S-1/A 1 d673604ds1a.htm S-1/A S-1/A
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As filed with the Securities and Exchange Commission on June 9, 2014

Registration No. 333-195679

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

Amendment No. 2

to

FORM S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

 

 

ECLIPSE RESOURCES CORPORATION

(Exact name of registrant as specified in its charter)

 

 

 

Delaware   1311   46-4812998

(State or other jurisdiction of

incorporation or organization)

 

(Primary Standard Industrial

Classification Code Number)

 

(I.R.S. Employer

Identification Number)

2121 Old Gatesburg Road, Suite 110

State College, Pennsylvania 16803

(866) 590-2568

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

 

 

Benjamin W. Hulburt

Chairman, President and Chief Executive Officer

Eclipse Resources Corporation

2121 Old Gatesburg Road, Suite 110

State College, Pennsylvania 16803

(866) 590-2568

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

 

 

Copies to:

 

Glen J. Hettinger

Bryn A. Sappington

Fulbright & Jaworski LLP

(a member of Norton Rose Fulbright)

2200 Ross Avenue, Suite 2800
Dallas, Texas 75201

(214) 855-8000

 

Sean T. Wheeler

Latham & Watkins LLP

811 Main Street, Suite 3700

Houston, Texas 77002

(713) 546-5400

 

 

Approximate date of commencement of proposed sale to the public: As soon as practicable after the effective date of this registration statement.

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

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

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

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

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

 

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

 

 

CALCULATION OF REGISTRATION FEE

 

 

 

Title of Each Class of

Securities to be Registered

  

Amount

to be
Registered(1)

    

Proposed

Maximum

Offering Price

Per Share(2)

    

Proposed

Maximum

Aggregate

Offering Price(1)(2)

    

Amount of

Registration Fee(3)

 

Common Stock, par value $0.01 per share

     34,845,000       $ 30.00       $ 1,045,350,000       $ 134,641.08   

 

 
(1) Estimated pursuant to Rule 457(a) under the Securities Act of 1933, as amended. Includes 4,545,000 additional shares of common stock that the underwriters have the option to purchase.
(2) Estimated solely for the purpose of calculating the registration fee.
(3) The Registrant previously paid $12,880 of the total registration fee in connection with the previous filing of this Registration Statement.

 

 

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

 

 

 


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The information in this prospectus is not complete and may be changed. Neither we nor the selling stockholders may sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell nor does it seek an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

 

SUBJECT TO COMPLETION, DATED JUNE 9, 2014

 

PRELIMINARY 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.”

 

We anticipate that the initial public offering price will be between $27.00 and $30.00 per share.

 

 

 

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

 

 

 

     Per Share      Total  

Public offering price

   $                    $                

Underwriting discounts and commissions(1)

   $         $     

Proceeds, before expenses, to us

   $         $     

Proceeds to the selling stockholders

   $         $     

 

(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                     , 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                     , 2014


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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.


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TABLE OF CONTENTS

 

     Page  

Summary

     1   

Risk Factors

     20   

Cautionary Statement Regarding Forward-Looking Statements

     51   

Use of Proceeds

     53   

Dividend Policy

     55   

Capitalization

     56   

Dilution

     57   

Selected Historical Consolidated and Unaudited Pro Forma Financial Data

     59   

Management’s Discussion and Analysis of Financial Condition and Results of Operations

     61   

Business

     85   

Management

     115   

Executive Compensation

     124   

Principal and Selling Stockholders

     132   

Corporate Reorganization

     135   

Certain Relationships and Related Party Transactions

     138   

Description of Capital Stock

     141   

Shares Eligible for Future Sale

     145   

Material U.S. Federal Income Tax Consequences to Non-U.S. Holders

     147   

Underwriting

     151   

Legal Matters

     156   

Experts

     156   

Where You Can Find Additional Information

     157   

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.”

 

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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.

 

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Industry and Market Data

 

The market data and certain other statistical information used throughout this prospectus are based on independent industry publications, government publications, 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.

 

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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 initial public offering price of the shares of our common stock will be $28.50 per share (which is the midpoint of the price range set forth on the cover of this prospectus), (ii) the underwriters’ option to purchase additional shares from the selling stockholders is not exercised, and (iii) 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.”

 

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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.

 

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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.”

 

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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 28/64th 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.

 

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

 

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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.

 

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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.

 

   

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

 

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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 $588.8 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.

 

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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)  

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

 

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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.

 

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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.

 

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

 

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.

 

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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 5th 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.

 

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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.

 

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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

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 34,845,000 shares of common stock in this offering.

 

Use of proceeds

We expect to receive approximately $578.9 million of net proceeds (assuming an initial public offering price of $28.50 per share, the midpoint of the range set forth on the cover of this prospectus) from the sale of the common stock offered by us after deducting underwriting discounts and commissions and estimated offering expenses payable by us.

 

  We intend to use approximately $518.9 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.”

 

  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. See “Use of Proceeds” and “Underwriting.”

 

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.”

 

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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.”

 

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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.

 

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    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        588,762     

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        1,774,859     

Total debt

    432,230          389,247        —          412,230     

Total partners’ / stockholders’ capital

    698,354          667,971        126,704        1,223,431     

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       

 

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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   

 

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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.

 

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RISK FACTORS

 

Investing in our common stock involves risks. You should carefully consider the information in this prospectus, including the matters addressed under “Cautionary Statement Regarding Forward-Looking Statements,” and the following risks before making an investment decision. The trading price of our common stock could decline due to any of these risks, and you may lose all or part of your investment.

