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As filed with the Securities and Exchange Commission on April 16, 2015.

Registration No. 333-202037

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

Pre-effective Amendment No. 1

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

(814) 308-9754

(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

(814) 308-9754

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

 

 

Copies to:

Glen J. Hettinger

Bryn A. Sappington

Norton Rose Fulbright US LLP

2200 Ross Avenue, Suite 3600

Dallas, Texas 75201

(214) 855-8000

 

 

Approximate date of commencement of proposed sale to the public: From time to time 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.  x

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		¨

 

 

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. The selling stockholders may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell 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 APRIL 16, 2015

PRELIMINARY PROSPECTUS

62,500,000 Shares

 

 

 

Eclipse Resources Corporation

Common Stock

 

 

This prospectus relates to the resale of up to 62,500,000 shares of our common stock, which may be offered for sale from time to time by the selling stockholders named in this prospectus. The shares of our common stock covered by this prospectus (the “Shares”) were issued by us to the selling stockholders in a private placement (the “private placement”) which closed on January 28, 2015. We are not selling any shares of common stock under this prospectus and will not receive any proceeds from the sale of any shares of common stock by the selling stockholders.

The selling stockholders may from time to time sell, transfer or otherwise dispose of any or all of their Shares in a number of different ways and at varying prices. See “Plan of Distribution” for more information.

We may amend or supplement this prospectus from time to time by filing amendments or supplements as required. You should read this entire prospectus and any amendments or supplements carefully before you make your investment decision.

We are an “emerging growth company” as defined in the Jumpstart Our Business Startups Act of 2012.

 

 

Investing in our common stock involves risks. See “Risk Factors” beginning on page 10 of this prospectus.

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.

Our shares of common stock are listed on the New York Stock Exchange (the “NYSE”) under the symbol “ECR.”

Prospectus dated                     , 2015

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TABLE OF CONTENTS

 

		Page
Summary			1
Risk Factors			10
Cautionary Statement Regarding Forward-Looking Statements			39
Use of Proceeds			41
Dividend Policy			42
Selected Historical Consolidated Financial Data			43
Summary Reserve, Production and Operating Data			44
Management’s Discussion and Analysis of Financial Condition and Results of Operations			46
Business			72
Management			95
Executive Compensation and Other Information			106
Principal Stockholders			115
Certain Relationships and Related Party Transactions			117
Description of Capital Stock			120
Selling Stockholders			124
Plan of Distribution			127
Market for Our Common Stock			130
Legal Matters			131
Experts			131
Where You Can Find Additional Information			131
Index to Consolidated Financial Statements			F-1
Annex A: Glossary of Defined Terms			A-1

 

 

This prospectus is part of a registration statement on Form S-1 that we filed with the Securities and Exchange Commission (the “SEC”) using a “shelf” registration process. Under this shelf registration process, the selling stockholders may, from time to time, offer and sell, in one or more offerings, the securities described in this prospectus.

This prospectus only provides you with a general description of the securities that may be offered. Each time the selling stockholders sell securities using this shelf registration, we may provide a supplement to this prospectus that will contain specific information about the terms of that offering, including the specific amounts, prices and terms of the securities offered. The prospectus supplement may include additional risk factors or other special considerations applicable to those securities and may also add, update or change information contained in this prospectus. If there is any inconsistency between the information in this prospectus and any applicable prospectus supplement, you should rely on the information in the applicable prospectus supplement. You should read in their entirety both this prospectus and any accompanying prospectus supplement, together with the additional information described under the sections entitled “Where You Can Find Additional Information,” before deciding to invest in any of the securities being offered.

You should rely only on the information contained in this prospectus or to which we have referred you. Neither we nor the selling stockholders have authorized anyone to provide you with information different from that contained in this prospectus. We take no responsibility for, and can provide no assurance as to the reliability of, any other information that others may give you. This prospectus may only be used where it is legal to sell these securities. 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 Corporation and its consolidated subsidiaries;

 

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

 

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

 

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

 

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

 

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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 a limited partner of Eclipse Holdings;

 

•

the “Management Funds” refers, collectively, to The Hulburt Family II, L.P., CKH Partners II, L.P. and Kirkwood Capital, L.P., each of which is an investment fund controlled by members of our management team and a limited partner of Eclipse Holdings;

 

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“Eclipse Management” refers to Eclipse Management, L.P., which is a limited partner of Eclipse Holdings;

 

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the “Oxford Acquisition” refers to our acquisition of The Oxford Oil Company, which we completed on June 26, 2013; and

 

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“Oxford” or “Oxford Oil Company” refers to The Oxford Oil Company. Immediately prior to the Oxford Acquisition, Oxford’s name was changed to Eclipse Resources—Ohio, LLC.

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

Industry and Market Data

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

Trademarks, 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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RISK FACTORS

Investing in our common stock involves risks. You should carefully consider the information in this prospectus and any applicable prospectus supplement, 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

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.

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:

 

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

 

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the price and quantity of imports of foreign natural gas, including liquefied natural gas, foreign oil and refined products;

 

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

 

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political conditions in or affecting other producing countries, including conflicts in the Middle East, Africa, South America and Russia;

 

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the level of global exploration and production;

 

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the level of global inventories;

 

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

 

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the proximity, capacity, cost and availability of gathering and transportation facilities, and other factors that result in differentials to benchmark prices;

 

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the cost of exploring for, developing, producing and transporting reserves;

 

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speculative trading in natural gas and crude oil derivative contracts;

 

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risks associated with operating drilling rigs;

 

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the price and availability of competitors’ supplies of natural gas, NGLs, oil and alternative fuels;

 

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localized and global supply and demand fundamentals and transportation availability;

 

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adverse or severe weather conditions and other natural disasters;

 

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technological advances affecting energy consumption and production; and

 

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domestic, local and foreign governmental regulation and taxes.

In addition, substantially all of our natural gas production and oil production is sold to purchasers under contracts with market-based prices based on New York Mercantile Exchange (“NYMEX”) Henry Hub prices and West Texas Intermediate (“WTI”) prices, respectively. The actual prices realized from the sale of natural gas and oil differ from the quoted NYMEX Henry Hub and WTI prices as a result of location differentials. Location differentials to NYMEX Henry Hub and WTI prices, also known as basis differential, result from variances in regional natural gas and oil prices as compared to NYMEX Henry Hub and WTI prices due to regional supply and demand factors. We may experience differentials to NYMEX Henry Hub and WTI prices in the future, which may be material and could reduce the price we receive for these products relative to these benchmarks.

Lower commodity prices and negative increases in our differentials will reduce our cash flows and borrowing ability. We may be unable to obtain needed capital or financing on satisfactory terms, or at all, which could lead to a decline in our reserves as existing reserves are depleted. Lower commodity prices and negative differentials could also cause a significant portion of our development and exploration projects to become uneconomic, which may result in our having to make significant downward adjustments to our reserves. As a result, a substantial or extended decline in commodity prices or an increase in our negative differentials may materially adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.

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

 

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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.

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 Mr. Barry West, a lessor under an Oxford oil and gas lease, to enforce its rights to access and drill a well on the lease during its initial 5-year primary term, which we refer to as the West Lawsuit. 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 trial court’s decision in the West Lawsuit 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 the lease is a “no term” perpetual lease, by ruling that perpetual leases are void as a matter of Ohio law and by invalidating such lease. 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. As of April 14, 2015, we are a party to one other lawsuit that makes allegations similar to those made by the lessor in the West Lawsuit. This lawsuit, together with the West Lawsuit, affect approximately 157 gross (157 net) leasehold acres and were capitalized on our balance sheet as of December 31, 2014 at $0.6 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 trial court’s ruling in the West Lawsuit. These efforts have resulted in modifications to leases covering approximately 34,256 net acres out of the approximately 46,549 net acres we believe may require modification to address the issues raised by the trial court in the West Lawsuit. However, we cannot predict whether we will be able to obtain modifications of the leases covering the remaining 12,293 net acres to effectively resolve issues related to the Belmont County trial court’s ruling in the West Lawsuit or the amount of time and expense that will be required to amend these leases and our other leases may also require modification to address such issue.

In light of the foregoing, if the appeals court affirms the trial court ruling in the West Lawsuit, 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. Consequently, this could result in a loss of our mineral rights and an impairment of our related assets, and 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.”

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

 

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alternative proppant and additives under pressure into target geological formations to fracture the surrounding rock and stimulate production. We regularly use hydraulic fracturing as part of our operations. Presently, hydraulic fracturing is regulated primarily at the state level, typically by state oil and natural gas commissions and similar agencies. However, with increased public concern regarding the potential for hydraulic fracturing to adversely affect drinking water supplies, proposals have been made to enact federal, state and local legislation and regulations that would increase the regulatory burden imposed on hydraulic fracturing. For example, the U.S. Environmental Protection Agency, or the EPA, has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel under the Safe Drinking Water Act, issued new air emission controls for oil and natural gas production and natural gas processing operations, initiated a study to examine the potential impacts of hydraulic fracturing on drinking water resources, and intends to propose standards for wastewater discharges from oil and gas extraction activities and regulations that would require companies to disclose information regarding the in hydraulic fracturing. The U.S. Congress continues to consider amending the Safe Drinking Water Act to remove the exemption for hydraulic fracturing activities and to require disclosure of additives constituents of fluids used in the fracturing process. The Department of the Interior proposed a rule that would regulate hydraulic fracturing activities on federal lands.

If new federal, state or local laws or regulations that significantly restrict hydraulic fracturing are adopted, such legal requirements could result in delays, eliminate certain drilling and injection activities and make it more difficult or costly for us to perform fracturing. Any such regulations limiting or prohibiting hydraulic fracturing could reduce our oil and natural gas exploration and production activities and, therefore, adversely affect our business. Such laws or regulations could also materially increase our costs of compliance and doing business by more strictly regulating how hydraulic fracturing wastes are handled or disposed.

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

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

 

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unexpected drilling conditions;

 

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title problems;

 

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pressure or lost circulation in formations;

 

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equipment failure or accidents;

 

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adverse weather conditions;

 

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compliance with environmental and other governmental or contractual requirements; and

 

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

 

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

Based upon the well data available to us, we have grouped the publicly disclosed Utica Shale wells within the Utica Core Area into several distinct hydrocarbon windows, phases or type curve areas in an effort to better understand the thermal maturation variability within the Utica Core Area. However, there is an inherent degree of variability within such hydrocarbon windows, phases or type curve areas. Additionally, the well data we have utilized is predominantly based upon initial production rate, Btu content, natural gas yields and condensate yields, which may change over time. As a result, the well data with respect to the windows, phases and type curve areas within the Utica Core Area may not be indicative of the actual hydrocarbon composition for the windows, phases or type curve areas, or may not be the hydrocarbon composition of the windows, phases or type curve areas at the time we drill. Due to such factors, the performance, Btu content and NGLs and/or condensate yields of our wells may be substantially less than we anticipate or substantially less than performance and yields of other operators in the Utica Core Area, which may materially adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.

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 2015 with cash on hand, cash generated by our operations, borrowings under our revolving credit facility. 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 flows from operations be used for the payment of interest and principal on our indebtedness, thereby reducing our ability to use cash flows from operations to fund working capital, capital expenditures and acquisitions.

Our cash flows from operations and access to capital are subject to a number of variables, including, without limitation, the following:

 

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our proved reserves;

 

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

 

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the prices at which our production is sold;

 

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our ability to acquire, locate and develop new reserves;

 

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the levels of our operating expenses; and

 

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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 our cash on hand, cash flows generated by our operations and available borrowings under our revolving credit facility are insufficient to meet our capital requirements, the failure to obtain additional financing could result in a

 

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curtailment of our operations relating to development of our properties, which in turn could lead to a decline in our reserves and production, and could adversely affect our business, financial condition and results of operations.

We have been an early entrant into the Utica Core Area, which is a new and emerging play, and are also an early entrant into the portion of the Marcellus Shale underlying Our Marcellus Project Area. As a result, our expected well results in these areas are uncertain, and the value of our undeveloped acreage will decline if well results are unsuccessful.

Our expected well results in the Utica Core Area and Our Marcellus Project Area are more uncertain than well results in areas that are more developed and have a greater number of producing wells. As a result, our cost of drilling, completing and operating wells in the Utica Core Area and Our Marcellus Project Area may be higher than initially expected, the ultimate production and reserves from these wells may be lower than initially expected and the value of our undeveloped acreage may decline. Additionally, we cannot assure you that all prospects will be economically viable or that we will not abandon our investments. We cannot assure you that unproved property acquired by us or undeveloped acreage leased by us will be profitably developed, that wells drilled by us in prospects that we pursue will be productive or that we will recover all or any portion of our investment in such unproved property or wells.

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

We have shown initial production rates for publicly available Utica and Marcellus Shale wells to demonstrate the apparent relative strength or weakness of certain wells in the Utica and Marcellus Shales in our project areas. While we believe that the presentation of these initial production rates can provide a useful tool in evaluating the early stage performance of these wells for comparative analysis, in many cases initial production rates may not be a reliable or accurate predictor of ultimate well recoveries, which require significantly more in depth analysis, including but not limited to, an analysis of the production over an extended period. Initial production rates can also vary across wells due to several variables such as the choke size being utilized on the well, the lack of compression, the time period measured, or natural gas line pressures. Additionally, we have shown normalized initial production rates for several Utica Shale wells which have adjusted the reported initial production rate for these wells proportionate to the difference between their actual complete lateral length and a 6,000 foot 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:

 

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

 

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landing our wellbore in the desired drilling zone;

 

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staying in the desired drilling zone while drilling horizontally through the formation;

 

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running our casing the entire length of the wellbore; and

 

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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:

 

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the ability to fracture stimulate the planned number of stages;

 

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the ability to run tools the entire length of the wellbore during completion operations; and

 

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the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage.

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

 

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

 

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pressure or irregularities in geological formations;

 

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shortages of or delays in obtaining equipment and qualified personnel or in obtaining water for hydraulic fracturing activities;

 

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equipment failures, accidents or other unexpected operational events;

 

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

 

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lack of available capacity on interconnecting transmission pipelines;

 

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adverse weather conditions, such as blizzards and ice storms;

 

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issues related to compliance with environmental regulations;

 

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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;

 

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

 

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declines in natural gas, NGLs and oil prices;

 

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limited availability of financing at acceptable terms;

 

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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 $183.2 million for the year ended December 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 December 31, 2014, the borrowing base under our revolving credit facility was $100.0 million, and there were no outstanding borrowings and approximately $26.9 million of outstanding letters of credit, resulting in borrowing availability of approximately $73.1 million under our revolving credit facility million was drawn. The borrowing base under our revolving credit facility is subject to periodic redeterminations based on our oil and gas reserves. 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.

 

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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 December 31, 2014, all of our total estimated proved reserves were attributable to properties located in this area. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, market limitations, water shortages, weather related conditions or interruption of the processing or transportation of natural gas, NGLs or oil. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations. In addition, a number of areas within the Appalachian Basin have historically been subject to mining operations, the existence of which could require coordination to avoid adverse impacts as a result of drilling and mining in close proximity. These restrictions on our operations, and any similar restrictions, can cause delays or interruptions or can prevent us from executing our business strategy, which could have a material adverse effect on our financial condition and results of operations.

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

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

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

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

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

A significant portion of our Utica Core Area acreage position is dedicated to long-term firm gas gathering, processing and fractionation agreements with primary terms of approximately 15 years. These agreements give us priority service and capacity over non-firm parties that wish to utilize the gas processing and fractionation plants and gas gathering system. As a result of such dedications, a significant portion of our operated acreage in the Rich Gas, Condensate and Rich Condensate Windows of the Utica Core Area is committed to Blue Racer for gathering, processing and fractionation. Additionally, a significant portion of our operated acreage in the Dry Gas

 

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Window of the Utica Core Area is committed to Eureka Hunter for gathering. While we believe we have reserved sufficient capacity at these plants and on such systems to gather, process and fractionate all of our projected production associated with our proved resources and a significant portion of our projected production from the Utica Core Area, that capacity may not be sufficient to handle all of our production or that the plants and systems will not experience significant mechanical problems or delays in construction or become unavailable to us due to unforeseen circumstances. As a result, we may be required to find alternative markets and gathering, processing or fractionation arrangements for our production from the Utica Core Area that is committed under these agreements, and such alternative arrangements may only be available on less favorable terms, or not at all.

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

The Appalachian Basin natural gas business environment has historically been characterized by periods in which production has surpassed local takeaway capacity, resulting in substantial discounts in the price received by producers. Although additional Appalachian Basin takeaway capacity has been added in recent years 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 operations.

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:

 

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incur additional indebtedness;

 

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sell assets;

 

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make loans to others;

 

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make investments;

 

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enter into joint ventures;

 

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enter into mergers;

 

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

 

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hedge future production or interest rates;

 

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incur certain lease obligations;

 

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incur liens;

 

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

 

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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 December 31, 2014, the borrowing base under our revolving credit facility was $100.0 million and there were no outstanding borrowings and approximately $26.9 million of outstanding letters of credit, resulting in borrowing availability of approximately $73.1 million under our revolving credit facility.

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 and 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 these plays. 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 December 31, 2014, after deducting wells that have been drilled or are in progress, we had identified approximately 3,112 gross (810 net) remaining 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 Properties.”

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 December 31, 2014, 2,336 gross (1,604 net) undeveloped acres scheduled to expire in 2015, 16,036 gross (4,721 net) undeveloped acres scheduled to expire in 2016, 41,693 gross (29,288 net) undeveloped acres scheduled to expire in 2017, and 34,082 gross (23,540 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 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 December 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:

 

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actual prices we receive for natural gas, NGLs and oil;

 

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actual cost of development and production expenditures;

 

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the effect of derivative transactions;

 

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the amount and timing of actual production; and

 

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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, Eclipse I, our predecessor, was not subject to federal taxation. Accordingly, our standardized measure for December 31, 2012 and December 31, 2013 does not provide for federal corporate income taxes because taxable income was passed through to our partners. As a corporation, we are treated as a taxable entity for federal income tax purposes, and our future income taxes are 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

 

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there are no obvious defects in title to the well. Frequently, as a result of such examinations, curative work must be done to correct defects in the marketability of the title, and such curative work entails expense. Our failure to cure any title defects may delay or prevent us from utilizing the associated mineral interest, which may adversely impact our ability in the future to increase production and reserves. Accordingly, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we could suffer a financial loss or impairment of our assets.

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

At December 31, 2014, approximately 45% of our total estimated proved reserves were classified as proved undeveloped. Our approximately 159.0 Bcfe of estimated proved undeveloped reserves will require an estimated $274.6 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 pre-tax 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 flows 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.

 

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

To achieve more predictable cash flows and reduce our exposure to adverse fluctuations in the prices of natural gas and oil, we may enter into derivative instrument contracts for a significant portion of our natural gas, NGLs and oil production, including fixed-price swaps, basis swaps, collars and firm sales agreements. 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:

 

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production is less than the volume covered by the derivative instruments;

 

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the counterparty to the derivative instrument defaults on its contractual obligations;

 

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there is an increase in the differential between the underlying price in the derivative instrument and actual prices received; or

 

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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 ($20.7 million at December 31, 2014) and the sale of our natural gas and oil production ($22.8 million in receivables at December 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. For the year ended December 31, 2014, two customers, Antero Resources and Asset Risk Management, account for approximately 47% and 25%, respectively, of our revenues. We do not require our customers to post collateral. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.

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

Our operations are subject to various federal, state and local governmental regulations. Matters subject to regulation include wastewater disposal, the spacing of wells, unitization and pooling of properties and taxation. In addition, the production, handling, storage, transportation, remediation, emission and disposal of oil and natural gas, by-products thereof and other substances and materials produced or used in connection with oil and

 

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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:

 

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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;

 

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abnormally pressured formations;

 

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

 

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fires, explosions and ruptures of pipelines or processing facilities;

 

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personal injuries and death;

 

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natural disasters; and

 

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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:

 

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injury or loss of life;

 

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

 

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pollution and other environmental damage;

 

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regulatory investigations and penalties;

 

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suspension of our operations; and

 

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repair and remediation costs.

In accordance with what we believe to be customary industry practice, we maintain insurance against some, but not all, of our business risks. Our insurance may not be adequate to cover any 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 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 team, 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:

 

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recoverable reserves;

 

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future natural gas, NGLs or oil prices and their applicable differentials;

 

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operating costs; and

 

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potential environmental and other liabilities.

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

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

Market conditions or the unavailability of satisfactory natural gas, NGLs or oil transportation arrangements may hinder our access to markets or delay our production. The availability of a ready market for our production depends on a number of factors, including the demand for and supply of natural gas, NGLs or oil and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. Because many of our operations are in an emerging play, much of this infrastructure is currently being built or is yet to be built, and we cannot assure you that it will be built on time or at all. Our failure to obtain such services on acceptable terms and concurrent with the completion of our wells could materially harm our business. We may be required to shut in wells due to lack of a market or inadequacy or unavailability of natural gas, NGLs or oil pipeline or gathering system capacity. In addition, if quality specifications for the third party pipelines with which we connect change so as to restrict our ability to transport product, our access to markets could be impeded. If our production becomes shut in for any of these or other reasons, we would be unable to realize revenue from those wells until other arrangements were made to deliver the products to market.

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

The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate

 

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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. Liberatore, 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 team 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:

 

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increased responsibilities for our executive level personnel;

 

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increased administrative burden;

 

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increased capital requirements; and

 

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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 Commodity Futures Trading Commission, or the CFTC, and the SEC to promulgate certain 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, including in the major energy markets and for the first time for swaps that are their economic equivalents. The CFTC’s initial position limit rules under the Dodd-Frank Act were vacated by the U.S. District Court for the District of Columbia in September 2012 before such rules took effect. However, on November 5, 2013, the CFTC proposed new rules that would place limits on positions in certain core futures, options and equivalent swaps contracts in certain physical commodities, subject to exceptions for certain bona fide hedging and other transactions. The proposed new position limit rules also included requirements for aggregating positions in determining compliance limits. As these new position limit rules are not yet final, the impact of those provisions on our use of derivatives for which federal position limits do currently exist is uncertain at this time.

The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing and execution on certain trading platforms. The CFTC has not yet proposed rules designating any other classes of swaps, including physical commodity swaps, for mandatory clearing or trade execution. 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 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 or cause 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.

 

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

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

The U.S. President’s Fiscal Year 2015 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 Our Common Stock

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

Eclipse Holdings, which is owned by the EnCap Funds, the Management Funds and Eclipse Management, beneficially owns a majority of our common stock. We have entered into a stockholders’ agreement with Eclipse Holdings and its limited partners, the EnCap Funds, the Management Funds and Eclipse Management, pursuant to which such stockholders have certain rights relative to designated director nominees and agreed 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 are 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:

 

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

 

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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

 

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

We are currently utilizing, and intend to continue to utilize, the exemption relating to the nominating and governance committee, and we may utilize this exemption for so long as we are a controlled company. Accordingly, you do 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 Eclipse Management, hold a substantial majority of our common stock.

Eclipse Holdings, which is owned by the EnCap Funds, the Management Funds and Eclipse Management, hold approximately 63% of the outstanding shares of our common stock. Eclipse Holdings is entitled to act separately in its own interest with respect to its shares of our common stock, and it has 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 has the ability to determine the outcome of all matters requiring stockholder approval, including mergers and other material transactions, and 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 entered into in connection with the completion of our IPO permit our principal stockholders to designate a majority of the members of our board of directors.

In connection with the completion of our IPO, we entered into a stockholders agreement with Eclipse Holdings and its limited partners, the EnCap Funds, the Management Funds and Eclipse Management, which we refer to as our principal stockholders, pursuant to which such stockholders were provided with certain rights relative to designated director nominees and agreed 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 of our directors and members of our management team control or have other relationships with our principal stockholders. See “Principal 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. 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.

We completed our IPO in June 2014. As a public company, we incur significant legal, accounting and other expenses that we did not incur as a private company. We also incur costs associated with our public company reporting requirements and with corporate governance requirements, including requirements under the Sarbanes-Oxley Act, as well as rules implemented by the SEC and the Financial Industry Regulatory Authority. These rules and regulations have increased our legal and financial compliance costs and make some activities more time-consuming and costly. These rules and regulations also make it more difficult and more expensive for us to obtain director and officer liability insurance. 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.

If we fail to establish and maintain effective internal control over financial reporting, our ability to accurately report our financial results could be adversely affected.

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.

The price of our common stock may fluctuate significantly and you could lose all or part of your investment.

Volatility in the market price of our common stock may prevent you from being able to sell your common stock at or above the price you paid for your common stock. The market price for our common stock could fluctuate significantly for various reasons, including:

 

•

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;

 

•

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, Eclipse Holdings, the selling stockholders or other stockholders, or the perception that such sales may occur;

 

•

changes in accounting principles, policies, guidance, interpretations or standards;

 

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•

additions or departures of key management personnel;

 

•

actions by our stockholders;

 

•

general market conditions, including fluctuations in commodity prices;

 

•

domestic and international economic, legal and regulatory factors unrelated to our performance; and

 

•

the realization of any risks describes under this “Risk Factors” section.

The stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock. Securities class action litigation has often been instituted against companies following periods of volatility in the overall market and in the market price of a company’s securities. Such litigation, if instituted against us, could result in very substantial costs, divert our management’s attention and resources and harm our business, operating results and financial condition.

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. As of April 1, 2015, we had 222,531,115 outstanding shares of common stock. This number includes the shares that the selling stockholders are offering pursuant to this prospectus, which may be resold immediately in the public market. Eclipse Holdings owns 140,353,407 shares of our common stock, or approximately 63% of our total outstanding shares, all of which are restricted from immediate resale under the federal securities laws, but may be sold into the market in the future. Subject to compliance with the Securities Act or exemptions therefrom, certain of our employees may sell their shares of common stock into the public market.

Subject to the satisfaction of vesting conditions and the requirements of Rule 144, shares registered under our registration statement on Form S-8 filed on July 2, 2015 relating to our equity incentive plan are available for resale immediately in the public market without restriction.

We cannot predict the size of future issuances of our common stock or securities convertible into common stock or the effect, if any, that future issuances and sales of shares of our common stock will have on the market price of our common stock. Sales of substantial amounts of our common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our common stock.

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;

 

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•

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.

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.

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

 

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for up to 5 years, although we will lose that status sooner if we have more than $1.0 billion of revenues in a fiscal year, have more than $700.0 million in market value of our common stock held by non-affiliates, or issue more than $1.0 billion of non-convertible debt over a 3-year period.

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

Our amended and restated certificate of incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our common stock respecting dividends and distributions, as our board of directors may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of our common stock.

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

The trading market for our common stock is 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 income or 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” in this prospectus.

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

 

•

our business strategy;

 

•

reserves;

 

•

general economic conditions;

 

•

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

 

•

realized natural gas, NGLs and oil prices;

 

•

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;

 

•

the anticipated benefits under our commercial agreements;

 

•

pending legal matters relating to our leases;

 

•

marketing of natural gas, NGLs and oil;

 

•

leasehold and business acquisitions;

 

•

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

 

•

credit markets;

 

•

uncertainty regarding our future operating results, including initial production rates and liquids yields in our type curve areas; 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 flows and access to capital, risks associated with our indebtedness, the timing of development expenditures, and the other risks described under the heading “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

We will not receive any proceeds from the sale of shares of our common stock 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 “Selling Stockholders.”

 

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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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SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA

The following table shows our selected historical consolidated 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 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, 2014, 2013 and 2012 are derived from our audited consolidated financial statements included elsewhere in this prospectus.

 

Statement of Operations data: (in thousands, except per share data)		Year Ended December 31,
		2014				2013				2012
REVENUES
Oil and natural gas sales		$	137,816			$	12,935			$	370
Total revenues			137,816				12,935				370
OPERATING EXPENSES
Lease operating			8,518				2,576				16
Transportation, gathering and compression			18,114				67				—
Production and ad valorem taxes			7,084				77				1
Depreciation, depletion and amortization			89,218				6,163				404
Exploration			21,186				3,022				4,692
General and administrative			45,392				21,276				4,425
Accretion of asset retirement obligations			791				364				—
Impairment of proved oil and gas properties			34,855				2,081				—
Gain on sale of properties			(960	)			—				(372	)
Gain on reduction of pension liability			(2,208	)			—				—
Total operating expenses			221,990				35,626				9,166
OPERATING LOSS			(84,174	)			(22,691	)			(8,796	)
OTHER INCOME (EXPENSE)
Gain on derivative instruments			20,791				—				—
Interest expense, net			(48,347	)			(20,850	)			37
Other income			353				—				—
Total other expense, net			(27,203	)			(20,850	)			37
LOSS BEFORE INCOME TAXES			(111,377	)			(43,541	)			(8,759	)
INCOME TAX EXPENSE			71,799				—				—
NET LOSS		$	(183,176	)		$	(43,541	)		$	(8,759	)
Statement of Cash Flow data:
Net cash provided by (used in)
Operating activities		$	23,266			$	15,250			$	(3,381	)
Investing activities			(733,189	)			(897,086	)			(47,535	)
Financing activities			667,931				964,288				68,916
Balance Sheet data:
Cash and cash equivalents		$	67,517			$	109,509			$	27,057
Total property and equipment, net			1,722,827				1,018,084				106,253
Total assets			1,884,946				1,143,523				133,522
Total debt			414,016				389,247				—
Total stockholders’ equity			1,152,711				667,971				126,704

 

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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 December 31, 2014, December 31, 2013 and December 31, 2012, based on the proved reserve reports prepared by NSAI, our independent petroleum engineers, and such proved reserve reports have been prepared in accordance with the rules and regulations of the SEC. For oil and NGL volumes, the average West Texas Intermediate spot price of $94.99 per barrel for December 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 NYMEX Henry Hub spot price of $4.35 per MMBtu for December 31, 2014, $3.67 per MMBtu for December 31, 2013 and $2.757 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 December 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.

 

		December 31,
		2014				2013				2012
Proved Developed Reserves:
Natural gas (MMcf)			132,959.5				27,880.3				1,289.6
NGLs (MBbls)			6,758.6				1,056.2				64.6
Oil (MBbls)			3,880.9				1,708.1				174.5
Combined (MMcfe)			196,796.4				44,466.6				2,724.0
Proved Undeveloped Reserves:
Natural gas (MMcf)			123,350.4				24,464.2				1,666.6
NGLs (MBbls)			4,120.4				882.1				112.4
Oil (MBbls)			1,816.4				709.2				211.5
Combined (MMcfe)			158,971.5				34,012.0				3,610.1
Proved Reserves:
Natural gas (MMcf)			256,309.9				52,344.5				2,956.1
NGLs (MBbls)			10,879.0				1,938.3				177.0
Oil (MBbls)			5,697.4				2,417.4				386.0
Combined (MMcfe)			355,767.9				78,478.6				6,334.2

 

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Summary Production and Operating Data

The following table sets forth summary data with respect to our production results, average realized prices and certain expenses on a per Mcfe basis for the periods indicated:

 

		For the Years Ended December 31,
		2014				2013				2012
Total Production Volumes:
Natural Gas (MMcf)			19,760.2				1,118.8				7.7
NGLs (MBbls)			536.0				1.3				—
Oil (MBbls)			594.9				87.2				4.5
Total (Mmcfe)			26,545.5				1,650.2				34.6
Average daily production volumes:
Natural Gas (Mcf/d)			54,137				3,065				21
NGLs (Bbls/d)			1,468				4				—
Oil (Bbls/d)			1,630				239				12
Total (Mcfe/d)			72,727				4,521				95
Volume weighted average realized prices:
Natural Gas ($/Mcf)(1)		$	3.51			$	3.85			$	3.53
NGLs ($/Bbl)			39.27				48.17				—
Oil ($/Bbl)			79.54				98.22				76.19
Total ($/Mmcfe)		$	5.19			$	7.84			$	10.69
Expenses (per Mcfe):
Lease Operating		$	0.32			$	1.56			$	0.46
Transportation, gathering and compression			0.68				0.04				—
Production, severance and ad valorem taxes			0.27				0.05				0.03
Depletion, depreciation and amortization			3.36				3.73				11.68
General and administrative			1.71				12.89				127.89

 

(1)

Including the effects of commodity hedging, the average effective price for the year ended December 31, 2014 would have been $4.57 per Mcf of gas. The total volume of gas associated with these hedges represented approximately 38% of our total sales volumes for the year ended December 31, 2014. There were no commodity derivatives in place as of or for the years ended December 31, 2013 and 2012.

 

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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.

On June 24, 2014, prior to the closing of our IPO, we completed our Corporate Reorganization, as described under “Business—Corporate Reorganization. As such, unless otherwise indicated, the information presented in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for the period from January 1, 2014 through June 23, 2014, as contained within the year ended December 31, 2014 and for the years ended December 31, 2013 and 2012, pertain to the historical financial statements and results of operations of Eclipse I, our accounting predecessor.

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 100,700 of our net acres are located in the Utica Shale fairway, which we refer to as the Utica Core Area, and approximately 27,250 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 85% of our net acreage within the Utica Core Area and Our Marcellus Project Area. We began assembling our acreage position in the Utica Core Area in 2011 based upon an 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 December 31, 2014, we, or our operating partners, had commenced drilling 183 gross (73.1 net) wells within the Utica Core Area and Our Marcellus Project Area,

 

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of which 32 gross (14.1 net) were drilling, 31 gross (15.1 net) were awaiting completion, 6 gross (1.8 net) were in the process of being completed, 14 gross (8.5 net) were awaiting midstream and 100 gross (33.6 net) had been turned to sales.

As of December 31, 2014, we:

 

•

were operating 3 horizontal rigs in the Utica Core Area;

 

•

had identified 3,112 gross (810 net) horizontal drilling locations across our acreage, comprised of 2,541 gross (605 net) locations within the Utica Core Area and 571 gross (205 net) locations within Our Marcellus Project Area;

 

•

had average daily production for the year ended December 31, 2014 of approximately 72.7 MMcfe comprised of approximately 75% natural gas, 12% NGLs and 13% oil; and

 

•

our estimated proved reserves were 355.8 Bcfe, or 59.3 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 55% of which were proved developed reserves. Our estimated proved reserves were approximately 72% natural gas, 18% NGLs and 10% oil, as of December 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, which are extracted from our natural gas during processing, and oil. During the year ended December 31, 2014, our revenues were comprised of approximately 50.4%, 15.3% and 34.3% 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 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 a mix of natural gas fixed price swaps, basis swaps and put option spreads and collars. Swaps are settled monthly based on differences between the fixed price specified in the contract and the referenced settlement price. When the referenced settlement price is less than the price specified in the contract, we receive a settlement from the counterparty based on the price difference multiplied by the volume. Similarly, when the referenced settlement price exceeds the price specified in the contract, we pay the counterparty an amount based on the price difference multiplied by the volume. A put option spread is the combination of a purchased put and a sold put. The purchased put establishes the minimum price that we will receive for the contracted volumes unless the referenced price falls below the sold put strike price, at which point the minimum price equals the reference price plus the excess of the purchased put strike price over the sold put strike price. Collars establish a minimum floor price and a predetermined ceiling price. 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. In July 2014, we began hedging basis differentials associated with our

 

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natural gas production. 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 in the period of change.

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. As a result of our IPO, we will continue to incur direct incremental general and administrative 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.

Corporate Reorganization. Information presented in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for the period from January 1, 2014 through June 23, 2014, as contained within the year ended December 31, 2014, and for the years ended December 31, 2013 and 2012 pertain to the historical financial statements and results of operations of Eclipse I, our accounting predecessor. As a result, the historical financial data may not give you an accurate indication of what our actual results would have been had our Corporate Reorganization been completed at the beginning of the periods presented or of what our future results of operations are likely to be.

The Oxford Acquisition. Eclipse I, our predecessor, 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. Accordingly, our historical financial data may not present an accurate indication of what our actuals 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. We recognized income tax expense of approximately $71.8 million for the year ended December 31, 2014. We were not a tax paying entity prior to the completion of our Corporate Reorganization on June 24, 2014 and therefore, no income tax expense was recorded by us prior to such time. Income tax expense for the year ended December 31, 2014 is made up of two elements: (i) the change in tax status charge, and (ii) income tax expense (benefit) from continuing operations.

Upon the consummation of our Corporate Reorganization on June 24, 2014, we became a tax paying entity, and as such, were required to record a charge against income equal to the estimated tax effect of the excess of the book carrying value of our net assets (primarily producing oil and gas properties) over their collective estimated tax bases as of the closing date of our Corporate Reorganization. As a result, we recorded a tax expense of approximately $97.6 million.

For the year ended December 31, 2014, we had an income tax benefit from continuing operations of $25.8 million. This represents an application of our estimated annual effective tax rate (including state income taxes) for 2014 to our income subject to corporate tax earned from our Corporate Reorganization date through December 31, 2014.

Increased Horizontal Drilling Activity. We began horizontal, unconventional drilling operations in 2012, and through December 31, 2014, we and our operating partners had commenced drilling 183 gross (73.1 net) wells. 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 historically drilled.

Financing Arrangements. As of December 31, 2014, we had outstanding indebtedness, excluding debt discount, of $422.5 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. We elected to settle our accrued interest payable on January 15, 2014 by issuing PIK securities of $22.5 million. We elected to settle our accrued interest payable on January 15, 2015 by paying cash of $12.7 million and by issuing PIK securities of $14.8 million.

Cumulative net proceeds from our Senior Unsecured Notes of $380.7 million, after offering fees and expenses, were used along with contributions from the EnCap Funds and the Management Funds 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 was amended and restated on January 12, 2015, and which matures on January 15, 2018 and includes customary affirmative and negative covenants. At December 31, 2014, the borrowing base was $100 million and the Company had no outstanding borrowings. After considering outstanding letters of credit issued by the Company, totaling $26.9 million, we had available capacity on our Revolving Credit Facility of $73.1 million at December 31, 2014. In March 2015, we had a redetermination of the borrowing base under our Revolving Credit Facility, which increased the borrowing base to $125 million.

On December 27, 2014, we entered into a Securities Purchase Agreement with the EnCap Funds, the Management Funds and the other stockholders party thereto, pursuant to which we agreed to issue and sell to such purchasers an aggregate of 62,500,000 shares of common stock at a price of $7.04 per share pursuant to the exemptions from registration provided in Rule 506 of Regulation D promulgated under Section 4(2) of the Securities Act, such transaction referred to herein as the “private placement.”

On January 28, 2015, we closed the private placement and received net proceeds from the issuance of the shares to the purchasers of approximately $434 million (after deducting placement agent commissions and our estimated expenses), which we intend to use to fund our capital expenditure plan and for general corporate

 

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purposes. Upon the closing of the private placement, we amended and restated the existing registration rights agreement that we entered into upon the closing of our IPO to give the stockholders certain registration rights with respect to the stock purchased in the private placement. Please see “Recent Developments—Amended and Restated Revolving Credit Facility” for more information.

Prior to our Corporate Reorganization, our capital expenditures were financed with capital contributions from the EnCap Funds and the Management Funds, net proceeds from the issuance of our secured 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

 

•

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.

 

•

Transportation, gathering and compression. Under some of our sales arrangements, we sell natural gas at a specific delivery point, pay transportation, gathering and compression costs to a third party and receive proceeds from the purchaser with no deduction. These costs represent those transportation, gathering and compression costs paid by us to third parties. Additionally, we plan to enter multiple firm transportation contracts that secure takeaway capacity that includes minimum volume commitments, the cost of which is included in these expenses.

 

•

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.

 

•

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 DD&A expense.

 

•

Exploration. These are geological and geophysical costs, seismic costs, delay rentals and the costs of unsuccessful exploratory dry holes. This category also includes unproved property impairment and expenses associated with lease expirations.

 

•

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 received 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.

 

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•

Impairment of oil and gas properties. Properties are evaluated for impairment when circumstances indicate that the carrying value of an asset could exceed its fair value. When the carrying value exceeds the sum of the future undiscounted cash flows, an impairment loss is recognized for the difference between the fair market value and carrying value of the asset.

 

•

Accretion expense. This expense includes the monthly accretion of the future abandonment costs of tangible assets such as wells, service assets, pipelines and other facilities.

 

•

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 changes in fair value 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. In addition to gains and losses recognized from changes in fair value of the derivative instruments, gain (loss) on derivative instruments includes actual amounts realized from settlement of derivative instruments upon expiration.

 

•

Interest expense. We have historically financed a portion of our cash requirements with proceeds from fixed-rate secured unsecured Notes and our revolving credit facility. 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 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 use Adjusted EBITDAX 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; 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; exploration expenses; and other unusual or infrequent items. Adjusted EBITDAX is not a measure of net income as determined by GAAP.

In addition to the operating metrics above, we 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 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 are used in the calculation, while the costs of acquisitions are 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 are 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.

 

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Overview of the Year Ended December 31, 2014 Results

Operationally, our performance during the year ended December 31, 2014 reflects continued development of our acreage. During the year ended December 31, 2014, we achieved the following financial and operating results:

 

•

increased our average daily net production by 1509% over the prior year, to 72.7 MMcfe per day;

 

•

increased total net proved reserves by 353% to 355.8 Bcfe;

 

•

commenced drilling 57 gross (41.3 net) operated Utica Shale wells, completed 30 gross (27.3 net) operated Utica Shale wells and turned-to-sales 28 gross (21.8 net) wells during the year;

 

•

participated in 70 gross (13.5 net) non-operated Utica Shale wells, completed 60 gross (10.0 net) non-operated Utica Shale wells and turned-to-sales 65 gross (9.6 net) wells during the year; and

 

•

net loss was $183.2 million for the year ended December 31, 2014 compared to $43.5 million for the year ended December 31, 2013.

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 years ended December 31, 2014, 2013 and 2012.

 

		Years Ended December 31,
		2014				2013				2012
NYMEX Henry Hub High ($/MMBtu)		$	6.15			$	4.46			$	3.90
NYMEX Henry Hub Low ($/MMBtu)			2.89				3.11				1.91
Average NYMEX Henry Hub ($/MMBtu)			4.26				3.73				2.83
NYMEX WTI High ($/Bbl)		$	107.26			$	110.53			$	109.77
NYMEX WTI Low ($/Bbl)			53.27				86.68				77.69
Average NYMEX WTI ($/Bbl)			92.91				98.05				94.15

Results of Operations

Year Ended December 31, 2014 Compared to Year Ended December 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 years ended December 31, 2014 and 2013.

 

		Year Ended December 31,
		2014				2013				Change
Revenues (in thousands):
Natural gas sales		$	69,450			$	4,303			$	65,147
NGLs sales			21,048				63				20,985
Oil sales			47,318				8,569				38,749
Total revenues		$	137,816			$	12,935			$	124,881

Our production grew by approximately 24,895 MMcfe for the year ended December 31, 2014 over the same period in 2013, which was attributable to additions from acquisitions and drilling success as we placed new wells

 

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on production, partially offset by natural decline. Our production for the years ended December 31, 2014 and 2013 is set forth in the following table:

 

		Year Ended December 31,
		2014				2013				Change
Production:
Natural gas (MMcf)			19,760.2				1,118.8				18,641.4
NGLs (Mbbls)			536.0				1.3				534.7
Oil (Mbbls)			594.9				87.2				507.7
Total (MMcfe)			26,545.5				1,650.2				24,895.3
Average daily production volume:
Natural gas (Mcf/d)			54,137				3,065				51,072
NGLs (Bbls/d)			1,468				4				1,464
Oil (Bbls/d)			1,630				239				1,391
Total (Mcfe/d)			72,727				4,521				68,206

Our average realized price received during the year ended December 31, 2014 was $5.19 per Mcfe compared to $7.84 per Mcfe in the year ended December 31, 2013. The decrease in the average realized price was due to a higher percentage of our total revenues being driven by natural gas production in the year ended December 31, 2014, as compared to the year ended December 31, 2013, and to the overall decline in oil and natural gas commodity prices during the year ended December 31, 2014. Average realized prices (wellhead) do not include any third party transportation costs, which are reported in transportation, gathering and compression expense on our condensed consolidated statements of operations. Average realized price calculations, excluding the effects of hedges, for the years ended December 31, 2014 and 2013 are shown in the following table.

 

		Year Ended December 31,
		2014				2013				Change
Volume weighted average realized prices:
Natural gas ($/Mcf)(1)		$	3.51			$	3.85			$	(0.34	)
NGLs ($/Bbl)			39.27				48.17				(8.90	)
Oil ($/Bbl)			79.54				98.22				(18.68	)
Average price ($/Mcfe)			5.19				7.84				(2.65	)
Differential to Average NYMEX Henry Hub(2)			(0.75	)			0.06				(0.69	)
Differential to Average NYMEX WTI(2)			(13.37	)			(0.38	)			(12.99	)

 

(1)

Including the effects of commodity hedging, the average effective natural gas sales price for the year ended December 31, 2014 would have been $4.57 per Mcf. The total volume of gas associated with these hedges for the year ended December 31, 2014 represented approximately 38% of our total natural gas sales volumes for the year ended December 31, 2014. There were no commodity derivatives in place for the year ended December 31, 2013.

