Edgar Filing: Eclipse Resources Corp

424B4

Filed Pursuant to Rule 424(b)(4)

Commission File No. 333-195679

PROSPECTUS

30,300,000 Shares

LOGO

Eclipse Resources Corporation

Common Stock

This is the initial public offering of the common stock of Eclipse Resources Corporation. We are offering 21,500,000 shares of our common stock and the selling stockholders identified in this prospectus are offering 8,800,000 shares of our common stock. We will not receive any proceeds from the sale of shares held by the selling stockholders. No public market currently exists for our common stock. We are an “emerging growth company” as defined in the Jumpstart Our Business Startups Act and are eligible for reduced public company reporting requirements. Please see “Summary—Emerging Growth Company Status.”

We have been approved to list our common stock on the New York Stock Exchange under the symbol “ECR.”

Investing in our common stock involves risks. See “Risk Factors” beginning on page 20 of this prospectus.


	Per Share		Total
Public offering price	$	27.0000	$	818,100,000
Underwriting discounts and commissions⁽¹⁾	$	1.41750	$	42,950,250
Proceeds, before expenses, to us	$	25.5825	$	550,023,750
Proceeds to the selling stockholders	$	25.5825	$	225,126,000

(1)

Please read “Underwriting” 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 4,545,000 additional shares of common stock on the same terms and conditions set forth above solely to cover over-allotments.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon 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 June 25, 2014.

Joint Book-Running Managers


Citigroup		Goldman, Sachs & Co.			Morgan Stanley


Barclays	BMO Capital Markets	Deutsche Bank Securities
KeyBanc Capital Markets		RBC Capital Markets

Senior Co-Managers


Jefferies			Wells Fargo Securities

Co-Managers


Capital One Securities		Johnson Rice & Company L.L.C.		Scotiabank/Howard Weil		Simmons & Company International

Prospectus dated June 19, 2014

LOGO

Eclipse Acreage Area represents the areas in which the highest concentration of our acreage and interests are located and in which we intend to focus our drilling efforts.

TABLE OF CONTENTS


	Page
Summary		1
Risk Factors		20
Cautionary Statement Regarding Forward-Looking Statements		51
Use of Proceeds		53
Dividend Policy		54
Capitalization		55
Dilution		56
Selected Historical Consolidated and Unaudited Pro Forma Financial Data		57
Management’s Discussion and Analysis of Financial Condition and Results of Operations		59
Business		83
Management		113
Executive Compensation		122
Principal and Selling Stockholders		130
Corporate Reorganization		133
Certain Relationships and Related Party Transactions		136
Description of Capital Stock		139
Shares Eligible for Future Sale		143
Material U.S. Federal Income Tax Consequences to Non-U.S. Holders		145
Underwriting		149
Legal Matters		154
Experts		154
Where You Can Find Additional Information		155
Index to Consolidated Financial Statements		F-1
Annex A: Glossary of Defined Terms		A-1

You should rely only on the information contained in this prospectus and any free writing prospectus prepared by us or on our behalf or to the information to 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. See “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements.”

Defined Terms

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

•

“Eclipse,” “Eclipse Resources,” the “Company,” “we,” “our,” “us” and like terms refer collectively to Eclipse Resources I, LP and its consolidated subsidiaries before the completion of our corporate reorganization described in “Corporate Reorganization” and to Eclipse Resources Corporation and its consolidated subsidiaries as of and following the completion of our corporate reorganization;

•

“Eclipse I” refers to Eclipse Resources I, LP;

•

“Eclipse Holdings” refers to Eclipse Resources Holdings, L.P.;

•

“Eclipse Operating” refers to Eclipse Resources Operating, LLC;

•

“EnCap” refers to EnCap Investments L.P.;

•

the “EnCap Funds” refers, collectively, to EnCap Energy Capital Fund VIII, L.P., EnCap Energy Capital Fund VIII Co-Investors, L.P. and EnCap Energy Capital Fund IX, L.P., each of which is a private equity fund managed by EnCap and will be a limited partner of Eclipse Holdings following the completion of this offering;

•

the “Management Funds” refers, collectively, to The Hulburt Family II Limited Partnership, CKH Partners II, L.P. and Kirkwood Capital, L.P., each of which is an investment fund controlled by a member of our management team and will be a limited partner of Eclipse Holdings following the completion of this offering;

•

“Management Holdco” refers to Eclipse Management, L.P., which will be a limited partner of Eclipse Holdings following the completion of this offering;

•

the “Oxford Acquisition” refers to our acquisition of the outstanding membership interests in Eclipse Resources-Ohio, LLC (successor-in-interest to Oxford), which we completed on June 26, 2013;

•

“Oxford” or “The Oxford Oil Company” refers to The Oxford Oil Company. Immediately prior to the Oxford Acquisition, Oxford merged into Eclipse Resources-Ohio, LLC;

•

the “Utica Core Area” refers to what we believe is the most prolific and economic area of the Utica Shale fairway and includes approximately 96,240 of our net acres overlying a portion of the Utica Shale and is depicted on the map located on the inside cover of this prospectus;

•

“Our Marcellus Project Area” refers to the area depicted on the map located on the inside cover of this prospectus and containing approximately 25,740 of our net acres;

•

“Dry Gas,” “Dry Gas Window,” “Dry Gas Hydrocarbon Phase” or “Dry Gas Type Curve Area” refers to the area within the Utica Core Area in which we expect the Utica Shale wells to produce natural gas having a heat content of less than approximately 1,100 Btu with a negligible initial condensate yield;

•

“Rich Gas,” “Rich Gas Window,” “Rich Gas Hydrocarbon Phase” or “Rich Gas Type Curve Area” refers to the area within the Utica Core Area in which we expect the Utica Shale wells to produce natural gas having a heat content between approximately 1,100 Btu and 1,230 Btu, with an initial condensate yield between approximately 1 and 30 barrels per MMcf of natural gas produced;

•

“Condensate,” “Condensate Window,” “Condensate Hydrocarbon Phase” or “Condensate Type Curve Area” refers to the area within the Utica Core Area in which we expect the Utica Shale wells to produce a natural gas having a heat content between approximately 1,231 Btu and 1,280 Btu, with an initial condensate yield of between approximately 31 and 180 barrels per MMcf of natural gas produced; and

•

“Rich Condensate,” “Rich Condensate Window,” “Rich Condensate Hydrocarbon Phase” or “Rich Condensate Type Curve Area” refers to the area within the Utica Core Area in which we expect the Utica Shale wells to produce natural gas having a heat content in excess of 1,280 Btu, with an initial condensate yield in excess of 180 barrels per MMcf of natural gas produced.

In Annex A to this prospectus, we also include a glossary of other defined terms used in this prospectus, including certain oil and natural gas industry terms.

Industry and Market Data

The market data and certain other statistical information used throughout this prospectus are based on independent industry publications, government publications, filings, press releases and presentations by other oil and gas companies, and other published independent sources. Some data is also based on our good faith estimates. Although we have no reason to believe these third party sources (including data related to third party wells) are not 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 titled “Risk Factors.” These and other factors could cause results to differ materially from those expressed in these publications.

Trademarks, Service Marks and Trade Names

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

iii

SUMMARY

This summary highlights some of the information contained in this prospectus and does not contain all of the information that may be important to you. 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 financial statements and the related notes thereto included elsewhere in this prospectus. Unless otherwise indicated, information presented in this prospectus assumes (i) the underwriters’ option to purchase additional shares from the selling stockholders is not exercised, and (ii) the completion of our corporate reorganization as set forth in “Corporate Reorganization.”

Please see “Defined Terms” on page ii of this prospectus for definitions of some of the terms used in this prospectus and Annex A to this prospectus for a glossary of other defined terms used in this prospectus, including certain oil and natural gas industry terms.

Our Company

We are an independent exploration and production company engaged in the acquisition and development of oil and natural gas properties in the Appalachian Basin. As of March 31, 2014, we had assembled an acreage position approximating 227,230 net acres in Eastern Ohio. Approximately 96,240 of our net acres are located in what we believe to be the most prolific and economic area of the Utica Shale fairway, which we refer to as the Utica Core Area, and approximately 25,740 of these net acres are also prospective for the highly liquids rich area of the Marcellus Shale in Eastern Ohio within what we refer to as Our Marcellus Project Area. The geographic extent of the Utica Core Area and Our Marcellus Project Area is depicted on the map located on the inside cover of this prospectus and defined in the section of this prospectus titled “Defined Terms.” We are the operator of approximately 81% of our net acreage within the Utica Core Area and Our Marcellus Project Area. As of March 31, 2014, we had identified 863 net horizontal drilling locations across our acreage, comprised of 668 locations within the Utica Core Area and 195 locations within Our Marcellus Project Area. As of March 31, 2014, we, or our operating partners, had commenced drilling 72 gross wells within the Utica Core Area and 3 gross wells within Our Marcellus Project Area. We intend to focus on developing our substantial inventory of horizontal drilling locations and will continue to opportunistically add to this acreage position where we can acquire acreage at attractive prices.

We have assembled a team of executive and operating professionals with significant knowledge and experience in the Appalachian Basin, particularly with respect to drilling unconventional oil and natural gas wells, managing large scale drilling programs and optimizing the value of the associated production through a coordinated midstream effort. Our senior management has over 250 years of combined, engineering, land, legal and financial expertise. Benjamin W. Hulburt, our Chairman, President and Chief Executive Officer, and Christopher K. Hulburt, our Executive Vice President, Secretary and General Counsel, co-founded Eclipse Resources in 2011. Ben Hulburt co-founded Rex Energy where he served as its President and Chief Executive Officer from that company’s inception through its considerable growth and entry into the liquids rich region of the Marcellus Shale. Chris Hulburt was formerly the Executive Vice President, Secretary and General Counsel of Rex Energy. Thomas S. Liberatore, our Executive Vice President and Chief Operating Officer, was formerly the Vice President and Appalachian Basin Regional Manager for Cabot Oil & Gas, where he led that company’s entry into its industry-leading Marcellus Shale position in Northeastern Pennsylvania. Additionally, our Vice Presidents of Drilling & Completions; Geology; Operations; Land; and Health, Safety, Environment & Regulatory all have significant experience in the Appalachian region. See “Management.”

We began assembling our acreage position in 2011 based upon a rigorous analytical evaluation of the shale properties within the Utica and Point Pleasant formations across Eastern Ohio. Based upon this evaluation, which incorporated multiple high-graded geological and petrophysical characteristics, we concentrated our acreage acquisition efforts in an area spanning parts of 5 counties that we believed would be the most prolific region of the play. This area, covering parts of Noble, Guernsey, Monroe, Belmont and Harrison counties, is located in what we now call the Utica Core Area. According to the Ohio Department of Natural Resources, as of February 8, 2014, there were 310 producing horizontal Utica Shale wells in the State of Ohio, 107 of which were in these 5 counties. Based upon production data from the wells we have drilled or participated in and our analysis of the results publicly released by other operators, we believe that our evaluation of the Utica Shale has been validated and that the Utica Core Area, where we have accumulated a substantially contiguous position of approximately 96,240 net acres, is the most prolific part of the play.

The composition of production from our wells and those of offset operators has corroborated our view of the type curve areas moving from east to west in the play. Across the Utica Core Area, the eastern boundary is more thermally mature and expected to produce dry gas, while the western boundary is less thermally mature and expected to produce a greater proportion of condensate and NGLs in addition to natural gas. We classify our acreage between these boundaries as being prospective for Dry Gas, Rich Gas, Condensate or Rich Condensate and define those terms in the section of this prospectus titled “Defined Terms.” We expect Our Marcellus Project Area to produce a significant proportion of condensate and NGLs in addition to natural gas. Additionally, we own approximately 131,070 net acres (which are approximately 85% held by production) outside of the Utica Core Area that may be prospective for the oil window of the Utica Shale representing upside potential. The table below outlines our Utica Core Area and Our Marcellus Project Area acreage and the identified drilling locations within each type curve area as of March 31, 2014, along with a summary of our expected 2014 drilling plan:


				Identified Drilling Locations				2014 Drilling Plan
Type Curve Area	Net Acreage⁽¹⁾			Gross⁽²⁾		Net⁽²⁾		Gross Wells Spud⁽³⁾		Net Wells Spud⁽³⁾		Net Wells Turned to Sales⁽³⁾
Dry Gas.		32,670			771		210		29		9.6		4.4
Rich Gas		34,160			937		239		61		16.7		6.8
Condensate		24,150			647		169		83		43.1		27.7
Rich Condensate		5,260			422		49		0		0		0

Total Utica Core Area		96,240			2,777		668		173		69.4		38.9

Our Marcellus Project Area		25,740	⁽⁴⁾		604		195		3		0.1		1.2

Total					3,381		863		176		69.5		40.1

(1)

Effective February 2012, we entered into a Participation and Exploration Agreement with Antero Resources in conjunction with the sale of approximately 21,000 of our net acres to Antero Resources, forming an area of mutual interest predominately in Noble County, Ohio. Antero Resources is the operator of our jointly owned properties in the area of mutual interest, where we owned approximately 51,430 gross (13,640 net) acres as of March 31, 2014. In addition, in December 2012, we entered into a Joint Operating Agreement with Triad Hunter covering 3 units consisting of 2,157 gross (1,009 net) acres in Monroe County, Ohio.

(2)

Drilling locations are specifically identified based on the current configuration of our leasehold, developed and planned units and proposed non-operated wells. We generally assume 1,000 foot interlateral spacing for acreage within the Dry Gas Window and 750 foot interlateral spacing elsewhere. We currently target a 6,000 foot lateral length for all of our horizontal wells. See page 32 of this prospectus for a discussion of certain risks and uncertainties relating to our ability to drill and develop our identified drilling locations.

(3)

73 gross operated wells and 103 gross non-operated wells planned to be spud, and 42 gross operated wells and 63 gross non-operated wells planned to be turned to sales.

(4)

Acreage in Our Marcellus Project Area is also included in our total Utica Core Area acreage.

Our Properties

Utica Shale

The Ordovician-aged Utica Shale is an unconventional reservoir comprised of organic-rich black shale, with most production occurring at vertical depths between 6,000 and 10,000 feet. The richest and thickest concentration of organic-carbon content is present within the Point Pleasant layer of the Lower Utica formation. Based on our geologic, engineering and petrophysical research, incorporating production data from wells we have drilled or participated in, as well as publicly disclosed well results from other operators in the play, we believe the Utica Shale is rapidly emerging as a premier North American unconventional resource play. To date, wells in the Utica Core Area in the southern portion of the Utica Shale play have yielded the strongest well results as measured by initial production rates. Our analysis of wells in the Utica Core Area fairway, which we believe to be the most prolific area of the play, indicates that single well rates of return in that region may rival any onshore resource play in North America.

We have evaluated the results of 56 wells that have been publicly disclosed within the Utica Core Area, 13 of which we have drilled or participated in. We have analyzed the initial production rate, or IP, Btu content of the wellhead gas and condensate yield for each well and have utilized this data to evaluate the reasonableness of our assumptions related to the production rate, liquids yield and ultimate recovery we project for the wells we plan to drill across our acreage. See pages 21, 22-23 and 25 of this prospectus for a discussion of certain risks and uncertainties relating to our use of publicly disclosed information regarding third party wells in this prospectus and expected well results.

When we plan our drilling program, we expect to drill wells with an average lateral length of approximately 6,000 feet, which generally enables us to deploy 4 horizontal wells (assuming 1,000 foot interlateral spacing) or 5 horizontal wells (assuming 750 foot interlateral spacing) in a drilling unit consisting of approximately 640 acres. In order to improve the comparability of well results publicly disclosed by different operators to the results we expect from our drilling program, we normalize the initial production rate data to a 6,000 foot lateral, which we refer to as a Normalized 6,000 Foot IP. The following table illustrates the average reported equivalent IP, Normalized 6,000 Foot IP and hydrocarbon composition for the 56 wells we have evaluated in the Utica Core Area. See page 25 of this prospectus for a discussion of certain risks and uncertainties relating to our use of publicly disclosed initial production rates in this prospectus.


Type Curve Area⁽¹⁾	Number of Wells		Reported Equiv. IP⁽²⁾ (Boe/d)		Normalized 6,000 ft. IP⁽²⁾ (Boe/d)		% NGLs⁽²⁾		% Condensate
Dry Gas		6		4,133		4,258		9		—
Rich Gas		23		4,261		4,402		40		10
Condensate		19		3,419		3,265		31		38
Rich Condensate		8		1,751		1,618		23		59

(1)

Based upon wells publicly disclosed as of March 31, 2014.

(2)

Represents sales volumes (post-processing) and assumes ethane recovery.

The highest Normalized 6,000 Foot IPs within each type curve area are located in close proximity to the greatest concentration of our acreage. Based upon the production data we have analyzed, we believe that our acreage is located within the most prolific and economic region of the Utica Core Area. A map with the location of, and a table containing the data for, each of the individual wells included in the table above are provided in “Business—Our Properties.”

Marcellus Shale

According to a study commissioned by the U.S. Energy Information Administration, the Devonian-aged Marcellus Shale gas field contains the largest natural gas resource base in the U.S. The Marcellus Shale consists of organic-rich black shale, with most production occurring at vertical depths between 5,000 and 8,000 feet. The Marcellus Shale is one of the most prolific North American shale plays due to its high well recoveries relative to drilling and completion costs, broad aerial extent, significant hydrocarbon resources in place and relatively homogenous high-quality reservoir characteristics.

As of March 31, 2014, we had approximately 25,740 net acres in the highly liquids rich area of the Marcellus Shale in Eastern Ohio within what we refer to as Our Marcellus Project Area. The reservoir underlying this acreage is less thermally mature than the Marcellus Shale in Southwestern Pennsylvania, and consequently, we believe natural gas production from this area will yield significant NGLs and condensate. We believe that publicly disclosed well results from other operators on and near our acreage and our Tippens 6HM well have confirmed our views regarding the richness of the gas and presence of both NGLs and condensate in this area. For example, in December 2011, Stone Energy reported average initial production rates from its 11 Marcellus Shale wells in the Mary Field in Wetzel County, West Virginia of 3-5 MMcf of gas per day with initial condensate yields of 70-100 barrels per MMcf of gas and that it expected 40 barrels of natural gas liquids per MMcf of gas. These wells are located approximately 5 miles east of Our Marcellus Project Area. In addition, in January 2012, Protégé Energy II LLC reported its drilling results for the Eisenbarth 3-H well to the State of Ohio with an initial production rate of 3.6 MMcf of gas and 397 barrels of condensate per day, equating to a condensate yield of 111 barrels per MMcf of gas. The Eisenbarth 3-H well is located in the center of Our Marcellus Project Area. In December 2013, Magnum Hunter announced 3 new Marcellus Shale wells in Monroe County approximately 3 miles east of Our Marcellus Project Area. Magnum Hunter reported an average initial production rate of 3.9 MMcf of gas and 596 barrels of condensate, equating to a condensate yield of 153 barrels per MMcf of gas. We own a 17.7% interest in 1 of the 3 announced wells. In 2013, we drilled the Tippens 6HM well to delineate the western limit of our acreage that we believed to be prospective for the Marcellus Shale. The Tippens 6HM well produced at a peak rate of 885 Mcf and 162 barrels of condensate per day, with 1,336 Btu gas. Based on gas samples in the immediate area and results from the Tippens 6HM, we expect the gas produced from our acreage in Our Marcellus Project Area to have a heating value of approximately 1,250 - 1,450 Btu.

Activity

Since entering the Utica Shale play in May 2011, through March 31, 2014, we, or our operating partners, had commenced drilling 75 gross wells within the Utica Core Area and Our Marcellus Project Area, of which 16 were drilling, 21 were awaiting completion, 6 were in the process of being completed, 8 were awaiting midstream and 24 had been turned to sales.

We commenced drilling our first Utica Shale test well, the Miley 5H, in 2011 in Noble County, Ohio. This was a vertical exploratory well and the first well to test the Utica Shale in Noble County, Ohio. Core analysis of the Miley 5H well confirmed our geological interpretation and assumptions about the Utica Shale in the area.

Our first operated Utica Shale horizontal well, the Tippens 6HS, which is located in the Dry Gas Window, had an initial peak production rate of 23.2 MMcf per day of natural gas, or 3,867 Boe per day, at a 28/64^th choke with approximately 5,300 psi casing pressure. The Tippens 6HS was drilled with a completed lateral section of approximately 5,850 feet and completed with 19 stages. The well was connected to a sales line on December 21, 2013 and produced a cumulative total of 549 MMcf of natural gas for an average rate of 18.3 MMcf per day in its first 30 days after connecting to a sales line.

maximize the drilling efficiency of our larger horizontal drilling rigs and reduce overall costs. We expect to continue running 3 operated horizontal rigs through the completion of this offering, increasing to 6 operated horizontal rigs by year end 2014. During 2014, we anticipate spudding a total of 73 gross (53 net) operated wells and expect to participate in 103 gross (17 net) non-operated wells, primarily with Antero Resources, Gulfport Energy, Chesapeake Energy and Magnum Hunter.

Midstream Agreements

We have contracted for firm gathering, processing and fractionation capacity for a significant portion of our operated acreage in the Rich Gas, Condensate and Rich Condensate Windows of the Utica Core Area with Blue Racer, a joint venture between Dominion Resources, Inc. and Caiman Energy II, LLC. Additionally, we have contracted with Eureka Hunter for firm gathering services on a significant portion of our operated acreage in the Dry Gas Window of the Utica Core Area. Neither of these gas processing agreements require us to make minimum volume deliveries or shortfall payments.

We work closely with our midstream partners to coordinate our drilling and completion schedule with their well hook up and facility construction schedule to ensure sufficient capacity is available to minimize any delays in turning production into sales. Our non-operated production operated by Antero Resources is gathered and marketed by Antero Resources on our behalf and is currently being processed and fractionated through long-term contracts Antero Resources has with MarkWest Energy Partners.

The following table illustrates the committed gathering and processing volumes associated with our operated assets through 2018:


Firm Gathering and Processing Volumes
Year	Gathering (MMcf/d)		Cryogenic Processing (MMcf/d)
2014		155		55
2015		475		225
2016		700		400
2017		720		420
2018		660		360

While we believe we have contracted for sufficient firm gathering and cryogenic processing volumes to accommodate 100% of our projected Utica Shale proved production and a significant percentage of our projected Utica Shale non-proved production, that capacity may not be sufficient to handle all of our production. Additionally, although we intend to enter into firm transportation agreements with major pipelines in the near future as our production grows, we have not yet entered into any such agreements. We refer you to the risk factors on pages 28-29.

On March 7, 2014, we entered into a 20 year contract with Shell Chemical for the sale of ethane to Shell Chemical’s proposed Appalachian cracker project in Monaca, Pennsylvania. Under the terms of the contract, we would sell to Shell Chemical, at a minimum, all of our Must Recover Ethane (i.e., 30% of total recoverable ethane) at Blue Racer’s fractionation facility near Natrium, West Virginia. The agreement provides for Shell Chemical to make a positive election during 2015 to keep the supply agreement in effect. See risk factors on pages 28-30 of this prospectus.

Our Competitive Strengths

We have a number of competitive strengths that we believe will help us to successfully execute our business strategies, including:

•

Premier Acreage Positions in the Core of the Utica Shale and the Highly Liquids Rich Area of the Marcellus Shale. We own an extensive and substantially contiguous acreage position in two of the premier North American shale plays. We have an approximately 96,240 net acre position in the Utica Core Area concentrated in a region where the highest initial production rates have been reported. Based upon the production data for wells that we have drilled or participated in as well as the initial production rates of wells that have been publicly disclosed by other operators, we believe that our acreage is located within the most prolific and economic region of the Utica Core Area. Additionally, based on the results of our first 2 Marcellus Shale wells completed within our 25,740 net acre Marcellus Shale Project Area, we believe Marcellus Shale wells within this area will produce rich natural gas with a heat content of approximately 1,250-1,450 Btu, and a condensate yield of approximately 100-200 barrels per Mmcf of gas. Furthermore, we own approximately 131,070 net acres (which are approximately 85% held by production) outside of the Utica Core Area that may be prospective for the oil window of the Utica Shale representing upside potential.

•

Multi-Year Drilling Inventory. As of March 31, 2014, we had identified approximately 3,381 gross (863 net) horizontal drilling locations within the Utica Core Area and Our Marcellus Project Area. We have drilled or commenced drilling 75 of these gross wells as of March 31, 2014. We plan to spud or participate in 176 gross (69 net) wells in those areas during 2014, representing a 19-year drilling inventory, which we calculate by dividing gross remaining identified drilling locations by gross wells expected to be spud in the 2014 drilling plan. We operate approximately 81% of our net acreage and the substantially contiguous nature of our leasehold enables us to enhance our single well economics by efficiently creating pad sites to drill multiple wells at the most effective lateral lengths. In determining our drilling locations, we have laid out a drilling plan that assumes average lateral lengths of 6,000 feet and interlateral spacing of 750 feet between wells for our operated acreage in the Rich Gas, Condensate and Rich Condensate Windows of the Utica Core Area and Our Marcellus Project Area, and 1,000 feet between wells for our operated acreage in the Dry Gas Window of the Utica Core Area. These identified drilling locations are shown on the map on the inside cover of this prospectus. Operators are currently testing tighter spacing, and if our acreage can support tighter spacing, then we expect that our number of drilling locations would significantly increase. Additionally, we expect to add net locations to our inventory as we lease or acquire incremental acreage and establish drilling units on acreage that does not currently support a 6,000 foot lateral.

•

Expertise and Experience in Unconventional Resource Plays, Particularly the Appalachian Basin. We have assembled a strong executive and technical staff that has extensive experience in horizontal drilling, operating multi-rig development programs and using advanced drilling and completion technology, predominately in the Appalachian Basin. We have sought to hire personnel who we believe to be the best in their field not only with respect to technical expertise, but also specifically with direct experience in the Appalachian Basin and the Utica and Marcellus Shales. Several members of our executive management team have extensive experience managing the successful early entrance and development in emerging unconventional areas of the Appalachian Basin, having led these efforts at companies such as Cabot Oil & Gas, Rex Energy and Chesapeake Energy.

•

the Dry Gas Window of the Utica Core Area. Our non-operated production operated by Antero Resources is marketed and processed by Antero Resources on our behalf and is currently being processed and fractionated by MarkWest Energy Partners. Further, our acreage position is centered near the confluence of several interstate pipeline systems including Texas Eastern, Rockies Express, Dominion Transmission, Dominion East Ohio and Tennessee Gas. This location provides us with the opportunity to assemble a diversified strategy to sell our gas, both within the Appalachian Region, and in other areas including the Gulf Coast and Mid-West markets. Additionally, we have recently entered into a long-term agreement with Shell to sell a significant portion of our projected ethane production from our rich gas assets, pending construction of their ethane cracker facility, which we expect to realize a premium price compared to net prices currently available after deducting transportation costs. We believe this approach will offer us diversity of revenue streams and a unique ability to manage our basis risk through a combination of long-term firm transportation, short to medium-term firm sales agreements, and short-term spot gas sales to capture market fluctuations.

•

Well Capitalized Balance Sheet with Financial Flexibility. As of March 31, 2014, on a pro forma basis after giving effect to this offering, we would have had cash on hand of approximately $555.1 million. We believe this cash balance, along with our cash flows from operations and our projected borrowing availability under our revolving credit facility, will be sufficient to fund our capital expenditures and other obligations necessary to execute our business plan over the 2 year period following the completion of this offering. Additionally, we expect to maintain a commodity hedging program designed to mitigate volatility in commodity prices and to protect our expected future cash flows. We expect to enter into commodity derivative contracts such as collars and swaps on at least 50% of our projected proved developed reserves on a forward-looking basis for a period of 1 to 3 years.

•

Proven Management that is Highly Aligned with Stockholders. Our management team possesses extensive oil and natural gas acquisition and development expertise in shale plays, particularly within the Appalachian Basin, and will have a significant economic interest in us upon completion of this offering. Several members of our senior management team have significant experience managing public companies, which we believe benefits our stockholders. Management’s economic interest in us will initially be held in the form of incentive units issued by Eclipse Holdings and could increase following completion of this offering, without diluting public investors, if our stock price appreciates. See “Executive Compensation—Long-Term Incentive Compensation—Incentive Units” for a description of the incentive units. Management’s current ownership interest in Eclipse Holdings combined with its potential for increased ownership interest in Eclipse Holdings provides a strong incentive for management to grow the value of our company.

Our Business Strategy

Our goal is to create stockholder value by aggressively developing our asset base while generating industry-leading rates of return on our capital. We intend to pursue a number of steps to execute our strategy, including:

•

Aggressively Grow Production, Cash Flow and Reserves through the Economic Development of Our Drilling Inventory. We intend to aggressively develop our portfolio of identified drilling locations to maximize the present value of the substantial resource we have accumulated. Our management team has considerable experience managing large-scale drilling programs and is focused on growing production, cash flow and reserves in an economically efficient manner. We began to delineate our acreage position within the Utica Core Area and Our Marcellus Project Area in 2013. We are currently operating 3 horizontal rigs, and we expect to bring our total operated horizontal rig count to 6 by year end 2014. In 2014, we plan to invest $577.4 million in drilling and completion capital and plan to spud or participate in 176 gross (69 net) shale wells.

•

Enhance Returns by Optimizing Full-Cycle Economics of Our Production. We will continually monitor our drilling program in order to achieve the highest total returns on our portfolio of drilling opportunities. As the operator of approximately 81% of our net acreage in the Utica Core Area and Our Marcellus Project Area, we are able to manage: (i) the timing of a large portion of our capital spending, (ii) the well and completion design, and (iii) our midstream takeaway options. We will constantly seek to optimize our well economics through thorough and continuous analysis of our, and our non-operated partners’, well results and midstream plans. We believe that our current operated rig count, along with our participation in non-operated wells with at least 7 different operators in the Utica Core Area, has provided, and will continue to provide us with, a growing body of data which will allow us to further optimize our drilling and completion techniques and enhance well economics.

•

Maximize Wellhead Economics with Diversified and Opportunistic Midstream Options. We expect to produce considerable volumes of NGLs and condensate associated with our growing natural gas production. We have secured firm gathering, processing and fractionation capacity with our midstream partners to ensure we are able to meet our projected production volumes and cash flows, as well as entered into a long-term contract for the sale of our ethane production. Further, as our acreage position is centered near the confluence of several interstate pipeline systems including Texas Eastern, Rockies Express, Dominion Transmission, Dominion East Ohio and Tennessee Gas, we are assembling a diversified takeaway strategy to sell our gas, both within the Appalachian Region and in other areas including the Gulf Coast and Mid-West markets. We believe this approach will offer us diversity of revenue streams and a unique ability to manage our basis risk through a combination of long-term firm transportation, short to medium-term firm sales agreements, and short-term spot gas sales to capture market fluctuations.

•

Continue Growing Our Core Acreage Position through Leasing and Strategic Acquisitions. We intend to continue to identify and acquire additional acreage and producing assets in our core areas. Based on specific geological and technical analysis, we initially targeted and acquired 27,000 net acres in the Utica Core Area in 2011, and as of March 31, 2014, we have grown our position in the Utica Core Area to approximately 96,240 net acres. We believe our technical assessment of the most productive area within the Utica Shale has been validated by the highest initial production rates in the play and that our approximately 96,240 net acres are in the most prolific and economic part of the play. We will continue to pursue both large and small acreage acquisitions to add to our inventory and increase our number of operated drilling units.

Proved Reserves

As of December 31, 2013 and March 31, 2014, our estimated proved reserves were 78.5 Bcfe, or 13.1 MMBoe, and 109.6 Bcfe, or 18.3 MMBoe, respectively, based on reserve reports prepared by Netherland, Sewell & Associates, Inc., or NSAI, our independent petroleum engineers. As of December 31, 2013, our estimated proved reserves were approximately 67% natural gas, 15% NGLs and 18% oil, and approximately 57% were proved developed reserves. As of March 31, 2014, our estimated proved reserves were approximately 63% natural gas, 21% NGLs and 16% oil, and approximately 52% were proved developed reserves. The following table provides information regarding our proved reserves as of December 31, 2013 and March 31, 2014:


	Estimated Total Proved Reserves
	Oil (MMBbls)		NGLs (MMBbls)		Natural Gas (Bcf)		Total (Bcfe)		Total (MMBoe)		% Liquids			% Developed			PV-10⁽¹⁾ (in millions)
December 31, 2013		2.4		1.9		52.3		78.5		13.1		33.3	%		56.7	%	$	155.3
March 31, 2014		3.0		3.8		69.0		109.6		18.3		37.1	%		51.8	%	$	253.8

(1)

standardized measure in this regard. However, in connection with the closing of this offering, as a result of our corporate reorganization, we will be a corporation subject to federal income tax and our future income taxes will be dependent upon our future taxable income, and following our corporate reorganization our calculation of standardized measure would include such tax inputs. Neither PV-10 nor standardized measure represents an estimate of the fair market value of our oil and natural gas properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities.

Risk Factors

Investing in our common stock involves risks that include the speculative nature of oil and natural gas exploration; competition; volatile oil, natural gas and NGLs prices; and other material factors. For a discussion of these risks and other considerations that could negatively affect us, including risks related to this offering and our common stock, see “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements.”

Corporate Reorganization

Eclipse I was formed in January 2011 by members of our management team and the EnCap Funds. Eclipse Operating was formed in December 2010 by members of our management team for purposes of operating Eclipse I. Eclipse I formed Eclipse Resources Corporation on February 13, 2014.

Pursuant to the terms of a corporate reorganization that will be completed contemporaneously with, and conditioned upon, the completion of this offering, (i) Eclipse I will acquire all of the outstanding equity interests in Eclipse Operating, (ii) the EnCap Funds, the Management Funds and Management Holdco will exchange their equity interests in Eclipse I for similar equity interests in Eclipse Holdings, (iii) the EnCap Funds, which own all of the outstanding equity interests in Eclipse GP, LLC, the general partner of Eclipse I, will transfer such equity interests to Eclipse Holdings, and (iv) Eclipse Holdings will contribute its equity interests in Eclipse I and the outstanding equity interests in Eclipse GP, LLC, in exchange for shares of common stock of Eclipse Resources Corporation. As a result of these steps, Eclipse Resources Corporation will become a majority controlled direct subsidiary of Eclipse Holdings, and Eclipse I will become a direct subsidiary of Eclipse Resources Corporation. Investors in this offering will only receive, and this prospectus only describes the offering of, shares of common stock of Eclipse Resources Corporation.

The following diagrams indicate our ownership structure (i) prior to our corporate reorganization and (ii) after giving effect to our corporate reorganization and this offering (assuming no exercise of the underwriters’ option to purchase additional shares from the selling stockholders). See “Corporate Reorganization” for more information regarding our corporate reorganization.

Ownership Structure Prior to Our Corporate Reorganization

LOGO

(1)

The Management Funds include The Hulburt Family II Limited Partnership, CKH Partners II, L.P and Kirkwood Capital, L.P., which are controlled by Benjamin W. Hulburt, Christopher K. Hulburt and Thomas S. Liberatore, respectively.

(2)

Management Holdco is controlled by the board of managers of its general partner. The current members of the board of managers are Benjamin W. Hulburt, Christopher K. Hulburt, Thomas S. Liberatore and Matthew R. DeNezza. The foregoing individuals have equal ownership interests in the general partner.

Ownership Structure After Giving Effect to Our Corporate Reorganization and this Offering

LOGO

(1)

(2)

Our Principal Stockholders

Upon the completion of our corporate reorganization and this offering, Eclipse Holdings will directly own 129,700,000 shares of our common stock, representing approximately 81.1% of the outstanding shares of our common stock (or 125,155,000 shares of our common stock, representing approximately 78.2% of the outstanding shares of our common stock, if the underwriters exercise in full their option to purchase additional shares). Eclipse Holdings will be owned by the EnCap Funds, the Management Funds and Management Holdco upon the completion of our corporate reorganization. EnCap was formed in 1988 and provides private equity to independent oil and gas companies focused on exploration, production and midstream activities. Since its inception, EnCap has formed 17 institutional oil and gas investment funds with aggregate capital commitments of approximately $18 billion. See “Principal and Selling Stockholders” for more information regarding the ownership of our common stock by our principal and selling stockholders.

Emerging Growth Company Status

We are an “emerging growth company” as defined in the Jumpstart Our Business Startups Act, or 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 & analysis of financial condition and results of operations;

•

comply with any new requirements adopted by the Public Company Accounting Oversight Board, or 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 stockholder advisory votes on executive compensation as required by the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act; or

•

obtain stockholder 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 $700.0 million or more as of June 30);

•

the date on which we issue more than $1.0 billion of non-convertible debt over a 3-year period; or

•

the last day of the fiscal year following the 5^th 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, or 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.

Corporate Information

Our principal executive offices are located at 2121 Old Gatesburg Road, Suite 110, State College, Pennsylvania 16803, and our telephone number is (866) 590-2568. Our website is www.eclipseresources.com. We expect to make our periodic reports and other information filed with, or furnished to, the Securities and Exchange Commission, or 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. The information on, or otherwise accessible through, our website or any other website does not constitute a part of this prospectus.

The Offering

Shares of common stock offered by us

21,500,000 shares.

Shares of common stock offered by the selling stockholders

8,800,000 shares (or 13,345,000 shares, if the underwriters exercise in full their option to purchase additional shares).

Shares of common stock to be outstanding after the offering

160,000,000 shares.

Shares of common stock owned by Eclipse Holdings after the offering

Eclipse Holdings will directly own 129,700,000 shares of our common stock, representing approximately 81.1% of the outstanding shares of our common stock (or 125,155,000 shares, representing approximately 78.2% of the outstanding shares of our common stock, if the underwriters exercise in full their option to purchase additional shares).

Option to purchase additional shares

Use of proceeds

We expect to receive approximately $545.2 million of net proceeds 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 approximately $485.2 million of our net proceeds to fund our capital expenditure plan and approximately $60.0 million of our net proceeds to repay borrowings under our revolving credit facility.

We will not receive any proceeds from the sale of shares by the selling stockholders (including pursuant to the underwriters’ option to purchase additional shares). However, certain affiliates of the EnCap Funds and certain of our executive officers may indirectly receive proceeds from such sale of shares by the selling stockholders as a result of a distribution of proceeds by the selling stockholders to their respective limited partners, as applicable. See “Principal and Selling Stockholders.”

Dividend policy

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

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 have been approved to list our common stock on the New York Stock Exchange under the symbol “ECR.”

Selected Historical Consolidated and Unaudited Pro Forma Financial Data

The following table shows selected historical consolidated financial data of Eclipse I, our accounting predecessor, and the selected unaudited pro forma financial data of Eclipse Resources Corporation for the periods and as of the dates indicated. Our historical results are not necessarily indicative of future operating results. The selected financial data presented below is qualified in its entirety by reference to, and should be read in conjunction with, “Capitalization,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and related notes included elsewhere herein.

The selected historical consolidated financial data as of and for the years ended December 31, 2012 and 2013 are derived from the audited consolidated financial statements of Eclipse I included elsewhere in this prospectus. The selected historical statement of operations data for the three months ended March 31, 2013 and 2014 and the historical balance sheet data as of March 31, 2014 are derived from the unaudited consolidated financial statements of Eclipse I included elsewhere in this prospectus. The selected historical unaudited historical consolidated interim financial data has been prepared on a consistent basis with the audited consolidated financial statements of Eclipse I. In the opinion of management, such selected unaudited historical consolidated financial interim data reflects all adjustments (consisting of normal and recurring accruals) considered necessary to present our financial position for the periods presented. The results of operations for the interim periods are not necessarily indicative of the results that may be expected for the full year because of the impact of fluctuations in prices received from natural gas, NGLs and oil, natural production declines, the uncertainty of exploration and development drilling results and other factors.

The selected unaudited pro forma consolidated statements of operations data for the three months ended March 31, 2014 and for the year ended December 31, 2013 has been prepared to give pro forma effect to (i) the Oxford Acquisition; (ii) the corporate reorganization transactions described under “Corporate Reorganization;” and (iii) this offering and the application of our net proceeds from this offering as if they had been completed as of January 1, 2013. The selected unaudited pro forma consolidated balance sheet data as of March 31, 2014 has been prepared to give pro forma effect to those transactions (other than the Oxford Acquisition that occurred on June 26, 2013, and thus, is already included in our historical consolidated balance sheet) as if they had been completed as of March 31, 2014. These data are subject 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 unaudited pro forma consolidated 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 Oxford Acquisition, the corporate reorganization 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.


	Eclipse I						Eclipse I						Eclipse Resources Corporation
	Three Months Ended March 31,						Year Ended December 31,						Pro Forma Three Months Ended March 31,			Pro Forma Year Ended December 31,
	2014			2013			2013			2012			2014			2013
	(Unaudited)			(Unaudited)									(Unaudited)			(Unaudited)
(in thousands)
Statement of operations data:

REVENUES
Natural gas, NGLs and oil sales	$	24,788		$	288		$	12,935		$	370		$	24,788		$	20,638

Total revenues		24,788			288			12,935			370			24,788			20,638

OPERATING EXPENSES
Exploration		4,545			72			3,022			3,899			4,545			3,205
Lease operating		1,791			5			2,576			16			1,791			4,736
Transportation, gathering and compression		904			—			67			—			904			67
Production and ad valorem taxes		353			4			77			1			353			164
Depreciation, depletion and amortization		12,027			488			6,163			404			12,027			9,256
Impairments		—			—			2,081			793			—			2,081
General and administrative		8,394			1,483			21,276			4,425			8,394			23,808
Accretion expense		186			—			364			—			186			702
Gain on reduction of pension liability		(2,208	)		—			—			—			(2,208	)		—

Total operating expenses		25,992			2,052			35,626			9,538			25,992			44,019

Gain on sale of property		—			—			—			372			—			—

OPERATING LOSS		(1,204	)		(1,764	)		(22,691	)		(8,796	)		(1,204	)		(23,381	)

OTHER INCOME (EXPENSE)
Gain (loss) on derivative instruments		(3,611	)		—			—			—			(3,611	)		—
Interest income (expense), net		(13,636	)		5			(20,850	)		37			(13,603	)		(41,552	)

Total other income (expense), net		(17,247	)		5			(20,850	)		37			(17,214	)		(41,552	)

LOSS BEFORE INCOME TAXES		(18,451	)		(1,759	)		(43,541	)		(8,759	)		(18,418	)		(64,933	)

INCOME TAX BENEFIT		—			—			—			—			6,446			24,897


NET LOSS	$	(18,451	)	$	(1,759	)	$	(43,541	)	$	(8,759	)	$	(11,972	)	$	(40,036	)


Balance sheet data (at period end):
Cash and cash equivalents		27,328						109,509			27,057			555,142
Total property and equipment, net		1,144,907						1,018,084			106,253			1,146,910
Total assets		1,211,293						1,143,523			133,522			1,741,239
Total debt		432,230						389,247			—			412,230
Total partners’ / stockholders’ capital		698,354						667,971			126,704			1,189,811

Net cash provided by (used in):
Operating activities		104			232			15,250			(3,381	)
Investing activities		(151,140	)		(69,211	)		(897,086	)		(47,535	)
Financing activities		68,855			58,136			964,288			68,916

Summary Reserve, Production and Operating Data

Summary Reserve Data

The following table presents our estimated net proved natural gas, NGLs and oil reserves as of March 31, 2014, and December 31, 2013 and December 31, 2012, based on the proved reserve reports prepared by NSAI, our independent petroleum engineers, and such proved reserve reports have been prepared in accordance with the rules and regulations of the SEC. For oil and NGL volumes, the average West Texas Intermediate spot price of $98.43 per barrel for March 31, 2014, $96.91 per barrel for December 31, 2013 and $94.71 per barrel for December 31, 2012 has been adjusted by property group for quality, transportation fees, and regional price differentials. For gas volumes, the average Henry Hub spot price of $3.99 per MMBtu for March 31, 2014, $3.67 per MMBtu for December 31, 2013 and $2.76 per MMBtu for December 31, 2012 has been adjusted by property group for energy content, transportation fees, and regional price differentials. All of our proved reserves are located in the United States. Copies of the proved reserve reports as of March 31, 2014, December 31, 2013 and December 31, 2012 prepared by NSAI with respect to our properties are included as exhibits to the registration statement of which this prospectus forms a part. Our estimates of net proved reserves have not been filed with or included in reports to any federal authority or agency other than the SEC in connection with this offering.


	March 31,		December 31,
	2014		2013		2012
Proved Developed Reserves:
Natural Gas (MMcf)		34,216.0		27,880.3		1,289.6
NGLs (MBbls)		1,678.6		1,056.2		64.6
Oil (MBbls)		2,072.0		1,708.1		174.5

Combined (MMcfe)		56,719.6		44,466.6		2,724.0
Proved Undeveloped Reserves:
Natural Gas (MMcf)		34,742.8		24,464.2		1,666.6
NGLs (MBbls)		2,078.6		882.1		112.4
Oil (MBbls)		940.7		709.2		211.5

Combined (MMcfe)		52,858.2		34,012.0		3,610.1
Proved Reserves:
Natural Gas (MMcf)		68,958.8		52,344.5		2,956.1
NGLs (MBbls)		3,757.2		1,938.3		177.0
Oil (MBbls)		3,012.7		2,417.4		386.0

Combined (MMcfe)		109,577.8		78,478.6		6,334.2

Production and Price History

The following table sets forth information regarding net production of natural gas, NGLs and oil, and certain price and cost information for the periods indicated:


	Three Months Ended March 31,
	2014		2013
Total production volumes:
Natural gas (MMcf)		2,759.0		14.2
NGLs (MBbls)		9.0		—
Oil (MBbls)		108.0		2.6

Combined (MMcfe)		3,461.0		29.6
Average daily production volumes:
Natural gas (Mcf/d)		30,656		158
NGLs (Bbls/d)		100		—
Oil (Bbls/d)		1,200		28

Combined (Mcfe/d)		38,456		329
Volume weighted average realized prices:
Natural gas ($/Mcf)⁽¹⁾	$	5.06	$	3.68
NGLs ($/Bbl)		63.88		—
Oil ($/Bbl)		94.94		91.89

Combined ($/Mcfe)	$	7.16	$	9.73
Expenses (per Mcfe):
Lease operating	$	0.52	$	0.17
Production, severance and ad valorem taxes		0.10		0.12
Depletion, depreciation and amortization		3.48		16.48
General and administrative		2.43		50.11
Transportation, gathering and compression		0.26		—

(1)

Including the effects of commodity hedging, the average effective price for the three months ended March 31, 2014 would have been $3.75 per Mcf of gas. The total volume of gas associated with these hedges for the three months ended March 31, 2014 represented approximately 52% of our total sales volumes for the three months ended March 31, 2014. There were no commodity derivatives in place for the three months ended March 31, 2013.

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

We are involved in lawsuits challenging the validity of some of our leases, which if unfavorably resolved, may materially adversely affect our financial condition, business prospects and the value of our common stock.

Prior to the Oxford Acquisition, Oxford commenced a lawsuit on October 24, 2011 in the Common Pleas Court of Belmont County, Ohio against a lessor to enforce its rights to access and drill a well on the lease during the initial 5-year primary term of the lease. The lessor counterclaimed, alleging, among other things, that the challenged Oxford lease constituted a lease in perpetuity and, accordingly, should be deemed void and contrary to public policy in the State of Ohio. On October 4, 2013, the Belmont County trial court granted a motion for summary judgment in favor of the lessor and ruled that the lease is a “no term” perpetual lease and, as such, is void as a matter of Ohio law.

We have appealed the Belmont County trial court’s decision to the Ohio Court of Appeals for the Seventh Appellate District, arguing, among other things, that the Belmont County trial court erred in finding that our lease is a “no term” perpetual lease, by ruling that perpetual leases are void as a matter of Ohio law and by invalidating our leases. We cannot predict the outcome of this lawsuit or the amount of time and expense that will be required to resolve the lawsuit.

In addition, many of our other oil and gas leases in Ohio contain provisions identical or similar to those found in the challenged Oxford lease. Following the ruling of the Belmont County trial court and as of May 30, 2014, 3 other lessors filed lawsuits, or amended existing complaints in pending lawsuits, that remain outstanding against us to make allegations similar to those made by the lessor in the Belmont County case discussed above. These 3 lawsuits, together with the Belmont County case discussed above, affect approximately 346 gross (346 net) leasehold acres and were capitalized on our balance sheet as of March 31, 2014 at $1.8 million.

We have undertaken efforts to amend the other leases acquired within the Utica Core Area in the Oxford Acquisition to address the issues raised by the Belmont County trial court’s ruling. These efforts have resulted in modifications to leases covering approximately 27,750 net acres out of the approximately 47,240 net acres we believe may require modification to address the issues raised by the trial court while our appeal is pending; however, we cannot predict whether we will be able to obtain modifications of the leases covering the remaining 19,490 net acres to effectively resolve issues related to the Belmont County trial court’s ruling or the amount of time and expense that will be required to amend these leases.

In light of the foregoing, if the appeals court affirms the trial court ruling, and if other courts in Ohio adopt a similar interpretation of the provisions in other oil and gas leases we acquired in the Oxford Acquisition, other lessors may challenge the validity of such leases and those challenged leases may be declared void. As a result, our ability to execute our planned drilling program as described in this prospectus could be substantially diminished. In addition, lawsuits concerning the validity of our leases could divert the attention of management and resources in general from day-to-day operations. An unfavorable resolution could, therefore, have a material adverse effect on our financial condition, business prospects and the value of our common stock. For further information regarding this lawsuit, please see “Business—Legal Proceedings.”

The information regarding third party wells included in this prospectus may not be reliable, and we may not be able to achieve similar results for our wells located near to those third party wells.

We have included in this prospectus publicly disclosed data related to initial production rates, liquids yields and other production and operating data for third party wells that have been drilled and completed on or near our acreage. This information was gathered from government databases, press releases and other publicly available sources as well as internally with respect to those wells in which we have an interest and access to such information. Other than a limited review with respect to those wells in which we own an interest, we have not undertaken any investigation to confirm the accuracy, completeness or reliability of this information or the methodology used by the third parties to determine this information, and such information may be materially incorrect, incomplete or unreliable. Furthermore, we obtained the information from multiple sources, and those sources may have been using inconsistent or incompatible methodologies. If the third party well information we have included in this prospectus is incorrect, incomplete or unreliable, then it may be inappropriate to expect wells that we drill and operate in our nearby acreage to perform at or near the levels indicated in the third party well information. Even if such information is reliable, drilling for oil and gas wells is a highly speculative undertaking, and there are many factors that affect the performance and yield of oil and gas wells, including decisions that we, our operating partners or other operators make regarding the drilling process, the geological features underlying the specific well, and other factors that are beyond our control. Moreover, initial production rates and liquids yields reported by us or other operators may not be indicative of future or long-term production rates and reserve potential. Accordingly, some or all of these factors, or factors that we do not or cannot anticipate, may cause the performance and yields of our wells to be substantially inferior to the actual or implied performance and yields of the nearby third party wells. As a result, our business, financial condition and results of operations could be substantially negatively affected.

Our operating history is limited and as a result there is only limited historical financial and operating information available upon which to base your evaluation of our performance. Moreover, the historical financial and operating information included in this prospectus may not be indicative of our future financial performance. Additionally, the historical financial and operating data relating to the Oxford Acquisition included in this prospectus is largely derived from the conventional, vertical drilling of natural gas and oil wells, while we expect our post-acquisition strategy to focus on the horizontal drilling of natural gas and oil wells. Moreover, we plan to expand our drilling operations significantly in the near future. We have yet to generate positive earnings from our current business strategy and there can be no assurance that we will ever operate profitably. If our current business strategy is not successful, and we are not able to operate profitably, investors may lose some or all of their investment.

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 additives under pressure into target geological formations to fracture the surrounding rock and stimulate production. We regularly use hydraulic fracturing as part of our operations. Presently, hydraulic fracturing is regulated primarily at the state level, typically by state oil and natural gas commissions and similar agencies. However, with increased public concern regarding the potential for hydraulic fracturing to adversely affect drinking water supplies, proposals have been made to enact federal, state and local legislation and regulations that would increase the regulatory burden imposed on hydraulic fracturing. For example, the U.S. Environmental Protection Agency, or the EPA, has asserted federal regulatory authority over certain hydraulic

fracturing activities involving diesel under the Safe Drinking Water Act, issued new air emission controls for oil and natural gas production and natural gas processing operations, initiated a study to examine the potential impacts of hydraulic fracturing on drinking water resources, and intends to propose standards for wastewater discharges from oil and gas extraction activities and regulations that would require companies to disclose information regarding the in hydraulic fracturing. The U.S. Congress continues to consider amending the Safe Drinking Water Act to remove the exemption for hydraulic fracturing activities and to require disclosure of additives constituents of fluids used in the fracturing process. The Department of the Interior proposed a rule that would regulate hydraulic fracturing activities on federal lands.

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 for us to perform fracturing. Any such regulations limiting or prohibiting hydraulic fracturing could reduce our 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.

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

Hydrocarbon windows, phases or type curve areas have an inherent degree of variability and may change over time, and as a result, the available well data with respect to such windows, phases and type curve areas may not be indicative of the actual hydrocarbon composition for the windows, phases or type curve areas.

Based upon the well data available to us, we have grouped the publicly disclosed Utica Shale wells within the Utica Core Area into several distinct hydrocarbon windows, phases or type curve areas in an effort to better understand the thermal maturation variability within the Utica Core Area. However, there is an inherent degree of variability within such hydrocarbon windows, phases or type curve areas. Additionally, the well data we have utilized is predominantly based upon initial production rate, Btu content, natural gas yields and condensate

yields, which may change over time. As a result, the well data with respect to the windows, phases and type curve areas within the Utica Core Area may not be indicative of the actual hydrocarbon composition for the windows, phases or type curve areas, or may not be the hydrocarbon composition of the windows, phases or type curve areas at the time we drill. Due to such factors, the performance, Btu content and NGLs and/or condensate yields of our wells may be substantially less than we anticipate or substantially less than performance and yields of other operators in the Utica Core Area, which may materially adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.

Natural gas, NGLs 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, NGLs and oil production 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 markets have been volatile. These markets 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, but are not limited to, 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, foreign oil and refined products;

•

the price and quantity of exported domestic crude oil, natural gas, including liquefied natural gas, NGLs and refined products;

•

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;

•

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, NGLs, oil and alternative fuels;

•

localized and global supply and demand fundamentals and transportation availability;

•

adverse or severe weather conditions and other natural disasters;

•

technological advances affecting energy consumption and production; and

•

domestic, local and foreign governmental regulation and taxes.

In addition, substantially all of our natural gas production and oil production is sold to purchasers under contracts with market-based prices based on New York Mercantile Exchange (“NYMEX”) Henry Hub prices and

West Texas Intermediate (“WTI”) prices, respectively. The actual prices realized from the sale of natural gas and oil differ from the quoted NYMEX Henry Hub and WTI prices as a result of location differentials. Location differentials to NYMEX Henry Hub and WTI prices, also known as basis differential, result from variances in regional natural gas and oil prices as compared to NYMEX Henry Hub and WTI prices due to regional supply and demand factors. We may experience differentials to NYMEX Henry Hub and WTI prices in the future, which may be material and could reduce the price we receive for these products relative to these benchmarks.

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, or at all, which could lead to a decline in our reserves as existing reserves are depleted. Lower commodity prices and negative differentials could also cause a significant portion of our development and exploration projects to become uneconomic, which may result in our having to make significant downward adjustments to our reserves. As a result, a substantial or extended decline in commodity prices or an increase in our negative differentials may materially 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, or at all, which could lead to a decline in our oil and natural gas reserves.

The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures for the development and acquisition of oil and natural gas reserves. We expect to fund our capital expenditures in 2014 with cash on hand, cash generated by our operations, borrowings under our revolving credit facility and a portion of our net proceeds from this offering. 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, NGLs and oil prices and differentials, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments. A reduction in realized natural gas, NGLs or oil prices from current levels may result in a decrease in our actual capital expenditures, which would negatively impact our ability to grow production. 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, without limitation, the following:

•

our proved reserves;

•

the volumes and types of hydrocarbons we are able to produce from existing and future wells;

•

the prices at which our production is sold;

•

our ability to acquire, locate and develop new reserves;

•

the levels of our operating expenses; and

•

our ability to borrow under our revolving credit facility and issue additional debt and equity securities.

If our revenues or the borrowing base under our revolving credit facility decrease as a result of lower natural gas, NGLs or oil prices, operating difficulties, declines in reserves or for any other reason, we 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 borrowings under our revolving credit facility are insufficient 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 the Utica Core Area, which is a new and emerging play, and are also an early entrant into the portion of the Marcellus Shale underlying Our Marcellus Project Area. As a result, our expected well results in these areas are uncertain, and the value of our undeveloped acreage will decline if well results are unsuccessful.

Our expected well results in the Utica Core Area and Our Marcellus Project Area are more uncertain than well results in areas that are more developed and have a greater number of producing wells. As a result, our cost of drilling, completing and operating wells in the Utica Core Area and Our Marcellus Project Area may be higher than initially expected, the ultimate production and reserves from these wells may be lower than initially expected and the value of our undeveloped acreage may decline. 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.

Initial production rates may not be a reliable or accurate predictor of ultimate well recoveries, and initial production rates may not be directly correlated to completed well lateral lengths.

We have shown initial production rates for publicly available Utica and Marcellus Shale wells to demonstrate the apparent relative strength or weakness of certain wells in the Utica and Marcellus Shales in our project areas. While we believe that the presentation of these initial production rates can provide a useful tool in evaluating the early stage performance of these wells for comparative analysis, in many cases initial production rates may not be a reliable or accurate predictor of ultimate well recoveries, which require significantly more in depth analysis, including but not limited to, an analysis of the production over an extended period. Initial production rates can also vary across wells due to several variables such as the choke size being utilized on the well, the lack of compression, the time period measured, or natural gas line pressures. Additionally, we have shown normalized initial production rates for several Utica Shale wells which have adjusted the reported initial production rate for these wells proportionate to the difference between their actual complete lateral length and a 6,000’ complete lateral length. While we believe the presentation of this information can provide the ability to compare wells without regard to the varying actual completed lateral length of the wells we have presented, there may not be a direct correlation of initial production rates to the completed lateral length.

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, other oil and gas exploration and production companies and our service providers. Risks that we face while drilling include, but are not limited to, the following:

•

drilling wells that are significantly longer and/or deeper than more conventional 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.

Drilling for and producing natural gas, NGLs and oil 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 production or that we will not recover all or any portion of our investment in such wells.

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, see “Business—Oil and Natural Gas Data.” 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, which could materially reduce our borrowing capacity. 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, without limitation, the following:

•

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 and processing facilities or delays in construction of gathering and processing facilities;

•

lack of available capacity on interconnecting transmission pipelines;

•

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;

•

terrorist (including eco-terrorist) attacks targeting natural gas and oil related facilities and infrastructure;

•

declines in natural gas, NGLs and oil prices;

•

limited availability of financing at acceptable terms;

•

title problems and well permit objections from coal operators; 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 have incurred losses from operations since our inception and may do so in the future.

We incurred a net loss of $8.8 million for the year ended December 31, 2012, a net loss of $43.5 million for the year ended December 31, 2013 and a net loss of $18.4 million for the three months ended March 31, 2014. Our development of and participation in an increasingly larger number of prospects has required, and will continue to require, substantial capital expenditures. The uncertainty and factors described throughout this “Risk Factors” section may impede our ability to economically find, develop and acquire oil and natural gas reserves. As a result, we may not be able to achieve or sustain profitability or positive cash flows from operating activities in the future, which could adversely affect the trading price of our common stock.

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 our revolving credit facility and our senior unsecured notes, depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and 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 when due.

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, raise additional capital or restructure or refinance indebtedness. Our ability to raise additional capital or 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 revolving credit facility and the indenture governing our senior unsecured notes currently restrict our ability to dispose of assets and our use of the proceeds from any 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.

As of March 31, 2014, the initial borrowing base under our revolving credit facility was $50.0 million with $20.0 million drawn at a weighted average interest rate of 1.99%. As of May 1, 2014, our borrowing base was increased to $100 million, of which $60 million was drawn. Our next scheduled borrowing base redetermination is expected to occur on July 1, 2014. In the future, we may not be able to access adequate funding under our revolving credit facility as a result of a decrease in borrowing base due to the issuance of new indebtedness, the outcome of a subsequent borrowing base redetermination, unwillingness of the lenders to increase their aggregate commitment up to an increased borrowing base amount or an unwillingness or inability on the part of one or more lenders to meet their funding obligations and the inability of other lenders to provide additional funding to cover each 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.

Our producing properties are concentrated in the Appalachian Basin, which makes us vulnerable to risks associated with operating in one major geographic area.

Our producing properties are geographically concentrated in the Appalachian Basin. At March 31, 2014, all of our total estimated proved reserves were attributable to properties located in this area. As a result of this

concentration, 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, weather related conditions or interruption of the processing or transportation of natural gas, NGLs or oil. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations. In addition, a number of areas within the Appalachian Basin have historically been subject to mining operations, the existence of which could require coordination to avoid adverse impacts as a result of drilling and mining in close proximity. These restrictions on our operations, and any similar restrictions, can cause delays or interruptions or can prevent us from executing our business strategy, which could have a material adverse effect on our financial condition and results of operations.

Due to the concentrated nature of our portfolio of natural gas and oil properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties.

We own non-operating interests in properties developed and operated by third parties, and as a result, we are unable to control the operation and profitability of such properties.

We frequently participate as a non-operator in the drilling and completion of wells with third parties that exercise exclusive control over such operations. As a non-operator participant, we rely on the third party operating company to successfully operate these properties pursuant to joint operating agreements and other similar contractual arrangements.

As a non-operator participant in these operations, we may not be able to maximize the value associated with these properties in the manner we believe appropriate, or at all. For example, we cannot control the success of drilling and development activities on properties operated by third parties, which depend on a number of factors under the control of a third party operator, including such operator’s determinations with respect to, among other things, the nature and timing of drilling and operational activities, the timing and amount of capital expenditures and the selection of suitable technology. In addition, the third party operator’s operational expertise and financial resources and ability to gain the approval of other participants in drilling wells will impact the timing and potential success of our drilling and development activities in a manner that we are unable to control. The failure of an operator of our wells to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in ways that are favorable to us could reduce our production and revenues, negatively impact our liquidity and cause us to spend capital in excess of our current plans, and have a material adverse effect on our financial condition and results of operations.

Our existing providers of gas gathering, processing and fractionation capacity may not be able to provide to us sufficient capacity for our production from the Utica Core Area, and as a result, we may be required to find alternative markets and gathering, processing or fractionation arrangements for our production from the Utica Core Area, which alternative arrangements may not be available on favorable terms, or at all.

A significant portion of our Utica Core Area acreage position is dedicated to long-term firm gas gathering, processing and fractionation agreements with primary terms of approximately 15 years. These agreements give us priority service and capacity over non-firm parties that wish to utilize the gas processing and fractionation plants and gas gathering system. As a result of such dedications, a significant portion of our operated acreage in the Rich Gas, Condensate and Rich Condensate Windows of the Utica Core Area is committed to Blue Racer for gathering, processing and fractionation. Additionally, a significant portion of our operated acreage in the Dry Gas Window of the Utica Core Area is committed to Eureka Hunter for gathering. While we believe we have reserved sufficient capacity at these plants and on such systems to gather, process and fractionate all of our projected production associated with our proved resources and a significant portion of our projected production from the Utica Core Area, that capacity may not be sufficient to handle all of our production or that the plants and systems will not experience significant mechanical problems or delays in construction or become unavailable to us due to

unforeseen circumstances. As a result, we may be required to find alternative markets and gathering, processing or fractionation arrangements for our production from the Utica Core Area that is committed under these agreements, and such alternative arrangements may only be available on less favorable terms, or not at all.

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, resulting in substantial discounts in the price received by producers. Although additional Appalachian Basin takeaway capacity has been added in 2012 and 2013 and several new projects to further expand this capacity have been announced, there may not be sufficient capacity to keep pace with the increased production caused by accelerated drilling in the basin. We expect that a significant portion of our production from the Utica and Marcellus Shales will be transported on pipelines that experience a negative differential to NYMEX Henry Hub prices. If we are unable to secure firm pipeline transportation capacity on major pipelines that are in existence or under construction in our operating area to accommodate our growing production, it could have a material adverse effect on our financial condition and results of operation.

We currently do not have agreements with providers of gas gathering, processing or fractionation capacity with respect to our production from Our Marcellus Project Area, and we may not be able to enter into such agreements on favorable terms, or at all.

We have not entered into any gas gathering, processing or fractionation agreements with respect to our production from Our Marcellus Project Area. We may not be able to enter into any such agreements on favorable terms, or at all. Without such agreements, we may not receive priority service or capacity over third parties that utilize the same gas processing and fractionation plants and gas gathering systems. Our inability to obtain sufficient gas gathering, processing and fractionation capacity for our production from Our Marcellus Project Area could negatively impact our cash flows, financial condition and results of operations and reduce the overall value of our assets within this area.

