As filed with the Securities and Exchange Commission on January 13, 2014

Registration No. 333-192894

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Amendment No. 3

to

Form S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

RICE ENERGY INC.

(Exact name of registrant as specified in its charter)

Delaware	1311	46-3785773
(State or other jurisdiction of incorporation or organization)	(Primary Standard Industrial Classification Code Number)	(IRS Employer Identification Number)

171 Hillpointe Drive, Suite 301

Canonsburg, Pennsylvania 15317

(724) 746-6720

(Address, including zip code, and telephone number,

including area code, of registrant’s principal executive offices)

Daniel J. Rice IV

Chief Executive Officer

171 Hillpointe Drive, Suite 301

Canonsburg, Pennsylvania 15317

(724) 746-6720

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

Copies to:

Douglas E. McWilliams Matthew R. Pacey Vinson & Elkins L.L.P. 1001 Fannin, Suite 2500 Houston, Texas 77002 (713) 758-2222 Gerald M. Spedale Jason A. Rocha Baker Botts L.L.P. One Shell Plaza 910 Louisiana Street Houston, Texas 77002 (713) 229-1234

Approximate date of commencement of proposed sale of the securities to the public: As soon as practicable after the effective date of this Registration Statement.

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

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

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

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

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

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

CALCULATION OF REGISTRATION FEE

Title of Each Class of Securities to be Registered	Amount to be Registered(1)	Proposed Maximum Offering Price Per Share(2)	Proposed Maximum Aggregate Offering Price (1)(2)	Amount of Registration Fee (3)
Common stock, par value $0.01 per share	46,000,000	$21.00	$966,000,000	$124,420.80

(1) Estimated pursuant to Rule 457(a) under the Securities Act of 1933, as amended. Includes 6,000,000 additional shares of common stock that the underwriters have the option to purchase.

(2) Estimated solely for the purpose of calculating the registration fee.

(3) The Registrant previously paid $103,040 of the total registration fee in connection with the previous filing of this Registration Statement.

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

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

Subject to Completion, dated January 13, 2014

PROSPECTUS

40,000,000 Shares

Rice Energy Inc.

Common Stock

This is the initial public offering of the common stock of Rice Energy Inc., a Delaware corporation. We are offering 30,000,000 shares and the selling stockholder identified in the prospectus is offering 10,000,000 shares of our common stock. We will not receive any proceeds from the sale of shares held by the selling stockholder. No public market currently exists for our common stock. We are an “emerging growth company” and are eligible for reduced reporting requirements. Please see “Prospectus Summary—Emerging Growth Company Status.”

We have been approved to list our common stock on the New York Stock Exchange under the symbol “RICE”, subject to official notice of issuance.

We anticipate that the initial public offering price will be between $19.00 and $21.00 per share.

Investing in our common stock involves risks. See “Risk Factors” beginning on page 21 of this prospectus.

	Per share	Total
Price to the public	$	$
Underwriting discounts and commissions (1)	$	$
Proceeds to us (before expenses)	$	$
Proceeds to the selling stockholder	$	$

(1) Please read “Underwriting (Conflicts of Interest)” for a description of all underwriting compensation payable in connection with this offering.

The selling stockholder has granted the underwriters the option to purchase up to 6,000,000 additional shares of common stock on the same terms and conditions set forth above if the underwriters sell more than 40,000,000 shares of common stock in this offering.

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

Barclays expects to deliver the shares on or about                     , 2014.

Barclays Citigroup Goldman, Sachs & Co.

Wells Fargo Securities BMO Capital Markets RBC Capital Markets

Comerica Securities SunTrust Robinson Humphrey Tudor, Pickering, Holt & Co.

Capital One Securities FBR Scotiabank / Howard Weil

Johnson Rice & Company L.L.C. Sterne Agee

Prospectus dated                     , 2014

TABLE OF CONTENTS

PROSPECTUS SUMMARY	1
RISK FACTORS	21
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS	52
USE OF PROCEEDS	54
DIVIDEND POLICY	56
CAPITALIZATION	57
DILUTION	59
SELECTED HISTORICAL CONSOLIDATED AND UNAUDITED PRO FORMA FINANCIAL DATA	61
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	63
BUSINESS	87
MANAGEMENT	114
EXECUTIVE COMPENSATION	121
PRINCIPAL AND SELLING STOCKHOLDERS	132
CORPORATE REORGANIZATION	134
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS	137
DESCRIPTION OF CAPITAL STOCK	141
SHARES ELIGIBLE FOR FUTURE SALE	146
MATERIAL U.S. FEDERAL INCOME AND ESTATE TAX CONSIDERATIONS FOR NON-U.S. HOLDERS	148
UNDERWRITING (CONFLICTS OF INTEREST)	152
LEGAL MATTERS	160
EXPERTS	160
WHERE YOU CAN FIND MORE INFORMATION	161
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS	F-1
ANNEX A: GLOSSARY OF OIL AND NATURAL GAS TERMS	A-1

You should rely only on the information contained in this prospectus and any free writing prospectus prepared by us or on behalf of us or to the information which we have referred you. Neither we, the selling stockholder nor the underwriters have authorized anyone to provide you with information different from that contained in this prospectus and any free writing prospectus. We take no responsibility for, and can provide no assurance as to the reliability of, any other information that others may give you. We, the selling stockholder and the underwriters are offering to sell shares of common stock and seeking offers to buy shares of common stock only in jurisdictions where offers and sales are permitted. The information in this prospectus is accurate only as of the date of this prospectus, regardless of the time of delivery of this prospectus or any sale of the common stock. Our business, financial condition, results of operations and prospects may have changed since that date.

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

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Commonly Used Defined Terms

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

• “Rice Energy,” “we,” “our,” “us” or like terms refer collectively to Rice Drilling B LLC and its consolidated subsidiaries before the completion of our corporate reorganization described in “Corporate Reorganization” and to Rice Energy Inc. and its consolidated subsidiaries, including Rice Drilling B LLC as of and following the completion of our corporate reorganization;

• “Rice Drilling B” refers to Rice Drilling B LLC and its consolidated subsidiaries;

• “Rice Partners” refers to Rice Energy Family Holdings, LP, an entity affiliated with members of the Rice family;

• “Rice Holdings” refers to Rice Energy Holdings LLC;

• “Rice Owners” refers to Rice Holdings, Rice Partners and Daniel J. Rice III;

• “Rice Appalachia” refers to Rice Energy Appalachia, LLC, the parent company of our predecessor;

• “Alpha Holdings” refers to Foundation PA Coal Company, LLC, a wholly owned indirect subsidiary of Alpha Natural Resources, Inc.;

• “Marcellus joint venture” refers collectively to Alpha Shale Resources, LP and its general partner, Alpha Shale Holdings, LLC;

• “Countrywide Energy Services” refers to Countrywide Energy Services, LLC;

• “Natural Gas Partners” refers to a family of private equity investment funds organized to make direct equity investments in the energy industry, including the funds invested in us;

• “NGP Holdings” refers to NGP Rice Holdings, LLC; and

• “Marcellus JV Buy-In,” “NSAI,” “Wright & Company” and our “reserve reports” are defined below under “—Presentation of Financial and Operating Data.”

We include a glossary of some of the oil and natural gas industry terms used in this prospectus in Appendix A to this prospectus.

Presentation of Financial and Operating Data

Equity Investment Financial Statements. We account for our 50% equity interests in our two joint ventures, Countrywide Energy Services and our Marcellus joint venture, as equity method investments in our consolidated financial statements. Rule 3-09 of Regulation S-X requires separate financial statements of 50% or less owned persons accounted for under the equity method by a registrant such as us if either the income or the investment test in Rule 1-02(w) of Regulation S-X exceeds 20%. We have determined that, for the year ended December 31, 2011, our equity interest in Countrywide Energy Services exceeded the 20% significance tests of Rule 3-09. Accordingly, this prospectus includes audited financial statements as of and for the period ended December 31, 2011 and audited financial statements as of and for the year ended December 31, 2012 of Countrywide Energy Services.

Presentation of Operating Data. As an investment accounted for under the equity method, the reserves and other operating data of our Marcellus joint venture were not consolidated into our historical reserves or operating data. As described in “Prospectus Summary – Recent Developments – Marcellus JV Buy-In,” we expect to acquire the ownership interests in our Marcellus joint venture held by Alpha Holdings concurrent with the closing of this offering, resulting in our ownership of 100% of the ownership interests in our Marcellus joint

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venture (the “Marcellus JV Buy-In”). Accordingly, we present in this prospectus (i) historical reserve and operating data of us and our Marcellus joint venture on both a standalone and, in certain circumstances, a combined basis and (ii) our pro forma reserve and operating data giving effect to the Marcellus JV Buy-In. Our other equity investee, Countrywide Energy Services, does not have any oil and gas reserves and, as such, does not impact such data. The estimated proved reserve information for the properties of each of us and our Marcellus joint venture contained in this prospectus are based on reserve reports relating thereto prepared by the independent petroleum engineers of Netherland, Sewell & Associates, Inc. (“NSAI”) and, with respect to the estimated proved reserve information for the properties of our Marcellus joint venture as of December 31, 2011, Wright & Company, Inc. (“Wright & Company”). We refer to these reports collectively as our “reserve reports.”

Industry and Market Data

The market data and certain other statistical information used throughout this prospectus are based on independent industry publications, government publications and other published independent sources. 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, the selling stockholder nor the underwriters have independently verified the accuracy or completeness of this information. The industry in which we operate is subject to a high degree of uncertainty and risk due to a variety of factors, including those described in the section entitled “Risk Factors.” These and other factors could cause results to differ materially from those expressed in these publications.

Trademarks and Trade Names

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

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PROSPECTUS SUMMARY

This summary highlights some of the information contained in this prospectus and does not contain all of the information that may be important to you. You should read this entire prospectus and the documents to which we refer you before making an investment decision. You should carefully consider the information set forth under “Risk Factors,” “Cautionary Statement Regarding Forward-Looking Statements” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the historical and unaudited pro forma financial statements and the related notes to those financial statements included elsewhere in this prospectus. Unless otherwise indicated, information presented in this prospectus assumes (i) the initial public offering price of the shares of our common stock will be $20.00 per share (which is the midpoint of the price range set forth on the cover of this prospectus), (ii) the underwriters’ option to purchase additional shares is not exercised, (iii) the completion of our corporate reorganization as set forth in “Corporate Reorganization” and (iv) the consummation of the Marcellus JV Buy-In as set forth below under “—Recent Developments—Marcellus JV Buy-In.”

Please see “Commonly Used Defined Terms” on page ii hereof for definitions of terms used herein and “Presentation of Financial and Operating Data” on pages ii and iii hereof for important information regarding the manner in which we describe our operations and financial and operating data.

Our Company

We are an independent natural gas and oil company engaged in the acquisition, exploration and development of natural gas and oil properties in the Appalachian Basin. We are focused on creating shareholder value by identifying and assembling a portfolio of low-risk assets with attractive economic profiles and leveraging our technical and managerial expertise to deliver industry-leading results. We strive to be an early entrant into the core of a shale play by identifying what we believe to be the core of the play and aggressively executing our acquisition strategy to establish a largely contiguous acreage position. We believe we were an early identifier of the core of both the Marcellus Shale in southwestern Pennsylvania and the Utica Shale in southeastern Ohio.

All of our current and planned development is located in what we believe to be the core of the Marcellus and Utica Shales. The Marcellus Shale is one of the most prolific unconventional resource plays in the United States, and we believe the Utica Shale, based on initial drilling results, is a premier North American shale play. Together, these resource plays offer what we believe to be among the highest rate of return wells in North America. We hold approximately 43,351 pro forma net acres in the southwestern core of the Marcellus Shale, primarily in Washington County, Pennsylvania. We established our Marcellus Shale acreage position through a combination of largely contiguous acreage acquisitions in 2009 and 2010 and through numerous bolt-on acreage acquisitions. In 2012, we acquired approximately 33,499 of our 46,488 net acres in the southeastern core of the Utica Shale, primarily in Belmont County, Ohio. We believe this area to be the core of the Utica Shale based on publicly available drilling results. We operate a substantial majority of our acreage in the Marcellus Shale and a majority of our acreage in the Utica Shale.

Since completing our first horizontal well in October 2010, our pro forma average net daily production has grown approximately 64x to 128 MMcf/d for the third quarter of 2013. All of our production to date has been dry gas attributable to our operations in the Marcellus Shale. Prior to the second quarter of 2013, we ran a two-rig drilling program focused on delineating and defining the boundaries of our Marcellus Shale acreage position. In the second quarter of 2013, we shifted our operational focus from exploration to development, commencing a four-rig drilling program consisting of two rigs specifically for drilling the tophole sections of our horizontal wells and two rigs specifically for drilling the curve and lateral sections of our horizontal wells. We expect to continue running this four-rig program in the Marcellus Shale through 2014. The following chart shows our pro forma average net daily production for each quarter since completing our first horizontal well in the Marcellus Shale.

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Pro Forma Average Net Daily Production (MMcf/d)

As of December 1, 2013, we had drilled and completed 37 horizontal Marcellus wells with lateral lengths ranging from 2,444 feet to 9,147 feet and averaging 5,669 feet. Our estimated ultimate recoveries (“EUR”) from these 37 wells, as estimated by our independent reserve engineer, NSAI, and normalized for each 1,000 feet of horizontal lateral, range from 1.2 Bcf per 1,000 feet to 2.9 Bcf per 1,000 feet, with an average of 1.8 Bcf per 1,000 feet. We have drilled and completed 37 horizontal Marcellus wells as of December 1, 2013 with a 100% success rate (defined as the rate at which wells are completed and produce in commercially viable quantities). As of December 1, 2013, we had 349 gross (325 net) pro forma identified drilling locations in the Marcellus Shale. Additionally, we have drilled and completed three Upper Devonian horizontal wells on our Marcellus Shale acreage with a 100% success rate. Based on our Upper Devonian wells and those of other operators in the vicinity of our acreage as well as other geologic data, we estimate that substantially all of our Marcellus Shale acreage in Southwestern Pennsylvania is prospective for the slightly shallower Upper Devonian Shale. As of December 1, 2013, we had 211 gross (194 net) pro forma identified drilling locations in the Upper Devonian Shale.

For the Utica Shale, we applied the same shale analysis and acquisition strategy that we developed and employed in the Marcellus Shale to acquire our acreage. We began to delineate our Utica Shale leasehold position with the spudding of our first well in Belmont County in October 2013. Please see “—Recent Developments—Initial Utica Well.” Our delineation operations are being conducted with a two-rig drilling program (one tophole rig and one horizontal rig), initially sourced from our Marcellus Shale rigs, which will be replaced in early 2014 with two new Marcellus Shale rigs. We intend to maintain this two-rig drilling program in the Utica Shale through 2014. In 2015, we intend to transition to a primarily development-focused strategy in the Utica Shale. As of December 1, 2013, we had 753 gross (233 net) identified drilling locations in the Utica Shale.

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As of September 30, 2013, our pro forma estimated proved reserves were 552 Bcf, all of which were in southwestern Pennsylvania, with 35% proved developed and 100% natural gas. In 2014, excluding $100 million cash to be paid with respect to the Marcellus JV Buy-In, we plan to invest $1,080 million in our operations as follows:

• $299 million for drilling and completion in the Marcellus Shale;

• $132 million for drilling and completion in the Utica Shale;

• $386 million for leasehold acquisitions, of which approximately $108 million is currently committed and the remainder is discretionary; and

• $263 million for midstream infrastructure development.

This represents a 72% increase over our $629 million pro forma 2013 capital budget. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity.” The following table provides a summary of our acreage, average working interest, producing wells, drilling locations, years of drilling inventory, projected 2014 gross wells drilled and projected 2014 drilling and completion capital budget as of December 1, 2013 and our average net daily production for the three months ended September 30, 2013, each on a pro forma basis for the Marcellus JV Buy-In and the asset sales described under “–Recent Developments–Guernsey and Lycoming Asset Sales”:

	Acreage				Average Working Interest			Producing Wells		Identified Drilling Locations (1)				Drilling Inventory (Years)			Q3 2013 Average Net Daily Production (MMcf/d)		2014 Projected Gross Wells Drilled			2014 Projected D&C Capex Budget ($mm)
	Gross		Net							Gross		Net
Marcellus Shale (2)		45,562		43,351		95	%		37		349		325		11.3	(3)		123		31		$	299
Utica Shale (4)		48,660		46,488		96	%		—		753		233		24.3	(3)		—		31	(5)		132
Upper Devonian Shale (6)									3		211		194		*			5		—			—
Total (6)		94,222		89,839					40		1,313		752					128		62		$	431

(1) Based on our reserve reports as of September 30, 2013, we had 49 gross (42.9 net) locations in the Marcellus Shale associated with proved undeveloped reserves and three gross (three net) locations in the Marcellus Shale associated with proved developed not producing reserves. Please see “Business—Our Operations—Reserve Data—Determination of Identified Drilling Locations” for more information regarding the process and criteria through which these drilling locations were identified. The drilling locations on which we actually drill will depend on the availability of capital, regulatory approval, commodity prices, costs, actual drilling results and other factors. Please see “Risk Factors—Risks Related to Our Business—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 substantial amount of capital that would be necessary to drill our identified drilling locations.”

(2) Excludes non-strategic properties consisting of 548 net acres in Fayette and Tioga Counties, Pennsylvania.

(3) Calculated by dividing our gross identified drilling locations by the number of wells we expect to drill in 2014.

(4) Utica Shale net identified drilling locations gives effect to our projected 31% working interest in the Utica Shale after applying unitization and participating interest assumptions described under “Business—Our Operations—Reserve Data—Determination of Identified Drilling Locations.”

(5) Includes an estimated 19 projected gross wells to be drilled by Gulfport Energy Corporation. Please see “—Utica Shale—Development Agreement and Area of Mutual Interest Agreement.”

(6) Approximately 39,020 gross (36,932 net) acres in the Marcellus Shale is also prospective for the Upper Devonian Shale. The Upper Devonian and the Marcellus Shale are stacked formations within the same geographic footprint.

* Not meaningful as a result of 2014 drilling program being primarily focused on the Marcellus and Utica Shales.

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Business Strategies

Our objective is to create shareholder value by identifying and assembling a portfolio of low-risk assets with attractive economic profiles and leveraging our technical and managerial expertise to deliver industry-leading results. We seek to achieve this objective by executing the following strategies:

• Pursue High-Graded Core Shale Acreage as an Early Entrant. Our acreage acquisition strategy has been predicated on our belief that core acreage provides superior production, EURs and returns on investment. We strive to be an early entrant into the core of a shale play by leveraging our technical expertise and analyzing third-party data. We develop an internally generated geologic model and then study publicly available third-party data, including well results and drilling and completion reports, to confirm our geologic model and define the core acreage position of a play. Once we believe that we have identified the core location, we aggressively execute on our acquisition strategy to establish a largely contiguous acreage position. By virtue of this strategy, we eliminate the need for large exploration programs requiring significant time and capital, and instead pursue areas that have been substantially de-risked, or high-graded, by our competitors. We have applied the expertise and approach that we employed in the Marcellus Shale to the Utica Shale, and we believe we will be able to achieve similar results.

• Target Contiguous Acreage Positions in Prolific Unconventional Resource Plays. We will seek to continue to expand on our success in targeting contiguous acreage positions within the core of the Marcellus and Utica Shales. We believe a concentrated acreage position requires fewer wells and inherently less capital to define the geologic properties across the play and allows us to optimize our wellbore economics. As of December 1, 2013, we have drilled and completed 37 horizontal Marcellus wells that have tested the outer boundaries of our Marcellus acreage position. Additionally, as a result of optimizing our wellbore design with a limited number of wells, we believe our ability to transition from exploration drilling to development drilling in the Marcellus Shale was accomplished with less capital invested than our peers. We intend to replicate this strategy in the Utica Shale.

• Aggressively Develop Leasehold Positions to Economically Grow Production, Cash Flow and Reserves. We intend to continue to aggressively drill and develop our portfolio of 1,313 gross (752 net) pro forma identified drilling locations as of December 1, 2013 with a goal of growing production, cash flow and reserves in an economically-efficient manner. We are currently running a four-rig drilling program. We began to delineate our Utica Shale leasehold position with the spudding of our first well in Belmont County in October 2013. Please see “—Recent Developments—Initial Utica Well.” We expect to add two rigs to our drilling program in the first quarter of 2014, bringing our total rig count to six. In executing our development strategy, we intend to leverage our operational control and the expertise of our technical team to deliver attractive production and cash flow growth. As the operator of a substantial majority of our acreage in the Marcellus and Utica Shales, we are able to manage (i) the timing and level of our capital spending, (ii) our exploration and development drilling strategies and (iii) our operating costs, which have resulted in our being a low cost per Mcf leader in the Marcellus Shale. We will seek to optimize our wellbore economics through a meticulous focus on rig efficiency, wellbore accuracy and completion design and execution. We believe that the combination of our operational control and technical expertise will allow us to build on our track record of superior production, cash flow and reserve growth.

• Maximize Pipeline Takeaway Capacity to Facilitate Production Growth. We maintain a strong commitment to build, own and operate the midstream infrastructure necessary to meet our production growth. We will also continue to enter into long-term firm transportation arrangements with third party midstream operators to ensure our access to market. We believe our commitment to midstream infrastructure allows us to commercialize our production more quickly and provides us with a competitive advantage in acquiring bolt-on acreage.

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Competitive Strengths

We possess a number of competitive strengths that we believe will allow us to successfully execute our business strategies:

• Large, Contiguous Positions Concentrated in the Core of the Marcellus and Utica Shales. We own extensive and contiguous acreage positions in the core of two of the premier North American shale plays. We believe we were an early identifier of both the Marcellus Shale core in southwestern Pennsylvania and the Utica Shale core, primarily in Belmont County, Ohio, which allowed us to acquire concentrated acreage positions. Our core position and contiguous acreage in the Marcellus Shale have allowed us to delineate our position as well as produce industry-leading well results, as our wells have some of the highest initial production rates and EURs in the Marcellus Shale. Through a consolidated approach, we are able to increase rig efficiency, turning wells into sales faster, and de-risk our acreage position more efficiently. Additionally, to service our concentrated acreage positions, we build water and midstream infrastructure, which enable us to reduce reliance on third party operators, minimize costs and increase our returns. This has been a strength in the Marcellus Shale and we believe our position in the Utica Shale will allow us to achieve similar results.

• Multi-Year, Low-Risk Development Drilling Inventory. Our drilling inventory as of December 1, 2013 consisted of 1,313 gross (752 net) pro forma identified drilling locations, with 349 gross (325 net) pro forma identified drilling locations in the Marcellus Shale, representing an 11.3 year drilling inventory, and 753 gross (233 net) and 211 gross (194 net) pro forma identified drilling locations in the Utica Shale and Upper Devonian Shale, respectively. We believe that we and other operators in the area have substantially delineated and de-risked our contiguous acreage position in the southwestern core of the Marcellus Shale. As of December 1, 2013, we have drilled and completed 37 wells on our Marcellus Shale acreage with a 100% success rate. We began to delineate our Utica acreage with the spudding of our first well in Belmont County in October 2013.

• Expertise in Unconventional Resource Plays and Technology. We have assembled a strong technical staff of shale petroleum engineers and shale geologists that have extensive experience in horizontal drilling, operating multi-rig development programs and using advanced drilling technology. We have been early adopters of new oilfield services and techniques for drilling (including rotary steerable tools) and completions (including reduced-length frac stages). In the Marcellus Shale as of December 1, 2013 on a pro forma basis, we have drilled 51 horizontal wells totaling approximately 325,000 lateral feet and have completed 37 of these wells totaling approximately 210,000 lateral feet. We have realized improvements in our drilling efficiency over time and we are now drilling lateral sections approximately 50% longer in approximately half the time as it has taken us historically. Our average horizontal lateral drilled in 2011 was 4,733 feet and took 13.0 days to drill from kickoff to total depth. Our average horizontal lateral drilled in 2013 was 7,700 feet and took 5.8 days to drill from kickoff to total depth. Our operating proficiency has also led to increased wellbore accuracy, completion design efficiencies and has yielded top tier production results as reflected in the fact that out of approximately 550 producing horizontal Marcellus Shale wells in Washington County, Pennsylvania, we drilled and completed the top two and four of the top six wells in terms of cumulative production through June 30, 2013, as reported by Pennsylvania’s oil and gas department. Further, we are able to enhance our wellbore economics through multi-well pad drilling (three to nine wells per rig move) and long laterals targeting 6,000 to 10,000 feet.

• Successful Infill Leasing Program. We have increased our acreage position in the core of the Marcellus Shale through bolt-on leases in the same targeted area. This strategy has allowed us to acquire acreage that provides additional drilling locations and/or adds horizontal feet to future wells. By implementing this strategy, we have grown our Marcellus Shale acreage position in Washington County from our initial acquisition of 642 net acres in 2009 to 43,351 net acres pro forma as of December 1, 2013. We have replicated this strategy successfully in the Utica Shale in Belmont

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County as well, leasing an additional 15,160 net acres since our initial acquisition of approximately 33,499 net acres in November 2012. We intend to continue to focus our near-term leasing program on Greene and Washington Counties in Pennsylvania and on Belmont County in Ohio, with the strategy of using bolt-on leases to acquire acreage that immediately increases our drilling locations and/or drillable horizontal feet.

• Access to Committed Takeaway Capacity. Our owned and operated gas gathering pipeline system is currently designed to handle up to approximately 1.5 Bcf/d in the aggregate and, as of December 1, 2013, has an operating capacity of approximately 620 MMcf/d in the aggregate. This system connects our producing wells to multiple interstate transmission and other third-party pipelines. We will continue to build out our Pennsylvania gathering system congruent with our future development plans. To supplement our gathering system’s operating capacity, we have contracted 110 MMcf/d of capacity on various third party gathering systems to transport our natural gas to the Texas Eastern transmission pipeline. We will replicate the strategy of owning and operating our own midstream system in Ohio and expect to have our gathering system in Belmont County substantially complete by the end of 2015. We believe our commitment to owning and operating midstream assets allows us to efficiently bring wells online, mitigates the risk of unplanned shut-ins and creates pricing and transportation optionality by connecting to multiple interstate pipelines. We also have secured approximately 642,000 MMBtu/d (which represents approximately 611 MMcf/d) of long-haul firm transportation capacity. By securing firm transportation and firm sales contracts, we are better able to accommodate our growing production and manage basis differentials.

• Significant Liquidity and Active Hedging Program. As of December 31, 2013, on a pro forma basis, we would have had cash on hand of approximately $315.1 million and availability under our revolving credit facility of approximately $317.1 million. We believe this liquidity, along with our cash flow from operations, is sufficient to execute our current capital program. Additionally, our hedging program mitigates commodity price volatility and protects our future cash flows. We review our hedge position on an ongoing basis, taking into account our current and forecasted production volumes and commodity prices. As of December 1, 2013, we have entered into hedging contracts covering approximately 62.9 Bcf (172 MMcf/d) of natural gas production for 2014 at a weighted average index floor price of $4.05 per MMBtu. Furthermore, as of December 1, 2013, we have entered into hedging contracts covering approximately 59.1 Bcf (162 MMcf/d) of natural gas production for 2015 at a weighted average index floor price of $4.05 per MMBtu.

• Proven and Stockholder-Aligned Management Team. Our management team possesses extensive oil and natural gas acquisition, exploration and development expertise in shale plays. For a discussion of our management’s experience, please read “Management.” Our Chief Executive Officer, Chief Operating Officer, Vice President of Exploration & Geology, Vice President of Completions and Vice President of Drilling have worked for us since we drilled our first horizontal Marcellus well. Our management team includes certain members of the Rice family (the founders of Rice Partners) who, along with other members of the management team, are also highly aligned with stockholders through a 33.4% economic interest in us upon completion of this offering. In addition, our management team has a significant indirect economic interest in us through their ownership of incentive units in the form of interests in Rice Holdings and NGP Holdings. The value of these incentive units may increase over time, without diluting public investors, if our stock price appreciates following the completion of this offering. For additional information regarding our incentive units, please read “Executive Compensation—Narrative Description to the Summary Compensation Table for the 2013 Fiscal Year—Long-Term Incentive Compensation.” We believe that our management team’s direct and indirect ownership interest in us will provide significant incentives to grow the value of our business.

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Recent Developments

Initial Utica Well

In the fourth quarter of 2013, we commenced drilling our initial Utica well, the Bigfoot 7H, in Belmont County, Ohio. In December 2013, after drilling approximately 1,200 feet of the lateral section within the Point Pleasant formation, the well unexpectedly began flowing gas with higher than anticipated bottomhole pressures of approximately 8,800 psi. We employed certain steps, including increasing our drilling mud weight, that successfully controlled the gas flow. However, certain uncased sections in the vertical portion of the wellbore were compromised by the higher mud weight, which ultimately inhibited our efforts to stabilize the gas flow and pressures. We elected to plug the Bigfoot 7H in late December 2013 and are preparing to drill a new horizontal well adjacent to the Bigfoot 7H with reconfigured mud and intermediate casing designs that are intended to better manage higher anticipated pressures and gas flows. We expect to obtain an initial production test from this well late in the first quarter or early in the second quarter of 2014. However, the ultimate timing of our initial production test for our next Utica well could be delayed by a number of factors, including an inability to address pressure concerns experienced by the Bigfoot 7H.

