volumes reflective of our net interest.

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

Industry and Market Data

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

Trademarks and Trade Names

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

iii

PROSPECTUS SUMMARY

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

Unless otherwise indicated, the information presented in this prospectus assumes that the underwriters’ option to purchase additional shares of common stock is not exercised. Unless otherwise indicated, the estimated reserve volumes, estimated reserve values and EURs presented in this prospectus were prepared by our independent reserve engineer as of December 31, 2015 based on the SEC’s reserve pricing rule, as more fully described in “— Reserve and Operating Data.” Certain operational terms used in this prospectus are defined in the “Glossary of Oil and Natural Gas Terms” set forth in Annex A hereto, and “Commonly Used Defined Terms”.

Our Company

We are a pure play natural gas company focused solely on the development of natural gas properties in the stacked Haynesville and Mid-Bossier shale plays in the Haynesville Basin of Northwest Louisiana. The Haynesville and Mid-Bossier shales are among the highest quality, highest return dry gas resource plays in North America with approximately 489 Tcf of natural gas in place in the Haynesville play, according to the Oil & Gas Journal. The Mid-Bossier shale overlaps the Haynesville shale and, while earlier in its development life cycle than the Haynesville shale, has demonstrated similar well results and characteristics. Both plays demonstrate high-quality petrophysical characteristics, such as being over-pressured and having high porosity, permeability and thickness. Both plays also exhibit consistent and predictable geology and high EURs relative to D&C costs. In addition, due to significant development activity in the Haynesville Basin beginning in 2008, production and decline rates are predictable, and low-cost midstream infrastructure is currently in place with underutilized capacity. As a result of these factors, as well as our proximity to Henry Hub and other premium Gulf Coast markets, LNG export facilities and other end-users, we believe we benefit from low breakeven costs relative to other North American natural gas plays, such as those in Appalachia and the Rockies.

We first entered the Haynesville Basin in 2014 following our acquisition of assets from Shell, which we refer to as the Shell Acquisition, and as of December 31, 2016, have approximately 96,000 net surface acres in what we believe to be the core of the Haynesville and Mid-Bossier plays. Approximately 88% of our acreage is held by production, providing us with the flexibility to control the pace of development without the threat of lease expiration. Our assets are located almost entirely in Red River, DeSoto and Sabine parishes of Northwest Louisiana, which based on RS Energy Group, have consistently demonstrated higher EURs relative to D&C costs than the Haynesville and Mid-Bossier plays in Texas and other parishes in Louisiana. Over 60% of our acreage is prospective for dual-zone development, providing us with over gross horizontal drilling locations. Utilizing eight gross rigs and assuming six wells per 640-acre section, we have over years of development opportunities.

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

Gross Identified Drilling Locations⁽¹⁾

Standard Lateral⁽²⁾

Long Lateral⁽²⁾

Total

Haynesville

Mid-Bossier

Total

(1)	“Business — Our Operations — Drilling Locations” contains a description of our methodology used to determine gross identified drilling locations.

(2)	Our typical standard lateral is approximately 4,600 ft and our typical long lateral is approximately 7,500 ft. We classify wells with lateral lengths of less than 5,000 ft as standard laterals and greater than 5,000 ft as long laterals.

Substantially all of our leasehold acreage is held through at least one developed well per section, which maintains all the leasehold position in that section while preserving the ability to drill additional wells in that section. Our acreage has been well delineated by over 500 gross horizontal wells drilled on our acreage in Sabine, Red River and DeSoto parishes, providing us with confidence that our inventory is low-risk and repeatable and able to continue to generate consistent economic returns. Our production has grown at a compounded annual growth rate of approximately 45% from third quarter 2015 to third quarter 2016 as a result of the 32 wells we have brought online since the Shell Acquisition. For the nine months ended September 30, 2016, our average net daily production was 206 MMcfd. The following chart summarizes information regarding our production growth.

LOGO

(1)

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

American dry gas plays such as those in Appalachia and the Rockies. As illustrated in the chart below, our basis differentials have averaged less than $0.10/Mcf over the last two years. We believe these low basis differentials and our long-term access to underutilized midstream infrastructure support the efficient development of our reserves and should enhance our returns.

LOGO

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

•

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

•

managing production rates to preserve downhole pressure;

•

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

•

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

•

improving wellbore landing accuracy.

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

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

Our 2017 capital budget is approximately $270 million, which is almost entirely allocated to the development of 49 gross (20 net) operated wells and the development of 30 gross (13 net) non-operated wells. We believe we can execute our stated growth strategy in future periods with similar levels of CapEx.

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

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

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

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

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

Business Strategy

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

•

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

•

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

•

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

•

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

•

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

Business Strengths

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

•

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

•

More Than Years of High Quality, Low Risk, Drilling Inventory which is 88% Held by Production. Our drilling inventory as of December 31, 2016 consisted of more than gross identified drilling locations in both the Haynesville and Mid-Bossier shale plays, which included locations where we intend to utilize longer laterals. Assuming an eight gross drilling rig program, we expect our inventory life of undrilled wells to be greater than years. We have been able to consistently achieve higher returns on our drilled wells through the use of longer laterals in excess of 8,000 ft (significantly longer than a typical standard lateral of 4,600 ft). We also believe that we may be able to add horizontal drilling locations across the majority of our acreage position in the future through downspacing. In addition, we may have opportunities to extend the economic life of existing wells as they age through recompletions that utilize current completion technologies in existing wells that have been historically understimulated. We consider our inventory of drilling locations to be low risk because it is in areas where we (and other producers) have extensive drilling and production experience. Because approximately 88% of our acreage is held by production, we have more flexibility than many other operators to control the pace of development without the threat of lease expiration.

•

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

•

Close Proximity to Premium Markets through Available Midstream Infrastructure. Our acreage position is in close proximity to premium markets along the Gulf Coast, which results in low basis

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

•

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

•

Significant Liquidity and Financial Flexibility. Upon completion of this offering and the application of net proceeds therefrom, we will have approximately $ million of liquidity which includes availability under our RBL and cash on hand. Our RBL has a $350 million floor, which should provide us with sufficient liquidity to manage future commodity cycles. As we continue converting our large inventory of undeveloped drilling locations to producing wells, we expect our cash flow and borrowing base to grow, thereby further enhancing our liquidity and financial strength. We believe this ample liquidity should provide us with sufficient capital to grow our production, increase shareholder value and weather any future industry downturn. Our RBL, maturing in 2019, is our earliest stated debt maturity, but we can extend the maturity to 2021 through two payments of a 25 basis point extension fee. In addition, we have built a hedge portfolio that extends into 2018 to protect us against downward movements of natural gas pricing and to support the achievement of our stated growth objectives. We also have interest rate swaps that protect our cash flows on floating rate debt against LIBOR increases. We evaluate and utilize swaps and collars to provide certainty of cash flows and to establish a minimum targeted return on our invested capital.

Risk Factors

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

Corporate Reorganization

We were recently incorporated pursuant to the laws of Delaware as Vine Resources Inc. to become a holding company for Vine Oil & Gas LP. Vine Oil & Gas LP was formed as a Delaware limited partnership in 2014.

Pursuant to the terms of a corporate reorganization that will be completed simultaneously with the closing of this offering, all of the interests in Vine Oil & Gas LP will be exchanged for common stock of Vine Resources Inc. As a result of the reorganization, Vine Oil & Gas LP will become a wholly owned subsidiary of Vine Resources Inc. Upon completion of this offering, Blackstone and its affiliates will initially own a % indirect interest in us through Vine Investment LLC, based on an assumed initial public offering price of $ per share. In addition, members of our management will initially own an aggregate % interest in us through their interest in Vine Investment LLC. “Corporate Reorganization” contains additional information on our reorganization.

The following simplified diagrams indicate our current ownership structure and our ownership structure after giving effect to our reorganization and this offering based on an assumed initial public offering price of $ per share.

Simplified Current Ownership Structure

LOGO

Simplified Ownership Structure After Giving Effect to this Offering

LOGO

Our Principal Stockholders

Following the completion of this offering and our corporate reorganization, Blackstone and Management Members will in the aggregate own % of our common stock or % if the underwriters’ option to purchase additional shares is exercised in full. Vine Investment is controlled by Blackstone, our private equity sponsor.

Blackstone is one of the world’s leading investment firms. Blackstone’s asset management businesses, with over $360 billion in assets under management, include investment vehicles focused on private equity, real estate, public debt and equity, non-investment grade credit, real assets and secondary funds, all on a global basis. Blackstone has committed and invested $10.9 billion in more than 30 energy private equity transactions throughout the energy and natural resources value chain on a global basis, primarily through Blackstone Energy Partners L.P., Blackstone Energy Partners II L.P., Blackstone Capital Partners VI L.P. and Blackstone Capital Partners VII L.P. Investments in oil and natural gas assets represent a substantial portion of this activity and include leading independent onshore and offshore exploration and production companies in North America and globally.

Emerging Growth Company Status

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

•

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

•

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

•

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

•

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

•

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

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

•

the last day of the year in which we have $1.0 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 $1.0 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, and prior to the effectiveness of this registration statement we will determine whether to opt out of the extended transition period and, if we do opt out, we will adopt new or revised accounting standards on the relevant dates in which adoption of such standards is required for other public companies.

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. .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.

The Offering

Common stock offered by us

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

Common stock to be outstanding after the offering

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

Option to purchase additional shares

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

Use of proceeds

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

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

Dividend policy

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

Directed share program

At our request, the underwriters have reserved for sale at the initial public offering price up to % of the shares offered by this prospectus for our officers, directors, employees and certain other persons associated with us. We do not know if these persons will choose to purchase all or any portion of these reserved shares, but any purchases they do make will reduce the number of shares available to the general public. “Underwriting” contains additional information regarding the directed share program.

Risk factors

The “Risk Factors” section beginning on page 17 contains additional information that should be carefully read and considered before deciding to invest in our common stock.

Listing and trading symbol

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

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

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

Summary Historical and Unaudited Pro Forma Financial Information

The following table shows summary historical financial information of our predecessor, and summary unaudited pro forma financial information for the periods and as of the dates indicated.

The summary historical financial information at December 31, 2015, and for the year then ended, was derived from the audited historical financial statements of our predecessor included elsewhere in this prospectus.

The summary unaudited historical consolidated financial information as of September 30, 2016 and for the nine months ended September 30, 2016 and 2015 were derived from the unaudited historical financial statements of our predecessor included elsewhere in this prospectus. The summary unaudited historical financial information has been prepared on a consistent basis with the audited financial statements of our predecessor. In our opinion, such summary unaudited historical financial information reflects all adjustments (consisting of normal and recurring accruals) necessary to present our financial position for the periods presented. The results of operations for the unaudited historical periods are not necessarily indicative of the results that may be expected for the full year because of the impact of natural gas price fluctuations, production declines, the uncertainty of exploration and development drilling results and other factors.

The summary unaudited pro forma income statements for 2015 and the nine months ended September 30, 2016 have been prepared to give pro forma effect to (i) the reorganization transactions described under “Corporate Reorganization” and (ii) this offering and the application of the net proceeds from this offering as if they had been completed as of January 1, 2015. The summary unaudited pro forma balance sheet information has been prepared to give pro forma effect to those transactions as if they had been completed as of September 30, 2016. This information is subject to and gives effect to the assumptions and adjustments described in the notes accompanying the unaudited pro forma financial statements included elsewhere in this prospectus. The summary unaudited pro forma financial information is presented for informational purposes only and should not be considered indicative of actual results of operations that would have been achieved had the reorganization transactions and this offering been consummated on the dates indicated, and do not purport to be indicative of statements of financial position or results of operations as of any future date or for any future period.

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


	Predecessor									Vine Resources Inc. Pro Forma
	Nine Months Ended September 30,						Year Ended December 31, 2015			Nine Months Ended September 30, 2016	Year Ended December 31, 2015
	2016			2015			Year Ended December 31, 2015			Nine Months Ended September 30, 2016	Year Ended December 31, 2015
	(in thousands, except per share data)
Statement of operations information:
Revenue:
Natural gas sales	$	119,572		$	122,405		$	154,005		$	$
Realized gain on commodity derivatives		55,068			15,298			30,038
Unrealized gain (loss) on commodity derivatives		(83,226	)		77,592			91,008

Total Revenue		91,414			215,295			275,051
Operating expenses:
Lease operating		15,916			19,826			26,190
Gathering and treating		16,299			19,520			24,085
Production and ad valorem taxes		7,717			9,985			13,109
General and administrative		3,016			7,729			9,349
Depreciation, depletion and accretion		82,215			86,277			118,217
Exploration		1,915			2,084			2,056
Acquisition-related		—			182			207

Total operating expenses		127,078			145,603			193,213

Operating Income		(35,664	)		69,692			81,838

Interest expense, net		(67,450	)		(69,806	)		(87,911	)
Income tax provision		(168	)		—			—

Net Income	$	(103,282	)	$	(114	)	$	(6,073	)	$	$

Balance sheet information (end of period):
Cash and cash equivalents	$	45,664					$	15,367		$	$
Total natural gas properties, net		1,360,784						1,320,288
Total assets		1,529,708						1,522,510
Total debt		946,199						839,825
Total partners’ capital/stockholders’ equity		343,653						446,310
Net cash provided by (used in):
Operating activities	$	45,545		$	12,316		$	(27,026	)
Investing activities		(112,748	)		(72,913	)		(103,496	)
Financing activities		97,500			(48,090	)		29,910
Other financial information:
Adjusted EBITDAX⁽¹⁾	$	124,077		$	81,085		$	113,817		$	$
Earnings (loss) per share — basic
Earnings (loss) per share — diluted

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

Non-GAAP Financial Measure

We define Adjusted EBITDAX as net (loss) income before interest expense, income taxes, depreciation, depletion and amortization, exploration expense and impairment of oil and gas properties, unrealized earnings on derivatives, acquisition-related expenses, and other non-cash and non-recurring 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 or capital structure. We exclude the items listed above from net income in arriving at Adjusted EBITDAX because these amounts can vary substantially within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income determined in accordance with GAAP. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are reflected in Adjusted EBITDAX. Our presentation of Adjusted EBITDAX should not be construed as an inference that our results will be unaffected by unusual or non-recurring items. Our computations of Adjusted EBITDAX may not be identical to other similarly titled measures of other companies.

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


	Predecessor									Vine Resources Inc. Pro Forma
	Nine Months Ended September 30,						Year Ended December 31, 2015			Nine Months Ended September 30, 2016	Year Ended December 31, 2015
	2016			2015			Year Ended December 31, 2015			Nine Months Ended September 30, 2016	Year Ended December 31, 2015
	(in thousands)
Net income	$	(103,282	)	$	(114	)	$	(6,073	)	$	$
Interest expense		67,450			69,806			87,911
Income tax provision		168			—			—
Depletion, depreciation and accretion		82,215			86,277			118,217
Unrealized (gain) loss on commodity derivatives		83,226			(77,592	)		(91,008	)
Exploration		1,915			2,084			2,056
Non-cash G&A		(320	)		624			833
Non-cash volumetric and production adjustment to gas gathering liability		(7,295	)		—			1,881

Adjusted EBITDAX	$	124,077		$	81,085		$	113,817		$	$

Summary Reserve, Production and Operating Data

Summary Reserve Data

The following table summarizes estimated proved reserves as of December 31, 2015 based on a report prepared by Von Gonten, our independent reserve engineer. All of these reserve estimates were prepared in accordance with the SEC’s rule regarding reserve reporting currently in effect.

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


	At December 31, 2015
Estimated proved reserves:⁽¹⁾⁽²⁾
Natural gas (MMcf)		1,294,315
Total proved developed reserves (MMcf)		132,394
Percent proved developed		10	%
Total proved undeveloped reserves (MMcf)		1,161,921

(1)

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, 2015, the SEC Price Deck was $2.59/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. The average resulting price used as of December 31, 2015 was $2.50 per Mcf for natural gas.

(2)	Our reserve information reflects an assumed 30-year reserve life.

Production and Operating Data

The following table sets forth information regarding production, revenue and production costs and other operating information for the nine months ended September 30, 2016 and the year ended December 31, 2015. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” contains additional information regarding our production and operation data.


	Nine Months Ended September 30, 2016		Year Ended December 31, 2015
Production data:
Natural gas (MMcf)		56,373		63,362
Average net daily production (MMcfd)		206		174
Average sales prices (per Mcf):
Before realized effects of derivatives	$	2.12	$	2.43
After realized effects of derivatives	$	3.10	$	2.91
Average costs (per Mcf):
Lease operating	$	0.28	$	0.41
Gathering and treating	$	0.29	$	0.38
Production and ad valorem taxes	$	0.14	$	0.21
Depreciation, depletion and accretion	$	1.46	$	1.87
General and administrative	$	0.05	$	0.15

RISK FACTORS

Investing in our 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 common stock could decline due to any of these risks, and you may lose all or part of your investment.

Risks Related to Our Business

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

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

•

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

•

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

•

the level of global exploration and production;

•

the level of global inventories;

•

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

•

extent of natural gas production associated with increased oil production;

•

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

•

localized and global supply and demand fundamentals and transportation availability;

•

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

•

technological advances affecting energy consumption;

•

speculative trading in natural gas markets;

•

end-user conservation trends;

•

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

•

the price and availability of alternative fuels;

•

domestic, local and foreign governmental regulation and taxes; and

•

liquefied petroleum products supply and demand balances.

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

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

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

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

•

our proved reserves;

•

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

•

the prices at which our production is sold;

•

our ability to acquire, locate and produce new reserves;

•

the extent and levels of our derivative activities;

•

the levels of our operating expenses; and

•

our ability to access the capital markets.

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

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

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

•

effectively controlling downhole pressure;

•

landing and maintaining our wellbore in the desired drilling zone;

•

running our casing the entire length of the wellbore;

•

deploying tools and other equipment consistently downhole;

•

stimulating the formation with the planned number of stages; and

•

cleaning out the wellbore after final fracture stimulation.

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

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

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

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

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

•

reductions or sustained declines in natural gas prices;

•

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

•

geological formation irregularities and pressures

•

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

•

equipment failures, accidents or other unexpected operational events;

•

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

•

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

•

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

•

natural disasters including regional flooding;

•

availability of financing at acceptable terms; and

•

title issues.

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

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

Our gathering contracts require delivery of minimum volumes of gas for each annual contract period and require settlement payments for any shortfalls in the gathered volumes. The minimum volume commitments in our gathering contracts step down from 705,000 MMbtud in 2016 to 377,000 MMbtud in August 2019 and to 95,000 MMbtud in April 2020 before expiring in January 2021. As of September 30, 2016, our expected annual future obligation under these agreements is an undiscounted $75-80 million. The fees we are required to pay under these gathering contracts may have a material adverse effect on our liquidity and results of operations.

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

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

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

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

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

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

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

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

•

incur additional indebtedness;

•

sell assets;

•

make loans to or investments in others;

•

enter into mergers;

•

make certain payments;

•

hedge future production or interest rates;

•

incur liens;

•

pay dividends, and

•

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

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

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

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

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

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

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

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

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

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

Of our future drilling locations, we do not expect to operate of such locations, including which we expect will be operated by GEP. Our JOA with GEP provides for our ability to propose wells on

acreage operated by them; however, we still have lesser rights than we would have if we were the operator, and there is risk that our partners may have economic, business or legal interests or goals that are inconsistent with ours. Furthermore, the development activities conducted by GEP will depend on a number of factors that will be largely outside of our control, including:

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their desired timing for CapEx;

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their expertise and financial resources;

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their selection of technology and the application thereof;

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their production rate; and

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their management of the asset and its future value.

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

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

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

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

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

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

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

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

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

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

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

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

The credit risk of financial institutions could adversely affect us.

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

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

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

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

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

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

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

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

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

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

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

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

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

In addition, EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance in February 2014 addressing the performance of such activities using diesel fuels in those states where EPA is the permitting authority. In May 2014, the EPA issued an Advance Notice of Proposed Rulemaking to collect data on chemicals used in hydraulic fracturing operations under Section 8 of the Toxic Substances Control Act. Further, the EPA finalized regulations under the federal Clean Water Act (“CWA”) in June 2016 prohibiting wastewater discharges from hydraulic fracturing and certain other natural gas operations to publicly-owned wastewater treatment plants. Also, in June 2015, the EPA released its draft report on the potential impacts of hydraulic fracturing on drinking water resources. The EPA report concluded that hydraulic fracturing activities have not led to widespread, systemic impacts on drinking water resources in the United States, although there are above and below ground mechanisms by which hydraulic fracturing activities have the potential to impact drinking water resources. In addition, the federal Bureau of Land Management finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal and American Indian lands; however, the U.S. District Court of Wyoming struck down this rule in June 2016. An appeal of this decision is pending.

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

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

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perform ongoing assessments of pipeline integrity;

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

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improve data collection, integration and analysis;

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repair and remediate the pipeline as necessary; and

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implement preventive and mitigating actions.

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

The 2011 Pipeline Safety Act is the most recent federal legislation to amend the NGPSA and HLPSA pipeline safety laws, requiring increased safety measures for gas and hazardous liquids pipelines. Among other things, the 2011 Pipeline Safety Act directs the Secretary of Transportation to promulgate regulations relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation, testing to confirm the material strength of certain pipelines, and operator verification of records confirming the maximum allowable pressure of certain intrastate gas transmission pipelines. Changes to pipeline safety laws by Congress and regulations by PHMSA or states that result in more stringent or costly safety standards could have a significant adverse effect on us and similarly situated midstream operators.

For example, in March of 2015, PHMSA finalized new rules applicable to gas and hazardous liquid pipelines that, among other changes, impose new post-construction inspections, welding, gas component pressure testing requirements, as well as requirements for calculating pressure reductions for immediate repairs on liquid pipelines. Also, in October 2015, PHMSA proposed new regulations for hazardous liquid pipelines that would significantly extend and expand the reach of certain PHMSA integrity management requirements (i.e., periodic assessments, repairs and leak detection), regardless of the pipeline’s proximity to a high consequence area. The proposal also requires new reporting requirements for certain unregulated pipelines, including all gathering lines. More recently, in March 2016, pursuant to one of the requirements in 2011 Pipeline Safety Act, PHMSA published a proposed rulemaking that would expand integrity management requirements and impose new pressure testing requirements on currently regulated pipelines. The proposal would also significantly expand the regulation of gathering lines, subjecting previously unregulated pipelines to requirements regarding damage prevention, corrosion control, public education programs, maximum allowable operating pressure limits, and other requirements. The safety enhancement requirements and other provisions of the 2011 Pipeline Safety Act

as well as any implementation of PHMSA, rules thereunder could require us to install new or modified safety controls, pursue additional capital projects, or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in our incurring increased operating costs that could have a material adverse effect on our results of operations or financial position.

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

We are subject to risks associated with climate change.

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

In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of GHGs and a number of states have already taken legal measures to reduce emissions of GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. The adoption of legislation or regulatory programs to reduce emissions of GHGs could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.

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:

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

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abnormally pressured formations;

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

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fires, explosions and ruptures of pipelines;

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personal injuries and death;

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natural disasters; and

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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:

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injury or loss of life;

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

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pollution and other environmental damage;

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regulatory investigations and penalties;

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suspension of our operations; and

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repair and remediation costs.

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

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

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

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

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unexpected drilling conditions;

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title problems;

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pressure or lost circulation in formations;

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equipment failure or accidents;

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adverse weather conditions;

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compliance with environmental and other governmental or contractual requirements; and

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

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

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

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

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

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

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

Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing natural gas and securing trained personnel. Also, there is substantial competition for capital available for investment in our industry. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to pay more for productive natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel has increased may increase substantially in the future. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business.

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

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

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

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

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

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

Increases in interest rates could adversely affect our business.

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

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

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

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

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

The Dodd-Frank Act authorized the CFTC to establish rules and regulations setting position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic

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

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

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

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

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

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

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

Risks Related to the Offering and our Common Stock

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

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

•

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

•

comply with rules promulgated by the NYSE;

•

prepare and distribute periodic public reports;

•

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

•

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

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

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

Prior to this offering, there has not been a public market for our 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 the stock exchange on which we list our common stock or otherwise or how liquid that market might become. If an active trading market does not develop, anyone purchasing our common stock may have difficulty selling it. The initial public offering price for the 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 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 common stock. Securities class action litigation has often been instituted against companies following periods of volatility in the overall market and in the market price of a company’s securities. Such litigation, if instituted against us, could result in very substantial costs, divert our management’s attention and resources and harm our business, operating results and financial condition.

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

Immediately following the completion of this offering, Vine Investment will hold approximately % of our common stock. The Existing Owners will, through their ownership interests in Vine Investment, have the collective voting power to elect all of the members of our board of directors and thereby control our management and affairs. In addition, they will be able to determine the outcome of all matters requiring stockholder 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 in control of our company that could deprive our stockholders of an opportunity to receive a premium for their common stock as part of a sale of our company. The existence of significant stockholders 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 stockholders to approve transactions that they may deem to be in the best interests of our company.

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

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

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

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 common stock.

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

•

limitations on the removal of directors;

•

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

•

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

•

the requirement that the affirmative vote of holders representing at least 66 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 Vine Investment beneficially owns at least 50% 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.