Insufficient processing or takeaway capacity in the Appalachian Basin could cause significant fluctuations in our realized natural gas, NGLs and oil prices.

The Appalachian Basin natural gas business environment has historically been characterized by periods in which production has surpassed local takeaway capacity, resulting in substantial discounts in the price received by producers such as us. We expect that a significant portion of our production from the Utica Core Area and Our Marcellus Project Area will be transported on pipelines that may consistently or periodically experience a negative differential to NYMEX Henry Hub prices.

We do not currently have arrangements for firm pipeline transportation capacity for all of our expected production. If we are unable to secure additional gathering and compression capacity and long-term firm takeaway capacity on major pipelines that are in existence or currently under construction in our core operating area to accommodate our growing production and to manage basis differentials, it could have a material adverse effect on our financial condition and results of operations.

Oil and condensate produced in the Appalachian Basin has increased substantially and is likely to continue to increase for the foreseeable future. There is limited takeaway capacity for these products and we anticipate sales of these products to occur at a discount to the benchmark WTI price. If we are unable to secure transportation for these products it could have a materials adverse effect on our financial condition and results of operations.

We currently are and in the future expect to be party to contracts with third parties that include contractual minimums.

We are currently party to and expect to continue to be party to service contracts with drilling rig companies that require us to make shortfall payments to such companies if our actual activity level falls below specified contractual minimum activity levels. Moreover, in the future, we expect to enter into service contracts, such as firm pipeline transportation contracts with companies owning interstate pipelines, that may require us to make shortfall payments if our actual throughput falls below specified contractual minimum volumes. We can provide no assurance that our activity levels will be sufficient to satisfy the minimum requirements under our drilling rig contracts or that our future volumes will be sufficient to satisfy the minimum requirements under any such firm transportation contracts. If we fail to satisfy the minimum activity levels or throughput requirements associated with such contracts, we would be obligated to make shortfall payments to our counterparties based on the difference between our actual activity levels and throughput volumes, respectively, and the contract minimums in each case. These differences and the associated shortfall payments could be significant and we may not be able to generate sufficient cash to cover those obligations, which may require us to reduce or delay our planned investments and capital expenditures or seek alternative means of financing.

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

Our revolving credit facility contains a number of significant covenants, including restrictive covenants that may limit our ability to, among other things:

•

incur additional indebtedness;

•

sell assets;

•

make loans to others;

•

make investments;

•

enter into joint ventures;

•

enter into mergers;

•

make payments, directly or indirectly, to purchase or otherwise retire our equity interests;

•

hedge future production or interest rates;

•

incur certain lease obligations;

•

incur liens;

•

modify the nature of our business or engage in international operations; and

•

pay dividends or make distributions.

The indenture governing our senior unsecured notes contains similar restrictive covenants. In addition, our revolving credit facility requires us to maintain certain financial ratios or to reduce our indebtedness if we are unable to comply with such ratios. These restrictions, together with those in the indenture governing our senior unsecured notes, may limit our ability to obtain future financings to withstand a future downturn in our business or the economy in general, or to otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants under our revolving credit facility and our indenture governing our senior unsecured notes impose on us.

A breach of any covenant in either our revolving credit facility or the indenture governing our senior unsecured notes would result in a default under the applicable agreement after any applicable grace periods. A default, if not waived or cured, could result in acceleration of the indebtedness outstanding under the relevant agreement and in a default with respect to, and an acceleration of, the indebtedness outstanding under other debt

agreements. 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 obtain sufficient capital to refinance such indebtedness. Even if a refinancing were available, it may not be on terms that are acceptable to us. Moreover, an increased interest rate is also payable in connection with a default under our revolving credit facility and certain payment defaults under our senior unsecured notes.

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

Our revolving credit facility limits the amounts we can borrow up to the lesser of a specified maximum borrowing base amount or the aggregate amount of lender commitments. The lenders, in their sole discretion, determine a borrowing base on a quarterly basis (until April 1, 2015, at which time such determinations will convert to a semi-annual basis) based upon the loan value assigned to the proved reserves attributable to our oil and gas properties evaluated in our most recent reserve report(s). Our lenders may further request two additional unscheduled borrowing base redeterminations during each calendar year. Any increase in the borrowing base requires the consent of the lenders holding 95.0% (or 100.0% if there are fewer than 3 lenders at the time of determination) of the commitments (provided that no lender’s commitment may increase without its consent). Distinct from determinations of a borrowing base, each lender, in its sole discretion, determines the maximum amount of loans it will commit to make under the revolving credit facility based, in part, on general economic considerations and its prevailing lending policies. Outstanding borrowings in excess of the lesser of the specified maximum borrowing base amount or the prevailing aggregate lender commitment must be repaid. If we fail to repay such excess borrowings on a timely basis, we must provide additional oil and gas properties as collateral to the extent necessary to eliminate the deficiency. As of March 31, 2014, the initial borrowing base under our revolving credit facility was $50.0 million, of which $20.0 million was drawn at a weighted average interest rate of 1.99%. As of May 1, 2014, our borrowing base was increased to $100 million, of which $60 million was drawn. Our next scheduled borrowing base redetermination is expected to occur on July 1, 2014.

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 oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including, without limitation, 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 oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.

Actual future production, natural gas and oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and 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 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 plays, such as the Utica Core Area and Our Marcellus Project Area, where we predominately operate, 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 production is from wells that have been operational for less than one year, and as estimated reserves vary substantially from well to well, estimated reserves may not be correlated to perforated lateral length or completion technique. Furthermore, the lack of operational history for horizontal wells in the Utica Core Area or Our Marcellus Project Area may also contribute to the inaccuracy of future estimates of reserves and could result in our failing to achieve expected results in the play. A material and adverse variance of actual production, revenues and expenditures from those underlying reserve estimates or management expectations would have a material adverse effect on our business, financial condition, results of operations and cash flows.

Our gross 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 capital that we expect to 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 ability to drill and develop these locations depends on a number of uncertainties, including natural gas, NGLs and oil prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, topographical constraints, lease expirations, the ability to form units, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, governmental regulation, the ability to pool or unitize our acreage with acreage leased to other operators and 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, some 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 March 31, 2014, we had approximately 3,381 gross (863 net) 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, see “Business—Our Company.”

We have acreage that we must commence operations upon before lease expiration 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 primary term of 5 years, after which they expire unless, prior to expiration, we commence operations within the spacing units covering the undeveloped acres. As of March 31, 2014, we had leases representing approximately 1,603 gross (1,603 net) undeveloped acres scheduled to expire in 2014, 2,731 gross (2,724 net) undeveloped acres scheduled to expire in 2015, 20,093 gross (5,678 net) undeveloped acres scheduled to expire in 2016, 44,018 gross (30,423 net) undeveloped acres scheduled to expire in 2017, and 28,788 gross (19,527 net) 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 create units larger than the leases currently permit, which may make it more difficult to hold our leases by production or optimally develop our leasehold position. 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. In addition, in order to hold our current leases scheduled to expire in 2014 and 2015, we will need to operate at least a one-rig program. 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 flows and income, are highly dependent on successfully developing our undeveloped leasehold acreage and the loss of any leases could materially 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, 2012, December 31, 2013 and March 31, 2014, 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 natural gas, NGLs and oil;

•

actual cost of development and production expenditures;

•

the effect of derivative transactions;

•

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 partnership, 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 our partners. 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 execute a lease agreement with payment subject to title verification. In most cases, we incur the expense of retaining lawyers, title abstractors or landmen 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 its 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, 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 could suffer a financial loss or impairment of our assets.

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 March 31, 2014, approximately 48% of our total estimated proved reserves were classified as proved undeveloped. Our approximately 53 Bcfe of estimated proved undeveloped reserves will require an estimated $82.2 million of development capital over the next 5 years. 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 PV-10 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.

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 oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Unless we successfully conduct ongoing development and exploration activities or continually acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Our future oil and 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 and oil, we may enter into derivative instrument contracts for a significant portion of our natural gas,

NGLs and oil production, including fixed-price swaps. As of March 31, 2014, we had entered into swap contracts through December 31, 2015 covering a total of approximately 13.4 Bcf of our projected natural gas production at a weighted average price of $4.13 per Mcf. In addition, we entered into natural gas put spread contracts through December 31, 2014 covering approximately 4.3 Bcf of our projected natural gas production with strike prices of $4.50 per Mcf for the purchased put and $4.00 per Mcf for the sold put. Accordingly, our 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. 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 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 ($9.5 million at March 31, 2014) and the sale of our natural gas and oil production ($20.9 million in receivables at March 31, 2014). 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. The largest purchaser of our operated natural gas and oil during the three months ended March 31, 2014 purchased approximately 40% of our operated production. We do not require our customers to post collateral. 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.

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

Our operations are subject to various federal, state and local governmental regulations. Matters subject to regulation include wastewater disposal, the spacing of wells, unitization and pooling of properties and taxation. In addition, the production, handling, storage, transportation, remediation, emission and disposal of oil and

natural gas, by-products thereof and other substances and materials produced or used in connection with oil and natural gas operations are subject to regulation under federal, state and local laws and regulations, primarily relating to protection of human health and the environment. Failure to comply with these laws, regulations and permits may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, the imposition of stricter conditions on or revocation of permits, the issuance of injunctions limiting or preventing some or all of our operations, delays in granting permits and cancellation of leases. Moreover, these laws and regulations have continually imposed increasingly strict requirements for water and air pollution control and solid waste management. Significant expenditures may be required to comply with governmental laws and regulations applicable to us. We believe the trend of more expansive and stricter environmental legislation and regulations will continue for the foreseeable future. Please read “Business—Regulation of the Oil and Natural Gas Industry” and “Business—Regulation of Environmental and Occupational Safety and Health Matters” for a description of the laws and regulations that affect us.

We make assumptions and develop expectations about possible expenditures based on current laws and regulations and current interpretations of those laws and regulations. If the interpretation of laws or regulations, or the laws and regulations themselves, change, our assumptions may change, new capital costs may be incurred to comply with such changes. In addition, new laws and regulations might adversely affect our operations and activities, including drilling, processing, storage and transportation, as well as waste management and air emissions.

Our operations may be exposed to significant delays, costs and liabilities as a result of environmental, health and safety requirements applicable to our business activities.

There is inherent risk of the incurrence of environmental costs and liabilities in our business, some of which may be material, due to the handling of our products as they are gathered, transported, processed and stored, air emissions related to our operations, historical industry operations, and water and waste disposal practices. Joint and several strict liability may be incurred without regard to fault under some environmental laws and regulations, including the Comprehensive Environmental Response, Compensation, and Liability Act, Resource Conservation and Recovery Act and analogous state laws, for the remediation of contaminated areas and in connection with spills or releases of natural gas, oil and wastes on, under, or from our properties and facilities. Private parties may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage arising from our operations. Some sites at which we operate may be located near current or former third party oil and natural gas operations or facilities, and there is a risk that contamination has migrated from those sites to ours. In addition, increasingly strict laws, regulations and enforcement policies could materially increase our compliance costs and the cost of any remediation that may become necessary. Our insurance may not cover all environmental risks and costs or may not provide sufficient coverage if an environmental claim is made against us.

We may be held responsible for all liabilities associated with the environmental condition of our facilities and assets, whether acquired or developed, regardless of when the liabilities arose and whether they are known or unknown. In connection with acquisitions and divestitures, we could acquire, or be required to provide indemnification against, environmental liabilities that could expose us to material losses, which may not be covered by insurance. In addition, the steps we could be required to take to bring facilities into compliance could be prohibitively expensive, and we might be required to shut down, divest or alter the operation of those facilities, which might cause us to incur losses.

Oil and natural gas producers’ operations, especially those using hydraulic fracturing, are substantially dependent on the availability of water and disposal options. Restrictions on the ability to obtain water or dispose of wastewater 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.

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 Clean Water Act, or the CWA, imposes restrictions and strict controls regarding the discharge of produced waters and other natural gas and oil waste 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. 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 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.

In recent years, federal, state and local governments have taken steps to reduce emissions of greenhouse gases, or GHGs. The EPA has finalized a series of GHG monitoring, reporting and emissions control rules for oil and natural gas industry, and the U.S. Congress has, from time to time, considered adopting legislation to reduce emissions. Almost one-half of the states have already taken measures to reduce emissions of GHGs primarily through the development of GHG emission inventories and/or regional GHG cap-and-trade programs. While we are subject to certain federal GHG monitoring and reporting requirements, our operations currently are not adversely impacted by existing federal, state and local climate change initiatives.

The costs that may be associated with the impacts of climate change 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, and the demand for and consumption of our products and services (due to changes in both costs and weather patterns). If we are unable to recover or pass through a significant level of our costs related to complying with climate change regulatory requirements imposed on us, it could have a material adverse effect on our results of operations and financial condition. To the extent financial markets view climate change and GHG emissions as a financial risk, this could negatively impact our cost of and access to capital. At this time, however, it is not possible to estimate how future laws or regulations or climatic changes may impact our business.

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

Our oil and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and 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 or river contamination;

•

abnormally pressured formations;

•

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

•

fires, explosions and ruptures of pipelines or processing facilities;

•

personal injuries and death;

•

natural disasters; and

•

terrorist (including eco-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 or all of the 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 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 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.

We have made asset and business acquisitions in the past and we may continue to make acquisitions of assets or businesses in the future 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 depends on our ability to integrate the acquired business effectively into our existing operations. The process of integrating acquired businesses may involve difficulties that require a disproportionate amount of our managerial and financial resources to resolve. For example, we recently acquired Oxford in June 2013, and following the completion of the acquisition, we have dedicated significant managerial and financial resources to update the informal and incomplete legal, financial, accounting and business records previously in place at Oxford to substantiate transactions undertaken by Oxford prior to the acquisition. In addition, we have expended significant resources, including the time and attention of our management, on integrating Oxford’s pre-existing operations, personnel and assets into our business plan.

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 successfully the acquired businesses and assets into our existing operations or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations.

In addition, our revolving credit facility and the indenture governing our senior unsecured notes impose certain limitations on our ability to enter into mergers or combination transactions and to make investments. Our revolving credit facility and the indenture governing our senior unsecured notes also limit our ability to incur certain indebtedness and liens, which could limit our ability to engage in acquisitions of businesses.

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

We have historically acquired assets and businesses that we feel complement our assets and business and may continue to do so in the future. The successful acquisition of producing properties requires an assessment of several factors, including:

•

recoverable reserves;

•

future natural gas, NGLs 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.

Market conditions or operational impediments may hinder our access to natural gas, NGLs or oil markets or delay our production.

Market conditions or the unavailability of satisfactory natural gas, NGLs or oil transportation 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 availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. Because many of our operations are in an emerging play, much of this infrastructure is currently being built or is yet to be built, and we cannot assure you that it will be built on time or at all. Our failure to obtain such services on acceptable terms and concurrent with the completion of our wells 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, NGLs 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. 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 deliver the products to market.

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. Some 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.

Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market natural gas, NGLs and oil 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, NGLs and oil 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 and oil 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 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 past success of our senior management with developing public natural gas and oil enterprises, and the expertise of our senior management in the acquisition, exploration and development of unconventional natural gas and oil properties does not guarantee our success or profitability.

As described in this prospectus, most of our executive officers and other key personnel, including our Chairman, President and Chief Executive Officer, Benjamin W. Hulburt, our Executive Vice President and Chief Operating Officer, Thomas S. Libertore, and our Executive Vice President, Secretary and General Counsel, Christopher K. Hulburt, have substantial past experience in the acquisition, exploration and development of unconventional natural gas and oil properties, including experience at Rex Energy, Cabot Oil & Gas, Chesapeake Energy and Stone Energy. See “Management.” However, the past experience and success of our executive officers and other key personnel with respect to previous endeavors in the natural gas and oil industry is not a guarantee of our future success or profitability.

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, including Benjamin W. Hulburt, our Chairman, President and Chief Executive Officer, Matthew R. DeNezza, our Executive Vice President and Chief Financial Officer, Thomas Liberatore, our Executive Vice President and Chief Operating Officer, and Christopher K. Hulburt, our Executive Vice President, Secretary and General Counsel, 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 since our inception in January 2011, including through the acquisition of Oxford in 2013. 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.

Seasonal weather conditions and regulations intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in the areas where we operate.

Natural gas and oil operations in our operating areas can be adversely affected by seasonal weather conditions and regulations designed to protect certain species of wildlife. For example, we must comply with state and federal regulations aimed at protecting the Indiana bat (Myotis soldalis), which has been listed as an endangered species by both federal and state law, and those regulations restrict or increase the cost of our operations by, among other things, limiting our ability to clear trees to establish rights of way or pad locations on some of our acreage during certain periods of the year. See “Business—Regulation of Environmental and Occupational Safety and Health Matters—Endangered Species Act and Migratory Bird Treaty Act.” Adverse seasonal weather conditions and wildlife regulations may limit 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. In addition, the designation of previously unprotected species in areas where we operate as threatened or endangered could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration, development and production activities.

Acts of terrorism (including eco-terrorism) could have a material adverse effect on our financial condition, results of operations and cash flows.

Our assets and operations, and the assets and operations of our providers of gas gathering, processing, transportation and fractionation services, may be targets of terrorist activities (including eco-terrorist activities) that could disrupt our business or cause significant harm to our operations, such as full or partial disruption to our ability to produce, process, transport, market or distribute natural gas, NGLs and oil. Acts of terrorism, as well as events occurring in response to or in connection with acts of terrorism, could cause environmental and other repercussions that could result in a significant decrease in revenues or significant reconstruction or remediation costs, which could have a material adverse effect on our financial condition, results of operations and cash flows. In addition, acts of terrorism, and the threat of such acts, could result in volatility in the prices for natural gas, NGLs and oil and could affect the markets for such commodities.

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 and increases in interest rates. 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 adversely affect our ability to achieve our planned growth and operating results.

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 Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, was enacted on July 21, 2010 and 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 Commodities Futures Trading Commission, or the 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.

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 adverse effect on us, our financial condition or our results of operations.

Proposed changes to U.S. and state tax laws, if adopted, could have an adverse effect on our business, financial condition, results of operations and cash flows.

The U.S. President’s Fiscal Year 2014 Revenue Proposals include provisions that would, if enacted, make significant changes to U.S. tax laws, and legislation has been introduced recently in Congress that would implement some of these proposals. These changes include, but are not limited to, eliminating the immediate deduction for intangible drilling and development costs, eliminating the deduction from income for domestic production activities relating to oil and natural gas exploration and development, repealing the percentage depletion allowance for oil and natural gas properties and extending the amortization period for certain geological and geophysical expenditures. These proposed changes in the U.S. tax laws, if adopted, or other similar changes that reduce or eliminate deductions currently available with respect to oil and natural gas exploration and development, could adversely affect our business, financial condition, results of operations and cash flows.

In February 2013, the governor of the State of Ohio proposed a plan to enact new severance taxes in fiscal 2014 and 2015. However, the Ohio State Senate did not include a severance tax increase in the version of the budget bill that it passed on June 7, 2013. On May 14, 2014, the Ohio House of Representatives passed a measure (H.B.375) that imposes a tax of 2.5% on the gross receipts received for oil and gas severed from a horizontal well on or after October 1, 2014. This measure replaces the existing tax based on volume. Legislative proposals in the State of Ohio to increase severance taxes on production from horizontally drilled wells could increase our future production tax rates, if such legislation is enacted.

Risks Related to the Offering and Our Common Stock

We expect to be a “controlled company” within the meaning of the NYSE rules and, as a result, will qualify for, and intend to rely on, exemptions from certain corporate governance requirements. You will not have the same protections afforded to stockholders of companies that are subject to such requirements.

Upon completion of this offering, Eclipse Holdings, which is owned by the EnCap Funds, the Management Funds and Management Holdco, will beneficially control a majority of our common stock. In connection with the completion of this offering, we will enter into a stockholders’ agreement with Eclipse Holdings and its limited partners, the EnCap Funds, the Management Funds and Management Holdco, pursuant to which such stockholders will be provided with certain rights relative to designated director nominees and will agree to vote their shares of common stock in accordance with the stockholders’ agreement, including as it relates to the election of directors. For additional information regarding the stockholders’ agreement, please read “Certain Relationships and Related Party Transactions—Stockholders 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 controlled company and may elect not to comply with certain NYSE corporate governance requirements, including the requirements that:

•

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

•

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

•

we have a compensation committee that is composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities.

Following this offering, we intend to utilize the exemptions relating to the nominating and governance committee and compensation committee requirements, and we may utilize any of these exemptions for so long as we are a controlled company. Accordingly, you will not have the same protections afforded to stockholders of companies that are subject to all of the corporate governance requirements of the NYSE. See “Management.”

Eclipse Holdings, which is owned by the EnCap Funds, the Management Funds and Management Holdco, will hold a substantial majority of our common stock.

Immediately following the completion of this offering, Eclipse Holdings, which is owned by the EnCap Funds, the Management Funds and Management Holdco, will hold approximately 81.1% of the outstanding shares of our common stock (assuming the underwriters’ option to purchase additional shares from the selling stockholders is not exercised). Eclipse Holdings is entitled to act separately in its own interest with respect to its shares of our common stock, and Eclipse Holdings will have the voting power to elect all of the members of our board of directors and thereby control our management and affairs. In addition, Eclipse Holdings 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 a significant stockholder 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 Eclipse Holdings continues to control a significant amount of our common stock, Eclipse Holdings and its limited partners 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 Eclipse Holdings and its limited partners 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.

The stockholders’ agreement we expect to enter into in connection with the completion of this offering will permit our principal stockholders to designate a majority of the members of our board of directors.

In connection with the completion of this offering, we will enter into a stockholders agreement with Eclipse Holdings and its limited partners, the EnCap Funds, the Management Funds and Management Holdco, which we refer to as our principal stockholders, pursuant to which such stockholders will be provided with certain rights relative to designated director nominees and will agree to vote their shares of common stock in accordance with the stockholders agreement, including as it relates to the election of directors. See “Certain Relationships and Related Party Transactions—Stockholders Agreement.” Certain members of our management control or have other relationships with our principal stockholders. See “Principal and Selling Stockholders.”

Conflicts of interest could arise in the future between us, on the one hand, and EnCap and its affiliates, including its portfolio companies, on the other hand, concerning, among other things, potential competitive business activities or business opportunities.

EnCap is a leading provider of private equity to the independent sector of the U.S. oil and gas industry and manages investment funds with ownership interests in Eclipse Holdings. EnCap and its affiliates 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. EnCap and its affiliates 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. Moreover, EnCap has an interest in Caiman Energy II, LLC, which owns a significant interest in Blue Racer, a provider of firm gathering, processing and fractionation capacity for our operated acreage in the Rich Gas, Condensate and Rich Condensate Windows of the Utica Core Area. See “Business—Midstream Agreements.” As a result, EnCap’s interests with respect to matters arising in connection with our arrangements with Blue Racer may not align with our interests. 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.

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 of 2002 (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, 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.

We are not currently required to comply with the SEC’s rules implementing Section 404 of the Sarbanes–Oxley Act, 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 publicly traded company, we will be required to comply with the SEC’s rules implementing Sections 302 and 404 of the Sarbanes–Oxley Act, 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. Though we will be required to disclose material changes made to our internal controls and procedures on a quarterly basis, we will not be required to make our first annual assessment of our internal control over financial reporting pursuant to Section 404 until the year following our first annual report required to be filed with the SEC. To comply with the requirements of being a publicly traded company, we will need to implement additional internal controls, reporting systems and procedures and hire additional accounting and finance staff. Furthermore, while we generally must comply with Section 404 of the Sarbanes–Oxley Act for our fiscal year ending 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 our annual report for the fiscal year ending December 31, 2019. 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, or operating. 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.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes-Oxley Act. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our shares of common stock.

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.

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 securities were 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. If an active, liquid and orderly trading market does not develop, you may have difficulty selling any of our common stock that you buy. 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 that we discuss in “Underwriting,” 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, or at all.

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;

•

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.

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:

•

a classified board of directors, so that only approximately one-third of our directors are elected each year;

•

limitations on the removal of directors;

•

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

•

providing that the board of directors is expressly authorized to adopt, or to alter or repeal our amended and restated bylaws; and

•

establishing advance notice and 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.

See “Description of Capital Stock—Anti-Takeover Effects of Provisions of Our Amended and Restated Certificate of Incorporation, Our Amended and Restated Bylaws and Delaware Law.”

Our amended and restated certificate of incorporation designates 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 or other employees.

Our amended and restated certificate of incorporation provides that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware shall 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, or (iv) any action asserting a claim against us governed by the internal affairs doctrine. Any person or entity purchasing or otherwise acquiring any interest in shares of our common stock shall be deemed to have notice of and consented to the provisions of our amended and restated certificate of incorporation described above. 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 or other employees, which may discourage such lawsuits against us and our directors, officers and other employees. 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.

Investors in this offering will experience immediate and substantial dilution of $19.57 per share.

Purchasers of our common stock in this offering will experience an immediate and substantial dilution of $19.57 per share in the net tangible book value per share of common stock from the initial public offering price,

and our net tangible book value as of March 31, 2014 on a pro forma basis would have been $7.43 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. See “Dilution.”

We may invest or spend our net proceeds from this offering in ways with which you may not agree or in ways which may not yield a return.

Our net proceeds from this offering are expected to be used to repay our borrowings under our revolving credit facility and fund our exploration and development program and other capital expenditures. Our management will have considerable discretion in the application of our net proceeds, and you will not have the opportunity, as part of your investment decision, to assess whether the proceeds are being used appropriately. Until our net proceeds are used, they may be placed in investments that do not produce significant income or that may lose value.

We do not intend to pay cash dividends on our common stock, and our revolving credit facility and the indenture governing our senior unsecured notes 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 cash dividends on shares of our common stock in the foreseeable future. Additionally, our revolving credit facility and the indenture governing our senior unsecured notes 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 will ever exceed the price that you pay in this offering.

Future sales of our common stock 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 or private offerings. We may also issue additional shares of common stock or convertible securities. After the completion of this offering, we will have outstanding shares of common stock. This number includes shares that we and the selling stockholders are selling in this offering and shares that the selling stockholders may sell in this offering if the underwriters exercise their option to purchase 4,545,000 additional shares in full, which may be resold immediately in the public market. Following the completion of this offering, and assuming no exercise of the underwriters’ option to purchase additional shares, Eclipse Holdings will own 129,700,000 shares of our common stock, or approximately 81.1% of our total outstanding shares, all of which are restricted from immediate resale under the federal securities laws and are subject to the lock-up agreements with the underwriters described in “Underwriting,” but may be sold into the market in the future. Eclipse Holdings and its limited partners will be parties to a registration rights agreement with us which will require us to effect the registration of their shares in certain circumstances no earlier than the expiration of the lock-up period contained in the underwriting agreement entered into in connection with this offering. Certain employees will be subject to restrictions on the sale of their shares for 180 days after the date of this prospectus. However, after such period, and subject to compliance with the Securities Act or exemptions therefrom, these employees may sell such shares into the public market. See “Shares Eligible for Future Sale” and “Certain Relationships and Related Party Transactions—Registration Rights.”

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, Eclipse Holdings, the limited partners of Eclipse Holdings, the EnCap Funds, the Management Funds and Management Holdco, all of our directors and executive officers and certain of our employees have entered into lock-up agreements with respect to their common stock, pursuant to which 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. Citigroup Global Markets Inc., Goldman, Sachs & Co. and Morgan Stanley & Co. LLC, 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.

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 5 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 Public Company Accounting Oversight Board 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 5 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 $700.0 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 3-year period.

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

Our amended and restated 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 our common stock.

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

The trading market for our common stock will be influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of our company or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our stock price or trading volume to decline. Moreover, if one or more of the analysts who cover our company downgrades our common stock or if our operating results do not meet their expectations, our stock price could decline.

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 and capital expenditures, prospects, plans and objectives of management are forward-looking statements. When used in this prospectus, the words “will,” “would,” “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 the heading “Risk Factors” included in this prospectus.

Forward-looking statements may include statements about, among other things:

•

pending legal matters relating to our leases;

•

uncertainty regarding our future operating results, including initial production rates and liquids yields in our type curve areas;

•

our business strategy;

•

reserves;

•

financial strategy, expenses, liquidity and capital required for developing our properties and the timing related thereto;

•

realized natural gas, NGLs and oil prices;

•

the anticipated benefits under our commercial agreements;

•

the timing and amount of our future production of natural gas, NGLs and oil;

•

our hedging strategy and results;

•

future drilling plans;

•

competition and government regulations, including those related to hydraulic fracturing;

•

marketing of natural gas, NGLs and oil;

•

leasehold and business acquisitions;

•

the costs, terms and availability of gathering, processing, fractionation and other midstream services;

•

general economic conditions;

•

credit markets; 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, legal and environmental risks, drilling and other operating risks, regulatory changes, commodity price volatility, inflation, lack of availability of drilling, production and processing equipment and services, counterparty credit risk, 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” in this prospectus.

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 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, 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.

USE OF PROCEEDS

We expect to receive approximately $545.2 million of net proceeds from this offering 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.

We intend to use approximately $485.2 million of our net proceeds from this offering to fund our capital expenditures plan and approximately $60.0 million of our net proceeds from this offering to repay borrowings under our revolving credit facility.

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	$580.5	Funding of our capital expenditure plan	$	485.2
		Repayment of our revolving credit facility⁽¹⁾		60.0
		Underwriting discounts, fees and expenses		35.3
Total Sources of Funds	$580.5	Total Uses of Funds	$	580.5

(1)

Includes $40.0 million that was drawn under our revolving credit facility subsequent to March 31, 2014 to finance our capital expenditure plan.

As of March 31, 2014, we had $20.0 million in outstanding borrowings under our revolving credit facility. Our revolving credit facility matures on January 15, 2018, and interest on outstanding borrowings accrue based on, at our option, LIBOR or the alternate base rate, in each case, plus an applicable margin that is determined based on our utilization of commitments under our revolving credit facility. The interest rate with respect to outstanding borrowings under our revolving credit facility was 1.99% as of March 31, 2014. The borrowings to be repaid were incurred primarily for our drilling and development program and for general corporate purposes. As of May 1, 2014, our borrowing base was increased to $100.0 million, of which $60.0 million was drawn. While we currently do not have plans to immediately borrow additional amounts under our revolving credit facility following the closing of this offering, we may at any time re-borrow amounts repaid under our revolving credit facility, and we expect to do so to fund our capital program.

The selling stockholders have granted the underwriters a 30-day option to purchase up to an aggregate of 4,545,000 additional shares of our common stock to the extent the underwriters sell more than 30,300,000 shares of common stock in this offering. We will not receive any proceeds from the sale of shares by the selling stockholders pursuant to any exercise by the underwriters of their option to purchase additional shares of our common stock from the selling stockholders. We will pay all expenses of the selling stockholders related to this offering, other than underwriting discounts and commissions related to the shares sold by the selling stockholders.

Certain affiliates of the EnCap Funds and certain of our executive officers may indirectly receive proceeds from the sale of shares by the selling stockholders as a result of a distribution of proceeds by the selling stockholders to their respective limited partners, as applicable. See “Principal and Selling Stockholders.”

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. In addition, certain of our debt instruments place restrictions on our ability to pay cash dividends.

CAPITALIZATION

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

•

on an actual basis; and

•

on a pro forma basis to give effect to our corporate reorganization as described under “Corporate Reorganization,” which will be completed immediately prior to or contemporaneously with the closing of this offering, our sale of 21.5 million shares of common stock in this offering at our initial public offering price of $27.00 per share, and our use of the net proceeds as set forth under “Use of Proceeds.”

This table should be read in conjunction with, and is qualified in its entirety by reference to, “Use of Proceeds” and our historical consolidated financial statements and unaudited pro forma financial information and the related notes thereto appearing elsewhere in this prospectus.


	As of March 31, 2014
	Actual		Pro Forma
	(in thousands, except share data)
Cash and cash equivalents⁽¹⁾	$	27,328	$	555,142

Indebtedness:
Revolving credit facility⁽²⁾	$	20,000		—
12.0% senior unsecured PIK notes due 2018		412,230		412,230

Total indebtedness		432,230		412,230
Equity:
Partners’ capital		698,048		—
Preferred stock, $0.01 par value; 50,000,000 shares authorized (pro forma); no shares issued and outstanding (pro forma)		—		—
Common stock, $0.01 par value; 1,000,000,000 shares authorized (pro forma); 160,000,000 shares issued and outstanding (pro forma)		—		1,600
Additional paid-in capital		—		1,241,689
Accumulated deficit		—		(53,784	)
Accumulated other comprehensive income		306		306

Total equity		698,354		1,189,811

Total capitalization	$	1,130,584	$	1,602,041

(1)

Cash and cash equivalents as of March 31, 2014 reflects $1.4 million of the estimated expenses from this offering that have already been paid.

(2)

As of May 1, 2014, our borrowing base was increased to $100.0 million, of which $60.0 million was drawn.

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 our corporate reorganization as described under “Corporate Reorganization” was $644.3 million, or $4.65 per share. Pro forma net tangible book value per share is determined by dividing our pro forma tangible net worth (tangible assets less total liabilities) by the total number of shares of common stock that will be outstanding immediately prior to the closing of this offering after giving effect to our corporate reorganization. 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 $1.2 billion, or $7.43 per share. This represents an immediate increase in the net tangible book value of $2.78 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 $19.57 per share. The following table illustrates the per share dilution to new investors purchasing shares in this offering:


Initial public offering price per share			$	27.00
Pro forma net tangible book value per share as of March 31, 2014 (after giving effect to our corporate reorganization)	$	4.65
Increase per share attributable to new investors in this offering	$	2.78

As adjusted pro forma net tangible book value per share after giving effect to our corporate reorganization and this offering			$	7.43

Dilution in pro forma net tangible book value per share to new investors in this offering			$	19.57

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 $27.00 per share, calculated before deduction of estimated underwriting discounts and commissions and expenses payable by us:


	Shares Acquired					Total Consideration					Average Price Per Share
	Number		Percent			Amount		Percent			Average Price Per Share
	(in thousands)
Existing owners⁽¹⁾		129,700,000		81.1	%	$	772,594		48.6	%	$	5.96
New investors in this offering		30,300,000		18.9	%		818,100		51.4	%	$	27.00

Total		160,000,000		100.0	%	$	1,590,694		100.0	%	$	9.94

(1)

The number of shares disclosed for the existing owners includes 4,545,000 shares that may be sold by the selling stockholders in this offering pursuant to any exercise of the underwriters’ option to purchase additional shares of common stock.

If the underwriters exercise in full their option to purchase 4,545,000 additional shares, then the number of shares held by new investors will increase to 34,845,000, or approximately 21.8% of our outstanding shares of common stock.

SELECTED HISTORICAL CONSOLIDATED AND UNAUDITED PRO FORMA FINANCIAL DATA

The following table shows the selected historical consolidated financial data of Eclipse I, our accounting predecessor, and our selected unaudited pro forma financial data for the periods and as of the dates indicated. Our historical results are not necessarily indicative of future operating results. The selected financial data presented below are qualified in their entirety by reference to, and should be read in conjunction with, “Use of Proceeds,” “Capitalization,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and related notes included elsewhere herein.

The selected unaudited pro forma consolidated statements of operations data for the three months ended March 31, 2014 and for the year ended December 31, 2013 has been prepared to give pro forma effect to (i) the Oxford Acquisition, (ii) the corporate reorganization transactions described under “Corporate Reorganization,” and (iii) this offering and the application of our net proceeds from this offering as if they had been completed as of January 1, 2013. The selected unaudited pro forma consolidated balance sheet data as of March 31, 2014 has been prepared to give pro forma effect to those transactions (other than the Oxford Acquisition, which was completed on June 26, 2013) as if they had been completed as of March 31, 2014. These data are subject 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 consolidated 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 Oxford Acquisition, the reorganization transactions and this offering been consummated on the dates indicated, and do not purport to be indicative of statements of our financial position or results of operations as of any future date or for any future period.


	Eclipse I						Eclipse I						Eclipse Resources Corporation
	Three Months Ended March 31,						Year Ended December 31,						Pro Forma Three Months Ended March 31,			Pro Forma Year Ended December 31,
	2014			2013			2013			2012			2014			2013
	(Unaudited)			(Unaudited)									(Unaudited)			(Unaudited)
(in thousands)
Statement of operations data:

REVENUES
Natural gas, NGLs and oil sales	$	24,788		$	288		$	12,935		$	370		$	24,788		$	20,638

Total revenues		24,788			288			12,935			370			24,788			20,638

OPERATING EXPENSES
Exploration		4,545			72			3,022			3,899			4,545			3,205
Lease operating		1,791			5			2,576			16			1,791			4,736
Transportation, gathering and compression		904			—			67			—			904			67
Production and ad valorem taxes		353			4			77			1			353			164
Depreciation, depletion and amortization		12,027			488			6,163			404			12,027			9,256
Impairments		—			—			2,081			793			—			2,081
General and administrative		8,394			1,483			21,276			4,425			8,394			23,808
Accretion expense		186			—			364			—			186			702
Gain on reduction of pension liability		(2,208	)		—			—			—			(2,208	)		—

Total operating expenses		25,992			2,052			35,626			9,538			25,992			44,019

Gain on sale of property		—			—			—			372			—			—

OPERATING LOSS		(1,204	)		(1,764	)		(22,691	)		(8,796	)		(1,204	)		(23,381	)

OTHER INCOME (EXPENSE)
Gain (loss) on derivative instruments		(3,611	)		—			—			—			(3,611	)		—
Interest income (expense), net		(13,636	)		5			(20,850	)		37			(13,603	)		(41,552	)

Total other income (expense), net		(17,247	)		5			(20,850	)		37			(17,214	)		(41,552	)

LOSS BEFORE INCOME TAXES		(18,451	)		(1,759	)		(43,541	)		(8,759	)		(18,418	)		(64,933	)

INCOME TAX BENEFIT		—			—			—			—			6,446			24,897


NET LOSS	$	(18,451	)	$	(1,759	)	$	(43,541	)	$	(8,759	)	$	(11,972	)	$	(40,036	)


Balance sheet data (at period end):
Cash and cash equivalents		27,328						109,509			27,057			555,142
Total property and equipment, net		1,144,907						1,018,084			106,253			1,146,910
Total assets		1,211,293						1,143,523			133,522			1,741,239
Total debt		432,230						389,247			—			412,230
Total partners’ / stockholders’ capital		698,354						667,971			126,704			1,189,811

Net cash provided by (used in):
Operating activities		104			232			15,250			(3,381	)
Investing activities		(151,140	)		(69,211	)		(897,086	)		(47,535	)
Financing activities		68,855			58,136			964,288			68,916

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, NGLs and oil 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. See “Cautionary Statement Regarding Forward-Looking Statements.” Also, 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.

Overview of Our Business

We are an independent exploration and production company engaged in the acquisition and development of oil and natural gas properties in the Appalachian Basin. We are focused on creating stockholder value by developing our substantial inventory of horizontal drilling locations, continuing to opportunistically add to our acreage position where we can acquire assets at attractive prices and leveraging our technical and managerial expertise to deliver industry-leading results.

Approximately 96,240 of our net acres are located in what we believe to be the most prolific and economic area of the Utica Shale fairway, which we refer to as the Utica Core Area, and approximately 25,740 of these net acres are also prospective for the highly liquids rich area of the Marcellus Shale in Eastern Ohio within what we refer to as Our Marcellus Project Area. We are the operator of approximately 81% of our net acreage within the Utica Core Area and Our Marcellus Project Area. We began assembling our acreage position in 2011 based upon a rigorous analytical evaluation of the shale properties within the Utica and Point Pleasant formations across Eastern Ohio. We initially targeted and acquired approximately 27,000 net acres in the Utica Core Area in 2011 through a combination of leasing and largely contiguous acreage acquisitions. In 2012, we entered into an agreement with Antero Resources to form an area of mutual interest covering approximately 43,600 gross acres predominately in Noble County, Ohio, which Antero Resources operates. Pursuant to our agreement, during a three-year term, we and Antero Resources have the option to purchase an interest in any acquisitions of oil and gas interests the other completes within the area of mutual interest. If the non-acquiring party elects to participate, we will own an undivided 30% interest and Antero Resources will own an undivided 70% interest in such acquired oil and gas interests. In June 2013, we acquired Oxford, which held approximately 180,000 net acres in Ohio, including approximately 49,000 net acres in the Utica Core Area and approximately 1,289 gross proved producing conventional wells.

approximately 5,850 feet and completed with 19 stages. The well was connected to a sales line on December 21, 2013 and produced at a cumulative total of 549 MMcf of natural gas for an average rate of 18.3 MMcf per day in its first 30 days after connecting to a sales line.

As of March 31, 2014, we were operating 3 horizontal rigs and 1 top-hole rig in the Utica Core Area. We frequently utilize top-hole rigs ahead of our horizontal rigs to drill the vertical portion of our wells in order to maximize the drilling efficiency of our larger horizontal drilling rigs and reduce overall costs. As of March 31, 2014, we had identified 3,381 gross (863 net) horizontal drilling locations across our acreage, comprised of 2,777 gross (668 net) locations within the Utica Core Area and 604 gross (195 net) locations within Our Marcellus Project Area.

As of March 31, 2014, we were producing approximately 185.5 gross (50.4 net) MMcfe per day comprised of approximately 69% natural gas, 16% NGLs and 15% oil.

As of March 31, 2014, our estimated proved reserves were 109.6 Bcfe, or 18.3 MMBoe, based on reserve reports prepared by Netherland, Sewell & Associates, Inc., or NSAI, our independent petroleum engineers, all of which were in Ohio and approximately 52% of which were proved developed reserves. Additionally, our estimated proved reserves were approximately 63% natural gas, 21% NGLs and 16% oil, as of March 31, 2014.

Factors That Significantly Affect Our Financial Condition and Results of Operations

We derive substantially all of our revenues from the production and sale of natural gas, NGLs and oil that are extracted from our natural gas during processing. During the three months ended March 31, 2014, our revenues were comprised of approximately 56.3%, 2.3% and 41.4% from the production and sale of natural gas, NGLs and oil, respectively. Our revenues, cash flow from operations and future growth depend substantially on factors beyond our control, such as economic, political and regulatory developments and competition from other sources of energy. Natural gas, NGLs and oil prices have historically been volatile and may fluctuate widely in the future due to a variety of factors, including, but not limited to, prevailing economic conditions, supply and demand of hydrocarbons in the marketplace and geopolitical events such as wars or natural disasters. Sustained periods of low prices for these commodities would materially and adversely affect our financial condition, our results of operations, the quantities of natural gas, NGLs and oil that we can economically produce and our ability to access capital.

In January 2014, we began using commodity derivative instruments, such as swaps, collars and puts, to manage and reduce price volatility and other market risks associated with our 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 swaps for 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. The prices contained in these derivative contracts are based on NYMEX Henry Hub prices. The NYMEX Henry Hub price of natural gas is a widely used benchmark for the pricing of natural gas in the United States. The actual prices realized from the sale of natural gas differ from the quoted NYMEX Henry Hub price as a result of location differentials. Location differentials to NYMEX Henry Hub prices, also known as basis differential, result from variances in regional natural gas prices compared to NYMEX Henry Hub prices as a result of regional supply and demand factors. Historically, we have not hedged basis differentials associated with our natural gas production, although we may elect to do so in the future. We have 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 read “—Quantitative and Qualitative Disclosures 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, oil and natural gas production from a given well naturally decreases. Thus, an exploration and production company depletes part of its asset base with each unit of reserves 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, NGLs and oil prices;

•

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:

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 and our other filings with the SEC, tax return preparation, independent auditor 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 $3 million per year. This estimate does not include non-cash compensation expenses, which we expect to incur in the future. These direct incremental G&A expenses are not included in our historical results of operations.

Corporate Reorganization. The historical consolidated financial statements included in this prospectus are based on the financial statements of Eclipse I, our accounting predecessor, prior to our corporate reorganization in connection with this offering as described in “Corporate Reorganization.” As a result, the historical financial data may not present 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.

The Oxford Acquisition. We acquired Oxford on June 26, 2013. As such, the results of Oxford’s operations prior to such date are not included in the historical financial statements of Eclipse I that are presented within this prospectus. Accordingly, our historical financial data may not present an accurate indication of what our actual results would have been if the Oxford Acquisition had been completed at the beginning of the periods presented or of what our future results of operations are likely to be.

Income Taxes. Eclipse I, our accounting predecessor, is a limited partnership not subject to federal income taxes. Accordingly, no provision for federal income taxes has been provided for in our historical results of operations because taxable income was passed through to Eclipse I’s limited partners. Although we are a corporation under the Internal Revenue Code of 1986, as amended (the “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 and deferred tax liabilities.

Increased Horizontal Drilling Activity. Historically, Oxford has drilled conventional vertical wells in Ohio. We began horizontal, unconventional drilling operations in 2012, and through March 31, 2014, we, or our operating partners, had commenced drilling 75 gross (27 net) wells. We expect to drill or participate in 176 gross (69 net) horizontal wells in 2014. Our current and future drilling activity is substantially weighted towards the development of our Utica and Marcellus Shale acreage using horizontal wells. The costs and production associated with the wells we expect to drill in the Utica and Marcellus Shale will differ substantially from the vertical conventional wells Oxford has historically drilled.

Financing Arrangements. As of March 31, 2014, we had outstanding indebtedness of $412.2 million. In June 2013, we issued $300.0 million in aggregate principle amount of 12.0% senior unsecured PIK notes due 2018, which we refer to as our Senior Unsecured Notes. In December 2013, we issued an additional $100.0 million of Senior Unsecured Notes at par.

Cumulative net proceeds from our Senior Unsecured Notes of $381.2 million, after offering fees and expenses, were used along with contributions from our equity investors to acquire Oxford and to continue to develop our acreage in the Utica Core Area and in Our Marcellus Project Area.

On February 18, 2014, we entered into a $500.0 million senior secured revolving credit facility, which we refer to as our Revolving Credit Facility. Our Revolving Credit Facility matures on January 15, 2018 and includes customary affirmative and negative covenants. The initial borrowing base under our Revolving Credit Facility was $50.0 million and the Company had outstanding borrowings of $20.0 million at a weighted average interest rate of 1.99% as of March 31, 2014. As of May 1, 2014, our borrowing base was increased to $100 million, of which $60 million was drawn.

To date, our capital expenditures have been financed with capital contributions from the EnCap Funds and the Management Funds, net proceeds from the issuance of our Senior Unsecured Notes and net cash provided by operating activities. In the future, we may incur additional indebtedness to fund our acquisition and development activities. Please read “—Credit Arrangements” for additional discussion of our financing arrangements.

Source of Our Revenues

Our historical revenues are derived from the sale of natural gas, NGLs and oil, and do not include the effects of derivatives. Revenues from product sales are a function of the volumes produced, prevailing market prices, product quality, gas Btu content and transportation costs. We generally sell production at a specific delivery point, pay transportation costs to a third party and receive proceeds from the purchaser with no transportation deduction. We record transportation costs as transportation, gathering and compression expense. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.

Principal Components of Our Cost Structure

•

Exploration. These are geological and geophysical costs, seismic costs, delay rentals and the costs of unsuccessful exploratory dry holes.

•

Transportation, gathering and compression. Under some of our sales arrangements, we sell natural gas at a specific delivery point, pay transportation, gathering and compression costs to a third party and

receive proceeds from the purchaser with no deduction. These costs represent those transportation, gathering and compression costs paid by us to third parties. Additionally, we often enter into firm transportation contracts that secure takeaway capacity that includes minimum volume commitments, the cost of which is included in these expenses.

•

Lease operating. These are day-to-day costs incurred to bring hydrocarbons out of the ground along with the daily costs incurred to maintain our producing properties. Such costs include compensation of our field employees, maintenance, repairs and workovers expenses related to our natural gas and oil properties. These costs are expected to remain a function of supply and demand.

•

Production and ad valorem taxes. Production taxes are paid on produced natural gas and oil based on a percentage of market prices or at fixed rates established by the applicable federal, state or local taxing authorities. Ad valorem taxes are generally based on reserve values at the end of each year.

•

Abandonment and impairment of unproved properties. This category includes unproved property impairment and expenses associated with lease expirations.

•

Depreciation, depletion and amortization. This includes the expensing of the capitalized costs incurred to acquire, explore and develop natural gas, NGLs and oil. As a successful efforts company, we capitalize all costs associated with our acquisition and development efforts and all successful exploration efforts, and apportion these costs to each unit of production through depreciation, depletion and amortization expense. This expense also includes the monthly accretion of the future abandonment costs of tangible assets such as wells, service assets, pipelines and other facilities.

•

General and administrative. 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. Included in this category are any overhead expense reimbursements we receive from working interest owners of properties, for which we serve as the operator. These reimbursements are received during both the drilling and operational stages of a property’s life.

•

Gain (Loss) on Derivative Instruments. We utilize commodity derivative contracts to reduce our exposure to fluctuations in the price of gas. None of our derivative contracts are designated as hedges for accounting purposes. Consequently, our derivative contracts are marked-to-market each quarter with fair value gains and losses recognized currently as a gain or loss in our results of operations. The amount of future gain or loss recognized on derivative instruments is dependent upon future gas prices, which will affect the value of the contracts. Cash flow is only impacted to the extent the actual settlements under the contracts result in making a payment to or receiving a payment from the counterparty.

•

Interest expense. We have historically financed a portion of our cash requirements with proceeds from fixed-rate senior notes. As a result, we incur interest expense that is affected by our financing decisions. We capitalize interest on expenditures for significant exploration and development projects while activities are in progress to bring the assets to their intended use. Upon completion of construction of the asset, the associated capitalized interest costs are included within our asset base and depleted accordingly.

How We Evaluate Our Operations

In evaluating our current and future financial results, we expect to focus on production and revenue growth, lease operating expense, general and administrative expense (both before and after non-cash stock compensation expense) and operating margin per unit of production. In addition to these metrics, we will use Adjusted EBITDAX growth to evaluate our financial results. We define Adjusted EBITDAX as net income (loss) before interest expense or interest income; income taxes; write-down of abandoned leases; impairments; depreciation, depletion and amortization (“DD&A”); amortization of deferred financing costs; gain (loss) on derivative instruments, net cash receipts (payments on settled derivative instruments, and premiums (paid) received on options that settled during the period; non-cash compensation expense; gain or loss from sale of interest in gas properties; and exploration expenses. Adjusted EBITDAX is not a measure of net income as determined by United States Generally Accepted Accounting Principles, or GAAP.

In addition to the operating metrics above, as we grow our reserve base, we will assess our capital spending by calculating our operated proved developed reserves and our operated proved developed finding costs and development costs. We believe that operated proved developed finding and development costs are one of the key measurements of the performance of an oil and gas exploration and production company. We will focus on our operated properties as we control the location, spending and operations associated with drilling these properties. In determining our proved developed finding and development costs, only cash costs incurred in connection with exploration and development will be used in the calculation, while the costs of acquisitions will be excluded because our board approves each material acquisition. In evaluating our proved developed reserve additions, any reserve revisions for changes in commodity prices between years will be excluded from the assessment, but any performance related reserve revisions are included.

We also continually evaluate our rates of return on invested capital in our wells. We believe the quality of our assets combined with our technical and managerial expertise can generate attractive rates of return as we develop our acreage in the Utica Core Area and Our Marcellus Project Area. We review changes in drilling and completion costs; lease operating costs; natural gas, NGLs and oil prices; well productivity; and other factors in order to focus our drilling on the highest rate of return areas within our acreage.

Overview of the Three Months Ended March 31, 2014 Results

Operationally, our performance during the three months ended March 31, 2014 reflects continued development of our Utica Core Area and Our Marcellus Project Area acreage, continuing the delineation process across these two acreage positions. During the three months ended March 31, 2014, we achieved the following financial and operating results:

•

increased total net proved reserves, adjusted for production, by 34.6 Bcfe to 109.6 Bcfe, which was comprised of 44.6 Bcfe of extensions, 0.6 Bcfe of positive price revisions, and offset by (10.6) Bcfe of technical revisions;

•

added 23 gross (6.5 net) wells to proved reserves of which, 4 gross (1.3 net) wells were classified as proved developed producing, 7 gross (1.6 net) wells were classified as proved developed nonproducing, and 12 gross (3.7 net) wells were classified as proved undeveloped;

•

drilled or participated in 16 gross (8 net) Utica Shale wells, 4.9 net wells of which had been completed;

•

issued $22.5 million in additional Senior Unsecured Notes to satisfy our accrued interest on the notes through January 15;

•

put in place a $500 million bank credit facility with a borrowing base at March 31, 2014 of $50 million; $20 million of which was drawn during the three months ended 2014;

•

increased our Utica Area acreage to 96,240 net acres and our Marcellus Project Area acreage to 25,740 net acres;

•

put in place gas hedges for a portion of our 2014 and 2015 natural gas production; and

•

entered contract with Shell Chemical for the sale of ethane to their proposed Appalachian cracker project.

Overview of Fiscal 2013 Results

Operationally, our fiscal 2013 performance reflects our expansion of our acreage in both the Utica Core Area and Our Marcellus Project Area, and the commencement of the delineation process across these 2 acreage positions. During the year ended December 31, 2013, we achieved the following financial and operating results:

•

increased total net proved reserves adjusted for production by 73.8 Bcfe to 78.5 Bcfe;

•

drilled or participated in 56 gross (17 net) Utica Shale wells and 3 gross (2 net) Marcellus Shale wells, 4.1 of which had been completed;

•

increased our acreage position in the Utica Core Area to approximately 93,900 net acres by acquiring Oxford and through in-fill leasing around these assets;

•

issued $400.0 million in aggregate principal amount of our Senior Unsecured Notes;

•

contracted for firm gathering, cryogenic processing and fractionation capacity for our operated Utica Shale liquids rich natural gas production; and

•

contracted for firm gathering services for a significant portion of our operated dry gas Utica Shale acreage.

Acquisitions

During the year ended December 31, 2013, we spent $906.9 million to expand our leasehold through the acquisition of Oxford for $652.5 million and through the leasing of additional unproved Utica and Marcellus Shale acreage for $254.4 million in Belmont, Guernsey, Harrison, Monroe, and Noble Counties in Ohio. We continue selective acreage leasing to add to our acreage positions primarily in the Utica Core Area and Our Marcellus Project Area.

Divestitures

During the year ended December 31, 2012, we sold approximately 21,000 net acres to Antero Resources for $126.5 million and created an area of mutual interest located predominately in Noble County, Ohio. The proceeds did not exceed our cost basis in the properties sold and were recorded on our balance sheet as a reduction of our cost basis.

During the year ended December 31, 2012, in conjunction with the sale of acreage to Antero Resources, we also sold 70% of our interest in the Miley 5H well in Noble County, Ohio for $5.2 million before customary closing adjustments. The proceeds included $2.4 million for the sale of 70% of our net acreage within the Miley Unit and $2.8 million for the reimbursement of 70% of our drilling costs incurred. The sales proceeds exceeded our cost basis in these properties, resulting in a gain of $0.4 million, and the reimbursement of drilling costs were recorded as a reduction of exploration expense in 2012.

During the year ended December 31, 2013, we sold an additional 1,220 net acres within our area of mutual interest with Antero Resources for $8.5 million. The proceeds did not exceed our cost basis in the properties sold and were recorded on our balance sheet as a reduction of our cost basis.

Fiscal 2014 Outlook

For fiscal 2014, our board approved a $696.3 million capital budget comprised of $577.4 million for drilling and completion, $115.8 million for land related expenditures and leasehold acquisitions and $3.2 million for other purposes. Our capital budget excludes acquisitions, other than routine leasehold acquisitions. Although we do not specifically allocate our drilling and completion capital budget into proved and non-proved categories, based on proved reserves as of December 31, 2013, we expect that approximately 96%, of our drilling and completion capital in 2014 will be allocated towards non-proved drilling activities. We expect to continue to fund our capital expenditures in fiscal 2014 with cash generated by operations, borrowings under our Revolving Credit Facility, net proceeds received from the issuance of our Senior Unsecured Notes, capital contributions received prior to the date of this offering and a portion of the net proceeds of this offering. 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, NGLs and oil prices, actual drilling results, the availability of drilling rigs and other services and equipment, regulatory, technological and competitive developments and completion of this offering. A reduction in natural gas, NGLs or oil prices from current levels may cause us to reduce our drilling activity resulting in a decrease in our actual capital expenditures, which would negatively impact our ability to grow production. 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.

Market Conditions

Prices for various quantities of natural gas, NGLs and oil that we produce significantly impact our revenues and cash flows. Prices for commodities, such as hydrocarbons, are inherently volatile. The following table lists average, high and low NYMEX Henry Hub prices for natural gas and NYMEX WTI prices for oil for the three months ended March 31, 2014 and 2013 and the year ended December 31, 2013 and 2012.


	Three Months Ended March 31,				Year Ended December 31,
	2014		2013		2013		2012
NYMEX Henry Hub High ($/MMBtu)	$	6.15	$	4.07	$	4.46	$	3.90
NYMEX Henry Hub Low ($/MMBtu)		4.01		3.11		3.11		1.91
Average NYMEX Henry Hub ($/MMBtu)		4.65		3.48		3.73		2.83

NYMEX WTI High ($/Bbl)	$	104.92	$	97.94	$	110.53	$	109.77
NYMEX WTI Low ($/Bbl)		91.66		90.12		86.68		77.69
Average NYMEX WTI ($/Bbl)		98.61		94.36		98.05		94.15

Results of Operations

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

Natural Gas, NGLs and Oil Sales, Production and Realized Price Calculations

The following table illustrates the revenue attributable to natural gas, NGLs and oil sales for the three months ended March 31, 2014 and 2013.


	Three Months Ended March 31,
	2014		2013		Change
Revenues (in thousands):
Natural gas sales	$	13,959	$	52	$	13,907
NGLs sales		575		—		575
Oil sales		10,254		236		10,018

Total revenues	$	24,788	$	288	$	24,500

Our production grew by approximately 3,431 MMcfe, of which approximately 988 MMcfe was attributable to additions from acquisitions and approximately 2,443 MMcfe was attributable to drilling success as we placed new wells on production, partially offset by natural decline. Our production for the three months ended March 31, 2014 and 2013 is set forth in the following table:


	Three Months Ended March 31,
	2014		2013		Change
Production:
Natural gas (MMcf)		2,759.0		14.2		2,744.8
NGLs (Mbbls)		9.0		—		9.0
Oil (Mbbls)		108.0		2.6		105.4
Total (MMcfe)		3,461.0		29.6		3,431.4

Average daily production volume:
Natural gas (Mcf/d)		30,656		158		30,498
NGLs (Bbls/d)		100		—		100
Oil (Bbls/d)		1,200		28		1,172
Total (Mcfe/d)		38,456		329		38,127

Our average realized price received during the three months ended March 31, 2014 was $7.16 per Mcfe compared to $9.73 per Mcfe in the three months ended March 31, 2013. The decrease in the average realized price was due to a significantly higher percentage of our total revenues being driven by natural gas production in the three months ended March 31, 2014, as compared to the three months ended March 31, 2013. Average realized prices (wellhead) do not include any third party transportation costs, which are reported in transportation, gathering and compression expense on our statements of operations. Average realized price calculations for the three months ended March 31, 2014 and 2013 are shown in the following table.


	Three Months Ended March 31,
	2014			2013		Change
Volume weighted average realized prices:
Natural gas ($/Mcf)⁽¹⁾	$	5.06		$	3.68	$	1.38
NGLs ($/Bbl)		63.88			—		63.88
Oil ($/Bbl)		94.94			91.89		3.05
Average price ($/Mcfe)		7.16			9.73		(2.57	)
Differential of realized natural gas price to Average NYMEX Henry Hub⁽²⁾		(0.02	)		0.09		(0.11	)
Differential of realized natural gas price to Average NYMEX WTI⁽²⁾		(3.35	)		2.14		(5.49	)

(1)

(2)

Differential compares actual NYMEX Henry Hub and WTI prices to our actual volume-weighted average realized prices.

Costs and Expenses

We believe some of our expense fluctuations are best analyzed on a unit-of-production, or per Mcfe, basis. The following table presents information about certain of our expenses for the three months ended March 31, 2014 and 2013.


	Three Months Ended March 31,
	2014		2013		Change
Operating expenses (in thousands):
Transportation, gathering and compression	$	904	$	—	$	904
Lease operating		1,791		5		1,786
Production, severance and ad valorem taxes		353		4		349
Depreciation, depletion and amortization		12,027		488		11,539
General and administrative		8,394		1,483		6,911

Operating expenses per Mcfe:
Transportation, gathering and compression	$	0.26	$	—	$	0.26
Lease operating		0.52		0.17		0.35
Production, severance and ad valorem taxes		0.10		0.12		(0.02	)
Depletion, depreciation and amortization		3.48		16.48		(13.00	)
General and administrative		2.43		50.11		(47.68	)

Transportation, gathering and compression expense was $0.9 million during the three months ended March 31, 2014 compared to $0 in the three months ended March 31, 2013. These third party costs were higher in the three months ended March 31, 2014 due to our production growth where we have third party gathering and compression agreements. We have excluded these costs in the calculation of average realized sales prices.

Lease operating expense was $1.8 million in the three months ended March 31, 2014 compared to less than $0.01 million in the three months ended March 31, 2013. The increase of $1.8 million is attributable to higher production during the three months ended March 31, 2014, as compared to the three months ended March 31, 2013. Lease operating expenses include normally recurring expenses to operate and produce our wells, non-recurring workovers and repairs. We experience increases in operating expenses as we add new wells and manage existing properties. We incurred $0.3 million of workover costs in three months ended March 31, 2014 compared to $0 in three months ended March 31, 2013.

Production and ad valorem taxes are paid based on market prices and applicable tax rates. Production and ad valorem taxes were $0.4 million in the three months ended March 31, 2014 compared to less than $0.01 million in the three months ended March 31, 2013. Production and ad valorem taxes increased from the three months ended March 31, 2013 to the three months ended March 31, 2014 due to an increase in production volumes subject to production or ad valorem taxes.

Depletion, depreciation and amortization was approximately $12.0 million in the three months ended March 31, 2014 compared to $0.5 million in the three months ended March 31, 2013. The increase in the three months ended March 31, 2014 when compared to the three months ended March 31, 2013 is due to the increase in production during 2014. On a per Mcfe basis, DD&A decreased to $3.48 in the three months ended March 31, 2014 from $16.48 in the three months ended March 31, 2013, which was predominantly driven by a lower depletion rate. Depletion rates in new plays tend to be higher in the beginning as increased initial outlays are amortized over proved reserves based on early stages of evaluations, which was the case in the three months ended March 31, 2013 and to a lesser extent during the three months ended March 2014. The decrease in depletion rate during the three months ended March 31, 2014 was due to total proved reserves (the denominator) increasing at a higher rate than production (the numerator) over the year. We currently expect our DD&A rate to be approximately $2.10 per Mcfe in fiscal 2014, based on our current production and reserve estimates.

General and administrative expense was $8.4 million for the three months ended March 31, 2014 compared to $1.5 million for the three months ended March 31, 2013. The increase of $6.9 million during the three months ended March 31, 2014 when compared to three months ended March 31, 2013 is primarily due to higher salaries and benefits ($4.5 million) related to the hiring of a significant number of new employees during the three months ended March 31, 2014, and higher legal and consulting expenses ($0.4 million) during the three months ended March 31, 2014. We recorded $0.03 million and $0 of non-cash incentive unit compensation charges for the three months ended March 31, 2014 and 2013 respectively. Our personnel costs will continue to increase as we invest in our technical teams and other staffing to support the expansion of our drilling program in the Utica Core Area and Our Marcellus Project Area.

Other Operating Expenses

Our total operating expenses also include other expenses that generally do not trend with production. These expenses include exploration expense, impairment charges and accretion of asset retirement obligation expense. The following table details our other operating expenses for three months ended March 31, 2014 and 2013.


	Three Months Ended March 31,
	2014			2013		Change
Other Operating Expenses (in thousands):
Exploration	$	4,545		$	72	$	4,473
Accretion		186			—		186
Gain on reduction of pension liability		(2,208	)		—		(2,208	)

Exploration expense increased to $4.5 million in the three months ended March 31, 2014 compared to $0.07 million in the three months ended March 31, 2013 due to lower dry hole costs, partially offset by higher seismic costs and delay rentals due to acreage increases. The following table details our exploration-related expenses for the three months ended March 31, 2014 and 2013.


	Three Months Ended March 31,
	2014		2013		Change
Exploration Expenses (in thousands):
Seismic	$	69	$	14	$	55
Delay rentals		4,449		31		4,418
Dry hole		28		27		1

	$	4,546	$	72	$	4,474

Accretion expense was $0.2 million in the three months ended March 31, 2014, compared to $0 in the three months ended March 31, 2013. The increase in accretion expense primarily relates to the increase in the asset retirement obligations associated with new wells drilled during the three months ended March 31, 2014 and existing wells acquired in the Oxford Acquisition in June 2013.