We believe that the pressures and natural flow rates experienced on the Bigfoot 7H indicate a highly permeable and porous Point Pleasant formation. However, these pressures may not be an indicator of the production amounts to be expected from future Utica wells. In addition, we may experience further difficulties drilling and completing Utica wells. Please read “Risk Factors—Risks Related to Our Business—We have been an early entrant into new or emerging plays. As a result, our drilling results in these areas are uncertain, and the value of our undeveloped acreage will decline if drilling results are unsuccessful.”

Marcellus Joint Venture Buy-In

On December 6, 2013, we entered into an agreement (the “Transaction Agreement”) with Foundation PA Coal Company, LLC (“Alpha Holdings”), a wholly owned indirect subsidiary of Alpha Natural Resources, Inc. Pursuant to the Transaction Agreement, Alpha Holdings has agreed to transfer its 50% interest in our Marcellus joint venture to us in exchange for total consideration of $300.0 million, consisting of $100.0 million of cash and our issuance to Alpha Holdings of 10,000,000 shares of our common stock (assuming an initial public offering price equal to the midpoint of the range set forth on the cover of this prospectus). The number of shares of our common stock to be issued to Alpha Holdings will be equal to $200.0 million divided by the price per share at which shares of common stock of Rice Energy are initially offered in this offering. A $1.00 decrease (or increase) in the public offering price would result in our issuance of an additional 526,316 shares (or 476,190 less shares) to Alpha Holdings. Please see “Dilution.” The closing of the transactions pursuant to the Transaction Agreement is subject to the satisfaction of customary closing conditions and the execution of a registration rights agreement and a stockholders’ agreement, each as described in “Certain Relationships and Related Party Transactions.” Assuming the satisfaction or waiver of the closing conditions, the closing of the transactions pursuant to the Transaction Agreement is expected to take place concurrently with, and is contingent upon, the consummation of this offering. The Transaction Agreement includes customary representations and warranties, covenants and indemnities from each of the parties thereto.

Utica Shale—Development Agreement and Area of Mutual Interest Agreement

On October 14, 2013, we entered into a Development Agreement and Area of Mutual Interest (“AMI”) Agreement with Gulfport Energy Corporation (“Gulfport”) covering approximately 50,000 aggregate net acres in the Utica Shale in Belmont County, Ohio. We refer to these agreements as our “Utica Development Agreements.” Pursuant to the Utica Development Agreements, we have an approximate 68.80% participating interest in acreage currently owned or subsequently acquired by us or Gulfport located within Goshen and Smith Townships, Belmont County, Ohio (the “Northern Contract Area”) and an approximate 42.63% participating interest in acreage currently owned or subsequently acquired by us or Gulfport located within Wayne and

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Washington Townships, Belmont County, Ohio (the “Southern Contract Area”). The remaining participating interests are held by Gulfport. The participating interests of us and Gulfport in each of the Northern and Southern Contract Areas approximate our current relative acreage positions in each area, with us and Gulfport respectively holding approximately 18,400 and 8,400 net acres in the Northern Contract Area and 9,700 and 13,100 net acres in the Southern Contract Area.

Pursuant to the Development Agreement, we are named the operator (or Gulfport will agree to vote in favor of our operatorship) of drilling units located in the Northern Contract Area, and Gulfport is named the operator (or we will agree to vote in favor of its operatorship) of drilling units located in the Southern Contract Area. Upon development of a well on the subject acreage, we and Gulfport, will convey to one another, pursuant to a cross conveyance, a working interest percentage equal to the amount of the underlying working interest multiplied by the applicable participating interest. For example, upon development of a well:

• Assuming an aggregate 90% working interest is held by us and/or Gulfport in the Northern Contract Area, we and Gulfport will make cross conveyances to one another such that we hold an approximately 61.92% (representing 68.80% of 90%) working interest and Gulfport holds an approximately 28.08% (representing 31.20% of 90%) working interest in the drilling unit; and

• Assuming an aggregate 90% working interest is held by us and/or Gulfport in the Southern Contract Area, we and Gulfport will make cross conveyances to one another such that we hold an approximate 38.37% (representing 42.63% of 90%) working interest and Gulfport holds an approximate 51.63% (representing 57.37% of 90%) working interest in the drilling unit.

As a result of the Development Agreement, we are the operator of approximately 27,000 aggregate net acres in the Northern Contract Area, and Gulfport is the operator of approximately 23,000 aggregate net acres in the Southern Contract Area. In addition, as wells are developed in the respective contract areas our average working interests in the Utica Shale will decrease as the applicable participating interests are applied to the developed wells.

Every six months during the term of the Development Agreement, we and Gulfport will establish a work program and budget detailing the proposed exploration and development to be performed in the Northern and Southern Contract Areas, respectively, for the following six months. The number of horizontal wells proposed to be drilled in each of the Northern Contract Area and Southern Contract Area is limited by the Development Agreement as follows: in 2014, between eight and 40 wells; in 2015, between eight and 50 wells; and thereafter, unlimited.

Pursuant to the AMI Agreement, each party has the right to participate at the level of its applicable participating interest in any acquisition by the other party of working interests or leases acquired within the AMIs. Unless a party elects not to participate therein upon notice by the other party, the subject working interest or lease will be governed by the Development Agreement.

The Utica Development Agreements have terms of ten years and are terminable upon 90 days’ notice by either party; provided that, with respect to interests included within a drilling unit, such interests shall remain subject to the applicable joint operating agreement and we and Gulfport shall remain operators of drilling units located in the Northern Contract Area and Southern Contract Area, respectively, following such termination.

Guernsey and Lycoming Asset Sales

In December 2013, we agreed to sell interests in noncore assets in Guernsey County, Ohio and Lycoming County, Pennsylvania in two separate transactions. We have agreed to sell an undivided 75.0% interest in certain of our Guernsey County leaseholds (representing approximately 2,136 net acres) to a third party in exchange for approximately $22.0 million, consisting of $11.0 million in cash and an $11.0 million carried working interest. In

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addition, we sold all of our Lycoming County acreage (100% non-operated) and related assets to another third party in exchange for $7.0 million. There was no production or net proved reserves attributable to the interests sold in either transaction.

Risk Factors

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

Corporate Sponsorship and Structure

We were recently incorporated pursuant to the laws of the State of Delaware as Rice Energy Inc. to become a holding company for Rice Drilling B LLC through the acquisition of its current parent holding company, Rice Energy Appalachia, LLC. Rice Drilling B LLC was formed as a Delaware limited liability company on February 12, 2008 by certain members of the Rice family, who currently serve as members of our senior management team. Since January 2012, private equity funds managed by Natural Gas Partners have made $300 million in equity investments in us. Natural Gas Partners, which was founded in 1988, is a family of private equity investment funds with aggregate committed capital under management since inception of over $10 billion and was organized to make direct equity investments in the energy industry.

Pursuant to the terms of a corporate reorganization that will be completed simultaneously with the closing of this offering, all of the interests in Rice Energy Appalachia, LLC, which are currently held primarily by Rice Partners, Rice Holdings and NGP Holdings, will be exchanged for common stock of Rice Energy Inc. As a result of the reorganization, Rice Energy Appalachia, LLC and Rice Drilling B LLC will become direct and indirect, respectively, wholly owned subsidiaries of Rice Energy Inc. For more information on our reorganization and the ownership of our common stock by our principal and selling stockholders, see “Corporate Reorganization” and “Principal and Selling Stockholders.”

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The following diagram indicates our simplified ownership structure after giving effect to our corporate reorganization, the Marcellus JV Buy-In and this offering (assuming an initial public offering price equal to the midpoint of the range set forth on the cover of this prospectus and that the underwriters’ option to purchase additional shares is not exercised and excluding the impact of shares of common stock issuable upon the conversion or exercise of convertible debentures and warrants described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity—Debt Agreements—Convertible Debentures and Warrants”).

Ownership Structure After Giving Effect to this Offering

(1) Two members of our board of directors, Scott A. Gieselman and Chris G. Carter, are Managing Directors of Natural Gas Partners, and Kevin S. Crutchfield will be designated by Alpha Natural Resources, Inc. Please see “Management—Board of Directors.”

(2) Following this offering, the convertible debentures and warrants of Rice Drilling B will be convertible or exercisable for 2,083,730 shares of common stock of Rice Energy Inc.

Our Principal Stockholders

Upon completion of this offering (assuming an initial public offering price equal to the midpoint of the range set forth on the cover of this prospectus), (i) Rice Holdings will initially own 20,311,125 shares of common stock, representing approximately 15.9% of our outstanding shares of common stock, (ii) Rice Partners will

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initially own 20,000,000 shares of common stock, representing approximately 15.6% of our outstanding shares of common stock, (iii) Daniel J. Rice III will initially own 2,374,652 shares of common stock, representing approximately 1.9% of our outstanding shares of common stock, (iv) NGP Holdings, the selling stockholder in this offering, will initially own 33,463,549 shares of common stock (or 27,463,549 shares if the underwriters’ option to purchase additional shares is exercised in full), representing approximately 26.1% (or 21.5% if the underwriters’ option to purchase additional shares is exercised in full) of our outstanding shares of common stock and (v) Alpha Holdings will initially own 10,000,000 shares of common stock, representing approximately 7.8% of our outstanding shares of common stock. For more information on our reorganization and the ownership of our common stock by our principal and selling stockholders, see “Corporate Reorganization” and “Principal and Selling Stockholders.”

Rice Drilling B was formed as a Delaware limited liability company on February 12, 2008 by members of the Rice family through Rice Partners. Since January 2012, private equity funds managed by Natural Gas Partners have made $300 million in equity investments in us. Natural Gas Partners, which was founded in 1988, is a family of private equity investment funds with aggregate committed capital under management since inception of $10 billion and was organized to make direct equity investments in the energy industry. Alpha Holdings is a wholly owned indirect subsidiary of Alpha Natural Resources, Inc., one of America’s premier coal suppliers operating in Northern and Central Appalachia and the Powder River Basin.

Emerging Growth Company Status

We are an “emerging growth company” as defined in the Jumpstart Our Business Startups Act, or the “JOBS Act.” For as long as we are an emerging growth company, unlike other public companies that are not emerging growth companies under the JOBS Act, we are not required to:

• provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act of 2002;

• provide more than two years of audited financial statements and related management’s discussion & analysis of financial condition and results of operations;

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

• provide certain disclosure regarding executive compensation required of larger public companies or hold shareholder advisory votes on executive compensation required by the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”); or

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

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

• the last day of the fiscal year in which we have $1.0 billion or more in annual revenues;

• the date on which we become a “large accelerated filer” (the fiscal year-end on which the total market value of our common equity securities held by non-affiliates is $700 million or more as of June 30);

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

• the last day of the fiscal year following the fifth anniversary of our initial public offering.

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

Corporate Information

Our principal executive offices are located at 171 Hillpointe Drive, Suite 301, Canonsburg, Pennsylvania 15317, and our telephone number is (724) 746-6720. Our website is www.riceenergy.com. We expect to make our periodic reports and other information filed with or furnished to the SEC available free of charge through our website as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. The information on, or otherwise accessible through, our website or any other website does not constitute a part of this prospectus.

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The Offering

Shares of common stock offered by us 30,000,000 shares.

Shares of common stock offered by the selling stockholder 10,000,000 shares (or 16,000,000 shares, if the underwriters exercise in full their option to purchase additional shares).

Shares of common stock to be outstanding after the offering 128,000,000 shares. The number of outstanding shares of our common stock includes shares to be issued in a concurrent private placement to Alpha Holdings as a portion of the consideration for our Marcellus JV Buy-In, which is dependent upon the price per share at which shares of our common stock are initially offered in this offering. A $1.00 decrease (or increase) in the public offering price would result in an additional 526,316 shares (or 476,190 less shares) outstanding following the completion of this offering.

Shares of common stock owned by our principal stockholders after the offering 20,311,125 shares, in the case of Rice Holdings; 20,000,000 shares, in the case of Rice Partners; 2,374,652 shares, in the case of Daniel J. Rice III; 33,463,549 shares (or 27,463,549 shares, if the underwriters exercise in full their option to purchase additional shares), in the case of NGP Holdings; and 10,000,000 shares, in the case of Alpha Holdings.

Option to purchase additional shares The selling stockholder has granted the underwriters a 30-day option to purchase up to an aggregate of 6,000,000 additional shares of our common stock to the extent the underwriters sell more than 40,000,000 shares of common stock in this offering.

Use of proceeds We expect to receive approximately $566.0 million of net proceeds (assuming an initial public offering price equal to the midpoint of the range set forth on the cover of this prospectus) from the sale of the common stock offered by us after deducting underwriting discounts and commissions and estimated offering expenses payable by us.

We intend to use the net proceeds from this offering (i) to repay all outstanding borrowings under the revolving credit facility of our Marcellus joint venture, (ii) to make a $100.0 million payment to Alpha Holdings in partial consideration for the Marcellus JV Buy-In, (iii) to repay all outstanding borrowings under our revolving credit facility and (iv) the remainder to fund a portion of our capital expenditure plan.

We will not receive any proceeds from the sale of shares of common stock by NGP Holdings, including pursuant to any exercise of the underwriters’ option to purchase additional shares. NGP Holdings is deemed under federal securities laws to be an underwriter with respect to the common stock it may sell in connection with this offering.

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Conflicts of interest Because an affiliate of Wells Fargo Securities, LLC is a lender under each of our revolving credit facility and our Marcellus joint venture’s revolving credit facility and will receive more than 5% of the net proceeds of this offering due to the repayment of borrowings thereunder, Wells Fargo Securities, LLC is deemed to have a conflict of interest within the meaning of Rule 5121 of the Financial Industry Regulatory Authority (“FINRA”). In accordance with that rule, the appointment of a “qualified independent underwriter” is not required in connection with this offering because the underwriter primarily responsible for managing this public offering does not have a “conflict of interest” under Rule 5121, is not an affiliate of any underwriter that does have a “conflict of interest” under Rule 5121 and meets the requirements of paragraph (f)(12)(E) of Rule 5121. Any underwriter that has a conflict of interest pursuant to Rule 5121 will not confirm sales to accounts in which it exercises discretionary authority without the prior written consent of the customer. See “Underwriting (Conflicts of Interest).”

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

Risk factors You should carefully read and consider the information set forth under the heading “Risk Factors” and all other information set forth in this prospectus before deciding to invest in our common stock.

Listing and trading symbol We have been approved to list our common stock on the New York Stock Exchange (the “NYSE”) under the symbol “RICE”, subject to official notice of issuance.

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Summary Historical Consolidated and Unaudited Pro Forma Financial Data

The following table shows summary historical consolidated financial data of Rice Drilling B, our accounting predecessor, and summary unaudited pro forma financial data for the periods and as of the dates indicated. Our historical results are not necessarily indicative of future operating results. The summary financial data presented below are qualified in their 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 summary historical consolidated financial data as of and for the years ended December 31, 2011 and 2012 are derived from the audited consolidated financial statements of Rice Drilling B included elsewhere in this prospectus. The summary historical statement of operations data for the nine months ended September 30, 2012 and 2013 and the historical balance sheet data as of September 30, 2013 are derived from the unaudited consolidated financial statements of Rice Drilling B included elsewhere in this prospectus. The summary historical unaudited historical consolidated interim financial data has been prepared on a consistent basis with the audited consolidated financial statements of Rice Drilling B. In the opinion of management, such summary unaudited historical consolidated financial interim data reflects all adjustments (consisting of normal and recurring accruals) considered necessary to present our financial position for the periods presented. The results of operations for the interim periods are not necessarily indicative of the results that may be expected for the full year because of the impact of fluctuations in prices received from oil and natural gas, natural production declines, the uncertainty of exploration and development drilling results and other factors.

The summary unaudited pro forma consolidated statements of operations data for the nine months ended September 30, 2013 and for the year ended December 31, 2012 has been prepared to give pro forma effect to (i) the Marcellus JV Buy-In described under “Summary—Recent Developments—Marcellus JV Buy-In,” (ii) the reorganization transactions described under “Corporate Reorganization” and (iii) this offering and the application of the net proceeds from this offering as if they had been completed as of January 1, 2012. The summary unaudited pro forma consolidated balance sheet data as of September 30, 2013 has been prepared to give pro forma effect to those transactions as if they had been completed as of September 30, 2013. These data are subject and give effect to the assumptions and adjustments described in the notes accompanying the unaudited pro forma financial statements included elsewhere in this prospectus. The summary unaudited pro forma consolidated financial data are presented for informational purposes only and should not be considered indicative of actual results of operations that would have been achieved had the reorganization transactions and this offering been consummated on the dates indicated, and do not purport to be indicative of statements of financial position or results of operations as of any future date or for any future period.

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	Rice Drilling B												Rice Energy Inc.
	Year Ended December 31,						Nine Months Ended September 30,						Pro Forma
													Year Ended December 31, 2012			Nine Months Ended September 30, 2013
	2011			2012			2012			2013
							(Unaudited)						(Unaudited)
(in thousands, except per share data)
Statement of operations data:
Revenues:
Natural gas sales	$	13,972		$	26,743		$	15,527		$	60,219		$	53,027		$	123,157
Other revenue		—			457			—			519			457			519
Total revenues		13,972			27,200			15,527			60,738			53,484			123,676
Operating expenses:
Lease operating		1,630			3,821			2,226			5,794			7,152			11,892
Gathering, compression and transportation		527			3,621			2,413			6,951			10,292			17,995
Production taxes and impact fees		—			1,382			1,165			1,029			2,251			1,691
Exploration		660			3,275			2,850			1,784			3,275			1,784
Restricted unit expense		170			—			—			40,087			—			40,087
General and administrative		5,208			7,599			5,374			9,952			9,657			11,952
Depreciation, depletion and amortization		5,981			14,149			10,209			23,215			28,342			52,836
Amortization of deferred financing costs		2,675			7,220			5,540			4,760			7,235			4,867
Write-down of abandoned leases		109			2,253			2,223			—			2,253			—
Gain from sale of interest in gas properties		(1,478	)		—			—			—			—			—
Total expenses		15,482			43,320			32,000			93,572			70,457			143,104
Operating loss		(1,510	)		(16,120	)		(16,473	)		(32,834	)		(16,973	)		(19,428	)
Interest expense		(531	)		(3,487	)		(1,801	)		(13,033	)		(3,859	)		(12,660	)
Other income (expense)		161			112			76			(347	)		112			(1,249	)
Gain (loss) on derivative instruments		574			(1,381	)		(3,407	)		16,698			(1,455	)		30,626
Loss on extinguishment of debt		—			—			—			(10,622	)		—			(10,622	)
Equity in income (loss) of joint ventures		370			1,532			(136	)		19,297			(209	)		(3	)
Loss before income taxes		(936	)		(19,344	)		(21,741	)		(20,841	)		(22,384	)		(13,336	)
Income tax benefit		—			—			—			—			9,288			5,534
Net loss	$	(936	)	$	(19,344	)	$	(21,741	)	$	(20,841	)	$	(13,096	)	$	(7,802	)
Balance sheet data (at period end):
Cash	$	4,389		$	8,547					$	27,661					$	425,493
Total property and equipment, net		150,646			273,640						613,702						948,787
Total assets		190,240			344,971						751,397						1,782,113
Total debt		107,795			149,320						312,314						312,314
Total members’ / stockholders’ capital		46,821			138,191						315,337						1,149,166
Net cash provided by (used in):
Operating activities	$	5,131		$	(3,014	)	$	(7,839	)	$	20,223
Investing activities		(79,245	)		(119,973	)		(85,591	)		(342,625	)
Financing activities		73,447			127,145			96,008			341,516
Other financial data (unaudited):
Adjusted EBITDAX (1)	$	7,342		$	11,768		$	5,823		$	24,990		$	25,186		$	68,612
Earnings per share—basic													$	(0.10	)	$	(0.06	)
Earnings per share—diluted													$	(0.10	)	$	(0.06	)

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

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Non-GAAP Financial Measures

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

We define Adjusted EBITDAX as net income (loss) before interest expense or interest income; income taxes; write-down of abandoned leases; impairments; depreciation, depletion and amortization; amortization of deferred financing costs; equity in (income) loss in our Marcellus joint venture; derivative fair value (gain) loss, excluding net cash receipts on settled derivative instruments; non-cash compensation expense; gain from sale of interest in gas properties; and exploration expenses. Adjusted EBITDAX is not a measure of net income as determined by United States generally accepted accounting principles, or GAAP.

Management believes Adjusted EBITDAX is useful because it allows them to more effectively evaluate our operating performance and compare the results of our operations from period to period and against our peers without regard to our financing methods or capital structure. We exclude the items listed above from net income in arriving at Adjusted EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDAX. Our computations of Adjusted EBITDAX may not be comparable to other similarly titled measures of other companies. We believe that Adjusted EBITDAX is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet debt service requirements.

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The following tables present a reconciliation of the non-GAAP financial measure of Adjusted EBITDAX to the GAAP financial measure of net income (loss) for each of us and our Marcellus joint venture.

	Rice Drilling B												Rice Energy Inc. Pro Forma
	Year Ended December 31,						Nine Months Ended September 30,						Year Ended December 31,			Nine Months Ended September  30,
	2011			2012			2012			2013			2012			2013
							(Unaudited)						(Unaudited)
(in thousands)
Adjusted EBITDAX reconciliation to net income (loss):
Net loss	$	(936	)	$	(19,344	)	$	(21,741	)	$	(20,841	)	$	(13,096	)	$	(7,802	)
Interest expense		531			3,487			1,801			13,033			3,859			12,660
Depreciation, depletion and amortization		5,981			14,149			10,209			23,215			28,342			52,836
Amortization of deferred financing costs		2,675			7,220			5,540			4,760			7,235			4,867
Equity in (income) loss of joint ventures		(370	)		(1,532	)		136			(19,297	)		209			3
Write-down of abandoned leases		109			2,253			2,223			—			2,253			—
Derivative fair value (gain) loss (1)		(574	)		1,381			3,407			(16,698	)		1,455			(30,626	)
Net cash receipts (payments) on settled derivative instruments (1)		574			879			1,398			(1,053	)		942			337
Restricted unit expense		170			—			—			40,087			—			40,087
Income tax benefit		—			—			—			—			(9,288	)		(5,534	)
Gain from sale of interest in gas properties		(1,478	)		—			—			—			—			—
Exploration expenses		660			3,275			2,850			1,784			3,275			1,784
Adjusted EBITDAX	$	7,342		$	11,768		$	5,823		$	24,990		$	25,186		$	68,612

(1) The adjustments for the derivative fair value (gains) losses and net cash receipts on settled commodity derivative instruments have the effect of adjusting net income (loss) for changes in the fair value of derivative instruments, which are recognized at the end of each accounting period because we do not designate commodity derivative instruments as accounting hedges. This results in reflecting commodity derivative gains and losses within Adjusted EBITDAX on a cash basis during the period the derivatives settled.

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Summary Pro Forma Reserve and Operating Data

Summary Reserve Data

The following table summarizes our pro forma estimated proved reserves as of December 31, 2012 and as of September 30, 2013 giving effect to our Marcellus JV Buy-In described under “Summary—Recent Developments—Marcellus JV Buy-In.” The estimated proved reserves as of December 31, 2012 and as of September 30, 2013 are based on reports prepared by our and our Marcellus joint venture’s independent reserve engineers, NSAI. Copies of the summary reports of NSAI with respect to reserves as of December 31, 2012 and as of September 30, 2013 are filed as exhibits to the registration statement of which this prospectus forms a part. See “Business—Our Operations—Reserve Data—Preparation of Reserve Estimates” for definitions of proved reserves and the technologies and economic data used in their estimation.

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

	Rice Energy Inc. Pro Forma (1)
	At December 31,            2012			At September 30, 2013
	(Unaudited)
Estimated proved reserves—Natural gas (Bcf):
Total estimated proved reserves		561			552
Total proved developed reserves		131			193
Proved developed producing reserves		101			167
Proved developed non-producing reserves		30			26
Proved undeveloped reserves		430			359
Percent developed reserves		23	%		35	%

(1) Our estimated pro forma proved reserves were determined using a 12-month average price for natural gas. The prices used in our reserve reports yield weighted average wellhead prices, which are based on index prices and adjusted for energy content, transportation fees and regional price differentials. The index prices and the equivalent wellhead prices are shown in the table below.

	Index Prices— Natural Gas (per MMBtu)		Weighted Average  Wellhead Prices— Natural Gas (per Mcf)
December 31, 2012	$	2.76	$	2.85
September 30, 2013		3.61		3.84

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Production, Revenues and Price History

The following table sets forth pro forma information regarding production, revenues and realized prices, and production costs for the years ended December 31, 2012, for the nine months ended September 30, 2013 giving effect to our Marcellus JV Buy-In described under “—Recent Developments—Marcellus JV Buy-In. ”

	For the Year Ended December 31,		Nine Months Ended September 30,
	2012		2013
Natural gas sales (in thousands)	$	53,027	$	123,157
Production data (MMcf)		17,361		31,688
Average prices before effects of hedges per Mcf	$	3.05	$	3.89
Average realized prices after effects of hedges per Mcf (1)	$	3.11	$	3.90
Average costs per Mcf (2)
Lease operating	$	0.41	$	0.38
Gathering, compression and transportation		0.59		0.57
General and administrative		0.56		0.38
Depletion, depreciation and amortization		1.63		1.67

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

(2) Does not include production taxes and impact fees. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Principal Components of our Cost Structure.”

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RISK FACTORS

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

Risks Related to Our Business

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

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

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

• the price and quantity of imports of foreign natural gas, including liquefied natural gas;

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

• the level of global exploration and production;

• the level of global inventories;

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

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

• localized and global supply and demand fundamentals and transportation availability;

• weather conditions and other natural disasters;

• technological advances affecting energy consumption;

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

• speculative trading in natural gas and crude oil derivative contracts;

• risks associated with operating drilling rigs;

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

• domestic, local and foreign governmental regulation and taxes.

Furthermore, the worldwide financial and credit crisis in recent years has reduced the availability of liquidity and credit to fund the continuation and expansion of industrial business operations worldwide resulting in a slowdown in economic activity and recession in parts of the world. This has reduced worldwide demand for energy and resulted in lower natural gas, NGL and oil prices.

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In addition, substantially all of our natural gas production is sold to purchasers under contracts with market-based prices based on New York Mercantile Exchange (“NYMEX”) Henry Hub prices. 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. We may experience differentials to NYMEX Henry Hub prices in the future, which may be material.

Lower commodity prices and negative increases in our differentials will reduce our cash flows and borrowing ability. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our reserves as existing reserves are depleted. Lower commodity prices may also reduce the amount of natural gas, NGLs and oil that we can produce economically.

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

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

The natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures for the development and acquisition of natural gas reserves. In 2014, excluding $100 million cash to be paid with respect to the Marcellus JV Buy-In, we plan to invest $1,080 million in our operations, including $299 million for drilling and completion in the Marcellus Shale, $132 million for drilling and completion in the Utica Shale, $386 million for leasehold acquisitions (of which approximately $108 million is currently committed and the remainder is discretionary) and $263 million for midstream infrastructure development. Our capital budget excludes acquisitions, other than leasehold acquisitions. We expect to fund our 2014 capital expenditures with cash generated by operations, borrowings under our revolving credit facility and a portion of the net proceeds of this offering. Our 2014 capital expenditure budget also assumes that the borrowing base under our revolving credit facility is increased during 2014. If our lenders do not increase our borrowing base, we may seek alternate debt financing or reduce our capital expenditures. In addition, a portion of our 2014 capital budget is projected to be financed with cash flows from operations derived from wells drilled on drilling locations not associated with proved reserves in our September 30, 2013 reserve report. The failure to achieve projected production and cash flows from operations from such wells could result in a reduction to our 2014 capital budget. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, natural gas prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments. A reduction in natural gas prices from current levels may result in a decrease in our actual capital expenditures, which would negatively impact our ability to grow production. We intend to finance our future capital expenditures primarily through cash flow from operations and through borrowings under our revolving credit facilities; however, our financing needs may require us to alter or increase our capitalization substantially through the issuance of debt or equity securities or the sale of assets. The issuance of additional indebtedness would require that a portion of our cash flow from operations be used for the payment of interest and principal on our indebtedness, thereby reducing our ability to use cash flow from operations to fund working capital, capital expenditures and acquisitions.

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

• our proved reserves;

• the level of hydrocarbons we are able to produce from existing wells;

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• the prices at which our production is sold;

• our ability to acquire, locate and produce new reserves;

• the levels of our operating expenses; and

• our ability to borrow under our revolving credit facility.

If our revenues or the borrowing base under our revolving credit facility decrease as a result of lower natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms acceptable to us, if at all. If cash flow generated by our operations or available borrowings under our revolving credit facility are not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our properties, which in turn could lead to a decline in our reserves and production, and could adversely affect our business, financial condition and results of operations.

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

We completed our first horizontal well in the Marcellus Shale in October 2010 and began to delineate our Utica Shale leasehold position in October 2013. While our costs to acquire undeveloped acreage in new or emerging plays have generally been less than those of later entrants into a developing play, our drilling results in these areas are more uncertain than drilling results in areas that are developed and producing. Since new or emerging plays have limited or no production history and since we have no experience drilling in these plays (including the Utica Shale), we are unable to use past drilling results in those areas to help predict our future drilling results. As a result, our cost of drilling, completing and operating wells in these areas may be higher than initially expected, and the value of our undeveloped acreage will decline if drilling results are unsuccessful. Additionally, we cannot assure you that all prospects will be economically viable or that we will not abandon our investments. For example, as a result of unexpected levels of pressure, in December 2013 we plugged and abandoned the first well we spud in the Utica Shale. Please see “Prospectus Summary—Recent Developments—Initial Utica Well.” We cannot assure you that unproved property acquired by us or undeveloped acreage leased by us will be profitably developed, that wells drilled by us in prospects that we pursue will be productive or that we will recover all or any portion of our investment in such unproved property or wells.