(2)	Differential compares actual NYMEX Henry Hub and WTI prices to our actual volume-weighted average realized prices for gas and oil, respectively.

 

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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 operating expenses for the years ended December 31, 2014 and 2013.

 

		Year Ended December 31,
		2014				2013				Change
Operating expenses (in thousands):
Lease operating		$	8,518			$	2,576			$	5,942
Transportation, gathering and compression			18,114				67				18,047
Production and ad valorem taxes			7,084				77				7,007
Depreciation, depletion and amortization			89,218				6,163				83,055
General and administrative			45,392				21,276				24,116
Operating expenses per Mcfe:
Lease operating		$	0.32			$	1.56			$	(1.24	)
Transportation, gathering and compression			0.68				0.04				0.64
Production and ad valorem taxes			0.27				0.05				0.22
Depletion, depreciation and amortization			3.36				3.73				(0.37	)
General and administrative			1.71				12.89				(11.18	)

Lease operating expense was $8.5 million in the year ended December 31, 2014 compared to $2.6 million in the year ended December 31, 2013. The increase of $5.9 million is attributable to higher production during the year ended December 31, 2014 as compared to the year ended December 31, 2013. Lease operating expenses include normally recurring expenses to operate and produce our wells and non-recurring workovers and repairs. We experience increases in operating expenses as we add new wells and manage existing properties. We incurred $1.0 million of workover costs in the year ended December 31, 2014 compared to $0 in the year ended December 31, 2013.

Transportation, gathering and compression expense was $18.1 million during the year ended December 31, 2014 compared to less than $0.1 million in the year ended December 31, 2013. These third party costs were higher in the year ended December 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.

Production and ad valorem taxes are paid based on market prices and applicable tax rates. Production and ad valorem taxes were $7.1 million in the year ended December 31, 2014 compared to less than $0.1 million in the year ended December 31, 2013. Production and ad valorem taxes increased from the year ended December 31, 2013 to the year ended December 31, 2014 due to higher production volumes subject to production or ad valorem taxes.

Depreciation, depletion and amortization was approximately $89.2 million in the year ended December 31, 2014 compared to $6.2 million in the year ended December 31, 2013. The increase in the year ended December 31, 2014 when compared to the year ended December 31, 2013 is due to the increase in production during 2014. On a per Mcfe basis, DD&A decreased to $3.36 in the year ended December 31, 2014 from $3.73 in the year ended December 31, 2013, which was predominantly driven by a lower depletion rate. The decrease in depletion rate during the year ended December 31, 2014 was due to total proved reserves (the denominator) increasing at a higher rate than production (the numerator) over the year.

General and administrative expense was $45.4 million for the year ended December 31, 2014 compared to $21.3 million for the year ended December 31, 2013. The increase of $24.1 million during the year ended December 31, 2014 when compared to the year ended December 31, 2013 is primarily due to higher salaries and

 

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benefits related to the hiring of a significant number of new employees during the year ended December 31, 2014. Our personnel costs may continue to increase as we invest in our technical teams and other staffing to support our drilling program. We also incurred $3.3 million related to the termination of drilling rig contracts for the year ended December 31, 2014. No such costs were incurred during the year ended December 31, 2013.

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, accretion of asset retirement obligation expense, gain on sale of assets, and reduction of pension obligations. The following table details our other operating expenses for the years ended December 31, 2014 and 2013.

 

		Year Ended December 31,								Change
		2014				2013
Other Operating Expenses (in thousands):
Exploration		$	21,186			$	3,022			$	18,164
Accretion of asset retirement obligations			791				364				427
Impairment of proved oil and natural gas properties			34,855				2,081				32,774
Gain on sale of assets			(960	)			—				(960	)
Gain on reduction of pension obligations			(2,208	)			—				(2,208	)

Exploration expense was $21.2 million in the year ended December 31, 2014 compared to $3.0 million in the year ended December 31, 2013. The increase was due to higher impairment of unproved properties related to lease expirations, dry hole costs, and delay rentals due to acreage increases and lease modifications. The following table details our exploration-related expenses for the years ended December 31, 2014 and 2013.

 

		Year Ended December 30,								Change
		2014				2013
Exploration Expenses (in thousands):
Geological and geophysical		$	802			$	124			$	678
Delay rentals			13,951				2,688				11,263
Impairment of unproved properties			5,671				—				5,671
Dry hole			762				210				552
		$	21,186			$	3,022			$	18,164

Impairment of unproved properties was $5.7 million for the year ended December 31, 2014 compared to $0 million for the year ended December 31, 2013. We assess individually significant unproved properties for impairment 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.

Accretion of asset retirement obligations was $0.8 million in the year ended December 31, 2014, compared to $0.4 million in the year ended December 31, 2013. The increase in accretion expense primarily relates to the increase in the asset retirement obligations associated with new wells drilled during the year ended December 31, 2014 and existing wells acquired in the Oxford Acquisition in June 2013.

 

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Impairment of proved oil and natural gas properties was $34.9 million for the year ended December 31, 2014 compared to $2.1 million in the year ended December 31, 2013. An analysis of proved properties determined the future undiscounted cash flows were less than the carrying value for certain asset groupings. An impairment expense was recognized for these asset groupings based on the difference between the fair market value and carrying value of the asset groupings. Approximately $30.9 million of this impairment expense relates to our conventional properties acquired in the Oxford Acquisition in June 2013 and the remaining $4.0 million relates to unconventional properties in our Utica Core Area.

Gain on sale of assets was $1.0 million for the year ended December 31, 2014 representing the gain on the sale of a central processing facility. No such sales occurred during the period ended December 31, 2013.

Gain on reduction of pension obligations was $2.2 million for the year ended December 31, 2014, compared to $0 in the year ended December 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)

Gain on derivative instruments was $20.8 million for the year ended December 31, 2014. There was no gain or loss on derivatives in the year ended December 31, 2013 as we did not have derivative instruments in place during this period. The Company made cash payments of approximately $1.6 million on derivative instruments that settled during the year ended December 31, 2014.

Interest expense, net was $48.3 million for the year ended December 31, 2014, compared to $20.9 million for the year ended December 31, 2013. The increase in interest expense during the year ended December 31, 2014 was due to the June 2013 and December 2013 issuance of $281.2 million and $100.0 million, respectively, of our Senior Unsecured Notes, net of discounts and offering expenses, as well as the $26.9 million drawn on our Revolving Credit Facility during 2014.

Income tax expense was $71.8 million for the year ended December 31, 2014 primarily related to a charge of $97.6 million to record the initial impact of the change in our tax status as a result of the Corporate Reorganization, partially offset by the income tax benefit of $25.8 million realized from the operating loss following the Corporate Reorganization.

Year Ended December 31, 2013 Compared to the Year Ended December 31, 2012 Natural Gas, NGLs and Oil Sales, Production and Realized Price Calculations

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 years ended December 31, 2013 and 2012.

 

		Year Ended December 31,								Change
		2013				2012
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

 

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

 

		Year Ended December 31,								Change
		2013				2012
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 the year ended December 31, 2013 was $7.84 per Mcfe compared to $10.69 per Mcfe in the year ended December 31, 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 the year ended December 31, 2013, as compared to the year ended December 31, 2012. Average realized prices (wellhead) do not include any third party transportation costs, which are reported in transportation, gathering and compression expense on our consolidated statements of operations. Average realized price calculations for the years ended December 31, 2013 and December 31, 2012 are shown in the following table:

 

		Year Ended December 31,								Change
		2013				2012
Volume weighted average realized prices:
Natural gas ($/Mcf)(1)		$	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 for gas and oil, respectively.

 

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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 years ended December 31, 2013 and December 31, 2012.

 

		Year Ended December 31,								Change
		2013				2012
Operating expenses (in thousands):
Lease operating		$	2,576			$	16			$	2,560
Transportation, gathering and compression			67				—				67
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:
Lease operating		$	1.56			$	0.46			$	1.10
Transportation, gathering and compression			0.04				—				0.04
Production 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	)

Lease operating expense was $2.6 million for the year ended December 31, 2013 compared to $0.02 million for the year ended December 31, 2012. The increase of $2.6 million is attributed 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 and 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 in workover costs in the year ended December 31, 2013 compared to $0 in the year ended December 31, 2012.

Transportation, gathering and compression expense was $0.07 million during the year ended December 31, 2013 compared to $0 during the year ended December 31, 2012. These third party costs were higher in the year ended December 31, 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.

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 the year ended December 31, 2013 compared to less than $0.01 million in the year ended December 31, 2012. Production and ad valorem taxes increased from the year ended December 31, 2012 to the year ended December 31, 2013 due to an increase in production volumes subject to production or ad valorem taxes.

Depreciation, depletion and amortization was approximately $6.2 million in the year ended December 31, 2013 compared to $0.4 million in the year ended December 31, 2012. The increase in the year ended December 31, 2013 when compared to the year ended December 31, 2012 is due to the increase in production during the year ended December 31, 2013. On a per Mcfe basis, DD&A decreased to $3.73 in the year ended December 31, 2013 from $11.68 in the year ended December 31, 2012, which was predominantly driven by a lower depletion rate. The decrease in depletion rate in the year ended December 31, 2013 was due to total proved reserves (the denominator) increasing at a higher rate than production (the numerator) over the period.

General and administrative expense was $21.3 million for the year ended December 31, 2013 compared to $4.4 million for the year ended December 31, 2012. The increase of $16.9 million during the year ended December 31, 2013 when compared to the year ended December 31, 2012 is primarily due to higher salaries and

 

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benefits related to the hiring of a significant number of new employees during the year ended December 31, 2013, including those that became employees through the Oxford Acquisition. In addition we recorded $0.04 million and $0.03 million of non-cash incentive unit compensation changes for the fiscal year end 2013 and 2012, respectively.

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 the years ended December 31, 2013 and 2012.

 

		Year Ended December 31,								Change
		2013				2012
Other Operating Expenses (in thousands):
Exploration		$	3,022			$	4,692			$	(1,670	)
Accretion of asset retirement obligations			364				—				364
Impairment of proved properties			2,081				—				2,081

Exploration expense decreased to $3.0 million in fiscal 2013 compared to $4.7 million in fiscal 2012 due to lower dry hole costs, impairment of unproved properties and seismic costs, partially offset by higher 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,								Change
		2013				2012
Exploration Expenses (in thousands):
Geological and geophysical		$	124			$	263			$	(139	)
Delay rentals			2,688				213				2,475
Impairment of unproved properties			—				793				(793	)
Dry hole			210				3,423				(3,213	)
		$	3,022			$	4,692			$	(1,670	)

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.

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.

Impairment of proved oil and gas 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 the carrying value. We compared the carrying value to estimated fair value and recognized an impairment charge. These

 

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assets were evaluated for impairment due to performance-related issues relative to our initial reserve expectations.

Other Income (Expense)

Interest expense, net was $20.9 million for the year ended December 31, 2013 compared to $0 in the year ended December 31, 2012. The increase in interest expense during year ended December 31, 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 of 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 proceeds from issuance of debt and equity. We sell a large portion of our production at the wellhead under floating market contracts.

Year Ended December 31, 2014 Compared to the Year Ended December 31, 2013

Net cash provided by operations in the year ended December 31, 2014 was $23.3 million compared to $15.3 million in the year ended December 31, 2013. The increase in cash used in operating activities from the year ended December 31, 2013 to the year ended December 31, 2014 reflects an increase in production, partially offset by higher operating costs. Net cash provided by operations is also affected by working capital changes or the timing of cash receipts and disbursements.

Net cash used in investing activities in the year ended December 31, 2014 was $733.2 million compared to $897.1 million in the year ended December 31, 2013.

During the year ended December 31, 2014, we:

 

•

spent $745.8 million on capital expenditures for oil and natural gas properties;

 

•

spent $3.6 million on property and equipment;

 

•

received proceeds of $15.5 million from the sale of a central processing facility; and

 

•

received proceeds of $0.8 million related to the acquisition of Eclipse Operating.

During the year ended December 31, 2013, we:

 

•

spent $252.8 million on capital expenditures for oil and natural gas properties;

 

•

spent $651.8 million on the Oxford acquisition; and

 

•

received proceeds of $8.5 million from the sale of properties.

Net cash provided by financing activities in the year ended December 31, 2014 decreased to $667.9 million compared to $964.3 million in the year ended December 31, 2013.

 

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During the year ended December 31, 2014, we:

 

•

issued shares of common stock in our IPO for proceeds to us totaling approximately $544.7 million, net of $5.3 million of IPO costs; and

 

•

received capital contributions of $124.7 million from private equity funds managed by EnCap and investment funds controlled by certain members of our management prior to our IPO.

During the year ended December 31, 2013, we:

 

•

received proceeds of $380.7 million from the issuance of debt, net of debt issuance costs; and

 

•

received capital contributions of $583.6 million from private equity funds managed by EnCap and investment funds controlled by certain members of our management.

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

Net cash provided by (used in) 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, partially 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.

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 $252.8 million on capital expenditures for oil and natural gas properties;

 

•

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

 

•

received proceeds of $8.5 million from the sale of properties.

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 by 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:

 

•

received proceeds of $380.7 million from the issuance of debt, net of debt issuance costs; and

 

•

received capital contributions of $538.6 million from private equity funds managed by EnCap and investment funds controlled by certain members of our management.

During 2012, we received capital contributions of $69.6 million from private equity funds managed by EnCap and investment funds controlled by certain members of management.

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

 

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programs which require substantial capital expenditures. We periodically review capital expenditures and adjust our budget based on liquidity, drilling results, leasehold acquisition opportunities, and commodity prices.

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 will continue using net cash on hand, cash flows from operations and proceeds available under our Revolving Credit Facility to satisfy near-term financial obligations and liquidity needs, and as necessary, we will seek additional sources of debt or equity to fund these requirements. Longer-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, excluding debt discount, totaled $422.5 million and $400.0 million at December 31, 2014 and December 31, 2013 respectively, and in each case, consisted 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 applicable covenants in the Indenture at December 31, 2014.

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 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 was payable by increasing the principal amount of the Senior Unsecured Notes (“PIK Interest”) or in cash. At our option, the subsequent four semiannual interest payments thereafter may be payable in the form of 6.0% per annum in cash and 7.0% per annum in PIK interest or all in cash. Thereafter, interest can only be paid as cash interest, which accrues at 12.0%. We elected to settle our accrued interest payable on January 15, 2014 by issuing PIK securities of $22.5 million and settled our accrued interest payable on July 15, 2014 with a cash payment of $25.3 million. We exercised our option to settle our accrued interest payable due on January 15, 2015 by paying cash of $12.7 million and by issuing PIK securities of $14.8 million.

In February 2014, we entered into our $500.0 million Revolving Credit Facility which was amended and restated on January 12, 2015, and which matures on January 15, 2018 and includes customary affirmative and negative covenants. As of December 31, 2014, the borrowing base was $100 million and the Company had no outstanding borrowings. After considering outstanding letters of credit issued by the Company, totaling $26.9 million, the Company had available capacity on our Revolving Credit Facility of $73.1 million at December 31, 2014. In March 2015, we had a redetermination of the borrowing base under the Revolving Credit Facility, which increased the borrowing base to $125 million. The borrowing base under our Revolving Credit Facility is scheduled to be redetermined semi-annually (in April and October) beginning on April 1, 2015.

 

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Commodity Hedging Activities

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

To mitigate the potential negative impact on our cash flow caused by changes in natural gas, NGLs and oil prices, we may enter into financial commodity derivative contracts to ensure that we receive minimum prices for a portion of our future production when management believes that favorable future prices can be secured. We 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. Below is a summary of our derivative instrument positions as of December 31, 2014:

 

Description(1)		Volume (MMBtu/d)				Production Period		Weighted Average Price ($/MMBtu)
Natural Gas Swaps:
			66,219			January 2015—December 2015		$	3.797
			25,000			January 2016—December 2016		$	3.660
Natural Gas Three-Way Collar:
Floor purchase price (put)			15,000			January 2015—December 2015		$	3.60
Ceiling sold price (call)			15,000			January 2015—December 2015		$	3.80
Floor sold price (put)			15,000			January 2015—December 2015		$	3.00
Natural Gas Put Sale:
			16,800			January 2015—December 2015		$	3.350
Natural Gas Collar:
Purchased put			5,000			January 2015—March 2015		$	4.000
Call sold			5,000			January 2015—March 2015		$	4.750
Basis Swaps:
			25,000			January 2015—March 2015		$	(1.067	)
			25,000			April 2015—October 2015		$	(1.208	)

 

(1)	The natural gas derivative 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.

 

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We have derivative instruments in place with Bank of Montreal and Key Bank N.A. We believe both institutions currently are an acceptable credit risk. As of December 31, 2014, we did not have any past due receivables from counterparties.

Subsequent to December 31, 2014, we entered into the following derivative instruments to mitigate our exposure to both oil and gas prices:

Natural Gas:

 

Description		Volume (MMBtu/d)				Production Period				Weighted Average Price ($/MMBtu)
Floor sold (put)			16,800				April 2015—October 2015			$	2.87
Floor purchased (put)			16,800				April 2015—October 2015			$	3.35
Floor sold (put)			16,800				January 2016—December 2016			$	2.75

Oil – WTI:

 

Description		Volume (Bbls/d)				Production Period		Weighted Average Price ($/Bbl)
Collar
Floor purchased (put)			3,000			March 2015—February 2016		$	55.00
Ceiling sold (call)			3,000			March 2015—February 2016		$	61.40

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 year ended December 31, 2014, costs incurred for drilling projects were $809.4 million, and for fiscal 2013 were $261.8 million. In the year ended December 31, 2014 there were no significant acquisitions of mineral properties, while during fiscal 2013, costs incurred for acquisition of unproved property totaled $621.0 million, primarily in the Utica Shale. Our fiscal 2014 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 common stock.

Our capital expenditure budget for fiscal 2015 excludes acquisitions, other than leasehold acquisitions, and is currently set at $640 million. We expect to fund our capital expenditures for 2015 with cash generated by operations, borrowings under our revolving credit facility, and net proceeds received from the private placement. 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 December 31, 2014 and December 31, 2013, our total debt and capitalization were as follows (in millions):

 

		December 31, 2014				December 31, 2013
Senior Unsecured Notes		$	422.5			$	400.0
Stockholders’ equity			1,152.7				667.9
Total capitalization		$	1,575.2			$	1,067.9
Debt to capitalization ratio			26.8	%			37.5	%

 

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Cash Contractual Obligations

Our contractual obligations include long-term debt, operating leases, drilling commitments, firm transportation, gas processing, gathering, and compressions services, and asset retirement obligations. As of December 31, 2014 and December 31, 2013, we do not have any capital leases, 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 December 31, 2014. In addition to the contractual obligations listed in the table below, our balance sheet at December 31, 2014 reflects accrued interest payable on our Senior Unsecured Notes of $25.2 million, compared to $20.3 million as of December 31, 2013. We settled $14.8 million of our accrued interest in January 2015 through the issuance of additional Senior Unsecured Notes.

The following summarizes our contractual financial obligations at December 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 and equity issuances, and proceeds from asset sales (in millions):

 

		2015				2016				2017				2018				2019				Thereafter				Total
Senior Unsecured Notes(1)		$	—			$	—			$	—			$	422.5			$	—			$	—			$	422.5
Drilling rig commitments(2)			23.5				18.7				8.1				—				—				—				50.3
Firm transportation(3)			19.7				42.0				120.2				130.0				123.5				1,123.1				1,558.5
Gas processing, gathering, and compression services(4)			7.5				7.4				8.0				—				—				—				22.9
Asset retirement obligation liability(5)			—				—				—				—				—				17.4				17.4
Operating leases			0.8				0.7				0.8				0.8				0.8				3.4				7.3
Vehicle loans.			0.3				0.3				0.3				0.3				0.1				—				1.3
		$	51.8			$	69.1			$	137.4			$	553.6			$	124.4			$	1,143.9			$	2,080.2

 

 

(1)	The ultimate settlement amount and timing cannot be precisely determined in advance. See Note 8 to our consolidated financial statements as of and for the year ended December 31, 2014.

(2)

At December 31, 2014, we had contracts for the services of three rigs, which expire at various dates from February 2015 through September 2017. The values in the table represent the gross amounts that we are committed to pay; however, we will record in our financial statements our proportionate share of costs based on our working interest.

(3)

We have entered into firm transportation agreements with various pipelines in order to facilitate the delivery of production to market. These contracts commit us to transport minimum daily natural gas or NGL volumes at a negotiated rate, or pay for any deficiencies at a specified reservation fee rate. The amounts in this table represent our minimum daily volumes at the reservation fee rate. The values in the table represent the gross amounts that we are committed to pay; however, we will record in our financial statements our proportionate share of costs based on our working interest.

(4)

Contractual commitments for gas processing, gathering and compression service agreements represent minimum commitments under long-term gas processing agreements as well as various gas compression agreements. The values in the table represent the gross amounts that we are committed to pay; however, we will record in our financial statements our proportionate share of costs based on our working interest.

(5)	Neither the ultimate settlement amounts nor the timing of our asset retirement obligations can be precisely determined in advance; however, we believe it is likely that a very small amount of these obligations will be settled within the next five years.

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 52% of our leases in the Utica Core Area have a 5-year extension at our

 

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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 December 31, 2014, we had $422.5 million, as compared to $400.0 million as of December 31, 2013, of Senior Unsecured Notes outstanding, excluding discounts, that bear interest at a fixed cash interest rate of 12.0% and is due semi-annually from the date of issuance. At our option, the first two interest payments can be PIK interest at a 13% per annum interest rate. Also at our option, the subsequent four semi-annual interest payments thereafter may be paid in the form of 6.0% per annum in cash and 7.0% per annum in PIK interest. Thereafter (subsequent to the sixth semi-annual interest payment), interest can only be paid in cash at a 12.0% per annum interest rate.

In February 2014, the Company entered into a $500 million senior secured revolving bank credit facility which was amended and restated on January 12, 2015 and matures in 2018. Borrowings under our Revolving Credit Facility are subject to borrowing base limitations based on the collateral value of the Company’s proved properties and commodity hedge positions and are subject to quarterly redeterminations through April 1, 2015 and semiannual redeterminations thereafter. At December 31, 2014, the borrowing base was $100 million and the Company had no outstanding borrowings. In March 2015, we had a redetermination of the borrowing base, which increased the borrowing base to $125 million. After considering outstanding letters of credit issued by the Company, totaling $26.9 million, the Company had available capacity on our Revolving Credit Facility of $73.1 million at December 31, 2014

Off-Balance Sheet Arrangements

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

Inflation and Changes in Prices

Our revenues, the value of our assets and our ability to obtain bank loans or additional capital on attractive terms have been and will continue to be affected by changes in natural gas, NGLs and oil prices and the costs to produce our reserves. Natural gas, NGLs and oil prices are subject to significant fluctuations that are beyond our ability to control or predict. Although certain of our costs and expenses are affected by general inflation, it does not normally have a significant effect on our business. We expect our costs in fiscal 2015 to continue to be a function of supply and demand.

Critical Accounting Estimates

Our discussion and analysis of our financial condition and results of operations are based upon consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at year end, the reported amounts of revenues and expenses during the year and proved natural gas and oil reserves. Some accounting policies involve judgments and uncertainties to such an extent there is a reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates

 

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and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying value of assets and liabilities that are not readily apparent from other sources. Actual results could differ from the estimates and assumptions used.

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

Natural Gas and Oil Properties

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

Proved reserves are defined by the SEC as those volumes of natural gas, NGLs, condensate and crude oil that geological and engineering data demonstrate with reasonable certainty are economically recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are volumes expected to be recovered through existing wells with existing equipment and operating methods, or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Although our engineers are knowledgeable of and follow the guidelines for reserves established by the SEC, including the rule revisions designed to modernize the oil and gas company reserves reporting requirements which were adopted effective December 31, 2009, the estimation of reserves requires engineers to make a significant number of assumptions based on professional judgment. Reserve estimates are updated at least annually and consider recent production levels and other technical information. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information, including: reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price and cost changes and other economic factors. Changes in natural gas, NGLs and oil prices can lead to a decision to start-up or shut-in production, which can lead to revisions to reserve quantities. Reserve revisions in turn cause adjustments in our depletion rates. We cannot predict what reserve revisions may be required in future periods. Reserve estimates are reviewed and approved by our Vice President, Business Development, Finance and Reservoir Engineering who reports directly to our Chief Financial Officer. To further ensure the reliability of our reserves estimates, we engage independent petroleum engineers to prepare our estimates of proved reserves at least annually. NSAI, our independent petroleum engineers, prepared 100% of our reserves for the years ended December 2014, 2013, and 2012. For additional discussion, see “Business—Oil and Natural Gas Data.”

Depletion rates are determined based on reserve quantity estimates and the capitalized costs of producing properties. As the estimated reserves are adjusted, the depletion expense for a property will change, assuming no change in production volumes or the capitalized costs. While total depletion expense for the life of a property is limited to the property’s total cost, proved reserve revisions result in a change in the timing of when depletion expense is recognized. Downward revisions of proved reserves may result in an acceleration of depletion

 

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expense, while upward revisions tend to lower the rate of depletion expense recognition. Estimated reserves are used as the basis for calculating the expected future cash flows from property asset groups, which are used to determine whether that property may be impaired. Reserves are also used to estimate the supplemental disclosure of the standardized measure of discounted future net cash flows relating to natural gas and oil producing activities and reserve quantities to our annual consolidated financial statements. Changes in the estimated reserves are considered a change in estimate for accounting purposes and are reflected on a prospective basis.

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

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

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

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

Acquisitions

As part of our business strategy, we periodically pursue the acquisition of oil and natural gas properties. The purchase price in an acquisition is allocated to the assets acquired and liabilities assumed based on their relative

 

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

Asset Retirement Obligations

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

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

Revenue Recognition

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

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

To the extent we have not been paid for production related to a given reporting period, we record an accrual for revenue based on our estimate of the amount of production delivered to purchasers and the price we will receive, along with any related transportation costs. We estimate volumes delivered based on production information or from historical operating results of individual properties when production information is not available, for example, for certain non-operated properties. Prices for such production and related transportation costs are defined in sales contracts and are readily determinable based on publicly available indices. Given the

 

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information available to us, we do not believe there to be any material implications with respect to uncertainties in developing these estimates and historically, our actual receipts have not been materially different from our accruals. The purchasers of such production have historically made payment for oil, NGLs and natural gas purchases within 30-60 days of the end of each production month, at which time any variance between our estimated revenue and transportation costs and actual payments is recorded.

Quantitative and Qualitative Disclosures About Market Risk

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

Commodity Price Risk

We are exposed to market risks related to the volatility of natural gas, NGLs and oil prices. Realized prices are primarily driven by worldwide prices for oil and spot market prices for North American gas production. Natural gas and oil prices have been volatile and unpredictable for many years. Natural gas prices affect us more than oil prices because approximately 72% of our December 31, 2014 and 67% of our December 31, 2013 proved reserves were natural gas.

For a discussion of how we use financial commodity derivative contracts to mitigate some of the potential negative impact on our cash flow caused by changes in natural gas prices, see “—Commodity Hedging Activities.”

A sensitivity analysis has been performed to determine the incremental effect on future earnings, related to open derivative instruments at December 31, 2014. A hypothetical 10 percent decrease in future natural gas prices would increase future earnings related to derivatives by $8.4 million. Similarly, a hypothetical 10 percent increase in future natural gas prices would decrease future earnings related to derivatives by $8.8 million.

Interest Rate Risk

At December 31, 2014, the cash interest rate with respect to our $422.5 million of Senior Unsecured Notes is fixed at 12.0%, and is due semi-annually from the date of issuance.

We will be exposed to interest rate risk in the future if we draw on our revolving credit facility. Interest on outstanding borrowings under our revolving credit facility will accrue based on, at our option, LIBOR or the alternate base rate, in each case, plus an applicable margin that is determined based on our utilization of commitments under our Revolving Credit Facility. As of December 31, 2014, the borrowing base was $100 million and the Company had no outstanding borrowings. After considering outstanding letters of credit issued by the Company, totaling $26.9 million, the Company had available capacity on our Revolving Credit Facility of $73.1 million at December 31, 2014.

Counterparty and Customer Credit Risk

Our principal exposures to credit risk are through receivables resulting from commodity derivatives contracts ($1.6 million at December 31, 2014), the sale of our oil and gas production ($24.1 million at December 31, 2014) which we market to energy companies, end users and refineries, and joint interest receivables ($20.7 million at December 31, 2014).

 

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By using derivative instruments that are not traded on an exchange to hedge exposures to changes in commodity prices, we expose ourselves to the credit risk of our counterparties. Credit risk is the potential failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty is expected to owe us, which creates credit risk. To minimize the credit risk in derivative instruments, it is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. The creditworthiness of our counterparties is subject to periodic review. We have economic hedges in place with two counterparties, both of which are lenders under our Credit Facility. The fair value of our commodity derivative contracts of approximately $19.0 at December 31, 2014 includes the following values by bank counterparty: Bank of Montreal $14.9 million; KeyBank NA $4.1 million. The estimated fair value of our commodity derivative assets has been risk adjusted using a discount rate based upon the respective published credit default swap rates (if available, or if not available, a discount rate based on the applicable Reuters bond rating) at December 31, 2014 for each of the European and American banks. We believe that all of these institutions currently are acceptable credit risks. Other than as provided by our revolving credit facility, we are not required to provide credit support or collateral to any of our counterparties under our derivative contracts, nor are they required to provide credit support to us. As of December 31, 2014, we did not have past-due receivables from, or payables to, any of the counterparties to our derivative contracts.

We are also subject to credit risk due to concentration of our receivables from several significant customers for sales of natural gas. We, generally, 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.

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.

 

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BUSINESS

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

Our Company

We are an independent exploration and production company engaged in the acquisition and development of oil and natural gas properties in the Appalachian Basin. As of December 31, 2014, we had assembled an acreage position approximating 221,700 net acres in Eastern Ohio. Approximately 100,700 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 27,250 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. Based on our initial drilling results, we believe the Utica and Marcellus shales offer some of the highest rate of return wells in North America. We are the operator of approximately 85% of our net acreage within the Utica Core Area and Our Marcellus Project Area. As of December 31, 2014, we had identified approximately 3,112 gross (810 net) remaining horizontal drilling locations across our acreage, comprised of 605 locations within the Utica Core Area and 205 locations within Our Marcellus Project Area. As of December 31, 2014, we and our operating partners had commenced drilling 179 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. See “Management.”

We are a Delaware corporation and were incorporated in February 2014 for purposes of facilitating our initial public offering.

Our Properties

We began assembling our acreage position in the Utica Core Area 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, 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. Based upon production data from the wells we have drilled and 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 is the most prolific part of 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 Annex A to this prospectus. We expect Our Marcellus Project Area to produce a significant proportion of condensate and NGLs in addition to natural gas. Additionally, we own approximately 121,000 net acres (which are approximately 86% held by production) outside of the Utica Core Area that may be prospective for the oil window of the Utica Shale.

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

 

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have drilled and 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.

As of December 31, 2014, we had approximately 100,700 net acres in the highly liquids rich area of the Utica Shale in Eastern Ohio within the Utica Core Area. 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. As of December 31, 2014, we and our operating partners had turned to sales 97 gross (31.9 net) wells within the Utica Core Area.

Marcellus Shale

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 December 31, 2014, we had approximately 27,250 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. As of December 31, 2014, we have participated in 3 gross (1.7 net) wells within Our Marcellus Project Area.

The table below outlines our Utica Core Area and Our Marcellus Project Area acreage and the remaining identified drilling locations within each type curve area as of December 31, 2014, after deducting wells that had been drilled or are in progress:

 

		Net Acreage				Identified Drilling Locations
Type Curve Area						Gross(1)				Net(1)
Dry Gas			34,850				715				207
Rich Gas			34,900				850				223
Condensate			25,650				558				130
Rich Condensate			5,300				412				45
Total Utica Core Area			100,700				2,541				605
Our Marcellus Project Area			27,250				571				205
Total							3,112				810

 

(1)	Drilling locations are specifically identified and generally assume 1,000 foot interlateral spacing for acreage within the Dry Gas Type Curve Area, 750 foot interlateral spacing elsewhere and a 6,000 foot lateral length.

 

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Activity

Through December 31, 2014, we and our operating partners had commenced drilling 182 gross wells within the Utica Core Area and Our Marcellus Project Area, which are summarized in the table below.

 

		Operated Gross Wells																Non-Operated Gross Wells
Type Curve Area		Producing to Sales				Awaiting Turn to Sales				Awaiting Completion/ Completing				Drilling				Producing to Sales				Awaiting Turn to Sales				Awaiting Completion/ Completing				Drilling
Dry Gas			6				—				—				—				9				3				8				—
Rich Gas			1				—				7				—				34				1				4				9
Condensate			21				9				12				12				25				1				6				11
Rich Condensate			—				—				—				—				1				—				—				—
Total Utica Core Area			28				9				19				12				69				5				18				20
Our Marcellus Project Area			1				—				—				—				2				—				—				—
Total			29				9				19				12				71				5				18				20

As of December 31, 2014, our estimated proved reserves were 355.8 Bcfe, or 59.3 MMBoe, an increase of 353% from December 31, 2013 reserves of 78.5 Bcfe, or 13.1 MMBoe, based on reserve reports prepared by Netherland, Sewell & Associates, Inc., or NSAI, our independent petroleum engineers. As of December 31, 2014, our estimated proved reserves were approximately 72% natural gas, 18% NGLs and 10% oil, and approximately 55% were proved developed reserves. The following table provides information regarding our proved reserves as of December 31, 2014, 2013, and 2012:

 

		Estimated Total Proved Reserves
		Oil (MMBbls)				NGLs (MMBbls)				Natural Gas (Bcf)				Total (Bcfe)				Total (MMBoe)				% Liquids				% Developed
December 31, 2012			0.4				0.2				3.0				6.3				1.1				54.5	%			43.0	%
December 31, 2013			2.4				1.9				52.3				78.5				13.1				33.3	%			56.7	%
December 31, 2014			5.7				10.9				256.3				355.8				59.3				28.0	%			55.3	%

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.

 

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The following table illustrates the firm transportation and sales volumes associated with our operated assets:

 

Firm Sales & Transportation		Start Date		Term		Volume (Dth/d)		Market
Firm Sales		November 2014		Various		Up to 95,000		Dominion South/TETCO M2
TETCO		April 2015		9.5 years		100,000		Gulf Coast, Midwest, and M3
Rockies Express		June 2015		17 months		50,000		Midwest
TCO		November 2016		15 years		205,000		TCO Pool
Energy Transfer		December 2016		15 years		100,000		Gulf Coast
Energy Transfer		June 2017		15 years		50,000		Canada

In March 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.

In August 2014, we entered into an agreement with EnLink Midstream for the marketing of our condensate and operation of our condensate stabilization facilities. Under the terms of the agreement, among other things, EnLink Midstream will purchase two of our existing condensate stabilization facilities, as well as construct and operate additional facilities to support our drilling program in the Utica Shale. We completed the sale of one of these two condensate stabilization facilities to EnLink Midstream in December 2014.

On November 7, 2014, we entered into an additional transportation agreement on the Rockies Express pipeline for 50,000 Dth per day commencing in June 2015. This additional agreement will offer us the ability to market a significant portion our gas to the Midwest markets. With this additional transportation agreement, we believe we have firm transportation or firm sales agreements covering approximately 100% of our planned gross operated natural gas production during 2015 and 2016. In addition, we expect that the majority of our non-operated production will be marketed at advantaged markets predominately outside of the Appalachian Basin.

In December 2014, we entered into a 10-year firm transportation and marketing agreement with Blue Racer to market a substantial portion of our operated production of propane and butane through Blue Racer’s firm capacity on Sunoco’s Mariner East II Project. The Mariner East II Project will connect the NGLs resources in the Marcellus and Utica Shale to Sunoco’s existing infrastructure and international port at its Marcus Hook facility near Philadelphia. Mariner East II is expected to be operational in late 2016. Under the agreement, we will have firm transportation, which grows from approximately 7,500 barrels to 14,000 barrels per day during the term of the agreement (67% propane and 33% butane). Through this agreement, we plan to export propane and butane in order to capture the premium pricing offered by international markets, but also retain the ability to sell domestically.

See “Risk Factors” for a discussion of risks and uncertainties relating to our gathering, processing and fractionation arrangements.

Corporate Reorganization

Pursuant to the terms of our corporate reorganization that was completed prior to the closing of our IPO, the following transactions occurred (collectively, our “Corporate Reorganization”):

 

•

the acquisition by Eclipse I of all of the outstanding equity interests in Eclipse Operating;

 

•

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

 

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•

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

 

•

the contribution of equity interests in Eclipse I and the outstanding equity interests in Eclipse GP, LLC, to us by Eclipse Holdings in exchange for 138,500,000 shares of our common stock.

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

Recent Developments

Operational Update

Our initial production estimate for the first quarter 2015 is approximately 160 MMcfe per day. This production represents a 29% increase over the fourth quarter 2014 and a 316% increase over the first quarter of 2014. The production mix during the first quarter was approximately 67% natural gas, 18% natural gas liquids and 15% oil. During the first quarter of 2015, we turned 11 gross operated and 9 gross non-operated wells into sales for a total of 20 gross wells (13 net wells) to sales. Of these 20 gross wells, 13 wells are in the condensate type curve areas, 3 are in the dry gas type curve areas and 4 are in the rich gas type curve areas.

2015 Capital Budget and Guidance

Our board of directors has approved a revised capital budget of $352 million for 2015, representing a 45% reduction from our initial capital budget for the year, and a 57% decrease from 2014. We expect to spud approximately 19 net operated wells, and 2 net non-operated wells. The company expects to place 29 net wells (18 net operated wells and 11 net non-operated) wells into sales during the year. For the full year 2015, we expect total production to be between 180 MMcfe per day and 190 MMcfe per day.

We currently expect to fund the 2015 capital budget with cash on hand, including the proceeds from the private placement, cash flows from operations and draws on our amended and restated revolving credit facility.

Private Placement of Common Stock

On December 27, 2014, we entered into a Securities Purchase Agreement with the EnCap Funds, the Management Funds and the other selling stockholders pursuant to which we agreed to issue and sell to such purchasers an aggregate of 62,500,000 shares of common stock at a price of $7.04 per share pursuant to the exemptions from registration provided in Rule 506 of Regulation D promulgated under Section 4(2) of the Securities Act, such transaction referred to herein as the “private placement.”

On January 28, 2015, we closed the private placement and received net proceeds from the issuance of the shares to the purchasers of approximately $434 million (after deducting placement agent commissions and our estimated expenses), which we intend to use to fund our capital expenditure plan and for general corporate purposes. Upon the closing of the private placement, we amended and restated the existing registration rights agreement that we entered into upon the closing of our IPO to give the selling stockholders certain registration rights with respect to the stock purchased in the private placement. Please see “Certain Relationships and Related Party Transactions—Amended and Restated Registration Rights Agreement” for more information.

 

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Amended and Restated Revolving Credit Facility

On January 12, 2015, we entered into an Amended and Restated Credit Agreement (the “Credit Agreement”) with Eclipse I, as borrower, the Bank of Montreal, as administrative agent and issuing bank, KeyBank National Association, as syndication agent, and each of the lenders party thereto. The Credit Agreement provides for a revolving credit facility, which we refer to as our revolving credit facility, of up to $500 million, subject to borrowing base availability, and is scheduled to mature on January 15, 2018. The borrowing base under our revolving credit facility was $100.0 million as of the effective date of the Credit Agreement and is subject to periodic redeterminations based on our oil and gas reserves. As of January 12, 2015, Eclipse I had no borrowings and approximately $26.9 million of outstanding letters of credit, resulting in borrowing availability of approximately $73.1 million under our revolving credit facility. In March 2015, we had a redetermination of the borrowing base under our revolving credit facility which increased the borrowing base to $125 million.

The Credit Agreement amended and restated Eclipse I’s previous credit agreement, dated as of February 18, 2014, as amended. The primary change effected by the Credit Agreement was to add Eclipse Resources Corporation as a party to the Credit Agreement and thereby subject us to the representations, warranties, covenants and events of default provisions thereof. Relative to the Eclipse I’s previous credit agreement, the Credit Agreement also (i) requires financial reporting regarding, and tests financial covenants with respect to, us rather than Eclipse I, (ii) increases the basket sizes under certain of the negative covenants, and (iii) includes certain other changes favorable to Eclipse I. Other terms of the Credit Agreement remain generally consistent with Eclipse I’s previous credit agreement. The previous revolving credit facility and the revolving credit facility provided for in the Credit Agreement are referred to herein as our Revolving Credit Facility.

Our Revolving Credit Facility is secured by mortgages on substantially all of Eclipse I’s properties and guarantees from us and our subsidiaries (other than immaterial subsidiaries). Interest is payable at a variable rate based on LIBOR or the prime rate based on Eclipse I’s election at the time of borrowing.

Initial Public Offering

On June 25, 2014, we completed our initial public offering (“IPO”) of 30,300,000 shares of our common stock, which included 21,500,000 shares sold by us and 8,800,000 shares sold by certain of our selling stockholders. Our net proceeds from our IPO were approximately $544.7 million, after deducting underwriting discounts and commissions and the offering expenses payable by us of approximately $35.8 million. We used a portion of the net proceeds we received from our IPO to repay the then-outstanding borrowings under Eclipse I’s revolving credit facility to fund our capital expenditure plan.

Our common stock is traded on the NYSE under the symbol “ECR.”

Oil and Natural Gas Data

Proved Reserves

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

We maintain an internal staff of engineers and geoscience professionals who work closely with NSAI to ensure the integrity, accuracy and timeliness of the data used to calculate our proved reserves relating to our

 

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

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

 

•

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

 

•

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

 

•

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

 

•

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

 

•

verification of property ownership by our land department.

The reserves estimates shown herein are based upon evaluations prepared by NSAI, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves report incorporated herein are Mr. Robert C. Barg and Mr. William J. Knights. Mr. Barg has been practicing consulting petroleum engineering at NSAI since 1989. Mr. Barg is a Licensed Professional Engineer in the State of Texas (No. 71658) and has over 30 years of practical experience in petroleum engineering, with over 24 years of experience in the estimation and evaluation of reserves. He graduated from Purdue University in 1983 with a Bachelor of Science Degree in Mechanical Engineering. Mr. Knights has been practicing consulting petroleum geology at NSAI since 1991. Mr. Knights is a Licensed Professional Geoscientist in the State of Texas, Geology (No. 1532) and has over 33 years of practical experience in petroleum geosciences, with over 27 years of experience in the estimation and evaluation of reserves. He graduated from Texas Christian University in 1981 with a Bachelor of Science Degree in Geology and in 1984 with a Master of Science Degree in Geology. Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

Estimation of Proved Reserves. Under SEC rules, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.” All of our proved reserves as of December 31, 2014, December 31, 2013 and December 31, 2012 were estimated using a deterministic method. The estimation of reserves involves two distinct determinations.

 

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The first determination results in the estimation of the quantities of recoverable oil and natural gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of recoverable oil and natural gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into four broad categories or methods: (1) production performance-based methods; (2) material balance-based methods; (3) volumetric-based methods; and (4) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserves for proved developed producing wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to similar production, both of which are considered to provide a relatively high degree of accuracy. Non-producing reserve estimates, for developed and undeveloped properties, were forecast using either volumetric or analogy methods, or a combination of both. These methods provide a relatively high degree of accuracy for predicting proved developed non-producing and proved undeveloped reserves for our properties.

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

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

 

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Summary of Natural Gas, NGLs and Oil Reserves. The following table presents our estimated net proved natural gas, NGLs and oil reserves as of December 31, 2014, December 31, 2013 and December 31, 2012, based on the proved reserve reports prepared by NSAI, our independent petroleum engineers, and such proved reserve reports have been prepared in accordance with the rules and regulations of the SEC. Our estimated proved reserves were determined using a 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December for the years 2013 and 2012. For oil and NGLs volumes, the average West Texas Intermediate spot price of $94.99 per barrel for December 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 $4.35 per MMBtu for December 31, 2014, $3.67 per MMBtu for December 31, 2013 and $2.76 per MMBtu for December 31, 2012 has been adjusted by property group for energy content, transportation fees and regional price differentials. All prices are held constant throughout the lives of the properties. All of our proved reserves are located in the United States. Copies of the proved reserve reports as of December 31, 2014, December 31, 2013 and December 31, 2012 prepared by NSAI with respect to our properties are incorporated by reference into this prospectus. 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.