Gain on reduction of pension liability was $2.2 million for the three months ended March 31, 2014, compared to $0 in the three months ended March 31, 2013. Effective March 31, 2014, the Company froze the benefit accruals related to the defined benefit pension plan it assumed in the Oxford Acquisition, which was completed during fiscal 2013.

Other Income (Expense)

Loss on derivative instruments was $3.6 million for the three months ended March 31, 2014 compared to $0 in the three months ended March 31, 2013. During the three months ended March 31, 2013, the Partnership entered into put-spread and swap agreements to manage the exposure to cash-flow variability related to production. Approximately $1.4 million of the $3.6 million loss on derivative instruments related to net cash payments on settled derivatives. Prior to 2014, we did not enter into any derivative instruments.

Interest expense, net was $13.6 million for the three months ended March 31, 2014. We incurred $0 in interest expense in the three months ended March 31, 2013. The increase in interest expense during the three months ended March 31, 2014 was due to the June 2013 and December 2013 issuances of $281.2 million and $100.0 million, respectively, of our Senior Unsecured Notes, net of discounts, and $0.02 million of related offering expenses as well as the $20.0 million drawn on our Revolving Credit Facility in March 2014. We used the net proceeds from the June 2013 issuance, along with contributions from our equity investors, to fund the Oxford Acquisition. In January 2014, we paid our semi-annual interest on our Senior Unsecured Notes with additional Senior Unsecured Notes at an interest rate of 13.0% as opposed to paying in cash at the cash interest rate of 12.0%. Interest expense is net of capitalized interest on expenditures made in connection with exploration and development projects that are not subject to current amortization.

At our option, the first two interest payments subsequent to the issuance of our Senior Unsecured Notes may be paid-in-kind by issuing additional Senior Unsecured Notes (“PIK Interest”). Also at our option, the subsequent four semi-annual interest payments thereafter may be paid in the form of 6.0% annum per cash and 7.0% annum in PIK Interest. Thereafter (subsequent to the sixth semi-annual interest payment), interest can only be paid in cash at 12.0% per annum.

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

Natural Gas, NGLs and Oil Sales, Production and Realized Price Calculations

The following table illustrates the revenue attributable to natural gas, NGLs and oil sales for each of the years ended December 31, 2013 and 2012.


	Year Ended December 31,
	2013		2012		Change
Revenues (in thousands):
Natural gas sales	$	4,303	$	27	$	4,276
NGLs sales		63		—		63
Oil sales		8,569		343		8,226

Total revenues	$	12,935	$	370	$	12,565

Our production grew by approximately 1,615 MMcfe, of which approximately 988 MMcfe was attributable to additions from acquisitions and approximately 627 MMcfe was attributable to drilling success as we placed new wells on production, partially offset by natural decline. Our production for each of the years ended December 31, 2013 and 2012 is set forth in the following table:


	Year Ended December 31,
	2013		2012		Change
Production:
Natural gas (MMcf)		1,118.8		7.7		1,111.1
NGLs (Mbbls)		1.3		—		1.3
Oil (Mbbls)		87.2		4.5		82.7
Total (MMcfe)		1,650.2		34.6		1,615.6

Average daily production volume:
Natural gas (Mcf/d)		3,065		21		3,044
NGLs (Bbls/d)		4		—		4
Oil (Bbls/d)		239		12		227
Total (Mcfe/d)		4,521		95		4,426

Our average realized price received during fiscal 2013 was $7.84 per Mcfe compared to $10.69 per Mcfe in fiscal 2012. The decrease in the average realized price was due to a significantly higher percentage of our total revenues being driven by natural gas production in fiscal 2013, as compared to fiscal 2012. Average realized prices (wellhead) do not include any third party transportation costs, which are reported in transportation, gathering and compression expense on our statements of operations. Average realized price calculations for each of the years ended December 31, 2013 and 2012 are shown in the following table.


	Year Ended December 31,
	2013			2012			Change
Volume weighted average realized prices:
Natural gas ($/Mcf)	$	3.85		$	3.53		$	0.32
NGLs ($/Bbl)		48.17			—			48.17
Oil ($/Bbl)		98.22			76.19			22.03
Average price ($/Mcfe)		7.84			10.69			(2.85	)
Differential to Average NYMEX Henry Hub⁽¹⁾		0.06			0.62			(0.56	)
Differential to Average NYMEX WTI⁽¹⁾		(0.38	)		(17.51	)		17.13

(1)

Differential compares actual NYMEX Henry Hub and WTI prices to our actual volume-weighted average realized prices.

Gain on the sale of assets was $0.37 million in fiscal 2012 as a result of selling 70% of our interest in the Miley 5H well in Noble County, Ohio. We did not record any gains on the sale of properties in fiscal 2013.

Costs and Expenses


	Year Ended December 31,
	2013		2012		Change
Operating expenses (in thousands):
Transportation, gathering and compression	$	67	$	—	$	67
Lease operating		2,576		16		2,560
Production, severance and ad valorem taxes		77		1		76
Depletion, depreciation and amortization		6,163		404		5,759
General and administrative		21,276		4,425		16,851

Operating expenses per Mcfe:
Transportation, gathering and compression	$	0.04	$	—	$	0.04
Lease operating		1.56		0.46		1.10
Production, severance and ad valorem taxes		0.05		0.03		0.02
Depletion, depreciation and amortization		3.73		11.68		(7.95	)
General and administrative		12.89		127.89		(115.00	)

Transportation, gathering and compression expense was $0.07 million in fiscal 2013 compared to $0 in fiscal 2012. These third party costs were higher in fiscal 2013 due to our production growth where we have third party gathering and compression agreements. We have excluded these costs in the calculation of average realized sales prices.

Lease operating expense was $2.6 million in fiscal 2013 compared to $0.02 million in fiscal 2012. The increase of $2.6 million is attributable to higher production during the year ended December 31, 2013, as compared to the year ended December 31, 2012. Lease operating expenses include normally recurring expenses to operate and produce our wells, non-recurring workovers and repairs. We experience increases in operating expenses as we add new wells and manage existing properties. We incurred $0.03 million of workover costs in fiscal 2013 compared to $0 in fiscal 2012.

Production and ad valorem taxes are paid based on market prices and applicable tax rates. Production and ad valorem taxes were $0.08 million in fiscal 2013 compared to less than $0.01 million in fiscal 2012. Production and ad valorem taxes increased from fiscal 2012 to fiscal 2013 due to an increase in production volumes subject to production or ad valorem taxes.

Depletion, depreciation and amortization was approximately $6.2 million in fiscal 2013 compared to $0.4 million in fiscal 2012. The increase in fiscal 2013 when compared to fiscal 2012 is due to the increase in production during fiscal 2013. On a per Mcfe basis, DD&A decreased to $3.73 in fiscal 2013 from $11.68 in fiscal 2012, which was predominantly driven by a lower depletion rate. Depletion rates in new plays tend to be higher in the beginning as increased initial outlays are amortized over proved reserves based on early stages of evaluations, which was the case in fiscal 2012. The decrease in depletion rate in fiscal 2013 was due to total proved reserves (the denominator) increasing at a higher rate than production (the numerator) over the year. We currently expect our DD&A rate to be approximately $2.10 per Mcfe in fiscal 2014, based on our current production and reserve estimates.

General and administrative expense was $21.3 million for fiscal 2013 compared to $4.4 million for fiscal 2012. The fiscal 2013 increase of $16.9 million when compared to fiscal 2012 is primarily due to higher salaries and benefits ($10.8 million) during fiscal 2013 related to the hiring of a significant number of new employees, including those that became employees through the Oxford Acquisition, and higher legal and consulting expenses ($4.5 million) during fiscal 2013. In addition we recorded $0.04 million and $0.003 million of non-cash incentive unit compensation charges for the fiscal year end 2013 and 2012, respectively. Our personnel costs will continue to increase as we invest in our technical teams and other staffing to support the expansion of our drilling program in the Utica Core Area and Our Marcellus Project Area.

Other Operating Expenses

Our total operating expenses also include other expenses that generally do not trend with production. These expenses include exploration expense, impairment charges, and accretion expense. The following table details our other operating expenses for each of the years ended December 31, 2013 and 2012.


	Year Ended December 31,
	2013		2012		Change
Other Operating Expenses (in thousands):
Exploration	$	3,022	$	3,899	$	(877	)
Impairments of proved and unproved properties		2,081		793		1,288
Accretion		364		—		364

Exploration expense decreased to $3.0 million in fiscal 2013 compared to $3.9 million in fiscal 2012 due to lower dry hole costs, partially offset by lower seismic costs and delay rentals due to acreage increases. The following table details our exploration-related expenses for each of the years ended December 31, 2013 and 2012.


	Year Ended December 31,
	2013		2012		Change
Exploration Expenses (in thousands):
Seismic	$	124	$	263	$	(139	)
Delay rentals		2,688		213		2,475
Dry hole		210		3,423		(3,213	)

	$	3,022	$	3,899	$	(877	)

Impairment of proved and unproved properties

Impairment of unproved properties was $0 in fiscal 2013 compared to $0.8 million in fiscal 2012. We assess individually significant unproved properties for impairment on a quarterly basis and recognize a loss where circumstances indicate impairment in value. In determining whether a significant unproved property is impaired we consider numerous factors including, but not limited to, current exploration plans, favorable or unfavorable activity on the property being evaluated and/or adjacent properties, our geologists’ evaluation of the property and the remaining months in the lease term for the property. Impairment of individually insignificant unproved properties is assessed and amortized on an aggregate basis based on our average holding period, expected forfeiture rate and anticipated drilling success. As we continue to review our acreage positions and high grade our drilling inventory based on the current price environment, additional leasehold impairments and abandonments may be recorded. Impairment of proved properties increased to $2.1 million in fiscal 2013 compared to $0 in fiscal 2012. Our analysis of these properties determined that undiscounted cash flows were less than their carrying value. We compared the carrying value to estimated fair value and recognized an impairment charge. These assets were evaluated for impairment due to performance-related issues relative to our initial reserve expectations. This type of impairment is common in new plays where the reserves and production associated with the play, or within areas of the play, is not initially known.

Accretion expense was $0.4 million in fiscal 2013, compared to $0 in fiscal 2012. Accretion expense relates to the increase in the asset retirement obligations associated with new wells drilled during fiscal 2013 and existing wells acquired in the Oxford Acquisition in June 2013.

Other Income (Expense)

Interest expense, net was $20.9 million for fiscal 2013. We incurred $0 in interest expense in fiscal 2012. The increase in interest expense in fiscal 2013 was due to the June 2013 and December 2013 issuances of $281.2 million and $100.0 million, respectively, of our Senior Unsecured Notes, net of discounts, and $0.02 million of related offering expenses. We used the net proceeds from the June 2013 issuance, along with contributions from our equity investors, to fund our acquisition of Oxford. In January 2014, we paid our semi-annual interest on our Senior Unsecured Notes with additional Senior Unsecured Notes at an interest rate of 13.0% as opposed to paying in cash at the cash interest rate of 12.0%. Interest expense is net of capitalized interest on expenditures made in connection with exploration and development projects that are not subject to current amortization.

At our option, the first two interest payments subsequent to the issuance of our Senior Unsecured Notes may be satisfied with PIK Interest. Also at our option, the subsequent four semi-annual interest payments thereafter may be paid in the form of 6.0% annum per cash and 7.0% annum in PIK Interest. Thereafter (subsequent to the sixth semi-annual interest payment), interest can only be paid in cash at 12.0% per annum.

Cash Flows, Capital Resources and Liquidity

Cash Flows

Cash flows from operations are primarily affected by production volumes and commodity prices. Our cash flows from operations also are impacted by changes in working capital. Short-term liquidity needs are satisfied by our operating cash flow, proceeds from asset sales, and the remaining proceeds from our fiscal 2013 issuances of Senior Unsecured Notes and equity units. We sell a large portion of our production at the wellhead under floating market contracts.

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

Net cash provided by operations in the three months ended March 31, 2014 was $0.1 million compared to $0.2 million in the three months ended March 31, 2013. The decrease in cash provided from operating activities from the three months ended 2013 to 2014 reflects an increase in production, offset by higher operating costs. Net cash provided from operations is also affected by working capital changes or the timing of cash receipts and disbursements. Changes in working capital (as reflected in our consolidated statements of cash flows) for the three months ended March 31, 2014 was $(12.9) million compared to $1.4 million for the three months ended March 31, 2013. The decrease in working capital is primarily due to requirements associated with drilling and exploration.

Net cash used in investing activities in the three months ended March 31, 2014 was $151.1 million compared to $69.2 million in the three months ended March 31, 2013.

During the three months ended March 31, 2014, we:

•

spent $149.6 million on related capital expenditures and unproved properties; and

•

spent $1.5 million on property and equipment

During the three months ended March 31, 2013, we:

•

spent $76.5 million on related capital expenditures and unproved properties; and

•

received proceeds of $7.3 million from the sale of properties

Net cash provided by financing activities in the three months ended March 31, 2014 increased to $68.9 million compared to $58.1 million in the three months ended March 31, 2013. Historically, sources of financing have been primarily from equity issuances.

During the three months ended March 31, 2014, we:

•

obtained a revolving credit facility for $50.0 million and incurred $0.8 million of related loan issuance costs; and

•

issued Series A, A-1 and B units for a total of $49.7 million.

During the three months ended March 31, 2013, we issued a total of $58.0 million in equity.

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

Net cash provided from (used by) operations in fiscal 2013 was $15.2 million compared to $(3.4) million in fiscal 2012. The increase in cash provided from operating activities from fiscal 2012 to fiscal 2013 reflects an increase in production, offset by higher operating costs. Net cash provided from operations is also affected by working capital changes or the timing of cash receipts and disbursements. Changes in working capital (as reflected in our consolidated statements of cash flows) for fiscal 2013 was $24.2 million compared to a $0.7 million for fiscal 2012. The increase in working capital is primarily due to requirements associated with drilling and exploration.

Net cash used in investing activities in fiscal 2013 was $897.1 million compared to $47.5 million in fiscal 2012.

During the year ended December 31, 2013, we:

•

spent $651.8 million, net of cash acquired, on the Oxford Acquisition;

•

spent $252.8 million on related capital expenditures and unproved properties; and

•

received proceeds of $8.5 million from the sale of 1,220 net acres within our area of mutual interest with Antero Resources in Noble County, Ohio.

During the year ended December 31, 2012, we:

•

spent $158.1 million on acreage, primarily in the Utica Shale, and capital expenditures of $21.1 million; and

•

received proceeds of $126.5 million primarily related to the sale of approximately 21,000 net acres within our area of mutual interest with Antero Resources, along with other insignificant sales.

Net cash provided from financing activities in fiscal 2013 increased to $964.3 million in fiscal 2013 compared to $68.9 million in fiscal 2012.

During the year ended December 31, 2013, we:

•

issued $400.0 million in aggregate principal amount of our Senior Unsecured Notes and incurred $12.0 million related to discounts and $7.3 million related to offering expenses; and

•

issued Series A, A-1 and B units for a total of $583.6 million.

During 2012, we issued of Series A and A-1 units for a total of $69.6 million.

Liquidity and Capital Resources

Our main sources of liquidity and capital resources are internally generated cash flow from operations, asset sales and access to the debt and equity capital markets. We must find new and develop existing reserves to maintain and grow our production and cash flows. We accomplish this primarily through successful drilling programs which requires substantial capital expenditures.

Future success in growing reserves and production will be highly dependent on capital resources available and the success of finding or acquiring additional reserves. We currently believe that net cash generated from borrowings activities, capital contributions, remaining proceeds from previous issuances of our Senior Unsecured Notes and equity units and proceeds under our Revolving Credit Facility will be adequate to satisfy near-term financial obligations and liquidity needs. To the extent our capital requirements exceed our internally generated cash flow and proceeds from asset sales, additional debt or equity may be issued to fund these requirements. Long-term cash flows are subject to a number of variables including the level of production and prices we receive for our production as well as various economic conditions that have historically affected the natural gas and oil business. Our ability to expand our reserve base is, in part, dependent on obtaining sufficient capital through internal cash flow, bank borrowings, asset sales or the issuance of debt or equity securities. There can be no assurance that internal cash flow and other capital sources will provide sufficient funds to maintain capital expenditures that we believe are necessary to offset inherent declines in production and proven reserves.

Credit Arrangements

Long-term debt at March 31, 2014 totaled $412.2 million and at December 31, 2013 totaled $389.2 million, consisting of our Senior Unsecured Notes.

The indenture governing our Senior Unsecured Notes imposes limitations on the payment of dividends and other restricted payments (as defined in the indenture). The indenture also contains customary covenants relating to debt incurrence, working capital, dividends and financial ratios. We were in compliance with all covenants at December 31, 2013.

In February 2014, we entered into our $500.0 million Revolving Credit Facility. As of March 21, 2014, the initial borrowing base under our Revolving Credit Facility was $50.0 million, of which $20.0 million was drawn at a weighted average interest rate of 1.99%. As of May 1, 2014, our borrowing base was increased to $100 million, of which $60 million was drawn. To ensure our borrowing base more closely conforms to our growth in reserves, the borrowing base under our Revolving Credit Facility is scheduled to be redetermined quarterly on April 1, July 1, October 1 of 2014 and January 1 of 2015 and semi-annually thereafter beginning on April 1, 2015 (April and October).

We have the right to redeem all or a portion of the Senior Unsecured Notes prior to December 20, 2015 by paying a redemption price equal to a “make whole premium” equal to the greater of 106.0% or an amount computed under the indenture governing the Senior Unsecured Notes plus accrued and unpaid interest. After December 20, 2015, we may redeem all or a part of the Senior Unsecured Notes at the redemption prices (expressed as percentages of principal amount) set forth below, plus accrued and unpaid interest:


Year following December 20, 2015	Redemption Price
Year 1		106.0	%
Year 2		103.0	%
Year 3 and thereafter		100.0	%

At our option, for the first 2 semi-annual interest payments following the date the notes were first issued, interest may be payable by increasing the principal amount of the Senior Unsecured Notes or by PIK interest. At our option, for the subsequent four semi-annual interest payments thereafter, interest may be payable in the form of 6.0% per annum in cash and 7.0% per annum in PIK interest. Thereafter, interest can only be paid as cash interest. Interest on the Senior Unsecured Notes paid by paying PIK interest accrues at 13.0%, while interest paid by cash accrues at 12.0%.

Commodity Hedging Activities

Our primary market risk exposure is in the prices we receive for our natural gas, NGLs and oil production. Realized pricing is primarily driven by the spot regional market prices applicable to our U.S. natural gas, NGLs

and oil production. Pricing for natural gas, NGLs 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, NGLs and oil prices, we may enter into financial commodity derivative contracts to ensure that we receive minimum prices for a portion of our future natural gas production when management believes that favorable future prices can be secured. In January 2014, we entered into financial commodity derivative contracts in the form of natural gas swaps for a portion of our natural gas volume in 2014 and 2015. In February 2014, we entered into financial commodity derivative contracts in the form of a natural gas put spread for a portion of our natural gas volume in 2014. We plan to typically hedge the NYMEX Henry Hub price for natural gas, the West Texas Intermediate, or WTI, price for oil and an NGLs basket based on prices at Mont Belvieu, Texas.

Our hedging activities are intended to support natural gas, NGLs and oil prices at targeted levels and to manage our exposure to price fluctuations. The counterparty is required to make a payment to us for the difference between the floor 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 floor price. We are required to make a payment to the counterparty for the difference between the ceiling price and the settlement price if the ceiling price is below the settlement price. These contracts may include price swaps whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty, zero cost collars that set a floor and ceiling price for the hedged production, and puts which require us to pay a premium either up front or at settlement and allow us to receive a fixed price at our option if the put price is above the market price. As of March 21, 2014, we had entered into the following derivative contracts:


Description	Volume (MMBtu/d)		Production Period		Weighted Average Swap Price ($/MMBtu)⁽¹⁾
Natural Gas Swaps:
		20,000		March 14—December 14	$	4.175
		20,000		January 15—December 15		4.090

Description:	Volume (MMBtu/d)		Production Period		Weighted Average Strike Price ($/MMBtu)⁽²⁾
Natural Gas Put Spread:
Purchased Put		20,000		June 14—December 14	$	4.50
Sold Put		20,000		June 14—December 14	$	4.00

(1)

The natural gas derivative contracts are settled based on the month’s average daily NYMEX price of natural gas at Henry Hub.

(2)

The natural gas put spread contracts are settled based on the NYMEX price of natural gas at Henry Hub on the last commodity business day of the futures contract corresponding to the calculation period.

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 Bank of Montreal. We believe Bank of Montreal currently is an acceptable credit risk. As of March 31, 2014, we did not have any past due receivables from counterparties.

Capital Requirements

Our primary needs for cash are for exploration, development and acquisition of natural gas and oil properties and repayment of principal and interest on outstanding debt. During the three months ended March 31, 2014, costs incurred for drilling projects were $137.2 million, and for fiscal 2013 were $261.8 million. In the three months ended March 31, 2014 there were no acquisitions, while during fiscal 2013, costs incurred for acquisition of unproved property totaled $621.0 million, primarily in the Utica Shale. Our fiscal 2013 capital program, excluding acquisitions, was funded by net cash flow from operations, proceeds from asset sales and proceeds from the issuances of Senior Unsecured Notes and equity units. Our capital expenditure budget for fiscal 2014 excludes acquisitions, other than leasehold acquisitions, and is currently set at $696.3 million. We expect to fund our capital expenditures in fiscal 2014 with cash generated by operations, borrowings under our Revolving Credit Facility, net proceeds received from our previous issuance of Senior Unsecured Notes, and a portion of the net proceeds of this offering. 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, NGLs and oil 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, NGLs or oil prices from current levels may result in a decrease in our actual capital expenditures, which would negatively impact our ability to grow production. 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.

Capitalization

As of March 31, 2014, December 31, 2013 and 2012, our total debt and capitalization were as follows (in millions):


	March 31 2014			2013			2012
Senior Unsecured Notes		412.2		$	389.2		$	—
Credit Facility		20.0			—			—
Partners’ capital		698.4			667.9			126.7

Total capitalization		1,130.6		$	1,057.1		$	126.7

Debt to capitalization ratio		36.5	%		36.8	%		0.0	%

Cash Contractual Obligations

Our contractual obligations include long-term debt, operating leases, drilling commitments, derivative obligations and asset retirement obligations. As of March 31, 2014 and December 31, 2013, we do not have any capital leases. As of March 31, 2014 and December 31, 2013, we do not have any significant off-balance sheet debt or other such unrecorded obligations and we have not guaranteed any debt of any unrelated party. The table below provides estimates of the timing of future payments that we are obligated to make based on agreements in place at March 31, 2014. In addition to the contractual obligations listed in the table below, our balance sheet at March 31, 2014 reflects accrued interest payable on our Senior Unsecured Notes of $11.4 million, compared to $20.3 million as of December 31, 2013. We settled $22.4 million of our accrued interest in January 2014 through the issuance of additional Senior Unsecured Notes. We expect to make interest payments of approximately $28.0 million on our Senior Unsecured Notes if paid with cash in 2014.

The following summarizes our contractual financial obligations at March 31, 2014 and their future maturities. We expect to fund these contractual obligations with cash generated from operating activities, borrowings under our Revolving Credit Facility, additional debt issuances and proceeds from asset sales (in millions).


	Payment due by period
	2014		2015		2016		2017 and 2018			Thereafter		Total
Senior Unsecured Notes⁽¹⁾	$	—	$	—	$	—	$	400.0	⁽¹⁾	$	—	$	400.0
Credit Facility		—		—		—		20.0			—		20.0
Operating leases		0.2		0.2		0.2		0.2			—		0.8
Drilling rig commitments		5.4		—		—		—			—		5.4
Asset retirement obligation liability		—		—		—		—			9.1		9.1

Total contractual obligations	$	5.6	$	0.2	$	0.2	$	420.2		$	9.1	$	435.3

(1)

The ultimate settlement amount and timing cannot be precisely determined in advance. See Note 7 to our unaudited consolidated financial statements as of and for the three months ended March 31, 2014.

Other

We lease acreage that is generally subject to lease expiration if operations are not commenced within a specified period, generally 5 years and approximately 72% of our leases in the Utica Core Area have a 5-year extension at our option. We do not expect to lose significant lease acreage because of failure to commence operations due to inadequate capital, equipment or personnel. However, based on our evaluation of prospective economics, including the cost of infrastructure to connect production, we have allowed acreage to expire and will allow additional acreage to expire in the future. To date, our expenditures to comply with environmental or safety regulations have not been a significant component of our cost structure and are not expected to be significant in the future. However, new regulations, enforcement policies, claims for damages or other events could result in significant future costs.

Interest Rates

At March 31, 2014, we had $412.2 million as compared to $389.2 million as of December 31, 2013 of Senior Unsecured Notes outstanding that bear interest at a fixed cash interest rate of 12.0% and is due semi-annually from the date of issuance. At our option, the first two interest payments can be PIK Interest at a 13% per annum interest rate. Also at our option, the subsequent four semi-annual interest payments thereafter may be paid in the form of 6.0% per annum in cash and 7.0% per annum in PIK Interest. Thereafter (subsequent to the sixth semi-annual interest payment), interest can only be paid in cash at a 12.0% per annum interest rate.

In February 2014, we entered into our $500.0 million senior secured revolving credit facility. As of March 31, 2014, the initial borrowing base under our Revolving Credit Facility was $50.0 million, of which $20.0 million was drawn at a weighted average interest rate of 1.99%. As of May 1, 2014 our borrowing base was increased to $100 million, of which $60 million was drawn. Interest on outstanding borrowings under our Revolving Credit Facility will accrue based on, at our option, LIBOR or the alternate base rate, in each case, plus an applicable margin that is determined based on our utilization of commitments under our Revolving Credit Facility.

Off-Balance Sheet Arrangements

We do not currently utilize any off-balance sheet arrangements with unconsolidated entities to enhance our liquidity or capital resource position, or for any other purpose. However, as is customary in the oil and gas industry, we have various contractual work commitments which are described above under cash contractual obligations.

Inflation and Changes in Prices

Our revenues, the value of our assets and our ability to obtain bank loans or additional capital on attractive terms have been and will continue to be affected by changes in natural gas, NGLs and oil prices and the costs to produce our reserves. Natural gas, NGLs and oil prices are subject to significant fluctuations that are beyond our ability to control or predict. Although certain of our costs and expenses are affected by general inflation, it does not normally have a significant effect on our business. We expect costs in fiscal 2014 to continue to be a function of supply and demand.

Critical Accounting Estimates

Our discussion and analysis of our financial condition and results of operations are based upon consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at year end, the reported amounts of revenues and expenses during the year and proved natural gas and oil reserves. Some accounting policies involve judgments and uncertainties to such an extent there is a reasonable 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 we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying value of assets and liabilities that are not readily apparent from other sources. Actual results could differ from the estimates and assumptions used.

Certain accounting estimates are considered to be critical if (a) the nature of the estimates and assumptions is material due to the level of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to changes; and (b) the impact of the estimates and assumptions on financial condition or operating performance is material.

Natural Gas and Oil Properties

We follow the successful efforts method of accounting for natural gas and oil producing activities. Unsuccessful exploration drilling costs are expensed and can have a significant effect on reported operating results. Successful exploration drilling costs and all development costs are capitalized and systematically charged to expense using the units of production method based on proved developed natural gas and oil reserves as estimated by our engineers and audited by independent engineers. Costs incurred for exploratory wells that find reserves that cannot yet be classified as proved are capitalized on our balance sheet if (a) the well has found a sufficient quantity of reserves to justify its completion as a producing well; and (b) we are making sufficient progress assessing the reserves and the economic and operating viability of the project. Proven property leasehold costs are amortized to expense using the units of production method based on total proved reserves. Properties are assessed for impairment as circumstances warrant (at least annually) and impairments to value are charged to expense. The successful efforts method inherently relies upon the estimation of proved reserves, which includes proved developed and proved undeveloped volumes.

Proved reserves are defined by the SEC as those volumes of natural gas, NGLs, condensate and crude oil that geological and engineering data demonstrate with reasonable certainty are economically recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are volumes expected to be recovered through existing wells with existing equipment and operating methods, or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Although our engineers are knowledgeable of and follow the guidelines for reserves established by the SEC, including the rule revisions designed to modernize the oil and gas company reserves reporting requirements which were adopted effective December 31, 2009, the estimation of reserves requires engineers to make a significant number of assumptions based on professional judgment. Reserve estimates are updated at least annually and consider recent production levels and other technical information. Estimated reserves are often

subject to future revisions, which could be substantial, based on the availability of additional information, including: reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price and cost changes and other economic factors. Changes in natural gas, NGLs and oil prices can lead to a decision to start-up or shut-in production, which can lead to revisions to reserve quantities. Reserve revisions in turn cause adjustments in our depletion rates. We cannot predict what reserve revisions may be required in future periods. Reserve estimates are reviewed and approved by our Vice President, Business Development, Finance and Reservoir Engineering who reports directly to our Chief Financial Officer. For additional discussion, see “Business—Proved Reserves.” To further ensure the reliability of our reserve estimates, we engage independent petroleum engineers to prepare our estimates of proved reserves at least annually. NSAI, our independent petroleum engineers, prepared 100% of our reserves in 2014, 2013 and 2012.

Depletion rates are determined based on reserve quantity estimates and the capitalized costs of producing properties. As the estimated reserves are adjusted, the depletion expense for a property will change, assuming no change in production volumes or the capitalized costs. While total depletion expense for the life of a property is limited to the property’s total cost, proved reserve revisions result in a change in the timing of when depletion expense is recognized. Downward revisions of proved reserves may result in an acceleration of depletion expense, while upward revisions tend to lower the rate of depletion expense recognition. Estimated reserves are used as the basis for calculating the expected future cash flows from property asset groups, which are used to determine whether that property may be impaired. Reserves are also used to estimate the supplemental disclosure of the standardized measure of discounted future net cash flows relating to natural gas and oil producing activities and reserve quantities in Note 12 to our consolidated financial statements. Changes in the estimated reserves are considered a change in estimate for accounting purposes and are reflected on a prospective basis.

We monitor our long-lived assets recorded in natural gas and oil properties in our consolidated balance sheets to ensure they are fairly presented. We must evaluate our properties for potential impairment when circumstances indicate that the carrying value of an asset could exceed its fair value. A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events. Such events include a projection of future natural gas, NGLs and oil prices, an estimate of the ultimate amount of recoverable natural gas, NGLs and oil reserves that will be produced from the property asset groups future production, future production costs, future abandonment costs, and future inflation. The need to test a property asset group for impairment can be based on several factors, including a significant reduction in sales prices for natural gas, NGLs and/or oil, unfavorable adjustments to reserves, physical damage to production equipment and facilities, a change in costs, or other changes to contracts or environmental regulations. Our natural gas and oil properties are reviewed for potential impairments at the lowest levels for which there are identifiable cash flows that are largely independent of other groups of assets. All of these factors must be considered when testing a property asset groups carrying value for impairment.

The review is done by determining if the historical cost of proved properties less the applicable accumulated depreciation, depletion and amortization is less than the estimated undiscounted future net cash flows. The expected undiscounted future net cash flows are estimated based on our plans to produce and develop reserves. Expected undiscounted future net cash inflows from the sale of produced reserves are calculated based on estimated future prices and estimated operating and development costs. We estimate prices based upon market related information including published futures prices. The estimated future level of production, which is based on proved and risk adjusted probable reserves, has assumptions surrounding the future levels of prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. In certain circumstances, we also consider potential sales of properties to third parties in our estimates of undiscounted future cash flows. When the carrying value exceeds the sum of undiscounted future net cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future net cash flows using a discount rate similar to that used by market participants) and the carrying value of the asset. We cannot predict whether impairment charges may be required in the future.

We believe that a sensitivity analysis regarding the effect of changes in assumptions on estimated impairment is impractical to provide because of the number of assumptions and variables involved which have interdependent effects on the potential outcome. If natural gas, NGLs and oil prices decrease or drilling efforts are unsuccessful, we may be required to record additional impairments.

We evaluate our unproved property investment periodically for impairment. The majority of these costs generally relate to the acquisition of leaseholds. The costs are capitalized and evaluated (at least quarterly) as to recoverability, based on changes brought about by economic factors and potential shifts in business strategy employed by management. Impairment of a significant portion of our unproved properties is assessed and amortized on an aggregate basis based on our average holding period, expected forfeiture rate and anticipated drilling success. Potential impairment of individually significant unproved property is assessed on a property-by-property basis considering a combination of time, geologic and engineering factors.

Acquisitions

As part of our business strategy, we periodically pursue the acquisition of oil and natural gas properties. The purchase price in an acquisition is allocated to the assets acquired and liabilities assumed based on their relative fair values as of the acquisition date, which may occur many months after the announcement date. Therefore, while the consideration to be paid may be fixed, the fair value of the assets acquired and liabilities assumed is subject to change during the period between the announcement date and the acquisition date. Our most significant estimates in our allocation typically relate to the value assigned to future recoverable oil and natural gas reserves and unproved properties. As the allocation of the purchase price is subject to significant estimates and subjective judgments, the accuracy of this assessment is inherently uncertain.

Asset Retirement Obligations

We have significant obligations to remove tangible equipment and restore land at the end of natural gas and oil production operations. Removal and restoration obligations are primarily associated with plugging and abandoning wells. Estimating the future asset removal costs is difficult and requires us to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.

Inherent in the fair value calculation are numerous assumptions and judgments including the ultimate retirement costs, inflation factors, credit-adjusted discount rates, timing of retirement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation (“ARO”), a corresponding adjustment is made to the natural gas and oil property balance. For example, as we analyze actual plugging and abandonment in formation, we may revise our estimate of current costs, the assumed annual inflation of the costs and/or the assumed productive lives of our wells. In addition, increases in the discounted ARO liability resulting from the passage of time are reflected as accretion expense, a component of depletion, depreciation and amortization in the accompanying consolidated statements of operations. Because of the subjectivity of assumptions and the relatively long lives of most of our wells, the costs to ultimately retire our wells may vary significantly from prior estimates.

Revenue Recognition

Natural gas, NGLs and oil sales are recognized when the products are sold and delivery to the purchaser has occurred. We use the sales method to account for gas imbalances, recognizing revenue based on gas delivered rather than our working interest share of gas produced. We generally sell natural gas, NGLs and oil under two types of agreements, which are common in our industry. Both types of agreements include transportation charges. We report our gathering and transportation costs in accordance with Financial Accounting Standards Board (“FASB”) Section 605-45-05 of Subtopic 605-45 for Revenue Recognition.

Under one type of agreement, we sell natural gas, NGLs or oil at a specific delivery point, pay transportation, gathering and compression to a third party and receive proceeds from the purchaser with no deduction. In that case, we record these costs as transportation, gatherings and compression expense. The other type of agreement, which is only used on a portion of our historically acquired vertical wells, is a netback arrangement under which we sell natural gas and oil at the wellhead and collect a price, net of transportation incurred by the purchaser. In this case, we record revenue at the price we received from the purchaser. In the case of NGLs, we receive a net price from the purchaser (which is net of processing costs) which is recorded in revenue at the net price. Regardless of agreement type, revenue is recorded in the month the product is delivered to the purchaser as title has transferred.

To the extent we have not been paid for production related to a given reporting period, we record an accrual for revenue based on our estimate of the amount of production delivered to purchasers and the price we will receive, along with any related transportation costs. We estimate volumes delivered based on production information or from historical operating results of individual properties when production information is not available, for example, for certain non-operated properties. Prices for such production and related transportation costs are defined in sales contracts and are readily determinable based on publicly available indices. Given the information available to us, we do not believe there to be any material implications with respect to uncertainties in developing these estimates and historically, our actual receipts have not been materially different from our accruals. The purchasers of such production have historically made payment for oil, NGLs and natural gas purchases within 30-60 days of the end of each production month, at which time any variance between our estimated revenue and transportation costs and actual payments is recorded.

Quantitative and Qualitative Disclosures 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 risks. The term “market risk” refers to the risk of loss arising from adverse changes in natural gas, NGLs and oil 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 exposure. All of our market-risk sensitive instruments were entered into for purposes other than trading. All accounts are US dollar denominated.

Commodity Price Risk

We are exposed to market risks related to the volatility of natural gas, NGLs and oil prices. Realized prices are primarily driven by worldwide prices for oil and spot market prices for North American gas production. Natural gas and oil prices have been volatile and unpredictable for many years. Natural gas prices affect us more than oil prices because approximately 63% of our March 31, 2014 and 67% of our December 31, 2013 proved reserves were natural gas.

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 prices, see “—Commodity Hedging Activities.”

Interest Rate Risk

At March 31, 2014, the cash interest rate with respect to our $412.2 million of Senior Unsecured Notes is fixed at 12.0%, and is due semi-annually from the date of issuance.

We will be exposed to interest rate risk in the future if we draw on our Revolving Credit Facility. Interest on outstanding borrowings under our Revolving Credit Facility will accrue based on, at our option, LIBOR or the alternate base rate, in each case, plus an applicable margin that is determined based on our utilization of commitments under our Revolving Credit Facility. As of March 31, 2014, the initial borrowing base under our Revolving Credit Facility was $50.0 million, of which $20.0 million was drawn at a weighted average interest rate of 1.99%. As of May 1, 2014, our borrowing base was increased to $100 million, of which $60 million was drawn.

BUSINESS

Please see “Defined Terms” on page ii of this prospectus for definitions of some terms used in this prospectus and Annex A to this prospectus for a glossary of other defined terms used in this prospectus, including certain oil and natural gas industry terms.

Our Company

We are an independent exploration and production company engaged in the acquisition and development of oil and natural gas properties in the Appalachian Basin. As of March 31, 2014, we had assembled a leasehold position approximating 227,230 net acres in Eastern Ohio. Approximately 96,240 of our net acres are located in what we believe to be the most prolific and economic area of the Utica Shale fairway, which we refer to as the Utica Core Area, and approximately 25,740 of these net acres are also prospective for the highly liquids rich area of the Marcellus Shale in Eastern Ohio within what we refer to as Our Marcellus Project Area. The geographic extent of the Utica Core Area and Our Marcellus Project Area is depicted on the map located on the inside cover of this prospectus and defined in the section of this prospectus titled “Defined Terms.” We are the operator of approximately 81% of our net acreage within the Utica Core Area and Our Marcellus Project Area. As of March 31, 2014, we had identified 863 net horizontal drilling locations across our acreage, comprised of 668 locations within the Utica Core Area and 195 locations within Our Marcellus Project Area. As of March 31, 2014, we, or our operating partners, had commenced drilling 72 gross wells within the Utica Core Area and 3 gross wells within Our Marcellus Project Area. We intend to focus on developing our substantial inventory of horizontal drilling locations and will continue to opportunistically add to our acreage position where we can acquire acreage at attractive prices.

We have assembled a team of executive and operating professionals with significant knowledge and experience in the Appalachian Basin, particularly with respect to drilling unconventional oil and natural gas wells, managing large scale drilling programs and optimizing the value of the associated production through a coordinated midstream effort. Our senior management has over 250 years of combined engineering, land, legal and financial expertise. Benjamin W. Hulburt, our Chairman, President and Chief Executive Officer, and Christopher K. Hulburt, our Executive Vice President, Secretary and General Counsel, co-founded Eclipse Resources in 2011. Ben Hulburt co-founded Rex Energy where he served as its President and Chief Executive Officer from the company’s inception through its considerable growth and entry into the liquids rich region of the Marcellus Shale. Chris Hulburt was formerly the Executive Vice President, Secretary and General Counsel of Rex Energy. Thomas S. Liberatore, our Executive Vice President and Chief Operating Officer, was formerly the Vice President and Appalachian Basin Regional Manager for Cabot Oil & Gas, where he led that company’s entry into its industry leading Marcellus Shale position in Northeastern Pennsylvania. Additionally, our Vice President of Drilling & Completions; Geology; Operations; Land; and Health, Safety, Environment & Regulatory all have significant experience in the Appalachian region. See “Management.”

We began assembling our acreage position in 2011 based upon a rigorous analytical evaluation of the shale properties within the Utica and Point Pleasant formations across Eastern Ohio. Based upon this evaluation, which incorporated multiple high-graded geological and petrophysical characteristics, we concentrated our acreage acquisition efforts in an area spanning parts of 5 counties that we believed would be the most prolific region of the play. This area, covering parts of Noble, Guernsey, Monroe, Belmont and Harrison counties, is located in what we now refer to as the Utica Core Area. According to the Ohio Department of Natural Resources, as of February 8, 2014, there were 310 producing horizontal Utica Shale wells in the State of Ohio, 107 of which were in these 5 counties. Based upon production data from the wells we have drilled or participated in and our analysis of the results publicly released by other operators, we believe that our evaluation of the Utica Shale has been validated and that the Utica Core Area, where we have accumulated a substantially contiguous position of approximately 96,240 net acres, is the most prolific part of the play.

The composition of production from our wells and those of offset operators has corroborated our view that there are various type curve areas in the Utica Core Area moving from east to west in the play. Across the Utica Core Area, the eastern boundary is more thermally mature and expected to produce dry gas, while the western boundary is less thermally mature and expected to produce a greater proportion of condensate and NGLs in addition to natural gas. We classify our acreage between these boundaries as being prospective for Dry Gas, Rich Gas, Condensate or Rich Condensate. We expect our Marcellus Project Area to produce a significant proportion of condensate and NGLs in addition to natural gas. Additionally, we own approximately 131,070 net acres (which are approximately 85% held by production) outside of the Utica Core Area that may be prospective for the oil window of the Utica Shale representing upside potential. The table below outlines our Utica Core Area and Our Marcellus Project Area acreage and identified drilling locations within each type curve area as of March 31, 2014, along with a summary of our expected 2014 drilling plan:


				Identified Drilling Locations				2014 Drilling Plan
Type Curve Area	Net Acreage⁽¹⁾			Gross⁽²⁾		Net⁽²⁾		Gross Wells Spud⁽³⁾		Net Wells Spud⁽³⁾		Net Wells Turned to Sales⁽³⁾
Dry Gas.		32,670			771		210		29		9.6		4.4
Rich Gas		34,160			937		239		61		16.7		6.8
Condensate		25,150			647		169		83		43.1		27.7
Rich Condensate		5,260			422		49		0		0		0

Total Utica Core Area		96,240			2,777		667		173		69.4		38.9

Marcellus Project Area		25,740	⁽⁴⁾		604		195		3		0.1		1.2

Total					3,381		863		176		69.5		40.1

(1)

(2)

(3)

73 gross operated wells and 103 gross non-operated wells planned to be spud, and 42 gross operated wells and 63 gross non-operated wells planned to be turned to sales.

(4)

Acreage in Our Marcellus Project Area is also included in our total Utica Core Area acreage.

Our Properties

Utica Shale

results as measured by initial production rates. Our analysis of wells in the Utica Core Area fairway, which we believe to be the most prolific area of the play, indicates that single well rates of return in that region may rival any onshore resource play in North America.

When we plan our drilling program, we expect to drill wells with an average lateral length of approximately 6,000 feet, which generally enables us to deploy 4 horizontal wells (assuming 1,000 foot interlateral spacing) or 5 horizontal wells (assuming 750 foot interlateral spacing) in a drilling unit consisting of approximately 640 acres. In order to improve the comparability of well results publicly disclosed by different operators to the results we expect from our drilling program, we normalize the initial production rate data to a 6,000 foot lateral, which we refer to as a Normalized 6,000 Foot IP. The following table illustrates the initial production rates, Normalized 6,000 Foot IP and hydrocarbon composition for the 56 wells we have evaluated in the Utica Core Area. The wells in the following table have been grouped by their location within the type curve areas that we use to classify our acreage within the Utica Core Area. Within each classification, such wells are sorted in descending order by Normalized 6,000 Foot IP. See page 25 of this prospectus for a discussion of certain risks and uncertainties relating to our use of publicly disclosed initial production rates in this prospectus.


Map	Well Name	Operator	Eclipse Partici- pation	Normalized 6,000 ft. IP (Boe/d)⁽¹⁾		Lateral Length (ft)		24 Hr IP⁽¹⁾ (Boe/d)		24 Hr Gas IP⁽¹⁾(MMcf/ d)		Gas (Btu)		Gas Shrink (%)⁽¹⁾		NGLs Yield⁽¹⁾ (Bbls/ MMcf)		Cond. Yield (Bbls/ MMcf)		% NGLs⁽¹⁾		% Cond.
1	Stalder 3UH	MHR	X		6,436		5,050		5,417		32.5		*		—		—		—		—		—
2	Irons 1-4H	Gulfport			4,571		6,629		5,050		30.3		1,072		—		—		—		—		—
3	Porterfield 1H-17	Hess			4,105		5,000		3,421		*		*		*		*		*		21		*
4	Tippens 6HS	Eclipse	X		3,966		5,850		3,867		23.2		1,035		—		—		—		—		—
5	Richland B 1H-34	Hess			3,651		4,905		2,985		*		*		*		*		*		*		*
6	Stutzman 1-14H	Gulfport			2,821		8,634		4,060		21.0		1,078		11		45		—		23		—
Dry Gas Average:					4,258		6,011		4,133		26.8		1,062		3		11		—		9		—
7	Yontz 1H	Antero			10,415		5,115		8,879		38.9		1,161		13		82		1		36		1
8	Rubel 1H	Antero			7,248		6,554		7,917		31.1		1,231		17		109		7		43		3
9	Rubel 2H	Antero			7,137		6,571		7,816		30.9		1,217		17		106		8		42		3
10	Norman 1H	Antero			6,745		5,498		6,181		26.1		1,186		15		93		2		39		1
11	Rubel 3H	Antero			6,629		6,424		7,097		28.4		1,220		17		106		5		42		2
12	Shugert 1-12H	Gulfport			5,477		8,197		7,482		28.5		1,204		10		102		11		39		4
13	Noble 1H	Rex			5,218		3,378		2,938		8.0		1,216		20		152		49		41		13
14	Guernsey 2H	Rex			5,128		3,640		3,111		8.1		1,207		20		148		70		39		18
15	Shugert 1-1H	Gulfport			5,119		5,758		4,913		20.0		1,204		17		100		7		41		3
16	Guernsey 1H	Rex			4,964		3,587		2,968		7.6		1,216		20		152		72		39		18
17	Gary 2H	Antero			4,885		8,900		7,246		28.9		1,220		16		106		6		42		2
18	Dollison 1 H	Antero	X		4,398		6,253		4,583		12.5		1,238		18		119		112		32		30
19	Wagner 1-28H	Gulfport			3,426		8,143		4,650		17.1		1,214		18		110		25		40		9
20	Buell 8H	CHK			2,814		6,418		3,010		9.5		*		*		*		*		*		*
21	J. Anderson 2H	Rex			2,783		4,250		1,971		5.2		1,257		12		147		83		39		22
22	J. Anderson 5H	Rex			2,713		4,250		1,922		5.1		1,257		12		156		76		41		20
23	J. Anderson 3H	Rex			2,620		4,250		1,856		5.0		1,257		12		151		71		41		19
24	J. Anderson 4H	Rex			2,616		4,250		1,853		5.0		1,257		12		150		73		40		20
25	J. Anderson 1H	Rex			2,584		4,250		1,830		5.1		1,257		12		146		69		40		19
26	Cadiz 1H-23	Hess			2,568		5,257		2,250		*		*		*		*		*		*		*
27	Wagner 3-28H	Gulfport			2,278		6,867		2,607		9.7		1,214		18		110		22		41		8
28	McCort 1-28H	Gulfport			1,774		7,501		2,218		9.6		1,167		14		87		—		38		—
29	McCort 2-28H	Gulfport			1,708		9,489		2,701		11.6		1,167		14		87		2		37		1
Rich Gas Average:					4,402		5,861		4,261		16.0		1,217		15		120		37		40		10
30	Milligan 2H	Antero	X		6,712		5,989		6,700		17.2		1,276		22		137		121		35		31
31	Milligan 3H	Antero	X		6,095		5,267		5,350		15.4		1,276		21		137		80		39		23
32	Wayne 4H	Antero	X		5,265		6,493		5,698		14.2		1,265		21		134		135		33		34
33	Wayne 3HA	Antero	X		5,231		6,712		5,852		14.7		1,272		21		137		130		34		33
34	Coal 3H	Antero	X		4,544		7,768		5,883		15.1		1,278		22		137		123		35		31
35	Wayne 2H	Antero	X		4,191		6,094		4,257		10.9		1,281		22		138		122		35		31
36	Milligan 1H	Antero	X		4,009		6,436		4,300		10.6		1,276		22		138		136		34		34
37	Miley 2H	Antero	X		3,647		6,153		3,740		8.6		1,278		22		136		169		31		39
38	BK Stephens 1-16H	Gulfport			3,420		5,276		3,007		6.9		1,207		11		110		177		25		41
39	Miley 5HA	Antero	X		3,211		6,296		3,369		7.7		1,291		22		142		167		32		38
40	Detweiler 42-3H	PDC			3,163		3,868		2,039		3.3		1,263		21		173		327		28		53
41	Rector 1H	Carizo	X		2,339		7,890		3,076		5.6		1,248		17		111		300		20		55
42	Ryser 1-25H	Gulfport			2,109		8,291		2,914		5.9		1,160		21		110		252		22		51
43	Clay 1-4H	Gulfport			1,812		7,372		2,226		5.9		1,258		27		129		127		34		34
44	Boy Scout 5-33H	Gulfport			1,654		6,029		1,662		2.9		1,259		22		132		311		23		54
45	Stout 1-28H	Gulfport			1,526		6,003		1,527		4.2		1,237		19		123		105		34		29
46	Boy Scout 4-33H	Gulfport			1,070		5,848		1,043		2.0		1,289		22		132		260		25		50
47	Stout 2-28H	Gulfport			1,127		6,914		1,299		3.3		1,269		20		135		125		34		32
48	Clay 3-4H	Gulfport			910		6,715		1,019		2.5		1,258		27		129		157		32		38
Condensate Average:					3,265		6,390		3,419		8.3		1,260		21		133		175		31		38
49	Boy Scout 1-33H	Gulfport			2,600		7,974		3,456		7.1		1,310		25		142		220		29		45
50	Onega Commissioners 14-25H	PDC			2,280		3,950		1,501		2.3		1,254		20		183		445		28		67
51	Groh 1-12H	Gulfport			2,144		5,414		1,935		2.8		1,247		18		131		424		19		61
52	Lyon 2-27H	Gulfport			1,591		7,100		1,883		1.8		1,320		23		155		763		15		73
53	Lyon 1-27H	Gulfport			1,577		6,694		1,759		2.5		1,271		21		137		435		19		62
54	Sanford 1H	Antero	X		962		7,159		1,148		1.8		1,316		22		142		363		22		57
55	Boy Scout 2-33H	Gulfport			922		8,511		1,308		2.1		1,310		25		142		356		23		57
56	Lyon 3-27H	Gulfport			869		7,004		1,014		2.0		1,271		21		137		239		27		47
Rich Condensate Average:					1,618		6,726		1,751		2.8		1,287		22		146		405		23		59

Source: Company Filings, Investor Presentations and Ohio Department of Natural Resources

(1)

Equivalent rates, gas shrink %, NGLs yield and % NGLs assume ethane recovery. Unless otherwise noted in this footnote, represents post-processing IP with a testing period of 24 hours. For the following wells, represents IP rates with the following testing periods: (i) Rubel 2H—6 hours, (ii) Rubel 3H—4 hours, (iii) Shugert 1-1H—32 hours, (iv) Shugert 1-12H—18 hours, (v) Clay 1-4H—12 hours, (vi) McCort 1-28H, McCort 2-28H and Wagner 3-28H—7 days each, and (vii) J. Anderson 2H, J. Anderson 5H, J. Anderson 3H, J. Anderson 4H and J. Anderson 1 H—5 days each

Not available

As shown on the following map, which should be read in conjunction with the preceding table, the highest publicly disclosed Normalized 6,000 Foot IPs within each type curve area are located in close proximity to the greatest concentration of our acreage. Based upon the production data we have analyzed, we believe that our acreage is located within the most prolific and economic region of the Utica Core Area.

LOGO

Eclipse Utica Shale Prospective Acreage Area represents the areas within the Utica Shale in which the highest concentration of our acreage and interests are located and in which we intend to focus our drilling efforts.

Marcellus Shale

As of March 31, 2014, we had approximately 25,740 net acres in the highly liquids rich area of the Marcellus Shale in Eastern Ohio within what we refer to as Our Marcellus Project Area. The reservoir underlying this acreage is less thermally mature than the Marcellus Shale in Southwestern Pennsylvania, and consequently, we believe natural gas production from this area will yield significant NGLs and condensate. We believe that publicly disclosed well results from other operators on and near our acreage and our Tippens 6HM well have confirmed our views regarding the richness of the gas and presence of both NGLs and condensate in this area. For example, in December 2011, Stone Energy reported average initial production rates from its 11 Marcellus Shale wells in the Mary Field in Wetzel County, West Virginia of 3-5 MMcf of gas per day with initial condensate yields of 70-100 barrels per MMcf of gas and that it expected 40 barrels of NGLs per MMcf of gas. These wells are located approximately 5 miles east of Our Marcellus Project Area. In addition, in January 2012, Protégé Energy II LLC reported its drilling results for the Eisenbarth 3-H well to the State of Ohio with an initial production rate of 3.6 MMcf of gas and 397 barrels of condensate per day, equating to a condensate yield of 111 barrels per MMcf of gas. The Eisenbarth 3-H well is located in the center of Our Marcellus Project Area as shown on the map below. In December 2013, Magnum Hunter announced 3 new Marcellus Shale wells in Monroe County approximately 3 miles east of Our Marcellus Project Area. Magnum Hunter reported an average initial production rate of 3.9 MMcf of gas and 596 barrels of condensate, equating to a condensate yield of 153 barrels per MMcf of gas. We own a 17.7% interest in 1 of the 3 announced wells. In 2013, we drilled the Tippens 6HM well to delineate the western limit of our acreage that we believed to be prospective for the Marcellus Shale. The Tippens 6HM well produced at a peak rate of 885 Mcf and 162 barrels of condensate per day, with 1,336 Btu gas. Based on gas samples in the immediate area and results from the Tippens 6HM, we expect the gas produced from our acreage in Our Marcellus Project Area to have a heating value of approximately 1,250-1,450 Btu.

Based on the well results from other operators discussed above and the Tippens 6HM well, we have limited our Marcellus Shale Project Area to the portion of our acreage extending eastward from the Tippens 6HM well. We believe this area will have sufficient depth, reservoir pressure and thermal maturity to produce at rates that meet our economic thresholds. In determining our Marcellus Shale drilling locations, we have included only those locations within the boundaries shown on the map below.

LOGO

Eclipse Marcellus Shale Prospective Acreage Area represents the area within the Marcellus Shale in which the highest concentration of our acreage and interest are located and in which we intend to focus our drilling efforts.

Activity

Our first operated Utica Shale horizontal well, the Tippens 6HS, which is located in the Dry Gas Window, had an initial peak production rate of 23.2 MMcf per day of natural gas, or 3,867 Boe per day, at a 28/64^th choke with approximately 5,300 psi casing pressure. The Tippens 6HS was drilled with a completed lateral section of approximately 5,850 feet and completed with 19 stages. The well was connected to a sales line on December 21, 2013 and produced a cumulative total of approximately 549 MMcf of natural gas for an average rate of 18.3 MMcf per day in its first 30 days after connecting to a sales line.

As of March 31, 2014, we were operating 3 horizontal rigs and 1 top-hole rig in the Utica Core Area. We frequently utilize top-hole rigs ahead of our horizontal rigs to drill the vertical portion of our wells in order to maximize the drilling efficiency of our larger horizontal drilling rigs and reduce overall costs. The table and map on the following pages summarize the wells we are currently participating in as an operator and as a non-operated working interest partner (as of March 31, 2014):


Operated
Map	Well Name	Working Interest%	Net Revenue Interest%	Operator	Area	Permitted Lateral Length (ft)	Status
1	Hayes 2H	93.55%	81.86%	Eclipse	Condensate	6,267	Drilling—Top Hole
2	Hayes 4H	93.55%	81.86%	Eclipse	Condensate	6,267	Drilling—Top Hole
3	Hayes 6H	93.55%	81.86%	Eclipse	Condensate	6,267	Drilling—Top Hole
4	Hayes 8H	93.55%	81.86%	Eclipse	Condensate	6,267	Drilling—Top Hole
5	Mizer Farms 1H	51.70%	45.24%	Eclipse	Condensate	6,063	Drilling—Top Hole
6	Mizer Farms 3H	51.70%	45.24%	Eclipse	Condensate	5,643	Drilling—Top Hole
7	Mizer Farms 5H	51.70%	45.24%	Eclipse	Condensate	5,643	Drilling—Top Hole
8	Pora 2H	90.17%	78.90%	Eclipse	Condensate	8,077	Drilling—Top Hole
9	Pora 6H	90.17%	78.90%	Eclipse	Condensate	7,994	Drilling—Top Hole
10	Mizer 2H	64.58%	56.51%	Eclipse	Condensate	6,062	Drilling
11	Mizer Farms 7H	51.70%	45.24%	Eclipse	Condensate	5,643	Drilling
12	Herrick A 3H	100%	80.00%	Eclipse	Dry Gas	6,000	Awaiting Completions
13	Herrick C 8H	80.50%	64.40%	Eclipse	Dry Gas	6,430	Awaiting Completions
14	Mizer 4H	64.58%	56.51%	Eclipse	Condensate	6,062	Awaiting Completions
15	Mizer 6H	64.58%	56.51%	Eclipse	Condensate	6,062	Awaiting Completions
16	Mizer 8H	64.58%	56.51%	Eclipse	Condensate	6,061	Awaiting Completions
17	Mizer 10H	64.58%	56.51%	Eclipse	Condensate	6,061	Awaiting Completions
18	Mizer Farms 9H	51.70%	45.24%	Eclipse	Condensate	5,643	Awaiting Completions
19	Shroyer 2H	92.98%	74.38%	Eclipse	Dry Gas	8,208	Awaiting Completions
20	Shroyer 4H	92.98%	74.38%	Eclipse	Dry Gas	7,959	Awaiting Completions
21	Herrick B 5H	70.39%	56.31%	Eclipse	Dry Gas	6,419	Completing

Non-Operated
Map	Well Name	Working Interest%	Net Revenue Interest%	Operator	Area	Permitted Lateral Length (ft)	Status
22	Amanda 1-14H	2.70%	2.16%	Gulfport	Dry Gas	7,886	Drilling
23	Law Unit 2H	23.29%	18.86%	Antero	Condensate	6,351	Drilling
24	McDougal Unit 2H	2.55%	2.07%	Antero	Rich Gas	8,882	Drilling
25	McDougal Unit 3H	2.55%	2.06%	Antero	Rich Gas	7,951	Drilling
26	Perkins 2-4H	6.43%	5.14%	Gulfport	Dry Gas	6,506	Drilling
27	DK Carpenter 1H	0.01%	0.00%	Antero	Rich Gas	10,632	Awaiting Completion
28	DK Carpenter 2H	0.01%	0.00%	Antero	Rich Gas	9,979	Awaiting Completion
29	Kirkwood 1H 33	0.09%	0.07%	Hess	Rich Gas	5,862	Awaiting Completion
30	Kirkwood 2H 33	0.09%	0.07%	Hess	Rich Gas	6,574	Awaiting Completion
31	Kirkwood 4H 33	0.09%	0.07%	Hess	Rich Gas	4,857	Awaiting Completion
32	Law Unit 1H	23.29%	18.86%	Antero	Condensate	5,529	Awaiting Completion
33	McDougal Unit 1H	3.52%	3.08%	Antero	Rich Gas	9,240	Awaiting Completion
34	Perkins 1-4H	6.43%	5.14%	Gulfport	Dry Gas	6,159	Awaiting Completion
35	Shugert 3-12H	3.36%	2.72%	Gulfport	Rich Gas	9,444	Awaiting Completion
36	Shugert 4-12H	3.26%	2.61%	Gulfport	Rich Gas	9,246	Awaiting Completion
37	Vorhies Unit 2H	23.69%	19.19%	Antero	Condensate	9,312	Awaiting Completions
38	Vorhies Unit 3H	23.69%	19.19%	Antero	Condensate	8,985	Awaiting Completions
39	Kirkwood 3H 33	0.09%	0.07%	Hess	Rich Gas	7,076	Completing
40	Schafer 1H	24.11%	19.53%	Antero	Condensate	7,609	Completing
41	Schafer 2H	24.11%	19.53%	Antero	Condensate	8,587	Completing
42	Shugert 2-12H	3.36%	2.72%	Gulfport	Rich Gas	7,743	Completing
43	Vorhies Unit 1H	23.69%	19.19%	Antero	Condensate	9,826	Completing
44	Dollison 2H	30.00%	24.51%	Antero	Rich Gas	5,637	Awaiting Midstream
45	Dollison 3H	30.00%	24.51%	Antero	Rich Gas	6,067	Awaiting Midstream
46	Dollison 4H	30.00%	24.51%	Antero	Rich Gas	6,396	Awaiting Midstream
47	Ormet 3-9H	17.73%	15.17%	MHR	Marcellus	4,797	Awaiting Midstream
48	Rector 1H	1.39%	1.11%	Carrizo	Condensate	7,151	Awaiting Midstream
49	Richard Stalder A-2MH	46.81%	39.14%	MHR	Marcellus	5,363	Awaiting Midstream
50	Yockey 3H	30.69%	26.86%	Chesapeake	Condensate	5,138	Awaiting Midstream
51	Yockey 7H	39.71%	34.63%	Chesapeake	Condensate	5,138	Awaiting Midstream

LOGO

We expect to continue running 3 operated horizontal rigs through the completion of this offering, increasing to 6 operated horizontal rigs by year end 2014. During 2014, we anticipate spudding a total of 73 gross (53 net) operated wells and expect to participate in 103 gross (17 net) non-operated wells, primarily with Antero Resources, Gulfport Energy, Chesapeake Energy and Magnum Hunter.

Midstream Agreements

The following table illustrates the committed gathering and processing volumes associated with our operated assets through 2018:


Firm Gathering and Processing Volumes
Year	Gathering (MMcf/d)		Cryogenic Processing (MMcf/d)
2014		155		55
2015		475		225
2016		700		400
2017		720		420
2018		660		360

Our Competitive Strengths

We have a number of competitive strengths that we believe will help us to successfully execute our business strategies, including:

•

Premier Acreage Positions in the Core of the Utica Shale and the Highly Liquids Rich Area of the Marcellus Shale. We own an extensive and substantially contiguous acreage position in two of the premier North American shale plays. We have approximately 96,240 net acre position in the Utica Core Area concentrated in a region where the highest initial production rates have been reported. Based upon the production data for wells that we have drilled or participated in as well as the initial production rates of wells that have been publicly disclosed by other operators, we believe that our acreage is located within the most prolific and economic region of the Utica Core Area. Additionally, based on the results of our first 2 Marcellus Shale wells completed within our 25,740 net acre Marcellus Shale Project Area, we believe Marcellus Shale wells within this area will produce rich natural gas with a heat content of approximately 1,250-1,450 Btu, and a condensate yield of approximately 100-200 barrels per MMcf of gas. Furthermore, we own approximately 131,070 net acres (which are approximately 85% held by production) outside of the Utica Core Area that may be prospective for the oil window of the Utica Shale representing upside potential.

•

Multi-Year Drilling Inventory. As of March 31, 2014, we had identified approximately 3,381 gross (863 net) horizontal drilling locations within the Utica Core Area and Our Marcellus Project Area. We have drilled or commenced drilling 75 of these gross wells as of March 31, 2014. We plan to spud or participate in 176 gross (69 net) wells in those areas during 2014, representing a 19-year drilling inventory, which we calculate by dividing gross remaining identified drilling locations by gross wells expected to be spud in the 2014 drilling plan. We operate approximately 81% of our net acreage and the substantially contiguous nature of our leasehold enables us to enhance our single well economics by efficiently creating pad sites to drill multiple wells at the most effective lateral lengths. In determining our drilling locations, we have laid out a drilling plan that assumes average lateral lengths of 6,000 feet and interlateral spacing of 750 feet between wells for our operated acreage in the Rich Gas, Condensate and Rich Condensate Windows of the Utica Core Area and Our Marcellus Shale Project Area, and 1,000 feet between wells for our operated acreage in the Dry Gas Window of the Utica Core Area. These identified drilling locations are shown on the map on the inside cover of this prospectus. Operators are currently testing tighter spacing, and if our acreage can support tighter spacing, then we expect that our number of drilling locations would significantly increase. Additionally, we expect to add net locations to our inventory as we lease or acquire incremental acreage and establish drilling units on acreage that does not currently support a 6,000 foot lateral.