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

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

We do not intend to pay dividends on our 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 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 common stock at a price greater than cost. There is no guarantee that the price of our common stock that will prevail in the market will ever exceed the price paid in this offering.

Future sales of our 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.

We may sell additional shares of common stock in subsequent public offerings. We may also issue additional shares of common stock or convertible securities. After the completion of this offering, we will have outstanding shares of common stock. This number includes shares that we are selling in this offering and shares if the underwriters’ option to purchase additional shares is fully exercised. Following the completion of this offering, assuming no exercise of the underwriters’ option to purchase additional shares, Vine Investment will own shares of our common stock, or approximately % of our total outstanding shares, all of which are restricted from immediate resale under the federal securities laws and are subject to the lock-up agreements with the underwriters described in “Underwriting,” but may be sold into the market in the future. Vine Investment will be party to a registration rights agreement with us which will require us to effect the registration of shares of our common stock under 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 — Stockholders’ Agreement” contains additional information.

In connection with this offering, we intend to file a registration statement with the SEC on Form S-8 providing for the registration of shares of our common stock issued or reserved for issuance under our LTIP. Subject to the satisfaction of vesting conditions, the expiration of lock-up agreements and the requirements of Rule 144, shares registered under the registration statement on Form S-8 will be available for resale immediately in the public market without restriction.

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 common stock will have on the market price of our common stock. Sales of substantial amounts of our 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 common stock.

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

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

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

Upon completion of this offering, Vine Investment will beneficially control a majority of the combined voting power of all classes of our outstanding voting stock. In connection with the completion of this offering, Vine Investment will enter into a stockholders’ agreement, pursuant to which the Existing Owners, through their ownership interests in Vine Investment, will agree to vote their shares of common stock in accordance with the terms thereof, including 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 those relating to accounting standards and disclosure about our executive compensation, that apply to other public companies.

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

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

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

The trading market for our 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 common stock or if our operating results do not meet their expectations, our stock price could decline.

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

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

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

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

Forward-looking statements may include statements about our:

•

business strategy;

•

reserves;

•

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

•

realized natural gas prices;

•

timing and amount of future production of natural gas;

•

hedging strategy and results;

•

future drilling plans;

•

competition and government regulations;

•

pending legal or environmental matters;

•

marketing of natural gas;

•

leasehold or business acquisitions;

•

general economic conditions;

•

credit markets;

•

uncertainty regarding our future operating results; and

•

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

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

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

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.

USE OF PROCEEDS

We intend to use $ million net proceeds from this offering to repay our outstanding indebtedness, with the balance of the net proceeds to be used for general corporate purposes, including funding a portion of our capital program. The debt instruments that are repaid will be determined by the repurchase prices we are able to negotiate with applicable lenders.

As of September 30, 2016, we had $247.5 million of outstanding borrowings under the RBL. The RBL matures November 2019, but in connection with a 25 basis point payment, is extendable by us for up to two consecutive years and bears interest at a variable rate based on LIBOR, plus an additional margin of 1.50% to 2.50% (based upon usage), which was 2% per annum at September 30, 2016.

The $400 million TLB matures in November 2021 and bears interest at LIBOR (with a 1% floor), plus an additional margin of 6.875%. The current rate was 7.875% per annum at September 30, 2016. The $350 million TLC matures in May 2022 and bears interest at LIBOR, plus an additional margin of 9.000%. The current rate was 10% per annum at September 30, 2016.

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

DIVIDEND POLICY

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

CAPITALIZATION

The following table sets forth our cash position and capitalization as of September 30, 2016:

•

on an actual basis for our predecessor; and

•

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

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


	As of September 30, 2016
	Actual		As Adjusted
	(In thousands, except share counts and par value)
Cash and cash equivalents	$	45,664	$

Long-term debt:
Superpriority Facility⁽¹⁾		—
RBL Credit Facility⁽²⁾		231,205
Term Loan B		381,555
Term Loan C		333,439

Total indebtedness	$	946,199	$

Partners’ capital/stockholders’ equity:
Partners’ capital		343,653
Common stock — $0.01 par value; no shares authorized, issued or outstanding, actual; shares authorized, shares issued and outstanding, as adjusted; shares authorized, shares issued and outstanding, pro forma		—
Additional paid in capital		—
Retained earnings		—

Total partners’ capital/stockholders’ equity	$	343,653	$

Total capitalization	$	1,289,852	$

(1)

We expect to enter into the Superpriority facility in January 2017. After giving effect to the consummation of the reorganization transactions described under “Corporate Reorganization,” the entry into the Superpriority facility and incurrence of borrowings thereunder and the application of the net proceeds of this offering, we expect to have $ million of available borrowing capacity under our RBL.

(2)

At September 30, 2016, we had outstanding borrowings under the RBL of $247.5 million and $37.5 million of outstanding letters of credit, which yield $65 million of remaining capacity under the RBL. After giving effect to the consummation of the reorganization transactions described under “Corporate Reorganization,” our incurrence of borrowings under our Superpriority and the application of the net proceeds of this offering, we expect to have $ million of available borrowing capacity under our RBL.

DILUTION

Purchasers of our common stock in this offering will experience immediate and substantial dilution in the net tangible book value per share of the common stock for accounting purposes. Our net tangible book value as of September 30, 2016, after giving effect to the transactions described under “Corporate Reorganization,” was $ , or $ per share. Pro forma net tangible book value per share is determined by dividing our pro forma tangible net worth (tangible assets less total liabilities) by the total number of outstanding shares of common stock that will be outstanding immediately prior to the closing of this offering after giving effect to our corporate reorganization. Assuming an IPO price of $ per share (the midpoint of the price range set forth on the cover page of this prospectus), after giving effect to the receipt of the estimated net proceeds (after deducting estimated underwriting discounts and commissions and estimated offering expenses), our adjusted pro forma net tangible book value as September 30, 2016 would have been approximately $ million, or $ per share. This represents an immediate increase in the net tangible book value of $ per share to our existing stockholders and an immediate dilution (i.e., the difference between the offering price and the adjusted pro forma net tangible book value after this offering) to new investors purchasing shares in this offering of $ per share. The following table illustrates the per share dilution to new investors purchasing shares in this offering:


IPO price per share		$
Pro forma net tangible book value per share as of September 30, 2016 (after giving effect to our corporate reorganization)	$
Increase per share attributable to new investors in this offering

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

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

A $1.00 change in the assumed initial public offering price of $ per share, which is the midpoint of the price range set forth on the cover page of this prospectus, would change our as adjusted pro forma net tangible book value per share after the offering by $ and change the dilution to new investors in this offering by $ per share, assuming the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same, after deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us. The following table summarizes, on an adjusted pro forma basis as of September 30, 2016, the total number of shares of common stock owned by existing stockholders and to be owned by new investors, the total consideration paid, and the average price per share paid by our existing stockholders and to be paid by new investors in this offering at our initial public offering price of $ per share, calculated before deduction of estimated underwriting discounts and commissions:

Shares Acquired

Total Consideration

Average
Price Per
Share

Amount
(in thousands)

Percent

Number

Percent

Vine Investment

New investors in this offering

Total

The above tables and discussion are based on the number of shares of our common stock to be outstanding as of the closing of this offering. The table does not reflect shares of common stock reserved for issuance under our long-term incentive plan, which we plan to adopt in connection with this offering. If the underwriters’ option to purchase additional shares is exercised in full, the number of shares held by new investors will be increased to , or approximately % of the total number of shares of common stock.

SELECTED HISTORICAL AND UNAUDITED PRO FORMA FINANCIAL INFORMATION

The following table shows selected historical financial information of our predecessor, and selected unaudited pro forma financial information for the periods and as of the dates indicated.

The selected historical financial information at December 31, 2015, and for the year then ended, was derived from the audited historical financial statements of our predecessor included elsewhere in this prospectus.

The selected unaudited historical consolidated financial information as of September 30, 2016 and for the nine months ended September 30, 2016 and 2015 were derived from the unaudited historical financial statements of our predecessor included elsewhere in this prospectus. The selected unaudited historical financial information has been prepared on a consistent basis with the audited financial statements of our predecessor. In our opinion, such selected unaudited historical financial information reflects all normal and recurring adjustments necessary to present our financial position for the periods presented. The results of operations for the unaudited historical periods are not necessarily indicative of the results that may be expected for the full year because of the impact of natural gas price fluctuations, production declines, the uncertainty of exploration and development drilling results and other factors.

The selected unaudited pro forma income statements for 2015 and the nine months ended September 30, 2016 have been prepared to give pro forma effect to (i) the reorganization transactions described under “Corporate Reorganization” and (ii) this offering and the application of the net proceeds from this offering as if they had been completed as of January 1, 2015. The selected unaudited pro forma balance sheet information has been prepared to give pro forma effect to those transactions as if they had been completed as of September 30, 2016. This information is subject to and gives effect to the assumptions and adjustments described in the notes accompanying the unaudited pro forma financial statements included elsewhere in this prospectus. The selected unaudited pro forma financial information is presented for informational purposes only and should not be considered indicative of actual results of operations that would have been achieved had the reorganization transactions and this offering been consummated on the dates indicated, and do not purport to be indicative of statements of financial position or results of operations as of any future date or for any future period.


	Predecessor									Vine Resources Inc. Pro Forma
	Nine Months Ended September 30,						Year Ended December 31, 2015			Nine Months Ended September 30, 2016	Year Ended December 31, 2015
	2016			2015			Year Ended December 31, 2015			Nine Months Ended September 30, 2016	Year Ended December 31, 2015
	(in thousands, except per share data)
Statement of operations information:
Revenue:
Natural gas sales	$	119,572		$	122,405		$	154,005		$	$
Realized gain on commodity derivatives		55,068			15,298			30,038
Unrealized gain (loss) on commodity derivatives		(83,226	)		77,592			91,008

Total Revenue		91,414			215,295			275,051
Operating expenses:
Lease operating		15,916			19,826			26,190
Gathering and treating		16,299			19,520			24,085
Production and ad valorem taxes		7,717			9,985			13,109
General and administrative		3,016			7,729			9,349
Depreciation, depletion and accretion		82,215			86,277			118,217
Exploration		1,915			2,084			2,056
Acquisition-related		—			182			207

Total operating expenses		127,078			145,603			193,213

Operating Income		(35,664	)		69,692			81,838

Interest expense, net		(67,450	)		(69,806	)		(87,911	)
Income tax provision		(168	)		—			—

Net Income	$	(103,282	)	$	(114	)	$	(6,073	)	$	$

Balance sheet information (end of period):
Cash and cash equivalents	$	45,664					$	15,367		$	$
Total natural gas properties, net		1,360,784						1,320,288
Total assets		1,529,708						1,522,510
Total debt		946,199						839,825
Total partners’ capital/stockholders’ equity		343,653						446,310
Net cash provided by (used in):
Operating activities	$	45,545		$	12,316		$	(27,026	)
Investing activities		(112,748	)		(72,913	)		(103,496	)
Financing activities		97,500			(48,090	)		29,910
Other financial information:
Adjusted EBITDAX⁽¹⁾	$	124,077		$	81,085		$	113,817		$	$
Earnings (loss) per share — basic
Earnings (loss) per share — diluted

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

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

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

Overview

We are a pure play natural gas company focused on the development of natural gas properties in the stacked Haynesville and Mid-Bossier shale plays in the Haynesville Basin of Northwest Louisiana. We first entered the Haynesville Basin in 2014 following our acquisition of assets from Shell which we refer to as the Shell Acquisition, and as of December 31, 2016, have approximately 96,000 net surface acres in what we believe to be the core of the Haynesville and Mid-Bossier plays. Approximately 88% of our acreage is held by production, providing us with the flexibility to control the pace of development without the threat of lease expiration. Our assets are located almost entirely in Red River, DeSoto and Sabine parishes of Northwest Louisiana. Over 60% of our acreage is prospective for dual-zone development, providing us with over horizontal drilling locations. Utilizing eight gross rigs and assuming six wells per 640-acre section, we have over years of development opportunities. For the nine months ended September 30, 2016, our average net daily production was 206 MMcfd.

Market Conditions and Operational Trends

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

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

Additionally, the oil and gas industry is subject to a number of operational trends, some of which are particularly prominent in the Haynesville Basin. Oil and gas companies are increasingly utilizing new techniques

to lower D&C costs and increase the efficiency of operations, including using more proppant per lateral foot, increasing use of longer laterals, increased stages per lateral foot and increased automation to reduce drilling time and costs. Furthermore, our industry, and the Haynesville Basin in particular, has benefited from reduced oilfield service pricing over the past two years as demand for such services has waned in response to lower oil and gas prices.

Evaluating Our Operations

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

•

reserve and production levels;

•

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

•

lease operating expenses;

•

Adjusted EBITDAX; and

•

D&C costs and overall CapEx levels.

Production Levels and Sources of Revenue

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

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

The following table presents our average realized commodity prices:


	Nine Months Ended September 30,						Year Ended December 31, 2015
	2015			2016			Year Ended December 31, 2015
NYMEX Henry Hub High	$	3.19		$	2.92		$	3.19
NYMEX Henry Hub Low	$	2.52		$	1.71		$	2.03
Differential to Average NYMEX Henry Hub⁽¹⁾	$	(0.08	)	$	(0.06	)	$	(0.09	)

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

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

Principal Components of our Cost Structure

Lease operating expense. Lease operating expenses (“LOE”) are the costs incurred in the operation of producing properties, including workover costs. Expenses for utilities, direct labor, chemicals, water disposal, materials and supplies comprise the most significant portion of our LOE. Certain items, such as direct labor and

materials and supplies, generally remain relatively fixed across broad production volume ranges, but can fluctuate depending on activities performed during a specific period. For instance, repairs to our well equipment or surface facilities result in increased LOE in periods during which they are performed. Certain of our operating cost components are variable and change in correlation to our production levels. For example, the disposal of water produced usually increases in connection with increased production. Also, we monitor our LOE in absolute dollar terms and on a per Mcf basis to determine if any wells or properties should be shut in, repaired or recompleted.

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

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

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

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

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

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

Adjusted EBITDAX

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

D&C Costs and CapEx

We evaluate our D&C costs by considering the absolute cost to drill and complete a well, as well as the cost on a per lateral foot basis. Moreover, we evaluate the levels of reserves developed per dollar spent in connection with that development to measure our capital efficiency. So long as these metrics continue to meet our expectations, we expect our overall CapEx levels to support an approximate 8 gross drilling rig program. Our capital efficiency is one of the key metrics we use to manage our business.

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

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

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

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

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

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

Results of Operations

For the nine months ended September 30, 2016 (the “2016 Period”), we had the following financial and operational highlights:

•

brought online 24 new gross wells (12 net);

•

grew production by 19% compared to the nine months ended September 30, 2015 (the “2015 Period”);

•

lowered unit lease operating expenses by $0.13 per Mcf compared to 2015; and

•

generated $43 million of incremental EBITDAX.

The following table sets forth selected operating data for the 2016 Period compared to the 2015 Period.


	For the Nine Months Ended September 30,
	2016					2015
	(in thousands, except per Mcf)
Production:
Total (MMcf)		56,373					47,248
Average Daily (MMcfd)		206					173
				Per Mcf					Per Mcf
Revenue:				Per Mcf					Per Mcf
Natural gas sales	$	119,572		$	2.12	$	122,405		$	2.59
Realized gain (loss) on commodity derivatives		55,068			0.98		15,298			0.32
Unrealized gain (loss) on commodity derivatives		(83,226	)				77,592

Total revenue	$	91,414				$	215,295
Operating Expenses:
Lease operating	$	15,916		$	0.28		19,826		$	0.42
Gathering and treating		16,299			0.29		19,520			0.41
Production and ad valorem taxes		7,717			0.14		9,985			0.21
General and administrative		3,016			0.05		7,729			0.16
Depletion, depreciation and accretion		82,215			1.46		86,277			1.83
Exploration		1,915					2,084
Acquisition-related		—					182

Total operating expenses	$	127,078				$	145,603

Operating income (loss)	$	(35,664	)			$	69,692

Interest expense	$	(67,450	)			$	(69,806	)
Income tax provision		(168	)				—

Net income (loss)	$	(103,282	)			$	(114	)

Interest expense	$	67,450				$	69,806
Income tax provision		168					—
Depreciation, depletion and accretion		82,215					86,277
Unrealized (gain) loss on commodity derivatives		83,226					(77,592	)
Exploration		1,915					2,084
Non-cash G&A		(320	)				624
Non-cash volumetric and production adjustment to gas gathering liability		(7,295	)				—

Adjusted EBITDAX⁽¹⁾	$	124,077				$	81,085

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

Revenue

Natural Gas Sales and Realized Commodity Derivatives

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


2015 Period	$	137,703
Volume increases		20,267
Price decreases		(23,100	)
Realized derivative increase		39,770

2016 Period	$	174,640

As a result of reduced natural gas prices, natural gas sales for the 2016 Period decreased from the 2015 Period despite a 17% increase in production. The 2016 Period increase in natural gas volume was primarily the result of additional producing wells, as well as production increases from ongoing well maintenance projects and effects of passive fracturing stimulations.

Since commodity prices were below the weighted average floor prices of our portfolio, we realized a gain on our natural gas derivatives during the 2016 Period. The average prices of natural gas in our commodity derivative contracts were $3.466 per MMBtu and $3.484 per MMBtu for the 2016 Period and 2015 Period, respectively. Additionally, our total volumes hedged for the 2016 Period was 86% higher than total volumes hedged for the 2015 Period.

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

Unrealized Gain (Loss) On Commodity Derivatives

We had an unrealized loss on our commodity derivative contracts for the 2016 Period primarily due to the increase in NYMEX natural gas futures prices at September 30, 2016 relative to December 31, 2015. The unrealized gain for the 2015 Period was primarily due to the decrease in NYMEX natural gas futures prices at September 30, 2015 relative to December 31, 2014. For example, the 2017 futures price was $3.09 at September 30, 2016, up from $2.79 at December 31, 2015, causing the value of our derivative portfolio to decline.

Operating Expenses

Lease Operating

LOE for the 2016 Period decreased in the aggregate from the 2015 Period primarily due to negotiated price reductions under strategic alliances with our key chemical and water disposal vendors, cost reductions on GEP-operated properties and overall service cost reductions due to the reduced capital activity in the Haynesville Basin. On a unit basis, LOE decreased 30%, which was attributable to the factors described above as well as the impact of fixed LOE over a greater amount of production.

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

Gathering and Treating

The following summarizes our gathering and treating expense:


	For the Nine Months Ended September 30,
	2016				2015
	(in thousands)		Per Mcf		(in thousands)		Per Mcf
Gathering and treating	$	11,427	$	0.20	$	14,328	$	0.30
Fuel		4,083		0.07		4,116		0.09
Other		789		0.02		1,076		0.02

Total	$	16,299	$	0.29	$	19,520	$	0.41

Gathering and treating expense on a per unit basis for the 2016 Period compared to the 2015 Period decreased $0.16 due to non-cash adjustments to our gathering shortfall liability, offset by $0.03 due to increased interconnect charges associated with new wells coming online and $0.01 due to an annual price increase.

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

Production and Ad Valorem Taxes

The following summarizes our production taxes and ad valorem taxes:


	For the Nine Months Ended September 30,
	2016				2015
	(in thousands)		Per Mcf		(in thousands)		Per Mcf
Production taxes	$	4,052	$	0.07	$	6,854	$	0.14
Ad valorem taxes		3,665		0.07		3,131		0.07

Total	$	7,717	$	0.14	$	9,985	$	0.21

Production taxes for the 2016 Period decreased 41% relative to the 2015 Period, which was primarily attributable to lower severance tax rates in Louisiana. Louisiana resets its severance tax rate annually in July, based on prevailing gas prices in the preceding year. We currently benefit from a severance tax holiday program, enacted by 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 wells reach payout. Each July, the state of Louisiana resets its severance tax rates, and in July 2015 it lowered the prevailing rate for wells that do not receive exemptions from $0.163 to $0.158 and again to $0.098 in July 2016.

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

General and Administrative

The following summarizes our G&A expense:


	For the Nine Months Ended September 30,
	2016			2015
	(in thousands)
Wages and benefits	$	9,725		$	5,737
Professional services		1,586			2,649
Other		5,327			4,918

Total gross G&A expense	$	16,638		$	13,304
Less:
Allocations to Affiliates		(3,867	)		—
Gain on inventory		(944	)		—
Recoveries		(8,811	)		(5,575	)

Net G&A expense	$	3,016		$	7,729

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

We expect our future G&A to increase as we grow our staffing to accommodate higher production volumes and expand our technical capabilities. Moreover, following our IPO, we would expect material cost increases associated with being a public company.

Depletion, Depreciation and Accretion

The following summarizes our DD&A expense:


	For the Nine Months Ended September 30,
	2016				2015
	(in thousands)		Per Mcf		(in thousands)		Per Mcf
Depletion	$	70,536	$	1.25	$	73,554	$	1.56
Depreciation		1,257		0.02		353		0.01
Accretion		10,422		0.19		12,370		0.26

Total	$	82,215	$	1.46	$	86,277	$	1.83

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

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

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

Exploration

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

Interest Expense

The following summarizes our interest expense:


	For the Nine Months Ended September 30,
	2016			2015
	(in thousands)
Interest costs on debt outstanding	$	57,891		$	54,600
Plus:
Fees paid on letters of credit outstanding		756			382
Non-cash interest		13,409			20,218

Total interest costs incurred	$	72,056		$	75,200
Less:
Interest capitalized		(4,606	)		(5,394	)

Interest expense	$	67,450		$	69,806

Non-cash interest expense includes amortization of deferred financing costs, original issue discount and unrealized loss on interest rate derivatives, which swapped $750 million of our variable-rate debt based on one-month LIBOR into fixed rate debt. “— Derivative Activities” below contains additional information regarding our interest rate derivatives. The 2015 Period includes a $6.2 million write-off of original issue discount and deferred debt issuance costs associated with a pay down on the TLB of $100 million.

Capital Resources and Liquidity

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

Our future success in growing reserves and production will be highly dependent on the availability of capital resources. For 2017, we plan to invest $250 million of our $270 million CapEx budget for drilling and completion, which represents a 50% increase over our 2016 CapEx. As of September 30, 2016, we had incurred approximately $112.8 million of our expected aggregate $180 million 2016 CapEx forecast.

After giving effect to this offering, we expect to fund our CapEx through 2017 with cash generated by operations, cash on hand and available capacity under our RBL. Following the completion of this offering, we estimate that we will have cash on hand of $ million and availability under our RBL of approximately $ million. Our capital forecast, including the amount, timing and allocation of CapEx, is largely discretionary and within our control but may change. If natural gas prices decline to levels below our acceptable return levels, or our costs increase to levels above our acceptable return levels, we could choose to defer a significant portion of our forecasted CapEx until later periods to achieve the desired balance between sources and uses of liquidity and prioritize capital projects that we believe will accomplish our strategic objectives. Any reduction in our CapEx could have the effect of delaying or limiting our development program, which would negatively impact our ability to grow production and operating cash flow.

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

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

Cash Flow Activity

Our financial condition and results of operations, including our liquidity and profitability, are significantly affected by the prices that we realize for our natural gas and the volumes of natural gas that we produce. Natural gas is a commodity product for which established trading markets exist. Accordingly, our operating cash flows are 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 do 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 in “— Capital Resources and Liquidity”.

The following summarizes our cash flow activity:


	For the Nine Months Ended September 30
	2016			2015
	(in thousands)
Operating cash flow	$	45,545		$	12,316
Investing cash flow		(112,748	)		(72,913	)
Financing cash flow		97,500			(48,090	)
Net change in cash	$	30,297		$	(108,687	)

Operating Cash Flow

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

Investing and Financing Cash Flow

The change in investing cash flow for the 2016 Period compared to the 2015 Period was attributable to the increase in our 2016 capital budget compared to 2015. In executing that plan, our capital spending exceeded our operating cash flows by a greater percentage in the 2016 Period compared to the 2015 Period. This resulted in the need to increase our borrowings under the RBL. For the 2015 Period, we drew a net amount of $72.0 million on our RBL to repay $100.0 million of TLB principal and fund $20.0 million in modification fees. We utilized cash on hand to fund the excess for these transactions.

Our CapEx in the 2016 Period includes our net costs of joint participation with GEP in an average four gross rig program compared with an average one gross rig program in the 2015 Period. During 2017, we expect our CapEx to be $270 million, which we expect will require additional RBL borrowings of approximately $90 million after giving effect to the use of proceeds of this offering. During January 2017, we expect to complete the placement of the $150 million Superpriority, which we will use the estimated proceeds of $ million to repay outstanding borrowings under the RBL, thereby creating additional liquidity. On a pro forma basis, we estimate our liquidity to be approximately $180 million at December 31, 2016. Assuming a similar capital program beyond 2017, we would expect that growth in production and revenue will cause our deficit spending to decrease until 2019, when we expect to be free cash flow positive.