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

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

• effectively controlling the level of pressure flowing from particular wells;

• landing our wellbore in the desired drilling zone;

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

• running our casing the entire length of the wellbore; and

• being able to run tools and other equipment consistently through the horizontal wellbore.

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

• the ability to fracture stimulate the planned number of stages;

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

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

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The results of our drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas have limited or no production history and, consequently, we are more limited in assessing future drilling results in these areas. If our drilling results are less than anticipated, the return on our investment for a particular project may not be as attractive as we anticipated and we could incur material write-downs of unevaluated properties and the value of our undeveloped acreage could decline in the future.

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

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

Our decisions to purchase, explore or develop prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these processes, see “—Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.” In addition, our cost of drilling, completing and operating wells is often uncertain before drilling commences.

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

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

• pressure or irregularities in geological formations;

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

• equipment failures, accidents or other unexpected operational events;

• lack of available gathering facilities or delays in construction of gathering facilities;

• lack of available capacity on interconnecting transmission pipelines;

• adverse weather conditions, such as blizzards and ice storms;

• issues related to compliance with environmental regulations;

• environmental hazards, such as natural gas leaks, oil spills, pipeline and tank ruptures, encountering naturally occurring radioactive materials, and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;

• declines in natural gas prices;

• limited availability of financing at acceptable terms;

• title problems; and

• limitations in the market for natural gas.

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

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We have incurred losses from operations for various periods since our inception and may do so in the future.

We incurred a net loss of $19.3 million for the year ended December 31, 2012. 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 natural gas reserves. As a result, we may not be able to 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 $500 million first lien secured revolving credit facility and our $300 million second lien secured term loan, depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness.

If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance indebtedness. Our ability to restructure or refinance indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. The terms of existing or future debt instruments may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet debt service and other obligations. Our revolving credit facility currently restricts our ability to dispose of assets and our use of the proceeds from such disposition. We may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations.

The borrowing base under our $500 million revolving credit facility is currently $155 million, and we anticipate that it will be increased to $350 million concurrent with the closing of this offering as a result of the Marcellus JV Buy-In. Our next scheduled borrowing base redetermination is expected to occur in April 2014. In the future, we may not be able to access adequate funding under our revolving credit facility as a result of a decrease in borrowing base due to the issuance of new indebtedness, the outcome of a subsequent borrowing base redetermination or an unwillingness or inability on the part of lending counterparties to meet their funding obligations and the inability of other lenders to provide additional funding to cover the defaulting lender’s portion. Declines in commodity prices could result in a determination to lower the borrowing base in the future and, in such a case, we could be required to repay any indebtedness in excess of the redetermined borrowing base. As a result, we may be unable to implement our drilling and development plan, make acquisitions or otherwise carry out business plans, which would have a material adverse effect on our financial condition and results of operations and impair our ability to service our indebtedness.

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

Our producing properties are geographically concentrated in the Marcellus Shale and Upper Devonian Shale formations in Washington and Greene Counties, Pennsylvania. At December 31, 2012, all of our total estimated

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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 or other drought related conditions or interruption of the processing or transportation of oil, natural gas or NGLs. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations. In addition, a number of areas within the Marcellus Shale and Utica Shale 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. For example, in connection with entering into the Marcellus JV Buy-In, we have agreed to continue to acknowledge the dominance of mining by Alpha Natural Resources, Inc. within the area of mutual interest of our Marcellus joint venture. As such, in addition to coordinating with Alpha Holdings on, and in certain circumstances obtaining the prior approval of Alpha Holdings for, future drilling operations, we may also be required to take steps to assure the dominance of the mining operations of Alpha Natural Resources, Inc., including the plugging and abandonment of wells at the direction of Alpha Holdings upon two years notice. 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 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.

During the term of the Utica Development Agreements, we will rely on Gulfport for the success of our project in the Southern Contract Area in Belmont County, Ohio, and we may not be able to maximize the value of our properties in the Southern Contract Area as we deem best because we are not in full control of this project.

During the term of the Utica Development Agreements, the success of our operation in the Southern Contract Area in Belmont County, Ohio, will depend in part on the ability of Gulfport to effectively exploit the acreage it operates under the Development Agreement. Please read “Business—Our Properties—Utica Shale—Development Agreement and Area of Mutual Interest Agreement.” Pursuant to the Development Agreement, we have designated Gulfport as the operator of our existing and future acreage in the Southern Contract Area. A failure or inability of Gulfport to adequately exploit the acreage it operates would have a significant impact on our results of operations. In addition, other than limitations set forth in the terms of the Development Agreement, we do not control the amount of capital that Gulfport may require for development of properties in the Southern Contract Area. Accordingly, we may be required to allocate capital to development of the Southern Contract Area at times when we otherwise would allocate capital to the Northern Contract Area, our Marcellus Shale acreage or elsewhere or otherwise be forced to terminate the Utica Development Agreements. Under any of these circumstances, our prospects for realization of the potential value of the oil, natural gas and NGL reserves associated with the Southern Contract Area could be adversely affected. Our lack of control may limit our ability to develop our properties in the manner we believe to be in our best interest.

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 such as us. Although additional Appalachian Basin takeaway capacity has been added in 2012 and 2013, we do not believe the existing and expected capacity will be sufficient to keep pace with the increased production caused by accelerated drilling in the area. We expect that a significant portion of our production from the Utica Shale will be transported on pipelines that experience a differential to NYMEX Henry Hub prices. 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.

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We are required to pay fees to our service providers based on minimum volumes regardless of actual volume throughput.

We have various gas transportation service agreements in place, each with minimum volume delivery commitments. As of December 1, 2013, our average annual contractual firm transportation obligations for 2014, 2015 and 2016 were approximately 267,000 MMBtu/d, 266,000 MMBtu/d, and 372,000 MMBtu/d, respectively, which for certain periods is in excess of our pro forma average daily operated production of 217,000 MMBtu/d for November 2013. In addition, we expect to enter into a new firm transportation contract for an incremental 45 MMBtu/d, 270,000 MMBtu/d and 270,000 MMBtu/d, respectively, for each of 2014, 2015 and 2016 in January 2014. While we believe that our future natural gas volumes will be sufficient to satisfy the minimum requirements under our gas transportation services agreements based on our current production and our exploration and development plan, we can provide no such assurances that such volumes will be sufficient. We are obligated to pay fees on minimum volumes to our service providers regardless of actual volume throughput, which could be significant. If these fees on minimum volumes are substantial, we may not be able to generate sufficient cash to cover these 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 and second lien term loan each contain a number of significant covenants (in addition to covenants restricting the incurrence of additional indebtedness), including restrictive covenants that may limit our ability to, among other things:

• sell assets;

• make loans to others;

• make investments;

• enter into mergers;

• make certain payments;

• hedge future production or interest rates;

• incur liens;

• engage in certain other transactions without the prior consent of the lenders; and

• pay dividends.

In addition, our credit facilities require us to maintain certain financial ratios or to reduce our indebtedness if we are unable to comply with such ratios. On certain occasions in the past we have not met these financial covenants. Our convertible debentures also require us to maintain certain financial ratios that could limit our ability to incur additional indebtedness. These restrictions may also 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 credit facilities and our convertible debentures impose on us.

Any significant reduction in our borrowing base 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 a borrowing base amount, which the lenders, in their sole discretion, determine on a semi-annual basis based upon projected revenues from the natural gas properties securing our loan. The lenders can unilaterally adjust the borrowing base and the borrowings

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permitted to be outstanding under our revolving credit facility. Any increase in the borrowing base requires the consent of the lenders holding 100% of the commitments. If the requisite number of lenders do not agree to an increase, then the borrowing base will be the lowest borrowing base acceptable to such lenders. Outstanding borrowings in excess of the borrowing base must be repaid, or we must pledge other natural gas properties as additional collateral after applicable grace periods. We do not currently have any substantial unpledged properties, and we may not have the financial resources in the future to make mandatory principal prepayments required under our revolving credit facility. The borrowing base under our revolving credit facility is currently $155 million, and we anticipate that it will be increased to $350 million concurrent with the closing of this offering as a result of the Marcellus JV Buy-In. Our next scheduled borrowing base redetermination is expected to occur in April 2014.

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

In certain circumstances we may have to purchase commodities on the open market or make cash payments under our hedging arrangements and these payments could be significant.

If our production is less than the volume commitments under our hedging arrangements, or if natural gas or oil prices exceed the price at which we have hedged our commodities, we may be obligated to make cash payments to our hedge counterparties or purchase the volume difference at market prices, which could, in certain circumstances, be significant. As of December 1, 2013, we had entered into hedging contracts through December 31, 2017 covering a total of approximately 186 Bcf of our projected natural gas production at a weighted average price of $4.09 per MMBtu. For the period from January 1, 2014 until December 31, 2014, we have hedged approximately 60 Bcf of our projected natural gas production at a weighted average price of $4.05 per MMBtu. If we have to purchase additional commodities on the open market or post cash collateral to meet our obligations under such arrangements, our cash otherwise available for use in our operations would be reduced.

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

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

In order to prepare reserve estimates, we must project production rates and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.

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

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

Reserve estimates for fields that do not have a lengthy production history are less reliable than estimates for fields with lengthy production histories. Less production history may contribute to less accurate estimates of reserves, future production rates and the timing of development expenditures. Most of our producing wells have been operational for less than one year and estimated reserves vary substantially from well to well and are not directly correlated to perforated lateral length or completion technique. Furthermore, the lack of operational history for horizontal wells in the Utica Shale may also contribute to the inaccuracy of future estimates of reserves and could result in our failing to achieve expected results in the play. A material and adverse variance of actual production, revenues and expenditures from those underlying reserve estimates or, in the case of the Utica Shale, 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 substantial amount of capital that would be necessary to drill our identified drilling locations.

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

As of December 1, 2013, we had 1,313 gross (752 net) pro forma identified drilling locations. As a result of the limitations described above, we may be unable to drill many of our identified drilling locations. In addition, we will require significant additional capital over a prolonged period in order to pursue the development of these locations, and we may not be able to raise or generate the capital required to do so. Any drilling activities we are able to conduct on these potential locations may not be successful or result in our ability to add additional proved reserves to our overall proved reserves or may result in a downward revision of our estimated proved reserves, which could have a material adverse effect on our future business and results of operations. For more information on our identified drilling locations, see “Business—Our Operations—Reserve Data—Determination of Identified Drilling Locations.”

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

Leases on our oil and natural gas properties typically have a term of three to five years, after which they expire unless, prior to expiration, production is established within the spacing units covering the undeveloped

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acres. As of December 1, 2013, on a pro forma basis, we had leases representing 60 undeveloped acres scheduled to expire in 2013, 1,348 undeveloped acres scheduled to expire in 2014, 2,365 undeveloped acres scheduled to expire in 2015, 4,132 undeveloped acres scheduled to expire in 2016 and 61,274 undeveloped acres scheduled to expire in 2017 and beyond. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. Moreover, many of our leases require lessor consent to unitize, which may make it more difficult to hold our leases by production. Any reduction in our current drilling program, either through a reduction in capital expenditures or the unavailability of drilling rigs, could result in the loss of acreage through lease expirations. In addition, in order to hold our current leases scheduled to expire in 2014 and 2015, we will need to operate at least a one-rig program. We cannot assure you that we will have the liquidity to deploy rigs when needed, or that commodity prices will warrant operating such a drilling program. Our reserves and future production and, therefore, our future cash flow and income are highly dependent on successfully developing our undeveloped leasehold acreage and the loss of any leases could materially and adversely affect our ability to so develop such acreage.

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

You should not assume that the standardized measure of discounted future net cash flows from our proved reserves is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements in effect at December 31, 2011 and 2012, we based the discounted future net cash flows from our proved reserves on the 12-month first-day-of-the-month oil and natural gas average prices without giving effect to derivative transactions. Actual future net cash flows from our oil and natural gas properties will be affected by factors such as:

• actual prices we receive for oil and natural gas;

• actual cost of development and production expenditures;

• the amount and timing of actual production; and

• changes in governmental regulations or taxation.

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

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

Leases in the Appalachian Basin are particularly vulnerable to title deficiencies due the long history of land ownership in the area, resulting in extensive and complex chains of title. In the course of acquiring the rights to develop oil and natural gas, it is standard procedure for us and the lessor to execute a lease agreement with payment subject to title verification. In most cases, we incur the expense of retaining lawyers to verify the rightful owners of the oil and gas interests prior to payment of such lease bonus to the lessor. There is no certainty, however, that a lessor has valid title to their lease’s oil and gas interests. In those cases, such leases are generally voided and payment is not remitted to the lessor. As such, title failures may result in fewer net acres to us. Prior to the drilling of an oil or natural gas well, however, it is the normal practice in our industry for the person or company acting as the operator of the well to obtain a preliminary title review to ensure there are no

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obvious defects in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct defects in the marketability of the title, and such curative work entails expense. Our failure to cure any title defects may delay or prevent us from utilizing the associated mineral interest, which may adversely impact our ability in the future to increase production and reserves. Accordingly, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss.

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 September 30, 2013, on a pro forma basis, approximately 35% of our total estimated proved reserves were classified as proved undeveloped. Our approximately 359 Bcf of pro forma estimated proved undeveloped reserves will require an estimated $304 million of development capital over the next five years. Development of these undeveloped reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Delays in the development of our reserves, increases in costs to drill and develop such reserves, or decreases in commodity prices will reduce the PV-10 value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our proved undeveloped reserves as unproved reserves.

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

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

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

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

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

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

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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, we enter into derivative instrument contracts for a significant portion of our natural gas production, including fixed-price swaps. As of December 1, 2013, we had entered into hedging contracts through December 31, 2017 covering a total of approximately 186 Bcf of our projected natural gas production at a weighted average price of $4.09 per MMBtu. For the period from January 1, 2014 until December 31, 2014, we have hedged approximately 60 Bcf of our projected natural gas production at a weighted average price of $4.05 per MMBtu. Accordingly, our earnings may fluctuate significantly as a result of changes in fair value of our derivative instruments.

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

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

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

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

• there are issues with regard to legal enforceability of such instruments.

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

Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the derivative contract and we may not be able to realize the benefit of the derivative contract. As of September 30, 2013, the estimated fair value of our commodity derivative contracts was approximately $15.5 million. Any default by the counterparty to these derivative contracts, Wells Fargo Bank N.A., 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 ($1.8 million at December 31, 2012) and the sale of our natural gas production ($5.6 million in receivables at December 31, 2012), which we market to two natural gas marketing companies. Joint interest receivables arise from billing entities who own partial interest in the wells we operate. These entities participate in our wells primarily based on their ownership in leased properties on which we wish to drill. We can do very little to choose who participates in our wells. We are also subject to credit risk due to concentration of our natural gas receivables with two natural gas marketing companies. The largest purchaser of our natural gas during the twelve months ended December 31, 2012 purchased approximately 100% of our operated production. We do not require our customers to post collateral. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.

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

Substantial costs, liabilities, delays and other significant issues could arise from environmental laws and regulations inherent in drilling and well completion, gathering, transportation, and storage, and we may incur substantial costs and liabilities in the performance of these types of operations. Our operations are subject to extensive federal, regional, state and local laws and regulations governing environmental protection, the discharge of materials into the environment and the security of chemical and industrial facilities. These laws include:

• Clean Air Act (“CAA”) and analogous state law, which impose obligations related to air emissions;

• Clean Water Act (“CWA”), and analogous state law, which regulate discharge of wastewaters and storm water from some our facilities into state and federal waters, including wetlands;

• Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), and analogous state law, which regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or locations to which we have sent wastes for disposal;

• Resource Conservation and Recovery Act (“RCRA”), and analogous state law, which impose requirements for the handling and discharge of any solid and hazardous waste from our facilities;

• National Environmental Policy Act (“NEPA”), which requires federal agencies to study likely environmental impacts of a proposed federal action before it is approved, such as drilling on federal lands;

• Safe Drinking Water Act (“SDWA”), and analogous state law, which restrict the disposal, treatment or release of water produced or used during oil and gas development;

• Endangered Species Act (“ESA”), and analogous state law, which seek to ensure that activities do not jeopardize endangered or threatened animals, fish and plant species, nor destroy or modify the critical habitat of such species; and

• Oil Pollution Act (“OPA”) of 1990, which requires oil storage facilities and vessels to submit to the federal government plans detailing how they will respond to large discharges, requires updates to technology and equipment, regulates above ground storage tanks and sets forth liability for spills by responsible parties.

Various governmental authorities, including the EPA, the U.S. Department of the Interior, the Bureau of Indian Affairs and analogous state agencies and tribal governments, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly actions. 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.

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 certain environmental laws and regulations, including CERCLA, RCRA 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

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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.

In March 2010, the EPA announced its National Enforcement Initiatives for 2011 to 2013, which includes “Assuring Energy Extraction Activities Comply with Environmental Laws.” According to the EPA’s website, “some techniques for natural gas extraction pose a significant risk to public health and the environment.” To address these concerns, the EPA’s goal is to “address incidences of noncompliance from natural gas extraction and production activities that may cause or contribute to significant harm to public health and/or the environment.” 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.

Our business may be adversely affected by increased costs due to stricter pollution control equipment requirements or liabilities resulting from non-compliance with required operating or other regulatory permits. Also, we might not be able to obtain or maintain from time to time all required environmental regulatory approvals for our operations. If there is a delay in obtaining any required environmental regulatory approvals, or if we fail to obtain and comply with them, the operation or construction of our facilities could be prevented or become subject to additional costs.

We are generally 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 certain 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 certain 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.

We make assumptions and develop expectations about possible expenditures related to environmental conditions 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, and any new capital costs may be incurred to comply with such changes. In addition, new environmental laws and regulations might adversely affect our products and activities, including drilling, processing, storage and transportation, as well as waste management and air emissions. For instance, federal and state agencies could impose additional safety requirements, any of which could affect our profitability. Further, new environmental laws and regulations might adversely affect our customers, which in turn could affect our profitability.

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

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. Hydraulic fracturing involves the injection of water, sand or alternative proppant and chemicals under pressure into target geological formations to fracture the surrounding rock and stimulate production. We regularly use hydraulic fracturing as part of our operations. Recently, there has been increased public concern regarding an alleged potential for hydraulic fracturing to adversely affect drinking water supplies, and proposals have been made to enact separate federal, state and local legislation that would increase the regulatory burden imposed on hydraulic fracturing. The SDWA regulates the underground injection of substances through the Underground Injection Control (“UIC”) program and exempts hydraulic fracturing from the definition of “underground injection”. Congress has in recent legislative sessions considered legislation to amend the SDWA, including legislation that would repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic

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fracturing, as well as require disclosure of the chemical constituents of the fluids used in the fracturing process. The U.S. Congress may consider similar SDWA legislation in the future.

In addition, EPA has asserted federal regulatory authority pursuant to the SDWA over certain hydraulic fracturing activities involving the use of diesel fuels and published draft permitting guidance in May 2012 addressing the performance of such activities using diesel fuels in those states where EPA is the permitting authority. Also, in November 2011, the EPA announced its intent to develop and issue regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing and the agency currently plans to issue a Notice of Proposed Rulemaking that would seek public input on the design and scope of such disclosure regulations. To date, the EPA has not issued a Notice of Proposed Rulemaking; therefore, it is unclear how any federal disclosure requirements that add to any applicable state disclosure requirements already in effect may affect our operations. Further, on October 21, 2011, the EPA announced its intention to propose federal Clean Water Act regulations by 2014 governing wastewater discharges from hydraulic fracturing and certain other natural gas operations. In addition, the U.S. Department of the Interior published a revised proposed rule on May 16, 2013, that would update existing regulation of hydraulic fracturing activities on federal lands, including requirements for chemical disclosure, well bore integrity and handling of flowback water. The revised proposed rule was subject to an extended 90-day public comment period, which ended on August 23, 2013.

Presently, hydraulic fracturing is regulated primarily at the state level, typically by state oil and natural gas commissions and similar agencies. Along with several other states, Pennsylvania (where we conduct operations) has adopted laws and proposed regulations that require oil and natural gas operators to disclose chemical ingredients and water volumes used to hydraulically fracture wells, in addition to more stringent well construction and monitoring requirements. The chemical ingredient information is generally available to the public via online databases, and this may bring more public scrutiny to hydraulic fracturing operations. In addition, local governments may also adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular or prohibit the performance of well drilling in general or hydraulic fracturing in particular. The Pennsylvania Supreme Court, in Robinson Township v. Commonwealth of Pennsylvania, recently limited the ability to regulate such ordinances from a state-wide level, as well as the ability to require the enactment of local ordinances aiding drilling activities. Following this decision, local governments in Pennsylvania may increasingly adopt ordinances relating to drilling and hydraulic fracturing activities, especially within residential areas. 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.

The EPA is conducting a study of the potential impacts of hydraulic fracturing activities on drinking water. The EPA issued a Progress Report in December 2012 and a draft final report is anticipated by 2014 for peer review and public comment. As part of this study, the EPA requested that certain companies provide them with information concerning the chemicals used in the hydraulic fracturing process. This study or other studies may be undertaken by the EPA or other governmental authorities, and depending on their results, could spur initiatives to regulate hydraulic fracturing under the SDWA or otherwise. If new federal, state or local laws or regulations that significantly restrict hydraulic fracturing are adopted, such legal requirements could result in delays, eliminate certain drilling and injection activities and make it more difficult or costly for our customers to perform fracturing. Any such regulations limiting or prohibiting hydraulic fracturing could reduce oil and natural gas exploration and production activities by our customers 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.

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Oil and natural gas producers’ operations, especially those using hydraulic fracturing, are substantially dependent on the availability of water. Restrictions on the ability to obtain water may impact our operations.

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

Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of natural gas. The 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. Specific to Pennsylvania, sending wastewater to POTWs requires certain levels of pretreatment that may effectively prohibit such disposal as a disposal option and our continued ability to use injection wells as a disposal option not only will depend on federal or state regulations but also on whether available injection wells have sufficient storage capacities. The EPA has also adopted regulations requiring certain natural gas and oil exploration and production facilities to obtain permits for storm water discharges. Compliance with current and future environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase our operating costs and cause delays, interruptions or termination of our operations, the extent of which cannot be predicted.

We are subject to risks associated with climate change.

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

On September 22, 2009, the EPA finalized a GHG reporting rule that requires large sources of GHG emissions to monitor, maintain records on, and annually report their GHG emissions beginning January 1, 2010. The rule applies primarily to large facilities emitting 25,000 metric tons or more of carbon dioxide-equivalent (CO₂e) emissions per year and to most upstream suppliers of fossil fuels, as well as manufacturers of vehicles and engines. Subsequently, on November 8, 2010, the EPA issued GHG monitoring and reporting regulations that went into effect on December 30, 2010, specifically for oil and natural gas facilities, including onshore and offshore oil and natural gas production facilities that emit 25,000 metric tons or more of CO₂e per year. The rule requires reporting of GHG emissions by regulated facilities to the EPA by March 2012 for emissions during 2011 and annually thereafter. We are required to report our GHG emissions to the EPA each year in March under this rule. The EPA also issued a final rule that makes certain stationary sources and newer modification projects subject to permitting requirements for GHG emissions, beginning in 2011, under the CAA. Under a phased-in approach, for most purposes, new permitting provisions are required for new facilities that emit 100,000 tons per year or more of CO₂e and existing facilities that make changes increasing emissions of CO₂e by 75,000 metric tons. The EPA has indicated in rulemakings that it may further reduce these regulatory thresholds in the future, making additional sources subject to permitting.

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The recent actions of the EPA and the passage of any federal or state climate change laws or regulations could result in increased costs to (i) operate and maintain our facilities, (ii) install new emission controls on our facilities and (iii) administer and manage any GHG emissions program. 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. Legislation or regulations that may be adopted to address climate change could also affect the markets for our products by making our products more or less desirable than competing sources of energy.

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

• environmental hazards, such as uncontrollable releases of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater, air and shoreline contamination;

• abnormally pressured formations;

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

• fires, explosions and ruptures of pipelines;

• personal injuries and death;

• natural disasters; and

• terrorist attacks targeting natural gas and oil related facilities and infrastructure.

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

• injury or loss of life;

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

• pollution and other environmental damage;

• regulatory investigations and penalties;

• suspension of our operations; and

• repair and remediation costs.

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

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accidental pollution event. However, we may not have coverage if we are unaware of the pollution event and unable to report the “occurrence” to our insurance company within the time frame required under our insurance policy. We have no coverage for gradual, long-term pollution events. In addition, these policies do not provide coverage for all liabilities, and we cannot assure you that the insurance coverage will be adequate to cover claims that may arise, or that we will be able to maintain adequate insurance at rates we consider reasonable. A loss not fully covered by insurance could have a material adverse effect on our financial condition, results of operations and cash flows.

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

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

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

• unexpected drilling conditions;

• title problems;

• pressure or lost circulation in formations;

• equipment failure or accidents;

• adverse weather conditions;

• compliance with environmental and other governmental or contractual requirements; and

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

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

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

The success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier

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acquisitions. No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations.

In addition, our credit facilities impose certain limitations on our ability to enter into mergers or combination transactions. Our credit facilities and our convertible debentures also limit our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions of businesses.

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

Market conditions or the unavailability of satisfactory natural gas, NGL or oil 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. Our failure to obtain such services on acceptable terms could materially harm our business. We may be required to shut in wells due to lack of a market or inadequacy or unavailability of natural gas, NGL or oil pipeline or gathering system capacity. In addition, if quality specifications for the third-party pipelines with which we connect change so as to restrict our ability to transport product, our access to markets could be impeded. 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.

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

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

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

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

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

The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with natural gas and oil prices, causing periodic shortages. We intend to continue our four-rig drilling program in the Marcellus Shale and to implement a two-rig drilling program in the Utica Shale; however, certain of the rigs performing work for us do so on a well-by-well basis and can refuse to provide such services at the conclusion of drilling on the current well. Historically, there have been shortages of drilling and workover rigs, pipe and other equipment as demand for rigs and equipment has increased along with the number of wells being drilled. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. Such shortages could delay or cause us to incur significant expenditures that are not provided for in our capital budget, which could have a material adverse effect on our business, financial condition or results of operations.

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

Section 1(b) of the Natural Gas Act of 1938, (“NGA”), exempts natural gas gathering facilities from regulation by the Federal Energy Regulatory Commission (“FERC”), as a natural gas company under the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress. If the FERC were to consider the status of an individual facility and determine that the facility and/or services provided by it are not exempt from FERC regulation, the rates for, and terms and conditions of services provided by such facility would be subject to regulation by the FERC. Such regulation could decrease revenues, increase operating costs, and depending upon the facility in question, could adversely affect our results of operations and cash flows. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA, this could result in the imposition of civil penalties as well as a requirement to disgorge charges collected for such service in excess of the cost-based rate established by the FERC.

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

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

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

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

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

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

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

We are susceptible to the potential difficulties associated with rapid growth and expansion and have a limited operating history.

We have grown rapidly over the last several years and have more than doubled our employee workforce during the first nine months of 2013. Our management believes that our future success depends on our ability to manage the rapid growth that we have experienced and the demands from increased responsibility on management personnel. The following factors could present difficulties:

• increased responsibilities for our executive level personnel;

• increased administrative burden;

• increased capital requirements; and

• increased organizational challenges common to large, expansive operations.

Our operating results could be adversely affected if we do not successfully manage these potential difficulties. The historical financial information incorporated herein is not necessarily indicative of the results that may be realized in the future. In addition, our operating history is limited and the results from our current producing wells are not necessarily indicative of success from our future drilling operations. We began development of our properties in 2010 with a two-rig drilling program. Recently, we expanded our development operations and are currently managing a four-rig drilling program. As a result, there is only limited historical financial and operating information available upon which to base your evaluation of our performance.

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

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

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Increases in interest rates could adversely affect our business.

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

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

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

• recoverable reserves;

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

• operating costs; and

• potential environmental and other liabilities.

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

The enactment of derivatives legislation, and the promulgation of regulations pursuant thereto, could have an adverse effect on our ability to use derivative instruments to hedge risks associated with our business.

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

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

The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing. The CFTC has not yet proposed rules designating any other classes of swaps, including physical commodity swaps, for mandatory clearing. Although we expect to qualify for the end-user exception from the mandatory clearing and trade execution requirements for swaps entered to hedge its commercial risks, the application of the mandatory clearing and trade execution requirements to other market participants, such as swap dealers, may

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change the cost and availability of the swaps that we use for hedging. In addition, for uncleared swaps, the CFTC or federal banking regulators may require end-users to enter into credit support documentation and/or post initial and variation margin. Posting of collateral could impact liquidity and reduce our cash available for capital expenditures, therefore reducing our ability to execute hedges to reduce risk and protect cash flows. The proposed margin rules are not yet final, and therefore the impact of those provisions to us is uncertain at this time.

The Dodd-Frank Act and regulations may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. The Dodd-Frank Act and regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, and reduce our ability to monetize or restructure our existing derivative contracts. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures.

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

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

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

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

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

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. The possibility remains that the severance tax increase on horizontal wells will resurface during compromise talks on the budget.

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Risks Related to the Offering and our Common Stock

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

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

• institute a more comprehensive compliance function;

• comply with rules promulgated by the NYSE;

• continue to prepare and distribute periodic public reports in compliance with our obligations under the federal securities laws;

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

• involve and retain to a greater degree outside counsel and accountants in the above activities.

