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INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

As filed with the Securities and Exchange Commission on July 7, 2014

Registration No. 333-

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form S-1

REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933

VANTAGE ENERGY INC.
(Exact name of registrant as specified in its charter)


Delaware (State or other jurisdiction of incorporation or organization)		1311 (Primary Standard Industrial Classification Code Number)		46-5608050 (IRS Employer Identification Number)

116 Inverness Drive East, Suite 107
Englewood, Colorado 80112
303-386-8600
(Address, including zip code, and telephone number, including area code, of registrant's principal executive offices)

Thomas B. Tyree, Jr.
President and Chief Financial Officer
116 Inverness Drive East, Suite 107
Englewood, Colorado 80112
303-386-8600
(Name, address, including zip code, and telephone number, including area code, of agent for service)


Copies to:
Jeffery K. Malonson Matthew R. Pacey Vinson & Elkins L.L.P. 1001 Fannin, Suite 2500 Houston, Texas 77002 (713) 758-2222		Kelly B. Rose Jason A. Rocha Baker Botts L.L.P. One Shell Plaza 910 Louisiana Street Houston, Texas 77002 (713) 229-1234

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: o

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. o

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. o

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. o

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


Large accelerated filer o		Accelerated filer o		Non-accelerated filer ý (Do not check if a smaller reporting company)		Smaller reporting company o

CALCULATION OF REGISTRATION FEE

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



Common stock, par value $0.01 per share	$400,000,000	$51,520

⁽¹⁾: Includes shares issuable upon exercise of the underwriters' option to purchase additional shares of 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 registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933, as amended, or until this registration statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

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

Subject to Completion, dated July 7, 2014

PROSPECTUS

Vantage Energy Inc.

Common Stock

This is the initial public offering of the common stock of Vantage Energy Inc., a Delaware corporation. We are offering shares of our common stock and the selling stockholders identified in this prospectus are offering sha res of our common stock. We will not receive any proceeds from the sale of shares by the selling stockholders. No public market currently exists for our common stock. We are an "emerging growth company" and are eligible for reduced reporting requirements. Please see "Prospectus Summary—Emerging Growth Company Status."

We intend to apply to list our common stock on the New York Stock Exchange under the symbol "VEI."

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

Investing in our common stock involves risks. Please see "Risk Factors" beginning on page 18 of this prospectus.

	Per share	Total

Price to the public	$	$
Underwriting discounts and commissions⁽¹⁾	$	$
Proceeds to us (before expenses)	$	$
Proceeds to the selling stockholders (before expenses)	$	$

(1): Please see "Underwriting (Conflicts of Interest)" for a description of all underwriting compensation payable in connection with this offering.

The selling stockholders 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 , 2014.


Barclays		Goldman, Sachs & Co.


Citigroup		Credit Suisse		Tudor, Pickering, Holt & Co.		Wells Fargo Securities

Prospectus dated , 2014

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PROSPECTUS SUMMARY			1
RISK FACTORS			18
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS			48
USE OF PROCEEDS			50
DIVIDEND POLICY			51
CAPITALIZATION			52
DILUTION			54
SELECTED HISTORICAL CONSOLIDATED AND UNAUDITED PRO FORMA FINANCIAL DATA			55
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			57
BUSINESS			80
MANAGEMENT			109
EXECUTIVE COMPENSATION			114
PRINCIPAL AND SELLING STOCKHOLDERS			120
CORPORATE REORGANIZATION			122
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS			124
DESCRIPTION OF CAPITAL STOCK			126
SHARES ELIGIBLE FOR FUTURE SALE			131
MATERIAL U.S. FEDERAL INCOME AND ESTATE TAX CONSIDERATIONS FOR NON-U.S. HOLDERS			133
UNDERWRITING (CONFLICTS OF INTEREST)			137
LEGAL MATTERS			145
EXPERTS			145
WHERE YOU CAN FIND MORE INFORMATION			145
INDEX TO CONSOLIDATED 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, the selling stockholders 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, the selling stockholders 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.

This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. Please see "Risk Factors" and "Cautionary Statement Regarding Forward-Looking Statements."

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Commonly Used Defined Terms

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

•: "Vantage" "we," "our," "us" or like terms refer collectively to the combined Vantage I and Vantage II, together with their consolidated subsidiaries before the completion of our corporate reorganization described in "Corporate Reorganization" (except as otherwise disclosed) and to Vantage Energy Inc. and its consolidated subsidiaries, including Vantage I and Vantage II, as of and following the completion of our corporate reorganization;
•: "Vantage I" refers to Vantage Energy, LLC;
•: "Vantage II" refers to Vantage Energy II, LLC;
•: "Vantage Investment I" refers to Vantage Energy Investment LLC;
•: "Vantage Investment II" refers to Vantage Energy Investment II LLC;
•: "Existing Owners" refers, collectively, to the Sponsors and the Management Members that own limited liability company interests in Vantage I and Vantage II prior to the completion of our corporate reorganization and in Vantage Investment I and Vantage Investment II as of and following the completion of our corporate reorganization;
•: "Management Members" refers, collectively, to the individual founders and employees and other individuals who, together with the Sponsors, initially formed Vantage I and Vantage II; and
•: "Sponsors" refers, collectively, to investment funds affiliated with or managed by Quantum Energy Partners ("Quantum"), Riverstone Holdings LLC ("Riverstone") and Lime Rock Partners ("Lime Rock").

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 accounting predecessor, Vantage I. The pro forma financial information presented in this prospectus treats the combination of Vantage I and Vantage II in connection with our corporate reorganization as an acquisition in a business combination of Vantage II by Vantage I, our accounting predecessor. Please see "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 Vantage I and Vantage II on a combined basis as of the dates and for the periods presented. Unless another date is specified, all acreage data presented in this prospectus is as of July 1, 2014. Unless otherwise noted, references to production volumes refer to sales volumes.

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, the selling stockholders 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

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Factors." These and other factors could cause results to differ materially from those expressed in these publications.

Trademarks and Trade Names

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

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PROSPECTUS SUMMARY

This summary provides a brief overview of information contained elsewhere in this prospectus. You should read this entire prospectus and the documents to which we refer you before making an investment decision. You should carefully consider the information set forth 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 consolidated and pro forma financial statements and the related notes to those financial statements included 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 from the selling stockholders 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 engineers based on the Securities and Exchange Commission ("SEC") pricing at December 31, 2013, as 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.

Our Company

We are a growth-oriented, independent oil and natural gas company engaged in the acquisition, development, exploitation and exploration of oil and natural gas properties in the United States, with a focus on the Marcellus Shale, where we hold a concentrated acreage position in what we believe to be the core of the play in Greene County, Pennsylvania. Additionally, we have a sizeable position in what we believe to be the core of the Barnett Shale. We believe these areas are among the most prolific unconventional resource plays in North America, and are generally characterized by high well recoveries relative to drilling and completion costs, predictable production profiles, significant hydrocarbons in place and favorable operating environments.

Our management team has a proven track record of implementing technically driven growth strategies to target best-in-class returns in some of the most prominent unconventional plays across the United States. Roger Biemans, our Chairman and Chief Executive Officer, and Tom Tyree, our President and Chief Financial Officer, founded our company with investments from affiliates of Quantum Energy Partners, Riverstone Holdings LLC and Lime Rock Partners. We made our initial entry into the Barnett Shale in 2007 and the Marcellus Shale in 2010. Since then, we have been committed to a strategy of disciplined growth through acquisitions and development drilling in the highest quality areas of these plays.

We utilize advanced well completion strategies and technologies, including pad drilling and downhole rotary steering, to optimize well economics and operational efficiencies. We believe that our horizontal drilling and completion expertise, coupled with the favorable geologic characteristics of our Marcellus and Barnett Shale acreage, positions us for continued strong results and growth. We have grown our net daily production from 18.1 MMcfe/d for the year ended December 31, 2011, to 63.3 MMcfe/d for the year ended December 31, 2013, representing a compounded annual growth rate of 86.8%. Our estimated average net daily wellhead production for the first five days of July 2014 was 82.5 MMcfe/d.

We have assembled a largely contiguous acreage position of 51,771 net acres in what we believe to be the core of the Marcellus Shale in Greene County, Pennsylvania. In addition, our Barnett Shale assets consist of approximately 38,347 net acres, 23,043 of which are located in what we believe to be the core of the basin in Denton, Wise and Tarrant Counties in Texas. We currently have two rigs operating in the Marcellus Shale and two rigs operating in the Barnett Shale and expect to operate approximately that same number of rigs for the remainder of 2014. As of April 30, 2014, we had 1,074 identified drilling locations, including 423 in the Marcellus Shale, 312 in the Upper Devonian Shale and 339 in the Barnett Shale.

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The following charts show the growth in our average net daily production and our net acreage position in the Marcellus and Barnett Shales since 2011.


Average Net Daily Total Production (Mmcfe/d)		Net Acres at Year End

(1): CAGR stands for compounded annual growth rate.

Our Properties

Marcellus Shale

The Marcellus Shale is the largest unconventional natural gas field in the U.S. The productive limits of the Marcellus Shale cover over 90,000 square miles within Pennsylvania, West Virginia, Ohio and New York. We believe that the Marcellus Shale is a premier North American shale play due to its high well recoveries relative to drilling and completion costs, broad aerial extent, high-quality reservoir characteristics and significant hydrocarbon resources in place.

Within the Marcellus Shale, all 51,771 of our net acres are located in Greene County, Pennsylvania, which we believe constitutes the core of the play. Based on our drilling results, as well as drilling results publicly released by other operators, we believe that Greene County offers some of the most attractive single-well rates of return in North America. We are focused on infill lease acquisitions that will consolidate our acreage, increase effective lateral lengths and result in operational efficiencies. Additionally, compared to other areas of the Marcellus Shale, we believe that Greene County is among the best-served by current and planned transportation infrastructure that will support our future production growth. We also maintain a strong commitment to developing the necessary midstream infrastructure to support our drilling schedule and production growth.

We currently have two rigs (both of which are bottom hole rigs) operating in the Marcellus Shale, and we expect to drill and case a total of 21 Marcellus Shale wells in 2014. As of December 31, 2013, we operated 99% of our acreage in the Marcellus Shale. Our net daily production in the Marcellus Shale has grown from 1.9 MMcf/d in the three months ended December 31, 2011 to 30.3 MMcf/d in the three months ended March 31, 2014. Our estimated average net daily wellhead production for the first five days of July 2014 was 44.6 MMcf/d.

As of July 1, 2014, we had 49 gross horizontal wells drilled in the Marcellus Shale, 42 of which are operated by us. Of those 49 wells, 18 were on production, 5 were temporarily shut-in for drilling and completion operations and the balance were either awaiting completion, in the process of being completed or completed and awaiting pipeline. We have a 100% success rate (defined as the

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percentage of completed wells which produce in commercially viable quantities) based on our producing wells. As of April 30, 2014, we had 423 identified drilling locations in the Marcellus Shale.

Since we began our current operational focus on the core of the Marcellus Shale in 2012, normalized for each 1,000 feet of horizontal lateral, the EURs from our Marcellus Shale wells brought on-line range from 1.2 Bcf per 1,000 feet to 2.5 Bcf per 1,000 feet, averaging 1.9 Bcf per 1,000 feet. These wells had lateral lengths ranging from 2,342 feet to 7,442 feet, averaging 5,273 feet. For more details about these wells, please see "Business—Our Properties—Marcellus Shale."

Based on well results from nearby operators and geologic data available to us, we believe substantially all of our Marcellus Shale acreage is also prospective for the shallower Upper Devonian Shale and may be prospective for the deeper Utica Shale. As of July 1, 2014, we had drilled three horizontal Upper Devonian Shale wells, all of which were awaiting completion and not yet on production. As of April 30, 2014, we had 312 identified drilling locations in the Upper Devonian Shale. The Upper Devonian and Utica Shales are formations stacked with the Marcellus Shale in the same geographic footprint.

Barnett Shale

Covering over 5,000 square miles and 18 counties in North Texas, the Barnett Shale was the first shale reservoir to be successfully exploited using horizontal drilling and fracture stimulation techniques. The Barnett Shale remains one of the most productive shale plays in North America and produced over 5 Bcfe/d in 2013.

Of our 38,347 net acres in the Barnett Shale, 23,043 are located in our primary development areas of Denton, Wise and Tarrant Counties in Texas, which we believe to constitute the core of the Barnett Shale. We currently have two rigs operating in the Barnett Shale and expect to drill and case a total of 55 wells in 2014. As of December 31, 2013, we operated 99% of our acreage in the Barnett Shale. Our net daily production in the Barnett Shale has grown from 6.1 MMcfe/d in the three months ended December 31, 2011 to 30.6 MMcfe/d in the three months ended March 31, 2014. Our estimated average net daily wellhead production for the first five days of July 2014 was 37.9 MMcfe/d.

As of July 1, 2014, in our core operating areas of the Barnett Shale, we had 106 gross horizontal wells drilled, excluding those that have been plugged or shut-in. Of those 106, 73 were on production, 4 were temporarily shut-in for drilling and completion operations and the balance were either awaiting completion or in the process of being completed. We have a 100% success rate in our core operating areas of the Barnett Shale. As of April 30, 2014, we had 339 identified drilling locations in the Barnett Shale.

Other Properties

We also hold over 80,000 net acres in other project areas, primarily comprised of our Uinta Basin properties in Utah. Although we are not actively developing these assets, we believe that they provide significant upside potential to our core operations.

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Reserve and Operating Data

The following table provides information regarding our proved reserves as of December 31, 2013 and our average net daily production for the three months ended March 31, 2014.

	Estimated Proved Reserves⁽¹⁾

	Estimated Proved Reserves⁽¹⁾											Average Net Daily Production (MMcfe/d)
	Natural Gas (Bcf)		NGLs (MMBbls)		Oil (MMBbls)		Total (Bcfe)		% Proved developed			Average Net Daily Production (MMcfe/d)
Marcellus Shale		565.0		—		—		565.0		11.6	%		30.3
Barnett Shale⁽²⁾		347.3		15.5		1.4		448.2		21.5	%		30.6


Total		912.4		15.5		1.4		1,013.4		16.0	%		60.9

(1): Volumes were determined using average adjusted product prices of $3.05 per Mcf for natural gas in the Marcellus and $2.89 per Mcf, $24.62 per Bbl, and $94.27 per Bbl for natural gas, NGLs and oil, respectively, in the Barnett Shale.
(2): Includes de minimis reserves and production attributable to our other properties.

The following table provides a summary of our core Marcellus Shale, Upper Devonian Shale and Barnett Shale operations, including our acreage as of July 1, 2014, our average working interest, gross producing wells, identified drilling locations and drilling inventory as of April 30, 2014 and our projections for the number of gross wells to be drilled and cased during the twelve months ending April 30, 2015.



Marcellus Shale	51,771	89	%	20		423	15.7	27
Upper Devonian Shale⁽³⁾		89	%	—		312	*	2
Barnett Shale	38,347	81	%	173	⁽⁴⁾	339	5.7	59


Total	90,118	86	%	193		1,074	*	88

(1): Includes 216 identified drilling locations associated with proved undeveloped reserves as of December 31, 2013. For a discussion of how we identify drilling locations, a portion of which constitute estimated locations based on our acreage and spacing assumptions, please see "Business—Our Operations—Reserve Data—Determination of Identified Drilling Locations."
(2): Represents the number of years of inventory based on the number of identified drilling locations (including drillable and estimated locations) in a project area divided by the anticipated number of wells to be drilled and cased in such area pursuant to our drilling and completion program during the twelve months ending April 30, 2015.
(3): Acres prospective for the Upper Devonian Shale are included in total Marcellus Shale net acres.
(4): Includes legacy vertical wells and horizontal wells outside of our core operating areas in the Barnett Shale. As of April 30, 2014, 66 horizontal wells were on production in our core operating areas in the Barnett Shale.
*: Not meaningful as a result of 2014 drilling program being primarily focused on the Marcellus and Barnett Shales.

Capital Program

Our 2014 capital program is primarily focused on developing low-cost, high return drilling opportunities in order to grow production and cash flow. Our 2014 capital expenditure budget, excluding capitalized general and administrative expenses and interest expenses, is $540 million, including:

•: $441 million for drilling and completion;

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•: $40 million for leasehold acquisitions;
•: $5 million for seismic and other activities; and
•: $54 million related to our gathering, compression and dehydration construction activities.

Business Strategy

Our strategy is to leverage our management team's experience in acquiring and developing natural gas and oil resources to cost efficiently grow our reserves, production and cash flow and thus maximize the value of our assets. Our strategy has the following principal elements:

•: Enhance returns by focusing on operational and cost efficiencies while deploying capital to highest return opportunities. We target best-in-class returns in the Marcellus and Barnett Shales. We continually monitor and adjust our drilling program with the objective of achieving the highest total returns on our drilling portfolio. As the operator of the substantial majority of our acreage in the Marcellus and Barnett Shales, we are able to manage the timing and level of our capital spending, our exploration and development drilling strategies and our operating costs. We believe that we will achieve this objective by maximizing well production and recoveries relative to drilling and completion costs through optimizing lateral length, the number of frac stages, perforation intervals and the type of fracture stimulation employed. In addition, we are focused on reducing our capital costs of drilling and completing horizontal wells and operating costs through efficient well management and procurement initiatives that generate favorable services and supplies pricing.
•: Create shareholder value through the aggressive development of our extensive drilling inventory. We intend to continue to aggressively drill and develop our portfolio of 1,074 identified drilling locations as of April 30, 2014 with a goal of growing production, cash flow and reserves in an economically efficient manner in order to maximize shareholder value. In executing our development strategy, we intend to leverage our operational control and the expertise of our technical team to deliver strong results. We began our development program in the Marcellus Shale in 2011 and have increased production from 1.9 MMcf/d in the three months ended December 31, 2011 to approximately 30.3 MMcf/d for the three months ended March 31, 2014. We will continue to deploy resources to develop our high rate of return inventory and continue to build on our track record of superior production, cash flow and reserve growth.
•: Continue growing our acreage position in the core of the Marcellus Shale through opportunistic leasing and strategic acquisitions. We intend to continue identifying and acquiring additional acreage and producing assets in the core of the Marcellus Shale, which we believe offers some of the most attractive single-well rates of return in North America. We believe that our experienced management and technical team will enable us to opportunistically expand our acreage position and drilling inventory in highly attractive areas. We have selectively built our Marcellus Shale position from less than 200 net acres as of December 31, 2010 to approximately 51,771 net acres as of July 1, 2014. We believe that our Marcellus Shale acreage has a significant inventory of expansion and consolidation opportunities, and we will continue to pursue transactions that meet our strategic and financial objectives. We are focused on infill lease acquisitions that we believe will further consolidate our acreage, increase effective lateral lengths and result in operational efficiencies.
•: Manage commodity price exposure through an active hedging program to protect our expected future cash flows. We are focused on maintaining an active hedging program to minimize volatility in cash flows and commodity price and regional basis differential exposure in an effort to protect returns on our capital investment program as well as expected future cash flows. As of March 31, 2014, Vantage I and Vantage II had entered into hedging contracts through 2017 covering a total of approximately 74 Bcfe of their projected natural gas, NGL and oil production at a weighted average price of $4.47 per Mcfe.

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Business Strengths

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

•: Large concentrated position in the core of the Marcellus Shale. Since 2010, we have built a significant contiguous acreage position in what we believe is the core of the Marcellus Shale in Greene County, Pennsylvania through a disciplined and focused leasing and acquisition program. We believe the core of the Marcellus Shale offers some of the most attractive single-well rates of return in North America. Our concentrated ownership of 51,771 net acres in Greene County has allowed us to efficiently delineate our position and produce industry-leading well results.
•: Complementary, highly economic position in the Barnett Shale. We have assembled a large and attractive leasehold position of approximately 38,347 net acres in the Barnett Shale, including 23,043 net acres in Denton, Wise and Tarrant Counties in Texas, which we believe constitute the core of the Barnett Shale. We believe we have a high quality Barnett Shale acreage position and high rate-of-return development program which complement our Marcellus Shale assets by providing additional cash flows to reinvest in our development program.
•: Multi-year, low-risk drilling inventory. We believe our concentrated acreage positions in the Marcellus and Barnett Shales are characterized by low geological risk and repeatable drilling opportunities that we expect will result in a predictable production growth profile. At April 30, 2014, we had 1,074 identified drilling locations, including 423 in the Marcellus Shale, 312 in the Upper Devonian Shale and 339 in the Barnett Shale. We believe that we and other operators in the area have substantially delineated and de-risked our acreage position in the core of the Marcellus Shale in Greene County. Additionally, we believe substantially all of our Marcellus Shale acreage is also prospective for the shallower Upper Devonian Shale and may be prospective for the deeper Utica Shale.
•: Low cost operator with significant control across our acreage position. We have historically had an intense focus on cost management which has translated into meaningful reductions in our overall capital and operating costs. We have implemented operational efficiencies to continue lowering our costs, such as pad drilling and the use of less expensive, shallow vertical drilling rigs to drill to the kick-off point of the horizontal wellbore. Our acreage position in the Marcellus and Barnett Shales is generally in contiguous blocks which allows us to conduct our operations more cost effectively and develop this acreage more efficiently. Additionally, our operational control allows us to more efficiently manage the pace of development activities, the gathering and marketing of our production and operating costs.
•: Access to multiple takeaway alternatives in the Marcellus Shale. We have numerous takeaway pipeline alternatives relative to other regions in the Marcellus Shale as a number of long-haul pipelines converge in Greene County. Our current natural gas production in the Marcellus Shale is gathered and subsequently delivered to Spectra Energy Partners' TETCo system and Dominion Resources' DTI system for long-haul delivery. Columbia Gas Transmission's TCO system, National Fuel Gas' Line N and EQT Midstream's Equitrans system are also in close proximity to our acreage. We currently have an aggregate of 115,000 MMBtu/d of production under firm marketing agreements in the Marcellus Shale beginning in October 2014 and November 2014. We also maintain a strong commitment to developing the necessary midstream infrastructure to support our drilling schedule and production growth.
•: Significant liquidity and financial flexibility. Following the completion of this offering, we estimate that we will have cash on hand and availability under our combined revolving credit facility of approximately $ million. After giving effect to this offering, we expect that our capital expenditure budgets for 2014 and 2015 will be fully funded through cash flows from operations,

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cash on hand and available capacity under our combined revolving credit facility, consistent with our overall financial strategy of maintaining a strong and stable capitalization profile.

•: Proven, experienced and incentivized management and technical teams. We believe our management team's experience and expertise across multiple resource plays provides a distinct competitive advantage. Our management team have an average of over 28 years of industry experience including executive officer positions at public exploration and production companies and key members with significant experience operating in the Marcellus and Barnett Shales. We have assembled a strong technical staff of engineers, geoscientists and field operations managers with extensive experience in horizontal development and operating multi-rig development programs. We have been early adopters of new oilfield services and techniques for drilling and completions. Our management and technical teams have a significant economic interest in us through their interests in our controlling stockholders, Vantage Investment I and Vantage Investment II. Management's percentage interest in our stock held by Vantage Investment I and Vantage Investment II may increase over time, without diluting public investors, if our stock price appreciates following this offering. We believe our management team's ability to increase their economic interest in us provides significant incentives to grow our stock price for the benefit of all stockholders.

Risk Factors

An investment in our common stock involves a number of risks that include the speculative nature of oil and natural gas exploration, competition, volatile commodity prices and other material factors. You 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. You could lose part or all of your investment. You should bear in mind, in reviewing this prospectus, that past experience is no indication of future performance. You should read "Cautionary Statement Regarding Forward-Looking Statements" for 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 under the laws of the State of Delaware to become a holding company for Vantage's assets and operations. Vantage I was founded in December 2006 with equity commitments from affiliates of Quantum, Riverstone and Lime Rock, as well the Management Members. Subsequently, Vantage II was founded in July 2012 with equity commitments from affiliates of those same Sponsors and the Management Members.