Derivative Activities

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

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

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

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

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

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


Period	Natural Gas Volume (MMBtud)		Weighted Average Swap Price
Fourth Quarter 2016		210,000	$	3.44
First Quarter of 2017		232,500	$	3.40
Second Quarter of 2017		262,500	$	3.38
Third Quarter of 2017		312,500	$	3.36
Fourth Quarter of 2017		332,500	$	3.38
First Quarter of 2018		240,000	$	3.33
Second Quarter of 2018		120,000	$	3.17

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

The following summarizes our interest rate derivatives as of September 30, 2016:

Notional Principal

Amount

Fixed Rate

Effective Date

Maturity Date

$400.0 million

1.784

June 30, 2015

June 30, 2019

$350.0 million

1.495

July 6, 2015

June 30, 2018

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

Debt Agreements

Superpriority Facility

In January 2017, we expect to enter into an incremental agreement evidencing the Superpriority facility. Upon the execution of the Superpriority agreement, we will draw $150 million aggregate principal, and in connection therewith, we will incur discounts and up-front fees totaling $ million. We intend to use the estimated proceeds to reduce our outstanding RBL borrowings by $ million. Concurrent with the incurrence of the Superpriority, we also plan to amend the RBL to reflect the changes associated with the priority position of the Superpriority described below. Such amendment does not require the consent of the other RBL lenders.

The Superpriority will have a face amount of $150 million which is not subject to redetermination. The terms of the Superpriority will closely resemble the RBL in respect of interest rate, covenants, restrictions, maturity and extensions. Collateral provisions will be similar to the RBL, however the Superpriority will have a priority in right of repayment and to the proceeds of collateral in the event of default. The Superpriority also will have priority in the event of disposal of properties that collateralize the facility and places limitations on certain types of restricted payments.

RBL Facility

On November 25, 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.

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

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

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

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

The RBL bears interest based on LIBOR plus an additional margin, based on the percentage of the borrowing base being utilized, ranging from 1.50% to 2.50%. There is also a commitment fee that ranges between 0.375% and 0.50% on the undrawn borrowing base amounts. The RBL may be prepaid without a premium. Interest on outstanding facility debt was LIBOR+2.0% at September 30, 2016.

Term Loan B

On November 25, 2014, in connection with the Shell Acquisition, we entered into the TLB with Morgan Stanley Senior Funding, Inc., as Administrative Agent and Collateral Agent and the banks, financial institutions and other lending institutions from time to time party thereto. The TLB was amended in January 2015.

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

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

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

Term Loan C

On November 25, 2014, in connection with the Shell Acquisition, we entered into the TLC with Morgan Stanley Senior Funding, Inc., as Administrative Agent and Collateral Agent and the banks, financial institutions and other lending institutions from time to time party thereto. The TLC was amended in January 2015.

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

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

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

Contractual Obligations

The following summarizes our contractual obligations as of December 31, 2015:


	For the year Ended December 31, 2015
	(Thousands of Dollars)
Contractual Obligations⁽¹⁾	2016		2017		2018		2019		2020		Thereafter		Total
RBL⁽²⁾	$	4,112	$	4,978	$	5,605	$	6,542	$	6,818	$	156,439	$	184,493
TLB		31,500		32,746		34,418		35,218		35,955		433,061		602,898
TLC		35,000		36,090		37,553		38,253		38,898		405,732		591,527
Gathering Commitment⁽³⁾		72,014		74,589		77,164		67,426		21,449		869		313,511
LC Fees⁽⁴⁾		887		934		1,260		1,335		1,404		1,047		6,868
Lease Obligations		599		609		598		592		298		—		2,696

Total	$	144,111	$	149,946	$	156,598	$	149,367	$	104,823	$	997,147	$	1,701,992

(1)	We are party to four drilling rig contracts, none of which had an original term beyond one year, and as a result, are not reflected in this table.

(2)	The RBL matures in November 2019; however, we have the option to extend its maturity for two one-year terms by payment of a 25 basis point fee for each extension. The information included in the table assumes each extension occurs.

(3)

Our gathering contracts require fees to be paid on minimum volumes of committed gas regardless of throughput. The minimum volume commitments in our gathering contracts step down from 705,000 MMbtud in 2016 to 377,000 MMbtud in August 2019 and to 95,000 MMbtud in April 2020 before expiring in January 2021.

(4)	Related to $37 million in outstanding letters of credit outstanding as of December 31, 2015.

Critical Accounting Estimates

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

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

Gathering Liability

Policy Description

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

Judgments and Assumptions

Our obligation for the gathering contracts was initially measured at fair value as of the acquisition date and represented the expected volume shortfall over the remaining contract period. The fair value was determined

using estimated future development pace, future production volumes, future inflation factors, and our weighted average cost of capital. We recognize accretion expense for the impact of increasing the discounted liability to its estimated settlement value. At each reporting period, the difference, if any, between the estimated payments at inception and actual current contract period payments expected to be required are recorded to gathering and treating expense. If our development plan changes or if production deviates from our initial estimation, the amount of the adjustments to the gas gathering liability recorded to gathering and treating expense could be material. For example, if our forecasted volumes were to decrease, we would need to increase the liability via additional gathering and treating expense. Conversely, if our forecasted volumes were to increase, we would reduce the liability via a reduction to gathering and treating expense.

Natural Gas Reserves

Policy Description

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

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

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

Judgments and Assumptions

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

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

Successful Efforts Method of Accounting for Natural Gas Properties

Policy Description

We use the successful efforts method of accounting for natural gas activities. Costs to acquire mineral interests in natural gas properties are capitalized as unproved properties whereas costs to drill and equip

wells that result in proved reserves are capitalized as proved properties. Costs to drill wells that do not identify proved reserves as well as geological and geophysical costs are expensed.

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

Judgments and Assumptions

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

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

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

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

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

Derivatives

Policy Description

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

Our derivatives are not designated as hedges for accounting purposes. Accordingly, changes in their fair value are recognized in income in the period of change. As the derivative cash flows are considered an

integral part of our operations, they are classified as cash flows from operating activities. All derivatives instruments are recognized as either an asset or liability on the balance sheet measured at their fair value determined by reference to published future market prices and interest rates.

Judgments and Assumptions

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

Asset Retirement Obligations

Policy Description

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

Judgments and Assumptions

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

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

JOBS Act

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

Recent Accounting Pronouncements

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

Internal Controls and Procedures

We are not currently required to comply with the SEC’s rules implementing Section 404 of SOX, and are therefore not required to make a formal assessment of the effectiveness of our internal control over financial reporting for that purpose. Upon becoming a public company, we will be required to comply with the SEC’s rules implementing Section 302 of SOX, which will require certifications in our quarterly and annual reports

and provision of an annual management report on the effectiveness of our internal control over financial reporting. We will not be required to have our independent registered accounting firm make its first assessment of our internal control over financial reporting under Section 404 until our first annual report subsequent to our ceasing to be an “emerging growth company”.

Quantitative and Qualitative Disclosure about Market Risk

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

Commodity Price Risk and Hedges

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

A $0.10 per Mcf change in our realized natural gas price would have resulted in an $0.8 million change in our natural gas revenue for the 2016 Period, after giving effect to our commodity derivative contracts. Our sole sources of cash are our production of natural gas and the related hedging.

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

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

Interest Rate Risk

At September 30, 2016, we had almost $1 billion of debt outstanding which bears interest at a floating rate, including $750 million of term loans with a LIBOR floor of 1%.

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

Counterparty and Customer Credit Risk

Our derivatives expose us to credit risk in the event of nonperformance by counterparties. While we do not require our counterparties to our derivatives to post collateral, our counterparties have principally been lenders

under the RBL, which allows for right-of-offset in the event that they do not perform. Recently, we have been utilizing other counterparties who have investment grade credit ratings and whom we will continue to evaluate creditworthiness over the terms of the derivatives.

Our principal exposures to credit risk are through receivables resulting from joint interest receivables and receivables from the sale of our natural gas production. The inability or failure of our significant customers to 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 2015, we had one customer that exceeded 10% of total natural gas revenue. We do not believe the loss of any single purchaser would materially impact our operating results because of gas fungibility, the depth of Gulf Coast markets and presence of numerous purchasers.

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

Inflation

Inflation in the U.S. has been relatively low in recent years and did not have a material impact on our results of operations for the 2016 Period. 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.

BUSINESS

Our Company

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

Standard Lateral⁽²⁾

Long Lateral⁽²⁾

Total

Gross Identified Drilling Locations⁽¹⁾

Haynesville

Mid-Bossier

Total

(1)	“— Our Operations — Drilling Locations” contains a description of our methodology used to determine gross identified drilling locations.

(2)	Our typical standard lateral is approximately 4,600 ft and our typical long lateral is approximately 7,500 ft. We classify wells with lateral lengths of less than 5,000 ft as standard laterals and greater than 5,000 ft as long laterals.

LOGO

(1)

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

LOGO

•

managing production rates to preserve downhole pressure;

•

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

•

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

•

improving wellbore landing accuracy.

Business Strategy

•

approximately 25% from the fourth quarter of 2015 through the third quarter of 2016. These cycle time reductions contribute to lower well costs because approximately 60% of our drilling costs are directly correlated to the number of days required to drill a well. We have also employed enhanced completion techniques (through longer horizontal wellbore laterals, increased frac stages, more proppant loading and reduced cluster spacing) and other drilling-related efficiencies (through dual-zone bi-directional well pads, well spacing and development patterns) to yield increased EURs. Certain of these measures also help increase our capital efficiency by allowing us to develop more reserves per lateral foot while also reducing the number of vertical wellbores and associated development, equipping and abandonment costs.

•

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

•

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

Business Strengths

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

•

Close Proximity to Premium Markets through Available Midstream Infrastructure. Our acreage position is in close proximity to premium markets along the Gulf Coast, which results in low basis differentials as compared to other plays, such as the Marcellus, Utica, Permian and Rockies. We believe this allows producers in our basin to benefit from better unit economics and to level the playing field with respect to our marginally higher Haynesville well costs when compared to other basins. Low-cost legacy gathering infrastructure with a design capacity of 2.8 Bcfd is in place across our acreage to support our development program with minimal incremental capital. We are not party to any transportation contracts or similar commitments and the minimum volume commitments in our gathering contracts materially decrease in August 2019 and further decrease in April 2020 before they completely expire in January 2021, at which point the gathering rate in place through 2025 at

approximately $0.31 per MMbtu is highly competitive. Because our only production is dry gas, we also have minimal cost to process our gas to meet pipeline specifications, which, based on current natural gas liquids pricing, may give us an economic advantage as compared to wet gas plays.

•

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

future drilling activity. The basin experienced a peak production of 10.6 Bcfd in 2011, compared to 6.0 Bcfd in December of 2016, according to the U.S. EIA. Furthermore, the basin is well positioned to capitalize on the emergence of LNG and other export facilities and increasing demand from a southern migration of the U.S. population, the growing petrochemical capacity in the Gulf Coast region and the retirement of certain coal-fired electricity generation.

Our Operations

Reserve Data

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

Reserves Presentation

Our estimated proved reserves as of December 31, 2015 are based on valuations prepared by our independent reserve engineer assuming a 30-year reserve life. Copies of the summary reports of our reserve engineers as of December 31, 2015 are filed as exhibits to the registration statement of which this prospectus forms a part. “Preparation of Reserve Estimates” contains additional definitions of proved reserves and the technologies and economic data used in their estimation.

The following table summarizes our estimated proved reserves based on SEC pricing.


	At December 31, 2015⁽¹⁾
Estimated Proved Reserves:
Total natural gas proved reserves (MMcf)		1,294,315
Total natural gas proved developed reserves (MMcf)		132,394
Percent proved developed		10	%
Total natural gas proved undeveloped reserves (MMcf)		1,161,921
Percent proved undeveloped		90	%

(1)

Proved Undeveloped Reserves

The following table summarizes the changes in our proved undeveloped reserves (in MMcf):


Proved undeveloped reserves at December 31, 2014	743,955
Conversions into proved developed reserves	(20,414	)
Extensions and discoveries	390,072
Revisions	(19,841	)

Acquisitions of reserves	68,149

Proved undeveloped reserves at December 31, 2015	1,161,921

Extensions and discoveries represent extensions to reserves attributable to additional gross locations to be developed in 2020 and reflect updated future rig count. Our acquisitions of reserves is attributable to additional leasing, which gave rise to incremental locations in the Haynesville. During 2015, we incurred costs of approximately $54.2 million to convert 20,414 MMcf of proved undeveloped reserves to proved developed reserves.

As of December 31, 2015, we had no proved undeveloped reserves that were forecasted to be developed beyond five years from the date of their initial recognition.

Estimated future development costs relating to the development of our proved undeveloped reserves at December 31, 2015 are approximately $1.5 billion over the next five years, which we expect to finance through operating cash flow and available capacity under our RBL. Based on our reserve report as of December 31, 2016, we had and identified drilling locations in the Haynesville Shale and Mid-Bossier Shale, respectively, associated with proved undeveloped reserves. “Risk Factors” contains additional information regarding the risks associated with development of our reserves.

Preparation of Reserve Estimates

Our reserve estimates as of December 31, 2015 included in this prospectus are based on a report prepared by Von Gonten, our independent reserve engineer, in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC in effect at such time. A copy of the report is included as an exhibit to the registration statement containing this prospectus. Von Gonten provides a variety of services to the oil and gas industry, including field studies, oil and gas reserve estimations, appraisals of oil and gas properties and reserve reports for their clients. Von Gonten is a Texas Registered Engineering Firm.

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

Internal Controls

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

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

reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs.

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

Drilling Locations

We have 453 gross proved undeveloped horizontal drilling locations as of December 31, 2015. On our acreage, we have over estimated drilling locations based on our well spacing assumptions and upon the evaluation of our horizontal drilling results and those of other operators in our area, combined with our interpretation of available geologic and engineering data. In addition, in evaluating the prospectivity of our horizontal acreage, we have reviewed available open-hole and mud log evaluations, core analysis and drill cuttings analysis. The drilling locations that we actually drill will depend on the review of prospectively available geologic and engineering data and on availability of capital, regulatory approvals, commodity prices, costs, results drilling other wells and other factors. Any drilling activities we are able to conduct on these identified locations may not be successful and may not result in our ability to add additional proved reserves to our existing proved reserves. Further, to the extent the drilling locations are associated with acreage operated by others, we may be dependent upon their capital allocation, development pace and development success.

Where our combined acreage with GEP and the geologic data support it, we plan to drill wells with longer lateral lengths of up to 10,000 ft, but in our 2015 reserve report we only reflect wells with lateral lengths of up to 7,500 ft. As of December 31, 2016, we had identified approximately long laterals as part of our more than locations. Our horizontal drilling location count generally implies six wells per 640 acre section in the primary target play, with six wells per 640 acre section in the secondary play, if applicable, based on standard lateral lengths.

Production, Revenue, Price and Production Costs

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


	Nine Months Ended September 30, 2016		Year Ended December 31, 2015
Production data:
Natural gas (MMcf)		56,373		63,362
Average daily combined production (MMcfd)		206		174
Average sales prices (per Mcf):
Before effects of derivatives	$	2.12	$	2.43
After effects of realized derivatives	$	3.10	$	2.91
Costs (per Mcf):
Lease operating	$	0.28	$	0.41
Gathering and treating	$	0.29	$	0.38
Production and ad valorem taxes	$	0.14	$	0.21
Depreciation, depletion and accretion	$	1.46	$	1.87
General and administrative	$	0.05	$	0.15

Productive Wells

The following table sets forth information regarding our productive wells as of September 30, 2016:


	Productive Wells				Average Working Interest
	Gross		Net		Average Working Interest
Natural gas wells operated by Vine or GEP		418		212		51	%
Natural gas wells operated by others		41		4		9	%
Total		459		216		47	%

Acreage

The following table sets forth certain information regarding our acreage at September 30, 2016.


Developed acres held by production			84,993
Undeveloped acres not held by production			10,912

Total			95,905

Undeveloped Acreage Expirations

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


	Acres
2016		2,500
2017		6,145
2018		327
2019		43
2020 and thereafter		1,897
Total		10,912

Drilling Activity

The following table summarizes drilling activity:


	For the Nine Months Ended September 30, 2016				Year Ended December 31, 2015
	Productive Wells				Productive Wells
	Gross		Net		Gross		Net
Mid-Bossier:
Development		2.0		1.0		1.0		0.5
Exploratory		—		—		—		—

Total		2.0		1.0		1.0		0.5

Haynesville Shale:
Development		29.0		14.7		12.0		6.5
Exploratory		—		—		—		—

Total		31.0		15.7		13.0		7.0

As of September 30, 2016, we had four wells that were actively being drilled, three wells that had been partially drilled but not being actively drilled, three wells that have been fully drilled but awaiting completion and nine wells that were in process of being actively completed.

Major Customers

In the 2016 Period, we sold over 60% of natural gas production to affiliates of Royal Dutch Shell and 10% to Enterprise Products Operating LLC. During such period, no other purchaser accounted for more than 10% of our revenue. Although a substantial portion of production is purchased by these customers, we do not believe the loss of them or any other party would have a material adverse effect on our business, as other customers or markets would be accessible to us. However, there is no guarantee that we will be able to enter into an agreement with a new customer on terms as favorable.

Title to Properties

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

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

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

Seasonality

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

Competition

Our industry is intensely competitive, and we compete with other companies that have greater resources than we do. Many of these companies not only explore for and produce natural gas, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for properties or define, evaluate, bid for and purchase a greater number of properties than we can. They may also be able to expend greater resources to attract qualified personnel. In addition, these companies may have a greater ability to conduct exploration during periods of low natural gas market prices. Our larger competitors may be able to absorb the existing and evolved laws and regulations more easily than we can,

which would adversely affect our competitiveness. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in eventually bidding or consummating transactions.

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

Regulation of the Natural Gas Industry

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

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

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

Regulation of Production

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

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

Regulation of Transportation and Sales of Natural Gas

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

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

Beginning in 1992, FERC issued a series of orders to implement its open access policies. As a result, the interstate pipelines’ traditional role as wholesalers of natural gas has been greatly reduced and replaced by a structure under which pipelines provide transportation and storage service on an open access basis to others who buy and sell natural gas. Although FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.

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

On December 26, 2007, FERC issued Order 704, a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing. Under Order 704, wholesale buyers and sellers of more than 2.2 million MMBtus of physical natural gas in the previous calendar year, including natural gas gatherers and marketers, are now required to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or

may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order 704. Order 704 also requires market participants to indicate whether they report prices to any index publishers, and if so, whether their reporting complies with FERC’s policy statement on price reporting.

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

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

Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress.

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

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

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

Regulation of Environmental and Occupational Safety and Health Matters

General

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

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

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

Hazardous Substances and Wastes

CERCLA, also known as the “Superfund law,” imposes cleanup obligations, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to be responsible for the release

of a “hazardous substance” into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that transported or disposed or arranged for the transport or disposal of the hazardous substances found at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA and any state analogs may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file corresponding common law claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. While petroleum and crude oil fractions are not considered hazardous substances under CERCLA and its analog because of the so-called “petroleum exclusion,” adulterated petroleum products containing other hazardous substances have been treated as hazardous substances in the past.

We also generate solid and hazardous wastes that may be subject to the requirements of the Resource Conservation and Recovery Act, as amended (“RCRA”), and comparable state statutes. RCRA regulates the generation, storage, treatment, transport and disposal of wastes. RCRA specifically excludes from the definition of hazardous waste “drilling fluids, produced waters and other wastes associated with the exploration, development or production of crude oil, natural gas or geothermal energy.” However, legislation has been proposed from time to time and environmental groups have filed lawsuits that, if successful, could result in the reclassification of certain natural gas exploration and production wastes as “hazardous wastes,” which would make such wastes subject to much more stringent handling, disposal and clean-up requirements. For example, in May 2016, several environmental groups filed a lawsuit in the U.S. District Court for the District of Columbia that seeks to compel the EPA to review and, if necessary, revise its regulations regarding existing exemptions for exploration and production related wastes. Any such changes in applicable laws and regulations could have a material adverse effect on its CapEx and operating expenses. Moreover, some ordinary industrial wastes which we generate, such as paint wastes, waste solvents, laboratory wastes and waste oils, may be regulated as hazardous wastes if they are determined to have hazardous characteristics.

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

Water Discharges

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

The process for obtaining permits has the potential to delay our operations. Spill prevention, control and countermeasure requirements of federal laws require appropriate containment berms and similar structures to

help prevent the contamination of navigable waters by a petroleum hydrocarbon tank spill, rupture or leak. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. Federal and state regulatory agencies can impose administrative, civil and criminal penalties as well as other enforcement mechanisms for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.

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

Hydraulic Fracturing

Hydraulic fracturing is an essential and common practice in the natural gas industry used to stimulate production of natural gas and/or oil from low permeability subsurface rock formations. Hydraulic fracturing involves using water, sand, and certain chemicals to fracture the hydrocarbon-bearing rock formation to allow flow of hydrocarbons into the wellbore. We regularly perform hydraulic fracturing as part of our operations. While hydraulic fracturing has historically been regulated by state oil and natural gas commissions, the practice has become increasingly controversial in certain parts of the country, resulting in increased scrutiny and regulation. For example, the EPA has asserted federal regulatory authority over certain hydraulic-fracturing activities under the SDWA involving the use of diesel fuels and published permitting guidance in February 2014 addressing the use of diesel in fracturing operations. Also, in May 2014 the EPA issued an Advanced Notice of Proposed Rulemaking to collect data on chemicals used in hydraulic fracturing operations under Section 8 of the Toxic Substances Control Act. Further, the EPA finalized regulations under the CWA in June 2016 prohibiting wastewater discharges from hydraulic fracturing and certain other natural gas operations to publicly owned wastewater treatment plants. Also, in June 2015, the EPA released its draft report on the potential impacts of hydraulic fracturing on drinking water resources. The EPA report concluded that hydraulic fracturing activities have not led to widespread, systemic impacts on drinking water resources in the United States, although there are above and below ground mechanisms by which hydraulic fracturing activities have the potential to impact drinking water resources. The draft report is expected to be finalized after a public comment period and a formal review by the EPA’s Science Advisory Board. Finally, the U.S. Department of the Interior’s Bureau of Land Management (“BLM”) finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal and American Indian lands, though the U.S. District Court of Wyoming struck down this rule in June 2016. An appeal of this decision is pending.

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

If hydraulic fracturing is further regulated at the federal state, or local level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment

requirements and also to attendant permitting delays and potential increases in costs. Such changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential legislation or regulation governing hydraulic fracturing, and any of the above risks could impair our ability to manage our business and have a material adverse effect on our operations, cash flows and financial position.

Air Emissions

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

Climate Change

In response to findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the CAA that, among other things, establish prevention of significant deterioration (“PSD”) pre-construction and Title V operating permit reviews for certain large stationary sources. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established on a case-by-case basis. EPA rulemakings related to GHG emissions could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and gas production sources in the United States on an annual basis, which include certain of our operations. Recently, in December 2015, the EPA finalized rules that added new sources to the scope of the greenhouse gases monitoring and reporting rule. These new sources include gathering and boosting facilities as well as completions and workovers from hydraulically fractured oil wells. The revisions also include the addition of well identification reporting requirements for certain facilities. Furthermore, in May 2016, the EPA finalized rules that establish new controls for emissions of methane from new, modified or reconstructed sources in the oil and natural gas source category, including production, processing, transmission and storage activities. The rule includes first-time standards to address emissions of methane from equipment and processes across the source category, including hydraulically fractured oil and natural gas well completions. The EPA has also announced that it intends to impose methane emission standards for existing sources as well but, to date, has not yet issued a proposal. The BLM has also proposed rules governing the emission of methane from oil and gas activities on federal lands. Several states,

including Louisiana, are pursuing similar measures to regulate emissions of methane from new and existing sources within the oil and natural gas source category. Compliance with these rules will require enhanced record-keeping practices, the purchase of new equipment, such as optical gas imaging instruments to detect leaks, and increased frequency of maintenance and repair activities to address emissions leakage. These rules will also likely require additional personnel time to support these activities or the engagement of third party contractors to assist with and verify compliance. These new and proposed rules could result in increased compliance costs on our operations.

While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. Although it is not possible at this time to estimate how potential future laws or regulations addressing GHG emissions would impact our business, either directly or indirectly, any future federal, state or local laws or implementing regulations that may be adopted to address GHG emissions in areas where we operate could require us or our customers to incur increased operating costs. Regulation of GHGs could also result in a reduction in demand for and production of oil and natural gas, which would result in a decrease in demand for our services and adversely affect our financial position and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. If any such effects were to occur, they could adversely affect or delay demand for the oil or natural gas produced by our customers or otherwise cause us to incur significant costs in preparing for or responding to those effects.

National Environmental Policy Act

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

Endangered Species Act and Migratory Bird Treaty Act

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

Worker Health and Safety

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

Employees

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

Legal Proceedings

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

MANAGEMENT

Directors and Executive Officers

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


Name	Age		Title
Eric D. Marsh		57	President and Chief Executive Officer, Director
John C. Regan		47	Chief Financial Officer
Brian D. Dutton		41	Chief Accounting Officer
Angelo G. Acconcia		37	Director
Gary D. Levin		34	Director
Adam M. Jenkins		33	Director

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

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

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

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

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

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

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

Board of Directors

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

Our board of directors has determined that Messrs. are independent under NYSE listing standards.