Furthermore, while we generally must comply with Section 404 of the Sarbanes Oxley Act of 2002 for our fiscal year ended December 31, 2013, we are not required to have our independent registered public accounting firm attest to the effectiveness of our internal controls until our first annual report subsequent to our ceasing to be an “emerging growth company” within the meaning of Section 2(a)(19) of the Securities Act. Accordingly, we may not be required to have our independent registered public accounting firm attest to the effectiveness of our internal controls until as late as our annual report for the fiscal year ending December 31, 2019. Once it is required to do so, our independent registered public accounting firm may issue a report that is adverse in the event it is not satisfied with the level at which our controls are documented, designed, operated or reviewed. Compliance with these requirements may strain our resources, increase our costs and distract management; and we may be unable to comply with these requirements in a timely or cost-effective manner.

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

In connection with past audits and reviews of our financial statements and those of our Marcellus joint venture, our independent registered public accounting firms identified and reported adjustments to management. Certain of such adjustments were deemed to be the result of internal control deficiencies that constitute a material weakness in internal controls over financial reporting. If one or more material weaknesses persist or if we or our Marcellus joint venture fail to establish and maintain effective internal control over financial reporting, our ability to accurately report our financial results could be adversely affected.

Prior to the completion of this offering, we have been a private company with limited accounting personnel to adequately execute our accounting processes and other supervisory resources with which to address our internal control over financial reporting. In addition, our Marcellus joint venture has relied on our accounting personnel for its accounting processes. Historically, we and our Marcellus joint venture have not maintained effective internal control environments in that the design and execution of such controls have not consistently

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resulted in effective review and supervision by individuals with financial reporting oversight roles. The lack of adequate staffing levels resulted in insufficient time spent on review and approval of certain information used to prepare the financial statements of us and our Marcellus joint venture. We have concluded that these control deficiencies constitute material weaknesses in our control environment. A material weakness is a control deficiency, or a combination of control deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis. The control deficiencies described above, at varying degrees of severity, contributed to the material weaknesses in the control environment as further described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Internal Controls and Procedures.”

In response, we have begun the process of evaluating our internal control over financial reporting, although we are in the early phases of our review and will not complete our review until after this offering is completed. We cannot predict the outcome of our review at this time. During the course of the review, we may identify additional internal control deficiencies, which could give rise to significant deficiencies and other material weaknesses in addition to the material weaknesses previously identified.

We are not currently required to comply with the SEC’s rules implementing Section 404 of the Sarbanes Oxley Act of 2002, and are therefore not required to make a formal assessment of the effectiveness of our internal control over financial reporting for that purpose. Upon becoming a publicly traded company, we will be required to comply with the SEC’s rules implementing Sections 302 and 404 of the Sarbanes Oxley Act of 2002, which will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. Though we will be required to disclose material changes made to our internal controls and procedures on a quarterly basis, we will not be required to make our first annual assessment of our internal control over financial reporting pursuant to Section 404 until the year following our first annual report required to be filed with the SEC. To comply with the requirements of being a publicly traded company, we will need to implement additional internal controls, reporting systems and procedures and hire additional accounting and finance staff. Furthermore, while we generally must comply with Section 404 of the Sarbanes Oxley Act of 2002 for our fiscal year ending December 31, 2014, we are not required to have our independent registered public accounting firm attest to the effectiveness of our internal controls until our first annual report subsequent to our ceasing to be an “emerging growth company” within the meaning of Section 2(a)(19) of the Securities Act. Accordingly, we may not be required to have our independent registered public accounting firm attest to the effectiveness of our internal controls until our annual report for the fiscal year ending December 31, 2019. Once it is required to do so, our independent registered public accounting firm may issue a report that is adverse in the event it is not satisfied with the level at which our controls are documented, designed, or operating.

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 of 2002. 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.

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

Prior to this offering, there has not been a public market for our common stock. We cannot predict the extent to which investor interest in our company will lead to the development of an active trading market on the

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stock exchange on which we list our common stock or otherwise or how liquid that market might become. If an active trading market does not develop, you may have difficulty selling any of our common stock that you buy. The initial public offering price for the common stock will be determined by negotiations between us and the representatives of the underwriters and may not be indicative of prices that will prevail in the open market following this offering. Consequently, you may not be able to sell our common stock at prices equal to or greater than the price you paid in this offering, or at all.

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

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

The following factors could affect our stock price:

• our operating and financial performance and drilling locations, including reserve estimates;

• quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income and revenues;

• the public reaction to our press releases, our other public announcements and our filings with the SEC;

• strategic actions by our competitors;

• our failure to meet revenue, reserves or earnings estimates by research analysts or other investors;

• changes in revenue or earnings estimates, or changes in recommendations or withdrawal of research coverage, by equity research analysts;

• speculation in the press or investment community;

• the failure of research analysts to cover our common stock;

• sales of our common stock by us, the selling stockholder or other stockholders, or the perception that such sales may occur;

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

• additions or departures of key management personnel;

• actions by our stockholders;

• general market conditions, including fluctuations in commodity prices;

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

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

The stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock. Securities class action litigation has often been instituted against companies

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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.

Rice Holdings, Rice Partners and NGP Holdings will collectively hold a substantial majority of our common stock.

Immediately following the completion of this offering, Rice Holdings, Rice Partners and NGP Holdings will hold approximately 15.9%, 15.6% and 26.1% of our common stock, respectively. Rice Holdings, Rice Partners and NGP Holdings will have the collective voting power to elect all of the members of our board of directors (subject to the right of Alpha Natural Resources Inc. to designate one director) and thereby control our management and affairs. In addition, they will be able to determine the outcome of all matters requiring stockholder approval, including mergers and other material transactions, and will be able to cause or prevent a change in the composition of our board of directors or a change in control of our company that could deprive our stockholders of an opportunity to receive a premium for their common stock as part of a sale of our company. The existence of significant stockholders may also have the effect of deterring hostile takeovers, delaying or preventing changes in control or changes in management, or limiting the ability of our other stockholders to approve transactions that they may deem to be in the best interests of our company.

So long as Rice Holdings, Rice Partners and NGP Holdings continue to control a significant amount of our common stock, each 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 Rice Holdings, Rice Partners and NGP Holdings may differ or conflict with the interests of our other stockholders. Moreover, this concentration of stock ownership may also adversely affect the trading price of our common stock to the extent investors perceive a disadvantage in owning stock of a company with a controlling stockholder.

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

In connection with the completion of this offering, we will enter into a stockholders’ agreement with Rice Holdings, Rice Partners, NGP Holdings and Alpha Natural Resources, Inc., pursuant to which Rice Holdings, NGP Holdings and Alpha Natural Resources, Inc. will be provided with certain rights relative to designated director nominees and will agree to vote their shares of common stock in accordance with the stockholders’ agreement, including as it relates to the election of directors.

Conflicts of interest could arise in the future between us, on the one hand, and Natural Gas Partners and its affiliates, including its portfolio companies, or affiliates of Daniel J. Rice III, on the other hand, concerning among other things, potential competitive business activities or business opportunities.

Natural Gas Partners is a family of private equity investment funds in the business of making investments in entities primarily in the U.S. energy industry. In addition, affiliates of Daniel J. Rice III (including GRT Capital Partners, for which he is the Lead Portfolio Manager in the energy division) make investments in the U.S. oil and gas industry from time to time. As a result, Natural Gas Partners and affiliates of Daniel J. Rice III 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. Natural Gas Partners and affiliates of Daniel J. Rice III 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. In addition, conflicts of interest may also arise between us and Alpha Natural Resources, Inc. Under our certificate of incorporation, Daniel J. Rice III, NGP Holdings and/or one or more of their respective affiliates are permitted to engage in business activities or invest in or acquire businesses which may compete with our business or do business with any client of ours. Any actual or perceived conflicts of interest with respect to the foregoing could have an adverse impact on the trading price of our common stock.

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Our amended and restated certificate of incorporation and amended and restated bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.

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

• limitations on the removal of directors;

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

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

• providing that the Board of Directors is expressly authorized to adopt, or to alter or repeal our bylaws; and

• establishing advance notice and certain information requirements for nominations for election to our Board of Directors or for proposing matters that can be acted upon by stockholders at stockholder meetings.

Investors in this offering will experience immediate and substantial dilution of $13.68 per share.

Based on an assumed initial public offering price of $20.00 per share (the midpoint of the range set forth on the cover of this prospectus), purchasers of our common stock in this offering will experience an immediate and substantial dilution of $13.68 per share in the as adjusted net tangible book value per share of common stock from the initial public offering price, and our as adjusted net tangible book value as of September 30, 2013 on a pro forma basis would be $6.32 per share. This dilution is due in large part to earlier investors having paid substantially less than the initial public offering price when they purchased their shares. See “Dilution.”

We may invest or spend the proceeds of this offering in ways with which you may not agree or in ways which may not yield a return.

A portion of the net proceeds from this offering are expected to be used to fund a portion of our capital expenditure plan. Our management will have considerable discretion in the application of the net proceeds, and you will not have the opportunity, as part of your investment decision, to assess whether the proceeds are being used appropriately. The net proceeds may be used for corporate purposes that do not increase our operating results or market value. Until the net proceeds are used, they may be placed in investments that do not produce significant income or that may lose value.

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

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

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Future sales of our common stock in the public market could reduce our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.

We may sell additional shares of common stock in subsequent public offerings. We may also issue additional shares of common stock or convertible securities. After the completion of this offering, we will have 128,000,000 outstanding shares of common stock. This number includes 40,000,000 shares that we and the selling stockholder are selling in this offering and 6,000,000 shares that the selling stockholder may sell in this offering if the underwriters’ option to purchase additional shares is fully exercised, which may be resold immediately in the public market. Following the completion of this offering, assuming an initial public offering price equal to the midpoint of the range set forth on the cover of this prospectus and no exercise of the underwriters’ option to purchase additional shares, Rice Holdings, Rice Partners, Daniel J. Rice III, NGP Holdings and Alpha Holdings, respectively, will own 20,311,125 shares, 20,000,000 shares, 2,374,652 shares, 33,463,549 shares and 10,000,000 shares of our common stock, or approximately 15.9%, 15.6%, 1.9%, 26.1% and 7.8% of our total outstanding shares, all of which are restricted from immediate resale under the federal securities laws and are subject to the lock-up agreements with the underwriters described in “Underwriting (Conflicts of Interest),” but may be sold into the market in the future. Rice Holdings, Daniel J. Rice III, NGP Holdings and Alpha Holdings will be party to a registration rights agreement with us which will require us to effect the registration of their shares (and shares of certain of their affiliates) in certain circumstances no earlier than the expiration of the lock-up period contained in the underwriting agreement entered into in connection with this offering. Certain employees will be subject to restrictions on the sale of their shares for 180 days after the date of this prospectus; however, after such period, and subject to compliance with the Securities Act or exemptions therefrom, these employees may sell such shares into the public market. See “Shares Eligible for Future Sale” and “Certain Relationships and Related Party Transactions—Registration Rights.”

In connection with this offering, we intend to file a registration statement with the SEC on Form S-8 providing for the registration of 17,500,000 shares of our common stock issued or reserved for issuance under our equity incentive plan. Subject to the satisfaction of vesting conditions, the expiration of lock-up agreements and the requirements of Rule 144, shares registered under the registration statement on Form S-8 will be available for resale immediately in the public market without restriction.

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

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

We, the Rice Owners, NGP Holdings, Alpha Holdings, all of our directors and executive officers and certain of our employees have entered into lock-up agreements with respect to their common stock, pursuant to which they are subject to certain resale restrictions for a period of 180 days following the effectiveness date of the registration statement of which this prospectus forms a part. Barclays Capital Inc., at any time and without notice, may release all or any portion of the common stock subject to the foregoing lock-up agreements. If the restrictions under the lock-up agreements are waived, then common stock will be available for sale into the public markets, which could cause the market price of our common stock to decline and impair our ability to raise capital.

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

Upon completion of this offering, Rice Holdings, Rice Partners, NGP Holdings and Alpha Holdings will collectively beneficially control a majority of the combined voting power of all classes of our outstanding voting stock. In connection with the completion of this offering, we will enter into a stockholders’ agreement with Rice

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Holdings, Rice Partners, NGP Holdings and Alpha Natural Resources, Inc., pursuant to which Rice Holdings, NGP Holdings and Alpha Natural Resources, Inc. will be provided with certain rights relative to designated director nominees and will agree to vote their shares of common stock in accordance with the stockholders’ agreement, including as it relates to the election of directors. For additional information regarding the stockholders’ agreement, please read “Certain Relationships and Related Party Transactions—Stockholders’ Agreement.” As a result, we expect to be a controlled company within the meaning of the NYSE corporate governance standards. Under the NYSE rules, a company of which more than 50% of the voting power is held by another person or group of persons acting together is a controlled company and may elect not to comply with certain NYSE corporate governance requirements, including the requirements that:

• a majority of the board of directors consist of independent directors;

• the nominating and governance committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities;

• the compensation committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities; and

• there be an annual performance evaluation of the nominating and governance and compensation committees.

These requirements will not apply to us as long as we remain a controlled company. Following this offering, we may utilize some or all of these exemptions. Accordingly, you may not have the same protections afforded to stockholders of companies that are subject to all of the corporate governance requirements of the NYSE. See “Management.”

For as long as we are an emerging growth company, we will not be required to comply with certain reporting requirements, including those relating to accounting standards and disclosure about our executive compensation, that apply to other public companies.

In April 2012, President Obama signed into law the JOBS Act. We are classified as an “emerging growth company” under the JOBS Act. For as long as we are an emerging growth company, which may be up to five full fiscal years, unlike other public companies, we will not be required to, among other things, (1) provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act, (2) comply with any new requirements adopted by the PCAOB requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer, (3) provide certain disclosure regarding executive compensation required of larger public companies or (4) hold nonbinding advisory votes on executive compensation. We will remain an emerging growth company for up to five years, although we will lose that status sooner if we have more than $1.0 billion of revenues in a fiscal year, have more than $700 million in market value of our common stock held by non-affiliates, or issue more than $1.0 billion of non-convertible debt over a three-year period.

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

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

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

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

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

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

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

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

Forward-looking statements may include statements about our:

• business strategy;

• reserves;

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

• realized natural gas, NGL and oil prices;

• timing and amount of future production of natural gas, NGLs and oil, including with respect to the timing and results of initial wells in the Utica Shale;

• hedging strategy and results;

• future drilling plans;

• competition and government regulations;

• pending legal or environmental matters;

• marketing of natural gas, NGLs and oil;

• leasehold or business acquisitions;

• costs of developing our properties and conducting our gathering and other midstream operations;

• general economic conditions;

• credit markets;

• uncertainty regarding our future operating results; and

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

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

Reserve engineering is a process of estimating underground accumulations of natural gas, NGLs and oil that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the

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results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of natural gas, and NGLs and oil that are ultimately recovered.

Should one or more of the risks or uncertainties described in this prospectus occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

All forward-looking statements, expressed or implied, included in this prospectus are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this prospectus.

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USE OF PROCEEDS

We expect to receive approximately $566.0 million of net proceeds (assuming an initial public offering price equal to the midpoint of the range on the cover of this prospectus) from the sale of the common stock offered by us after deducting underwriting discounts and commissions and estimated offering expenses payable by us. We will not receive any proceeds from the sale of shares of common stock by the selling stockholder.

We intend to use the net proceeds from this offering (i) to repay borrowings outstanding under the revolving credit facility of our Marcellus joint venture, (ii) to make a $100.0 million payment to Alpha Holdings in partial consideration for the Marcellus JV Buy-In, (iii) to repay borrowings under our revolving credit facility and (iv) the remainder to fund a portion of our capital expenditure plan. The remaining consideration for the Marcellus JV Buy-In will consist of our issuance to Alpha Holdings of common stock with a value of $200.0 million (based on the initial public offering price of the common stock offered hereby). For a description of the Marcellus JV Buy-In, please read “Prospectus Summary—Recent Developments—Marcellus Joint Venture Buy-In.” For a description of our capital expenditure plan, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operation—Capital Resources and Liquidity.”

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

Sources of Funds (In millions)		Uses of Funds (In millions)
Gross proceeds from this offering	$600.0	Repayment of Marcellus joint venture revolving credit facility	$75.4
		Cash consideration for Marcellus JV Buy-In	100.0
		Repayment of our revolving credit facility (1)	165.0
		Funding of capital expenditure plan	225.6
		Underwriting discounts, fees and expenses	34.0
Total Sources of Funds	$600.0	Total Uses of Funds	$600.0

(1) Includes an estimated $50.0 million expected to be drawn under our revolving credit facility prior to the closing of this offering to finance our capital expenditure plan.

As of December 31, 2013, we had $115.0 million in outstanding borrowings under our revolving credit facility, which matures in April 2018 and bears interest at a variable rate, which was approximately 2.64% as of December 31, 2013. The borrowings to be repaid were incurred primarily for our drilling and development program and for general corporate purposes. While we currently do not have plans to immediately borrow additional amounts under our revolving credit facility following the closing of this offering, we may at any time reborrow amounts repaid under our revolving credit facility and we expect to do so to fund our capital program.

As of December 31, 2013, our Marcellus joint venture had $75.4 million in outstanding borrowings under its revolving credit facility, which matures in September 2017. The borrowings to be repaid were incurred primarily for the drilling and development program and general corporate purposes of our Marcellus joint venture. The Marcellus joint venture revolving credit agreement will be terminated in connection with the closing of the Marcellus JV Buy-In.

NGP Holdings, the selling stockholder, has granted the underwriters a 30-day option to purchase up to an aggregate of 6,000,000 additional shares of our common stock to the extent the underwriters sell more than 40,000,000 shares of common stock in this offering. We will not receive any proceeds from the sale of shares by the selling stockholder. NGP Holdings is deemed under federal securities laws to be an underwriter with respect to the common stock it may sell in connection with this offering.

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A $1.00 increase or decrease in the assumed initial public offering price of $20.00 per share would cause the net proceeds from this offering, after deducting the underwriting discounts and commissions and estimated offering expenses, received by us to increase or decrease, respectively, by approximately $28.5 million. If the proceeds increase due to a higher initial public offering price or an increase in the size of the offering, we would use the additional net proceeds to fund a portion of our capital expenditure plan. If the proceeds decrease due to a lower initial public offering price or a decrease in the size of the offering, then we would reduce by a corresponding amount the net proceeds directed to fund our capital expenditure program.

An affiliate of Wells Fargo Securities, LLC is a lender under each of our revolving credit facility and our Marcellus joint venture’s and will receive a portion of the proceeds of this offering. Accordingly, this offering is being made in compliance with Rule 5121 of the FINRA. See “Underwriting (Conflicts of Interest).”

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DIVIDEND POLICY

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

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CAPITALIZATION

The following table sets forth our cash and cash equivalents and capitalization as of September 30, 2013:

• on an actual basis; and

• on a pro forma basis to give effect to (i) the Marcellus JV Buy-In described under “Summary—Recent Developments—Marcellus JV Buy-In”, (ii) the transactions described under “Corporate Reorganization” which will be completed immediately prior to or contemporaneously with the closing of this offering and (iii) the application of the net proceeds from this offering as set forth under “Use of Proceeds.”

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

	As of September 30, 2013
	Rice Drilling B Actual			Rice Energy Inc. Pro Forma
	(Unaudited)
(in thousands)
Cash and cash equivalents (1)	$	27,661		$	425,493
Restricted cash (2)		8,268			8,268
Long-term debt, including current maturities:
Revolving credit facility (3)		—			—
Second lien term loan (4)		294,361			294,361
Convertible debentures (5)		6,890			6,890
NPI note payable (6)		7,771			7,771
Other		3,292			3,292
Total indebtedness		312,314			312,314
Members’ equity		362,215			—
Shareholders equity:
Common stock, $0.01 par value; 650,000,000 shares authorized (as adjusted); 128,000,000 shares issued and outstanding (as adjusted)		—			13,570
Preferred stock, $0.01 par value; 50,000,000 shares authorized (as adjusted); no shares issued and outstanding (as adjusted)		—			—
Warrants		3,294			3,294
Additional paid-in capital		—			1,132,302
Accumulated deficit		(50,172	)		—
Total equity		315,337			1,149,166
Total capitalization	$	627,651		$	1,461,480

(1) As of December 31, 2013, we had cash and cash equivalents of $39.5 million.

(2) Includes $8.3 million of restricted cash included in current assets.

(3) As of December 31, 2013, we had $115.0 million in outstanding borrowings under our revolving credit facility, which matures in April 2018 and bears interest at a variable rate, which was approximately 2.64% as of December 31, 2013. Such amounts will be repaid in full in connection with the closing of this offering. These amounts do not include an estimated $50.0 million expected to be drawn under our revolving credit facility prior to the closing of this offering to finance our capital expenditure plan.

(4) Net of original issue discount of approximately $4.5 million.

(5) As of December 1, 2013, approximately $6.9 million of convertible debentures remained outstanding.

(6) Net of discount of approximately $1.0 million.

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The table set forth above is based on the number of shares of our common stock expected to be outstanding as of the closing of this offering. The number of outstanding shares of our common stock includes shares to be issued in a concurrent private placement to Alpha Holdings as a portion of the consideration for our Marcellus JV Buy-In, which is dependent upon the price per share at which shares of our common stock are initially offered in this offering. A $1.00 decrease (or increase) in the public offering price would result in an additional 526,316 shares (or 476,190 less shares) outstanding following the completion of this offering. The table does not reflect 17,500,000 shares of common stock reserved for issuance under our long-term incentive plan, which we plan to adopt in connection with this offering, and up to 2,083,730 shares of common stock issuable upon the conversion of our convertible debentures or upon exercise of outstanding warrants to purchase common stock. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity—Debt Agreements—Convertible Debentures and Warrants.”

A $1.00 increase or decrease in the assumed initial public offering price of $20.00 per share, which is the midpoint of the range set forth on the cover of this prospectus, would increase or decrease each of pro forma total equity and total capitalization by approximately $28.5 million, assuming that the number of shares offered by us, as set forth on the cover of this prospectus, remains the same and after deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us. We may also increase or decrease the number of shares we are offering. Each increase of 1.0 million shares in the number of shares offered by us at an assumed offering price of $20.00 per share, which is the midpoint of the estimated offering price range set forth on the cover of this prospectus, would increase each of our pro forma total stockholders’ equity and total capitalization by approximately $19.0 million. Similarly, each decrease of 1.0 million shares in the number of shares offered by us, at an assumed offering price of $20.00 per share, which is the midpoint of the estimated offering price range set forth on the cover of this prospectus, would decrease each of our pro forma total equity and total capitalization by approximately $19.0 million. The pro forma information discussed above gives effect to the adjustment in the number of shares to be issued to Alpha Holdings as partial consideration for the Marcellus JV Buy-In and is illustrative only and will be adjusted based on the actual initial public offering price and other terms of this offering determined at pricing.

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DILUTION

Purchasers of the common stock in this offering will experience immediate and substantial dilution in the net tangible book value per share of the common stock for accounting purposes. Assuming an initial public offering price of $20.00 per share (the midpoint of the range on the cover of this prospectus), our net tangible book value as of September 30, 2013, after giving effect to the transactions described under “Corporate Reorganization” and the Marcellus JV Buy-In was $352.8 million, or $4.01 per share. Pro forma net tangible book value per share is determined by dividing our pro forma tangible net worth (tangible assets less total liabilities) by the total number of outstanding shares of common stock that will be outstanding immediately prior to the closing of this offering after giving effect to our corporate reorganization and the Marcellus JV Buy-In. After giving effect to the sale of the shares in this offering and further assuming the receipt of the estimated net proceeds (assuming an initial public offering price equal to the midpoint of the range on the cover of this prospectus and after deducting estimated underwriting discounts and commissions and estimated offering expenses), our adjusted pro forma net tangible book value as of September 30, 2013 would have been approximately $808.3 million, or $6.32 per share. This represents an immediate increase in the net tangible book value of $2.31 per share to our existing stockholders and an immediate dilution (i.e., the difference between the offering price and the adjusted pro forma net tangible book value after this offering) to new investors purchasing shares in this offering of $13.68 per share. The following table illustrates the per share dilution to new investors purchasing shares in this offering:

Assumed initial public offering price per share			$	20.00
Pro forma net tangible book value per share as of September 30, 2013 (after giving effect to our corporate reorganization)	$	4.01
Increase per share attributable to new investors in this offering		2.31
As adjusted pro forma net tangible book value per share after giving effect to our corporate reorganization and this offering				6.32
Dilution in pro forma net tangible book value per share to new investors in this offering			$	13.68

The following table summarizes, on an adjusted pro forma basis as of September 30, 2013, the total number of shares of common stock owned by existing stockholders and to be owned by new investors, the total consideration paid, and the average price per share paid by our existing stockholders and to be paid by new investors in this offering at $20.00 per share, the midpoint of the range of the initial public offering price set forth on the cover of this prospectus, calculated before deduction of estimated underwriting discounts and commissions:

	Shares Acquired					Total Consideration					Average Price   Per Share
	Number		Percent			Amount   (in  thousands)		Percent
Existing owners		88,000,000		69	%	$	352,766		31	%	$	4.01
New investors in this offering		40,000,000		31			800,000		69			20.00
Total		128,000,000		100	%	$	1,152,766		100	%	$	9.01

The above tables and discussion are based on the number of shares of our common stock expected to be outstanding as of the closing of this offering. The number of outstanding shares of our common stock includes shares to be issued in a concurrent private placement to Alpha Holdings as a portion of the consideration for our Marcellus JV Buy-In, which is dependent upon the price per share at which shares of our common stock are initially offered in this offering. A $1.00 decrease (or increase) in the public offering price would result in an additional 526,316 shares (or 476,190 less shares) outstanding following the completion of this offering. The table does not reflect 17,500,000 shares of common stock reserved for issuance under our long-term incentive plan, which we plan to adopt in connection with this offering, and 2,083,730 shares of common stock issuable upon the conversion of our convertible debentures or upon exercise of outstanding warrants to purchase common stock. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—

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Capital Resources and Liquidity—Debt Agreements—Convertible Debentures and Warrants.” To the extent convertible debentures are converted or outstanding warrants are exercised, new investors will experience further dilution.

A $1.00 increase or decrease in the assumed initial public offering price of $20.00 per share, which is the midpoint of the range set forth on the cover of this prospectus, would increase or decrease our as adjusted pro forma net tangible book value of the shares of our common stock as of September 30, 2013 by approximately $38.0 million, the as adjusted pro forma net tangible book value per share after this offering by $0.08 per share and the dilution in pro forma as adjusted net tangible book value per share to new investors in this offering by $1.08 per share, assuming the number of shares offered by us, as set forth on the cover of this prospectus, remains the same and after deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us.

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SELECTED HISTORICAL CONSOLIDATED AND UNAUDITED PRO FORMA FINANCIAL DATA

The following table shows selected historical consolidated financial data of Rice Drilling B, our accounting predecessor, and the summary unaudited pro forma financial data for the periods and as of the dates indicated. Our historical results are not necessarily indicative of future operating results. The selected financial data presented below are qualified in their entirety by reference to, and should be read in conjunction with, “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, 2011 and 2012 are derived from the audited consolidated financial statements of Rice Drilling B included elsewhere in this prospectus. The selected historical statement of operations data for the nine months ended September 30, 2012 and 2013 and the historical balance sheet data as of September 30, 2013 are derived from the unaudited consolidated financial statements included elsewhere in this prospectus. The selected historical unaudited historical consolidated interim financial data has been prepared on a consistent basis with the audited consolidated financial statements of Rice Drilling B. In the opinion of management, such selected unaudited historical consolidated financial interim data reflects all adjustments (consisting of normal and recurring accruals) considered necessary to present our financial position for the periods presented. The results of operations for the interim periods are not necessarily indicative of the results that may be expected for the full year because of the impact of fluctuations in prices received from oil and natural gas, natural production declines, the uncertainty of exploration and development drilling results and other factors.

The summary unaudited pro forma consolidated statements of operations data for the nine months ended September 30, 2013 and for the year ended December 31, 2012 has been prepared to give pro forma effect to (i) the Marcellus JV Buy-In described under “Summary—Recent Developments—Marcellus JV Buy-In,” (ii) the reorganization transactions described under “Corporate Reorganization” and (iii) this offering and the application of the net proceeds from this offering as if they had been completed as of January 1, 2012. The summary unaudited pro forma consolidated balance sheet data as of September 30, 2013 has been prepared to give pro forma effect to those transactions as if they had been completed as of September 30, 2013. These data are subject and give effect to the assumptions and adjustments described in the notes accompanying the unaudited pro forma financial statements included elsewhere in this prospectus. The summary unaudited pro forma consolidated financial data are presented for informational purposes only and should not be considered indicative of actual results of operations that would have been achieved had the reorganization transactions and this offering been consummated on the dates indicated, and do not purport to be indicative of statements of financial position or results of operations as of any future date or for any future period.