Pursuant to the terms of a corporate reorganization that will be completed simultaneously with the closing of this offering, (i) Vantage I and Vantage II will merge into subsidiaries of newly-formed holding companies, Vantage Investment I and Vantage Investment II, that will be owned by the Existing Owners in equal proportions to their current ownership of Vantage I and Vantage II and (ii) the Existing Owners will contribute all of the interests in Vantage I and Vantage II to us in exchange for all of our issued and outstanding shares of common stock (prior to the issuance of shares of common stock in this offering). As a result of the reorganization, Vantage I and Vantage II will become direct, wholly owned subsidiaries of Vantage Energy Inc. We were incorporated to serve as the issuer in this offering and have no previous operations, assets or liabilities. As a result, we do not qualify as the accounting acquirer. Accordingly, in the corporate reorganization, the combination of Vantage I (our accounting predecessor) into us will be accounted for at historical cost and the combination of Vantage II into us will be accounted for at fair value as a purchase business combination. For more information on our reorganization and the ownership of our common stock by our principal and selling

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stockholders, please see "Corporate Reorganization," "Principal and Selling Stockholders" and the unaudited pro forma financial statements included elsewhere in this prospectus.

The following diagram indicates our simplified ownership structure after giving effect to our corporate reorganization and this offering (assuming that the underwriters' option to purchase additional shares is not exercised).

Our Principal Stockholders

Following the completion of this offering and our corporate reorganization, Vantage Investment I and Vantage Investment II will directly own % and %, respectively, of our common stock, or % and %, respectively, if the underwriters' option to purchase additional shares from Vantage Investment I and Vantage Investment II is exercised in full. Vantage Investment I and Vantage Investment II are controlled by Quantum, Riverstone and Lime Rock. Please see "Corporate Reorganization."

Founded in 1998, Quantum is a leading provider of private equity capital to the global energy industry which, together with its affiliates, has had more than $7 billion of capital under stewardship. The employees of Quantum are experienced energy professionals with expertise in finance and operations and broad technical skills in the oil and natural gas business.

Riverstone is an energy and power-focused private investment firm founded in 2000 with approximately $27 billion of equity capital raised. Riverstone conducts buyout and growth capital investments in the exploration and production, midstream, oilfield services, power, and renewable sectors of the energy industry. With offices in New York, London, Mexico City and Houston, as of June 30, 2014, the firm has committed approximately $26 billion to 108 investments in North America, Latin America, Europe, Africa, and Asia.

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Established in 1998, Lime Rock Management LP ("Lime Rock Management") has raised approximately $5.5 billion in private equity funds for investment in the energy industry through Lime Rock Partners ("Lime Rock"), investors of growth capital in exploration and production and oilfield services companies worldwide, and Lime Rock Resources, acquirers and operators of oil and gas properties in the United States. Lime Rock is a creative investment partner in building differentiated oil and gas businesses side by side with entrepreneurs every day. From three locations worldwide, the Lime Rock team brings its specialist finance and operating expertise, global presence, technology leadership, people-centered strategies, and patient hard work to help its investors and portfolio company partners profit from operational growth.

Emerging Growth Company Status

We are an "emerging growth company" as defined in the Jumpstart Our Business Startups Act (the "JOBS Act.") For as long as we are an emerging growth company, unlike other public companies that are not emerging growth companies under the JOBS Act, 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 the Sarbanes-Oxley Act of 2002;
•: provide more than two years of audited financial statements and related management's discussion and analysis of financial condition and results of operations nor more than two years of selected financial data;
•: comply with any new requirements adopted by the Public Company Accounting Oversight Board (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;
•: provide certain disclosure regarding executive compensation required of larger public companies or hold shareholder advisory votes on executive compensation required by the Dodd-Frank Wall Street Reform and Consumer Protection Act (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 fiscal year in which we have $1.0 billion or more in annual revenues;
•: the date on which we become a "large accelerated filer" (the fiscal year-end on 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 over a three-year period; or
•: the last day of the fiscal year following the fifth anniversary of our initial public offering.

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

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Corporate Information

Our principal executive offices are located at 116 Inverness Drive East, Suite 107, Englewood, Colorado 80112, and our telephone number at that address is (303) 386-8600. Our website is located at www.vantageenergy.com. We expect to make our periodic reports and other information filed with or furnished to the SEC available free of charge through our website as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on, or otherwise accessible through, our website or any other website is not incorporated by reference herein and does not constitute a part of this prospectus.

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The Offering


Common stock offered by us		shares.
Common stock offered by the selling stockholders		shares (or shares, if the underwriters exercise in full their option to purchase additional shares).
Common stock to be outstanding after the offering		shares.
Shares of common stock owned by the Existing Owners after this offering		shares.
Option to purchase additional shares		The selling stockholders 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 $ 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 after deducting underwriting discounts and commissions and estimated offering expenses payable by us.
		We intend to use the net proceeds from this offering to repay and retire the Vantage I second lien term loan and the Vantage II second lien term loan. We intend to use the remaining net proceeds to repay the outstanding borrowings under our combined revolving credit facility and for general corporate purposes, including to fund a portion of our development program.
		We will not receive any of the proceeds from the sale of shares of our common stock by the selling stockholders (including pursuant to any exercise by the underwriters of their option to purchase additional shares of our common stock from the selling stockholders).
		Please see "Use of Proceeds."

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Conflicts of interest		Because affiliates of and are lenders under the Vantage I second lien term loan and are expected to be lenders under our combined revolving credit facility and will each receive more than 5% of the net proceeds of this offering due to the repayment of borrowings under the Vantage I second lien term loan and our combined revolving credit facility, such underwriters are deemed to have a conflict of interest within the meaning of Rule 5121 of the Financial Industry Regulatory Authority, Inc. ("FINRA"). In accordance with that rule, the appointment of a "qualified independent underwriter" is not required in connection with this offering because the underwriter primarily responsible for managing this public offering does not have a "conflict of interest" under Rule 5121, is not an affiliate of any underwriter that does have a "conflict of interest" under Rule 5121 and meets the requirements of paragraph (f)(12)(E) of Rule 5121. Any underwriter that has a conflict of interest pursuant to Rule 5121 will not confirm sales to accounts in which it exercises discretionary authority without the prior written consent of the customer. Please see "Underwriting (Conflicts of Interest)."
Dividend policy		We do not anticipate paying any cash dividends on our common stock. In addition, our combined revolving credit facility is expected to place certain restrictions on our ability to pay cash dividends.
Risk factors		You should carefully read and consider the information set forth under the heading "Risk Factors" and all other information set forth in this prospectus before deciding to invest in our common stock.
Listing and trading symbol		We intend to apply to list our common stock on the New York Stock Exchange (the "NYSE"), under the symbol "VEI."

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.

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Summary Historical Consolidated and Unaudited Pro Forma Financial Data

Vantage Energy Inc. was formed in May 2014 and does not have historical financial operating results. The following table shows summary historical consolidated financial data of our accounting predecessor, Vantage I, and summary unaudited pro forma financial data for the periods and as of the dates indicated.

The summary historical consolidated financial data as of and for the years ended December 31, 2013 and 2012 were derived from the audited historical consolidated financial statements of our predecessor included elsewhere in this prospectus.

The summary historical consolidated financial data as of and for the three months ended March 31, 2014 and 2013 were derived from the unaudited historical condensed consolidated financial statements of our predecessor included elsewhere in this prospectus.

The summary unaudited pro forma statements of operations data for the year ended December 31, 2013 and the three months ended March 31, 2014 has been prepared to give pro forma effect to (i) the reorganization transactions described under "Corporate Reorganization" and (ii) this offering and the application of the net proceeds from this offering as if they had been completed as of January 1, 2013. The summary unaudited pro forma balance sheet data has been prepared to give pro forma effect to those transactions as if they had been completed as of March 31, 2014. These data are subject to and give 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 data are 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.

You should read the following table in conjunction with "Use of Proceeds," "Management's Discussion and Analysis of Financial Condition and Results of Operations," "Corporate Reorganization," the historical consolidated financial statements of our predecessor and the unaudited pro forma financial statements included elsewhere in this prospectus. Among other things, those historical and unaudited pro forma financial statements include more detailed information regarding the basis of presentation for the following information.

	Vantage I (Predecessor)											Vantage Energy Inc.

	Three Months Ended March 31,						Year Ended December 31,
	Three Months Ended March 31,						Year Ended December 31,					Pro Forma Three Months Ended March 31, 2014	Pro Forma Year Ended December 31, 2013
	2014			2013			2013		2012			Pro Forma Three Months Ended March 31, 2014	Pro Forma Year Ended December 31, 2013
(in thousands, except per share data)
Statement of operations data:
Operating revenues:
Natural gas	$	16,775		$	9,819		$	46,266	$	23,068		$	$
Oil		1,605			692			5,152		2,473
NGL		2,612			1,249			6,599		8,370
Gas gathering revenues		—			—			99		(2	)
Gain (loss) on commodity derivatives		(14,577	)		(11,167	)		8,074		3,495


Total operating revenues		6,415			593			66,190		37,404
Operating expenses:
Production and ad valorem taxes		955			1,657			3,225		1,858
Marketing and gathering		713			469			2,640		1,389
Lease operating and workover		3,670			2,911			10,946		9,503
Gas gathering operating expenses		244			73			325		—
General and administrative		1,216			555			3,698		4,524

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	Vantage I (Predecessor)												Vantage Energy Inc.

	Three Months Ended March 31,						Year Ended December 31,
	Three Months Ended March 31,						Year Ended December 31,						Pro Forma Three Months Ended March 31, 2014	Pro Forma Year Ended December 31, 2013
	2014			2013			2013			2012			Pro Forma Three Months Ended March 31, 2014	Pro Forma Year Ended December 31, 2013
Depreciation, depletion, amortization and accretion		5,707			2,705			22,283			16,604
Impairment of proved oil and gas properties		—			—			—			8,043


Total operating expenses		12,505			8,370			43,117			41,921


Operating (loss) income		(6,090	)		(7,777	)		23,073			(4,517	)
Other (income) expense		9			(36	)		—			—
Interest income, net		—			3			—			9
Interest expense, net of capitalized income		4,159			—			417			—


Income (loss) before income taxes		(10,258	)		(7,738	)		22,656			(4,508	)
Income tax expense (benefit)		—			—			—			—


Net income (loss)		(10,258	)		(7,738	)	$	22,656		$	(4,508	)




Balance sheet data (at period end):
Cash	$	31,181		$	8,710		$	80,211		$	2,844		$
Total oil and gas properties, net		480,779			385,538			442,194			361,888
Total gas gathering system, net		23,741			8,972			17,290			9,040
Total assets		562,564			420,112			564,914			383,786
Total debt		197,593			96,000			198,000			50,000
Total members' / stockholders' capital		308,089			287,952			318,347			295,642
Net cash provided by (used in):
Operating activities	$	1,777		$	(3,563	)	$	43,981		$	28,349
Investing activities		(49,972	)		(36,645	)		(110,051	)		(116,445	)
Financing activities		(835	)		46,049			144,437			87,821
Other financial data (unaudited):
Adjusted EBITDA⁽¹⁾	$	10,865		$	6,378		$	41,747		$	24,833		$	$
Earnings per share—basic													$	$
Earnings per share—diluted													$	$

(1): Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to net income (loss), please see "—Non-GAAP Financial Measure" below.

Non-GAAP Financial Measure

Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies.

We define Adjusted EBITDA as net income (loss) before interest, income taxes, impairment of proved oil and gas properties, depreciation, depletion, amortization and accretion, derivative fair value (gain) loss, excluding net cash receipts on settled derivative instruments, and non-cash compensation expense. Adjusted EBITDA is not a measure of net income as determined by United States generally accepted accounting principles ("GAAP").

Management believes Adjusted EBITDA is useful because it allows them to more effectively evaluate our operating performance and compare the results of our operations from period to period and 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 EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and

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book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA 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 EBITDA. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies. We believe that Adjusted EBITDA is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet debt service requirements.

The following tables present a reconciliation of the non-GAAP financial measure of Adjusted EBITDA to the GAAP financial measure of net income (loss).

	Vantage I (Predecessor)												Vantage Energy Inc.

	Three Months Ended March 31,						Year Ended December 31,
														Pro Forma Year Ended December 31, 2013
													Pro Forma Three Months Ended March 31, 2014
	2014			2013			2013			2012			Pro Forma Three Months Ended March 31, 2014
(in thousands)
Adjusted EBITDA reconciliation to net income (loss):
Net income (loss)	$	(10,258	)	$	(7,738	)	$	22,656		$	(4,508	)	$	$
Interest income, net		—			(3	)		—			(9	)
Interest expense, net of capitalized interest		4,159			—			417			—
Depreciation, depletion, amortization and accretion		5,707			2,705			22,283			16,604
Impairment of proved oil & gas properties		—			—			—			8,043
Unrealized (gain) loss on commodity derivatives⁽¹⁾		11,257			11,414			(3,609	)		4,703
Income tax (expense) benefit		—			—			—			—


Adjusted EBITDA	$	10,865		$	6,378		$	41,747		$	24,833		$	$

(1): The adjustments for the unrealized (gain) loss on commodity derivatives have the effect of adjusting net income (loss) for changes in the fair value of derivative instruments, which are recognized at the end of each accounting period because we do not designate commodity derivative instruments as accounting hedges.

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Summary Reserve, Production and Operating Data

Summary Reserve Data

The following table summarizes the combined estimated proved reserves of Vantage I and Vantage II at December 31, 2013 based on SEC pricing.

The information in the following table does not give any effect to or reflect our commodity hedges. Please see "Business—Our Operations—Reserve Data" for more information about our reserves.

	Pro Forma

	At December 31, 2013
Estimated proved reserves:
Natural gas (Bcf)		912.4
NGLs (MMBbl)		15.5
Oil (MMBbl)		1.4
Total equivalent proved reserves (Bcfe)		1,013.4
Total equivalent proved developed reserves (Bcfe)		162.0
Percent proved developed		16.0	%
Total equivalent proved undeveloped reserves (Bcfe)		851.4

Production, Revenues and Price History

The following table sets forth information regarding production, revenues and realized prices, and production costs for the three months ended March 31, 2014 and the years ended December 31, 2013 and 2012, on a pro forma basis giving effect to the reorganization transactions described under "Corporate Reorganization." For additional information on price calculations, please see "Management's Discussion and Analysis of Financial Condition and Results of Operations."

			Pro forma Year Ended December 31,

	Pro forma Three Months Ended March 31, 2014		Pro forma Year Ended December 31,
	Pro forma Three Months Ended March 31, 2014		2013		2012
Production data:
Natural gas (Bcf)		5		21		11
NGLs (MBbl)		83		240		271
Oil (MBbl)		17		54		27
Total combined production (Bcfe)		6		23		13
Average daily combined production (MMcfe/d)		61		63		34
Average sales prices:
Natural gas (per Mcf)	$	4.92	$	3.38	$	2.16
NGLs (per Bbl)	$	31.47	$	27.52	$	30.91
Oil (per Bbl)	$	93.87	$	95.77	$	91.59
Combined average sales prices before effects of cash settled derivatives (per Mcfe)⁽¹⁾	$	5.15	$	3.63	$	2.72
Combined average sales prices after effects of cash settled derivatives (per Mcfe)⁽¹⁾	$	4.44	$	3.82	$	3.37

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			Pro forma Year Ended December 31,

	Pro forma Three Months Ended March 31, 2014		Pro forma Year Ended December 31,
	Pro forma Three Months Ended March 31, 2014		2013		2012
Average costs per Mcfe:
Lease operating and workover expenses	$	0.74	$	0.55	$	0.77
Marketing and gathering	$	0.30	$	0.31	$	0.12
Production and ad valorem taxes	$	0.17	$	0.14	$	0.15
Depreciation, depletion, amortization and accretion	$	1.40	$	1.36	$	1.34
General and administrative	$	0.58	$	0.34	$	0.50

(1): Average sales prices shown reflect both the before and after effects of our cash settled derivatives. Our calculation of such effects includes realized gains or losses on cash settlements for commodity derivatives, which do not qualify for hedge accounting because we do not designate them as hedges.

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RISK FACTORS

Investing in our common stock involves risks. You should carefully consider the information in this prospectus, including the matters addressed under "Cautionary Statement Regarding Forward-Looking Statements," and the following risks before making an investment decision. 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, NGL and oil prices are volatile. A substantial or extended decline in commodity prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

The prices we receive for our natural gas production heavily influence, and to the extent we produce oil and NGLs in the future, the prices we receive for oil and NGL production will heavily influence, our revenue, operating results profitability, access to capital, future rate of growth and carrying value of our properties. Natural gas, NGLs and oil are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the commodities market has been volatile. This market will likely 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. These factors include the following:

•: worldwide and regional economic conditions impacting the global supply of and demand for natural gas, NGLs and oil;
•: the price and quantity of imports of foreign natural gas, including liquefied natural gas;
•: political conditions in or affecting other producing countries, including conflicts in the Middle East, Africa, South America and Russia;
•: 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;
•: the proximity, capacity, cost and availability of gathering and transportation facilities, and other factors that result in differentials to benchmark prices;
•: localized and global supply and demand fundamentals and transportation availability;
•: weather conditions and other natural disasters;
•: technological advances affecting energy consumption;
•: the cost of exploring for, developing, producing and transporting reserves;
•: speculative trading in natural gas and crude oil derivative contracts;
•: risks associated with operating drilling rigs;
•: the price and availability of competitors' supplies of natural gas and oil and alternative fuels; and
•: domestic, local and foreign governmental regulation and taxes.

Furthermore, the worldwide financial and credit crisis in recent years has reduced the availability of liquidity and credit to fund the continuation and expansion of industrial business operations

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worldwide resulting in a slowdown in economic activity and recession in parts of the world. This has reduced worldwide demand for energy and resulted in lower natural gas, NGL and oil prices.

Lower commodity prices and negative increases in our differentials will reduce our cash flows and borrowing ability. 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, NGLs and oil that we can produce economically.

If commodity prices further decrease or our negative differentials further increase, a significant portion of our development and exploration projects could become uneconomic. This may result in our having to make significant downward adjustments to our estimated proved reserves. As a result, a substantial or extended decline in commodity prices or an increase in our negative differentials may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.

Our development and exploration projects require substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms, which could lead to a decline in our natural gas reserves.

The natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures for the development and acquisition of natural gas reserves. In 2014, we plan to invest $540 million in our operations, including $441 million for drilling and completion, $40 million for leasehold acquisitions, $5 million for seismic and other activities and $54 million related to our gathering, compression and other midstream operations. We have not allocated any capital spending to properties other than our primary Marcellus and Barnett Shale operations. Our capital budget excludes acquisitions, other than leasehold acquisitions.

The actual amount and timing of our future capital expenditures 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 in natural gas prices from current levels may result in a decrease in our actual capital expenditures, which would negatively impact our ability to grow production. We intend to finance our future capital expenditures primarily through cash flow from operations and through available capacity under our combined revolving credit facility; 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 would require that a portion of our cash flow from operations be used for the payment of interest and principal on our indebtedness, thereby reducing our ability to use cash flow from operations to fund working capital, capital expenditures and acquisitions.

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

•: our proved reserves;
•: the level of hydrocarbons 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 levels of our operating expenses; and
•: our ability to borrow under our combined revolving credit facility.

If our revenues or the borrowing bases under our combined revolving credit facility decrease as a result of lower natural gas prices, operating difficulties, declines in reserves or for any other reason, we

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may have limited ability to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms acceptable to us, if at all. If cash flow generated by our operations or available capacity under our combined revolving credit facility are not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our properties, which in turn could lead to a decline in our reserves and production, and could adversely affect our business, financial condition and results of operations.

We have been an early entrant into new or emerging plays. As a result, our drilling results in these areas are uncertain, and the value of our undeveloped acreage will decline if drilling results are unsuccessful.

In addition to our primary operations in the Marcellus and Barnett Shales, we hold additional acreage in the Uinta and Pieance plays in Utah and Colorado, respectively. Moreover, we believe substantially all of our Marcellus Shale acreage is also prospective for the Upper Devonian Shale and may be prospective for the Utica Shale. Due to the limited operational history, each of the Upper Devonian Shale, Utica Shale, Uinta and Piceance plays may be considered a new or emerging play.

While our costs to acquire undeveloped acreage in new or emerging plays have generally been less than those of later entrants into a developing play, our drilling results in these areas are more uncertain than drilling results in areas that are developed and producing. Since new or emerging plays have limited production history and since we have limited experience drilling in these plays, we are unable to use past drilling results in those areas to help predict our future drilling results. As a result, our cost of drilling, completing and operating wells in these areas may be higher than initially expected, and the value of our undeveloped acreage will decline if drilling results are unsuccessful. Additionally, we cannot assure you that all prospects will be economically viable or that we will not abandon our investments. We cannot assure you that unproved property acquired by us or undeveloped acreage leased by us will be profitably developed, that wells drilled by us in prospects that we pursue will be productive or that we will recover all or any portion of our investment in such unproved property or wells.

Part of our strategy involves using some of the latest available horizontal drilling and completion techniques, which involve risks and uncertainties in their application.

Our operations involve utilizing some of the latest drilling and completion techniques as developed by us and our service providers. Risks that we face while drilling include, but are not limited to, the following:

•: effectively controlling the level of pressure flowing from particular wells;
•: landing our wellbore in the desired drilling zone;
•: staying in the desired drilling zone while drilling horizontally through the formation;
•: running our casing the entire length of the wellbore; and
•: being able to run tools and other equipment consistently through the horizontal wellbore.

Risks that we face while completing our wells include, but are not limited to, the following:

•: the ability to fracture stimulate the planned number of stages;
•: the ability to run tools the entire length of the wellbore during completion operations; and
•: the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage.

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The results of our drilling in new or emerging formations are more uncertain initially than drilling results in 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 drilling results are less than anticipated, the return on our investment for a particular project may not be as attractive as we anticipated and we could incur material write-downs of unevaluated properties and the value of our undeveloped acreage could decline in the future.

Drilling for and producing natural gas are high-risk activities with many uncertainties that could result in a total loss of investment or otherwise adversely affect our business, financial condition or results of operations.

Our future financial condition and results of operations will depend on the success of our development and acquisition activities, which are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable natural gas production, that we will not recover all or any portion of our investment in such wells or that various characteristics of the well will cause us to plug or abandon the well prior to producing in commercially viable quantities.

Our decisions to purchase, explore or develop prospects or 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. For a discussion of the uncertainty involved in these processes, please see "—Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves." In addition, our cost of drilling, completing and operating wells is often uncertain before drilling commences.

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

•: delays imposed by or resulting from compliance with regulatory requirements, including limitations resulting from wastewater disposal, discharge of greenhouse gases and limitations on hydraulic fracturing;
•: pressure or irregularities in geological formations;
•: shortages of or delays in obtaining equipment and qualified personnel or in obtaining water for hydraulic fracturing activities;
•: equipment failures, accidents or other unexpected operational events;
•: lack of available gathering facilities or delays in construction of gathering facilities;
•: lack of available capacity on interconnecting transmission pipelines or the failure of our product to meet qualify specifications for such pipeline;
•: lack of available processing facilities on economic terms;
•: adverse weather conditions, such as blizzards and ice storms;
•: issues related to compliance with environmental regulations;
•: environmental hazards, such as natural gas leaks, oil spills, pipeline and tank ruptures, encountering naturally occurring radioactive materials, and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;
•: declines in natural gas prices;

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•: limited availability of financing at acceptable terms;
•: title problems; and
•: limitations in the market for natural gas.

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

We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under applicable debt instruments, which may not be successful.

Our ability to make scheduled payments on or to refinance our indebtedness obligations, including the combined revolving credit facility that we expect to enter into in connection with the completion of this offering, the $200 million Vantage I second lien term loan and the $100 million Vantage II second lien term loan, 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 not be able to maintain a level of cash flows from operating activities sufficient 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 service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance 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 business operations. The terms of existing or future debt instruments may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet debt service and other obligations. Our combined revolving credit facility is expected to restrict our ability to dispose of assets and our use of the proceeds from such disposition. We may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations.