•

Expertise and Experience in Unconventional Resource Plays, Particularly the Appalachian Basin. We have assembled a strong executive and technical staff that has extensive experience in horizontal drilling, operating multi-rig development programs and using advanced drilling and completion technology, predominately in the Appalachian Basin. We have sought to hire personnel who we believe to be the best in their field not only with respect to technical expertise but also specifically with direct experience in the Appalachian Basin and the Utica and Marcellus Shales. Several members of our executive management team have extensive experience managing the successful early entrance and development in emerging unconventional areas of the Appalachian Basin, having led these efforts at companies such as Cabot Oil & Gas, Rex Energy and Chesapeake Energy.

•

Secure Processing, Fractionation and Pipeline Takeaway Capacity. To ensure sufficient capacity is available to handle our forecasted volumes as wells come online, we have obtained firm gathering, cryogenic processing and fractionation capacity for a significant portion of our operated acreage in the Rich Gas, Condensate and Rich Condensate Windows of the Utica Core Area with Blue Racer. Additionally, we have contracted with Eureka Hunter for firm gathering services on a significant portion of our operated acreage in the Dry Gas Window of the Utica Core Area. Our non-operated production operated by Antero Resources is marketed and processed by Antero Resources on our behalf and is currently being processed and fractionated by MarkWest Energy Partners. Further, our acreage position is

centered near the confluence of several interstate pipeline systems including Texas Eastern, Rockies Express, Dominion Transmission, Dominion East Ohio and Tennessee Gas. This location provides us with the opportunity to assemble a diversified strategy to sell our gas, both within the Appalachian Region, and in other areas including the Gulf Coast and Mid-West markets. Additionally, we have recently entered into a long-term agreement with Shell to sell a significant portion of our projected ethane production from our rich gas assets, pending construction of their ethane cracker facility, which we expect to realize a premium price compared to net prices currently available after deducting transportation costs. We believe this approach will offer us diversity of revenue streams and a unique ability to manage our basis risk through a combination of long-term firm transport actions, short to medium-term firm sales agreements, and short-term spot gas sales to capture market fluctuations.

•

Proven Management Team that is Highly Aligned with Stockholders. Our management team possesses extensive oil and natural gas acquisition and development expertise in shale plays, particularly within the Appalachian Basin, and will have a significant economic interest in us upon completion of this offering. Several members of our senior management team have significant experience managing public companies, which we believe will benefit our stockholders. Management’s economic interest in us will initially be held in the form of incentive units issued by Eclipse Holdings and could increase following completion of this offering, without diluting public investors, if our stock price appreciates. See “Executive Compensation—Long-term Incentive Compensation—Incentive Units” for a description of the incentive units. Management’s current ownership interest in Eclipse Holdings combined with its potential for increased ownership interest in Eclipse Holdings provides a strong incentive for management to grow the value of our company.

Our Business Strategy

•

Aggressively Grow Production, Cash Flow and Reserves through the Economic Development of Our Drilling Inventory. We intend to aggressively develop our portfolio of identified drilling locations to maximize the present value of the substantial resource we have accumulated. Our management team has considerable experience managing large-scale drilling programs and is focused on growing production, cash flow and reserves in an economically efficient manner. We began to delineate our acreage position within the Utica Core Area and Our Marcellus Project Area in 2013. We are currently operating 3 horizontal rigs, and we expect to bring our total operated horizontal rig count to 6 by year end 2014. In 2014, we plan to invest $577.4 million in drilling and completion capital and plan to spud or participate in 176 gross (69 net) shale wells.

•

partners’, well results and midstream plans. We believe that our current operated rig count, along with our participation in non-operated wells with at least 7 different operators in the Utica Core Area, has provided and will continue to provide us with a growing body of data which will allow us to further optimize our drilling and completion techniques and enhance well economics.

•

Continue Growing Our Core Acreage Position through Leasing and Strategic Acquisitions. We intend to continue to identify and acquire additional acreage and producing assets in our core areas. Based on specific geological and technical analysis, we initially targeted and acquired 27,000 net acres in the southern portion of the Utica Core Area in 2011, and as of March 31, 2014, we have grown our position in the Utica Core Area to approximately 96,240 net acres. We believe our technical assessment of the most productive area within the Utica Shale has been validated by the highest initial production rates in the play and that our approximately 96,240 net acres are in the most prolific and economic part of the play. We will continue to pursue both large and small acreage acquisitions to add to our inventory and increase our number of operated drilling units.

Proved Reserves

As of December 31, 2013 and March 31, 2014, our estimated proved reserves were 78.5 Bcfe, or 13.1 MMBoe, and 109.6 Bcfe, or 18.3 MMBoe, respectively, based on reserve reports prepared by Netherland, Sewell & Associates, Inc., or NSAI, our independent petroleum engineers. As of December 31, 2013, our estimated proved reserves were approximately 67% natural gas, 15% NGLs and 18% oil, and approximately 57% were proved developed reserves. As of March 31, 2014, our estimated proved reserves were approximately 63% natural gas, 21% NGLs and 16% oil, and approximately 52% were proved reserves. The following table provides information regarding our proved reserves as of December 31, 2013 and March 31, 2014:


	Estimated Total Proved Reserves
	Oil (MMBbls)		NGLs (MBbls)		Natural Gas (Bcf)		Total (Bcfe)		Total (MMBoe)		% Liquids			% Developed			PV-10⁽¹⁾ (in millions)
December 31, 2013		2.4		1.9		52.3		78.5		13.1		33.3	%		56.7	%	$	155.3
March 31, 2014		3.0		3.8		69.0		109.6		18.3		37.1	%		51.8	%	$	253.8

(1)

PV-10 is a non-GAAP financial measure and generally differs from standardized measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. As we were not subject to entity level taxation, there is no difference between PV-10 and our standardized measure in this regard. However, in connection with the closing of this offering, as a result of our corporate reorganization, we will be a corporation subject to federal income tax and our future income taxes will be dependent upon our future taxable income, and following our corporate reorganization our calculation of standardized measure would include such tax inputs. Neither PV-10 nor standardized measure represents an estimate of the fair market value of our oil and natural gas properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities.

Oil and Natural Gas Data

Proved Reserves

Evaluation and Review of Proved Reserves. Our historical proved reserve estimates were prepared by NSAI. The technical persons responsible for preparing our proved reserve estimates meet the requirements with regard to qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. NSAI does not own an interest in any of our properties, nor is it employed by us on a contingent basis. A copy of NSAI’s proved reserve reports as of March 31, 2014, December 31, 2013 and December 31, 2012 are attached hereto as exhibits.

We maintain an internal staff of engineers and geoscience professionals who work closely with NSAI to ensure the integrity, accuracy and timeliness of the data used to calculate our proved reserves relating to our assets. Our internal technical team members meet with NSAI periodically during the period covered by the proved reserve report to discuss the assumptions and methods used in the proved reserve estimation process. We provide historical information for our properties to NSAI, such as ownership interest, oil and natural gas production, well test data, commodity prices and operating and development costs. Bryan Moody, our Vice President—Finance and Engineering, is primarily responsible for overseeing the preparation of all of our reserve estimates. Mr. Moody is an engineer with over 10 years of reservoir and operations experience and our geoscience staff has an average of approximately 8 years of industry experience per person.

The preparation of our proved reserve estimates are completed in accordance with our internal control procedures. These procedures, which are intended to ensure reliability of reserve estimations, include the following:

•

review and verification of historical production data, which data is based on actual production as reported by us;

•

preparation of reserve estimates by Mr. Moody or under his direct supervision;

•

review by Mr. Moody of all of our reported proved reserves at the close of each quarter, including the review of all significant reserve changes and all new proved undeveloped reserves additions by our Chief Executive Officer, Chief Operating Officer and Chief Financial Officer;

•

direct reporting responsibilities by Mr. Moody to our Chief Financial Officer; and

•

verification of property ownership by our land department.

The reserves estimates shown herein are based upon evaluations prepared by NSAI, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. 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. Robert C. Barg and Mr. William J. Knights. Mr. Barg has been practicing consulting petroleum engineering at NSAI since 1989. Mr. Barg is a Licensed Professional Engineer in the State of Texas (No. 71658) and has over 30 years of practical experience in petroleum engineering, with over 24 years of experience in the estimation and evaluation of reserves. He graduated from Purdue University in 1983 with a Bachelor of Science Degree in Mechanical 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 33 years of practical experience in petroleum geosciences, with over 27 years of 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 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.

Estimation of Proved Reserves. Under SEC rules, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.” All of our proved reserves as of March 31, 2014, December 31, 2013 and December 31, 2012 were estimated using a deterministic method. The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and natural gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of recoverable oil and natural gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into four broad categories or methods: (1) production performance-based methods; (2) material balance-based methods; (3) volumetric-based methods; and (4) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserves for proved developed producing wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to similar production, both of which are considered to provide a relatively high degree of accuracy. Non-producing reserve estimates, for developed and undeveloped properties, were forecast using either volumetric or analogy methods, or a combination of both. These methods provide a relatively high degree of accuracy for predicting proved developed non-producing and proved undeveloped reserves for our properties.

To estimate economically recoverable proved reserves and related future net cash flows, NSAI considered many factors and assumptions, including the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and the SEC pricing requirements and forecasts of future production rates.

Under SEC rules, reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. To establish reasonable certainty with respect to our estimated proved reserves, the technologies and economic data used in the estimation of our proved reserves have been demonstrated to yield results with consistency and repeatability, and include production and well test data, downhole completion information, geologic data, electrical logs, radioactivity logs, core analyses, available seismic data and historical well cost and operating expense data.

Summary of Natural Gas, NGLs and Oil Reserves. The following table presents our estimated net proved natural gas, NGLs and oil reserves as of March 31, 2014, December 31, 2013 and December 31, 2012, based on the proved reserve reports prepared by NSAI, our independent petroleum engineers, and such proved reserve reports have been prepared in accordance with the rules and regulations of the SEC. Our estimated proved reserves were determined using a 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December for the years 2013 and 2012. For oil and NGLs volumes, the average West Texas Intermediate spot price of $98.43 per barrel for March 31, 2014, $96.91 per barrel for December 31, 2013 and $94.71 per barrel for December 31, 2012, has been adjusted by property group for quality, transportation fees and regional price differentials. For gas volumes, the average Henry Hub spot price of $3.99 per MMBtu for March 31, 2014, $3.67 per MMBtu for December 31, 2013 and $2.76 per MMBtu for December 31, 2012 has been adjusted by property group for energy content, transportation fees and regional price differentials. All prices are held constant throughout the lives of the properties. All of our proved reserves

are located in the United States. Copies of the proved reserve reports as of March 31, 2014, December 31, 2013 and December 31, 2012 prepared by NSAI with respect to our properties are included as exhibits to the registration statement of which this prospectus forms a part. Our estimates of net proved reserves have not been filed with or included in reports to any federal authority or agency other than the SEC in connection with this offering.


	March 31, 2014		December 31,
	March 31, 2014		2013		2012
Proved Developed Reserves:
Natural gas (MMcf)		34,216.0		27,880.3		1,289.6
NGLs (MBbls)		1,678.6		1,056.2		64.6
Oil (MBbls)		2,072.0		1,708.1		174.5

Combined (MMcfe)		56,719.6		44,466.6		2,724.0

Proved Undeveloped Reserves:
Natural gas (MMcf)		34,742.8		24,464.2		1,666.6
NGLs (MBbls)		2,078.6		882.1		112.4
Oil (MBbls)		940.7		709.2		211.5

Combined (MMcfe)		52,858.2		34,012.0		3,610.1

Proved Reserves:
Natural Gas (MMcf)		68,958.8		52,344.5		2,956.1
NGLs (MBbls)		3,757.2		1,938.3		177.0
Oil (MBbls)		3,012.7		2,417.4		386.0

Combined (MMcfe)		109,577.8		78,478.6		6,334.2

Reserve engineering is and must be recognized as a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas, 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.

Additional information regarding our proved reserves can be found in the notes to our consolidated financial statements included elsewhere in this prospectus and the proved reserve reports as of March 31, 2014, December 31, 2013 and December 31, 2012, which are included as exhibits to the registration statement of which this prospectus forms a part.

Proved Reserves Additions and Revisions

To maintain and grow production and cash flow, we must continue to develop existing proved reserves and locate or acquire new natural gas, NGLs and oil reserves. The following is a discussion of net proved reserves, reserve additions and revisions and future net cash flows from proved reserves.


	Natural Gas (MMcf)			NGLs (MBbls)			Oil (MBbls)			Total (MMcfe)
Proved Reserves:
December 31, 2012		2,956.1			177.0			386.0			6,334.2

Extensions and discoveries		41,215.5			1,710.6			1,323.3			59,419.0
Reserve revisions		2,645.0			52.1			(163.2	)		1,978.4
Acquisition		6,646.6			—			958.5			12,397.6
Production		(1,118.8	)		(1.3	)		(87.2	)		(1,650.2	)

December 31, 2013		52,344.5			1,938.4			2,417.4			78,478.6

Extensions and discoveries		25,384.0			2,177.6			1,023.4			44,589.9
Reserve revisions		(6,010.6	)		(349.8	)		(320.1	)		(10,029.7	)
Acquisition		—			—			—			—
Production		(2,759.0	)		(9.0	)		(108.0	)		(3,461.0	)

March 31, 2014		68,958.8			3,757.2			3,012.7			109,577.8

During fiscal 2013, we added 73.8 Bcfe of proved reserves, primarily in the Utica Shale, due to drilling activities, evaluations of proved areas, the Oxford Acquisition and revisions to previous estimates. During the three months ended March 31, 2014, we added 34.6 Bcfe of proved reserves, primarily due to drilling activities in the Utica Shale. This increase in proved reserves was comprised of 44.6 Bcfe of extensions and 0.6 Bcfe of positive price revisions, and was partially offset by (10.6) Bcfe of technical revisions. The majority of these technical revisions were attributable to two proved producing wells that underperformed our expectations which also resulted in downward revisions in their offsetting proved undeveloped locations.

Future Net Cash Flows. At March 31, 2014 and December 31, 2013, the PV-10 value of estimated future net cash flows from our proved reserves was $253.8 million and $155.3 million, respectively. The PV-10 value of our estimated future net cash flows at December 31, 2012 was $21.9 million. These PV-10 values were calculated based on the unweighted average first-day-of-the-month oil and gas prices for the prior twelve months held flat for the life of the reserves.

Proved Undeveloped Reserves (PUDs)

As of March 31, 2014 our proved undeveloped reserves were comprised of 940.7 MBbls of oil, 34,742.8 MMcf of natural gas and 2,078.6 MBbls of NGLs, for a total of 52,858 MMcfe. As of December 31, 2013, our proved undeveloped reserves were composed of 709.2 MBbls of oil, 24,464.2 MMcf of natural gas and 882.1 MBbls of NGLs, for a total of 34,012 MMcfe. PUDs will be converted from undeveloped to developed as the applicable wells begin production.

100

The following table summarizes our changes in PUDs during 2013 (in MMcfe):


Balance, December 31, 2012	3,610.1
Revisions of previous estimates⁽¹⁾	(271.0	)
Purchases of minerals-in-place	0.0
Extensions and discoveries	32,853.0
Transfers to proved developed	(2,180.2	)

Balance, December 31, 2013	34,012.0
Revisions of previous estimates⁽²⁾	(4,908.1	)
Purchases of minerals-in-place	0
Extensions and discoveries	27,142.4
Transfers to proved developed	(3,388.1	)

Balance, March 31, 2014	52,858.2

(1)

Revisions to previous estimates are comprised of 270.9 MMcfe of negative technical revisions and 0.1 MMcfe of negative price revisions.

(2)

Revisions to previous estimates are comprised of 5,008.8 MMcfe of negative technical revisions and partially offset by 100.7 MMcfe of positive price revisions.

Costs incurred relating to the development of PUDs reflected in our 2012 proved reserve report were $4.4 million during 2013. In addition, we incurred costs of $0.3 million to develop locations that became classified as PUDs during 2013. Estimated future development costs relating to the development of PUDs as of March 31, 2014 are projected to be approximately $24.1 million for the remainder of 2014, $47.8 million in 2015, $10.4 million in 2016, $0.0 million in 2017 and $0.0 million in 2018. Of our PUDs, we plan to develop 31%, or 16,556 MMcfe, in 2014, 30%, or 16,032 MMcfe, in 2015, and 39%, or 20,270 MMcfe, in 2016. As we continue to develop our properties and have more well production and completion data, we believe we will continue to realize cost savings and experience lower relative drilling and completion costs as we convert PUDs into proved developed reserves in upcoming years. All of our PUD drilling locations are scheduled to be drilled prior to the end of 2018.

As of March 31, 2014 and December 31, 2013, approximately 11% and 24%, respectively, of our total proved reserves were classified as proved developed non-producing.

101

Oil and Natural Gas Production Prices and Production Costs

Production and Price History

The following table sets forth information regarding net production of natural gas, NGLs and oil, and certain price and cost information for the periods indicated:


	Three Months Ended March 31,
	2014		2013
Total production volumes:
Natural gas (MMcf)		2,759.0		14.2
NGLs (MBbls)		9.0		—
Oil (MBbls)		108.0		2.6

Combined (MMcfe)		3,461.0		29.6

Average daily production volumes:
Natural gas (Mcf/d)		30,656		158
NGLs (Bbls/d)		100		—
Oil (Bbls/d)		1,200		28

Combined (Mcfe/d)		38,456		329

Volume weighted average realized prices:
Natural gas ($/Mcf)⁽¹⁾	$	5.06	$	3.68
NGLs ($/Bbl)		63.88		—
Oil ($/Bbl)		94.94		91.89

Combined ($/Mcfe)	$	7.16	$	9.73

Expenses (per Mcfe):
Lease operating	$	0.52	$	0.07
Production, severance and ad valorem taxes		0.10		0.05
Depletion, depreciation and amortization		3.48		7.15
General and administrative		2.43		21.73
Transportation, gathering and compression		0.26		—

(1)

Productive Wells

Productive wells consist of wells that are capable of producing hydrocarbons, including wells awaiting connection to production facilities, in sufficient quantities such that proceeds from the sale of the production exceeds production expenses and taxes.

As of December 31, 2013, we owned an average 88.6% working interest in 1,002 gross (887.5 net) productive wells, which were comprised of 659 gross (580.5 net) gas wells and 343 gross (307.1 net) oil wells. In addition, we owned an average 68.8% working interest in 243 gross (167.2 net) wells producing in uneconomic quantities, which were comprised of 192 gross (131.2 net) gas wells and 51 gross (36.0 net) oil wells.

As of March 31, 2014, we owned an average 84.9% working interest in 1,057 gross (897.3 net) productive wells, which were comprised of 661 gross (561.5 net) gas wells and 396 gross (335.9 net) oil wells. In addition, we owned an average 74.8% working interest in 196 gross (146.6 net) wells producing in uneconomic quantities, which were comprised of 172 gross (129.8 net) gas wells and 24 gross (16.8 net) oil wells.

Gross wells are the total number of producing wells in which we have an interest, and net wells are the sum of our fractional working interests owned in gross wells.

102

Developed and Undeveloped Acreage

The following table sets forth information as of March 31, 2014 relating to our leasehold acreage. Developed acres are acres spaced or assigned to productive wells and does not include undrilled acreage held by production under the terms of the lease. Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains proved reserves. A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned. A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.


	Developed Acreage				Undeveloped Acreage				Total Acreage
Area	Gross		Net⁽¹⁾		Gross		Net⁽¹⁾		Gross		Net⁽¹⁾
Ohio		169,125		150,540		114,688		76,689		283,813		227,229
West Virginia		—		—		307		177		307		177

Total		169,125		150,540		114,955		76,866		284,120		227,406

(1)

Fossil Creek owns a right to participate for a 12.5% working interest in approximately 9,740 gross acres within our area of mutual interest with Antero Resources. In calculating our net acreage, we have assumed that Fossil Creek will elect to participate in all wells in which they have a right to participate for their full interest and have deducted this 12.5% working interest from our net acreage where applicable.

Many of the leases comprising the undeveloped acreage set forth in the table above will expire at the end of their respective primary terms unless operations have commenced on the leasehold acreage or lands pooled therewith have been established prior to such date, in which event the lease will remain in effect until the cessation of production in commercial quantities. As of March 31, 2014, we had leases representing approximately 1,603 gross (1,603 net) acres scheduled to expire in 2014, 2,731 gross (2,724 net) acres scheduled to expire in 2015, 20,093 gross (5,678 net) acres scheduled to expire in 2016, 44,018 gross (30,423 net) acres scheduled to expire in 2017 and 28,788 gross (19,527 net) acres scheduled to expire in 2018 and beyond, although approximately 72% of our leases in the Utica Core Area have a 5-year extension at our option. We have not attributed any PUD reserves to acreage whose expiration date precedes the scheduled date for PUD drilling. In calculating our PUD reserves we have assumed that Fossil Creek will elect to participate in the drilling of these wells for their full interest and have deducted this interest when calculating our net PUD reserves.

Drilling Results

The following table sets forth information with respect to the number of wells completed during the periods indicated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce commercial quantities of hydrocarbons, whether or not they produce a reasonable rate of return.


	March 31,				Year ended December 31,
	2014				2013				2012
	Gross		Net		Gross		Net		Gross		Net
Development Wells:
Productive		16		3.4		34		30.7		1		0.3
Dry holes		—		—		—		—		—		—

Exploratory Wells:
Productive		1		1		2		1.2		—		—
Dry holes		—		—		—		—		1		1.0

Total:
Productive		17		4.4		36		31.9		1		0.3
Dry holes		—		—		—		—		1		1.0

103

As of December 31, 2013, we had 60 gross (23 net) wells in the process of drilling, completing or shut in awaiting infrastructure that are not reflected in the above table. As of March 31, 2014, we had 51 gross (20 net) wells in the process of drilling, completing or shut in awaiting infrastructure that are not reflected in the above table.

Operations

General

As of December 31, 2013, we operated approximately 64% of our proved reserves. As operator, we design and manage the development of a well and supervise operation and maintenance activities on a day-to-day basis. Independent contractors engaged by us provide all the equipment and personnel associated with these activities. We employ engineers, geologists and land professionals who work to improve production rates, increase reserves and lower the cost of operating our oil and natural gas properties.

Major Customers

For the three months ended March 31, 2014, sales to Antero Resources, ARM Energy Management and Magnum Hunter represented 52%, 22% and 17% of our total sales, respectively. For the year ended December 31, 2013, sales to Antero Resources, Devco Oil Inc. and Dominion East Ohio represented 38%, 24% and 13% of our total sales, respectively. For the year ended December 31, 2012, Antero Resources accounted for 100% of our total sales. Although a substantial portion of production is purchased by these major customers, we do not believe the loss of any one or several customers would have a material adverse effect on our business, as other customers or markets would be accessible to us.

Title to Properties

We believe that we have satisfactory title to all of our producing properties in accordance with generally accepted industry standards. As is customary in the industry, in the case of undeveloped properties, often cursory investigation of record title is made at the time of lease acquisition. Investigations are made before the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties. Individual properties may be subject to burdens that we believe do not materially interfere with the use or affect the value of the properties. Burdens on properties may include:

•

customary royalty interests;

•

liens incident to operating agreements and for current taxes;

•

obligations or duties under applicable laws;

•

development obligations under natural gas leases;

•

net profits interests;

•

mortgages by a lessor; or

•

rights of way or easements held by third parties such as utilities.

Seasonality

Demand for natural gas generally decreases during the spring and fall months and increases during the summer and winter months. However, seasonal anomalies such as mild winters or mild summers sometimes lessen this fluctuation. In addition, some natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations. These seasonal anomalies can increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay our operations.

104

Competition

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

Regulation of the Oil and Natural Gas Industry

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

Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the industry increases the cost of doing business and affects profitability. Although we believe that we are in substantial compliance with all applicable laws and regulations, such laws and regulations are frequently amended or reinterpreted. Therefore, we are unable to predict our future ability to comply with applicable law and regulations or the future costs or impact of compliance.

Additional proposals and proceedings that affect the natural gas industry are regularly considered by Congress, the states, the Federal Energy Regulatory Commission, or the FERC, and the courts. We cannot predict the substance or outcome of such proposals and proceedings or when or whether any such proposals may become effective. We believe we are in substantial compliance with currently applicable laws and regulations and that continued substantial compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations. However, current regulatory requirements may change, currently unforeseen environmental incidents may occur or past non-compliance with environmental laws or regulations may be discovered.

Regulation of Production of Natural Gas and Oil

The production of natural gas and oil is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. All of the states in which we own and operate properties have regulations governing conservation matters, including provisions for the unitization or pooling of

105

natural gas and oil properties, the establishment of maximum allowable rates of production from natural gas and oil wells, the regulation of well spacing or density, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of natural gas and oil that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although in some cases we can apply for exceptions to such regulations or to have reductions in well spacing or density. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of natural gas, NGLs and oil within its jurisdiction.

We own interests in properties located onshore in two U.S. states. These states regulate drilling and operating activities by requiring, among other things, permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled and the plugging and abandonment of wells. The laws of these states also govern a number of environmental and conservation matters, including the handling and disposing or discharge of waste materials, the size of drilling and spacing units or proration units and the density of wells that may be drilled, unitization and pooling of oil and gas properties and establishment of maximum rates of production from oil and gas wells. Some states have the power to prorate production to the market demand for oil and gas. The failure to comply with these rules and regulations can result in substantial penalties.

Regulation of Transportation and Sales of Natural Gas

Historically, the transportation (including storage services) and sale for resale of natural gas in interstate commerce have been regulated by agencies of the U.S. federal government, primarily FERC. FERC regulates interstate natural gas transportation rates and service conditions, which affects the marketing of natural gas that we produce and the revenues we receive for sales of our natural gas.

FERC’s current policies allow for the sale of natural gas by producers at market-based prices. However, Congress could enact price controls in the future. The transportation and sale for resale of natural gas in interstate commerce is regulated primarily under the Natural Gas Act, or NGA, and by regulations and orders promulgated under the NGA by FERC. In some limited circumstances, intrastate transportation and wholesale sales of natural gas may also be affected directly or indirectly by laws enacted by Congress and by FERC regulations.

The Energy Policy Act of 2005, or the EPAct 2005, includes an extensive set of tax incentives, authorized appropriations for grants and guaranteed loans, and significant changes to the statutory policy that broadly affect the energy industry. Among other matters, the EPAct 2005 amends the NGA to add an anti-market manipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC, and furthermore provides FERC with additional civil penalty authority. The EPAct 2005 provides FERC with the power to assess civil penalties of up to $1,000,000 per day for violations of the NGA and increases FERC’s civil penalty authority under the NGPA from $5,000 per violation per day to $1,000,000 per violation per day. The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce.

On January 19, 2006, FERC issued Order No. 670, a rule implementing the anti-market manipulation provision of the EPAct 2005. The rules make it unlawful for any entity, directly or indirectly, in connection with the purchase or sale of natural gas or transportation services subject to the jurisdiction of FERC, to (1) use or employ any device, scheme or artifice to defraud; (2) make any untrue statement of material fact or omit to make any such statement necessary to make the statements made, in light of the circumstances under which they were made, not misleading; or (3) engage in any act, practice or course of business that operates, or would operate, as a fraud or deceit upon any entity. The anti-market manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction.

106

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

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

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

Section 1(b) of the NGA excludes natural gas gathering facilities from regulation by FERC under the NGA. Further, an entity is not subject to regulation under NGA by FERC as a “natural gas company” solely by virtue of such entity owning or operating such facilities. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to determine that the owner/operator of such facilities is not subject to regulation as a natural gas company under the NGA. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of ongoing litigation and FERC and Congress have discretion to revise the jurisdictional line. Consequently, the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress.

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

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

107

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

Regulation of Environmental and Occupational Safety and Health Matters

General

Our operations are subject to numerous federal, regional, state, local, and other laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Applicable U.S. federal environmental laws include, but are not limited to, the Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA, the Clean Water Act, or the CWA, and the Clean Air Act, or the CAA. These laws and regulations govern environmental cleanup standards, require permits for air, water, underground injection, solid and hazardous waste disposal and set environmental compliance criteria. In addition, state and local laws and regulations set forth specific standards for drilling wells, the maintenance of bonding requirements in order to drill or operate wells, the spacing and location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells, and the prevention and cleanup of pollutants and other matters. We maintain insurance against costs of clean-up operations, but we are not fully insured against all such risks. Additionally, Congress and federal and state agencies frequently revise environmental laws and regulations, and any changes that result in delay or more stringent and costly permitting, waste handling, disposal and clean-up requirements for the oil and gas industry could have a significant impact on our operating costs.

In addition, public and regulatory scrutiny of the energy industry has resulted in increased environmental regulation and enforcement being either proposed or implemented. For example, the EPA’s 2014 – 2016 National Enforcement Initiatives include “Assuring Energy Extraction Activities Comply with Environmental Laws.” According to the EPA’s website, “some techniques for natural gas extraction pose a significant risk to public health and the environment.” To address these concerns, the EPA’s goal is to “address incidences of noncompliance from natural gas extraction and production activities that may cause or contribute to significant harm to public health and/or the environment.” The EPA has emphasized that this initiative will be focused on those areas of the country where energy extraction activities are concentrated, and the focus and nature of the enforcement activities will vary with the type of activity and the related pollution problem presented. This initiative could involve a large scale investigation of our facilities and processes, and could lead to potential enforcement actions, penalties or injunctive relief against us.

Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal fines and penalties and the imposition of injunctive relief. Accidental releases or spills may occur in the course of our operations, and we cannot be sure that we will not incur significant costs and liabilities as a result of such releases or spills, including any third party claims for damage to property, natural resources or persons. Although we believe that we are in substantial compliance with applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on us, there can be no assurance that this will continue in the future.

The Safe Drinking Water Act and the Underground Injection Control Program

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from subsurface rock formations. We regularly use hydraulic fracturing as part of our operations. Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the federal Safe Drinking Water Act, or the SDWA, over hydraulic fracturing activities involving the use of diesel fuel. From time to time, however, Congress has proposed legislation to amend the SDWA to repeal the exemption for hydraulic fracturing from the definition of

108

“underground injection” and require federal permitting and regulatory control of all hydraulic fracturing activities, as well as to require disclosure of the chemical constituents of the fluids used in the fracturing process. Scrutiny of hydraulic fracturing activities by the EPA continues in other ways, with the EPA having commenced a multi-year study of the potential environmental impacts of hydraulic fracturing, draft results of which are anticipated to be available in 2014. In addition, on October 20, 2011, the EPA announced its intention to propose regulations by 2014 under the CWA to develop standards for wastewater discharges from hydraulic fracturing and other natural gas production activities. According to EPA’s website, the agency expects publication of a proposed rule in 2014. Moreover, the United States Department of the Interior published a revised proposed rule on May 24, 2013 that would implement updated requirements for hydraulic fracturing activities on federal lands, including new requirements relating to public disclosure, well bore integrity and handling of flowback water. Other governmental agencies, including the United States Department of Energy have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms and could ultimately make it more difficult or costly for us to perform fracturing and increase our costs of compliance and doing business.

At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure, and well construction requirements on hydraulic fracturing activities. In Ohio, the Department of Natural Resources has proposed draft regulations that would require a minimum distance between the hydraulic fracturing facilities and streams, require operators to take spill-containment measures, and regulate the types of liners required for waste storage. Local governments may also seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nonetheless regulations can be expected to become stricter in the future, and, 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.

Hazardous Substances and Wastes

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

The Resource Conservation and Recovery Act, or the RCRA, regulates the generation and disposal of wastes. The RCRA specifically excludes from the definition of hazardous waste “drilling fluids, produced waters and other wastes associated with the exploration, development or production of crude oil, natural gas or geothermal energy.” However, legislation has been proposed from time to time that could reclassify certain natural gas and oil exploration and production wastes as “hazardous wastes,” which would make the reclassified wastes subject to much more stringent handling, disposal and clean-up requirements. If such legislation were to be enacted, it could have a significant impact on our operating costs, as well as the natural gas and oil industry in general. Moreover, some ordinary industrial wastes which we generate, such as paint wastes, waste solvents, laboratory wastes and waste oils, may be regulated as hazardous wastes.

109

In addition, current and future regulations governing the handling and disposal of Naturally Occurring Radioactive Materials, or NORM, may affect our operations. For example, the Ohio Department of Natural Resources has asked operators to identify technologically enhanced NORM, or TENORM, in their processes, such as hydraulic fracturing sand, recycled drilling mud, and spent tank bottoms. Local landfills only accept such waste when it meets their TENORM standards. As a result, we may have to locate out-of-state landfills to accept TENORM waste from time to time, potentially increasing our disposal costs.

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

Waste Discharges

The CWA and its state analog impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. The CWA and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. Spill prevention, control and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of navigable waters by a petroleum hydrocarbon tank spill, rupture or leak. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. Federal and state regulatory agencies can impose administrative, civil and criminal penalties as well as other enforcement mechanisms for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.

Air Emissions

The CAA and its state analog and regulations restrict the emission of air pollutants from many sources, including oil and gas operations. New facilities may be required to obtain permits before construction can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. On April 17, 2012, the EPA also approved final rules that establish new air emission controls for oil and natural gas production and natural gas processing operations. These new rules address emissions of various pollutants frequently associated with oil and natural gas production and processing activities by, among other things, requiring new or reworked hydraulically-fractured gas wells to control emissions through flaring until 2015, after which reduced emission (or “green”) completions must be used. The rules also establish specific new requirements, effective in 2012, for emissions from compressors, controllers, dehydrators, storage tanks, gas processing plants, and certain other equipment. On September 23, 2013, EPA published amendments to the rule that would, among other things, provide additional time for recently constructed, modified or reconstructed storage tanks to install emission controls. EPA is continuing to consider other aspects of the new rules and may propose additional amendments in early 2014. These rules may require a number of modifications to our own operations, including the installation of new equipment to control emissions. Compliance with such rules could result in additional costs for us and our customers, including increased capital expenditures and operating costs, which may adversely impact our cash flows and results of operations.

110

Oil Pollution Act

The Oil Pollution Act of 1990, or the OPA, and regulations thereunder impose a variety of requirements on “responsible parties” related to the prevention of oil spills and liability for damages resulting from such spills in United States waters. A “responsible party” includes the owner or operator of an onshore facility, pipeline or vessel, or the lessee or permittee of the area in which an offshore facility is located. The OPA assigns liability to each responsible party for oil cleanup costs and a variety of public and private damages. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of a federal safety, construction or operating regulation. If the party fails to report a spill or to cooperate fully in the cleanup, liability limits likewise do not apply. Few defenses exist to the liability imposed by the OPA. The OPA imposes ongoing requirements on a responsible party, including the preparation of oil spill response plans and proof of financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill.

National Environmental Policy Act

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

Endangered Species Act and Migratory Bird Treaty Act

The Endangered Species Act, or the ESA, and similar applicable state legislation restrict activities that may affect endangered or threatened species of their habitats. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. Moreover, as a result of a settlement approved by the United States District Court for the District of Columbia in September 2011, the United States Fish and Wildlife Service is required to make a determination on listing of more than 250 species as endangered or threatened under the ESA by no later than completion of the agency’s 2017 fiscal year. For example, regulations designed to protect the Indiana bat (Myotis soldalis), which is an endangered species protected by the ESA and similar state legislation, restrict or increase the cost of our operations by, among other things, limiting our ability to clear trees to establish rights of way or pad locations on some of our acreage during certain periods of the year. While some of our operations may be located in areas that are designated as habitats for endangered or threatened species or that may attract migratory birds we believe that we are in substantial compliance with the ESA, similar applicable state legislation and the Migratory Bird Treaty Act, and we are not aware of any proposed ESA listings that will materially affect our operations. However, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected states.

Worker Safety

The Occupational Safety and Health Act, or the OSHA, and any analogous state law regulate the protection of the safety and health of workers. The OSHA hazard communication standard requires maintenance of information about hazardous materials used or produced in operations and provision of such information to employees. Other OSHA standards regulate specific worker safety aspects of our operations. Failure to comply with OSHA requirements can lead to the imposition of penalties.

111

Employees

As of March 31, 2014, we had 159 full-time employees. Our future success will depend partially on our ability to attract, retain and motivate qualified personnel. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages. We utilize the services of independent contractors to perform various field and other services.

Legal Proceedings

West Lawsuit

Other

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

112

MANAGEMENT

Directors, Executive Officers and Other Key Employees

The following table sets forth names, ages and titles of our directors, director nominees and executive officers as of May 15, 2014.


Name	Age		Position with Eclipse Resources
Benjamin W. Hulburt		40	Chairman, President and Chief Executive Officer
D. Martin Phillips		60	Director
Robert L. Zorich		64	Director
Douglas E. Swanson, Jr.		42	Director
Mark E. Burroughs, Jr.		38	Director
Christopher K. Hulburt		43	Director, Executive Vice President, Secretary and General Counsel
Randall M. Albert		56	Director Nominee
Richard D. Paterson		63	Director Nominee
Joseph C. Winkler, III		62	Director Nominee
Matthew R. DeNezza		43	Executive Vice President and Chief Financial Officer
Thomas S. Liberatore		57	Executive Vice President and Chief Operating Officer

The following table sets forth information regarding our other key employees as of May 15, 2014.


Name	Age		Position with Eclipse Resources
Oleg Tolmachev		39	Vice President, Drilling & Completions
Roy Steward		42	Vice President, Chief Accounting Officer
Marty L. Byrd		57	Vice President, Land
Bruce King		53	Vice President, Operations
Dr. Brian Panetta		44	Vice President, Geology
Bryan M. Moody		44	Vice President, Business Development, Finance and Reservoir Engineering
Melissa L. Hamsher		47	Vice President, Health, Safety, Environment & Regulatory
Lawrence Gorski		60	Vice President, Administration
Todd Bart		49	Vice President and Controller
John Colling, Jr.		57	Vice President and Treasurer

Set forth below is the description of the backgrounds of our directors, director nominees, executive officers and other key employees. References to positions held at Eclipse Resources include positions held at Eclipse Operating prior to our corporate reorganization.

Directors, Director Nominees and Executive Officers

Benjamin W. Hulburt co-founded Eclipse Resources in January 2011 and has served as our Chief Executive Officer, President and member of our board since our inception. He has also served as the Chairman of the board of directors of Eclipse Resources Corporation since its inception. Prior to co-founding Eclipse Resources, Mr. Hulburt served as the Chief Executive Officer and a member of the board of directors of Rex Energy, an independent oil and gas exploration and production company with operations in the Appalachian and Illinois Basins within the United States, from March 2007 to October 2010. He also served as President of Rex Energy from February 2008 until October 2010. Mr. Hulburt co-founded Rex Energy in 2001 and led Rex Energy through its initial public offering in 2007. Prior to Rex Energy’s initial public offering, Mr. Hulburt served as the Chief Executive Officer of Rex Energy Operating Corp. from October 2006 until October 2010, and as the President of Rex Energy Operating Corp. from March 2004 until October 2006. Mr. Hulburt also served as the Chief Financial Officer of Douglas Oil & Gas Limited Partnership, an affiliate of Rex Energy, from January 2001 until February 2004. Prior to November 2000, Mr. Hulburt served on active duty as a commissioned officer in the United States Army for four years, leaving the service holding the rank of Captain. Mr. Hulburt received his Bachelor of Science degree in Finance from The Pennsylvania State University. He is the brother of Christopher K. Hulburt.

113

Our board believes that Mr. Hulburt should serve as a member of our board due to his perspective and experience as our co-founder, Chief Executive Officer and President and his considerable leadership, financial and operational experience at both public and private companies in the oil and gas exploration and production industry.

D. Martin Phillips has served as a member of our board since January 2011. He currently serves as a Managing Partner of EnCap. Prior to joining EnCap in 1989, Mr. Phillips served as a Senior Vice President in the Energy Banking Group of NationsBank in Dallas, Texas. In his capacity as Manager of the U.S./International Division of NationsBank from 1987 to 1989, he had responsibility for credit commitments to a broad spectrum of energy-related companies. Mr. Phillips began his career in 1978 with Republic Bank and served in various senior energy banking positions, including Vice President and Manager of Republic Bank’s energy loan production office in Denver, from 1980 to 1985, and Senior Vice President and Division Manager in Republic Bank’s Houston office from 1986 to 1987. Mr. Phillips holds M.B.A. and B.S. degrees from Louisiana State University. He is a member of the LSU College of Business Hall of Distinction. Mr. Phillips also attended the Stonier Graduate School of Banking at Rutgers University. Mr. Phillips serves on the board of several EnCap portfolio companies and is a member of the Independent Petroleum Association of America, the American Petroleum Institute and the Houston Producers’ Forum.

Our board believes that Mr. Phillips should serve as a member of our board due to his significant experience with energy companies and investments and broad knowledge of the oil and gas industry.

Robert L. Zorich has served as a member of our board since January 2011. He is the co-founder of EnCap and currently serves as a Managing Partner. Prior to co-founding EnCap, Mr. Zorich was a Senior Vice President of Trust Company of the West, a privately-held pension fund management company, where he was in charge of its Houston office. Prior to joining Trust Company of the West, Mr. Zorich co-founded MAZE Exploration, Inc., an oil and gas exploration, development and reserve acquisition company, where he served as its Co-Chief Executive Officer. During the first seven years of Mr. Zorich’s career, he was a Vice President and Division Manager in the Energy Department of Republic Bank. Approximately half of his tenure with Republic Bank was spent managing Republic Bank’s energy office in London, where he assembled a number of major project financings for development in the North Sea. Mr. Zorich received his B.A. in Economics from the University of California at Santa Barbara. He also received a Master’s Degree in International Management (with distinction) in 1974 from the American Graduate School of International Management in Phoenix, Arizona. Mr. Zorich serves on the board of several EnCap portfolio companies and is a member of the Independent Petroleum Association of America, the Houston Producers’ Forum and Texas Independent Producers and Royalty Owners Association. Mr. Zorich also served on the board of Oasis Petroleum Inc. and its predecessor entities from March 2007 until March 2012.

Our board believes that Mr. Zorich should serve as a member of our board due to his significant experience with energy companies and investments and broad knowledge of the oil and gas industry.

Douglas E. Swanson, Jr. has served as a member of our board since January 2011. He is currently a Partner of EnCap. Prior to joining EnCap in 1999, he was in the corporate lending division of Frost National Bank from 1995 to 1997, specializing in energy related service companies, and was a financial analyst in the corporate lending group of Southwest Bank of Texas from 1994 to 1995. Mr. Swanson serves on the board of Oasis Petroleum Inc. and several EnCap portfolio companies. Mr. Swanson is a member of the Independent Petroleum Association of America and the Texas Independent Producers and Royalty Owners Association. Mr. Swanson holds a B.A. in Economics and an M.B.A., both from the University of Texas at Austin.

Our board believes that Mr. Swanson should serve as a member of our board due to his extensive experience in the oil and gas exploration and production industry, including serving on the boards of public and private oil and gas exploration and production companies, which will enable Mr. Swanson to provide our board with insight and advice on a full range of business, strategic and governance matters.

114

Mark E. Burroughs, Jr. has served as a member of our board since January 2011. He currently serves as a Managing Director of EnCap. Prior to joining EnCap in March 2007, Mr. Burroughs spent four years working in UBS Investment Bank’s Global Energy Group. Prior to joining UBS Investment Bank, Mr. Burroughs spent three years at Sanders Morris Harris, Inc., an investment banking firm in Houston, Texas. He received an M.B.A. from the Jesse H. Jones School of Management at Rice University and a B.A. in Economics from The University of Texas at Austin. Mr. Burroughs serves on the board of several EnCap portfolio companies as well as Frontier Tubular Solutions. He is also a member of the Houston Producers’ Forum and the Independent Petroleum Association of America.

Our board believes that Mr. Burroughs should serve as a member of our board due to his extensive experience in the oil and gas exploration and production industry as well as his experience as an investment banker, which will enable Mr. Burroughs to provide our board with insight and advice on a full range of business, strategic and financial matters.

Christopher K. Hulburt co-founded Eclipse Resources in January 2011 and has served as our Executive Vice President, Secretary and General Counsel and a member of our board since our inception. Prior to co-founding Eclipse Resources, Mr. Hulburt served as the Executive Vice President, Secretary and General Counsel of Rex Energy. Mr. Hulburt had previously served as the Vice President, Secretary and General Counsel for each of the predecessor companies of Rex Energy since April 2005. From January 2001 until April 2005, Mr. Hulburt was a senior associate for the law firm of Hodgson Russ LLP in its corporate and securities practice group. Before joining Hodgson Russ, he served as a commissioned officer in the U.S. Army’s Judge Advocate General’s Corps as a military prosecutor beginning in January 1997, and, in his last two years of service, also held the position of Special Assistant United States Attorney for the U.S. Department of Justice. Mr. Hulburt received his Bachelor’s degree in History/Education from Niagara University and his law degree from Western New England College School of Law. Mr. Hulburt is the brother of Benjamin W. Hulburt.

Our board believes that Mr. Hulburt should serve as a member of our board due to his perspective and experience as our co-founder, Executive Vice President, Secretary and General Counsel and his considerable legal experience at both public and private companies in the oil and gas exploration and production industry.

Randall M. Albert will become a member of our board in connection with the closing of this offering. Mr. Albert served as the Chief Operating Officer of the Gas Division of CONSOL Energy Inc., a producer of coal and natural gas (“CONSOL”), from 2010 until November 2013. From 2005 until 2010, he was the operational leader of CONSOL’s gas business in Northern Appalachia. Mr. Albert began working for CONSOL in 1979 and was selected to lead the operation of its coalbed methane gas business in Southern Appalachia in 1985. He is a board member of the Virginia Oil and Gas Association and served as a founding advisory member of the board and chairman of the Marcellus Shale Coalition. Additionally, he currently serves on the advisory board for the Virginia Tech Mining Engineering Department. Mr. Albert is a Registered Professional Engineer in Virginia and West Virginia and holds a B.S. degree in Mining Engineering from Virginia Polytechnic Institute and State University.

Our board believes that Mr. Albert should serve as a member of our board due to significant executive and operational experiences within the natural gas industry, particularly with respect to the Appalachia Basin.

Richard D. Paterson will become a member of our board in connection with the closing of this offering. Mr. Paterson retired from PricewaterhouseCoopers LLP, an international network of auditors, tax and business consultants (“PwC”), in June 2011 after 37 years of service. Most recently, he served as PwC’s Global Leader of its Consumer, Industrial Products and Services Practices (comprising the Automotive, Consumer and Retail, Energy, Utilities and Mining, Industrial Products, Pharmaceutical and Health Industries Sectors) and also as Managing Partner of its Houston Office and U.S. Energy Practice. From 2001 to 2010, Mr. Paterson was PwC’s Global Leader of its Energy, Utilities and Mining Practice. From 1997 to 2001, Mr. Paterson led PwC’s Energy Practice for Europe, Middle East and Africa. Prior to 1997, Mr. Paterson was responsible for the audits of numerous PwC clients, principally in the energy sector. He began his career with PwC in 1974 and was admitted as a partner of PwC in 1987. Mr. Paterson serves on the board and as chairman of the audit committee of Parker

115

Drilling Company, a provider of contract drilling and drilling related services and rental tools to the energy industry, and he previously served on the board and as chairman of the audit committee of Zaff GP LLC, a private equity fund investing in emerging markets with a focus on the energy, infrastructure and real estate sectors. Mr. Paterson is a member of the National Association of Corporate Directors and has been a frequent speaker at the World Energy Congress and World Petroleum Congress. Mr. Paterson also previously served as a board member of the U.S./Russia Business Council and the U.S. Energy Association. Mr. Paterson received a B.A. in Marketing and an M.B.A. in Accounting from Michigan State University. He is also a Certified Public Accountant.

Our board believes that Mr. Paterson should serve as a member of our board due to his extensive knowledge of the energy industry and his significant expertise in capital markets, corporate governance matters and the preparation and review of financial statements and disclosures.

Joseph C. Winkler, III will become a member of our board in connection with the closing of this offering. Mr. Winkler served as Chairman and Chief Executive Officer of Complete Production Services, Inc., a provider of specialized oil and gas services and equipment in North America (“Complete”), from March 2007 until February 2012, at which time Complete was acquired by Superior Energy Services, Inc. From June 2005 to March 2007, Mr. Winkler served as Complete’s President and Chief Executive Officer. Prior to that, from March 2005 until June 2005, Mr. Winkler served as the Executive Vice President and Chief Operating Officer of National Oilwell Varco, Inc., an oilfield capital equipment and services company, and from May 2003 until March 2005, as the President and Chief Operating Officer of such company’s predecessor, Varco International, Inc. (“Varco”). From April 1996 until May 2003, Mr. Winkler served in various other capacities with Varco and its predecessor, including Executive Vice President and Chief Financial Officer. From 1993 to April 1996, Mr. Winkler served as the Chief Financial Officer of D.O.S., Ltd., a privately held provider of solids control equipment and services and coil tubing equipment to the oil and gas industry, which was acquired by Varco in April 1996. Prior to joining D.O.S., Ltd., Mr. Winkler served as Chief Financial Officer of Baker Hughes INTEQ, and served in a similar role for various companies owned by Baker Hughes Incorporated, including Eastman/Telco and Milpark Drilling Fluids. Mr. Winkler serves on the board and as chairman of the audit and conflicts committee of the general partner of Hi-Crush Partners LP, an integrated producer, transporter, marketer and distributor of a specialized mineral used to enhance production in oil and natural gas wells. Mr. Winkler also serves on the board and as a member of the compensation and nominating and governance committees of Dresser-Rand Group, Inc., a provider of rating equipment solutions, and serves on the board and as a member of the finance committee of Commercial Metals Company, a vertically integrated steel company. Mr. Winkler is a Gulf Coast District Director of the Petroleum Equipment Suppliers Association (PESA), an oilfield service and supply industry trade association. Mr. Winkler received a B.S. degree in Accounting from Louisiana State University.

Our board believes that Mr. Winkler should serve as a member of our board due to his extensive operational, financial, international and capital markets experience, a significant portion of which was with publicly-traded companies in the oil and gas industry.

Matthew R. DeNezza has served as our Executive Vice President and Chief Financial Officer since April 2013. Prior to joining Eclipse Resources and commencing in 2002, Mr. DeNezza served in the Global Natural Resources Group at Deutsche Bank Securities where he was promoted to Managing Director and was responsible for leading merger and acquisition advisory assignments, as well as aiding clients in understanding capital markets and developing and executing financing transactions. During his tenure with Deutsche Bank, Mr. DeNezza assisted on numerous investment banking transactions for both public and private oil and gas exploration and production companies and refining companies. Prior to joining Deutsche Bank, from 1999 to 2001, Mr. DeNezza was the Assistant Vice President, Corporate Finance of Janney Montgomery Scott, LLC, a financial advisory and services firm. Mr. DeNezza served in the United States Navy as a commissioned officer from 1993 to 1998, leaving the service at the rank of Lieutenant. Mr. DeNezza received his Bachelor of Arts degree from Harvard University and Masters of Business Administration degree from New York University’s Leonard N. Stern School of Business.

116

Thomas S. Liberatore has served as our Executive Vice President and Chief Operating Officer and a member of the board of managers of Eclipse I since June 2011. Prior to joining Eclipse Resources, from June 2009 until May 2011, Mr. Liberatore was self-employed and formed Libco Energy LLC, which leased oil and gas interests for its own account and brokered the sale of oil and gas mineral interests in West Virginia and Alabama, and he served as a consultant to oil and gas attorneys and land companies. From January 2002 until May 2009, Mr. Liberatore served as Vice President and Appalachian Regional Manager for Cabot Oil & Gas where he managed drilling and acquisition investments, including those in the Devonian Huron Marcellus Shale. From March 1999 to December 2001, Mr. Liberatore served as the Vice President, Exploration and Production for North Coast Energy, Inc. Mr. Liberatore began his career as a geologist and had various positions of increasing responsibility for Presidio Oil Company and Belden & Blake Corporation. Mr. Liberatore received his Bachelor of Science degree in Geology from West Virginia University. He is a member of the American Association of Petroleum Geologists, Appalachian Geological Society, has served on the board of directors of the West Virginia Oil and Natural Gas Association, is a Past President of Independent Oil and Gas Association West Virginia and is a registered professional geologist in the Commonwealth of Kentucky.

Other Key Employees

Oleg Tolmachev has served as our Vice President, Drilling & Completions since February 2013. Prior to joining Eclipse Resources, from April 2011 to February 2013, Mr. Tolmachev served as the Senior Asset Manager, Utica Shale with Chesapeake Energy where he was responsible for leading an asset team comprised of land, geology, drilling, resource development and operations for Chesapeake Energy’s Utica Shale projects in Ohio. Prior to joining Chesapeake Energy, from August 2008 to 2011, Mr. Tolmachev held the position of Group Lead Completions, Mid-Continent Business Unit at EnCana Oil and Gas (USA) Inc. where he managed well completions and intervention operations in its Barnett Shale, Deep Bossier and East Texas Haynesville Shale business units. Mr. Tolmachev received his Bachelors of Science degree in Petroleum Engineering from the University of Oklahoma.

Roy Steward has been our Vice President, Chief Accounting Officer since March 2014. Prior to joining Eclipse Resources, Mr. Steward was a partner in the audit practice with KPMG LLP. During his 19-year career with KPMG, Mr. Steward provided professional services to public and private companies in the energy industry, including leading multinational audit teams and reviews of SEC filings. Mr. Steward served as a partner in KPMG’s national Department of Professional Practice consulting with teams on accounting, auditing and SEC reporting issues and completed an international rotation with KPMG in Sydney, Australia. Mr. Steward is a Certified Public Accountant in the State of Texas and is currently a member of the American Institute of Certified Public Accountants and the Texas Society of Certified Public Accountants. Mr. Steward received his Bachelor of Business Administration degree in Accounting from Texas Christian University.

Marty L. Byrd has served as our Vice President, Land since July 2013. Prior to joining Eclipse Resources, from January 2006 to January 2013, Mr. Byrd served as the Vice President, Land, Eastern Division—Appalachian Basin for Chesapeake Energy, where he was responsible for overseeing the acquisition of over a million leasehold acres in the Marcellus Shale and managing the land activities to support the drilling of over 400 horizontal wells with a drilling schedule utilizing up to 26 rigs. From January 2001 to January 2006, Mr. Byrd worked in Chesapeake Energy’s Mid-Continent Region and served as the Land Manager in the Anadarko Basin District. Mr. Byrd received his Bachelors of Science degree in Business Administration from the University of Central Oklahoma.

Bruce King has served as our Vice President, Operations since September 2013. Prior to joining Eclipse Resources, from April 2011 to September 2013, Mr. King served as the Operations Manager, Stone Energy, Appalachia where he was responsible for construction, pipelines, facilities and production, including developing infrastructure for its unconventional shale program in West Virginia and Pennsylvania. Prior to joining Stone Energy, from August 2009 to April 2011, Mr. King was the Gas Systems and Facilities Manager at EnerVest Operating Company. From August 2000 to August 2009, he served as Facility Manager at Cabot Oil & Gas

117

where he oversaw development of gathering systems, gas treatment and midstream assets, including the core infrastructure for its Marcellus Shale development. Prior to his time at Cabot Oil & Gas, Mr. King spent 8 years with Columbia Gas Transmission (NiSource) where he oversaw major infrastructure projects in natural gas transmission and storage. Mr. King received his Bachelors of Science degree in Mechanical Engineering from the West Virginia University Institute of Technology.

Dr. Brian Panetta has served as our Vice President, Geology since March 2011. Prior to joining Eclipse Resources, from 2009 to 2011, Dr. Panetta was a geologist with Waco Oil & Gas Co., Inc. where he was responsible for geological and petrophysical analysis of the Marcellus Shale and Utica Shale and the development of its Marcellus Shale drilling program in West Virginia. Prior to joining Waco Oil & Gas Co., Inc., from 2008 to 2009, Dr. Panetta served as a Senior Geologist for Chesapeake Energy, and from 2006 to 2008, he served as a geologist at Chesapeake Energy. While at Chesapeake Energy, Mr. Panetta was responsible for geological and petrophysical analysis of the Marcellus Shale in Southwest Pennsylvania and West Virginia. Dr. Panetta earned his Bachelor of Science degree in Geology from the University of South Carolina, Master of Science degrees in Geology from the University of Kentucky and The University of Alabama, and a Doctorate degree in Geology from The University of Alabama. He is a member of the American Association of Petroleum Geologists and is a registered professional geologist in the State of Alabama and Commonwealth of Pennsylvania.

Bryan M. Moody has served as our Vice President, Business Development, Finance and Reservoir Engineering since May 2012. Prior to joining Eclipse Resources, from June 2010 to May 2012, Mr. Moody served as the Director of Development Planning for EXCO Resources, Inc. where he was responsible for developing strategic initiatives, implementing portfolio optimization, improving budgeting and the reserve forecasting and reporting process in both its Dallas and Pittsburgh offices. Prior to joining EXCO Resources, Inc., from 2007 to 2010, Mr. Moody served as the Director of Reservoir Reporting for SandRidge Energy, Inc., where he focused on economic reserves analysis and reporting, evaluating drilling joint venture proposals, asset sales, acquisitions and divestitures. Before joining Sandridge Energy, Inc., Mr. Moody founded the Montecito Consulting Group, a consulting firm specializing in financial analysis and valuation, accounting policy, and compliance with SEC and International Financial Reporting Standards regulations. Mr. Moody served in the United States Navy as a nuclear engineer. He received his Bachelor of Science degree in Nuclear Engineering Technology from Thomas Edison State College and his Master of Business Administration degree with concentrations in Finance and International Management from the Simon Graduate School of Business, University of Rochester.

Melissa L. Hamsher has served as our Vice President, Health, Safety, Environment & Regulatory since September 2011. Prior to joining Eclipse Resources, from August 2008 to August 2011, Mrs. Hamsher served as the Vice President of Health, Safety, Environmental and Regulatory Compliance for Rex Energy where she was responsible for the establishment and management of Rex Energy’s health, safety, environmental and regulatory programs, including the establishment of its Marcellus Shale drilling & completion best practices and water management. Prior to joining Rex Energy, from September 2002 to August 2008, Mrs. Hamsher was an engineer for the Pennsylvania Department of Environmental Protection, Bureau of Oil and Gas Management. Mrs. Hamsher holds Bachelor of Science degrees in Structural Design and Construction Engineering and Environmental Engineering from The Pennsylvania State University.

Lawrence Gorski has served as our Vice President, Administration since August 2013. Prior to joining Eclipse Resources, from April 2009 to August 2013, Mr. Gorski served as the Senior Vice President, Human Resources for F.N.B. Corporation, a publicly traded bank holding company. Prior to joining F.N.B Corporation, from December 2007 to April 2009, Mr. Gorski was the Vice President, Human Resources and Administration for Rex Energy. Mr. Gorski has over 30 years of experience in employee and labor relations and compliance and regulatory matters in global public companies. He has chaired compensation and benefit committees and worked with boards of directors on compensation, benefits, stock plans and executive succession matters. Mr. Gorksi has experience in mergers and acquisitions in Europe and North America and he has also handled matters with the National Labor Relations Board, Occupational Safety and Health Administration, the Equal Employment Opportunity Commission, the Internal Revenue Service, the U.S. Department of Labor and various international

118

regulatory authorities. Mr. Gorski earned a Bachelor of Arts degree in Labor Studies from The Pennsylvania State University, a Master of Arts degree in Personnel and Industrial Relations from St. Francis University, and a law degree from the Duquesne University School of Law.

Todd Bart has served as our Vice President and Controller since October 2013. From February 2011 until September 2013, Mr. Bart served as our Director of Accounting. Mr. Bart has over 15 years of oil and gas industry accounting experience. Prior to joining Eclipse Resources, from August 2007 until January 2011, Mr. Bart was a self-employed accountant, performing small business consulting services. From April 2006 until July 2007, Mr. Bart served as the Chief Financial Officer for EnerJex Resources, Inc., a mid-continent oil and gas exploration and production company. Prior to joining EnerJex Resources, Inc., from January 2005 to March 2006, Mr. Bart was the Vice President and Controller for Bois d’Arc Energy, Inc., an independent oil and gas exploration and production company with operations focused in the Gulf of Mexico. Prior to joining Bois d’Arc Energy, Inc., from 1995 until 2004, Mr. Bart was an executive financial officer for PANACO, Inc., an independent oil and gas exploration and production company with operations focused in the Gulf of Mexico and onshore in the Gulf Coast region. Mr. Bart received his Bachelor of Business Administration in Accounting degree from Abilene Christian University. Mr. Bart received his Certified Public Accountant designation from the State of Kansas in 1993 and the State of Texas in 1991 and is currently a member of the American Institute of Certified Public Accountants.

John Colling, Jr. has served as our Vice President, Treasurer since May 2014. Prior to joining Eclipse Resources, from December 2010 through April 2014, Mr. Colling was a self-employed accounting and treasury consultant advising clients on acquisition valuation, capital deployment and financing transactions, including senior debt financings and initial public offerings. From May 2008 through December 2010, Mr. Colling served as President of Certicell LLC, a provider of reverse logistic and repair management services for electronic products where his responsibilities included management of U.S. reverse logistic operations and financial and administrative activities. From July 2005 through May 2008, Mr. Colling served as the Treasurer of MAPCO Express and Delek Refining, each a subsidiary of Delek US Holdings, Inc., an integrated downstream energy company that operates in petroleum refining, logistics, and convenience store retailing businesses. Mr. Colling also served as the Vice President and Treasurer of Delek US Holdings, Inc. from May 2006 until May 2008. From November 2003 to July 2005, Mr. Colling was the Treasurer of Nu-kote International, Inc., a manufacturer and distributor of printer cartridges, and from July 1990 to September 2003, Mr. Colling served as the Vice President and Treasurer of Magnetek, Inc., a provider of digital power and electronic products, where he was responsible for world-wide treasury activities including, mergers and acquisitions, corporate finance transactions, corporate risk management and financial planning. Mr. Colling holds a Bachelor of Science degree from the University of Illinois and a Master of Business Administration degree from Southern Illinois University. He received his Certified Public Accounting designation from the State of Illinois.

Board of Directors

Our board of directors currently consists of 6 members, Benjamin W. Hulburt, Christopher K. Hulburt, D. Martin Phillips, Robert L. Zorich, Douglas E. Swanson, Jr., and Mark E. Burroughs, Jr. In connection with the completion of this offering, we will enter into a stockholders agreement with Eclipse Holdings and its limited partners, the EnCap Funds, the Management Funds and Management Holdco, which we refer to as our principal stockholders. Please see “Certain Relationships and Related Party Transactions—Stockholders Agreement.” Pursuant to the stockholders agreement, we and our principal stockholders will agree to take certain actions to cause individuals designated by our principal stockholders to become members of our board of directors. We expect that Randall M. Albert, Richard D. Paterson and Joseph C. Winkler, III will become members of our board of directors in connection with the closing of this offering.

In connection with the closing of this offering, Messrs. Paterson (Chair), Albert and Winkler will serve on our audit committee. We also expect that our board will review the independence of our current directors using the independence standards of the NYSE, and based on this review, determine that Messrs. Phillips, Zorich, Swanson Burroughs, Albert, Paterson and Winkler are independent within the meaning of the NYSE listing

119

standards currently in effect. As a result, we expect that our board of directors will consist of 9 members after the completion of this offering, 7 of whom will be independent under the NYSE’s listing standards.

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

In connection with the completion of this offering, our directors will be divided into 3 classes serving staggered 3-year terms. Class I, Class II and Class III directors will serve until our annual meetings of stockholders in 2015, 2016 and 2017, respectively. We anticipate that Messrs. Swanson, Phillips and Albert will be assigned to Class I, Messrs. Zorich, Christopher K. Hulburt and Winkler will be assigned to Class II and Messrs. Burroughs, Benjamin W. Hulburt and Paterson will be assigned to Class III. At each annual meeting of stockholders held after the initial classification, directors will be elected to succeed the class of directors whose terms have expired. This classification of our board of directors could have the effect of increasing the length of time necessary to change the composition of a majority of the board of directors because generally at least 2 annual meetings of stockholders will be necessary for stockholders to effect a change in a majority of the members of the board of directors.

Status as a Controlled Company

Because Eclipse Holdings and its limited partners, including the EnCap Funds, the Management Funds and Management Holdco, will collectively beneficially own a majority of our outstanding common stock following the completion of this offering and will be deemed a group as a result of the stockholders agreement to be entered into in connection with the closing of this offering, we expect to be a controlled company under NYSE corporate governance standards. A controlled company may elect not to comply with certain NYSE corporate governance standards, including the requirements that:

•

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

•

we have a nominating and corporate governance committee that is composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities; and

•

we have a compensation committee that is composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities.

Following this offering, we intend to utilize the exemptions relating to the nominating and governance committee and compensation committee requirements, but expect that our board of directors will consist of a majority of independent directors within the meaning of the NYSE listing standards currently in effect. However, we may utilize any of these exemptions for so long as we are a controlled company. Accordingly, you will not have the same protections afforded to stockholders of companies that are subject to all of the corporate governance requirements of the NYSE.