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	Rice Drilling B												Rice Energy Inc.
	Year Ended December 31,						Nine Months Ended September 30,						Pro Forma
													Year Ended December 31, 2012			Nine Months Ended September 30, 2013
	2011			2012			2012			2013
							(Unaudited)						(Unaudited)
(in thousands, except per share data)
Statement of operations data:
Revenues:
Natural gas sales	$	13,972		$	26,743		$	15,527		$	60,219		$	53,027		$	123,157
Other revenue		—			457			—			519			457			519
Total revenues		13,972			27,200			15,527			60,738			53,484			123,676
Operating expenses:
Lease operating		1,630			3,821			2,226			5,794			7,152			11,892
Gathering, compression and transportation		527			3,621			2,413			6,951			10,292			17,995
Production taxes and impact fees		—			1,382			1,165			1,029			2,251			1,691
Exploration		660			3,275			2,850			1,784			3,275			1,784
Restricted unit expense		170			—			—			40,087			—			40,087
General and administrative		5,208			7,599			5,374			9,952			9,657			11,952
Depreciation, depletion and amortization		5,981			14,149			10,209			23,215			28,342			52,836
Amortization of deferred financing costs		2,675			7,220			5,540			4,760			7,235			4,867
Write-down of abandoned leases		109			2,253			2,223			—			2,253			—
Gain from sale of interest in gas properties		(1,478	)		—			—			—			—			—
Total expenses		15,482			43,320			32,000			93,572			70,457			143,104
Operating loss		(1,510	)		(16,120	)		(16,473	)		(32,834	)		(16,973	)		(19,428	)
Interest expense		(531	)		(3,487	)		(1,801	)		(13,033	)		(3,859	)		(12,660	)
Other income (expense)		161			112			76			(347	)		112			(1,249	)
Gain (loss) on derivative instruments		574			(1,381	)		(3,407	)		16,698			(1,455	)		30,626
Loss on extinguishment of debt		—			—			—			(10,622	)		—			(10,622	)
Equity in income (loss) of joint ventures		370			1,532			(136	)		19,297			(209	)		(3	)
Loss before income taxes		(936	)		(19,344	)		(21,741	)		(20,841	)		(22,384	)		(13,336	)
Income tax benefit		—			—			—			—			9,288			5,534
Net loss	$	(936	)	$	(19,344	)	$	(21,741	)	$	(20,841	)	$	(13,096	)	$	(7,802	)
Balance sheet data (at period end):
Cash	$	4,389		$	8,547					$	27,661					$	425,493
Total property and equipment, net		150,646			273,640						613,702						948,787
Total assets		190,240			344,971						751,397						1,782,113
Total debt		107,795			149,320						312,314						312,314
Total members’ / stockholders’ capital		46,821			138,191						315,337						1,149,166
Net cash provided by (used in):
Operating activities	$	5,131		$	(3,014	)	$	(7,839	)	$	20,223
Investing activities		(79,245	)		(119,973	)		(85,591	)		(342,625	)
Financing activities		73,447			127,145			96,008			341,516
Other financial data (unaudited):
Adjusted EBITDAX (1)	$	7,342		$	11,768		$	5,823		$	24,990		$	25,186		$	68,612
Earnings per share – basic													$	(0.10	)	$	(0.06	)
Earnings per share – diluted													$	(0.10	)	$	(0.06	)

(1) Adjusted EBITDAX is a non-GAAP financial measure. For a definition of Adjusted EBITDAX and a reconciliation of Adjusted EBITDAX to net income (loss), see “Prospectus Summary—Non-GAAP Financial Measure.”

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes appearing elsewhere in this prospectus. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions, or beliefs about future events may, and often do, vary from actual results and the differences can be material. Some of the key factors which could cause actual results to vary from our expectations include changes in natural gas prices, the timing of planned capital expenditures, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below and elsewhere in this prospectus, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. 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. Unless otherwise indicated, the information presented in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” does not give pro forma effect to (i) our corporate reorganization described in “Corporate Reorganization” or (ii) our Marcellus JV Buy-In described in “Summary—Recent Developments—Marcellus JV Buy-In.”

Overview

We are an independent natural gas and oil company engaged in the acquisition, exploration and development of natural gas and oil properties in the Appalachian Basin. We are focused on creating shareholder value by identifying and assembling a portfolio of low-risk assets with attractive economic profiles and leveraging our technical and managerial expertise to deliver industry-leading results. We strive to be an early entrant into the core of a shale play by identifying what we believe to be the core of the play and aggressively executing our acquisition strategy to establish a largely contiguous acreage position. We believe we were an early identifier of the core of both the Marcellus Shale in southwestern Pennsylvania and the Utica Shale in southeastern Ohio.

We hold approximately 43,351 pro forma net acres in the southwestern core of the Marcellus Shale, primarily in Washington County, Pennsylvania. We established our Marcellus Shale acreage position through a combination of largely contiguous acreage acquisitions in 2009 and 2010 and through numerous bolt-on acreage acquisitions. In 2012, we acquired approximately 33,499 of our 46,488 net acres in the southeastern core of the Utica Shale, primarily in Belmont County, Ohio. We believe this area to be the core of the Utica Shale based on publicly available drilling results. We operate a substantial majority of our acreage in the Marcellus Shale and a majority of our acreage in the Utica Shale.

Since completing our first horizontal well in October 2010, our average net daily production has grown approximately 64x to 128 MMcf/d for the third quarter of 2013. We have drilled and completed 37 horizontal Marcellus wells and three horizontal Upper Devonian wells as of December 1, 2013 with a 100% success rate (defined as the rate at which wells are completed and produce in commercially viable quantities). As of December 1, 2013, we had 1,313 gross (752 net) pro forma identified drilling locations, consisting of 349 gross (325 net) pro forma in the Marcellus Shale, 753 gross (233 net) in the Utica Shale and 211 gross (194 net) pro forma in the Upper Devonian Shale.

As of September 30, 2013, our pro forma estimated proved reserves were 552 Bcf, all of which were in southwestern Pennsylvania, with 35% proved developed and 100% natural gas.

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Factors That Significantly Affect Our Financial Condition and Results of Operations

We derive substantially all of our revenues from the sale of natural gas that is produced from our interests in properties located in the Marcellus Shale. 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 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. In the future, we will also be subject to fluctuations in oil and NGL prices. Sustained periods of low natural gas prices could materially and adversely affect our financial condition, our results of operations, the quantities of natural gas that we can economically produce and our ability to access capital.

We use commodity derivative instruments, such as swaps and collars, to manage and reduce price volatility and other market risks associated with our natural gas 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 combination of fixed price natural gas swaps and zero cost collars for which we receive a fixed price (via either swap price, floor of collar or put price) for future production in exchange for a payment of the variable market price received at the time future production is sold. The prices contained in these derivative contracts are based on NYMEX Henry Hub prices. The NYMEX Henry Hub price of natural gas is a widely used benchmark for the pricing of natural gas in the United States. The actual prices realized from the sale of natural gas differ from the quoted NYMEX Henry Hub price as a result of location differentials. Location differentials to NYMEX Henry Hub prices, also known as basis differential, result from variances in regional natural gas prices compared to NYMEX Henry Hub prices as a result of regional supply and demand factors. Historically, we have not hedged basis differentials associated with our natural gas production. We elected not to designate our current portfolio of commodity derivative contracts as hedges for accounting purposes. Therefore, changes in fair value of these derivative instruments are recognized in earnings. Please read “—Quantitative and Qualitative Disclosures About Market Risk” for additional discussion of our commodity derivative contracts.

Like other businesses engaged in the exploration and production of oil and natural gas, we face the challenge of natural production declines. As initial reservoir pressures are depleted, oil and natural gas production from a given well naturally decreases. Thus, a natural gas exploration and production company depletes part of its asset base with each unit of natural gas 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 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.

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

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

Public Company Expenses. Upon completion of this offering, we expect to incur direct, incremental general and administrative (“G&A”) expenses as a result of being a publicly traded company, including, but not limited to, costs associated with annual and quarterly reports to stockholders, tax return preparation, independent auditor fees, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs and independent director compensation. We estimate these direct, incremental G&A expenses will be approximately $2.0 million per year. These direct, incremental G&A expenses are not included in our historical results of operations.

Corporate Reorganization and Marcellus JV Buy-In. The historical consolidated financial statements included in this prospectus are based on the financial statements of Rice Drilling B, our accounting predecessor, prior to our reorganization in connection with this offering as described in “Corporate Reorganization” and the Marcellus JV Buy-In. As a result, the historical financial data may not give you an accurate indication of what our actual results would have been if the transactions described in “Corporate Reorganization” and the Marcellus JV Buy-In had been completed at the beginning of the periods presented or of what our future results of operations are likely to be. For example, concurrently with the closing of this offering, we expect to acquire Alpha Holdings’ 50% interest in our Marcellus joint venture and, as a result, for periods following the completion of this offering, the results of operations of our Marcellus joint venture will be included in our results of operations. Please see “Summary—Recent Developments—Marcellus JV Buy-In.”

Income Taxes. Rice Drilling B, our accounting predecessor, is a limited liability company not subject to federal income taxes. Accordingly, no provision for federal income taxes has been provided for in our historical results of operations because taxable income was passed through to Rice Drilling B’s members. Although we are a corporation under the Internal Revenue Code, subject to federal income taxes at a statutory rate of 35% of pretax earnings, we do not expect to report any income tax benefit or expense until the consummation of this offering. Based on our deductions primarily related to intangible drilling costs (“IDCs”), that are expected to exceed 2014 earnings, we expect to generate significant net operating loss assets and deferred tax liabilities.

Increased Drilling Activity. We began horizontal drilling operations in 2010 and drilled 29 wells through December 31, 2012. As of December 1, 2013, we have drilled 25 of our expected 29 horizontal wells in 2013, and we expect to drill 62 horizontal wells in 2014. From 2010 through June 2013, we ran a two-rig drilling program. Beginning in June 2013, we began operating a four-rig drilling program (consisting of two tophole rigs and two horizontal rigs) on our Marcellus Shale properties and expect to increase to a six-rig drilling program (consisting of three tophole rigs and three horizontal rigs) in the first quarter of 2014. We expect to continue to operate this six-rig drilling program through 2014. We expect our future drilling activity will become increasingly weighted towards the development of our Utica Shale acreage. The costs and production associated with the wells we expect to drill in the Utica Shale may differ substantially from those we have historically drilled in the Marcellus Shale.

Financing Arrangements. As of September 30, 2013, we had outstanding indebtedness of $312.3 million. In April 2013, we entered into our $500 million senior secured revolving credit facility, which we refer to as our revolving credit facility, and our $300 million second lien term loan agreement, which we refer to as our term loan. Net proceeds of $288.3 million after offering fees and expenses was used to repay existing debt of $176.1 million and to partially fund the acquisition of approximately 33,499 net acres in the Utica Shale in Belmont County, Ohio.

As of September 30, 2013, the borrowing base under our revolving credit facility was $140.0 million but no amounts were drawn. The borrowing base under our revolving credit facility was redetermined in August 2013 and October 2013 and increased to $140.0 million and $155.0 million, respectively, and is anticipated to be

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increased to $350 million concurrent with the closing of the Marcellus JV Buy-In. As of September 30, 2013, the borrowing base under our Marcellus joint venture’s credit facility was $130.0 million. In October 2013, the borrowing base under our Marcellus joint venture’s credit facility was increased to $145.0 million. As of September 30, 2013, our Marcellus joint venture had $72.0 million of borrowings and $13.5 million of letters of credit outstanding under the revolving credit facility. The Marcellus joint venture revolving credit agreement will be terminated in connection with the closing of the Marcellus JV Buy-In. The primary components of our outstanding debt at September 30, 2013 were $294.4 million outstanding on the term loan.

To date, our capital expenditures have been financed with capital contributions from NGP and other private investors, borrowings under our revolving credit facility and net cash provided by operating activities. In the future, we may incur additional indebtedness to fund our acquisition and development activities. Please read “—Debt Agreements” for additional discussion of our financing arrangements.

Sources of Revenues

Our revenues are derived from the sale of natural gas and do not include the effects of derivatives. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.

NYMEX Henry Hub prompt month contract prices are widely-used benchmarks in the pricing of natural gas. The following table provides the high and low prices for NYMEX Henry Hub prompt month contract prices and our differential to the average of those benchmark prices for the periods indicated.

	Year Ended December 31,					Nine Months Ended September 30,
	2011			2012		2012			2013
NYMEX Henry Hub High	$	4.85		$	3.90	$	3.20		$	4.38
NYMEX Henry Hub Low		2.99			1.91		1.82			3.08
Differential to Average NYMEX Henry Hub (1)		(0.12	)		0.08		(0.19	)		(0.14	)

(1) Differential is calculated by comparing the average NYMEX Henry Hub price to our volume weighted average realized price per MMBtu, including our proportionate 50% share of the volumes sold by our Marcellus joint venture.

We sell substantially all of our production to a single natural gas marketer, Sequent Energy Management, LP (“Sequent”). For the three months ended September 30, 2013, sales to Sequent and Dominion Field Services (“Dominion”) represented 88% and 12% of our total sales, respectively. For the year ended December 31, 2012, sales to Sequent accounted for 100% of our total sales. If our natural gas marketers decided to stop purchasing natural gas from us, our revenues could decline and our operating results and financial condition could be harmed. Although a substantial portion of production is purchased by these major customers, we do not believe the loss of one or both customers would have a material adverse effect on our business, as other customers or markets would be accessible to us.

Principal Components of our Cost Structure

• Lease operating expense. These are the day to day operating costs incurred to maintain production of our natural gas producing wells. Such costs include produced water disposal, maintenance and repairs. Cost levels for these expenses can vary based on supply and demand for oilfield services.

• Gathering, compression and transportation. These are costs incurred to bring natural gas to the market. Such costs include the costs to operate and maintain our low- and high-pressure gathering and compression systems as well as fees paid to third parties who operate low- and high-pressure gathering systems that transport our natural gas. We often enter into firm transportation contracts that secure takeaway capacity that includes minimum volume commitments, the cost for which is included in these expenses.

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• Production taxes and impact fees. Pennsylvania imposes an annual impact fee on each producing shale well for a period of 15 years. Ohio imposes a production tax which is based upon annual production. As we expand our operations into the Utica Shale in Ohio, the proportion of our production and producing wells from each state may change over time and, as a result, the proportion of our production taxes and impact fees will vary depending on our quantities produced from the Utica Shale, the number of producing shale wells in Pennsylvania, and the applicable production tax rates and impact fees then in effect.

• Exploration expense. These include geological and geophysical costs, seismic costs and delay rental payments.

• General and administrative expense. We expect that we will incur additional general and administrative expenses as a result of being a publicly-traded company. Please see “– Factors That Significantly Affect Comparability of Our Financial Condition and Results of Operations – Public Company Expenses.” In addition, certain of our employees currently hold incentive units in Rice Appalachia that entitle the holder to a portion of distributions made by Rice Appalachia. Concurrent with the closing of this offering, the holders of these incentive units will contribute their incentive units for substantially similar incentive units in each of Rice Holdings and NGP Holdings, and such incentive units will entitle holders thereof to portions of future distributions by Rice Holdings and NGP Holdings. Please see “Executive Compensation – Narrative Description of the Summary Compensation Table for the 2013 Fiscal Year – Long-Term Incentive Compensation – Incentive Units.” While any such distributions will not involve any cash payment by us, we will recognize a non-cash compensation expense, which may be material, in the period in which such payment is made. In addition, in connection with our corporate reorganization, approximately 143,661 shares of our common stock will be issued to certain of the incentive holders in exchange for the extinguishment of the incentive burden attributable to Mr. Daniel J. Rice III. As such, we expect that we will recognize a non-cash compensation expense of approximately $2.9 million in the first quarter of 2014.

• Depreciation, depletion and amortization. Depreciation, depletion and amortization (“DD&A”) includes the systematic expensing of the capitalized costs incurred to acquire, explore and develop natural gas. As a “successful efforts” company, we capitalize all costs associated with our acquisition and development efforts and all successful exploration efforts and allocate these costs to each unit of production using the units of production method.

• Write-down of abandoned leases. These write-downs include the cost of expensing certain lease acquisition costs associated with properties that we no longer expect to drill.

• Interest expense. We have financed a portion of our working capital requirements and property acquisitions with borrowings under our revolving credit facility, term loan and proceeds from our convertible debentures. As a result, we incur interest expense that is affected by the level of drilling, completion and acquisition activities, as well as fluctuations in interest rates and our financing decisions. We also incur interest expense on our convertible debentures. We will likely continue to incur significant interest expense as we continue to grow. To date, we have not entered into any interest rate hedging arrangements to mitigate the effects of interest rate changes. Additionally, we capitalized $7.7 million and $5.6 million of interest expense for the year ended December 31, 2012 and the nine month period ended September 30, 2013.

• Derivative fair value loss (gain). We utilize commodity derivative contracts to reduce our exposure to fluctuations in the price of natural gas. We recognize gains and losses associated with our open commodity derivative contracts as commodity prices and the associated fair value of our commodity derivative contracts change. The commodity derivative contracts we have in place are not designated as hedges for accounting purposes. Consequently, these commodity derivative contracts are recorded at fair value at each balance sheet with changes in fair value recognized currently as a gain or loss in our results of operations. 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.

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• Equity in income (loss) of joint ventures. This line item represents our proportionate share of earnings and losses from our equity method investments, including our Marcellus joint venture. Concurrently with the closing of this offering, we expect to acquire Alpha Holdings’ 50% interest in our Marcellus joint venture and, as a result, for periods following the completion of this offering, the results of operations of our Marcellus joint venture will be included in our results of operations. Please see “Summary—Recent Developments—Marcellus JV Buy-In.”

• Income tax expense. Rice Drilling B, our accounting predecessor, is a limited liability company not subject to federal income taxes. Accordingly, no provision for federal income taxes has been provided for in our historical results of operations because taxable income was passed through to Rice Drilling B’s members. Although we are a corporation under the Internal Revenue Code, subject to federal income taxes at a statutory rate of 35% of pretax earnings, we do not expect to report any income tax benefit or expense until the consummation of this offering. Based on our deductions primarily related to IDCs that are expected to exceed 2014 earnings, we expect to generate significant net operating loss assets and deferred tax liabilities. We may report and pay state income or franchise taxes in periods where our IDC deductions do not exceed our taxable income or where state income or franchise taxes are determined on another basis.

How We Evaluate Our Operations

In evaluating our financial results, we focus on production, revenues, per unit cash production, G&A and our Adjusted EBITDAX. 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; equity in (income) loss in our Marcellus joint venture; derivative fair value (gain) loss, excluding net cash receipts on settled derivative instruments; non-cash compensation expense; gain from sale of interest in gas properties; and exploration expenses. Adjusted EBITDAX is not a measure of net income as determined by United States generally accepted accounting principles, or GAAP.

Management believes that the presentation of our Adjusted EBITDAX provides information useful in assessing our financial condition and results of operations and that Adjusted EBITDAX is a widely accepted financial indicator of a company’s results of operations.

Adjusted EBITDAX may not be comparable to similarly titled measures used by other companies and should be considered in conjunction with net income (loss) and other performance measures prepared in accordance with GAAP, such as operating income or cash flows from operating activities. Adjusted EBITDAX has important limitations as an analytical tool because it excludes certain items that affect net income (loss) attributable to common stockholders. Adjusted EBITDAX should not be considered in isolation or as a substitute for an analysis of our results as reported under GAAP.

We also 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 core acreage position in the Marcellus and Utica Shales. Additionally, by focusing on concentrated acreage positions, we can build and own centralized midstream infrastructure, including low- and high-pressure gathering lines, compression facilities and water pipeline systems, which enable us to reduce reliance on third-party operators, minimize costs and increase our returns.

We measure the expected return of our wells based on EUR and the related costs of acquisition, development and production. As of December 1, 2013, we had drilled and completed 37 horizontal Marcellus wells with lateral lengths ranging from 2,444 feet to 9,147 feet and averaging 5,669 feet. Our EUR from these 37 wells, as estimated by our independent reserve engineer, NSAI, and normalized for each 1,000 feet of horizontal lateral, range from 1.2 Bcf per 1,000 feet to 2.9 Bcf per 1,000 feet, with an average of 1.8 Bcf per 1,000 feet.

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Results of Operations

Nine Months Ended September 30, 2013 Compared to Nine Months Ended September 30, 2012

Below are some highlights of our financial and operating results for the nine months ended September 30, 2013:

• Our production volumes, including our 50% share of the production in our Marcellus joint venture, increased 185% to 23,708 MMcf in the nine months ended September 30, 2013 compared to 8,318 MMcf in the nine months ended September 30, 2012.

• Our natural gas sales increased 288% to $60.2 million in the nine months ended September 30, 2013 compared to $15.5 million in the nine months ended September 30, 2012.

• Our per unit cash production costs decreased 18% to $1.44 per Mcf in the nine months ended September 30, 2013 compared to $1.76 per Mcf in the nine months ended September 30, 2012. Cash production costs include amounts paid for Pennsylvania impact fees of $0.07 per Mcf and $0.20 per Mcf for the nine months ended September 30, 2013 and September 30, 2012, respectively. Pennsylvania began assessing an impact fee on wells spud in the first quarter of 2012 and retroactively assessed fees for wells spud prior to 2012. Of the $0.20 per Mcf incurred in the nine months ended September 30, 2012, approximately $0.11 per Mcf relates to charges assessed by the state of Pennsylvania for wells spud prior to 2012. The remaining $0.09 relates to wells spud in 2012.

• Our general and administrative expenses increased 85% to $10.0 million in the nine months ended September 30, 2013 compared to $5.4 million for the nine months ended September 30, 2012.

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The following tables set forth selected operating data for the nine months ended September 30, 2013 compared to the nine months ended September 30, 2012:

	Rice Drilling B
	For the Nine Months Ended September 30,						Amount of Change
	2012			2013
	(Unaudited)
(in thousands)
Revenues:
Natural gas sales	$	15,527		$	60,219		$	44,692
Other revenue		—			519			519
Total revenues		15,527			60,738			45,211
Operating expenses:
Lease operating		2,226			5,794			3,568
Gathering, compression and transportation		2,413			6,951			4,538
Production taxes and impact fees		1,165			1,029			(136	)
Exploration		2,850			1,784			(1,066	)
Restricted unit expense		—			40,087			40,087
General and administrative		5,374			9,952			4,578
Depreciation, depletion and amortization		10,209			23,215			13,006
Amortization of deferred financing costs		5,540			4,760			(780	)
Write-down of abandoned leases		2,223			—			(2,223	)
Total expenses		32,000			93,572			61,572
Operating loss		(16,473	)		(32,834	)		(16,361	)
Other income (expense):
Interest expense		(1,801	)		(13,033	)		(11,232	)
Other income (expense)		76			(347	)		(423	)
Gain (loss) on derivative instruments		(3,407	)		16,698			20,105
Loss on extinguishment of debt		—			(10,622	)		(10,622	)
Equity in income of joint ventures		(136	)		19,297			19,433
Total other income (expense)		(5,268	)		11,993			17,261
Net loss	$	(21,741	)	$	(20,841	)	$	900

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	For the Nine Months Ended September 30,				Amount of Change
	2012		2013
	(Unaudited)
Natural gas sales (in thousands):
Rice Drilling B	$	15,527	$	60,219		44,692
Marcellus Joint Venture (1)		7,228		31,469		24,241
Production data (MMcf):
Rice Drilling B		5,683		15,728		10,045
Marcellus Joint Venture (1)		2,635		7,980		5,345
Average prices before effects of hedges per Mcf:
Rice Drilling B	$	2.73	$	3.83		1.10
Marcellus Joint Venture		2.74		3.94		1.20
Average realized prices after effects of hedges per Mcf (2):
Rice Drilling B	$	2.98	$	3.76		0.78
Marcellus Joint Venture		2.74		4.12		1.38
Average costs per Mcf:
Rice Drilling B
Lease operating	$	0.39	$	0.32		(0.07	)
Gathering, compression and transportation		0.42		0.49		0.07
General and administrative		0.95		0.63		(0.32	)
Depletion, depreciation and amortization		1.80		1.48		(0.32	)
Marcellus Joint Venture:
Lease operating	$	0.28	$	0.38		0.10
Gathering, compression and transportation		0.64		0.69		0.05
General and administrative		0.25		0.13		(0.12	)
Depletion, depreciation and amortization		1.35		1.06		(0.29	)

(1) Amounts presented for our Marcellus joint venture give effect to our 50% equity investment therein.

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

Natural gas sales revenues. The $44.7 million increase was a result of an increase in production of 10,045 MMcf in the first nine months of 2013 compared to the prior year period. The increase in production was a result of increased drilling and completion activity in Washington County, Pennsylvania. In addition, average prices before the effect of hedges increased from $2.73 per Mcf in the first nine months of 2012 to $3.83 per Mcf in the first nine months of 2013.

Lease operating expenses. The $3.6 million increase in lease operating expenses is attributable to higher production during the nine months ended September 30, 2013. In addition, lease operating expenses per unit of production decreased due to having more wells in early stages of production in the nine month period ended September 30, 2013 as compared to the nine month period ended September 30, 2012.

Gathering, compression and transportation. The $4.5 million increase in gathering, compression and transportation expenses is primarily attributable to increased production. However the cost per Mcf of these expenses increased during the nine months ended September 30, 2013 primarily as a result of increased utilization of firm transportation.

Restricted unit expense. The $40.1 million increase in restricted unit expense relates to an increase in the fair value of the units during the nine months ended September 30, 2013. For a description of the restricted units, please see Note 11 to the audited consolidated financial statements of our predecessor. In connection with this offering, the restricted units will be exchanged for shares of our common stock. Accordingly, we will not recognize such restricted unit expense subsequent to the exchange.

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G&A. The $4.6 million increase was primarily attributable to the additions of personnel to support our growth activities.

DD&A. The $13.0 million increase was a result of higher average capitalized costs in the nine month period ended September 30, 2013 compared to the prior year period. The increase in capitalized costs is consistent with our expanded drilling program and increased production during the period.

Write-down of abandoned leases. The $2.2 million write off in the first nine months of 2012 was attributable to our abandonment of certain leases that are outside our core areas of drilling focus.

Gain (loss) on derivative instruments. The $16.7 million gain on derivatives contracts in the nine months ended September 30, 2013 was comprised of $17.8 million in unrealized gains and $1.1 million of cash payments made on settlement of maturing contracts. In 2012, the $3.4 million loss was comprised of $4.8 million in unrealized losses and $1.4 million of cash payments received on settlement of maturing contracts. The gain in 2013 was due to a decrease in market prices after we executed significant derivative contracts.

Interest expense. The $11.2 million increase was a result of higher levels of average borrowings outstanding during the 2013 period in order to fund our drilling programs.

Equity in income (loss) of joint ventures. The $19.4 million increase was primarily a result of operations at our Marcellus joint venture. Approximately $6.3 million of the increased income from our Marcellus joint venture was attributable to unrealized gains associated with its hedging program. Substantially all of the remaining increase in income was due to higher revenues, attributable to increased production volumes resulting from the execution of our Marcellus joint venture’s drilling program.

Year Ended December 31, 2012 Compared to Year Ended December 31, 2011

Below are some highlights of our financial and operating results for the year ended December 31, 2012:

• Our production volumes, including our 50% share of the production in our Marcellus joint venture, increased 220% to 13,065 MMcf in the year ended December 31, 2012 compared to 4,089 MMcf in the year ended December 31, 2011.

• Our natural gas sales increased 91% to $26.7 million in the year ended December 31, 2012 compared to $14.0 million in the year ended December 31, 2011.

• Our per unit cash production costs decreased 23% to $1.72 per Mcf in the year ended December 31, 2012 compared to $2.23 per Mcf in the year ended December 31, 2011. Cash production costs include amounts paid for Pennsylvania impact fees of $0.16 per Mcf for year ended December 31, 2012. Pennsylvania began assessing an impact fee on wells spud in the first quarter of 2012 and retroactively assessed fees for wells spud prior to 2012. Of the $0.16 per Mcf incurred in the year ended December 31, 2012, approximately $0.07 per Mcf relates to charges assessed by the state of Pennsylvania for wells spud prior to 2012. The remaining $0.09 per Mcf relates to wells spud in 2012.

• Our total operating expenses increased 179% to $43.3 million in the year ended December 31, 2012 compared to $15.5 million in the year ended December 31, 2011. This increase was generally in line with our increase in revenue resulting from the execution of our drilling program.

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The following table sets forth selected operating data for the year ended December 31, 2012 compared to the year ended December 31, 2011:

	Rice Drilling B
	For the Year Ended December,						Amount of Change
	2011			2012
(in thousands)
Revenues:
Natural gas sales	$	13,972		$	26,743		$	12,771
Other revenue		—			457			457
Total revenues		13,972			27,200			13,228
Operating expenses:
Lease operating		1,630			3,821			2,191
Gathering, compression and transportation		527			3,621			3,094
Production taxes and impact fees		—			1,382			1,382
Exploration		660			3,275			2,615
Restricted unit expense		170			—			(170	)
General and administrative		5,208			7,599			2,391
Depreciation, depletion and amortization		5,981			14,149			8,168
Amortization of deferred financing costs		2,675			7,220			4,545
Write-down of abandoned leases		109			2,253			2,144
Gain from sale of interest in gas properties		(1,478	)		—			1,478
Total operating expenses		15,482			43,320			27,838
Operating loss		(1,510	)		(16,120	)		(14,610	)
Other income (expense):
Interest expense		(531	)		(3,487	)		(2,956	)
Other income		161			112			(49	)
Gain (loss) on derivative instruments		574			(1,381	)		(1,955	)
Equity in income of joint ventures		370			1,532			1,162
Total other income (expenses)		574			(3,224	)		(3,798	)
Net loss	$	(936	)	$	(19,344	)	$	(18,408	)

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	For the Year Ended December 31,				Amount of Change
	2011		2012
Natural gas sales (in thousands):
Rice Drilling B	$	13,972	$	26,743		12,771
Marcellus Joint Venture (1)		2,872		13,142		10,270
Production data (MMcf):
Rice Drilling B		3,392		8,769		5,377
Marcellus Joint Venture (1)		697		4,296		3,599
Average prices before effects of hedges per Mcf:
Rice Drilling B	$	4.12	$	3.05		(1.07	)
Marcellus Joint Venture		4.12		3.06		(1.06	)
Average realized prices after effects of hedges per Mcf (2):
Rice Drilling B	$	4.29	$	3.15		(1.14	)
Marcellus Joint Venture		4.12		3.07		(1.05	)
Average costs per Mcf:
Rice Drilling B
Lease operating	$	0.48	$	0.44		(0.04	)
Gathering, compression and transportation		0.16		0.41		0.25
General and administrative		1.59		0.87		(0.72	)
Depletion, depreciation and amortization		1.76		1.61		(0.15	)
Marcellus Joint Venture:
Lease operating	$	0.51	$	0.39		(0.12	)
Gathering, compression and transportation		0.04		0.78		0.74
General and administrative		0.26		0.24		(0.02	)
Depletion, depreciation and amortization		1.57		1.10		(0.47	)

(1) Amounts presented for our Marcellus joint venture give effect to our 50% equity investment therein.