In the future, we may not be able to access adequate funding under our combined revolving credit facility as a result of a decrease in borrowing bases due to the issuance of new indebtedness, the outcome of a subsequent borrowing base redetermination or 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 the defaulting lender's portion. Declines in commodity prices could result in a determination to lower the borrowing base in the future and, in such a case, we could be required to repay any indebtedness in excess of the redetermined borrowing base. As a result, we may be unable to implement our drilling and development plan, make acquisitions or otherwise carry out business plans, which would have a material adverse effect on our financial condition and results of operations and impair our ability to service our indebtedness.

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Substantially all of our producing properties are located in the Marcellus Shale and Barnett Shale, making us vulnerable to risks associated with operating in only two geographic areas.

Substantially all of our producing properties are located in the Marcellus Shale and in the Barnett Shale. As a result of this geographic concentration, an adverse development in the oil and natural gas business in our operating areas could have a greater impact on our financial condition and results of operations than if we were more geographically diverse. Due to the concentrated nature of our properties, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, market limitations, water shortages or other drought related conditions or interruption of the processing or transportation of oil, natural gas or NGLs. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.

Insufficient takeaway capacity in the Appalachian Basin could cause significant fluctuations in our realized natural gas prices.

The Appalachian Basin natural gas business environment has historically been characterized by periods in which production has surpassed local takeaway capacity, sometimes resulting in curtailment of production or substantial discounts in the price received by producers. We expect that a significant portion of our production in the Marcellus Shale will be transported on pipelines that experience a negative differential to NYMEX Henry Hub prices. Should production growth in the Appalachian Basin continue to outpace the increases in takeaway capacity or if we are unable to secure firm takeaway capacity to accomodate our growing production, it could result in substantial discounts in the price we receive for our production, may limit our ability to market our production and could have a material adverse effect on our financial condition and results of operations.

Restrictions in our existing and future debt agreements could limit our growth and our ability to engage in certain activities.

The Vantage I and Vantage II revolving credit facilities and second lien term loan facilities each contain, and our combined revolving credit facility is expected to contain, a number of significant covenants (in addition to covenants restricting the incurrence of additional indebtedness), including restrictive covenants that may limit our ability to, among other things:

•: sell assets;
•: make loans to others;
•: make investments;
•: enter into mergers;
•: make certain payments;
•: hedge future production or interest rates;
•: incur liens;
•: engage in certain other transactions without the prior consent of the lenders; and
•: pay dividends.

In addition, our debt instruments require us to maintain certain financial ratios or to reduce our indebtedness if we are unable to comply with such 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. As of March 31, 2014, Vantage I and Vantage II were out of compliance with certain covenants, including hedging restrictions, under their respective revolving credit facilities and were required to seek waivers. Please see "Management's Discussion and Analysis of Financial Condition and Results of Operations—Pro Forma Capital Resources and Liquidity—Debt Agreements—Vantage I Revolving Credit Facility" and "—Vantage II Revolving Credit Facility."

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Any significant reduction in our borrowing base under our combined revolving credit facility as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.

Our combined revolving credit facility that we intend to enter into in connection with the completion of this offering is expected to limit the amounts we can borrow up to a borrowing base amount, which the lenders, in their sole discretion, determine on a semi-annual basis based upon projected revenues from the natural gas and oil properties securing our loan. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under our revolving credit facilities. Any increase in the borrowing base requires the consent of the lenders holding 100% of the commitments. If the requisite number of lenders do not agree to an increase, then the borrowing base will be the lowest borrowing base acceptable to such lenders. Outstanding borrowings in excess of the borrowing base must be repaid, or we must pledge other natural gas and oil properties as additional collateral after applicable grace periods. We do not currently have any substantial unpledged properties, and we may not have the financial resources in the future to make mandatory principal prepayments required under our revolving credit facilities.

If we are unable to comply with the restrictions and covenants in the agreements governing our indebtedness, there could be an event of default under the terms of such agreements, which could result in an acceleration of repayment.

As of March 31, 2014, we were out of compliance with certain covenants in our revolving credit facilities. Please see "Management's Discussion and Analysis of Financial Condition and Results of Operations—Pro Forma Capital Resources and Liquidity—Debt Agreements." Although we were able to obtain waivers of such breaches from our lenders with respect to these breaches, there is no guarantee that we would be able to obtain waivers with respect to any future breaches under our debt obligations.

A breach of any covenant in any of our facilities would result in a default under the applicable agreement after any applicable grace periods. A default, if not waived, could result in acceleration of the indebtedness outstanding under the relevant facility and in a default with respect to, and an acceleration of, the indebtedness outstanding under other debt agreements, which would have a material adverse effect on us. The accelerated indebtedness would become immediately due and payable. If that occurs, we may not be able to make all of the required payments or borrow sufficient funds to refinance such indebtedness. Even if new financing were available at that time, it may not be on terms that are acceptable to us.

Should we no longer be able to hedge at pricing we view as attractive, it could have a material adverse effect on our financial condition. Additionally, if development drilling costs increase significantly in the future, our hedged revenues may not be sufficient to cover our costs. Finally, in certain circumstances we may have to purchase commodities on the open market or make cash payments under our hedging arrangements and these payments could be significant.

As of December 31, 2013, Vantage I and Vantage II had entered into a number of hedge contracts for approximately 72 Bcfe of their projected natural gas, NGL and oil production through 2015. In the past, Vantage I and Vantage II have received significant benefit from these hedge positions. For example, for the years ended December 31, 2013 and 2012, Vantage I and Vantage II collectively received approximately $4.5 million and $8.2 million, respectively, in revenues pursuant to their hedges, which represented approximately 7% and 22%, respectively, of our total revenues for such periods. If we are unable to enter into new hedge contracts in the future at favorable pricing and for a sufficient amount of our production, our financial condition and results of operations could be materially adversely affected. Additionally, to the extent our development drilling costs are not fixed under contract and increase significantly in the future, our hedged revenues may not be sufficient to cover our costs.

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As of March 31, 2014, Vantage I and Vantage II had entered into hedging contracts through 2017 covering a total of approximately 74 Bcfe of their projected natural gas, NGL and oil production at a weighted average price of $4.47 per Mcfe. For the period from January 1, 2015 to December 31, 2015, Vantage I and Vantage II have hedged approximately 52 Bcfe of our projected natural gas, NGL and oil production at a weighted average price of $4.42 per MMBtu. If we have to purchase additional commodities on the open market or post cash collateral to meet obligations under such arrangements, our cash otherwise available for use in our operations would be reduced.

Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

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 must project production rates and timing of development expenditures. 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 natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.

Actual future production, natural gas, oil and NGL prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas reserves will vary from our estimates. As a substantial portion of our reserve estimates are made without the benefit of a lengthy production history, any significant variance from the above assumption could materially affect the estimated quantities and present value of our reserves. In addition, we may adjust reserve estimates to reflect production history, results of exploration and development, existing commodity prices and other factors, many of which are beyond our control.

You should not assume that the present value of future net revenues from our reserves is the current market value of our estimated natural gas, oil and NGL reserves. We generally base the estimated discounted future net cash flows from reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate.

Reserve estimates for fields that do not have a lengthy production history are less reliable than estimates for fields with lengthy production histories. Less production history may contribute to less accurate estimates of reserves, future production rates and the timing of development expenditures. Most of our producing wells have been operational for less than one year and estimated reserves vary substantially from well to well and are not directly correlated to perforated lateral length or completion technique. A material and adverse variance of actual production, revenues and expenditures from those underlying reserve estimates would have a material adverse effect on our business, financial condition, results of operations and cash flows.

Our identified drilling locations are scheduled out over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill our identified drilling locations.

Our management team has specifically identified and scheduled certain well locations as an estimation of our future multi-year drilling activities on our existing acreage. These well locations represent a significant part of our growth strategy. Our identified drilling locations are made up of drillable and estimated locations. Drillable locations are mapped locations that our reserve engineers

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have deemed to have a high likelihood of being drilled or are currently in development but have not yet commenced production. Drillable locations are subject to change, and their determination is based on many of the same assumptions and projections as with determining our reserve estimates. Estimated locations are calculated based on the same spacing assumptions as with our drillable and producing locations, but are risked at 50%. Estimated locations are not mapped locations and are highly dependent on the interpretations of available technical data and assumptions that we use in determining our drillable locations. As a result, changes in our determination of drillable locations may have an effect on our calculation of estimated locations. For example, changes to our well spacing assumptions with respect our drillable locations could have a significant impact on our estimated locations.

Our ability to drill and develop these locations depends on a number of uncertainties, including natural gas and oil prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors. Because of these uncertain factors, we do not know if the numerous drilling locations we have identified will ever be drilled or if we will be able to produce natural gas or oil from these or any other identified drilling locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the potential locations are obtained, the leases for such acreage will expire. Further, certain of the horizontal wells we intend to drill in the future may require unitization with adjacent leaseholds controlled by third parties. If these third parties are unwilling to unitize such leaseholds with ours, this may limit the total locations we can drill. As such, our actual drilling activities may materially differ from those presently identified.

As of April 30, 2014, we had 1,074 identified drilling locations. As a result of the limitations described above, we may be unable to drill many of our identified drilling locations. In addition, we will require significant additional capital over a prolonged period in order to pursue the development of these locations, and we may not be able to raise or generate the capital required to do so. Any drilling activities we are able to conduct on these potential locations may not be successful or result in our ability to add additional proved reserves to our overall proved reserves or may result in a downward revision of our estimated proved reserves, which could have a material adverse effect on our future business and results of operations. For more information on our identified drilling locations, please see "Business—Our Operations—Reserve Data—Determination of Identified Drilling Locations."

The development of our estimated proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated proved undeveloped reserves may not be ultimately developed or produced.

At December 31, 2013, 84% of our total estimated proved reserves were classified as proved undeveloped. Our approximately 851.4 Bcfe of estimated proved undeveloped reserves as of that date will require an estimated $735 million of development capital over the next five years. Moreover, the development of probable and possible reserves will require additional capital expenditures and such reserves are less certain to be recovered than proved reserves. Development of these undeveloped reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Delays in the development of our reserves, increases in costs to drill and develop such reserves, or decreases in commodity prices will reduce the value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our proved undeveloped reserves as unproved reserves.

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Our acreage must be drilled before lease expiration, generally within three to five years, in order to hold the acreage by production. In a highly competitive market for acreage, failure to drill sufficient wells to hold acreage may result in a substantial lease renewal cost, or if renewal is not feasible, loss of our lease and prospective drilling opportunities.

Leases on our oil and natural gas properties typically have a term of three to five years, after which they expire unless, prior to expiration, production is established within the spacing units covering the undeveloped acres. As of April 30, 2014, we had leases representing 5,498 undeveloped acres scheduled to expire in 2014, 13,704 undeveloped acres scheduled to expire in 2015, 5,301 undeveloped acres scheduled to expire in 2016, 7,173 undeveloped acres scheduled to expire in 2017 and 29,693 undeveloped acres scheduled to expire in 2018 and beyond. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. Moreover, many of our leases require lessor consent to unitize, which may make it more difficult to hold our leases by production. Any reduction in our current drilling program, either through a reduction in capital expenditures or the unavailability of drilling rigs, could result in the loss of acreage through lease expirations. We cannot assure you that we will have the liquidity to deploy rigs when needed, or that commodity prices will warrant operating such a drilling program. Our reserves and future production and, therefore, our future cash flow and income are highly dependent on successfully developing our undeveloped leasehold acreage and the loss of any leases could materially and adversely affect our ability to so develop such acreage.

The standardized measure of discounted future net cash flows from our proved reserves will not be the same as the current market value of our estimated oil and natural gas reserves.

You should not assume that the standardized measure of discounted future net cash flows from our proved reserves is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements in effect at December 31, 2013, we based the discounted future net cash flows from our proved reserves on the 12-month first-day-of-the-month oil and natural gas average prices without giving effect to derivative transactions. Actual future net cash flows from our oil and natural gas properties will be affected by factors such as:

•: actual prices we receive for oil and natural gas;
•: actual cost of development and production expenditures;
•: the amount and timing of actual production; and
•: changes in governmental regulations or taxation.

The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating standardized measure may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general. As a limited liability company, our predecessor was not subject to federal taxation. Accordingly, our standardized measure does not provide for federal corporate income taxes because taxable income was passed through to the predecessor members. As a corporation, we will be treated as a taxable entity for federal income tax purposes and our future income taxes will be dependent on our future taxable income. Actual future prices and costs may differ materially from those used in the present value estimates included in this prospectus which could have a material effect on the value of our reserves.

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

Leases in the Appalachian Basin are particularly vulnerable to title deficiencies due the long history of land ownership in the area, resulting in extensive and complex chains of title. In the course of acquiring the rights to develop oil and natural gas, it is standard procedure for us and the lessor to

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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 oil and 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 oil and 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 an oil or 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.

If commodity prices decrease to a level such that our future undiscounted cash flows from our properties are less than their carrying value for a significant period of time, we will be required to take write-downs of the carrying values of our properties.

Accounting rules require that we periodically review the carrying value of our properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our properties. A write-down constitutes a non-cash charge to earnings. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations for the periods in which such charges are taken.

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

Producing natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Unless we conduct successful ongoing development and exploration activities or continually acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. 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.

Conservation measures and technological advances could reduce demand for oil and natural gas.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows.

Our derivative activities could result in financial losses or could reduce our earnings.

To achieve more predictable cash flows and reduce our exposure to adverse fluctuations in the prices of natural gas, we enter into derivative instrument contracts for a significant portion of our natural gas production, including fixed-price swaps. As of March 31, 2014, Vantage I and Vantage II

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had entered into hedging contracts through 2015 covering a total of approximately 74 Bcfe of their projected natural gas, NGL and oil production at a weighted average price of $4.47 per Mcfe. For the period from January 1, 2015 to December 31, 2015, Vantage I and Vantage II have hedged approximately 52 Bcfe of their projected natural gas, NGL and oil production at a weighted average price of $4.42 per MMBtu. Accordingly, earnings may fluctuate significantly as a result of changes in fair value of our derivative instruments.

Derivative instruments also expose us to the risk of financial loss in some circumstances, including when:

•: production is less than the volume covered by the derivative instruments;
•: the counterparty to the derivative instrument defaults on its contractual obligations;
•: there is an increase in the differential between the underlying price in the derivative instrument and actual prices received; or
•: there are issues with regard to legal enforceability of such instruments.

The use of derivatives may, in some cases, require the posting of cash collateral with counterparties. If we enter into derivative instruments that require cash collateral and commodity prices or interest rates change in a manner adverse to us, our cash otherwise available for use in our operations would be reduced which could limit our ability to make future capital expenditures and make payments on our indebtedness, and which could also limit the size of our borrowing base. Future collateral requirements will depend on arrangements with our counterparties, highly volatile oil and natural gas prices and interest rates.

Our hedging transactions expose us to risk of financial loss if 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. As of March 31, 2014, for Vantage I and Vantage II, the estimated fair value of our commodity derivative contracts was approximately $12.3 million. 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.

In addition, derivative arrangements could limit the benefit we would receive from increases in the prices for natural gas, which could also have an adverse effect on our financial condition.

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

In addition to credit risk related to receivables from commodity derivative contracts, our principal exposures to credit risk are through joint interest receivables ($8.4 million at March 31, 2014) and the sale of our natural gas production ($8.0 million in receivables at March 31, 2014), which we primarily market to two natural gas marketing companies. Joint interest receivables arise from billing entities who own partial interest in the wells we operate. These entities participate in our wells primarily based on their ownership in leased properties on which we wish to drill. We can do very little to choose who participates in our wells. We are also subject to credit risk due to concentration of our natural gas receivables with two natural gas marketing companies. These two purchasers of our natural gas during the twelve months ended December 31, 2013 purchased approximately 54% of our operated production. We do not require our customers to post collateral. The inability or failure of our significant customers or working interest holders to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.

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Our operations are subject to governmental laws and regulations relating to the protection of the environment, which 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 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. 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.

Certain environmental laws impose strict as well as joint and several liability for costs required to remediate and restore sites where hazardous substances, hydrocarbons, or solid wastes have been stored or released. We may be required to remediate contaminated properties currently or formerly operated by us or facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. 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. 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.

Changes in laws or government regulations regarding hydraulic fracturing could increase our costs of doing business, limit the areas in which we can operate and reduce our oil and natural gas production, which could adversely impact our 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.

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In addition, EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act ("SDWA") 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. Also, in November 2011, the EPA announced its intent to develop and issue regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing. On May 9, 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. To date, no other action has been taken. Further, on October 21, 2011, the EPA announced its intention to propose regulations under the federal Clean Water Act ("CWA") by late 2014 governing wastewater discharges from hydraulic fracturing and certain other natural gas operations. In addition, the U.S. Department of the Interior published a revised proposed rule on May 16, 2013, that would update existing regulation of hydraulic fracturing activities on federal lands, including requirements for chemical disclosure, well bore integrity and handling of flowback water.

Presently, 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, Pennsylvania, Texas, Colorado and Utah (where we conduct operations) have 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. For example, the Pennsylvania Supreme Court recently limited the ability to regulate such ordinances from a state-wide level, as well as the ability to require the enactment of local ordinances aiding drilling activities. Following this decision, local governments in Pennsylvania may increasingly adopt ordinances relating to drilling and hydraulic fracturing activities, especially within residential areas. In addition, on May 6, 2014, in response to concerns regarding hydraulic fracturing, the city of Denton, Texas issued a moratorium on the issuance of new drilling permits inside the Denton city limits until September 9, 2014. Although the moratorium is not expected to have an impact on our current production and operations in Denton, a continuation of the moratorium beyond the currently planned end date or an expansion of the moratorium scope could cause us to revise our drilling plan in this area and could have an adverse effect on our operations. 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, the EPA is conducting a study of the potential impacts of hydraulic fracturing activities on water resources. The EPA issued a Progress Report in December 2012 and a draft final report is anticipated by late 2014 for peer review and public comment. The results of this study or similar governmental reviews could spur initiatives to regulate hydraulic fracturing under the SDWA or otherwise. If new federal, state or local laws or regulations that significantly restrict hydraulic fracturing are adopted, such legal requirements could result in delays, eliminate certain drilling and injection activities and make it more difficult or costly to perform fracturing. Any such regulations limiting or prohibiting hydraulic fracturing could reduce oil and natural gas exploration and production activities and, therefore, adversely affect our business. Such laws or regulations could also materially increase our costs of compliance and doing business by more strictly regulating how hydraulic fracturing wastes are handled or disposed.

Oil and natural gas producers' operations, especially those using hydraulic fracturing, are substantially dependent on the availability of water. Restrictions on the ability to obtain water for exploration and production activities and the disposal of produced water may impact our operations.

Water is an essential component of oil and natural gas production during the drilling and, in particular, hydraulic fracturing, process. Our inability to locate sufficient amounts of water, or dispose of or recycle water used in our exploration and production operations, could adversely impact our operations.

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Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of natural gas. The CWA imposes restrictions and strict controls regarding the discharge of pollutants into navigable waters. Permits must be obtained to discharge pollutants to waters and to conduct construction activities in waters and wetlands. The CWA and similar state laws provide for civil, criminal and administrative penalties for any unauthorized discharges of pollutants and unauthorized discharges of reportable quantities of oil and other hazardous substances. State and federal discharge regulations prohibit the discharge of produced water and sand, drilling fluids, drill cuttings and certain other substances related to the natural gas and oil industry into coastal waters. Specific to Pennsylvania, sending wastewater to publicly owned treatment works requires certain levels of pretreatment that may effectively prohibit this method as a disposal option, leaving disposal via saltwater disposal injection well as our primary option. Our continued ability to use injection wells as a disposal option on economic terms not only will depend on federal or state regulations but also on the cost and availability of wells with sufficient storage capacities. The EPA has also adopted regulations requiring certain natural gas and oil exploration and production facilities to obtain permits for storm water discharges. Compliance with current and future environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells and any inability to secure transportation and access to disposal wells with sufficient capacity to accept all our produced water on economic terms may increase our operating costs and cause delays, interruptions or termination of our operations, the extent of which cannot be predicted.

We are subject to risks associated with climate change.

There is a growing belief that emissions of greenhouse gases ("GHGs") may be linked to climate change. Climate change and the costs that may be associated with its impacts and the regulation of GHGs have the potential to affect our business in many ways, including negatively impacting the costs we incur in providing our products and services, the demand for and consumption of our products and services (due to change in both costs and weather patterns), and the economic health of the regions in which we operate, all of which can create financial risks. In addition, legislative and regulatory responses related to GHGs and climate change creates the potential for financial risk. The U.S. Congress has previously considered legislation related to GHG emissions. There have also been international efforts seeking legally binding reductions in emissions of GHGs. In addition, increased public awareness and concern may result in more state, regional and/or federal requirements to reduce or mitigate GHG emissions.

In 2009, the EPA finalized a GHG reporting rule under the federal Clean Air Act ("CAA") that requires large sources of GHG emissions to monitor, maintain records on, and annually report their GHG emissions beginning January 1, 2010. The rule applies primarily to large facilities emitting 25,000 metric tons or more of carbon dioxide-equivalent ("CO2e") emissions per year and to most upstream suppliers of fossil fuels, as well as manufacturers of vehicles and engines. Subsequently, in 2010, the EPA issued GHG monitoring and reporting regulations onshore and offshore oil and natural gas production facilities that emit 25,000 metric tons or more of CO2e per year. We are required to report our GHG emissions to the EPA each year in March under this rule. The EPA also issued a final rule that makes certain stationary sources and newer modification projects subject to permitting requirements for GHG emissions, beginning in 2011, under the CAA.

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

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cap and trade programs that typically require major sources of GHG emissions 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 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.

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 exploration and production activities are subject to all of the operating risks associated with drilling for and producing natural gas, including the possibility of:

•: environmental hazards, such as uncontrollable releases of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater, air and shoreline contamination;
•: abnormally pressured formations;
•: mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse;
•: fires, explosions and ruptures of pipelines;
•: personal injuries and death;
•: natural disasters; and
•: terrorist attacks targeting natural gas and oil related facilities and infrastructure.

Any of these risks could adversely affect our ability to conduct operations or result in substantial loss to us as a result of claims for:

•: injury or loss of life;
•: damage to and destruction of property, natural resources and equipment;
•: pollution and other environmental damage;
•: regulatory investigations and penalties;
•: suspension of our operations; and
•: repair and remediation costs.

In accordance with what we believe to be customary industry practice, we maintain insurance against some, but not all, of our business risks. Our insurance may not be adequate to cover any losses or liabilities we may suffer. Also, insurance may no longer be available to us or, if it is, its availability may be at premium levels that do not justify its purchase. The occurrence of a significant uninsured claim, a claim in excess of the insurance coverage limits maintained by us or a claim at a time when we are not able to obtain liability insurance could have a material adverse effect on our ability to conduct normal business operations and on our financial condition, results of operations or cash flows. In

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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.

Since hydraulic fracturing activities are a large part of our operations, they are covered by our insurance against claims made for bodily injury, property damage and clean-up costs stemming from a sudden and accidental pollution event. However, we may not have coverage if we are unaware of the pollution event and unable to report the "occurrence" to our insurance company within the time frame required under our insurance policy. We have no coverage for gradual, long-term pollution events. In addition, these policies do not provide coverage for all liabilities, and we cannot assure you that the insurance coverage will be adequate to cover claims that may arise, or that we will be able to maintain adequate insurance at rates we consider reasonable. A loss not fully covered by insurance could have a material adverse effect on our financial condition, results of operations and cash flows.

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, NGLs or oil in commercially viable quantities.