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

Committees of the Board of Directors

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

120

Audit Committee

We will establish an audit committee prior to the completion of this offering. Rules implemented by the NYSE and SEC require us to have an audit committee comprised of at least three directors who meet the independence and experience standards established by the NYSE and the Exchange Act, subject to transitional relief during the one-year period following the completion of this offering. Our audit committee will initially consist of Messrs. Paterson (Chair), Albert and Winkler, each of whom will be independent under the rules of the SEC and the listing standards of the NYSE. As required by the rules of the SEC and listing standards of the NYSE, the audit committee will consist solely of independent directors. SEC rules also require that a public company disclose whether or not its audit committee has an “audit committee financial expert” as a member. An “audit committee financial expert” is defined as a person who, based on his or her experience, possesses the attributes outlined in such rules. We anticipate that Mr. Paterson will satisfy the definition of “audit committee financial expert.”

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

Lack of Compensation Committee Interlocks and Insider Participation

Because we are a controlled company within the meaning of the NYSE corporate governance standards, we do not have a compensation committee. Messrs. Burroughs, Swanson, Phillips and Zorich have historically made all final determinations regarding executive officer compensation. For a description of certain transactions involving us and our directors and executive officers, see “Certain Relationships and Related Party Transactions.”

Code of Business Conduct and Ethics

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

Corporate Governance Guidelines

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

121

EXECUTIVE COMPENSATION

Named Executive Officers

For fiscal year 2013, our Named Executive Officers were as follows. Please see “Management” for a description of our current executive officers, including historical roles held by our 2013 Named Executive Officers.


Name		Principal Position
Benjamin W. Hulburt		Chairman, President and Chief Executive Officer
Matthew R. DeNezza		Executive Vice President and Chief Financial Officer
Thomas S. Liberatore		Executive Vice President and Chief Operating Officer
Christopher K. Hulburt		Executive Vice President, Secretary and General Counsel

Summary Compensation Table

The following table summarizes, with respect to our Named Executive Officers, information relating to the compensation earned for services rendered in all capacities during the fiscal year ended December 31, 2013.


Name and Principal Position	Year		Salary		Bonus		Equity Awards⁽¹⁾		All Other Compensation⁽²⁾		Total
Benjamin W. Hulburt		2013		$261,038		$—		$—		$29,217		$290,255
(Chairman, President and CEO)

Matthew R. DeNezza		2013		$195,673⁽³⁾		$150,000⁽⁴⁾		$12,580		$56,615		$414,868
(Executive Vice President and CFO)

Thomas S. Liberatore		2013		$261,038		$—		$—		$28,393		$289,431
(Executive Vice President and COO)

Christopher K. Hulburt		2013		$261,038		$—		$—		$28,857		$289,895
(Executive Vice President, Secretary and General Counsel)

(1)

Amount shown represents the grant date fair value of Class C-1 Units and Class C-2 Units of Eclipse I granted to Mr. DeNezza as determined in accordance with FASB ASC Topic 718.

(2)

Includes 401(k) match, health and life insurance benefits and cellphone allowance, and for Mr. DeNezza, $37,843 of relocation reimbursement.

(3)

Mr. DeNezza commenced employment with us on April 1, 2013.

(4)

Represents sign-on bonus received upon commencement of employment.

Narrative Description to the Summary Compensation Table for the 2013 Fiscal Year

We have begun the process of reviewing our executive compensation program with the goal of modifying it to be more suitable for a public company. To aid in this process, our board of directors has engaged a nationally recognized compensation consultant, which we refer to herein as the Compensation Consultant, for compensation advice and analysis. The following discussion describes the elements of our current executive compensation program and identifies certain changes that are contemplated to be made in connection with this offering.

Base Salary

Each Named Executive Officer’s base salary is a fixed component of compensation for each year for performing specific job duties and functions. The base salaries of Messrs. DeNezza, Liberatore and C. Hulburt, were set pursuant to arms-length negotiations with our senior management, subject to EnCap’s approval. Mr. Benjamin W. Hulburt’s base salary was set pursuant to arms-length negotiations directly with the representatives of EnCap serving on our board of directors.

122

In connection with this offering, we anticipate that an informal compensation committee comprised of Mr. Phillips, Mr. Zorich, Mr. Swanson and Mr. Burroughs, which we refer to as the Committee, will analyze the appropriateness of the base salary for each of our Named Executive Officers in light of the base salaries of other executives in the peer group that we identify with the assistance of the Compensation Consultant, both on a stand-alone basis and as a component of total compensation.

Annual Cash Bonus

For fiscal 2013, the only cash bonus awarded to our Named Executive Officers was a $150,000 sign-on bonus paid to Mr. DeNezza in connection with the commencement of his employment with us.

Following the conclusion of our Committee’s review of our compensation program with data and analysis provided by the Compensation Consultant, we expect to implement an annual incentive cash bonus program to reward the achievement of financial or operational goals so that total compensation reflects actual company and individual performance.

Long-Term Incentive Compensation

Incentive Units

Eclipse I has issued non-voting Series C-1 units and Series C-2 units, which we refer to as the Incentive Units, to certain employees of Eclipse I and Eclipse Operating. As limited partners of Eclipse I, the holders of Incentive Units will begin to participate in distributions from Eclipse I after distributions have been made to the EnCap Funds, as limited partners of Eclipse Holdings, to satisfy specified hurdle rates and return on investment factors, with the level of participation in such distributions adjusting upwards if such distributions satisfy additional specified hurdle rates and return on investment factors. Holders of Series C-2 units participate in distributions after holders of Series C-1 units have received specified cash distributions from Eclipse I. The Incentive Units vest on varying schedules as determined by the vesting schedule set forth in each grant agreement (generally in equal annual amounts over a set period of time or upon a sale of Eclipse), and a holder of Incentive Units forfeits unvested Incentive Units upon ceasing to be an employee of Eclipse I or Eclipse Operating. The vesting of the Incentive Units will not be accelerated as a result of our corporate reorganization or the offering or sale of our common stock in this offering.

Prior to our corporate reorganization, the holders of Incentive Units will contribute their Incentive Units to Management Holdco, which will hold all outstanding Incentive Units. The former holders of Incentive Units will then have economic rights as limited partners of Management Holdco that will approximate as closely as practicable the economic rights such holders had when directly holding their Incentive Units. For example, a former holder of Incentive Units receives a percentage of distributions from Management Holdco calculated by dividing (i) the distributions from Eclipse I to Management Holdco attributable to the former holder’s contributed Incentive Units by (ii) the aggregate distributions from Eclipse I to Management Holdco attributable to all contributed Incentive Units. The Incentive Units will remain subject to the terms of the employees’ respective award agreements, such as the vesting provisions set forth in those agreements.

In connection with our corporate reorganization, Management Holdco will contribute the Incentive Units it holds to Eclipse Holdings in exchange for limited partner interests in Eclipse Holdings that are substantially identical to the Incentive Units, and Eclipse Holdings will subsequently contribute Incentive Units to Eclipse Resources Corporation. As a result, following our corporate reorganization, employees that formerly held Incentive Units will continue to hold limited partner interests in Management Holdco, which itself will hold limited partner interests in Eclipse Holdings that are economically substantially identical to the Incentive Units formerly held by those employees. Management Holdco, as a limited partner of Eclipse Holdings and holder of the incentive units of Eclipse Holdings, will begin to participate in distributions from Eclipse Holdings after distributions have been made to the EnCap Funds, as limited partners of Eclipse Holdings, to satisfy specified hurdle rates and return on investment factors, with the level of participation in such distributions adjusting upwards if such distributions satisfy additional specified hurdle rates and return on investment factors.

123

Our management’s indirect ownership of limited partner interests in Eclipse Holdings provides our management with a strong incentive to continue to grow the value of our company. Specifically, the level of participation of Management Holdco in the distributions from Eclipse Holdings adjusts following any “payout,” which occurs when: (i) the aggregate distributions to the EnCap Funds, when discounted at the applicable hurdle rate from the respective dates of such distributions to January 31, 2011, equal the aggregate capital contributions of the EnCap Funds, when discounted at the applicable hurdle rate from the respective dates of such capital contributions to January 31, 2011; and (ii) the aggregate distributions that the EnCap Funds have received equal or exceed the product of the applicable return on investment factor and the aggregate capital contributions made by the EnCap Funds. Management Holdco will: (i) participate in 12.07% of distributions following the first payout (i.e., a payout using a hurdle rate of 8% per annum compounded monthly and a return on investment factor of 1.10); (ii) participate in 22.42% of distributions following the second payout (i.e., a payout using a hurdle rate of 20% per annum compounded monthly and a return on investment factor of 1.75); and (iii) participate in 27.59% of distributions following the third payout (i.e., a payout using a hurdle rate of 30% per annum compounded monthly and a return on investment factor of 2.50).

Distributions from Eclipse Holdings to Management Holdco (and therefore indirectly to the former holders of Incentive Units) will be made from the assets of Eclipse Holdings through either (i) an in-kind distribution of our common stock that will be held by Eclipse Holdings immediately following our corporate reorganization, or (ii) a cash distribution generated by the sale of such common stock at the discretion of the board of Eclipse Holdings. Compensation expense for the Incentive Units is calculated based on the fair value of the award at the date of grant and is recognized over the requisite service period. Such charges to stock compensation expense for awards that continue to vest subsequent to our corporate reorganization will be recorded by us and credited to additional paid-in capital. If the vesting of the Incentive Units is accelerated through a sale or transfer of all or substantially all of our common stock or assets, any unrecognized compensation cost will be recorded at that time.

In 2013, Mr. DeNezza was granted Series C-1 units and Series C-2 units of Eclipse I in connection with the commencement of his employment with us. The Incentive Units issued to Mr. DeNezza in 2013 are subject to vesting, with one-third of each class of the Incentive Units vesting on each anniversary of his hire date, though the vesting may accelerate upon the earlier of a sale or transfer of substantially all of the interests or assets of Eclipse I, including by way of a merger; provided that the vesting of such units will not be accelerated as a result of our corporate reorganization or the offering or sale of our common stock in this offering.

Long-Term Incentive Plan

To incentivize management members following the completion of this offering, we anticipate that our board of directors will adopt an omnibus long-term incentive plan for employees, consultants and directors, which we refer to as the LTIP. Once adopted, our Named Executive Officers will be eligible to participate in the LTIP, which we expect will become effective upon the consummation of this offering. We anticipate that the LTIP will provide for the grant of bonus stock, restricted stock, restricted stock units, options, stock appreciation rights, dividend equivalent rights, performance awards, annual incentive awards and other stock-based awards intended to align the interests of key employees (including the Named Executive Officers) with those of our stockholders.

Set forth below is a summary of our current expectations of the material features of the LTIP that we anticipate our board of directors will adopt. The terms and conditions described below remain subject to change unless and until our board of directors adopts the LTIP.

The LTIP – Generally

The LTIP will provide us with the flexibility to make grants of stock options (both incentive stock options or options that do not constitute incentive stock options), restricted stock, restricted stock units, dividend equivalents, performance awards, annual incentive awards, bonus stock awards, or other stock-based awards. All officers and

124

employees of Eclipse Resources or our subsidiaries, as well as other individuals who provide services to us or our subsidiaries (including directors), will be eligible to receive awards under the LTIP. The LTIP will expire upon the earliest of (i) its termination by our board of directors, (ii) the date common stock is no longer available under the LTIP for grants of awards, or (iii) the tenth anniversary of the effective date of the LTIP. Shares that may be granted under the LTIP are subject to the availability of shares in the share pool.

Administration of LTIP

The LTIP will initially be administered by our board of directors or a subcommittee thereof (the “Plan Committee”). Under the terms of the LTIP, the Plan Committee will have the power to: (i) adopt, amend, and rescind administrative and interpretative rules and regulations relating to the LTIP; (ii) determine which eligible individuals will be granted awards under the LTIP and the time or times at which such awards will be granted; (iii) determine the amount of cash and/or the number of shares of common stock that will be subject to each award under the LTIP; (iv) determine the terms and provisions of each award agreement; (v) accelerate the time of vesting or exercisability of any award that has been granted under the LTIP; (vi) construe the respective award agreements and the LTIP; (vii) make determinations of the fair market value of the common stock pursuant to the LTIP; (viii) delegate its duties under the LTIP (including, but not limited to, the authority to grant awards) to such agents as it may appoint from time to time; (ix) subject to the terms of the LTIP, terminate, modify, or amend the LTIP; and (x) make all other determinations, perform all other acts, and exercise all other powers and authority necessary or advisable for administering the LTIP, including the delegation of those ministerial acts and responsibilities as our Plan Committee deems appropriate.

Shares Available for Awards Under the LTIP

We expect the aggregate maximum number of shares of our common stock that may be issued under the LTIP will not exceed 16,000,000. Shares of common stock cancelled, settled in cash, forfeited, withheld, or tendered by the participant to satisfy exercise prices or tax withholding obligations will be available for delivery pursuant to other awards. The common stock delivered pursuant to such awards may be common stock acquired in the open market or acquired from any affiliate or other person, or any combination of the foregoing, as determined in the discretion of the Plan Committee.

We expect the LTIP to provide that in any single calendar year during the term of the LTIP an employee may not be granted stock options or stock appreciation rights relating to more than 4,000,000 shares of our common stock. Further, we expect that the following limitations will apply with respect to performance awards granted under the LTIP to the extent the performance awards are intended to qualify as “performance-based compensation” under section 162(m) of the Internal Revenue Code of 1986, as amended (the “Code”), and granted to a “covered employee” as defined under section 162(m) of the Code:

•

The maximum number of shares of our common stock that may be subject to awards denominated in shares of our common stock granted to any one individual during any one calendar year in the term of the LTIP (excluding awards granted in connection with this offering) may not exceed 4,000,000 shares; and

•

The maximum payment under any performance award denominated in dollars that may be granted to a covered employee during any calendar year will be $5,000,000 for each 12-month period contained in the performance period for such performance award.

We expect that the LTIP will provide that if we effect a subdivision or consolidation or an extraordinary cash dividend on the shares of our common stock, the number of shares of stock subject to the award and the purchase price thereunder (if applicable) will be proportionately adjusted. If we recapitalize, reclassify, or otherwise change our capital structure, outstanding awards will be adjusted so that the award will thereafter cover the number and class of shares to which the holder would have been entitled if he had been the holder of record of the shares covered by such award immediately prior to the recapitalization, reclassification, or other change in our capital structure. Further, the aggregate number of shares available under the LTIP and the individual award limitations described above will also be appropriately adjusted.

125

Types of LTIP Awards

At the discretion of our Plan Committee, we expect that awards under the LTIP may be granted in the forms described below. Each award will be evidenced by an award agreement setting forth the specific terms and conditions applicable to the award.

Options. The LTIP will provide for the granting of incentive stock options or options that do not constitute incentive stock options. The Plan Committee will determine the terms of any stock options granted under the LTIP, including the purchase price and when such options become vested and exercisable. The Plan Committee will also determine the term of each option (up to a maximum term of 10 years), the time at which an option may be exercised, and the method by which payment of the purchase price may be made.

Stock Appreciation Rights. Stock appreciation rights allow the recipient to receive the appreciation in the fair market value of our common stock between the date of grant and the exercise date. The Plan Committee will determine the terms of any stock appreciation rights, including when such rights become vested and exercisable and whether to pay the appreciation in cash, in shares of our common stock, or a combination thereof. The term of each stock appreciation right may not exceed 10 years from the date of grant.

Restricted Stock. Pursuant to a grant of restricted stock, shares of our common stock may be issued or delivered to participants, subject to certain restrictions on the disposition thereof and certain obligations to forfeit the shares to us as may be determined in the discretion of the Plan Committee. The restrictions on disposition and the forfeiture restriction for restricted stock may lapse at such times and under such circumstances (including based on achievement of performance goals and/or future service requirements) or in such installments as the Plan Committee may determine. The recipient may not sell, transfer, pledge, exchange, hypothecate, or otherwise dispose of the shares until the expiration of the restriction period. However, upon the issuance of shares of our common stock pursuant to a restricted stock award, except as otherwise determined by the Plan Committee, the holder will have all the rights of a holder of our common stock with respect to the shares, including the right to vote the shares and to receive all dividends and other distributions paid with respect to the shares. Dividends made on restricted stock may or may not be subjected to the same vesting provisions as the restricted stock, depending on the terms of the award agreement pursuant to which the restricted stock award is granted.

Restricted Stock Units. A restricted stock unit is a notional share of our common stock that entitles the grantee to receive a share of our common stock upon the vesting of the restricted stock unit or, in the discretion of the Plan Committee, the cash equivalent to the value of a share of our common stock. The Plan Committee may determine to make grants of restricted stock units under the LTIP to participants containing such terms as it determines. The Plan Committee will determine the period over which restricted stock units granted to participants will vest. Like restricted stock, restricted stock units may vest over time, pursuant to performance criteria, or based on a combination of service and performance.

Dividend Equivalents. The Plan Committee, in its discretion, may grant dividend equivalent rights (either tandem to other awards or on a stand-alone basis) that entitle the holder to receive cash, stock, or other awards equal to any dividends made on a specified number of shares of common stock.

Performance and Annual Incentive Awards. For awards granted under the LTIP that are based upon performance criteria specified by the Plan Committee, the Plan Committee will establish the maximum number of shares of common stock subject to, or the maximum value of, each performance award and the performance period over which the performance applicable to the award will be measured. As determined by the Plan Committee, the performance goals applicable to an award may provide for a targeted level or levels of achievement, measured on a GAAP or non-GAAP basis, relating to earnings per share, increase in revenues, increase in cash flow, increase in cash flow from operations, increase in cash flow return, return on net assets, return on assets, return on investment, return on capital, return on equity, economic value added, operating margin, contribution margin, net income, net income per share, pretax earnings, pretax earnings before interest,

126

depreciation and amortization, pretax operating earnings after interest expense and before incentives, service fees, and extraordinary or special items, total stockholder return, debt reduction, market share, change in the fair market value of our stock, operating income, amount of oil and natural gas reserves, oil and natural gas reserve additions, cost of finding oil and natural gas reserves, oil and natural gas reserve replacement ratios, oil and natural gas production amounts, oil and natural gas production sales amounts, safety targets, regulatory compliance, and any of the above goals determined on an absolute or relative basis or as compared to the performance of a published or special index deemed applicable by the Plan Committee, including, but not limited to, the Standard & Poor’s 500 Stock Index or a group of comparable companies. Performance goals may differ from participant to participant and from award to award. Any of these metrics may be subject to adjustment as provided in the LTIP. Payment of a performance award may be made in cash, shares of our common stock, or a combination thereof, as determined by the Plan Committee. The Plan Committee may establish a performance pool, which will be an unfunded pool, for purposes of measuring the achievement of a performance goal or goals based on one or more criteria set forth above during the given performance period. The Plan Committee may specify the amount of a performance pool as a percentage of any of such criteria, a percentage in the excess of a threshold amount, or as another amount which need not be linearly related to such criteria.

Bonus Stock Awards. Bonus stock awards are unrestricted shares of our common stock that are subject to such terms and conditions as the Plan Committee may determine. They need not be subject to performance criteria or objectives or to forfeiture.

Other Stock-Based Awards. The Plan Committee, in its discretion, may also grant to participants an award denominated or payable in, referenced to, or otherwise based on or related to the value of our common stock.

Recoupment Policy. We expect that all payments will be subject to our Recoupment Policy, as may be amended by our board of directors from time to time.

Change in Control

The LTIP will provide that, upon a “change in control” (as defined in the LTIP), the Plan Committee, in its sole discretion, may accelerate the vesting and exercise date of options and stock appreciation rights, cancel options and stock appreciation rights, and cause us to make payments in respect thereof in cash or adjust the outstanding options and stock appreciation rights as appropriate to reflect the change in control. In addition, under the LTIP, upon the occurrence of a change in control, the Plan Committee will be permitted to fully vest any awards then outstanding (including restricted stock, restricted stock units, and performance awards) or make such other adjustments to awards as it deems appropriate.

Amendment and Termination of the LTIP

Our board of directors will be permitted to terminate the LTIP at any time with respect to any shares of our common stock for which awards have not been granted. Our board will also be permitted to alter or amend the LTIP or any part thereof or award thereunder from time to time; provided that no change to the LTIP or such award may be made that would materially impair the rights of a participant without consent of the participant. To the extent any amendment to the LTIP requires stockholder approval pursuant to any applicable federal or state law or regulation or the rule of any stock exchange or automated quotation system on which our common stock may then be listed or quoted, including any increase in any share limitation, such amendment will be subject to the approval of our stockholders.

127

Outstanding Equity Awards at 2013 Fiscal Year End

Grant
Date

Stock Awards

Name⁽¹⁾

Number of Shares
or Units of Stock
That Have Not
Vested as of 12/31/13
(#)

Value of Shares or
Units of Stock That
Have Not
Vested as of 12/31/13
($)

Benjamin W. Hulburt⁽²⁾

Eclipse I Class C Units (Series C-1)

1/31/11

76.11

—

Matthew R. DeNezza⁽⁴⁾

Eclipse I Class C Units (Series C-1)

4/1/2013

12,580

Eclipse I Class C Units (Series C-2)

4/1/2013

105

—

Thomas S. Liberatore⁽⁴⁾

Eclipse I Class C Units (Series C-1)

6/30/11

76.11

—

Christopher K. Hulburt⁽²⁾

Eclipse I Class C Units (Series C-1)

1/31/11

76.11

—

(1)

The Eclipse I Class C Units (Series C-1) are non-voting limited partnership interests that are entitled to participate in distributions by Eclipse I only after applicable payout thresholds for the Class A-1 and Class B units have been met. The Eclipse I Class C Units (Series C-2) are non-voting limited partnership interests that are entitled to participate in distributions by Eclipse I only after applicable payout thresholds for the Class A-1, Class B and higher ranking Class C units have been met.

(2)

The Eclipse I Class C Units (Series C-1) reported in this table for Messrs. Benjamin W. Hulburt and Christopher K. Hulbert fully vested on February 1, 2014.

(3)

The Eclipse I Class C Units (Series C-1) and Eclipse I Class C Units (Series C-2) reported in this table for Mr. DeNezza will vest in three equal annual installments beginning April 1, 2014, though vesting will accelerate upon the earlier of a sale or transfer of substantially all of the interests in or assets of Eclipse I, including by way of merger; provided that the vesting of such units will not be accelerated as a result of our corporate reorganization or the offering or sale of our common stock in this offering. Mr. DeNezza will forfeit any unvested units upon the termination of his employment with us for any reason, though vested units will remain outstanding.

(4)

The Eclipse I Class C Units (Series C-1) reported in this table for Mr. Liberatore will vest in full on June 1, 2014, though vesting will accelerate upon the earlier of a sale or transfer of substantially all of the interests in or assets of Eclipse I, including by way of merger; provided that the vesting of such units will not be accelerated as a result of our corporate reorganization or the offering or sale of our common stock in this offering. Mr. Liberatore will forfeit any unvested units upon the termination of his employment with us for any reason, though vested units will remain outstanding.

Neither our corporate reorganization nor this offering will result in a “change in control” under the limited partnership agreement for Eclipse I that would result in a distribution of cash or shares.

Additional Narrative Disclosure Regarding Retirement Benefits and Other Potential Payments Upon Termination or a Change in Control

Retirement Benefits

We currently maintain a retirement plan intended to provide benefits under section 401(k) of the Code, under which employees, including our Named Executive Officers, are allowed to contribute portions of their compensation to a tax-qualified retirement account. Under our 401(k) plan, we provide matching contributions equal to 100% of the first 6% of employees’ eligible compensation contributed to the plan.

As described in more detail under “—Narrative Description to the Summary Compensation Table for the 2013 Fiscal Year—Long-Term Incentive Compensation” above, the Incentive Units held by our Named

128

Executive Officers are either forfeited or remain outstanding following the officer’s termination of employment, with no acceleration of vesting or payment being made under the awards upon such termination of employment.

Employment, Severance or Change in Control Agreements

We historically have not maintained any employment, severance or change in control agreements with any of our Named Executive Officers. In addition, none of the Named Executive Officers are entitled to any payments or other benefits in connection with a termination of their employment or a change in control, except that in certain instances, a change in control (a “Fundamental Change,” as such term is defined in the Eclipse I LP Agreement and summarized under “—Narrative Description to the Summary Compensation Table for the 2013 Fiscal Year Long Term Incentive Compensation—Long-Term Incentive Compensation—Incentive Units” above) may result in a distribution of cash or shares of our common stock being made to holders of vested Incentive Units, in accordance with the distribution priority specified in the Eclipse I LP Agreement (unvested Incentive Units do not become vested upon a change in control). We expect that we will enter into employment agreements with each of our Named Executive Officers after the closing of this offering.

Compensation of Directors

We did not award any compensation to our non-employee directors during 2013. Going forward, our board of directors believes that attracting and retaining qualified non-employee directors will be critical to the future value growth and governance of our company. Our board of directors also believes that the compensation package for our non-employee directors should require a portion of the total compensation package to be equity-based to align the interest of these directors with our stockholders.

We are reviewing the non-employee compensation package paid by our peer group and are considering a non-employee director compensation program. We expect that directors who are also our employees will not receive any additional compensation for their service on our board of directors.

129

PRINCIPAL AND SELLING STOCKHOLDERS

Beneficial Ownership

The following table sets forth information with respect to the beneficial ownership of our common stock as of June 19, 2014 after giving effect to our corporation reorganization by:

•

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

•

each of our named executive officers;

•

each of our directors and any director nominees;

•

all of our directors and executive officers as a group; and

•

each of the selling stockholders.

Except as otherwise noted, the person or entities listed below have sole voting and investment power with respect to all shares of our common stock beneficially owned by them, except to the extent this power may be shared with a spouse. All information with respect to beneficial ownership has been furnished by the respective directors, officers and 5% or more stockholders, as the case may be. Unless otherwise noted, the mailing address of each person or entity named in the table is c/o Eclipse Resources Corporation, 2121 Old Gatesburg Road, Suite 110, State College, Pennsylvania 16803. Please see “Certain Relationships and Related Party Transactions” for a discussion of positions, offices and other material relationships which the selling stockholder has had with us, our predecessors and affiliates during the past three years.

We have determined beneficial ownership in accordance with the rules of the SEC. Prior to the completion of our corporate reorganization (which will occur immediately prior to or contemporaneously with the completion of this offering), the ownership interests of our existing owners were represented by partnership interests in Eclipse I.

The selling stockholders have granted the underwriters the option to purchase up to 4,545,000 additional shares of common stock and will sell such shares only to the extent such option is exercised.


	Shares Beneficially Owned Prior to the Offering					Shares Being Offered			Shares Beneficially Owned After the Offering
Name and Address of Beneficial Owner	Number		Percentage			Shares Being Offered			Number			Percentage
Selling Stockholders and 5% Stockholders⁽¹⁾:
Eclipse Resources Holdings, L.P.		129,700,000		94	%		—			129,700,000	⁽²⁾		81	%⁽²⁾
EnCap Funds⁽³⁾		8,704,732		6	%		8,704,732	⁽⁴⁾		—			—
The Hulburt Family II Limited Partnership		63,512		*			63,512	⁽⁴⁾		—			—
CKH Partners II, L.P.		15,878		*			15,878	⁽⁴⁾		—			—
Kirkwood Capital, L.P.		15,878		*			15,878	⁽⁴⁾		—			—
Directors, Director Nominees and Named Executive Officers:
Benjamin W. Hulburt⁽¹⁾		63,512		*			63,512			—			—
D. Martin Phillips⁽¹⁾		8,704,732		6	%		8,704,732			—			—
Robert L. Zorich⁽¹⁾		8,704,732		6	%		8,704,732			—			—
Douglas E. Swanson, Jr.⁽¹⁾		—		—			—			—			—
Mark E. Burroughs, Jr.⁽¹⁾		—		—			—			—			—
Christopher K. Hulburt⁽¹⁾		15,878		*			15,878			—			—
Randall M. Albert		—		—			—			—			—
Richard D. Paterson		—		—			—			—			—
Joseph C. Winkler, III		—		—			—			—			—
Matthew R. DeNezza		—		—			—			—			—
Thomas S. Liberatore⁽¹⁾		15,878		*			15,878			—			—
All Directors and Executive Officers as a Group (8 Persons)⁽¹⁾		8,800,000		6	%		8,800,000			—			—

130

Less than one percent.

(1)

Eclipse Holdings is governed by a board of managers that includes three members (currently Benjamin W. Hulburt, Christopher K. Hulburt and Thomas S. Liberatore) appointed by the Management Funds and four members (currently Mark E. Burroughs, Jr., Douglas E. Swanson, Jr., Robert L. Zorich and D. Martin Phillips) appointed by the EnCap Funds. The board of managers has authority to vote or dispose of the common stock held by Eclipse Holdings, subject to the terms of the stockholders agreement described below.

Following our corporate reorganization, funds affiliated with EnCap, specifically EnCap Energy Capital Fund VIII, L.P., EnCap Energy Capital Fund VIII Co-Investors, L.P. and EnCap Energy Capital Fund IX, L.P., will collectively own 100% of the Class A limited partner interests in Eclipse Holdings. The EnCap Funds are controlled indirectly by David B. Miller, D. Martin Phillips, Gary R. Petersen, and Robert L. Zorich, who are the controlling members of RNBD GP LLC. RNBD GP LLC is the sole member of EnCap Investments GP, L.L.C., which is the general partner of EnCap Investments L.P., which is the general partner of (i) EnCap Equity Fund VIII GP, L.P., which is the general partner of EnCap Energy Capital Fund VIII, L.P. and EnCap Energy Capital Fund VIII Co-Investors, L.P., and (ii) EnCap Equity Fund IX GP, L.P, which is the general partner of EnCap Energy Capital Fund IX, L.P. As a result of such control, the shares of our stock that are beneficially owned by the EnCap Funds are also reported as beneficially owned by Messrs. Phillips and Zorich. The address for the EnCap Funds is 1100 Louisiana Street, Suite 4900, Houston, Texas 77002.

Following our corporate reorganization, The Hulburt Family II Limited Partnership, controlled by Benjamin W. Hulburt, will own approximately 66% of the Class B limited partner interests in Eclipse Holdings, CKH Partners II, L.P., controlled by Christopher K. Hulburt, will own approximately 17% of the Class B limited partner interests in Eclipse Holdings, and Kirkwood Capital, L.P., controlled by Thomas S. Liberatore, will own approximately 17% of the Class B limited partner interests in Eclipse Holdings. Benjamin W. Hulburt, Christopher K. Hulburt and Thomas S. Liberatore are the beneficial owners of the shares of our common stock held by The Hulburt Family II Limited Partnership, CKH Partners II, L.P. and Kirkwood Capital, L.P., respectively, due to the control of such individuals over the respective partnerships.

Following our corporate reorganization, Management Holdco will own 100% of the Class C limited partner interests in Eclipse Holdings. Benjamin W. Hulburt, Christopher K. Hulburt, Matthew R. DeNezza and Thomas S. Liberatore have equal ownership interests in, and serve as the members of the board of managers of, Eclipse Management GP, LLC, the general partner of Management Holdco, and therefore indirectly control Management Holdco.

We, Eclipse Holdings, and the foregoing limited partners of Eclipse Holdings will enter into a stockholders agreement following our corporate reorganization as further described under “Corporate Reorganization—Stockholders Agreement.” In connection with the closing of this offering, we will enter into a registration rights agreement, or the Registration Rights Agreement, with Eclipse Holdings and its limited partners, the EnCap Funds, the Management Funds and Management Holdco. Pursuant to the Registration Rights Agreement, we have agreed to register the sale of shares of our common stock under certain circumstances. See “Certain Relationships and Related Party Transactions—Registration Rights Agreement.”

(2)

Assumes no exercise of the underwriters’ option to purchase additional shares of our common stock from the selling stockholders. If the underwriters’ option to purchase additional shares of common stock from the selling stockholders is exercised in full, Eclipse Holdings will distribute such shares to its limited partners that are the selling stockholders, and immediately after such distribution and the completion of the offering: Eclipse Holdings will own 125,155,000 shares of our common stock (representing approximately 78% of the outstanding shares of our common stock as of the date set forth above).

(3)

Represents 3,766,343 shares of our common stock (representing approximately 2.7% of the outstanding shares of our common stock as of the date set forth above) held by EnCap Energy Capital Fund VIII, L.P., 2,092,413 shares of our common stock (representing approximately 1.5% of the outstanding shares of

131

our common stock as of the date set forth above) held by EnCap Energy Capital Fund VIII Co-Investors, L.P., and 2,845,976 shares of our common stock (representing approximately 2.1% of the outstanding shares of our common stock as of the date set forth above) held by EnCap Energy Capital Fund IX, L.P. See footnote 1 regarding the control of the EnCap Funds and their ownership interests in Eclipse Holdings.

(4)

Assumes no exercise of the underwriters’ option to purchase additional shares of our common stock from the selling stockholders. If the underwriters’ option to purchase additional shares of common stock from the selling stockholders is exercised in full, Eclipse Holdings will distribute such shares to its limited partners that are the selling stockholders, and (i) the EnCap Funds will collectively offer 13,200,527 shares of our common stock in the offering, (ii) The Hulburt Family II Limited Partnership will offer 96,315 shares of our common stock in the offering, (iii) CKH Partners II, L.P. will offer 24,079 shares of our common stock in the offering, and (iv) Kirkwood Capital, L.P. will offer 24,079 shares of our common stock in the offering.

132

CORPORATE REORGANIZATION

Eclipse Resources Corporation is a Delaware corporation formed by Eclipse I on February 13, 2014. Contemporaneously with, and conditional upon, the completion of this offering, a corporate reorganization will be completed as described below. Investors in this offering will only receive, and this prospectus only describes the offering of, shares of common stock of Eclipse Resources Corporation. See “Description of Capital Stock” for additional information regarding the terms of our amended and restated certificate of incorporation and amended and restated bylaws as will be in effect upon the closing of this offering and “Defined Terms” on page ii of this prospectus for definitions of terms used in this prospectus.

The corporate reorganization will consist of the following steps:

•

the acquisition by Eclipse I of all of the outstanding equity interests in Eclipse Operating, an entity formed in December 2010 by members of our management team for purposes of operating Eclipse I;

•

the contribution of equity interests in Eclipse I to Eclipse Holdings by the EnCap Funds, the Management Funds and Management Holdco in exchange for similar equity interests in Eclipse Holdings;

•

the transfer of the outstanding equity interests in Eclipse GP, LLC, the general partner of Eclipse I, to Eclipse Holdings; and

•

the contribution of equity interests in Eclipse I and the outstanding equity interests in Eclipse GP, LLC, to Eclipse Resources Corporation by Eclipse Holdings in exchange for shares of common stock of Eclipse Resources Corporation.

As a result of these steps, Eclipse Resources Corporation will become a majority controlled direct subsidiary of Eclipse Holdings, and Eclipse I will become a direct subsidiary of Eclipse Resources Corporation.

We refer to the transactions above collectively as our “corporate reorganization.”

133

Ownership Structure Prior to Our Corporate Reorganization

LOGO

(1)

(2)

134

Ownership Structure After Giving Effect to Our Corporate Reorganization and this Offering

LOGO

(1)

(2)

135

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Corporate Reorganization

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

Historical Transactions with Affiliates

Since its inception in January 2011, Eclipse I has issued additional limited partnership interests as consideration for capital contributions received from its limited partners, including the EnCap Funds. Capital contributions made by the investment funds managed by EnCap for the years ended December 31, 2013, 2012 and 2011 were approximately $580.7 million, $67.7 million and $68.6 million, respectively. In addition, Eclipse I paid the legal fees of EnCap in connection with these transactions.

Eclipse I previously issued profits interests in Eclipse I to certain officers and employees of Eclipse Operating. In connection with our corporate reorganization, all of such profits interests will be exchanged for similar profits interests in Management Holdco, which will become a limited partner of Eclipse Holdings.

In December 2010, Eclipse Operating was formed by members of our management team for purposes of operating Eclipse I. Our Chairman, President and Chief Executive Officer, Executive Vice President, Secretary and General Counsel and Executive Vice President and Chief Operating Officer each own 33% of the membership units of Eclipse Operating. Eclipse Operating provides administrative and management services to Eclipse I under the terms of an Administrative Services Agreement. In connection with our corporate reorganization, Eclipse I will acquire of all the outstanding equity interests of Eclipse Operating for $127,500, which is the amount of the aggregate capital contributions made to Eclipse Operating by its members. As a result, Eclipse Operating will become a wholly owned subsidiary of Eclipse I.

Under the terms of the Administrative Services Agreement, Eclipse I pays Eclipse Operating a monthly management fee equal to the sum of all general and administrative expenditures incurred by Eclipse Operating in the management and administration of Eclipse I’s operations. These costs include salaries, wages and benefits, rent, insurance, and other expenses and costs required to operate Eclipse I. These expenses are billed to Eclipse I in arrears at the actual cost to Eclipse Operating. During the years ended December 31, 2013 and 2012, management fee expense totaled approximately $14.7 million and $4.2 million, respectively.

On December 16, 2013, we entered into a Gas Gathering, Processing and Fractionation Agreement with Blue Racer and its subsidiary, Blue Racer Natrium, LLC, under which we have obtained firm gathering, processing and fractionation capacity for a significant portion of our operated acreage in the Rich Gas, Condensate and Rich Condensate Windows of the Utica Core Area. See “Business—Midstream Agreements.” Blue Racer is a joint venture between Dominion Resources, Inc. and Caiman Energy II, LLC. Affiliates of EnCap owned, directly or indirectly, approximately 38% of Caiman Energy II, LLC as of December 31, 2013.

Stockholders Agreement

In connection with the completion of this offering, we will enter into a stockholders agreement, or the Stockholders Agreement, with Eclipse Holdings and its limited partners, the EnCap Funds, the Management Funds and Management Holdco, which we refer to as our principal stockholders.

The Stockholders Agreement will provide that we, Eclipse Holdings and its limited partners will agree to take certain actions, such as soliciting proxies or voting shares of our common stock, to cause our board of directors to consist of the following members: (i) Benjamin W. Hulburt, for so long as he remains our President and Chief Executive Officer; (ii) Christopher K. Hulburt, for so long as he remains our Executive Vice President, Secretary and General Counsel; and (iii) a number of members designated by the EnCap Funds, initially up to five, which number will be adjusted in the future based on the level of beneficial ownership of our shares of

136

common stock by the EnCap Funds and their affiliates. For so long as the EnCap Funds and its affiliates beneficially own at least 50% of our outstanding common stock, we, Eclipse Holdings and its limited partners will take certain actions to cause at least one of the directors designated by the EnCap Funds to be a member of each committee of our board of directors (subject to applicable legal requirements and stock exchange rules). In addition, we, Eclipse Holdings and its limited partners will take certain actions to cause Benjamin W. Hulburt to be elected as Chairman of our board of directors.

Other than with respect to the election of our board of directors, each limited partner of Eclipse Holdings will be entitled to instruct Eclipse Holdings regarding how to vote the number of shares of our common stock held by Eclipse Holdings on the applicable voting record date that such limited partner would receive following a complete distribution on the applicable voting record date of the shares of our common stock held by Eclipse Holdings.

Registration Rights Agreement

In connection with the closing of this offering, we will enter into a registration rights agreement, or the Registration Rights Agreement, with Eclipse Holdings and its limited partners, the EnCap Funds, the Management Funds and Management Holdco. Pursuant to the Registration Rights Agreement, we will agree to register the resale of shares of our common stock issued in our corporate reorganization under certain circumstances.

Demand Registration Rights. At any time after the closing of this offering, subject to the limitations set forth below, Eclipse Holdings and its limited partners will have the right, to the extent they hold specified shares of our common stock, to require us by written notice to prepare and file a registration statement registering the offer and sale of a number of their shares of common stock. Generally, we are required to provide notice of the request within 5 days following the receipt of such demand request to all additional holders of our common stock that are parties to the Registration Rights Agreement, who may, in certain circumstances, participate in the registration. In no event shall a demand registration occur within 90 days of a firm commitment underwritten offering. We are also not obligated to effect any demand registration in which the anticipated aggregate value of the shares of common stock (based on a 20-day VWAP) included in such demand is less than $30 million. Once we are eligible to effect a registration on Form S-3, any such demand registration may be for a shelf registration statement. Any holder that is able to request a demand registration will also have the option to require us to effectuate a distribution of their shares of our common stock through a firm commitment underwritten offering (so long as the aggregate value of the shares to be included in the offering is at least $30 million (based on a 20-day VWAP)). We will be required to maintain the effectiveness of any such registration statement until the earlier of (i) 180 days (or two years if a “shelf registration” is requested) after the effective date or (ii) the date of the consummation of the distribution by the participating holders or on which the shares covered by the registration statement cease to be registrable securities pursuant to the Registration Rights Agreement.

Piggy-Back Rights. If, at any time, we propose to register an offering of common stock (subject to certain exceptions) whether or not for our own account, then we must give at least 5 days’ notice to all holders of registrable securities to allow them to include a specified number of their shares in that offering.

Conditions and Limitations; Expenses. These registration rights are subject to certain conditions and limitations, including the right of the underwriters to limit the number of shares to be included in a firm commitment underwritten offering and our right to terminate or suspend an offering under certain circumstances. We will generally pay all registration expenses in connection with our obligations under the Registration Rights Agreement, regardless of whether a registration statement is filed or becomes effective or whether any shares of our common stock are sold.

We will not be required to pay any discounts, commissions or fees of underwriters, selling brokers, dealer managers or similar industry professionals and stock transfer taxes applicable to the resale of shares of our common stock or fees of legal counsel to any holder or selling stockholder.

137

Procedures for Approval of Related Party Transactions

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

•

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

•

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

•

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

•

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

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

138

DESCRIPTION OF CAPITAL STOCK

Upon completion of this offering, the authorized capital stock of Eclipse Resources Corporation will consist of 1,000,000,000 shares of common stock, $0.01 par value per share, of which 160,000,000 shares will be issued and outstanding, and 50,000,000 shares of preferred stock, $0.01 par value per share, of which no shares will be issued and outstanding.

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

Common Stock

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

Preferred Stock

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

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

Some provisions of Delaware law, our amended and restated certificate of incorporation and our amended and restated bylaws will contain provisions that could make the following transactions more difficult: acquisitions of us by means of a tender offer, a proxy contest or otherwise, or the removal of our incumbent

139

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

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

Delaware Law

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

•

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

•

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

•

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

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

Amended and Restated Certificate of Incorporation and Amended and Restated Bylaws

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

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

•

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

•

provide our board of directors the ability to authorize undesignated preferred stock. This ability makes it possible for our board of directors to issue, without stockholder approval, preferred stock with voting or other rights or preferences that could impede the success of any attempt to change control of us. These and other provisions may have the effect of deferring hostile takeovers or delaying changes in control or management of our company;

140

•

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

•

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

•

at any time after Eclipse Holdings and EnCap and their respective affiliates no longer collectively beneficially own more than 50% of the outstanding shares of our common stock,

•

provide that any action required or permitted to be taken by the stockholders must be effected at a duly called annual or special meeting of stockholders and may not be effected by any consent in writing in lieu of a meeting of such stockholders, subject to the rights of the holders of any series of preferred stock with respect to such series (prior to such time, such actions may be taken without a meeting by written consent of holders of common stock having not less than the minimum number of votes that would be necessary to authorize such action at a meeting);

•

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

•

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

•

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

•

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

•

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

Forum Selection

Our amended and restated certificate of incorporation will provide that unless we consent in writing to the selection of an alternative forum, 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:

•

any derivative action or proceeding brought on our behalf;

•

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;

141

•

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

•

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 of the State of Delaware having personal jurisdiction over the indispensable parties named as defendants therein.

Our amended and restated certificate of incorporation will also provide that any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock will be deemed to have notice of and to have consented to this forum selection provision. However, it is possible that a court could find our forum selection provision to be inapplicable or unenforceable.

Limitation of Liability and Indemnification Matters

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

•

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

•

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

•

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

•

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

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

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

Transfer Agent and Registrar

The transfer agent and registrar for our common stock will be Computershare Trust Company, N.A.

Listing

We have been approved to list our common stock on the NYSE under the symbol “ECR.”

142

SHARES ELIGIBLE FOR FUTURE SALE

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

Sales of Restricted Shares

Upon completion of this offering, we will have outstanding an aggregate of 160,000,000 shares of common stock. Of these shares, all of the 30,300,000 shares of common stock to be sold in this offering (or 34,845,000 shares if the underwriters exercise their option to purchase additional shares from the selling stockholders in full) will be freely tradable without restriction or further registration under the Securities Act, unless the shares are held by any of our “affiliates” as such term is defined in Rule 144 under the Securities Act. All remaining shares of common stock will be deemed “restricted securities” as such term is defined under Rule 144. The restricted securities were, or will be, issued and sold by us in private transactions and are eligible for public sale only if registered under the Securities Act or if they qualify for an exemption from registration under Rule 144 or Rule 701 under the Securities Act, which rules are summarized below.

Lock-up Agreements

We, Eclipse Holdings, the limited partners of Eclipse Holdings, the EnCap Funds, the Management Funds and Management Holdco, all of our directors and executive officers, and certain of our employees have agreed not to sell any common stock or securities convertible into or exchangeable for shares of common stock for a period of 180 days from the date of this prospectus, subject to certain exceptions. See “Underwriting” for a description of these lock-up provisions.

Rule 144

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

A person (or persons whose shares are aggregated) who is deemed to be an affiliate of ours and who has beneficially owned restricted securities within the meaning of Rule 144 for at least six months would be entitled to sell within any three-month period a number of shares that does not exceed the greater of one percent of the then outstanding shares of our common stock or the average weekly trading volume of our common stock reported through the NYSE during the four calendar weeks preceding the filing of notice of the sale. Such sales are also subject to certain manner of sale provisions, notice requirements and the availability of current public information about us.

143

Rule 701

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

Stock Issued Under Employee Plans

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

Registration Rights

In connection with the closing of this offering, we will enter into a registration rights agreement with Eclipse Holdings and its limited partners, the EnCap Funds, the Management Funds and Management Holdco, which will require us to file and effect the registration of the resale of our common stock held by them (and by certain of their affiliates) in certain circumstances no earlier than the expiration of the lock-up period contained in the underwriting agreement entered into in connection with this offering. Please see “Certain Relationships and Related Party Transactions—Registration Rights Agreement.”

144

MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES TO NON-U.S. HOLDERS

The following discussion is a summary of the material U.S. federal income tax consequences to non-U.S. holders (as defined below) of the purchase, ownership and disposition of our common stock issued pursuant to this offering, but does not purport to be a complete analysis of all potential tax effects. The effects of other U.S. federal tax laws, such as estate and gift tax laws, and any applicable state, local or foreign tax laws are not discussed. This discussion is based on the Code, Treasury Regulations promulgated thereunder, judicial decisions and published rulings and administrative pronouncements of the Internal Revenue Service (the “IRS”) in effect as of the date of this offering. These authorities may change or be subject to differing interpretations. Any such change may be applied retroactively in a manner that could adversely affect a non-U.S. holder of our common stock. We have not sought and will not seek any rulings from the IRS regarding the matters discussed below. There can be no assurance the IRS or a court will not take a contrary position regarding the tax consequences of the purchase, ownership and disposition of our common stock.

This discussion is limited to non-U.S. holders that hold our common stock as a “capital asset” within the meaning of Section 1221 of the Code (property held for investment). This discussion does not address all U.S. federal income tax consequences relevant to a non-U.S. holder’s particular circumstances, including the impact of the unearned income Medicare contribution tax. In addition, it does not address consequences relevant to non-U.S. holders subject to particular rules, including, without limitation:

•

U.S. expatriates and certain former citizens or long-term residents of the United States;

•

persons subject to the alternative minimum tax;

•

persons holding our common stock as part of a hedge, straddle or other risk reduction strategy or as part of a conversion transaction or other integrated investment;

•

banks, insurance companies and other financial institutions;

•

real estate investment trusts or regulated investment companies;

•

brokers, dealers or traders in securities;

•

“controlled foreign corporations,” “passive foreign investment companies” and corporations that accumulate earnings to avoid U.S. federal income tax;

•

S corporations, partnerships or other entities or arrangements treated as partnerships for U.S. federal income tax purposes;

•

tax-exempt organizations or governmental organizations;

•

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

•

persons who hold or receive our common stock pursuant to the exercise of any employee stock option or otherwise as compensation; and

•

tax-qualified retirement plans.

If a partnership (or other entity treated as a partnership for U.S. federal income tax purposes) holds our common stock, the tax treatment of a partner in the partnership will depend on the status of the partner, the activities of the partnership and certain determinations made at the partner level. Accordingly, partnerships holding our common stock and the partners in such partnerships should consult their tax advisors regarding the U.S. federal income tax consequences to them.

THIS DISCUSSION IS FOR INFORMATION PURPOSES ONLY AND IS NOT INTENDED AS TAX ADVICE. INVESTORS SHOULD CONSULT THEIR TAX ADVISORS WITH RESPECT TO THE APPLICATION OF THE U.S. FEDERAL INCOME TAX LAWS TO THEIR PARTICULAR

145

SITUATIONS AS WELL AS ANY TAX CONSEQUENCES OF THE PURCHASE, OWNERSHIP AND DISPOSITION OF OUR COMMON STOCK ARISING UNDER THE U.S. FEDERAL ESTATE OR GIFT TAX LAWS OR UNDER THE LAWS OF ANY STATE, LOCAL OR NON-U.S. TAXING JURISDICTION OR UNDER ANY APPLICABLE INCOME TAX TREATY.

Definition of a Non-U.S. Holder

For purposes of this discussion, a “non-U.S. holder” is any beneficial owner of our common stock that is neither a “U.S. person” nor a partnership for United States federal income tax purposes. A U.S. person is any of the following:

•

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

•

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

•

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

•

a trust that (1) is subject to the primary supervision of a U.S. court and the control of one or more United States persons (within the meaning of Section 7701(a)(30) of the Code) or (2) has made a valid election under applicable Treasury Regulations to continue to be treated as a United States person.

Distributions

We do not anticipate declaring or paying dividends to holders of our common stock in the foreseeable future. However, if we make distributions on our common stock, such distributions of cash or property on our common stock will constitute dividends for U.S. federal income tax purposes to the extent paid from our current or accumulated earnings and profits, as determined under U.S. federal income tax principles. Amounts not treated as dividends for U.S. federal income tax purposes will constitute a return of capital and first be applied against and reduce a non-U.S. holder’s adjusted tax basis in its common stock, but not below zero. Any excess will be treated as capital gain and will be treated as described below in the section relating to the sale or disposition of our common stock.

Subject to the discussion below on backup withholding and foreign accounts, dividends paid to a non-U.S. holder of our common stock that are not effectively connected with the non-U.S. holder’s conduct of a trade or business within the United States will be subject to U.S. federal withholding tax at a rate of 30% of the gross amount of the dividends (or such lower rate specified by an applicable income tax treaty).

Non-U.S. holders may be entitled to a reduction in or an exemption from withholding on dividends as a result of either (a) an applicable income tax treaty or (b) the non-U.S. holder holding our common stock in connection with the conduct of a trade or business within the United States and dividends being paid in connection with that trade or business. To claim such a reduction in or exemption from withholding, the non-U.S. holder must provide the applicable withholding agent with a properly executed (a) IRS Form W-8BEN claiming an exemption from or reduction of the withholding tax under the benefit of an income tax treaty between the United States and the country in which the non-U.S. holder resides or is established, or (b) IRS Form W-8ECI stating that the dividends are not subject to withholding tax because they are effectively connected with the conduct by the non-U.S. holder of a trade or business within the United States, as may be applicable. These certifications must be provided to the applicable withholding agent prior to the payment of dividends and must be updated periodically. Non-U.S. holders that do not timely provide the applicable withholding agent with the required certification, but that qualify for a reduced rate under an applicable income tax treaty, may obtain a refund of any excess amounts withheld under these rules by timely filing an appropriate claim for refund with the IRS.

146

Subject to the discussion below on backup withholding and foreign accounts, if dividends paid to a non-U.S. holder are effectively connected with the non-U.S. holder’s conduct of a trade or business within the United States (and, if required by an applicable income tax treaty, the non-U.S. holder maintains a permanent establishment in the United States to which such dividends are attributable), then, although exempt from U.S. federal withholding tax (provided the non-U.S. holder provides appropriate certification, as described above), the non-U.S. holder will be subject to U.S. federal income tax on such dividends on a net income basis at the regular graduated U.S. federal income tax rates. In addition, a non-U.S. holder that is a corporation may be subject to a branch profits tax at a rate of 30% (or such lower rate specified by an applicable income tax treaty) on its effectively connected earnings and profits for the taxable year that are attributable to such dividends (and, if required by an applicable income tax treaty, that are attributable to a permanent establishment maintained by the corporate non-U.S. holder in the United States), as adjusted for certain items. Non-U.S. holders should consult their tax advisors regarding their entitlement to benefits under any applicable income tax treaty.

Sale or Other Taxable Disposition

Subject to the discussions below on backup withholding and foreign accounts, a non-U.S. holder will not be subject to U.S. federal income tax on any gain realized upon the sale or other disposition of our common stock unless:

•

the gain is effectively connected with the non-U.S. holder’s conduct of a trade or business within the United States (and, if required by an applicable income tax treaty, the non-U.S. holder maintains a permanent establishment in the United States to which such gain is attributable);

•

the non-U.S. holder is a nonresident alien individual present in the United States for 183 days or more during the taxable year of the disposition and certain other requirements are met; or

•

our common stock constitutes a U.S. real property interest by reason of our status as a U.S. real property holding corporation, or a USRPHC, for U.S. federal income tax purposes.

Gain described in the first bullet point above will generally be subject to U.S. federal income tax on a net income basis at the regular graduated U.S. federal income tax rates. A non-U.S. holder that is a foreign corporation also may be subject to a branch profits tax at a rate of 30% (or such lower rate specified by an applicable income tax treaty) of a portion of its effectively connected earnings and profits for the taxable year, as adjusted for certain items.

A non-U.S. holder described in the second bullet point above will be subject to U.S. federal income tax at a rate of 30% (or such lower rate specified by an applicable income tax treaty) on any gain derived from the disposition, which may be offset by certain U.S. source capital losses of the non-U.S. holder (even though the individual is not considered a resident of the United States) provided the non-U.S. holder has timely filed U.S. federal income tax returns with respect to such losses.

With respect to the third bullet point above, we believe that we currently are, and expect to remain for the foreseeable future, a USRPHC for U.S. federal income tax purposes. However, so long as our common stock is “regularly traded on an established securities market,” a non-U.S. holder will be subject to U.S. federal net income tax on a disposition of our common stock only if the non-U.S. holder actually or constructively holds or held (at any time during the shorter of the 5-year period preceding the date of disposition or the holder’s holding period) more than 5% of our common stock. If our common stock is not considered to be so traded, all non-U.S. holders would be subject to U.S. federal net income tax on disposition of our common stock and a 10% withholding tax would apply to the gross proceeds from the sale of our common stock by a non-U.S. holder.

Non-U.S. holders should consult their tax advisors regarding potentially applicable income tax treaties that may provide for different rules.

147

Information Reporting and Backup Withholding

A non-U.S. holder will not be subject to backup withholding with respect to payments of dividends on our common stock we make to the non-U.S. holder, provided the applicable withholding agent does not have actual knowledge or reason to know such holder is a United States person and the holder certifies its non-U.S. status, such as by providing a valid IRS Form W-8BEN or W-8ECI, or other applicable certification. However, information returns will be filed with the IRS in connection with any dividends on our common stock paid to the non-U.S. holder, regardless of whether any tax was actually withheld. Copies of these information returns may also be made available under the provisions of a specific treaty or agreement to the tax authorities of the country in which the non-U.S. holder resides or is established.

Information reporting and backup withholding may apply to the proceeds of a sale of our common stock within the United States, and information reporting may (although backup withholding generally will not) apply to the proceeds of a sale of our common stock outside the United States conducted through certain U.S.-related financial intermediaries, in each case, unless the beneficial owner certifies under penalty of perjury that it is a non-U.S. holder on IRS Form W-8BEN or other applicable form (and the payor does not have actual knowledge or reason to know that the beneficial owner is a United States person) or such owner otherwise establishes an exemption.

Backup withholding is not an additional tax. Any amounts withheld under the backup withholding rules may be allowed as a refund or a credit against a non-U.S. holder’s U.S. federal income tax liability, provided the required information is timely furnished to the IRS.

Additional Withholding Tax on Payments Made to Foreign Accounts

Withholding taxes may be imposed under the Foreign Account Tax Compliance Act, or the FATCA, on certain types of payments made to non-U.S. financial institutions and certain other non-U.S. entities. Specifically, a 30% withholding tax may be imposed on dividends on, or gross proceeds from the sale or other disposition of, our common stock paid to a “foreign financial institution” or a “non-financial foreign entity” (each as defined in the Code), unless (1) the foreign financial institution undertakes certain diligence and reporting obligations, (2) the non-financial foreign entity either certifies it does not have any “substantial United States owners” (as defined in the Code) or furnishes identifying information regarding each substantial United States owner, or (3) the foreign financial institution or non-financial foreign entity otherwise qualifies for an exemption from these rules. If the payee is a foreign financial institution and is subject to the diligence and reporting requirements in (1) above, it must enter into an agreement with the U.S. Department of the Treasury requiring, among other things, that it undertake to identify accounts held by certain “specified United States persons” or “United States-owned foreign entities” (each as defined in the Code), annually report certain information about such accounts and withhold 30% on payments to non-compliant foreign financial institutions and certain other account holders. Foreign financial institutions located in jurisdictions that have an intergovernmental agreement with the United States governing FATCA may be subject to different rules.

Under the applicable Treasury Regulations, withholding under FATCA generally will apply to payments of dividends on our common stock made on or after July 1, 2014 and to payments of gross proceeds from the sale or other disposition of such stock on or after January 1, 2017.

Prospective investors should consult their tax advisors regarding the potential application of withholding under FATCA to their investment in our common stock.

148

UNDERWRITING

Citigroup Global Markets Inc., Goldman, Sachs & Co. and Morgan Stanley & Co. LLC are acting as joint book-running managers of this offering and as representatives of the underwriters named below. Subject to the terms and conditions stated in the underwriting agreement dated the date of this prospectus, each underwriter named below has severally agreed to purchase, and we and the selling stockholders have agreed to sell to that underwriter, the number of shares set forth opposite the underwriter’s name.


Underwriter	Number of Shares
Citigroup Global Markets Inc.		5,757,000
Goldman, Sachs & Co.		5,757,000
Morgan Stanley & Co. LLC		5,757,000
Barclays Capital Inc.		2,121,000
BMO Capital Markets Corp.		2,121,000
Deutsche Bank Securities Inc.		2,121,000
KeyBanc Capital Markets Inc.		2,121,000
RBC Capital Markets, LLC		2,121,000
Jefferies LLC		606,000
Wells Fargo Securities, LLC		606,000
Capital One Securities, Inc.		303,000
Johnson Rice & Company L.L.C.		303,000
Scotia Capital (USA) Inc.		303,000
Simmons & Company International		303,000

Total		30,300,000

The underwriting agreement provides that the obligations of the underwriters to purchase the shares included in this offering are subject to approval of legal matters by counsel and to other conditions. The underwriters are obligated to purchase all the shares (other than those covered by the option to purchase additional shares described below) if they purchase any of the shares.

Shares sold by the underwriters to the public will initially be offered at the initial public offering price set forth on the cover of this prospectus. Any shares sold by the underwriters to securities dealers may be sold at a discount from the initial public offering price not to exceed $0.8505 per share. If all the shares are not sold at the initial offering price, the underwriters may change the offering price and the other selling terms. The representatives have advised us and the selling stockholders that the underwriters do not intend to make sales to discretionary accounts. The offering of the shares by the underwriters is subject to receipt and acceptance and subject to the underwriters right to reject any order in whole or part.

If the underwriters sell more shares than the total number set forth in the table above, the selling stockholders have granted to the underwriters an option, exercisable for 30 days from the date of this prospectus, to purchase up to 4,545,000 additional shares at the public offering price less the underwriting discount. The underwriters may exercise the option solely for the purpose of covering over-allotments, if any, in connection with this offering. To the extent the option is exercised, each underwriter must purchase a number of additional shares approximately proportionate to that underwriter’s initial purchase commitment. Any shares issued or sold under the option will be issued and sold on the same terms and conditions as the other shares that are the subject of this offering.

We, Eclipse Holdings, the limited partners of Eclipse Holdings, the EnCap Funds, the Management Funds and Management Holdco, all of directors and executive officers, and certain of our employees have agreed that, for a period of 180 days from the date of this prospectus, subject to certain exceptions, we and they will not, without the prior written consent of the representatives, dispose of or hedge any shares or any securities convertible into or

149

exchangeable for our common stock. The representatives in their sole discretion may release any of the securities subject to these lock-up agreements at any time, which, in the case of officers and directors, shall be with notice.

Prior to this offering, there has been no public market for our shares. Consequently, the initial public offering price for the shares was determined by negotiations among us, the selling stockholders and the representatives. Among the factors considered in determining the initial public offering price were our results of operations, our current financial condition, our future prospects, our markets, the economic conditions in and future prospects for the industry in which we compete, our management, and currently prevailing general conditions in the equity securities markets, including current market valuations of publicly traded companies considered comparable to our company. We cannot assure you, however, that the price at which the shares will sell in the public market after this offering will not be lower than the initial public offering price or that an active trading market in our shares will develop and continue after this offering.

We have been approved to have our shares listed on the New York Stock Exchange under the symbol “ECR.”

The following table shows the underwriting discounts and commissions that we and the selling stockholders are to pay to the underwriters in connection with this offering. With respect to the selling stockholders, these amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase additional shares.


	Paid by Eclipse Resources		Paid by Selling Stockholders
	Paid by Eclipse Resources		No Exercise		Full Exercise
Per share	$	1.4175	$	1.4175	$	1.4175
Total	$	30,476,250	$	12,474,000	$	18,916,538

The expenses of this offering that are payable by us are estimated to be approximately $4.8 million, excluding underwriting discounts and commissions. We have also agreed to pay expenses incurred by the selling stockholders in connection with this offering, other than the underwriting discounts and commissions. We have also agreed to reimburse the underwriters for certain of their expenses in an amount up to $50,000.

In connection with the offering, the underwriters may purchase and sell shares in the open market. Purchases and sales in the open market may include short sales, purchases to cover short positions, which may include purchases pursuant to the option to purchase additional shares, and stabilizing purchases.

•

Short sales involve secondary market sales by the underwriters of a greater number of shares than they are required to purchase in the offering.

•

“Covered” short sales are sales of shares in an amount up to the number of shares represented by the underwriters’ option to purchase additional shares.

•

“Naked” short sales are sales of shares in an amount in excess of the number of shares represented by the underwriters’ option to purchase additional shares.

•

Covering transactions involve purchases of shares either pursuant to the underwriters’ option to purchase additional shares or in the open market in order to cover short positions.

•

To close a naked short position, the underwriters must purchase shares in the open market. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the shares in the open market after pricing that could adversely affect investors who purchase in the offering.

•

To close a covered short position, the underwriters must purchase shares in the open market or must exercise the option to purchase additional shares. In determining the source of shares to close the covered short position, the underwriters will consider, among other things, the price of shares available for purchase in the open market as compared to the price at which they may purchase shares through the underwriters’ option to purchase additional shares.

•

Stabilizing transactions involve bids to purchase shares so long as the stabilizing bids do not exceed a specified maximum.

150

Purchases to cover short positions and stabilizing purchases, as well as other purchases by the underwriters for their own accounts, may have the effect of preventing or retarding a decline in the market price of the shares. They may also cause the price of the shares to be higher than the price that would otherwise exist in the open market in the absence of these transactions. The underwriters may conduct these transactions on the NYSE, in the over-the-counter market or otherwise. If the underwriters commence any of these transactions, they may discontinue them at any time.

Other Relationships

The underwriters are full service financial institutions engaged in various activities, which may include securities trading, commercial and investment banking, financial advisory, investment management, principal investment, hedging, financing and brokerage activities. The underwriters and their respective affiliates may, from time to time, engage in transactions with and perform services for us in the ordinary course of their business for which they may receive customary fees and reimbursement of expenses. In the ordinary course of their various business activities, the underwriters and their respective affiliates may make or hold a broad array of investments and actively trade debt and equity securities (or related derivative securities) and financial instruments (which may include bank loans and/or credit default swaps) for their own account and for the accounts of their customers and may at any time hold long and short positions in such securities and instruments. Such investments and securities activities may involve securities and/or instruments of ours or our affiliates.

Affiliates of Citigroup Global Markets Inc., Goldman Sachs & Co., Morgan Stanley & Co. LLC, BMO Capital Markets Corp. and KeyBanc Capital Markets Inc. are lenders under our revolving credit facility and, accordingly, will receive a portion of the net proceeds of this offering upon the repayment of borrowings under our revolving credit facility in connection with the closing of this offering. See “Use of Proceeds.” In addition, an affiliate of Deutsche Bank Securities Inc. acts as trustee with respect to the indenture governing our Senior Unsecured Notes.