In connection with this offering, we will enter into a stockholders’ agreement with Vine Investment, which is expected to provide Vine Investment with the right to designate a certain number of nominees to our board of directors so long as it and its affiliates collectively beneficially own more than % of the outstanding shares of our common stock. Our board of directors will be divided into three classes of directors, with each class as equal in number as possible, serving staggered three-year terms, and such directors will be removable only for “cause.”

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

Status as a Controlled Company

Because Vine Investment will own a majority of our outstanding common stock following the completion of this offering, we expect to be a controlled company under NYSE corporate governance standards. A controlled company need not comply with the applicable corporate governance rules that its board of directors have a majority of independent directors and independent compensation and nominating and governance committees.

Notwithstanding our status as a controlled company, we will remain subject to the applicable corporate governance standard that requires us to have an audit committee composed entirely of independent directors. As a result, our audit committee must have at least one independent director by the date our common stock is listed on the NYSE, as applicable, at least two independent directors within 90 days of the listing date and at least three independent directors within one year of the listing date.

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

Committees of the Board of Directors

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

Audit Committee

We will establish an audit committee prior to the completion of this offering. Following completion of this offering, our audit committee will consist of , with serving as chairman. As required by the rules of the SEC and listing standards of the NYSE, the audit committee will consist solely of independent directors, subject to the phase-in exceptions. SEC rules also require that a public company disclose whether or not its audit committee has an “audit committee financial expert” which is defined as a person whose experience yields the attributes outlined in such rules. We anticipate that at least one of our independent directors will satisfy this definition.

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

Compensation Committee

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

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

Nominating and Corporate Governance Committee

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

If and when we are no longer a “controlled company” within the meaning of the NYSE corporate governance standards, we will be required to establish a nominating and corporate governance committee shortly after the completion of this offering. We anticipate that such a nominating and corporate governance committee would consist of three directors who will be “independent” under the rules of the SEC. This committee would

identify, evaluate and recommend qualified nominees to serve on our board of directors, develop and oversee our internal corporate governance processes and maintain a management succession plan. Upon formation of a compensation committee, we would expect to adopt a nominating and corporate governance committee charter defining the committee’s primary duties in a manner consistent with the rules of the SEC and applicable stock exchange or market standards.

Compensation Committee Interlocks and Insider Participation

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

Code of Business Conduct and Ethics

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

Corporate Governance Guidelines

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

EXECUTIVE COMPENSATION

We are currently considered an “emerging growth company,” within the meaning of the Securities Act, for purposes of the SEC’s executive compensation disclosure rules. In accordance with such rules, we are required to provide a Summary Compensation Table and an Outstanding Equity Awards at Fiscal Year End Table, as well as limited narrative disclosures regarding executive compensation for our last completed year. Further, our reporting requirements extend only to our “named executive officers,” who are the individuals who served as our principal executive officer and our two other most highly compensated officers who served as executive officers during the last completed year. For 2015, our named executive officers were:


Name		Principal Position
Eric D. Marsh		Chief Executive Officer
John C. Regan		Chief Financial Officer

Summary Compensation Table

The following table summarizes, with respect to our named executive officers, information relating to compensation earned for services rendered in all capacities during the year ended December 31, 2015.

Name

Year

Salary
($)

Bonus
($)

All Other
Compensation
($)

Total
($)

Eric D. Marsh

2015

John C. Regan

2015

Outstanding Equity Awards at 2015 Year-End

The following table reflects information regarding outstanding management incentive awards held by our Named Executive Officers as of December 31, 2015.

Vested
Units (#)

Unvested
Units (#)

Exercise
Price ($)

Expiration
Date

Eric D. Marsh

N/A

John C. Regan

N/A

Director Compensation

Vine Resources Inc., the issuer of common stock in this offering, was formed in December 2016. No obligations with respect to compensation for directors have been accrued or paid for any periods prior to such formation date or following such formation date. Individuals serving on the board of managers of Vine Oil & Gas LP, our predecessor, did not receive any compensation for their services on such boards of managers during 2016.

Going forward, we believe that attracting and retaining qualified disinterested directors will be critical to our future growth and governance. We also believe that a portion of the total compensation package for our non-employee directors should be equity-based to align the interest of directors with our stockholders.

Long-Term Incentive Plan

Prior to the completion of this offering, we anticipate that our board of directors will adopt a long-term incentive plan pursuant to which our employees and directors (and those of our subsidiaries), including our named executive officers, will be eligible to receive awards. We anticipate that the long-term incentive plan (our “LTIP”) will provide for the grant of stock options, stock appreciation rights, restricted stock, restricted stock units, stock awards, dividend equivalents, other stock-based awards, cash awards, substitute awards, and performance awards intended to align the interests of participants with those of our stockholders.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth the beneficial ownership of our common stock that, upon the consummation of our corporate reorganization in connection with the completion of this offering, will be owned by:

•

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

•

each of our Named Executive Officers;

•

each member of our board of directors; and

•

all of our directors and executive officers as a group.

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

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

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

Shares Beneficially
Owned Before this
Offering

Shares
Offered
Hereby

Shares Beneficially
Owned After this
Offering (Assuming No
Exercise of the
Underwriters’ Option to
Purchase Additional
Shares)

Shares Beneficially
Owned After this
Offering (Assuming the
Underwriters’ Option to
Purchase Additional
Shares

Name of Beneficial Owner⁽¹⁾

Number

Percentage

Number

Percentage

Number

Percentage

5% Shareholders:

Vine Investment⁽²⁾

Named Executive Officers and Directors:

Eric D. Marsh

John C. Regan

Angelo G. Acconcia⁽³⁾

Gary D. Levin⁽³⁾

Adam M. Jenkins⁽³⁾

Executive Officers and Directors as a Group ( persons)

*	Less than 1%.

(1)

Does not include common stock that may be purchased in the directed share program. “Underwriting — Directed Share Program” contains additional information regarding the directed share program. In addition, does not include an aggregate of shares of restricted stock (based on the midpoint of the price range set forth on the cover page of this prospectus) that our board of directors intends to grant to our executive officers and directors in connection with the completion of this offering.

(2)

Vine Investment is owned by Vine Oil & Gas Holdings LLC (“Holdings”) and Vintner Resources, LLC, which is controlled by Eric Marsh, our Chief Executive Officer. Holdings is owned by Blackstone Capital Partners VI-Q L.P. (“BCP VI-Q”), Blackstone Energy Partners Q L.P. (“BEP Q”), Blackstone Family Investment Partnership VI-ESC L.P. (“BFIP VI”), Blackstone Energy Family Investment Partnership ESC L.P. (“BEFIP ESC”) and Blackstone Energy Family Investment Partnership SMD L.P. (“BEFIP SMD”). The general partner of BCP VI-Q is Blackstone Management Associates VI L.L.C. The sole member of Blackstone Management Associates VI L.L.C. is BMA VI L.L.C. The general partner of BEP Q is Blackstone Energy Management Associates L.L.C. The sole member of

Blackstone Energy Management Associates L.L.C. is Blackstone EMA L.L.C. The general partner of BFIP VI is BCP VI Side-by-Side GP L.L.C. The general partner of BEFIP ESC is BEP Side-by-Side GP L.L.C. The general partner of BEFIP SMD is Blackstone Family GP L.L.C., which is in turn, wholly-owned by Blackstone’s senior managing directors and controlled by its founder, Stephen A. Schwarzman. Blackstone Holdings III L.P. is the managing member of each of BMA VI L.L.C. and Blackstone EMA L.L.C. and the sole member of each of BCP VI Side-by-Side GP L.L.C. and BEP Side-by-Side GP L.L.C. The general partner of Blackstone Holdings III L.P. is Blackstone Holdings III GP L.P. The general partner of Blackstone Holdings III GP L.P. is Blackstone Holdings III GP Management L.L.C. The sole member of Blackstone Holdings III GP Management L.L.C. is The Blackstone Group L.P. The general partner of The Blackstone Group L.P. is Blackstone Group Management L.L.C. Blackstone Group Management L.L.C. is wholly-owned by Blackstone’s senior managing directors and controlled by its founder, Stephen A. Schwarzman. Each of the Blackstone entities described in this footnote and Stephen A. Schwarzman (other than to the extent it or he directly holds securities as described herein) may be deemed to beneficially own the shares directly or indirectly controlled by such Blackstone entities or him, but each disclaims beneficial ownership of such shares. The address of each of the foregoing entities is 345 Park Avenue, 31st Floor, New York, New York 10154, provided that the address for Vintner Resources is 891 Foxglove Trail, Fairview, Texas 75069.

(3)	Messrs. Acconcia, Levin and Jenkins are each employees of Blackstone, but each disclaims beneficial ownership of the shares beneficially owned by Blackstone. The address for Messrs. Acconcia, Levin and Jenkins is c/o The Blackstone Group L.P., 345 Park Avenue, New York, New York 10154.

CORPORATE REORGANIZATION

Vine Resources Inc. is a Delaware corporation that was formed for the purpose of making this offering. Pursuant to the terms of a corporate reorganization that will be completed concurrently with the closing of this offering, Vine Resources Inc. will acquire all of the outstanding limited partner interests in Vine Oil & Gas LP in exchange for shares of Vine Resources Inc.’s common stock. Therefore, investors in this offering will only receive, and this prospectus only describes the offering of, shares of common stock of Vine Resources Inc. Our business will continue to be conducted through Vine Oil & Gas LP, as a wholly owned subsidiary of Vine Resources Inc. “Description of Capital Stock” contains additional information regarding the terms of our certificate of incorporation and bylaws as will be in effect upon the closing of this offering.

Pursuant to the reorganization, all of the interests in Vine Oil & Gas LP, which are currently held by the Existing Owners, will be exchanged for interests in Vine Investment LLC. Vine Investment LLC will then contribute all of the limited partner interests in Vine Oil & Gas LP to Vine Resources Inc. in exchange for shares of common stock in Vine Resources Inc. In connection with our corporate reorganization, we expect to record a net deferred tax liability of approximately $ million for differences between the book and tax bases of our assets and liabilities and a corresponding income tax expense.

Contemporaneously with Vine Oil & Gas LP becoming a wholly owned subsidiary of Vine Resources Inc., the limited partnership agreement of Vine Oil & Gas LP will be amended and restated to terminate certain rights and obligations of its limited partners.

We refer to (i) the reorganization pursuant to which the outstanding limited partner interests of Vine Oil & Gas LP will be contributed to Vine Investment LLC, (ii) the acquisition by Vine Resources Inc. of all of the limited partnership interests of Vine Oil & Gas LP in exchange for shares of Vine Resources Inc.’s common stock, (iii) the effectiveness of the limited liability company agreement of Vine Investment LLC and (iv) the consummation of the other related transactions collectively as our “corporate reorganization.”

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Corporate Reorganization

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

Historical Transactions with Affiliates

Management Services Agreement

During 2016, our predecessor entered into a management services agreement (the “MSA”) with its wholly-owned subsidiary, Vine Management Services LLC (“VMS”), pursuant to which VMS agreed to provide personnel to manage and develop our predecessors’ assets and conduct certain operational, technical and administrative services. The MSA is evergreen but may be terminated under certain circumstances, including upon our predecessor’s failure to perform any of its material obligations. The management fee under the MSA is determined based on the direct and allocable portion of VMS’ actual out-of-pocket expenses attributable to our predecessor (plus 2%) and is paid semiannually. The management fee for the 2016 Period was $0.1 million, which is included within general and administrative expenses in our predecessor’s audited consolidated statements of operations. VMS also provides management services to other entities which are controlled by Blackstone and members of management, as described in “—Other Historical Arrangements” below.

Advisory Agreement

During 2014 our predecessor entered into an advisory agreement (the “Advisory Agreement”) with Vintner Resources, LLC (“Vintner Resources”) and Blackstone Management Partners L.L.C. (“BMP”, and together with Vintner Resources, the “Advisors”) pursuant to which the Advisors and their affiliates agreed to provide advisory and consulting services to our predecessor. Vintner Resources is indirectly controlled by Eric D. Marsh, our president and chief executive officer. The advisory and consulting services may include advice regarding financings and relationships with lenders and bankers; advice regarding the selection, retention and supervision of independent auditors, outside legal counsel, investment bankers and other advisors or consultants; advice regarding environmental, social and governance issues; advice regarding general business strategy and activities; and such other advice as may be reasonably requested by our predecessor. The monitoring fee earned by the Advisors under the Advisory Agreement is based on 2% of our predecessor’s EBITDA, as defined in the Advisory Agreement. The monitoring fees for the nine months ended September 30, 2016 and 2015 and the year ended December 31, 2015 were $1.4 million, $1.4 million and $1.6 million, respectively, and were included in G&A. The Advisors’ obligation to provide such advisory and consulting services will terminate upon the consummation of this offering.

Additionally, pursuant to the Advisory Agreement the Advisors may also provide advisory and consulting services with respect to potential transactions, including due diligence investigations, business and investment analysis, financing and structuring assistance and general business assistance. The transaction fee earned by the Advisors in connection with such transactions is paid upon the funding of each capital contribution to our predecessor, and is equal to 1% of such capital contribution (net of the portion of the capital contribution attributable to the transaction fee). No such transaction fees were recognized for the 2016 Period and 2015 Period and the year ended December 31, 2015.

Blackstone

Our predecessor was formed in 2014 in connection with an equity contribution by Blackstone. The limited partnership agreement of our predecessor provides for a number of different classes of units, which are owned by Blackstone and certain members of management.

Pursuant to our predecessor’s limited partnership agreement, our predecessor, Vintner Resources and Blackstone entered into an area of mutual interest agreement (the “AMI Agreement”) pursuant to which the limited partners agreed to refrain from pursuing investments in unconventional shale opportunities and other related rights, assets and interests in the Haynesville and Mid-Bossier formations in northern Louisiana, subject to certain exceptions. The AMI Agreement will terminate upon the consummation of this offering.

In 2015, Blackstone acquired $81.9 million face amount of the TLB and $283.5 million face amount of the TLC through open-market transactions.

Other Historical Arrangements

VMS is party to separate management services agreements with Brix Oil & Gas Holdings LP (“Brix”) and Harvest Royalties Holdings LP (“Harvest”), and VMS and Blackstone are party to advisory agreements with Brix and Harvest. Brix and Harvest are indirectly controlled by Blackstone and members of management. The terms of these management services agreements and advisory agreements are substantially similar to those of the MSA and the Advisory Agreement, respectively. Following the completion of the IPO, we expect Brix and Harvest to not be more than minimally engaged in new activity.

Stockholders’ Agreement

In connection with the closing of this offering, we expect Vine Investment to enter into a stockholders’ agreement, pursuant to which the Existing Owners, through their ownership interests in Vine Investment, will agree to vote their shares of common stock in accordance with the terms thereof, including with respect to the election of directors.

Registration Rights Agreement

In connection with the closing of this offering, we will enter into a registration rights agreement with Vine Investment granting registration rights to certain of the Existing Owners on account of their ownership interests in Vine Investment. Under the registration rights agreement, we will agree to register the sale of shares of our common stock under certain circumstances.

Procedures for Approval of Related Party Transactions

Prior to the closing of this offering, we have not maintained a policy for approval of Related Party Transactions. A “Related Party Transaction” is a transaction, arrangement or relationship in which we or any of our subsidiaries was, is or will be a participant, the amount of which involved exceeds $120,000, and in which any Related Person had, has or will have a direct or indirect material interest. A “Related Person” means:

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any person who is, or at any time during the applicable period was, one of our executive officers or one of our directors;

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any person who is known by us to be the beneficial owner of more than 5% of our common stock;

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any immediate family member of any of the foregoing persons, which means any child, stepchild, parent, stepparent, spouse, sibling, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law or sister-in-law of a director, executive officer or a beneficial owner of more than 5% of our common stock, and any person (other than a tenant or employee) sharing the household of such director, executive officer or beneficial owner of more than 5% of our common stock; and

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any firm, corporation or other entity in which any of the foregoing persons is a partner or principal or in a similar position or in which such person has a 10% or greater beneficial ownership interest.

We anticipate that our board of directors will adopt a written related party transactions policy prior to the completion of this offering. Pursuant to this policy, we expect that our audit committee will review all material facts of all Related Party Transactions.

DESCRIPTION OF CAPITAL STOCK

Upon completion of this offering the authorized capital stock of Vine Resources Inc. will consist of shares of common stock, $0.01 par value per share, of which shares will be issued and outstanding, and shares of preferred stock, $0.01 par value per share, of which no shares will be issued and outstanding.

The following summary of the capital stock and amended and restated certificate of incorporation and amended and restated bylaws of Vine Resources Inc. does not purport to be complete and is qualified in its entirety by reference to the provisions of applicable law and to our amended and restated certificate of incorporation and amended and restated bylaws, which are filed as exhibits to the registration statement of which this prospectus is a part.

Common Stock

Except as provided by law or in a preferred stock designation, holders of common stock are entitled to one vote for each share held of record on all matters submitted to a vote of the stockholders, will have the exclusive right to vote for the election of directors and do not have cumulative voting rights. Except as otherwise required by law, holders of common stock, are not entitled to vote on any amendment to the amended and restated certificate of incorporation (including any certificate of designations relating to any series of preferred stock) that relates solely to the terms of any outstanding series of preferred stock if the holders of such affected series are entitled, either separately or together with the holders of one or more other such series, to vote thereon pursuant to the amended and restated certificate of incorporation (including any certificate of designations relating to any series of preferred stock) or pursuant to the DGCL. Subject to prior rights and preferences that may be applicable to any outstanding shares or series of preferred stock, holders of common stock are entitled to receive ratably in proportion to the shares of common stock held by them such dividends (payable in cash, stock or otherwise), if any, as may be declared from time to time by our board of directors out of funds legally available for dividend payments. All outstanding shares of common stock are fully paid and non-assessable, and the shares of common stock to be issued upon completion of this offering will be fully paid and non-assessable. The holders of common stock have no preferences or rights of conversion, exchange, pre-emption or other subscription rights. There are no redemption or sinking fund provisions applicable to the common stock. In the event of any voluntary or involuntary liquidation, dissolution or winding-up of our affairs, holders of common stock will be entitled to share ratably in our assets in proportion to the shares of common stock held by then that are remaining after payment or provision for payment of all of our debts and obligations and after distribution in full of preferential amounts to be distributed to holders of outstanding shares of preferred stock, if any.

Preferred Stock

Our amended and restated certificate of incorporation authorizes our board of directors, subject to any limitations prescribed by law, without further stockholder approval, to establish and to issue from time to time one or more classes or series of preferred stock, par value $0.01 per share, covering up to an aggregate of shares of preferred stock. Each class or series of preferred stock will cover the number of shares and will have the powers, preferences, rights, qualifications, limitations and restrictions determined by the board of directors, which may include, among others, dividend rights, liquidation preferences, voting rights, conversion rights, preemptive rights and redemption rights. Except as provided by law or in a preferred stock designation, the holders of preferred stock will not be entitled to vote at or receive notice of any meeting of stockholders.

Anti-Takeover Effects of Provisions of Our Amended and Restated Certificate of Incorporation, our Amended and Restated Bylaws and Delaware Law

Some provisions of Delaware law, our amended and restated certificate of incorporation and our amended and restated bylaws will contain provisions that could make the following transactions more difficult:

acquisitions of us by means of a tender offer, a proxy contest or otherwise; or removal of our incumbent officers and directors. These provisions may also have the effect of preventing changes in our management. It is possible that these provisions could make it more difficult to accomplish or could deter transactions that stockholders may otherwise consider to be in their best interest or in our best interests, including transactions that might result in a premium over the market price for our shares.

These provisions are expected to discourage coercive takeover practices and inadequate takeover bids. These provisions are also designed to encourage persons seeking to acquire control of us to first negotiate with us. We believe that the benefits of increased protection and our potential ability to negotiate with the proponent of an unfriendly or unsolicited proposal to acquire or restructure us outweigh the disadvantages of discouraging these proposals because, among other things, negotiation of these proposals could result in an improvement of their terms.

Delaware Law

Section 203 of the DGCL prohibits a Delaware corporation, including those whose securities are listed for trading on the NYSE, from engaging in any business combination with any interested stockholder for a period of three years following the date that the stockholder became an interested stockholder, unless:

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the transaction is approved by the board of directors before the date the interested stockholder attained that status;

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upon consummation of the transaction that resulted in the stockholder becoming an interested stockholder, the interested stockholder owned at least 85% of the voting stock of the corporation outstanding at the time the transaction commenced; or

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on or after such time the business combination is approved by the board of directors and authorized at a meeting of stockholders by at least two-thirds of the outstanding voting stock that is not owned by the interested stockholder.

We will elect to not be subject to the provisions of Section 203 of the DGCL.

Amended and Restated Certificate of Incorporation and Amended and Restated Bylaws

Provisions of our amended and restated certificate of incorporation and amended and restated bylaws, which will become effective upon the closing of this offering, may delay or discourage transactions involving an actual or potential change in control or change in our management, including transactions in which stockholders might otherwise receive a premium for their shares, or transactions that our stockholders might otherwise deem to be in their best interests. Therefore, these provisions could adversely affect the price of our common stock.

Among other things, upon the completion of this offering, our amended and restated certificate of incorporation and amended and restated bylaws will:

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establish advance notice procedures with regard to stockholder proposals relating to the nomination of candidates for election as directors or new business to be brought before meetings of our stockholders. These procedures provide that notice of stockholder proposals must be timely given in writing to our corporate secretary prior to the meeting at which the action is to be taken. Generally, to be timely, notice must be received at our principal executive offices not less than 90 days nor more than 120 days prior to the first anniversary date of the annual meeting for the preceding year. Our amended and restated bylaws specify the requirements as to form and content of all stockholders’ notices. These requirements may preclude stockholders from bringing matters before the stockholders at an annual or special meeting;

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provide our board of directors the ability to authorize undesignated preferred stock. This ability makes it possible for our board of directors to issue, without stockholder approval, preferred stock with voting

or other rights or preferences that could impede the success of any attempt to change control of us. These and other provisions may have the effect of deferring hostile takeovers or delaying changes in control or management of our company;

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provide that the authorized number of directors may be changed only by resolution of the board of directors;

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provide that all vacancies, including newly created directorships, may, except as otherwise required by law or, if applicable, the rights of holders of a series of preferred stock, be filled by the affirmative vote of a majority of directors then in office, even if less than a quorum;

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at any time after Vine Investment and each of its affiliates no longer collectively beneficially own more than 50% of the outstanding shares of our common stock, provide that any action required or permitted to be taken by the stockholders must be effected at a duly called annual or special meeting of stockholders and may not be effected by any consent in writing in lieu of a meeting of such stockholders, subject to the rights of the holders of any series of preferred stock with respect to such series (prior to such time, such actions may be taken without a meeting by written consent of holders of common stock having not less than the minimum number of votes that would be necessary to authorize such action at a meeting);

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provide our certificate of incorporation and bylaws may be amended by the affirmative vote of the holders of at least two-thirds of our then outstanding common stock (prior to such time, our certificate of incorporation and bylaws may be amended by the affirmative vote of the holders of a majority of our then outstanding common stock);

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provide that special meetings of our stockholders may only be called by the board of directors, the chief executive officer or the chairman of the board (prior to such time, a special meeting may also be called at the request of stockholders holding a majority of the outstanding shares entitled to vote);

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provide for our board of directors to be divided into three classes of directors, with each class as nearly equal in number as possible, serving staggered three year terms, other than directors which may be elected by holders of preferred stock, if any. This system of electing and removing directors may tend to discourage a third party from making a tender offer or otherwise attempting to obtain control of us, because it generally makes it more difficult for stockholders to replace a majority of the directors;

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provide that we renounce any interest in the business opportunities of Blackstone or any of their officers, directors, agents, stockholders, members, partners, affiliates, employees and subsidiaries (other than our directors that are presented business opportunities in their capacity as our directors) and that they have no obligation to offer us those investments or opportunities; and

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provide that our bylaws can be amended or repealed at any regular or special meeting of stockholders or by the board of directors, including the requirement that any amendment by the stockholders at a meeting, at any time after Vine Investment and its affiliates no longer collectively own more than 50% of the outstanding shares of our common stock, be upon the affirmative vote of at least 66²⁄₃% of the shares of common stock generally entitled to vote in the election of directors.

Forum Selection

Our amended and restated certificate of incorporation will provide that unless we consent in writing to the selection of an alternative forum, a state court located within the State of Delaware (or, if no state court located within the state of Delaware has jurisdiction, the federal district court for the District of Delaware) will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for:

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any derivative action or proceeding brought on our behalf;

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any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers or other employees to us or our stockholders;

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any action asserting a claim against us or any of our directors, officers or other employees arising pursuant to any provision of the DGCL, our amended and restated certificate of incorporation or our bylaws; or

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any action asserting a claim against us or any of our directors, officers or other employees 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.

It is possible that a court could find our forum selection provision to be inapplicable or unenforceable.