Properties that we decide to drill that do not yield natural gas, NGLs or oil in commercially viable quantities will adversely affect our results of operations and financial condition. Our project areas are in various stages of development, ranging from project areas with current drilling or production activity to project areas that consist of recently acquired leasehold acreage or that have limited drilling or production history. If the wells in the process of being completed do not produce sufficient revenues to return a profit or if we drill dry holes in the future, our business may be materially affected. In addition, there is no way to predict in advance of drilling and testing whether any particular prospect will yield natural gas, NGLs or oil in sufficient quantities to recover drilling or completion costs or to be economically viable. 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, NGLs or oil will be present or, if present, whether natural gas, NGLs or oil will be present in commercial quantities. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects. Further, our drilling operations may be curtailed, delayed or cancelled as a result of numerous factors, including:

•: unexpected drilling conditions;
•: title problems;
•: pressure or lost circulation in formations;
•: equipment failure or accidents;
•: adverse weather conditions;
•: compliance with environmental and other governmental or contractual requirements; and
•: increase in the cost of, or shortages or delays in the availability of, electricity, supplies, materials, drilling or workover rigs, equipment and services.

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We may be unable to make attractive acquisitions or successfully integrate acquired businesses, and any inability to do so may disrupt our business and hinder our ability to grow.

In the future we may make acquisitions of businesses that complement or expand our current business. We may not be able to identify attractive acquisition opportunities. Even if we do identify attractive acquisition opportunities, we may not be able 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 combined revolving credit facility is expected to impose certain limitations on our ability to enter into mergers or combination transactions. Our combined revolving credit facility is also expected to limit our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions of businesses.

We depend upon a limited number of significant purchasers for the sale of most of our production. The loss of one or more of these purchasers could, among other factors, limit our access to suitable markets for the hydrocarbons we produce.

The availability of a ready market for any hydrocarbons we produce depends on numerous factors beyond the control of our management, including but not limited to the extent of domestic production and imports of oil, the proximity and capacity of natural gas pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of oil and natural gas production and federal regulation of natural gas sold in interstate commerce. In addition, we depend upon a limited number of significant purchasers for the sale of most of our production, and our contracts with those customers typically are on a month-to-month basis. The loss of these customers could adversely affect our revenues and have a material and adverse effect on our financial condition and results of operations. We cannot assure you that any of our customers will continue to do business with us or that we will continue to have ready access to suitable markets for our future production.

Market conditions or the availability and capacity of gathering systems, transportation and processing facilities may hinder our access to natural gas, NGL or oil markets or delay our production.

Market conditions or the unavailability of satisfactory natural gas, NGL or oil gathering, transportation or processing arrangements may hinder our access to markets or delay our production. The availability of a ready market for our production depends on a number of factors, including the demand for and supply of natural gas, NGLs or oil and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the operation, availability, proximity, capacity and expansion of gathering systems, pipelines and processing facilities owned and operated by third parties. Our failure to obtain such services on acceptable terms could materially harm our business. We may be required to shut in wells due to lack of a market or inadequacy or unavailability of natural gas, NGL or oil pipeline or gathering system capacity. In addition, if quality specifications for the third-party pipelines with which we connect change so as to restrict our ability to transport product, our access to markets could be impeded. Our access to

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transportation options, including trucks owned by third parties, may also be affected by U.S. federal and state regulation of natural gas, NGL and oil production and transportation. If our production becomes shut in for any of these or other reasons, we would be unable to realize revenue from those wells until other arrangements were made to gather, process and deliver the products to market. In addition, we have entered into contracts for firm transportation and any failure to renew those contracts on the same or better commercial terms could increase our costs and our exposure to the risks described above.

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities.

Our exploration, production and transportation operations are subject to complex and stringent laws and regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. We may incur substantial costs in order to maintain compliance with these existing laws and regulations. In addition, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. Such costs could have a material adverse effect on our business, financial condition and results of operations.

Our business is subject to federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration for, and the production and transportation of, natural gas. Failure to comply with such laws and regulations, including any evolving interpretation and enforcement by governmental authorities, could have a material adverse effect on our business, financial condition and results of operations.

Changes to existing or new regulations may unfavorably impact us, could result in increased operating costs and have a material adverse effect on our financial condition and results of operations. Such potential regulations could increase our operating costs, reduce our liquidity, delay or halt our operations or otherwise alter the way we conduct our business, which could in turn have a material adverse effect on our financial condition, results of operations and cash flows. Further, the discharges of oil, natural gas, natural gas liquids and other pollutants into the air, soil or water may give rise to significant liabilities on our part to the government and third parties. Please see "Business—Regulation of Environmental and Occupational Safety and Health Matters" for a further description of laws and regulations that affect us.

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 personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with natural gas and oil prices, causing periodic shortages. We intend to continue our two-rig drilling program in the Marcellus Shale, and our two-rig drilling program in the Barnett Shale; however, certain of the rigs performing work for us do so on a well-by-well basis and can refuse to provide such services at the conclusion of drilling on the current well. Historically, there have been shortages of drilling and workover rigs, pipe and other equipment as demand for rigs and equipment has increased along with the number of wells being drilled. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. Such shortages 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.

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A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.

Section 1(b) of the Natural Gas Act of 1938 ("NGA") exempts natural gas gathering facilities from regulation by the Federal Energy Regulatory Commission ("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. If the FERC were to consider the status of an individual facility and determine that the facility or services provided by it are not exempt from FERC regulation, the rates for, and terms and conditions of services provided by such facility would be subject to regulation by the FERC. Such regulation could decrease revenues, increase operating costs, and depending upon the facility in question, could adversely affect our results of operations and cash flows. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA, this could result in the imposition of civil penalties as well as a requirement to disgorge charges collected for such service in excess of the cost-based rate established by the FERC.

State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. We cannot predict what new or different regulations federal and state regulatory agencies may adopt, or what effect subsequent regulation may have on our activities. Such regulations may have a material adverse effect on our financial condition, result of operations and cash flows.

Should we fail to comply with all applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.

Under the Energy Policy Act of 2005 ("EPAct 2005"), FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1 million per day for each violation and disgorgement of profits associated with any violation. While our systems have not been regulated by FERC as a natural gas company under the NGA, we are required to report aggregate volumes of natural gas purchased or sold at wholesale to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. In addition, Congress may enact legislation or FERC may adopt regulations that may subject certain of our otherwise non-FERC jurisdictional facilities to further regulation. Failure to comply with those regulations in the future could subject us to civil penalty liability.

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 the oil and natural gas 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 over the past three years due to competition and may increase substantially in the future. We may not be able to

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compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business.

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

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

We are susceptible to the potential difficulties associated with rapid growth and expansion.

We have grown rapidly over the last several years. Our management believes that our future success depends on our ability to manage the rapid growth that we have experienced and the demands from increased responsibility on management personnel. The following factors could present difficulties:

•: increased responsibilities for our executive level personnel;
•: increased administrative burden;
•: increased capital requirements; and
•: increased organizational challenges common to large, expansive operations.

Our operating results could be adversely affected if we do not successfully manage these potential difficulties. The historical financial information incorporated herein is not necessarily indicative of the results that may be realized in the future. In addition, our operating history is limited and the results from our current producing wells are not necessarily indicative of success from our future drilling operations. We began development of our Barnett Shale properties in 2006. In 2011, we expanded our development operations and are currently managing a drilling program in both the Barnett Shale and Marcellus Shale. As a result, there is only limited historical financial and operating information available upon which to base your evaluation of our performance, especially in regards to our Marcellus Shale operations.

Seasonal weather conditions and regulations adversely affect our ability to conduct drilling activities in some of the areas where we operate.

Operations in our operating areas can be adversely affected by seasonal weather conditions and regulations designed to protect various wildlife. This limits our ability to operate in those areas and can intensify competition during those months for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs.

Increases in interest rates could adversely affect our business.

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 financial markets may lead to a contraction in credit availability impacting our ability to finance our operations. We require continued access to capital. 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.

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We may be subject to risks in connection with acquisitions of properties.

The successful acquisition of producing properties requires an assessment of several factors, including:

•: recoverable reserves;
•: future natural gas, NGL or oil prices and their applicable differentials;
•: operating costs; and
•: potential environmental and other liabilities.

The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an "as is" basis.

The enactment of derivatives legislation, and the promulgation of regulations pursuant thereto, could have an adverse effect on our ability to use derivative instruments 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. Although we expect to qualify for the end-user exception from the mandatory clearing and trade execution requirements for swaps entered to hedge its commercial risks, the application of the mandatory clearing and trade execution requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. In addition, for uncleared swaps, the CFTC or federal banking regulators may require end-users to enter into credit support documentation and/or post initial and variation margin. Posting of collateral could impact liquidity and reduce our cash available for capital expenditures, therefore reducing our ability to execute hedges to reduce risk and protect cash flows. The proposed margin rules are not yet final, and therefore the impact of those provisions to us is uncertain at this time.

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The Dodd-Frank Act and regulations may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. 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 capital expenditures.

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 revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and regulations is lower commodity prices.

Any of these consequences could have a material and adverse effect on us, our financial condition or our results of operations.

Certain federal income tax deductions currently available with respect to natural gas and oil exploration and development may be eliminated, and additional state taxes on natural gas extraction may be imposed, as a result of future legislation.

The Fiscal Year 2014 Budget proposed by the President recommends the elimination of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production companies, and legislation has been introduced in Congress that would implement many of these proposals. Such changes include, but are not limited to: (i) the repeal of the percentage depletion allowance for oil and gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; (iii) the elimination of the deduction for certain U.S. production activities for oil and gas production; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear, however, whether any such changes will be enacted or how soon such changes could be effective.

The passage of this legislation or any other similar change in U.S. federal income tax law could eliminate or postpone certain tax deductions that are currently available with respect to natural gas and oil exploration and development, and any such change could negatively affect our financial condition and results of operations.

Our method of accounting for investments in oil and natural gas properties may result in impairment of asset value.

We account for our oil and natural gas producing activities using the full cost method of accounting. Accordingly, all costs incurred in the acquisition, exploration and development of proved oil and natural gas properties, including the costs of abandoned properties, dry holes, geophysical costs and annual lease rentals are capitalized. We also capitalize direct operating costs for services performed with internally owned drilling and well servicing equipment. All general and administrative corporate costs unrelated to drilling activities are expensed as incurred. Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change. Depletion of evaluated oil and natural gas properties is computed on the units of production method based on proved reserves. The average depletion rate per MMcfe of production was $1.32 and $1.28 for 2013 and 2012, respectively. Total depletion expense for oil and natural gas properties was $21.1 million and $16.0 million for 2013 and 2012, respectively. The net capitalized costs of proved oil and natural gas properties are subject to a full cost ceiling limitation in which the costs are not allowed to exceed their

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related estimated future net revenues discounted at 10%. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depreciation, depletion, amortization, accretion and impairment exceed the discounted future net revenues of proved reserves, the excess capitalized costs are charged to expense.

We recorded a required impairment of proved oil and gas properties in 2012 of $8.0 million due to capitalized costs being higher than the ceiling threshold, and we may experience impairments of proved oil and gas properties again in the future. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates" for a more detailed description of our method of accounting.

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 the Sarbanes-Oxley Act of 2002, related regulations of the SEC and the requirements of the NYSE, with which we are not required to comply as a private company. Complying with these statutes, regulations and requirements will occupy a significant amount of time of our board of directors and management and will significantly increase our costs and expenses. We will need to:

•: institute a more comprehensive compliance function;
•: comply with rules promulgated by the NYSE;
•: continue to prepare and distribute periodic public reports in compliance with our obligations under the federal securities laws;
•: establish new internal policies, such as those relating to insider trading; and
•: involve and retain to a greater degree outside counsel and accountants in the above activities.

Furthermore, while we generally must comply with Section 404 of the Sarbanes Oxley Act of 2002 for our fiscal year ended December 31, 2014, 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" within the meaning of Section 2(a)(19) of the Securities Act. Accordingly, 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 fiscal year ending December 31, 2020. Once it is required to do so, our independent registered public accounting firm may issue a report that is adverse in the event it is not satisfied with the level at which our controls are documented, designed, operated or reviewed. Compliance with these 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.

In addition, we expect that being a public company subject to these rules and regulations may make it more difficult and more expensive for us to obtain director and officer liability insurance and we may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for us to attract and retain qualified individuals to serve on our board of directors or as executive officers. We are currently evaluating these rules, and we cannot predict or estimate the amount of additional costs we may incur or the timing of such costs.

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There is no existing market for our common stock, and we do not know if one will develop to provide you with adequate liquidity to sell our common stock at prices equal to or greater than the price you paid in this offering.

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, you may have difficulty selling any of our common stock that you buy. 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, you may not be able to sell our common stock at prices equal to or greater than the price you paid in this offering, or at all.

The initial public offering price of our common stock may not be indicative of the market price of our common stock after this offering. In addition, an active, liquid and orderly trading market for our common stock may not develop or be maintained, and our stock price may be volatile.

Prior to this offering, our common stock was not traded on any market. An active, liquid and orderly trading market for our common stock may not develop or be maintained after this offering. Active, liquid and orderly trading markets usually result in less price volatility and more efficiency in carrying out investors' purchase and sale orders. The market price of our common stock could vary significantly as a result of a number of factors, some of which are beyond our control. In the event of a drop in the market price of our common stock, you could lose a substantial part or all of your investment in our common stock. The initial public offering price was determined by negotiations between us, the selling stockholders and representatives of the underwriters, based on numerous factors which we discuss in "Underwriting (Conflicts of Interest)," and may not be indicative of the market price of our common stock after this offering. Consequently, you may not be able to sell shares of our common stock at prices equal to or greater than the price paid by you in this offering.

The following factors could affect our stock price:

•: our operating and financial performance and drilling locations, including reserve estimates;
•: quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income and revenues;
•: the public reaction to our press releases, our other public announcements and our filings with the SEC;
•: strategic actions by our competitors;
•: our failure to meet revenue, reserves or earnings estimates by research analysts or other investors;
•: changes in revenue or earnings estimates, or changes in recommendations or withdrawal of research coverage, by equity research analysts;
•: speculation in the press or investment community;
•: the failure of research analysts to cover our common stock;
•: sales of our common stock by us, the selling stockholders or other stockholders, or the perception that such sales may occur;
•: changes in accounting principles, policies, guidance, interpretations or standards;
•: additions or departures of key management personnel;

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•: actions by our stockholders;
•: general market conditions, including fluctuations in commodity prices;
•: domestic and international economic, legal and regulatory factors unrelated to our performance; and
•: the realization of any risks describes under this "Risk Factors" section.

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.

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

Immediately following the completion of this offering, Vantage Investment I and Vantage Investment II will hold approximately % and %, respectively, of our common stock. Vantage Investment I and Vantage Investment II (and indirectly, our Sponsors) will 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 our Sponsors continue to control a significant amount of our common stock, they will continue to 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 our Sponsors 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, on the one hand, and our Sponsors and their affiliates, including their portfolio companies, on the other hand, concerning among other things, potential competitive business activities or business opportunities.

Our Sponsors are each families of private equity investment funds in the business of making investments in entities primarily in the U.S. energy industry. As a result, our Sponsors may, from time to time, acquire interests in businesses that directly or indirectly compete with our business, as well as businesses that are significant existing or potential customers. Our Sponsors may acquire or seek to acquire 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. Under our certificate of incorporation, our Sponsors and/or one or more of their respective affiliates are permitted to engage in business activities or invest in or acquire businesses which may compete with our business or do business with any client

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of ours. 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;
•: 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 March 31, 2014 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. Please see "Dilution."

We do not intend to pay dividends on our common stock, and our debt instruments place certain restrictions on our ability to do so. Consequently, your only opportunity to achieve a return on your investment is if the price of our common stock appreciates.

We do not plan to declare dividends on shares of our common stock in the foreseeable future. Additionally, our combined revolving credit facility is expected to place certain restrictions on our ability to pay cash dividends. Consequently, your only opportunity to achieve a return on your investment in us will be if you sell your common stock at a price greater than you paid for it. There is no guarantee that the price of our common stock that will prevail in the market will ever exceed the price that you pay 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

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will have outstanding shares of common stock. This number includes shares that we and the selling stockholders are selling in this offering and shares that the selling stockholders may sell in this offering if the underwriters' option to purchase additional shares is fully exercised, which may be resold immediately in the public market. Following the completion of this offering, assuming no exercise of the underwriters' option to purchase additional shares, Vantage Investment I and Vantage Investment II will collectively 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 (Conflicts of Interest)," but may be sold into the market in the future. Vantage Investment I and Vantage Investment II will be party to a registration rights agreement with us which will require us to effect the registration of their shares (and shares of 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. Please see "Shares Eligible for Future Sale" and "Certain Relationships and Related Party Transactions—Registration Rights Agreement."

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 equity incentive plan. 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, Vantage Investment I, Vantage Investment II, 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. Barclays Capital Inc., 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.

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, Vantage Investment I and Vantage Investment II will collectively beneficially control a majority of the combined voting power of all classes of our outstanding voting stock. In connection with the completion of this offering, Vantage I and Vantage II will enter into a voting agreement, pursuant to which they will agree to vote their shares of common stock in accordance with the voting agreement, including as it relates to the election of directors. For additional information regarding the voting agreement, please see "Certain Relationships and Related Party Transactions—Voting Agreement." 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

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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. Please see "Management."

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. 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, (1) 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 the Sarbanes-Oxley Act, (2) 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, (3) provide certain disclosure regarding executive compensation required of larger public companies or (4) hold nonbinding advisory votes on executive compensation. We will remain an emerging growth company for up to five years, although we will lose that status sooner if we have more than $1.0 billion of revenues in a fiscal year, have more than $700 million in market value of our common stock held by non-affiliates, or issue more than $1.0 billion of non-convertible debt over a three-year period.

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.

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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. Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock will be deemed to have notice of, and consented to, the provisions of our amended and restated certificate of incorporation described in the preceding sentence. This choice of forum provision 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 business, financial condition or results of operations.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

The information in this prospectus includes "forward-looking statements." All statements, other than statements of historical fact included in this prospectus, regarding our strategy, future operations, financial position, estimated revenues 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, NGLs and oil prices;
•: timing and amount of future production of natural gas, NGLs and oil;
•: hedging strategy and results;
•: future drilling plans;
•: competition and government regulations;
•: pending legal or environmental matters;
•: marketing of natural gas, NGLs and oil;
•: leasehold or business acquisitions;
•: costs of developing our properties and conducting our gathering and other midstream operations;
•: 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, gathering and sale of natural gas, NGLs and oil. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas, NGLs and oil 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, NGLs and oil that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the

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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 NGLs 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.

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USE OF PROCEEDS

We expect to receive approximately $ million of net proceeds (assuming the midpoint of the price range set forth on the cover of this prospectus) from the sale of the common stock offered by us after deducting underwriting discounts and commissions and estimated offering expenses payable by us. We will not receive any proceeds from the sale of shares of common stock by the selling stockholders (including pursuant to any exercise by the underwriters of their option to purchase additional shares of our common stock from the selling stockholders).

We intend to use the net proceeds from this offering to repay and retire the Vantage I second lien term loan and the Vantage II second lien term loan. We intend to use the remaining net proceeds to repay the outstanding borrowings under our combined revolving credit facility and for general corporate purposes, including to fund a portion of our development program. In connection with the repayment of the term loans and credit facility borrowings, we expect to record a $ million earnings charge for the extinguishment of debt.

The following table illustrates our anticipated use of the proceeds of this offering:

Sources of Funds (in millions)		Uses of Funds (in millions)

Gross proceeds from this offering	$	Repayment of Vantage I second lien term loan	$
		Repayment of Vantage II second lien term loan
		Repayment of combined revolving credit facility borrowings
		General corporate purposes
		Underwriting discounts, fees and expenses


Total	$	Total	$

As of April 30, 2014, we had no outstanding borrowings under the Vantage I revolving credit facility. The Vantage I revolving credit facility matures July 19, 2015 and bears interest at a variable rate, which was 2.91% per annum at March 31, 2014. As of April 30, 2014, we had $25.0 million of outstanding borrowings under the Vantage II revolving credit facility. The Vantage II revolving credit facility matures November 8, 2016 and bears interest at a variable rate, which was 2.91% per annum at March 31, 2014.

The $200 million Vantage I second lien term loan matures December 20, 2018 and bears interest at a variable rate, which was 8.5% per annum at March 31, 2014. On May 8, 2014, we entered into the $100 million Vantage II second lien term loan, which matures on May 8, 2017 and bears interest at a variable rate equal to LIBOR plus 7.5%.

The outstanding borrowings under our revolving credit facilities and term loans were incurred to fund our development program. We may at any time reborrow amounts repaid under our combined revolving credit facility, and we expect to do so to fund our development program.

A $1.00 increase or decrease 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 increase or decrease, respectively, by approximately $ million, assuming 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, including to fund a portion of our development program. If the proceeds decrease for any reason, then we would reduce by a corresponding amount the net proceeds directed for general corporate purposes.

Affiliates of and are lenders under the Vantage I second lien term loan and are expected to be lenders under our combined revolving credit facility and will receive more than 5% of the net proceeds of this offering. Accordingly, this offering is being made in compliance with Rule 5121 of the FINRA. Please see "Underwriting (Conflicts of Interest)."

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DIVIDEND POLICY

We do not anticipate declaring or paying any cash dividends to holders of our common stock in the foreseeable future. We currently intend to retain future earnings, if any, to 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. Additionally, our combined revolving credit facility is expected to place certain restrictions on our ability to pay cash dividends.

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CAPITALIZATION

The following table sets forth our cash and cash equivalents and capitalization as of March 31, 2014:

•: on an actual basis for our predecessor, Vantage I;
•: on an as adjusted basis to give effect to the transactions described under "Corporate Reorganization"; and
•: on a pro forma basis to give further effect to (i) the sale of shares of our common stock by us in this offering at an assumed initial public offering price of $ per share (the midpoint of the range set forth on the cover of this prospectus) and the application of the net proceeds as set forth under "Use of Proceeds" and (ii) the expected amendment of the Vantage I revolving credit facility.

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 predecessor's historical audited consolidated financial statements and the unaudited pro forma financial statements and the accompanying notes appearing elsewhere in this prospectus.

	As of March 31, 2014

	Actual			As Adjusted		Pro Forma
	(In thousands, except share counts and par value)
Cash and cash equivalents⁽¹⁾	$	31,181		$		$
Long-term debt, including current maturities:
Vantage I revolving credit facility⁽²⁾		—			—		—
Vantage II revolving credit facility⁽²⁾		—			—		—
Vantage I second lien term loan⁽³⁾		197,593			197,593		—
Combined revolving credit facility		—			—		—


Total indebtedness	$	197,593		$	197,593	$




Contingently redeemable Founders' units⁽⁴⁾	$	5,787			—		—
Members'/Stockholders' equity:
Members' equity	$	428,228			—		—
Preferred stock—$0.01 par value; no shares authorized, issued or outstanding, actual; shares authorized, no shares issued or outstanding, as adjusted and pro forma		—			—		—
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⁽⁵⁾		—			—
Accumulated deficit		(120,139	)


Total Members'/Stockholders' equity	$	308,089




Total capitalization	$	511,469		$		$

(1): We intend to use a portion of the proceeds of this offering to repay the Vantage I second lien term loan, the Vantage II second lien term loan (which we entered into in May 2014) and the

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outstanding borrowings under the Vantage II revolving credit facility. Please see "Use of Proceeds."

(2): As of April 30, 2014, the outstanding amount under the Vantage I and Vantage II revolving credit facilities totaled $25.0 million, and we had $142.0 million of aggregate undrawn borrowing base. After giving effect to the consummation of the reorganization transactions described under "Corporate Reorganization" and the application of the net proceeds of this offering, we expect to have $ million of available borrowing capacity under our new combined revolving credit facility. As of April 30, 2014, $0.1 million of letters of credit were outstanding under our revolving credit facilities.
(3): Net of approximately $1.9 million of issue discount, which will be amortized over the term of the loan.
(4): Please see Note 9 to the audited consolidated financial statements of each of Vantage I and Vantage II included elsewhere in this prospectus for a description of the contingently redeemable Founders' units.
(5): In connection with our corporate reorganization, we expect to recognize non-cash stock compensation expense of approximately $ at the time of the offering. In addition, approximately $ of stock compensation expense will be amortized over the remaining service period. The stock compensation expense recognized in the statement of operations will be offset by capital contributions from Vantage Investment I and Vantage Investment II; therefore, the stock compensation charge will have no effect on total equity. The estimated stock compensation charge that we will recognize at the time of the offering is reflected in the pro forma amounts. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Corporate Reorganization."