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

Natural gas sales revenues. The $12.8 million increase was a result of an increase in production of 5,377 MMcf in 2012 compared to the prior year, partially offset by a 26% decrease in average prices before the effect of hedges. The increase in production was a result of a significant acceleration of our drilling and completion program.

Lease operating expenses. The $2.2 million increase in lease operating expenses is generally consistent with the increase in production volumes in 2012 compared to 2011.

Gathering, compression and transportation. Of the $3.1 million increase, $2.4 million is attributable to our purchase of firm transportation to transport our produced natural gas to the markets where it is sold. The firm transportation commitment was made in anticipation of increasing production volumes, which resulted in increased utilization of this firm transportation throughout 2012 and into 2013. The remaining increase in gathering, compression and transportation is due to overall higher production volumes in 2012 compared to 2011.

G&A. The increase of $2.4 million was primarily attributable to the addition of personnel to support our growth activities.

DD&A. The increase of $8.2 million was a result of higher average capitalized costs in 2012 compared to 2011. The increase in capitalized costs is consistent with our expanded drilling program and increased production during the period.

Amortization of deferred financing costs. The increase of $4.5 million was a result of higher levels of average borrowings outstanding during the 2012 period in order to fund our drilling programs.

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Write-down of abandoned leases. The $2.3 million write-off in 2012 was attributable to our abandonment of certain leases that are outside our core areas of drilling focus.

Gain from sale of interest in gas properties. In 2011, we recognized a gain related to the sale of a 50% working interest in certain gas properties in the Marcellus Shale.

Gain (loss) on derivative instruments. The $1.4 million loss on derivatives contracts in 2012 was comprised of $2.3 million in unrealized losses and $0.9 million of cash payments received on settlement of maturing contracts. In 2011, the $0.6 million gain was represented by cash payments received on settlement of maturing contracts.

Interest expense. The increase of $3.0 million was primarily attributable to higher levels of average borrowings outstanding during the 2012 period in order to fund our drilling programs.

Equity in income (loss) of joint ventures. The increase of $1.2 million was primarily a result of an increase in operating income attributable to higher production volumes of our Marcellus joint venture.

Capital Resources and Liquidity

Our primary sources of liquidity have been equity contributions from our sponsors, borrowings under bank credit facilities, net proceeds from the sale of our convertible debentures and proceeds from our term loan. Our primary use of capital has been the acquisition and development of natural gas properties. As we pursue reserve and production growth, we monitor which capital resources, including equity and debt financings, are available to us to meet our future financial obligations, planned capital expenditure activities and liquidity requirements. We also expect to fund a portion of these requirements with cash flow from operations as we continue to bring additional production online.

Our future success in growing proved reserves and production will be highly dependent on the capital resources available to us. In 2014, excluding $100 million to be paid with respect to the Marcellus JV Buy-In, we plan to invest $1,080 million in our operations, including $299 million for drilling and completion in the Marcellus Shale, $132 million for drilling and completion in the Utica Shale, $386 million for leasehold acquisitions (of which approximately $108 million is currently committed and the remainder is discretionary) and $263 million for midstream infrastructure development. This represents a 72% increase over our $629 million pro forma 2013 capital budget. Without giving pro forma effect to the Marcellus JV Buy-In, our 2013 capital budget was $578 million. We expect to fund our 2014 capital expenditures with cash generated by operations, borrowings under our revolving credit facility and a portion of the net proceeds of this offering. Our 2014 capital expenditure budget also assumes that the borrowing base under our revolving credit facility is increased during 2014. If our lenders do not increase our borrowing base, we may seek alternate debt financing or reduce our capital expenditures. In addition, a portion of our 2014 capital budget is projected to be financed with cash flows from operations derived from wells drilled on drilling locations not associated with proved reserves in our September 30, 2013 reserve report. The failure to achieve projected production and cash flows from operations from such wells could result in a reduction to our 2014 capital budget. Our 2014 capital budget may be further adjusted as business conditions warrant. The amount, timing and allocation of capital expenditures is largely discretionary and within our control. If natural gas prices decline to levels below our acceptable levels, or costs increase to levels above our acceptable levels, we could choose to defer a significant portion of our budgeted capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity and prioritize capital projects that we believe will have the highest expected rates of return and potential to generate near-term cash flow. We routinely monitor and adjust our capital expenditures in response to changes in commodity prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in drilling activities, contractual obligations, internally generated cash flow and other factors both within and outside our control.

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We believe that operating cash flows, available borrowings under our revolving credit facility and the proceeds to us from this offering should be sufficient to meet our cash requirements, including normal operating needs, debt service obligations, capital expenditures, and commitments and contingencies. However, to the extent that we consider market conditions favorable, we may access the capital markets to raise capital from time to time to fund acquisitions, pay down our revolving credit facility and for general working capital purposes.

See “Debt Agreements” below for additional details on our outstanding borrowings and available liquidity under our various financing arrangements.

Cash Flow Provided by Operating Activities

Net cash provided by operating activities was $20.2 million for the nine months ended September 30, 2013, compared to $7.8 million of net cash used in operating activities for the nine month period ended September 30, 2012. The change in operating cash flow was primarily the result of a $13.9 million increase in net income before DD&A; $19.4 million of which was attributable to undistributed earnings from our Marcellus joint venture.

For the full year 2012, net cash used in operating activities was $3.0 million compared to net cash provided by operating activities of $5.1 million for the year ended December 31, 2011. The decrease in cash flow from operations for the year ended December 31, 2012 compared to 2011 was primarily due to an approximate $4.7 million change in working capital items.

Cash Flow Used In Investing Activities

During the nine months ended September 30, 2012 and 2013, cash flows used in investing activities were $85.6 million and $342.6 million, respectively, primarily related to our capital expenditures for drilling, development and acquisition costs. In addition, we made a $10.0 million investment in our Marcellus Shale joint venture in the nine months ended September 30, 2012.

During the years ended December 31, 2011 and 2012, cash flows used in investing activities were $79.2 million and $120.0 million, respectively, primarily related to our capital expenditures for drilling, development and acquisition costs, net of sales proceeds. Nearly all of our investments in unconsolidated joint ventures of $15.2 million and $10.0 million for the years ended December 31, 2011 and 2012 related to our Marcellus joint venture.

As of September 30, 2013, we have spent approximately $342.6 million of our 2013 budgeted capital expenditures, primarily on drilling and completion and new leasing activities.

Cash Flow Provided By Financing Activities

Net cash provided by financing activities of $341.5 million during the nine months ended September 30, 2013 was primarily the result of debt borrowings net of repayments that are more fully described in “Debt Agreements” below. In addition, we received capital contributions from our members of $97.2 million and $198.0 million during the nine month periods ended September 30, 2012 and 2013, respectively.

Net cash provided by financing activities of $73.4 million during the year ended December 31, 2011 was primarily the result of net borrowings that are further described in “Debt Agreements” below. Net cash provided by financing activities of $127.1 million during the year ended December 31, 2012 was primarily attributable to capital contributions from our members and net borrowings under debt agreements.

During the nine months ended September 2013, we finalized a $300 million equity commitment from NGP, of which approximately $200 million was funded in April 2013. Cash proceeds from the investment were used to partially fund our Utica Shale leasehold acquisitions in southeastern Ohio. NGP’s equity commitments will terminate in connection with the closing of this offering.

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Debt Agreements

Senior Secured Revolving Credit Facility

On April 25, 2013, we entered into a revolving credit facility with Wells Fargo Bank, N.A., as administrative agent, and a syndicate of lenders with a maximum credit amount of $500 million and a sublimit for letters of credit of $10 million. As of September 30, 2013 and December 1, 2013, the sublimit for the letters of credit was $25 million and $100 million, respectively. The amount available to be borrowed under the revolving credit facility is subject to a borrowing base that is redetermined semiannually as of each January 1 and July 1 and depends on the volumes of our proved oil and gas reserves and estimated cash flows from these reserves and our commodity hedge positions. The next redetermination is scheduled to occur in April 2014. As of November 1, 2013, the borrowing base was $155.0 million. As of December 31, 2013, we had $115.0 million in borrowings and approximately $22.5 million in letters of credit outstanding under our revolving credit facility. The revolving credit facility matures April 25, 2018.

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

The credit facility is secured by liens on substantially all of our properties and guarantees from our subsidiaries other than any subsidiary that we have designated as an unrestricted subsidiary. The credit facility contains restrictive covenants that may limit our ability to, among other things:

• incur additional indebtedness;

• sell assets;

• make loans to others;

• make investments;

• enter into mergers;

• make or declare dividends;

• hedge future production or interest rates;

• incur liens; and

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

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

• a current ratio, which is the ratio of our consolidated current assets (includes unused commitment under the credit facility and excludes derivative assets) to our consolidated current liabilities, of not less than 0.75 to 1.0 as of March 31, 2013 and 1.0 to 1.0 at the end of each fiscal quarter thereafter;

• a minimum interest coverage ratio, which is the ratio of consolidated EBITDAX based on the trailing twelve month period to consolidated interest expense, of not less than 2.5 to 1.0; and

• an asset coverage ratio, which is the ratio of the present value of our oil and gas reserves (discounted at 10% per annum) to the sum of all our secured debt (including 50% of any debt incurred by our Marcellus joint venture under its credit facility or any replacement or refinancing of its credit facility) of not less than 1.5 to 1.0 so long as any debt is outstanding under the term loan facility.

We were in compliance with such covenants and ratios as of September 30, 2013.

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Concurrently with the closing of this offering, we expect to amend our revolving credit facility to, among other things, increase the maximum commitment amount to $1.5 billion and lower the interest rate owed on amounts borrowed under the revolving credit facility. After giving effect to the amendment, we anticipate that the borrowing base under our credit facility will be increased to $350 million as a result of the Marcellus JV Buy-In. Eurodollar loans under the amended revolving credit facility will bear interest at a rate per annum equal to LIBOR plus an applicable margin ranging from 150 to 250 basis points, depending on the percentage of our borrowing base utilized. Base rate loans will bear interest at a rate per annum equal to the greatest of (i) the agent bank’s reference rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the rate for one month Eurodollar loans plus 100 basis points, plus an applicable margin ranging from 50 to 150 basis points, depending on the percentage of our borrowing base utilized. We will be subject to the same financial ratios and substantively the same restricted covenants as under the current revolving credit facility. The amended revolving credit facility will mature upon the earlier of the date that is five years following the closing of the amendment and the date that is 180 days prior to the maturity of the second lien term loan facility, if any amounts are outstanding under that facility as of such date.

Second Lien Term Loan Facility

On April 25, 2013, we entered into a second lien term loan credit facility with Barclays Bank PLC, as administrative agent, and a syndicate of lenders in an aggregate principal amount of $300 million. We may increase the size of the term loan facility by up to $50 million in certain circumstances. The credit facility matures October 25, 2018.

Principal amounts borrowed under the term loan facility are payable in an amount equal to 0.25% of the initial principal amount at the end of each quarter with the remainder payable on the maturity date. Interest is payable in arrears at the end of each quarter and on the maturity date. We have a choice of borrowing in Eurodollars or at the base rate. Eurodollar loans bear interest at a rate per annum equal to LIBOR plus 725 basis points with a minimum LIBOR rate of 1.25%. Base rate loans bear interest at a rate per annum equal to the greatest of (i) 2.25%, (ii) the agent bank’s reference rate, (iii) the federal funds effective rate plus 50 basis points and (iv) the rate for one month Eurodollar loans plus 100 basis points, plus 625 basis points. We may prepay the borrowings under the term loan facility at any time, provided that any prepayments of principal amounts during the first year following the closing date are subject to a 2% premium and any prepayments of principal during the second year following the closing date are subject to 1% premium.

The term loan facility is secured by liens on substantially all of our properties that are subordinated to the liens securing the revolving credit facility and guarantees from our subsidiaries other than any subsidiary that we have designated as an unrestricted subsidiary. The credit facility contains restrictive covenants that may limit our ability to, among other things:

• incur additional indebtedness;

• sell assets;

• make loans to others;

• make investments;

• enter into mergers;

• make or declare dividends;

• hedge future production or interest rates;

• incur liens; and

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

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The term loan facility also requires us to maintain an asset coverage ratio, which is the ratio of the present value of our oil and gas reserves (discounted at 10% per annum) to the sum of all our secured debt (including any debt incurred by our Marcellus joint venture under its credit facility or any replacement or refinancing of its credit facility) of not less than 1.5 to 1.0.

We were in compliance with such covenants and ratios as of September 30, 2013.

Convertible Debentures and Warrants

In June 2011, we sold $60 million of 12.00% senior subordinated convertible debentures, which are due July 31, 2014. The convertible debentures are unsecured and subordinated to our secured indebtedness, including the revolving credit facility and the term loan facility. Interest on the notes is payable monthly in arrears on the 15th of each month. We were able to redeem all or part of the notes beginning on July 31, 2013 at a redemption price of 100% of the principal being redeemed plus a premium of 50% of the principal being redeemed. In August 2013, we redeemed a portion of the notes and, as of September 30, 2013, we had $6.9 million of the convertible debentures outstanding. Following this offering, holders of the convertible debentures each may convert part or all of the principal amount of the convertible debentures held by such holder into shares of our common stock. Please see “Corporate Reorganization.” If all of the holders of our currently outstanding convertible debentures exercised their right of conversion, they would receive approximately 752,039 shares of our common stock (assuming an initial public offering price equal to the midpoint of the price range set forth on the cover of this prospectus). This conversion right may be exercised at any time and from time to time, provided that any partial conversion must be for a minimum amount of $50,000 with additional integral multiples of $10,000.

We used the proceeds from the issuances of the convertible debentures to secure additional leasehold interest in the Marcellus Shale and for general corporate purposes.

The convertible debentures contain restrictive covenants including maintenance of a debt coverage ratio of the present value of our proved reserves (discounted at 10%) to our net debt or at least 1.0 to 1.0. Net debt is calculated as the difference between our outstanding debt that is senior or pari passu with the convertible debentures minus the aggregate amount of any unrestricted cash and marketable securities. The debt coverage ratio is tested as of June 30 and December 31 of each year. In the event that the debt coverage ratio is less than 1.0 to 1.0 but greater than 0.8 to 1.0, we have three months to cure in order to comply with the debt coverage ratio. Additionally, the convertible debentures restrict our ability to enter into certain transactions with certain entities controlled by the Rice family without the consent of holders of at least 75% of the outstanding principal amount under the convertible debentures. We were in compliance with such covenants and the debt coverage ratio requirement as of September 30, 2013.

On August 15, 2011, we issued warrants to certain of the broker-dealers involved in our private placement of convertible notes. These warrants are considered to be separate instruments issued solely in lieu of cash compensation for services provided by the broker-dealers. Please see “Description of Capital Stock—Warrants.”

Marcellus Joint Venture Revolving Credit Facility

On September 7, 2012, our Marcellus joint venture entered into a revolving credit facility with Wells Fargo Bank, N.A., as administrative agent, and a syndicate of lenders with a maximum credit amount of $200 million and a sublimit for letters of credit of $25 million. The amount available to be borrowed under the revolving credit facility is subject to a borrowing base that is redetermined semiannually as of each January 1 and July 1 and depends on the volumes of our Marcellus joint venture’s proved oil and gas reserves and estimated cash flows from these reserves and our commodity hedge positions. As of September 30, 2013, the borrowing base was $130 million. In July 2013 and October 2013, our borrowing base was increased to $130 million and $145 million, respectively. The next redetermination is scheduled to occur in April 2014. As of September 30, 2013,

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our Marcellus joint venture had $72.0 million of borrowings and $13.5 million in letters of credit outstanding under the revolving credit facility. The credit facility matures September 7, 2017. The Marcellus joint venture revolving credit agreement will be repaid in full and terminated in connection with the closing of the Marcellus JV Buy-In.

Commodity Hedging Activities

Our primary market risk exposure is in the prices we receive for our natural gas production. Realized pricing is primarily driven by the spot regional market prices applicable to our U.S. natural gas production. Pricing for natural gas 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 oil and natural gas prices, we have entered into financial commodity derivative contracts in the form of swaps, zero cost collars, calls, puts and basis swaps to ensure that we receive minimum prices for a portion of our future oil and natural gas production when management believes that favorable future prices can be secured. We typically hedge the NYMEX Henry Hub price for natural gas.

Our hedging activities are intended to support natural gas prices at targeted levels and to manage our exposure to natural gas 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 and zero cost collars that set a floor and ceiling price for the hedged production. For a description of our commodity derivative contracts, please see Note 4 to the unaudited consolidated financial statements of Rice Drilling B as of and for the nine months ended September 30, 2013 included elsewhere in this prospectus.

By using derivative instruments to hedge exposures to changes in commodity prices, we expose ourselves to the credit risk of our counterparties. Credit risk is the potential failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty is expected to owe us, which creates credit risk. To minimize the credit risk in derivative instruments, it is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. The creditworthiness of our counterparties is subject to periodic review. We have derivative instruments in place with seven different counterparties. As of September 30, 2013, our contracts with Wells Fargo Bank N.A. accounted for 92% of the net fair market value of our derivative assets. We believe Wells Fargo Bank N.A. currently is an acceptable credit risk. We are not required to provide credit support or collateral to Wells Fargo Bank N.A. under current contracts, nor are they required to provide credit support or collateral to us. As of December 31, 2012 and September 30, 2013, we did not have any past due receivables from counterparties.

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Contractual obligations. A summary of our contractual obligations as of September 30, 2013 is provided in the following table, which does not reflect this offering or the use of proceeds therefrom.

	October-December 2013		Payments due by period For the Year Ended December 31,
			2014		2015		2016		2017		Thereafter		Total
	(in thousands)
Revolving Credit Facility (1)	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Term Loan Facility (1)		750		3,000		3,000		3,000		3,000		285,750		298,500
Convertible Debentures (2)		—		6,890		—		—		—		—		6,890
NPI Note		—		8,500		—		—		—		—		8,500
Drilling rig commitments (3)		3,715		11,732		9,707		—		—		—		25,154
Gathering and firm transportation		5,103		19,589		24,619		26,498		26,498		183,912		286,219
Asset retirement obligations (4)		—		—		—		—		—		9,800		9,800
Other		604		2,166		1,120		310		281		64		4,545
Total	$	10,172	$	51,877	$	38,446	$	29,808	$	29,779	$	479,526	$	639,608

(1) Includes outstanding principal amounts at September 30, 2013. This table does not include future commitment fees, amortization of deferred financing costs, interest expense or other fees on these facilities because they are floating rate instruments and we cannot determine with accuracy the timing of future loan advances, repayments or future interest rates to be charged

(2) Includes accrued interest and put premium for each period through maturity. From July 31, 2013 through August 20, 2013, any holder of convertible debentures had the right to cause us to repurchase all or any portion of the convertible debentures it owned at 100% of the portion of the principal amount of the convertible debentures as to which the right was being exercised, plus a premium of 20%. During this period, we repurchased $53.1 million of outstanding convertible debentures and paid a put premium of $10.6 million in accordance with the terms of the convertible debentures.

(3) As of September 30, 2013, we had three horizontal drilling rigs under contract. One of these contracts expires in 2013 and one expires in 2014. The third rig, which we take delivery of in January 2014, expires in 2015. Any other rig performing work for us is doing so on a well-by-well basis and therefore can be released without penalty at the conclusion of drilling on the current well. These types of drilling obligations have not been included in the table above. The values in the table represent the gross amounts that we are committed to pay. However, we will record in our financials our proportionate share based on our working interest.

(4) Represents gross retirement costs with no discounting impact.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to

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be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our consolidated financial statements. See Note 1 of the notes to the audited consolidated financial statements for an expanded discussion of our significant accounting policies and estimates made by management.

Revenue Recognition

Sales of natural gas are recognized when natural gas has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured, and the sales price is fixed or determinable. Natural gas is sold by us under contract with our natural gas marketer and only customer as of December 31, 2012. Pricing provisions are tied to the Platts Gas Daily market prices.

Investments in Joint Ventures

We account for our Marcellus joint venture and oilfield service company joint venture investments under the equity method of accounting as we have significant influence, but not control, over the joint ventures.

Under the equity method of accounting, investments are carried at cost, adjusted for our proportionate share of the undistributed earnings or losses and reduced for any distributions from the investment. We also evaluate our equity method investments for potential impairment whenever events or changes in circumstances indicate that there is an other-than-temporary decline in value of the investment. Such events may include sustained operating losses by the investee or long-term negative changes in the investee’s industry. These indicators were not present, and as a result, we did not recognize any impairment charges related to our equity method investments for any of the periods presented in the consolidated financial statements.

Gas Properties

We use the successful efforts method of accounting for gas-producing activities. Costs to acquire mineral interests in gas properties and to drill and equip exploratory wells that result in proved reserves are capitalized. Costs to drill exploratory wells that do not identify proved reserves as well as geological and geophysical costs and costs of carrying and retaining unproved properties are expensed.

Unproved gas properties that are individually significant are periodically assessed for impairment of value, and a loss is recognized at the time of impairment by providing an impairment allowance. Capitalized costs of producing gas properties and support equipment directly related to such properties, after considering estimated residual salvage values, are depreciated and depleted by the units of production method. Support equipment and other property and equipment not directly related to gas properties are depreciated over their estimated useful lives.

Management’s estimates of proved reserves are based on quantities of natural gas that engineering and geological analysis demonstrates, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic conditions. External engineers prepare the annual reserve and economic evaluation of all properties on a well-by-well basis. Additionally, we adjust natural gas reserves for major well rework or abandonment during the year as needed. The process of estimating and evaluating natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering, and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, revisions in existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates represent our most accurate assessments possible, the subjective decisions and variances in available

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data for various properties increase the likelihood of significant changes in these estimates over time. Because estimates of reserves significantly affect our DD&A expense, a change in our estimated reserves could have a material effect on our net income or loss.

On the sale of an entire interest in an unproved property for cash, a gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained unless the proceeds received are in excess of the cost basis which would result in gain on sale.

Asset Retirement Obligations

We record the fair value of a legal liability for an asset retirement obligation in the period in which it is incurred. For gas properties, this is the period in which a gas well is acquired or drilled. Our retirement obligations relate to the abandonment of gas-producing facilities and include costs to reclaim drilling sites and dismantle and relocate or dispose of gathering systems, wells, and related structures. Estimates are based on historical experience in plugging and abandoning wells and estimated remaining lives of those wells based on reserve estimates.

When a new liability is recorded, we capitalize the costs of the liability by increasing the carrying amount of the related long-lived asset. To the extent future revisions to 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 information, we may revise our estimate of current costs, the assumed annual inflation of the costs and/or the assumed productive lives of our wells. The liability is accreted to its present value each period and the capitalized cost is depreciated over the units of production basis.

Equity Incentives

We have entered into certain compensation arrangements with employees and, in limited cases, consultants. These arrangements have resulted in certain of the awards contained within the arrangements being accounted for as equity awards whereas other awards do not have the characteristics of equity and accordingly are not accounted for as such. These compensation arrangements require us to estimate the fair value of such arrangements. This estimate is based upon an option pricing model with various assumptions including internal business plans that are based on judgments and estimates regarding future economic conditions, costs, inflation rates and discount rates among other factors. To the extent market transactions are known this information is factored into fair value estimates. Certain of the compensation arrangements contain performance conditions that need to be achieved in order for vesting in the arrangements to occur. We routinely monitor these performance conditions in order to determine if compensation expense is required to be recorded in the consolidated financial statements.

Income Taxes

Rice Drilling B, our accounting predecessor, is a limited liability company not subject to federal income taxes. Accordingly, no provision for federal income taxes has been provided for in our historical results of operations because taxable income was passed through to Rice Drilling B’s members. Although we are a corporation under the Internal Revenue Code, subject to federal income taxes at a statutory rate of 35% of pretax earnings, we do not expect to report any income tax benefit or expense until the consummation of this offering. Based on our deductions primarily related to IDCs that are expected to exceed 2014 earnings, we expect to generate significant net operating loss assets and deferred tax liabilities.

Depletion

Capitalized amounts attributable to proved oil and gas properties are depleted by the unit-of-production method over proved reserves. Depletion of the costs of wells and related equipment and facilities, including

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capitalized asset retirement costs, is computed using proved developed 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.

Internal Controls and Procedures

Prior to the completion of this offering, we have been a private company with limited accounting personnel to adequately execute our accounting processes and other supervisory resources with which to address our internal control over financial reporting. In addition, our Marcellus joint venture has relied on our accounting personnel for its accounting processes. We and our Marcellus joint venture have not maintained effective control environments in that the design and execution of our controls has not consistently resulted in effective review and supervision by individuals with financial reporting oversight roles. The lack of adequate staffing levels resulted in insufficient time spent on review and approval of certain information used to prepare the financial statements of us and our Marcellus joint venture. We have concluded that these control deficiencies constitute a material weakness in our control environment and in the control environment of our Marcellus joint venture. A material weakness is a control deficiency, or a combination of control deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis.

In 2011, we and our Marcellus joint venture did not maintain effective controls to ensure proper close processes, formal account reconciliations and technical accounting matter resolution and documentation. In 2012, we and our Marcellus joint venture did not maintain effective controls to ensure proper staffing and supervisory review. For each of these periods, effective controls were not adequately designed or consistently operating to ensure that key computations were properly reviewed before the amounts were recorded in our accounting records. The above identified control deficiencies resulted in audit adjustments to our consolidated financial statements during 2011 and 2012.

Although remediation efforts are still in progress, management has taken steps to address the causes of the 2011 and 2012 audit adjustments by putting into place new accounting processes and control procedures. During 2013, we hired 14 additional individuals to complement our existing accounting staff of four individuals as of December 31, 2012. These hires were made to allow for additional preparation and review time during our monthly accounting close process. During the first quarter of 2014, we expect to implement a comprehensive review of our internal controls, including our overall control environment, and to formalize our review and approval processes.

While we have begun the process of evaluating our internal control over financial reporting, we are in the early phases of our review and will not complete our review until after this offering is completed. We cannot predict the outcome of our review at this time. During the course of the review, we may identify additional control deficiencies, which could give rise to significant deficiencies and other material weaknesses, in addition to the material weaknesses previously identified. Management has taken steps to improve our internal control over financial reporting, including the implementation of new accounting processes and control procedures and the identification of gaps in our skills base and expertise of the staff required to meet the financial reporting requirements of a public company.

We are not currently required to comply with the SEC’s rules implementing Section 404 of the Sarbanes Oxley Act of 2002, and are therefore not required to make a formal assessment of the effectiveness of our internal control over financial reporting for that purpose. Upon becoming a publicly traded company, we will be required to comply with the SEC’s rules implementing Sections 302 and 404 of the Sarbanes Oxley Act of 2002, which will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. Though we will be required to disclose material changes made to our internal controls and procedures on a quarterly basis, we will not be required to make our first annual assessment of our internal control over financial

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reporting pursuant to Section 404 until the year following our first annual report required to be filed with the SEC. To comply with the requirements of being a publicly traded company, we will need to implement additional internal controls, reporting systems and procedures and hire additional accounting and finance staff. Furthermore, while we generally must comply with Section 404 of the Sarbanes Oxley Act of 2002 for our fiscal year ending December 31, 2014, we are not required to have our independent registered public accounting firm attest to the effectiveness of our internal controls until our first annual report subsequent to our ceasing to be an “emerging growth company” within the meaning of Section 2(a)(19) of the Securities Act. Accordingly, we may not be required to have our independent registered public accounting firm attest to the effectiveness of our internal controls until our annual report for the fiscal year ending December 31, 2019. Once it is required to do so, our independent registered public accounting firm may issue a report that is adverse in the event it is not satisfied with the level at which our controls are documented, designed, or operating.

Further, our independent registered public accounting firm is not yet required to formally attest to the effectiveness of our internal controls over financial reporting until the year following our first annual report required to be filed with the SEC. Once it is required to do so, our independent registered public accounting firm may issue a report that is adverse in the event it is not satisfied with the level at which our controls are documented, designed, operated or reviewed. Our remediation efforts may not enable us to remedy or avoid material weaknesses or significant deficiencies in the future.