 

		December 31,
		2014				2013				2012
Proved Developed Reserves:
Natural gas (MMcf)			132,959.5				27,880.3				1,289.6
NGLs (MBbls)			6,758.6				1,056.2				64.6
Oil (MBbls)			3,880.9				1,708.1				174.5
Combined (MMcfe)			196,796.4				44,466.6				2,724.0
Proved Undeveloped Reserves:
Natural gas (MMcf)			123,350.4				24,464.2				1,666.6
NGLs (MBbls)			4,120.4				882.1				112.4
Oil (MBbls)			1,816.4				709.2				211.5
Combined (MMcfe)			158,971.5				34,012.0				3,610.1
Proved Reserves:
Natural gas (MMcf)			256,309.9				52,344.5				2,956.1
NGLs (MBbls)			10,879.0				1,938.3				177.0
Oil (MBbls)			5,697.4				2,417.4				386.0
Combined (MMcfe)			355,767.9				78,478.6				6,334.2

Reserve engineering is and must be recognized as a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas, NGLs and oil that are ultimately recovered. Estimates of economically recoverable natural gas, NGLs and oil and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs. Please see the information set forth under “Risk Factors” beginning on page 11 of this prospectus.

Additional information regarding our proved reserves can be found in the notes to our consolidated financial statements and the proved reserve reports as of December 31, 2014, December 31, 2013 and December 31, 2012, each of which is incorporated by reference into this prospectus.

 

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Proved Reserves Additions and Revisions

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

 

		Natural Gas (MMcf)				NGLs (MBbls)				Oil (MBbls)				Total (MMcfe)
Proved Reserves:
December 31, 2011			—				—				—				—
Extensions and discoveries			2,963.8				177.0				390.5				6,368.9
Production			(7.7	)			—				(4.5	)			(34.7	)
December 31, 2012			2,956.1				177.0				386.0				6,334.2
Extensions and discoveries			41,215.5				1,710.6				1,323.3				59,419.0
Reserve revisions			2,645.0				52.1				(163.2	)			1,978.4
Acquisition			6,646.6				—				958.5				12,397.6
Production			(1,118.8	)			(1.3	)			(87.2	)			(1,650.2	)
December 31, 2013			52,344.5				1,938.4				2,417.4				78,478.6
Extensions and discoveries			235,816.9				10,216.3				4,337.5				323,140.1
Reserve revisions			(12,091.2	)			(739.7	)			(462.6	)			(19,305.3	)
Acquisition			—				—				—				—
Production			(19,760.2	)			(536.0	)			(594.9	)			(26,545.5	)
December 31, 2014			256,309.9				10,879.0				5,697.4				355,767.9

During the year ended December 31, 2014, we added 277.3 Bcfe of proved reserves, primarily due to drilling activities in the Utica Shale. This increase in proved reserves was comprised of 323.1 Bcfe of extensions, partially offset by 19.3 Bcfe of negative revisions and 26.5 Bcfe of production. The negative revisions consisted of 2.5 Bcfe of pricing revisions, 1.3 Bcfe related to expense assumptions, and 15.5 Bcfe due to technical revisions. During fiscal 2013, we added 72.1 Bcfe of proved reserves, primarily in the Utica Shale, due to drilling activities, evaluations of proved areas, the Oxford Acquisition and revisions to previous estimates.

Future Net Cash Flows. At December 31, 2014, 2013, and 2012 the PV-10 value of estimated future net cash flows from our proved reserves was $509.4 million, $155.3 million, and $21.9 million, respectively. These PV-10 values were calculated based on the unweighted average first-day-of-the-month oil and gas prices for the prior twelve months held flat for the life of the reserves.

The following table sets forth the estimated future net cash flows from our proved reserves (without giving effect to our commodity hedges), the present value of those net cash flows before income tax (PV-10) and the present value of those net cash flows after income tax (standardized measure):

 

		Year ended December 31,
(In millions, except per Mcf data)		2014				2013				2012
Future net cash flows		$	792,091			$	286,855			$	36,151
Present value of future net cash flows:
Before income tax (PV-10)		$	509,389			$	155,295			$	21,894
Income taxes			(178,732	)			—				—
After income tax (Standardized measure)		$	330,657			$	155,295			$	21,894

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

 

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revenues. Prior to our Corporate Reorganization on June 24, 2014, we were not subject to entity level taxation, there was no difference between PV-10 and our standardized measure in this regard. However, as a result of our corporate reorganization, we are a corporation subject to federal income tax and our future income taxes will be dependent upon our future taxable income, and our calculation of standardized measure as of December 31, 2014 includes 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.

Proved Undeveloped Reserves (PUDs)

As of December 31, 2014 our proved undeveloped reserves were comprised of 1,816.4 MBbls of oil, 123,350.4 MMcf of natural gas and 4,120.4 MBbls of NGLs, for a total of 158,971.5 MMcfe. As of December 31, 2013, our proved undeveloped reserves were composed of 709.2 MBbls of oil, 24,464.2 MMcf of natural gas and 882.1 MBbls of NGLs, for a total of 34,012.0 MMcfe. PUDs will be converted from undeveloped to developed as the applicable wells begin production.

The following table summarizes our changes in PUDs during 2013 and 2014 (in MMcfe):

 

Balance, December 31, 2012			3,610.1
Revisions of previous estimates(1)			(271.0	)
Purchases of minerals-in-place			—
Extensions and discoveries			32,853.0
Transfers to proved developed			(2,180.2	)
Balance, December 31, 2013			34,012.0
Revisions of previous estimates(2)			(25,959.4	)
Purchases of minerals-in-place			—
Extensions and discoveries			157,548.0
Transfers to proved developed			(6,629.1	)
Balance, December 31, 2014			158,971.5

 

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

(2)	Revisions to previous estimates are comprised of 1,033.8 MMcfe due to positive price revisions, 1,015.7 MMcfe negative revision due to expense assumptions, 25,977.5 MMcfe of negative technical revisions.

Costs incurred relating to the development of PUDs reflected in our 2012 proved reserve report were $4.4 million during 2013. In addition, we incurred costs of $0.3 million to develop locations that became classified as PUDs during 2013. Estimated future development costs relating to the development of PUDs as of December 31, 2014 are projected to be approximately $34.3 million in 2015, $21.2 million in 2016, $135.9 million in 2017, $64.9 million in 2018, and $18.3 million in 2019. Of PUDs, we plan to develop 15%, or 24,639 MMcfe, in 2015, and 3%, or 4,522 MMcfe, in 2016. As we continue to develop our properties and have more well production and completion data, we believe we will continue to realize cost savings and experience lower relative drilling and completion costs as we convert PUDs into proved developed reserves in upcoming years. All of our PUD drilling locations are scheduled to be drilled prior to the end of 2019.

 

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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:

 

		Year ended December 31,
		2014				2013				2012
Total production volumes:
Natural gas (MMcf)			19,760.2				1,118.8				7.7
NGLs (MBbls)			536.0				1.3				—
Oil (MBbls)			594.9				87.2				4.5
Combined (MMcfe)			26,545.5				1,650.2				34.6
Average daily production volumes:
Natural gas (Mcf/d)			54,137				3,065				21
NGLs (Bbls/d)			1,468				4				—
Oil (Bbls/d)			1,630				239				12
Combined (Mcfe/d)			72,727				4,521				95
Volume weighted average realized prices:
Natural gas ($/Mcf)(1)		$	3.51			$	3.85			$	3.53
NGLs ($/Bbl)			39.27				48.17				—
Oil ($/Bbl)			79.54				98.22				76.19
Combined ($/Mcfe)		$	5.19			$	7.84			$	10.69
Expenses (per Mcfe):
Lease operating		$	0.32			$	1.56			$	0.46
Transportation, gathering and compression			0.68				0.04				—
Production, severance and ad valorem taxes			0.27				0.05				0.03
Depletion, depreciation and amortization			3.36				3.73				11.68
General and administrative			1.71				12.89				127.89

 

(1)

Including the effects of commodity hedging, the average effective price for the year ended December 31, 2014 would have been $4.57 per Mcf of gas. The total volume of gas associated with these hedges represented approximately 38% of our total sales volumes for the year ended December 31, 2014. There were no commodity derivatives in place as of or for the years ended December 31, 2013 and 2012.

For the year ended December 31, 2014, our revenue consisted of 50% natural gas, 15% NGLs, and 35% oil.

Productive Wells

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

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

As of December 31, 2014, we owned an average 80.3% working interest in 1,118 gross (897.3 net) productive wells, which were comprised of 712 gross (554.9 net) gas wells and 406 gross (356.0 net) oil wells. In addition, we owned an average 82.8% working interest in 159 gross (131.7 net) wells producing in uneconomic quantities, which were comprised of 144 gross (120.6 net) gas wells and 15 gross (11.0 net) oil wells.

 

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

Developed and Undeveloped Acreage

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

 

		Developed Acreage								Undeveloped Acreage								Total Acreage
Area		Gross				Net(1)				Gross				Net(1)				Gross				Net(1)
Ohio			175,668				143,833				114,618				77,904				290,286				221,737
West Virginia			—				—				307				177				307				177
Total			175,668				143,833				114,925				78,081				290,593				221,914

 

(1)

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

Many of the leases comprising the undeveloped acreage set forth in the table above will expire at the end of their respective primary terms unless operations have commenced on the leasehold acreage or lands pooled therewith have been established prior to such date, in which event the lease will remain in effect until the cessation of production in commercial quantities. As of December 31, 2014, we had leases representing approximately 2,336 gross (1,604 net) acres scheduled to expire in 2015, 16,036 gross (4,721 net) acres scheduled to expire in 2016, 41,693 gross (29,288 net) acres scheduled to expire in 2017 and 34,082 gross (23,540 net) acres scheduled to expire in 2018 and beyond, although approximately 52% of our leases in the Utica Core Area have a 5-year extension at our option. We have not attributed any PUD reserves to acreage whose expiration date precedes the scheduled date for PUD drilling. In calculating our PUD reserves we have assumed that Fossil Creek will elect to participate in the drilling of these wells for their full interest and have deducted this interest when calculating our net PUD reserves.

 

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Drilling Results

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

 

		Year ended December 31,
		2014								2013								2012
		Gross				Net				Gross				Net				Gross				Net
Development Wells:
Productive			100				33.6				34				30.7				1				0.3
Dry holes			—				—				—				—				—				—
Exploratory Wells:
Productive			1				.05				2				1.2				—				—
Dry holes			—				—				—				—				1				1.0
Total:
Productive			101				34.1				36				31.9				1				0.3
Dry holes			—				—				—				—				1				1.0

As of December 31, 2013, we had 60 gross (23 net) wells in the process of drilling, completing or shut in awaiting infrastructure that are not reflected in the above table. As of December 31, 2014, we had 83 gross (39.5 net) wells in the process of drilling, completing or shut in awaiting infrastructure that are not reflected in the above table.

Operations

General

As of December 31, 2014, we operated approximately 85% of our proved reserves. As operator, we design and manage the development of a well and supervise operation and maintenance activities on a day-to-day basis. Independent contractors engaged by us provide all the equipment and personnel associated with these activities. We employ engineers, geologists and land professionals who work to improve production rates, increase reserves and lower the cost of operating our oil and natural gas properties.

Major Customers

For the year ended December 31, 2014, sales to Antero Resources and ARM Energy Management represented approximately 47% and 25% of our total sales, respectively. For the year ended December 31, 2013, sales to Antero Resources, Devco Oil Inc., Dominion East Ohio, and Ergon represented approximately 38%, 24%, 13%, and 12% of our total sales, respectively. For the year ended December 31, 2012, Antero Resources accounted for 100% of our total sales. Although a substantial portion of production is purchased by these major customers, we do not believe the loss of any one or several customers would have a material adverse effect on our business, as other customers or markets would be accessible to us.

Title to Properties

We believe that we have satisfactory title to all of our producing properties in accordance with generally accepted industry standards. As is customary in the industry, in the case of undeveloped properties, often cursory investigation of record title is made at the time of lease acquisition. Investigations are made before the consummation of an acquisition of producing properties and before commencement of drilling operations on

 

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undeveloped properties. Individual properties may be subject to burdens that we believe do not materially interfere with the use or affect the value of the properties. Burdens on properties may include:

 

•

customary royalty interests;

 

•

liens incident to operating agreements and for current taxes;

 

•

obligations or duties under applicable laws;

 

•

development obligations under natural gas leases;

 

•

net profits interests;

 

•

mortgages by a lessor; or

 

•

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

Seasonality

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

Competition

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

Regulation of the Oil and Natural Gas Industry

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

 

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

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

Regulation of Production of Natural Gas and Oil

The production of natural gas and oil is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. All of the states in which we own and operate properties have regulations governing conservation matters, including provisions for the unitization or pooling of natural gas and oil properties, the establishment of maximum allowable rates of production from natural gas and oil wells, the regulation of well spacing or density, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of natural gas and oil that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although in some cases we can apply for exceptions to such regulations or to have reductions in well spacing or density. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of natural gas, NGLs and oil within its jurisdiction.

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

Regulation of Transportation and Sales of Natural Gas

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

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

 

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

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

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

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

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

Section 1(b) of the NGA excludes natural gas gathering facilities from regulation by FERC under the NGA. Further, an entity is not subject to regulation under NGA by FERC as a “natural gas company” solely by virtue of such entity owning or operating such facilities. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to determine that the owner/operator of such facilities is not subject to

 

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regulation as a natural gas company under the NGA. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of ongoing litigation and FERC and Congress have discretion to revise the jurisdictional line. Consequently, the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress.

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

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

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

Regulation of Environmental and Occupational Safety and Health Matters

General

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

In addition, public and regulatory scrutiny of the energy industry has resulted in increased environmental regulation and enforcement being either proposed or implemented. For example, the EPA’s 2014—2016 National Enforcement Initiatives include “Assuring Energy Extraction Activities Comply with Environmental Laws.” According to the EPA’s website, “some techniques for natural gas extraction pose a significant risk to public health and the environment.” To address these concerns, the EPA’s goal is to “address incidences of noncompliance from natural gas extraction and production activities that may cause or contribute to significant

 

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harm to public health and/or the environment.” The EPA has emphasized that this initiative will be focused on those areas of the country where energy extraction activities are concentrated, and the focus and nature of the enforcement activities will vary with the type of activity and the related pollution problem presented. This initiative could involve a large scale investigation of our facilities and processes, and could lead to potential enforcement actions, penalties or injunctive relief against us.

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

The Safe Drinking Water Act and the Underground Injection Control Program

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from subsurface rock formations. We regularly use hydraulic fracturing as part of our operations. Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the federal Safe Drinking Water Act, or the SDWA, over hydraulic fracturing activities involving the use of diesel fuel. From time to time, however, Congress has proposed legislation to amend the SDWA to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of all hydraulic fracturing activities, as well as to require disclosure of the chemical constituents of the fluids used in the fracturing process. Scrutiny of hydraulic fracturing activities by the EPA continues in other ways, with the EPA having commenced a multi-year study of the potential environmental impacts of hydraulic fracturing, draft results of which are anticipated to be available in 2014. In addition, on October 20, 2011, the EPA announced its intention to propose regulations by 2014 under the CWA to develop standards for wastewater discharges from hydraulic fracturing and other natural gas production activities. According to EPA’s website, the agency expects publication of a proposed rule in 2015. Moreover, the United States Department of the Interior published a revised proposed rule on May 24, 2013 that would implement updated requirements for hydraulic fracturing activities on federal lands, including new requirements relating to public disclosure, well bore integrity and handling of flowback water. Other governmental agencies, including the United States Department of Energy have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms and could ultimately make it more difficult or costly for us to perform fracturing and increase our costs of compliance and doing business.

At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure, and well construction requirements on hydraulic fracturing activities. In Ohio, the Department of Natural Resources has proposed draft regulations that would require a minimum distance between the hydraulic fracturing facilities and streams, require operators to take spill-containment measures, and regulate the types of liners required for waste storage. Local governments may also seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nonetheless regulations can be expected to become stricter in the future, and, if new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

 

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Hazardous Substances and Wastes

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

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

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

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

Waste Discharges

The CWA and its state analog impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. The CWA and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. Spill prevention, control and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of navigable waters by a petroleum hydrocarbon tank spill, rupture or leak. In addition, the CWA and analogous state laws require

 

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individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. Federal and state regulatory agencies can impose administrative, civil and criminal penalties as well as other enforcement mechanisms for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.

Air Emissions

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

Oil Pollution Act

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

National Environmental Policy Act

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

 

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Endangered Species Act and Migratory Bird Treaty Act

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

Worker Safety

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

Employees

As of December 31, 2014, we had approximately 227 full-time employees. Our future success will depend partially on our ability to attract, retain and motivate qualified personnel. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages. We utilize the services of independent contractors to perform various field and other services.

Legal Proceedings

The West Appeal

Prior to the Oxford Acquisition, Oxford commenced a lawsuit on October 24, 2011 in the Common Pleas Court of Belmont County, Ohio against Mr. Barry West, a lessor under an Oxford oil and gas lease, to enforce its rights to access and drill a well pursuant to the lease during its initial 5-year primary term, which we refer to as the West Lawsuit. 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 trial court’s decision in the West Lawsuit 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 the lease is a “no term” perpetual lease, by ruling that perpetual leases are void as a matter of Ohio law and by invalidating such leases. We cannot predict the outcome of this lawsuit or the amount of time and expense that will be required to resolve the lawsuit.

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April 14, 2015, we are a party to one other lawsuit that makes allegations similar to those made in the West Lawsuit. This lawsuit, together with the West Lawsuit, affect approximately 157 gross (157 net) leasehold acres and were capitalized on our balance sheet as of December 31, 2014 at $0.6 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 in the West Lawsuit. These efforts have resulted in modifications to leases covering approximately 34,256 net acres out of the approximately 46,549 net acres we believe may require modification to address the issues raised by the trial court in the West Lawsuit. However, we cannot predict whether we will be able to obtain modifications of the leases covering the remaining 12,293 net acres to effectively resolve issues related to the Belmont County trial court’s ruling in the West Lawsuit or the amount of time and expense that will be required to amend these leases and our other leases may also require modification to address such issue.

In light of the foregoing, if the appeals court affirms the trial court ruling in the West Lawsuit, 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. Consequently, this could result in a loss of our mineral rights and an impairment of our related assets, and 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.

On September 26, 2014, the Ohio Court of Appeals for the Seventh Appellate District, which is the Appellate Court that will decide our appeal in the West Lawsuit, issued its decision in Hupp v. Beck Energy. Hupp v. Beck Energy was an appeal of a Monroe County trial court decision upon which the trial court in the West Lawsuit based its decision. The Appellate Court in Hupp v. Beck Energy held that while Ohio law disfavors perpetual leases, courts in Ohio have not found them to be per se illegal or void from their inception. The Appellate Court in Hupp v. Beck Energy further held that the trial court misinterpreted both the pertinent lease provisions and Ohio law on the subject and erred in concluding that the subject lease was a no-term, perpetual lease that was void ab initio as against public policy. On November 7, 2014, the plaintiff landowners filed an appeal of the Appellate Court’s decision in Hupp v. Beck Energy with the Supreme Court of Ohio, which was accepted by the Supreme Court of Ohio on January 28, 2015. On March 2, 2015, the Ohio Court of Appeals for the Seventh Appellate District stayed all proceedings in the Company’s appeal in the West case pending a decision by the Supreme Court of Ohio in the Hupp v. Beck Energy appeal.

We believe that there are strong grounds for appeal of the trial court’s decision in the West Lawsuit, and therefore, we intend to pursue all available appellate rights, and to vigorously defend against the claims in the West Lawsuit. Based on the merits of our appeal and the favorable holdings in the Hupp v. Beck Energy, we believe that it is not probable that trial court’s decision in the West Lawsuit will be upheld in the appeal or that we will incur a material loss in the West Lawsuit.

Other

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

 

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MANAGEMENT

Directors, Executive Officers and Other Key Employees

The following table sets forth names, ages and titles of our directors and executive officers as of April 1, 2015

 

Name		Age				Position with Eclipse Resources
Benjamin W. Hulburt			41			Chairman, President and Chief Executive Officer
D. Martin Phillips			61			Director
Robert L. Zorich			65			Director
Douglas E. Swanson, Jr.			43			Director
Mark E. Burroughs, Jr.			39			Director
Christopher K. Hulburt			44			Director, Executive Vice President, Secretary and General Counsel
Randall M. Albert			57			Director
Richard D. Paterson			64			Director
Joseph C. Winkler, III			63			Director
Matthew R. DeNezza			44			Executive Vice President and Chief Financial Officer
Thomas S. Liberatore			58			Executive Vice President and Chief Operating Officer

The following table sets forth information regarding our other key employees as of April 1, 2015.

 

Name		Age				Position with Eclipse Resources
Oleg Tolmachev			40			Vice President, Drilling & Completions
Roy Steward			43			Vice President, Chief Accounting Officer
Marty L. Byrd			58			Vice President, Land
Bruce King			54			Vice President, Operations
Dr. Brian Panetta			44			Vice President, Geology
Bryan M. Moody			45			Vice President, Business Development, Finance and Reservoir Engineering
Melissa L. Hamsher			48			Vice President, Health, Safety, Environment & Regulatory
Lawrence Gorski			61			Vice President, Administration
Todd Bart			50			Vice President and Controller
John Colling, Jr.			58			Vice President and Treasurer
Dana Bryant			39			Vice President, Marketing
Timothy J. Loos			35			Vice President, Financial Planning & Analysis
Daniel T. Sweeney			38			Vice President, Assistant Secretary and Associate General Counsel

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

Directors and Executive Officers

Benjamin W. Hulburt co-founded Eclipse Resources in January 2011 and has served as our Chief Executive Officer, President and member of our board since our inception. He has also served as the Chairman of the board of directors of Eclipse Resources Corporation since its inception. Prior to co-founding Eclipse Resources, Mr. Hulburt served as the Chief Executive Officer and a member of the board of directors of Rex Energy, an independent oil and gas exploration and production company with operations in the Appalachian and Illinois Basins within the United States, from March 2007 to October 2010. He also served as President of Rex Energy from February 2008 until October 2010. Mr. Hulburt co-founded Rex Energy in 2001 and led Rex Energy through its initial public offering in 2007. Prior to Rex Energy’s initial public offering, Mr. Hulburt served as the Chief Executive Officer of Rex Energy Operating Corp. from October 2006 until October 2010, and as the President of Rex Energy Operating Corp. from March 2004 until October 2006. Mr. Hulburt also served as

 

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the Chief Financial Officer of Douglas Oil & Gas Limited Partnership, an affiliate of Rex Energy, from January 2001 until February 2004. Prior to November 2000, Mr. Hulburt served on active duty as a commissioned officer in the United States Army for four years, leaving the service holding the rank of Captain. Mr. Hulburt received his Bachelor of Science degree in Finance from The Pennsylvania State University. He is the brother of Christopher K. Hulburt.

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

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

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

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

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

Douglas E. Swanson, Jr. has served as a member of our board since January 2011. He is currently a Managing Partner of EnCap. Prior to joining EnCap in 1999, he was in the corporate lending division of Frost National Bank from 1995 to 1997, specializing in energy related service companies, and was a financial analyst in the corporate lending group of Southwest Bank of Texas from 1994 to 1995. Mr. Swanson serves on the board of Oasis Petroleum Inc., Earthstone Energy, Inc., and several EnCap portfolio companies. Mr. Swanson is a

 

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member of the Independent Petroleum Association of America and the Texas Independent Producers and Royalty Owners Association. Mr. Swanson holds a B.A. in Economics and an M.B.A., both from the University of Texas at Austin.

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

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

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

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

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

Randall M. Albert has served as a member of our board since June 2014. Mr. Albert served as the Chief Operating Officer of the Gas Division of CONSOL Energy Inc., a producer of coal and natural gas (“CONSOL”), from 2010 until November 2013. From 2005 until 2010, he was the operational leader of CONSOL’s gas business in Northern Appalachia. Mr. Albert began working for CONSOL in 1979 and was selected to lead the operation of its coalbed methane gas business in Southern Appalachia in 1985. He is a board member of the Virginia Oil and Gas Association and served as a founding advisory member of the board and chairman of the Marcellus Shale Coalition. Additionally, he currently serves on the advisory board for the Virginia Tech Mining Engineering Department. Mr. Albert is a Registered Professional Engineer in Virginia and West Virginia and holds a B.S. degree in Mining Engineering from Virginia Polytechnic Institute and State University.

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

 

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Richard D. Paterson has served as a member of our board since June 2014. Mr. Paterson retired from PricewaterhouseCoopers LLP, an international network of auditors, tax and business consultants (“PwC”), in June 2011 after 37 years of service. Most recently, he served as PwC’s Global Leader of its Consumer, Industrial Products and Services Practices (comprising the Automotive, Consumer and Retail, Energy, Utilities and Mining, Industrial Products, Pharmaceutical and Health Industries Sectors) and also as Managing Partner of its Houston Office and U.S. Energy Practice. From 2001 to 2010, Mr. Paterson was PwC’s Global Leader of its Energy, Utilities and Mining Practice. From 1997 to 2001, Mr. Paterson led PwC’s Energy Practice for Europe, Middle East and Africa. During the aforementioned time periods, Mr. Paterson also was responsible for the audits of numerous PwC clients, principally in the energy sector. He began his career with PwC in 1974 and was admitted as a partner of PwC in 1987. Mr. Paterson serves on the board, a member of the governance committee, and as chairman of the audit committee of Parker Drilling Company, a provider of contract drilling and drilling related services and rental tools to the energy industry. He also serves on the board and audit and finance committees of Tidewater, Inc., a provider of marine services to the energy industry, and he previously served on the board and as chairman of the audit committee of Zaff GP LLC, a private equity fund investing in emerging markets with a focus on the energy, infrastructure and real estate sectors. Mr. Paterson is a member of the National Association of Corporate Directors and has been a speaker at the World Energy Congress and World Petroleum Congress. Mr. Paterson also previously served as a board member of the U.S./Russia Business Council and the U.S. Energy Association. Mr. Paterson received a B.A. in Marketing and an M.B.A. in Accounting from Michigan State University. He is also a Certified Public Accountant.

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

Joseph C. Winkler, III has served as a member of our board since June 2014. Mr. Winkler served as Chairman and Chief Executive Officer of Complete Production Services, Inc., a provider of specialized oil and gas services and equipment in North America (“Complete”), from March 2007 until February 2012, at which time Complete was acquired by Superior Energy Services, Inc. From June 2005 to March 2007, Mr. Winkler served as Complete’s President and Chief Executive Officer. Prior to that, from March 2005 until June 2005, Mr. Winkler served as the Executive Vice President and Chief Operating Officer of National Oilwell Varco, Inc., an oilfield capital equipment and services company, and from May 2003 until March 2005, as the President and Chief Operating Officer of such company’s predecessor, Varco International, Inc. (“Varco”). From April 1996 until May 2003, Mr. Winkler served in various other capacities with Varco and its predecessor, including Executive Vice President and Chief Financial Officer. From 1993 to April 1996, Mr. Winkler served as the Chief Financial Officer of D.O.S., Ltd., a privately held provider of solids control equipment and services and coil tubing equipment to the oil and gas industry, which was acquired by Varco in April 1996. Prior to joining D.O.S., Ltd., Mr. Winkler served as Chief Financial Officer of Baker Hughes INTEQ, and served in a similar role for various companies owned by Baker Hughes Incorporated, including Eastman/Telco and Milpark Drilling Fluids. Mr. Winkler serves on the board and as chairman of the audit and conflicts committee of the general partner of Hi-Crush Partners LP, an integrated producer, transporter, marketer and distributor of a specialized mineral used to enhance production in oil and natural gas wells. Mr. Winkler also serves on the board and as a member of the compensation and nominating and governance committees of Dresser-Rand Group, Inc., a provider of rating equipment solutions, and serves on the board and as a member of the finance committee of Commercial Metals Company, a vertically integrated steel company. Mr. Winkler is a Gulf Coast District Director of the Petroleum Equipment Suppliers Association (PESA), an oilfield service and supply industry trade association. Mr. Winkler received a B.S. degree in Accounting from Louisiana State University.

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

Matthew R. DeNezza has served as our Executive Vice President and Chief Financial Officer since April 2013. Prior to joining Eclipse Resources and commencing in 2002, Mr. DeNezza served in the Global Natural

 

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

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

Other Key Employees

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

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

Marty L. Byrd has served as our Vice President, Land since July 2013. Prior to joining Eclipse Resources, from January 2006 to January 2013, Mr. Byrd served as the Vice President, Land, Eastern Division—Appalachian Basin for Chesapeake Energy, where he was responsible for overseeing the acquisition of over a million leasehold acres in the Marcellus Shale and managing the land activities to support the drilling of over 400

 

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horizontal wells with a drilling schedule utilizing up to 26 rigs. From January 2001 to January 2006, Mr. Byrd worked in Chesapeake Energy’s Mid-Continent Region and served as the Land Manager in the Anadarko Basin District. Mr. Byrd received his Bachelors of Science degree in Business Administration from the University of Central Oklahoma.

Bruce King has served as our Vice President, Operations since September 2013. Prior to joining Eclipse Resources, from April 2011 to September 2013, Mr. King served as the Operations Manager, Stone Energy, Appalachia where he was responsible for construction, pipelines, facilities and production, including developing infrastructure for its unconventional shale program in West Virginia and Pennsylvania. Prior to joining Stone Energy, from August 2009 to April 2011, Mr. King was the Gas Systems and Facilities Manager at EnerVest Operating Company. From August 2000 to August 2009, he served as Facility Manager at Cabot Oil & Gas where he oversaw development of gathering systems, gas treatment and midstream assets, including the core infrastructure for its Marcellus Shale development. Prior to his time at Cabot Oil & Gas, Mr. King spent 8 years with Columbia Gas Transmission (NiSource) where he oversaw major infrastructure projects in natural gas transmission and storage. Mr. King received his Bachelors of Science degree in Mechanical Engineering from the West Virginia University Institute of Technology.

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

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

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

 

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

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

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

Dana Bryant has served as our Vice President, Marketing for Eclipse Resources since January 2014. Prior to joining Eclipse Resources, from June 2012 to January 2014, Mrs. Bryant served as Senior Commercial Development Representative for Williams Partners L.P., a master limited partnership specializing in natural gas transportation and processing, where she developed gathering and processing projects for Marcellus producers in West Virginia and Ohio. Prior to joining Williams Partners, from October 2001 to May 2012, Mrs. Bryant served

 

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as Director—Producer Services for BP Energy Company where she was responsible for structuring deals with Marcellus producers, including gas purchases, capacity releases and asset management agreements. Mrs. Bryant graduated with a Bachelor of Science degree from Texas A&M University in College Station, Texas and a Masters of Business Administration degree from Tulane University in New Orleans, Louisiana.

Timothy J. Loos has served as our Vice President, Financial Planning & Analysis since December 2014. From July 2014 until November 2014, Mr. Loos served as our Director of Financial Reporting. Prior to joining Eclipse Resources, from February 2013 until June 2014, Mr. Loos served as Business Specialist for EQT Corporation where he was responsible for developing financial budgets, forecasts, analysis and modeling. Prior to joining EQT, from January 2009 until January 2013, Mr. Loos served as the Manager of Gas Accounting for CONSOL. From July 2007 until December 2008, he served as a senior auditor for Deloitte & Touche LLP. From October 2003 until June 2007, he served as senior auditor for UHY LLP, a licensed independent CPA firm. Mr. Loos received his Bachelor of Science degree in Accounting and Finance from John Carroll University and Masters of Business Administration from the Joseph M. Katz Graduate School of Business, University of Pittsburgh. He received his Certified Public Accounting designation from the State of Virginia in 2005 and is currently a member of the American Institute of Certified Public Accountants.

Daniel T. Sweeney has served as our Vice President, Assistant Secretary and Associate General Counsel since August 2014. Beginning in April 2013, Mr. Sweeney previously served as our Associate General Counsel and Assistant Secretary. Prior to joining Eclipse Resources, from November 2010 to April 2013, Mr. Sweeney served as Associate Division Counsel—Eastern Division for Chesapeake Energy Corporation where he advised the company on a wide range of energy related legal matters concerning shale plays in Ohio, Pennsylvania and West Virginia. Prior to joining Chesapeake Energy, from April 2008 to November 2010, Mr. Sweeney served as Director—Legal Services for Rex Energy Corporation. Prior to joining Rex Energy, from May 2005 to April 2008, Mr. Sweeney worked for several Pittsburgh, Pennsylvania law firms where he focused his practice on commercial and complex litigation. Mr. Sweeney graduated with a Bachelors of Arts degree from Case Western Reserve University in Cleveland, Ohio and a Juris Doctorate degree from Duquesne University in Pittsburgh, Pennsylvania.

Board of Directors

Our board of directors currently consists of nine members, Benjamin W. Hulburt, Christopher K. Hulburt, D. Martin Phillips, Robert L. Zorich, Douglas E. Swanson, Jr., Mark E. Burroughs, Jr., Randall M. Albert, Richard D. Paterson and Joseph C. Winkler, III.

In connection with the completion of our IPO, we entered into a stockholders agreement with Eclipse Holdings and its limited partners, the EnCap Funds, the Management Funds and Eclipse Management, which we refer to as our principal stockholders. Please see “Certain Relationships and Related Party Transactions—Stockholders Agreement.” Pursuant to the stockholders agreement, we and our principal stockholders agreed to take certain actions to cause individuals designated by our principal stockholders to become members of our board of directors.

In connection with our IPO, our board reviewed the independence of our current directors using the independence standards of the NYSE, and based on this review, determined that Messrs. Phillips, Zorich, Swanson, Burroughs, Albert, Paterson and Winkler are independent within the meaning of the NYSE listing standards. As a result, our board consists of nine members, seven of whom are independent.

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

 

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

Status as a Controlled Company

Because Eclipse Holdings and its limited partners, including the EnCap Funds, the Management Funds and Eclipse Management, collectively beneficially own a majority of our outstanding common stock and are deemed a group as a result of our stockholders agreement, we are a controlled company under NYSE corporate governance standards. A controlled company may elect not to comply with certain NYSE corporate governance standards, including the requirements that:

 

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

 

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

 

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

We have utilized, and intend to continue to utilize, the exemption relating to the nominating and governance committee requirements, but our board of directors consists of a majority of independent directors within the meaning of the NYSE listing standards and we have recently appointed a compensation committee with a written charter addressing the committee’s purpose and responsibilities. However, we may utilize any of these exemptions for so long as we are a controlled company. Accordingly, you do have the same protections afforded to stockholders of companies that are subject to all of the corporate governance requirements of the NYSE.

Committees of the Board of Directors

We currently have an audit committee and compensation committee of our board of directors, and may have such other committees as the board of directors shall determine from time to time. The audit committee and compensation committee of our board of directors has the composition and responsibilities described below.

Audit Committee

Rules implemented by the NYSE and SEC require us to have an audit committee comprised of at least three directors who meet the independence and experience standards established by the NYSE and the Exchange Act, subject to transitional relief during the one-year period following the completion of our IPO. Our audit committee consists of Messrs. Paterson (Chair), Albert and Winkler, each of whom is independent under the rules of the SEC and the listing standards of the NYSE. As required by the rules of the SEC and listing standards of the NYSE, the audit committee consists solely of independent directors. Our board has also determined that Mr. Paterson satisfies the definition of “audit committee financial expert.”

The audit committee oversees, reviews, acts on and reports on various auditing and accounting matters to our board of directors, including: the selection of our independent accountants, the scope of our annual audits, fees to be paid to the independent accountants, the performance of our independent accountants and our accounting practices. In addition, the audit committee oversees our compliance programs relating to legal and

 

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regulatory requirements. We have adopted an audit committee charter defining the committee’s primary duties in a manner consistent with the rules of the SEC and applicable stock exchange or market standards. A copy of our audit committee charter is posted on our website at http://ir.eclipseresources.com/committee-charters.

Compensation Committee

Although we are a controlled company within the meaning of the NYSE corporate governance standards and previously relied on an exemption from the requirement that we have a compensation committee, our board of directors appointed Messrs. Burroughs (Chair), Albert and Winkler to our compensation committee on January 20, 2015, each of whom is independent under the rules of the SEC and the listing standards of the NYSE.

Our compensation committee reviews, evaluates and approves the agreements, plans, policies and programs of the company to compensate our executive officers and directors. The compensation committee’s goal is to ensure that our compensation programs are designed to provide a competitive level of compensation to attract and retain talented directors and executives, reward and encourage maximum corporate and individual performance, promote accountability and assure that employees and director interests are aligned with the interests of our stockholders. Our compensation committee has adopted a written charter addressing the committee’s purpose and responsibilities in a manner consistent with the rules of the SEC and applicable stock exchange or market standards. A copy of our compensation committee charter is posted on our website at http://ir.eclipseresources.com/committee-charters.

Compensation Committee Interlocks and Insider Participation

None of Messrs. Albert, Winkler and Burroughs, the individuals who presently serve on the compensation committee, has interlocking relationships as defined by the SEC or has had any relationships with Eclipse requiring disclosure under the SEC rules relating to certain relationships and related party transactions.

Corporate Code of Business Conduct and Ethics and Financial Code of Ethics

Our board of directors has adopted a corporate code of business conduct and ethics applicable to our employees, directors and officers, and a financial code of ethics applicable to our senior financial officers, in accordance with applicable U.S. federal securities laws and the corporate governance rules of the NYSE. Any waiver of these codes may be made only by our board of directors and will be promptly disclosed as required by applicable U.S. federal securities laws and the corporate governance rules of the NYSE. The corporate code of business conduct and ethics and the financial code of ethics are posted on the our website at http://ir.eclipseresources.com/corporate-governance.

Corporate Governance Guidelines

Our board of directors believes that sound governance practices and policies provide an important framework to assist it in fulfilling its duty to stockholders. Our corporate governance guidelines cover the following principal subjects:

 

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role and functions of the board of directors;

 

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qualifications and independence of directors;

 

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size of the board of directors and director selection process;

 

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committee functions and independence of committee members;

 

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meetings of non-employee directors;

 

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self-evaluation;

 

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compensation of the board of directors;

 

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succession planning;

 

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Access to senior management and to independent advisors; and

 

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director orientation and continuing education.

The corporate governance guidelines are posted on the our website at http://ir.eclipseresources.com/corporate-governance. The corporate governance guidelines will be reviewed periodically and as necessary by our board.

The NYSE has adopted rules that require listed companies to adopt governance guidelines covering certain matters. We believe that the corporate governance guidelines comply with the NYSE rules.

 

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EXECUTIVE COMPENSATION AND OTHER INFORMATION

Named Executive Officers

The following table sets forth our “Named Executive Officers.” As an emerging growth company (as such term is defined in the Jumpstart Our Business Startups Act) we have opted to comply with the executive compensation disclosure rules in Item 402 of Regulation S-K applicable to “smaller reporting companies” (as such term is defined in Item 10(f) of Regulation S-K), which require compensation disclosure for our principal executive officer and the two most highly compensated executive officers other than our principal executive officer. Please see “Directors and Executive Officers” for a description of our current executive officers, including historical roles held by our 2013 and 2014 Named Executive Officers.

 

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

Summary Compensation Table

The following table summarizes, with respect to our Named Executive Officers, information relating to the compensation earned for services rendered in all capacities during the fiscal year ended December 31, 2014.

 

Name and Principal Position		Year				Salary				Bonus				Equity Awards(1)				All Other Compensation(2)				Total
Benjamin W. Hulburt			2014			$	362,675			$	130,519			$	—			$	35,346			$	528,540
(Chairman, President and CEO)			2013			$	261,038			$	—			$	—			$	29,217			$	290,255
Matthew R. DeNezza			2014			$	287,777			$	220,336	(4)		$	—			$	74,496			$	582,609
(Executive Vice President and CFO)			2013			$	195,673	(3)		$	150,000	(5)		$	12,580			$	56,615			$	414,868
Christopher K. Hulburt			2014			$	287,154			$	130,519			$	—			$	33,508			$	451,181
(Executive Vice President, Secretary and General Counsel)			2013			$	261,038			$	—			$	—			$	28,857			$	289,895

 

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

(2)	Includes 401(k) match, health and life insurance benefits and cellphone allowance, and for Mr. DeNezza, $37,843 of relocation costs reimbursement in 2013 and $38,574 of relocation costs reimbursement in 2014.

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

(4)	Includes a bonus of $136,404 related to his employment letter stipulating that Mr. DeNezza must be employed by the Company on April 1, 2014.

(5)	Represents sign-on bonus received upon commencement of employment.

Narrative Disclosure to Summary Compensation Table

The following describes material features of our compensation disclosed in the Summary Compensation Table above. Although we are a controlled company within the meaning of the NYSE corporate governance standards and previously relied on an exemption from the requirement that we have a Compensation Committee, the Board appointed Messrs. Burroughs (Chair), Albert and Winkler to the Compensation Committee on January 20, 2015. Prior to January 20, 2015, all final determinations regarding executive officer compensation were made by analyzing the appropriateness of the base salary for each of our Named Executive Officers in light of the base salaries of other executives in the peer group that we have identified, with the assistance of an independent compensation consultant, both on a stand-alone basis and as a component of total compensation.

We have reviewed the background, experience and independence of the Compensation Committee members and based on this review, we have determined that each member of the Compensation Committee (i) meets the

 

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independence requirements of the NYSE corporate governance listing standards, (ii) is an “outside director” pursuant to the criteria established by the Internal Revenue Service, and (iii) meets the enhanced independence standards for compensation committee members established by the SEC.

In addition, the Board has determined that each member of the Compensation Committee is (i) independent pursuant to the enhanced independence standards for compensation committee members set forth in Section 303A.02(A)(ii) of the NYSE Listed Company Manual, based on evaluations conducted in accordance with and considering the factors set forth in Section 303A.02(A)(ii), and (ii) an “outside director” pursuant to the criteria established by the Internal Revenue Service.

Base Salary

Each Named Executive Officer’s base salary is a fixed component of compensation for each year for performing specific job duties and functions. Prior to our initial public offering, the base salaries of Messrs. DeNezza and C. Hulburt, were set pursuant to arms-length negotiations with our senior management, subject to EnCap’s approval (Mr. B. Hulburt’s base salary was set pursuant to arms-length negotiations directly with the representatives of EnCap serving on the Board). On August 26, 2014, we entered into employment agreements with Messrs. B. Hulburt, C. Hulburt and DeNezza which set the base salaries for such individual at amounts recommended by our independent compensation consultant in light of the base salaries of executives in our peer groups.

Annual Cash Bonus

During 2014, we paid cash bonuses to each of our Named Executive Officers. The targeted bonus amount for each Named Executive Officer was equal to 50% of their respective earned wages during 2013 and payment of the bonuses was at the discretion of the board of managers of Eclipse I. In addition, Mr. DeNezza received an additional bonus of $136,404 in accordance with his initial terms of employment, which provided the bonus on the first anniversary of his initial employment date.

Employment Agreements

On August 26, 2014, we entered into employment agreements with each of our Named Executive Officers. The employment agreements are for an initial term of three years, and automatically extend for an additional one-year renewal term for every year thereafter unless we or the Named Executive Officer gives written notice to the other party that the automatic extension will not occur at least 90 days prior to the end of the initial term, or, if applicable, the then-current renewal term, in each case, unless terminated earlier in accordance with the terms and conditions set forth therein. Pursuant to the terms of the employment agreements, Messrs. Benjamin W. Hulburt, Matthew R. DeNezza and Christopher K. Hulburt will (i) receive an annual base salary of $563,550, $317,050 and $315,000, respectively, and (ii) be eligible to receive an annual performance-based bonus equal to 100%, 85% and 80%, respectively, of their base salaries. The base salaries and the annual performance-based bonus percentages may be increased by the Board of Directors or a designated committee thereof in its discretion but may not be decreased without the Named Executive Officer’s written consent.

The employment agreements also contain non-solicitation, non-competition and confidentiality covenants on behalf of the Named Executive Officers in favor of us. In addition, any amounts payable to the Named Executive Officer under the employment agreements will be subject to any “clawback” policy established by us from time to time.

See “—Employment, Severance or Change in Control Agreements” below for a description of the severance benefits payable to our Named Execution Officers under their respective employment agreements.

 

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Long-Term Incentive Compensation

Incentive Units

Prior to our corporate reorganization, Eclipse I issued non-voting Series C-1 units and Series C-2 units, which we refer to as the Incentive Units, to certain employees of Eclipse I and Eclipse Resources Operating, LLC (“Eclipse Operating”). Pursuant to our corporate reorganization, the Series C-1 Units and Series C-2 Units were exchanged for Series C-1 Units and Series C-2 Units in Eclipse Holdings, and such Incentive Units are held by Eclipse Management, a limited partner of Eclipse Holdings of which management members holding Series C-1 and Series C-2 units are partners. Holders of Incentive Units have economic rights as limited partners of Eclipse Management that approximate the economic rights such holders had when directly holding their Incentive Units. Holders of Incentive Units participate in distributions from Eclipse Holdings through Eclipse Management after distributions have been made to the EnCap Funds, with the level of participation in such distributions adjusting upwards if such distributions satisfy additional specified hurdle rates and return on investment factors. Through Eclipse Management, holders of Series C-2 units participate in distributions from Eclipse Holdings after holders of Series C-1 units have received specified cash distributions. The Incentive Units vest on varying schedules as determined by the vesting schedule set forth in each grant agreement (generally in equal annual amounts over a set period of time or upon a sale of Eclipse).