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DILUTION

Purchasers of the 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 March 31, 2014, after giving effect to the transactions described under "Corporate Reorganization." 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 initial public offering price of $ per share (which is the midpoint of the price range set forth on the cover page of this prospectus), after giving effect to the sale of the shares in this offering and further assuming the receipt of the estimated net proceeds (after deducting estimated underwriting discounts and commissions and estimated offering expenses), our adjusted pro forma net tangible book value as of March 31, 2014 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:


Initial public offering price per share		$
Pro forma net tangible book value per share as of March 31, 2014 (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 increase (decrease) 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 increase (decrease) our as adjusted pro forma net tangible book value per share after the offering by $ and increase (decrease) 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 March 31, 2014, 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:

				Total Consideration

	Shares Acquired			Total Consideration
	Shares Acquired			Amount (in thousands)			Average Price Per Share
	Number	Percent		Amount (in thousands)	Percent		Average Price Per Share
Existing owners			%	$		%	$
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.

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SELECTED HISTORICAL CONSOLIDATED AND UNAUDITED PRO FORMA FINANCIAL DATA

The selected historical consolidated financial data as of and for the three months ended March 31, 2014 and 2013 were derived from the unaudited historical consolidated financial statements of our predecessor included elsewhere in this prospectus.

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historical and unaudited pro forma financial statements include more detailed information regarding the basis of presentation for the following information.

	Vantage I (Predecessor)

	Vantage I (Predecessor)												Vantage Energy Inc.
	Three Months Ended March 31,						Year Ended December 31,						Vantage Energy Inc.
	Three Months Ended March 31,						Year Ended December 31,						Pro Forma Three Months Ended March 31, 2014	Pro Forma Year Ended December 31, 2013
	2014			2013			2013			2012			Pro Forma Three Months Ended March 31, 2014	Pro Forma Year Ended December 31, 2013
(in thousands, except per share data)
Statement of operations data:
Operating revenues:
Natural gas	$	16,775		$	9,819		$	46,266		$	23,068		$	$
Oil		1,605			692			5,152			2,473
NGL		2,612			1,249			6,599			8,370
Gas gathering revenues		—			—			99			(2	)
Gain (loss) on commodity derivatives		(14,577	)		(11,167	)		8,074			3,495


Total operating revenues		6,415			593			66,190			37,404
Operating expenses:
Production and ad valorem taxes		955			1,657			3,225			1,858
Marketing and gathering		713			469			2,640			1,389
Lease operating and workover		3,670			2,911			10,946			9,503
Gas gathering operating expenses		244			73			325			—
General and administrative		1,216			555			3,698			4,524
Depreciation, depletion, amortization and accretion		5,707			2,705			22,283			16,604
Impairment of proved oil and gas properties		—			—			—			8,043


Total operating expenses		12,505			8,370			43,117			41,921


Operating income (loss)		(6,090	)		(7,777	)		23,073			(4,517	)
Other (income) expense		9			(36	)		—			—
Interest income, net		—			3			—			9
Interest expense, net of capitalized income		4,159			—			417			—


Income (loss) before income taxes		(10,258	)		(7,738	)		22,656			(4,508	)
Income tax expense (benefit)		—			—			—			—


Net income (loss)	$	(10,258	)	$	(7,738	)	$	22,656		$	(4,508	)




Balance sheet data (at period end):
Cash	$	31,181		$	8,710		$	80,211		$	2,844		$
Total oil and gas properties, net		480,779			385,538			442,194			361,888
Total gas gathering system, net		23,741			8,972			17,290			9,040
Total assets		562,564			420,112			564,914			383,786
Total debt		197,593			96,000			198,000			50,000
Total members' / stockholders' capital		308,089			287,952			318,347			295,642
Net cash provided by (used in):
Operating activities	$	1,777		$	(3,563	)	$	43,981		$	28,349
Investing activities		(49,972	)		(36,645	)		(110,051	)		(116,445	)
Financing activities		(835	)		46,049			144,437			87,821
Other financial data (unaudited):
Adjusted EBITDA⁽¹⁾	$	10,865		$	6,378		$	41,747		$	24,833		$	$
Earnings per share—basic													$	$
Earnings per share—diluted													$	$

(1): Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to net income (loss), please see "Prospectus Summary—Summary Historical Consolidated and Unaudited Pro Forma Financial Data—Non-GAAP Financial Measure."

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

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated 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 expected performance. We caution that assumptions, expectations, projections, intentions, or beliefs about future events may, and often do, vary from actual results and the differences can be material. 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 capital expenditures, availability of acquisitions, 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. Please see "Cautionary Statement Regarding Forward-Looking Statements." Also, please see the risk factors and other cautionary statements described under the heading "Risk Factors" included elsewhere in this prospectus. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law. Unless otherwise indicated, the historical financial information presented in "Management's Discussion and Analysis of Financial Condition and Results of Operations" speaks only with respect to our predecessor, Vantage I, and does not give pro forma effect to our corporate reorganization described in "Corporate Reorganization."

Overview

We utilize advanced well completion strategies and technologies, including pad drilling and downhole rotary steering, to optimize well economics and operational efficiencies. We believe that our horizontal drilling and completion expertise, coupled with the favorable geologic characteristics of our Marcellus and Barnett Shale acreage, positions us for continued strong results and growth. We have grown our net daily production from 18.1 MMcfe/d for the year ended December 31, 2011 to 63.3 MMcfe/d for the year ended December 31, 2013, representing a compounded annual growth rate of 86.8%. Our estimated average net daily wellhead production for the first five days of July 2014 was 82.5 MMcfe/d.

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Factors That Significantly Affect Our Financial Condition and Results of Operations

Our revenues are primarily derived from the sale of our natural gas and oil production, as well as the sale of NGLs that are extracted from our natural gas during processing. Our production revenues derive entirely from the continental United States. For the year ended December 31, 2013, our production revenues were comprised of approximately 80.0% from the production and sale of natural gas and 20.0% from the production and sale of oil and NGLs. Substantially all of our production is derived from natural gas wells which also produce NGLs and limited quantities of oil. Natural gas, oil and NGL prices are inherently volatile and are influenced by many factors outside of our control.

We use commodity derivative instruments, such as swaps and collars, to manage and reduce price volatility and other market risks associated with our natural gas, NGL and oil production. These arrangements are structured to reduce our exposure to commodity price decreases, but they can also limit the benefit we might otherwise receive from commodity price increases. Our risk management activity is generally accomplished through over-the-counter commodity derivative contracts with large financial institutions. We currently use fixed price natural gas, NGL and oil swaps for which we receive a fixed swap price for future production in exchange for a payment of the variable market price received at the time future production is sold. The prices contained in natural gas derivative contracts are based on NYMEX Henry Hub, Inside FERC Dominion and Inside FERC West Texas ("WAHA"). The prices contained in NGL and oil derivative contracts are based on OPIS Mont Belvieu and NYMEX West Texas Intermediate ("WTI") prices, respectively. The NYMEX Henry Hub, Inside FERC Dominion and WAHA prices of natural gas and OPIS Mont Belvieu price of NGLs and NYMEX WTI price of oil are widely used benchmarks for the pricing of natural gas, NGL and oil, respectively, in the United States. The actual prices realized from the sale of natural gas, NGL's and oil differ from the quoted index prices as a result of basis differentials, which result from variances in regional natural gas, NGL and oil prices compared to index prices as a result of regional supply and demand factors. We are focused on maintaining an active hedging program to minimize volatility in cash flows and commodity prices and regional basis differential exposure in an effort to protect our capital investment program as well as expected future cash flows. As of March 31, 2014, Vantage I and Vantage II had entered into hedging contracts through 2017 covering a total of approximately 74 Bcfe of their projected natural gas, NGL and oil production at a weighted average price of $4.47 per Mcfe. We elected not to designate our current portfolio of commodity derivative contracts as hedges for accounting purposes. Therefore, changes in fair value of these derivative instruments are recognized in earnings. Please see "—Quantitative and Qualitative Disclosure About Market Risk" for additional discussion of our commodity derivative contracts.

Like other businesses engaged in the exploration and production of oil and natural gas, we face the challenge of natural production declines. As initial reservoir pressures are depleted, natural gas and oil production from a given well naturally decreases. Thus, a natural gas and oil exploration and production company depletes part of its asset base with each unit of natural gas and oil it produces. We attempt to overcome this natural decline by drilling to find additional reserves and acquiring more reserves than we produce. Our future growth will depend on our ability to enhance production levels from our existing reserves and to continue to add reserves in excess of production in a cost effective manner. Our ability to make capital expenditures to increase production from our existing reserves and to add reserves through drilling is dependent on our capital resources and can be limited by many factors, including our ability to access capital in a cost effective manner and to timely obtain drilling permits and regulatory approvals.

Our financial condition and results of operations, including the growth of production, cash flows and reserves, are driven by several factors, including:

•: success in drilling new wells;
•: natural gas, oil and NGLs prices;

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•: the availability of attractive acquisition opportunities and our ability to execute them;
•: the amount of capital we invest in the leasing and development of our properties;
•: facility or equipment availability and unexpected downtime;
•: delays imposed by or resulting from compliance with regulatory requirements; and
•: the rate at which production volumes on our wells naturally decline.

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:

Corporate Reorganization. The historical consolidated financial statements included in this prospectus are based on the financial statements of our accounting predecessor, Vantage I, prior to our corporate reorganization to be completed in connection with the completion of this offering. In our corporate reorganization, the combination of Vantage II into us will be accounted for at fair value, which is expected to significantly alter our full cost pool and increase future depletion costs, among other changes. In addition, we expect to record a significant amount of goodwill in connection with the acquisition of Vantage II for the excess of the consideration over the net assets received, representing the future economic benefits arising from assets acquired that could not be individually identified and separately recognized. The purchase price will be derived considering both the fair value of the common stock issued in the corporate reorganization and the fair value of proved and unproved reserves, the expected timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. Finally, we will also be a taxable entity in future periods. Because Vantage I and Vantage II have assets that substantially overlap and have been operated as a single business under a single management and operational team, we do not expect that the corporate reorganization will have any significant impacts on our business or operations going forward. Please see "Corporate Reorganization." As a result, the historical financial data do not include the results of Vantage II and may not give you an accurate indication of what our actual results would have been if the transactions described in "Corporate Reorganization" had been completed at the beginning of the periods presented or of what our future results of operations are likely to be. For more information, please see the audited historical financial statements of Vantage II and the unaudited pro forma financial statements included elsewhere in this prospectus.

Public Company Expenses. Upon completion of this offering, we expect to incur direct, incremental general and administrative ("G&A") expenses as a result of being a publicly traded company, including, but not limited to, costs associated with annual and quarterly reports to stockholders, tax return preparation, independent auditor fees, SOX compliance fees, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs and independent director compensation. We estimate these direct, incremental G&A expenses will be approximately $2.5 million per year. These direct, incremental G&A expenses are not included in our historical results of operations.

Income Taxes. Vantage I, our accounting predecessor, is a limited liability company 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 the members of Vantage I. Although we are a corporation under the Internal Revenue Code, subject to federal income taxes at a statutory rate of 35% of pretax earnings, we do not expect to report any income tax benefit or expense until the consummation of this offering. Based on our deductions primarily related to intangible drilling costs ("IDCs"), that are expected to exceed 2014 earnings, we expect to generate significant net operating loss assets.

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Increased Drilling Activity. Our 2014 combined capital program is primarily focused on identifying and developing low-cost, high return natural gas drilling opportunities in order to grow production and cash flow. In 2014 we plan to invest a total of $540 million in our operations (including Vantage I and Vantage II). This represents a 57% increase over our aggregate $344 million 2013 capital expenditures for the two entities. We currently have two rigs operating in the Marcellus Shale and two rigs operating in the Barnett Shale, and we expect to operate approximately that same number for the remainder of 2014. This material increase in our activity levels between 2013 and 2014 could make our historical financial information even less indicative of future results. The ultimate amount of capital that we expend may fluctuate materially based on market conditions and our drilling results.

Sources of Revenues

Our revenues are derived from the sale of natural gas, oil and NGLs and gathering and compression fees collected by our gas gathering system and include the effects of derivatives. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.

To achieve more predictable cash flows and to reduce our exposure to downward price fluctuations, we use derivative instruments to hedge future sales prices on a significant portion of our natural gas, oil and NGL production. We currently use fixed price natural gas swaps in which we receive a fixed price for future production in exchange for a payment of the variable market price received at the time future production is sold. At the end of each period we estimate the fair value of these swaps and, because we have not elected hedge accounting, we recognize the changes in the fair value of unsettled commodity derivative instruments in earnings at the end of each accounting period. We expect continued volatility in the fair value of these swaps.

We normally sell a large portion of our production to a relatively small number of customers. For the year ended December 31, 2013, sales to ETC Marketing and Sequent Energy represented 32% and 22% of our total sales, respectively. For the year ended December 31, 2012, sales to ETC Marketing, Sequent Energy, Texas Energy Management and Devon Gas Services represented 31%, 16%, 14% and 14% of our total sales, respectively. Although a substantial portion of production is purchased by these major customers, we do not believe the loss of one or several of these customers would have a material adverse effect on our business, as oil and natural gas are fungible products with well-established markets and numerous purchasers.

Principal Components of our Cost Structure

•: Production and ad valorem taxes. Production taxes are paid on produced natural gas, oil and NGLs based on a percentage of revenues from production sold at fixed rates established by federal, state or local taxing authorities. In general, the production taxes we pay correlate to the changes in natural gas, oil and NGLs revenues. We are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the valuation of our natural gas and oil properties. Where available, we benefit from tax credits and exemptions in our various taxing jurisdictions.
•: Marketing and gathering. These are costs incurred to bring natural gas to the market. Such costs include fees paid to third parties who operate low- and high-pressure gathering systems that transport our natural gas.
•: Lease operating and workover expenses. These are the day to day operating costs incurred to maintain production of our natural gas and oil producing wells. Such costs include produced water disposal, maintenance and repairs. Cost levels for these expenses can vary based on supply and demand for oilfield services. The state of Pennsylvania imposes an impact fee on oil and gas

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production based on a formula applied towards individual wells. We record these impact fees in lease operating and workover expenses in the consolidated statement of operations.

•: General and administrative expense. We expect that we will incur additional general and administrative expenses as a result of being a publicly-traded company. Please see "—Factors That Significantly Affect Our Financial Condition and Results of Operations." These costs include overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production and development operations, franchise taxes, audit and other professional fees and legal compliance expenses.
•: Depreciation, depletion, amortization and accretion. Depreciation, depletion, amortization and accretion ("DD&A") includes the systematic expensing of the capitalized costs incurred to acquire, explore and develop natural gas, oil and NGLs. As a "full cost" company all costs incurred in the acquisition, exploration and development of properties (including costs of surrendered and abandoned leaseholds, delay lease rentals, dry holes and overhead related to exploration and development activities) are capitalized. Capitalized costs are depleted using the units of production method.
•: Impairment of proved oil and gas properties. Under the full cost method we are required to perform a ceiling test for each cost center. If the net book value of our oil and gas properties exceeds the ceiling, a non-cash impairment is required.
•: Interest expense. We have financed a portion of our working capital requirements and drilling activities with borrowings under our revolving credit facilities and term loan. As a result, we incur interest expense that is affected by the level of drilling, completion and acquisition activities, as well as fluctuations in interest rates and our financing decisions. We will likely continue to incur significant interest expense as we continue to grow. Additionally, we capitalized $2.8 million of interest expense for the year ended December 31, 2013.
•: Income tax expense. Vantage I, our accounting predecessor, is a limited liability company 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 the members of our predecessor. Although Vantage Energy Inc. is a corporation under the Internal Revenue Code, subject to federal income taxes at a statutory rate of 35% of pretax earnings, we do not expect to report any income tax benefit or expense until the consummation of this offering. Based on our deductions primarily related to IDCs that are expected to exceed 2014 earnings, we expect it to generate significant net operating loss assets and deferred tax assets. We may report and pay state income or franchise taxes in periods where our IDC deductions do not exceed our taxable income or where state income or franchise taxes are determined on another basis.

Corporate Reorganization

The limited liability company agreements of Vantage Investment I and Vantage Investment II to be adopted in connection with the closing of this offering provide a mechanism by which the shares of our common stock to be allocated amongst the members of Vantage Investment I and Vantage Investment II will be determined. As a result, the satisfaction of all performance, market, and service conditions relative to the membership interests awards held by certain Management Members will be probable. Accordingly, we will recognize approximately $ in a non-cash charge for stock compensation expense for the estimated fair value of the prospective distributions in respect of those awards at the closing of this offering and approximately an additional $ over the remaining service period. The charge will not have a dilutive effect on the pro forma net tangible book value per share to new investors in this offering.

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Because consideration for the membership interests awards will be deemed given by Vantage Investment I and Vantage Investment II, the charge to expense will be accounted for as capital contributions by Vantage Investment I and Vantage Investment II to us and credited to additional paid-in capital.

Vantage I (Predecessor) Results of Operations

Three Months Ended March 31, 2014 Compared to Three Months Ended March 31, 2013

Below are some highlights of our financial and operating results for the three months ended March 31, 2014:

•: Our production volumes increased 10.9% to 4,022 MMcfe for the three months ended March 31, 2014 compared to 3,627 MMcfe for the three months ended March 31, 2013.
•: Natural gas, oil and NGL sales revenues increased 78.5% to $21.0 million for the three months ended March 31, 2014 compared to $11.8 million for the three months ended March 31, 2013.

The following table sets forth selected operating data for the three months ended March 31, 2014 compared to the three months ended March 31, 2013:

	Vantage I (Predecessor)

	For the Three Months Ended March 31,
	For the Three Months Ended March 31,						Amount of Change
(in thousands)	2014			2013			Amount of Change
Revenues:
Natural gas, oil and NGL sales	$	20,992		$	11,760		$	9,232
Loss on commodity derivatives		(14,577	)		(11,167	)		(3,410	)


Total revenues		6,415			593			5,822
Operating expenses:
Production and ad valorem		955			1,657			(702	)
Marketing and gathering		713			469			244
Gas gathering operating expense		244			73			171
Lease operating and workover		3,670			2,911			759
General and administrative		1,216			555			661
Depreciation, depletion, amortization and accretion		5,707			2,705			3,002


Total operating expenses		12,505			8,370			4,135


Operating loss		(6,090	)		(7,777	)		1,687


Other (expense) income:
Other expense (income)		9			(36	)		45
Interest income, net		—			3			3
Interest expense, net of capitalized interest		4,159			—			4,159


Total other income (expense)		4,168			(39	)		4,207


Net loss		(10,258	)		(7,738	)		(2,520	)

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	Vantage I (Predecessor)

	For the Three Months Ended March 31,
	For the Three Months Ended March 31,				Amount of Change
(in thousands)	2014		2013		Amount of Change
Revenues (in thousands):
Natural gas	$	16,775	$	9,819	$	6,956
Oil		1,605		692		913
NGLs		2,612		1,249		1,363


Total sales	$	20,992	$	11,760	$	9,232
Production data:
Natural gas(MMcf)		3,422		3,286		136
Oil (MBbls)		17		8		9
NGLs (MBbls)		83		49		34


Total (MMcfe)		4,022		3,628		394
Average prices before effects of hedges per Mcfe:
Natural gas	$	4.17	$	2.71	$	1.46
Oil		0.40		0.19		0.21
NGLs		0.65		0.34		0.31


Total	$	5.22	$	3.24	$	1.98
Average realized prices after effects of hedges per Mcfe⁽¹⁾:
Natural gas	$	3.50	$	2.69	$	0.81
Oil		0.37		0.20		0.17
NGLs		0.52		0.42		0.10


Total	$	4.39	$	3.31	$	1.08
Average costs per Mcfe:
Production and ad valorem taxes	$	0.24	$	0.46	$	(0.22	)
Marketing and gathering		0.18		0.13		0.05
Lease operating and workover		0.91		0.80		0.11
General and administrative		0.30		0.15		0.15
Depletion, depreciation and amortization		1.42		0.75		0.67

(1): The effect of hedges includes realized gains and losses on commodity derivative transactions.

Natural gas, oil and NGL sales revenues. Sales revenues increased from $11.8 million for the three months ended March 31, 2013 to $21.0 million for the three months ended March 31, 2014, an increase of $9.2 million. The increase was primarily due to an increase in production of 394 MMcfe and a 61.1% increase in average prices before the effect of hedges. Natural gas revenues increased $7.0 million over the three months ended March 31, 2013. Of the increase, $6.6 million was due to an increase in average prices before the effect of hedges and $0.4 million was due to increased production from our Marcellus Shale assets. Oil and NGL revenues increased $2.2 million due to increased oil and NGL production and higher oil and NGL prices. Of the increase, $0.9 million and $0.7 million was due to increased Barnett Shale NGL and oil production, respectively.

Loss on commodity derivatives. The $11.2 million loss on derivative contracts for the three months ended March 31, 2013 was comprised of $11.4 million in unrealized losses, offset by $0.2 million of settlements received on contracts. For the three months ended March 31, 2014, the $14.6 million loss was comprised of $11.3 million in unrealized losses and $3.3 million of settlements paid on contracts. Commodity derivative fair value gains or losses will vary based on future commodity prices and have no

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cash flow impact until the derivative contracts are settled. We expect continued volatility in the fair value of our derivative instruments.

Production and ad valorem taxes. Production and ad valorem taxes decreased $0.7 million from $1.7 million for the three months ended March 31, 2013 to $1.0 million for the three months ended March 31, 2014. The decrease was due to lower ad valorem expenses during the three months ended March 31, 2014, offset by increased production taxes resulting from our expanded drilling program and increased production.

Marketing and gathering. Marketing and gathering expenses increased $0.2 million from $0.5 million for the three months ended March 31, 2013 to $0.7 million for the three months ended March 31, 2014. The increase is primarily due to increased gathering, compression, and transportation associated with the increased production of natural gas.

Lease operating and workover expenses. Lease operating and workover expenses increased $0.8 million from $2.9 million for the three months ended March 31, 2013 to $3.7 million for the three months ended March 31, 2014. The increase is primarily due to increases in well counts and production, including water disposal and compression charges and workover cost incurred.

General and administrative expense. General and administrative expenses increased $0.6 million from $0.6 million for the three months ended March 31, 2013 to $1.2 million for the three months ended March 31, 2014. The increase in G&A expenses is a result of additional personnel and legal and accounting services to support our growth activities.

Depreciation, depletion, and amortization. The increase of $3.0 million was a result of higher average capitalized costs of $182.9 million during the three months ended March 31, 2014 compared to the three months ended March 31, 2013. Depreciation on our gathering system increased $0.2 million due to increased capitalized costs to support our operations.

Interest expense. The increase of $4.2 million was attributable to higher levels of borrowings, primarily related to the Vantage I second lien term loan, in order to fund our drilling programs.

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

Below are some highlights of our financial and operating results for the year ended December 31, 2013:

•: Our production volumes increased 28.3% to 16,010 MMcfe in the year ended December 31, 2013 compared to 12,482 MMcfe in the year ended December 31, 2012.
•: Our natural gas, oil and NGLs sales increased 71.1% to $58.0 million in the year ended December 31, 2013 compared to $33.9 million in the year ended December 31, 2012.
•: Our per unit lease operating and workover expenses decreased 10.5% to $0.68 per Mcfe in the year ended December 31, 2013 compared to $0.76 per Mcfe in the year ended December 31, 2012.