Limitation of Liability and Indemnification Matters

Our amended and restated certificate of incorporation limits the liability of our directors for monetary damages for breach of their fiduciary duty as directors, except for liability that cannot be eliminated under the DGCL. Delaware law provides that directors of a company will not be personally liable for monetary damages for breach of their fiduciary duty as directors, except for liabilities:

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for any breach of their duty of loyalty to us or our stockholders;

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for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law;

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for unlawful payment of dividend or unlawful stock repurchase or redemption, as provided under Section 174 of the DGCL; or

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for any transaction from which the director derived an improper personal benefit.

Any amendment, repeal or modification of these provisions will be prospective only and would not affect any limitation on liability of a director for acts or omissions that occurred prior to any such amendment, repeal or modification.

Our amended and restated certificate of incorporation and amended and restated bylaws also provide that we will indemnify our directors and officers to the fullest extent permitted by Delaware law. Our amended and restated certificate of incorporation and amended and restated bylaws also permit us to purchase insurance on behalf of any officer, director, employee or other agent for any liability arising out of that person’s actions as our officer, director, employee or agent, regardless of whether Delaware law would permit indemnification. We intend to enter into indemnification agreements with each of our current and future directors and officers. These agreements will require us to indemnify these individuals to the fullest extent permitted under Delaware law against liability that may arise by reason of their service to us, and to advance expenses incurred as a result of any proceeding against them as to which they could be indemnified. We believe that the limitation of liability provision in our amended and restated certificate of incorporation and the indemnification agreements will facilitate our ability to continue to attract and retain qualified individuals to serve as directors and officers.

Transfer Agent and Registrar

The transfer agent and registrar for our common stock will be .

Listing

We intend to apply to list our common stock on the NYSE under the symbol “VRI.”

SHARES ELIGIBLE FOR FUTURE SALE

Prior to this offering, there has been no public market for our common stock. Future sales of our common stock in the public market, or the availability of such shares for sale in the public market, could adversely affect the market price of our common stock prevailing from time to time. As described below, only a limited number of shares will be available for sale shortly after this offering due to contractual and legal restrictions on resale. Nevertheless, sales of a substantial number of shares of our common stock in the public market after such restrictions lapse, or the perception that those sales may occur, could adversely affect the prevailing market price of our common stock at such time and our ability to raise equity-related capital at a time and price we deem appropriate.

Sales of Restricted Shares

Upon completion of this offering, we will have outstanding an aggregate of shares of common stock. Of these shares, all of the shares of common stock to be sold in this offering (or shares assuming the underwriters exercise the option to purchase additional shares in full) will be freely tradable without restriction or further registration under the Securities Act, unless the shares are held by any of our “affiliates” as such term is defined in Rule 144 under the Securities Act. All remaining shares of common stock will be deemed “restricted securities” as such term is defined under Rule 144. The restricted securities were, or will be, issued and sold by us in private transactions and are eligible for public sale only if registered under the Securities Act or if they qualify for an exemption from registration under Rule 144 or Rule 701 under the Securities Act, which rules are summarized below.

As a result of the lock-up agreements described below and the provisions of Rule 144 and Rule 701 under the Securities Act, the shares of our common stock (excluding the shares to be sold in this offering) that will be available for sale in the public market are as follows:

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no shares will be eligible for sale on the date of this prospectus or prior to 180 days after the date of this prospectus; and

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shares will be eligible for sale upon the expiration of the lock-up agreements beginning 180 days after the date of this prospectus and when permitted under Rule 144 or Rule 701.

Lock-up Agreements

We, Vine Investment, and all of our directors and executive officers have agreed not to sell any common stock or securities convertible into or exchangeable for shares of common stock for a period of 180 days from the date of this prospectus, subject to certain exceptions. “Underwriting” contains a description of these lock-up agreements.

Rule 144

In general, under Rule 144 under the Securities Act as currently in effect, a person (or persons whose shares are aggregated) who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned restricted securities within the meaning of Rule 144 for a least Nine Months (including any period of consecutive ownership of preceding non-affiliated holders) would be entitled to sell those shares, subject only to the availability of current public information about us. A non-affiliated person who has beneficially owned restricted securities within the meaning of Rule 144 for at least one year would be entitled to sell those shares without regard to the provisions of Rule 144.

A person (or persons whose shares are aggregated) who is deemed to be an affiliate of ours and who has beneficially owned restricted securities within the meaning of Rule 144 for at least Nine Months would be entitled to sell within any three-month period a number of shares that does not exceed the greater of one percent

of the then outstanding shares of our common stock or the average weekly trading volume of our common stock reported through the NYSE, as applicable, during the four calendar weeks preceding the filing of notice of the sale. Such sales are also subject to certain manner of sale provisions, notice requirements and the availability of current public information about us.

Rule 701

In general, under Rule 701 under the Securities Act, any of our employees, directors, officers, consultants or advisors who purchases shares from us in connection with a compensatory stock or option plan or other written agreement before the effective date of this offering is entitled to sell such shares 90 days after the effective date of this offering in reliance on Rule 144, without having to comply with the holding period requirement of Rule 144 and, in the case of non-affiliates, without having to comply with the public information, volume limitation or notice filing provisions of Rule 144. The SEC has indicated that Rule 701 will apply to typical stock options granted by an issuer before it becomes subject to the reporting requirements of the Exchange Act, along with the shares acquired upon exercise of such options, including exercises after the date of this prospectus.

Stock Issued Under Employee Plans

We intend to file a registration statement on Form S-8 under the Securities Act to register shares of common stock issuable under our long-term incentive plan. This registration statement on Form S-8 is expected to be filed following the effective date of the registration statement of which this prospectus is a part and will be effective upon filing. Accordingly, shares registered under such registration statement will be available for sale in the open market following the effective date, unless such shares are subject to vesting restrictions with us, Rule 144 restrictions applicable to our affiliates or the lock-up restrictions described above.

Registration Rights

We expect to enter into a registration rights agreement with Vine Investment which will require us to file and effect the registration of our common stock held thereby (and by certain of their affiliates) 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. “Certain Relationships and Related Party Transactions —Registration Rights” contains additional information regarding the registration rights agreement.

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

The following is a summary of the material U.S. federal income tax considerations related to the purchase, ownership and disposition of our common stock by a non-U.S. holder (as defined below) that acquired such common stock pursuant to this offering and that holds such common stock as a “capital asset” (generally property held for investment). This summary is based on the provisions of the Internal Revenue Code of 1986, as amended (the “Code”), U.S. Treasury regulations, administrative rulings and judicial decisions, all as in effect on the date hereof, and all of which are subject to change, possibly with retroactive effect. We have not sought any ruling from the Internal Revenue Service (“IRS”) with respect to the statements made and the conclusions reached in the following summary, and there can be no assurance that the IRS or a court will agree with such statements and conclusions.

This summary does not address all aspects of U.S. federal income taxation that may be relevant to non-U.S. holders in light of their personal circumstances. In addition, this summary does not address the Medicare tax on certain investment income, U.S. federal estate or gift tax laws, any state, local or non-U.S. tax laws or any tax treaties. This summary also does not address tax considerations applicable to investors that may be subject to special treatment under the U.S. federal income tax laws, such as:

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banks, insurance companies or other financial institutions;

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tax-exempt or governmental organizations;

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qualified foreign pension funds (or any entities all of the interests of which are held by a qualified foreign pension fund);

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dealers in securities or foreign currencies;

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traders in securities that use the mark-to-market method of accounting for U.S. federal income tax purposes;

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persons subject to the alternative minimum tax;

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partnerships or other pass-through entities for U.S. federal income tax purposes or holders of interests therein;

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persons deemed to sell our common stock under the constructive sale provisions of the Code;

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persons that acquired our common stock through the exercise of employee stock options or otherwise as compensation or through a tax-qualified retirement plan;

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certain former citizens or long-term residents of the United States; and

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persons that hold our common stock as part of a straddle, appreciated financial position, synthetic security, hedge, conversion transaction, wash sale or other integrated investment or risk reduction transaction.

PROSPECTIVE INVESTORS ARE ENCOURAGED TO CONSULT THEIR TAX ADVISORS WITH RESPECT TO THE APPLICATION OF THE U.S. FEDERAL INCOME TAX LAWS TO THEIR PARTICULAR SITUATION, AS WELL AS ANY TAX CONSEQUENCES OF THE PURCHASE, OWNERSHIP AND DISPOSITION OF OUR COMMON STOCK ARISING UNDER THE U.S. FEDERAL ESTATE OR GIFT TAX LAWS OR UNDER THE LAWS OF ANY STATE, LOCAL, NON-U.S. OR OTHER TAXING JURISDICTION OR UNDER ANY APPLICABLE INCOME TAX TREATY.

Non-U.S. Holder Defined

For purposes of this discussion, a “non-U.S. holder” is a beneficial owner of our common stock that is not for U.S. federal income tax purposes partnership or any of the following:

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an individual who is a citizen or resident of the United States;

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a corporation (or other entity treated as a corporation for U.S. federal income tax purposes) created or organized in or under the laws of the United States, any state thereof or the District of Columbia;

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an estate the income of which is subject to U.S. federal income tax regardless of its source; or

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a trust (i) the administration of which is subject to the primary supervision of a U.S. court and which has one or more United States persons who have the authority to control all substantial decisions of the trust or (ii) which has made a valid election under applicable U.S. Treasury regulations to be treated as a United States person.

If a partnership (including an entity or arrangement treated as a partnership for U.S. federal income tax purposes) holds our common stock, the tax treatment of a partner in the partnership generally will depend upon the status of the partner, upon the activities of the partnership and upon certain determinations made at the partner level. Accordingly, we urge partners in partnerships (including entities or arrangements treated as partnerships for U.S. federal income tax purposes) considering the purchase of our common stock to consult their tax advisors regarding the U.S. federal income tax considerations of the purchase, ownership and disposition of our common stock by such partnership.

Distributions

As described in the section entitled “Dividend Policy,” we do not anticipate making any distributions on our common stock in the foreseeable future. However, if we do make distributions of cash or other property on our common stock, those distributions will constitute dividends for U.S. federal income tax purposes to the extent paid from our current or accumulated earnings and profits, as determined under U.S. federal income tax principles. To the extent those distributions exceed our current and accumulated earnings and profits, the distributions will be treated as a non-taxable return of capital, which will reduce the non-U.S. holder’s tax basis in our common stock, until such basis equals zero, and thereafter as capital gain from the sale or exchange of such common stock. “— Gain on Disposition of Common Stock” contains additional information. Subject to the withholding requirements under FATCA (as defined below) and with respect to effectively connected dividends, each of which is discussed below, any distribution made to a non-U.S. holder on our common stock generally will be subject to U.S. withholding tax at a rate of 30% of the gross amount of the distribution unless an applicable income tax treaty provides for a lower rate. To receive the benefit of a reduced treaty rate, a non-U.S. holder must generally provide the applicable withholding agent with an IRS Form W-8BEN or IRS Form W-8BEN-E (or other applicable or successor form) certifying qualification for the reduced rate.

Dividends paid to a non-U.S. holder that are effectively connected with a trade or business conducted by the non-U.S. holder in the United States (and, if required by an applicable income tax treaty, are treated as attributable to a permanent establishment maintained by the non-U.S. holder in the United States) generally will be taxed on a net income basis at the rates and in the manner generally applicable to United States persons (as defined under the Code). Such effectively connected dividends will not be subject to U.S. withholding tax if the non-U.S. holder satisfies certain certification requirements by providing the applicable withholding agent with a properly executed IRS Form W-8ECI certifying eligibility for exemption. If the non-U.S. holder is a corporation for U.S. federal income tax purposes, it may also be subject to a branch profits tax (at a 30% rate or such lower rate as specified by an applicable income tax treaty) on its effectively connected earnings and profits (as adjusted for certain items), which will include effectively connected dividends.

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Gain on Disposition of Common Stock

Subject to the discussion below under “— Additional Withholding Requirements under FATCA,” a non-U.S. holder generally will not be subject to U.S. federal income tax on any gain realized upon the sale or other disposition of our common stock unless:

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the non-U.S. holder is an individual who is present in the United States for a period or periods aggregating 183 days or more during the calendar year in which the sale or disposition occurs and certain other conditions are met;

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the gain is effectively connected with a trade or business conducted by the non-U.S. holder in the United States (and, if required by an applicable income tax treaty, is attributable to a permanent establishment maintained by the non-U.S. holder in the United States); or

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our common stock constitutes a United States real property interest by reason of our status as a United States real property holding corporation (“USRPHC”) for U.S. federal income tax purposes during the shorter of the five-year period ending on the date of the disposition or the non-U.S. holders’ holding period for our common stock.

A non-U.S. holder described in the first bullet point above will be subject to U.S. federal income tax at a rate of 30% (or such lower rate as specified by an applicable income tax treaty) on the amount of such gain, which generally may be offset by U.S. source capital losses.

A non-U.S. holder whose gain is described in the second bullet point above or, subject to the exceptions described in the next paragraph and the third bullet point above, generally will be taxed on a net income basis at the rates and in the manner generally applicable to United States persons (as defined under the Code) unless an applicable income tax treaty provides otherwise. If such non-U.S. holder is a corporation for U.S. federal income tax purposes, it may also be subject to a branch profits tax (at a 30% rate or such lower rate specified by an applicable income tax treaty) on its effectively connected earnings and profits (as adjusted for certain items), which will include any effectively connected gain described in the second bullet point above.

Generally, a corporation is a USRPHC if the fair market value of its United States real property interests equals or exceeds 50% of the sum of the fair market value of its worldwide real property interests and its other assets used or held for use in a trade or business. We believe that we currently are, and expect to remain for the foreseeable future, a USRPHC for U.S. federal income tax purposes. However, provided that our common stock is and continues to be regularly traded on an established securities market, only a non-U.S. holder that actually or constructively owns or owned at any time during the shorter of the five-year period ending on the date of the disposition or the non-U.S. holder’s holding period for the common stock, more than 5% of our common stock will be taxable on gain realized on the disposition of our common stock as a result of our status as a USRPHC. If our common stock were not considered to be regularly traded on an established securities market, such non-U.S. holder (regardless of the percentage of stock owned) would be subject to U.S. federal income tax on a taxable disposition of our common stock (as described in the preceding paragraph), and a 15% withholding tax would apply to the gross proceeds from such disposition.

Non-U.S. holders should consult their tax advisors with respect to the application of the foregoing rules to their ownership and disposition of our common stock.

Backup Withholding and Information Reporting

Any dividends paid to a non-U.S. holder must be reported annually to the IRS and to the non-U.S. holder. Copies of these information returns may be made available to the tax authorities in the country in which the non-U.S. holder resides or is established. Payments of dividends to a non-U.S. holder generally will not be subject to backup withholding if the non-U.S. holder establishes an exemption by properly certifying its non-U.S. status on an IRS Form W-8BEN, IRS Form W-8BEN-E (or other applicable or successor form).

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Payments of the proceeds from a sale or other disposition by a non-U.S. holder of our common stock effected by or through a U.S. office of a broker generally will be subject to information reporting and backup withholding (at the applicable rate, which is currently 28%) unless the non-U.S. holder establishes an exemption by properly certifying its non-U.S. status on an IRS Form W-8BEN, IRS Form W-8BEN-E (or other applicable or successor form) and certain other conditions are met. Information reporting and backup withholding generally will not apply to any payment of the proceeds from a sale or other disposition of our common stock effected outside the United States by a non-U.S. office of a broker. However, unless such broker has documentary evidence in its records that the non-U.S. holder is not a United States person and certain other conditions are met, or the non-U.S. holder otherwise establishes an exemption, information reporting will apply to a payment of the proceeds of the disposition of our common stock effected outside the United States by such a broker if it has certain relationships within the United States.

Backup withholding is not an additional tax. Rather, the U.S. income tax liability (if any) of persons subject to backup withholding will be reduced by the amount of tax withheld. If backup withholding results in an overpayment of taxes, a refund may be obtained, provided that the required information is timely furnished to the IRS.

Additional Withholding Requirements under FATCA

Sections 1471 through 1474 of the Code, and the U.S. Treasury regulations and administrative guidance issued thereunder (“FATCA”), impose a 30% withholding tax on any dividends paid on our common stock and on the gross proceeds from a disposition of our common stock (if such disposition occurs after December 31, 2018), in each case if paid to a “foreign financial institution” or a “non-financial foreign entity” (each as defined in the Code) (including, in some cases, when such foreign financial institution or non-financial foreign entity is acting as an intermediary), unless (i) in the case of a foreign financial institution, such institution enters into an agreement with the U.S. government to withhold on certain payments, and to collect and provide to the U.S. tax authorities substantial information regarding U.S. account holders of such institution (which includes certain equity and debt holders of such institution, as well as certain account holders that are non-U.S. entities with U.S. owners); (ii) in the case of a non-financial foreign entity, such entity certifies that it does not have any “substantial United States owners” (as defined in the Code) or provides the applicable withholding agent with a certification identifying the direct and indirect substantial United States owners of the entity (in either case, generally on an IRS Form W-8BEN-E); or (iii) the foreign financial institution or non-financial foreign entity otherwise qualifies for an exemption from these rules and provides appropriate documentation (such as an IRS Form W-8BEN-E). Foreign financial institutions located in jurisdictions that have an intergovernmental agreement with the United States governing these rules may be subject to different rules. Under certain circumstances, a holder might be eligible for refunds or credits of such taxes. Non-U.S. holders are encouraged to consult their own tax advisors regarding the effects of FATCA on their investment in our common stock.

INVESTORS CONSIDERING THE PURCHASE OF OUR COMMON STOCK ARE URGED TO CONSULT THEIR OWN TAX ADVISORS REGARDING THE APPLICATION OF THE U.S. FEDERAL INCOME TAX LAWS TO THEIR PARTICULAR SITUATIONS AND THE APPLICABILITY AND EFFECT OF U.S. FEDERAL ESTATE AND GIFT TAX LAWS AND ANY STATE, LOCAL OR NON-U.S. TAX LAWS AND TAX TREATIES.

103

UNDERWRITING

Under the terms and subject to the conditions contained in an underwriting agreement dated the date of this prospectus, the underwriters named below, for whom is acting as representative, have agreed to purchase, and we have agreed to sell, the number of shares indicated below:


Name		Number of Shares


Total

The underwriters and the representative are collectively referred to as the “underwriters” and the “representative,” respectively. The underwriters are offering the shares of common stock subject to their acceptance of the shares from us and subject to prior sale. The underwriting agreement provides that the obligations of the several underwriters to pay for and accept delivery of the shares of common stock offered by this prospectus are subject to certain conditions contained in the underwriting agreement including:

•

the obligation to purchase all of the shares of common stock offered hereby (other than those shares of common stock covered by their option to purchase additional shares as described below), if any of the shares are purchased;

•

the representations and warranties made by us to the underwriters are true;

•

there is no material change in our business or the financial markets; and

•

we deliver customary closing documents to the underwriters.

The per share price of any shares sold by the underwriters shall be the public offering price listed on the cover page of this prospectus, in United States dollars, less an amount not greater than the per share amount of the concession to dealers described below.

The underwriters initially propose to offer part of the shares of common stock directly to the public at the public offering price listed on the cover page of this prospectus and part to certain dealers at a price that represents a concession not in excess of $ a share under the public offering price. Any underwriter may allow, and such dealers may reallow, a concession not in excess of $ a share to other underwriters or to certain dealers. After the initial offering of the shares of common stock, the offering price and other selling terms may from time to time be varied by the representative.

We have granted to the underwriters an option, exercisable for days from the date of this prospectus, to purchase up to an aggregate of additional shares of common stock at the public offering price listed on the cover page of this prospectus, less underwriting discounts and commissions. The underwriters may exercise this option solely for the purpose of covering over-allotments, if any, made in connection with the offering of the shares of common stock offered by this prospectus. To the extent the option is exercised, each underwriter will become obligated, subject to certain conditions, to purchase the same percentage of the additional shares of common stock as the number listed next to the underwriter’s name in the preceding table bears to the total number of shares of common stock listed next to the names of all underwriters in the preceding table. If the underwriters’ option is exercised in full based upon an assumed initial offering price of $ per share, the total price to the public would be approximately $ , the total underwriters’ discounts and commissions would be approximately $ , and the total proceeds to us would be approximately $ .

The following table shows the per share and total underwriting discounts and commissions to be paid to the underwriters by us. These amounts are shown assuming no exercise and full exercise of the underwriters’ option to purchase additional shares.


	Paid by Us
	No Exercise	Full Exercise
Per Share	$	$
Total	$	$

104

We estimate that the expenses of the offering, not including underwriting discounts and commissions, will be approximately $ .

We have agreed to reimburse the underwriters for fees and expenses related to any required review by FINRA in an amount not greater than $ .

The underwriters have informed us that they do not intend sales to discretionary accounts to exceed % of the total number of shares of common stock offered by them.

Our common stock has been approved for listing on the NYSE under the symbol “VRI.”

We, all of our directors and officers and certain of our principal stockholders have agreed that, without the prior written consent of and subject to certain exceptions, on behalf of the underwriters, we and they will not, during the period ending days after the date of this prospectus:

•

offer, pledge, sell, contract to sell, sell any option or contract to purchase, purchase any option or contract to sell, grant any option, right or warrant to purchase, lend or otherwise transfer or dispose of, directly or indirectly, any shares of common stock beneficially owned or any securities so owned that are convertible into or exercisable or exchangeable for common stock;

•

enter into any swap or other arrangement that transfers to another, in whole or in part, any of the economic consequences of ownership of the common stock; or

•

file any registration statement with the SEC relating to the offering of any shares of common stock or any securities convertible into or exercisable or exchangeable for common stock;

whether any such transaction described above is to be settled by delivery of common stock or such other securities, in cash or otherwise. The restrictions described in this paragraph shall not apply to the sale of shares to the underwriters pursuant to the underwriting agreement.

In order to facilitate the offering of the common stock, the underwriters may engage in transactions that stabilize, maintain or otherwise affect the price of the common stock. Specifically, the underwriters may over-allot in connection with the offering, creating a short position in the common stock for their own account. In addition, to cover over-allotments or to stabilize the price of the common stock, the underwriters may bid for, and purchase, shares of common stock in the open market. Finally, the underwriting syndicate may reclaim selling concessions allowed to an underwriter or a dealer for distributing the common stock in the offering, if the syndicate repurchases previously distributed common stock in transactions to cover syndicate short positions, in stabilization transactions or otherwise. Any of these activities may stabilize or maintain the market price of the common stock above independent market levels. The underwriters are not required to engage in these activities, and may end any of these activities at any time.

We and the underwriters have agreed to indemnify each other against certain liabilities, including liabilities under the Securities Act.

Directed Share Program Prospectus Disclosure

At our request, certain of the underwriters have reserved up to % of the common stock being offered by this prospectus (excluding any shares to be issued upon exercise of the over-allotment option) for sale at the initial public offering price to our directors, officers, employees, consultants, business associates, and related persons associated with us. The sales will be made by , through a directed share program. We do not know if these persons will choose to purchase all or any portion of these reserved shares, but any purchases they do make will reduce the number of shares available to the general public. Any reserved shares which are not so purchased will be offered by the underwriters to the general public on the same basis as the other shares offered by this prospectus. Participants in the directed share program who purchase more than $ of shares will be subject to

105

a -day lock-up with respect to any shares sold to them pursuant to that program. This lock-up will have similar restrictions and an identical extension provision to the lock-up agreements described above. Any shares sold in the directed share program to our directors, executive officers or existing security holders will also be subject to the lock-up agreements described above. We have agreed to indemnify and the underwriters in connection with the directed share program, including for the failure of any participant to pay for its shares.

Pricing of the Offering

Prior to this offering, there has been no public market for our common stock. The initial public offering price is determined by negotiations between us and the representatives. Among the factors to be considered in determining the initial public offering price will be the information set forth in this prospectus, our history and prospects, the history of and prospects for our industry in general, our sales, earnings and certain other financial and operating information in recent periods, and the price-earnings ratios, price-sales ratios, market prices of securities, certain financial and operating information of companies engaged in activities similar to ours and other factors deemed relevant by the underwriters and us. The estimated initial public offering price range set forth on the cover page of the preliminary prospectus is subject to change as a result of market conditions and other factors.

Selling Restrictions

Canada

The securities may be sold only to purchasers purchasing, or deemed to be purchasing, as principal that are accredited investors, as defined in National Instrument 45-106 Prospectus Exemptions or subsection 73.3(1) of the Securities Act (Ontario), and are permitted clients, as defined in National Instrument 31-103 Registration Requirements, Exemptions and Ongoing Registrant Obligations. Any resale of the securities must be made in accordance with an exemption from, or in a transaction not subject to, the prospectus requirements of applicable securities laws.

Securities legislation in certain provinces or territories of Canada may provide a purchaser with remedies for rescission or damages if this prospectus (including any amendment thereto) contains a misrepresentation, provided that the remedies for rescission or damages are exercised by the purchaser within the time limit prescribed by the securities legislation of the purchaser’s province or territory. The purchaser should refer to any applicable provisions of the securities legislation of the purchaser’s province or territory for particulars of these rights or consult with a legal advisor.