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

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

In 2013, Mr. DeNezza was granted Series C-1 units and Series C-2 units of Eclipse I in connection with the commencement of his employment with us. The Incentive Units issued to Mr. DeNezza in 2013 are subject to vesting, with one-third of each class of the Incentive Units vesting on each anniversary of his hire date. The first third of each class of Incentive Units vested in fiscal 2014, and two-thirds remain unvested, though the vesting may accelerate upon the earlier of a sale or transfer of substantially all of the interests or assets of Eclipse I, including by way of a merger.

Long-Term Incentive Plan

The Board adopted an omnibus long-term incentive plan for employees, consultants and directors, which we refer to as the LTIP. Our Named Executive Officers are eligible to participate in the LTIP, which provides for the

 

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grant of bonus stock, restricted stock, restricted stock units, options, stock appreciation rights, dividend equivalent rights, performance awards, annual incentive awards and other stock-based awards intended to align the interests of key employees (including the Named Executive Officers) with those of our stockholders.

Set forth below is a summary of the material terms of the LTIP.

The LTIP Generally

The LTIP provides us with the flexibility to make grants of stock options (both incentive stock options or options that do not constitute incentive stock options), restricted stock, restricted stock units, dividend equivalents, performance awards, annual incentive awards, bonus stock awards, or other stock-based awards. All officers and employees of the company or our subsidiaries, as well as other individuals who provide services to us or our subsidiaries (including directors), are eligible to receive awards under the LTIP. The LTIP will expire upon the earliest of (i) its termination by our board of directors, (ii) the date common stock is no longer available under the LTIP for grants of awards, or (iii) the tenth anniversary of the effective date of the LTIP. Shares that may be granted under the LTIP are subject to the availability of shares in the share pool.

Administration of LTIP

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

Shares Available for Awards Under the LTIP

The aggregate maximum number of shares of our common stock that may be issued under the LTIP is 16,000,000. Shares of common stock cancelled, settled in cash, forfeited, withheld, or tendered by the participant to satisfy exercise prices or tax withholding obligations will be available for delivery pursuant to other awards. The common stock delivered pursuant to such awards may be common stock acquired in the open market or acquired from any affiliate or other person, or any combination of the foregoing, as determined in the discretion of the Plan Committee.

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

 

•

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

 

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•

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

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

Types of LTIP Awards

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

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

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

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

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

 

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

Performance and Annual Incentive Awards. For awards granted under the LTIP that are based upon performance criteria specified by the Plan Committee, the Plan Committee will establish the maximum number of shares of common stock subject to, or the maximum value of, each performance award and the performance period over which the performance applicable to the award will be measured. As determined by the Plan Committee, the performance goals applicable to an award may provide for a targeted level or levels of achievement, measured on a GAAP or non-GAAP basis, relating to earnings per share, increase in revenues, increase in cash flow, increase in cash flow from operations, increase in cash flow return, return on net assets, return on assets, return on investment, return on capital, return on equity, economic value added, operating margin, contribution margin, net income, net income per share, pretax earnings, pretax earnings before interest, depreciation and amortization, pretax operating earnings after interest expense and before incentives, service fees, and extraordinary or special items, total stockholder return, debt reduction, market share, change in the fair market value of our stock, operating income, amount of oil and natural gas reserves, oil and natural gas reserve additions, cost of finding oil and natural gas reserves, oil and natural gas reserve replacement ratios, oil and natural gas production amounts, oil and natural gas production sales amounts, safety targets, regulatory compliance, and any of the above goals determined on an absolute or relative basis or as compared to the performance of a published or special index deemed applicable by the Plan Committee, including, but not limited to, the Standard & Poor’s 500 Stock Index or a group of comparable companies. Performance goals may differ from participant to participant and from award to award. Any of these metrics may be subject to adjustment as provided in the LTIP. Payment of a performance award may be made in cash, shares of our common stock, or a combination thereof, as determined by the Plan Committee. The Plan Committee may establish a performance pool, which will be an unfunded pool, for purposes of measuring the achievement of a performance goal or goals on one or more criteria set forth above during the given performance period. The Plan Committee may specify the amount of a performance pool as a percentage of any of such criteria, a percentage in the excess of a threshold amount, or as another amount which need not be linearly related to such criteria.

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

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

Recoupment Policy. All payments are subject to our Recoupment Policy, as may be amended by the Board from time to time.

Change in Control

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

Amendment and Termination of the LTIP

The Board is permitted to terminate the LTIP at any time with respect to any shares of our common stock for which awards have not been granted. The Board is also permitted to alter or amend the LTIP or any part

 

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thereof or award thereunder from time to time; provided that no change to the LTIP or such award may be made that would materially impair the rights of a participant without consent of the participant. To the extent any amendment to the LTIP requires stockholder approval pursuant to any applicable federal or state law or regulation or the rule of any stock exchange or automated quotation system on which our common stock may then be listed or quoted, including any increase in any share limitation, such amendment will be subject to the approval of our stockholders.

Outstanding Equity Awards at 2014 Fiscal Year-End

The following table summarizes the outstanding equity awards held by each of our Named Executive Officers as of December 31, 2014.

 

Name		Number of Shares or Units of Stock That Have Not Vested (#)				Value of Shares or Units of Stock That Have Not Vested ($)
Benjamin W. Hulburt			—				—
Matthew R. DeNezza(1)
Eclipse I Class C Units (Series C-1)			13.4				8,429
Eclipse I Class C Units (Series C-2)			70.35				—
Christopher K. Hulburt			—				—

 

(1)

The Eclipse Management Class C Units (Series C-1) and Eclipse Management Class C Units (Series C-2) reported in this table for Mr. DeNezza will vest in three equal annual installments beginning April 1, 2014, though vesting will accelerate upon the earlier of a sale or transfer of substantially all of the interests in or assets of Eclipse Management, including by way of merger. Mr. DeNezza will forfeit any unvested units upon the termination of his employment with us for any reason, though vested units will remain outstanding.

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

Additional Narrative Disclosure

Retirement Benefits

We currently maintain a retirement plan intended to provide benefits under section 401(k) of the Internal Revenue Code of 1986, as amended, under which employees, including our Named Executive Officers, are allowed to contribute portions of their compensation to a tax-qualified retirement account. Under our 401(k) plan, we provide matching contributions equal to 100% of the first 6% of employees’ eligible compensation contributed to the plan. As described in more detail under “—Narrative Disclosure to Summary Compensation Table—Long-Term Incentive Compensation” above, the Incentive Units held by our Named Executive Officers are either forfeited or remain outstanding following the officer’s termination of employment, with no acceleration of vesting or payment being made under the awards upon such termination of employment.

Employment, Severance or Change in Control Agreements

As disclosed above under “—Employment Agreements,” on August 26, 2014 we entered into employment agreements with each of our Named Executive Officers. The employment agreements provide each Named Executive Officer with certain severance benefits upon termination. If the Named Executive Officer’s employment is terminated by us “without Cause” or by the Named Executive Officer for “Good Reason” (as such terms are defined in the employment agreements), then:

 

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we will make a lump sum payment to the Named Executive Officer equal to two times (three times in the case of Benjamin W. Hulburt) the sum of (i) the Named Executive Officer’s annual base salary as

 

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of the termination date, and (ii) the average annual bonus paid to the Named Executive Officer for the three immediately preceding completed calendar years (or if the Named Executive Officer has not been employed for three complete calendar years, then the average of the annual bonuses paid to the Named Executive Officer for the calendar years employed with us);

 

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we will reimburse the Named Executive Officer for any amounts necessary to continue the health care coverage under our group health plans for the Named Executive Officer and his qualified dependents for a period of up to 18 months following the termination date (the “Post-Employment Health Coverage”);

 

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we will pay the Named Executive Officer a prorated annual bonus for the year of termination; and

 

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all unvested equity awards held by the Named Executive Officer at the time of termination that would have vested during the 36-month period following the termination but for the Named Executive Officer’s termination of employment will immediately vest and become exercisable (if applicable), and all performance goals or other vesting criteria with respect to such awards will be deemed achieved at their target levels; provided, however, that equity awards intended to qualify as “performance-based compensation” under Section 162(m) of the Internal Revenue Code of 1986, as amended, will only vest if the performance measures established for those awards are actually attained (unless the termination occurs within the period beginning six months before a change of control and ending on the one-year anniversary of the change of control, in which case all equity awards then held by the Named Executive Officer will fully vest and all performance goals or other vesting criteria with respect to such awards will be deemed achieved at their target levels).

If the Named Executive Officer’s employment is terminated upon the Named Executive Officer’s death or “Disability” (as defined in the employment agreements), then we will make a lump sum payment to the Named Executive Officer equal to one times the Named Executive Officer’s annual base salary as of the termination date and we will provide the Named Executive Officer with the Post-Employment Health Coverage.

Compensation of Directors

During 2014, we implemented a director compensation program to reflect the increased time and responsibility that being the director of a publicly traded company entails. Under this new program, all of our non-employee directors receive the following (the “Director Compensation Program”):

 

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an annual cash retainer of $75,000 ($90,000 for the Chairman of our Audit Committee) paid quarterly in equal installments; and

 

•

an annual equity grant of restricted stock equal in value to approximately $120,000, vesting in full on the first anniversary of the date of grant.

All cash amounts and equity grants under the Director Compensation Program in 2014 were prorated to reflect the period of the year during which we were a publicly traded company. The fees paid to our non-employee directors that are affiliated with EnCap are paid to the funds they manage rather than to the individual directors. Each director is also reimbursed for his reasonable out associated with the attendance of meetings and activities of our board of directors or its committees.

On October 7, 2014, we awarded 4,445 shares of common stock to each of our non-employee directors under the LTIP. These shares are scheduled to vest in full on June 25, 2015, which is the first anniversary date of the completion of our initial public offering of common stock.

Benjamin W. Hulburt and Christopher K. Hulburt are members of our board of directors but are employed by us and, as such, receive no additional compensation for their service on our board of directors.

 

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Director Compensation Table

The following table summarizes the compensation earned by our non-employee directors in 2014. Benjamin W. Hulburt and Christopher K. Hulburt did not receive any compensation for their services as directors during 2014. Please refer to the Summary Compensation Table above for the compensation received by Benjamin W. Hulburt and Christopher K. Hulburt for their services as executive officers during 2014.

 

Name		Fees Earned or Paid in Cash(1)				Stock Awards(2)				Total
Randall M. Albert		$	58,516			$	63,252			$	121,768
Mark E. Burroughs, Jr.		$	75,000			$	63,252			$	138,252
Richard D. Paterson		$	70,220			$	63,252			$	133,472
D. Martin Phillips		$	75,000			$	63,252			$	138,252
Douglas E. Swanson, Jr.		$	75,000			$	63,252			$	138,252
Joseph C. Winkler		$	58,516			$	63,252			$	121,768
Robert L. Zorich		$	75,000			$	63,252			$	138,252

 

(1)

Amounts shown represent the cash retainers for (i) our non-employee directors who are not affiliated with EnCap (Messrs. Burroughs, Phillips, Swanson and Zorich), which are paid annually to the funds they manage rather than to the individual directors, and (ii) our non-employee directors who are not affiliated with EnCap (Messrs. Albert, Paterson and Winkler), which are paid quarterly to such individuals.

(2)

Amount shown represents the grant date fair value of the shares of restricted stock granted during 2014 to each of our non-employee directors. These amounts were calculated based on the closing market price for our shares on the New York Stock Exchange on the date of grant. Each of our non-employee directors held 4,445 shares of restricted stock as of December 31, 2014, the value of each of which is reported in the table above.

 

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PRINCIPAL STOCKHOLDERS

Beneficial Ownership

The following table sets forth information with respect to the beneficial ownership of our common stock as of April 1, 2015 by:

 

•

each person to be known by us to be the beneficial owner of more than 5% of our outstanding shares of common stock;

 

•

each of our named executive officers;

 

•

each of our directors; and

 

•

all of our directors and executive officers as a group.

As of April 1, 2015 approximately 222,531,115 shares of our common stock were outstanding. Unless otherwise noted, the mailing address of each person or entity named in the table below is c/o Eclipse Resources Corporation, 2121 Old Gatesburg Road, Suite 110, State College, Pennsylvania 16803.

 

Name and Address of Beneficial Owner		Number of Shares(1)				Percent of Class(1)
5% Stockholders:
Eclipse Resources Holdings, L.P.(1)			140,353,407				63.1	%
EnCap Funds(2)			34,091,593				15.3	%
Directors and Named Executive Officers:
D. Martin Phillips(1)			4,445				*
Robert L. Zorich(1)			4,445				*
Douglas E. Swanson(1)			4,445				*
Mark E. Burroughs, Jr.(1)			4,445				*
Richard D. Paterson			6,445				*
Randall M. Albert			6,445				*
Joseph C. Winkler, III			11,945				*
Benjamin W. Hulburt(1)			—				*
Christopher K. Hulburt(1)			—				*
Matthew R. DeNezza(1)			—				*
All directors and executive officers as a group (11 individuals)			42,615				*

 

*	Less than 1%

(1)

Eclipse Holdings is governed by a board of managers that includes four members (currently D. Martin Phillips, Robert L. Zorich, Douglas E. Swanson, Jr. and Mark E. Burroughs) appointed by the EnCap Funds and three members (currently Benjamin W. Hulburt, Christopher K. Hulburt and Thomas S. Liberatore) appointed by the Management Funds. The board of managers has authority to vote or dispose of the common stock held by Eclipse Holdings. Eclipse Holdings’ business address is 2121 Old Gatesburg Road, Suite 110, State College, Pennsylvania 16803.

 

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

 

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The Hulburt Family II Limited Partnership, controlled by Benjamin W. Hulburt, owns approximately 66% of the Class B limited partner interests in Eclipse Holdings, CKH Partners II, L.P., controlled by Christopher K. Hulburt, owns approximately 17% of the Class B limited partner interests in Eclipse Holdings, and Kirkwood Capital, L.P., controlled by Thomas S. Liberatore, owns approximately 17% of the Class B limited partner interests in Eclipse Holdings.

 

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

 

(2)

Represents 7,260,330 shares of our common stock (which represents approximately 3.3% of the outstanding shares of our common stock ) purchased in the private placement by EnCap Energy Capital Fund VIII Co-Investors, L.P., and 26,831,263 shares of our common stock (which represents approximately 12.1% of the outstanding shares of our common stock) purchased in the private placement by EnCap Energy Capital Fund IX, L.P. See footnote 1 regarding the control of the EnCap Funds and their ownership interests in Eclipse Holdings.

 

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Private Placement

On December 27, 2014, we entered into a Securities Purchase Agreement with the EnCap Funds, the Management Funds and the other selling stockholders pursuant to which we agreed to issue and sell to such purchasers an aggregate of 62,500,000 shares of common stock at a price of $7.04 per share. Members of our board of directors and the board of managers of Eclipse Holdings are affiliated with the EnCap Funds and the Management Funds. In the Private Placement, the EnCap Funds purchased 44,662,273 shares of our common stock, The Hulburt Family II Limited Partnership, which is controlled by Benjamin W. Hulburt, our Chairman, President and Chief Executive Officer, purchased 55,151 shares of our common stock, CKH Partners II, L.P., an entity controlled by Christopher K. Hulburt, our Executive Vice President, Secretary and General Counsel, purchased 13,788 shares of our common stock and Kirkwood Capital, L.P., an entity controlled by Thomas S. Liberatore, our Executive Vice President and Chief Operating Officer, purchased 13,788 shares of our common stock.

On January 28, 2015, we closed the Private Placement and received net proceeds from the issuance of the shares to the purchasers of approximately $434 million (after deducting placement agent commissions and our estimated expenses). See “Summary—Recent Developments—Private Placement of Common Stock” and “Selling Stockholders” for more information.

Amended and Restated Registration Rights Agreement

Upon the closing of the private placement, we amended and restated the existing registration rights agreement that we entered into upon the closing of our IPO. Pursuant to the Amended and Restated Registration Rights Agreement, (i) we agreed to prepare and file the registration statement of which this prospectus constitutes a part with the SEC no later than February 11, 2015 in order to register the offer and resale, on a continuous or delayed basis pursuant to Rule 415 under the Securities Act, of the 62,500,000 shares of common stock sold in the private placement to the selling stockholders, (ii) at any time, Eclipse Holdings and affiliates of EnCap, including the EnCap Funds and the general and limited partners of Eclipse Holdings, including the Management Funds (collectively, the “Affiliated Holders”) have the right, to the extent they hold registrable securities with a market value of at least $25 million, to require us to prepare and file a registration statement registering the offer and resale of their shares of common stock, (iii) at any time we are eligible to conduct a registered offering and sale on Form S-3, selling stockholders (other than the Affiliated Holders), have the right, to the extent they hold registrable securities with a market value of at least $25 million, to require us to prepare and file a registration statement on Form S-3 registering the offer and resale of their shares of common stock, and (iv) at any time we propose to register an offering of common stock (subject to certain exceptions, including offerings pursuant to this registration statement), we will be required to provide notice to all holders of registrable securities to allow them to include a specified number of their shares of common stock in that offering.

Stockholders Agreement

In connection with the closing of our IPO, we entered into the Stockholders Agreement with Eclipse Holdings and its limited partners, including the EnCap Funds, the Management Funds and Eclipse Management. The Stockholders Agreement provides that we, Eclipse Holdings and its limited partners will take certain actions, such as soliciting proxies or voting shares of our common stock, to cause our board of directors to consist of the following members: (i) Benjamin W. Hulburt, for so long as he remains our President and Chief Executive Officer; (ii) Christopher K. Hulburt, for so long as he remains our Executive Vice President, Secretary and General Counsel; and (iii) a number of members designated by the EnCap Funds, currently up to five, which number will be adjusted in the future based on the level of beneficial ownership of our shares of common stock by the EnCap Funds and their affiliates. For so long as the EnCap Funds and its affiliates beneficially own at least 50% of our outstanding common stock, we, Eclipse Holdings and its limited partners have agreed take

 

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certain actions to cause at least one of the directors designated by the EnCap Funds to be a member of each committee of our board of directors (subject to applicable legal requirements and stock exchange rules). In addition, we, Eclipse Holdings and its limited partners have agreed to take certain actions to cause Benjamin W. Hulburt to be elected as Chairman of our board of directors.

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

Corporate Reorganization

In connection with our Corporate Reorganization, we engaged in transactions with certain affiliates and our existing equity holders. See “Business—Corporate Reorganization” for a description of these transactions.

Historical Transactions with Affiliates

Since its inception in January 2011 until the completion of our Corporation Reorganization, Eclipse I, our subsidiary, issued additional limited partnership interests as consideration for capital contributions received from its limited partners, including the EnCap Funds. Capital contributions made by the EnCap Funds for the years ended December 31, 2014, 2013 and 2012 were approximately $124.1 million, $580.7 million and $67.7 million, respectively. In addition, Eclipse I paid the legal fees of EnCap in connection with these transactions.

Eclipse I previously issued profits interests in Eclipse I to certain officers and employees of Eclipse Operating. In connection with our Corporate Reorganization, all of such profits interests were exchanged for similar profits interests in Eclipse Management, which became a limited partner of Eclipse Holdings.

In December 2010, members of our management team formed Eclipse Operating for purposes of operating Eclipse I. Our Chairman, President and Chief Executive Officer, Executive Vice President, Secretary and General Counsel and Executive Vice President and Chief Operating Officer each owned 33% of the membership units of Eclipse Operating. Eclipse Operating provided administrative and management services to Eclipse I under the terms of an Administrative Services Agreement. In connection with our Corporate Reorganization, Eclipse I acquired all the outstanding equity interests of Eclipse Operating for $127,500, which was the amount of the aggregate capital contributions made to Eclipse Operating by its members. As a result, Eclipse Operating became a wholly owned subsidiary of Eclipse I. As of December 31, 2014, we have recorded an accrued liability of $972,000 related to a final distribution of the assets of Eclipse Operating. This amount will be distributed equally among the three former shareholders during 2015 and relates to the final income tax obligations of these former shareholders arising from the operations of Eclipse Operating prior to the acquisition by Eclipse I.

Under the terms of the Administrative Services Agreement, Eclipse I paid Eclipse Operating a monthly management fee equal to the sum of all general and administrative expenditures incurred by Eclipse Operating in the management and administration of Eclipse I’s operations. These costs included salaries, wages and benefits, rent, insurance, and other expenses and costs required to operate Eclipse I. These expenses were billed to Eclipse I in arrears at the actual cost to Eclipse Operating. During the years ended December 31, 2014, 2013 and 2012, management fee expense totaled approximately $15.2 million, $14.7 million and $4.2 million, respectively.

During the year ended December 31, 2014, we incurred approximately $0.2 million related to flight charter services provided by BWH Air, LLC and BWH Air II, LLC, which are owned by our Chairman, President and Chief Executive Officer. The fees are paid in accordance with a standard service contract that does not obligate us to any minimum terms.

 

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On December 16, 2013, we entered into a Gas Gathering, Processing and Fractionation Agreement with Blue Racer and its subsidiary, Blue Racer Natrium, LLC, under which we have obtained firm gathering, processing and fractionation capacity for a significant portion of our operated acreage in the Rich Gas, Condensate and Rich Condensate Windows of the Utica Core Area. In addition, in December, 2014, we entered into a 10-year firm transportation and marketing agreement with Blue Racer to market a substantial portion of our operated production of propane and butane through Blue Racer’s firm capacity on Sunoco’s Mariner East II Project. Blue Racer is a joint venture between Dominion Resources, Inc. and Caiman Energy II, LLC. Affiliates of EnCap owned, directly or indirectly, approximately 26% of Caiman Energy II, LLC as of December 31, 2014.

Procedures for Approval of Related Party Transactions

Our board of directors has determined that our audit committee is best suited to review and approve or ratify transactions with related persons, in accordance with our written policy governing related party transactions. A “related party transaction” is a transaction, arrangement or relationship in which we or any of our subsidiaries, on the one hand, and either (i) a related person, (ii) a person that was a related person less than 12 months prior to the transaction, arrangement or relationship, or (iii) an entity in which a related person has a direct or indirect material interest, on the other hand, are participants, and in which the amount involved exceeds $120,000. A “related person” means any of our directors or executive officers, any nominee to our board of directors, any beneficial owner of more than five percent of our common stock, any of the foregoing person’s immediate family members, and any firm, corporation or other entity in which any of the foregoing persons is employed or is a partner or principal or in a similar position or in which such person has a five percent or greater beneficial ownership. Pursuant to this policy, our audit committee reviews all material facts of all related party transactions, including the terms of the transaction and the nature of the related person’s interest in the transaction.

 

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DESCRIPTION OF CAPITAL STOCK

The authorized capital stock of Eclipse Resources Corporation consists of 1,000,000,000 shares of common stock, $0.01 par value per share, of which 222,531,115 shares are issued and outstanding, and 50,000,000 shares of preferred stock, $0.01 par value per share, of which no shares are issued and outstanding.

The following summary of the capital stock and amended and restated certificate of incorporation and amended and restated bylaws of Eclipse Resources Corporation does not purport to be complete and is qualified in its entirety by reference to the provisions of applicable law and to our amended and restated certificate of incorporation and amended and restated bylaws, copies of which are included as exhibits to the registration statement of which this prospectus forms a part. You should also be aware that the summary below does not give full effect to the provisions of statutory or common law that may affect your rights as a stockholder.

Common Stock

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

Preferred Stock

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

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

Some provisions of Delaware law, our amended and restated certificate of incorporation and our amended and restated bylaws contain provisions that could make the following transactions more difficult: acquisitions of us by means of a tender offer, a proxy contest or otherwise, or the removal of our incumbent officers and

 

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directors. These provisions may also have the effect of preventing changes in our management. It is possible that these provisions could make it more difficult to accomplish or could deter transactions that stockholders may otherwise consider to be in their best interest or in our best interests, including transactions that might result in a premium over the market price for our shares.

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

Delaware Law

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

 

•

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

 

•

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

 

•

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

We have elected not to be subject to the provisions of Section 203 of the DGCL.

Amended and Restated Certificate of Incorporation and Amended and Restated Bylaws

Provisions of our amended and restated certificate of incorporation and amended and restated bylaws may delay or discourage transactions involving an actual or potential change in control or change in our management, including transactions in which stockholders might otherwise receive a premium for their shares, or transactions that our stockholders might otherwise deem to be in their best interests.

Among other things, our amended and restated certificate of incorporation and amended and restated bylaws:

 

•

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

 

•

provide our board of directors the ability to authorize undesignated preferred stock. This ability makes it possible for our board of directors to issue, without stockholder approval, preferred stock with voting or other rights or preferences that could impede the success of any attempt to change control of us. These and other provisions may have the effect of deferring hostile takeovers or delaying changes in control or management of our company;

 

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•

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

 

•

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

 

•

at any time after Eclipse Holdings and EnCap and their respective affiliates no longer collectively beneficially own more than 50% of the outstanding shares of our common stock,

 

•

provide that any action required or permitted to be taken by the stockholders must be effected at a duly called annual or special meeting of stockholders and may not be effected by any consent in writing in lieu of a meeting of such stockholders, subject to the rights of the holders of any series of preferred stock with respect to such series (prior to such time, such actions may be taken without a meeting by written consent of holders of common stock having not less than the minimum number of votes that would be necessary to authorize such action at a meeting);

 

•

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

 

•

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

 

•

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

 

•

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

 

•

provide that our amended and restated bylaws can be amended or repealed at any regular or special meeting of stockholders or by the board of directors, including the requirement that any amendment by the stockholders at a meeting, at any time after Eclipse Holdings and EnCap and their respective affiliates no longer collectively own more than 50% of the outstanding shares of our common stock, be upon the affirmative vote of at least two-thirds (66 2/3%) of the shares of common stock generally entitled to vote in the election of directors.

Forum Selection

Our amended and restated certificate of incorporation provides that unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, is the sole and exclusive forum for:

 

•

any derivative action or proceeding brought on our behalf;

 

•

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

 

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•

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

 

•

any action asserting a claim against us that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery of the State of Delaware having personal jurisdiction over the indispensable parties named as defendants therein.

Our amended and restated certificate of incorporation also provides that any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock will be deemed to have notice of and to have consented to this forum selection provision. However, it is possible that a court could find our forum selection provision to be inapplicable or unenforceable.

Limitation of Liability and Indemnification Matters

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

 

•

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

 

•

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

 

•

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

 

•

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

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

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

Transfer Agent and Registrar

The transfer agent and registrar for our common stock is Computershare Trust Company, N.A.

Listing

Our common stock is listed on the NYSE under the symbol “ECR.”

 

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SELLING STOCKHOLDERS

This prospectus covers the public resale of the shares of common stock purchased in the private placement by the selling stockholders named below, which we refer to collectively herein as the Shares. The selling stockholders may from time to time offer and sell pursuant to this prospectus any or all of the Shares owned by them, but make no representation that any of the Shares will be offered for sale. The table below presents information regarding the selling stockholders and the Shares that each selling stockholder may offer and sell from time to time under this prospectus.

The following table sets forth:

 

•

the name of each selling stockholder;

 

•

the number of Shares beneficially owned by each selling stockholder prior to the sale of the Shares covered by this prospectus;

 

•

the number of Shares that may be offered by each selling stockholder pursuant to this prospectus;

 

•

the number of Shares to be beneficially owned by each selling stockholder following the sale of any Shares covered by this prospectus; and

 

•

the percentage of our issued and outstanding common stock to be owned by each selling stockholder following the sale of any Shares covered by this prospectus (based on 222,531,115 shares of our common stock issued and outstanding as of April 1, 2015).

All information with respect to common stock ownership of the selling stockholders has been furnished by or on behalf of the selling stockholders and is as of April 1, 2015. We believe, based on information supplied by the selling stockholders, that except as may otherwise be indicated in the footnotes to the table below, the selling stockholders have sole voting and dispositive power with respect to the common stock reported as beneficially owned by them. Because the selling stockholders identified in the table may sell some or all of the Shares owned by them which are included in this prospectus, and because there are currently no agreements, arrangements or understandings with respect to the sale of any of the Shares, no estimate can be given as to the number of Shares available for resale hereby that will be held by the selling stockholders upon termination of this offering. In addition, the selling stockholders may have sold, transferred or otherwise disposed of, or may sell, transfer or otherwise dispose of, at any time and from time to time, the common stock they hold in transactions exempt from the registration requirements of the Securities Act after the date on which they provided the information set forth on the table below. We have, therefore, assumed for the purposes of the following table, that the selling stockholders will sell all of the Shares beneficially owned by them that are covered by this prospectus, but will not sell any other shares of our common stock that they may presently own.

 

Name of Selling Stockholder		Number of Shares Beneficially Owned Prior to this Offering				Number of Shares Available for Sale Pursuant to this Prospectus				Number of Shares Beneficially Owned After Sale of Shares				Percent of Outstanding Common Stock Beneficially Owned After Sale of Shares
EnCap Energy Capital Fund IX, L.P.(1)			26,831,263				26,831,263				—				—
EnCap Energy Capital Fund VIII Co-Investors, L.P.(1)			7,260,330				7,260,330				—				—
EnCap Energy Capital Fund VIII, L.P.(1)			—				—				—				—
Buckeye Investors L.P.(2)			10,650,000				10,650,000				—				—
GSO Capital Opportunities Fund II (Luxembourg) S.à.r.l.(3)			3,410,000				3,410,000				—				—
Fir Tree Value Master Fund, L.P.(4)			10,203,800				2,275,000				7,928,800				3.6	%
Luxor Capital Partners Offshore Master Fund, LP(5)			738,400				738,400				—				—
Luxor Capital Partners, LP(5)			681,600				681,600				—				—
The Hulburt Family II Limited Partnership(6)			—				—				—				—
CKH Partners II, L.P.(7)			—				—				—				—
Kirkwood Capital, L.P.(8)			—				—				—				—

 

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(1)

EnCap Energy Capital Fund VIII, L.P., EnCap Energy Capital Fund VIII Co-Investors, L.P. and EnCap Energy Capital Fund IX, L.P. (together, the “EnCap Funds”) collectively own 100% of the Class A limited partner interests in Eclipse Holdings, our majority stockholder. The EnCap Funds are controlled indirectly by David B. Miller, D. Martin Phillips, Gary R. Petersen, and Robert L. Zorich, who are the controlling members of RNBD GP LLC. Messrs. Phillips and Zorich are directors of the Company. RNBD GP LLC is the sole member of EnCap Investments GP, L.L.C., which is the general partner of EnCap, which is the general partner of (i) EnCap Equity Fund VIII GP, L.P., which is the general partner of EnCap Energy Capital Fund VIII, L.P. and EnCap Energy Capital Fund VIII Co-Investors, L.P., and (ii) EnCap Equity Fund IX GP, L.P, which is the general partner of EnCap Energy Capital Fund IX, L.P. As a result, the foregoing persons and entities may be deemed to beneficially own the shares of our common stock held by the EnCap Funds. See “Principal Stockholders” for information about the shares of our common stock held by Eclipse Holdings.

(2)	The general partner of Buckeye LP is Buckeye Investors GP LLC (“Buckeye GP”). The membership interests of Buckeye GP are held by KKR North America Fund XI L.P.

 

Each of KKR North America Fund XI L.P., KKR North America Fund XI ESC L.P., KKR North America Fund XI SBS L.P. and KKR Partners III, L.P. (collectively, the “KKR Funds”) directly owns limited partnership interests in Buckeye LP with the majority of such interests held by KKR North America Fund XI L.P. The sole general partner of KKR North America Fund XI L.P. is KKR Associates North America XI L.P., and the sole general partner of KKR Associates North America XI L.P. is KKR North America XI Limited. The sole general partner of KKR North America Fund XI ESC L.P. is KKR North America XI Limited. The sole general partner of KKR North America Fund XI SBS L.P. also is KKR North America XI Limited. The sole shareholder of KKR North America XI Limited is KKR Fund Holdings L.P. KKR III GP LLC is the sole general partner of KKR Partners III, L.P. The managers of KKR III GP LLC are Messrs. Henry Kravis and George Roberts. The general partners of KKR Fund Holdings L.P. are KKR Fund Holdings GP Limited and KKR Group Holdings L.P. The sole shareholder of KKR Fund Holdings GP Limited is KKR Group Holdings L.P. The sole general partner of KKR Group Holdings L.P. is KKR Group Limited. The sole shareholder of KKR Group Limited is KKR & Co. L.P. The sole general partner of KKR & Co. L.P. is KKR Management LLC. The designated members of KKR Management LLC are Messrs. Kravis and Roberts.

 

Each of KKR North America Fund XI L.P., KKR Associates North America XI L.P., KKR North America XI Limited, KKR Fund Holdings L.P., KKR Fund Holdings GP Limited, KKR Group Holdings L.P., KKR Group Limited, KKR & Co. L.P., KKR Management LLC and Messrs. Kravis and Roberts may be deemed to share voting and investment power with respect to the shares beneficially owned by Buckeye LP but each has disclaimed beneficial ownership of such shares. The address for all entities noted above and for Mr. Kravis is c/o Kohlberg Kravis Roberts & Co. L.P., 9 West 57th Street, Suite 4200, New York, NY 10019. The address for Mr. Roberts is c/o Kohlberg Kravis Roberts & Co. L.P., 2800 Sand Hill Road, Suite 200, Menlo Park, CA 94025.

 

(3)

GSO Capital Partners LP is the investment advisor for GSO Capital Opportunities Fund II (Luxembourg) S.’a.r.l. (the “GSO Fund”). GSO Advisor Holdings L.L.C. is the general partner of GSO Capital Partners LP. Blackstone Holdings I L.P. is the sole member of GSO Advisor Holdings L.L.C. Blackstone Holdings I/II GP Inc. is the general partner of Blackstone Holdings I L.P. The Blackstone Group L.P. is the controlling shareholder of Blackstone Holdings I/II GP Inc. Blackstone Group Management L.L.C. is the general partner of The Blackstone Group L.P. Blackstone Group Management L.L.C. is wholly-owned by Blackstone’s senior managing directors and controlled by its founder, Stephen A. Schwarzman. In addition, each of Bennett J. Goodman, J. Albert Smith III and Douglas I. Ostrover is an executive of GSO Capital Partners LP and may be deemed to have shared voting power and/or investment power with respect to the securities held by the GSO Fund. Each of the foregoing entities and individuals disclaims beneficial ownership of the shares held directly by the GSO Fund (other than the GSO Fund to the extent of its direct holdings). The address for the GSO Fund is 16, Avenue Pasteur, L-2310 Luxembourg, Luxembourg.

 

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(4)

Fir Tree Inc., as the investment manager for Fir Tree Value Master Fund, L.P. (“Fir Tree Value”), has the shared power to vote or direct the voting, and to dispose or direct the disposition of, the shares of our common stock beneficially owned by Fir Tree Value and may be deemed to beneficially own the shares of our common stock held by Fir Tree Value. Fir Tree, L.L.C., as general partner of Fir Tree Value, may be deemed to beneficially own the shares of our common stock beneficially owned by Fir Tree Value. Jeffrey Tannenbaum is the controlling person of Fir Tree, L.L.C. The address for Fir Tree Value is c/o Fir Tree Inc., 505 Fifth Avenue, 23rd Floor, New York, NY 10017.

(5)

Luxor Capital Group, LP (“Luxor Capital Group”), as the investment manager for Luxor Capital Partners, LP and Luxor Capital Partners Offshore Master Fund, LP, may be deemed to beneficially own the shares of our common stock held by Luxor Capital Partners, LP and Luxor Capital Partners Offshore Master Fund, LP. Luxor Management, LLC (“Luxor Management”), as general partner of Luxor Capital Group, may be deemed to beneficially own the shares of our common stock beneficially owned by Luxor Capital Group. Christian Leone, as the managing member of Luxor Management, may also be deemed to beneficially own the shares of our common stock beneficially owned by Luxor Management.

(6)

The Hulburt Family II Limited Partnership is controlled by Benjamin W. Hulburt, the Chairman of our Board of Directors and our President and Chief Executive Officer, and as result, Benjamin W. Hulburt beneficially owns the shares of our common stock held by The Hulburt Family II Limited Partnership. The Hulburt Family II Limited Partnership also owns approximately 66% of the Class B limited partner interests in Eclipse Holdings, our majority stockholder. See “Principal Stockholders” for information about the shares of our common stock held by Eclipse Holdings.

(7)

CKH Partners II, L.P. is controlled by Christopher K. Hulburt, our Executive Vice President, Secretary and General Counsel and a director of the Company, and as a result, Christopher K. Hulburt beneficially owns the shares of our common stock held by CKH Partners II, L.P. CKH Partners II, L.P. also owns approximately 17% of the Class B limited partner interests in Eclipse Holdings, our majority stockholder. See “Principal Stockholders” for information about the shares of our common stock held by Eclipse Holdings.

(8)

Kirkwood Capital, L.P. is controlled by Thomas S. Liberatore, our Executive Vice President and Chief Operating Officer, and as a result, Thomas S. Liberatore beneficially owns the shares of our common stock held by Kirkwood Capital, L.P. Kirkwood Capital, L.P. also owns approximately 17% of the Class B limited partner interests in Eclipse Holdings, our majority stockholder. See “Principal Stockholders” for information about the shares of our common stock held by Eclipse Holdings.

Except as described in the table and related footnotes above, none of the selling stockholders has had any position, office or other material relationship with us in the past three years.

The selling stockholders and intermediaries through whom such securities are sold may be deemed “underwriters” within the meaning of the Securities Act with respect to the Shares offered by this prospectus, and any profits realized or commissions received may be deemed underwriting compensation.

Additional selling stockholders not named in this prospectus will not be able to use this prospectus for resales until they are named in the table above by prospectus supplement or post-effective amendment. Transferees, successors and donees of identified selling stockholders will not be able to use this prospectus for resales until they are named in the table above by prospectus supplement or post-effective amendment. If required, we will add transferees, successors and donees by prospectus supplement in instances where the transferee, successor or donee has acquired its shares from holders named in this prospectus after the effective date of this prospectus.

 

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PLAN OF DISTRIBUTION

We are registering 62,500,000 shares of our common stock for possible sale by the selling stockholders. Unless the context otherwise requires, as used in this prospectus, “selling stockholders” includes the selling stockholders named in this prospectus and donees, pledgees, transferees or other successors-in-interest selling shares received from the selling stockholders as a gift, pledge, partnership distribution or other transfer after the date of this prospectus.

The selling stockholders may offer and sell all or a portion of the shares covered by this prospectus from time to time, in one or more of the following transactions:

 

•

on the NYSE, in the over-the-counter market or on any other national securities exchange on which our shares are listed or traded;

 

•

in exchange distributions in accordance with the applicable exchange rules;

 

•

in privately negotiated transactions;

 

•

in underwritten transactions;

 

•

in block trades in which a broker-dealer will attempt to sell the offered shares as agent but may position and resell a portion of the block as principal to facilitate the transaction;

 

•

through purchases by a broker-dealer as principal and resale by the broker-dealer for its account pursuant to this prospectus;

 

•

in ordinary brokerage transactions and transactions in which the broker solicits purchasers;

 

•

through the writing of options (including put or call options), whether the options are listed on an options exchange or otherwise;

 

•

through loans or pledges of the securities to a broker-dealer or an affiliate thereof;

 

•

by entering into transactions with third parties who may (or may cause others to) issue securities convertible or exchangeable into, or the return of which is derived in whole or in part from the value of, our common stock; and

 

•

any combination of any such methods of sale.

The selling stockholders may sell the shares at fixed prices, at prices then prevailing or related to the then current market price or at negotiated prices. The offering price of the shares from time to time will be determined by the selling stockholders and, at the time of the determination, may be higher or lower than the market price of our common stock on the NYSE or any other exchange or market.

The shares may be sold directly or through broker-dealers acting as principal or agent, or pursuant to a distribution by one or more underwriters on a firm commitment or best-efforts basis. The selling stockholders may also enter into hedging transactions with broker-dealers. In connection with such transactions, broker-dealers of other financial institutions may engage in short sales of our common stock in the course of hedging the positions they assume with the selling stockholders. The selling stockholders may also enter into options or other transactions with broker-dealers or other financial institutions which require the delivery to such broker-dealer or other financial institution of shares offered by this prospectus, which shares such broker-dealer or other financial institution may resell pursuant to this prospectus (as supplemented or amended to reflect such transaction). In connection with an underwritten offering, underwriters or agents may receive compensation in the form of discounts, concessions or commissions from the selling stockholders or from purchasers of the offered shares for whom they may act as agents. In addition, underwriters may sell the shares to or through dealers, and those dealers may receive compensation in the form of discounts, concessions or commissions from the underwriters and/or commissions from the purchasers for whom they may act as agents. The selling stockholders and any underwriters, dealers or agents participating in a distribution of the shares may be deemed to be underwriters

 

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within the meaning of the Securities Act, and any profit on the sale of the shares by the selling stockholders and any commissions received by broker-dealers may be deemed to be underwriting commissions under the Securities Act.

The selling stockholders may agree to indemnify an underwriter, broker-dealer or agent against certain liabilities related to the selling of their shares, including liabilities arising under the Securities Act. Under the registration rights agreement, we have agreed to indemnify the selling stockholders against certain liabilities related to the sale of the common stock, including certain liabilities arising under the Securities Act. Under the registration rights agreement, we have also agreed to pay the costs, expenses and fees of registering the shares of common stock; however, the selling stockholders will pay any underwriting discounts or commissions relating to the sale of the shares of common stock in any underwritten offering.

The selling stockholders have advised us that they have not entered into any agreements, understandings or arrangements with any underwriters or broker-dealers regarding the sale of their shares. Upon our notification by the selling stockholders that any material arrangement has been entered into with an underwriter or broker-dealer for the sale of shares through a block trade, special offering, exchange distribution, secondary distribution or a purchase by an underwriter or broker-dealer, we will file a supplement to this prospectus, if required, pursuant to Rule 424(b) under the Securities Act, disclosing certain material information, including:

 

•

the name of the selling stockholders;

 

•

the number of shares being offered;

 

•

the terms of the offering;

 

•

the names of the participating underwriters, broker-dealers or agents;

 

•

any discounts, commissions or other compensation paid to underwriters or broker-dealers and any discounts, commissions or concessions allowed or re-allowed or paid by any underwriters to dealers;

 

•

the public offering price; and

 

•

other material terms of the offering.

The selling stockholders are subject to the applicable provisions of the Exchange Act, and the rules and regulations under the Exchange Act, including Regulation M. This regulation may limit the timing of purchases and sales of any of the shares of common stock offered in this prospectus by the selling stockholders. The anti-manipulation rules under the Exchange Act may apply to sales of shares in the market and to the activities of the selling stockholders and its affiliates. Furthermore, Regulation M may restrict the ability of any person engaged in the distribution of the shares to engage in market-making activities for the particular securities being distributed for a period of up to five business days before the distribution. The restrictions may affect the marketability of the shares and the ability of any person or entity to engage in market-making activities for the shares.

To the extent required, this prospectus may be amended and/or supplemented from time to time to describe a specific plan of distribution. Instead of selling the shares of common stock under this prospectus, the selling stockholders may sell the shares of common stock in compliance with the provisions of Rule 144 under the Securities Act, if available, or pursuant to other available exemptions from the registration requirements of the Securities Act.

Under the securities laws of some states, if applicable, the securities registered hereby may be sold in those states only through registered or licensed brokers or dealers. In addition, in some states such securities may not be sold unless they have been registered or qualified for sale or an exemption from registration or qualification requirements is available and is complied with.

We cannot assure you that the selling stockholders will sell all or any portion of our common stock offered hereby.

 

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Under the registration rights agreement, we agreed to use our reasonable efforts to keep the registration statement of which this prospectus constitutes a part continuously effective under the Securities Act until the earlier of (i) date on which all of the shares of common stock covered by this prospectus have been sold, (ii) the date on which the non-affiliated holders own, in the aggregate, a number of shares of common stock which represents less than 1% of the total number of shares of common stock issued and outstanding at such time, and (iii) the date on which all of the shares of common stock covered by this prospectus cease to be “registrable securities” under the registration rights agreement.

 

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MARKET FOR OUR COMMON STOCK

Our common stock is listed on the NYSE under the symbol “ECR” and has been trading since June 20, 2014. Prior to that, there was no public market for our common stock. The table below sets forth, for the periods indicated, the high and low sales prices per share of our common stock.