Quantitative and Qualitative Disclosure about Market Risk

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

Commodity price risk and hedges

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

Interest rate risks

At September 30, 2013, we had no indebtedness outstanding under our revolving credit facility. We have a choice of borrowing in Eurodollars or at the base rate. Eurodollar loans bear interest at a rate per annum equal to LIBOR plus an applicable margin ranging from 175 to 275 basis points (and we anticipate the applicable margin will be reduced to 150 to 250 basis points concurrent with the closing of this offering as a result of the Marcellus JV Buy-In), depending on the percentage of our borrowing base utilized. Base rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank’s reference rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the rate for one month Eurodollar loans plus 100 basis points, plus an applicable margin ranging from 75 to 175 basis points (and we anticipate the applicable margin to be reduced to 50 to 150 basis points concurrent with the closing of this offering as a result of the Marcellus JV Buy-In), depending on the percentage of our borrowing base utilized.

On April 25, 2013, we entered into the term loan with a syndicate of banks. As of September 30, 2013, we had indebtedness outstanding under our term loan of $294.4 million which bears interest at a floating rate. The interest rate on this indebtedness as of September 30, 2013 was approximately 8.5%. Interest is payable in arrears at the end of each quarter and on the maturity date. We have a choice of borrowing in Eurodollars or at the base rate. Eurodollar loans bear interest at a rate per annum equal to LIBOR plus 725 basis points with a minimum

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LIBOR rate of 1.25%. Base rate loans bear interest at a rate per annum equal to the greatest of (i) 2.25%, (ii) the agent bank’s reference rate, (iii) the federal funds effective rate plus 50 basis points and (iv) the rate for one month Eurodollar loans plus 100 basis points, plus 625 basis points. As of September 30, 2013, the 90-day LIBOR rate was approximately 0.3%, which is 0.95% lower than the minimum LIBOR rate on the term loan. Accordingly, a 100 basis point increase in the LIBOR rate would not materially change our interest expense. Based on the outstanding balance on the term loan as of September 30, 2013, a 100 basis point increase in the LIBOR rate beyond the minimum LIBOR rate of 1.25% would increase interest expense by $2.9 million per year.

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

Counterparty and customer credit risk

Our principal exposures to credit risk are through joint interest receivables ($3.8 million at September 30, 2013) and the sale of our natural gas production ($12.9 million in receivables at September 30, 2013), which we market to two natural gas marketing companies. Joint interest receivables arise from billing entities who own partial interest in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we wish to drill. We can do very little to choose who participates in our wells. We are also subject to credit risk due to concentration of our natural gas receivables with two natural gas marketing companies. 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.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.

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BUSINESS

Unless the context indicates or otherwise requires, the estimated proved reserve information and other operating data included in this prospectus reflects the combination of (i) our estimated proved reserve information and production data and (ii) 50% of the estimated proved reserves and production of our Marcellus joint venture attributable to our equity interests therein. Our other equity investee, Countrywide Energy Services, does not have any oil and gas reserves and, as such, is not included in such data. The estimated proved reserve information for the properties of each of us and our Marcellus joint venture contained in this prospectus are based on reserve reports relating thereto prepared by the independent petroleum engineers of NSAI and Wright & Company. We refer to these reports collectively as our “reserve reports.”

Our Company

We are an independent natural gas and oil company engaged in the acquisition, exploration and development of natural gas and oil properties in the Appalachian Basin. We are focused on creating shareholder value by identifying and assembling a portfolio of low-risk assets with attractive economic profiles and leveraging our technical and managerial expertise to deliver industry-leading results. We strive to be an early entrant into the core of a shale play by identifying what we believe to be the core of the play and aggressively executing our acquisition strategy to establish a largely contiguous acreage position. We believe we were an early identifier of the core of both the Marcellus Shale in southwestern Pennsylvania and the Utica Shale in southeastern Ohio.

All of our current and planned development is located in what we believe to be the core of the Marcellus and Utica Shales. The Marcellus Shale is one of the most prolific unconventional resource plays in the United States, and we believe the Utica Shale, based on initial drilling results, is a premier North American shale play. Together, these resource plays offer what we believe to be among the highest rate of return wells in North America. We hold approximately 43,351 pro forma net acres in the southwestern core of the Marcellus Shale, primarily in Washington County, Pennsylvania. We established our Marcellus Shale acreage position through a combination of largely contiguous acreage acquisitions in 2009 and 2010 and through numerous bolt-on acreage acquisitions. In 2012, we acquired approximately 33,499 of our 46,488 net acres in the southeastern core of the Utica Shale, primarily in Belmont County, Ohio. We believe this area to be the core of the Utica Shale based on publicly available drilling results. We operate a substantial majority of our acreage in the Marcellus Shale and a majority of our acreage in the Utica Shale.

Since completing our first horizontal well in October 2010, our pro forma average net daily production has grown approximately 64x to 128 MMcf/d for the third quarter of 2013. All of our production to date has been dry gas attributable to our operations in the Marcellus Shale. Prior to the second quarter of 2013, we ran a two-rig drilling program focused on delineating and defining the boundaries of our Marcellus Shale acreage position. In the second quarter of 2013, we shifted our operational focus from exploration to development, commencing a four-rig drilling program consisting of two rigs specifically for drilling the tophole sections of our horizontal wells and two rigs specifically for drilling the curve and lateral sections of our horizontal wells. We expect to continue running this four-rig program in the Marcellus Shale through 2014. The following chart shows our pro forma average net daily production for each quarter since completing our first horizontal well in the Marcellus Shale.

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Pro Forma Average Net Daily Production (MMcf/d)

As of December 1, 2013, we had drilled and completed 37 horizontal Marcellus wells with lateral lengths ranging from 2,444 feet to 9,147 feet and averaging 5,669 feet. Our estimated ultimate recoveries (“EUR”) from these 37 wells, as estimated by our independent reserve engineer, NSAI, and normalized for each 1,000 feet of horizontal lateral, range from 1.2 Bcf per 1,000 feet to 2.9 Bcf per 1,000 feet, with an average of 1.8 Bcf per 1,000 feet. We have drilled and completed 37 horizontal Marcellus wells as of December 1, 2013 with a 100% success rate (defined as the rate at which wells are completed and produce in commercially viable quantities). As of December 1, 2013, we had 349 gross (325 net) pro forma identified drilling locations in the Marcellus Shale. Additionally, we have drilled and completed three Upper Devonian horizontal wells on our Marcellus Shale acreage with a 100% success rate. Based on our Upper Devonian wells and those of other operators in the vicinity of our acreage as well as other geologic data, we estimate that substantially all of our Marcellus Shale acreage in Southwestern Pennsylvania is prospective for the slightly shallower Upper Devonian Shale. As of December 1, 2013, we had 211 gross (194 net) pro forma identified drilling locations in the Upper Devonian Shale.

For the Utica Shale, we applied the same shale analysis and acquisition strategy that we developed and employed in the Marcellus Shale to acquire our acreage. We began to delineate our Utica Shale leasehold position with the spudding of our first well in Belmont County in October 2013. Please see “Prospectus Summary—Recent Developments—Initial Utica Well.” Our delineation operations are being conducted with a two-rig drilling program (one tophole rig and one horizontal rig), initially sourced from our Marcellus Shale rigs, which will be replaced in early 2014 with two new Marcellus Shale rigs. We intend to maintain this two-rig drilling program in the Utica Shale through 2014. In 2015, we intend to transition to a primarily development-focused strategy in the Utica Shale. As of December 1, 2013, we had 753 gross (233 net) identified drilling locations in the Utica Shale.

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As of September 30, 2013, our pro forma estimated proved reserves were 552 Bcf, all of which were in southwestern Pennsylvania, with 35% proved developed and 100% natural gas. In 2014, excluding $100 million cash to be paid with respect to the Marcellus JV Buy-In, we plan to invest $1,080 million in our operations as follows:

• $299 million for drilling and completion in the Marcellus Shale;

• $132 million for drilling and completion in the Utica Shale;

• $386 million for leasehold acquisitions, of which approximately $108 million is currently committed and the remainder is discretionary; and

• $263 million for midstream infrastructure development.

This represents a 72% increase over our $629 million pro forma 2013 capital budget. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity.” The following table provides a summary of our acreage, average working interest, producing wells, drilling locations, years of drilling inventory, projected 2014 gross wells drilled and projected 2014 drilling and completion capital budget as of December 1, 2013 and our average net daily production for the three months ended September 30, 2013, each on a pro forma basis for the Marcellus JV Buy-In and the asset sales described under “—Recent Developments—Guernsey and Lycoming Asset Sales.”:

	Acreage				Average Working Interest			Producing Wells		Identified Drilling Locations (1)				Drilling Inventory (Years)			Q3 2013 Average Net Daily Production (MMcf/d)		2014 Projected Gross Wells Drilled			2014 Projected D&C Capex Budget ($mm)
	Gross		Net							Gross		Net
Marcellus Shale (2)		45,562		43,351		95	%		37		349		325		11.3	(3)		123		31		$	299
Utica Shale (4)		48,660		46,488		96	%		—		753		233		24.3	(3)		—		31	(5)		132
Upper Devonian Shale (6)									3		211		194			*		5		—			—
Total (6)		94,222		89,839					40		1,313		752					128		62		$	431

(1) Based on our reserve reports as of September 30, 2013, we had 49 gross (42.9 net) locations in the Marcellus Shale associated with proved undeveloped reserves and three gross (three net) locations in the Marcellus Shale associated with proved developed not producing reserves. Please see “Business—Our Operations—Reserve Data—Determination of Identified Drilling Locations” for more information regarding the process and criteria through which these drilling locations were identified. The drilling locations on which we actually drill will depend on the availability of capital, regulatory approval, commodity prices, costs, actual drilling results and other factors. Please see “Risk Factors—Risks Related to Our Business—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 substantial amount of capital that would be necessary to drill our identified drilling locations.”

(2) Excludes non-strategic properties consisting of 548 net acres in Fayette and Tioga Counties, Pennsylvania.

(3) Calculated by dividing our gross identified drilling locations by the number of wells we expect to drill in 2014.

(4) Utica Shale net identified drilling locations gives effect to our projected 31% working interest in the Utica Shale after applying unitization and participating interest assumptions described under “Business—Our Operations—Reserve Data—Determination of Identified Drilling Locations.”

(5) Includes an estimated 19 projected gross wells to be drilled by Gulfport Energy Corporation. Please see “—Development Agreement and Area of Mutual Interest Agreement.”

(6) Approximately 39,020 gross (36,932 net) acres in the Marcellus Shale is also prospective for the Upper Devonian Shale. The Upper Devonian and the Marcellus Shale are stacked formations within the same geographic footprint.

* Not meaningful as a result of 2014 drilling program being primarily focused on the Marcellus and Utica Shales.

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Our Properties

The Appalachian Basin, which covers over 185,000 square miles in portions of Kentucky, Tennessee, Virginia, West Virginia, Ohio, Pennsylvania and New York, is considered a highly attractive energy resource producing region with a long history of oil, natural gas and coal production. More importantly, the Appalachian Basin is strategically located near the high energy demand markets of the northeast United States, which has historically resulted in higher realized sales prices due to the reduced transportation costs a purchaser must incur to transport commodities to end users. Over the past five years, the focus of many producers has shifted from the younger, shallower conventional sandstone and carbonate reservoirs to the older, deeper Marcellus Shale and the newly emerging Utica Shale plays, which has driven Appalachian basin production growth. The U.S. Energy Information Administration estimates that Marcellus Shale natural gas production is expected to exceed 13 Bcf/d in December of 2013, which is approximately 18% of total U.S. natural gas production.

Marcellus Shale

We believe 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, relatively homogeneous high-quality reservoir characteristics and significant hydrocarbon resources in place. Based on these attributes, as well as drilling results publicly released by other operators, we believe that the Marcellus Shale offers some of the most attractive single-well rates of return of all North American conventional and unconventional play types. We also believe that the Marcellus Shale has two core areas: (i) the southwestern core in southwestern Pennsylvania and northern West Virginia and (ii) the northeastern core in northeastern Pennsylvania. According to RigData, approximately 90% of the 89 drilling rigs operating in the Marcellus Shale as of September 2013 were located in these two core areas.

The Devonian-aged Marcellus Shale is an unconventional reservoir that produces natural gas, NGLs and oil and is the largest unconventional natural gas field in the U.S. The productive limits of the Marcellus Shale cover over 90,000 square miles within Pennsylvania, West Virginia, Ohio and New York. The Marcellus Shale is a black, organic-rich shale deposit generally productive at depths between 6,000 to 10,000 feet. Production from the brittle, natural gas-charged shale reservoir is best derived from hydraulically fractured horizontal wellbores that exceed 2,000 feet in lateral length and involve multi-stage fracture stimulations.

In addition, we believe substantially all of our acreage is prospective for the Upper Devonian Shale, which is a black, organic rich shale comprised of the Geneseo Shale, Middlesex Shale and Rhinestreet Shale and is at shallower depths than the Marcellus Shale formation. In Washington and Greene Counties, Pennsylvania, the Upper Devonian Shale and Marcellus Shale are separated by the Tully Limestone which is approximately 30 feet thick in this area. We have drilled and completed three wells in the Upper Devonian Shale and confirmed the presence of the Upper Devonian Shale formation in each of our Marcellus Shale wells drilled as of December 1, 2013.

We have experienced virtually no geologic complexity in our drilling activities through December 1, 2013, which has resulted in a fairly predictable band of expected recoveries per 1,000 feet of lateral length on our wells. We completed nine gross (9 net) horizontal Marcellus Shale wells in 2012 and 22 gross (19.9 net) horizontal Marcellus Shale wells in 2013, through December 1, 2013. As of December 1, 2013, we had a total of 37 gross (34.3 net) producing wells in the Marcellus Shale and an additional 29 gross (26.2 net) wells in progress. As of December 1, 2013, we had 1,313 gross (752 net) pro forma identified drilling locations.

For the month ended November 30, 2013, we had average pro forma net daily production of 161 MMcf/d. As of December 1, 2013, we had two rigs operating in the Marcellus Shale (one tophole rig and one horizontal rig), two rigs operating in the Utica Shale (one tophole rig and one horizontal rig) and expect to drill 29 wells in 2013, of which 25 had been drilled as of December 1, 2013.

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The following table provides a summary of our current gross and net acreage by county in Pennsylvania on a pro forma basis.

County	Gross Acres		Net Acres
Core Southwestern Pennsylvania:
Washington		29,052		27,474
Greene		16,313		15,680
Allegheny		197		197
Total		45,562		43,351
Other (1)		548		548
Total		46,110		43,899

(1) Our other acreage within the Marcellus Shale is located in Fayette and Tioga Counties, Pennsylvania.

In December 2013, we sold all of our Lycoming County acreage (100% non-operated) and related assets to another third party in exchange for $7.0 million. There was no production or net proved reserves attributable to the interests sold in either transaction. We expect to incur a loss of $4.2 million in the fourth quarter of 2013 as a result of this transaction.

Utica Shale

The Ordovician-aged Utica Shale is an unconventional reservoir underlying the Marcellus Shale. The productive limits of the Utica Shale cover over 80,000 square miles within Ohio, Pennsylvania, West Virginia and New York. The Utica Shale is an organic-rich continuous black shale, with most production occurring at vertical depths between 7,000 and 10,000 feet. To date, the rich and dry gas windows of the southern Utica Shale play with BTUs ranging from 1,050 to 1,250 have yielded the strongest well results. We estimate that approximately 20% of our Utica acreage is in this rich gas window, with BTUs ranging from 1,100 to 1,200, and the remaining 80% is in the dry gas window. The richest and thickest concentration of organic-carbon content is present within the Point Pleasant Shale layer of the Lower Utica formation. The Point Pleasant Shale is our primary targeted development play of the Utica Shale.

Based on initial drilling results of our peers, we believe the Utica Shale is a premier North American shale play. We believe that the core area is located in the southern portion of the play, which has been defined by significant drilling activity by several operators. We own 46,488 net acres in the core of the Utica Shale and expect to add to our sizeable land position. The proximity of our Utica acreage position to our operations in the Marcellus Shale allows us to capitalize on operating and midstream synergies. As of December 1, 2013, we had approximately 753 gross (233 net) identified drilling locations in the Utica Shale.

The following table provides a summary of our current gross and net acreage by county in Ohio.

County	Gross Acres(1)		Net Acres
Belmont		43,996		43,996
Guernsey		3,899		1,727
Harrison		765		765
Total		48,660		46,488

(1) Excludes Gulfport’s acreage covered by our Development Agreement and AMI Agreement.

In the fourth quarter of 2013, we commenced drilling our initial Utica well, the Bigfoot 7H, in Belmont County, Ohio. In December 2013, after drilling approximately 1,200 feet of the lateral section within the Point Pleasant formation, the well unexpectedly began flowing gas with higher than anticipated bottomhole pressures

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of approximately 8,800 psi. We employed certain steps, including increasing our drilling mud weight, that successfully controlled the gas flow. However, certain uncased sections in the vertical portion of the wellbore were compromised by the higher mud weight, which ultimately inhibited our efforts to stabilize the gas flow and pressures. We elected to plug the Bigfoot 7H in late December 2013 and are preparing to drill a new horizontal well adjacent to the Bigfoot 7H with reconfigured mud and intermediate casing designs that are intended to better manage higher anticipated pressures and gas flows. We expect to obtain an initial production test from this well late in the first quarter or early in the second quarter of 2014. However, the ultimate timing of our initial production test for our next Utica well could be delayed by a number of factors, including an inability to address pressure concerns experienced by the Bigfoot 7H. We expect to write-off approximately $5.9 million of costs associated with the drilling of the Bigfoot 7H in the fourth quarter of 2013.

We believe that the pressures and natural flow rates experienced on the Bigfoot 7H indicate a highly permeable and porous Point Pleasant formation. However, these pressures may not be an indicator of the production amounts to be expected from future Utica wells. In addition, we may experience further difficulties drilling and completing Utica wells. Please read “Risk Factors—Risks Related to Our Business—We have been an early entrant into new or emerging plays. As a result, our drilling results in these areas are uncertain, and the value of our undeveloped acreage will decline if drilling results are unsuccessful.”

Development Agreement and Area of Mutual Interest Agreement

On October 14, 2013, we entered into a Development Agreement and AMI Agreement with Gulfport covering approximately 50,000 aggregate net acres in the Utica Shale in Belmont County, Ohio. We refer to these agreements as our “Utica Development Agreements.” Pursuant to the Utica Development Agreements, we have an approximately 68.80% participating interest in the Northern Contract Area and an approximately 42.63% participating interest in the Southern Contract Area, each within Belmont County, Ohio. The remaining participating interests are held by Gulfport. The participating interests of us and Gulfport in each of the Northern and Southern Contract Areas approximate our current relative acreage positions in each area.

Pursuant to the Development Agreement, we are named the operator (or Gulfport will agree to vote in favor of our operatorship) of drilling units located in the Northern Contract Area, and Gulfport is named the operator (or we will agree to vote in favor of its operatorship) of drilling units located in the Southern Contract Area. Upon development of a well on the subject acreage, we and Gulfport, will convey to one another, pursuant to a cross conveyance, a working interest percentage equal to the amount of the underlying working interest multiplied by the applicable participating interest. For example, upon development of a well:

• Assuming an aggregate 90% working interest is held by us and/or Gulfport in the Northern Contract Area, we and Gulfport will make cross conveyances to one another such that we hold an approximately 61.92% working interest (representing 68.80% of 90%) and Gulfport holds an approximately 28.08% (representing 31.20% of 90%) working interest in the drilling unit; and

• Assuming an aggregate 90% working interest is held by us and/or Gulfport in the Southern Contract Area, we and Gulfport will make cross conveyances to one another such that we hold an approximate 38.37% working interest (representing 42.63% of 90%) and Gulfport holds an approximate 51.63% (representing 57.37% of 90%) working interest in the drilling unit.

As a result of the Development Agreement, we are the operator of approximately 27,000 aggregate net acres in the Northern Contract Area, and Gulfport is the operator of approximately 23,000 aggregate net acres in the Southern Contract Area. In addition, as wells are developed in the respective contract area, our average working interests in the Utica Shale will decrease as the applicable participating interests are applied to the developed wells.

Every six months during the term of the Development Agreement, we and Gulfport will establish a work program and budget detailing the proposed exploration and development to be performed in the Northern and

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Southern Contract Areas, respectively, for the following six months. The number of horizontal wells proposed to be drilled in each of the Northern Contract Area and Southern Contract Area is limited by the Development Agreement as follows: in 2014, between eight and 40 wells; in 2015, between eight and 50 wells; and thereafter, unlimited.

Pursuant to the AMI Agreement, each party has the right to participate at the level of its applicable participating interest in any acquisition by the other party of working interests or leases acquired within the AMIs. Unless a party elects not to participate therein upon notice by the other party, the subject working interest or lease will be governed by the Development Agreement.

The Utica Development Agreements have terms of ten years and are terminable upon 90 days’ notice by either party; provided that, with respect to interests included within a drilling unit, such interests shall remain subject to the applicable joint operating agreement and we and Gulfport shall remain operators of drilling units located in the Northern Contract Area and Southern Contract Area, respectively, following such termination.

Drilling Program

Prior to the second quarter of 2013, we ran a two-rig drilling program focused on defining the boundaries of our Marcellus Shale acreage position. In the second quarter of 2013, we shifted our operational focus towards development, commencing a four-rig drilling program consisting of two rigs specifically for drilling the tophole sections of our horizontal wells, and two rigs specifically for drilling the curve and lateral sections of our horizontal wells. In addition, we began to delineate our Utica Shale leasehold position with the spudding of our first well in Belmont County in October 2013. Please see “Prospectus Summary—Recent Developments—Initial Utica Well.” We expect to add two rigs to our drilling program in the first quarter of 2014, bringing our total rig count to six. We intend to maintain this rig count through 2014.

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Operating Data

The following table provides certain operational data related to our proved developed producing wells as of December 1, 2013. We are the operator of each of these wells.

	Formation	Lateral Length (Feet)		Reserve Category as of 9/30/13	Producing Wells				First Production		Days Producing (2)		Cumulative Production (Bcf) (2)		Cum. Prod./ Days Prod. (MMcf/d)(2)		Periodic Flow Rates (MMcf/d)(2)						D&C ($MM)		D&C ($/Foot)
Well Name					EUR (Bcf)(1)		BCF/ 1,000’										0-90		91-180		181-360
X-Man 1H	Marcellus		2,444	PDP		4.5		1.8		10/18/2010		585		1.5		2.6		3.6		2.9		3.0	$	6.1	$	2,490
Hulk 2H	Marcellus		2,930	PDP		7.8		2.7		3/4/2011		835		3.0		3.6		5.6		5.8		4.2	$	6.8	$	2,318
Hulk 1H	Marcellus		3,182	PDP		5.1		1.6		3/4/2011		815		2.0		2.5		4.9		3.9		2.3	$	7.1	$	2,227
Thunder 1.2H	Marcellus		3,950	PDP		8.1		2.0		5/7/2011		801		3.8		4.7		6.6		7.9		5.6	$	9.0	$	2,289
Mojo 2H	Marcellus		4,092	PDP		9.3		2.3		6/9/2011		679		3.3		4.9		5.7		7.9		6.1	$	9.2	$	2,247
Capt Planet 1H	Marcellus		3,090	PDP		8.1		2.6		10/14/2011		735		3.4		4.7		6.7		7.4		5.2	$	7.3	$	2,359
Capt Planet 4H	Geneseo		3,450	PDP		4.9		1.4		12/1/2011		651		1.7		2.6		3.0		4.4		2.8	$	6.6	$	1,899
Thunder 2-5H	Marcellus		6,700	PDP		11.1		1.7		1/4/2012		499		4.6		9.3		8.5		15.1		8.7	$	11.7	$	1,744
AU2 1.1H	Marcellus		4,220	PDP		8.7		2.1		4/16/2012		469		3.2		6.8		8.8		9.2		6.2	$	8.1	$	1,923
AU2 3H	Marcellus		4,450	PDP		9.3		2.1		4/20/2012		478		3.1		6.5		8.8		9.5		5.8	$	9.5	$	2,137
Mono 4H	Marcellus		6,233	PDP		12.6		2.0		5/19/2012		476		5.4		11.3		12.7		14.1		11.4	$	9.0	$	1,438
Mojo 4H	Marcellus		5,006	PDP		8.7		1.7		9/7/2012		423		2.4		5.7		6.1		7.9		5.0	$	6.9	$	1,381
Mojo 3H	Marcellus		5,080	PDP		6.0		1.2		9/7/2012		412		1.8		4.4		5.3		5.9		3.6	$	6.8	$	1,330
Mojo 1H	Marcellus		5,448	PDP		8.4		1.5		9/6/2012		399		2.3		5.9		7.1		7.3		5.0	$	7.2	$	1,322
Mojo G4	Geneseo		5,200	PDP		4.4		0.9		9/7/2012		399		1.2		2.9		4.7		3.0		2.2	$	6.7	$	1,280
Thunder 1 6H	Marcellus		6,780	PDP		9.9		1.5		10/16/2012		382		3.3		8.7		12.1		10.3		6.5	$	10.8	$	1,594
Thunder 1 8H	Marcellus		7,666	PDP		12.3		1.6		10/16/2012		382		3.8		10.0		11.3		10.8		9.5	$	11.4	$	1,483
Amigos 3H	Marcellus		6,346	PDP		11.4		1.8		1/18/2013		269		2.8		10.4		11.8		11.1		—	$	8.4	$	1,316
Amigos 6H	Marcellus		6,228	PDP		12.5		2.0		1/18/2013		276		2.9		10.4		12.1		11.0		—	$	8.3	$	1,333
Amigos 4H	Marcellus		3,239	PDP		9.3		2.9		1/19/2013		246		1.5		6.2		6.8		6.2		—	$	6.4	$	1,977
Whipkey 1H	Marcellus		6,655	PDP		11.7		1.8		2/6/2013		293		3.0		10.2		10.4		10.6		—	$	11.3	$	1,697
AU2 2H	Marcellus		6,025	PDP		8.9		1.5		3/8/2013		212		1.9		8.8		10.3		8.3		—	$	7.5	$	1,248
AU2 1H	Marcellus		5,816	PDP		7.0		1.2		3/8/2013		212		1.6		7.7		9.9		6.8		—	$	7.6	$	1,306
Lusk 3H	Marcellus		5,999	PDP		10.6		1.8		4/1/2013		241		2.4		9.8		10.5		10.2		—	$	7.8	$	1,301
Lusk 1H	Marcellus		5,560	PDP		11.1		2.0		4/1/2013		240		2.2		9.3		10.3		9.8		—	$	8.4	$	1,516
Brova 1H	Marcellus		3,552	PDP		8.2		2.3		4/24/2013		221		1.9		8.8		9.8		9.2		—	$	8.5	$	2,381
X-Man 5H	Marcellus		8,862	PDP		12.6		1.4		5/14/2013		200		2.8		14.0		14.3		15.8		—	$	9.8	$	1,107
X-Man 7H	Marcellus		5,957	PDP		9.2		1.6		5/21/2013		194		2.0		10.1		11.7		9.3		—	$	7.9	$	1,318
X-Man G5	Geneseo		5,607	PDP		3.4		0.6		5/21/2013		194		0.6		3.0		3.4		2.6		—	$	7.1	$	1,264
Thunder 2 8H	Marcellus		8,864	PDP		11.5		1.3		7/12/2013		127		1.4		11.1		11.4		—		—	$	9.7	$	1,091
Thunder 2 10H	Marcellus		9,147	PDP		11.2		1.2		7/13/2013		117		1.3		11.4		11.8		—		—	$	10.6	$	1,158
Big Daddy Shaw 4H	Marcellus		2,900	PDP		5.5		1.9		9/27/2013		65		0.4		6.2		—		—		—	$	4.8	$	1,664
Big Daddy Shaw 2H	Marcellus		3,400	PDP		6.6		1.9		9/27/2013		65		0.5		7.6		—		—		—	$	5.8	$	1,699
Amigos 2H	Marcellus		5,630	PDNP		9.9		1.8		10/28/2013		34		0.3		9.7		—		—		—	$	7.6	$	1,354
Amigos 5H	Marcellus		6,622	PDNP		11.0		1.7		10/29/2013		33		0.4		11.4		—		—		—	$	8.7	$	1,308
Amigos 7H	Marcellus		6,698	PDNP		11.0		1.6		10/29/2013		33		0.3		10.6		—		—		—	$	8.2	$	1,224
Hulk 4H	Marcellus		9,000	PUD		13.4		1.5		11/8/2013		23		0.4		16.2		—		—		—	$	9.0	$	1,001
Hulk 6H	Marcellus		9,000	PUD		13.2		1.5		11/9/2013		22		0.3		12.4		—		—		—	$	8.5	$	946
Hulk 8H	Marcellus		9,000	PUD		13.1		1.5		11/8/2013		23		0.3		15.1		—		—		—	$	8.8	$	978
Zorro 7H	Marcellus		4,000	N/A		N/A		1.9		11/21/2013		10		0.0		4.3		—		—		—		N/A		N/A
Marcellus Average (3)
All Wells			5,669			9.7		1.8				312		2.1		8.5		9.1		9.0		5.9	$	8.3	$	1,589
<6,000’			4,283			8.1		1.9				389		2.0		6.3		7.5		7.5		4.7	$	7.4	$	1,827
>6,000’			7,489			11.7		1.6				210		2.2		11.3		11.5		11.9		9.0	$	9.5	$	1,292
Marcellus Producing Well Count by Period (3)
All Wells																37		28		26		15
<6,000’																21		17		17		11
>6,000’																16		11		9		4

(1) EUR represents the sum of gross reserves remaining as of a given date and cumulative production as of that date. EUR is based on the estimated gross reserves attributable to each location in our reserve report as of December 1, 2013.