Pursuant to section 3A.3 (or, in the case of securities issued or guaranteed by the government of a non-Canadian jurisdiction, section 3A.4) of National Instrument 33-105 Underwriting Conflicts (“NI 33-105”), the underwriters are not required to comply with the disclosure requirements of NI 33-105 regarding underwriter conflicts of interest in connection with this offering.

European Economic Area

In relation to each Member State of the European Economic Area which has implemented the Prospectus Directive (each, a “Relevant Member State”) an offer to the public of any shares of our common stock may not be made in that Relevant Member State, except that an offer to the public in that Relevant Member State of any shares of our common stock may be made at any time under the following exemptions under the Prospectus Directive, if they have been implemented in that Relevant Member State:

•

to any legal entity which is a qualified investor as defined in the Prospectus Directive;

•

to fewer than 100 or, if the Relevant Member State has implemented the relevant provision of the 2010 PD Amending Directive, 150, natural or legal persons (other than qualified investors as defined in the Prospectus Directive), as permitted under the Prospectus Directive, subject to obtaining the prior consent of the representatives for any such offer; or

106

•

in any other circumstances falling within Article 3(2) of the Prospectus Directive, provided that no such offer of shares of our common stock shall result in a requirement for the publication by us or any underwriter of a prospectus pursuant to Article 3 of the Prospectus Directive.

For the purposes of this provision, the expression an “offer to the public” in relation to any shares of our common stock in any Relevant Member State means the communication in any form and by any means of sufficient information on the terms of the offer and any shares of our common stock to be offered so as to enable an investor to decide to purchase any shares of our common stock, as the same may be varied in that Member State by any measure implementing the Prospectus Directive in that Member State, the expression “Prospectus Directive” means Directive 2003/71/EC (and amendments thereto, including the 2010 PD Amending Directive, to the extent implemented in the Relevant Member State), and includes any relevant implementing measure in the Relevant Member State, and the expression “2010 PD Amending Directive” means Directive 2010/73/EU.

United Kingdom

Each underwriter has represented and agreed that:

•

it has only communicated or caused to be communicated and will only communicate or cause to be communicated an invitation or inducement to engage in investment activity (within the meaning of Section 21 of the Financial Services and Markets Act 2000 (“FSMA”) received by it in connection with the issue or sale of the shares of our common stock in circumstances in which Section 21(1) of the FSMA does not apply to us; and

•

it has complied and will comply with all applicable provisions of the FSMA with respect to anything done by it in relation to the shares of our common stock in, from or otherwise involving the United Kingdom.

Russia

Under Russian law, shares of common stock may be considered securities of a foreign issuer. Neither we, nor this prospectus, nor shares of our common stock have been, or are intended to be, registered with the Central Bank of the Russian Federation under the Federal Law No. 39-FZ “On Securities Market” dated April 22, 1996 (as amended, the “Russian Securities Law”), and none of the shares of our common stock are intended to be, or may be offered, sold or delivered, directly or indirectly, or offered or sold to any person for reoffering or re-sale, directly or indirectly, in the territory of the Russian Federation or to any resident of the Russian Federation, except pursuant to the applicable laws and regulations of the Russian Federation.

The information provided in this prospectus does not constitute any representation with respect to the eligibility of any recipients of this prospectus to acquire shares of our common stock under the laws of the Russian Federation, including, without limitation, the Russian Securities Law and other applicable legislation.

This prospectus is not to be distributed or reproduced (in whole or in part) in the Russian Federation by the recipients of this prospectus. Recipients of this prospectus undertake not to offer, sell or deliver, directly or indirectly, or offer or sell to any person for reoffering or re-sale, directly or indirectly, shares of our common stock in the territory of the Russian Federation or to any resident of the Russian Federation, except pursuant to the applicable laws and regulations of the Russian Federation.

Recipients of this prospectus understand that respective receipt/acquisition of shares of our common stock is subject to restrictions and regulations applicable from the Russian law perspective.

107

Switzerland

The shares of common stock may not be publicly offered in Switzerland and will not be listed on the SIX Swiss Exchange, or SIX, or on any other stock exchange or regulated trading facility in Switzerland. This document has been prepared without regard to the disclosure standards for issuance prospectuses under art. 652a or art. 1156 of the Swiss Code of Obligations or the disclosure standards for listing prospectuses under art. 27 ff. of the SIX Listing Rules or the listing rules of any other stock exchange or regulated trading facility in Switzerland. Neither this document nor any other offering or marketing material relating to the shares or the offering may be publicly distributed or otherwise made publicly available in Switzerland. Neither this document nor any other offering or marketing material relating to the offering, us, or the shares have been or will be filed with or approved by any Swiss regulatory authority. In particular, this document will not be filed with, and the offer of shares will not be supervised by, the Swiss Financial Market Supervisory Authority FINMA, or FINMA, and the offer of shares has not been and will not be authorized under the Swiss Federal Act on Collective Investment Schemes, or CISA. The investor protection afforded to acquirers of interests in collective investment schemes under the CISA does not extend to acquirers of shares.

Dubai International Financial Centre

This prospectus relates to an Exempt Offer in accordance with the Offered Securities Rules of the Dubai Financial Services Authority, or DFSA. This prospectus is intended for distribution only to persons of a type specified in the Offered Securities Rules of the DFSA. It must not be delivered to, or relied on by, any other person. The DFSA has no responsibility for reviewing or verifying any documents in connection with Exempt Offers. The DFSA has not approved this prospectus nor taken steps to verify the information set forth herein and has no responsibility for the prospectus. The shares to which this prospectus relates may be illiquid and/or subject to restrictions on their resale. Prospective purchasers of the shares offered should conduct their own due diligence on the shares. If you do not understand the contents of this prospectus you should consult an authorized financial advisor.

Australia

No placement document, prospectus, product disclosure statement or other disclosure document has been lodged with the Australian Securities and Investments Commission, or ASIC, in relation to the offering. This prospectus does not constitute a prospectus, product disclosure statement or other disclosure document under the Corporations Act 2001, or the Corporations Act, and does not purport to include the information required for a prospectus, product disclosure statement or other disclosure document under the Corporations Act.

Any offer in Australia of the shares may only be made to persons, or the Exempt Investors, who are “sophisticated investors” (within the meaning of section 708(8) of the Corporations Act), “professional investors” (within the meaning of section 708(11) of the Corporations Act) or otherwise pursuant to one or more exemptions contained in section 708 of the Corporations Act so that it is lawful to offer the shares without disclosure to investors under Chapter 6D of the Corporations Act.

The shares applied for by Exempt Investors in Australia must not be offered for sale in Australia in the period of 12 months after the date of allotment under the offering, except in circumstances where disclosure to investors under Chapter 6D of the Corporations Act would not be required pursuant to an exemption under section 708 of the Corporations Act or otherwise or where the offer is pursuant to a disclosure document which complies with Chapter 6D of the Corporations Act. Any person acquiring shares must observe such Australian on-sale restrictions.

This prospectus contains general information only and does not take into account the investment objectives, financial situation or particular needs of any particular person. It does not contain any securities recommendations or financial product advice. Before making an investment decision, investors need to consider whether the information in this prospectus is appropriate for their needs, objectives and circumstances, and, if necessary, seek expert advice on those matters.

108

New Zealand

The shares of common stock offered hereby have not been offered or sold, and will not be offered or sold, directly or indirectly in New Zealand and no offering materials or advertisements have been or will be distributed in relation to any offer of shares in New Zealand, in each case other than:

•

to persons whose principal business is the investment of money or who, in the course of and for the purposes of their business, habitually invest money; or

•

to persons who in all the circumstances can properly be regarded as having been selected otherwise than as members of the public; or

•

to persons who are each required to pay a minimum subscription price of at least NZ$500,000 for the shares before the allotment of those shares (disregarding any amounts payable, or paid, out of money lent by the issuer or any associated person of the issuer); or

•

in other circumstances where there is no contravention of the Securities Act 1978 of New Zealand (or any statutory modification or re-enactment of, or statutory substitution for, the Securities Act 1978 of New Zealand).

Hong Kong

The shares of common stock have not been offered or sold and will not be offered or sold in Hong Kong, by means of any document, other than (i) to “professional investors” as defined in the Securities and Futures Ordinance (Cap. 571) of Hong Kong and any rules made under that Ordinance; or (ii) in other circumstances which do not result in the document being a “prospectus” as defined in the Companies (Winding Up and Miscellaneous Provisions) Ordinance (Cap. 32) of Hong Kong or which do not constitute an offer to the public within the meaning of that Ordinance. No advertisement, invitation or document relating to the shares of common stock has been or may be issued or has been or may be in the possession of any person for the purposes of issuance, whether in Hong Kong or elsewhere, which is directed at, or the contents of which are likely to be accessed or read by, the public of Hong Kong (except if permitted to do so under the securities laws of Hong Kong) other than with respect to shares of common stock which are or are intended to be disposed of only to persons outside Hong Kong or only to “professional investors” as defined in the Securities and Futures Ordinance and any rules made under that Ordinance.

Japan

No registration pursuant to Article 4, paragraph 1 of the Financial Instruments and Exchange Law of Japan (Law No. 25 of 1948, as amended), or the FIEL, has been made or will be made with respect to the solicitation of the application for the acquisition of the shares of common stock.

Accordingly, the shares of common stock have not been, directly or indirectly, offered or sold and will not be, directly or indirectly, offered or sold in Japan or to, or for the benefit of, any resident of Japan (which term as used herein means any person).

109

LEGAL MATTERS

The validity of our common stock offered by this prospectus will be passed upon for us by Kirkland & Ellis LLP, Houston, Texas. Certain legal matters in connection with this offering will be passed upon for the underwriters by Vinson & Elkins L.L.P., Houston, Texas.

EXPERTS

The financial statements of Vine Oil & Gas LP as of and for the year ended December 31, 2015, included in this prospectus, have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report appearing herein. Such financial statements are included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

The balance sheet of Vine Resources Inc. as of December 31, 2016, included herein in this prospectus, has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report appearing herein. Such financial statement is included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

Estimates of our natural gas reserves, related future net cash flows and the present values thereof related to our properties as of December 31, 2015 included elsewhere in this prospectus were based upon reserve reports prepared by independent petroleum engineers Von Gonten. We have included these estimates in reliance on the authority of such firms as experts in such matters.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement on Form S-1 (including the exhibits, schedules and amendments thereto) under the Securities Act, with respect to the shares of our common stock offered hereby. This prospectus does not contain all of the information set forth in the registration statement and the exhibits and schedules thereto and we refer potential investors to the registration statement and the exhibits and schedules filed therewith for further information. Statements contained in this prospectus as to the contents of any contract, agreement or any other document are summaries of the material terms of such contract, agreement or other document and are not necessarily complete. With respect to each of these contracts, agreements or other documents filed as an exhibit to the registration statement, reference is made to the exhibits for a more complete description of the matter involved. A copy of our registration statement, and the exhibits and schedules thereto, may be inspected without charge at the public reference facilities maintained by the SEC at 100 F Street NE, Washington, D.C. 20549. Copies of these materials may be obtained, upon payment of a duplicating fee, from the Public Reference Room of the SEC at 100 F Street NE, Washington, D.C. 20549. Further information on the operation of the Public Reference Room is available by calling the SEC at 1-800-SEC-0330. The SEC maintains a website that contains reports, proxy and information statements and other information regarding registrants that file electronically with the SEC. The address of the SEC’s website is www.sec.gov.

As a result of the offering, we will become subject to full information requirements of the Exchange Act. We will fulfill our obligations with respect to such requirements by filing periodic reports and other information with the SEC. We intend to furnish our stockholders with annual reports containing financial statements certified by an independent public accounting firm.

110

INDEX TO FINANCIAL STATEMENTS


Vine Resources Inc.
Unaudited Pro Forma Financial Statements as of and for the nine months ended September 30, 2016 and for the year ended December 31, 2015			F-

Vine Oil & Gas LP (Predecessor)
Audited Financial Statements as of and for the year ended December 31, 2015			F-3
Unaudited Financial Statements as of September 30, 2016 and for the nine months ended September 30, 2016 and 2015			F-21

Vine Resources Inc.
Audited Balance Sheet as of December 31, 2016			F-38

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Managers and Partners of

Vine Oil & Gas LP

Dallas, Texas

We have audited the accompanying balance sheet of Vine Oil & Gas LP (the “Company”) as of December 31, 2015, and the related statements of operations, partners’ capital, and cash flows for the year then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States) and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, such financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2015, and the results of its operations and its cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

January 6, 2017

F-2

VINE OIL & GAS LP

STATEMENT OF OPERATIONS

(Amounts in thousands)


	For the Year Ended December 31, 2015
Revenue:
Natural gas sales	$	154,005
Realized gain on derivatives instruments		30,038
Unrealized gain on derivatives instruments		91,008

Total Revenue		275,051

Operating Expenses:
Lease operating		26,190
Gathering and treating		24,085
Production and ad valorem taxes		13,109
General and administrative		9,349
Depletion, depreciation and accretion		118,217
Exploration		2,056
Acquisition-related		207

Total operating expenses		193,213


Operating Income		81,838
Interest expense, net		(87,911	)

Net Income	$	(6,073	)

The accompanying notes are integral to the financial statements.

F-3

VINE OIL & GAS LP

BALANCE SHEET

(Amounts in thousands)


	December 31, 2015
Assets
Current assets:
Cash and cash equivalents	$	15,367
Accounts receivable		21,002
Joint interest billing receivables		44,009
Derivative instruments		49,756
Prepaid and other		948

Total current assets		131,082
Natural gas properties (successful efforts):
Proved		1,359,788
Unproved		70,550
Accumulated depletion		(110,050	)

Total natural gas properties, net		1,320,288

Other property and equipment, net		7,480
Derivative instruments		63,660

Total assets	$	1,522,510


Liabilities and Partners’ Capital
Current liabilities:
Accounts payable	$	26,396
Accrued expenses		40,440
Revenue payable		4,566
Gas gathering liability		49,708

Total current liabilities		121,110
Long-term liabilities:
Long-term debt		710,018
Revolving credit facility		129,807
Gas gathering liability		102,137
Asset retirement obligations		11,230
Other		1,898

Total liabilities		1,076,200
Commitments and contingencies (Note 10)
Partners’ capital		446,310

Total liabilities and partners’ capital	$	1,522,510

The accompanying notes are integral to the financial statements.

F-4

VINE OIL & GAS LP

STATEMENT OF PARTNERS’ CAPITAL

(Amounts in thousands)


Balance as of December 31, 2014	$	451,550
Equity-based compensation		833
Net income		(6,073	)

Balance as of December 31, 2015	$	446,310

The accompanying notes are integral to the financial statements.

F-5

VINE OIL & GAS LP

STATEMENT OF CASH FLOWS

(Amounts in thousands)


	For the Year Ended December 31, 2015
Operating Activities
Net income	$	(6,073	)
Adjustments to reconcile net income to net cash from operating activities:
Depletion, depreciation and accretion		118,217
Amortization and write off of financing costs		11,866
Amortization and write off of debt discount		6,120
Equity-based compensation		833
Unrealized gain on commodity derivative instruments		(91,008	)
Unrealized loss on interest rate derivative instruments		3,422
Payments on gas gathering liability		(43,849	)
Exploration expense		2,056
Volumetric and production adjustment to gas gathering liability		(1,884	)
Changes in assets and liabilities:
Accounts receivable		(13,200	)
Joint interest billing receivables		(44,009	)
Accounts payable and accrued expenses		25,811
Revenue payable		4,566
Other		106

Net cash from operating activities		(27,026	)
Investing Activities
Capital expenditures		(103,496	)

Net cash from investing activities		(103,496	)
Financing Activities
Payments on long-term debt		(100,000	)
Proceeds from revolving credit facility		230,000
Payments on revolving credit facility		(80,000	)
Deferred financing costs paid		(20,090	)

Net cash from financing activities		29,910
Net (decrease) in cash and cash equivalents		(100,612	)
Cash and cash equivalents at beginning of period		115,979

Cash and cash equivalents at end of period	$	15,367

Supplemental information:
Cash paid for interest	$	72,332
Non-cash transactions:
Additions to natural gas properties in accrued expenses	$	14,489

The accompanying notes are integral to the financial statements.

F-6

VINE OIL & GAS LP

NOTES TO FINANCIAL STATEMENTS

(Amounts in thousands)

1.	Nature of Business and Organization

Vine Oil & Gas LP (the “Company,” “we,” “us,” or “our”) is engaged in the development, production and sale of natural gas in the Haynesville and Mid-Bossier plays of the Haynesville Basin in Northern Louisiana. The Company’s executive offices are located in Plano, Texas.

On November 25, 2014, we completed the acquisition of natural gas properties (“Shell Acquisition”) from affiliates of Royal Dutch Shell plc (“Shell”). The total purchase price for the Shell Acquisition was $1.1 billion and was funded by cash contributions from Blackstone and members of management and through the issuance of long term debt.

2.	Summary of Significant Accounting Policies

Basis of Accounting

Use of Estimates

Preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amount of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and reported revenue and expenses during the reporting period. Estimates of reserves are used to determine depletion and to conduct impairment analyses. Estimating reserves has inherent uncertainty, including the projection of future rates of production and the timing of development expenditures.

Cash and Cash Equivalents

We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. We have no cash equivalents as of December 31, 2015.

Receivables

Accounts receivable from joint interest billings sent to our working interest partners are generally collected within 30 to 60 days after they are billed, which usually occurs within 10 days after each month’s end. Other accounts receivable principally consists of amounts due from purchasers of our gas and settled, but not yet paid, derivative receivables. We review our accounts receivable periodically, and if necessary, reduce the carrying amount by a valuation allowance that reflects our best estimate of all potentially uncollectible amounts. We have no allowances for uncollectible accounts receivable as of December 31, 2015.

Natural Gas Properties

We utilize the successful efforts method of accounting for our natural gas producing activities, through which, we capitalize all property acquisition costs and costs of development wells. Costs to drill exploratory wells are capitalized until we complete an evaluation of whether the wells yield proved reserves. If an exploratory well does not yield proved reserves, those well costs are expensed.

F-7

Geological and geophysical costs, including seismic studies and costs of carrying and retaining unproved properties, are charged to exploration expense as incurred. Expenditures for maintenance, repairs and minor renewals necessary to maintain properties in operating condition are charged to workover expense as incurred. Major betterments, replacements and renewals are capitalized as additions to property and equipment.

Proved natural gas properties are depleted on a units-of-production basis based on production and estimates of proved reserves quantities. Because all of our natural gas properties are located in a single basin, we assess depletion on a single cost center for that basin. Capitalized costs of proved mineral interests are depleted over total estimated proved reserves, and capitalized costs of wells and related equipment and facilities are depleted over estimated proved developed reserves. We capitalize interest expense related to significant investments in unproved properties that are not being depleted.

We review our proved properties for impairment annually in the fourth quarter, or whenever events and circumstances indicate that a decline in the recoverability of their carrying values may have occurred. We estimate the expected undiscounted future cash flows of our properties and compare such undiscounted future cash flows to the carrying amount of the properties. If the carrying amount exceeds the estimated undiscounted future cash flows, we adjust the carrying amount of the properties to estimated fair value. Our impairment analysis for natural gas properties does not include value associated with our derivative portfolio. There were no impairments on proved natural gas properties during 2015.

We review our unproved properties for impairment annually in the fourth quarter, or whenever events and circumstances indicate that a decline in the recoverability of their carrying values may have occurred. There were no impairments of our unproved properties during 2015.

Other Property and Equipment

Other property and equipment are recorded at cost and depreciated on a straight-line basis over the individual asset’s useful life, which ranges from 5-25 years, once placed into service.

We evaluate other property and equipment for potential impairment annually in the fourth quarter, or whenever indicators of impairment are present. Circumstances that could indicate potential impairment include significant adverse changes in industry trends and the economic outlook, legal actions, regulatory changes and significant declines in utilization rates.

If we determine that other property and equipment are potentially impaired, we estimate the future undiscounted net cash flow from the use and eventual disposition of the assets grouped at the lowest level at which cash flows can be identified. If that estimate is less than the carrying value of the assets, we recognize an impairment loss equal to the assets’ carrying values in excess of their estimated fair values. There were no impairments on such assets during 2015.

Gathering Liability

In connection with the Shell Acquisition, we became party to two gathering contracts that require delivery of minimum volumes of natural gas for each annual contract period. These gathering contracts require annual settlement payments for any shortfalls in the gathered volumes. Our obligation for the gathering contracts was initially measured at fair value as of the acquisition date and represents the expected volume shortfall over the remaining contract period. The fair value was determined using estimated future production volumes, future inflation factors, and our weighted average cost of capital. We recognize accretion expense for the impact of increasing the discounted liability to its estimated settlement value. The difference, if any, between the estimated payments recognized at inception and actual current contract period payments required are recorded as volumetric and production adjustments to gathering and treating expense.

F-8

Asset Retirement Obligations

Asset retirement obligations (“ARO”) consist of future abandonment costs on our natural gas properties. We record the fair value of the 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 natural gas properties by the same amount as the liability. In periods subsequent to initial measurement, the ARO is recognized as expense through depletion. Changes in the ARO are recognized for both the passage of time and revisions to either the timing or the amount of estimated cash flows. We recognize accretion expense for the impact of increasing the discounted liability to its estimated settlement value.

Revenue Recognition

We recognize revenue when title to our production transfers to the purchaser. We use the sales method to account for our production revenue, whereby we recognize revenue on all production sold to our purchasers, regardless of whether the sales reflect our ownership in the property. A receivable or liability is recognized only to the extent that we have an imbalance on a specific property greater than the expected remaining proved reserves.

Derivatives

To mitigate risks associated with market volatility, we enter into derivative financial instruments, including commodity swaps, to reduce the effects of natural gas price fluctuations on our production and interest rate swaps to stabilize LIBOR fluctuations.

We recognize our derivatives as an asset or liability measured at fair value, with their changes in fair value recognized in earnings. Our derivatives feature monthly settlements with the counterparties, the impact of which is reflected as an operating cash flow. We have not designated any derivative instruments as hedges and do not enter into such instruments for speculative purposes.

The fair value of our commodity swaps is determined by references to published future market prices and interest rates. We estimate the fair value of our interest rate swaps primarily by using internal discounted cash flow calculations based upon forward interest rates. The most significant variable to our cash flow calculations is our estimate of future interest rates. We base these estimates on our own internal model that utilizes forward curves such as LIBOR or the Federal Funds Rate provided by third parties. The resulting estimated future cash inflows or outflows over the lives of the contracts are discounted using LIBOR and money market futures rates.

Income Taxes

As a limited partnership, we are not a taxpaying entity for federal income tax purposes. As such, we have not recorded federal income tax expense. Our limited partners are responsible for federal income taxes on their respective share of taxable income. We file federal income tax returns in the United States. We incurred de minimis state taxes during 2015, and the accompanying financial statements reflect such taxes.

As of December 31, 2015, no tax returns remained open to possible examination by the tax authorities, and none are currently under examination by any tax authorities. We have incurred no penalties or interest related to tax matters, and we have no uncertain tax positions.

Concentrations of Credit Risk

Financial instruments that potentially subject us to a concentration of credit risk consist principally of cash, certificates of deposit, joint interest billing receivables, accounts receivable and derivative financial instruments. We maintain cash deposits primarily in one financial institution, the total of which, regularly exceeds the amount covered by insurance provided by the U.S. Federal Deposit Insurance Corporation (“FDIC”). We have not experienced any losses related to amounts in excess of FDIC limits.

F-9

In 2015, we began utilizing an unaffiliated third party to market the majority of our gas production to various purchasers, which consist of credit-worthy counterparties, including 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 an affiliate of Shell who remits directly to us. Our receivables from purchasers are generally unsecured; however, we have not experienced any credit losses to date.

The counterparties to most of our derivatives are financial institutions that participate in our credit facility and that we believe have acceptable credit ratings.

Generally, we have the right to offset future revenue against unpaid joint interest billing charges.

Recently Issued Accounting Standards

Adopted

The Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2015-03, “Interest — Imputation of Interest (Subtopic 835-30): Simplification of Debt Issuance Costs” which requires debt issuance costs, other than those related to line-of-credit arrangements, be presented as a direct deduction from the face amount of the related debt liability, similar to the presentation for debt discounts. We have elected this presentation in our financial statements and footnote disclosures for periods after January 1, 2015.

Not Yet Adopted

The FASB issued ASU No. 2016-15, “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force)” in order to reduce diversity in practice in classifying transactions for cash flow purposes. The update addresses eight different transaction types and clarifies how to classify each in the statement of cash flows. We expect to adopt this guidance January 1, 2018, however, the impact is not expected to be material.

The FASB issued ASU No. 2016-13, “Financial Instruments — Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” which introduces guidance for estimating credit losses on certain types of financial instruments based on expected losses and the timing of the recognition of such losses. We expect to adopt this guidance January 1, 2020, however, the impact is not expected to be material.

The FASB issued ASU No. 2016-09, Compensation — Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (“Update 2016-09”), which seeks to simplify several aspects of the accounting for share-based payments, including income tax consequences, classification of awards as either equity or liabilities, and their cash flow classification. We expect to adopt this guidance January 1, 2017. We are currently evaluating the new guidance to determine the impact it will have on our financial statements.