The underwriters and their affiliates may also make investment recommendations and/or publish or express independent research views in respect of such securities or financial instruments and may hold, or recommend to clients that they acquire, long and/or short positions in such securities and instruments.

We and the selling stockholders have agreed to indemnify the several underwriters against certain liabilities, including liabilities under the Securities Act, or to contribute to payments the underwriters may be required to make because of any of those liabilities.

Notice to Prospective Investors in the European Economic Area

In relation to each member state of the European Economic Area that has implemented the Prospectus Directive (each, a relevant member state), with effect from and including the date on which the Prospectus Directive is implemented in that relevant member state (the relevant implementation date), an offer of shares described in this prospectus may not be made to the public in that relevant member state other than:

•

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

•

to fewer than 100 or, if the relevant member state has implemented the relevant provision of the 2010 PD Amending Directive, 150 natural or legal persons (other than qualified investors as defined in the Prospectus Directive), as permitted under the Prospectus Directive, subject to obtaining the prior consent of the relevant Dealer or Dealers nominated by us for any such offer; or

•

in any other circumstances falling within Article 3(2) of the Prospectus Directive,

provided that no such offer of shares shall require us or any underwriter to publish a prospectus pursuant to Article 3 of the Prospectus Directive.

151

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

The sellers of the shares have not authorized and do not authorize the making of any offer of shares through any financial intermediary on their behalf, other than offers made by the underwriters with a view to the final placement of the shares as contemplated in this prospectus. Accordingly, no purchaser of the shares, other than the underwriters, is authorized to make any further offer of the shares on behalf of the sellers or the underwriters.

Notice to Prospective Investors in the United Kingdom

This prospectus is only being distributed to, and is only directed at, persons in the United Kingdom that are qualified investors within the meaning of Article 2(1)(e) of the Prospectus Directive that are also (i) investment professionals falling within Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005 (the “Order”) or (ii) high net worth entities, and other persons to whom it may lawfully be communicated, falling within Article 49(2)(a) to (d) of the Order (each such person being referred to as a “relevant person”). This prospectus and its contents are confidential and should not be distributed, published or reproduced (in whole or in part) or disclosed by recipients to any other persons in the United Kingdom. Any person in the United Kingdom that is not a relevant person should not act or rely on this document or any of its contents.

Notice to Prospective Investors in France

Neither this prospectus nor any other offering material relating to the shares described in this prospectus has been submitted to the clearance procedures of the Autorité des Marchés Financiers or of the competent authority of another member state of the European Economic Area and notified to the Autorité des Marchés Financiers. The shares have not been offered or sold and will not be offered or sold, directly or indirectly, to the public in France. Neither this prospectus nor any other offering material relating to the shares has been or will be:

•

released, issued, distributed or caused to be released, issued or distributed to the public in France; or

•

used in connection with any offer for subscription or sale of the shares to the public in France.

Such offers, sales and distributions will be made in France only:

•

to qualified investors (investisseurs qualifiés) and/or to a restricted circle of investors (cercle restreint d’investisseurs), in each case investing for their own account, all as defined in, and in accordance with articles L.411-2, D.411-1, D.411-2, D.734-1, D.744-1, D.754-1 and D.764-1 of the French Code monétaire et financier;

•

to investment services providers authorized to engage in portfolio management on behalf of third parties; or

•

in a transaction that, in accordance with article L.411-2-II-1°-or-2°-or 3° of the French Code monétaire et financier and article 211-2 of the General Regulations (Règlement Général) of the Autorité des Marchés Financiers, does not constitute a public offer (appel public à l’épargne).

The shares may be resold directly or indirectly, only in compliance with articles L.411-1, L.411-2, L.412-1 and L.621-8 through L.621-8-3 of the French Code monétaire et financier.

152

Notice to Prospective Investors in Hong Kong

The shares may not be offered or sold in Hong Kong by means of any document other than (i) in circumstances which do not constitute an offer to the public within the meaning of the Companies Ordinance (Cap. 32, Laws of Hong Kong), or (ii) to “professional investors” within the meaning of the Securities and Futures Ordinance (Cap. 571, Laws of Hong Kong) and any rules made thereunder, or (iii) in other circumstances which do not result in the document being a “prospectus” within the meaning of the Companies Ordinance (Cap. 32, Laws of Hong Kong) and no advertisement, invitation or document relating to the shares may be issued or may be in the possession of any person for the purpose of issue (in each case whether in Hong Kong or elsewhere), which is directed at, or the contents of which are likely to be accessed or read by, the public in Hong Kong (except if permitted to do so under the laws of Hong Kong) other than with respect to shares which are or are intended to be disposed of only to persons outside Hong Kong or only to “professional investors” within the meaning of the Securities and Futures Ordinance (Cap. 571, Laws of Hong Kong) and any rules made thereunder.

Notice to Prospective Investors in Japan

The shares offered in this prospectus have not been and will not be registered under the Financial Instruments and Exchange Law of Japan. The shares have not been offered or sold and will not be offered or sold, directly or indirectly, in Japan or to or for the account of any resident of Japan (including any corporation or other entity organized under the laws of Japan), except (i) pursuant to an exemption from the registration requirements of the Financial Instruments and Exchange Law and (ii) in compliance with any other applicable requirements of Japanese law.

Notice to Prospective Investors in Singapore

This prospectus has not been registered as a prospectus with the Monetary Authority of Singapore. Accordingly, this prospectus and any other document or material in connection with the offer or sale, or invitation for subscription or purchase, of the shares may not be circulated or distributed, nor may the shares be offered or sold, or be made the subject of an invitation for subscription or purchase, whether directly or indirectly, to persons in Singapore other than (i) to an institutional investor under Section 274 of the Securities and Futures Act, Chapter 289 of Singapore (the “SFA”), (ii) to a relevant person pursuant to Section 275(1), or any person pursuant to Section 275(1A), and in accordance with the conditions specified in Section 275 of the SFA or (iii) otherwise pursuant to, and in accordance with the conditions of, any other applicable provision of the SFA, in each case subject to compliance with conditions set forth in the SFA.

Where the shares are subscribed or purchased under Section 275 of the SFA by a relevant person which is:

•

a corporation (which is not an accredited investor (as defined in Section 4A of the SFA)) the sole business of which is to hold investments and the entire share capital of which is owned by one or more individuals, each of whom is an accredited investor; or

•

a trust (where the trustee is not an accredited investor) whose sole purpose is to hold investments and each beneficiary of the trust is an individual who is an accredited investor,

shares, debentures and units of shares and debentures of that corporation or the beneficiaries’ rights and interest (howsoever described) in that trust shall not be transferred within six months after that corporation or that trust has acquired the shares pursuant to an offer made under Section 275 of the SFA except:

•

to an institutional investor (for corporations, under Section 274 of the SFA) or to a relevant person defined in Section 275(2) of the SFA, or to any person pursuant to an offer that is made on terms that such shares, debentures and units of shares and debentures of that corporation or such rights and interest in that trust are acquired at a consideration of not less than S$200,000 (or its equivalent in a foreign currency) for each transaction, whether such amount is to be paid for in cash or by exchange of securities or other assets, and further for corporations, in accordance with the conditions specified in Section 275 of the SFA;

•

where no consideration is or will be given for the transfer; or

•

where the transfer is by operation of law.

153

LEGAL MATTERS

The validity of our common stock offered by this prospectus will be passed upon for us by Fulbright & Jaworski LLP (a member of Norton Rose Fulbright), Dallas, Texas. Certain legal matters in connection with this offering will be passed upon for the underwriters by Latham & Watkins LLP, Houston, Texas.

EXPERTS

The balance sheet of Eclipse Resources Corporation as of February 20, 2014 included in this prospectus and elsewhere in the registration statement has been so included in reliance upon the report of Grant Thornton LLP, independent registered public accountants, upon the authority of said firm as experts in accounting and auditing.

The consolidated financial statements of Eclipse Resources I, LP as of December 31, 2013 and 2012, and for each of the years in the two-year period ended December 31, 2013, included in this prospectus and elsewhere in the registration statement have been so included in reliance upon the report of Grant Thornton LLP, independent registered public accountants, upon the authority of said firm as experts in accounting and auditing.

The financial statements of Eclipse Resources–Ohio, LLC as of June 25, 2013 and December 31, 2012, and for the year ended December 31, 2012 and the period January 1, 2013 through June 25, 2013, included in this prospectus and elsewhere in the registration statement have been so included in reliance upon the report of Grant Thornton LLP, independent certified public accountants, upon the authority of said firm as experts in accounting and auditing.

The financial statements of Eclipse Resources Operating, LLC as of December 31, 2013 and 2012, and for each of the years in the two-year period ended December 31, 2013, included in this prospectus and elsewhere in the registration statement have been so included in reliance upon the report of Grant Thornton LLP, independent registered public accountants, upon the authority of said firm as experts in accounting and auditing.

Estimates of our natural gas and oil reserves, related future net cash flows and the present values thereof related to (i) our properties as of March 31, 2014, December 31, 2013, June 30, 2013 and December 31, 2012 and (ii) the properties of The Oxford Oil Company as of December 31, 2012, included elsewhere in this prospectus were based in part upon reserve reports prepared by independent petroleum engineers, Netherland, Sewell & Associates, Inc. We have included these estimates in reliance on the authority of such firm as experts in such matters.

154

WHERE YOU CAN FIND ADDITIONAL INFORMATION

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

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

155

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS


ECLIPSE RESOURCES CORPORATION

Unaudited Pro Forma Consolidated Financial Statements
Introduction			F-3
Balance Sheet as of March 31, 2014			F-5
Statement of Operations for the Year Ended December 31, 2013			F-6
Statement of Operations for the Three Months Ended March 31, 2014			F-7
Notes to Unaudited Pro Forma Consolidated Financial Statements			F-8

Historical Balance Sheet
Report of Independent Registered Public Accounting Firm			F-11
Balance Sheets as of February 20, 2014 and March 31, 2014			F-12
Notes to Balance Sheets			F-13

ECLIPSE RESOURCES I, LP (PREDECESSOR)

Unaudited Historical Consolidated Financial Statements
Balance Sheets as of March 31, 2014 and December 31, 2013			F-14
Statements of Operations for the Three Months Ended March 31, 2014 and 2013			F-15
Statements of Comprehensive Loss for the Three Months Ended March 31, 2014 and 2013			F-16
Statement of Partners’ Capital for the Three Months Ended March 31, 2014 and for the Year Ended December 31, 2013			F-17
Statements of Cash Flows for the Three Months Ended March 31, 2014 and 2013			F-18
Notes to the Consolidated Financial Statements			F-19

Historical Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm			F-40
Balance Sheets as of December 31, 2013 and 2012			F-41
Statements of Operations for the Years Ended December 31, 2013 and 2012			F-42
Statements of Comprehensive Loss for the Years Ended December 31, 2013 and 2012			F-43
Statements of Partners’ Capital for the Years Ended December 31, 2013 and 2012			F-44
Statements of Cash Flows for the Years Ended December 31, 2013 and 2012			F-45
Notes to the Consolidated Financial Statements			F-46

ECLIPSE RESOURCES-OHIO, LLC

Historical Financial Statements
Report of Independent Certified Public Accountants			F-67
Balance Sheets as of June 25, 2013 and December 31, 2012			F-68
Statements of Operations for the Period Ended June 25, 2013 and the Year Ended December 31, 2012			F-69
Statements of Comprehensive Loss for the Period Ended June 25, 2013 and the Year Ended December 31, 2012			F-70
Statements of Member’s Equity (Deficit) for the Period Ended June 25, 2013 and the Year Ended December 31, 2012			F-71
Statements of Cash Flows for the Period Ended June 25, 2013 and the Year Ended December 31, 2012			F-72
Notes to the Financial Statements			F-73

ECLIPSE RESOURCES OPERATING, LLC

Unaudited Historical Consolidated Financial Statements
Balance Sheets as of March 31, 2014 and December 31, 2013			F-89
Statements of Operations for the Three Months Ended March 31, 2014 and 2013			F-90
Statement of Members’ Equity (Deficit) for the Three Months Ended March 31, 2014 and for the Year Ended December 31, 2013			F-91
Statements of Cash Flows for the Three Months Ended March 31, 2014 and 2013			F-92
Notes to the Financial Statements			F-93

F-1


Historical Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm			F-97
Balance Sheets as of December 31, 2013 and 2012			F-98
Statements of Operations for the Years Ended December 31, 2013 and 2012			F-99
Statements of Members’ Equity (Deficit) for the Years Ended December 31, 2013 and 2012			F-100
Statements of Cash Flows for the Years Ended December 31, 2013 and 2012			F-101
Notes to the Financial Statements			F-102

F-2

ECLIPSE RESOURCES CORPORATION

PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Introduction

Eclipse Resources Corporation (the “Company”) is a newly-formed Delaware corporation formed by Eclipse Resources I, LP (“Eclipse I”) to engage in the exploitation, development, exploration and acquisition of oil and natural gas properties in the Appalachian Basin. The following unaudited pro forma consolidated financial statements of the Company reflect the historical consolidated results of Eclipse I, on a pro forma basis to give effect to the following transactions, which are described in further detail below, as if they had occurred on March 31, 2014, for pro forma balance sheet purposes and on January 1, 2013, for pro forma statements of operations purposes:

•

The Oxford Acquisition. On June 26, 2013, Eclipse I acquired all of the equity interests of Eclipse Resources-Ohio LLC (“Oxford”) from Salt Run Capital, Inc., an Ohio corporation, for consideration of $652.5 million (the “Oxford Acquisition”).

•

The Eclipse Operating Acquisition. In connection with the Offering (defined below), Benjamin W. Hulburt, Christopher K. Hulburt, and Thomas S. Liberatore will each sell to Eclipse I their ownership interests in Eclipse Resources Operating, LLC (“Eclipse Operating”) in exchange for $0.04 million in cash each (the “Eclipse Operating Acquisition”).

•

The Corporate Reorganization. Pursuant to the terms of a corporate reorganization (the “Corporate Reorganization”) that will be completed contemporaneously with, and conditioned upon, the completion of this offering, (i) Eclipse I will acquire all of the outstanding equity interests of Eclipse Operating, (ii) all of the outstanding equity interests of the existing limited partners of Eclipse I will be exchanged for similar equity interests in Eclipse Holdings, (iii) all of the outstanding equity interests in Eclipse GP, LLC, the general partner of Eclipse I, will be transferred to Eclipse Holdings, and (iv) Eclipse Holdings will contribute all of its equity interest in Eclipse I and the outstanding equity interests in Eclipse GP, LLC to Eclipse Resources Corporation. As a result of these steps, Eclipse Resources Corporation will become a direct subsidiary of Eclipse Holdings.

•

The Offering. For purposes of the unaudited pro forma consolidated financial statements, the “Offering” is defined as the planned issuance and sale to the public of 21.5 million shares of common stock of the Company as contemplated by this prospectus and the application by the Company of the net proceeds from such issuance as described in “Use of Proceeds.” The net proceeds from the sale of the common stock are expected to be approximately $545.2 million (based on our initial public offering price of $27.00 per share), net of underwriting discounts and commissions of approximately $30.5 million and other offering costs of approximately $4.8 million.

The unaudited pro forma consolidated balance sheet of the Company is based on the unaudited historical consolidated balance sheet of Eclipse I as of March 31, 2014, and includes pro forma adjustments to give effect to the Eclipse Operating Acquisition, the Corporate Reorganization and the Offering as if they had occurred on March 31, 2014.

The unaudited pro forma consolidated statements of operations of the Company are based on (i) the unaudited historical consolidated statement of operations of Eclipse I for the period ended March 31, 2014, having given effect to the Eclipse Operating Acquisition and the Corporate Reorganization as if they had occurred on January 1, 2013, (ii) the audited historical consolidated statement of operations of Eclipse I for the year ended December 31, 2013, having given effect to the Oxford Acquisition, the Eclipse Operating Acquisition, and the Corporate Reorganization as if they had occurred on January 1, 2013, (iii) the audited historical statement of operations of Oxford for the period from January 1, 2013 through June 25, 2013 included

F-3

ECLIPSE RESOURCES CORPORATION

PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

elsewhere in this prospectus, and (iv) the historical statement of operations of Eclipse Operating for the three months ended March 31, 2014 and the year ended December 31, 2013, included elsewhere in this prospectus.

The unaudited pro forma consolidated financial statements have been prepared on the basis that the Company will be taxed as a corporation under the Internal Revenue Code of 1986, as amended, and as a result, will become a tax-paying entity subject to U.S. federal and state income taxes, and should be read in conjunction with the notes thereto and with “Corporate Reorganization,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the audited historical consolidated financial statements and related notes of Eclipse I, each included elsewhere in this prospectus.

The pro forma data presented reflect events directly attributable to the described transactions and certain assumptions the Company believes are reasonable. The pro forma data are not necessarily indicative of financial results that would have been attained had the described transactions occurred on the dates indicated below or which could be achieved in the future because they necessarily exclude various operating expenses, such as incremental general and administrative expenses associated with being a public company. The adjustments are based on currently available information and certain estimates and assumptions. Therefore, the actual adjustments may differ from the pro forma adjustments. However, management believes that the assumptions provide a reasonable basis for presenting the significant effects of the transactions as contemplated and that the pro forma adjustments give appropriate effect to those assumptions and are properly applied in the unaudited pro forma financial statements.

The unaudited pro forma consolidated financial statements and related notes are presented for illustrative purposes only. If the Offering and other transactions contemplated herein had occurred in the past, the Company’s operating results might have been materially different from those presented in the unaudited pro forma financial statements. The unaudited pro forma consolidated financial statements should not be relied upon as an indication of operating results that the Company would have achieved if the Offering and other transactions contemplated herein had taken place on the specified date. In addition, future results may vary significantly from the results reflected in the unaudited pro forma consolidated statements of operations and should not be relied on as an indication of the future results the Company will have after the completion of the Offering and the other transactions contemplated by these unaudited pro forma consolidated financial statements.

F-4

ECLIPSE RESOURCES CORPORATION

PRO FORMA CONSOLIDATED BALANCE SHEET

MARCH 31, 2014

(Unaudited)


	Eclipse Resources, I Historical			Eclipse Operating			Corporate Reorganization			Offering			Pro Forma As Adjusted
				^(a)
	(in thousands)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	27,328		$	1,182		$	—		$	526,632	^(e)(f)	$	555,142
Accounts receivable		30,369			590			(590	)^(b)		—			30,369
Other current assets		270			511			—			—			781
Deferred tax asset		—			—			1,006	^(c)		—			1,006

Total current assets		57,967			2,283			416			526,632			587,298
PROPERTY AND EQUIPMENT, AT COST
Oil and natural gas properties, successful efforts method
Unproved properties		1,062,033			—			—			—			1,062,033
Proved oil and gas properties		99,614			—			—			—			99,614
Accumulated depreciation, depletion and amortization		(20,553	)		—			—			—			(20,553	)

Total oil and natural gas properties, net		1,141,094			—			—			—			1,141,094
Other property and equipment, net		3,813			2,003			—			—			5,816

Total property, plant and equipment, net		1,144,907			2,003			—			—			1,146,910
NONCURRENT ASSETS
Debt issue costs, net		6,976			—			—			—			6,976
Other assets		1,443			—			—			(1,388	)^(c)		55

Total noncurrent assets		8,419			—			—			(1,388	)		7,031

TOTAL ASSETS	$	1,211,293		$	4,286		$	416		$	525,244		$	1,741,239

LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable	$	40,309		$	911		$	—		$	—		$	41,220
Accrued liabilities		7,445			1,753			—			—			9,198
Accrued capital expenditures		11,385			—			—			—			11,385
Accrued interest payable		11,442			—			—			—			11,442
Accrued liabilities—related party		539			—			(539	)^(b)		—			—
Deferred revenue		—			1,608			(1,608	)^(b)		—			—

Total current liabilities		71,120			4,272			(2,147	)		—			73,245
NONCURRENT LIABILITIES
Debt, net of unamortized discount of $10.2 million		412,230			—			—			—			412,230
Credit facility		20,000			—			—			(20,000	)^(f)		—
Pension liabilities		278			—			—			—			278
Deferred revenue		—			17			(17	)^(b)		—			—
Asset retirement obligations		9,311			—			—			—			9,311
Deferred tax liability		—			—			56,364	^(c)		—			56,364

Total noncurrent liabilities		441,819			17			56,347			(20,000	)		478,183
COMMITMENTS AND CONTINGENCIES
MEMBERS’ EQUITY		698,048			—	(3)		(698,045	)^(d)		—			—
STOCKHOLDERS’ EQUITY
Preferred stock		—			—			—			—			—
Common stock		—			—			1,385	^(d)		215	^(e)		1,600
Additional paid-in capital		—			—			696,660	^(d)		545,029	^(e)		1,241,689
Accumulated deficit		—			—			(53,784	)^(c)		—			(53,784	)
Accumulated other comprehensive income		306			—			—			—			306

Total stockholders’ equity		306			—			644,261			545,244			1,189,811

TOTAL LIABILITIES AND EQUITY	$	1,211,293		$	4,286		$	416		$	525,244		$	1,741,239

The accompanying notes are an integral part of these unaudited pro forma consolidated financial statements.

F-5

ECLIPSE RESOURCES CORPORATION

PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS

FOR THE YEAR ENDED DECEMBER 31, 2013

(Unaudited)


	Eclipse Resources, I Historical			Eclipse Operating			Eclipse Resources - Ohio Acquisition			Corporate Reorganization			Pro Forma As Adjusted
				^(g)			^(h)
	(in thousands, except per share data)
REVENUES
Oil and natural gas sales	$	12,935		$	13,658		$	7,703		$	(13,658	)^(l)	$	20,638

Total revenues		12,935			13,658			7,703			(13,658	)		20,638
OPERATING EXPENSES
Exploration		3,022			—			183			—			3,205
Lease operating		2,576			—			2,160			—			4,736
Transportation and gathering		67			—			—			—			67
Production and ad valorem taxes		77			—			87			—			164
Depreciation, depletion and amortization		6,163			—			3,093	⁽ⁱ⁾		—			9,256
Impairments		2,081			—			—			—			2,081
General and administrative		21,276			13,658			2,532			(13,658	)^(l)		23,808
Accretion expense		364			—			338	^(j)		—			702

Total operating expenses		35,626			13,658			8,393			(13,658	)		44,019

OPERATING LOSS		(22,691	)		—			(690	)		—			(23,381	)
OTHER (EXPENSE)
Interest expense, net		(20,850	)		(2	)		(20,700	)^(k)		—			(41,552	)

Total other (expense), net		(20,850	)		(2	)		(20,700	)		—			(41,552	)

LOSS BEFORE INCOME TAXES		(43,541	)		(2	)		(21,390	)		—			(64,933	)
INCOME TAX BENEFIT		—			—			—			24,897	^(m)		24,897

NET LOSS	$	(43,541	)	$	(2	)	$	(21,390	)	$	24,897		$	(40,036	)


NET LOSS PER COMMON SHARE (n)
Basic and Diluted													$	(0.41	)

WEIGHTED AVERAGE COMMON SHARES OUTSTANDING (n)
Basic and Diluted														96,761

The accompanying notes are an integral part of these unaudited pro forma consolidated financial statements.

F-6

ECLIPSE RESOURCES CORPORATION

PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS

FOR THE THREE MONTHS ENDED MARCH 31, 2014

(Unaudited)


	Eclipse Resources, I Historical			Eclipse Operating		Corporate Reorganization			Offering			Pro Forma As Adjusted
				(o)
	(in thousands, except per share data)
REVENUES
Oil and natural gas sales	$	24,788		$	7,494	$	(7,494	)^(p)	$	—		$	24,788

Total revenues		24,788			7,494		(7,494	)		—			24,788
OPERATING EXPENSES
Exploration		4,545			—		—			—			4,545
Lease operating		1,791			—		—			—			1,791
Transportation and gathering		904			—		—			—			904
Production and ad valorem taxes		353			—		—			—			353
Depreciation, depletion and amortization		12,027			—		—			—			12,027
General and administrative		8,394			7,494		(7,494	)^(p)		—			8,394
Accretion expense		186			—		—			—			186
Gain on reduction in pension liability		(2,208	)		—		—			—			(2,208	)

Total operating expenses		25,992			7,494		(7,494	)		—			25,992

OPERATING LOSS		(1,204	)		—		—			—			(1,204	)
OTHER INCOME (EXPENSE)
Loss on derivative instruments		(3,611	)		—		—			—			(3,611	)
Interest expense, net		(13,636	)		1		—			32	^(r)		(13,603	)

Total other income (expense), net		(17,247	)		1		—			32			(17,214	)

LOSS BEFORE INCOME TAXES		(18,451	)		1		—			32			(18,418	)
INCOME TAX BENEFIT		—			—		6,457	^(q)		(11	)^(r)		6,446

NET LOSS	$	(18,451	)	$	1	$	6,457		$	21		$	(11,972	)

NET LOSS PER COMMON SHARE (s)
Basic and diluted												$	(0.08	)

WEIGHTED AVERAGE COMMON SHARES OUTSTANDING (s)
Basic and diluted													144,085

The accompanying notes are an integral part of these unaudited pro forma consolidated financial statements.

F-7

ECLIPSE RESOURCES CORPORATION

NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. BASIS OF PRESENTATION, THE OFFERING AND OTHER TRANSACTIONS

The historical financial information is derived from the consolidated financial statements of Eclipse I, Eclipse Resources-Ohio, LLC and Eclipse Resources Operating, LLC included elsewhere in this prospectus. For purposes of the unaudited pro forma balance sheet, it is assumed that the Eclipse Operating Acquisition, the Corporate Reorganization and the Offering described elsewhere in this prospectus had each taken place on March 31, 2014. For purposes of the unaudited pro forma statements of operations, it is assumed that the Oxford Acquisition, the Eclipse Operating Acquisition, the Corporate Reorganization and the Offering described elsewhere in this prospectus all transactions had taken place on January 1, 2013.

NOTE 2. PRO FORMA ADJUSTMENTS AND ASSUMPTIONS

The Company made the following adjustments and assumptions in the preparation of the unaudited pro forma consolidated balance sheet:

(a)

Reflects the acquisition of Eclipse Operating for $0.1 million. Eclipse Operating serves as manager of Eclipse I’s assets. In performing such function, Eclipse Operating (i) collects all revenue and pays all expenses of Eclipse I and other working interest partners, and (ii) distributes all cash and bills all expenses to Eclipse I and other working interest partners for their respective interests. As such, the only assets and liabilities of Eclipse Operating are accounts receivable, fixed assets, and accounts payable. At March 31, 2014, Eclipse I had a net account payable outstanding of $0.5 million to Eclipse Operating. As the acquisition cost of $0.1 million was not material and the Company will assume all the assets and liabilities of Eclipse Operating presented herein, no purchase price allocation has been presented.

(b)

Reflects the elimination of (i) intra-company accounts receivable (payable) between Eclipse I and Eclipse Operating, and (ii) Eclipse Operating deferred revenue.

(c)

Reflects estimated change in deferred tax assets and liabilities for temporary differences between the historical cost basis and tax basis of the Company’s assets and liabilities as the result of its deemed change in tax status to a subchapter C corporation at March 31, 2014. A corresponding charge to earnings has not been reflected in the unaudited pro forma statement of operations as the charge is considered non-recurring.

(d)

Reflects the exchange of 138.5 million shares of the Company’s common stock for all the membership interest of Eclipse I.

(e)

Reflects estimated proceeds of approximately $545.2 million from the issuance and sale of shares of common stock at our initial public offering price of $27.00 per share, net of underwriting discounts and commissions of approximately $30.5 million, in the aggregate, and additional estimated expenses related to the Offering of approximately $4.8 million, of which approximately $1.4 million was paid prior to March 31, 2014 and recorded in Other Assets in the Company’s Consolidated Balance Sheet at March 31, 2014.

(f)

Reflects the repayment of $20.0 million of outstanding borrowings as of March 31, 2014 under the Eclipse I revolving credit facility with proceeds from the Offering.

The Company made the following adjustments and assumptions in the preparation of the unaudited pro forma statement of operations as of December 31, 2013:

(g)

Reflects the historical results of operations of Eclipse Operating during the year ended December 31, 2013, derived from the historical audited financial statements of Eclipse Operating, included elsewhere in this prospectus.

(h)

Reflects the results of operations of Oxford for the period from January 1, 2013 through June 25, 2013, derived from the historical audited financial statements of Oxford, with the exception of the pro forma

F-8

ECLIPSE RESOURCES CORPORATION

NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

adjustments related to depreciation, depletion and amortization expense, accretion of asset retirement obligation expense and interest expense which gave effect to the Company’s accounting policies and calculated as if the Oxford Acquisition had occurred on January 1, 2013.

(i)

Adjustments reflect changes in depreciation, depletion and amortization expense that would have been recorded with respect to the allocated fair value attributable to proved oil and gas properties acquired in the Oxford Acquisition, had such acquisition occurred on January 1, 2013.

(j)

Adjustments reflect additional accretion of asset retirement obligation expense that would have been recorded with respect to the asset retirement obligations assumed in the Oxford Acquisition, had such acquisition occurred on January 1, 2013.

(k)

Reflects additional interest expense, accretion of debt discount and amortization of debt issue costs associated with the issuance of the Eclipse I Senior Notes, had such issuance occurred on January 1, 2013.

(l)

Reflects the elimination of the intra-company revenue and expense between Eclipse I and Eclipse Operating.

(m)

Reflects estimated incremental income tax benefit associated with the Company’s historical results of operations assuming the Company’s earnings had been subject to federal income tax as a subchapter C corporation using an effective tax rate of approximately 35%. This rate is inclusive of federal and state income taxes.

(n)

Reflects basic and diluted income per common share for the issuance of shares of common stock in the Corporate Reorganization and the Offering.

The Company made the following adjustments and assumptions in the preparation of the unaudited pro forma statement of operations as of March 31, 2014:

(o)

Reflects the historical results of operations of Eclipse Operating during the three months ended March 31, 2014, derived from the historical unaudited financial statements of Eclipse Operating, included elsewhere in this prospectus.

(p)

Reflects the elimination of the intra-company revenue and expense between Eclipse I and Eclipse Operating.

(q)

(r)

Reflects the reduction in interest expense under the Company’s revolving credit agreement as a result of the repayment of $20.0 million of outstanding borrowings as of March 31, 2014 in connection with the Offering and the associated income tax benefit from this reduction. On a pro forma basis, there would have been no outstanding borrowings under the Company’s revolving credit facility as of January 1, 2013.

(s)

Reflects basic and diluted income per common share for the issuance of shares of common stock in the Corporate Reorganization and the Offering.

NOTE 3. SUPPLEMENTAL DISCLOSURE OF OIL AND NATURAL GAS OPERATIONS

The following pro forma standardized measure of the discounted net future cash flows and changes applicable to Eclipse I’s proved reserves reflect the effect of income taxes assuming Eclipse I’s standardized measure had been subject to federal and state income tax as a subchapter C corporation. The future cash flows are discounted at 10% per year and assume continuation of existing economic conditions.

F-9

ECLIPSE RESOURCES CORPORATION

NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

The standardized measure of discounted future net cash flows, in management’s opinion, should be examined with caution. The basis for this table is the reserve studies prepared by independent petroleum engineering consultants, which contain imprecise estimates of quantities and rates of production of reserves. Revisions of previous year estimates can have a significant impact on these results. Also, exploration costs in one year may lead to significant discoveries in later years and may significantly change previous estimates of proved reserves and their valuation. Therefore, the standardized measure of discounted future net cash flow is not necessarily indicative of the fair value of Eclipse I’s proved oil and natural gas properties.

The data presented should not be viewed as representing the expected cash flow from or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. Actual future prices and costs are likely to be substantially different from the prices and costs utilized in the computation of reported amounts.

The pro forma standardized measure of discounted estimated future net cash flows was as follows as of December 31, 2013 (in thousands):


	Eclipse I Historical			Corporate Reorganization			Pro Forma As Adjusted
	(in thousands)
Future cash inflows	$	479,527		$	—		$	479,527
Future production costs		(116,161	)		—			(116,161	)
Future development costs		(76,511	)		—			(76,511	)
Future income tax expenses		—			(74,343	)		(74,343	)

Future net cash flows		286,855			(74,343	)		212,512
10% discount to reflect timing of cash flows		(131,560	)		34,515			(97,045	)

Standardized measure of discounted future net cash flows	$	155,295		$	(39,828	)	$	115,467

The changes in the pro forma standardized measure of discounted estimated future net cash flows were as follows for 2013 (in thousands):


	Eclipse I Historical			Eclipse Resources Ohio Acquisition			Corporate Reorganization			Pro Forma As Adjusted
							(in thousands)
Standardized measure of discounted future net cash flows at beginning of the period	$	21,894		$	—		$	—		$	21,894
Changes in the year resulting from:
Sales, net of production costs		(10,281	)		(5,543	)		—			(15,824	)
Purchase of minerals in place		28,984			1,931			—			30,915
Extensions and discoveries, net of future development costs		106,720			—			—			106,720
Net changes in prices and production costs		(5,354	)		(199	)		—			(5,553	)
Changes in estimated future development costs		(1,148	)		(94	)		—			(1,242	)
Revisions of previous quantity estimates		8,354			489			—			8,843
Accretion of discount		2,189			3,091			—			5,280
Net change in income taxes		—			—			(39,828	)		(39,828	)
Net changes in timing of production and other		3,937			325			—			4,262

Standardized measure of discounted future net cash flows at end of the period	$	155,295		$	—		$	(39,828	)	$	115,467

F-10

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Shareholders.

Eclipse Resources Corporation

We have audited the accompanying balance sheet of Eclipse Resources Corporation (a Delaware corporation) (the “Company”) as of February 20, 2014. This financial statement is the responsibility of the Company’s management. Our responsibility is to express an opinion on this financial statement based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statement is free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the financial statement referred to above present fairly, in all material respects, the financial position of Eclipse Resources Corporation as of February 20, 2014 in conformity with accounting principles generally accepted in the United States of America.

/s/ GRANT THORNTON LLP

Cleveland, Ohio

February 21, 2014

F-11

ECLIPSE RESOURCES CORPORATION

BALANCE SHEETS


	February 20, 2014		March 31, 2014
			(Unaudited)
TOTAL ASSETS
Cash	$	10	$	10

TOTAL ASSETS	$	10	$	10

STOCKHOLDER’S EQUITY
Common stock, $0.01 par value, authorized 1,000 shares;
1,000 issued and outstanding	$	10	$	10

TOTAL STOCKHOLDER’S EQUITY	$	10	$	10

The accompanying notes are an integral part of this financial statement.

F-12

ECLIPSE RESOURCES CORPORATION

NOTES TO BALANCE SHEETS

1. Nature of Operations

Eclipse Resources Corporation (the “Company”) was formed on February 13, 2014, pursuant to the laws of the State of Delaware to become a holding company for Eclipse Resources I, LP.

2. Summary of Significant Accounting Policies

The balance sheets have been prepared in accordance with accounting principles generally accepted in the United States (“U.S. GAAP”). Separate statements of operations, statements of changes in stockholders’ equity and statements of cash flows have not been presented because the Company has had no business transactions or activities to date.

3. Subsequent Events

Management has evaluated subsequent events through February 21, 2014 for the February 20, 2014 balance sheet and May 2, 2014 for the March 31, 2014 unaudited balance sheet and believes that there are no events that would have a material impact on the aforementioned financial statements and related disclosures through such dates.

4. Interim Financial Statement Presentation (Unaudited)

Basis of Presentation

The accompanying unaudited balance sheet as of March 31, 2014 is presented in accordance with the requirements of U.S. GAAP for interim reporting. They do not include all disclosures normally made and contained in annual financial statements. In management’s opinion, all adjustments necessary for a fair presentation of the Company’s financial position for the periods disclosed have been made.

F-13

ECLIPSE RESOURCES I, LP

CONSOLIDATED BALANCE SHEETS

(in thousands)

(Unaudited)


	March 31, 2014			December 31, 2013
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	27,328		$	109,509
Accounts receivable		30,369			8,678
Other current assets		270			594

Total current assets		57,967			118,781
PROPERTY AND EQUIPMENT, AT COST
Oil and natural gas properties, successful efforts method
Unproved properties		1,062,033			926,812
Proved properties		99,614			97,528
Accumulated depreciation, depletion and amortization		(20,553	)		(8,596	)

Total oil and natural gas properties, net		1,141,094			1,015,744
Other property and equipment, net		3,813			2,340

Total property and equipment, net		1,144,907			1,018,084
NONCURRENT ASSETS
Debt issuance costs, net of $1.1 million and $0.7 million of amortization, respectively		6,976			6,570
Other assets		1,443			88

Total noncurrent assets		8,419			6,658

TOTAL ASSETS	$	1,211,293		$	1,143,523

LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES
Accounts payable	$	40,309		$	29,368
Accrued capital expenditures		11,385			19,200
Accrued liabilities		7,445			4,940
Accrued interest payable		11,442			20,294
Accrued liabilities—related party		539			1,951

Total current liabilities		71,120			75,753
NONCURRENT LIABILITIES
Debt, net of unamortized discount of $10.2 million and $10.8 million, respectively		412,230			389,247
Credit facility		20,000			—
Pension liability		278			1,497
Asset retirement obligations		9,311			9,055

Total noncurrent liabilities		441,819			399,799
COMMITMENTS AND CONTINGENCIES
PARTNERS’ CAPITAL
Partners’ capital		698,048			666,803
Accumulated other comprehensive income		306			1,168

Total partners’ capital		698,354			667,971

TOTAL LIABILITIES AND PARTNERS’ CAPITAL	$	1,211,293		$	1,143,523

The accompanying notes are an integral part of these consolidated financial statements.

F-14

ECLIPSE RESOURCES I, LP

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands except per share data)

(Unaudited)


	For the Three Months Ended March 31,
	2014			2013
REVENUES
Oil and natural gas sales	$	24,788		$	288

Total revenues		24,788			288
OPERATING EXPENSES
Exploration		4,545			72
Lease operating		1,791			5
Transportation, gathering and compression		904			—
Production and ad valorem taxes		353			4
Depreciation, depletion and amortization		12,027			488
General and administrative		8,394			1,483
Accretion of asset retirement obligations		186			—
Gain on reduction of pension liability		(2,208	)		—

Total operating expenses		25,992			2,052

OPERATING LOSS		(1,204	)		(1,764	)
OTHER INCOME (EXPENSE)
Loss on derivative instruments		(3,611	)		—
Interest income (expense), net		(13,636	)		5

Total other income (expense), net		(17,247	)		5

NET LOSS	$	(18,451	)	$	(1,759	)


PRO FORMA INFORMATION (UNAUDITED)
Net loss	$	(18,451	)
Pro forma provision for income taxes		6,458

Pro forma net loss	$	(11,993	)

Pro forma loss per common share
Basic and diluted	$	(0.10	)
Weighted average pro forma shares outstanding
Basic and diluted		122,585

The accompanying notes are an integral part of these consolidated financial statements.

F-15

ECLIPSE RESOURCES I, LP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

(in thousands)

(Unaudited)


	For the Three Months Ended March 31,
	2014			2013
NET LOSS	$	(18,451	)	$	(1,759	)
Other comprehensive loss:
Pension obligation adjustment		(862	)		—

TOTAL COMPREHENSIVE LOSS	$	(19,313	)	$	(1,759	)

The accompanying notes are an integral part of these consolidated financial statements.

F-16

ECLIPSE RESOURCES I, LP

CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL

FOR THE THREE MONTHS ENDED MARCH 31, 2014

(in thousands)

(Unaudited)


	Total Partners’ Equity			Accumulated other comprehensive income			Total Partners’ Capital
BALANCE AT DECEMBER 31, 2013	$	666,803		$	1,168		$	667,971
Capital contributions		49,667			—			49,667
Incentive unit compensation		29			—			29
Net loss		(18,451	)		—			(18,451	)
Change in accumulated other comprehensive income		—			(862	)		(862	)

BALANCE AT MARCH 31, 2014	$	698,048		$	306		$	698,354

The accompanying notes are an integral part of these consolidated financial statements.

F-17

ECLIPSE RESOURCES I, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)


	For the Three Months Ended March 31,
	2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(18,451	)	$	(1,759	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		12,027			488
Accretion of asset retirement obligations		186			—
Exploration expense		4,545			72
Incentive unit compensation		29			—
Interest not paid in cash		13,609			—
Loss on derivative instruments		3,611			—
Net cash (payments) receipts on settled derivatives		(1,441	)		—
Amortization of deferred financing costs		406			—
Amortization of debt discount		522			—
Pension benefit costs		127			—
Gain on reduction of pension liability		(2,208	)		—
Changes in operating assets and liabilities, net of acquisitions:
Accounts receivable		(21,691	)		(72	)
Other assets		(1,031	)		(50	)
Accounts payable and accrued liabilities		11,276			1,502
Accrued liabilities—related parties		(1,412	)		51

Net cash provided by operating activities		104			232

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures on oil and natural gas properties		(149,597	)		(76,514	)
Additions to other property and equipment		(1,543	)		—
Proceeds from the sale of assets		—			7,303

Net cash used in investing activities		(151,140	)		(69,211	)

CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings under revolving credit facility		20,000			—
Debt issuance costs		(812	)		—
Capital contributions		49,667			58,136

Net cash provided by financing activities		68,855			58,136

Net decrease in cash and cash equivalents		(82,181	)		(10,843	)
Cash and cash equivalents at beginning of year		109,509			27,057

Cash and cash equivalents at end of year	$	27,328		$	16,214

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid for interest	$	—		$	—

Cash paid for income taxes	$	—		$	—

SUPPLEMENTAL DISCLOSURE OF NON-CASH ACTIVITIES:
Asset retirement obligations incurred, including changes in estimate	$	70		$	—

Additions to oil and natural gas properties—change in accrued capital expenditure	$	(7,815	)	$	1,337

Interest paid-in-kind	$	22,461		$	—

The accompanying notes are an integral part of these consolidated financial statements.

F-18

ECLIPSE RESOURCES I, LP

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

FOR THE THREE MONTHS ENDED MARCH 31, 2014 and 2013

(Unaudited)

Note 1—Organization and Nature of Operations

Eclipse Resources I, LP (“Eclipse I” or the “Partnership”) a Delaware limited partnership, was formed on January 20, 2011. Eclipse I is engaged in the acquisition and development of oil and natural gas properties in the Appalachian Basin of the United States, which encompasses the Utica Shale and Marcellus Shale prospective areas. The accompanying financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”).

Note 2—Basis of Presentation

The accompanying consolidated financial statements, which are unaudited except the balance sheet at December 31, 2013 which is derived from audited financial statements, are presented in accordance with the requirements of and accounting principles generally accepted in the United States (“U.S. GAAP”) for interim reporting. They do not include all disclosures normally made and contained in annual financial statements. In management’s opinion, all adjustments necessary for a fair presentation of the Partnership’s financial position, results of operations and cash flows for the periods disclosed have been made. These interim consolidated financial statements should be read in conjunction with the audited financial statements and notes thereto presented in the Partnership’s financial statements for the year ended December 31, 2013. The results of operations for the three months ended March 31, 2014 may not necessarily be indicative of the results of operations for the full year ending December 31, 2014.

Preparation in accordance with GAAP requires the Partnership to (1) adopt accounting policies within accounting rules set by the Financial Accounting Standards Board (“FASB”) and (2) make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and other disclosed amounts. Note 3—Summary of Significant Accounting Policies describes our significant accounting policies. Our management believes the major estimates and assumptions impacting our consolidated financial statements are the following:

•

estimates of proved reserves of oil and natural gas, which affect the calculations of depletion, depreciation and amortization and impairment of capitalized costs of oil and natural gas properties;

•

estimates of asset retirement obligations;

•

estimates of the fair value of oil and natural gas properties we own, particularly properties that we have not yet explored, or fully explored, by drilling and completing wells;

•

impairment of undeveloped properties and other assets; and

•

depreciation and depletion of property and equipment.

Actual results may differ from estimates and assumptions of future events and these revisions could be material. Future production may vary materially from estimated oil and natural gas proved reserves. Actual future prices may vary significantly from price assumptions.

Note 3—Summary of Significant Accounting Policies

(a) Cash and Cash Equivalents

Cash and cash equivalents are comprised of cash in banks and highly liquid instruments with original maturities of three months or less, primarily consisting of bank time deposits and investments in institutional money market funds. The carrying amounts approximate fair value due to the short-term nature of these items. Cash in bank accounts at times may exceed federally insured limits.

F-19

ECLIPSE RESOURCES I, LP

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

FOR THE THREE MONTHS ENDED MARCH 31, 2014 and 2013

(Unaudited)

(b) Accounts Receivable

Accounts receivable are carried at estimated net realizable value. Receivables deemed uncollectible are charged directly to expense. Trade credit is generally extended on a short-term basis and therefore, accounts receivable do not bear interest, although a finance charge may be applied to such receivables that are past due. A valuation allowance is provided for those accounts for which collection is estimated as doubtful; uncollectible accounts are written off and charged against the allowance. In estimating the allowance, management considers, among other things, how recently and how frequently payments have been received and the financial position of the party. The Partnership did not deem any of its accounts receivable uncollectable as of March 31, 2014 or December 31, 2013.

The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas and crude oil and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Partnership’s records and management’s estimates of the related commodity sales and transportation and compression fees which are, in turn, based upon applicable product prices. The Partnership had $20.9 million and $4.1 million of unbilled revenues at March 31, 2014 and December 31, 2013, respectively, which were included in accounts receivable within the Partnership’s balance sheet.

(c) Property and Equipment

Oil and Natural Gas Properties

The Partnership follows the successful efforts method of accounting for its oil and natural gas operations. Acquisition costs for oil and natural gas properties, costs of drilling and equipping productive wells, and costs of unsuccessful development wells are capitalized and amortized on an equivalent unit-of-production basis over the life of the remaining related oil and gas reserves. The estimated future costs of dismantlement, restoration, plugging and abandonment of oil and gas properties and related facilities disposal are capitalized when asset retirement obligations are incurred and amortized as part of depreciation, depletion and amortization expense (see “Depreciation, depletion and amortization (DD&A)” section below).

Costs incurred to acquire producing and non-producing leaseholds are capitalized. All unproved leasehold acquisition costs are initially capitalized, including the cost of leasing agents, title work and due diligence. If the Partnership acquires leases in a prospective area, these costs are capitalized as unproved leasehold costs. If no leases are acquired by the Partnership with respect to the initial costs incurred or the Partnership discontinues leasing in a prospective area, the costs are charged to exploration expense. These costs are reviewed regularly and a final determination for unproved leasehold costs is made within one year of the costs being incurred. Unproved leasehold costs that are determined to have proved oil and gas reserves are transferred to producing leasehold costs.

Upon the sale or retirement of a complete field of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to the Partnership’s consolidated statements of operations. Upon the sale of an individual well, the proceeds are credited to accumulated depreciation and depletion within the Partnership’s consolidated balance sheets. Upon sale of an entire interest in an unproved property where the property had been assessed for impairment individually, a gain or loss is recognized in the Partnership’s consolidated statements of operations. If a partial interest in an unproved property is sold, any funds received are accounted for as a reduction of the cost in the interest retained.

F-20

ECLIPSE RESOURCES I, LP

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

FOR THE THREE MONTHS ENDED MARCH 31, 2014 and 2013

(Unaudited)

A summary of property and equipment including oil and natural gas properties is as follows (in thousands):


	March 31, 2014			December 31, 2013
Oil and natural gas properties:
Proved	$	99,614		$	97,528
Unproved		1,062,033			926,812

Gross oil and natural gas properties		1,161,647			1,024,340
Less accumulated depreciation, depletion and amortization		(20,553	)		(8,596	)

Oil and natural gas properties, net		1,141,094			1,015,744
Other property and equipment		3,930			2,392
Less accumulated depreciation		(117	)		(52	)

Other property and equipment, net		3,813			2,340

Property and equipment, net	$	1,144,907		$	1,018,084

Exploration expenses, including geological and geophysical expenses and delay rentals for unevaluated oil and gas properties are charged to expense as incurred. Exploratory drilling costs are initially capitalized as unproved property, not subject to depletion, but charged to expense if and when the well is determined not to have found proved oil and gas reserves. Exploratory drilling costs are evaluated and a determination of classification is made within one-year from the completion of drilling. As of March 31, 2014 and December 31, 2013, there were no costs capitalized in connection with exploratory wells in progress.

Other Property and Equipment

(d) Revenue Recognition

Oil and natural gas sales revenue is recognized when produced quantities of oil and natural gas are delivered to a custody transfer point such as a pipeline, processing facility or a tank lifting has occurred, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sales is reasonably assured and the sales price is fixed or determinable. Revenues from the sales of natural gas, crude oil or natural gas liquids in which the Partnership has an interest with other producers are recognized using the sales method on the basis of the Partnership’s net revenue interest. The Partnership had no material imbalances as of March 31, 2014 and December 31, 2013.

In accordance with the terms of joint operating agreements, from time to time, the Partnership may be paid monthly fees for operating or drilling wells for outside owners. The fees are meant to recoup some of the operator’s general and administrative costs in connection with well and drilling operations and are accounted for as credits to general and administrative expense.

(e) Major Customers

The Partnership sells production volumes to various purchasers. For the three months ended March 31, 2014 and 2013, there were three customers and one customer, respectively, that accounted for 10% or more of total

F-21

ECLIPSE RESOURCES I, LP

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

FOR THE THREE MONTHS ENDED MARCH 31, 2014 and 2013

(Unaudited)

natural gas, natural gas liquids (NGLs) and oil sales. Management believes that the loss of any one customer would not have an adverse effect on the Partnership’s ability to sell natural gas, NGLs and oil production. The following table sets forth the Partnership’s major customers and associated percentage of revenue for the periods indicated:


	For the Three Months Ended March 31,
	2014			2013
Purchaser
Antero Resources Corporation		52	%		100	%
ARM Energy Management.		22	%		—	%
Magnum Hunter Marketing		17	%		—	%

Total		91	%		100	%

Management believes that there are potential alternative purchasers and that it may be necessary to establish relationships with new purchasers. However, there can be no assurance that the Partnership can establish such relationships or that those relationships will result in an increased number of purchasers. Although the Partnership is exposed to a concentration of credit risk, management believes that all of the Partnership’s purchasers are credit worthy.

(f) Concentration of Credit Risk

The following table summarizes concentration of receivables, net of allowances, by product or service as of March 31, 2014 and December 31, 2013 (in thousands):


	March 31, 2014		December 31, 2013
Receivables by product or service:
Sale of oil and natural gas and related products and services	$	20,912	$	4,092
Joint interest owners		9,457		4,586

Total	$	30,369	$	8,678

Oil and natural gas customers include pipelines, distributions companies, producers, gas marketers and industrial users primarily located in the Utica Shale. As a general policy, collateral is not required for receivables, but customers’ financial condition and credit worthiness are evaluated regularly.

By using derivative instruments that are not traded on an exchange 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 economic hedges in place with one counterparty. The fair value of our commodity derivative contract with Bank of Montreal is a loss position of approximately $2.6 million at March 31, 2014. We believe that this institution currently has an acceptable credit risk. Other than as provided by our revolving credit facility, we are not required to provide credit support or

F-22

ECLIPSE RESOURCES I, LP

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

FOR THE THREE MONTHS ENDED MARCH 31, 2014 and 2013

(Unaudited)

collateral to any of our counterparties under our contracts, nor are they required to provide credit support to us. As of March 31, 2014, we did not have past-due receivables from or payables to any of our counterparties.

(g) Accumulated Other Comprehensive Loss

Comprehensive loss includes net loss and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under GAAP, have not been recognized in the calculation of net loss. These changes, other than net loss, are referred to as “other comprehensive loss” and for the Partnership they include pension benefit plans that require an employer to (i) recognize the overfunded or underfunded status of a defined benefit retirement plan as an asset or liability in its balance sheet and (ii) recognize changes in that funded status in the year in which the changes occur through other comprehensive loss. The Partnership’s pension plan was under-funded by $0.3 million and $1.5 million at March 31, 2014 and December 31, 2013, respectively. The Partnership did not have a pension plan prior to the acquisition of Oxford on June 26, 2013 (see “Note 4” below). Effective March 31, 2014, benefit accruals in the plan were frozen resulting in a gain on reduction of pension liability of $2.2 million for the three months ended March 31, 2014.

(h) Depreciation, depletion and amortization (DD&A)

Oil and Natural Gas Properties

Depreciation, depletion, and amortization (DD&A) of capitalized costs of proved oil and natural gas properties is computed using the unit-of-production method on a unit level basis using total estimated proved reserves. The reserve base used to calculate DD&A for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. The reserve base used to calculate DD&A for drilling, completion and well equipment costs, which include development costs and successful exploration drilling costs, includes only proved developed reserves. DD&A expense for the three months ended March 31, 2014 and 2013 totaled approximately $11.95 million and $0.5 million, respectively.

Other Property and Equipment

Depreciation with respect to other property and equipment is calculated using straight-line methods based on expected lives of the individual assets or groups of assets ranging from 5 to 40 years. Depreciation for the three months ended March 31, 2014 totaled approximately $0.07 million and $0.5 million for the three months ended ended March 31, 2013. This amount is included in depreciation, depletion, and amortization expense in the statement of operations.

(i) Impairment of Long-Lived Assets

The Partnership reviews its long lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount for that asset to its estimated fair value if such carrying amount exceeds the fair value.

F-23

ECLIPSE RESOURCES I, LP

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

FOR THE THREE MONTHS ENDED MARCH 31, 2014 and 2013

(Unaudited)

future cash flow from the sale of production of reserves is calculated based on estimated future prices. The Partnership estimates prices based upon current contracts in place, adjusted for basis differentials and market related information including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets.

The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results.

Unproved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. An impairment charge is recorded if conditions indicate the Partnership will not explore the acreage prior to expiration of the applicable leases. There was no impairment of unproved oil and gas properties for the three months ended March 31, 2014 or 2013.

Proved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. There were no impairments of proved oil and gas properties recorded by the Partnership for the three months ended March 31, 2014 or 2013.

(j) Income Taxes

The Partnership is a limited partnership and is not subject to U.S. federal and most state income taxes. The partners of the Partnership are liable for any income taxes in regards to their distributive share of the Partnership’s taxable income. This taxable income may vary substantially from net income reported in the accompanying financial statements due to differences in accounting between U.S. income tax law and U.S. GAAP.

The FASB’s Accounting Standards Codification (“ASC”) Topic 740 “Income Taxes” provides that a tax benefit from an uncertain tax position may be recognized when it is more likely than not that the position will be sustained upon examination, including resolutions of any related appeals or litigation processes, based on the technical merits. Income tax positions must meet a more-likely-than-not recognition threshold at the effective date to be recognized upon the adoption of the uncertain tax position guidance and in subsequent periods. This interpretation also provides guidance on measurement, derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition.

Given the above discussion and the Partnership’s historical pass through status, the Partnership has determined that no federal or state income tax liability for uncertain tax positions is required to be recorded for the years presented in the accompanying financial statements.

(k) Fair Value of Financial Instruments

The Partnership has established a hierarchy to measure its financial instruments at fair value which requires it to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The hierarchy defines three levels of inputs that may be used to measure fair value:

Level 1—Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date.

F-24

ECLIPSE RESOURCES I, LP

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

FOR THE THREE MONTHS ENDED MARCH 31, 2014 and 2013

(Unaudited)

Level 2—Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market date for substantially the entire contractual term of the asset or liability.

Level 3—Unobservable inputs that reflect the entity’s own assumptions about the assumption market participants would use in the pricing of the asset or liability and are consequently not based on market activity but rather through particular valuation techniques.

The estimated fair values of the Partnership’s financial instruments closely approximate the carrying amounts due, including long-term debt, based on their recent issuance by the Company.

Valuation techniques that maximize the use of observable inputs are favored. Assets and liabilities are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy.

(l) Derivative Financial Instruments and Hedging Activities

The Partnership uses derivative financial instruments to reduce exposure to fluctuations in the prices of natural gas. These transactions are in the form of swaps and put spreads.

The Partnership’s derivative instruments were not designated as hedges for accounting purposes for any of the periods presented. Accordingly, the changes in fair value are recognized in the consolidated statement of operations in the period of change. Gains and losses on derivatives are included in cash flows from operating activities. Premiums paid for put options are included in cash flows from operating activities.

(m) Asset Retirement Obligation

The Partnership recognizes a legal liability for its asset retirement obligations (“ARO”) in accordance with Topic ASC 410, “Asset Retirement and Environmental Obligations,” associated with the retirement of a tangible long-lived asset, in the period in which it is incurred or becomes determinable, with an associated increase in the carrying amount of the related long-lived asset. The cost of the tangible asset, including the initially recognized asset retirement cost, is depreciated over the useful life of the asset and accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. The Partnership measures the fair value of its ARO using expected future cash outflows for abandonment discounted back to the date that the abandonment obligation was measured using an estimated credit adjusted rate, which was 8.96% for the three months ended March 31, 2104.

Estimating the future ARO requires management to make estimates and judgments based on historical estimates regarding timing and existence of a liability, as well as what constitutes adequate restoration. Inherent in the fair value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset.

F-25

ECLIPSE RESOURCES I, LP

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

FOR THE THREE MONTHS ENDED MARCH 31, 2014 and 2013

(Unaudited)

The following table sets forth the changes in the Partnership’s ARO liability for the period indicated (in thousands):


	Three Months Ended March 31, 2014
Asset retirement obligations, beginning of period	$	9,055
Additional liabilities incurred		70
Accretion		186

Asset retirement obligations, end of period	$	9,311

The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition. Additions to ARO represent a significant nonrecurring Level 3 measurement.

(n) Lease Obligations

The Partnership leases office space under an operating lease that expires in 2018. The lease term begins on the date of initial possession of the leased property for purposes of recognizing lease expense on a straight-line basis over the term of the lease. The Partnership does not assume renewals in its determination of the lease term unless the renewals are deemed to be reasonably assured at lease inception.

(o) Off-Balance Sheet Arrangements

The Partnership does not have any off-balance sheet arrangements.

(p) Segment Reporting

The Partnership operates in one industry segment: the oil and natural gas exploration and production industry in the United States. All of its operations are conducted in one geographic area of the United States. All revenues are derived from customers located in the United States.

(q) Debt Issuance Costs

The expenditures related to issuing debt are capitalized and included in other assets in the accompanying balance sheets. These costs are amortized over the expected life of the related instruments using the effective interest rate method. When debt is retired before maturity or modifications significantly change the cash flows, related unamortized costs are expensed.

(r) Recent Accounting Pronouncements

The FASB issued ASU 2013-11, “Income Taxes (Topic 740)—Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists” in December 2013. These amendments provide that an unrecognized tax benefit, or a portion thereof, should be presented in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward, except to the extent that a net operating loss carryforward, a similar tax loss, or a tax credit carryforward is not available at the reporting date to settle any additional income taxes

F-26

ECLIPSE RESOURCES I, LP

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

FOR THE THREE MONTHS ENDED MARCH 31, 2014 and 2013

(Unaudited)

that would result from disallowance of a tax position, or the tax law does not require the entity to use, and the entity does not intend to use, the deferred tax asset for such purpose, then the unrecognized tax benefit should be presented as a liability. The adoption of this ASU did not impact the Partnership’s financial position, results of operations or liquidity.

The FASB issued ASU 2014-06, “Technical Corrections and Improvements Related to Glossary Terms”. These amendments relate to glossary terms and cover a wide range of Topics in the Codification. These amendments are presented in four sections: 1) Deletion of Master Glossary Terms arising because of terms that were carried forward from source literature to the Codification but were not utilized in the Codification; 2) Addition of Master Glossary Term Links arising from Master Glossary terms whose links did not carry forward to the Codification; 3) Duplicate Master Glossary Terms arising from Master Glossary terms that appear multiple times in the Master Glossary with similar, but not identical, definitions; and 4) Other Technical Corrections Related to Glossary Terms arising from miscellaneous changes to update Master Glossary terms. The adoption of this ASU did not impact the Partnership’s financial position, results of operations or liquidity.

Note 4—Acquisition

The Eclipse Resources-Ohio, LLC Acquisition

On June 26, 2013, the Partnership acquired 100% of the outstanding equity interests of Oxford. Oxford holds interests in approximately 181,000 net acres of Utica Shale leaseholds, and related producing properties located primarily in Belmont, Guersney, Monroe, Noble, and Harrison Counties in Ohio along with various other related rights, permits, contracts, equipment and other assets. The aggregate purchase price totaled $652.5 million in cash. The acquisition provided strategic additions adjacent to the Partnership’s core project area. The acquisition contributed revenue of $3.4 million to Eclipse I for the three months ended March 31, 2014.

The Purchase and Sales Agreement (“PSA”) contained customary closing conditions and a $32.5 million escrow which was withheld from the initial purchase price to provide for certain contingencies. The notice period for any claims related to these contingencies expires June 25, 2014. The acquisition is accounted for using the acquisition method under ASC Topic 805, “Business Combinations” which requires the acquired assets and liabilities to be recorded at fair values as of the acquisition date of July 26, 2013. The following table summarizes the preliminary purchase price allocation and the values of assets acquired and liabilities assumed and is subject to finalization (in thousands):


Purchase Price	June 26, 2013
Consideration Given
Cash	$	652,500

Allocation of Purchase Price
Unproved properties		621,039
Proved properties		40,914
Cash		653
Building and land		1,500

Total assets		664,106
Asset retirement obligations		(8,378	)
Pension obligation		(2,522	)
Other working capital		(706	)

Fair value of net assets acquired	$	652,500

F-27

ECLIPSE RESOURCES I, LP

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

FOR THE THREE MONTHS ENDED MARCH 31, 2014 and 2013

(Unaudited)

The purchase price allocation set forth above represented a significant Level 3 measurement in the fair value hierarchy and was derived in accordance with ASC 805 by an outside third party. The inputs used in such determination were forecasted cash flows, market comparisons, actuarial studies and Oxford’s historical accounting records.

Oxford is party to various lawsuits, primarily related to the validity of certain oil and gas leases. (see “Note 10”).

Pro Forma Financial Information (unaudited)

The following unaudited pro forma financial information represents the combined results for the Partnership and Oxford for the three months ended March 31, 2013, as if the acquisition had occurred on January 1, 2012. The pro forma information includes the effects of adjustments for depletion, depreciation, amortization and accretion expense of $3.2 million for the three months ended March 31, 2013. The pro forma information includes the effects of adjustments for amortization of financing costs of $0.2 million for three months ended March 31, 2013. The pro forma information includes the effects of the amortization of debt discount of $0.3 million for the three months ended March 31, 2013. The pro forma information includes the effects of the incremental interest expense on acquisition financing of $5.2 million for the three months ended March 31, 2013. The pro forma results do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by the Partnership to integrate the properties acquired. The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of January 1, 2012, nor are they necessarily indicative of future results (in thousands).


	For the Three Months Ended March 31, 2013
Oil and natural gas sales	$	4,139
Net loss		(8,991	)

Note 5—Derivative Instruments

Commodity derivatives

The Partnership periodically uses derivative instruments to manage it exposure to cash-flow variability from commodity price risk inherent in its production. These include over-the-counter (“OTC”) swaps and put option spreads. Swaps are settled monthly based on differences between the prices specified in the instruments and the settlement prices of futures contracts. Generally, when the applicable settlement price is less than the price specified in the contract, the Partnership receives a settlement from the counterparty based on the difference multiplied by the volume or amounts hedged. Similarly, when the applicable settlement price exceeds the price specified in the contract, the Partnership pays the counterparty based on the difference. A put option spread is the combination of a purchased put and a sold put. The purchased put establishes the minimum price that Partnership will receive for the contracted volumes unless the market price for the commodity falls below the sold put strike price, at which point the minimum price equals the reference price plus the excess of the purchased put strike price over the sold put strike price. The following summarizes the Partnership’s derivatives outstanding at March 31, 2014.

F-28

ECLIPSE RESOURCES I, LP

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

FOR THE THREE MONTHS ENDED MARCH 31, 2014 and 2013

(Unaudited)

For the remainder of 2014, the Partnerships derivative activity is as follows:


Description	Notional (MMbtu)		Weighted Average Strike Price
Natural gas swap agreements		5,500,000	$	4.18
Natural gas put spread agreements		4,280,000	$	4.00 - 4.50

For 2015, the Partnerships derivative activity is as follows:


Description	Notional (MMbtu)		Weighted Average Strike Price
Natural gas swap agreements		7,300,000	$	4.09

All of the Partnership’s derivative financial instruments are used for risk management purposes, none are held for trading or speculative purposes and its derivative financial instruments are with parties that are lenders under its bank credit facility. The Partnership is not required to provide any credit support to its counterparties other than cross collateralization with the assets securing its bank credit facility. The Partnership has an unrealized deferred premium that is settled over the life of the natural gas put spread agreements totaling $1.0 million.