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The following table sets forth selected operating data for the year ended December 31, 2013 compared to the year ended December 31, 2012:

	Vantage I (Predecessor)

	For the Year Ended December 31,
	For the Year Ended December 31,						Amount of Change
(in thousands)	2013			2012			Amount of Change
Revenues:
Natural gas, oil and NGL sales	$	58,017		$	33,911		$	24,106
Gathering revenues		99			(2	)		101
Gain on commodity derivatives		8,074			3,495			4,579


Total revenues		66,190			37,404			28,786
Operating expenses:
Production and ad valorem		3,225			1,858			1,367
Marketing and gathering		2,640			1,389			1,251
Gathering system		325			—			325
Lease operating and workover		10,946			9,503			1,443
General and administrative		3,698			4,524			(826	)
Depreciation, depletion, amortization and accretion		22,283			16,604			5,679
Impairment of proved oil and gas properties		—			8,043			(8,043	)


Total operating expenses		43,117			41,921			1,196


Operating income (loss)		23,073			(4,517	)		27,590


Interest (expense) income:
Interest income, net		—			9			(9	)
Interest expense, net of capitalized interest		(417	)		—			(417	)


Total interest (expense) income		(417	)		9			(426	)


Net income (loss)	$	22,656		$	(4,508	)	$	27,164

	Vantage I (Predecessor) For the Year Ended December 31,

	Vantage I (Predecessor) For the Year Ended December 31,				Amount of Change
	2013		2012		Amount of Change
Revenues (in thousands):
Natural gas	$	46,266	$	23,068	$	23,198
Oil		5,152		2,473		2,679
NGLs		6,599		8,370		(1,771	)


Total sales	$	58,017	$	33,911	$	24,106
Production data:
Natural gas (MMcf)		14,246		10,694		3,552
Oil (MBbls)		54		27		27
NGLs (MBbls)		240		271		(31	)
Total (MMcfe)		16,010		12,482		3,528

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	Vantage I (Predecessor) For the Year Ended December 31,

	Vantage I (Predecessor) For the Year Ended December 31,				Amount of Change
	2013		2012		Amount of Change
Average prices before effects of hedges per Mcfe:
Natural gas	$	2.89	$	1.85	$	1.04
Oil		0.32		0.20		0.12
NGLs		0.41		0.67		(0.26	)
Total	$	3.62	$	2.72	$	0.90
Average realized prices after effects of hedges per Mcfe⁽¹⁾:
Natural gas	$	3.09	$	2.37	$	0.72
Oil		0.32		0.25		0.07
NGLs		0.49		0.75		(0.26	)
Total	$	3.90	$	3.37	$	0.53
Average costs per Mcfe:
Production and ad valorem taxes	$	0.20	$	0.15	$	0.05
Marketing and gathering		0.16		0.11		0.05
Lease operating and workover		0.68		0.76		(0.08	)
General and administrative		0.23		0.36		(0.13	)
Depreciation, depletion, amortization and accretion		1.39		1.33		0.06

(1): The effect of hedges includes realized gains and losses on commodity derivative transactions.

Natural gas, oil and NGL sales revenues. Sales revenues increased $24.1 million over the prior year primarily due to an increase in production of 3,528 MMcfe and a 33.1% increase in average prices before the effect of hedges. Natural gas revenues increased $23.2 million over the prior year. Of the increase, $7.7 million was due to increased production resulting from a significant acceleration of our drilling and completion program in the Marcellus and Barnett Shale's and $15.5 million was due to an increase in average prices before the effect of hedges. Oil and NGL revenues increased $0.9 million due to increased oil production, partially offset by lower NGL production and lower oil and NGL prices. Of the increase, $1.5 million was due primarily to increased oil production in the Barnett Shale offset by $(0.6) million primarily due to lower NGL prices.

Gathering system revenue and expenses. Revenues and expenses associated with our gathering operations increased over the prior year primarily due to our expansion of the gathering system to support our operations.

Gain on derivative instruments. The $8.1 million gain on derivative contracts in 2013 was comprised of $3.6 million in unrealized gains and $4.5 million of settlements received on contracts. In 2012, the $3.5 million gain was comprised of $4.7 million in unrealized losses offset by $8.2 million of settlements received on contracts. Commodity derivative fair value gains or losses will vary based on future commodity prices and have no cash flow impact until the derivative contracts are settled. We expect continued volatility in the fair value of our derivative instruments.

Production and ad valorem taxes. Production and ad valorem taxes increased $1.4 million over the prior year primarily due to our expanded drilling program and increased production of 3,528 MMcfe during the period.

Marketing and gathering. Marketing and gathering expenses increased $1.3 million over the prior year primarily due to increased gathering, compression and transportation associated with the increased production in natural gas.

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Lease operating and workover expenses. Lease operating and workover expenses increased $1.4 million over the prior year primarily due to the increased well count and production. On a per unit basis, our costs have decreased from $0.76 per Mcfe in 2012 to $0.68 per Mcfe in 2013. The decreased cost per unit is a result of new lower-cost wells coming on line in 2013 and as a direct result of our efforts to reduce costs such as entering into master service agreements and other long-term contracts with our critical vendors.

General and administrative expense. General and administrative expenses decreased $0.8 million from $4.5 million in 2012 to $3.7 million in 2013. While we experienced additional personnel to support our growth activities we were able to reduce overall G&A expenses through reduction of consultants and corporate office expense and through the sharing of costs with Vantage II per a management services agreement.

Depreciation, depletion and amortization. The increase of $5.7 million was a result of higher average capitalized costs of $101.4 million in 2013 compared to 2012. The increase in capitalized costs is consistent with our expanded drilling program and increased production of 3,528 MMcfe during the period. Depreciation on our gathering system increased $0.7 million primarily due to our acquisition of the gathering system in late 2012 and due to an $8.9 million increase in capitalized costs in 2013 compared to 2012.

Impairment of proved oil and gas properties. The decrease of $8.0 million was a result of a required ceiling test write-down in 2012 due to capitalized costs being higher than the ceiling threshold. We did not have an impairment of proved oil and gas properties in 2013, as capitalized costs were below the ceiling threshold.

Interest expense. The increase of $0.4 million was primarily attributable to higher levels of average borrowings outstanding during the 2013 period in order to fund our drilling programs and certain interest costs being expensed as opposed to capitalized, in accordance with GAAP.

Pro Forma Capital Resources and Liquidity

Our primary sources of liquidity have been equity contributions from our Existing Owners, cash generated by our operations, borrowings under our revolving credit facilities and proceeds from the Vantage I second lien term loan and the Vantage II second lien term loan. Our primary use of capital has been the acquisition and development of natural gas, oil and NGLs properties. As we pursue reserve and production growth, we monitor which capital resources, including equity and debt financings, are available to us to meet our future financial obligations, planned capital expenditure activities and liquidity requirements. We also expect to fund a portion of these requirements with cash flow from operations as we continue to bring additional production online.

Our future success in growing proved reserves and production will be highly dependent on the capital resources available to us. In 2014, we plan to invest $540 million in our operations (including Vantage I and Vantage II), including $441 million for drilling and completion, $40 million for leasehold acquisitions, $5 million for seismic and other activities and $54 million related to our gathering, compression and other midstream operations. This represents a 57% increase over our $344 million 2013 combined capital expenditures. We have not allocated any capital spending to properties other than our primary Marcellus and Barnett Shale operations. After giving effect to this offering, we expect to fund our 2014 capital expenditures with cash generated by operations, available capacity under our combined revolving credit facility and a portion of the net proceeds of this offering. Our cash flow from operations has historically contributed little to funding our capital requirements, specifically with respect to our capital expenditure budget. We believe that the lag time between initial investment and cash flow from such investment is typical of the oil and gas industry. We expect that our drilling program will result in meaningful increases in our production and associated cash flows. We expect to use this, in part, to fund a portion of our 2014 capital expenditures.

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Following the completion of this offering, we expect that our overall borrowing costs will be lower, with the retirement of the Vantage I second lien term loan and the Vantage II second lien term loan, which bear interest at rates greater than what we expect to pay under our new combined revolving credit facility. Specifically, each of the Vantage I and Vantage II second lien term loans bear interest at a rate of LIBOR plus 7.5%, while our new combined revolving credit facility is expected to bear interest at a rate of LIBOR plus 1.5% to 2.5%, depending on borrowing base utilization. To the extent we are required to rely on borrowings under our combined revolving credit facility to a greater degree to fund our capital expenditures, we may have less availability and flexibility to provide for working capital and other operational expenses. However, even though we believe lower borrowing costs will give us greater flexibility in funding our capital expenditures 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.

Our 2014 capital budget may be further adjusted as business conditions warrant. The amount, timing and allocation of capital expenditures is largely discretionary and within our control. If natural gas, oil and NGLs prices decline to levels below our acceptable levels, or costs increase to levels above our acceptable levels, we could choose to defer a significant portion of our budgeted capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity and prioritize capital projects that we believe will have the highest expected rates of return and potential to generate near-term cash flow. We routinely monitor and adjust our capital expenditures in response to changes in commodity prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in drilling activities, contractual obligations including drilling commitments, internally generated cash flow and other factors both within and outside our control. Any reduction in our capital expenditure budget could have the effect of delaying or limiting our development program, which would negatively impact our ability to grow production and could materially and adversely affect our future business, financial condition, results of operations or liquidity.

After giving effect to this offering, we believe that operating cash flows, available capacity under our combined revolving credit facility and cash on hand should be sufficient to fully fund our capital expenditure budgets for 2014 and 2015 and meet our cash requirements, including normal operating needs, debt service obligations and commitments and contingencies. However, to the extent that we consider market conditions favorable, we may access the capital markets to raise capital from time to time to fund acquisitions, pay down our combined revolving credit facility and for general working capital purposes.

Please see "—Debt Agreements" for additional details on our outstanding borrowings and available liquidity under our various financing arrangements.

Predecessor Cash Flow Provided by Operating Activities

Net cash provided by operating activities was $44.0 million for the year ended December 31, 2013, compared to $28.3 million of net cash provided by operating activities for the year ended December 31, 2012. The change in operating cash flow was primarily the result of a $27.2 million increase in net income (loss) for the year ended December 31, 2013 compared to December 31, 2012.

Net cash provided by operating activities was $1.8 million for the three months ended March 31, 2014, compared to $3.5 million of net cash used in operating activities for the three months ended March 31, 2013. The change in operating cash flow was primarily the result of changes in operating assets and liabilities, primarily accrued liabilities related to drilling advances from other working interest owners, from March 31, 2013 to March 31, 2014.

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Predecessor Cash Flow Used In Investing Activities

During the years ended December 31, 2013 and 2012, cash flows used in investing activities were $111.1 million and $116.4 million, respectively. The decrease is primarily related to our capital expenditures for drilling, development and acquisition costs of oil and gas properties and our gas gathering system.

During the three months ended March 31, 2014 and 2013, cash flows used in investing activities were $50.0 million and $36.6 million, respectively. The increase is primarily related to our expenditures for drilling, development, and acquisition costs of oil and gas properties and the gas gathering system.

Predecessor Cash Flow Provided By Financing Activities

Net cash provided by financing activities of $144.4 million during the year ended December 31, 2013 was primarily attributable to net borrowings under debt agreements as further described in "—Debt Agreements" below. Net cash provided by financing activities of $87.8 million during the year ended December 31, 2012 was primarily the result of additional member equity contributions.

Net cash used in financing activities of $0.8 million during the three months ended March 31, 2014 was primarily attributable to principal payments on the Vantage I second lien term loan. Net cash provided by financing activities of $46.0 million during the three months ended March 31, 2013 was primarily the result of borrowings under the Vantage I revolving credit facility.

Debt Agreements

Vantage I Revolving Credit Facility

On December 20, 2013, Vantage I entered into a second amended and restated revolving credit facility with Wells Fargo Bank, N.A., as administrative agent, and a syndicate of lenders with a maximum credit amount of $750 million and a sublimit for letters of credit of the lesser of $50 million or the borrowing base. As of December 31, 2013, the sublimit for the letters of credit was $50 million. The amount available to be borrowed under the revolving credit facility is subject to a borrowing base that is redetermined semiannually each May and November and depends on the volumes of Vantage I's proved oil and gas reserves and estimated cash flows from these reserves and commodity derivative positions. The next redetermination is scheduled to occur in November 2014. As of March 31, 2014, the borrowing base was $140 million. As of March 31, 2014, Vantage I had letters of credit of $0.1 million outstanding under its revolving credit facility. The revolving credit facility matures July 19, 2015.

Principal amounts borrowed are payable on the maturity date, and interest is payable quarterly for base rate loans and at the end of the applicable interest period for Eurodollar loans. Vantage I has a choice of borrowing in Eurodollars or at the base rate. Eurodollar loans bear interest at a rate per annum equal to LIBOR plus an applicable margin ranging from 175 to 275 basis points, depending on the percentage of the borrowing base utilized. Base rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank's reference rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the rate for one month Eurodollar loans plus 100 basis points, plus an applicable margin ranging from 75 to 175 basis points, depending on the percentage of the borrowing base utilized. Vantage I may repay any amounts borrowed prior to the maturity date without any premium or penalty other than customary LIBOR breakage costs.

The credit facility is secured by liens on substantially all of Vantage I's properties and guarantees from its subsidiaries other than any subsidiary that it has designated as an unrestricted subsidiary. The credit facility contains restrictive covenants that may limit Vantage I's ability to, among other things:

•: incur additional indebtedness;
•: sell assets;

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•: make loans to others;
•: make investments;
•: enter into mergers;
•: make or declare dividends;
•: hedge future production or interest rates;
•: incur liens; and
•: engage in certain other transactions without the prior consent of the lenders.

The credit facility also requires Vantage I to maintain the following four financial ratios, which are measured at the end of each calendar quarter:

•: a current ratio, which is the ratio of its consolidated current assets (includes unused commitment under the credit facility and excludes derivative assets) to its consolidated current liabilities, of not less than 1.0 to 1.0 at the end of each fiscal quarter;
•: a leverage ratio, which is the ratio of its Consolidated Debt (as defined in our amended revolving credit facility) to Adjusted Consolidated EBITDA for such quarter multiplied by four minus certain non-recurring extraordinary charges, of not greater than 4.0 to 1.0;
•: a minimum interest coverage ratio, which is the ratio of Adjusted Consolidated EBITDA for such quarter multiplied by four minus certain non-recurring extraordinary charges to consolidated interest charges multiplied by four, of not less than 2.5 to 1.0; and
•: a minimum asset coverage ratio, which is the ratio of the present value of Vantage I's oil and gas reserves (discounted at 10% per annum) to Consolidated Debt (excluding cash and cash equivalents) of not less than 1.5 to 1.0, and the present value of its oil and gas reserves (discounted at 10% per annum), but excluding its proved undeveloped reserves, of not less than $140 million.

Vantage I was in compliance with such covenants and ratios as of December 31, 2013. As of March 31, 2014, Vantage I was out of compliance with a hedging covenant restricting the percentage of future production that can be hedged. Vantage I obtained a waiver of this covenant which limits Vantage I's ability to enter into additional hedging contracts and stays in place until Vantage I's future production hedged as a percentage of anticipated production is reduced to the agreed upon levels. We expect that Vantage I will be in compliance in future periods and intend to monitor our hedging and production levels to achieve that compliance and avoid the need for future waivers. However, to the extent we are required to seek additional waivers of a covenant breach in the future and are unable to do so, it could result in the acceleration of some or all of our outstanding indebtedness, which would have a material adverse effect on us. In addition, even if we were able to obtain a waiver, it may limit our flexibility or contain meaningful restrictions on our ability to incur indebtedness or enter into additional derivative contracts. Please see "Risk Factors—Risks Related to Our Business—Restrictions in our existing and future debt agreements could limit our growth and our ability to engage in certain activities."

In connection with the completion of this offering, we expect to enter into an amended and restated credit agreement that will combine the Vantage II revolving credit facility with the Vantage I revolving credit facility. We intend to use a portion of the proceeds of this offering to repay borrowings outstanding under that combined revolving credit facility.

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Vantage II Revolving Credit Facility

On November 29, 2012, Vantage II entered into a revolving credit facility with Wells Fargo Bank, N.A., as administrative agent and lender, with a maximum credit amount of $500 million and a sublimit for letters of credit of the lesser of $50 million or the borrowing base. As of December 31, 2013, the sublimit for the letters of credit was $27 million. As of December 31, 2013, Vantage II had no borrowings or letters of credit outstanding under its revolving credit facility. The revolving credit facility matures November 8, 2016.

Eurodollar loans bear interest at a rate per annum equal to LIBOR plus an applicable margin ranging from 175 to 275 basis points, depending on the percentage of the borrowing base utilized. Base rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank's reference rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the rate for one month Eurodollar loans plus 100 basis points, plus an applicable margin ranging from 75 to 175 basis points, depending on the percentage of the borrowing base utilized. Vantage II may repay any amounts borrowed prior to the maturity date without any premium or penalty other than customary LIBOR breakage costs.

As of March 31, 2014, Vantage II was not in compliance with the minimum current ratio covenant. Vantage II obtained a waiver and we expect that Vantage II will be in compliance in future periods.

As of March 31, 2014, Vantage II was out of compliance with a hedging covenant restricting the percentage of future production that can be hedged. Vantage II obtained a waiver of this covenant which limits Vantage II's ability to enter into additional hedging contracts and stays in place until Vantage II's future production hedged as a percentage of anticipated production is reduced to the agreed upon levels. We expect that Vantage II will be in compliance in future periods and intend to monitor our hedging and production levels to achieve that compliance and avoid the need for future waivers. However, to the extent we are required to seek additional waivers of a covenant breach in the future and are unable to do so, it could result in the acceleration of some or all of our outstanding indebtedness, which would have a material adverse effect on us. In addition, even if we were able to obtain a waiver, it may limit our flexibility or contain meaningful restrictions on our ability to incur indebtedness or enter into additional derivative contracts. Please see "Risk Factors—Risks Related to Our Business—Restrictions in our existing and future debt agreements could limit our growth and our ability to engage in certain activities."

In connection with the completion of this offering, we expect to enter into an amendment that will combine the Vantage II revolving credit facility with the Vantage I revolving credit facility. We intend to use a portion of the proceeds of this offering to repay borrowings outstanding under that combined revolving credit facility.

Vantage I Second Lien Term Loan

On December 20, 2013, Vantage I entered into a second lien term loan credit facility with Credit Suisse AG, Cayman Islands Branch, as administrative agent, and a syndicate of lenders in an aggregate principal amount of $200 million. As of December 31, 2013, the effective interest rate was 8.5% and $200 million remained outstanding under the term loan facility. The term loan facility matures on December 20, 2018.

We intend to use a portion of the proceeds of this offering to repay and retire the Vantage I second lien term loan facility.

Vantage II Second Lien Term Loan

On May 8, 2014, Vantage II entered into a second lien term loan credit facility with affiliates of GSO Capital Partners LP in an aggregate principal amount of $100 million. The term loan facility

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bears interest at a rate of LIBOR plus 7.5% (subject to a minimum LIBOR rate of 1.0%) and matures on May 8, 2017.

We intend to use a portion of the proceeds of this offering to repay and retire the Vantage II second lien term loan facility.

Commodity Derivative Activities

Our primary market risk exposure is in the prices we receive for our natural gas, oil and NGL production. Realized pricing is primarily driven by the spot regional market prices applicable to our U.S. natural gas, oil and NGL production. Pricing for natural gas and oil production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control, including volatility in the differences between product prices at sales points and the applicable index price.

To mitigate the potential negative impact on our cash flow caused by changes in natural gas, oil and NGL prices, we have entered into financial commodity derivative contracts in the form of swaps basis swaps to ensure that we receive minimum prices for a portion of our future natural gas, oil and NGL production when management believes that favorable future prices can be secured. We typically hedge the NYMEX Henry Hub, Inside FERC Dominion or Inside FERC WAHA price for natural gas, NYMEX WTI price for oil and NYMEX OPIS price for NGLs.

Our hedging activities are intended to support natural gas, oil and NGL prices at targeted levels and to manage our exposure to natural gas, oil and NGL price fluctuations. Under swap contracts, the counterparty is required to make a payment to us for the difference between the swap price specified in the contract and the settlement price, which is based on market prices on the settlement date, if the settlement price is below the swap price. We are required to make a payment to the counterparty for the difference between the swap price and the settlement price if the swap price is below the settlement price. For a description of our commodity derivative contracts, please see Note 6 to the audited consolidated financial statements of our predecessor as of and for the year ended December 31, 2013 and Note 4 to the unaudited consolidated financial statements of our predecessor as of and for the three months ended March 31, 2014 included elsewhere in this prospectus.

By using derivative instruments to hedge exposures to changes in commodity prices, we expose ourselves to the credit risk of our counterparties. Credit risk is the potential failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty is expected to owe us, which creates credit risk. To minimize the credit risk in derivative instruments, it is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. The creditworthiness of our counterparties is subject to periodic review. We have derivative instruments in place with two different counterparties. As of December 31, 2013 and March 31, 2014, for Vantage I and Vantage II, our contracts with Wells Fargo accounted for 73% and 65%, respectively, of the net fair market value of our derivative assets. We believe Wells Fargo currently is an acceptable credit risk. We are not required to provide credit support or collateral to Wells Fargo under current contracts, nor are they required to provide credit support or collateral to us. As of March 31, 2014 and December 31, 2013 and 2012, we did not have any past due receivables from counterparties.

Contractual Obligations

A summary of contractual obligations as of December 31, 2013 for Vantage I, Vantage II and on a combined basis is provided in the following table. As of March 31, 2014, the only material change was $25 million of outstanding borrowings under the Vantage II revolving credit facility. The table does not

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reflect the Vantage II second lien term loan (which was entered into in May 2014) or this offering or the use of proceeds therefrom.

	Payments due by period For the Year Ended December 31,

	2014		2015		2016		2017		2018		Thereafter		Total
	(in thousands)
Vantage I:
Vantage I revolving credit facility⁽¹⁾	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Vantage I second lien term loan facility⁽¹⁾		2,000		2,000		2,000		2,000		192,000		—		200,000
Drilling rig commitments⁽²⁾		—		—		—		—		—		—		—
Gathering and firm transportation		9,882		8,763		7,297		4,361		829		—		31,132
Asset retirement obligations⁽³⁾		1,004		—		—		—		—		12,949		13,953
Other⁽⁴⁾		198		—		—		—		—		—		198


Total	$	13,084	$	10,763	$	9,297	$	6,361	$	192,829	$	12,949	$	245,283




Vantage II:
Vantage II revolving credit facility⁽¹⁾	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Drilling rig commitments⁽²⁾		9,061		8,970		—		—		—		—		18,031
Asset retirement obligations⁽³⁾		—		—		—		—		—		1,201		1,201
Other⁽⁴⁾		—		—		—		—		—		—		—


Total	$	9,061	$	8,970	$	—	$	—	$	—	$	1,201	$	19,232




Combined:
Revolving credit facilities⁽¹⁾	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Vantage I second lien term loan facility⁽¹⁾		2,000		2,000		2,000		2,000		192,000		—		200,000
Drilling rig commitments⁽²⁾		9,061		8,970		—		—		—		—		18,031
Gathering and firm transportation		9,882		8,763		7,297		4,361		829		—		31,132
Asset retirement obligations⁽³⁾		1,004		—		—		—		—		14,150		15,154
Other⁽⁴⁾		198		—		—		—		—		—		198


Total	$	22,145	$	19,733	$	9,297	$	6,361	$	192,829	$	14,150	$	264,515

(1): Includes outstanding principal amounts on December 31, 2013. This table does not include future commitment fees, amortization of deferred financing costs, interest expense or other fees on these facilities because they are floating rate instruments and we cannot determine with accuracy the timing of future loan advances, repayments or future interest rates to be charged.
(2): As of December 31, 2013, we had contracts for rig services which expire at various dates from 2014 through 2015. The values in the table represent the gross amounts that we are committed to pay; however, we will record in our financial statements our proportionate share of costs based on our working interest.
(3): Represents gross retirement costs with no discounting impact. We have not included the long-term asset retirement obligations because we are not able to precisely predict the timing of these amounts.
(4): Represents operating leases associated with field compression.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon the consolidated financial statements of our predecessor, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable

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likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our consolidated financial statements. See Note 1 of the notes to the audited consolidated financial statements of Vantage I for an expanded discussion of our significant accounting policies and estimates made by management.