The FASB issued ASU No. 2016-02, Leases (Topic 842) which requires leases to be recognized as assets and liabilities. This ASU becomes effective for us beginning January 1, 2019 but does not apply to oil and gas leases. We are currently evaluating the new guidance to determine the impact it will have on our financial statements.

The FASB issued ASU No. 2015-17 which requires non-current classification of all deferred tax assets and liabilities. This update becomes effective for us January 1, 2017, however, the impact is not expected to be material.

The FASB issued ASU No. 2014-15, “Presentation of Financial Statements — Going Concern” (Subtopic 205-40) which provides guidance on management’s responsibility to evaluate whether a substantial doubt exists regarding an entity’s ability to continue as a going concern and the disclosure thereof. We will adopt this ASU on January 1, 2017 but do not expect it to have a material impact.

F-10

The FASB issued ASU No. 2014-09 that introduces a new five-step revenue recognition model in which an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This ASU also requires disclosures sufficient to enable users to understand the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers, including qualitative and quantitative disclosures about contracts with customers, significant judgments and changes in judgments, and assets recognized from the costs to obtain or fulfill a contract. In August 2015, the FASB issued ASU No. 2015-14, which deferred the required adoption of ASU No. 2014-09 for one year. We expect to adopt this guidance January 1, 2018, however, the impact is not expected to be material.

3.	Property and Equipment

Natural Gas Properties

Our natural gas properties consisted of the following:


	December 31, 2015
Proved natural gas properties subject to depletion	$	1,359,788
Unproved natural gas properties		70,550

Total capitalized costs		1,430,338
Less: Accumulated depletion		(110,050	)

Natural gas properties, net	$	1,320,288

We recognized depletion expense of $100.6 million during 2015. We capitalized interest of $7.2 million during 2015.

Other Property and Equipment

Our other property and equipment consisted of the following:


	December 31, 2015
Software development costs	$	6,600
Other		2,055

Total cost		8,655
Accumulated depreciation		(1,175	)

Other property and equipment, net	$	7,480

We recognized depreciation expense of $1.1 million during 2015.

4.	Asset Retirement Obligations

The following table summarizes changes in our estimated ARO:


	December 31, 2015
Balance, beginning of period	$	10,260
Accretion expense		875
Liabilities incurred		95

Balance, end of period	$	11,230

F-11

5.	Gathering Liability

The following table summarizes changes in our gathering liability:


	December 31, 2015
Balance, beginning of period	$	181,995
Payments on liability		(43,849	)
Accretion expense		15,579
Expense adjustment		(1,880	)

Balance, end of period	$	151,845

The discounted value of the estimated remaining gathering liability as of December 31, 2015:


2016	$	49,708
2017		45,006
2018		33,239
2019		19,461
2020		4,431

Total gathering liability	$	151,845

6.	Long-Term Debt

During 2014, we executed a series of debt transactions in conjunction with the Shell Acquisition. We entered into our credit facility and borrowed under our Term Loan B and Term Loan C. We used the net proceeds to fund a portion of the purchase price and pay transaction expenses.

Revolving Credit Facility

During 2014, we entered into a five-year first lien credit facility (the “RBL”) with a syndicate of banks. This reserved-based facility features a borrowing base equal to the greater of a fixed amount or a variable amount. The fixed amount was set at $250.0 million. The variable amount is based upon the value of our reserves as assessed by the banking syndicate. The borrowing base for the RBL is supported by the value of our proved reserves and is redetermined semi-annually in April and October. The RBL has a variable annual interest rate based on adjusted LIBOR or Alternate Base Rate (“ABR”) plus an applicable margin. LIBOR loans bear interest at the U.S. dollar LIBOR rate plus a margin ranging between 1.5% and 2.5% per annum depending on the borrowing base utilization. ABR loans bear interest at the ABR rate plus a margin ranging between 0.5% and 1.5% per annum depending on the borrowing base utilization. In addition, a commitment fee between 0.375% and 0.5% per annum is charged on the unutilized balance of the committed borrowing base and is included in interest expense. During 2015, total interest expense relating to the RBL, including amortization of deferred debt issuance costs and unutilized commitment fees, amounted to $8.4 million. As of December 31, 2015, the fair value of the RBL approximates carrying value as it bears interest at variable rates over the term of the loan.

In January 2015, we entered into an amendment to the RBL which included the following changes: (1) increased the fixed amount to $350.0 million; (2) added the ability to extend (not more than twice) the maturity of the commitments for up to one year; and (3) added the ability to incur up to $150.0 million in additional superpriority indebtedness.

As of December 31, 2015, the Company had outstanding letters of credit of $37 million.

F-12

Term Loan B

During 2014, we borrowed $500.0 million under our seven-year Term Loan B (“TLB”), which is secured on a secondary priority basis. The term loans were borrowed at 97% of par and incurred debt issuance cost of $16.5 million. The TLB has a variable annual interest rate based on adjusted LIBOR (which is subject to a floor of 1%) plus an applicable margin of 6.875% or ABR (which is subject to a floor of 2%) plus an applicable margin of 5.875%. During 2015, total interest expense relating to TLB, including amortization of original issue discount and deferred debt issuance costs, amounted to $35.8 million. Interest is currently paid monthly.

In January 2015, we drew $124.3 million on the RBL to (1) repay $100.0 million of TLB principal; fund $20.0 million in modification fees which are being amortized over the remaining term of the RBL and; (3) pay accrued interest of $4.3 million on TLB and TLC. In conjunction with the $100 million repayment, we wrote off $6.2 million of the original issue discount and deferred debt issuance costs. This amount is included in interest expense, net on the accompanying statement of operations. As of December 31, 2015 the fair value of the TLB is approximately $270 million.

Term Loan C

During 2014, we borrowed $350.0 million under our seven-and-a-half-year Term Loan C (“TLC”), which is secured on a third priority basis. The term loans were borrowed at 97% of par and incurred debt issuance cost of $11.5 million. The TLC has a variable annual interest rate based on adjusted LIBOR (which is subject to a floor of 1%) plus an applicable margin of 9% or ABR (which is subject to a floor of 2%) plus an applicable margin of 8%. During 2015, total interest expense relating to TLC, including amortization of original issue discount and deferred debt issuance costs, amounted to $38.6 million. Interest is currently paid monthly. As of December 31, 2015 the fair value of the TLC is approximately $200 million.

Long-term debt consisted of the following:


	December 31, 2015
RBL, face amount	$	150,000
TLB, face amount		400,000
TLC, face amount		350,000

Total face amount		900,000

RBL, deferred finance costs		(20,193	)
TLB, deferred finance costs		(11,094	)
TLC, deferred finance costs		(9,857	)

Total deferred finance costs		(41,144	)

TLB, discount		(10,090	)
TLC, discount		(8,941	)

Total discount		(19,031	)

Total debt		839,825
Less: short-term portion		—

Total long-term debt	$	839,825

Other Information

As of December 31, 2015, the prepayment premium on TLB was 1% and 2% on TLC, though these reduced to 0% and 1%, respectively, in November 2016. There are no prepayment premiums or penalties associated with the RBL.

F-13

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

7.	Fair Value Measurements

Certain of our assets and liabilities are measured at fair value. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. We use market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. GAAP establishes a fair value hierarchy that prioritizes the inputs used to measure fair value.

The three levels of fair value hierarchy are as follows:

•

Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date.

•

Level 2 — Pricing inputs are other than quoted prices in active markets, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies.

•

Level 3 — Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.

Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Assessment of the significance of a particular input requires judgment that may affect the valuation and its placement within the hierarchy levels.

The carrying values of financial instruments, including accounts receivable and accounts payable, approximate fair value due to the short maturity of these instruments. None of our financial instruments are held for trading purposes.

All derivative financial instruments are Level 2 measurements as independent quoted market prices are not available in active markets.

Certain assets are measured at fair value on a non-recurring basis. These assets can include long-lived assets that have been reduced to fair value when they are held for sale, initial recognition of ARO and proved and unproved properties that are written down to fair value when they are impaired. The fair value of our natural gas properties is determined using valuation techniques consistent with the income and market approach.

F-14

8.	Derivative Instruments

Derivative assets and liabilities are presented as gross assets and liabilities, without regard to master netting arrangements, which are considered in the presentation of derivative assets and liabilities in the accompanying balance sheet. The following table summarizes the gross fair value of our derivative assets and liabilities and the effect of netting as of December 31, 2015:


	Balance Sheet Classification		Gross Amounts		Netting Adjustment		Net Amounts Presented on the Balance Sheet
December 31, 2015:
Assets:
Commodity Derivative instruments		Current derivative instruments	$	49,756	$	—	$	49,756
Commodity Derivative instruments		Noncurrent derivative instruments		63,660		—		63,660

Total assets			$	113,416	$	—	$	113,416

Liabilities:
Interest Rate Derivative instruments		Accrued expenses	$	4,228	$	—	$	4,228
Interest Rate Derivative instruments		Other long-term liabilities		—		—		—

Total liabilities			$	4,228	$	—	$	4,228

Commodity Derivatives

The following summarizes our commodity derivative positions as of December 31, 2015:


Production Year	Daily Volumes (MMBTU)		Swap Price Henry Hub (NYMEX)
2016		122,521	$	3.60
2017		122,466	$	3.67
2018		70,000	$	3.62
2019		42,466	$	3.47

In early 2016, we restructured the portfolio to move the value of our 2018 and 2019 hedges to increase the swap price of new swaps covering the last three quarters of 2016 and all of 2017, respectively. No gain or loss was recorded on the restructuring.

Interest Rate Derivatives

In June 2015, we entered into two interest rate derivative instruments, which swapped $750.0 million of our variable-rate debt based on one-month LIBOR into fixed rate debt.

During 2015, we had $3.4 million of unrealized losses, which are reflected in interest expense. The following summarizes our interest rate derivative positions as of December 31, 2015:

Notional Principal Amount

Fixed Rate

Effective Date

Maturity Date

$400.0 million

1.784

June 30, 2015

June 30, 2019

$350.0 million

1.495

July 6, 2015

June 30, 2018

F-15

9.	Partners’ Capital and Profit Interests Awards

Background

The Partnership Agreement (the “Agreement”) authorizes the issuance of two classes of equity interests: General Partner Interests and Limited Partnership Interests. The Limited Partnership Interests are divided into three series: Class A Units, Class B Units and Class C Units, each with the rights, privileges, preferences, restrictions and obligations as provided in the Agreement.

A total of 100 General Partner interests are authorized for issuance, 100 Class A Units, 2,000,000 Class B Units and 5,000 Class C Units. Each Class B Unit and Class C Unit has a fixed price of $1,000.

In general, cash distributions follow a waterfall set out in the Agreement whereby the Class B and Class C Unit Holders (collectively, the “Common Unit Holders”) receive payment until they have received distributions equal to the amount of their respective capital contributed. Once the capital is returned and certain rate of returns are achieved, distributions will be made to Class A Unit Holders in accordance with the Agreement. The distributions to Class A Holders increase based on stated return thresholds to the Common Unit Holders.

Class A Units

The Class A Units are Partnership interests that provide economic incentives to our employees who receive them. The Class A Units are intended to be “profits interests.” The Class A Units vest over a five-year period and may be forfeited or repurchased by the Company under certain circumstances as set forth in the plan governing the Class A Units and individual Class A Unit grant agreements.

The Company has granted Class A Units to select members of the Company’s management. Most of the Class A Units are treated as conditionally vesting equity but are deemed to be a profit sharing arrangement due to certain forfeiture or repurchase features of the plan. Award recipients may derive economic value in the instrument through profit sharing distributions. As such, these Class A Units are a compensation liability award and will trigger no compensation expense until amounts payable under such awards become probable and estimable.

The remainder of the Class A Units are also deemed to be equity; however, they have different forfeiture and repurchase features, and as such, the units are accounted for as equity-based compensation.

The following table summarizes the Class A Unit activity for 2015:


	Class A Units
	Equity-based Compensation Awards		Liability Awards		Total
Outstanding at January 1, 2015		40.0		30.5		70.5
Granted		—		19.0		19.0
Forfeited		—		—		—

Outstanding at December 31, 2015		40.0		49.5		89.5

We utilized the Black Scholes option pricing method to estimate grant date fair value of the equity-based compensation awards, which included probability of various outcomes. Expected volatilities are based on historical volatilities of the stock of comparable companies in our industry. The risk-free rate for periods within the contractual life of the option is based on the U.S. Treasury yield curve in effect at the time of grant. Actual

F-16

results may vary depending on the assumptions applied within the model. The following table presents the assumptions used in the valuation and resulting grant date fair value:

Expected volatility — 40.0%

Expected dividends — N/A

Expected term — 4.2 years

Risk-free rate — 1.20%

The grant date fair value of the Class A equity-based compensation awards was $3.0 million.

Compensation expense is recognized on a straight-line basis over the requisite service period. During 2015, we recognized compensation expense of $0.8 million. Total unrecognized compensation costs related to unvested awards at December 31, 2015 is $2.2 million and is expected to be recognized over the next four years. No distributions were made during 2015.

Class B Units

As of December 31, 2015, there were 462,517 Class B Units issued and outstanding in exchange for capital contributions.

Class C Units

As of December 31, 2015, there were 2,704 Class C Units issued and outstanding in exchange for capital contributions. Due to their redemption attributes, the capital contributed for Class C Units is included in other long-term liabilities.

10.

Commitments and Contingencies

Litigation

Occasionally, we are subject to legal proceedings and claims that arise in the ordinary course of business. Like other natural gas producers, our operations are subject to extensive and rapidly changing federal and state environmental, health and safety and other laws and regulations governing air emissions, wastewater discharges and solid and hazardous waste management activities. We are not currently a party to any material legal proceeding and are not aware of any material legal or governmental proceedings against us or contemplated to be brought against us.

Environmental Remediation

We may become subject to certain liabilities as they relate to environmental remediation of well sites related to their development or operation. In connection with our acquisition of existing or previously drilled wells, we may not be aware of the environmental safeguards that were taken at the time such wells were drilled or operated. Should we determine that a liability exists with respect to any environmental cleanup or restoration, we would be responsible for curing such a violation. No claim has been made, nor are we aware of any liability that exists, as it relates to any environmental cleanup or restoration or the violation of any rules or regulations relating thereto.

11.

Related Party Transactions

During 2015, we recognized aggregate expense of $1.6 million under a management and consulting agreement with Blackstone and our CEO, of which over 98% was attributable to Blackstone.

In January 2015, Blackstone became a significant creditor under the TLB and TLC.

F-17

12.

Subsequent Events

We have evaluated subsequent events through January 6, 2017, the date on which these financial statements were available for issuance.

13.

Supplemental Natural Gas Reserve Information (Unaudited)

Natural Gas Quantities and Property Summary

The reserves at December 31, 2015 presented below were prepared by the independent engineering firm Von Gonten. All our reserves are located within the stacked Haynesville and Mid-Bossier shale plays in the Haynesville Basin of Northwest Louisiana. Proved natural gas reserves are the estimated quantities of natural gas which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimate is made. Proved developed natural gas reserves are proved reserves that can be expected to be recovered through existing wells and equipment in place and under operating methods being utilized at the time the estimates were made. A variety of methodologies are used to determine our proved reserve estimates. The principal methodologies employed are decline curve analysis, advance production type curve matching, petro physics/log analysis and analogy. Some combination of these methods is used to determine our reserve estimates. Reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing natural gas properties. Accordingly, these estimates are expected to change as future information becomes available.

The following summarizes the changes in our proved reserves (in MMcf):


Balance at December 31, 2014	934,459
Production	(61,832	)
Revision of previous estimates⁽¹⁾	6,765
Acquisitions of reserves⁽²⁾	61,362
Extensions and discoveries⁽³⁾	353,561

Balance at December 31, 2015	1,294,315

Proved developed reserves	132,394

Proved undeveloped reserves	1,161,921

(1)	Revision of previous estimates reflect changes in previous estimates attributable to negative changes in economic factors of 40,401 MMcf, offset by changes in non-economic factors of 47,166 MMcf, including:

•

Well performance of producing wells (increase of 18,798 MMcf)

•

Revisions to type curves of wells based on producing analogs (increase of 13,026 MMcf)

•

Revisions to working interests for proved properties (increase of 11,281 MMcf)

•

Well performance of new wells converted to producing in 2015 (increase of 2,292 MMcf)

•

Revisions to future well locations to optimize development (increase of 1,769 MMcf)

(2)	Our acquisition of reserves is attributable to additional leasing, which gave rise to incremental locations in the Haynesville shale.

(3)	Extensions and discoveries represent extensions to reserves attributable to additional gross locations to be developed in 2020 and reflect updated future rig count.

F-18

The carrying value of our natural gas assets as of December 31, 2015 was as follows:


Proved properties	$	1,359,788
Unevaluated properties		70,550
Accumulated DD&A		(110,050	)

Net capitalized costs	$	1,320,288

Our capital costs incurred for acquisition, exploration and development activities during 2015 were as follows:


Proved acreage	$	5,376
Unproved acreage		—
Development costs		87,749

Total	$	93,125

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Natural Gas Reserves

We develop the standardized measure of discounted future net cash flows from production of proved reserves using: (1) Estimates are made of quantities of proved reserves and future periods during which they are expected to be produced based on year-end economic conditions. (2) The estimated future cash flows are determined multiplying production by the twelve month average of the first of the month prices. (3) The future production and development costs are determined based on year-end economic conditions. (4) Future net cash flows are discounted to present value by applying a discount rate of 10%.

The assumptions used to compute the standardized measure are those prescribed by the FASB and the SEC and do not reflect the expected undiscounted or discounted cash flows or the estimated fair value. The limitations inherent in the reserve quantity estimation process, as previously discussed, are equally applicable to the standardized measure computations, since these reserve quantity estimates are the basis for the valuation process.

The Standardized Measure at December 31, 2015 was as follows:


Future natural gas sales	$	3,231,200
Future production costs		(1,122,274	)
Future development costs		(1,503,993	)
Future income tax expense⁽¹⁾		—

Future net cash flows	$	604,933

10% annual discount		(327,712	)

Standardized measure of discounted future net cash flows	$	277,221

F-19

The primary changes in the standardized measure during 2015:


Balance at beginning of period	$	1,109,131
Sales of natural gas, net		(136,639	)
Revision of previous quantity estimates		150,213
Acquisitions of reserves		76,192
Previously estimated development costs incurred		172,943
Net changes in future development costs		—
Net changes in prices		(1,435,570	)
Accretion of discount		102,360
Net change in income taxes⁽¹⁾		—
Changes in timing and other differences		238,591

Balance at end of period	$	277,221

(1)	Our calculations of the standardized measure of discounted future net cash flows and the related changes therein do not include the effect of estimated future income tax expenses because we are not subject to income taxes.

F-20

VINE OIL & GAS LP

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Amounts in thousands — Unaudited)


	For the Nine Months Ended September 30,
	2016			2015
Revenue:
Natural gas sales	$	119,572		$	122,405
Realized gain on commodity derivatives		55,068			15,298
Unrealized gain (loss) on commodity derivatives		(83,226	)		77,592

Total revenue		91,414			215,295
Operating Expenses:
Lease operating		15,916			19,826
Gathering and treating		16,299			19,520
Production and ad valorem taxes		7,717			9,985
General and administrative		3,016			7,729
Depletion, depreciation and accretion		82,215			86,277
Exploration		1,915			2,084
Acquisition-related		—			182

Total operating expenses		127,078			145,603

Operating Income		(35,664	)		69,692

Interest expense, net		(67,450	)		(69,806	)

Income before income taxes		(103,114	)		(114	)

Income tax provision		(168	)		—

Net Income	$	(103,282	)	$	(114	)

The accompanying notes are integral to the financial statements.

F-21

VINE OIL & GAS LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Amounts in thousands — Unaudited)


	September 30, 2016			December 31, 2015
Assets
Current assets:
Cash and cash equivalents	$	45,664		$	15,367
Accounts receivable		26,365			21,002
Joint interest billing receivables		58,787			44,009
Derivative instruments		24,970			49,756
Prepaid and other		203			948

Total current assets		155,989			131,082

Natural gas properties (successful efforts):
Proved		1,466,161			1,359,788
Unproved		75,209			70,550
Accumulated depletion		(180,586	)		(110,050	)

Total natural gas properties, net		1,360,784			1,320,288

Other property and equipment, net		7,716			7,480
Derivative instruments		5,219			63,660

Total assets	$	1,529,708		$	1,522,510

Liabilities and Partners’ Capital
Current liabilities:
Accounts payable	$	10,284		$	26,396
Accrued expenses		71,536			40,440
Revenue payable		8,930			4,566
Gas gathering liability		40,370			49,708

Total current liabilities		131,120			121,110

Long-term liabilities:
Long-term debt		714,994			710,018
Revolving credit facility		231,205			129,807
Gas gathering liability		89,368			102,137
Asset retirement obligations		12,214			11,230
Other		7,154			1,898

Total liabilities		1,186,055			1,076,200

Commitments and contingencies (Note 10)
Partners’ capital		343,653			446,310

Total liabilities and partners’ capital	$	1,529,708		$	1,522,510

The accompanying notes are integral to the financial statements.

F-22

VINE OIL & GAS LP

CONDENSED CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL

(Amounts in thousands — Unaudited)


Balance as of December 31, 2015	$	446,310
Equity-based compensation		625
Net income		(103,282	)

Balance as of September 30, 2016	$	343,653

The accompanying notes are integral to the financial statements.

F-23

VINE OIL & GAS LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Amounts in thousands — Unaudited)


	For the Nine Months Ended September 30,
	2016			2015
Operating Activities
Net income	$	(103,282	)	$	(114	)
Adjustments to reconcile net income to net cash from operating activities:
Depletion, depreciation and accretion		82,215			86,277
Amortization of financing costs		6,504			9,681
Amortization of debt discount		2,370			5,324
Equity-based compensation		625			625
Unrealized (gain) loss on commodity derivatives		83,226			(77,592	)
Volumetric and production adjustment to gas gathering liability		(7,295	)		—
Unrealized loss on interest rate derivatives		4,535			5,213
Payment on gas gathering liability		(24,514	)		(19,868	)
Exploration expense		1,915			2,084
Other		(945	)		—
Changes in assets and liabilities:
Accounts receivable		(5,363	)		(11,016	)
Joint interest billing receivables		(14,778	)		(29,451	)
Accounts payable and accrued expenses		14,339			35,252
Revenue payable		4,364			5,708
Other		1,629			193

Net cash from operating activities		45,545			12,316

Investing Activities
Capital expenditures		(112,748	)		(72,913	)

Net cash from investing activities		(112,748	)		(72,913	)

Financing Activities
Payments on long-term debt		—			(100,000	)
Proceeds from revolving credit facility		97,500			152,000
Payments on revolving credit facility		—			(80,000	)
Deferred financing costs paid		—			(20,090	)

Net cash from financing activities		97,500			(48,090	)

Net increase in cash and cash equivalents		30,297			(108,687	)
Cash and cash equivalents at beginning of period		15,367			115,979

Cash and cash equivalents at end of period	$	45,664		$	7,292

Supplemental information:
Cash paid for interest	$	54,324		$	54,566

Non-cash transactions:
Additions to natural gas properties in accrued expenses	$	14,970		$	18,265

The accompanying notes are integral to the financial statements.

F-24

VINE OIL & GAS LP

CONDENSED CONSOLIDATED NOTES TO FINANCIAL STATEMENTS

(Amounts in thousands — Unaudited)

1.	Nature of Business and Organization

Vine Oil & Gas LP (the “Company,” “we,” “us,” or “our”), is engaged in the development, production and sale of natural gas in the Haynesville and Mid-Bossier plays of the Haynesville Basin in Northern Louisiana. The Company’s executive offices are located in Plano, Texas.

We were organized as a Delaware partnership on May 28, 2014, with our principal ownership being Blackstone Energy Partners, an affiliate of The Blackstone Group L.P. (collectively “Blackstone”), which owns 99% of the outstanding partner units. For the nine months ended September 30, 2016 (the “2016 Period”), the accompanying consolidated financial statements also include the results of Vine Management Services LLC (“VMS”) which was formed in March 2016 and provides services and back office support to us. All material intercompany balances and transactions have been eliminated in consolidation.

2.	Summary of Significant Accounting Policies

Basis of Accounting

These financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”). We had no items of other comprehensive income (loss) for the 2016 Period or the nine months ended September 30, 2015 (the “2015 Period”). The Company operates only one reportable segment. In our opinion, all adjustments, consisting primarily of normal recurring accruals that are considered necessary for a fair statement of consolidated financial information, have been included; however, operating results for the period presented are not necessarily indicative of the results that may be expected for a full year. These unaudited financial statements should be read in conjunction with our audited financial statements and notes for the year ended December 31, 2015.

Use of Estimates

Cash and Cash Equivalents

We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. We have no cash equivalents as of September 30, 2016.

Receivables

F-25

accounts receivable principally consists of amounts due from purchasers of our gas and settled, but not yet paid, derivative receivables. We review our accounts receivable periodically, and if necessary, reduce the carrying amount by a valuation allowance that reflects our best estimate of all potentially uncollectible amounts. We have no allowances for uncollectible accounts receivable as of September 30, 2016 or December 31, 2015.