None of the derivative contracts have been designated as cash flow hedges. Eclipse I recognizes the gains and losses of its derivative financial instruments as separate components of other income (expenses). The Partnership had losses on its derivative financial instruments of $3.6 million during the three months ended March 31, 2014 and did not have any derivative financial instruments in place during the three months ended March 31, 2013. The estimated fair value of the Partnership’s derivative financial instruments was a current liability of $1.2 million as of March 31, 2014 based on estimated settlement dates, and is recorded in accrued liabilities on the consolidated balance sheet. At December 31, 2013 Eclipse I did not have any derivative financial instruments in place.

The following table presents the Partnership’s net exposure from its offsetting derivative asset and liability positions as of the reporting dates indicated (in thousands):


	Gross Amounts			Netting Adjustments(a)			Net Amount Presented in the Consolidated Balance Sheets
March 31, 2014
Derivative instrument assets with right of offset or master netting agreements	$	1,475		$	(1,475	)	$	—
Derivative instrument liabilities with right of offset or master netting agreements	$	(2,639	)	$	1,475		$	(1,164	)

(a)

The Partnership has agreements in place that allow for the financial right of offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements.

F-29

ECLIPSE RESOURCES I, LP

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

FOR THE THREE MONTHS ENDED MARCH 31, 2014 and 2013

(Unaudited)

Note 6—Fair Value Measurements

Fair Value Measurement on a Recurring Basis

The following table presents, by level within the fair value hierarchy, the Partnership’s assets and liabilities that are measured at fair value on a recurring basis (in thousands). The carrying amounts reported in the consolidated balance sheets for cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the nature of the instrument and/or the short-term maturity of these instruments.


	Level 1		Level 2			Level 3		Total fair value
As of March 31, 2014:
Commodity derivative instruments	$	—	$	(1,164	)	$	—	$	(1,164	)

Total	$	—	$	(1,164	)	$	—	$	(1,164	)

The Partnership did not have any open commodity derivative instruments as of December 31, 2013.

Nonfinancial Assets and Liabilities

Assets and liabilities acquired in business combinations are recorded at their fair value on the date of acquisition. Significant Level 3 assumptions associated with the calculation of future cash flows used in the analysis of fair value of the oil and natural gas property acquired include the Partnership’s estimate of future commodity prices, production costs, development expenditures, production, risk-adjusted discount rates, and other relevant data. Additionally, fair value is used to determine the inception value of the Partnership’s AROs. The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition. Additions to the Partnership’s ARO represent a nonrecurring Level 3 measurement.

The estimated fair values of the Partnership’s financial instruments closely approximate the carrying amounts due, including long-term debt.

The Partnership reviews its proved oil and natural gas properties for impairment purposes by comparing the expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset. Significant assumptions associated with the calculation of future cash flows used in the impairment analysis include the estimate of future commodity prices, production costs, development expenditures, production, risk-adjusted discount rates and other relevant data. As such, the fair value of oil and natural gas properties used in estimating impairment represents a nonrecurring Level 3 measurement.

Note 7—Debt

12% Senior Unsecured PIK Notes Due 2018

On June 26, 2013, Eclipse I completed a private placement offering of an initial aggregate principal amount of $300 million, with an additional $100 million notes option, at the discretion of the Partnership, of 12% Senior Unsecured PIK Notes due in 2018 (the “Senior Notes”). The Senior Notes were issued at 96% of par and Eclipse I received $280.7 million of net cash proceeds, after deducting the discount to initial purchasers of $12 million and offering expenses of $7.3 million. In December 2013, the Partnership exercised its option and issued an additional $100 million of Senior Notes with the same terms, at par. The Partnership received $100 million net

F-30

ECLIPSE RESOURCES I, LP

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

FOR THE THREE MONTHS ENDED MARCH 31, 2014 and 2013

(Unaudited)

cash proceeds, as no discounts and $0.2 million of offering expenses were incurred in connection with the exercise of the option. During the three months ended March 31, 2014, Eclipse amortized $0.9 million of deferred financing costs and debt discount to interest expense using the effective interest method.

We have the right to redeem all or a portion of the Senior Unsecured Notes prior to the 2-year anniversary of the final funding date, which we refer to as the Non-Call Period, by paying a redemption price equal to 100.0% times a “make whole premium” equal to the greater of 106.0% or an amount computed under the indenture governing the Senior Unsecured Notes plus accrued and unpaid interest. After the Non-Call Period, we may redeem all or a part of the Senior Unsecured Notes at the redemption prices (expressed as percentages of principal amount) set forth below, plus accrued and unpaid interest:


Year following expiration of the Non-Call Period	Redemption Price
Year 1		106.00	%
Year 2		103.00	%
Year 3 and thereafter		100.00	%

At the Partnership’s option, for the first 2 semi-annual interest payments following the Issue Date, interest may be payable by increasing the principal amount of the Senior Notes or by issuing payment in kind (“PIK”) securities. At the Partnership’s option, for the subsequent four semi-annual interest payments thereafter, interest may be payable in the form of 6.0% per annum in cash and 7.0% per annum in PIK securities. Thereafter, interest can only be paid as cash interest. Interest is payable on July 15 and January 15 each year, beginning in January 2014. Interest paid by issuing PIK securities accrues at 13%, interest paid by cash accrues at 12%. The Partnership elected to settle its accrued interest payable of $22.5 million with PIK Securities on January 15, 2014. As of March, 2014, the Partnership had accrued additional PIK interest in the amount of $11.4 million. The Partnership capitalized interest expense totaling $0.8 million for the three months ended March 31, 2014.

The Partnership’s obligations under the Senior Notes are guaranteed by its 100% owned subsidiaries. The Partnership may not among other things, directly or indirectly: (1) consolidate or merge with or into another Person (whether or not the Partnership is the survivor), or (2) sell, assign, transfer, convey, lease or otherwise dispose of all or more than 50% of its properties or assets, in one or more related transactions, to another Person, unless in each case certain restrictive conditions contained in the Indenture are met.

The indenture governing the Senior Notes requires the Partnership to be in compliance with certain other covenants, including the prompt payment of interest, including PIK interest; any and all material taxes, assessments and government levies imposed; timely submission of quarterly and audited annual financial statements; reserve reports, budgets; and other notices; along with meeting other recurring obligations. The indenture governing the Senior Notes also places restrictions on Eclipse I and its subsidiaries with respect to additional indebtedness, liens, dividends and other payments, investments, acquisitions, mergers, asset dispositions, transactions with affiliates, change of control and other matters. The Partnership was in compliance with its covenants at March 31, 2014.

The Senior Notes are subject to certain events of default. If an event of default occurs and is continuing, the outstanding Senior Notes may, and under certain circumstances, will be accelerated. The purchasers of the Senior Notes are entitled to the benefits of a registration rights agreement pursuant to which the Partnership agreed to file a registration statement with the Securities and Exchange Commission to allow for the resale of the Notes under the Securities Act.

F-31

ECLIPSE RESOURCES I, LP

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

FOR THE THREE MONTHS ENDED MARCH 31, 2014 and 2013

(Unaudited)

Revolving Credit Facility

During the first quarter of 2014, the Company put in place a $500 million senior secured revolving bank credit facility (the Credit Facility) with two bank lenders that matures in 2018. Borrowings under the Credit Facility are subject to borrowing base limitations based on the collateral value of the Company’s proved properties and commodity hedge positions and are subject to quarterly redeterminations through April 1, 2015 and semiannual redeterminations thereafter. At March 31, 2014, the borrowing base was $50 million and the Company had outstanding borrowings of $20 million at a weighted average interest rate of 1.99%. Effectively the Company had unused capacity of $30 million at March 31, 2014.

The Credit Facility is secured by mortgages on substantially all of the Company’s properties and guarantees from the Company’s operating subsidiaries. The Credit Facility contains certain covenants, including restrictions on indebtedness and dividends, and requirements with respect to working capital and interest coverage ratios. Interest is payable at a variable rate based on LIBOR or the prime rate based on the Company’s election at the time of borrowing. The Company was in compliance with all of the covenants under the Credit Facility as of March 31, 2014. Commitment fees on the unused portion of the Credit Facility are due quarterly at rates ranging from 0.375% to 0.50% of the unused facility based on utilization.

Note 8—Benefit Plans

The Partnership maintains a defined benefit pension plan covering 34 of its employees, of which two are retired, four have deferred vested termination, and one is a survivor. Benefits are based on the employee’s years of service and compensation. The Partnership’s plans are funded in conformity with the funding requirements of ASC 715 as of March 31, 2014. As a result of the Oxford acquisition (refer to “Note 4” above) on June 26, 2013, the Partnership assumed the defined benefit pension plan, and therefore, no pension benefit plan was in effect prior to such date. Effective March 31, 2014, benefit accruals in the plan were frozen resulting in a gain on reduction of pension liability of $2.2 million for the three months ended March 31, 2014.

The authoritative guidance for defined benefit pension plans requires an employer to recognize the overfunded or underfunded status as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through other comprehensive income.

F-32

ECLIPSE RESOURCES I, LP

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

FOR THE THREE MONTHS ENDED MARCH 31, 2014 and 2013

(Unaudited)

A summary of the pension benefit as of the three months ended March 31, 2014 is set forth in the below tables (in thousands):


Change in benefit obligation
Benefit obligation at beginning of year	$	9,018
Service cost		70
Interest cost		107
Gain on reduction of pension liability		(2,137	)
Actuarial loss		717
Benefits paid		(16	)

Benefit obligation at end of period	$	7,759

Change in plan assets
Fair value of plan assets at beginning of year	$	7,521
Actual return on plan assets		(24	)
Benefit paid		(16	)

Fair value of plan assets at March 31, 2014	$	7,481

The funding level of the qualified pension plan is in compliance with standards set by applicable law or regulation. As shown in the table below, the current pension plan is underfunded. All defined benefit pension obligations, regardless of the funding status of the plan, are fully supported by the financial strength of the Partnership.


Assets in excess of (less than) benefit obligation at March 31, 2014
Vested amount	$	(7,759	)
Additional benefits required		—

Projected benefit obligation		(7,759	)
Funded amount		7,481

Unfunded amount	$	(278	)


Other amounts recognized in other comprehensive loss during the year ended March 31, 2014
Assets in excess of (less than) benefit obligation at end of period	$	(278	)
Amounts recorded in the consolidated balance sheet consist of:
Accrued benefit liability		(278	)

Total recorded	$	(278	)

Beginning amount recorded in other accumulated comprehensive income		1,168

Amounts recorded in accumulated other comprehensive loss consist of:
Pension obligation adjustment	$	(862	)

Total recorded in accumulated other comprehensive income	$	306

F-33

ECLIPSE RESOURCES I, LP

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

FOR THE THREE MONTHS ENDED MARCH 31, 2014 and 2013

(Unaudited)

The long-term expected rate of return on funded assets shown below is established for each benefit plan by developing a forward-looking, long-term return assumption for each asset class, taking into account factors such as the expected real return for the specific asset class and inflation. A single, long-term rate of return is then calculated as the weighted average of the target asset allocation percentages and the long-term return assumption for each asset class. The discount rate is determined by constructing a portfolio of high-quality, noncallable bonds with cash flows that match estimated outflows for benefit payments.


Weighted average assumptions to determine benefit obligation at March 31, 2014
Discount rate		4.25	%
Expected rate of return		6.00	%
Rate of compensation increase		N/A
Inflation		3.00	%
Components of net periodic benefit cost for the year ended March 31, 2014
Service cost	$	70
Interest cost		107
Expected return on plan assets		(112	)
Amortization of transition obligation		70
Amortization of net (gain) loss		(8	)

Net period benefit cost	$	127

The following benefit payments are expected to be paid over the next ten years (in thousands):


2014	$	50
2015		49
2016		98
2017		161
2018		202
2019—2023	$	2,082

The Partnership’s investment strategy for benefit plan assets reflects a long-term view, a careful assessment of the risks inherent in various asset classes and broad diversification to reduce the risk of the portfolio. The Partnership, along with its investment manager, determines the investment policies and strategies for the plan assets to determine the allocations to the various asset classes based on the results of the studies targeted percentages. The following tables below set forth the breakout of asset categories as of March 31, 2014 (in thousands):


Plan assets by category
Equity securities		—
Debt securities		7,363
Cash		118

Total Assets	$	7,481

Plan assets by category
Equity securities		N/A
Debt securities		98.4	%
Cash		1.6	%

Total Assets		100	%

F-34

ECLIPSE RESOURCES I, LP

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

FOR THE THREE MONTHS ENDED MARCH 31, 2014 and 2013

(Unaudited)

The following tables set forth by level, within the fair value hierarchy, the fair value of pension assets and liabilities as of March 31, 2014 (in thousands):


	March 31, 2014
	Level 1		Level 2		Level 3		Total
Pension assets	$	7,153		328		—	$	7,481

The fair value measurement levels are accounting terms that refer to different methods of valuing assets. The terms do not represent the relative risk or credit quality of an investment.

Note 9—Equity

The Partnership has four classes of Partnership interests outstanding consisting of three classes (Class A-1, A-2, and B) designated for investments of capital into the Partnership and two series (Series C-1 and Series C-2) that are authorized to be issued to key employees of the Partnership. None of the classes of outstanding units are entitled to current cash distributions or are convertible into indebtedness. The Partnership has no obligation to repurchase these units at the election of the unitholders. Profits or losses are allocated to each class of units based on the agreement of limited partnership. Upon an Exit Event, as defined below, each class of units will share in the distribution based on the terms of the partnership agreement.

The following tables set forth the Class A-1, A-2 and B units issued and outstanding (in thousands):


	March 31, 2014
	Units Authorized		Units Issued
Units
A-1		3,896		3,896
A-2		5,427		5,427
B		104		104

Total Units		9,427		9,427


	March 31, 2013
	Units Authorized		Units Issued
Units
A-1		1,934		1,934
A-2		—		—
B		60		52

Total Units		1,994		1,986

During the three months ended March 31, 2014, the Company issued 0.5 million units of A-2 units for $49.7 million.

The Partnership has a total of 1,000 Class C-1 units and 1,000 Class C-2 units authorized to be issued to employees (“Incentive Units”). The Incentive Units are non-voting and do not entitle the holder to any rights with respect Partnership matters. The Incentive Units may participate in distributions of the profits from a sale of Partnership interests only after certain payout thresholds to the Class A-1, Class A-2 and Class B units have been reached, in the case of the Class C units.

F-35

ECLIPSE RESOURCES I, LP

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

FOR THE THREE MONTHS ENDED MARCH 31, 2014 and 2013

(Unaudited)

The Incentive Units were issued with one of two vesting scenarios, either (i) in one-third increments or (ii) vesting at the earlier of (a) an “Exit Event” or (b) seven years. An Exit Event has been defined as the sale of the Partnership, to one or more persons, in one transaction or a series of related transactions, whether structured as (i) a sale or transfer of all or substantially all of the Partnership Interests of the Partnership (including by way of merger, consolidation, share exchange, or similar transaction), (ii) the sale or other transfer of all or substantially all of the assets of the Partnership promptly followed by a dissolution and liquidation of the Partnership, or (iii) a combination of any of the foregoing. The Corporate Reorganization and the offering will not constitute an Exit Event. In the event an employee terminates his or her employment with the Partnership prior to vesting, the non-vested Incentive Units will be forfeited by the holder. Compensation expense for these awards is calculated based on the fair value of the Incentive Units at the date of grant and is recognized over the requisite service period.

A summary of the Incentive Unit awards as of March 31, 2014 and 2013, along with the changes during the periods then ended, is as follows:


	2014					2013
	C-1 Units			Weighted Average Grant Date Fair Value per unit		C-1 Units			Weighted Average Grant Date Fair Value per unit
Nonvested at December 31,		560		$	131		794		$	48
Granted		—			—		15			629
Vested		(283	)		30		(55	)		24
Forfeited		(20	)		965		—			—

Nonvested at March 31,		257		$	274		754		$	61


	2014					2013
	C-2 Units			Weighted Average Grant Date Fair Value		C-2 Units		Weighted Average Grant Date Fair Value
Nonvested at December 31,		182		$	2,501		—	$	—
Granted		30			11,883		30		—
Vested		(12	)		1,943		—		—
Forfeited		(13	)		1,174		—		—

Nonvested at March 31,		187		$	3,590		30	$	—

Total compensation cost related to the Incentive Units was $0.3 million and $0.1 million for three months ended March 31, 2014 and 2013, respectively. As of March 31, 2014, there was $0.8 million of total unrecognized compensation cost related to Incentive Units, which is expected to be recognized over a weighted-average period of 6.45 years.

The determination of the fair value of the awards noted above uses significant Level 3 assumptions in the fair value hierarchy including an estimate of the timing of an Exit Event, forfeitures, the risk free rate and a volatility estimate tied to the Partnership’s public peer group.

F-36

ECLIPSE RESOURCES I, LP

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

FOR THE THREE MONTHS ENDED MARCH 31, 2014 and 2013

(Unaudited)

Note 10—Related Party Transactions

The President and Chief Executive Officer of Eclipse I, its Executive Vice President, Secretary, and General Counsel and its Executive Vice President and Chief Operating Officer, each own 33% of the membership units of Eclipse Resources Operating, LLC (“Eclipse Operating”), a Delaware limited liability company that provides administrative and management services to the Partnership under the terms of an Administrative Services Agreement. Each of the members of Eclipse Operating also controls entities that own the Class B units in the Partnership.

Under the terms of the Administrative Services Agreement, the Partnership pays Eclipse Operating a monthly management fee equal to the sum of all general and administrative expenditures incurred in the management and administration of the Partnership’s operations. These costs include salaries, wages and benefits, rent, insurance, and other expenses and costs required to operate the Partnership. These expenses are billed in arrears at the actual cost to Eclipse Operating.

The Partnership considered the requirements of ASC Topic 810 “Consolidation” and determined Eclipse Operating to be a variable interest entity. The variable interest primarily relates to the administrative agreement between the two entities and the management fee charged for the services provided by Eclipse Operating to the Partnership equal to the actual expenditures incurred for such operations. The Partnership has concluded it is not the primary beneficiary of the variable interest entity. During the three months ended March 31, 2014 and 2013, the Partnership’s management fee to Eclipse Operating was $7.8 million and $1.3 million, respectively, classified as within “General and Administrative expenses” in the consolidated statements of operations.

Note 11—Commitments and Contingencies

(a) Legal Matters

West Matter

“West lawsuit”). The lawsuit was filed after the defendant landowners prevented Oxford from drilling a well on the property subject to the oil and gas lease. Oxford brought claims for breach of contract, unjust enrichment, and promissory estoppel, and sought a declaratory judgment that Oxford had a valid and enforceable lease with the defendant landowners. The defendant landowners filed counterclaims for defective execution of the lease, fraud, bad faith, breach of the implied duty to develop, improper assignment of the lease, and a claim that the lease was void as a lease in perpetuity contrary to law and the public policies of the State of Ohio. Oxford filed a motion for summary judgment on July 15, 2013, and the defendant landowners filed their motion for summary judgment on August 26, 2013. On October 4, 2013, the trial court granted the defendant’s motion for summary judgment and held that the lease in question was “void ab initio” because the lease is a “no-term lease” and a “lease in perpetuity.” On October 8, 2013, the Partnership appealed the trial court’s judgment to the Seventh District Court of Appeals of the State of Ohio.

F-37

ECLIPSE RESOURCES I, LP

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

FOR THE THREE MONTHS ENDED MARCH 31, 2014 and 2013

(Unaudited)

ruling and if other courts in Ohio adopt a similar interpretation of the language in our other leases with similar term language, such leases may also be determined to be void if the lessor challenges the validity of the lease. Consequently, this could result in a loss of the mineral rights and an impairment of the related assets which could have a material adverse impact on the Partnership’s financial statements. The Partnership had $7.5 million in capitalized leasehold costs associated with West related lawsuits at March 31, 2014. These costs could potentially be impaired if it was determined that the West lawsuit leases were invalid. Other than this potential impairment, the Partnership is not able to estimate the range of other potential losses related to this matter.

The Partnership believes that there are strong grounds for appeal, and therefore, the Partnership intends to pursue all available appellate rights, and to vigorously defend against the claims in this lawsuit. Based on the merits of the appeal, the Partnership believes that it is not probable that trial court’s decision will be upheld in the appeal or that the Partnership will incur a material loss in the lawsuit. The Partnership has not recorded an accrual for the potential losses attributable to this lawsuit.

Other Matters

From time to time, the Partnership may be a party to legal proceedings arising in the ordinary course of business. Management does not believe that a material loss is probable as a result of such proceedings.

(b) Environmental Matters

The Partnership is subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes environmental protection requirements that result in increased costs to the oil and natural gas industry in general, the business and prospects of the Partnership could be adversely affected.

(c) Leases

The development of the Partnership’s oil and natural gas properties under their related leases will require a significant amount of capital. The timing of those expenditures will be determined by the lease provisions, the term of the lease and other factors associated with unproved leasehold acreage. To the extent that the Partnership is not the operator of oil and natural gas properties that it owns an interest in, the timing, and to some degree the amount, of capital expenditures will be controlled by the operator of such properties.

The Partnership entered into a lease agreement for office space for the corporate headquarters in April 2013 with a current term of five years, ending April 2018. This lease includes an option to cancel the lease if the landlord does not deliver additional space within one year. Rent expense related to the lease agreement for the three months ended March 31, 2014 and 2013 was $0.02 million and $0.03 million, respectively.

Note 12—Subsequent Events

As of April 29, 2014, the borrowing base of the Company’s senior secured revolving bank credit facility of $50 million was increased to $100 million.

Management has evaluated subsequent events through May 2, 2014 and believes that there are no events that would have a material impact on the aforeme.ntioned financial statements and related disclosures.

F-38

ECLIPSE RESOURCES I, LP

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

FOR THE THREE MONTHS ENDED MARCH 31, 2014 and 2013

(Unaudited)

Note 13—Unaudited Pro Forma Net Income Per Share

Pro forma basic and diluted net income per share have been computed to give effect to the termination of the limited partnership status and conversion to C-corporation status in connection with the initial public offering, which changes the provision for income taxes for each period presented. We assume a blended statutory federal, state and local income tax rate of 35% in 2014. The annual pro forma provisions for income taxes are estimated using the asset and liability method. This approach recognizes the amount of federal, state and foreign income taxes payable or refundable each year, as well as deferred tax assets and liabilities that result from differences between the carrying amounts of existing assets and liabilities in the consolidated financial statements and their respective tax bases, with adjustments for net operating losses and tax credit carryforwards applicable to specific tax jurisdictions and operating subsidiaries, if any. The interim pro forma provisions for income taxes are presented using an estimate of the effective tax rate expected to be applicable for the year presented, which is based on actual results for the interim period and management’s estimate of income before provision for income taxes for the entire tax year. The estimated annual effective tax rate is then applied to income before provision for income taxes for the interim period.

F-39

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Managers and Unitholders

Eclipse Resources I, LP

We have audited the accompanying consolidated balance sheets of Eclipse Resources I, LP (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of December 31, 2013 and 2012, and the related consolidated statements of operations, comprehensive loss, changes in partners’ capital and cash flows for each of the two years in the period ended December 31, 2013. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Partnership’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Eclipse Resources I, LP and subsidiaries as of December 31, 2013 and 2012 and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2013 in conformity with accounting principles generally accepted in the United States of America.

/s/ GRANT THORNTON LLP

Cleveland, Ohio

February 21, 2014

F-40

ECLIPSE RESOURCES I, LP

CONSOLIDATED BALANCE SHEETS

(in thousands)


	December 31,
	2013			2012
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	109,509		$	27,057
Accounts receivable		8,678			172
Other current assets		594			—

Total current assets		118,781			27,229
PROPERTY AND EQUIPMENT, AT COST
Oil and natural gas properties, successful efforts method
Unproved properties		926,812			99,671
Proved properties		97,528			6,986
Accumulated depreciation, depletion and amortization		(8,596	)		(404	)

Total oil and natural gas properties, net		1,015,744			106,253
Other property and equipment, net		2,340			—

Total property and equipment, net		1,018,084			106,253
NONCURRENT ASSETS
Debt issuance cost, net of $0.7 million of amortization		6,570			—
Other assets		88			40

Total noncurrent assets		6,658			40

TOTAL ASSETS	$	1,143,523		$	133,522

LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES
Accounts payable	$	29,368		$	3,934
Accrued capital expenditures		19,200			826
Accrued liabilities		4,940			1,663
Accrued interest payable		20,294			—
Accrued liabilities—related party		1,951			382

Total current liabilities		75,753			6,805
NONCURRENT LIABILITIES
Debt, net of unamortized discount of $10.8 million		389,247			—
Pension liability		1,497			—
Asset retirement obligations		9,055			13

Total noncurrent liabilities		399,799			13
COMMITMENTS AND CONTINGENCIES
PARTNERS’ CAPITAL
Partners’ capital		666,803			126,704
Accumulated other comprehensive income		1,168			—

Total partners’ capital		667,971			126,704

TOTAL LIABILITIES AND PARTNERS’ CAPITAL	$	1,143,523		$	133,522

The accompanying notes are an integral part of these consolidated financial statements.

F-41

ECLIPSE RESOURCES I, LP

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands except per share data)


	For the Years Ended December 31,
	2013			2012
REVENUES
Oil and natural gas sales	$	12,935		$	370

Total revenues		12,935			370
OPERATING EXPENSES
Exploration		3,022			3,899
Lease operating		2,576			16
Transportation, gathering and compression		67			—
Production and ad valorem taxes		77			1
Depreciation, depletion and amortization		6,163			404
Impairment of oil and gas properties		2,081			793
General and administrative		21,276			4,425
Accretion of asset retirement obligations		364			—

Total operating expenses		35,626			9,538
Gain on sale of properties		—			372

OPERATING LOSS		(22,691	)		(8,796	)
OTHER INCOME (EXPENSE)
Interest income (expense), net		(20,850	)		37

Total other income (expense), net		(20,850	)		37

NET LOSS	$	(43,541	)	$	(8,759	)


PRO FORMA INFORMATION (UNAUDITED)
Net loss	$	(43,541	)
Pro forma benefit for income taxes		15,239

Pro forma net loss	$	(28,302	)

Pro forma loss per common share
Basic and diluted	$	(0.38	)
Weighted average pro forma shares outstanding
Basic and diluted		75,261

The accompanying notes are an integral part of these consolidated financial statements.

F-42

ECLIPSE RESOURCES I, LP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

(in thousands)


	For the Years Ended December 31,
	2013			2012
NET LOSS	$	(43,541	)	$	(8,759	)
Other comprehensive loss:
Pension obligation adjustment		1,168			—

TOTAL COMPREHENSIVE LOSS	$	(42,373	)	$	(8,759	)

The accompanying notes are an integral part of these consolidated financial statements.

F-43

ECLIPSE RESOURCES I, LP

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

FOR THE YEARS ENDED DECEMBER 31, 2013 AND 2012

(in thousands)


	Partners’ Capital			Accumulated Other Comprehensive Income		Total Partners’ Capital
Balance, December 31, 2011	$	66,544		$	—	$	66,544
Capital contributions		69,554			—		69,554
Incentive unit compensation		3			—		3
Net loss		(8,759	)		—		(8,759	)
Distributions		(638	)		—		(638	)

Balance, December 31, 2012		126,704			—		126,704
Capital contributions		583,597			—		583,597
Incentive unit compensation		43			—		43
Net loss		(43,541	)		—		(43,541	)
Change in accumulated other comprehensive income		—			1,168		1,168

Balance, December 31, 2013	$	666,803		$	1,168	$	667,971

The accompanying notes are an integral part of these consolidated financial statements.

F-44

ECLIPSE RESOURCES I, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)


	For the Years Ended December 31,
	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(43,541	)	$	(8,759	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		6,163			404
Impairment of oil and gas properties		2,081			793
Accretion of asset retirement obligations		364			—
Exploration expense		3,022			3,899
Incentive unit compensation		43			3
Interest not paid in cash		20,294			—
Gain on sale of oil and natural gas properties		—			(372	)
Amortization of deferred financing costs		739			—
Amortization of debt discount		1,247			—
Pension benefit costs		575			—
Changes in operating assets and liabilities, net of acquisitions:
Accounts receivable		(5,971	)		(172	)
Other current assets		1,389			50
Accounts payable and accrued liabilities		27,276			747
Accrued liabilities—related parties		1,569			26

Net cash provided by (used in) operating activities		15,250			(3,381	)

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures on oil and natural gas properties		(252,844	)		(179,209	)
Acquisition of Eclipse Resources—Ohio, LLC, net of cash acquired		(651,847	)		—
Additions to other property and equipment		(892	)		—
Proceeds from the sale of assets		8,497			131,674

Net cash used in investing activities		(897,086	)		(47,535	)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from issuance of debt		388,000			—
Debt issuance costs		(7,309	)		—
Capital contributions		583,597			69,554
Distributions		—			(638	)

Net cash provided by financing activities		964,288			68,916

Net increase in cash and cash equivalents		82,452			18,000
Cash and cash equivalents at beginning of year		27,057			9,057

Cash and cash equivalents at end of year	$	109,509		$	27,057

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid for interest	$	—		$	—

Cash paid for income taxes	$	—		$	—

SUPPLEMENTAL DISCLOSURE OF NON-CASH ACTIVITIES:
Asset retirement obligations incurred, including changes in estimate	$	300		$	—

Additions to oil and natural gas properties—change in accrued capital expenditure	$	17,537		$	1,663

Assets and liabilities assumed in acquisition of Eclipse Resources-Ohio, LLC	$	5,102		$	—

The accompanying notes are an integral part of these consolidated financial statements.

F-45

ECLIPSE RESOURCES I, LP

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2013 AND 2012

Note 1—Organization and Nature of Operations

Eclipse Resources I, LP (“Eclipse I” or the “Partnership”) a Delaware limited partnership, was formed on January 20, 2011. The accompanying consolidated financial statements of Eclipse I for the years ended December 31, 2013 and 2012 include the results of its wholly owned subsidiary, Eclipse Resources-Ohio, LLC, formerly known as the Oxford Oil Company, LLC, (“Oxford”) from June 26, 2013 to December 31, 2013 (see “Note 4” below). Eclipse I is engaged in the acquisition and development of oil and natural gas properties in the Appalachian Basin of the United States, which encompasses the Utica Shale and Marcellus Shale prospective areas.

Note 2—Basis of Presentation

These financial statements and related notes are presented in accordance with accounting principles generally accepted in the United States of America (“GAAP”). Preparation in accordance with GAAP requires the Partnership to (1) adopt accounting policies within accounting rules set by the Financial Accounting Standards Board (“FASB”) and (2) make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and other disclosed amounts. Note 3—Summary of Significant Accounting Policies describes our significant accounting policies. Our management believes the major estimates and assumptions impacting our consolidated financial statements are the following:

•

estimates of proved reserves of oil and natural gas, which affect the calculations of depletion, depreciation and amortization and impairment of capitalized costs of oil and natural gas properties;

•

estimates of asset retirement obligations;

•

estimates of the fair value of oil and natural gas properties we own, particularly properties that we have not yet explored, or fully explored, by drilling and completing wells;

•

impairment of undeveloped properties and other assets; and

•

depreciation and depletion of property and equipment.

Note 3—Summary of Significant Accounting Policies

(a) Cash and Cash Equivalents

(b) Accounts Receivable

F-46

ECLIPSE RESOURCES I, LP

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2013 AND 2012

the party. The Partnership did not deem any of its accounts receivable uncollectable as of December 31, 2013 or December 31, 2012.

The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas and crude oil and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Partnership’s records and management’s estimates of the related commodity sales and transportation and compression fees which are, in turn, based upon applicable product prices (see “Note 2” above for further description). The Partnership had $4.1 million and $0.2 million of unbilled revenues at December 31, 2013 and 2012, respectively, which were included in accounts receivable within the Partnership’s balance sheet.

(c) Property and Equipment

Oil and Natural Gas Properties

F-47

ECLIPSE RESOURCES I, LP

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2013 AND 2012

A summary of property and equipment including oil and natural gas properties is as follows (in thousands):


	December 31,
	2013			2012
Oil and natural gas properties:
Proved	$	97,528		$	6,986
Unproved		926,812			99,671

Gross oil and natural gas properties		1,024,340			106,657
Less accumulated depreciation, depletion and amortization		(8,596	)		(404	)

Oil and natural gas properties, net		1,015,744			106,253
Other property and equipment		2,392			—
Less accumulated depreciation		(52	)		—

Other property and equipment, net		2,340			—

Property and equipment, net	$	1,018,084		$	106,253

Exploration expenses, including geological and geophysical expenses and delay rentals for unevaluated oil and gas properties are charged to expense as incurred. Exploratory drilling costs are initially capitalized as unproved property, not subject to depletion, but charged to expense if and when the well is determined not to have found proved oil and gas reserves. Exploratory drilling costs are evaluated and a determination of classification is made within one-year from the completion of drilling. As of December 31, 2013 and 2012, there were no costs capitalized in connection with exploratory wells in progress.

Other Property and Equipment

Other property and equipment include land, buildings, vehicles, computer equipment and software, telecommunications equipment, and furniture and fixtures. These items are recorded at cost, or fair value if acquired through a business acquisition. The Partnership had no other property and equipment prior to the acquisition of Oxford on June 26, 2013 (see “Note 4” below).

(d) Revenue Recognition

Oil and natural gas sales revenue is recognized when produced quantities of oil and natural gas are delivered to a custody transfer point such as a pipeline, processing facility or a tank lifting has occurred, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sales is reasonably assured and the sales price is fixed or determinable. Revenues from the sales of natural gas, crude oil or natural gas liquids in which the Partnership has an interest with other producers are recognized using the sales method on the basis of the Partnership’s net revenue interest. The Partnership has no material imbalances as of December 31, 2013 and 2012.

(e) Major Customers

The Partnership sells production volumes to various purchasers. For the years ended December 31, 2013 and 2012, there were four customers and one customer, respectively, that accounted for 10% or more of total natural gas, natural gas liquids (NGLs) and oil sales. Management believes that the loss of any one customer would not

F-48

ECLIPSE RESOURCES I, LP

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2013 AND 2012

have an adverse effect on the Partnership’s ability to sell natural gas, NGLs and oil production. The following table sets forth the Partnership’s major customers and associated percentage of revenue for the periods indicated:


	For the Years Ended December 31,
	2013			2012
Purchaser
Antero Resources Corporation		38	%		100	%
Devco Oil Inc.		24	%		—	%
Dominion Resources Inc.		13	%		—	%
Ergon Inc.		12	%		—	%

Total		87	%		100	%

(f) Concentration of Credit Risk

The following table summarizes concentration of receivables, net of allowances, by product or service as of December 31, 2013 and 2012 (in thousands):


	December 31,
	2013		2012
Receivables by product or service:
Sale of oil and natural gas and related products and services	$	4,092	$	149
Joint interest owners		4,586		23

Total	$	8,678	$	172

(g) Accumulated Other Comprehensive Loss

Comprehensive loss includes net loss and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under GAAP, have not been recognized in the calculation of net loss. These changes, other than net loss, are referred to as “other comprehensive loss” and for the Partnership they include pension benefit plans that require an employer to (i) recognize the overfunded or underfunded status of a defined benefit retirement plan as an asset or liability in its balance sheet and (ii) recognize changes in that funded status in the year in which the changes occur through other comprehensive loss. The Partnership’s pension plan was under-funded by $1.5 million at December 31, 2013. The Partnership did not have a pension plan prior to the acquisition of Oxford on June 26, 2013 (see “Note 4” below).

F-49

ECLIPSE RESOURCES I, LP

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2013 AND 2012

(h) Depreciation, depletion and amortization (DD&A)

Oil and Natural Gas Properties

Depreciation, depletion, and amortization (DD&A) of capitalized costs of proved oil and natural gas properties is computed using the unit-of-production method on a unit level basis using total estimated proved reserves. The reserve base used to calculate DD&A for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. The reserve base used to calculate DD&A for drilling, completion and well equipment costs, which include development costs and successful exploration drilling costs, includes only proved developed reserves. DD&A expense for the years ended December 31, 2013 and 2012 totaled approximately $5.9 million and $0.4 million, respectively.

Other Property and Equipment

Depreciation with respect to other property and equipment is calculated using straight-line methods based on expected lives of the individual assets or groups of assets ranging from 5 to 40 years. Depreciation for the years ended December 31, 2013 totaled approximately $0.3 million. This amount is included in depreciation, depletion, and amortization expense in the statement of operations.

(i) Impairment of Long-Lived Assets

The review of the Partnership’s oil and gas properties is done on a unit level basis by determining if the historical cost of proved properties less the applicable accumulated depletion, depreciation and amortization and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on the Partnership’s plans to continue to produce and develop proved reserves. Expected future cash flow from the sale of production of reserves is calculated based on estimated future prices. The Partnership estimates prices based upon current contracts in place, adjusted for basis differentials and market related information including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets.

F-50

ECLIPSE RESOURCES I, LP

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2013 AND 2012

Proved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. During the year ended December 31, 2013, the Partnership recognized an impairment charge related to a well drilled and completed in 2012 in the amount of $2.1 million. There were no impairments of proved oil and gas properties recorded by the Partnership for the year ended December 31, 2012.

The aforementioned impairment charges represented a significant Level 3 measurement in the fair value hierarchy. The primary input used was the Partnership’s forecasted discounted net cash flows.

(j) Income Taxes

(k) Fair Value of Financial Instruments

Level 1—Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date.

The estimated fair values of the Partnership’s financial instruments closely approximate the carrying amounts due, including long-term debt, based on their recent issuance by the Company.

The fair value assumptions used to determine the inception value of AROs is a level 3 input within the hierarchy.

F-51

ECLIPSE RESOURCES I, LP

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2013 AND 2012

(l) Asset Retirement Obligation

The following table sets forth the changes in the Partnership’s ARO liability for the periods indicated (in thousands):


	Year Ended December 31,
	2013		2012
Asset retirement obligations, beginning of year	$	13	$	—
Additional liabilities incurred		300		13
Assumption of Oxford asset retirement obligations		8,378		—
Accretion		364		—

Asset retirement obligations, end of year	$	9,055	$	13

(m) Lease Obligations

(n) Off-Balance Sheet Arrangements

The Partnership does not have any off-balance sheet arrangements.

F-52

ECLIPSE RESOURCES I, LP

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2013 AND 2012

(o) Segment Reporting

(p) Debt Issuance Costs

(q) Recent Accounting Pronouncements

The FASB issued Accounting Standard Update (“ASU”) 2011-11, “Disclosures about Offsetting Assets and Liabilities” in December 2011, and issued ASU 2013-01, “Clarifying the Scope of Disclosures About Offsetting Assets and Liabilities” in January 2013. These ASUs create new disclosure requirements regarding the nature of an entity’s rights of setoff and related arrangements associated with its derivative instruments, repurchase agreements and securities lending transactions. Certain disclosures of the amounts of certain instruments subject to enforceable master netting arrangements would be required, irrespective of whether the entity has elected to offset those instruments in the statement of financial position. These ASUs are effective retrospectively for annual reporting periods beginning on or after January 1, 2013. The adoption of these ASUs did not impact the Partnership’s financial position, results of operations or liquidity.

The FASB issued ASU 2013-02, “Comprehensive Income (Topic 220)—Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income” in February 2013. The amendments do not change the current requirements for reporting net income or other comprehensive income in financial statements. These amendments require an entity to provide information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, an entity is required to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income but only if the amount reclassified is required under U.S. GAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under U.S. GAAP to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures required under U.S. GAAP that provide additional details about those amounts. The adoption of this ASU did not impact the Partnership’s financial position, results of operations or liquidity.

Note 4—Acquisition

The Eclipse Resources-Ohio, LLC Acquisition

On June 26, 2013, the Partnership acquired 100% of the outstanding equity interests of Oxford. Oxford holds interests in approximately 181,000 net acres of Utica Shale leaseholds, and related producing properties located primarily in Belmont, Guersney, Monroe, Noble, and Harrison Counties in Ohio along with various other related rights, permits, contracts, equipment and other assets. The aggregate purchase price totaled $652.5 million in cash. The acquisition provided strategic additions adjacent to the Partnership’s core project area. The acquisition contributed revenue of $7.6 million to Eclipse I for the year ended December 31, 2013. Transaction costs related to the acquisition incurred through December 31, 2013 were approximately $12.2 million and are recorded in the statement of operations within the general and administrative expenses line item.

F-53

ECLIPSE RESOURCES I, LP

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2013 AND 2012

The acquisition is accounted for using the acquisition method under ASC Topic 805, “Business Combinations” which requires the acquired assets and liabilities to be recorded at fair values as of the acquisition date of July 26, 2013. The following table summarizes the preliminary purchase price allocation and the values of assets acquired and liabilities assumed and is subject to finalization (in thousands):


Purchase Price	June 26, 2013
Consideration Given
Cash	$	652,500

Allocation of Purchase Price
Unproved properties		621,039
Proved properties		40,914
Cash		653
Building and land		1,500

Total assets		664,106
Asset retirement obligations		(8,378	)
Pension obligation		(2,522	)
Other working capital		(706	)

Fair value of net assets acquired	$	652,500

The purchase price allocation set forth above represented a significant Level 3 measurement in the fair value hierarchy and was derived in accordance with ASC 805. The inputs used in such determination were forecasted cash flows, market comparisons, actuarial studies and Oxford’s historical accounting records.

Oxford is party to various lawsuits, primarily related to the validity of certain oil and gas leases. (see “Note 10”).

Pro Forma Financial Information (unaudited)

The following unaudited pro forma financial information represents the combined results for the Partnership and Oxford for the years ended December 31, 2013 and 2012 as if the acquisition had occurred on January 1, 2012. The pro forma information includes the effects of adjustments for depletion, depreciation, amortization and accretion expense of $3.4 million and $0.8 million for the years ended December 31, 2013 and 2012, respectively. The pro forma information includes the effects of adjustments for amortization of financing costs of $0.7 million and $1.5 million for the years ended December 31, 2013 and 2012, respectively. The pro forma information includes the effects of the amortization of debt discount of $1.2 million and $2.4 million for the years ended December 31, 2013 and 2012, respectively. The pro forma information includes the effects of the incremental interest expense on acquisition financing of $26.9 million and $53.9 million for the years ended December 31, 2013 and 2012, respectively. The pro forma results do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by the Partnership to integrate the properties acquired. The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of January 1, 2012, nor are they necessarily indicative of future results (in thousands).

F-54

ECLIPSE RESOURCES I, LP

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2013 AND 2012


	For the Year Ended December 31,
	2013			2012
	(unaudited)
Oil and natural gas sales		20,638			13,936
Net loss		(71,131	)		(56,065	)

During the year end December 31, 2012, the Partnership also acquired $157.6 million of unproved properties.

Note 5—Sale of Oil and Natural Gas Property Interests

Effective March 16, 2012, the Partnership entered into a Purchase and Exploration Agreement (“PEA”) to sell 70% of its interests in certain unproved oil and gas properties. During 2012, the Partnership completed the sale of 21,114 net acres under the PEA for net proceeds of $126.5 million. The cumulative proceeds of the sale did not exceed the Partnership’s cost basis in the properties; therefore, no gain was recognized on the sale.

During the year ended December 31, 2012, the Partnership sold 70% of its interest in a proved oil and gas property for $5.2 million, before customary purchase price adjustments. The proceeds included $2.4 million for the sale of 70% of its net acreage in the unit and $2.8 million for the reimbursement of 70% of the Partnership’s net drilling costs incurred. The sales proceeds exceeded the Partnership’s cost basis in the unit, resulting in a gain of $0.4 million during 2012.

During the year ended December 31, 2013, the Partnership sold an additional 1,220 acres for net proceeds of $8.5 million. The cumulative proceeds of the sale did not exceed the Partnership’s cost basis in the properties; therefore, no gain was recognized on the sale.

Note 6—Debt

12% Senior Unsecured PIK Notes Due 2018

F-55

ECLIPSE RESOURCES I, LP

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2013 AND 2012


Year following expiration of the Non-Call Period	Redemption Price
Year 1		106.00	%
Year 2		103.00	%
Year 3 and thereafter		100.00	%

At the Partnership’s option, for the first 2 semi-annual interest payments following the Issue Date, interest may be payable by increasing the principal amount of the Senior Notes or by issuing payment in kind (“PIK”) securities. At the Partnership’s option, for the subsequent four semi-annual interest payments thereafter, interest may be payable in the form of 6.0% per annum in cash and 7.0% per annum in PIK securities. Thereafter, interest can only be paid as cash interest. Interest is payable on July 15 and January 15 each year, beginning in January 2014. Interest paid by issuing PIK securities accrues at 13%, interest paid by cash accrues at 12%. The Partnership elected to settle its accrued interest payable at December 31, 2013 with PIK Securities on January 15, 2014. The Partnership capitalized interest expense totaling $1.5 million during the year ended December 31, 2013.

The Partnership’s obligations under the Senior Notes are guaranteed by its 100% owned subsidiaries, Oxford. The Partnership may not among other things, directly or indirectly: (1) consolidate or merge with or into another Person (whether or not the Partnership is the survivor), or (2) sell, assign, transfer, convey, lease or otherwise dispose of all or more than 50% of its properties or assets, in one or more related transactions, to another Person, unless in each case certain restrictive conditions contained in the Indenture are met.

Note 7—Benefit Plans

The Partnership maintains a defined benefit pension plan covering 34 of its employees, of which two are retired, four have deferred vested termination, and one is a survivor. Benefits are based on the employee’s years of service and compensation. The Partnership’s plans are funded in conformity with the funding requirements of ASC 715 as of December 31, 2013. As a result of the Oxford acquisition (refer to “Note 4” above) on June 26, 2013, the Partnership assumed the defined benefit pension plan, and therefore, no pension benefit plan was in effect prior to such date.

F-56

ECLIPSE RESOURCES I, LP

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2013 AND 2012

A summary of the pension benefit as of the and the year ended December 31, 2013 is set forth in the below tables (in thousands):


Change in benefit obligation
Benefit obligation at beginning of year	$	—
Oxford assumed benefit obligation		9,045
Service cost		144
Interest cost		203
Actuarial (gain) loss		(350	)
Benefits paid		(24	)

Benefit obligation at end of year	$	9,018

Change in plan assets
Fair value of plan assets at beginning of year	$	—
Oxford assumed plan assets		6,523
Actual return on plan assets		1,012
Employer contributions		10
Benefit paid		(24	)

Fair value of plan assets at end of year	$	7,521

The funding levels of all qualified pension plans are in compliance with standards set by applicable law or regulation. As shown in the table below, the current pension plan is underfunded. All defined benefit pension obligations, regardless of the funding status of the underlying plans, are fully supported by the financial strength of the Partnership.


Assets in excess of (less than) benefit obligation at December 31, 2013
Vested amount	$	(7,039	)
Additional benefits required		(1,979	)

Projected benefit obligation		(9,018	)
Funded amount		7,521

Unfunded amount	$	(1,497	)

Other amounts recognized in other comprehensive loss during the year ended December 31, 2013
Assets in excess of (less than) benefit obligation at end of period	$	(1,497	)

Amounts recorded in the consolidated balance sheet consist of:
Accrued benefit liability		(1,497	)

Total recorded	$	(1,497	)

Amounts recorded in accumulated other comprehensive income consist of:
Pension obligation adjustment	$	1,168

Total recorded in accumulated other comprehensive income	$	1,168

F-57

ECLIPSE RESOURCES I, LP

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2013 AND 2012

The discount rate is determined by constructing a portfolio of high-quality, noncallable bonds with cash flows that match estimated outflows for benefit payments.


Weighted average assumptions to determine benefit obligation at December 31, 2013
Discount rate		4.75	%
Expected rate of return		6.00	%
Rate of compensation increase		4.00	%
Inflation		3.00	%
Components of net periodic benefit cost for the year ended December 31, 2013
Service cost	$	144
Interest cost		203
Expected return on plan assets		(195	)
Amortization of transition obligation		140

Net period benefit cost	$	292

The following benefit payments are expected to be paid over the next ten years (in thousands):


2014	$	50
2015		49
2016		104
2017		175
2018		222
2019—2023	$	2,422

The Partnership’s investment strategy for benefit plan assets reflects a long-term view, a careful assessment of the risks inherent in various asset classes and broad diversification to reduce the risk of the portfolio. Studies are periodically conducted to establish the preferred target asset allocation percentages. The Partnership, along with its investment manager, determines the investment policies and strategies for the plan assets to determine the allocations to the various asset classes based on the results of the studies targeted percentages. The following tables below set forth the breakout of asset categories as of December 31, 2013 (in thousands):


Plan assets by category
Equity securities	$	7,397
Debt securities		117
Cash		6

Total Assets	$	7,520

Plan assets by category
Equity securities		98.3	%
Debt securities		1.6	%
Cash		0.1	%

Total Assets		100	%

F-58

ECLIPSE RESOURCES I, LP

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2013 AND 2012

The following tables set forth by level, within the fair value hierarchy, the fair value of pension assets and liabilities as of December 31, 2013 (in thousands):


	December 31, 2013
	Level 1		Level 2		Level 3		Total
Pension assets	$	7,403		117		—	$	7,520

The fair value measurement levels are accounting terms that refer to different methods of valuing assets. The terms do not represent the relative risk or credit quality of an investment.

Note 8—Equity

The following tables set forth the Class A-1, A-2 and B units issued and outstanding (in thousands):


	December 31, 2013
	Units Authorized		Units Issued
Units
A-1		3,896		3,896
A-2		5,427		4,930
B		104		104

Total Units		9,427		8,930


	December 31, 2012
	Units Authorized		Units Issued
Units
A-1		1,450		1,363
B		50		37

Total Units		1,500		1,400

F-59

ECLIPSE RESOURCES I, LP

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2013 AND 2012

as (i) a sale or transfer of all or substantially all of the Partnership Interests of the Partnership (including by way of merger, consolidation, share exchange, or similar transaction), (ii) the sale or other transfer of all or substantially all of the assets of the Partnership promptly followed by a dissolution and liquidation of the Partnership, or (iii) a combination of any of the foregoing. In the event an employee terminates his or her employment with the Partnership prior to vesting, the non-vested Incentive Units will be forfeited by the holder. Compensation expense for these awards is calculated based on the fair value of the Incentive Units at the date of grant and is recognized over the requisite service period.

A summary of the Incentive Unit awards as of December 31, 2013 and 2012, along with the changes during the years then ended, is as follows:


	C-1 Units			Weighted Average Grant Date Fair Value per unit
Nonvested at December 31, 2011		950		$	—
Granted		60			629
Vested		(216	)		—

Nonvested at December 31, 2012		794			48
Granted		40			1,033
Vested		(224	)		1,022
Forfeited		(50	)		—

Nonvested at December 31, 2013		560		$	131


	C-2 Units			Weighted Average Grant Date Fair Value
Nonvested at December 31, 2012		—		$	—
Granted		182			2,501

Nonvested at December 31, 2013		182		$	2,501

There were no C-2 unit awards issued prior to December 31, 2012.

Total compensation cost related to the Incentive Units was $43,225 and $2,845 for the years ended December 31, 2013 and 2012, respectively. As of December 31, 2013, there was $0.7 million of total unrecognized compensation cost related to Incentive Units, which is expected to be recognized over a weighted-average period of 6.2 years.

Note 9—Related Party Transactions

F-60

ECLIPSE RESOURCES I, LP

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2013 AND 2012

Agreement. Each of the members of Eclipse Operating also controls entities that own the Class B units in the Partnership.

The Partnership considered the requirements of ASC Topic 810 “Consolidation” and determined Eclipse Operating to be a variable interest entity. The variable interest primarily relates to the administrative agreement between the two entities and the management fee charged for the services provided by Eclipse Operating to the Partnership equal to the actual expenditures incurred for such operations. The Partnership has concluded it is not the primary beneficiary of the variable interest entity. During the years ended December 31, 2013 and 2012, the Partnership’s management fee to Eclipse Operating was $14.7 million and $4.2 million, respectively, classified as within “General and Administrative expenses” in the consolidated statements of operations.

Note 10—Commitments and Contingencies

(a) Legal Matters

West Matter

In October 2011, Oxford filed a lawsuit in the Common Pleas Court of Belmont County, Ohio against Barry M. West and other landowners holding an interest in property subject to an oil and gas lease held by Oxford (the “West lawsuit”). The lawsuit was filed after the defendant landowners prevented Oxford from drilling a well on the property subject to the oil and gas lease. Oxford brought claims for breach of contract, unjust enrichment, and promissory estoppel, and sought a declaratory judgment that Oxford had a valid and enforceable lease with the defendant landowners. The defendant landowners filed counterclaims for defective execution of the lease, fraud, bad faith, breach of the implied duty to develop, improper assignment of the lease, and a claim that the lease was void as a lease in perpetuity contrary to law and the public policies of the State of Ohio. Oxford filed a motion for summary judgment on July 15, 2013, and the defendant landowners filed their motion for summary judgment on August 26, 2013. On October 4, 2013, the trial court granted the defendant’s motion for summary judgment and held that the lease in question was “void ab initio” because the lease is a “no-term lease” and a “lease in perpetuity.” On October 8, 2013, the Partnership appealed the trial court’s judgment to the Seventh District Court of Appeals of the State of Ohio.

The judgment of the trial court has been stayed pending the outcome of this appeal. The Partnership believes that the trial court erred in finding that the lease in question was a perpetual lease, and that the judgment of the trial court that perpetual leases are “void ab initio” is not consistent with applicable Ohio law. However, since the ruling in the West lawsuit, adverse parties in other lawsuits in which the Partnership is involved have amended their complaints to make allegations similar to those made by the lessor in the West lawsuit, and the Partnership may be subject to additional lawsuits alleging that our leases are void. If the appeals court does affirm the court ruling and if other courts in Ohio adopt a similar interpretation of the language in our other leases with similar term language, such leases may also be determined to be void if the lessor challenges the validity of the lease. Consequently, this could result in a loss of the mineral rights and an impairment of the related assets which could have a material adverse impact on the Partnership’s financial statements.

F-61

ECLIPSE RESOURCES I, LP

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2013 AND 2012

merits of the appeal, the Partnership believes that it is not probable that trial court’s decision will be upheld in the appeal or that the Partnership will incur a material loss in the lawsuit, and accordingly, the Partnership has not recorded an accrual for the potential losses attributable to this lawsuit.

Other Matters

(b) Environmental Matters

(c) Leases

The Partnership entered into a lease agreement for office space for the corporate headquarters in April 2013 with a current term of five years, ending April 2018. This lease includes an option to cancel the lease if the landlord does not deliver additional space within one year. Rent expense related to the lease agreement for the year ended December 31, 2013 was $0.1 million. No rent expense was incurred for the year ended December 31, 2012.

The following is a schedule, by year, of the future minimum lease payments required under the lease agreement as of December 31, 2013 (in thousands), assuming the lease is not cancelled within one year:


2014	$	173
2015		173
2016		173
2017		173
2018		58

Total minimum lease payments	$	750

Note 11—Subsequent Events

Revolving Credit Facility

In February 2014, Eclipse I entered into a $500 million senior secured Revolving Credit Facility. The maturity date of the Revolving Credit Facility is January 15, 2018. Interest on outstanding borrowings under the Revolving Credit Facility will accrue based on, at our option, LIBOR or the alternate base rate, in each case, plus

F-62

ECLIPSE RESOURCES I, LP

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2013 AND 2012

an applicable margin that is determined based on the Partnership’s utilization of commitments under the Revolving Credit Facility. The revolver is subject to customary financial and restriction covenants. Currently, the Partnership does not have an established borrowing base under the Revolving Credit Facility.

In January and February 2014, Eclipse I entered into financial commodity derivative contracts with respect to 40,000 Mmbtu per day of its natural gas production in the form of natural gas swaps and puts for a portion of its natural gas volume in 2014 and 2015.

Management has evaluated subsequent events through February 21, 2014 and believes that there are no events that would have a material impact on the aforementioned financial statements and related disclosures.

Note 12—Unaudited Pro Forma Net Income Per Share

Note 13—Supplemental Oil and Natural Gas Information (unaudited)

(a) Capitalized Costs

A summary of the Partnership’s capitalized costs are contained in the table below (in thousands):


	December 31,
	2013			2012
Oil and natural gas properties:
Proved properties	$	97,528		$	6,986
Unproved properties		926,812			99,671

Total oil and natural gas properties		1,024,340			106,657
Less accumulated depreciation, depletion and amortization		(8,596	)		(404	)

Net oil and natural gas properties	$	1,015,744		$	106,253

F-63

ECLIPSE RESOURCES I, LP

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2013 AND 2012

(b) Costs Incurred in Oil and Natural Gas Property Acquisition and Development Activities

A summary of the Partnership’s cost incurred in oil and natural gas property acquisition and development activities is set forth below (in thousands):


	December 31,
	2013		2012
Acquisition costs:
Proved properties	$	40,914	$	2,498
Unproved properties		621,039		158,131
Development cost		258,825		16,344
Exploration cost		3,022		3,899

Total acquisition, development and exploration costs	$	923,800	$	180,872

(c) Reserve Quantity Information

The following information represents estimates of the Partnership’s proved reserves as of December 31, 2013 and December 31, 2012, which have been prepared and presented under SEC rules. These rules require companies to prepare their reserve estimates using specified reserve definitions and pricing based on a 12-month unweighted average of the first-day-of-the-month pricing. The pricing that was used for estimates of the Partnership’s reserves as of December 31, 2013 and December 31, 2012 was based on an unweighted average 12-month average West Texas Intermediate posted price per Bbl for oil and a Henry Hub spot natural gas price per MMBtu for natural gas.

Subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. This requirement may limit the Partnership’s potential to record additional proved undeveloped reserves as it pursues its drilling program, particularly as it develops its significant acreage in the Appalachian Basin of Ohio. Moreover, the Partnership may be required to write down its proved undeveloped reserves if it does not drill on those reserves with the required five-year timeframe. The Partnership does not have any proved undeveloped reserves which have remained undeveloped for five years or more.

The Partnership’s proved oil and natural gas reserves are all located in the United States, within the State of Ohio. All of the estimates of the proved reserves at December 31, 2013 and December 31, 2012, were prepared by Netherland, Sewell & Associates, Inc. (“NSAI”), independent petroleum engineers. Proved reserves were estimated in accordance with the guidelines established by the SEC and the FASB.

Oil and natural gas reserve quantity estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing and production may cause either upward or downward revision of previous estimates.

Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The Partnership emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and natural gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future.

F-64

ECLIPSE RESOURCES I, LP

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2013 AND 2012

The following table provides a roll-forward of the total proved reserves for the year ended December 31, 2013 and 2012, as well as proved developed and proved undeveloped reserves at the beginning and end of each respective year:


	Oil (MBbl)			Natural Gas (MMcf)			Natural Gas Liquids (MBbl)			TOTAL (MMcfe)
December 31, 2011		—			—			—			—
Extensions and discoveries		390.5			2,963.8			177.0			6,368.9
Production		(4.5	)		(7.7	)		—			(34.6	)

End of year, December 31, 2012		386.0			2,956.1			177.0			6,334.2

Revisions		(163.2	)		2,645.0			52.1			1,978.4
Extensions and discoveries		1,323.3			41,215.5			1,710.6			59,419.0
Acquisition of reserves		958.5			6,646.6			—			12,397.6
Production		(87.2	)		(1,118.8	)		(1.3	)		(1,650.2	)

End of year, December 31, 2013		2,417.4			52,344.4			1,938.4			78,478.6

Proved developed reserves:
December 31, 2012		174.5			1,289.6			64.6			2,724.0
December 31, 2013		1,708.1			27,880.3			1,056.2			44,466.6
Proved undeveloped reserves:
December 31, 2012		211.5			1,666.6			112.4			3,610.1
December 31, 2013		709.2			24,464.1			882.2			34,012.0

Extensions and discoveries of 59,419 MMcfe and 6,369 MMcfe during the years ended December 31, 2013 and December 31, 2012, respectively, resulted primarily from the drilling of new wells during each year and from new proved undeveloped locations added during each year. Acquisition of reserves of 12,398 MMcfe during the year ended December 31, 2013, resulted from the acquisition of Oxford (refer to “Note 4” above). Revisions of reserves of 1,978 MMcfe during the year ended December 31, 2013, which consists of 1,596.7 MMcfe of technical revisions and 381.7 MMcfe of upward pricing revisions related to oil and gas slightly offset by negative pricing revisions related to NGLs. Thousands of cubic feet of gas equivalent (“Mcfe”) and millions of cubic feet of gas equivalent (“MMcfe”) amounts have been calculated by using the conversion ratio of one barrel of oil (1 bbl) to six thousand cubic feet (6 Mcf) of natural gas.

(d) Standardized Measure of Discounted Future Net Cash Flows

The standardized measure of discounted future net cash flows does not purport to be, nor should it be interpreted to present, the fair value of the oil and natural gas reserves of the property. An estimate of fair value would take into account, among other things, the recovery of reserves not presently classified as proved, the value of unproved properties, and consideration of expected future economic and operating conditions. The estimates of future cash flows and future production and development costs as of December 31, 2013 and 2012 are based on the unweighted arithmetic average first-day-of-the-month price for the preceding 12-month period. Estimated future production of proved reserves and estimated future production and development costs of proved reserves are based on current costs and economic conditions. All wellhead prices are held flat over the forecast

F-65

ECLIPSE RESOURCES I, LP

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2013 AND 2012

period for all reserve categories. The estimated future net cash flows are then discounted at a rate of 10%. The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is as follows at December 31, 2013 and 2012 (in thousands):


	December 31,
	2013			2012
Future cash inflows (total revenues)	$	479,527		$	50,614
Future production costs (severance and ad valorem taxes plus LOE)		(116,161	)		(6,448	)
Future development costs (capital costs)		(76,511	)		(8,015	)
Future income tax expense⁽¹⁾		—			—

Future net cash flows		(286,855	)		36,151
10% annual discount for estimated timing of cash flows		(131,560	)		(14,257	)

Standardized measure of Discounted Future Net Cash Flow	$	155,295		$	21,894

(1)

Future net cash flows do not include the effects of income taxes on future revenues because Eclipse I was a limited partnership not subject to entity-level income taxation as of December 31, 2013 and December 31, 2012. Accordingly, no provision for federal or state corporate income taxes has been provided because taxable income was passed through to Eclipse I’s partners’.

It is not intended that the FASB’s standardized measure of discounted future net cash flows represent the fair market value of the Partnership’s proved reserves. The Partnership cautions that the disclosures shown are based on estimates of proved reserve quantities and future production schedules which are inherently imprecise and subject to revision, and the 10% discount rate is arbitrary. In addition, costs and prices as of the measurement date are used in the determinations, and no value may be assigned to probable or possible reserves.

(e) Changes in the Standardized Measure of Discounted Future Net Cash Flows

A summary of the changes in the standardized measure of discounted future net cash flows are contained in the table below (in thousands):


	December 31,
	2013			2012
Standardized Measure, beginning of the year	$	21,894		$	—
Net change in prices and production costs		(5,345	)		354
Net change in future development costs		(1,148	)		—
Sales, Less production costs		(10,281	)		(354	)
Extensions		106,720			21,894
Acquisitions		28,984			—
Revisions of previous quantity estimates		8,354			—
Accretion of discount		2,189			—
Changes in timing and other		3,937			—

Period Balance	$	155,295		$	21,894

F-66

REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS

Board of Managers of Eclipse Resources I, LP

Eclipse Resources-Ohio, LLC

We have audited the accompanying financial statements of Eclipse Resources-Ohio, LLC (an Ohio limited liability company), formerly The Oxford Oil Company, which comprise the balance sheets as of June 25, 2013 and December 31, 2012 and the related statements of operations, comprehensive loss, member’s equity, and cash flows for the period from January 1, 2013 through June 25, 2013 and for the year ended December 31, 2012, and the related notes to the financial statements.

Management’s responsibility for the financial statements

Management is responsible for the preparation and fair presentation of these financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.

Auditor’s responsibility

Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Eclipse Resources-Ohio, LLC as of June 25, 2013 and December 31, 2012, and the results of its operations and its cash flows for the period from January 1, 2013 through June 25, 2013 and for the year ended December 31, 2012, in accordance with accounting principles generally accepted in the United States of America.

/s/ GRANT THORNTON LLP

Cleveland, Ohio

February 21, 2014

F-67

ECLIPSE RESOURCES-OHIO, LLC

BALANCE SHEETS

(in thousands)


	June 25, 2013			December 31, 2012
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	653		$	480
Accounts receivable		2,535			2,584
Materials inventory		1,913			687
Other current assets		118			193

Total current assets		5,219			3,944

PROPERTY AND EQUIPMENT, AT COST
Oil and natural gas properties, successful efforts method
Unproved properties		4,096			267
Proved oil and gas properties		101,490			101,150
Accumulated depletion, depreciation and amortization		(36,830	)		(31,423	)

Total oil and natural gas properties, net		68,756			69,994
Other property and equipment, net		1,904			1,894

Total property and equipment, net		70,660			71,888

TOTAL ASSETS	$	75,879		$	75,832

LIABILITIES AND MEMBER’S EQUITY
CURRENT LIABILITIES
Accounts payable	$	1,327		$	1,526
Accrued liabilities		945			805

Total current liabilities		2,272			2,331

NONCURRENT LIABILITIES
Asset retirement obligations		9,649			9,179
Pension liability		2,522			3,918

Total non-current liabilities		12,171			13,097

Total liabilities		14,443			15,428

COMMITMENTS AND CONTINGENCIES
MEMBER’S EQUITY
Member’s equity		63,036			63,790
Accumulated other comprehensive loss		(1,600	)		(3,386	)

Total member’s equity		61,436			60,404

TOTAL LIABILITIES AND MEMBER’S EQUITY	$	75,879		$	75,832

The accompanying notes are an integral part of these financial statements.