Revenue Recognition

Crude oil, natural gas and NGL revenues are recognized when delivery has occurred, title has transferred and collection is probable. We account for crude oil, natural gas and NGL sales using the "entitlements method." Under the entitlements method, revenue is recorded based upon our ownership share of volumes sold, regardless of whether it has taken its ownership share of such volumes. We record a receivable or a liability to the extent it receives less or more than its share of the volumes and related revenue. Any amount received in excess of our share is treated as a liability. If we receive less than its entitled share, the underproduction is recorded as a receivable. We sell the majority of our products soon after production at various locations, including the wellhead, at which time title and risk of loss pass to the buyer.

Our gathering revenues are generated from gathering and compressing natural gas. We provide gathering services and compression services under fee-based arrangements.

Oil and Gas Properties

We follow the full-cost method of accounting for natural gas and crude oil properties.

All costs associated with property acquisition, exploration, and development activities are capitalized. Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development activities, and other costs incurred for the purpose of finding oil and gas reserves. Salaries and benefits paid to employees directly involved in the exploration and development of properties, as well as other internal costs that can be directly identified with acquisition, exploration, and development activities, are also capitalized. We capitalized certain internal costs of approximately $1.9 million and $1.8 million, respectively, during the years ended December 31, 2013 and 2012.

Costs of acquiring unproved oil and gas properties are initially excluded from the depletable base and are assessed at each reporting period to ascertain whether impairment has occurred. When proved reserves are assigned to the property or the property is considered to be impaired, the costs of the property or the amount of impairment is added to the depletable base.

Capitalized costs, as adjusted for estimated future development costs and estimated asset retirement costs, less estimated salvage values, are depreciated, depleted, and amortized using the units-of-production method based on estimated proved reserves as determined by petroleum engineers. The costs of wells-in-progress and unevaluated properties, including any related capitalized interest and internal costs, are not amortized. For the purposes of this calculation, crude oil and natural gas liquid reserves and production are converted to equivalent volumes of natural gas based on the relative energy content of one barrel to six thousand cubic feet of gas. Proceeds from the disposal of properties are normally deducted from the full-cost pool without recognition of gains or losses, except under circumstances where the deduction would significantly alter the relationship between capitalized costs and proved reserves of the cost center, in which case a gain or loss is recorded.

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Full cost accounting rules require us to perform a "ceiling test" calculation to test its oil and gas properties for possible impairment. The primary components impacting the calculation are commodity prices, reserve quantities added and produced, overall exploration and development costs and depletion expense. If the net capitalized cost of our oil and gas properties subject to amortization (the "carrying value") exceeds the ceiling limitation, the excess would be charged to expense. The ceiling limitation is equal to the sum of the present value discounted at 10% of estimated future net cash flows from proved reserves, the cost of properties not being amortized, the lower of cost or estimated fair value of unproven properties included in the costs being amortized, and all related income tax effects. The present value of estimated future net revenues is computed by applying the average first-day-of-the-month oil and gas price during the 12-month period ended December 31, 2013 to estimated future production of proved oil and gas reserves as of period-end, less estimated future expenditures to be incurred in developing and producing the proved reserves, assuming the continuation of existing economic conditions. As of December 31, 2013, the full-cost pool did not exceed the ceiling limitation. As of December 31, 2012, the full-cost pool exceeded the ceiling limitation by $8.0 million and was recorded as an impairment of proved oil and gas properties in the accompanying consolidated statements of operations.

Natural Gas, NGL and Oil Reserve Quantities and Standardized Measure of Future Cash Flows

Our independent reserve engineers and internal technical staff prepare the estimates of natural gas, NGL, and oil reserves and associated future net cash flows. Current accounting guidance allows only proved natural gas, NGL, and oil reserves to be included in our financial statement disclosures. The SEC has defined proved reserves as the estimated quantities of natural gas, NGL, and oil which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Our independent reserve engineers and internal technical staff must make a number of subjective assumptions based on their professional judgment in developing reserve estimates. Reserve estimates are updated annually and consider recent production levels and other technical information about each field. Natural gas, NGL, and oil reserve engineering is a subjective process of estimating underground accumulations of natural gas, NGL, and oil that cannot be precisely measured. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Periodic revisions to the estimated reserves and future cash flows may be necessary as a result of a number of factors, including reservoir performance, new drilling, natural gas, NGL, and oil prices, cost changes, technological advances, new geological or geophysical data, or other economic factors. Accordingly, reserve estimates are generally different from the quantities of natural gas, NGL, and oil that are ultimately recovered. We cannot predict the amounts or timing of future reserve revisions. If such revisions are significant, they could significantly affect future amortization of capitalized costs and result in impairment of assets that may be material.

Asset Retirement Obligations

Asset retirement obligations relate to future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage and returning such land to its original condition. The fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred and the cost of such liability is recorded as an increase in the carrying amount of the related long-lived asset by the same amount. The liability is accreted each period and the capitalized cost is depleted as part of the full cost pool. Revisions to estimated asset retirement obligations result in adjustments to the related capitalized asset and corresponding liability.

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Equity Incentives

Certain of the Management Members hold incentive membership interests in Vantage I and Vantage II that currently have rights to participate in certain distribution events of Vantage I and Vantage II if sufficient valuation thresholds are met. Historically, we have accounted for these incentive membership interests as a profits interests plan and did not record stock compensation expense because the satisfaction of all performance, market and service conditions, which would only occur upon a liquidating event, was not probable.

In connection with the completion of this offering, it is possible that all performance, market and service conditions relative to the incentive membership interests held by certain of the Management Members in Vantage Investment I and Vantage Investment II would be probable. If that happens, we will recognize a non-cash charge for stock compensation expense.

Income Taxes

Vantage I, our accounting predecessor, is a multi-member limited liability company 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 the members of Vantage I. Although Vantage Energy Inc. is a corporation under the Internal Revenue Code, subject to federal income taxes at a statutory rate of 35% of pretax earnings, we do not expect to report any income tax benefit or expense until the consummation of this offering. Based on our deductions primarily related to IDCs that are expected to exceed 2014 earnings, we expect to generate significant net operating loss assets and deferred tax liabilities.

We account for uncertainty in income taxes in accordance with generally accepted accounting principles, which prescribes a comprehensive model for recognizing, measuring, presenting, and disclosing in the consolidated financial statements tax positions taken or expected to be taken on a tax return, including a decision on whether or not to file in a particular jurisdiction. Only tax positions that meet a more-likely-than-not recognition threshold at the effective date may be recognized or continue to be recognized.

Interest and penalties associated with tax positions are recorded in the period assessed as general and administrative expenses. No interest or penalties have been assessed as of December 31, 2013. Vantage I's information returns for tax years subject to examination by tax authorities include 2009 and 2010 through the current year for state and federal tax reporting purposes, respectively.

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Jumpstart Our Business Startups Act of 2012

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. However, we have irrevocably opted out of the extended transition period.

Internal Controls and Procedures

We are not currently required to comply with the SEC's rules implementing Section 404 of the Sarbanes Oxley Act of 2002, 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 the Sarbanes-Oxley Act of 2002, which will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. We will not be required to make our 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" within the meaning of Section 2(a)(19) of the Securities Act.

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 oil and 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

The following tables detail the financial derivative contracts that Vantage I had in place as of March 31, 2014:

	Quantity

	Quantity					Contract Period		Estimated Fair Value
Commodity	Remaining		Units	Prices	Price Index	Contract Period		Estimated Fair Value
Crude oil swaps		165,072	Bbl	$83.50-$90.80	NYMEX WTI		4/14-12/15	$	(481	)


Natural gas swaps
Dominion		8,971,000	MMBtu	$3.11-$3.75	Dominion Southpoint		4/14-12/15		(2,090	)
TETCO M1		426,000	MMBtu	$3.40-$3.73	TETCO MI Kosi		4/14-12/15		(279	)
WAHA		40,767,870	MMBtu	$3.72-$4.19	WAHA		4/14-12/15		(2,369	)
NYMEX Henry Hub		26,747,103	MMBtu	$4.02-$4.29	NYMEX Henry Hub		4/14-12/15		(255	)
Basis		14,455,000	MMBtu	($0.73)-($1.01)	DSP Basis		4/14-12/15		(1,051	)


Total		91,366,973							(6,044	)

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	Quantity

	Quantity					Contract Period		Estimated Fair Value
Commodity	Remaining		Units	Prices	Price Index	Contract Period		Estimated Fair Value
NGL swaps
Ethane		2,836,890	Gal	$0.65	OPIS MB Ethane		4/14-12/15		1,030
Propane		11,570,353	Gal	$0.65-$0.95	OPIS MB Propane		4/14-12/15		(1,941	)
IsoButane		2,001,437	Gal	$0.65-$1.57	OPIS MB IsoButane		4/14-12/15		308
Normal butane		3,559,792	Gal	$0.65-$1.50	OPIS MB NButane		4/14-12/15		429
Natural gasoline		4,230,762	Gal	$0.65-$1.91	OPIS MB Nat Gasoline		4/14-12/15		(893	)


Total		24,199,234							(1,067	)


Grand total								$	(7,592	)

While these contracts limit the downside risk of adverse price movements, they may also limit future revenues from favorable price movements.

Under the terms of Vantage I's revolving credit facility, the form of commodity derivative instruments to be entered into is in Vantage I's discretion, subject to certain maximum limitations.

For a discussion of how we use financial commodity derivative contracts to mitigate some of the potential negative impact on our cash flow caused by changes in natural gas, NGL and oil prices, please see "—Pro Forma Capital Resources and Liquidity—Commodity Derivative Activities."

Interest Rate Risks

At March 31, 2014, we had no borrowings outstanding under the Vantage I revolving credit facility and $25 million of outstanding borrowings under the Vantage II revolving credit facility. We have a choice of borrowing in Eurodollars or at the base rate. Under the Vantage I revolving credit facility, Eurodollar loans bear interest at a rate per annum equal to LIBOR plus an applicable margin ranging from 175 to 275 basis points, depending on the percentage of the borrowing base utilized. Base rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank's reference rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the rate for one month Eurodollar loans plus 100 basis points, plus an applicable margin ranging from 75 to 175 basis points, depending on the percentage of the borrowing base utilized. Under the Vantage II revolving credit facility, Eurodollar loans bear interest at a rate per annum equal to LIBOR plus an applicable margin ranging from 175 to 275 basis points, depending on the percentage of the borrowing base utilized. Base rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank's reference rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the rate for one month Eurodollar loans plus 100 basis points, plus an applicable margin ranging from 75 to 175 basis points, depending on the percentage of the borrowing base utilized.

As of March 31, 2014, we had indebtedness outstanding under the Vantage I second lien term loan of $200 million which bears interest at a floating rate. The interest rate on this indebtedness as of March 31, 2014 was approximately 8.5%. Interest is payable in arrears at the end of each quarter and on the maturity date. We have a choice of borrowing in Eurodollars or at the base rate. Eurodollar loans bear interest at a rate per annum equal to the Adjusted LIBOR rate plus 750 basis points with a minimum Adjusted LIBOR rate of 1.00%. Base rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank's reference rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the rate for one month Eurodollar loans plus 100 basis points, plus 650 basis points. As of March 31, 2014, the Adjusted LIBOR rate was approximately 1.0%, which is the minimum Adjusted LIBOR rate on the term loan. Accordingly, a 100 basis point increase in the Adjusted LIBOR rate would not materially change our interest expense. Based on the outstanding balance on the term loan as of March 31, 2014, a 100 basis point increase in the Adjusted LIBOR rate beyond the minimum Adjusted LIBOR rate of 1.00% would increase interest expense by $2.0 million per year.

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On May 8, 2014, Vantage II entered into a second lien term loan credit facility with affiliates of GSO Capital Partners LP in an aggregate principal amount of $100 million. Please see "—Debt Agreements—Vantage II Second Lien Term Loan."

We do not currently have any derivatives in place to mitigate the effects of interest rate risk. We may implement an interest rate hedging strategy in the future.

Counterparty and Customer Credit Risk

Our natural gas and oil derivative contracts expose us to credit risk in the event of nonperformance by counterparties. While our predecessor does not require our counterparties to our derivative contracts to post collateral, our predecessor does evaluate the credit standing of such counterparties as it deems appropriate. We plan to continue to evaluate the credit standings of our counterparties in a similar manner. The counterparties to our predecessor's derivative contracts currently in place have investment grade ratings.

Our principal exposures to credit risk are through receivables resulting from joint interest receivables ($8.4 million at March 31, 2014) and receivables from the sale of our natural gas, oil and NGLs production ($8.0 million in receivables at March 31, 2014) due to the concentration of its natural gas, oil and NGLs receivables with several significant customers. 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.

Joint operations receivables arise from billings to entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we intend to drill. We have little ability to control whether these entities will participate in our wells.

Off-Balance Sheet Arrangements

Currently, neither we, our predecessor nor Vantage II have off-balance sheet arrangements.

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BUSINESS

Our Company

We utilize advanced well completion strategies and technologies, including pad drilling and downhole rotary steering, to optimize well economics and operational efficiencies. We believe that our horizontal drilling and completion expertise, coupled with the favorable geologic characteristics of our Marcellus and Barnett Shale acreage, positions us for continued strong results and growth. We have grown our net daily production from 18.1 MMcfe/d for the year ended December 31, 2011 to 63.3 MMcfe/d for the year ended December 31, 2013, representing a compounded annual growth rate of 86.8%. Our estimated average net daily wellhead production for the first five days of July 2014 was 82.5 MMcfe/d.

Our Properties

Marcellus Shale

The Appalachian Basin, which covers over 185,000 square miles in portions of Kentucky, Tennessee, Virginia, West Virginia, Ohio, Pennsylvania and New York, is considered a highly attractive energy resource producing region with a long history of oil, natural gas and coal production. More importantly, the Appalachian Basin is strategically located near the high energy demand markets of the northeast United States, which has historically resulted in higher realized sales prices due to the reduced transportation costs a purchaser must incur to transport commodities to end users. Over the past five years, the focus of many producers has shifted from the younger, shallower conventional sandstone and carbonate reservoirs in the Appalachian Basin to the older, deeper Marcellus Shale and the newly emerging Utica Shale plays, which has driven production growth in the basin. According to

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the U.S. Energy Information Administration, natural gas production in the Marcellus Shale in March 2014 exceeded 14 Bcf/d, making it the largest unconventional gas play in the world.

The productive limits of the Marcellus Shale cover over 90,000 square miles within Pennsylvania, West Virginia, Ohio and New York. We believe that the Marcellus Shale is a premier North American shale play due to its high well recoveries relative to drilling and completion costs, broad aerial extent, high-quality reservoir characteristics and significant hydrocarbon resources in place.

The Marcellus Shale is a black, organic-rich shale deposit generally productive at depths between 5,500 and 10,000 feet. Production from the brittle, gas-charged shale reservoir is best derived from hydraulically fractured horizontal wellbores that exceed 2,000 feet in lateral length and involve multistage fracture stimulations. The geology of the Marcellus Shale is analogous to the Barnett, Woodford and Fayetteville Shales.

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following table provides certain operational data relating to these wells, certain of which are non-operated.

Well Name		Reserve Category (1)

Pultorak 1H	3,994	PDP	6.1	1.5	1/1/2012	765	1.9	2.5	3.3
Pultorak 2H	4,271	PDP	6.0	1.4	1/1/2012	775	1.9	2.5	3.1
Scotts Run Unit 590956	5,969	PDP	12.4	2.1	11/7/2012	497	4.0	8.1	7.2
Scotts Run Unit 590986	5,522	PDP	12.9	2.3	11/8/2012	482	3.6	7.5	7.1
Porter St 1 5H	5,240	PDP	6.1	1.2	12/17/2012	361	1.4	3.8	3.8
Porter St 1 6H	5,222	PDP	7.1	1.4	1/29/2013	318	1.3	4.1	4.1
Moore 591130 ROG146H3	7,442	PDP	18.9	2.5	5/6/2013	330	4.1	12.4	8.8
Moore 591132 ROG146H5	4,591	PDP	10.5	2.3	5/10/2013	326	2.5	7.7	8.8
Moore 591129 ROG146H2	6,542	PDP	14.6	2.2	5/14/2013	320	3.2	9.9	8.0
Sandrock 1H	4,474	PDP	10.5	2.4	5/15/2013	299	2.3	7.6	8.9
Sandrock 2H	4,935	PDP	11.0	2.2	5/15/2013	304	2.0	6.7	7.2
Moore 591128 ROG146H1	6,841	PDP	12.7	1.9	5/18/2013	314	3.2	10.2	7.8
Moore 591131 ROG146H3	2,342	PDP	5.8	2.5	6/7/2013	298	1.3	4.3	9.7
Ridge Road 1H	6,430	PDP	9.0	1.4	12/20/2013	95	0.9	9.4	7.7
Average	5,273		10.3	1.9		392	2.4	6.9	6.8

(1): As of December 31, 2013 and assuming a 30-year reserve life.
(2): As of March 31, 2014.
(3): Cumulative production divided by days producing.
(4): Average daily production normalized to the average lateral length for these wells.

The Upper Devonian and Utica Shales are formations stacked with the Marcellus Shale in the same geographic footprint. Based on well results from nearby operators and geologic data available to us, we believe substantially all of our Marcellus Shale acreage is also prospective for the Upper Devonian Shale, which is a black, organic rich shale comprised of the Geneseo Shale, Middlesex Shale and Rhinestreet Shale and is at shallower depths than the Marcellus Shale formation. In Washington and Greene Counties, Pennsylvania, the Upper Devonian Shale and Marcellus Shale are separated by the Tully Limestone, which is approximately 30 feet thick in this area. As of July 1, 2014, we had drilled three horizontal Upper Devonian Shale wells, all of which were awaiting completion and not yet on production. As of April 30, 2014, we had 312 identified drilling locations in the Upper Devonian Shale.

Additionally, we believe our acreage may be prospective for the Utica Shale, an unconventional reservoir underlying the Marcellus Shale. The productive limits of the Utica Shale cover over 80,000 square miles within Ohio, Pennsylvania, West Virginia and New York. The Utica Shale is an organic-rich continuous black shale, with most production occurring at vertical depths between 7,000 and 10,000 feet.

Barnett Shale

The Fort Worth Basin is a mature hydrocarbon basin covering more than ten counties in North Texas and extending into Southern Oklahoma. Production began with the exploitation of Bend Conglomerate and Strawn Sandstone reservoirs in the early 1900s. Today, the Fort Worth basin is mainly known as the location of the Barnett Shale, which covers approximately 3,400 square miles and was the first resource play to exploit blanket horizontal drilling in an area previously thought to be unproductive. The Barnett Shale is one of the largest and most mature natural gas fields in North America. Located primarily in the Fort Worth Basin of North Texas, the "core" region of the Barnett

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Shale has produced a total of over 12 Tcf of natural gas, according to Wood Mackenzie, an energy research and consulting firm.

The successful development of the Barnett Shale in the core area of the Fort Worth Basin can be attributed to its unique reservoir characteristics that include a thick (up to 800 feet), highly organic formation that contains free gas in the fractures and pore spaces throughout the reservoir. In addition, the presence of effective bottom and top seals act as effective frac barriers which limit the production of water from other formations and enhance the recovery of the gas in place. As is typical of all resource plays, the Barnett Shale is laterally continuous over a very large area which allows for the mechanical exploitation of the resource without the traditional risks of structural or stratigraphic variations within the defined limits of the reservoir.

Other Properties

We also hold over 80,000 net acres in other project areas, primarily comprised of our Uinta Basin properties in Utah. The Uinta Basin is a mature hydrocarbon basin located in Duchesne and Uintah Counties of Utah. This basin covers more than 9,000 square miles with development beginning in the 1950s. Formed during the late Cretaceous to Eocene periods, the Uinta Basin is an active oil and gas development basin with focus on development within three main petroleum systems: Mesaverde gas, Wasatch oil and Green River oil. Today, development is focused primarily on Wasatch and Green River black wax crude, aided by advanced completion technologies tied to both vertical and horizontal development. Recovery from these petroleum systems is often aided by secondary water flood, in conjunction with new well development. The Uinta Basin targets are mature with over 30,000 wells drilled to date, according to Wood Mackenzie. In addition, the Uinta Basin has produced over 650 million barrels of oil and over 5 Tcf of natural gas during its productive history, according to the Utah Division of Oil, Gas and Mining production data for Duchesne and Uintah counties.

Although we are not currently developing our other properties, we believe that they provide significant upside potential to our primary operations.

Drilling Program

Our 2014 capital program is primarily focused on identifying and developing low-cost, high return natural gas drilling opportunities in order to grow production and cash flow. In 2014 we plan to invest

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$540 million in our operations. This represents a 57% increase over our $344 million 2013 capital expenditures. Of our anticipated $540 million capital program, approximately 82% or $441 million, will be allocated to drilling and completion expenditures. Of this $441 million, we are allocating approximately $309 million of 2014 drilling and completion capital to the Marcellus Shale to run two operated rigs and $132 million for the Barnett Shale to run two operated rigs. We also plan to spend $45 million between contemplated land acquisitions, seismic and other activities and $54 million for our gathering, compression and other midstream activities. We plan to use the majority of our land spend to add acreage in the prospect areas where we already control significant positions to allow us to extend planned laterals and add wellbores to pads, which we believe will further enhance already compelling well economics.

Operating Data

The following chart provides a summary of our EUR per PUD well based on our December 31, 2013 reserve estimates, delineated by each of our operating regions:

	Average EUR Per PUD Well

	Natural Gas (MMcf)		NGLs (MBbls)		Oil (MBbls)		Total (MMcfe)		Identified Drilling Locations
Marcellus Shale		9,348		—		—		9,348		66
Barnett Shale
Denton / Wise		2,494		227		21		3,987		83
Tarrant		5,449		—		—		5,449		67

Transportation and Takeaway Capacity

We have numerous takeaway capacity alternatives relative to other regions in the Marcellus Shale as a number of long-haul pipelines converge in Greene County, where all of our Marcellus Shale acreage is located. Our current natural gas production in the Marcellus Shale is gathered and subsequently delivered to Spectra Energy Partners' TETCo system and Dominion Resources' DTI system for long-haul delivery. Columbia Gas Transmission's TCO system, National Fuel Gas' Line N and EQT Midstream's Equitrans system are also in close proximity to our acreage. Our Barnett Shale acreage is in proximity to some of the most extensive midstream infrastructure in North America.

We have entered into firm marketing agreements covering 40,000 MMBtu/d of our Appalachian Basin production during the period from October 2014 until October 2020 and 75,000 MMBtu/d of our Appalachian Basin production during the period from November 2014 until October 2019. Under the firm marketing agreements, our production will be sold at prices tied to certain Appalachian Basin indices and we are obligated to sell these daily volumes or purchase replacement gas for any deficiencies in deliveries.

We continue to actively identify and evaluate additional takeaway capacity to facilitate production growth in our Marcellus Shale positions.

Gathering Arrangements

We have entered into gathering agreements with midstream operators in our Barnett and Marcellus Shale areas of operation. Certain of these gathering agreements in the Barnett Shale include minimum volume commitments, which could require us to pay minimum gathering fees to the provider if we were unable to deliver sufficient production volumes. Based on our operations and expected production growth, we do not believe that we will face any material liabilities as a result of the failure to meet minimum volume commitments.