Natural Gas Properties

Other Property and Equipment

Other property and equipment are recorded at cost and depreciated on a straight-line basis over the individual asset’s useful life, which ranges from 5-25 years, once placed into service.

F-26

Gathering Liability

Asset Retirement Obligations

Revenue Recognition

Derivatives

Income Taxes

As a limited partnership, we are not a taxpaying entity for federal income tax purposes. As such, we have not recorded federal income tax expense. Our limited partners are responsible for federal income taxes on their respective share of taxable income. We file federal income tax returns in the United States. We incurred de minimis state taxes, and the accompanying financial statements reflect such taxes.

F-27

VMS is taxed as a C-corporation, recognizing income taxes using the liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying values and tax bases of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which these temporary differences are expected to be recovered or settled. We recognize the effect of changes in tax rates in income in the period when enacted. In addition, we establish a valuation allowance if it is determined that it is more likely than not that some portion of the deferred tax asset will not be realized. There were no deferred tax assets, liabilities or valuation allowances as of September 30, 2016.

As of September 30, 2016, no tax returns remained open to possible examination by the tax authorities, and none are currently under examination by any tax authorities. We have incurred no penalties or interest related to tax matters, and we have no uncertain tax positions.

Concentrations of Credit Risk

The counterparties to most of our derivatives are financial institutions that participate in our credit facility and that we believe have acceptable credit ratings.

Generally, we have the right to offset future revenue against unpaid joint interest billing charges.

Recently Issued Accounting Standards

Adopted

The Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2015-03, “Interest — Imputation of Interest (Subtopic 835-30): Simplification of Debt Issuance Costs” which requires debt issuance costs, other than those related to line-of-credit arrangements, be presented as a direct deduction from the face amount of the related debt liability, similar to the presentation for debt discounts. We have elected this presentation in our consolidated financial statements and footnote disclosures for periods after January 1, 2015.

Not Yet Adopted

F-28

The FASB issued ASU No. 2014-09 that introduces a new five-step revenue recognition model in which an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This ASU also requires disclosures sufficient to enable users to understand the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers, including qualitative and quantitative disclosures about contracts with customers, significant judgments and changes in judgments, and assets recognized from the costs to obtain or fulfill a contract. In August 2015, the FASB issued ASU No. 2015-14, which deferred the required adoption of ASU No. 2014-09 for one year. We expect to adopt this guidance January 1, 2018; however, the impact is not expected to be material.

3.	Property and Equipment

Natural Gas Properties

Our natural gas properties consisted of the following:


	September 30, 2016			December 31, 2015
Proved natural gas properties subject to depletion	$	1,466,161		$	1,359,788
Unproved natural gas properties		75,209			70,550

Total capitalized costs		1,541,370			1,430,338
Less: Accumulated depletion		(180,586	)		(110,050	)

Natural gas properties, net	$	1,360,784		$	1,320,288

We recognized depletion expense, for the 2016 and 2015 Periods, of $70.5 million and $73.5 million, respectively. For the 2016 and 2015 Periods, we capitalized interest of $4.6 million and $5.4 million, respectively.

F-29

Other Property and Equipment

Our other property and equipment consisted of the following:


	September 30, 2016			December 31, 2015
Software development costs	$	7,789		$	6,600
Other		2,577			2,055

Total cost		10,366			8,655
Accumulated depreciation		(2,650	)		(1,175	)

Other property and equipment, net	$	7,716		$	7,480

We recognized depreciation expense, for the 2016 and 2015 Periods, of $2.6 million and $0.4 million, respectively.

4.	Asset Retirement Obligations

The following table summarizes changes in our estimated ARO:


	For the Nine Months Ended September 30, 2016
Balance, beginning of period	$	11,230
Accretion expense		720
Liabilities incurred		264

Balance, end of period	$	12,214

5.	Gathering Liability

The following table summarizes changes in our gathering liability:


	For the Nine Months Ended September 30, 2016
Balance, beginning of period	$	151,845
Payments on liability		(24,514	)
Accretion expense		9,703
Expense adjustment		(7,296	)

Balance, end of period	$	129,738

The discounted value of the estimated remaining gathering liability as of September 30, 2016 is as follows:


Remainder of 2016	$	19,884
2017		47,855
2018		36,072
2019		21,119
2020		4,808

Total gathering liability	$	129,738

6.	Long-Term Debt

F-30

Revolving Credit Facility

During 2014, we entered into a five-year first lien credit facility (the “RBL”) with a syndicate of banks. This reserved-based facility features a borrowing base equal to the greater of a fixed amount or a variable amount. The fixed amount was set at $250.0 million. The variable amount is based upon the value of our reserves as assessed by the banking syndicate. The borrowing base for the RBL is supported by the value of our proved reserves and is redetermined semi-annually in April and October. The RBL has a variable annual interest rate based on adjusted LIBOR or Alternate Base Rate (“ABR”) plus an applicable margin. LIBOR loans bear interest at the U.S. dollar LIBOR rate plus a margin ranging between 1.5% and 2.5% per annum depending on the borrowing base utilization. ABR loans bear interest at the ABR rate plus a margin ranging between 0.5% and 1.5% per annum depending on the borrowing base utilization. In addition, a commitment fee between 0.375% and 0.5% per annum is charged on the unutilized balance of the committed borrowing base and is included in interest expense. Total interest expense relating to the RBL, including amortization of deferred debt issuance costs and unutilized commitment fees, for the 2016 and 2015 Periods was $8.1 million and $1.5 million, respectively. As of September 30, 2016, the fair value of the RBL approximates carrying value as it bears interest at variable rates over the term of the loan.

As of September 30, 2016, the Company had outstanding letters of credit of $37.5 million.

Term Loan B

During 2014, we borrowed $500.0 million under our seven-year Term Loan B (“TLB”), which is secured on a secondary priority basis. The term loans were borrowed at 97% of par and incurred debt issuance cost of $16.5 million. The TLB has a variable annual interest rate based on adjusted LIBOR (which is subject to a floor of 1%) plus an applicable margin of 6.875% or ABR (which is subject to a floor of 2%) plus an applicable margin of 5.875%. Total interest expense relating to TLB, including amortization of original issue discount and deferred debt issuance costs, was $26.8 million for each of the 2016 and 2015 Periods. Interest is currently paid monthly.

In January 2015, we drew $124.3 million on the RBL to (1) repay $100.0 million of TLB principal; fund $20.0 million in modification fees which are being amortized over the remaining term of the RBL and; (3) pay accrued interest of $4.3 million on TLB and TLC. In conjunction with the $100 million repayment, we wrote off $6.2 million of the original issue discount and deferred debt issuance costs. This amount is included in interest expense, net on the accompanying statement of operations. As of September 30, 2016, the fair value of TLB is approximately $300 million.

Term Loan C

During 2014, we borrowed $350.0 million under our seven-and-a-half-year Term Loan C (“TLC”), which is secured on a third priority basis. The term loans were borrowed at 97% of par and incurred debt issuance cost of $11.5 million. The TLC has a variable annual interest rate based on adjusted LIBOR (which is subject to a floor of 1%) plus an applicable margin of 9% or ABR (which is subject to a floor of 2%) plus an applicable margin of 8%. Total interest expense relating to TLC, including amortization of original issue discount and deferred debt issuance costs, for the 2016 and 2015 Periods, was $28.9 million and $28.8 million, respectively. Interest is currently paid monthly. As of September 30, 2016, the fair value of TLC is approximately $240 million.

F-31

Long-term debt consisted of the following:


	September 30, 2016			December 31, 2015
RBL, face amount	$	247,500		$	150,000
TLB, face amount		400,000			400,000
TLC, face amount		350,000			350,000

Total face amount		997,500			900,000
RBL, deferred finance costs		(16,295	)		(20,193	)
TLB, deferred finance costs		(9,659	)		(11,094	)
TLC, deferred finance costs		(8,686	)		(9,857	)

Total deferred finance costs		(34,640	)		(41,144	)
TLB, discount		(8,786	)		(10,090	)
TLC, discount		(7,875	)		(8,941	)

Total discount		(16,661	)		(19,031	)

Total debt		946,199			839,825
Less: short-term portion		—			—

Total long-term debt	$	946,199		$	839,825

Other Information

As of September 30, 2016, the prepayment premium on TLB was 1% and 2% on TLC, though these reduced to 0% and 1%, respectively, in November 2016. There are no prepayment premiums or penalties associated with the RBL.

7.	Fair Value Measurements

The three levels of fair value hierarchy are as follows:

•

Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date.

•

F-32

All derivative financial instruments are Level 2 measurements as independent quoted market prices are not available in active markets.

Certain assets are measured at fair value on a non-recurring basis. These assets can include long-lived assets that have been reduced to fair value when they are held for sale, the initial recognition of ARO and proved and unproved properties that are written down to fair value when they are impaired. The fair value of our natural gas properties is determined using valuation techniques consistent with the income and market approach.

8.	Derivative Instruments

The following table summarizes the gross fair value of our derivative assets and liabilities and the effect of netting for the 2016 and 2015 Periods:


	Balance Sheet Classification		Gross Amounts		Netting Adjustment			Net Amounts Presented on the Balance Sheet
September 30, 2016:
Assets:
Commodity Derivative instruments		Current derivative instruments	$	28,227	$	(3,256	)	$	24,971
Commodity Derivative instruments		Noncurrent derivative instruments		6,382		(1,162	)		5,220

Total assets			$	34,609	$	(4,418	)	$	30,191

Liabilities:
Interest Rate Derivative instruments		Accrued expenses	$	4,392	$	—		$	4,392
Interest Rate Derivative instruments		Other long-term liabilities		3,565		—			3,565

Total liabilities			$	7,957	$	—		$	7,957

December 31, 2015:
Assets:
Commodity Derivative instruments		Current derivative instruments	$	49,755	$	—		$	49,755
Commodity Derivative instruments		Noncurrent derivative instruments		63,660					63,660

Total assets			$	113,415	$	—		$	113,415

Liabilities:
Interest Rate Derivative instruments		Accrued expenses	$	4,228	$	—		$	4,228
Interest Rate Derivative instruments		Other long-term liabilities		—		—			—

Total liabilities			$	4,228	$	—		$	4,228

F-33

Commodity Derivatives

The following summarizes our commodity derivative positions as of September 30, 2016:


Production Year	Daily Volumes (MMBTU)		Swap Price Henry Hub (NYMEX)
2016		52,886	$	3.44
2017		204,932	$	3.39

Interest Rate Derivatives

In June 2015, we entered into two interest rate derivative instruments, which effectively swapped $750.0 million of our variable-rate debt based on one-month LIBOR into fixed rate debt.

For the 2016 and 2015 Periods, we had $4.5 million and $5.2 million, respectively, of unrealized losses, which are reflected in interest expense. The following summarizes our interest rate derivative positions as of September 30, 2016:


Notional Principal Amount	Fixed Rate			Effective Date	Maturity Date
$400.0 million		1.784	%	June 30, 2015	June 30, 2019
$350.0 million		1.495	%	July 6, 2015	June 30, 2018

9.	Partners’ Capital and Profit Interests Awards

Background

Class A Units

F-34

forfeiture or repurchase features of the plan. Award recipients may derive economic value in the instrument through profit sharing distributions. As such, these Class A Units are a compensation liability award and will trigger no compensation expense until amounts payable under such awards become probable and estimable.

The following table summarizes the Class A Unit activity for 2016 Period:


	Class A Units
	Equity-based Compensation Awards		Liability Awards		Total
Outstanding at January 1, 2016		40.0		49.5		89.5
Granted		—		—		—
Forfeited		—		—		—

Outstanding at September 30, 2016		40.0		49.5		89.5

We utilized the Black Scholes option pricing method to estimate grant date fair value of the Class A equity-based compensation awards, which included probability of various outcomes. Expected volatilities are based on historical volatilities of the stock of comparable companies in our industry. The risk-free rate for periods within the contractual life of the option is based on the U.S. Treasury yield curve in effect at the time of grant. Actual results may vary depending on the assumptions applied within the model. The following table presents the assumptions used in the valuation and resulting grant date fair value:

•

Expected volatility — 40.0%

•

Expected dividends — N/A

•

Expected term — 4.2 years

•

Risk-free rate — 1.20%

The grant date fair value of the Class A equity-based compensation awards was $3.0 million.

Compensation expense is recognized on a straight-line basis over the requisite service period. During both the 2016 and 2015 Periods, we recognized compensation expense of $0.8 million. Total unrecognized compensation costs related to unvested awards at September 30, 2016 is $1.4 million and is expected to be recognized over the next three years. No distributions were made during the 2016 Period.

Class B Units

As of September 30, 2016 and December 31,2015, there were 462,517 Class B Units issued and outstanding in exchange for capital contributions.

Class C Units

As of September 30, 2016 and December 31, 2015, there were 3,588 and 2,704, respectively, Class C Units issued and outstanding in exchange for capital contributions. Due to their redemption attributes, the capital contributed for Class C Units is included in other long-term liabilities.

F-35

10.

Commitments and Contingencies

Litigation

Environmental Remediation

11.

Related Party Transactions

We recognized aggregate expense of $1.4 million for each 2016 and 2015 Periods, under a management and consulting agreement with Blackstone and our CEO, of which, over 98% was attributable to Blackstone.

In January 2015, Blackstone became a significant creditor under the TLB and TLC.

During the 2016 Period, VMS billed two of our affiliates $6.2 million for services rendered and administrative costs incurred, including a service fee totaling $0.1 million. We have a receivable for these affiliates for such services of $1.5 million, which is included in accounts receivable. Additionally, Vine has issued joint interest bills to one of the affiliates totaling $1.2 million for their share of capital expenditures on wells that we have drilled. As of September 30, 2016, the total related receivable is $1.2 million, which is included in joint interest billing receivables.

12.

Subsequent Events

We have evaluated subsequent events through January 6, 2017, the date on which these financial statements were available for issuance.

F-36

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholder of

Vine Resources Inc.

Dallas, Texas

We have audited the accompanying balance sheet of Vine Resources Inc. (the “Company”) as of December 31, 2016. This financial statement is the responsibility of the Company’s management. Our responsibility is to express an opinion on this financial statement based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States) and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statement is free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statement, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, such balance sheet presents fairly, in all material respects, the financial position of Vine Resources Inc. as of December 31, 2016, in conformity with accounting principles generally accepted in the United States of America.

/s DELOITTE & TOUCHE LLP

Houston, Texas

January 6, 2017

F-37

VINE RESOURCES INC.

BALANCE SHEET


	December 31, 2016
Assets
Total assets	$	—

Stockholders’ equity
Notes receivable from Vine Investment LLC	$	(10	)

Common stock, $0.01 par value; authorized 1,000 shares; 1,000 issued and outstanding at December 31, 2016	$	10

Total stockholders’ equity	$	—

The accompanying notes are integral to the balance sheet.

F-38

VINE RESOURCES INC.

NOTES TO BALANCE SHEET

1.	Nature of Operations

Vine Resources Inc. (“Vine”) was formed on December 30, 2016, pursuant to the laws of the State of Delaware to become a holding company for Vine Oil & Gas LP.

2.	Summary of Significant Accounting Policies

Basis of Presentation

This balance sheet has been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). Separate statements of income, changes in stockholder’s equity and of cash flows have not been presented because Vine has had no business transactions or activities to date.

F-39

ANNEX A: 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.” Asset retirement obligation.

“Bcf.” One billion cubic feet of natural gas.

“Bcfd.” One billion cubic feet of natural gas per day.

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

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

“CapEx.” Capital expenditures.

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

“D&C costs.” Drilling and completion costs.

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

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

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

“FERC.” The Federal Energy Regulatory Commission.

“Field.” An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

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

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

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

“Identified drilling locations.” Total gross (net) resource play locations that we may be able to drill on our existing acreage. A portion of our identified drilling locations constitute estimated locations based on our acreage

A-1

and spacing assumptions, as described in “Business — Our Operations — Reserve Data — Drilling Locations”. Actual drilling activities may change depending on the availability of capital, regulatory approvals, seasonal restrictions, natural gas and oil prices, costs, drilling results and other factors.

“IDC.” Intangible drilling cost.

“JOA” Joint operating agreement.

“LNG” means liquid natural gas.

“Mcf.” One thousand cubic feet of natural gas.

“MMBtu.” One million Btu.

“MMcf.” One million cubic feet of natural gas.

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

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

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

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

“Proved developed reserves.” Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

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

“Proved undeveloped reserves” or “PUDs.” Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

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

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

“Spacing.” 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.” 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

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taxes, if applicable, are computed by applying the statutory tax rate to the excess of pre-tax cash inflows over our tax basis in the natural gas and oil properties. Future net cash inflows after income taxes are discounted using a 10% annual discount rate.

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

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

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

“Working interest.” 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.

A-3

Shares

LOGO

Vine Resources Inc.

Common Stock

Prospectus

Joint Book-Running Managers

, 2017

Through and including , 2017 (the 25th day after the date of this prospectus), all dealers effecting transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to a dealer’s obligation to deliver a prospectus when acting as underwriters and with respect to an unsold allotment or subscription.

PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

Item 13. Other expenses of issuance and distribution

The following table sets forth an itemized statement of the amounts of all expenses (excluding underwriting discounts and commissions) payable by us in connection with the registration of the common stock offered hereby. With the exception of the Registration Fee, FINRA Filing Fee and NYSE listing fee), the amounts set forth below are estimates.


SEC Registration Fee		*
FINRA Filing Fee		*
NYSE listing fee		*
Accountants’ fees and expenses		*
Legal fees and expenses		*
Printing and engraving expenses		*
Transfer agent and registrar fees		*
Miscellaneous		*

Total	$	*

*	To be filed by amendment.

Item 14. Indemnification of Directors and Officers

Our amended and restated certificate of incorporation will provide that a director will not be liable to the corporation or its stockholders for monetary damages to the fullest extent permitted by the DGCL. In addition, if the DGCL is amended to authorize the further elimination or limitation of the liability of directors, then the liability of a director of the corporation, in addition to the limitation on personal liability provided for in our certificate of incorporation, will be limited to the fullest extent permitted by the amended DGCL. Our amended and restated bylaws will provide that the corporation will indemnify, and advance expenses to, any officer or director to the fullest extent authorized by the DGCL.

Section 145 of the DGCL provides that a corporation may indemnify directors and officers as well as other employees and individuals against expenses, including attorneys’ fees, judgments, fines and amounts paid in settlement in connection with specified actions, suits and proceedings whether civil, criminal, administrative, or investigative, other than a derivative action by or in the right of the corporation, if they acted in good faith and in a manner they reasonably believed to be in or not opposed to the best interests of the corporation and, with respect to any criminal action or proceeding, had no reasonable cause to believe their conduct was unlawful. A similar standard is applicable in the case of derivative actions, except that indemnification extends only to expenses, including attorneys’ fees, incurred in connection with the defense or settlement of such action and the statute requires court approval before there can be any indemnification where the person seeking indemnification has been found liable to the corporation. The statute provides that it is not exclusive of other indemnification that may be granted by a corporation’s certificate of incorporation, bylaws, disinterested director vote, stockholder vote, agreement or otherwise.

Our amended and restated certificate of incorporation will also contain indemnification rights for our directors and our officers. Specifically, our amended and restated certificate of incorporation will provide that we shall indemnify our officers and directors to the fullest extent authorized by the DGCL. Further, we may maintain insurance on behalf of our officers and directors against expense, liability or loss asserted incurred by them in their capacities as officers and directors.

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In addition, we intend to enter into indemnification agreements with our current directors and officers containing provisions that are in some respects broader than the specific indemnification provisions contained in the DGCL. The indemnification agreements will require us, among other things, to indemnify our directors against certain liabilities that may arise by reason of their status or service as directors and to advance their expenses incurred as a result of any proceeding against them as to which they could be indemnified. We also intend to enter into indemnification agreements with our future directors and officers.

We intend to maintain liability insurance policies that indemnify our directors and officers against various liabilities, including certain liabilities under arising under the Securities Act and the Exchange Act that may be incurred by them in their capacity as such.

The proposed form of Underwriting Agreement to be filed as Exhibit 1.1 to this registration statement provides for indemnification of our directors and officers by the underwriters against certain liabilities arising under the Securities Act or otherwise in connection with this offering.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers or persons controlling us pursuant to the foregoing provisions, we have been informed that in the opinion of the SEC, such indemnification is against public policy as expressed in the Securities Act and is therefore unenforceable.

Item 15. Recent Sales of Unregistered Securities

Prior to the closing of this offering, based on the assumed initial public offering price of $ per share of common stock (the midpoint of the price range set forth on the cover of this prospectus), we will issue shares of our common stock to Vine Investment in connection with the Corporate Reorganization. The shares of our common stock described in this Item 15 will be issued in reliance upon the exemption from the registration requirements of the Securities Act provided by Section 4(a)(2) of the Securities Act as sales by an issuer not involving any public offering.

Item 16. Exhibits and financial statement schedules

See the Exhibit Index immediately following the signature page hereto, which is incorporated by reference as if fully set forth herein.

Item 17. Undertakings

The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

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The undersigned registrant hereby undertakes that:

(1) For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.

(2) For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Plano, State of Texas, on , 2017.


By:
		Eric D. Marsh
		President and Chief Executive Officer

Each person whose signature appears below appoints Eric D. Marsh and John C. Regan, and each of them, any of whom may act without the joinder of the other, as his true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this Registration Statement and any Registration Statement (including any amendment thereto) for this offering that is to be effective upon filing pursuant to Rule 462(b) under the Securities Act of 1933, as amended, and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he might or would do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them or their or his substitute or substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Act of 1933, as amended, this Registration Statement has been signed below by the following persons in the capacities and the dates indicated.


Signature	Title	Date

Eric D. Marsh	President and Chief Executive Officer (Principal Executive Officer)	, 2017

John C. Regan	Chief Financial Officer (Principal Financial Officer)	, 2017

Brian D. Dutton	Chief Accounting Officer (Principal Accounting Officer)	, 2017

Angelo G. Acconcia	Director	, 2017

Gary D. Levin	Director	, 2017

Adam M. Jenkins	Director	, 2017

II-4

INDEX TO EXHIBITS


Exhibit number		Description

*1.1		Form of Underwriting Agreement.

*3.1		Form of Amended and Restated Certificate of Incorporation of Vine Resources Inc.

*3.2		Form of Amended and Restated Bylaws of Vine Resources Inc.

*4.1		Form of Common Stock Certificate.

*4.2		Form of Shareholders’ Agreement.

*4.3		Form of Registration Rights Agreement.

*5.1		Form of opinion of Kirkland & Ellis LLP as to the legality of the securities being registered.

*10.1		Superpriority Facility, dated as of , 2017, by and among the Company, HSBC Bank USA, National Association, as Administrative Agent, Swingline Lender and as Issuing Bank and the banks, financial institutions and other lending institutions from time to time party thereto, as amended.

*10.2		RBL Credit Facility, dated as of November 25, 2014, by and among the Company, HSBC Bank USA, National Association, as Administrative Agent, Collateral Agent, Swingline Lender and as Issuing Bank and the banks, financial institutions and other lending institutions from time to time party thereto, as amended.

*10.3		First Amendment to RBL Credit Facility, dated as of January 6, 2015, by and among the Company, HSBC Bank USA, National Association, as Administrative Agent, Collateral Agent, Swingline Lender and the banks, financial institutions and other lending institutions party thereto.

*10.4		Term Loan B Credit Facility, dated November 25, 2014, by and among the Company, Morgan Stanley Senior Funding, Inc., as Administrative Agent and Collateral Agent and the banks, financial institutions and other lending institutions from time to time party thereto, as amended.

*10.5		First Amendment to Term Loan B Credit Facility, dated January 6, 2015, by and among the Company, Morgan Stanley Senior Funding, Inc., as Administrative Agent and Collateral Agent and the banks, financial institutions and other lending institutions party thereto.

*10.6		Term Loan C Credit Facility, dated November 25, 2014, by and among the Company, Morgan Stanley Senior Funding, Inc., as Administrative Agent and Collateral Agent and the banks, financial institutions and other lending institutions from time to time party thereto, as amended.

*10.7		First Amendment to Term Loan C Credit Facility, dated January 6, 2015, by and among the Company, Morgan Stanley Senior Funding, Inc., as Administrative Agent and Collateral Agent and the banks, financial institutions and other lending institutions thereto.

*†10.7		Form of Indemnification Agreement.

*†10.8		Form of Vine Resources Inc. Long-Term Incentive Plan.

*†10.9		Form of Employment Agreement.

*21.1		List of subsidiaries of Vine Resources Inc.

*23.1		Consent of Deloitte & Touche LLP.

*23.2		Consent of W.D. Von Gonten & Co.

*23.3		Consent of Kirkland & Ellis LLP (included as part of Exhibit 5.1 hereto).

24.1		Power of Attorney (included on the signature page of this Registration Statement).

*99.1		W.D. Von Gonten & Co. Summary of Reserves at December 31, 2015.

*	To be filed by amendment.

†	Compensatory plan or arrangement.

II-5

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