 

		Sales Prices
		High				Low
2015
First Quarter		$	8.10			$	5.07
2014
Fourth Quarter		$	16.80			$	5.18
Third Quarter		$	25.33			$	15.85
Second Quarter (beginning June 20, 2014)		$	27.18			$	24.27
First Quarter		$	N/A			$	N/A

The closing price of our common stock on the NYSE on April 14, 2015 was $6.12 per share.

As of April 1, 2015 we had approximately 10 holders of record of our common stock, based on information provided by our transfer agent.

 

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LEGAL MATTERS

The validity of our common stock offered by this prospectus will by passed upon for us by Norton Rose Fulbright US LLP, Dallas, Texas.

EXPERTS

The audited consolidated financial statements of Eclipse Resources Corporation as of December 31, 2014 and 2013, and for each of the years in the three-year period ended December 31, 2014, included in this prospectus and elsewhere in the registration statement have been so included in reliance upon the report of Grant Thornton LLP, independent registered public accountants, upon the authority of said firm as experts in accounting and auditing.

The audited financial statements of Eclipse Resources-Ohio, LLC as of June 25, 2013 and December 31, 2012, and for the year ended December 31, 2012 and the period January 1, 2013 through June 25, 2013, included in this prospectus and elsewhere in the registration statement have been so included in reliance upon the report of Grant Thornton LLP, independent certified public accountants, upon the authority of said firm as experts in accounting and auditing.

The audited financial statements of Eclipse Resources Operating, LLC as of December 31, 2013 and 2012, and for each of the years in the two-year period ended December 31, 2013, included in this prospectus and elsewhere in the registration statement have been so included in reliance upon the report of Grant Thornton LLP, independent registered public accountants, upon the authority of said firm as experts in accounting and auditing.

Estimates of our natural gas and oil reserves, related future net cash flows and the present values thereof related to our properties as of December 31, 2014, December 31, 2013 and December 31, 2012, included elsewhere in this prospectus were based in part upon reserve reports prepared by independent petroleum engineers, Netherland, Sewell & Associates, Inc. We have included these estimates in reliance on the authority of such firm as experts in such matters.

WHERE YOU CAN FIND ADDITIONAL INFORMATION

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

 

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We are required to file annual and quarterly reports and other information with the SEC. You may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Room 1580, Washington, D.C., 20549. Please call 1-800-SEC-0330 for further information on the operation of the Public Reference Room. Our filings will also be available to the public from commercial document retrieval services and at the web site maintained by the SEC at www.sec.gov. Our reports and other information that we have filed, or may in the future file, with the SEC are not incorporated by reference into and do not constitute part of this prospectus.

 

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INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

 

ECLIPSE RESOURCES CORPORATION
Unaudited Pro Forma Consolidated Financial Statements
Introduction			F-2
Statement of Operations for the Year Ended December 31, 2014			F-4
Notes to Unaudited Pro Forma Consolidated Financial Statements			F-5
Historical Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm			F-6
Balance Sheets as of December 31, 2014 and 2013			F-7
Statements of Operations for the Years Ended December 31, 2014, 2013 and 2012			F-8
Statements of Comprehensive Loss for the Years Ended December 31, 2014, 2013 and 2012			F-9
Statements of Stockholders’ Equity for the Years Ended December 31, 2014, 2013 and 2012			F-10
Statements of Cash Flows for the Years Ended December 31, 2014, 2013 and 2012			F-11
Notes to the Consolidated Financial Statements			F-12
ECLIPSE RESOURCES-OHIO, LLC
Historical Financial Statements
Report of Independent Certified Public Accountants			F-41
Balance Sheets as of June 25, 2013 and December 31, 2012			F-42
Statements of Operations for the Period Ended June 25, 2013 and the Year Ended December 31, 2012			F-43
Statements of Comprehensive Loss for the Period Ended June 25, 2013 and the Year Ended December  31, 2012			F-44
Statements of Member’s Equity for the Period Ended June 25, 2013 and the Year Ended December  31, 2012			F-45
Statements of Cash Flows for the Period Ended June 25, 2013 and the Year Ended December 31, 2012			F-46
Notes to the Financial Statements			F-47
ECLIPSE RESOURCES OPERATING, LLC
Unaudited Historical Consolidated Financial Statements
Balance Sheets as of March 31, 2014 and December 31, 2013			F-61
Statements of Operations for the Three Months Ended March 31, 2014 and 2013			F-62
Statement of Members’ Equity (Deficit) for the Three Months Ended March 31, 2014			F-63
Statements of Cash Flows for the Three Months Ended March 31, 2014 and 2013			F-64
Notes to the Financial Statements			F-65
Historical Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm			F-69
Balance Sheets as of December 31, 2013 and 2012			F-70
Statements of Operations for the Years Ended December 31, 2013 and 2012			F-71
Statements of Members’ Equity (Deficit) for the Years Ended December 31, 2013 and 2012			F-72
Statements of Cash Flows for the Years Ended December 31, 2013 and 2012			F-73
Notes to the Financial Statements			F-74

 

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ECLIPSE RESOURCES CORPORATION

PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Introduction

Eclipse Resources Corporation (the “Company”) is a Delaware corporation formed by Eclipse Resources I, LP (“Eclipse I”) to engage in the exploitation, development, exploration and acquisition of oil and natural gas properties in the Appalachian Basin. The following unaudited pro forma consolidated financial statements of the Company reflect the historical consolidated results of Eclipse Resources Corporation and Eclipse I, the Company’s accounting predecessor, on a pro forma basis to give effect to the following transactions, which are described in further detail below, as if they had occurred on January 1, 2014, for pro forma statements of operations purposes:

 

•

The Corporate Reorganization. On June 24, 2014 prior to the completion of the IPO (as defined below), a Corporate Reorganization was completed. As a part of this corporate reorganization the following transactions occurred (collectively, the “Corporate Reorganization”):

 

•

the acquisition by Eclipse I of all of the outstanding equity interests in Eclipse Resources Operating, LLC (“Eclipse Operating”);

 

•

the contribution of equity interests in Eclipse I to Eclipse Resources Holdings, L.P. (“Eclipse Holdings”) by its then limited partners in exchange for similar equity interests in Eclipse Holdings;

 

•

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

 

•

the contribution of equity interests in Eclipse I and the outstanding equity interests in Eclipse I GP, LLC, to the Company by Eclipse Holdings in exchange for 138,500,000 shares of common stock.

 

•

The Initial Public Offering. On June 25, 2014, the Company completed the initial public offering (the “IPO” or the “Initial Public Offering”) of 30,300,000 shares of $0.01 par value common stock, which included 21,500,000 shares sold by the Company and 8,800,000 shares sold by certain selling stockholders.

The unaudited pro forma consolidated statements of operations of the Company are based on (i) the audited historical consolidated statements of operations of Eclipse Resources Corporation for the year ended December 31, 2014, having given effect to the Corporate Reorganization and Initial Public Offering as if they had occurred on January 1, 2014, and (ii) the unaudited historical operations of Eclipse Operating for the period from January 1, 2014 through June 24, 2014.

The pro forma data presented reflects events directly attributable to the described transactions and certain assumptions the Company believes are reasonable. The pro forma data are not necessarily indicative of financial results that would have been attained had the described transactions occurred on the dates indicated below or which could be achieved in the future because they necessarily exclude various operating expenses, such as incremental general and administrative expenses associated with being a public company. The adjustments are based on currently available information and certain estimates and assumptions. Therefore, the actual adjustments may differ from the pro forma adjustments. However, management believes that the assumptions provide a reasonable basis for presenting the significant effects of the transactions as contemplated and that the pro forma adjustments give appropriate effect to those assumptions and are properly applied in the unaudited pro forma financial statements.

 

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The unaudited pro forma consolidated financial statements and related notes are presented for illustrative purposes only. If the Initial Public Offering and other transactions contemplated herein had occurred in the past, the Company’s operating results might have been materially different from those presented in the unaudited pro forma financial statements. The unaudited pro forma consolidated financial statements should not be relied upon as an indication of operating results that the Company would have achieved if the Initial Public Offering and other transactions contemplated herein had taken place on the specified date. In addition, future results may vary significantly from the results reflected in the unaudited pro forma consolidated statements of operations and should not be relied on as an indication of the future results the Company will have after the completion of the Initial Public Offering and the other transactions contemplated by these unaudited pro forma consolidated financial statements.

 

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ECLIPSE RESOURCES CORPORATION

PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS

FOR THE YEAR ENDED DECEMBER 31, 2014

(Unaudited)

 

		Eclipse Resources Corporation Historical				Eclipse Operating				Corporate Reorganization				Initial Public Offering				Pro Forma As Adjusted
						(a)
		(in thousands, except per share data)
REVENUES
Oil and natural gas sales		$	137,816			$	—			$	—			$	—			$	137,816
Other revenue			—				14,687				(14,687	)(b)			—				—
Total revenues			137,816				14,687				(14,687	)			—				137,816
OPERATING EXPENSES
Lease operating			8,518				—				—				—				8,518
Transportation and gathering			18,114				—				—				—				18,114
Production and ad valorem taxes			7,084				—				—				—				7,084
Depreciation, depletion and amortization			89,218				—				—				—				89,218
Exploration			21,186				—				—				—				21,186
General and administrative			45,392				14,687				(14,687	)(b)			—				45,392
Accretion expense			791				—				—				—				791
Impairment of oil and gas properties			34,855				—				—				—				34,855
Gain on sale of assets			(960	)			—				—				—				(960	)
Gain on reduction in pension liability			(2,208	)			—				—				—				(2,208	)
Total operating expenses			221,990				14,687				(14,687	)			—				221,990
OPERATING INCOME (LOSS)			(84,174	)			—				—				—				(84,174	)
OTHER INCOME (EXPENSE)
Gain on derivative instruments			20,791				—				—				—				20,791
Interest expense, net			(48,347	)			—				—				236	(c)			(48,111	)
Other income			353				—				(353	)(d)			—				—
Total other income (expense), net			(27,203	)			—				(353	)			236				(27,320	)
INCOME (LOSS) BEFORE INCOME TAXES			(111,377	)			—				(353	)			236				(111,494	)
INCOME TAX EXPENSE (BENEFIT)			71,799				—				(107,650	)(e)			83	(c)			(35,768	)
NET LOSS		$	(183,176	)		$	—			$	107,297			$	153			$	(75,726	)
NET LOSS PER COMMON SHARE (f)
Basic and diluted																		$	(0.49	)
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING (f)
Basic and diluted																			154,677

The accompanying notes are an integral part of these unaudited pro forma consolidated financial statements.

 

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ECLIPSE RESOURCES CORPORATION

NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. BASIS OF PRESENTATION, THE OFFERING AND OTHER TRANSACTIONS

The historical financial information is derived from the consolidated financial statements of Eclipse Resources Corporation, Eclipse Resources-Ohio, LLC and Eclipse Resources Operating, LLC included elsewhere in this prospectus. For purposes of the unaudited pro forma statements of operations, it is assumed that the Eclipse Operating Acquisition, the Corporate Reorganization and the Initial Public Offering described elsewhere in this prospectus all transactions had taken place on January 1, 2014.

NOTE 2. PRO FORMA ADJUSTMENTS AND ASSUMPTIONS

The Company made the following adjustments and assumptions in the preparation of the unaudited pro forma statement of operations as of December 31, 2014:

 

(a)

Reflects the historical results of operations of Eclipse Operating for the period from January 1, 2014 through June 24, 2014, derived from the historical unaudited financial statements of Eclipse Operating directly prior to the Corporate Reorganization.

 

(b)

Reflects the elimination of the intra-company revenue and expense between Eclipse Resources Corporation and Eclipse Operating.

 

(c)

Reflects the reduction in interest expense, and related tax impact, under the Company’s revolving credit agreement as of December 31, 2014. On a pro forma basis, the Company would not have had outstanding borrowings under the Company’s revolving credit facility.

 

(d)

Reflects the elimination of the bargain purchase gain on the acquisition of Eclipse Operating as part of the Corporate Reorganization.

 

(e)

Reflects the elimination of the change in tax status charge of approximately $97.6 million and the estimated income tax benefit associated with the Company’s historical results of operations assuming the Company’s earnings had been subject to federal income tax as a subchapter C corporation using an effective tax rate of approximately 35%. The rate is inclusive of federal and state income taxes.

 

(f)

Reflects basic and diluted loss per common share for the issuance of shares of common stock in the Corporate Reorganization and IPO.

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders

Eclipse Resources Corporation

We have audited the accompanying consolidated balance sheets of Eclipse Resources Corporation (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2014 and 2013, and the related consolidated statements of operations, comprehensive loss, changes in stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2014. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Eclipse Resources Corporation as of December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014 in conformity with accounting principles generally accepted in the United States of America.

 

/s/ GRANT THORNTON LLP

Cleveland, Ohio

March 6, 2015

 

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ECLIPSE RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS

(in thousands, except share and per share data)

 

		December 31,
		2014				2013
ASSETS
CURRENT ASSETS
Cash and cash equivalents		$	67,517			$	109,509
Accounts receivable			46,378				8,678
Assets held for sale			20,673				—
Other current assets			19,711				594
Total current assets			154,279				118,781
PROPERTY AND EQUIPMENT, AT COST
Oil and natural gas properties, successful efforts method
Unproved properties			1,044,469				926,812
Proved properties, net			670,255				88,932
Other property and equipment, net			8,103				2,340
Total property and equipment, net			1,722,827				1,018,084
OTHER NONCURRENT ASSETS
Debt issuance costs, net of $2.5 million and $0.8 million of amortization, respectively			6,058				6,570
Other assets			1,782				88
Total other noncurrent assets			7,840				6,658
TOTAL ASSETS		$	1,884,946			$	1,143,523
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable		$	137,415			$	29,368
Accrued capital expenditures			51,360				19,200
Accrued liabilities			13,576				4,940
Accrued interest payable			25,187				20,294
Deferred income taxes			5,246				—
Accrued liabilities—related party			—				1,951
Total current liabilities			232,784				75,753
NONCURRENT LIABILITIES
Debt, net of unamortized discount of $8.5 million and $10.8 million, respectively			414,016				389,247
Pension obligations			1,321				1,497
Asset retirement obligations			17,400				9,055
Deferred income taxes			66,714				—
Total noncurrent liabilities			499,451				399,799
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS’ EQUITY
Preferred stock, 50,000 shares authorized, no shares issued and outstanding			—				—
Common stock, $0.01 par value, 1,000,000,000 shares authorized, 160,031,115 and 121,533,408 shares issued and outstanding			1,600				1,215
Additional paid in capital			1,391,004				721,757
Accumulated deficit			(239,345	)			(56,169	)
Accumulated other comprehensive income (loss)			(548	)			1,168
Total stockholders’ equity			1,152,711				667,971
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY		$	1,884,946			$	1,143,523

The accompanying notes are an integral part of these consolidated financial statements.

 

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ECLIPSE RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands except per share data)

 

		For the year ended December 31,
		2014				2013				2012
REVENUES
Oil and natural gas sales		$	137,816			$	12,935			$	370
Total revenues			137,816				12,935				370
OPERATING EXPENSES
Lease operating			8,518				2,576				16
Transportation, gathering and compression			18,114				67				—
Production and ad valorem taxes			7,084				77				1
Depreciation, depletion and amortization			89,218				6,163				404
Exploration			21,186				3,022				4,692
General and administrative			45,392				21,276				4,425
Accretion of asset retirement obligations			791				364				—
Impairment of proved oil and gas properties			34,855				2,081				—
Gain on sale of assets			(960	)			—				(372	)
Gain on reduction of pension obligations			(2,208	)			—				—
Total operating expenses			221,990				35,626				9,166
OPERATING LOSS			(84,174	)			(22,691	)			(8,796	)
OTHER INCOME (EXPENSE)
Gain on derivative instruments			20,791				—				—
Interest income (expense), net			(48,347	)			(20,850	)			37
Other income			353				—				—
Total other income (expense), net			(27,203	)			(20,850	)			37
LOSS BEFORE INCOME TAXES			(111,377	)			(43,541	)			(8,759	)
INCOME TAX EXPENSE			71,799				—				—
NET LOSS		$	(183,176	)		$	(43,541	)		$	(8,759	)
NET LOSS PER COMMON SHARE
Basic and diluted		$	(1.27	)		$	(0.58	)		$	(0.63	)
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING
Basic and diluted			144,369				75,261				13,880

The accompanying notes are an integral part of these consolidated financial statements.

 

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ECLIPSE RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

(in thousands)

 

		For the Year Ended December 31,
		2014				2013				2012
NET LOSS		$	(183,176	)		$	(43,541	)		$	(8,759	)
Other comprehensive loss:
Pension obligation adjustment			(1,716	)			1,168				—
TOTAL COMPREHENSIVE LOSS		$	(184,892	)		$	(42,373	)		$	(8,759	)

The accompanying notes are an integral part of these consolidated financial statements.

 

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ECLIPSE RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDER’S EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2014, 2013, and 2012

(in thousands, except share and per share data)

 

		Number of Shares				Common Stock ($0.01 Par)				Additional Paid-in- Capital				Accumulated Deficit				Accumulated Other Comprehensive Income (Loss)				Total
Balances, December 31, 2011			9,583,090			$	95			$	70,318			$	(3,869	)		$	—			$	66,544
Capital contributions			9,466,359				95				69,459				—				—				69,554
Share-based compensation			—				—				3				—				—				3
Distributions			—				—				(638	)			—				—				(638	)
Net loss			—				—				—				(8,759	)			—				(8,759	)
Balances, December 31, 2012			19,049,449				190				139,142				(12,628	)			—				126,704
Capital contributions			102,483,959				1,025				582,572				—				—				583,597
Share-based compensation			—				—				43				—				—				43
Change in accumulated other comprehensive income			—				—				—				—				1,168				1,168
Net loss			—				—				—				(43,541	)			—				(43,541	)
Balances, December 31, 2013			121,533,408				1,215				721,757				(56,169	)			1,168				667,971
Capital contributions			16,966,592				170				124,497				—				—				124,667
Issuance of restricted stock			31,115				—				—				—				—				—
Share-based compensation			—				—				256				—				—				256
Pension obligation adjustment			—				—				—				—				(1,716	)			(1,716	)
Shares of common stock issued in initial public offering			21,500,000				215				549,810				—				—				550,025
Costs related to initial public offering			—				—				(5,316	)			—				—				(5,316	)
Net loss			—				—				—				(183,176	)			—				(183,176	)
Balances, December 31, 2014			160,031,115			$	1,600			$	1,391,004			$	(239,345	)		$	(548	)		$	1,152,711

The accompanying notes are an integral part of these consolidated financial statements.

 

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ECLIPSE RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

 

		For the Year Ended December 31,
		2014				2013				2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss		$	(183,176	)		$	(43,541	)		$	(8,759	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities
Depreciation, depletion and amortization			89,218				6,163				404
Exploration expense			21,186				3,022				4,692
Pension benefit costs			56				575				—
Incentive unit compensation			256				43				3
Impairment of proved oil and gas properties			34,855				2,081				—
Accretion of asset retirement obligations			791				364				—
Gain on reduction of pension liability			(2,208	)			—				—
Gain on derivative instruments			(20,791	)			—				—
Net cash receipts on settled derivatives			564				—				—
Net cash payments on option premiums			(385	)			—				—
Gain on sale of assets			(960	)			—				(372	)
Gain on business acquisition			(353	)			—				—
Deferred income taxes			71,667				—				—
Interest not paid in cash			15,721				20,294				—
Amortization of deferred financing costs			1,744				739				—
Amortization of debt discount			2,308				1,247				—
Changes in operating assets and liabilities, net of acquisitions:
Accounts receivable			(33,605	)			(5,971	)			(172	)
Other assets			(1,188	)			1,389				50
Accounts payable and accrued liabilities			29,517				27,276				747
Accrued liabilities—affiliate			(1,951	)			1,569				26
Net cash provided by (used in) operating activities			23,266				15,250				(3,381	)
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures for oil and natural gas properties			(745,766	)			(252,844	)			(179,209	)
Additions to other property and equipment			(3,637	)			(892	)			—
Proceeds from the sale of oil and gas properties			15,460				8,497				131,674
Acquisition of business, net of cash acquired			754				(651,847	)			—
Net cash used in investing activities			(733,189	)			(897,086	)			(47,535	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from issuance of long-term debt			—				388,000				—
Debt issuance costs			(1,232	)			(7,309	)			—
Repayments of long-term debt			(213	)			—				—
Repayments (borrowings) under revolving credit facility			—				—				—
Capital contributions			124,667				583,597				69,554
Distributions			—				—				(638	)
Proceeds from issuance of common stock, net of underwriting fees			550,025				—				—
Initial public offering costs			(5,316	)			—				—
Net cash provided by financing activities			667,931				964,288				68,916
Net increase (decrease) in cash and cash equivalents			(41,992	)			82,452				18,000
Cash and cash equivalents at beginning of period			109,509				27,057				9,057
Cash and cash equivalents at end of period		$	67,517			$	109,509			$	27,057
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid for interest		$	26,020			$	—			$	—
Cash paid for income taxes		$	—			$	—			$	—
SUPPLEMENTAL DISCLOSURE OF NON-CASH INVESTING AND FINANCING ACTIVITIES:
Asset retirement obligations incurred, including changes in estimate		$	7,554			$	300			$	—
Additions of other property through debt financing		$	945			$	—			$	—
Additions to oil and natural gas properties—changes in accounts payable, accrued liabilities, and accrued capital expenditures		$	126,656			$	17,537			$	1,663
Assets and liabilities assumed in acquisition of Eclipse Resources-Ohio, LLC		$	—			$	5,102			$	—
Assets held for sale associated with central gathering facility		$	20,673			$	—			$	—
Interest paid-in-kind		$	22,461			$	—			$	—

The accompanying notes are an integral part of these consolidated financial statements.

 

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ECLIPSE RESOURCES CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2014, 2013 and 2012

Note 1—Organization and Nature of Operations

Eclipse Resources Corporation (the “Company”) was formed on February 13, 2014, pursuant to the laws of the State of Delaware to become a holding company for Eclipse Resources I, LP (“Eclipse I”). Eclipse I is engaged in the acquisition and development of oil and natural gas properties in the Appalachian Basin of the United States, which encompasses the Utica Shale and Marcellus Shale prospective areas.

On June 24, 2014 prior to the completion of the IPO, a Corporate Reorganization was completed. As a part of this corporate reorganization the following transactions occurred (collectively, the “Corporate Reorganization”):

 

•

the acquisition by Eclipse I of all of the outstanding equity interests in Eclipse Resources Operating, LLC (“Eclipse Operating”);

 

•

the contribution of equity interests in Eclipse I to Eclipse Resources Holdings, L.P. (“Eclipse Holdings”) by its then limited partners in exchange for similar equity interests in Eclipse Holdings;

 

•

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

 

•

the contribution of equity interests in Eclipse I and the outstanding equity interests in Eclipse I GP, LLC, to the Company by Eclipse Holdings in exchange for 138,500,000 shares of common stock.

As a result of the Corporate Reorganization, the Company became a majority controlled direct subsidiary of Eclipse Holdings, and Eclipse I became a direct subsidiary of the Company. Each of the transactions that occurred as part of the Corporate Reorganization have been accounted for as a reorganization of entities under common control, with the exception of the acquisition of the outstanding equity interests of Eclipse Operating by Eclipse I, which has been accounted for as a business combination using the acquisition method (See “Note 4—Acquisitions”).

On June 25, 2014, the Company completed the initial public offering (“IPO”) of 30,300,000 shares of $0.01 par value common stock, which included 21,500,000 shares sold by the Company and 8,800,000 shares sold by certain selling stockholders.

The gross proceeds to the Company and selling stockholders were approximately $818.1 million, which resulted in net proceeds to the Company of approximately $544.7 million after deducting expenses and underwriting discounts and commissions of approximately $35.8 million. The Company did not receive any proceeds from the sale of the shares by the certain selling stockholders. The net proceeds from the IPO were used to repay all of the then outstanding borrowings under the revolving credit facility and the Company expects to use the remaining net proceeds to fund a portion of the capital expenditure plan.

Note 2—Basis of Presentation

The accompanying consolidated financial statements of Eclipse Resources Corporation for the period from January 1, 2014 through June 23, 2014, as contained within the year ended December 31, 2014 and as of December 31, 2013, and the years ended December 31, 2013 and 2012 pertain to the historical financial statements and results of operations of Eclipse Resources I, LP, our accounting predecessor. In February 2014, Eclipse Resources Corporation was formed as a Delaware corporation for the purpose of becoming a publicly traded company and the holding company of Eclipse I. The historical financial information contained in this report relates to periods that ended prior to the completion of the IPO of Eclipse Resources Corporation. In connection with the completion of the corporate reorganization on June 24, 2014, Eclipse Resources Corporation

 

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became a holding company whose sole material asset consists of a 100% indirect ownership interest in Eclipse I. As the sole managing member of Eclipse I, Eclipse Resources Corporation is responsible for all operational, management and administrative decisions relating to Eclipse I. Accordingly, this reorganization constituted a common control transaction and the accompanying consolidated financial statements are presented as though this reorganization had occurred for the earliest period presented herein.

The accompanying consolidated financial statements are presented in accordance with the requirements of accounting principles generally accepted in the United States (“U.S. GAAP”). All significant intercompany accounts have been eliminated in consolidation.

Preparation in accordance with U.S. GAAP requires the Company to (1) adopt accounting policies within accounting rules set by the Financial Accounting Standards Board (“FASB”) and (2) make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and other disclosed amounts. “Note 3—Summary of Significant Accounting Policies” describes our significant accounting policies. The Company’s management believes the major estimates and assumptions impacting the consolidated financial statements are the following:

 

•

estimates of proved reserves of oil and natural gas, which affect the calculations of depreciation, depletion and amortization and impairment of capitalized costs of oil and natural gas properties;

 

•

estimates of asset retirement obligations;

 

•

estimates of the fair value of oil and natural gas properties the Company owns, particularly properties that the Company has not yet explored, or fully explored, by drilling and completing wells;

 

•

impairment of undeveloped properties and other assets; and

 

•

depreciation and depletion of property and equipment.

Actual results may differ from estimates and assumptions of future events and these revisions could be material. Future production may vary materially from estimated oil and natural gas proved reserves. Actual future prices may vary significantly from price assumptions.

Note 3—Summary of Significant Accounting Policies

(a) Cash and Cash Equivalents

Cash and cash equivalents are comprised of cash in banks and highly liquid instruments with original maturities of three months or less, primarily consisting of bank time deposits and investments in institutional money market funds. The carrying amounts approximate fair value due to the short-term nature of these items. Cash in bank accounts at times may exceed federally insured limits.

(b) Accounts Receivable

Accounts receivable are carried at estimated net realizable value. Receivables deemed uncollectible are charged directly to expense. Trade credit is generally extended on a short-term basis, and therefore, accounts receivable do not bear interest, although a finance charge may be applied to such receivables that are past due. A valuation allowance is provided for those accounts for which collection is estimated as doubtful and uncollectible accounts are written off and charged against the allowance. In estimating the allowance, management considers, among other things, how recently and how frequently payments have been received and the financial position of the party. The Company did not deem any of its accounts receivables to be uncollectable as of December 31, 2014 or December 31, 2013.

The Company accrues revenue due to timing differences between the delivery of natural gas, natural gas liquids (NGLs), and crude oil and the receipt of a delivery statement. These revenues are recorded based upon

 

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volumetric data from the Company’s records and management’s estimates of the related commodity sales and transportation and compression fees which are, in turn, based upon applicable product prices. The Company had $24.1 million and $4.1 million of accrued revenues, net of expenses at December 31, 2014 and December 31, 2013, respectively, which were included in accounts receivable within the Company’s consolidated balance sheets.

(c) Property and Equipment

Oil and Natural Gas Properties

The Company follows the successful efforts method of accounting for its oil and natural gas operations. Acquisition costs for oil and natural gas properties, costs of drilling and equipping productive wells, and costs of unsuccessful development wells are capitalized and amortized on an equivalent unit-of-production basis over the life of the remaining related oil and gas reserves. The estimated future costs of dismantlement, restoration, plugging and abandonment of oil and gas properties and related disposal are capitalized when asset retirement obligations are incurred and amortized as part of depreciation, depletion and amortization expense (see “Depreciation, Depletion and Amortization” below).

Costs incurred to acquire producing and non-producing leaseholds are capitalized. All unproved leasehold acquisition costs are initially capitalized, including the cost of leasing agents, title work and due diligence. If the Company acquires leases in a prospective area, these costs are capitalized as unproved leasehold costs. If no leases are acquired by the Company with respect to the initial costs incurred or the Company discontinues leasing in a prospective area, the costs are charged to exploration expense. Unproved leasehold costs that are determined to have proved oil and gas reserves are transferred to proved leasehold costs.

Upon the sale or retirement of a complete field of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to the Company’s consolidated statements of operations. Upon the sale of an individual well, the proceeds are credited to accumulated depreciation and depletion within the Company’s consolidated balance sheets. Upon sale of an entire interest in an unproved property where the property had been assessed for impairment individually, a gain or loss is recognized in the Company’s consolidated statements of operations. If a partial interest in an unproved property is sold, any funds received are accounted for as a reduction of the cost in the interest retained.

A summary of property and equipment including oil and natural gas properties is as follows (in thousands):

 

		December 31, 2014				December 31, 2013
Oil and natural gas properties:
Unproved		$	1,044,469			$	926,812
Proved			802,112				97,528
Gross oil and natural gas properties			1,846,581				1,024,340
Less accumulated depreciation, depletion and amortization			(131,857	)			(8,596	)
Oil and natural gas properties, net			1,714,724				1,015,744
Other property and equipment			8,912				2,392
Less accumulated depreciation			(809	)			(52	)
Other property and equipment, net			8,103				2,340
Property and equipment, net		$	1,722,827			$	1,018,084

Exploration expenses, including geological and geophysical expenses and delay rentals for unevaluated oil and gas properties are charged to expense as incurred. Exploratory drilling costs are initially capitalized as unproved property, not subject to depletion, but charged to expense if and when the well is determined not to have found proved oil and gas reserves.

 

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Other Property and Equipment

Other property and equipment include land, buildings, leasehold improvements, vehicles, computer equipment and software, telecommunications equipment, and furniture and fixtures. These items are recorded at cost, or fair value if acquired through a business acquisition.

(d) Revenue Recognition

Oil and natural gas sales revenue is recognized when produced quantities of oil and natural gas are delivered to a custody transfer point such as a pipeline, processing facility or a tank lifting has occurred, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sales is reasonably assured and the sales price is fixed or determinable. Revenues from the sales of natural gas, crude oil or NGLs in which the Company has an interest with other producers are recognized using the sales method on the basis of the Company’s net revenue interest. The Company had no material imbalances as of December 31, 2014 and December 31, 2013.

In accordance with the terms of joint operating agreements, from time to time, the Company may be paid monthly fees for operating or drilling wells for outside owners. The fees are meant to recoup some of the operator’s general and administrative costs in connection with well and drilling operations and are accounted for as credits to general and administrative expense.

(e) Major Customers

The Company sells production volumes to various purchasers. For the years ended December 31, 2014, 2013 and 2012, there were two, four, and one customer that accounted for 10% or more of the total natural gas, NGLs and oil sales. Management believes that the loss of any one customer would not have an adverse effect on the Company’s ability to sell natural gas, NGLs and oil production. The following table sets forth the Company’s major customers and associated percentage of revenue for the periods indicated:

 

		For the Year Ended December 31,
		2014				2013				2012
Purchaser
Antero Resources Corporation			47	%			38	%			100	%
Devco Oil Inc.			—				24	%			—
Dominion Resources Inc.			—				13	%			—
ARM Energy Management			25	%			—				—
Ergon			—				12	%			—
Total			72	%			87	%			100	%

Management believes that there are potential alternative purchasers and that it may be necessary to establish relationships with new purchasers. However, there can be no assurance that the Company can establish such relationships or that those relationships will result in an increased number of purchasers. Although the Company is exposed to a concentration of credit risk, management believes that all of the Company’s purchasers are credit worthy.

 

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(f) Concentration of Credit Risk

The following table summarizes concentration of receivables, net of allowances, by product or service as of December 31, 2014 and December 31, 2013 (in thousands):

 

		December 31, 2014				December 31, 2013
Receivables by product or service:
Sale of oil and natural gas and related products and services		$	22,777			$	4,092
Joint interest owners			20,666				4,586
Miscellaneous other			2,935				—
Total		$	46,378			$	8,678

Oil and natural gas customers include pipelines, distribution companies, producers, gas marketers and industrial users primarily located in the State of Ohio. As a general policy, collateral is not required for receivables, but customers’ financial condition and credit worthiness are evaluated regularly.

By using derivative instruments that are not traded on an exchange to hedge exposures to changes in commodity prices, the Company exposes itself to the credit risk of 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 the Company, which creates credit risk. To minimize the credit risk in derivative instruments, it is the Company’s policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market-makers. Additionally, the Company uses master netting agreements to minimize credit-risk exposure. The creditworthiness of the Company’s counterparties is subject to periodic review. The fair value of the Company’s commodity derivative contracts is a net asset position of $19.0 million at December 31, 2014. Other than as provided by the revolving credit facility, the Company is not required to provide credit support or collateral to any of its counterparties under the Company’s contracts, nor are they required to provide credit support to the Company. As of December 31, 2014, the Company did not have past-due receivables from or payables to any of the counterparties.

(g) Accumulated Other Comprehensive Income (Loss)

Comprehensive loss includes net loss and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under U.S. GAAP, have not been recognized in the calculation of net loss. These changes, other than net loss, are referred to as “other comprehensive loss” and for the Company they include a pension benefit plan that requires the Company to (i) recognize the overfunded or underfunded status of a defined benefit retirement plan as an asset or liability in its balance sheet and (ii) recognize changes in that funded status in the year in which the changes occur through other comprehensive loss. The Company’s pension plan was underfunded by $1.3 million and $1.5 million at December 31, 2014 and December 31, 2013, respectively. Effective March 31, 2014, benefit accruals in the plan were frozen resulting in a gain on reduction of pension liability of $2.2 million for the year ended December 31, 2014. No such gain was recorded for the year ended December 31, 2013.

(h) Depreciation, Depletion and Amortization

Oil and Natural Gas Properties

Depreciation, depletion, and amortization (“DD&A”) of capitalized costs of proved oil and natural gas properties is computed using the unit-of-production method on a field level basis using total estimated proved reserves. The reserve base used to calculate DD&A for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. The reserve base used to calculate DD&A for drilling, completion and well equipment costs, which include development costs and

 

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successful exploration drilling costs, includes only proved developed reserves. DD&A expense relating to proved oil and natural gas properties for the years ended December 31, 2014, 2013 and 2012 totaled approximately $88.4 million, $5.9 million and $0.2 million, respectively.

Through September 30, 2014, the Company calculated depletion of proved properties at the individual unit level. Effective October 1, 2015, the Company changed its estimate for calculating depletion expense of proved properties to be performed at the field level consistent with the assessment for impairment of proved property costs. As a result of this change, DD&A expense recorded by the Company for the year ended December 31, 2014 was $1.3 million lower than it would have been if the Company had not made this change.

Other Property and Equipment

Depreciation with respect to other property and equipment is calculated using straight-line methods based on expected lives of the individual assets or groups of assets ranging from 5 to 40 years. Depreciation for the years ended December 31, 2014, 2013, and 2012 totaled approximately $0.8 million, $0.3 million and $0.2 million, respectively. This amount is included in DD&A expense in the consolidated statements of operations.

(i) Impairment of Long-Lived Assets

The Company reviews its long lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount for that asset to its estimated fair value if such carrying amount exceeds the fair value.

During the year ended December 31, 2014, the Company changed its estimate for assessing impairment of proved property costs. Through September 30, 2014, such assessments were performed at the individual unit level. Effective October 1, 2014, assessment for impairment of proved properties is performed at the field level, which for the Company consists of three fields, including Conventional production, the Utica Shale, and the Marcellus Shale. With the increase in the Company’s activity level, this change will result in a more appropriate identification of cash flows utilized in the assessment of recoverability of proved properties as additional units are placed into production, resulting in increased sharing of revenues and costs across units related to infrastructure, equipment, and fulfillment of sales and transportation contracts.

The review of the Company’s oil and gas properties is done by determining if the historical cost of proved properties less the applicable accumulated DD&A and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on the Company’s plans to continue to produce and develop proved reserves and a risk-adjusted portion of probable reserves. Expected future cash flow from the sale of production of reserves is calculated based on estimated future prices. The Company estimates prices based upon current contracts in place, adjusted for basis differentials and market-related information, including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets. The Company recognized impairment expenses relating to proved properties of $34.9 million and $2.1 million for the years ended December 31, 2014 and 2013, respectively. Approximately $30.9 million of the impairment recorded for the year ended December 31, 2014 was recorded during the fourth quarter of 2014 as a result of the significant decline in oil and natural gas commodity prices during the quarter related to the conventional properties acquired during the Oxford Acquisition. The remaining $4.0 million related to unconventional properties in the Utica Shale. There were no impairments of proved properties for the year ended December 31, 2012.

 

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The aforementioned impairment charges represented a significant Level 3 measurement in the fair value hierarchy. The primary input used was the Company’s forecasted discount net cash flows.

The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results.

Unproved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. An impairment charge is recorded if conditions indicate the Company will not explore the acreage prior to expiration of the applicable leases. The Company recorded impairment charges of unproved oil and gas properties related to lease expirations of $5.7 million and $0.8 million for the years ended December 31, 2014 and 2012, respectively. These costs are included in exploration expense in the consolidated statements of operations. No such impairments were recorded for year ended December 31, 2013.

(j) Income Taxes

The Company accounts for income taxes, as required, under the liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carry-forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized.

Upon the closing of the Corporate Reorganization, the Company owns 100% of Eclipse I, Eclipse Resources-Ohio, LLC and Eclipse Operating. Eclipse I was a limited partnership not subject to federal income taxes before the Corporate Reorganization. However, in connection with the closing of the Corporate Reorganization, the Company became a corporation subject to federal and state income tax and, as such, the Company’s future income taxes will be dependent upon its future taxable income. The change in tax status requires the recognition of a deferred tax asset or liability for the initial temporary differences at the time of the change in status. The resulting net deferred tax liability of approximately $97.6 million was recorded as income tax expense in the consolidated statements of operations for the year ended December 31, 2014.

The FASB’s Accounting Standards Codification (“ASC”) Topic 740 “Income Taxes” provides that a tax benefit from an uncertain tax position may be recognized when it is more likely than not that the position will be sustained upon examination, including resolutions of any related appeals or litigation processes, based on the technical merits. Income tax positions must meet a more-likely-than-not recognition threshold at the effective date to be recognized upon the adoption of the uncertain tax position guidance and in subsequent periods. This interpretation also provides guidance on measurement, derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The Company recognizes fines and penalties as income tax expense.

 

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(k) Fair Value of Financial Instruments

The Company has established a hierarchy to measure its financial instruments at fair value which requires it to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The hierarchy defines three levels of inputs that may be used to measure fair value:

Level 1—Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date.

Level 2—Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market date for substantially the entire contractual term of the asset or liability.

Level 3—Unobservable inputs that reflect the entity’s own assumptions about the assumption market participants would use in the pricing of the asset or liability and are consequently not based on market activity but rather through particular valuation techniques.

Valuation techniques that maximize the use of observable inputs are favored. Assets and liabilities are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy.

(l) Derivative Financial Instruments

The Company uses derivative financial instruments to reduce exposure to fluctuations in the prices of the energy commodities it sells.

Derivatives are recorded at fair value and are included on the consolidated balance sheets as current and noncurrent assets and liabilities. Derivatives are classified as current or noncurrent based on the contractual expiration date. Derivatives with expiration dates within the next 12 months are classified as current. The Company netted the fair value of derivatives by counterparty in the accompanying consolidated balance sheets where the right to offset exists. The Company’s derivative instruments were not designated as hedges for accounting purposes for any of the periods presented. Accordingly, the changes in fair value are recognized in the consolidated statements of operations in the period of change. Gains and losses on derivatives are included in cash flows from operating activities. Premiums for options are included in cash flows from operating activities.

The valuation of the Company’s derivative financial instruments represents a Level 2 measurement in the fair value hierarchy.

(m) Asset Retirement Obligation

The Company recognizes a legal liability for its asset retirement obligations (“ARO”) in accordance with Topic ASC 410, “Asset Retirement and Environmental Obligations,” associated with the retirement of a tangible long-lived asset, in the period in which it is incurred or becomes determinable, with an associated increase in the carrying amount of the related long-lived asset. The cost of the tangible asset, including the initially recognized asset retirement cost, is depreciated over the useful life of the asset and accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. The Company measures the fair value of its ARO using expected future cash outflows for abandonment discounted back to the date that the abandonment obligation was measured using an estimated credit adjusted rate, which was 9.89% and 8.96% for the years ended December 31, 2014 and 2013, respectively.

Estimating the future ARO requires management to make estimates and judgments based on historical estimates regarding timing and existence of a liability, as well as what constitutes adequate restoration, inherent in the fair value calculation are numerous assumptions and judgments including the ultimate costs, inflation

 

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factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset. As of December 31, 2014, management revised its assumptions relating to certain wells including useful lives, working interest, and abandonment costs. These revisions increased the asset retirement obligation for the wells, and as a result, the Company recorded an incremental layer of approximately $6.5 million.

The following table sets forth the changes in the Company’s ARO liability for the period indicated (in thousands):

 

		2014				2013				2012
Asset retirement obligations, beginning of period		$	9,055			$	13			$	—
Revisions of prior estimates			6,470				—				—
Additional liabilities incurred			1,084				300				13
Assumption of Oxford asset retirement obligations			—				8,378				—
Accretion			791				364				—
Asset retirement obligations, end of period		$	17,400			$	9,055			$	13

The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition. Additions to ARO represent a significant nonrecurring Level 3 measurement.

(n) Lease Obligations

The Company leases office space under operating leases that expire between the years 2015—2025. The lease terms begin on the date of initial possession of the leased property for purposes of recognizing lease expense on a straight-line basis over the term of the lease. The Company does not assume renewals in its determination of the lease terms unless the renewals are deemed to be reasonably assured at lease inception.

(o) Off-Balance Sheet Arrangements

The Company does not have any off-balance sheet arrangements.

(p) Segment Reporting

The Company operates in one industry segment: the oil and natural gas exploration and production industry in the United States. All of its operations are conducted in one geographic area of the United States. All revenues are derived from customers located in the United States.

(q) Debt Issuance Costs

The expenditures related to issuing debt are capitalized and included in other assets in the accompanying balance sheets. These costs are amortized over the expected life of the related instruments using the effective interest rate method. When debt is retired before maturity or modifications significantly change the cash flows, related unamortized costs are expensed.

(r) Recent Accounting Pronouncements

The FASB issued ASU 2013-11, “Income Taxes (Topic 740)—Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists” in December 2013. These amendments provide that an unrecognized tax benefit, or a portion thereof, should be

 

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presented in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward, except to the extent that a net operating loss carryforward, a similar tax loss, or a tax credit carryforward is not available at the reporting date to settle any additional income taxes that would result from disallowance of a tax position, or the tax law does not require the entity to use, and the entity does not intend to use, the deferred tax asset for such purpose, then the unrecognized tax benefit should be presented as a liability. These requirements were effective for annual reporting periods beginning after December 15, 2013, including interim periods within that reporting period. The adoption of this ASU did not impact the Company’s financial position, results of operations or liquidity.

The FASB issued ASU 2014-09, “Revenue from Contracts with Customers (Topic 606) (“Update 2014-09”)”, which supersedes the revenue recognition requirements (and some cost guidance) in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the industry topics of the Accounting Standards Codification. In addition, the existing requirements for the recognition of a gain or loss on the transfer of nonfinancial assets that are not in a contract with a customer (for example, assets within the scope of Topic 360, Property, Plant and Equipment, and intangible assets within the scope of Topic 350, Intangibles—Goodwill and Other) are amended to be consistent with the guidance on recognition and measurement (including the constraint on revenue) in Update 2014-09. Topic 606 requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this, an entity should identify the contract with a customer, identify the performance obligations in the contract, determine the transaction price, allocate the transaction price to the performance obligations in the contract and recognize revenue when (or as) the entity satisfies the performance obligations. These requirements are effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. Early adoption is not permitted. The Company is evaluating the impact of the adoption on its financial position, results of operations and related disclosures.