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Business Strategy

•: Enhance returns by focusing on operational and cost efficiencies while deploying capital to highest return opportunities. We target best-in-class returns in the Marcellus and Barnett Shales. We continually monitor and adjust our drilling program with the objective of achieving the highest total returns on our drilling portfolio. As the operator of the substantial majority of our acreage in the Marcellus and Barnett Shales, we are able to manage the timing and level of our capital spending, our exploration and development drilling strategies and our operating costs. We believe that we will achieve this objective by maximizing well production and recoveries relative to drilling and completion costs through optimizing lateral length, the number of frac stages, perforation intervals and the type of fracture stimulation employed. In addition, we are focused on reducing our capital costs of drilling and completing horizontal wells and operating costs through efficient well management and procurement initiatives that generate favorable services and supplies pricing.
•: Create shareholder value through the aggressive development of our extensive drilling inventory. We intend to continue to aggressively drill and develop our portfolio of 1,074 identified drilling locations as of April 30, 2014 with a goal of growing production, cash flow and reserves in an economically efficient manner in order to maximize shareholder value. In executing our development strategy, we intend to leverage our operational control and the expertise of our technical team to deliver continued production and cash flow growth. We began our development program in the Marcellus Shale in 2011 and have increased production from 1.9 MMcf/d in the three months ended December 31, 2011 to approximately 30.3 MMcf/d for the three months ended March 31, 2014. We will continue to deploy resources to develop our high rate of return inventory and continue to build on our track record of superior production, cash flow and reserve growth.
•: Continue growing our acreage position in the core of the Marcellus Shale through opportunistic leasing and strategic acquisitions. We intend to continue identifying and acquiring additional acreage and producing assets in the core of the Marcellus Shale, which we believe offers some of the most attractive single-well rates of return in North America. We believe that our experienced management and technical team will enable us to opportunistically expand our acreage position and drilling inventory in highly attractive areas. We have selectively built our Marcellus Shale position from less than 200 net acres as of December 31, 2010 to approximately 51,771 net acres as of April 30, 2014. We believe that our Marcellus Shale acreage has a significant inventory of expansion and consolidation opportunities, and we will continue to pursue transactions that meet our strategic and financial objectives. We are focused on infill lease acquisitions that we believe will further consolidate our acreage, increase effective lateral lengths and result in operational efficiencies.
•: Manage commodity price exposure through an active hedging program to protect our expected future cash flows. We are focused on maintaining an active hedging program to minimize volatility in cash flows and commodity price and regional basis differential exposure in an effort to protect returns on our capital investment program as well as expected future cash flows. As of March 31, 2014, Vantage I and Vantage II had entered into hedging contracts through 2015 covering a total of approximately 74 Bcfe of their projected natural gas, NGL and oil production at a weighted average price of $4.47 per Mcfe.

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Business Strengths

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

•: Large concentrated position in the core of the Marcellus Shale. Since 2010, we have built a significant contiguous acreage position in what we believe is the core of the Marcellus Shale in Greene County, Pennsylvania through a disciplined and focused leasing and acquisition program. We believe the core of the Marcellus Shale offers some of the most attractive single-well rates of return in North America. Our concentrated ownership of 51,771 net acres in Greene County has allowed us to efficiently delineate our position and produce industry-leading well results.
•: Complementary, highly economic position in the Barnett Shale. We have assembled a large and attractive leasehold position of approximately 38,347 net acres in the Barnett Shale, including 23,043 net acres in Denton, Wise and Tarrant Counties in Texas, which we believe constitute the core of the Barnett Shale. We believe we have a high quality Barnett Shale acreage position and high rate-of-return development program which complement our Marcellus Shale assets by providing additional cash flows to reinvest in our development program.
•: Multi-year, low-risk drilling inventory. We believe our concentrated acreage positions in the Marcellus and Barnett Shales are characterized by low geological risk and repeatable drilling opportunities that we expect will result in a predictable production growth profile. At April 30, 2014, we had 1,074 identified drilling locations, including 423 in the Marcellus Shale, 312 in the Upper Devonian Shale and 339 in the Barnett Shale. We believe that we and other operators in the area have substantially delineated and de-risked our acreage position in the core of the Marcellus Shale in Greene County, and. Additionally, we believe substantially all of our Marcellus Shale acreage is also prospective for the Upper Devonian Shale and may be prospective for the Utica Shale.
•: Low cost operator with significant control across our acreage position. We have historically had an intense focus on cost management which has translated into meaningful reductions in our overall capital and operating costs. We have implemented operational efficiencies to continue lowering our costs, such as pad drilling, the use of less expensive, shallow vertical drilling rigs to drill to the kick-off point of the horizontal wellbore. Our acreage position in the Marcellus and Barnett Shales is generally in contiguous blocks which allows us to conduct our operations more cost effectively and develop this acreage more efficiently. Additionally, our operational control allows us to more efficiently manage the pace of development activities, the gathering and marketing of our production and operating costs.
•: Access to multiple takeaway alternatives in the Marcellus Shale. We have numerous takeaway pipeline alternatives relative to other regions in the Marcellus Shale as a number of long-haul pipelines converge in Greene County. Our current natural gas production in the Marcellus Shale is gathered and subsequently delivered to Spectra Energy Partners' TETCo system and Dominion Resources' DTI system for long-haul delivery. Columbia Gas Transmission's TCO system, National Fuel Gas' Line N and EQT Midstream's Equitrans system are also in close proximity to our acreage. We currently have an aggregate of 115,000 MMBtu/d of production under firm marketing agreements in the Marcellus Shale beginning in October 2014 and November 2014, respectively. We also maintain a strong commitment to developing the necessary midstream infrastructure to support our drilling schedule and production growth.
•: Significant liquidity and financial flexibility. Following the completion of this offering, we estimate that we will have cash on hand and availability under our combined revolving credit facility of approximately $ million. After giving effect to this offering, we expect that our capital expenditure budgets for 2014 and 2015 will be fully funded through cash flows from operations,

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cash on hand and available capacity under our combined revolving credit facility, consistent with our overall financial strategy of maintaining a strong and stable capitalization profile.

•: Proven, experienced and incentivized management and technical teams. We believe our management team's experience and expertise across multiple resource plays provides a distinct competitive advantage. Our management team have an average of over 28 years of industry experience including executive officer positions at public exploration and production companies and key members with significant experience operating in the Marcellus and Barnett Shales. We have assembled a strong technical staff of engineers, geoscientists and field operations managers with extensive experience in horizontal development and operating multi-rig development programs. We have been early adopters of new oilfield services and techniques for drilling and completions. Our management and technical teams have a significant economic interest in us through their interests in our controlling stockholders, Vantage Investment I and Vantage Investment II. Management's percentage interest in our stock held by Vantage Investment I and Vantage Investment II may increase over time, without diluting public investors, if our stock price appreciates following this offering. We believe our management team's ability to increase their economic interest in us provides significant incentives to grow our stock price for the benefit of all stockholders.

Our Operations

Reserve Data

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

Reserves Presentation

Our estimated proved reserves as of December 31, 2013 are based on valuations prepared by our independent reserve engineers. Copies of the summary reports of our reserve engineers with respect to our reserves as of December 31, 2013 are filed as exhibits to the registration statement of which this prospectus forms a part. Please see "—Preparation of Reserve Estimates" for definitions of proved reserves and the technologies and economic data used in their estimation.

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The following table summarizes the combined historical and estimated proved reserves of Vantage I, Vantage II and the two entities on a combined basis at December 31, 2013 based on SEC pricing.



*Vantage I*:
Estimated Proved Reserves⁽¹⁾:
Natural gas (Bcf)	612.7
NGLs (MMBbl)	15.5
Oil (MMBbl)	1.4


Total equivalent proved reserves	713.7
Total equivalent proved developed reserves	126.0
Natural gas (Bcf)	106.8
NGLs (MMBbl)	3.0
Oil (MMBbl)	0.2
Percent proved developed	17.7	%
Total equivalent proved undeveloped reserves	587.7
Natural gas (Bcf)	505.9
NGLs (MMBbl)	12.4
Oil (MMBbl)	1.2
Percent proved undeveloped	82.3	%
*Vantage II*:
Estimated Proved Reserves⁽¹⁾:
Total natural gas proved reserves (Bcf)	299.7
Total natural gas proved developed reserves (Bcf)	36.0
Percent proved developed	12.0	%
Total natural gas proved undeveloped reserves (Bcf)	263.7
Percent proved undeveloped	88.0	%
*Combined*:
Estimated Proved Reserves⁽¹⁾:
Natural gas (Bcf)	912.4
NGLs (MMBbl)	15.5
Oil (MMBbl)	1.4


Total equivalent proved reserves	1,013.4
Total equivalent proved developed reserves	162.0
Natural gas (Bcf)	142.8
NGLs (MMBbl)	3.0
Oil (MMBbl)	0.2
Percent proved developed	16.0	%
Total equivalent proved undeveloped reserves	851.4
Natural gas (Bcf)	769.6
NGLs (MMBbl)	12.4
Oil (MMBbl)	1.2
Percent proved undeveloped	84.0	%

(1): Volumes were determined using average adjusted product prices of $3.05 per Mcf for natural gas in the Marcellus and $2.89 per Mcf, $24.62 per Bbl, and $94.27 per Bbl for natural gas, NGLs and oil, respectively, in the Barnett Shale.

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Proved Undeveloped Reserves

The following table summarizes the changes in the combined proved undeveloped reserves of Vantage I, Vantage II and the two entities on a combined basis during 2013 (in MMcfe):


*Vantage I*:
Proved undeveloped reserves at December 31, 2012	454,485
Conversions into proved developed reserves	(39,825	)
Extensions and discoveries	126,732
Acquisitions	22,912
Revisions	23,360


Proved undeveloped reserves at December 31, 2013	587,664




*Vantage II*:
Proved undeveloped reserves at December 31, 2012	60,014
Conversions into proved developed reserves	(6,279	)
Extensions and discoveries	77,260
Acquisitions	119,346
Revisions	13,322


Proved undeveloped reserves at December 31, 2013	263,663




*Combined*:
Proved undeveloped reserves at December 31, 2012	514,499
Conversions into proved developed reserves	(46,104	)
Extensions and discoveries	203,992
Acquisitions	142,258
Revisions	36,682


Proved undeveloped reserves at December 31, 2013	851,327

During the year ended December 31, 2013, extensions were comprised of 155,193 MMcfe and 48,799 MMcfe from the Appalachian and Fort Worth Basins, respectively. The increases resulted from new proved undeveloped locations added during the year associated with the drilling of new wells.

During the year ended December 31, 2013, the increase due to acquisitions was primarily related to our acquisitions of properties in the Appalachian Basin from third parties.

During the year ended December 31, 2013, revisions were primarily attributable to increases in price; however, we did experience an increase due to technical revisions in both the Appalachian and Fort Worth Basins.

During the year ended December 31, 2013, we incurred costs of approximately $24 million to convert 46,104 MMcfe of proved undeveloped reserves to proved developed reserves.

As of December 31, 2013, we had no proved undeveloped reserves that had remained undeveloped for more than five year since initial booking.

Estimated future development costs relating to the development of our proved undeveloped reserves at December 31, 2013 are approximately $735 million over the next five years, which we expect to finance through the proceeds of this offering, cash flow from operations, available capacity under our combined revolving credit facility and other sources of capital financing. Our drilling program through the first quarter of 2014 has focused on proving our undeveloped leasehold acreage through delineation drilling. While we will continue to drill leasehold delineation wells and build on our current leasehold position, we will also focus on drilling our proved undeveloped reserves. Based on our reserve reports as of December 31, 2013, we had 66, none and 150 identified drilling locations in the

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Marcellus Shale, Upper Devonian Shale and Barnett Shale, respectively, associated with proved undeveloped reserves and 1, none and 7 identified drilling locations in the Marcellus Shale, Upper Devonian Shale and Barnett Shale, respectively, associated with proved developed not producing reserves. All of our proved undeveloped reserves are expected to be developed within five years of initial booking. Please see "Risk Factors—Risks Related to Our Business—The development of our estimated proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated proved undeveloped reserves may not be ultimately developed or produced."

Preparation of Reserve Estimates

Our reserve estimates as of December 31, 2013 included in this prospectus are based on evaluations prepared by the independent petroleum engineering firms of Netherland, Sewell & Associates, Inc. ("NSAI") and Wright & Company in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Evaluation Engineers and definitions and guidelines established by the SEC. Our independent reserve engineers were selected for their historical experience and geographic expertise in engineering unconventional resources.

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 engineers use 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 per well are estimated using performance analysis and volumetric analysis. The estimates of the proved developed reserves and EURs for each developed well 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 work closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of data furnished to our independent reserve engineers in their reserve auditing process. Periodically, our technical team meets with the independent reserve engineers to review properties and discuss methods and assumptions used by us to prepare reserve estimates.

Our external prepared reserve estimates and related reports for our Appalachian Basin assets are reviewed and approved by our Appalachian Asset Development Manager, Richard D. Starkey, who has been with us since July 2007. Mr. Starkey has 34 years of experience in oil and gas reservoir engineering, conventional and unconventional reservoir characterization, development operations, strategic planning and reserve management. From August 2002 to June 2007, Mr. Starkey served as Development Group Lead for DJ and Jonah field operations and Business Development Group Lead

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for EnCana Oil and Gas (USA) LTD. From 1981 to 2002, Mr. Starkey served in various domestic and international reservoir engineering, development operations, and asset management positions with Malkewicz Hueni Associates, Cody Energy, LLC, Ampolex USA Inc., Bridge Oil (USA) Inc. and Tenneco Oil Company. Mr. Starkey holds a B.S. in Petroleum Engineering from the Colorado School of Mines.

For all properties outside of the Appalachian Basin, our internally prepared reserve estimates and related reports are reviewed and approved by our Fort Worth and Uinta Asset Development Manager, Seth Urruty. Mr. Urruty has been with Vantage since November 2007. Mr. Urruty has 8 years of experience in oil and gas operations, reservoir management, and strategic planning. From 2006 to November 2007 Mr. Urruty was a Reservoir and Operations Engineer for Petro-Canada (USA) operations. Mr. Urruty is a graduate of Gonzaga University's School of Engineering with a B.S. in Mechanical Engineering and minor in Business Administration.

Our proved reserve estimates shown herein at December 31, 2013 have been independently prepared by NSAI and Wright & Company. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves report incorporated herein are Mr. Randolph K. Green and Mr. William J. Knights. Mr. Green has been practicing consulting petroleum engineering at NSAI since 1983. Mr. Green is a Licensed Professional Engineer in the State of Texas (No. 72951) and has over 30 years of practical experience in petroleum engineering, with over 30 years experience in the estimation and evaluation of reserves. He graduated from Texas Tech University in 1982 with a Bachelor of Science Degree in Petroleum Engineering. Mr. Knights has been practicing consulting petroleum geology at NSAI since 1991. Mr. Knights is a Licensed Professional Geoscientist in the State of Texas, Geology (No. 1532) and has over 32 years of practical experience in petroleum geosciences, with over 32 years experience in the estimation and evaluation of reserves. He graduated from Texas Christian University in 1981 with a Bachelor of Science Degree in Geology and from Texas Christian University in 1984 with a Master of Science Degree in Geology. Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

Wright & Company was founded in 1988 and performs consulting petroleum engineering services under Texas Board of Professional Engineers. Within Wright & Company, the technical person primarily responsible for preparing the estimates set forth in the Wright & Company letter, which is filed as an exhibit to the registration statement of which this prospectus forms a part, was D. Randall Wright. Mr. Wright has been a practicing consulting petroleum engineer at Wright & Company since its founding in 1988. Mr. Wright is a Registered Professional Engineer in the State of Texas (License No. 43291) and has over 35 years of practical experience in the estimation and evaluation of petroleum reserves. He graduated from Tennessee Technological University with a Master of Science degree in Mechanical Engineering. Mr. Wright meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; he is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserve definitions and guidelines.

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

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estimates often differ from the quantities of oil and natural gas, NGLs and oil that are ultimately recovered. Estimates of economically recoverable natural gas, NGLs and oil 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. Please read "Risk Factors" appearing elsewhere in this prospectus.

Determination of Identified Drilling Locations

Our identified drilling locations, which include both drillable and estimated locations, are those drilling locations identified by management based on the following criteria:

•: Drillable locations—These are mapped locations that our reserve engineers have deemed to have a high likelihood of being drilled or are currently in development but have not yet commenced production. As of April 30, 2014, we had 250, 8 and 332 drillable locations associated with our Marcellus Shale, Upper Devonian Shale and Barnett Shale acreage, respectively.
•: Estimated locations—For our Pennsylvania acreage, we currently anticipate full development at approximately 88 acre spacing for both the Marcellus and the Upper Devonian Shales. Assuming the same 88 acre spacing as for the drillable and producing locations, the remaining acreage, on an unrisked basis, would yield 346 and 608 additional locations for the Marcellus and the Upper Devonian Shales, respectively, under the same spacing assumptions. We risk these locations associated with the remaining acreage at 50% to arrive at the estimated locations for the Marcellus and the Upper Devonian Shales of 173 and 304, respectively, as of April 30, 2014. With respect to our Barnett Shale acreage, we apply the 50% risking factor to our 14 internally-identified possible locations to arrive at 7 estimated locations in the Barnett Shale as of April 30, 2014.

We believe the risking of our estimated locations provides a more accurate number of gross and net identified drilling locations that could be drilled. Even though our reserve engineers have not mapped specific estimated locations, we believe the risked number provides a reasonable estimate of the number of locations that could actually be mapped. Accordingly, we believe summing drillable locations with estimated locations into a single identified drilling locations calculation provides useful information about our future operations and growth potential.

In addition, our identified lateral footage is calculated by multiplying our identified drilling locations by the average lateral length of our horizontal wells in the respective area. As of April 30, 2014, we had 2,185,850 gross (2,019,566 net), 1,668,402 gross (1,184,134 net) and 1,607,935 gross (1,437,953 net) identified lateral feet in the Marcellus Shale, Barnett Shale and Upper Devonian Shale, respectively.

Production, Revenues and Price History

Natural gas, NGLs, and oil are commodities; therefore, the price that we receive for our production is largely a function of market supply and demand. While demand for natural gas in the United States has increased dramatically since 2000, natural gas and NGL supplies have also increased significantly as a result of horizontal drilling and fracture stimulation technologies which have been used to find and recover large amounts of oil and natural gas from various shale formations throughout the United States. Demand is impacted by general economic conditions, weather and other seasonal conditions. Over or under supply of natural gas can result in substantial price volatility. Historically, commodity prices have been volatile, and we expect that volatility to continue in the future. A substantial or extended decline in natural gas prices or poor drilling results could have a material adverse effect on our financial position, results of operations, cash flows, quantities of natural gas reserves that may be economically produced and our ability to access capital markets. Please see "Risk

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Factors—Risks Related to Our Business—Natural gas, NGL and oil prices are volatile. A substantial or extended decline in commodity prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments."

The following table sets forth information regarding production, revenues and realized prices, and production costs for the years ended December 31, 2013 and 2012, for Vantage I, Vantage II and the two entities on a combined basis giving effect to the reorganization transactions described under "Corporate Reorganization." For additional information on price calculations, see information set forth in "Management's Discussion and Analysis of Financial Condition and Results of Operations."

	At December 31,

	2013		2012
*Vantage I*:
Production data:
Marcellus Shale:
Natural gas (Bcf)		4		2
NGLs (MBbl)		—		—
Oil (MBbl)		—		—
Total combined production (Bcfe)		4		2
Average daily combined production (MMcfe/d)		12		6
Barnett Shale:
Natural gas (Bcf)		10		9
NGLs (MBbl)		240		271
Oil (MBbl)		50		25
Total combined production (Bcfe)		12		10
Average daily combined production (MMcfe/d)		32		28
Total:
Natural gas (Bcf)		14		11
NGLs (MBbl)		240		271
Oil (MBbl)		504		257
Total combined production (Bcfe)		16		12
Average daily combined production (MMcfe/d)		44		34
Average sales prices:
Natural gas (per Mcf)	$	3.25	$	2.16
NGLs (per Bbl)	$	27.52	$	30.91
Oil (per Bbl)	$	95.77	$	91.59
Combined average sales prices before effects of cash settled derivatives (per Mcfe)⁽¹⁾	$	3.62	$	2.72
Combined average sales prices after effects of cash settled derivatives (per Mcfe)⁽¹⁾	$	3.90	$	3.37
Average costs per Mcfe:
Lease operating and workover expenses	$	0.68	$	0.76
Marketing and gathering	$	0.16	$	0.11
Production and ad valorem taxes	$	0.20	$	0.15
Depreciation, depletion, amortization and accretion	$	1.39	$	1.33
General and administrative	$	0.23	$	0.36

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	At December 31,

	2013		2012
*Vantage II*:
Production data:
Natural gas (Bcf)		7		—
Average daily combined production (MMcf/d)		19		—
Average sales prices:
Average natural gas sales prices before effects of cash settled derivatives (per Mcf)⁽¹⁾	$	3.65	$	—
Average natural gas sales prices after effects of cash settled derivatives (per Mcf)⁽¹⁾	$	3.45	$	—
Average costs per Mcf:
Lease operating and workover expenses	$	0.26	$	—
Marketing and gathering	$	0.64	$	—
Production and ad valorem taxes	$	—	$	—
Depreciation, depletion, amortization and accretion	$	1.29	$	—
General and administrative	$	0.60	$	—
*Combined*:
Production data:
Marcellus Shale:
Natural gas (Bcf)		11		2
NGLs (MBbl)		—		—
Oil (MBbl)		—		—
Total combined production (Bcfe)		11		2
Average daily combined production (MMcfe/d)		31		6
Barnett Shale:
Natural gas (Bcf)		10		9
NGLs (MBbl)		240		271
Oil (MBbl)		50		25
Total combined production (Bcfe)		12		10
Average daily combined production (MMcfe/d)		32		28
Total:
Natural gas (Bcf)		21		11
NGLs (MBbl)		240		271
Oil (MBbl)		50		25
Total combined production (Bcfe)		23		13
Average daily combined production (MMcfe/d)		63		34
Average sales prices:
Natural gas (per Mcf)	$	3.38	$	2.16
NGLs (per Bbl)	$	27.52	$	30.91
Oil (per Bbl)	$	95.77	$	91.59
Combined average sales prices before effects of cash settled derivatives (per Mcfe)⁽¹⁾	$	3.63	$	2.72
Combined average sales prices after effects of cash settled derivatives (per Mcfe)⁽¹⁾	$	3.82	$	3.37

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	At December 31,

	2013		2012
Average costs per Mcfe:
Lease operating and workover expenses	$	0.55	$	0.77
Marketing and gathering	$	0.31	$	0.12
Production and ad valorem taxes	$	0.14	$	0.15
Depreciation, depletion, amortization and accretion	$	1.36	$	1.34
General and administrative	$	0.34	$	0.50

(1): Average sales prices shown reflect both the before and after effects of our cash settled derivatives. Our calculation of such effects includes realized gains or losses on cash settlements for commodity derivatives, which do not qualify for hedge accounting because we do not designate them as hedges.

Productive Wells

The following table sets forth information regarding productive wells as of December 31, 2013 for Vantage I, Vantage II and the two entities on a combined basis:

	Productive Wells

	Productive Wells				Average Working Interest
	Gross		Net		Average Working Interest
Vantage I:
Oil		2		2		100	%
Natural gas		215		167		78	%
Total		217		169		78	%
Vantage II:
Natural gas		14		5		35	%
Combined:
Oil		2		2		100	%
Natural gas		222		172		77	%
Total		224		174		78	%

Acreage

The following table sets forth certain information regarding the total developed and undeveloped acreage in which we owned an interest as of April 30, 2014 at Vantage I, Vantage II and on a combined basis. Approximately 40% of our Marcellus Shale acreage and 85% of our Barnett Shale

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acreage was held by production at April 30, 2014. Acreage related to royalty, overriding royalty and other similar interests is excluded from this table.

	Developed Acres				Undeveloped Acres				Total Acres

	Gross		Net		Gross		Net		Gross		Net
Vantage I:
Marcellus Shale		2,188		1,396		14,956		13,924		17,144		15,320
Barnett Shale		5,819		4,641		40,106		32,484		45,925		37,125
Uinta, Piceance and other⁽¹⁾		260		212		135,718		81,616		135,978		81,828


Total		8,267		6,249		190,780		128,024		199,047

Vantage Energy Inc. S-1