F-68

ECLIPSE RESOURCES-OHIO, LLC

STATEMENTS OF OPERATIONS

(in thousands)


	January 1, 2013 through June 25, 2013			Year ended December 31, 2012
REVENUES
Oil and natural gas sales	$	7,703		$	13,566

Total revenues		7,703			13,566

OPERATING EXPENSES
Exploration		183			409
Lease operating		2,160			4,909
Production and ad valorem taxes		87			166
Depletion, depreciation and amortization		5,525			10,878
General and administrative		2,532			3,508
Accretion of asset retirement obligation		470			867

Total operating expenses		10,957			20,737
Gain on sale of properties		—			2,849

OPERATING LOSS		(3,254	)		(4,322	)

NET LOSS	$	(3,254	)	$	(4,322	)

The accompanying notes are an integral part of these financial statements.

F-69

ECLIPSE RESOURCES-OHIO, LLC

STATEMENTS OF COMPREHENSIVE LOSS

(in thousands)


	January 1, 2013 through June 25, 2013			Year ended December 31, 2012
NET LOSS	$	(3,254	)	$	(4,322	)
Other comprehensive loss:
Pension obligation adjustment		(1,786	)		1,772

TOTAL COMPREHENSIVE LOSS	$	(5,040	)	$	(2,550	)

The accompanying notes are an integral part of these financial statements.

F-70

ECLIPSE RESOURCES-OHIO, LLC

STATEMENTS OF MEMBER’S EQUITY

FOR THE PERIOD JANUARY 1, 2013 TO JUNE 25, 2013 AND

THE YEAR ENDED DECEMBER 31, 2012

(in thousands)


	Member’s Equity			Accumulated Other Comprehensive Loss			Total Member’s Equity
Balance, December 31, 2011	$	72,831		$	(1,614	)	$	71,217

Net loss		(4,322	)		—			(4,322	)
Distributions		(4,719	)		—			(4,719	)
Change in accumulated other comprehensive loss		—			(1,772	)		(1,772	)

Balance, December 31, 2012	$	63,790		$	(3,386	)	$	60,404

Net loss		(3,254	)		—			(3,254	)
Contributions		2,500			—			2,500
Change in accumulated other comprehensive loss		—			1,786			1,786

Balance, June 25, 2013	$	63,036		$	(1,600	)	$	61,436

The accompanying notes are an integral part of these financial statements.

F-71

ECLIPSE RESOURCES-OHIO, LLC

STATEMENTS OF CASH FLOWS

(in thousands)


	January 1, 2013 through June 25, 2013			Year ended December 31, 2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(3,254	)	$	(4,322	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		5,525			10,878
Accretion of asset retirement obligation		470			867
Gain on sale of properties		—			(2,849	)
Pension obligations		390			532
Changes in operating assets and liabilities
Accounts receivable		49			1,485
Materials inventory		(1,226	)		259
Other current assets		75			(17	)
Accounts payable		(199	)		(2,632	)
Accrued liabilities		140			(156	)

Net cash provided by operating activities		1,970			4,045

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures on crude oil and natural gas properties		(4,297	)		(7,398	)
Proceeds from sale of assets		—			4,400

Net cash used in investing activities		(4,297	)		(2,998	)

CASH FLOWS FROM FINANCING ACTIVITIES
Distributions		—			(1,458	)
Contributions		2,500			—

Net cash provided by (used in) financing activities		2,500			(1,458	)

Net change in cash and cash equivalents		173			(411	)
Cash and cash equivalents at beginning of period		480			891

Cash and cash equivalents at end of period	$	653		$	480

SUPPLEMENTAL DISCLOSURE OF NON-CASH FLOW INFORMATION
Asset retirement obligation incurred, including changes in estimate		—			153
Non-cash distribution to Salt Run		—			3,261

The accompanying notes are an integral part of these financial statements.

F-72

ECLIPSE RESOURCES-OHIO, LLC

NOTES TO THE FINANCIAL STATEMENTS

FOR THE PERIOD FROM JANUARY 1, 2013 THROUGH JUNE 25, 2013

AND FOR THE YEAR ENDED DECEMBER 31, 2012

Note 1—Organization and Nature of Operations

Eclipse Resources-Ohio, LLC (the “Company”) was formed on June 18, 2013 as an Ohio limited liability company and is the successor-in-interest to The Oxford Oil Company, an Ohio S corporation (“Oxford”), organized in 1947 with a principle place of business in Zanesville, Ohio.

The Company was formed to facilitate the sale of all of the outstanding equity interests of Oxford, which owned crude oil, natural gas and natural gas liquid reserves and unevaluated acreage in the Appalachian Basin in Ohio (see Note 7—Subsequent Events). On June 26, 2013, Oxford was merged with and into the Company, with the Company being the surviving entity (the “Merger”). Prior to the Merger, both Oxford and the Company were 100% owned by Salt Run Capital, Inc., an Ohio corporation (“Salt Run”), and subsequent to the Merger, but prior to the acquisition by Eclipse Resources I, LP, all of the member interests of the Company were held by Salt Run. As such, the Merger has been treated as a reorganization of entities under common control and the historical results presented herein are those of Oxford for all periods. The financial statements of the Company, prior to the Merger, were not significant; therefore, no pro forma financial information is presented.

Note 2—Basis of Presentation

These financial statements and related notes are presented in accordance with accounting principles generally accepted in the United States of America (“GAAP”). Preparation in accordance with GAAP requires us to (1) adopt accounting policies within accounting rules set by the Financial Accounting Standards Board (“FASB”) and (2) make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and other disclosed amounts. Note 3—Summary of Significant Accounting Policies describes our significant accounting policies. Our management believes the major estimates and assumptions impacting our consolidated financial statements are the following:

•

estimates of proved reserves of oil and natural gas, which affect the calculations of depletion, depreciation and amortization and impairment of capitalized costs of oil and natural gas properties;

•

estimates of asset retirement obligations;

•

estimates of the fair value of oil and natural gas properties we own, particularly properties that we have not yet explored, or fully explored, by drilling and completing wells;

•

impairment of undeveloped properties and other assets; and

•

depreciation and depletion of property and equipment.

The estimated fair values of our unevaluated oil and natural gas properties affects our assessment of unevaluated capitalized costs.

Note 3—Summary of Significant Accounting Policies

(a) Cash and Cash Equivalents

F-73

ECLIPSE RESOURCES-OHIO, LLC

NOTES TO THE FINANCIAL STATEMENTS

FOR THE PERIOD FROM JANUARY 1, 2013 THROUGH JUNE 25, 2013

AND FOR THE YEAR ENDED DECEMBER 31, 2012

money market funds. The carrying amounts approximate fair value due to the short-term nature of these items. Cash in bank accounts at times may exceed federally insured limits.

(b) Accounts Receivable

Accounts receivable are carried at estimated net realizable value. Receivables deemed uncollectible are charged directly to expense. Trade credit is generally extended on a short-term basis and therefore, accounts receivable do not bear interest, although a finance charge may be applied to such receivables that are past due. A valuation allowance is provided for those accounts for which collection is estimated as doubtful; uncollectible accounts are written off and charged against the allowance. In estimating the allowance, management considers, among other things, how recently and how frequently payments have been received and the financial position of the party. The Company has established a $0.5 million allowance for a note receivable included in accounts receivable that has been deemed uncollectible as of June 25, 2013. No allowance was required as of December 31, 2012.

The Company accrues unbilled revenue due to timing differences between the delivery of natural gas and crude oil and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Company’s records and management estimates of the related commodity sales and transportation and compression fees which are, in turn, based upon applicable product prices. The Company had unbilled revenues at June 25, 2013 of $2.4 million and December 31, 2012 of $1.8 million, respectively, which were included in accounts receivable within the Company’s balance sheet.

(c) Materials Inventory

Materials inventory are stated at the lower of cost or market and consists of oil and gas drilling or repair items such as tubing, casing and pumping units. These items are primarily acquired for use in future drilling or repair operations and are carried at lower of cost or market. “Market,” in the context of valuation, represents net realizable value, which is the amount that the Company is allowed to bill to the joint interest accounts under joint operating agreements to which the Company is a party. As of June 25, 2013, the Company estimated that all of its tubular goods and equipment will be utilized within one year.

(d) Property and Equipment

Oil and Natural Gas Properties

The Company follows the successful efforts method of accounting for its oil and natural gas operations. Acquisition costs for oil and natural gas properties, costs of drilling and equipping productive wells, and costs of unsuccessful development wells are capitalized and amortized on an equivalent unit-of-production basis over the life of the remaining related oil and gas reserves. The estimated future costs of dismantlement, restoration, plugging and abandonment of oil and gas properties and related facilities disposal are capitalized when asset retirement obligations are incurred and amortized as part of depreciation, depletion and amortization expense (see “Depreciation, depletion and amortization (DD&A)” section below).

Costs incurred to acquire producing and non-producing leaseholds are capitalized. When conditions warrant, the Company capitalizes interest on unproved properties. All unproved leasehold acquisition costs are initially capitalized, including the cost of leasing agents, title work and due diligence. If the Company acquires leases in a prospective area, these costs are capitalized as unproved leasehold costs. If no leases are acquired by the Company with respect to the initial costs incurred or the Company discontinues leasing in a prospective area, the costs are charged to exploration expense. These costs are reviewed regularly and a final determination for

F-74

ECLIPSE RESOURCES-OHIO, LLC

NOTES TO THE FINANCIAL STATEMENTS

FOR THE PERIOD FROM JANUARY 1, 2013 THROUGH JUNE 25, 2013

AND FOR THE YEAR ENDED DECEMBER 31, 2012

unproved leasehold costs is made within one year of the costs being incurred. Unproved leasehold costs that are determined to have proved oil and gas reserves are transferred to producing leasehold costs.

A summary of property and equipment including oil and natural gas properties is as follows (in thousands):


	June 25, 2013			December 31, 2012
Oil and natural gas properties:
Subject to depletion	$	101,490		$	101,150
Not subject to depletion		4,096			267

Gross oil and natural gas properties		105,586			101,417
Less accumulated depreciation, depletion and amortization		(36,830	)		(31,423	)

Oil and natural gas properties, net		68,756			69,994

Other property and equipment		5,945			5,816
Less accumulated depreciation		(4,041	)		(3,922	)

Other property and equipment, net		1,904			1,894

Property and equipment, net	$	70,660		$	71,888

Exploration expenses, including geological and geophysical expenses and delay rentals for unevaluated oil and gas properties are charged to expense as incurred. Exploratory drilling costs are initially capitalized as unproved property, not subject to depletion, but charged to expense if and when the well is determined not to have found proved oil and gas reserves. Exploratory drilling costs are evaluated and a determination of classification is made within one-year from the completion of drilling. As of June 25, 2013 and December 31, 2012, there were no costs capitalized in connection with exploratory wells in progress.

Upon the sale or retirement of a complete field of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to the Company’s statements of operations. Upon the sale of an individual well, the proceeds are credited to accumulated depreciation and depletion within the Company’s balance sheets. Upon sale of an entire interest in an unproved property where the property had been assessed for impairment individually, a gain or loss is recognized in the Company’s consolidated statements of operations. If a partial interest in an unproved property is sold, any funds received are accounted for as a reduction of the cost in the interest retained.

Other Property and Equipment

Other property and equipment includes land, buildings, vehicles, computer equipment and software, telecommunications equipment, and furniture and fixtures. These items are recorded at cost.

(e) Revenue Recognition

Oil and natural gas sales revenue is recognized when produced quantities of oil and natural gas are delivered to a custody transfer point such as a pipeline, processing facility or a tank lifting has occurred, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sales is reasonably assured and the sales price is fixed or determinable. Revenues from the production of natural gas, crude oil or natural gas liquids in which the Company has an interest with other producers are recognized on the basis of the Company’s net revenue interest.

F-75

ECLIPSE RESOURCES-OHIO, LLC

NOTES TO THE FINANCIAL STATEMENTS

FOR THE PERIOD FROM JANUARY 1, 2013 THROUGH JUNE 25, 2013

AND FOR THE YEAR ENDED DECEMBER 31, 2012

In accordance with the terms of joint operating agreements, from time to time, the Company may be paid monthly fees for operating or drilling wells for outside owners. The fees are meant to recoup some of the operator’s general and administrative costs in connection with well and drilling operations and are accounted for as credits to general and administrative expense.

(f) Major Customers

The Company sells production volumes to various purchasers. From January 1, 2013 through June 25, 2013 and for the year ended December 31, 2012, there were two customers that accounted for 10% or more of total natural gas, natural gas liquids (NGLs) and oil sales. Management believes that the loss of any one customer would not have an adverse effect on the Company’s ability to sell natural gas, NGL and oil production. The following table sets forth the Company’s major customers and associated percentage of revenue for the periods indicated:


	January 1, 2013 through June 25, 2013			Year Ended December 31, 2012
Devco Oil Inc.		42.5	%		48.2	%
Ergon Inc.		20.4	%		23.2	%

Total		62.9	%		71.4	%

(g) Accumulated Other Comprehensive Loss

Comprehensive loss includes net loss and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under accounting principles generally accepted in the United States, have not been recognized in the calculation of net loss. These changes, other than net loss, are referred to as “other comprehensive loss” and for the Company they include pension benefit plans that require an employer to recognize the overfunded or underfunded status of a defined benefit retirement plan as an asset or liability in its balance sheet and to recognize changes in that funded status in the year in which the changes occur through other comprehensive loss. The Company’s pension plan was under-funded by $2.5 million and $3.9 million at June 25, 2013 and December 31, 2012, respectively.

(h) Depreciation, depletion and amortization (DD&A)

Oil and Natural Gas Properties

Depreciation, depletion, and amortization (DD&A) of capitalized costs of proved oil and natural gas properties is computed using the unit-of-production method on a field basis using total estimated proved reserves. The reserve base used to calculate DD&A for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. The reserve base used to calculate DD&A for drilling, completion and well equipment costs, which include development costs and successful exploration drilling costs, includes only proved developed reserves. DD&A expense for the period from January 1, 2013 through June 25, 2013 and for the year ended December 31, 2012 totaled approximately $5.4 million and $10.6 million, respectively.

Other Property and Equipment

Depreciation expense on other property and equipment is calculated using straight-line methods based on expected lives of the individual assets or groups of assets ranging from 5 to 40 years. Depreciation for the period

F-76

ECLIPSE RESOURCES-OHIO, LLC

NOTES TO THE FINANCIAL STATEMENTS

FOR THE PERIOD FROM JANUARY 1, 2013 THROUGH JUNE 25, 2013

AND FOR THE YEAR ENDED DECEMBER 31, 2012

from January 1, 2013 through June 25, 2013 and for the year ended December 31, 2012, totaled approximately $0.1 million and $0.2 million, respectively, and is included in depreciation, depletion, and amortization expense in the statements of operations.

(i) Impairment of Long-Lived Assets

The Company reviews its long lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount for that asset to its estimated fair value if such carrying amount exceeds the fair value.

The review of the Company’s oil and gas properties is done on a field level basis by determining if the historical cost of proved properties, less the applicable accumulated depletion, depreciation and amortization and abandonment, is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on the Company’s plans to continue to produce and develop proved reserves. Expected future cash flow from the sale of production of reserves is calculated based on estimated future prices. The Company estimates prices based upon current contracts in place, adjusted for basis differentials and market related information including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets.

Unproved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. An impairment charge is recorded if conditions indicate the Company will not explore the acreage prior to expiration of the applicable leases. There were no impairments of unproved oil and gas properties for the period from January 1, 2013 through June 25, 2013 or for the year ended December 31, 2012.

Proved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. There were no impairments of proved oil and gas properties for the period from January 1, 2013 through June 25, 2013 and for the year ended December 31, 2012.

(j) Income Taxes

During the periods presented, the Company was a wholly-owned Qualified Subchapter S subsidiary (“Q Sub”) of Salt Run Capital, Inc., which is taxed as an S corporation. Accordingly, the Company’s operations have been included within the tax filings of Salt Run and are passed through to its shareholder for U.S federal and state income tax purposes. As a result, the Company has not been subject to U.S. federal and most state income taxes as the shareholder of Salt Run is liable for any income tax on such earnings.

F-77

ECLIPSE RESOURCES-OHIO, LLC

NOTES TO THE FINANCIAL STATEMENTS

FOR THE PERIOD FROM JANUARY 1, 2013 THROUGH JUNE 25, 2013

AND FOR THE YEAR ENDED DECEMBER 31, 2012

Accounting Standards Codification (“ASC”) 740 provides that a tax benefit from an uncertain tax position may be recognized when it is more likely than not that the position will be sustained upon examination, including resolutions of any related appeals or litigation processes, based on the technical merits. Income tax positions must meet a more-likely-than-not recognition threshold at the effective date to be recognized upon the adoption of the uncertain tax position guidance and in subsequent periods. This interpretation also provides guidance on measurement, derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition.

Given the above discussion and the Company’s historical pass through status, the Company has determined that no federal or state income tax liability for uncertain tax positions is required to be recorded as of the adoption date nor for the years presented in the accompanying financial statements.

(k) Fair Value of Financial Instruments

The Company has established a hierarchy to measure its financial instruments at fair value which requires it to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The hierarchy defines three levels of inputs that may be used to measure fair value:

Level 1—Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date.

The estimated fair values of the Company’s financial instruments closely approximate the carrying amounts due to the short maturity of these instruments.

(l) Asset Retirement Obligation

The Company recognizes a legal liability for its asset retirement obligations (“ARO”) in accordance with the FASB’s Accounting Standards Codification (“ASC”) Topic ASC 410, “Asset Retirement and Environmental Obligations,” associated with the retirement of a tangible long-lived asset, in the period in which it is incurred or becomes determinable, with an associated increase in the carrying amount of the related long-lived asset. The cost of the tangible asset, including the initially recognized asset retirement cost, is depreciated over the useful life of the asset and accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. The Company measures the fair value of its ARO using expected future cash outflows for abandonment discounted back to the date that the abandonment obligation was measured using an estimated credit adjusted rate of 10.50% for the period January 1, 2013 through June 25, 2013 and for year ended December 31, 2012.

F-78

ECLIPSE RESOURCES-OHIO, LLC

NOTES TO THE FINANCIAL STATEMENTS

FOR THE PERIOD FROM JANUARY 1, 2013 THROUGH JUNE 25, 2013

AND FOR THE YEAR ENDED DECEMBER 31, 2012

and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset.

The following table sets forth the changes in the Company’s ARO liability for the periods indicated (in thousands):


	January 1, 2013 through June 25, 2013		Year Ended December 31, 2012
Asset retirement obligation at beginning of period	$	9,179	$	8,159
Liabilities incurred		—		153
Accretion		470		867

Asset retirement obligation at end of period	$	9,649	$	9,179

(m) Off-Balance Sheet Arrangements

The Company does not have any off-balance sheet arrangements.

(n) Segment Reporting

The Company operates in one industry segment: the oil and natural gas exploration and production industry in the United States. All of its operations are conducted in one geographic area of the United States. All revenues are derived from customers located in the United States.

(o) Recent Accounting Pronouncements

The FASB issued Accounting Standard Update (“ASU”) 2011-11, “Disclosures about Offsetting Assets and Liabilities” in December 2011, and issued ASU 2013-01, “Clarifying the Scope of Disclosures About Offsetting Assets and Liabilities” in January 2013. These ASUs create new disclosure requirements regarding the nature of an entity’s rights of setoff and related arrangements associated with its derivative instruments, repurchase agreements and securities lending transactions. Certain disclosures of the amounts of certain instruments subject to enforceable master netting arrangements would be required, irrespective of whether the entity has elected to offset those instruments in the statement of financial position. These ASUs are effective retrospectively for annual reporting periods beginning on or after January 1, 2013. The adoption of these ASUs will not impact the Company’s financial position, results of operations or liquidity.

F-79

ECLIPSE RESOURCES-OHIO, LLC

NOTES TO THE FINANCIAL STATEMENTS

FOR THE PERIOD FROM JANUARY 1, 2013 THROUGH JUNE 25, 2013

AND FOR THE YEAR ENDED DECEMBER 31, 2012

required under U.S. GAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under U.S. GAAP to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures required under U.S. GAAP that provide additional details about those amounts.

Note 4—Sale of Oil and Natural Gas Property Interests

During the year end December 31, 2012, the Company sold all of its interest in a producing oil and gas field for $4.4 million. The sales proceeds exceeded the Company’s cost basis, resulting in a gain of $2.8 million during 2012.

Note 5—Benefit Plans

The Company maintains a defined benefit pension plan covering 34 of its employees, of which two are retired, four have deferred vested termination, and one is a survivor. Benefits are based on the employee’s years of service and compensation. The Company’s plans are funded in conformity with the funding requirements of ASC Topic 715 “Compensation—Retirement Benefits” as of June 25, 2013 and December 31, 2012.

A summary of the pension benefit within the below tables is as follows (in thousands):


	January 1, 2013 through June 25, 2013			Year Ended December 31, 2012
Change in benefit obligation
Benefit obligation at beginning of year	$	10,096		$	7,025
Service cost		165			249
Interest cost		201			409
Actuarial (gain) loss		(1,194	)		2,461
Benefit paid		(223	)		(48	)

Benefit obligation at end of year	$	9,045		$	10,096


	January 1, 2013 through June 25, 2013			Year Ended December 31, 2012
Change in plan assets
Fair value of plan assets at beginning of year	$	6,177		$	5,411
Actual return on plan assets		569			805
Employer contributions		—			9
Benefits paid		(223	)		(48	)

Fair value of plan assets at end of year	$	6,523		$	6,177

F-80

ECLIPSE RESOURCES-OHIO, LLC

NOTES TO THE FINANCIAL STATEMENTS

FOR THE PERIOD FROM JANUARY 1, 2013 THROUGH JUNE 25, 2013

AND FOR THE YEAR ENDED DECEMBER 31, 2012


	June 25, 2013			Year Ended December 31, 2012
Assets in excess of (less than) benefit obligation
Vested amount	$	(6,787	)	$	(7,324	)
Additional benefits required		(2,258	)		(2,771	)

Projected benefit obligation		(9,045	)		(10,095	)
Funded amount		6,523			6,177

Unfunded amount	$	(2,522	)	$	(3,918	)


	June 25, 2013			Year Ended December 31, 2012
Other amounts recognized in other comprehensive loss
Assets in excess of (less than) benefit obligation at end of period	$	(2,522	)	$	(3,918	)

Amounts recorded in the consolidated balance sheet consist of:
Accrued benefit liability		(2,522	)		(3,918	)

Total recorded	$	(2,522	)	$	(3,918	)

Amounts recorded in accumulated other comprehensive loss consist of:
Transition obligation	$	(1,207	)	$	(1,416	)
Net gain (loss)		(393	)		(1,970	)

Total recorded in accumulated other comprehensive loss	$	(1,600	)	$	(3,386	)


	June 25, 2013	Year Ended December 31, 2012
Weighted average assumptions to determine benefit obligation
Discount rate	4.50%	4.00%
Expected rate of return	6.00%	6.00%
Rate of compensation increase	4.00%	4.00%
Inflation	3.00%	3.00%

F-81

ECLIPSE RESOURCES-OHIO, LLC

NOTES TO THE FINANCIAL STATEMENTS

FOR THE PERIOD FROM JANUARY 1, 2013 THROUGH JUNE 25, 2013

AND FOR THE YEAR ENDED DECEMBER 31, 2012


	January 1, 2013 through June 25, 2013			Year Ended December 31, 2012
Components of net periodic benefit cost
Service cost	$	165		$	249
Interest cost		201			409
Expected return on plan assets		(185	)		(323	)
Amortization of transition obligation		209			197

Net period benefit cost	$	390		$	532

The following benefit payments are expected to be paid over the next ten years (in thousands):


2014	$	50
2015		49
2016		104
2017		175
2018		222
2019—2023	$	2,422

The Company’s investment strategy for benefit plan assets reflects a long-term view, a careful assessment of the risks inherent in various asset classes and broad diversification to reduce the risk of the portfolio. Studies are periodically conducted to establish the preferred target asset allocation percentages. The Company along with its investment manager determines the investment policies and strategies for the plan assets to determine the allocations to the various asset classes based on the results of the studies targeted percentages. The following tables below set forth the breakout of asset categories (in thousands):


	June 25, 2013		Year Ended December 31, 2012
Plan assets by category
Equity securities	$	6,223	$	5,877
Debt securities		133		115
Cash		167		185

Total Assets	$	6,523	$	6,177


	June 25, 2013			Year Ended December 31, 2012
Plan assets by category
Equity securities		95.4	%		95.1	%
Debt securities		2.0	%		1.9	%
Cash		2.6	%		3.0	%

Total Assets		100	%		100	%

F-82

ECLIPSE RESOURCES-OHIO, LLC

NOTES TO THE FINANCIAL STATEMENTS

FOR THE PERIOD FROM JANUARY 1, 2013 THROUGH JUNE 25, 2013

AND FOR THE YEAR ENDED DECEMBER 31, 2012

The following tables set forth by level, within the fair value hierarchy, the fair value of pension assets and liabilities as of June 25, 2013 and December 31, 2012 (in thousands):


	June 25, 2013
	Level 1		Level 2		Level 3		Total
Pension assets	$	6,390		133		—	$	6,523


	December 31, 2012
	Level 1		Level 2		Level 3		Total
Pension assets	$	6,062		115		—	$	6,177

The fair value measurement levels are accounting terms that refer to different methods of valuing assets. The terms do not represent the relative risk or credit quality of an investment.

Note 6—Commitments and Contingencies

West Matter

In October 2011, Oxford filed a lawsuit in the Common Pleas Court of Belmont County, Ohio against Barry M. West and other landowners holding an interest in property subject to an oil and gas lease held by Oxford (the “West lawsuit”). The lawsuit was filed after the defendant landowners prevented Oxford from drilling a well on the property subject to the oil and gas lease. Oxford brought claims for breach of contract, unjust enrichment, and promissory estoppel, and sought a declaratory judgment that Oxford had a valid and enforceable lease with the defendant landowners. The defendant landowners filed counterclaims for defective execution of the lease, fraud, bad faith, breach of the implied duty to develop, improper assignment of the lease, and a claim that the lease was void as a lease in perpetuity contrary to law and the public policies of the State of Ohio. The Company filed a motion for summary judgment on July 15, 2013, and the defendant landowners filed their motion for summary judgment on August 26, 2013. On October 4, 2013, the trial court granted the defendant’s motion for summary judgment and held that the lease in question was “void ab initio” because the lease is a “no-term lease” and a “lease in perpetuity.” On October 8, 2013, the Company appealed the trial court’s judgment to the Seventh District Court of Appeals of the State of Ohio.

The judgment of the trial court has been stayed pending the outcome of this appeal. The Company believes that the trial court erred in finding that the lease in question was a perpetual lease, and that the judgment of the trial court that perpetual leases are “void ab initio” is not consistent with applicable Ohio law. However, since the ruling in the West lawsuit, adverse parties in other lawsuits in which the Company is involved have amended their complaints to make allegations similar to those made by the lessor in the West lawsuit, and the Company may be subject to additional lawsuits alleging that our leases are void. If the appeals court does affirm the court ruling and if other courts in Ohio adopt a similar interpretation of the language in our other leases with similar term language, such leases may also be determined to be void if the lessor challenges the validity of the lease. Consequently, this could result in a loss of the mineral rights and an impairment of the related assets which could have a material adverse impact on the Company’s financial statements.

The Company believes that there are strong grounds for appeal, and therefore, the Company intends to pursue all available appellate rights, and to vigorously defend against the claims in this lawsuit. Based on the merits of the appeal, the Company believes that it is not probable that trial court’s decision will be upheld in the appeal or that the Company will incur a material loss in the lawsuit, and accordingly, the Company has not recorded an accrual for the potential losses attributable to this lawsuit.

F-83

ECLIPSE RESOURCES-OHIO, LLC

NOTES TO THE FINANCIAL STATEMENTS

FOR THE PERIOD FROM JANUARY 1, 2013 THROUGH JUNE 25, 2013

AND FOR THE YEAR ENDED DECEMBER 31, 2012

Other Matters

From time to time, the Company may be a party to legal proceedings arising in the ordinary course of business. Management does not believe that a material loss is probable as a result of such proceedings.

Additionally, the Company is subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes environmental protection requirements that result in increased costs to the oil and natural gas industry in general, the business and prospects of the Company could be adversely affected.

The development of the Company’s oil and natural gas properties under their related leases will require a significant amount of capital. The timing of those expenditures will be determined by the lease provisions, the term of the lease and other factors associated with unproved leasehold acreage. To the extent that the Company is not the operator of oil and natural gas properties that it owns an interest in, the timing, and to some degree the amount, of capital expenditures will be controlled by the operator of such properties.

Note 7—Subsequent Events

On June 26, 2013, Eclipse Resources I, LP purchased 100% of the outstanding membership interests of the Company for a net cash purchase price of $652.5 million.

Management has evaluated subsequent events through February 21, 2014, the date the financial statements were available to be issued. Except as described herein, no reportable events have occurred subsequent to June 25, 2013 through the date of issuance of the accompanying financial statements that would, in the opinion of management, have a material impact on the aforementioned statements and related disclosures.

Note 8—Supplemental Oil and Natural Gas Information (unaudited)

(a) Capitalized Costs

A summary of the capitalized costs are contained in the table below (in thousands):


	June 25, 2013			Year Ended December 31, 2012
Oil and natural gas properties:
Proved properties	$	101,490		$	101,150
Unproved properties		4,096			267

Total oil and natural gas properties		105,586			101,417
Less accumulated depreciation, depletion and amortization		(36,830	)		(31,423	)

Net oil and natural gas properties capitalized	$	68,756		$	69,994

F-84

ECLIPSE RESOURCES-OHIO, LLC

NOTES TO THE FINANCIAL STATEMENTS

FOR THE PERIOD FROM JANUARY 1, 2013 THROUGH JUNE 25, 2013

AND FOR THE YEAR ENDED DECEMBER 31, 2012

(b) Costs Incurred in Oil and Natural Gas Property Acquisition and Development Activities

A summary of the Company’s cost incurred in oil and natural gas property acquisition and development activities is set forth below (in thousands):


	January 1, 2013 through June 25, 2013		Year Ended December 31, 2012
Acquisition costs:
Proved properties	$	53	$	—
Unproved properties		3,829		—
Development cost		—		—
Exploration expenses		183		409

Total acquisition, development and exploration costs	$	4,065	$	409

(c) Reserve Quantity Information

The following information represents estimates of the Company’s proved reserves as of June 25, 2013, and December 31, 2012, which have been prepared and presented under SEC rules. These rules require companies to prepare their reserve estimates using specified reserve definitions and pricing based on a 12-month unweighted average of the first-day-of-the-month pricing. The pricing that was used for estimates of the Company’s reserves as of June 25, 2013 and December 31, 2012 was based on an unweighted average 12-month average West Texas Intermediate posted price per Bbl for oil and a Henry Hub spot natural gas price per MMBtu for natural gas.

Subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. This requirement may limit the Company’s potential to record additional proved undeveloped reserves as it pursues its drilling program, particularly as it develops its significant acreage in the Appalachian Basin of Ohio. Moreover, the Company may be required to write down its proved undeveloped reserves if it does not drill on those reserves with the required five-year timeframe. The Company does not have any proved undeveloped reserves which have remained undeveloped for five years or more.

The Company’s proved oil and natural gas reserves are all located in the United States, within the state of Ohio. All of the estimates of the proved reserves at June 25, 2013 and December 31, 2012, were prepared by Netherland, Sewell & Associates, Inc. (“NSAI”), independent petroleum engineers. Proved reserves were estimated in accordance with the guidelines established by the SEC and the FASB.

Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and natural gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future.

F-85

ECLIPSE RESOURCES-OHIO, LLC

NOTES TO THE FINANCIAL STATEMENTS

FOR THE PERIOD FROM JANUARY 1, 2013 THROUGH JUNE 25, 2013

AND FOR THE YEAR ENDED DECEMBER 31, 2012

The following table provides a rollforward of the total proved reserves for the year ended December 31, 2012, and the period ended June 25, 2013, as well as proved developed and proved undeveloped reserves at the beginning and end of each respective year:


	Oil (MBbl)			Natural Gas (MMcf)			TOTAL (MMcfe)
January 1, 2012		1,139			8,723			15,557
Revisions		(18	)		(733	)		(841	)
Extensions and discoveries		41			381			627
Production		(101	)		(1,479	)		(2,085	)

December 31, 2012		1,061			6,892			13,258
Revisions		(50	)		470			170
Extensions and discoveries		—			1			1
Production		(53	)		(716	)		(1,034	)

End of period, June 25, 2013		958			6,647			12,395

Proved developed reserves:
January 1, 2012		1,139			8,723			15,557
December 31, 2012		1,061			6,892			13,258
Proved developed reserves:
January 1, 2013		1,061			6,892			13,258
June 25, 2013		958			6,647			12,395

Extensions and discoveries of 13 MMcfe and 627 MMcfe during the period ended June 25, 2013 and for the year ended December 31, 2012, resulted from the drilling of new wells during each year. There were no proved undeveloped reserves during the period ended June 25, 2013 and for the year ended December 31, 2012. Thousands of cubic feet of gas equivalent (“Mcfe”) and millions of cubic feet of gas equivalent (“MMcfe”) amounts have been calculated by using the conversion ratio of one barrel of oil (1 bbl) to six thousand cubic feet (6 Mcf) of natural gas.

F-86

ECLIPSE RESOURCES-OHIO, LLC

NOTES TO THE FINANCIAL STATEMENTS

FOR THE PERIOD FROM JANUARY 1, 2013 THROUGH JUNE 25, 2013

AND FOR THE YEAR ENDED DECEMBER 31, 2012

(d) Standardized Measure of Discounted Future Net Cash Flows

The standardized measure of discounted future net cash flows does not purport to be, nor should it be interpreted to present, the fair value of the oil and natural gas reserves of the property. An estimate of fair value would take into account, among other things, the recovery of reserves not presently classified as proved, the value of unproved properties, and consideration of expected future economic and operating conditions. The estimates of future cash flows and future production and development costs as of June 25, 2013, and December 31, 2012 are based on the unweighted arithmetic average first-day-of-the-month price for the preceding 12-month period. Estimated future production of proved reserves and estimated future production and development costs of proved reserves are based on current costs and economic conditions. All wellhead prices are held flat over the forecast period for all reserve categories. The estimated future net cash flows are then discounted at a rate of 10%. The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is as follows at June 25, 2013 and December 31, 2012 (in thousands):


	June 25, 2013			Year Ended December 31, 2012
Future cash inflows (total revenues)	$	112,472		$	118,778
Future production costs (severance and ad valorem taxes plus LOE)		(44,565	)		(46,045	)
Future development costs (capital costs)		(11,402	)		(11,276	)
Future income tax expense⁽¹⁾		—			—

Future net cash flows		56,505			61,457
10% annual discount for estimated timing of cash flows		(27,521	)		(30,542	)

Standardized measure of Discounted Future Net Cash Flow	$	28,984		$	30,915

(1)

Future net cash flows do not include the effects of income taxes on future revenues because Eclipse Resources-Ohio, LLC was a pass through entity not subject to entity-level income taxation as of June 25, 2013 and December 31, 2012. Accordingly, no provision for federal or state corporate income taxes has been provided because taxable income was passed through.

It is not intended that the FASB’s standardized measure of discounted future net cash flows represent the fair market value of the Company’s proved reserves. The Company cautions that the disclosures shown are based on estimates of proved reserve quantities and future production schedules which are inherently imprecise and subject to revision, and the 10% discount rate is arbitrary. In addition, costs and prices as of the measurement date are used in the determinations, and no value may be assigned to probable or possible reserves.

F-87

ECLIPSE RESOURCES-OHIO, LLC

NOTES TO THE FINANCIAL STATEMENTS

FOR THE PERIOD FROM JANUARY 1, 2013 THROUGH JUNE 25, 2013

AND FOR THE YEAR ENDED DECEMBER 31, 2012

(e) Changes in the Standardized Measure of Discounted Future Net Cash Flows

A summary of the changes in the standardized measure of discounted future net cash flows are contained in the table below (in thousands):


	June 25, 2013			Year Ended December 31, 2012
Standardized measure, beginning of the year	$	30,915		$	43,261
Net change in prices and production costs		(199	)		(5,431	)
Net change in future development costs		(94	)		—
Sales, less production costs		(5,543	)		(8,658	)
Extensions		—			1,555
Revisions of previous quantity estimates		489			(2,996	)
Accretion of discount		3,091			4,326
Changes in timing and other		325			(1,142	)

Period balance	$	28,984		$	30,915

F-88

ECLIPSE RESOURCES OPERATING, LLC

BALANCE SHEETS

(in thousands)

(Unaudited)


	March 31,			December 31,
	2014			2013
ASSETS
CURRENT ASSETS
Cash	$	1,182		$	1,025
Accounts receivable—related party		590			1,951
Prepaid expenses and other		511			512

Total current assets		2,283			3,488

PROPERTY AND EQUIPMENT, AT COST
Fixed assets		2,470			1,797
Accumulated depreciation		(467	)		(336	)

Total property and equipment		2,003			1,461

TOTAL ASSETS	$	4,286		$	4,949

LIABILITIES & MEMBERS’ EQUITY (DEFICIT)

CURRENT LIABILITIES
Accounts payable	$	911		$	422
Accrued liabilities		1,753			3,245
Deferred revenue		1,608			1,266

Total current liabilities		4,272			4,933

NONCURRENT LIABILITIES
Deferred revenue		17			17

Total liabilities		4,289			4,950

COMMITMENTS AND CONTINGENCIES
MEMBERS’ EQUITY (DEFICIT)
Total members’ equity (deficit)		(3	)		(1	)

TOTAL LIABILITIES AND MEMBERS’ EQUITY (DEFICIT)	$	4,286		$	4,949

The accompanying notes are an integral part of these financial statements.

F-89

ECLIPSE RESOURCES OPERATING, LLC

STATEMENTS OF OPERATIONS

(in thousands)

(Unaudited)


	Three Months Ended March 31,
	2014		2013
REVENUES
Management fee income	$	7,494	$	1,349

OPERATING EXPENSES
Salaries, wages and employee benefits		5,308		962
Employee recruiting and relocation		498		71
Organizational, legal and professional services		5		3
Travel and business meals		309		30
Facilities, supplies and software		299		75
Depreciation and amortization		131		21
Professional services and other operating		944		186

Total operating expenses		7,494		1,348

OPERATING LOSS		—		1
OTHER INCOME (EXPENSE)
Interest income (expense)		1		(1	)

Total other income/(expense)		1		(1	)

NET INCOME	$	1	$	—

The accompanying notes are an integral part of these financial statements.

F-90

ECLIPSE RESOURCES OPERATING, LLC

STATEMENT OF MEMBERS’ EQUITY (DEFICIT)

(in thousands)

(Unaudited)


	Total Members’ Equity (Deficit)
Balance at December 31, 2013	$	(1	)
Distributions		(3	)
Net income		1

Balance at March 31, 2014	$	(3	)

The accompanying notes are an integral part of this financial statement.

F-91

ECLIPSE RESOURCES OPERATING, LLC

STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)


	Three Months Ended March 31,
	2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	1		$	—
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense		131			21
Changes in assets and liabilities:
Accounts receivable—related party		1,361			(50	)
Prepaids and other assets		1			25
Accounts payable and accrued liabilities		(1,003	)		126
Deferred revenue		342			—

Net cash provided by operating activities		833			122

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures for property and equipment		(673	)		(41	)

Net cash used in investing activities		(673	)		(41	)

CASH FLOWS FROM FINANCING ACTIVITIES
Repayment of long-term debt		—			(4	)
Capital distributions		(3	)		(6	)

Net cash used in financing activities		(3	)		(10	)

Net increase in cash		157			71
Cash at beginning of year		1,025			11

Cash at end of year	$	1,182		$	82

The accompanying notes are an integral part of these financial statements.

F-92

ECLIPSE RESOURCES OPERATING, LLC

NOTES TO FINANCIAL STATEMENTS FOR

THE THREE MONTHS ENDED MARCH 31, 2014 AND 2013

(UNAUDITED)

Note 1—Organization and Nature of Operations

Eclipse Resources Operating, LLC (“Eclipse Operating” or the “Company”), a Delaware limited liability company, was formed on December 20, 2010 to manage the operations of oil and natural gas ventures. Eclipse Operating is owned equally by Benjamin W. Hulburt, Christopher K. Hulburt and Thomas S. Liberatore.

The Company provides management services for Eclipse Resources I, LP (“Eclipse I”). Management services include providing personnel, equipment, office space and other goods and services as needed to manage the operations of Eclipse I. Pursuant to an Administrative Services Agreement with Eclipse I, the Company receives a monthly management fee for these services. Each of the owners of Eclipse Operating also owns direct and indirect interests in Eclipse I.

Note 2—Basis of Presentation

The accompanying financial statements, which are unaudited except the balance sheet at December 31, 2013 which is derived from audited financial statements, are presented in accordance with the requirements of and accounting principles generally accepted in the United States (“U.S. GAAP”) for interim reporting. They do not include all disclosures normally made and contained in annual financial statements. In management’s opinion, all adjustments necessary for a fair presentation of the Company’s financial position, results of operations and cash flows for the periods disclosed have been made. These interim consolidated financial statements should be read in conjunction with the audited financial statements and notes thereto presented in the Company’s financial statements for the year ended December 31, 2013. The results of operations for the three months ended March 31, 2014 may not necessarily be indicative of the results of operations for the full year ending December 31, 2014. Preparation in accordance with GAAP requires the Company to (1) adopt accounting policies within accounting rules set by the Financial Accounting Standards Board (“FASB”) and (2) make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and other disclosed amounts. Note 3—Summary of Significant Accounting Policies describes our significant accounting policies.

Actual results may differ from estimates and assumptions of future events and these differences could be material.

Note 3—Summary of Significant Accounting Policies

(a) Cash

(b) Accounts Receivable

F-93

ECLIPSE RESOURCES OPERATING, LLC

NOTES TO FINANCIAL STATEMENTS FOR

THE THREE MONTHS ENDED MARCH 31, 2014 AND 2013

(UNAUDITED)

among other things, how recently and how frequently payments have been received and the financial position of the party. The Company did not deem any of its accounts receivable uncollectable as of March 31, 2014 or December 31, 2013. The majority of accounts receivable at March 31, 2014 and December 31, 2013 are due from Eclipse I.

(c) Property and Equipment

Property and equipment include vehicles, computer equipment and software, telecommunications equipment, and furniture and fixtures. These items are recorded at cost, or fair value if acquired through a business acquisition. Depreciation is computed using the straight-line method over the estimated useful lives of the assets, or the estimated remaining lease or license term in the case of computer software and leasehold improvements, whichever is shorter. Depreciation expense for the three months ended March 31, 2014 and 2013 was $0.13 million and $0.02 million, respectively.

Capitalized Property and Equipment

During the three months ended March 31, 2014 and 2013, the Company acquired $0.7 million and $0.04 million, respectively, in capitalized property and equipment additions as shown below (in thousands):


	For the Three Months Ended March 31,
	2014		2013
Property and Equipment additions
Computer hardware and equipment	$	367	$	25
Computer software		285		—
Furniture and fixtures		13		16
Leasehold improvements		8		—

Total property and equipment additions	$	673	$	41

(d) Revenue Recognition

The Company receives a fee for the management of Eclipse I equal to the actual expenditures incurred for such operations. This reimbursement is recorded by the Company as management fee income. As of March 31, 2014 and December 31, 2013, the Company had received $1.6 million and $1.3 million, respectively, of management fee income that relates to services and costs that will be earned in future periods and is being treated as deferred revenue. Such amounts will be accounted for as revenues during the period to which they relate and are earned.

(e) Impairment

The Company evaluates the recoverability of property and equipment for possible impairment whenever events or circumstances indicate that the carrying amount of such assets may not be recoverable. In addition to the recoverability assessment, the Company routinely reviews the remaining estimated useful lives of property and equipment. If the estimated useful life assumption for any asset is reduced, the remaining unamortized balance would be amortized or depreciated over the revised estimated useful life.

F-94

ECLIPSE RESOURCES OPERATING, LLC

NOTES TO FINANCIAL STATEMENTS FOR

THE THREE MONTHS ENDED MARCH 31, 2014 AND 2013

(UNAUDITED)

(f) Income Taxes

Eclipse Operating has elected to be taxed as an S Corporation, and as a result, the Company is not subject to U.S. federal and most state income taxes. Accordingly, the Company’s members are liable for income taxes in regards to their distributive share of the Company’s taxable income.

(g) Lease Obligations

The Company leases office space under an operating lease that expires in 2016. The lease terms begin on the date of initial possession of the leased property for purposes of recognizing lease expense on a straight-line basis over the term of the lease. Eclipse Operating does not assume renewals in its determination of the lease term unless the renewals are deemed to be reasonably assured at lease inception.

Note 4—Members’ Equity

Each member owns a 33.33% membership interest in the Company. Timing of admission into the Company will result in differing member equity balances, however, under the terms of the Company operating agreement, each member shares equally in the Company’s income or loss, or distributions regardless of their equity in the Company. In addition, taxable income and the allocation of taxable income for distributions may vary substantially from net income reported in the accompanying financial statements.

Note 5—Debt

The Company maintains a $400,000 credit line. The balance is paid monthly with amounts outstanding over 30 days charged an annualized interest rate of 12.99%. There were no amounts past due at either March 31, 2014 or December 31, 2013.

Note 6—Related Party Transactions

The Company manages the operations of Eclipse I under the terms of an Administrative Services Agreement. The members of the Company also own direct and indirect interests in Eclipse I.

F-95

ECLIPSE RESOURCES OPERATING, LLC

NOTES TO FINANCIAL STATEMENTS FOR

THE THREE MONTHS ENDED MARCH 31, 2014 AND 2013

(UNAUDITED)

Eclipse Operating. The reimbursement of these expenses is recognized as management fee income by the Company. In addition, the Company incurs costs related to the acquisition of leases and other oil and gas assets, which costs are passed through to Eclipse I as appropriate.

During the three months ended March 31, 2014 and 2013, the Company recognized $7.5 million and $1.3 million, respectively, in management fee income from Eclipse I. At March 31, 2014 and December 31, 2013, Eclipse I owed the Company $0.5 million and $2.0 million, respectively, in accrued management fees.

The Company periodically incurs expenses for the use of an airplane primarily owned by an officer of the Company. Expenses are billed on a per use basis and totaled $0.04 million and $0 for the three months ended March 31, 2014 and 2013.

Note 7—Commitments and Contingencies

From time to time, the Company may be a party to legal proceedings arising in the ordinary course of business. Eclipse Operating is not currently a party to any legal proceedings and believes the likelihood of being a party to a proceeding that could have a material adverse effect on its financial condition, results of operations or cash flows is remote.

Environmental Matters

The Company is subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes environmental protection requirements that result in increased costs to the oil and natural gas industry in general, the business and prospects of Eclipse Operating could be adversely affected.

Leases

The Company leases 8,072 square feet of office space for its corporate headquarters in State College, Pennsylvania. The space is leased in two parts, 5,246 square feet of which expires in July 2016. The remaining 2,826 square feet expires in July 2015.

Operating lease expense totaled $0.07 million and $0.03 million for the three months ended March 31, 2014 and 2013, respectively.

Note 8—Employee Benefit Plan

The Company currently maintains a retirement plan intended to provide benefits under section 401(K) of the Internal Revenue Code, under which employees are allowed to contribute portions of their compensation to a tax-qualified retirement account. Under the 401(K) plan, the Partnership provides matching contributions equal to 100% of the first 6% of employees’ eligible compensation contributed to the plan. The Company contributed $0.2 million and $0.02 million in matching contributions for the three months ended March 31, 2014 and 2013, respectively.

Note 9—Subsequent Events

Management has evaluated subsequent events through May 2, 2014 and believes that there are no events that would have a material impact on the aforementioned financial statements and related disclosures.

F-96

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Managers and Members

Eclipse Resources Operating, LLC

We have audited the accompanying balance sheets of Eclipse Resources Operating, LLC (a Delaware limited liability company) (the “Company”) as of December 31, 2013 and 2012, and the related statements of operations, changes in members’ equity (deficit), and cash flows for each of the two years in the period ended December 31, 2013. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Eclipse Resources Operating, LLC as of December 31, 2013 and 2012, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2013 in conformity with accounting principles generally accepted in the United States of America.

/s/ GRANT THORNTON LLP

Cleveland, Ohio

February 21, 2014

F-97

ECLIPSE RESOURCES OPERATING, LLC

BALANCE SHEETS

(in thousands)


	December 31,
	2013			2012
ASSETS
CURRENT ASSETS
Cash	$	1,025		$	11
Accounts receivable—related party		1,951			382
Prepaid expenses and other		512			61

Total current assets		3,488			454

PROPERTY AND EQUIPMENT, AT COST
Fixed assets		1,797			361
Accumulated depreciation		(336	)		(106	)

Total property and equipment		1,461			255

TOTAL ASSETS	$	4,949		$	709

LIABILITIES & MEMBERS’ EQUITY (DEFICIT)

CURRENT LIABILITIES
Accounts payable	$	422		$	143
Accrued liabilities		3,245			329
Deferred revenue		1,266			230

Total current liabilities		4,933			702

NONCURRENT LIABILITIES
Deferred revenue		17			—

Total liabilities		4,950			702

COMMITMENTS AND CONTINGENCIES
MEMBERS’ EQUITY (DEFICIT)
Total members’ equity (deficit)		(1	)		7

TOTAL LIABILITIES AND MEMBERS’ EQUITY (DEFICIT)	$	4,949		$	709

The accompanying notes are an integral part of these financial statements.

F-98

ECLIPSE RESOURCES OPERATING, LLC

STATEMENTS OF OPERATIONS

(in thousands)


	Year Ended December 31,
	2013			2012
REVENUES
Management fee income	$	13,658		$	4,091

OPERATING EXPENSES
Salaries, wages and employee benefits		9,286			3,068
Employee recruiting and relocation		805			181
Oil and gas related		—			6
Organizational, legal and professional services		16			14
Travel and business meals		570			158
Facilities, supplies and software		692			230
Depreciation and amortization		230			72
Professional services and other operating		2,059			362

Total operating expenses		13,658			4,091

OPERATING LOSS		—			—
OTHER INCOME (EXPENSE)
Other income		—			3
Interest expense		(2	)		(3	)

Total other expense		(2	)		—

NET LOSS	$	(2	)	$	—

The accompanying notes are an integral part of these financial statements.

F-99

ECLIPSE RESOURCES OPERATING, LLC

STATEMENTS OF MEMBERS’ EQUITY (DEFICIT)

FOR THE YEARS ENDED DECEMBER 31, 2013 AND 2012

(in thousands)


	Total Members’ Equity (Deficit)
Balance, December 31, 2011	$	84
Net income		—
Capital distributions		(77	)

Balance, December 31, 2012		7
Net loss		(2	)
Capital distributions		(6	)

Balance, December 31, 2013	$	(1	)

The accompanying notes are an integral part of these financial statements.

F-100

ECLIPSE RESOURCES OPERATING, LLC

STATEMENTS OF CASH FLOWS

(in thousands)


	Year Ended December 31,
	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(2	)	$	—
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and amortization expense		230			72
Changes in assets and liabilities
Accounts receivable—related party		(1,568	)		(27	)
Prepaids and other assets		(453	)		(2	)
Accounts payable and accrued liabilities		3,196			(99	)
Deferred revenue		1,053			110

Net cash provided by operating activities		2,456			54

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures for property and equipment		(1,436	)		(96	)

Net cash used in investing activities		(1,436	)		(96	)

CASH FLOWS FROM FINANCING ACTIVITIES
Capital distributions		(6	)		(77	)

Net cash used in financing activities		(6	)		(77	)

Net increase (decrease) in cash		1,014			(119	)
Cash at beginning of year		11			130

Cash at end of year	$	1,025		$	11

The accompanying notes are an integral part of these financial statements.

F-101

ECLIPSE RESOURCES OPERATING, LLC

NOTES TO FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2013 AND 2012

Note 1—Organization and Nature of Operations

Note 2—Basis of Presentation

These financial statements and related notes are presented in accordance with accounting principles generally accepted in the United States of America (“GAAP”). Preparation in accordance with GAAP requires the Company to (1) adopt accounting policies within accounting rules set by the Financial Accounting Standards Board (“FASB”) and (2) make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and other disclosed amounts. Note 3—Summary of Significant Accounting Policies describes our significant accounting policies.

Actual results may differ from estimates and assumptions of future events and these differences could be material.

Note 3—Summary of Significant Accounting Policies

(a) Cash

(b) Accounts Receivable

Accounts receivable are carried at estimated net realizable value. Receivables deemed uncollectible are charged directly to expense. Trade credit is generally extended on a short-term basis and therefore, accounts receivable do not bear interest, although a finance charge may be applied to such receivables that are past due. A valuation allowance is provided for those accounts for which collection is estimated as doubtful; uncollectible accounts are written off and charged against the allowance. In estimating the allowance, management considers, among other things, how recently and how frequently payments have been received and the financial position of the party. The Company did not deem any of its accounts receivable uncollectable as of December 31, 2013 or December 31, 2012. All accounts receivable at December 31, 2013 and 2012 are due from Eclipse I.

(c) Property and Equipment

Property and equipment include vehicles, computer equipment and software, telecommunications equipment, and furniture and fixtures. These items are recorded at cost, or fair value if acquired through a business acquisition. Depreciation is computed using the straight-line method over the estimated useful lives of the assets, or the estimated remaining lease or license term in the case of computer software and leasehold improvements, whichever is shorter. Depreciation expense for the years ended December 31, 2013 and 2012 was $0.2 million and $0.1 million, respectively.

F-102

ECLIPSE RESOURCES OPERATING, LLC

NOTES TO FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2013 AND 2012

Capitalized Property and Equipment

During the years ended December 31, 2013 and 2012, the Company acquired $1.4 million and $0.1 million, respectively, in capitalized property and equipment additions as shown below (in thousands):


	December 31,
	2013		2012
Property and Equipment additions
Computer hardware and equipment	$	545	$	31
Computer software		702		41
Furniture and fixtures		146		24
Leasehold improvements		43		—

Total property and equipment additions	$	1,436	$	96

(d) Revenue Recognition

The Company receives a fee for the management of Eclipse I equal to the actual expenditures incurred for such operations. This reimbursement is recorded by the Company as management fee income. At December 31, 2013 and 2012, the Company had received $1.3 million and $0.2 million, respectively, of management fee income that relates to services and costs that will be earned in future periods and is being treated as deferred revenue. Such amounts will be accounted for as revenues during the period to which they relate and are earned.

(e) Impairment

(f) Income Taxes

F-103

ECLIPSE RESOURCES OPERATING, LLC

NOTES TO FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2013 AND 2012

(g) Lease Obligations

The Company leases office space under an operating leases that expires in 2016. The lease terms begin on the date of initial possession of the leased property for purposes of recognizing lease expense on a straight-line basis over the term of the lease. Eclipse Operating does not assume renewals in its determination of the lease term unless the renewals are deemed to be reasonably assured at lease inception.

Note 4—Members’ Equity

Each member owns a 33.33% membership interest in the Company. Timing of admission into the Company will result in differing member equity balances, however, under the terms of the Company operating agreement, each member shares equally in the Company’s income or loss, or distributions regardless of their equity in the partnership. In addition, taxable income and the allocation of taxable income for distributions may vary substantially from net income reported in the accompanying financial statements.

Note 5—Debt

The Company maintains a $425,000 credit line. The balance is paid monthly with amounts outstanding over 30 days charged an annualized interest rate of 12.99%. There were no outstanding amounts at either December 31, 2013 or 2012.

Note 6—Related Party Transactions

The Company manages the operations of Eclipse I under the terms of an Administrative Services Agreement. The members of the Company also own direct and indirect interests in Eclipse I.

In return for performing its duties and obligations under the Administrative Services Agreement (“Agreement”), Eclipse Operating receives a monthly management fee equal to the sum of all costs and expenses incurred, in the management of Eclipse I. These costs include salaries, wages and benefits, rent, insurance, and other expenses and costs required to operate Eclipse I. These expenses are billed in arrears at the actual cost to Eclipse Operating. The reimbursement of these expenses is recognized as management fee income by the Company. In addition, the Company incurs costs related to the acquisition of leases and other oil and gas assets, which costs are passed through to Eclipse I as appropriate.

During the years ended December 31, 2013 and December 31, 2012, the Company recognized $13.7 million and $4.1 million, respectively, in management fee income from Eclipse I. At December 31, 2013 and December 31, 2012, Eclipse I owed the Company $2.0 million and $0.4 million, respectively, in accrued management fees.

The Company periodically incurs expenses for the use of an airplane primarily owned by an officer of the company. Expenses are billed on a per use basis and totalled $.03 million for the year ended December 31, 2013.

Note 7—Commitments and Contingencies

F-104

ECLIPSE RESOURCES OPERATING, LLC

NOTES TO FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2013 AND 2012

Environmental Matters

Leases

Eclipse Operating leases two office space locations in State College, Pennsylvania. The Company leases 8,072 square feet of office space with an initial term of three years with an option to renew for an additional two years. The Company extended this option for an additional year, which expires in 2015.

Following is a schedule, by year, of the future minimum lease payments required under operating lease as of December 31, 2013 (in thousands):


2014	$	133
2015		78

Total minimum lease payments	$	211

Operating lease expense totaled $0.2 million and $0.1 million for the years ended December 31, 2013 and December 31, 2012, respectively.

Note 8—Employee Benefit Plan

The Company currently maintains a retirement plan intended to provide benefits under section 401(K) of the Internal Revenue Code, under which employees are allowed to contribute portions of their compensation to a tax-qualified retirement account. Under the 401(K) plan, the Partnership provides matching contributions equal to 100% of the first 6% of employees’ eligible compensation contributed to the plan. The Company contributed $0.2 million and $0.1 million in matching contributions for the year ended December 31, 2013 and 2012, respectively.

Note 9—Subsequent Events

F-105

ANNEX A

Glossary of Oil and Natural Gas Companies

The following terms are used in this prospectus to refer to the following entities and their respective subsidiaries and affiliates:

“Antero” or “Antero Resources” refers to Antero Resources Corporation.

“Blue Racer” refers to Blue Racer Midstream, LLC.

“Cabot Oil & Gas” refers to Cabot Oil & Gas Corporation.

“Carrizo” refers to Carrizo Oil & Gas, Inc.

“Chesapeake Energy” or “Chesapeake” refers to Chesapeake Energy Corporation.

“Eureka Hunter” refers to Eureka Hunter Pipeline LLC, a subsidiary of Magnum Hunter.

“EXCO Resources” refers to Exco Resources, Inc.

“Gulfport Energy” or “Gulfport” refers to Gulfport Energy Corporation.

“Hess” refers to the Hess Corporation.

“Magnum Hunter” or “MHR” refers to Magnum Hunter Resources Corporation.

“MarkWest Energy Partners” refers to MarkWest Energy Partners, L.P.

“PDC” refers to PDC Energy, Inc.

“Rex Energy” or “Rex” refers to Rex Energy Corporation.

“Shell Chemical” refers to Shell Chemical LP.

“Stone Energy” refers to Stone Energy Corporation.

“Triad Hunter” refers to Triad Hunter, LLC, a subsidiary of Magnum Hunter.

II.

Glossary of Oil and Natural Gas Terms

The following are abbreviations and definitions of some of the oil and gas industry terms used in this prospectus:

“Bbl” refers to one stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate or NGLs.

“Bcf” refers to one billion cubic feet of natural gas.

“Bcfe” refers to one billion cubic feet of natural gas equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

“Boe” refers to barrels of oil equivalent, determined using the ratio of one Bbl of crude oil, condensate or natural gas liquids to six Mcf of natural gas.

A-1

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

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

“Delineation” refers to the process of placing a number of wells in various parts of a reservoir to determine its boundaries and production characteristics.

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

“Development well” refers to a well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

“Dry hole” refers to a well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

“Exploratory well” refers to a well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir. Generally, an exploratory well is any well that is not a development well, a service well, or a stratigraphic test well.

“Field” refers to an area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms “structural feature” and “stratigraphic condition” are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

“Formation” refers to a layer of rock which has distinct characteristics that differs from nearby rock.

“Gross acres” or “gross wells” refers to the total acres or wells, as the case may be, in which a working interest is owned.

“Horizontal drilling” refers to a drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.

“Identified drilling locations” refers to total gross (net) resource play locations that we may be able to drill on our existing acreage. Actual drilling activities may change depending on the availability of capital, regulatory approvals, seasonal restrictions, natural gas and oil prices, costs, drilling results and other factors.

“MBbls” refers to one thousand barrels of crude oil, condensate or NGLs.

“Mcf” refers to one thousand cubic feet of natural gas.

“Mcfe” refers to one thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or NGLs.

“MMBbls” refers to one million barrels of crude oil, condensate or NGLs.

“MMcf” refers to one million cubic feet of natural gas.

A-2

“MMcfe” refers to one million cubic feet of gas equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

“MMBoe” refers to one million barrels of oil equivalent, determined using the ratio of one Bbl of crude oil, condensate or natural gas liquids to six Mcf of natural gas.

“MMBtu” refers to one million Btu.

“Net revenue interest” refers to an owner’s interest in the revenues of a well after deducting proceeds allocated to royalty and overriding interests.

“Net acres” refers to the amount of leased real estate that a petroleum and/or natural gas company has a true working interest in. Net acres express actual percentage interest when a company shares its working interest with another company; the total acreage under lease by a company is referred to as gross acres. Net acres account for the company’s percentage interest, multiplied by the gross acreage. If a company holds the entire working interest, its net acreage and gross acreage will be the same.

“NGLs” refers to natural gas liquids, which are a mixture of light hydrocarbons that exist in the gaseous phase and are recovered as liquids in gas processing plants. NGLs differ from condensate in two principal respects: (1) NGLs are extracted and recovered in gas plants rather than lease separators or other lease facilities, and (2) NGLs include very light hydrocarbons (ethane, propane, butanes) as well as the pentanes-plus that are the main constituents of condensates.

“NYMEX” refers to the New York Mercantile Exchange.

“Productive well” refers to a well that is expected to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceeds production expenses and taxes.

“Prospect” refers to a geological feature mapped as a location or probable location of a commercial oil and/or gas accumulation. A prospect is defined as a result of geophysical and geological studies allowing the identification and quantification of uncertainties, probabilities of success, estimates of potential resources and economic viability.

“Proved developed reserves” refers to proved reserves that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well, and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

“Proved oil and gas reserves” refers to those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible-from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations-prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

“Proved undeveloped reserves” refers to proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

A-3

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir (as defined in Rule 4-10(a)(2) of Regulation S-X), or by other evidence using reliable technology establishing reasonable certainty.

“Psi” refers to pounds per square inch.

“PV-10” refers to, when used with respect to natural gas and oil reserves, the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production, future development and abandonment costs, using sales prices used in estimating proved oil and gas reserves and costs in effect at the determination date, before income taxes, and without giving effect to non-property-related expenses, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the SEC.

“Reservoir” refers to a porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.

“Spacing” refers to the distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.

“Standardized measure” refers to discounted future net cash flows estimated by applying sales prices used in estimating proved oil and gas reserves to the estimated future production of year-end proved reserves. Future cash inflows are reduced by estimated future production and development costs based on period-end costs to determine pre-tax cash inflows. Future income taxes, if applicable, are computed by applying the statutory tax rate to the excess of pre-tax cash inflows over our tax basis in the natural gas and oil properties. Future net cash inflows after income taxes are discounted using a 10% annual discount rate.

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

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

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

“Working interest” refers to a company’s equity interest in a project before reduction for royalties or production share owed to others under the applicable fiscal terms.

A-4

30,300,000 Shares

LOGO

Eclipse Resources Corporation

Common Stock

PROSPECTUS

June 19, 2014

Citigroup

Goldman, Sachs & Co.

Morgan Stanley

Barclays

BMO Capital Markets

Deutsche Bank Securities

KeyBanc Capital Markets

RBC Capital Markets

Jefferies

Wells Fargo Securities

Capital One Securities

Johnson Rice & Company L.L.C.

Scotiabank/Howard Weil

Simmons & Company International

Until July 14, 2014, all dealers that buy, sell or trade our common stock, whether or not participating in this offering, may be required to deliver a prospectus. This requirement is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.