In June 2014, the FASB issued ASU 2014-12, Compensation—Stock Compensation (Topic 718) (“Update 2014-12”). The amendments in Update 2014-12 require that a performance target that affects vesting and that could be achieved after the requisite service period, be treated as a performance condition. As such, the performance target should not be reflected in estimating the grant date fair value of the award. Compensation cost should be recognized in the period in which it becomes probable that the performance target will be achieved and should represent the compensation cost attributable to the period(s) for which the requisite service has already been rendered. If the performance target becomes probable of being achieved before the end of the requisite service period, the remaining unrecognized compensation cost should be recognized prospectively over the remaining requisite service period. The total amount of compensation cost recognized during and after the requisite service period should reflect the number of awards that are expected to vest and should be adjusted to reflect those awards that ultimately vest. The requisite service period ends when the employee can cease rendering service and still be eligible to vest in the award if the performance target is achieved. The amendments in Update 2014-12 are effective for annual periods and interim periods within those annual periods beginning after December 15, 2015. Earlier adoption is permitted. Entities may apply the amendments in Update 2014-12 either (a) prospectively to all awards granted or modified after the effective date, or (b) retrospectively to all awards with performance targets that are outstanding as of the beginning of the earliest annual period presented in the financial statements and to all new or modified awards thereafter. The Company will adopt the requirements of Update 2014-12 upon its effective date of January 1, 2016, and is evaluating the impact of the adoption on its financial position, results of operations and related disclosures.

In April 2014, the FASB issued ASU 2014-08, “Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360)”: Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity”. The objective of the amendments in this update is to change the criteria for reporting discontinued operations and enhance convergence of the FASB’s and the International Accounting Standard Board’s (IASB) reporting requirements for discontinued operations. The amendments in this update change the requirements for reporting discontinued operations in Subtopic 205-20. A discontinued operation may

 

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include a component of an entity or a group of components of an entity, or a business or nonprofit activity. A disposal of a component of an entity or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results. The amendments in this update require an entity to present, for each comparative period, the assets and liabilities of a disposal group that includes a discontinued operation separately in the asset and liability sections, respectively, of the statement of financial position. The amendments in this update also require additional disclosures about discontinued operations. Public business entities must apply the amendments in this update prospectively to both of the following: (1) All disposals (or classifications as held for sale) of components of an entity that occur within annual periods beginning on or after December 15, 2014, and interim periods within those years; (2) All businesses or nonprofit activities that, on acquisition, are classified as held for sale that occur within annual periods beginning on or after December 15, 2014, and interim periods within those years. Early adoption is permitted, but only for disposals (or classifications as held for sale) that have not been reported in financial statements previously issued or available for issuance. The Company is evaluating the impact of the adoption on its financial position, results of operations and related disclosures.

In August 2014, the FASB issued Accounting Standards Update No. 2014-15, Presentation of Financial Statements—Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern. The new standard provides guidance on determining when and how to disclose going concern uncertainties in the financial statements. Management will be required to perform interim and annual assessments of the Company’s ability to continue as a going concern within one year of the date and financial statements are issued. ASU 2014-15 is effective for annual periods ending after December 15, 2016, and interim periods within those years, with early adoption permitted. The adoption of this standard is not expected to have an impact on the Company’s financial statement disclosures.

Note 4—Acquisition

Eclipse Resources Operating, LLC Acquisition

On June 24, 2014, prior to the closing of the IPO, the Company acquired all of the outstanding equity interests of Eclipse Operating for total consideration of $0.1 million. The fair value of the net assets acquired, consisting primarily of cash, accounts receivable, property and equipment, accounts payable and accrued liabilities exceeded the purchase price paid. As a result, the Company recognized a gain of $0.4 million related to the purchase, which is included in other income on the consolidated statements of operations.

The Eclipse Resources-Ohio, LLC Acquisition

On June 26, 2013, Eclipse I acquired (the “Oxford Acquisition”) 100% of the outstanding equity interests of Oxford. Oxford held interests in approximately 181,000 net acres of Utica Shale leaseholds, and related producing properties located primarily in Belmont, Guersney, Monroe, Noble, and Harrison Counties in Ohio along with various other related rights, permits, contracts, equipment and other assets. The aggregate purchase price totaled $652.5 million in cash. The acquisition provided strategic additions adjacent to the Company’s core project area.

 

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The Purchase and Sales Agreement (“PSA”) for the Oxford Acquisition contained customary closing conditions and a $32.5 million escrow which was withheld from the initial purchase price to provide for certain contingencies. The notice period for any claims related to these contingencies expired June 25, 2014 and all amounts were released from escrow to the seller. The acquisition is accounted for using the acquisition method under ASC Topic 805, “Business Combinations” which requires the acquired assets and liabilities to be recorded at fair values as of the acquisition date of July 26, 2013. The following table summarizes the purchase price allocation and the values of assets acquired and liabilities assumed (in thousands):

 

Purchase Price		June 26, 2013
Consideration Given
Cash		$	652,500
Allocation of Purchase Price
Unproved properties			621,039
Proved properties			40,914
Cash			653
Building and land			1,500
Total assets			664,106
Asset retirement obligations			(8,378	)
Pension obligation			(2,522	)
Other working capital			(706	)
Fair value of net assets acquired		$	652,500

The purchase price allocation set forth above represented a significant Level 3 measurement in the fair value hierarchy and was derived in accordance with ASC 805 by an outside third party. The inputs used in such determination were forecasted cash flows, market comparisons, actuarial studies and Oxford’s historical accounting records.

Immediately prior to the completion of the Oxford Acquisition, Oxford merged into Eclipse Resources—Ohio, LLC (“Eclipse Ohio”). Eclipse Ohio is party to various lawsuits, primarily related to the validity of certain oil and gas leases (see “Note 13—Commitments and Contingencies”).

Pro Forma Financial Information (unaudited)

The following unaudited pro forma financial information represents the combined results for the Company and Oxford for the years ended December 31, 2013 and 2012 as if the acquisition had occurred on January 1, 2012. The pro forma information includes the effects of adjustments for depletion, depreciation, amortization and accretion expense of $3.4 million and $0.8 million for the years ended December 31, 2013 and 2012, respectively. The pro forma information includes the effects of adjustments for amortization of financing costs of $0.7 million and $1.5 million for the years ended December 31, 2013 and 2012, respectively. The pro forma information includes the effects of the amortization of debt discount of $1.2 million and $2.4 million for the years ended December 31, 2013 and 2012, respectively. The pro forma information includes the effects of the incremental interest expense on acquisition financing of $26.9 million and $53.9 million for the years ended December 31, 2013 and 2012, respectively. The pro forma results do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by the Company to integrate the properties acquired. The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of January 1, 2012, nor are they necessarily indicative of future results (in thousands).

 

		For the Year Ended December 31,
		2013				2012
Oil and natural gas sales		$	20,638			$	13,936
Net loss		$	(71,131	)		$	(56,065	)

 

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Note 5—Sale of Oil and Natural Gas Property Interests

Effective March 16, 2012, the Partnership entered into a Purchase and Exploration Agreement (“PEA”) to sell 70% of its interests in certain unproved oil and gas properties. During 2012, the Partnership completed the sale of 21,114 net acres under the PEA for net proceeds of $126.5 million. The cumulative proceeds of the sale did not exceed the Partnership’s cost basis in the properties; therefore, no gain was recognized on the sale.

During the year ended December 31, 2012, the Partnership sold 70% of its interest in a proved oil and gas property for $5.2 million, before customary purchase price adjustments. The proceeds included $2.4 million for the sale of 70% of its net acreage in the unit and $2.8 million for the reimbursement of 70% of the Partnership’s net drilling costs incurred. The sales proceeds exceeded the Partnership’s cost basis in the unit, resulting in a gain of $0.4 million during 2012.

During the year ended December 31, 2013, the Partnership sold an additional 1,220 acres for net proceeds of $8.5 million. The cumulative proceeds of the sale did not exceed the Partnership’s cost basis in the properties; therefore, no gain was recognized on the sale.

During the year ended December 31, 2014, the Company sold a central processing facility for proceeds of $16.8 million, of which $15.5 million had been received by December 31, 2014. The proceeds exceeded the Company’s cost basis in the facility, resulting in a gain of approximately $1.0 million during 2014.

As of December 31, 2014, the Company was actively negotiating the sale of a second central processing facility, which is expected to close during 2015. As a result, costs related to this facility of approximately $20.7 million are classified as assets held for sale in the consolidated balances sheets as of December 31, 2014.

Note 6—Derivative Instruments

Commodity derivatives

The Company is exposed to market risk from changes in energy commodity prices within its operations. The Company utilizes derivatives to manage exposure to the variability in expected future cash flows from forecasted sales of natural gas. The Company currently uses a mix of over-the-counter (“OTC”) natural gas fixed price swaps, basis swaps and put options spreads and collars to manage its exposure to natural gas price fluctuations. All of the Company’s derivative instruments are used for risk management purposes and none are held for trading or speculative purposes.

The Company is exposed to credit risk in the event of non-performance by counterparties. The creditworthiness of counterparties is subject to continuing review. The Company has not experienced any issues of non-performance by derivative counterparties.

 

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Below is summary of the Company’s derivative instrument positions, as of December 31, 2014, for future production periods:

 

Description		Volume (MMBtu/d)				Production Period				Weighted Average Price ($/MMBtu)
Natural Gas Swaps:
			66,219				January 2015—December 2015			$	3.797
			25,000				January 2016—December 2016			$	3.660
Natural Gas Three-way Collar:
Floor purchase price (put)			15,000				January 2015—December 2015			$	3.60
Ceiling sold price (call)			15,000				January 2015—December 2015			$	3.80
Floor sold price (put)			15,000				January 2015—December 2015			$	3.00
Natural Gas Put Sale:
Put sold			16,800				January 2015—December 2015			$	3.350
Natural Gas Collar:
Purchased put			5,000				January 2015—March 2015			$	4.000
Call sold			5,000				January 2015—March 2015			$	4.750
Basis Swaps:
			25,000				January 2015—March 2015			$	(1.067	)
			25,000				April 2015—October 2015			$	(1.208	)

Fair values and gains (losses)

The following table summarizes the fair value of the Company’s derivative instruments on a gross basis and on a net basis as presented in the consolidated balance sheets (in thousands). None of the derivative instruments are designated as hedges for accounting purposes.

 

Derivatives not designated as hedging instruments under ASC 815		Gross Amount				Netting Adjustments(a)				Net Amount Presented in the Balance Sheets				Balance Sheet Location
As of December 31, 2014
Assets
Commodity derivatives—current		$	22,349			$	(5,012	)		$	17,337			Other current assets
Commodity derivatives—noncurrent			1,741				(44	)			1,697			Other assets
Total assets		$	24,090			$	(5,056	)		$	19,034
Liabilities
Commodity derivatives—current		$	(5,012	)		$	5,012			$	—
Commodity derivatives—noncurrent			(44	)			44				—
Total liabilities		$	(5,056	)		$	5,056			$	—

 

(a)	The Company has agreements in place that allow for the financial right to offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements.

At December 31, 2013, the Company did not have any derivative instruments in place.

The following table presents the Company’s reported gains and losses on derivative instruments and where such values are recorded in the consolidated statements of operations for the periods presented (in thousands):

 

		Location of Gain (Loss)				Years Ended December 31,
						2014				2013				2012
Commodity derivatives			Gain on derivative instruments			$	20,791			$	—			$	—

 

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Note 7—Fair Value Measurements

Fair Value Measurement on a Recurring Basis

The following table presents, by level within the fair value hierarchy, the Company’s assets and liabilities that are measured at fair value on a recurring basis. The carrying amounts reported in the consolidated balance sheets for cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the nature of the instrument and/or the short-term maturity of these instruments.

The fair value of the Company’s derivatives is based on third-party pricing models which utilize inputs that are readily available in the public market, such as natural gas forward curves. These values are compared to the values given by counterparties for reasonableness. Since natural gas swaps do not include optionality and therefore generally have no unobservable inputs, they are classified as Level 2.

 

		Level 1				Level 2				Level 3				Total Fair Value
As of December 31, 2014: (in thousands)
Commodity derivative instruments		$	—			$	19,034			$	—			$	19,034
Total		$	—			$	19,034			$	—			$	19,034

The Company did not have any assets or liabilities that were measured at fair value on a recurring basis as of December 31, 2013, except for pension assets as described in Note 9.

Nonfinancial Assets and Liabilities

Assets and liabilities acquired in business combinations are recorded at their fair value on the date of acquisition. Significant Level 3 assumptions associated with the calculation of future cash flows used in the analysis of fair value of the oil and natural gas property acquired include the Company’s estimate of future commodity prices, production costs, development expenditures, production, risk-adjusted discount rates, and other relevant data. Additionally, fair value is used to determine the inception value of the Company’s AROs. The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition. Additions to the Company’s ARO represent a nonrecurring Level 3 measurement. (See Note 3(m)).

The Company reviews its proved oil and natural gas properties for impairment purposes by comparing the expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset. Significant assumptions associated with the calculation of future cash flows used in the impairment analysis include the estimate of future commodity prices, production costs, development expenditures, production, risk-adjusted discount rates and other relevant data. As such, the fair value of oil and natural gas properties used in estimating impairment represents a nonrecurring Level 3 measurement. (See Note 3(i)).

The estimated fair values of the Company’s financial instruments closely approximate the carrying amounts due, except for long-term debt. (see “Note 8—Debt”)

Note 8—Debt

12% Senior Unsecured PIK Notes Due 2018

On June 26, 2013, Eclipse I completed a private placement offering of an initial aggregate principal amount of $300 million, with an additional $100 million notes option, at the discretion of Eclipse I, of 12% Senior Unsecured PIK Notes due in 2018 (the “Senior Unsecured Notes”). The Senior Unsecured Notes were issued at 96% of par and Eclipse I received $280.7 million of net cash proceeds, after deducting the discount to initial purchasers of $12 million and offering expenses of $7.3 million. In December 2013, Eclipse I exercised its option

 

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and issued an additional $100 million of Senior Unsecured Notes with the same terms, at par. Eclipse I received $100 million net cash proceeds, as no discounts and $0.2 million of offering expenses were incurred in connection with the exercise of the option. During the year ended December 31, 2014, the Company amortized $4.1 of deferred financing costs and debt discount to interest expense using the effective interest method.

The Company has the right to redeem all or a portion of the Senior Unsecured Notes prior to the 2-year anniversary of the final funding date, which the Company refers to as the Non-Call Period, by paying a redemption price equal to 100.0% times a “make whole premium” equal to the greater of 106.0% or an amount computed under the Indenture governing the Senior Unsecured Notes (the “Indenture”) plus accrued and unpaid interest. After the Non-Call Period, the Company may redeem all or a part of the Senior Unsecured Notes at the redemption prices (expressed as percentages of principal amount) set forth below, plus accrued and unpaid interest:

 

Year following expiration of the Non-Call Period		Redemption Price
Year 1			106.00	%
Year 2			103.00	%
Year 3 and thereafter			100.00	%

At the Company’s option, for the first 2 semi-annual interest payments following the issue date, interest may be payable by increasing the principal amount of the Senior Unsecured Notes or by issuing payment in kind (“PIK”) securities. Interest paid by issuing PIK securities accrues at 13%, interest paid by cash accrues at 12%. At the Company’s option, for the subsequent four semi-annual interest payments thereafter, interest may be payable in the form of 6.0% per annum in cash and 7.0% per annum in PIK securities. Thereafter, interest can only be paid as cash interest. Interest is payable on July 15 and January 15 each year, beginning in January 2014. The Company elected to settle its accrued interest payable on January 15, 2014 by issuing PIK securities of $22.5 million and settle its accrued interest payable on July 15, 2014 with a cash payment of $25.3 million. The Company elected to settle its accrued interest payable on January 15, 2015 by issuing PIK securities of $14.8 million and a cash payment of $12.7 million.

The Company’s obligations under the Senior Unsecured Notes are guaranteed by its 100% owned subsidiaries. The Company may not among other things, directly or indirectly: (1) consolidate or merge with or into another Person (whether or not the Company is the survivor), or (2) sell, assign, transfer, convey, lease or otherwise dispose of all or more than 50% of its properties or assets, in one or more related transactions, to another Person, unless in each case certain restrictive conditions contained in the Indenture are met.

The Indenture requires the Company to be in compliance with certain other covenants, including the prompt payment of interest, including PIK interest, and any and all material taxes, assessments and government levies imposed; timely submission of quarterly and audited annual financial statements, reserve reports, budgets and other notices, and other recurring obligations. The Indenture places restrictions on the Company and its subsidiaries with respect to additional indebtedness, liens, dividends and other payments, investments, acquisitions, mergers, asset dispositions, transactions with affiliates, change of control and other matters. The Company was in compliance with all applicable covenants in the Indenture at December 31, 2014.

The Senior Unsecured Notes are subject to certain events of default. If an event of default occurs and is continuing, the outstanding Senior Notes may, and under certain circumstances, will be accelerated. The purchasers of the Senior Notes are entitled to the benefits of a registration rights agreement pursuant to which the Company agreed to file a registration statement with the Securities and Exchange Commission to allow for the resale of the Notes under the Securities Act.

As of December 31, 2014, the principal amount outstanding related to the Senior Unsecured Notes was $422.5 million. The fair value of the Senior Unsecured Notes as of December 31, 2014 was $482.8 million. This fair value estimate is classified as Level 2 in the fair value hierarchy. The valuation techniques used are industry-standard models that consider various assumptions, including quoted forward rates, time value, volatility factors

 

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and current market and contractual rates, as well as other relevant economic measures. Substantially all of the assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace.

Revolving Credit Facility

During the first quarter of 2014, the Company entered into a $500 million senior secured revolving bank credit facility (the “Revolving Credit Facility”) that matures in 2018. Borrowings under the Revolving Credit Facility are subject to borrowing base limitations based on the collateral value of the Company’s proved properties and commodity hedge positions and are subject to quarterly redeterminations through April 1, 2015 and semiannual redeterminations thereafter. At December 31, 2014, the borrowing base was $100 million and the Company had no outstanding borrowings. After considering outstanding letters of credit issued by the Company, totaling $26.9 million, the Company had available capacity on the Revolving Credit Facility of $73.1 million at December 31, 2014. In March 2015, the borrowing base of the Revolving Credit Facility was redetermined, resulting in an increase in the borrowing base to $125 million.

The Revolving Credit Facility was amended and restated on January 12, 2015. The primary change effected by the Amendment was to add Eclipse Resources Corporation as a party to the Revolving Credit Facility and thereby subject the Company to the representations, warranties, covenants and events of default provisions thereof. Relative to the Eclipse I’s previous credit agreement, the Credit Agreement also (i) requires financial reporting regarding, and tests financial covenants with respect to, Eclipse Resources Corporation rather than Eclipse I, (ii) increases the basket sizes under certain of the negative covenants, and (iii) includes certain other changes favorable to Eclipse I. Other terms of the Credit Agreement remain generally consistent with Eclipse I’s previous credit agreement.

The Revolving Credit Facility is secured by mortgages on substantially all of the Company’s properties and guarantees from the Company’s operating subsidiaries. The Revolving Credit Facility contains certain covenants, including restrictions on indebtedness and dividends, and requirements with respect to working capital and interest coverage ratios. Interest is payable at a variable rate based on LIBOR or the prime rate based on the Company’s election at the time of borrowing. The Company was in compliance with all applicable covenants under the Revolving Credit Facility as of December 31, 2014. Commitment fees on the unused portion of the Revolving Credit Facility are due quarterly at rates ranging from 0.375% to 0.50% of the unused facility based on utilization.

Note 9—Benefit Plans

Defined Contribution Plan

The Company currently maintains a retirement plan intended to provide benefits under section 401(K) of the Internal Revenue Code, under which employees are allowed to contribute portions of their compensation to a tax-qualified retirement account. Under the 401(K) plan, the Company provides matching contributions equal to 100% of the first 6% of employees’ eligible compensation contributed to the plan. The Company contributed $0.4 million, $0.2 million and $0.1 million in matching contributions for the years ended December 31, 2014, 2013 and 2012, respectively.

Defined Benefit Plan

The Company maintains a defined benefit pension plan covering 28 of its employees, of which two are retired, four have deferred vested termination, and one is a survivor. Benefits are based on the employee’s years of service and compensation. The Partnership’s plans are funded in conformity with the funding requirements of ASC 715 as of December 31, 2014. As a result of the Oxford acquisition (refer to “Note 4” above) on June 26, 2013, the Partnership assumed the defined benefit pension plan, and therefore, no pension benefit plan was in effect prior to such date. Effective March 31, 2014, benefit accruals in the plan were frozen resulting in a gain on reduction of pension liability of $2.2 million for the year ended December 31, 2014.

 

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The authoritative guidance for defined benefit pension plans requires an employer to recognize the overfunded or underfunded status as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through other comprehensive income.

A summary of the pension benefit as of the years ended December 31, 2014 and 2013 is set forth in the below tables (in thousands):

 

		2014				2013
Change in benefit obligation
Benefit obligation at beginning of year		$	9,018			$	—
Oxford assumed benefit obligations			—				9,045
Service cost			70				144
Interest cost			335				203
Gain on reduction of pension liability			(2,208	)			—
Actuarial loss			1,616				(350	)
Benefits paid			(2,031	)			(24	)
Benefit obligation at end of period		$	6,800			$	9,018
Change in plan assets
Fair value of plan assets at beginning of year		$	7,521			$	—
Oxford assumed plan assets			—				6,523
Actual return on plan assets			(11	)			1,012
Employer contributions			—				10
Benefit paid			(2,031	)			(24	)
Fair value of plan assets at December 31, 2014		$	5,479			$	7,521

The funding level of the qualified pension plan is in compliance with standards set by applicable law or regulation. As shown in the table below, the current pension plan is underfunded. All defined benefit pension obligations, regardless of the funding status of the plan, are fully supported by the financial strength of the Company.

 

		2014				2013
		(in thousands)
Assets in excess of (less than) benefit obligation at December 31,
Vested amount		$	(6,800	)		$	(7,039	)
Additional benefits required			—				(1,979	)
Projected benefit obligation			(6,800	)			(9,018	)
Funded amount			5,479				7,521
Unfunded amount		$	(1,321	)		$	(1,497	)
Other amounts recognized in other comprehensive loss during the year ended December 31,
Assets in excess of (less than) benefit obligation at end of period		$	(1,321	)		$	(1,497	)
Amounts recorded in the consolidated balance sheet consist of:
Accrued benefit liability			(1,321	)			(1,497	)
Total recorded		$	(1,321	)		$	(1,497	)
Beginning amount recorded in other accumulated comprehensive income		$	1,168			$	—
Amounts recorded in accumulated other comprehensive loss consist of:
Pension obligation adjustment, net of tax			(1,716	)			1,168
Total recorded in accumulated other comprehensive income		$	(548	)		$	1,168

 

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The long-term expected rate of return on funded assets shown below is established for each benefit plan by developing a forward-looking, long-term return assumption for each asset class, taking into account factors such as the expected real return for the specific asset class and inflation. A single, long-term rate of return is then calculated as the weighted average of the target asset allocation percentages and the long-term return assumption for each asset class. The discount rate is determined by constructing a portfolio of high-quality, noncallable bonds with cash flows that match estimated outflows for benefit payments.

 

		For the Year Ended December 31,
		2014				2013
Weighted average assumptions to determine benefit obligation
Discount rate			3.75	%			4.75	%
Expected rate of return			6.00	%			6.00	%
Rate of compensation increase			4.00	%			4.00	%
Inflation			3.00	%			3.00	%
Components of net periodic benefit cost (in thousands)
Service cost		$	70			$	144
Interest cost			335				203
Expected return on plan assets			(448	)			(195	)
Amortization of transition obligation			70				140
Amortization of net (gain) loss			29				—
Net period benefit cost		$	56			$	292

The following benefit payments are expected to be paid over the next ten years (in thousands):

 

2015		$	8
2016			9
2017			25
2018			68
2019			106
2020-2024			1,798

The Company’s investment strategy for benefit plan assets reflects a long-term view, a careful assessment of the risks inherent in various asset classes and broad diversification to reduce the risk of the portfolio. The Company, along with its investment manager, determines the investment policies and strategies for the plan assets to determine the allocations to the various asset classes based on the results of the studies targeted percentages. The following tables below set forth the breakout of asset categories as of December 31, 2014 and 2013 (in thousands):

 

		December 31,
		2014				2013
Plan assets by category
Equity securities		$	—			$	7,398
Debt securities			5,392				117
Cash			87				6
Total Assets		$	5,479			$	7,521
Plan assets by category
Equity securities			N/A				98.3	%
Debt securities			98.4	%			1.6	%
Cash			1.6	%			0.1	%
Total Assets			100	%			100	%

 

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The following tables set forth by level, within the fair value hierarchy, the fair value of pension assets as of December 31, 2014 and 2013 (in thousands):

 

		December 31, 2014
		Level 1				Level 2				Level 3				Total
Pension assets		$	5,206				273				—			$	5,479
		December 31, 2013
		Level 1				Level 2				Level 3				Total
Pension assets		$	7,404				117				—			$	7,521

The fair value measurement levels are accounting terms that refer to different methods of valuing assets. The terms do not represent the relative risk or credit quality of an investment.

Note 10—Equity

Initial Public Offering

On June 25, 2014, the Company completed its initial public offering (“IPO”) of 30,300,000 shares of our common stock, which included 21,500,000 shares sold by the Company and 8,800,000 shares sold by certain stockholders. The net proceeds from the IPO were approximately $544.7 million, after deducting underwriting discounts and commissions and the offering expenses payable by the Company of approximately $35.8 million. The Company used a portion of the net proceeds received from the IPO to repay the then-outstanding borrowings under Eclipse I’s revolving credit facility and to fund the Company’s capital expenditure plan.

Incentive Units

Eclipse Holdings has a total of 1,000 Class C-1 units and 1,000 Class C-2 units authorized to be issued to employees (“Incentive Units”). The Series C-1 and C-2 Incentive Units are non-voting with respect to partnership matters, and the holder thereof will begin to participate in distributions from Eclipse Holdings after distributions have been made to the holders of the Series A-1 and A-2 units that satisfy a specified hurdle rate and return on investment factor, with the level of participation in distributions adjusting upwards as distributions to the holders of the Series A-1 and A-2 units satisfy additional specified hurdle rates and return on investment factors.

Total compensation cost related to the Incentive Units was less than $0.1 million for each of the years ended December 31, 2014, 2013 and 2012. As of December 31, 2014, there was $0.7 million of total unrecognized compensation cost related to Incentive Units, which is expected to be recognized over a weighted-average period of 6.34 years.

The determination of the fair value of the awards noted above uses significant Level 3 assumptions in the fair value hierarchy including an estimate of the timing of an Exit Event, forfeitures, the risk free rate and a volatility estimate tied to the Company’s public peer group.

Restricted Stock Issued to Directors

The Company has 16,000,000 shares of common stock authorized to be issued in accordance with its 2014 Long-Term Incentive Plan. On October 7, 2014, the Company issued 31,115 restricted shares of common stock, par value $0.01, to seven non-employee members of its Board of Directors. As of December 31, 2014 the Company recognized expense of approximately $0.1 million and expects to recognize $0.3 million during 2015 until the restricted shares become fully vested on June 25, 2015.

 

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Private Placement of Common Stock

On December 27, 2014, the Company entered into a Securities Purchase Agreement with the EnCap Funds, the Management Funds and the other stockholders pursuant to which was agreed to issue and sell to such purchasers an aggregate of 62,500,000 shares of common stock at a price of $7.04 per share pursuant to the exemptions from registration provided in Rule 506 of Regulation D promulgated under Section 4(2) of the Securities Act, such transaction referred to herein as the “private placement.”

On January 28, 2015, the Company closed the private placement and received net proceeds from the issuance of the shares to the purchasers of approximately $434 million (after deducting placement agent commissions and estimated expenses), which the Company intends to use to fund its capital expenditure plan and for general corporate purposes. Upon the closing of the private placement, the Company amended and restated the existing registration rights agreement that was entered into upon the closing of the IPO to give the stockholders certain registration rights with respect to the stock purchased in the private placement.

Note 11—Earnings (Loss) Per Share

Earnings (loss) Per Share

Basic earnings (loss) per share (“EPS”) is computed by dividing net income (loss) by the weighted-average number of shares of common stock outstanding during the period. Diluted EPS takes into account the dilutive effect of potential common stock that could be issued by the Company in conjunction with any stock awards that have been granted to directors and employees. In accordance with FASB ASC Topic 260, awards of non-vested shares shall be considered to be outstanding as of the grant date for purposes of computing diluted EPS even though their exercise is contingent upon vesting. The following is a calculation of the basic and diluted weighted-average number of shares of common stock outstanding and EPS for the years ended:

 

(in thousands, except per share data)		Year Ended December 31,
		2014				2013				2012
Loss (numerator):
Net loss			(183,176	)			(43,541	)			(8,759	)
Weighted-average shares (denominator):
Weighted-average number of shares of common stock—basic and diluted			144,369				75,261				13,880
Loss per share:
Basic and diluted		$	(1.27	)		$	(0.58	)		$	(0.63	)

Note 12—Related Party Transactions

In December 2010, Eclipse Operating was formed by members of the Company’s management team for purposes of operating Eclipse I. The Company’s Chairman, President and Chief Executive Officer, Executive Vice President, Secretary and General Counsel and Executive Vice President and Chief Operating Officer each owned 33% of the membership units of Eclipse Operating. Eclipse Operating provide administrative and management services to Eclipse I under the terms of an Administrative Services Agreement. In connection with the Corporate Reorganization, Eclipse I acquired of all the outstanding equity interests of Eclipse Operating for $0.1 million, which is the amount of the aggregate capital contributions made to Eclipse Operating by its members. As a result, Eclipse Operating became a wholly owned subsidiary of Eclipse I.

Under the terms of the Administrative Services Agreement, Eclipse I paid Eclipse Operating a monthly management fee equal to the sum of all general and administrative expenditures incurred in the management and administration of Eclipse I’s operations. These costs included salaries, wages and benefits, rent, insurance, and other expenses and costs required to operate Eclipse I. These expenses were billed in arrears at the actual cost to Eclipse Operating. During the period from January 1, 2014 to June 23, 2014 the Company’s management fee to

 

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Eclipse Operating was $15.6 million. The Company’s management fee to Eclipse Operating was $14.7 million, and $4.2 million for the years ending December 31, 2013 and 2012, respectively. These expenses are classified within “Operating expenses—General and administrative” in the consolidated statements of operations.

As of December 31, 2014, the Company has recorded an accrued liability of $972,000 related to a final distribution of the assets of Eclipse Operating. This amount will be distributed equally among the three former shareholders during 2015 and is reflected as a reduction of initial gain recorded on the acquisition of Eclipse Operating, which is classified within “Other income” in the Consolidated Statements of Operations.

During the year ended December 31, 2014 the Company incurred approximately $0.2 million related to flight charter services provided by BWH Air, LLC and BWH Air II, LLC, which are owned by the Company’s Chairman, President and Chief Executive Officer. The fees are paid in accordance with a standard service contract that does not obligate the Company to any minimum terms.

Note 13—Commitments and Contingencies

(a) Legal Matters

Prior to the Oxford Acquisition, Oxford commenced a lawsuit on October 24, 2011 in the Common Pleas Court of Belmont County, Ohio against Mr. Barry West, a lessor under an Oxford oil and gas lease, to enforce its rights to access and drill a well pursuant to the lease during its initial 5-year primary term. 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.

The Company has appealed the trial court’s decision in the West case 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 the lease is a “no term” perpetual lease, by ruling that perpetual leases are void as a matter of Ohio law and by invalidating such leases. The Company 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 the Company’s other oil and gas leases in Ohio contain provisions identical or similar to those found in the challenged Oxford lease. As of March 6, 2015, we are a party to one other lawsuit that makes allegations similar to those made by the lessor in the West lawsuit. This lawsuit, together with the West case, affect approximately 157 gross (157 net) leasehold acres and were capitalized on our balance sheet as of December 31, 2014 at $0.6 million.

The Company has undertaken efforts to amend the other leases acquired within the Utica Core Area in the Oxford Acquisition to address the issues raised by the trial court’s ruling in the West case. These efforts have resulted in modifications to leases covering approximately 34,256 net acres out of the approximately 46,549 net acres. The Company’s offer may require modification to address the issues raised by the trial court while the Company’s appeal is pending; however, the Company cannot predict whether the Company will be able to obtain modifications of the leases covering the remaining 12,293 net acres to effectively resolve issues related to the West 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 in the West case, and if other courts in Ohio adopt a similar interpretation of the provisions in other oil and gas leases the Company acquired in the Oxford Acquisition, other lessors may challenge the validity of such leases and those challenged leases may be declared void. Consequently, this could result in a loss of the mineral rights and an impairment of the related assets which could have a material adverse impact on the Company’s financial statements. These costs could potentially be impaired if it was determined that the West lawsuit leases are invalid. Other than this potential impairment, the Company is not able to estimate the range of other potential losses related to this matter.

 

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On September 26, 2014, the Ohio Court of Appeals for the Seventh Appellate District, the same appellate court that will decide the Company’s appeal in the West case, issued its decision in the case of Clyde Hupp et al. v. Beck Energy Corporation, an appeal of a Monroe County trial court decision upon which the trial court in West based its decision. The appellate court held that while Ohio law disfavors perpetual leases, courts in Ohio have not found them to be per se illegal or void from their inception. The appellate court further held that the trial court misinterpreted both the pertinent lease provisions and Ohio law on the subject and erred in concluding that the Beck Energy lease is a no-term, perpetual lease that is void ab initio as against public policy. On November 7, 2014, the plaintiff landowners filed an appeal of the appellate court’s decision with the Supreme Court of Ohio, which was accepted by the Supreme Court of Ohio on January 28, 2015. On March 2, 2015, the Ohio Court of Appeals for the Seventh Appellate District stayed all proceedings in the Company’s appeal in the West case pending a decision by the Supreme Court of Ohio in the Hupp v. Beck Energy appeal.

The Company believes that there are strong grounds for appeal of the West decision, and therefore, the Company intends to pursue all available appellate rights, and to vigorously defend against the claims in this lawsuit. Based on the merits of the Company’s appeal and the favorable holdings in the Hupp v. Beck Energy appellate decision described above, the Company believes that it is not probable that trial court’s decision in West will be upheld in the appeal or that the Company will incur a material loss in the lawsuit. The Company has not recorded an accrual for the potential losses attributable to this lawsuit.

Other Matters

From time to time, the Company may be a party to legal proceedings arising in the ordinary course of business. Management does not believe that a material loss is probable as a result of such proceedings.

(b) Environmental Matters

The Company is subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes environmental protection requirements that result in increased costs to the oil and natural gas industry in general, the business and prospects of the Company could be adversely affected.

(c) Leases

The development of the Company’s oil and natural gas properties under their related leases will require a significant amount of capital. The timing of those expenditures will be determined by the lease provisions, the term of the lease and other factors associated with unproved leasehold acreage. To the extent that the Company is not the operator of oil and natural gas properties that it owns an interest in, the timing, and to some degree the amount, of capital expenditures will be controlled by the operator of such properties.

The Company leases office space under operating leases that expire between the years 2015 to 2025. Rent expense related to the lease agreements for the years-ended December 31, 2014 and 2013 was $0.3 million and $0.1 million. No rent expense was incurred for the year ended December 31, 2012.

The following is a schedule by year, of the future minimum lease payments required under the lease agreements as of December 31, 2014 (in thousands).

 

2015		$	773
2016			749
2017			753
2018			756
2019			756
Thereafter			3,494
Total minimum lease payments		$	7,281

 

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Note 14—Income Tax

For 2014, the Company’s annual effective tax rate is an expense of approximately 64.47%, inclusive of the “Change in Tax Status” charge (see “Note 3—Summary of Significant Accounting Policies”) and the gain on acquisition of Eclipse Operating (see “Note 4—Acquisitions”). The Company incurred a tax loss in the current year (due principally to the ability to expense certain intangible drilling and development costs under current law) and thus, no current federal income taxes will be due. This tax loss results in a net operating loss carryforward at year-end; however, no valuation allowance has been recorded as management believes that there is sufficient future taxable income to fully utilize all tax attributes. This future taxable income arises from reversing temporary differences due to the excess of the book carrying value of oil and gas properties over their corresponding tax bases. Management is not relying on other sources of taxable income in concluding that no valuation allowance is needed.

 

		Year Ended December 31, 2014(1)
		(in thousands)
Current
Federal		$	—
State			132
Total current			132
Deferred
Federal			71,838
State			(171	)
Total deferred			71,667
Total income tax expense		$	71,799

 

(1)	For the 2013 and 2012 comparable periods, the calculation is not applicable as the Company was not a taxable entity until June 25, 2014.

The Company’s income tax expense differs from the amount derived by applying the statutory federal rate to pretax loss principally due the effect of the following items (in thousands):

 

		Year Ended December 31, 2014(1)
Loss before income taxes		$	(111,377	)
Statutory rate			35	%
Income tax benefit computed at statutory rate			(38,982	)
Reconciling items:
Non-deductible pre-IPO loss			13,264
State income taxes			(39	)
Other, net			71
Change in tax status			97,609
Gain on acquisition of Eclipse Operating			(124	)
Income tax expense		$	71,799

 

(1)	For the 2013 and 2012 comparable periods, the calculation is not applicable as the Company was not a taxable entity until June 25, 2014.

 

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Deferred income taxes primarily represent the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. The components of our deferred taxes are detailed in the table below (in thousands):

 

		Year Ended December 31, 2014(1)
Current deferred tax asset:
State effect of current deferreds		$	104
Other, net			2,140
Net current deferred tax asset		$	2,244
Non-current deferred tax asset:
Federal tax loss carryforwards		$	127,497
State effect of non-current deferreds			21
Other, net			668
Net non-current deferred tax asset		$	128,186
Current deferred tax liability:
Derivative instruments and other		$	6,966
Other, net			524
Net current deferred tax liability		$	7,490
Non-current deferred tax liability:
Oil and gas properties and equipment		$	194,900
Other, net			—
Net non-current deferred tax liability		$	194,900
Reflected in the accompanying balance sheet as:
Net deferred tax liability—current		$	5,246
Net deferred tax liability—noncurrent		$	66,714

 

(1)	For the 2013 and 2012 comparable periods, the calculation is not applicable as the Company was not a taxable entity until June 25, 2014.

The Company has a U.S. federal tax loss carryforward (“NOL”) of approximately $364 million as of December 31, 2014. This NOL was generated in tax year 2014 and will generally be available for use through tax year 2034. The Company expects to file initial corporate tax returns for federal and various state jurisdictions for the tax year ended December 31, 2014 prior to the extended due dates. Upon filing, the tax year ended December 31, 2014 will remain open to examination under the applicable statute of limitations in the U.S. and other jurisdictions in which the Company and its subsidiaries file income tax returns. However, the statute of limitations for examination of NOLs and other similar attribute carryforwards does not commence until the year the attribute is utilized. In some instances, state statutes of limitations are longer than those under U.S. federal tax law. Tax returns for predecessor entities prior to 2011 are generally not subject to examination.

As of December 31, 2014, the Company has not recorded a reserve for any uncertain tax positions. No federal income tax payments are expected in the upcoming four quarterly reporting periods.

On September 13, 2013, the US Treasury and IRS issued final Tangible Property Regulations (“TPR”) under IRC Section 162 and IRC Section 263(a) for tax years beginning on or after January 1, 2014. The Company analyzed the TPR and concluded there is minimal impact for the tax year ended December 31,2014. The Company will continue to monitor the impact of any future changes to the TPR on the Company prospectively.

 

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Note 15—Subsequent Events

Management has evaluated subsequent events and believes that there are no events that would have a material impact on the aforementioned financial statements and related disclosures, except for the amendment to the Revolving Credit Facility in January 2015 and redetermination of the borrowing base in March 2015 (refer Note 8—Debt) and the Private Placement of Common Stock that closed in January 2015 (refer Note 10—Equity).

Note 16—Quarterly Financial Information (unaudited)

Summarized quarterly financial data for the years ended December 31, 2014 and 2013 are presented in the following table. In the following table, the sum of basic and diluted “Earnings (Loss) per common share” for the four quarters may differ from the annual amounts due to the required method of computing weighted average number of shares in the respective periods. Additionally, due to the effect of rounding, the sum of the individual quarterly earnings (loss) per share amounts may not equal the calculated year earnings (loss) per share amount (in thousands, except per share data).

 

		First Quarter				Second Quarter				Third Quarter				Fourth Quarter
Year ended December 13, 2014
Total operating revenues			24,788				26,955				35,702				50,371
Total operating expenses			25,992				34,166				60,806				101,026
Operating loss			(1,204	)			(7,211	)			(25,104	)			(50,655	)
Net loss			(18,451	)			(112,648	)			(19,054	)			(33,023	)
Loss per common share:
Basic and diluted		$	(0.15	)		$	(0.84	)		$	(0.12	)		$	(0.21	)
		First Quarter				Second Quarter				Third Quarter				Fourth Quarter
Year ended December 13, 2013
Total operating revenues			288				570				4,510				7,567
Total operating expenses			2,052				5,766				10,055				17,753
Operating loss			(1,764	)			(5,196	)			(5,545	)			(10,186	)
Net loss			(1,759	)			(5,740	)			(16,484	)			(19,558	)
Loss per common share:
Basic and diluted.		$	(0.10	)		$	(0.10	)		$	(0.14	)		$	(0.16	)

Note 17—Supplemental Oil and Natural Gas Information (unaudited)

(a) Capitalized Costs

A summary of the Company’s capitalized costs are contained in the table below (in thousands):

 

		December 31,
		2014				2013
Oil and natural gas properties:
Proved properties		$	1,044,469			$	926,812
Unproved properties			802,112				97,528
Total oil and natural gas properties			1,846,581				1,024,340
Less accumulated depreciation, depletion and amortization			(131,857	)			(8,596	)
Net oil and natural gas properties		$	1,714,724			$	1,015,744

 

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(b) Costs Incurred in Oil and Natural Gas Property Acquisition and Development Activities

A summary of the Company’s cost incurred in oil and natural gas property acquisition and development activities is set forth below (in thousands):

 

		December 31,
		2014				2013				2012
Acquisition costs:
Proved properties		$	—			$	40,914			$	2,498
Unproved properties			134,156				621,039				158,131
Development cost			714,796				258,825				16,344
Exploration cost			21,186				3,022				3,899
Total acquisition, development and exploration costs		$	870,138			$	923,800			$	180,872

(c) Reserve Quantity Information

The following information represents estimates of the Company’s proved reserves as of December 31, 2014 and December 31, 2013, which have been prepared and presented under SEC rules. These rules require companies to prepare their reserve estimates using specified reserve definitions and pricing based on a 12-month unweighted average of the first-day-of-the-month pricing. The pricing that was used for estimates of the Company’s reserves as of December 31, 2014 and December 31, 2013 was based on an unweighted average 12-month average West Texas Intermediate posted price per Bbl for oil and NGLs and a Henry Hub spot natural gas price per MMBtu for natural gas.

Subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. This requirement may limit the Company’s potential to record additional proved undeveloped reserves as it pursues its drilling program, particularly as it develops its significant acreage in the Appalachian Basin of Ohio. Moreover, the Company may be required to write down its proved undeveloped reserves if it does not drill on those reserves within the required five-year timeframe. The Company does not have any proved undeveloped reserves which have remained undeveloped for five years or more.

The Company’s proved oil and natural gas reserves are all located in the United States, within the State of Ohio. All of the estimates of the proved reserves at December 31, 2014 and December 31, 2013, were prepared by Netherland, Sewell & Associates, Inc. (“NSAI”), independent petroleum engineers. Proved reserves were estimated in accordance with the guidelines established by the SEC and the FASB.

Oil and natural gas reserve quantity estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing and production may cause either upward or downward revision of previous estimates.

Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and natural gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future.

 

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The following table provides a roll-forward of the total proved reserves for the year ended December 31, 2014, 2013, and 2012 as well as proved developed and proved undeveloped reserves at the beginning and end of each respective year:

 

		Natural Gas (MMCF)				Natural Gas Liquids (MBbl)				Oil (MBbl)				TOTAL (MMcfe)
End of year, December 31, 2011			—				—				—				—
Extensions and discoveries			2,963.8				177.0				390.5				6,368.9
Production			(7.7	)			—				(4.5	)			(34.7	)
End of year, December 31, 2012			2,956.1				177.0				386.0				6,334.2
Revisions			2,645.0				52.1				(163.2	)			1,978.4
Extensions and discoveries			41,215.5				1,710.6				1,323.3				59,419.0
Acquisition of reserves			6,646.6				—				958.5				12,397.6
Production			(1,118.8	)			(1.3	)			(87.2	)			(1,650.2	)
End of year, December 31, 2013			52,344.4				1,938.4				2,417.4				78,478.6
Revisions			(12,091.2	)			(739.7	)			(462.6	)			(19,305.3	)
Extensions and discoveries			235,816.9				10,216.3				4,337.5				323,140.1
Production			(19,760.2	)			(536.0	)			(594.9	)			(26,545.5	)
End of year, December 31, 2014			256,309.9				10,879.0				5,697.4				355,767.9
Proved developed reserves:
December 31, 2012			1,289.6				64.6				174.5				2,724.0
December 31, 2013			27,880.3				1,056.2				1,708.1				44,466.6
December 31, 2014			132,959.5				6,758.6				3,880.9				196,796.4
Proved undeveloped reserves:
December 31, 2012			1,666.6				112.4				211.5				3,610.1
December 31, 2013			24,464.1				882.2				709.2				34,012.0
December 31, 2014			123,350.4				4,120.4				1,816.4				158,971.5

Extensions and discoveries of 323,140.1 MMCFE and 59,419 MMCFE during the years ended December 31, 2014 and December 31, 2013, respectively, resulted primarily from the drilling of new wells during each year and from new proved undeveloped locations added during each year.