 

Risks Related to Our Business

 

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 26,943 net acres out of the approximately 47,367 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 20,424 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.”

 

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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.

 

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

 

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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

 

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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

 

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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.

 

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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.

 

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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.

 

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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

 

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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

 

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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.

 

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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

 

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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.

 

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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

 

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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

 

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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,

 

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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

 

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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.

 

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Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of natural gas. The 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.

 

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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

 

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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.

 

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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.

 

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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

 

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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.

 

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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.”

 

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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.

 

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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.

 

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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 will be negotiated 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

 

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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 $20.86 per share.

 

Based on an assumed initial public offering price of $28.50 per share (the midpoint of the range set forth on the cover of this prospectus), purchasers of our common stock in this offering will experience an immediate and substantial dilution of $20.86 per share in the net tangible book value per share of common stock from the

 

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initial public offering price, and our net tangible book value as of March 31, 2014 on a pro forma basis would have been $7.65 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.

 

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We cannot predict the size of future issuances of our common stock or securities convertible into common stock or the effect, if any, that future issuances and sales of shares of our 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.

 

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

 

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

 

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

 

The information in this prospectus includes “forward-looking statements.” All statements, other than statements of historical fact included in this prospectus, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs 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.

 

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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.

 

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USE OF PROCEEDS

 

Assuming an initial offering price of $28.50 per share, the midpoint of the range set forth on the cover of this prospectus, we expect to receive approximately $578.9 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 $518.9 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

    $612.8     

Funding of our capital expenditure plan

  $ 518.9   
    Repayment of our revolving credit facility(1)     60.0   
    Underwriting discounts, fees and expenses     33.9   

Total Sources of Funds

    $612.8      Total Uses of Funds   $ 612.8   

 

(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.

 

A $1.00 increase or decrease in the assumed initial public offering price of $28.50 per share would cause our net proceeds from this offering, after deducting the underwriting discounts and commissions and estimated offering expenses payable to us, to increase or decrease, respectively, by approximately $20.5 million. If the proceeds increase due to a higher initial public offering price, we would use the additional net proceeds to fund our exploration and development program. If the proceeds decrease due to a lower initial public offering price, then we would reduce by a corresponding amount our net proceeds directed to our exploration and development 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 34,845,000 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.”

 

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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. See “Underwriting.”

 

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DIVIDEND POLICY

 

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

 

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CAPITALIZATION

 

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

 

   

on an actual basis; 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 an assumed offering price of $28.50 per share, which is the midpoint of the range set forth on the cover of this prospectus, 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       $ 588,762  
  

 

 

    

 

 

 

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

     —           1,275,309   

Accumulated deficit

     —           (53,784

Accumulated other comprehensive income

     306         306   
  

 

 

    

 

 

 

Total equity

     698,354         1,223,431   
  

 

 

    

 

 

 

Total capitalization

   $ 1,130,584       $ 1,635,661  
  

 

 

    

 

 

 

 

(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.

 

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DILUTION

 

Purchasers of the common stock in this offering will experience immediate and substantial dilution in the net tangible book value per share of the common stock for accounting purposes. Our net tangible book value as of March 31, 2014, after giving effect to 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 $7.64 per share. This represents an immediate increase in the net tangible book value of $2.99 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 $20.86 per share. The following table illustrates the per share dilution to new investors purchasing shares in this offering:

 

Assumed initial public offering price per share

      $ 28.50   

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

   $ 2.99      
  

 

 

    

 

 

 

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

      $ 7.64   
     

 

 

 

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

      $ 20.86   
     

 

 

 

 

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 $28.50 per share, the midpoint of the range set forth on the cover of this prospectus, 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    
     (in thousands)  

Existing owners(1)

     129,700,000         81.1   $ 772,594         47.2   $ 5.96   

New investors in this offering

     30,300,000         18.9     863,550         52.8   $ 28.50   
  

 

 

    

 

 

   

 

 

    

 

 

   

Total

     160,000,000         100.0   $ 1,636,144         100.0   $ 10.23   
  

 

 

    

 

 

   

 

 

    

 

 

   

 

(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.

 

A $1.00 increase or decrease in the assumed initial public offering price of $28.50 per share, which is the midpoint of the range set forth on the cover of this prospectus, would increase or decrease, respectively, our as adjusted pro forma net tangible book value as of March 31, 2014 by approximately $20.5 million, the as adjusted pro forma net tangible book value per share after this offering by $0.14 per share and the dilution in pro forma as adjusted net tangible book value per share to new investors in this offering by $0.86 per share, assuming the number of shares offered by us, as set forth on the cover of this prospectus, remains the same and after deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us.

 

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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.

 

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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 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, 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.

 

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    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        588,762     

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        1,774,859     

Total debt

    432,230          389,247        —          412,230     

Total partners’ / stockholders’ capital

    698,354          667,971        126,704        1,223,431     

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       

 

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

 

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes appearing elsewhere in this prospectus. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions, or beliefs about future events may, and often do, vary from actual results and the differences can be material. Some of the key factors which could cause actual results to vary from our expectations include changes in natural gas, 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.

 

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.

 

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 28/64th choke with approximately 5,300 psi casing pressure. The Tippens 6HS was drilled with a completed lateral section of

 

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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.

 

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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.

 

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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

 

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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.

 

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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;

 

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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.

 

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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   

 

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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)   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.
(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.

 

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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

 

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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.

 

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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.

 

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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

 

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 each of the years ended December 31, 2013 and 2012.

 

     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.

 

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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.

 

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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

 

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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.

 

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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

 

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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.

 

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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.

 

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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