 

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(d) Standardized Measure of Discounted Future Net Cash Flows

The standardized measure of discounted future net cash flows does not purport to be, nor should it be interpreted to present, the fair value of the oil and natural gas reserves of the property. An estimate of fair value would take into account, among other things, the recovery of reserves not presently classified as proved, the value of unproved properties, and consideration of expected future economic and operating conditions. The estimates of future cash flows and future production and development costs as of December 31, 2014 and 2013 are based on the unweighted arithmetic average first-day-of-the-month price for the preceding 12-month period. Estimated future production of proved reserves and estimated future production and development costs of proved reserves are based on current costs and economic conditions. All wellhead prices are held flat over the forecast period for all reserve categories. The estimated future net cash flows are then discounted at a rate of 10%. The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is as follows at December 31, 2014 and 2013 (in thousands):

 

		December 31,
		2014				2013				2012
Future cash inflows (total revenues)		$	1,870,319			$	479,527			$	50,614
Future production costs (severance and ad valorem taxes plus LOE)			(728,041	)			(116,161	)			(6,448	)
Future development costs (capital costs)			(350,187	)			(76,511	)			(8,015	)
Future income tax expense			(277,500	)			—				—
Future net cash flows			514,591				286,855				36,151
10% annual discount for estimated timing of cash flows			(183,934	)			(131,560	)			(14,257	)
Standardized measure of Discounted Future Net Cash Flow		$	330,657			$	155,295			$	21,894

It is not intended that the FASB’s standardized measure of discounted future net cash flows represent the fair market value of the Company’s proved reserves. The Company cautions that the disclosures shown are based on estimates of proved reserve quantities and future production schedules which are inherently imprecise and subject to revision, and the 10% discount rate is arbitrary. In addition, costs and prices as of the measurement date are used in the determinations, and no value may be assigned to probable or possible reserves.

(e) Changes in the Standardized Measure of Discounted Future Net Cash Flows

A summary of the changes in the standardized measure of discounted future net cash flows are contained in the table below (in thousands):

 

		December 31,
		2014				2013				2012
Standardized Measure, beginning of the year		$	155,295			$	21,894			$	—
Net change in prices and production costs			(52,642	)			(5,354	)			354
Net change in future development costs			(2,122	)			(1,148	)			—
Sales, Less production costs			(104,099	)			(10,281	)			(354	)
Extensions			491,067				106,720				21,894
Acquisitions			—				28,984				—
Revisions of previous quantity estimates			(38,201	)			8,354				—
Previously estimated development costs incurred			16,807				—				—
Accretion of discount			15,529				2,189				—
Net change in taxes			(178,732	)			—				—
Changes in timing and other			27,755				3,937				—
Period Balance		$	330,657			$	155,295			$	21,894

 

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REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS

Board of Managers of Eclipse Resources I, LP

Eclipse Resources-Ohio, LLC

We have audited the accompanying financial statements of Eclipse Resources-Ohio, LLC (an Ohio limited liability company), formerly The Oxford Oil Company, which comprise the balance sheets as of June 25, 2013 and December 31, 2012 and the related statements of operations, comprehensive loss, member’s equity, and cash flows for the period from January 1, 2013 through June 25, 2013 and for the year ended December 31, 2012, and the related notes to the financial statements.

Management’s responsibility for the financial statements

Management is responsible for the preparation and fair presentation of these financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.

Auditor’s responsibility

Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Eclipse Resources-Ohio, LLC as of June 25, 2013 and December 31, 2012, and the results of its operations and its cash flows for the period from January 1, 2013 through June 25, 2013 and for the year ended December 31, 2012, in accordance with accounting principles generally accepted in the United States of America.

/s/ GRANT THORNTON LLP

Cleveland, Ohio

February 21, 2014

 

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ECLIPSE RESOURCES-OHIO, LLC

BALANCE SHEETS

(in thousands)

 

		June 25, 2013				December 31, 2012
ASSETS
CURRENT ASSETS
Cash and cash equivalents		$	653			$	480
Accounts receivable			2,535				2,584
Materials inventory			1,913				687
Other current assets			118				193
Total current assets			5,219				3,944
PROPERTY AND EQUIPMENT, AT COST
Oil and natural gas properties, successful efforts method
Unproved properties			4,096				267
Proved oil and gas properties			101,490				101,150
Accumulated depletion, depreciation and amortization			(36,830	)			(31,423	)
Total oil and natural gas properties, net			68,756				69,994
Other property and equipment, net			1,904				1,894
Total property and equipment, net			70,660				71,888
TOTAL ASSETS		$	75,879			$	75,832
LIABILITIES AND MEMBER’S EQUITY
CURRENT LIABILITIES
Accounts payable		$	1,327			$	1,526
Accrued liabilities			945				805
Total current liabilities			2,272				2,331
NONCURRENT LIABILITIES
Asset retirement obligations			9,649				9,179
Pension liability			2,522				3,918
Total non-current liabilities			12,171				13,097
Total liabilities			14,443				15,428
COMMITMENTS AND CONTINGENCIES
MEMBER’S EQUITY
Member’s equity			63,036				63,790
Accumulated other comprehensive loss			(1,600	)			(3,386	)
Total member’s equity			61,436				60,404
TOTAL LIABILITIES AND MEMBER’S EQUITY		$	75,879			$	75,832

The accompanying notes are an integral part of these financial statements.

 

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ECLIPSE RESOURCES-OHIO, LLC

STATEMENTS OF OPERATIONS

(in thousands)

 

		January 1, 2013 through June 25, 2013				Year ended December 31, 2012
REVENUES
Oil and natural gas sales		$	7,703			$	13,566
Total revenues			7,703				13,566
OPERATING EXPENSES
Exploration			183				409
Lease operating			2,160				4,909
Production and ad valorem taxes			87				166
Depletion, depreciation and amortization			5,525				10,878
General and administrative			2,532				3,508
Accretion of asset retirement obligation			470				867
Total operating expenses			10,957				20,737
Gain on sale of properties			—				2,849
OPERATING LOSS			(3,254	)			(4,322	)
NET LOSS		$	(3,254	)		$	(4,322	)

The accompanying notes are an integral part of these financial statements.

 

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ECLIPSE RESOURCES-OHIO, LLC

STATEMENTS OF COMPREHENSIVE LOSS

(in thousands)

 

		January 1, 2013 through June 25, 2013				Year ended December 31, 2012
NET LOSS		$	(3,254	)		$	(4,322	)
Other comprehensive loss:
Pension obligation adjustment			(1,786	)			1,772
TOTAL COMPREHENSIVE LOSS		$	(5,040	)		$	(2,550	)

The accompanying notes are an integral part of these financial statements.

 

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ECLIPSE RESOURCES-OHIO, LLC

STATEMENTS OF MEMBER’S EQUITY

FOR THE PERIOD JANUARY 1, 2013 TO JUNE 25, 2013 AND

THE YEAR ENDED DECEMBER 31, 2012

(in thousands)

 

		Member’s Equity				Accumulated Other Comprehensive Loss				Total Member’s Equity
Balance, December 31, 2011		$	72,831			$	(1,614	)		$	71,217
Net loss			(4,322	)			—				(4,322	)
Distributions			(4,719	)			—				(4,719	)
Change in accumulated other comprehensive loss			—				(1,772	)			(1,772	)
Balance, December 31, 2012		$	63,790			$	(3,386	)		$	60,404
Net loss			(3,254	)			—				(3,254	)
Contributions			2,500				—				2,500
Change in accumulated other comprehensive loss			—				1,786				1,786
Balance, June 25, 2013		$	63,036			$	(1,600	)		$	61,436

The accompanying notes are an integral part of these financial statements.

 

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ECLIPSE RESOURCES-OHIO, LLC

STATEMENTS OF CASH FLOWS

(in thousands)

 

		January 1, 2013 through June 25, 2013				Year ended December 31, 2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss		$	(3,254	)		$	(4,322	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization			5,525				10,878
Accretion of asset retirement obligation			470				867
Gain on sale of properties			—				(2,849	)
Pension obligations			390				532
Changes in operating assets and liabilities
Accounts receivable			49				1,485
Materials inventory			(1,226	)			259
Other current assets			75				(17	)
Accounts payable			(199	)			(2,632	)
Accrued liabilities			140				(156	)
Net cash provided by operating activities			1,970				4,045
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures on crude oil and natural gas properties			(4,297	)			(7,398	)
Proceeds from sale of assets			—				4,400
Net cash used in investing activities			(4,297	)			(2,998	)
CASH FLOWS FROM FINANCING ACTIVITIES
Distributions			—				(1,458	)
Contributions			2,500				—
Net cash provided by (used in) financing activities			2,500				(1,458	)
Net change in cash and cash equivalents			173				(411	)
Cash and cash equivalents at beginning of period			480				891
Cash and cash equivalents at end of period		$	653			$	480
SUPPLEMENTAL DISCLOSURE OF NON-CASH FLOW INFORMATION
Asset retirement obligation incurred, including changes in estimate			—				153
Non-cash distribution to Salt Run			—				3,261

The accompanying notes are an integral part of these financial statements.

 

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ECLIPSE RESOURCES-OHIO, LLC

NOTES TO THE FINANCIAL STATEMENTS

FOR THE PERIOD FROM JANUARY 1, 2013 THROUGH JUNE 25, 2013

AND FOR THE YEAR ENDED DECEMBER 31, 2012

Note 1—Organization and Nature of Operations

Eclipse Resources-Ohio, LLC (the “Company”) was formed on June 18, 2013 as an Ohio limited liability company and is the successor-in-interest to The Oxford Oil Company, an Ohio S corporation (“Oxford”), organized in 1947 with a principle place of business in Zanesville, Ohio.

The Company was formed to facilitate the sale of all of the outstanding equity interests of Oxford, which owned crude oil, natural gas and natural gas liquid reserves and unevaluated acreage in the Appalachian Basin in Ohio (see Note 7—Subsequent Events ). On June 26, 2013, Oxford was merged with and into the Company, with the Company being the surviving entity (the “Merger”). Prior to the Merger, both Oxford and the Company were 100% owned by Salt Run Capital, Inc., an Ohio corporation (“Salt Run”), and subsequent to the Merger, but prior to the acquisition by Eclipse Resources I, LP, all of the member interests of the Company were held by Salt Run. As such, the Merger has been treated as a reorganization of entities under common control and the historical results presented herein are those of Oxford for all periods. The financial statements of the Company, prior to the Merger, were not significant; therefore, no pro forma financial information is presented.

Note 2—Basis of Presentation

These financial statements and related notes are presented in accordance with accounting principles generally accepted in the United States of America (“GAAP”). Preparation in accordance with GAAP requires us to (1) adopt accounting policies within accounting rules set by the Financial Accounting Standards Board (“FASB”) and (2) make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and other disclosed amounts. Note 3—Summary of Significant Accounting Policies describes our significant accounting policies. Our management believes the major estimates and assumptions impacting our consolidated financial statements are the following:

 

•

estimates of proved reserves of oil and natural gas, which affect the calculations of depletion, depreciation and amortization and impairment of capitalized costs of oil and natural gas properties;

 

•

estimates of asset retirement obligations;

 

•

estimates of the fair value of oil and natural gas properties we own, particularly properties that we have not yet explored, or fully explored, by drilling and completing wells;

 

•

impairment of undeveloped properties and other assets; and

 

•

depreciation and depletion of property and equipment.

The estimated fair values of our unevaluated oil and natural gas properties affects our assessment of unevaluated capitalized costs.

Actual results may differ from estimates and assumptions of future events and these revisions could be material. Future production may vary materially from estimated oil and natural gas proved reserves. Actual future prices may vary significantly from price assumptions.

Note 3—Summary of Significant Accounting Policies

(a) Cash and Cash Equivalents

Cash and cash equivalents are comprised of cash in banks and highly liquid instruments with original maturities of three months or less, primarily consisting of bank time deposits and investments in institutional

 

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money market funds. The carrying amounts approximate fair value due to the short-term nature of these items. Cash in bank accounts at times may exceed federally insured limits.

(b) Accounts Receivable

Accounts receivable are carried at estimated net realizable value. Receivables deemed uncollectible are charged directly to expense. Trade credit is generally extended on a short-term basis and therefore, accounts receivable do not bear interest, although a finance charge may be applied to such receivables that are past due. A valuation allowance is provided for those accounts for which collection is estimated as doubtful; uncollectible accounts are written off and charged against the allowance. In estimating the allowance, management considers, among other things, how recently and how frequently payments have been received and the financial position of the party. The Company has established a $0.5 million allowance for a note receivable included in accounts receivable that has been deemed uncollectible as of June 25, 2013. No allowance was required as of December 31, 2012.

The Company accrues unbilled revenue due to timing differences between the delivery of natural gas and crude oil and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Company’s records and management estimates of the related commodity sales and transportation and compression fees which are, in turn, based upon applicable product prices. The Company had unbilled revenues at June 25, 2013 of $2.4 million and December 31, 2012 of $1.8 million, respectively, which were included in accounts receivable within the Company’s balance sheet.

(c) Materials Inventory

Materials inventory are stated at the lower of cost or market and consists of oil and gas drilling or repair items such as tubing, casing and pumping units. These items are primarily acquired for use in future drilling or repair operations and are carried at lower of cost or market. “Market,” in the context of valuation, represents net realizable value, which is the amount that the Company is allowed to bill to the joint interest accounts under joint operating agreements to which the Company is a party. As of June 25, 2013, the Company estimated that all of its tubular goods and equipment will be utilized within one year.

(d) Property and Equipment

Oil and Natural Gas Properties

The Company follows the successful efforts method of accounting for its oil and natural gas operations. Acquisition costs for oil and natural gas properties, costs of drilling and equipping productive wells, and costs of unsuccessful development wells are capitalized and amortized on an equivalent unit-of-production basis over the life of the remaining related oil and gas reserves. The estimated future costs of dismantlement, restoration, plugging and abandonment of oil and gas properties and related facilities disposal are capitalized when asset retirement obligations are incurred and amortized as part of depreciation, depletion and amortization expense (see “Depreciation, depletion and amortization (DD&A)” section below).

Costs incurred to acquire producing and non-producing leaseholds are capitalized. When conditions warrant, the Company capitalizes interest on unproved properties. All unproved leasehold acquisition costs are initially capitalized, including the cost of leasing agents, title work and due diligence. If the Company acquires leases in a prospective area, these costs are capitalized as unproved leasehold costs. If no leases are acquired by the Company with respect to the initial costs incurred or the Company discontinues leasing in a prospective area, the costs are charged to exploration expense. These costs are reviewed regularly and a final determination for unproved leasehold costs is made within one year of the costs being incurred. Unproved leasehold costs that are determined to have proved oil and gas reserves are transferred to producing leasehold costs.

 

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A summary of property and equipment including oil and natural gas properties is as follows (in thousands):

 

		June 25, 2013				December 31, 2012
Oil and natural gas properties:
Subject to depletion		$	101,490			$	101,150
Not subject to depletion			4,096				267
Gross oil and natural gas properties			105,586				101,417
Less accumulated depreciation, depletion and amortization			(36,830	)			(31,423	)
Oil and natural gas properties, net			68,756				69,994
Other property and equipment			5,945				5,816
Less accumulated depreciation			(4,041	)			(3,922	)
Other property and equipment, net			1,904				1,894
Property and equipment, net		$	70,660			$	71,888

Exploration expenses, including geological and geophysical expenses and delay rentals for unevaluated oil and gas properties are charged to expense as incurred. Exploratory drilling costs are initially capitalized as unproved property, not subject to depletion, but charged to expense if and when the well is determined not to have found proved oil and gas reserves. Exploratory drilling costs are evaluated and a determination of classification is made within one-year from the completion of drilling. As of June 25, 2013 and December 31, 2012, there were no costs capitalized in connection with exploratory wells in progress.

Upon the sale or retirement of a complete field of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to the Company’s statements of operations. Upon the sale of an individual well, the proceeds are credited to accumulated depreciation and depletion within the Company’s balance sheets. Upon sale of an entire interest in an unproved property where the property had been assessed for impairment individually, a gain or loss is recognized in the Company’s consolidated statements of operations. If a partial interest in an unproved property is sold, any funds received are accounted for as a reduction of the cost in the interest retained.

Other Property and Equipment

Other property and equipment includes land, buildings, vehicles, computer equipment and software, telecommunications equipment, and furniture and fixtures. These items are recorded at cost.

(e) Revenue Recognition

Oil and natural gas sales revenue is recognized when produced quantities of oil and natural gas are delivered to a custody transfer point such as a pipeline, processing facility or a tank lifting has occurred, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sales is reasonably assured and the sales price is fixed or determinable. Revenues from the production of natural gas, crude oil or natural gas liquids in which the Company has an interest with other producers are recognized on the basis of the Company’s net revenue interest.

In accordance with the terms of joint operating agreements, from time to time, the Company may be paid monthly fees for operating or drilling wells for outside owners. The fees are meant to recoup some of the operator’s general and administrative costs in connection with well and drilling operations and are accounted for as credits to general and administrative expense.

 

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(f) Major Customers

The Company sells production volumes to various purchasers. From January 1, 2013 through June 25, 2013 and for the year ended December 31, 2012, there were two customers that accounted for 10% or more of total natural gas, natural gas liquids (NGLs) and oil sales. Management believes that the loss of any one customer would not have an adverse effect on the Company’s ability to sell natural gas, NGL and oil production. The following table sets forth the Company’s major customers and associated percentage of revenue for the periods indicated:

 

		January 1, 2013 through June 25, 2013				Year Ended December 31, 2012
Devco Oil Inc.			42.5	%			48.2	%
Ergon Inc.			20.4	%			23.2	%
Total			62.9	%			71.4	%

(g) Accumulated Other Comprehensive Loss

Comprehensive loss includes net loss and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under accounting principles generally accepted in the United States, have not been recognized in the calculation of net loss. These changes, other than net loss, are referred to as “other comprehensive loss” and for the Company they include pension benefit plans that require an employer to recognize the overfunded or underfunded status of a defined benefit retirement plan as an asset or liability in its balance sheet and to recognize changes in that funded status in the year in which the changes occur through other comprehensive loss. The Company’s pension plan was under-funded by $2.5 million and $3.9 million at June 25, 2013 and December 31, 2012, respectively.

(h) Depreciation, depletion and amortization (DD&A)

Oil and Natural Gas Properties

Depreciation, depletion, and amortization (DD&A) of capitalized costs of proved oil and natural gas properties is computed using the unit-of-production method on a field basis using total estimated proved reserves. The reserve base used to calculate DD&A for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. The reserve base used to calculate DD&A for drilling, completion and well equipment costs, which include development costs and successful exploration drilling costs, includes only proved developed reserves. DD&A expense for the period from January 1, 2013 through June 25, 2013 and for the year ended December 31, 2012 totaled approximately $5.4 million and $10.6 million, respectively.

Other Property and Equipment

Depreciation expense on other property and equipment is calculated using straight-line methods based on expected lives of the individual assets or groups of assets ranging from 5 to 40 years. Depreciation for the period from January 1, 2013 through June 25, 2013 and for the year ended December 31, 2012, totaled approximately $0.1 million and $0.2 million, respectively, and is included in depreciation, depletion, and amortization expense in the statements of operations.

(i) Impairment of Long-Lived Assets

The Company reviews its long lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated

 

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future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount for that asset to its estimated fair value if such carrying amount exceeds the fair value.

The review of the Company’s oil and gas properties is done on a field level basis by determining if the historical cost of proved properties, less the applicable accumulated depletion, depreciation and amortization and abandonment, is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on the Company’s plans to continue to produce and develop proved reserves. Expected future cash flow from the sale of production of reserves is calculated based on estimated future prices. The Company estimates prices based upon current contracts in place, adjusted for basis differentials and market related information including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets.

The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results.

Unproved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. An impairment charge is recorded if conditions indicate the Company will not explore the acreage prior to expiration of the applicable leases. There were no impairments of unproved oil and gas properties for the period from January 1, 2013 through June 25, 2013 or for the year ended December 31, 2012.

Proved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. There were no impairments of proved oil and gas properties for the period from January 1, 2013 through June 25, 2013 and for the year ended December 31, 2012.

(j) Income Taxes

During the periods presented, the Company was a wholly-owned Qualified Subchapter S subsidiary (“Q Sub”) of Salt Run Capital, Inc., which is taxed as an S corporation. Accordingly, the Company’s operations have been included within the tax filings of Salt Run and are passed through to its shareholder for U.S federal and state income tax purposes. As a result, the Company has not been subject to U.S. federal and most state income taxes as the shareholder of Salt Run is liable for any income tax on such earnings.

Accounting Standards Codification (“ASC”) 740 provides that a tax benefit from an uncertain tax position may be recognized when it is more likely than not that the position will be sustained upon examination, including resolutions of any related appeals or litigation processes, based on the technical merits. Income tax positions must meet a more-likely-than-not recognition threshold at the effective date to be recognized upon the adoption of the uncertain tax position guidance and in subsequent periods. This interpretation also provides guidance on measurement, derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition.

Given the above discussion and the Company’s historical pass through status, the Company has determined that no federal or state income tax liability for uncertain tax positions is required to be recorded as of the adoption date nor for the years presented in the accompanying financial statements.

 

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(k) Fair Value of Financial Instruments

The Company has established a hierarchy to measure its financial instruments at fair value which requires it to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The hierarchy defines three levels of inputs that may be used to measure fair value:

Level 1—Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date.

Level 2—Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market date for substantially the entire contractual term of the asset or liability.

Level 3—Unobservable inputs that reflect the entity’s own assumptions about the assumption market participants would use in the pricing of the asset or liability and are consequently not based on market activity but rather through particular valuation techniques.

The estimated fair values of the Company’s financial instruments closely approximate the carrying amounts due to the short maturity of these instruments.

(l) Asset Retirement Obligation

The Company recognizes a legal liability for its asset retirement obligations (“ARO”) in accordance with the FASB’s Accounting Standards Codification (“ASC”) Topic ASC 410, “Asset Retirement and Environmental Obligations,” associated with the retirement of a tangible long-lived asset, in the period in which it is incurred or becomes determinable, with an associated increase in the carrying amount of the related long-lived asset. The cost of the tangible asset, including the initially recognized asset retirement cost, is depreciated over the useful life of the asset and accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. The Company measures the fair value of its ARO using expected future cash outflows for abandonment discounted back to the date that the abandonment obligation was measured using an estimated credit adjusted rate of 10.50% for the period January 1, 2013 through June 25, 2013 and for year ended December 31, 2012.

Estimating the future ARO requires management to make estimates and judgments based on historical estimates regarding timing and existence of a liability, as well as what constitutes adequate restoration. Inherent in the fair value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset.

The following table sets forth the changes in the Company’s ARO liability for the periods indicated (in thousands):

 

		January 1, 2013 through June 25, 2013				Year Ended December 31, 2012
Asset retirement obligation at beginning of period		$	9,179			$	8,159
Liabilities incurred			—				153
Accretion			470				867
Asset retirement obligation at end of period		$	9,649			$	9,179

 

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The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition. Additions to ARO represent a significant nonrecurring Level 3 measurement.

(m) Off-Balance Sheet Arrangements

The Company does not have any off-balance sheet arrangements.

(n) Segment Reporting

The Company operates in one industry segment: the oil and natural gas exploration and production industry in the United States. All of its operations are conducted in one geographic area of the United States. All revenues are derived from customers located in the United States.

(o) Recent Accounting Pronouncements

The FASB issued Accounting Standard Update (“ASU”) 2011-11, “Disclosures about Offsetting Assets and Liabilities” in December 2011, and issued ASU 2013-01, “Clarifying the Scope of Disclosures About Offsetting Assets and Liabilities” in January 2013. These ASUs create new disclosure requirements regarding the nature of an entity’s rights of setoff and related arrangements associated with its derivative instruments, repurchase agreements and securities lending transactions. Certain disclosures of the amounts of certain instruments subject to enforceable master netting arrangements would be required, irrespective of whether the entity has elected to offset those instruments in the statement of financial position. These ASUs are effective retrospectively for annual reporting periods beginning on or after January 1, 2013. The adoption of these ASUs will not impact the Company’s financial position, results of operations or liquidity.

The FASB issued ASU 2013-02, “Comprehensive Income (Topic 220)—Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income” in February 2013. The amendments do not change the current requirements for reporting net income or other comprehensive income in financial statements. These amendments require an entity to provide information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, an entity is required to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income but only if the amount reclassified is required under U.S. GAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under U.S. GAAP to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures required under U.S. GAAP that provide additional details about those amounts.

Note 4—Sale of Oil and Natural Gas Property Interests

During the year end December 31, 2012, the Company sold all of its interest in a producing oil and gas field for $4.4 million. The sales proceeds exceeded the Company’s cost basis, resulting in a gain of $2.8 million during 2012.

Note 5—Benefit Plans

The Company maintains a defined benefit pension plan covering 34 of its employees, of which two are retired, four have deferred vested termination, and one is a survivor. Benefits are based on the employee’s years of service and compensation. The Company’s plans are funded in conformity with the funding requirements of ASC Topic 715 “Compensation—Retirement Benefits” as of June 25, 2013 and December 31, 2012.

 

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The authoritative guidance for defined benefit pension plans requires an employer to recognize the overfunded or underfunded status as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through other comprehensive income.

A summary of the pension benefit within the below tables is as follows (in thousands):

 

		January 1, 2013 through June 25, 2013				Year Ended December 31, 2012
Change in benefit obligation
Benefit obligation at beginning of year		$	10,096			$	7,025
Service cost			165				249
Interest cost			201				409
Actuarial (gain) loss			(1,194	)			2,461
Benefit paid			(223	)			(48	)
Benefit obligation at end of year		$	9,045			$	10,096

 

		January 1, 2013 through June 25, 2013				Year Ended December 31, 2012
Change in plan assets
Fair value of plan assets at beginning of year		$	6,177			$	5,411
Actual return on plan assets			569				805
Employer contributions			—				9
Benefits paid			(223	)			(48	)
Fair value of plan assets at end of year		$	6,523			$	6,177

The funding levels of all qualified pension plans are in compliance with standards set by applicable law or regulation. As shown in the table below, the current pension plan is underfunded. All defined benefit pension obligations, regardless of the funding status of the underlying plans, are fully supported by the financial strength of the Company.

 

		June 25, 2013				Year Ended December 31, 2012
Assets in excess of (less than) benefit obligation
Vested amount		$	(6,787	)		$	(7,324	)
Additional benefits required			(2,258	)			(2,771	)
Projected benefit obligation			(9,045	)			(10,095	)
Funded amount			6,523				6,177
Unfunded amount		$	(2,522	)		$	(3,918	)

 

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		June 25, 2013				Year Ended December 31, 2012
Other amounts recognized in other comprehensive loss
Assets in excess of (less than) benefit obligation at end of period		$	(2,522	)		$	(3,918	)
Amounts recorded in the consolidated balance sheet consist of:
Accrued benefit liability			(2,522	)			(3,918	)
Total recorded		$	(2,522	)		$	(3,918	)
Amounts recorded in accumulated other comprehensive loss consist of:
Transition obligation		$	(1,207	)		$	(1,416	)
Net gain (loss)			(393	)			(1,970	)
Total recorded in accumulated other comprehensive loss		$	(1,600	)		$	(3,386	)

The long-term expected rate of return on funded assets shown below is established for each benefit plan by developing a forward-looking, long-term return assumption for each asset class, taking into account factors such as the expected real return for the specific asset class and inflation. A single, long-term rate of return is then calculated as the weighted average of the target asset allocation percentages and the long-term return assumption for each asset class. The discount rate is determined by constructing a portfolio of high-quality, noncallable bonds with cash flows that match estimated outflows for benefit payments.

 

		June 25, 2013				Year Ended December 31, 2012
Weighted average assumptions to determine benefit obligation
Discount rate			4.50	%			4.00	%
Expected rate of return			6.00	%			6.00	%
Rate of compensation increase			4.00	%			4.00	%
Inflation			3.00	%			3.00	%

 

		January 1, 2013 through June 25, 2013				Year Ended December 31, 2012
Components of net periodic benefit cost
Service cost		$	165			$	249
Interest cost			201				409
Expected return on plan assets			(185	)			(323	)
Amortization of transition obligation			209				197
Net period benefit cost		$	390			$	532

The following benefit payments are expected to be paid over the next ten years (in thousands):

 

2014		$	50
2015			49
2016			104
2017			175
2018			222
2019—2023		$	2,422

The Company’s investment strategy for benefit plan assets reflects a long-term view, a careful assessment of the risks inherent in various asset classes and broad diversification to reduce the risk of the portfolio. Studies are periodically conducted to establish the preferred target asset allocation percentages. The Company along with its

 

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investment manager determines the investment policies and strategies for the plan assets to determine the allocations to the various asset classes based on the results of the studies targeted percentages. The following tables below set forth the breakout of asset categories (in thousands):

 

		June 25, 2013				Year Ended December 31, 2012
Plan assets by category
Equity securities		$	6,223			$	5,877
Debt securities			133				115
Cash			167				185
Total Assets		$	6,523			$	6,177
		June 25, 2013				Year Ended December 31, 2012
Plan assets by category
Equity securities			95.4	%			95.1	%
Debt securities			2.0	%			1.9	%
Cash			2.6	%			3.0	%
Total Assets			100	%			100	%

The following tables set forth by level, within the fair value hierarchy, the fair value of pension assets and liabilities as of June 25, 2013 and December 31, 2012 (in thousands):

 

		June 25, 2013
		Level 1				Level 2				Level 3				Total
Pension assets		$	6,390				133				—			$	6,523

 

		December 31, 2012
		Level 1				Level 2				Level 3				Total
Pension assets		$	6,062				115				—			$	6,177

The fair value measurement levels are accounting terms that refer to different methods of valuing assets. The terms do not represent the relative risk or credit quality of an investment.

Note 6—Commitments and Contingencies

West Matter

In October 2011, Oxford filed a lawsuit in the Common Pleas Court of Belmont County, Ohio against Barry M. West and other landowners holding an interest in property subject to an oil and gas lease held by Oxford (the “West lawsuit”). The lawsuit was filed after the defendant landowners prevented Oxford from drilling a well on the property subject to the oil and gas lease. Oxford brought claims for breach of contract, unjust enrichment, and promissory estoppel, and sought a declaratory judgment that Oxford had a valid and enforceable lease with the defendant landowners. The defendant landowners filed counterclaims for defective execution of the lease, fraud, bad faith, breach of the implied duty to develop, improper assignment of the lease, and a claim that the lease was void as a lease in perpetuity contrary to law and the public policies of the State of Ohio. The Company filed a motion for summary judgment on July 15, 2013, and the defendant landowners filed their motion for summary judgment on August 26, 2013. On October 4, 2013, the trial court granted the defendant’s motion for summary judgment and held that the lease in question was “void ab initio” because the lease is a “no-term lease” and a “lease in perpetuity.” On October 8, 2013, the Company appealed the trial court’s judgment to the Seventh District Court of Appeals of the State of Ohio.

 

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The judgment of the trial court has been stayed pending the outcome of this appeal. The Company believes that the trial court erred in finding that the lease in question was a perpetual lease, and that the judgment of the trial court that perpetual leases are “void ab initio” is not consistent with applicable Ohio law. However, since the ruling in the West lawsuit, adverse parties in other lawsuits in which the Company is involved have amended their complaints to make allegations similar to those made by the lessor in the West lawsuit, and the Company may be subject to additional lawsuits alleging that our leases are void. If the appeals court does affirm the court ruling and if other courts in Ohio adopt a similar interpretation of the language in our other leases with similar term language, such leases may also be determined to be void if the lessor challenges the validity of the lease. Consequently, this could result in a loss of the mineral rights and an impairment of the related assets which could have a material adverse impact on the Company’s financial statements.

The Company believes that there are strong grounds for appeal, and therefore, the Company intends to pursue all available appellate rights, and to vigorously defend against the claims in this lawsuit. Based on the merits of the appeal, the Company believes that it is not probable that trial court’s decision will be upheld in the appeal or that the Company will incur a material loss in the lawsuit, and accordingly, the Company has not recorded an accrual for the potential losses attributable to this lawsuit.

Other Matters

From time to time, the Company may be a party to legal proceedings arising in the ordinary course of business. Management does not believe that a material loss is probable as a result of such proceedings.

Additionally, the Company is subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes environmental protection requirements that result in increased costs to the oil and natural gas industry in general, the business and prospects of the Company could be adversely affected.

The development of the Company’s oil and natural gas properties under their related leases will require a significant amount of capital. The timing of those expenditures will be determined by the lease provisions, the term of the lease and other factors associated with unproved leasehold acreage. To the extent that the Company is not the operator of oil and natural gas properties that it owns an interest in, the timing, and to some degree the amount, of capital expenditures will be controlled by the operator of such properties.

Note 7—Subsequent Events

On June 26, 2013, Eclipse Resources I, LP purchased 100% of the outstanding membership interests of the Company for a net cash purchase price of $652.5 million.

Management has evaluated subsequent events through February 21, 2014, the date the financial statements were available to be issued. Except as described herein, no reportable events have occurred subsequent to June 25, 2013 through the date of issuance of the accompanying financial statements that would, in the opinion of management, have a material impact on the aforementioned statements and related disclosures.

 

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Note 8—Supplemental Oil and Natural Gas Information (unaudited)

(a) Capitalized Costs

A summary of the capitalized costs are contained in the table below (in thousands):

 

		June 25, 2013				Year Ended December 31, 2012
Oil and natural gas properties:
Proved properties		$	101,490			$	101,150
Unproved properties			4,096				267
Total oil and natural gas properties			105,586				101,417
Less accumulated depreciation, depletion and amortization			(36,830	)			(31,423	)
Net oil and natural gas properties capitalized		$	68,756			$	69,994

(b) Costs Incurred in Oil and Natural Gas Property Acquisition and Development Activities

A summary of the Company’s cost incurred in oil and natural gas property acquisition and development activities is set forth below (in thousands):

 

		January 1, 2013 through June 25, 2013				Year Ended December 31, 2012
Acquisition costs:
Proved properties		$	53			$	—
Unproved properties			3,829				—
Development cost			—				—
Exploration expenses			183				409
Total acquisition, development and exploration costs		$	4,065			$	409

(c) Reserve Quantity Information

The following information represents estimates of the Company’s proved reserves as of June 25, 2013, and December 31, 2012, which have been prepared and presented under SEC rules. These rules require companies to prepare their reserve estimates using specified reserve definitions and pricing based on a 12-month unweighted average of the first-day-of-the-month pricing. The pricing that was used for estimates of the Company’s reserves as of June 25, 2013 and December 31, 2012 was based on an unweighted average 12-month average West Texas Intermediate posted price per Bbl for oil and a Henry Hub spot natural gas price per MMBtu for natural gas.

Subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. This requirement may limit the Company’s potential to record additional proved undeveloped reserves as it pursues its drilling program, particularly as it develops its significant acreage in the Appalachian Basin of Ohio. Moreover, the Company may be required to write down its proved undeveloped reserves if it does not drill on those reserves with the required five-year timeframe. The Company does not have any proved undeveloped reserves which have remained undeveloped for five years or more.

The Company’s proved oil and natural gas reserves are all located in the United States, within the state of Ohio. All of the estimates of the proved reserves at June 25, 2013 and December 31, 2012, were prepared by Netherland, Sewell & Associates, Inc. (“NSAI”), independent petroleum engineers. Proved reserves were estimated in accordance with the guidelines established by the SEC and the FASB.

 

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Oil and natural gas reserve quantity estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing and production may cause either upward or downward revision of previous estimates.

Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and natural gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future.

The following table provides a rollforward of the total proved reserves for the year ended December 31, 2012, and the period ended June 25, 2013, as well as proved developed and proved undeveloped reserves at the beginning and end of each respective year:

 

		Oil (MBbl)				Natural Gas (MMcf)				TOTAL (MMcfe)
January 1, 2012			1,139				8,723				15,557
Revisions			(18	)			(733	)			(841	)
Extensions and discoveries			41				381				627
Production			(101	)			(1,479	)			(2,085	)
December 31, 2012			1,061				6,892				13,258
Revisions			(50	)			470				170
Extensions and discoveries			—				1				1
Production			(53	)			(716	)			(1,034	)
End of period, June 25, 2013			958				6,647				12,395
Proved developed reserves:
January 1, 2012			1,139				8,723				15,557
December 31, 2012			1,061				6,892				13,258
Proved developed reserves:
January 1, 2013			1,061				6,892				13,258
June 25, 2013			958				6,647				12,395

Extensions and discoveries of 13 MMcfe and 627 MMcfe during the period ended June 25, 2013 and for the year ended December 31, 2012, resulted from the drilling of new wells during each year. There were no proved undeveloped reserves during the period ended June 25, 2013 and for the year ended December 31, 2012. Thousands of cubic feet of gas equivalent (“Mcfe”) and millions of cubic feet of gas equivalent (“MMcfe”) amounts have been calculated by using the conversion ratio of one barrel of oil (1 bbl) to six thousand cubic feet (6 Mcf) of natural gas.

(d) Standardized Measure of Discounted Future Net Cash Flows

The standardized measure of discounted future net cash flows does not purport to be, nor should it be interpreted to present, the fair value of the oil and natural gas reserves of the property. An estimate of fair value would take into account, among other things, the recovery of reserves not presently classified as proved, the value of unproved properties, and consideration of expected future economic and operating conditions. The estimates of future cash flows and future production and development costs as of June 25, 2013, and December 31, 2012 are based on the unweighted arithmetic average first-day-of-the-month price for the preceding 12-month period. Estimated future production of proved reserves and estimated future production and development costs of proved reserves are based on current costs and economic conditions. All wellhead prices

 

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are held flat over the forecast period for all reserve categories. The estimated future net cash flows are then discounted at a rate of 10%. The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is as follows at June 25, 2013 and December 31, 2012 (in thousands):

 

		June 25, 2013				Year Ended December 31, 2012
Future cash inflows (total revenues)		$	112,472			$	118,778
Future production costs (severance and ad valorem taxes plus LOE)			(44,565	)			(46,045	)
Future development costs (capital costs)			(11,402	)			(11,276	)
Future income tax expense(1)			—				—
Future net cash flows			56,505				61,457
10% annual discount for estimated timing of cash flows			(27,521	)			(30,542	)
Standardized measure of Discounted Future Net Cash Flow		$	28,984			$	30,915

 

(1)

Future net cash flows do not include the effects of income taxes on future revenues because Eclipse Resources-Ohio, LLC was a pass through entity not subject to entity-level income taxation as of June 25, 2013 and December 31, 2012. Accordingly, no provision for federal or state corporate income taxes has been provided because taxable income was passed through.

It is not intended that the FASB’s standardized measure of discounted future net cash flows represent the fair market value of the Company’s proved reserves. The Company cautions that the disclosures shown are based on estimates of proved reserve quantities and future production schedules which are inherently imprecise and subject to revision, and the 10% discount rate is arbitrary. In addition, costs and prices as of the measurement date are used in the determinations, and no value may be assigned to probable or possible reserves.

(e) Changes in the Standardized Measure of Discounted Future Net Cash Flows

A summary of the changes in the standardized measure of discounted future net cash flows are contained in the table below (in thousands):

 

		June 25, 2013				Year Ended December 31, 2012
Standardized measure, beginning of the year		$	30,915			$	43,261
Net change in prices and production costs			(199	)			(5,431	)
Net change in future development costs			(94	)			—
Sales, less production costs			(5,543	)			(8,658	)
Extensions			—				1,555
Revisions of previous quantity estimates			489				(2,996	)
Accretion of discount			3,091				4,326
Changes in timing and other			325				(1,142	)
Period balance		$	28,984			$	30,915

 

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ECLIPSE RESOURCES OPERATING, LLC

BALANCE SHEETS

(in thousands)

(Unaudited)

 

		March 31,				December 31,
		2014				2013
ASSETS
CURRENT ASSETS
Cash		$	1,182			$	1,025
Accounts receivable—related party			590				1,951
Prepaid expenses and other			511				512
Total current assets			2,283				3,488
PROPERTY AND EQUIPMENT, AT COST
Fixed assets			2,470				1,797
Accumulated depreciation			(467	)			(336	)
Total property and equipment			2,003				1,461
TOTAL ASSETS		$	4,286			$	4,949
LIABILITIES & MEMBERS’ EQUITY (DEFICIT)
CURRENT LIABILITIES
Accounts payable		$	911			$	422
Accrued liabilities			1,753				3,245
Deferred revenue			1,608				1,266
Total current liabilities			4,272				4,933
NONCURRENT LIABILITIES
Deferred revenue			17				17
Total liabilities			4,289				4,950
COMMITMENTS AND CONTINGENCIES
MEMBERS’ EQUITY (DEFICIT)
Total members’ equity (deficit)			(3	)			(1	)
TOTAL LIABILITIES AND MEMBERS’ EQUITY (DEFICIT)		$	4,286			$	4,949

The accompanying notes are an integral part of these financial statements.

 

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ECLIPSE RESOURCES OPERATING, LLC

STATEMENTS OF OPERATIONS

(in thousands)

(Unaudited)

 

		Three Months Ended March 31,
		2014				2013
REVENUES
Management fee income		$	7,494			$	1,349
OPERATING EXPENSES
Salaries, wages and employee benefits			5,308				962
Employee recruiting and relocation			498				71
Organizational, legal and professional services			5				3
Travel and business meals			309				30
Facilities, supplies and software			299				75
Depreciation and amortization			131				21
Professional services and other operating			944				186
Total operating expenses			7,494				1,348
OPERATING LOSS			—				1
OTHER INCOME (EXPENSE)
Interest income (expense)			1				(1	)
Total other income/(expense)			1				(1	)
NET INCOME		$	1			$	—

The accompanying notes are an integral part of these financial statements.

 

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ECLIPSE RESOURCES OPERATING, LLC

STATEMENT OF MEMBERS’ EQUITY (DEFICIT)

(in thousands)

(Unaudited)

 

		Total Members’ Equity   (Deficit)
Balance at December 31, 2013		$	(1	)
Distributions			(3	)
Net income			1
Balance at March 31, 2014		$	(3	)

The accompanying notes are an integral part of this financial statement.

 

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ECLIPSE RESOURCES OPERATING, LLC

STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)

 

		Three Months Ended March 31,
		2014				2013
CASH FLOWS FROM OPERATING ACTIVITIES
Net income		$	1			$	—
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense			131				21
Changes in assets and liabilities:
Accounts receivable—related party			1,361				(50	)
Prepaids and other assets			1				25
Accounts payable and accrued liabilities			(1,003	)			126
Deferred revenue			342				—
Net cash provided by operating activities			833				122
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures for property and equipment			(673	)			(41	)
Net cash used in investing activities			(673	)			(41	)
CASH FLOWS FROM FINANCING ACTIVITIES
Repayment of long-term debt			—				(4	)
Capital distributions			(3	)			(6	)
Net cash used in financing activities			(3	)			(10	)
Net increase in cash			157				71
Cash at beginning of year			1,025				11
Cash at end of year		$	1,182			$	82

The accompanying notes are an integral part of these financial statements.

 

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ECLIPSE RESOURCES OPERATING, LLC

NOTES TO FINANCIAL STATEMENTS FOR

THE THREE MONTHS ENDED MARCH 31, 2014 AND 2013

(UNAUDITED)

Note 1—Organization and Nature of Operations

Eclipse Resources Operating, LLC (“Eclipse Operating” or the “Company”), a Delaware limited liability company, was formed on December 20, 2010 to manage the operations of oil and natural gas ventures. Eclipse Operating is owned equally by Benjamin W. Hulburt, Christopher K. Hulburt and Thomas S. Liberatore.

The Company provides management services for Eclipse Resources I, LP (“Eclipse I”). Management services include providing personnel, equipment, office space and other goods and services as needed to manage the operations of Eclipse I. Pursuant to an Administrative Services Agreement with Eclipse I, the Company receives a monthly management fee for these services. Each of the owners of Eclipse Operating also owns direct and indirect interests in Eclipse I.

Note 2—Basis of Presentation

The accompanying financial statements, which are unaudited except the balance sheet at December 31, 2013 which is derived from audited financial statements, are presented in accordance with the requirements of and accounting principles generally accepted in the United States (“U.S. GAAP”) for interim reporting. They do not include all disclosures normally made and contained in annual financial statements. In management’s opinion, all adjustments necessary for a fair presentation of the Company’s financial position, results of operations and cash flows for the periods disclosed have been made. These interim consolidated financial statements should be read in conjunction with the audited financial statements and notes thereto presented in the Company’s financial statements for the year ended December 31, 2013. The results of operations for the three months ended March 31, 2014 may not necessarily be indicative of the results of operations for the full year ending December 31, 2014. Preparation in accordance with GAAP requires the Company to (1) adopt accounting policies within accounting rules set by the Financial Accounting Standards Board (“FASB”) and (2) make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and other disclosed amounts. Note 3—Summary of Significant Accounting Policies describes our significant accounting policies.

Actual results may differ from estimates and assumptions of future events and these differences could be material.

Note 3—Summary of Significant Accounting Policies

(a) Cash

Cash and cash equivalents are comprised of cash in banks and highly liquid instruments with original maturities of three months or less, primarily consisting of bank time deposits and investments in institutional money market funds. The carrying amounts approximate fair value due to the short-term nature of these items. Cash in bank accounts at times may exceed federally insured limits.

(b) Accounts Receivable

Accounts receivable are carried at estimated net realizable value. Receivables deemed uncollectible are charged directly to expense. Trade credit is generally extended on a short-term basis and therefore, accounts receivable do not bear interest, although a finance charge may be applied to such receivables that are past due. A valuation allowance is provided for those accounts for which collection is estimated as doubtful; uncollectible accounts are written off and charged against the allowance. In estimating the allowance, management considers,

 

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among other things, how recently and how frequently payments have been received and the financial position of the party. The Company did not deem any of its accounts receivable uncollectable as of March 31, 2014 or December 31, 2013. The majority of accounts receivable at March 31, 2014 and December 31, 2013 are due from Eclipse I.

(c) Property and Equipment

Property and equipment include vehicles, computer equipment and software, telecommunications equipment, and furniture and fixtures. These items are recorded at cost, or fair value if acquired through a business acquisition. Depreciation is computed using the straight-line method over the estimated useful lives of the assets, or the estimated remaining lease or license term in the case of computer software and leasehold improvements, whichever is shorter. Depreciation expense for the three months ended March 31, 2014 and 2013 was $0.13 million and $0.02 million, respectively.

Capitalized Property and Equipment

During the three months ended March 31, 2014 and 2013, the Company acquired $0.7 million and $0.04 million, respectively, in capitalized property and equipment additions as shown below (in thousands):

 

		For the Three Months Ended March 31,
		2014				2013
Property and Equipment additions
Computer hardware and equipment		$	367			$	25
Computer software			285				—
Furniture and fixtures			13				16
Leasehold improvements			8				—
Total property and equipment additions		$	673			$	41

(d) Revenue Recognition

The Company receives a fee for the management of Eclipse I equal to the actual expenditures incurred for such operations. This reimbursement is recorded by the Company as management fee income. As of March 31, 2014 and December 31, 2013, the Company had received $1.6 million and $1.3 million, respectively, of management fee income that relates to services and costs that will be earned in future periods and is being treated as deferred revenue. Such amounts will be accounted for as revenues during the period to which they relate and are earned.

(e) Impairment

The Company evaluates the recoverability of property and equipment for possible impairment whenever events or circumstances indicate that the carrying amount of such assets may not be recoverable. In addition to the recoverability assessment, the Company routinely reviews the remaining estimated useful lives of property and equipment. If the estimated useful life assumption for any asset is reduced, the remaining unamortized balance would be amortized or depreciated over the revised estimated useful life.

(f) Income Taxes

Eclipse Operating has elected to be taxed as an S Corporation, and as a result, the Company is not subject to U.S. federal and most state income taxes. Accordingly, the Company’s members are liable for income taxes in regards to their distributive share of the Company’s taxable income.

 

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Accounting Standards Codification (“ASC”) 740 provides that a tax benefit from an uncertain tax position may be recognized when it is more likely than not that the position will be sustained upon examination, including resolutions of any related appeals or litigation processes, based on the technical merits. Income tax positions must meet a more-likely-than-not recognition threshold at the effective date to be recognized upon the adoption of the uncertain tax position guidance and in subsequent periods. This interpretation also provides guidance on measurement, derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition.

Given the above discussion and the Company’s historical pass through status, the Company has determined that no federal or state income tax liability for uncertain tax positions is required to be recorded as of the adoption date nor for the years presented in the accompanying financial statements.

(g) Lease Obligations

The Company leases office space under an operating lease that expires in 2016. The lease terms begin on the date of initial possession of the leased property for purposes of recognizing lease expense on a straight-line basis over the term of the lease. Eclipse Operating does not assume renewals in its determination of the lease term unless the renewals are deemed to be reasonably assured at lease inception.

Note 4—Members’ Equity

Each member owns a 33.33% membership interest in the Company. Timing of admission into the Company will result in differing member equity balances, however, under the terms of the Company operating agreement, each member shares equally in the Company’s income or loss, or distributions regardless of their equity in the Company. In addition, taxable income and the allocation of taxable income for distributions may vary substantially from net income reported in the accompanying financial statements.

Note 5—Debt

The Company maintains a $400,000 credit line. The balance is paid monthly with amounts outstanding over 30 days charged an annualized interest rate of 12.99%. There were no amounts past due at either March 31, 2014 or December 31, 2013.

Note 6—Related Party Transactions

The Company manages the operations of Eclipse I under the terms of an Administrative Services Agreement. The members of the Company also own direct and indirect interests in Eclipse I.

In return for performing its duties and obligations under the Administrative Services Agreement (“Agreement”), Eclipse Operating receives a monthly management fee equal to the sum of all costs and expenses incurred, in the management of Eclipse I. These costs include salaries, wages and benefits, rent, insurance, and other expenses and costs required to operate Eclipse I. These expenses are billed in arrears at the actual cost to Eclipse Operating. The reimbursement of these expenses is recognized as management fee income by the Company. In addition, the Company incurs costs related to the acquisition of leases and other oil and gas assets, which costs are passed through to Eclipse I as appropriate.

During the three months ended March 31, 2014 and 2013, the Company recognized $7.5 million and $1.3 million, respectively, in management fee income from Eclipse I. At March 31, 2014 and December 31, 2013, Eclipse I owed the Company $0.5 million and $2.0 million, respectively, in accrued management fees.

The Company periodically incurs expenses for the use of an airplane primarily owned by an officer of the Company. Expenses are billed on a per use basis and totaled $0.04 million and $0 for the three months ended March 31, 2014 and 2013.

 

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Note 7—Commitments and Contingencies

From time to time, the Company may be a party to legal proceedings arising in the ordinary course of business. Eclipse Operating is not currently a party to any legal proceedings and believes the likelihood of being a party to a proceeding that could have a material adverse effect on its financial condition, results of operations or cash flows is remote.

Environmental Matters

The Company is subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes environmental protection requirements that result in increased costs to the oil and natural gas industry in general, the business and prospects of Eclipse Operating could be adversely affected.

Leases

The Company leases 8,072 square feet of office space for its corporate headquarters in State College, Pennsylvania. The space is leased in two parts, 5,246 square feet of which expires in July 2016. The remaining 2,826 square feet expires in July 2015.

Operating lease expense totaled $0.07 million and $0.03 million for the three months ended March 31, 2014 and 2013, respectively.

Note 8—Employee Benefit Plan

The Company currently maintains a retirement plan intended to provide benefits under section 401(K) of the Internal Revenue Code, under which employees are allowed to contribute portions of their compensation to a tax-qualified retirement account. Under the 401(K) plan, the Partnership provides matching contributions equal to 100% of the first 6% of employees’ eligible compensation contributed to the plan. The Company contributed $0.2 million and $0.02 million in matching contributions for the three months ended March 31, 2014 and 2013, respectively.

Note 9—Subsequent Events

Management has evaluated subsequent events through May 2, 2014 and believes that there are no events that would have a material impact on the aforementioned financial statements and related disclosures.

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Managers and Members

Eclipse Resources Operating, LLC

We have audited the accompanying balance sheets of Eclipse Resources Operating, LLC (a Delaware limited liability company) (the “Company”) as of December 31, 2013 and 2012, and the related statements of operations, changes in members’ equity (deficit), and cash flows for each of the two years in the period ended December 31, 2013. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Eclipse Resources Operating, LLC as of December 31, 2013 and 2012, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2013 in conformity with accounting principles generally accepted in the United States of America.

/s/ GRANT THORNTON LLP

Cleveland, Ohio

February 21, 2014

 

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ECLIPSE RESOURCES OPERATING, LLC

BALANCE SHEETS

(in thousands)

 

		December 31,
		2013				2012
ASSETS
CURRENT ASSETS
Cash		$	1,025			$	11
Accounts receivable—related party			1,951				382
Prepaid expenses and other			512				61
Total current assets			3,488				454
PROPERTY AND EQUIPMENT, AT COST
Fixed assets			1,797				361
Accumulated depreciation			(336	)			(106	)
Total property and equipment			1,461				255
TOTAL ASSETS		$	4,949			$	709
LIABILITIES & MEMBERS’ EQUITY (DEFICIT)
CURRENT LIABILITIES
Accounts payable		$	422			$	143
Accrued liabilities			3,245				329
Deferred revenue			1,266				230
Total current liabilities			4,933				702
NONCURRENT LIABILITIES
Deferred revenue			17				—
Total liabilities			4,950				702
COMMITMENTS AND CONTINGENCIES
MEMBERS’ EQUITY (DEFICIT)
Total members’ equity (deficit)			(1	)			7
TOTAL LIABILITIES AND MEMBERS’ EQUITY (DEFICIT)		$	4,949			$	709

The accompanying notes are an integral part of these financial statements.

 

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ECLIPSE RESOURCES OPERATING, LLC

STATEMENTS OF OPERATIONS

(in thousands)

 

		Year Ended December 31,
		2013				2012
REVENUES
Management fee income		$	13,658			$	4,091
OPERATING EXPENSES
Salaries, wages and employee benefits			9,286				3,068
Employee recruiting and relocation			805				181
Oil and gas related			—				6
Organizational, legal and professional services			16				14
Travel and business meals			570				158
Facilities, supplies and software			692				230
Depreciation and amortization			230				72
Professional services and other operating			2,059				362
Total operating expenses			13,658				4,091
OPERATING LOSS			—				—
OTHER INCOME (EXPENSE)
Other income			—				3
Interest expense			(2	)			(3	)
Total other expense			(2	)			—
NET LOSS		$	(2	)		$	—

The accompanying notes are an integral part of these financial statements.

 

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ECLIPSE RESOURCES OPERATING, LLC

STATEMENTS OF MEMBERS’ EQUITY (DEFICIT)

FOR THE YEARS ENDED DECEMBER 31, 2013 AND 2012

(in thousands)

 

		Total Members’ Equity (Deficit)
Balance, December 31, 2011		$	84
Net income			—
Capital distributions			(77	)
Balance, December 31, 2012			7
Net loss			(2	)
Capital distributions			(6	)
Balance, December 31, 2013		$	(1	)

The accompanying notes are an integral part of these financial statements.

 

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ECLIPSE RESOURCES OPERATING, LLC

STATEMENTS OF CASH FLOWS

(in thousands)

 

		Year Ended December 31,
		2013				2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss		$	(2	)		$	—
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and amortization expense			230				72
Changes in assets and liabilities
Accounts receivable—related party			(1,568	)			(27	)
Prepaids and other assets			(453	)			(2	)
Accounts payable and accrued liabilities			3,196				(99	)
Deferred revenue			1,053				110
Net cash provided by operating activities			2,456				54
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures for property and equipment			(1,436	)			(96	)
Net cash used in investing activities			(1,436	)			(96	)
CASH FLOWS FROM FINANCING ACTIVITIES
Capital distributions			(6	)			(77	)
Net cash used in financing activities			(6	)			(77	)
Net increase (decrease) in cash			1,014				(119	)
Cash at beginning of year			11				130
Cash at end of year		$	1,025			$	11

The accompanying notes are an integral part of these financial statements.

 

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ECLIPSE RESOURCES OPERATING, LLC

NOTES TO FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2013 AND 2012

Note 1—Organization and Nature of Operations

Eclipse Resources Operating, LLC (“Eclipse Operating” or the “Company”), a Delaware limited liability company, was formed on December 20, 2010 to manage the operations of oil and natural gas ventures. Eclipse Operating is owned equally by Benjamin W. Hulburt, Christopher K. Hulburt and Thomas S. Liberatore.

The Company provides management services for Eclipse Resources I, LP (“Eclipse I”). Management services include providing personnel, equipment, office space and other goods and services as needed to manage the operations of Eclipse I. Pursuant to an Administrative Services Agreement with Eclipse I, the Company receives a monthly management fee for these services. Each of the owners of Eclipse Operating also owns direct and indirect interests in Eclipse I.

Note 2—Basis of Presentation

These financial statements and related notes are presented in accordance with accounting principles generally accepted in the United States of America (“GAAP”). Preparation in accordance with GAAP requires the Company to (1) adopt accounting policies within accounting rules set by the Financial Accounting Standards Board (“FASB”) and (2) make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and other disclosed amounts. Note 3—Summary of Significant Accounting Policies describes our significant accounting policies.

Actual results may differ from estimates and assumptions of future events and these differences could be material.

Note 3—Summary of Significant Accounting Policies

(a) Cash

Cash and cash equivalents are comprised of cash in banks and highly liquid instruments with original maturities of three months or less, primarily consisting of bank time deposits and investments in institutional money market funds. The carrying amounts approximate fair value due to the short-term nature of these items. Cash in bank accounts at times may exceed federally insured limits.

(b) Accounts Receivable

Accounts receivable are carried at estimated net realizable value. Receivables deemed uncollectible are charged directly to expense. Trade credit is generally extended on a short-term basis and therefore, accounts receivable do not bear interest, although a finance charge may be applied to such receivables that are past due. A valuation allowance is provided for those accounts for which collection is estimated as doubtful; uncollectible accounts are written off and charged against the allowance. In estimating the allowance, management considers, among other things, how recently and how frequently payments have been received and the financial position of the party. The Company did not deem any of its accounts receivable uncollectable as of December 31, 2013 or December 31, 2012. All accounts receivable at December 31, 2013 and 2012 are due from Eclipse I.

(c) Property and Equipment

Property and equipment include vehicles, computer equipment and software, telecommunications equipment, and furniture and fixtures. These items are recorded at cost, or fair value if acquired through a business acquisition. Depreciation is computed using the straight-line method over the estimated useful lives of

 

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the assets, or the estimated remaining lease or license term in the case of computer software and leasehold improvements, whichever is shorter. Depreciation expense for the years ended December 31, 2013 and 2012 was $0.2 million and $0.1 million, respectively.

Capitalized Property and Equipment

During the years ended December 31, 2013 and 2012, the Company acquired $1.4 million and $0.1 million, respectively, in capitalized property and equipment additions as shown below (in thousands):

 

		December 31,
		2013				2012
Property and Equipment additions
Computer hardware and equipment		$	545			$	31
Computer software			702				41
Furniture and fixtures			146				24
Leasehold improvements			43				—
Total property and equipment additions		$	1,436			$	96

(d) Revenue Recognition

The Company receives a fee for the management of Eclipse I equal to the actual expenditures incurred for such operations. This reimbursement is recorded by the Company as management fee income. At December 31, 2013 and 2012, the Company had received $1.3 million and $0.2 million, respectively, of management fee income that relates to services and costs that will be earned in future periods and is being treated as deferred revenue. Such amounts will be accounted for as revenues during the period to which they relate and are earned.

(e) Impairment

The Company evaluates the recoverability of property and equipment for possible impairment whenever events or circumstances indicate that the carrying amount of such assets may not be recoverable. In addition to the recoverability assessment, the Company routinely reviews the remaining estimated useful lives of property and equipment. If the estimated useful life assumption for any asset is reduced, the remaining unamortized balance would be amortized or depreciated over the revised estimated useful life.

(f) Income Taxes

Eclipse Operating has elected to be taxed as an S Corporation, and as a result, the Company is not subject to U.S. federal and most state income taxes. Accordingly, the Company’s members are liable for income taxes in regards to their distributive share of the Company’s taxable income.

Accounting Standards Codification (“ASC”) 740 provides that a tax benefit from an uncertain tax position may be recognized when it is more likely than not that the position will be sustained upon examination, including resolutions of any related appeals or litigation processes, based on the technical merits. Income tax positions must meet a more-likely-than-not recognition threshold at the effective date to be recognized upon the adoption of the uncertain tax position guidance and in subsequent periods. This interpretation also provides guidance on measurement, derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition.

Given the above discussion and the Company’s historical pass through status, the Company has determined that no federal or state income tax liability for uncertain tax positions is required to be recorded as of the adoption date nor for the years presented in the accompanying financial statements.

 

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(g) Lease Obligations

The Company leases office space under an operating leases that expires in 2016. The lease terms begin on the date of initial possession of the leased property for purposes of recognizing lease expense on a straight-line basis over the term of the lease. Eclipse Operating does not assume renewals in its determination of the lease term unless the renewals are deemed to be reasonably assured at lease inception.

Note 4—Members’ Equity

Each member owns a 33.33% membership interest in the Company. Timing of admission into the Company will result in differing member equity balances, however, under the terms of the Company operating agreement, each member shares equally in the Company’s income or loss, or distributions regardless of their equity in the partnership. In addition, taxable income and the allocation of taxable income for distributions may vary substantially from net income reported in the accompanying financial statements.

Note 5—Debt

The Company maintains a $425,000 credit line. The balance is paid monthly with amounts outstanding over 30 days charged an annualized interest rate of 12.99%. There were no outstanding amounts at either December 31, 2013 or 2012.

Note 6—Related Party Transactions

The Company manages the operations of Eclipse I under the terms of an Administrative Services Agreement. The members of the Company also own direct and indirect interests in Eclipse I.

In return for performing its duties and obligations under the Administrative Services Agreement (“Agreement”), Eclipse Operating receives a monthly management fee equal to the sum of all costs and expenses incurred, in the management of Eclipse I. These costs include salaries, wages and benefits, rent, insurance, and other expenses and costs required to operate Eclipse I. These expenses are billed in arrears at the actual cost to Eclipse Operating. The reimbursement of these expenses is recognized as management fee income by the Company. In addition, the Company incurs costs related to the acquisition of leases and other oil and gas assets, which costs are passed through to Eclipse I as appropriate.

During the years ended December 31, 2013 and December 31, 2012, the Company recognized $13.7 million and $4.1 million, respectively, in management fee income from Eclipse I. At December 31, 2013 and December 31, 2012, Eclipse I owed the Company $2.0 million and $0.4 million, respectively, in accrued management fees.

The Company periodically incurs expenses for the use of an airplane primarily owned by an officer of the company. Expenses are billed on a per use basis and totalled $.03 million for the year ended December 31, 2013.

Note 7—Commitments and Contingencies

From time to time, the Company may be a party to legal proceedings arising in the ordinary course of business. Eclipse Operating is not currently a party to any legal proceedings and believes the likelihood of being a party to a proceeding that could have a material adverse effect on its financial condition, results of operations or cash flows is remote.

Environmental Matters

The Company is subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. To the extent laws are enacted or other

 

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governmental action is taken that restricts drilling or imposes environmental protection requirements that result in increased costs to the oil and natural gas industry in general, the business and prospects of Eclipse Operating could be adversely affected.

Leases

Eclipse Operating leases two office space locations in State College, Pennsylvania. The Company leases 8,072 square feet of office space with an initial term of three years with an option to renew for an additional two years. The Company extended this option for an additional year, which expires in 2015.

Following is a schedule, by year, of the future minimum lease payments required under operating lease as of December 31, 2013 (in thousands):

 

2014		$	133
2015			78
Total minimum lease payments		$	211

Operating lease expense totaled $0.2 million and $0.1 million for the years ended December 31, 2013 and December 31, 2012, respectively.

Note 8—Employee Benefit Plan

The Company currently maintains a retirement plan intended to provide benefits under section 401(K) of the Internal Revenue Code, under which employees are allowed to contribute portions of their compensation to a tax-qualified retirement account. Under the 401(K) plan, the Partnership provides matching contributions equal to 100% of the first 6% of employees’ eligible compensation contributed to the plan. The Company contributed $0.2 million and $0.1 million in matching contributions for the year ended December 31, 2013 and 2012, respectively.

Note 9—Subsequent Events

Management has evaluated subsequent events through February 21, 2014 and believes that there are no events that would have a material impact on the aforementioned financial statements and related disclosures.

 

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ANNEX A

 

I.	Glossary of Oil and Natural Gas Companies

The following terms are used in this prospectus to refer to the following entities and their respective subsidiaries and affiliates:

“Antero Resources” refers to Antero Resources Corporation.

“Blue Racer” refers to Blue Racer Midstream, LLC.

“Cabot Oil & Gas” refers to Cabot Oil & Gas Corporation.

“Chesapeake Energy” refers to Chesapeake Energy Corporation.

“EnLink Midstream” refers to EnLink Midstream Operating, L.P.

“Eureka Hunter” refers to Eureka Hunter Pipeline LLC, a subsidiary of Magnum Hunter Resources Corporation.

“MarkWest Energy Partners” refers to MarkWest Energy Partners, L.P.

“Rex Energy” refers to Rex Energy Corporation.

“Shell Chemical” refers to Shell Chemical LP.

“Stone Energy” refers to Stone Energy Corporation.

 

II.	Glossary of Oil and Natural Gas Terms

The following are abbreviations and definitions of some of the oil and gas industry terms used in this prospectus:

“Bbl” refers to one stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate or NGLs.

“Bcf” refers to one billion cubic feet of natural gas.

“Bcfe” refers to one billion cubic feet of natural gas equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

“Btu” refers to one British thermal unit, the quantity of heat required to raise the temperature of a one-pound mass of water by one degree of Fahrenheit.

“Basin” refers to a large natural depression on the earth’s surface in which sediments generally brought by water accumulate.

“Completion” refers to the process of treating a drilled well followed by the installation of permanent equipment for the production of oil or natural gas or, in the case of a dry hole, the reporting of abandonment to the appropriate agency.

“Condensate” or “Condensate Window” 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.

 

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“Developed acreage” refers to the number of acres that are allocated or assignable to productive wells or wells capable of production.

“Development well” refers to a well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

“Differential” refers to an adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.

“Dry Gas” or “Dry Gas Window” 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.

“Dry hole” refers to a well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

“Dth” is a thermal unit, and is equal to one million Btus.

“Exploratory well” refers to a well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir. Generally, an exploratory well is any well that is not a development well, a service well, or a stratigraphic test well.

“Field” refers to an area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms “structural feature” and “stratigraphic condition” are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

“Formation”refers to a layer of rock which has distinct characteristics that differs from nearby rock.

“Gross acres” or “gross wells” refers to the total acres or wells, as the case may be, in which a working interest is owned.

“Horizontal drilling” refers to a drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.

“Identified drilling locations” refers to total gross (net) resource play locations that we may be able to drill on our existing acreage. Actual drilling activities may change depending on the availability of capital, regulatory approvals, seasonal restrictions, natural gas and oil prices, costs, drilling results and other factors.

“MBbls” refers to one thousand barrels of crude oil, condensate or NGLs.

“Mcf” refers to one thousand cubic feet of natural gas.

“Mcfe” refers to one thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or NGLs.

“MMBbls” refers to one million barrels of crude oil, condensate or NGLs.

“MMBoe” refers to one million barrels of oil equivalent, determined using the ratio of one Bbl of crude oil, condensate or natural gas liquids to six Mcf of natural gas.

 

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“MMBtu” refers to one million Btu.

“MMcf” refers to one million cubic feet of natural gas.

“MMcfe” refers to one million cubic feet of gas equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

“Net acres” refers to the amount of leased real estate that a petroleum and/or natural gas company has a true working interest in. Net acres express actual percentage interest when a company shares its working interest with another company; the total acreage under lease by a company is referred to as gross acres. Net acres account for the Company’s percentage interest, multiplied by the gross acreage. If a company holds the entire working interest, its net acreage and gross acreage will be the same.

“Net production” refers to production that is owned by us less royalties and production due others.

“NGLs” refers to natural gas liquids, which are a mixture of light hydrocarbons that exist in the gaseous phase and are recovered as liquids in gas processing plants. NGLs differ from condensate in two principal respects: (1) NGLs are extracted and recovered in gas plants rather than lease separators or other lease facilities, and (2) NGLs include very light hydrocarbons (ethane, propane, butanes) as well as the pentanes-plus that are the main constituents of condensates.

“NYMEX” refers to the New York Mercantile Exchange.

“Operator” refers to the individual or company responsible for the exploration and/or production of an oil or natural gas well or lease.

“Plugging” refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface.

“Productive well” refers to a well that is expected to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceeds production expenses and taxes.

“Prospect” refers to a geological feature mapped as a location or probable location of a commercial oil and/or gas accumulation. A prospect is defined as a result of geophysical and geological studies allowing the identification and quantification of uncertainties, probabilities of success, estimates of potential resources and economic viability.

“Proved developed reserves” refers to proved reserves that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well, and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

“Proved oil and gas reserves” refers to those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible-from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations-prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

“Proved undeveloped reserves” refers to proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

 

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(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir (as defined in Rule 4-10(a)(2) of Regulation S-X), or by other evidence using reliable technology establishing reasonable certainty.

“PV-10” refers to, when used with respect to natural gas and oil reserves, the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production, future development and abandonment costs, using sales prices used in estimating proved oil and gas reserves and costs in effect at the determination date, before income taxes, and without giving effect to non-property-related expenses, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the SEC.

“Realized price” refers to the cash market price less all expected quality, transportation and demand adjustments.

“Reservoir” refers to a porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.

“Rich Condensate” or “Rich Condensate Window” 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.

“Rich Gas” 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.

“Spacing” refers to the distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.

“Standardized measure” refers to discounted future net cash flows estimated by applying sales prices used in estimating proved oil and gas reserves to the estimated future production of year-end proved reserves. Future cash inflows are reduced by estimated future production and development costs based on period-end costs to determine pre-tax cash inflows. Future income taxes, if applicable, are computed by applying the statutory tax rate to the excess of pre-tax cash inflows over our tax basis in the natural gas and oil properties. Future net cash inflows after income taxes are discounted using a 10% annual discount rate.

“Undeveloped acreage” refers to lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether such acreage contains proved reserves.

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

 

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“Wellbore” refers to the hole drilled by the bit that is equipped for oil or natural gas production on a completed well. Also called well or borehole.

“Working interest” refers to a company’s equity interest in a project before reduction for royalties or production share owed to others under the applicable fiscal terms.

“WTI” refers to West Texas Intermediate crude oil.

 

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62,500,000 Shares

 

Eclipse Resources Corporation

Common Stock

 

 

Prospectus

 

 

                    , 2015

 

 

 

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PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

 

Item 13.

Other Expenses of Issuance and Distribution

The following table sets forth an itemized statement of the amounts of all expenses payable by us in connection with the registration of the common stock offered hereby. With the exception of the Registration Fee, the amounts set forth below are estimates.

 

SEC Registration Fee		$	51,527
Accountants’ fees and expenses		$	75,000
Legal fees and expenses		$	100,000
Miscellaneous		$	75,000
Total		$	301,527

 

Item 14.

Indemnification of Directors and Officers

Our amended and restated certificate of incorporation provides that a director will not be liable to the corporation or its stockholders for monetary damages to the fullest extent permitted by the DGCL. In addition, if the DGCL is amended to authorize the further elimination or limitation of the liability of directors, then the liability of a director of the corporation, in addition to the limitation on personal liability provided for in our certificate of incorporation, will be limited to the fullest extent permitted by the amended DGCL. Our amended and restated bylaws provide that the corporation will indemnify, and advance expenses to, any officer or director to the fullest extent authorized by the DGCL.

Section 145 of the DGCL provides that a corporation may indemnify directors and officers as well as other employees and individuals against expenses, including attorneys’ fees, judgments, fines and amounts paid in settlement in connection with specified actions, suits and proceedings whether civil, criminal, administrative, or investigative, other than a derivative action by or in the right of the corporation, if they acted in good faith and in a manner they reasonably believed to be in or not opposed to the best interests of the corporation and, with respect to any criminal action or proceeding, had no reasonable cause to believe their conduct was unlawful. A similar standard is applicable in the case of derivative actions, except that indemnification extends only to expenses, including attorneys’ fees, incurred in connection with the defense or settlement of such action and the statute requires court approval before there can be any indemnification where the person seeking indemnification has been found liable to the corporation. The statute provides that it is not exclusive of other indemnification that may be granted by a corporation’s certificate of incorporation, bylaws, disinterested director vote, stockholder vote, agreement or otherwise.

Our amended and restated certificate of incorporation also contains indemnification rights for our directors and our officers. Specifically, our amended and restated certificate of incorporation provides that we shall indemnify our officers and directors to the fullest extent authorized by the DGCL. Further, we may maintain insurance on behalf of our officers and directors against expense, liability or loss asserted incurred by them in their capacities as officers and directors.

We have obtained directors’ and officers’ insurance to cover our directors, officers and some of our employees for certain liabilities.

We have entered into written indemnification agreements with our directors and executive officers. Under these proposed agreements, if an officer or director makes a claim of indemnification to us, either a majority of the independent directors or independent legal counsel selected by the independent directors must review the relevant facts and make a determination whether the officer or director has met the standards of conduct under Delaware law that would permit (under Delaware law) and require (under the indemnification agreement) us to indemnify the officer or director.

 

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Item 15.

Recent Sales of Unregistered Securities

On December 27, 2014, EnCap Energy Capital Fund VIII, L.P., EnCap Energy Capital Fund VIII Co-Investors, L.P., EnCap Energy Capital Fund IX, L.P., The Hulburt Family II Limited Partnership, CKH Partners II, L.P., Kirkwood Capital, L.P., Buckeye Investors L.P., GSO Capital Opportunities Fund II (Luxembourg) S.à.r.l., Fir Tree Value Master Fund, L.P., Luxor Capital Partners, LP and Luxor Capital Partners Offshore Master Fund, LP purchased an aggregate of 62,500,000 shares of the common stock of the Company at a price of $7.04 per share. On January 28, 2015, the Company issued the shares to the selling stockholders, all of whom qualify as “accredited investors” (as such term is defined in Rule 501(a) of Regulation D promulgated under the Securities Act) pursuant to the exemptions from registration provided in Rule 506 of Regulation D promulgated under Section 4(2) of the Securities Act.

Upon closing, we received net proceeds from the issuance of the shares to the purchasers of approximately $434 million (after deducting placement agent commissions and our estimated expenses), which we intend to use to fund our capital expenditure plan and for general corporate purposes.

 

Item 16.

Exhibits and Financial Statement Schedules

(a) See the Exhibit Index immediately following the signature page hereto, which is incorporated by reference as if fully set forth herein.

 

Item 17.

Undertakings

The undersigned registrant hereby undertakes:

(1) To file, during any period in which offers or sales are being made, a post-effective amendment to this registration statement:

(i) To include any prospectus required by Section 10(a)(3) of the Securities Act of 1933, as amended;

(ii) To reflect in the prospectus any facts or events arising after the effective date of the registration statement (or the most recent post-effective amendment thereof) which, individually or in the aggregate, represent a fundamental change in the information set forth in the registration statement. Notwithstanding the foregoing, any increase or decrease in volume of securities offered (if the total dollar value of securities offered would not exceed that which was registered) and any deviation from the low or high end of the estimated maximum offering range may be reflected in the form of prospectus filed with the Securities and Exchange Commission pursuant to Rule 424(b) if, in the aggregate, the changes in volume and price represent no more than a 20% change in the maximum aggregate offering price set forth in the “Calculation of Registration Fee” table in the effective registration statement; and

(iii) To include any material information with respect to the plan of distribution not previously disclosed in the registration statement or any material change to such information in the registration statement;

(2) That, for the purpose of determining any liability under the Securities Act of 1933, each such post-effective amendment shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

(3) To remove from registration by means of a post-effective amendment any of the securities being registered which remain unsold at the termination of the offering.

(4) That, for the purpose of determining liability under the Securities Act of 1933 to any purchaser, each prospectus filed pursuant to Rule 424(b) as part of a registration statement relating to an offering, other than registration statements relying on Rule 430B or other than prospectuses filed in reliance on Rule 430A (§230.430A of this chapter), shall be deemed to be part of and included in the registration statement as of the date

 

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it is first used after effectiveness. Provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such first use, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such date of first use.

(5) That, for the purpose of determining liability of the registrant under the Securities Act of 1933 to any purchaser in the initial distribution of the securities:

The undersigned registrant undertakes that in a primary offering of securities of the undersigned registrant pursuant to this registration statement, regardless of the underwriting method used to sell the securities to the purchaser, if the securities are offered or sold to such purchaser by means of any of the following communications, the undersigned registrant will be a seller to the purchaser and will be considered to offer or sell such securities to such purchaser:

(i) Any preliminary prospectus or prospectus of the undersigned registrant relating to the offering required to be filed pursuant to Rule 424;

(ii) Any free writing prospectus relating to the offering prepared by or on behalf of the undersigned registrant or used or referred to by the undersigned registrant;

(iii) The portion of any other free writing prospectus relating to the offering containing material information about the undersigned registrant or its securities provided by or on behalf of the undersigned registrant; and

(iv) Any other communication that is an offer in the offering made by the undersigned registrant to the purchaser.

Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act of 1933 and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act of 1933 and will be governed by the final adjudication of such issue.

 

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the registrant has duly caused this Pre-effective Amendment No. 1 to registration statement on Form S-1 to be signed on its behalf by the undersigned, thereunto duly authorized in the City of State College, Commonwealth of Pennsylvania, on April 16, 2015.

 

Pursuant to the requirements of the Securities Act of 1933, as amended, this Pre-effective Amendment No. 1 to registration statement on Form S-1 has been signed below by the following persons in the capacities and the dates indicated.

 

Signature		Title		Date
* Benjamin W. Hulburt		Chairman, President and Chief Executive Officer (Principal Executive Officer)		April 16, 2015
* Matthew R. DeNezza		Executive Vice President and Chief Financial Officer (Principal Financial Officer)		April 16, 2015
* Roy Steward		Vice President and Chief Accounting Officer (Principal Accounting Officer)		April 16, 2015
/s/ Christopher K. Hulburt Christopher K. Hulburt		Director, Executive Vice President, Secretary and General Counsel		April 16, 2015
* D. Martin Phillips		Director		April 16, 2015
* Robert L. Zorich		Director		April 16, 2015
* Douglas E. Swanson, Jr.		Director		April 16, 2015
* Mark E. Burroughs, Jr.		Director		April 16, 2015
* Joseph C. Winkler, III		Director		April 16, 2015
* Richard D. Paterson		Director		April 16, 2015
* Randall M. Albert		Director		April 16, 2015

 

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*

The undersigned, pursuant to a power of attorney executed by each of the officers and directors above and filed with the SEC on November 11, 2015 on the signature page to the registration statement on Form S-1 and incorporated herein by reference, by signing his name hereto, does hereby sign and deliver this Pre-effective Amendment No. 1 to registration statement on Form S-1 on behalf of each of the persons noted above in the capacities indicated.

 

 

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EXHIBIT INDEX

 

Exhibit No.		Description
3.1		Amended and Restated Certificate of Incorporation of Eclipse Resources Corporation (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed with the SEC on June 24, 2014)
3.2		Form of Amended and Restated Bylaws of Eclipse Resources Corporation (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K filed with the SEC on June 24, 2014)
4.1		Stockholders Agreement, dated June 25, 2014, by and among Eclipse Resources Corporation, Eclipse Resources Holdings, L.P., CKH Partners II, L.P., The Hulburt Family II Limited Partnership, Kirkwood Capital, L.P, EnCap Energy Capital Fund VIII, L.P., EnCap Energy Capital Fund VIII Co-Investors, L.P., EnCap Energy Capital Fund IX, L.P. and Eclipse Management, L.P. (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on June 30, 2014)
4.2		Amended and Restated Registration Rights Agreement, dated January 28, 2015, by and among Eclipse Resources Corporation, Eclipse Resources Holdings, L.P., CKH Partners II, L.P., The Hulburt Family II Limited Partnership, Kirkwood Capital, L.P, EnCap Energy Capital Fund VIII, L.P., EnCap Energy Capital Fund VIII Co-Investors, L.P., EnCap Energy Capital Fund IX, L.P., Eclipse Management, L.P., Buckeye Investors L.P., GSO Capital Opportunities Fund II (Luxembourg) S.à.r.l., Fir Tree Value Master Fund, L.P., Luxor Capital Partners, LP and Luxor Capital Partners Offshore Master Fund, LP (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on January 29, 2015)
4.3		Form of Common Stock Certificate of Eclipse Resources Corporation (incorporated by reference to Exhibit 4.1 to Amendment No. 1 to the Company’s Registration Statement on Form S-1 filed with the SEC on June 2, 2014)
5.1**		Opinion of Norton Rose Fulbright US LLP as to the legality of the securities being registered
10.1		Indenture, dated as of June 26, 2013, by and among Eclipse Resources I, LP and each of the subsidiary guarantors party thereto and Deutsche Bank Trust Company Americas relating to the 12.0% Senior Unsecured PIK Notes due 2018 (including form of Note) (incorporated by reference to Exhibit 10.1 to the Company’s Registration Statement on Form S-1 filed with the SEC on May 5, 2014)
10.2		First Supplemental Indenture, dated as of June 26, 2013, by and among Eclipse Resources-Ohio, LLC, Eclipse Resources I, LP and Deutsche Bank Trust Company Americas, as trustee, relating to the 12.0% Senior Unsecured PIK Notes due 2018 (incorporated by reference to Exhibit 10.2 to the Company’s Registration Statement on Form S-1 filed with the SEC on May 5, 2014)
10.3		Second Supplemental Indenture, dated as of November 1, 2013, by and among Buckeye Minerals & Royalties, LLC, Eclipse Resources I, LP and Deutsche Bank Trust Company Americas, as trustee, relating to the 12.0% Senior Unsecured PIK Notes due 2018 (incorporated by reference to Exhibit 10.3 to the Company’s Registration Statement on Form S-1 filed with the SEC on May 5, 2014)
10.4**		Third Supplemental Indenture, dated as of June 12, 2014, by and among Eclipse Resources Corporation, Eclipse Resources-Ohio, LLC, Eclipse Resources I, LP and Deutsche Bank Trust Company Americas, as trustee, relating to the 12.0% Senior Unsecured PIK Notes due 2018
10.5**		Fourth Supplemental Indenture, dated as of December 11, 2014, by and among Eclipse Resources Operating, LLC, Eclipse Resources I, LP and Deutsche Bank Trust Company Americas, as trustee, relating to the 12.0% Senior Unsecured PIK Notes due 2018

 

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Exhibit No.		Description
10.6**		Fifth Supplemental Indenture, dated as of January 15, 2015, by and among Eclipse GP, LLC, Eclipse Resources Midstream, LP, Eclipse Resources Marketing, LP, Eclipse Resources I, LP and Deutsche Bank Trust Company Americas, as trustee, relating to the 12.0% Senior Unsecured PIK Notes due 2018
10.7		Amended and Restated Credit Agreement, dated as of January 12, 2015, by and among Eclipse Resources I, LP, as borrower, Eclipse Resources Corporation, the Bank of Montreal, as administrative agent and issuing bank, KeyBank National Association, as syndication agent, and each of the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on January 15, 2015)
10.8†		Eclipse Resources Corporation 2014 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on June 24, 2014)
10.9		Master Reorganization Agreement, dated June 6, 2014, by and among Eclipse Resources I, LP, Eclipse GP, LLC, EnCap Energy Capital Fund VIII, L.P., EnCap Energy Capital Fund VIII Co-Investors, L.P., EnCap Energy Capital Fund IX, L.P., CKH Partners II, L.P., The Hulburt Family II Limited Partnership, Kirkwood Capital, L.P., Eclipse Management, L.P., Eclipse Resources Holdings, L.P., Eclipse Resources Corporation and Benjamin W. Hulburt, Christopher K. Hulburt and Thomas S. Liberatore (incorporated by reference to Exhibit 10.9 to Amendment No. 2 to the Company’s Registration Statement on Form S-1 filed with the SEC on June 9, 2014)
10.10†		Form of Indemnification Agreement for Eclipse Resources Corporation Officers and Directors (incorporated by reference to Exhibit 10.10 to Amendment No. 1 to the Company’s Registration Statement on Form S-1 filed with the SEC on June 2, 2014)
10.11		Agreement of Limited Partnership of Eclipse Resources Holdings, L.P. (incorporated by reference to Exhibit 10.13 to Amendment No. 2 to the Company’s Registration Statement on Form S-1 filed with the SEC on June 9, 2014)
10.12		Limited Partnership Agreement of Eclipse Management, L.P. (incorporated by reference to Exhibit 10.14 to Amendment No. 2 to the Company’s Registration Statement on Form S-1 filed with the SEC on June 9, 2014)
10.13†		Executive Employment Agreement dated as of August 26, 2014, by and between Eclipse Resources Corporation and Benjamin W. Hulburt (incorporated by referenced to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on August 29, 2014)
10.14†		Executive Employment Agreement dated as of August 26, 2014, by and between Eclipse Resources Corporation and Matthew R. DeNezza (incorporated by referenced to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the SEC on August 29, 2014)
10.15†		Executive Employment Agreement dated as of August 26, 2014, by and between Eclipse Resources Corporation and Christopher K. Hulburt (incorporated by referenced to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed with the SEC on August 29, 2014)
10.16†		Executive Employment Agreement dated as of August 26, 2014, by and between Eclipse Resources Corporation and Thomas S. Liberatore (incorporated by referenced to Exhibit 10.4 to the Company’s Current Report on Form 8-K filed with the SEC on August 29, 2014)
10.17		Securities Purchase Agreement, dated as of December 27, 2014, by and between Eclipse Resources Corporation, CKH Partners II, L.P., The Hulburt Family II Limited Partnership, Kirkwood Capital, L.P, EnCap Energy Capital Fund VIII, L.P., EnCap Energy Capital Fund VIII Co-Investors, L.P., EnCap Energy Capital Fund IX, L.P., Buckeye Investors L.P., GSO Capital Opportunities Fund II L.P., GSO Eclipse Holdings I LP, Fir Tree Value Master Fund, L.P., Luxor Capital Partners, LP and Luxor Capital Partners Offshore Master Fund, LP. (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on December 29, 2014)

 

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Exhibit No.		Description
10.18		Form of Restricted Stock Unit Award Agreement for Employees (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on February 25, 2015)
10.19		Form of Performance Unit Award Agreement for Employees (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the SEC on February 25, 2015)
21.1**		List of Subsidiaries of Eclipse Resources Corporation
23.1*		Consent of Grant Thornton LLP (Eclipse Resources Corporation)
23.2*		Consent of Grant Thornton LLP (Eclipse Resources Operating, LLC)
23.3*		Consent of Grant Thornton LLP (Eclipse Resources—Ohio, LLC)
23.4*		Consent of Netherland, Sewell & Associates, Inc.
23.5**		Consent of Norton Rose Fulbright US LLP (included as part of Exhibit 5.1 hereto)
24.1**		Power of Attorney (included on the signature page of the original registration statement filed on February 11, 2015)
99.1**		Netherland, Sewell & Associates, Inc., Summary of Reserves at December 31, 2014 (Eclipse Resources Corporation)
99.2		Netherland, Sewell & Associates, Inc., Summary of Reserves at December 31, 2013 (Eclipse Resources I, LP) (incorporated by reference to Exhibit 99.2 to the Company’s Registration Statement on Form S-1 filed with the SEC on May 5, 2014)
99.3		Netherland, Sewell & Associates, Inc., Summary of Reserves at December 31, 2012 (Eclipse Resources I, LP) (incorporated by reference to Exhibit 99.3 to the Company’s Registration Statement on Form S-1 filed with the SEC on May 5, 2014)
101.INS*		XBRL Instance Document
101.SCH*		XBRL Taxonomy Extension Schema Document
101.CAL*		XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*		XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*		XBRL Taxonomy Extension Label Linkbase Document
101.PRE*		XBRL Taxonomy Extension Presentation Linkbase Document

 

*	Filed herewith

**	Previously filed with the original registration statement filed with the SEC on February 11, 2015.

†	Compensatory plan or arrangement.

 

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