(2) Production data as of December 1, 2013. Periodic flow rates are one of several factors considered by our independent reserve engineers in determining the EUR attributable to our proved developed locations and may not correlate to the EUR for such locations. For a description of the methodology used by our independent reserve engineers to determine proved reserves, please see “—Our Operations—Reserve Data—Preparation of Reserve Estimates.”

(3) Excludes information related to three wells targeting the Geneseo formation presented in the table above.

* Producing wells EUR and Bcf/1,000 feet is presented for wells that were producing as of December 1, 2013.

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Midstream Operations

Our exploration and development activities are supported by our operated natural gas low- and high-pressure gathering, compression and transportation assets, as well as by third-party arrangements. Unlike many producing basins in the United States, certain portions of the Appalachian Basin do not have sufficient midstream infrastructure to support the existing and expected increasing levels of production. Actively managing these midstream operations allows us to ensure that we can obtain the necessary takeaway capacity for our production.

We maintain a strong commitment to developing the necessary midstream infrastructure to support our drilling schedule and production growth. We seek to accomplish this goal through a combination of internal asset developments and contractual relationships with third-party midstream service providers. We have invested in building low- and high-pressure gathering lines and water pipeline systems. We will continue to invest in our midstream infrastructure, as it allows us to optimize our gathering and takeaway capacity to support our expected rapid production growth, affords us more control over the direction and planning of our drilling schedule and has historically lowered our operating costs. In 2014, we estimate we will spend a total of approximately $263 million on midstream infrastructure. To supplement our gathering system’s operating capacity, we have contracted 110 MMcf/d of capacity on various third party gathering systems to transport our gas to Texas Eastern transmission pipeline.

As of December 1, 2013, we owned and operated 25 miles of high-pressure gathering pipelines on our Marcellus Shale acreage in Washington County, Pennsylvania. Due to the high flow rates and flowing tube pressures experienced with our Marcellus wells, none of our wells require nor utilize artificial lift or compression.

Our midstream infrastructure in Pennsylvania also includes 25 miles of high-density polyethylene pipelines connected to multiple freshwater impoundments for transporting water to our well completion operations. We commenced construction of this system in 2010 and first utilized the system during the completion of our second horizontal Marcellus well. Since then, we have continued to expand this system and, as of September 30, 2013, this system has been utilized for the completion on substantially all of our Marcellus wells. We will continue to expand this system as our well development progresses and we estimate substantially all of our gross identified drilling locations in the Marcellus will be connectable to this system. This system delivers year-round water supply, lessens water handling costs and decreases water truck traffic on local roadways. The cost savings associated with sourcing our water through this system, when compared to wells completed with water sourced only by truck, is approximately $500,000 per horizontal well. We anticipate substantially all of our 2013 wells will utilize this water system.

Transportation and Takeaway Capacity

As of December 1, 2013, our average annual firm transportation contracts and firm sales arrangements for 2014, 2015 and 2016 were approximately 267,000 MMBtu/d, 266,000 MMBtu/d and 372,000 MMBtu/d, respectively. In addition, we expect to enter into a new firm transportation contract for an incremental 45 MMBtu/d, 270,000 MMBtu/d and 270,000 MMBtu/d, respectively, for each of 2014, 2015 and 2016 in January 2014. Our primary long-haul firm transportation commitments include the following:

• We have several firm transportation contracts on the Columbia Gas Transmission Pipeline, which currently takes Marcellus natural gas to the Leach Delivery Point in Kentucky. We have 142,000 MMBtu/d of long term contracts that expire after 2020. Beginning in the second half of 2014, 50,000 of the 142,000 MMBtu/d on the Columbia Gas Transmission Pipeline will have firm access to the Gulf Coast. To meet our short term production needs, we supplement this long term commitment with up to 65,000 MMBtu/d of short term firm transportation agreements.

• We have approximately 136,000 MMBtu/d of firm transportation on Texas Eastern Transmission pipeline. This transportation begins in November 2015 and expires after 2020.

Under firm transportation contracts, we are obligated to deliver minimum daily volumes or pay fees for any deficiencies in deliveries.

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We have approximately 115,000 MMBtu/d of firm sales contracted with a third party. This contract has a term of one year and may be renewed in October 2014. We are currently in negotiations with a third party to extend the existing arrangement to 2019. In addition, we also have approximately 50,000 MMBtu/d of firm sales contracts with a third party from November 2014 through October 2019.

We continue to actively identify and evaluate additional takeaway capacity to facilitate production growth in our Appalachian Basin position.

Business Strategies

Our objective is to create shareholder value by identifying and assembling a portfolio of low-risk assets with attractive economic profiles and leveraging our technical and managerial expertise to deliver industry-leading results. We seek to achieve this objective by executing the following strategies:

• Pursue High-Graded Core Shale Acreage as an Early Entrant. Our acreage acquisition strategy has been predicated on our belief that core acreage provides superior production, EURs and returns on investment. We strive to be an early entrant into the core of a shale play by leveraging our technical expertise and analyzing third-party data. We develop an internally generated geologic model and then study publicly available third-party data, including well results and drilling and completion reports, to confirm our geologic model and define the core acreage position of a play. Once we believe that we have identified the core location, we aggressively execute on our acquisition strategy to establish a largely contiguous acreage position. By virtue of this strategy, we eliminate the need for large exploration programs requiring significant time and capital, and instead pursue areas that have been substantially de-risked, or high-graded, by our competitors. We have applied the expertise and approach that we employed in the Marcellus Shale to the Utica Shale, and we believe we will be able to achieve similar results.

• Target Contiguous Acreage Positions in Prolific Unconventional Resource Plays. We will seek to continue to expand on our success in targeting contiguous acreage positions within the core of the Marcellus and Utica Shales. We believe a concentrated acreage position requires fewer wells and inherently less capital to define the geologic properties across the play and allows us to optimize our wellbore economics. As of December 1, 2013, we have drilled and completed 37 horizontal Marcellus wells that have tested the outer boundaries of our Marcellus acreage position. Additionally, as a result of optimizing our wellbore design with a limited number of wells, we believe our ability to transition from exploration drilling to development drilling in the Marcellus Shale was accomplished with less capital invested than our peers. We intend to replicate this strategy in the Utica Shale.

• Aggressively Develop Leasehold Positions to Economically Grow Production, Cash Flow and Reserves. We intend to continue to aggressively drill and develop our portfolio of 1,313 gross (752 net) pro forma identified drilling locations as of December 1, 2013 with a goal of growing production, cash flow and reserves in an economically-efficient manner. We are currently running a four-rig drilling program. We began to delineate our Utica Shale leasehold position with the spudding of our first well in Belmont County in October 2013. Please see “Prospectus Summary—Recent Developments—Initial Utica Well.” We expect to add two rigs to our drilling program in the first quarter of 2014, bringing our total rig count to six. In executing our development strategy, we intend to leverage our operational control and the expertise of our technical team to deliver attractive production and cash flow growth. As the operator of a substantial majority of our acreage in the Marcellus and Utica Shales, we are able to manage (i) the timing and level of our capital spending, (ii) our exploration and development drilling strategies and (iii) our operating costs, which have resulted in our being a low cost per Mcf leader in the Marcellus Shale. We will seek to optimize our wellbore economics through a meticulous focus on rig efficiency, wellbore accuracy and completion design and execution. We believe that the combination of our operational control and technical expertise will allow us to build on our track record of superior production, cash flow and reserve growth.

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• Maximize Pipeline Takeaway Capacity to Facilitate Production Growth. We maintain a strong commitment to build, own and operate the midstream infrastructure necessary to meet our production growth. We will also continue to enter into long-term firm transportation arrangements with third party midstream operators to ensure our access to market. We believe our commitment to midstream infrastructure allows us to commercialize our production more quickly and provides us with a competitive advantage in acquiring bolt-on acreage.

Competitive Strengths

We possess a number of competitive strengths that we believe will allow us to successfully execute our business strategies:

• Large, Contiguous Positions Concentrated in the Core of the Marcellus and Utica Shales. We own extensive and contiguous acreage positions in the core of two of the premier North American shale plays. We believe we were an early identifier of both the Marcellus Shale core in southwestern Pennsylvania and the Utica Shale core, primarily in Belmont County, Ohio, which allowed us to acquire concentrated acreage positions. Our core position and contiguous acreage in the Marcellus Shale have allowed us to delineate our position as well as produce industry-leading well results, as our wells have some of the highest initial production rates and EURs in the Marcellus Shale. Through a consolidated approach, we are able to increase rig efficiency, turning wells into sales faster, and de-risk our acreage position more efficiently. Additionally, to service our concentrated acreage positions, we build water and midstream infrastructure, which enable us to reduce reliance on third party operators, minimize costs and increase our returns. This has been a strength in the Marcellus Shale and we believe our position in the Utica Shale will allow us to achieve similar results.

• Multi-Year, Low-Risk Development Drilling Inventory. Our drilling inventory as of December 1, 2013 consisted of 1,313 gross (752 net) pro forma identified drilling locations, with 349 gross (325 net) pro forma identified drilling locations in the Marcellus Shale, representing an 11.3 year drilling inventory, and 753 gross (233 net) and 211 gross (194 net) pro forma identified drilling locations in the Utica Shale and Upper Devonian Shale, respectively. We believe that we and other operators in the area have substantially delineated and de-risked our contiguous acreage position in the southwestern core of the Marcellus Shale. As of December 1, 2013, we have drilled and completed 37 wells on our Marcellus Shale acreage with a 100% success rate. We began to delineate our Utica acreage with the spudding of our first well in Belmont County in October 2013.

• Expertise in Unconventional Resource Plays and Technology. We have assembled a strong technical staff of shale petroleum engineers and shale geologists that have extensive experience in horizontal drilling, operating multi-rig development programs and using advanced drilling technology. We have been early adopters of new oilfield services and techniques for drilling (including rotary steerable tools) and completions (including reduced-length frac stages). In the Marcellus Shale as of December 1, 2013 on a pro forma basis, we have drilled 51 horizontal wells totaling approximately 325,000 lateral feet and have completed 37 of these wells totaling approximately 210,000 lateral feet. We have realized improvements in our drilling efficiency over time and we are now drilling lateral sections approximately 50% longer in approximately half the time as it has taken us historically. Our average horizontal lateral drilled in 2011 was 4,733 feet and took 13.0 days to drill from kickoff to total depth. Our average horizontal lateral drilled in 2013 was 7,700 feet and took 5.8 days to drill from kickoff to total depth. Our operating proficiency has also led to increased wellbore accuracy, completion design efficiencies and has yielded top tier production results as reflected in the fact that out of approximately 550 producing horizontal Marcellus Shale wells in Washington County, Pennsylvania, we drilled and completed the top two and four of the top six wells in terms of cumulative production through June 30, 2013, as reported by Pennsylvania’s oil and gas department. Further, we are able to enhance our wellbore economics through multi-well pad drilling (three to nine wells per rig move) and long laterals targeting 6,000 to 10,000 feet.

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• Successful Infill Leasing Program. We have increased our acreage position in the core of the Marcellus Shale through bolt-on leases in the same targeted area. This strategy has allowed us to acquire acreage that provides additional drilling locations and/or adds horizontal feet to future wells. By implementing this strategy, we have grown our Marcellus Shale acreage position in Washington County from our initial acquisition of 642 net acres in 2009 to 43,351 net acres pro forma as of December 1, 2013. We have replicated this strategy successfully in the Utica Shale in Belmont County as well, leasing an additional 15,160 net acres since our initial acquisition of approximately 33,499 net acres in November 2012. We intend to continue to focus our near-term leasing program on Greene and Washington Counties in Pennsylvania and on Belmont County in Ohio, with the strategy of using bolt-on leases to acquire acreage that immediately increases our drilling locations and/or drillable horizontal feet.

• Access to Committed Takeaway Capacity. Our owned and operated gas gathering pipeline system is currently designed to handle up to approximately 1.5 Bcf/d in the aggregate and, as of December 1, 2013, has an operating capacity of approximately 620 MMcf/d in the aggregate. This system connects our producing wells to multiple interstate transmission and other third-party pipelines. We will continue to build out our Pennsylvania gathering system congruent with our future development plans. To supplement our gathering system’s operating capacity, we have contracted 110 MMcf/d of capacity on various third party gathering systems to transport our natural gas to the Texas Eastern transmission pipeline. We will replicate the strategy of owning and operating our own midstream system in Ohio and expect to have our gathering system in Belmont County substantially complete by the end of 2015. We believe our commitment to owning and operating midstream assets allows us to efficiently bring wells online, mitigates the risk of unplanned shut-ins and creates pricing and transportation optionality by connecting to multiple interstate pipelines. We also have secured approximately 642,000 MMBtu/d (which represents approximately 611 MMcf/d) of long-haul firm transportation capacity. By securing firm transportation and firm sales contracts, we are better able to accommodate our growing production and manage basis differentials.

• Significant Liquidity and Active Hedging Program. As of December 31, 2013, on a pro forma basis, we would have had cash on hand of approximately $315.1 million and availability under our revolving credit facility of approximately $317.1 million. We believe this liquidity, along with our cash flow from operations, is sufficient to execute our current capital program. Additionally, our hedging program mitigates commodity price volatility and protects our future cash flows. We review our hedge position on an ongoing basis, taking into account our current and forecasted production volumes and commodity prices. As of December 1, 2013, we have entered into hedging contracts covering approximately 62.9 Bcf (172 MMcf/d) of natural gas production for 2014 at a weighted average index floor price of $4.05 per MMBtu. Furthermore, as of December 1, 2013, we have entered into hedging contracts covering approximately 59.1 Bcf (162 MMcf/d) of natural gas production for 2015 at a weighted average index floor price of $4.05 per MMBtu.

• Proven and Stockholder-Aligned Management Team. Our management team possesses extensive oil and natural gas acquisition, exploration and development expertise in shale plays. For a discussion of our management’s experience, please read “Management.” Our Chief Executive Officer, Chief Operating Officer, Vice President of Exploration & Geology, Vice President of Completions and Vice President of Drilling have worked for us since we drilled our first horizontal Marcellus well. Our management team includes certain members of the Rice family (the founders of Rice Partners) who, along with other members of the management team, are also highly aligned with stockholders through a 33.4% economic interest in us upon completion of this offering. In addition, our management team has a significant indirect economic interest in us through their ownership of incentive units in the form of interests in Rice Holdings and NGP Holdings, the value of which may increase over time, without diluting public investors, if our stock price appreciates following the completion of this offering. For additional information regarding our incentive units, please read “Executive Compensation—Narrative Description to the Summary Compensation Table for the 2013 Fiscal Year—Long-Term Incentive Compensation.” We believe that our management team’s direct and indirect ownership interest in us will provide significant incentives to grow the value of our business.

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Our Operations

Reserve Data

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

Reserves Presentation

Our estimated proved reserves and PV-10 as of December 31, 2012 and as of September 30, 2013 are based on evaluations prepared by our independent reserve engineers, NSAI. See “Prospectus Summary—Summary Reserve and Operating Data—Summary Reserve Data.” A copy of the summary reports of NSAI with respect to our reserves as of December 31, 2012 and September 30, 2013 are filed as exhibits to the registration statement of which this prospectus forms a part. See “—Preparation of Reserve Estimates” for definitions of proved reserves and the technologies and economic data used in their estimation.

The following table summarizes our historical and pro forma estimated proved reserves and related PV-10 at December 31, 2012 and September 30, 2013.

	Natural Gas
	Estimated Net Reserves (Bcf)
	At December 31, 2012 (1)									At September 30, 2013
	Rice Energy Inc. Pro  Forma			Rice Drilling B			Marcellus Joint Venture (2)			Rice Energy Inc. Pro Forma			Rice Drilling B			Marcellus Joint Venture (2)
Estimated Proved Reserves:
Total proved reserves		561			304			128			552			348			102
Total proved developed reserves		131			61			35			193			85			54
Total proved developed producing reserves		101			57			22			167			85			41
Total proved developed non-producing reserves		30			4			13			26			—			13
Total proved undeveloped reserves		430			243			93			359			263			48
Percent proved developed		23	%		20	%		27	%		35	%		24	%		53	%
PV-10 of proved reserves (in millions) (3)	$	245		$	102		$	71		$	566		$	344		$	111

(1) Our historical and pro forma estimated proved reserves, PV-10 and standardized measure were determined using a 12-month average price for natural gas. The prices used in our reserve reports yield weighted average wellhead prices, which are based on index prices and adjusted for energy content, transportation fees and regional price differentials. The index prices and the equivalent wellhead prices are shown in the table below.

	Index Prices – Natural Gas (per MMBtu)						Weighted Average Wellhead Prices – Natural Gas (per Mcf)
	Rice Energy Inc. Pro Forma		Rice Drilling B		Marcellus Joint Venture		Rice Energy Inc. Pro Forma		Rice Drilling B		Marcellus Joint Venture
December 31, 2012	$	2.76	$	2.76	$	2.76	$	2.85	$	2.86	$	2.84
September 30, 2013		3.61		3.61		3.61		3.84		3.84		3.84

(2) Historical amounts presented for our Marcellus joint venture give effect to our 50% equity investment in our Marcellus joint venture.

(3) 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. However, the respective PV-10s and standardized measures of us and our Marcellus joint venture are equivalent because as of December 31, 2012 and September 30, 2013, we and our Marcellus joint venture were not subject to entity level taxation. Accordingly, no provision for federal or state corporate income taxes has been provided because taxable income is passed through to our respective equity holders. However, in connection with the closing of this offering, as a result of our corporate reorganization, we will be a corporation subject to federal income tax and our future income taxes will be dependent upon our future taxable income. We estimate that our pro forma standardized measure, our historical standardized measure and the historical standardized measure for our Marcellus joint venture as of December 31, 2012, would have been approximately $163 million, $67 million and $96 million, respectively, as adjusted to give effect to the present value of approximately $84 million, $37 million and $47 million, respectively, of future income taxes as a result of our being treated as a corporation for federal income tax purposes. Neither PV-10 nor standardized measure represents an estimate of the fair market value of our 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

Proved undeveloped reserves are included in the previous table of total proved reserves. The following table summarizes the changes in the estimated historical and pro forma proved undeveloped reserves of us and our Marcellus joint venture during 2012 (in MMcf):

	Rice Energy Inc. Pro Forma		Rice Drilling B			Marcellus Joint Venture (1)
Proved undeveloped reserves, December 31, 2011		294,857		207,599			87,258
Conversions into proved developed reserves		(33,908)		(15,120	)		(18,788	)
Extensions		330,851		164,561			166,290
Price revisions		(162,543)		(113,993	)		(48,550	)
Proved undeveloped reserves, December 31, 2012		429,257		243,047			186,210

(1) Amounts presented for our Marcellus joint venture do not give effect to our 50% equity investment therein.

During 2012, on a pro forma basis, extensions, discoveries, and other additions of 330,851 MMcf proved undeveloped reserves were added through the drillbit in the Marcellus Shale. Downward price revisions resulted in a reduction of proved undeveloped reserves by 162,543 MMcf.

During 2012, on a pro forma basis, we incurred costs of approximately $36.0 million to convert 33,908 MMcf of proved undeveloped reserves to proved developed reserves. Estimated future development costs relating to the development of our proved undeveloped reserves at December 31, 2012 on a pro forma basis are approximately $432 million over the next five years, which we expect to finance through the proceeds of this offering, cash flow from operations, borrowings under our revolving credit facility and other sources of capital financing. Our drilling programs through the first three quarters of 2013 have focused on proving our undeveloped leasehold acreage through delineation drilling. While we will continue to drill leasehold delineation wells and build on our current leasehold position, we will also focus on drilling our proved undeveloped reserves. Based on our reserve reports as of September 30, 2013, we had 49 gross (42.9 net) pro forma locations in the Marcellus Shale associated with proved undeveloped reserves and three gross (three net) locations in the Marcellus Shale associated with proved developed not producing reserves. All of our proved undeveloped reserves are expected to be developed over the next five years. See “Risk Factors—Risks Related to Our Business—The development of our estimated proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated proved undeveloped reserves may not be ultimately developed or produced.”

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Preparation of Reserve Estimates

Our reserve estimates as of December 31, 2012 and 2011 and as of September 30, 2013 included in this prospectus were based on evaluations prepared by the independent petroleum engineering firms of NSAI and Wright & Company in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Evaluation Engineers and definitions and guidelines established by the SEC. Our independent reserve engineers were selected for their historical experience and geographic expertise in engineering unconventional resources.

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

Internal Controls

We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of data furnished to NSAI in their reserves estimation process. Ryan I. Kanto, our Vice President of Production, is the technical person primarily responsible for overseeing the preparation of our reserve estimates. He has substantial industry experience with positions of increasing responsibility in engineering and evaluations. Throughout each fiscal year, our technical team meets with representatives of our independent reserve engineers to review properties and discuss methods and assumptions used in preparation of the proved reserves estimates. While we have no formal committee specifically designated to review reserves reporting and the reserves estimation process, a preliminary copy of the reserve report is reviewed by our senior management with representatives of our independent reserve engineers and internal technical staff.

Qualifications of Responsible Technical Persons

Ryan I. Kanto joined Rice Energy in June 2011 and currently serves as our Vice President of Production. Prior to Rice Energy, Mr. Kanto worked at EnCana Oil & Gas (USA) Inc. from June 2007 to May 2011. During this time he served as a facilities engineer in the Deep Bossier from June 2007 to January 2008, a reservoir engineer in the Barnett Shale until February 2009, and completion engineer in the Haynesville Shale until his departure. Mr. Kanto has bachelors degrees in Chemical Engineering and Engineering Management from the University of Arizona and has significant experience in unconventional shale gas plays.

Our proved reserve estimates shown herein at December 31, 2012 and 2011 and at September 30, 2013 and the proved reserve estimates shown herein for our Marcellus joint venture have been independently 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

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the Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical person primarily responsible for preparing the estimates set forth in the NSAI letters, each of which is filed as an exhibit to this registration statement, was Richard B. Talley, Jr., Vice President, Team Leader, and a consulting petroleum engineer. Mr. Talley is a Registered Professional Engineer in the State of Texas (License No. 102425). Mr. Talley joined NSAI in 2004 after serving as a Senior Engineer at ExxonMobil Production Company. Mr. Talley’s areas of specific expertise include probabilistic assessment of exploration prospects and new discoveries, estimation of oil and gas reserves, and workovers and completions. Mr. Talley received an MBA degree from Tulane University in 2001 and a BS degree in Mechanical Engineering from University of Oklahoma in 1998. Mr. Talley meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; he is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserve definitions and guidelines.

The proved reserve estimates shown herein at December 31, 2011 for our Marcellus joint venture have been independently prepared by Wright & Company. Wright & Company was founded in 1988 and performs consulting petroleum engineering services under Texas Board of Professional Engineers. Within Wright & Company, the technical person primarily responsible for preparing the estimates set forth in the Wright & Company letter, filed as an exhibit to this registration statement, was D. Randall Wright. Mr. Wright has been a practicing consulting petroleum engineer at Wright & Company since its founding in 1988. Mr. Wright is a Registered Professional Engineer in the State of Texas (License No. 43291) and has over 35 years of practical experience in petroleum engineering, with over 25 years of experience in the estimation and evaluation of reserves. He graduated from Tennessee Technological University with a Master of Science degree in Mechanical Engineering. Mr. Wright meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; he is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserve definitions and guidelines.

Determination of Identified Drilling Locations

Our gross (net) identified drilling locations are those drilling locations identified by management based on the following criteria:

• Drillable Locations – These are mapped locations that our Vice President of Exploration & Geology has deemed to have a high likelihood as being drilled or are currently in development but have not yet commenced production. With respect to our Pennsylvania acreage, we had 224 gross (200 net) pro forma drillable Marcellus locations and 134 gross (117 net) pro forma drillable Upper Devonian locations as of December 1, 2013. With respect to our Ohio acreage, as of December 1, 2013, we had 637 gross (192 net) drillable Utica locations, all of which are located within the contract areas covered by our Development Agreement and AMI Agreement with Gulfport.

• Estimated Locations – These remaining estimated locations are calculated by taking our total acreage, less acreage that is producing or included in drillable locations, and dividing such amount by our expected well spacing to arrive at our unrisked estimated locations which is then multiplied by a risking factor. We assume these Marcellus locations have 6,000 foot laterals and 600 foot spacing between Marcellus wells which yields approximately 80 acre spacing. We assume these Upper Devonian locations have 6,000 foot laterals and 1,000 foot spacing between Upper Devonian wells which yields approximately 140 acre spacing. We assume these Utica locations have 8,000 foot laterals and 600 foot spacing between Utica wells which yields approximately 110 acre spacing. With respect to our Pennsylvania acreage, we multiply our unrisked estimated Marcellus and Upper Devonian locations by a risking factor of 50% to arrive at total risked estimated locations. As a result, we had 125 gross (125 net) pro forma estimated risked Marcellus locations and 77 gross (77 net) pro forma estimated risked Upper Devonian locations as of December 1, 2013. With respect to our Ohio acreage,

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we multiply our unrisked estimated locations by a risking factor of approximately 37% to arrive at total risked estimated locations. We then apply our assumed working interest for such location, calculated by applying the impact of assumed unitization on the underlying working interest as well as, in the case of locations within the AMI with Gulfport, the applicable participating interest. As a result, as of December 1, 2013, we had 116 gross (41 net) estimated risked Utica locations.

We believe the risking of our estimated locations provides a more accurate number of gross and net identified drilling locations that could be drilled. With respect to our Utica Shale identified drilling locations within Belmont County, our net identified drilling locations give effect to the application of the applicable participating interest to gross identified drilling locations within the Northern and Southern Contract Areas. Please see “—Development Agreement and Area of Mutual Interest Agreement.” Had we not risked our pro forma estimated locations, our gross identified drilling locations as of December 1, 2013 would have been approximately 1,712.

Production, Revenues and Price History

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

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The following table sets forth information regarding production, revenues and realized prices, and production costs for the years ended December 31, 2011 and 2012, for the nine months ended September 30, 2012 and 2013, for us and our Marcellus joint venture on a standalone basis. Amounts shown for our Marcellus joint venture give effect to our 50% equity investment therein. For additional information on price calculations, see information set forth in “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

	For the Year Ended December 31,				Nine Months Ended September 30,
	2011		2012		2012		2013
Natural gas sales (in thousands):						(Unaudited)
Pro Forma Rice Energy Inc.			$	53,027			$	123,157
Rice Drilling B	$	13,972		26,743	$	15,527		60,219
Marcellus Joint Venture		2,872		13,142		7,228		31,469
Production data (MMcf):
Pro Forma Rice Energy Inc.				17,361				31,688
Rice Drilling B		3,392		8,769		5,683		15,728
Marcellus Joint Venture		697		4,296		2,635		7,980
Average prices before effects of hedges per Mcf:
Pro Forma Rice Energy Inc.			$	3.05			$	3.89
Rice Drilling B	$	4.12		3.05	$	2.73		3.83
Marcellus Joint Venture		4.12		3.06		2.74		3.94
Average realized prices after effects of hedges per Mcf (1):
Pro Forma Rice Energy Inc.			$	3.11			$	3.90
Rice Drilling B	$	4.29		3.15	$	2.98		3.76
Marcellus Joint Venture		4.12		3.07		2.74		4.12
Average costs per Mcf (2):
Pro Forma Rice Energy Inc.:
Lease operating			$	0.41			$	0.38
Gathering, compression and transportation				0.59				0.57
General and administrative				0.56				0.38
Depletion, depreciation and amortization				1.63				1.67
Rice Drilling B:
Lease operating	$	0.48	$	0.44	$	0.39	$	0.32
Gathering, compression and transportation		0.16		0.41		0.42		0.49
General and administrative		1.59		0.87		0.95		0.63
Depletion, depreciation and amortization		1.76		1.61		1.80		1.48
Marcellus Joint Venture:
Lease operating	$	0.51	$	0.39	$	0.28	$	0.38
Gathering, compression and transportation		0.04		0.78		0.64		0.69
General and administrative		0.26		0.24		0.25		0.13
Depletion, depreciation and amortization		1.57		1.10		1.35		1.06

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

(2) Does not include production taxes and impact fees. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Principal Components of our Cost Structure.”

Productive Wells

As of December 1, 2013, we had a total of 37 gross (34.3 net) producing wells in the Marcellus Shale. We do not have interests in any wells that produce oil or NGLs.

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Acreage

The following table sets forth certain information regarding the total developed and undeveloped acreage in which we owned an interest as of December 1, 2013. Approximately 48% of our Marcellus acreage and none of our Utica acreage was held by production at December 1, 2013. Acreage related to royalty, overriding royalty and other similar interests is excluded from this table.

	Developed Acres				Undeveloped Acres				Total Acres
Basin	Gross		Net		Gross		Net		Gross		Net
Marcellus (1)		4,077		3,670		41,485		39,681		45,562		43,351
Utica		—		—		48,660		46,488		48,660		46,488
Total		4,077		3,670		90,145		86,169		94,222		89,839

(1) Presented on a pro forma basis to give effect to our Marcellus JV Buy-In described under “Summary—Recent Developments—Marcellus JV Buy-In.”

Undeveloped Acreage Expirations

The following table sets forth the number of total undeveloped acres as of December 1, 2013 that will expire in 2013, 2014, 2015, 2016 and 2017 unless production is established within the spacing units covering the acreage prior to the expiration dates or unless such leasehold rights are extended or renewed. We have not attributed any PUD reserves to acreage for which the expiration date precedes the scheduled date for PUD drilling. In addition, we do not anticipate material delay rental or lease extension payments in connection with such acreage.

Basin	2013		2014		2015		2016		2017+
Marcellus—Southwestern Pennsylvania Core (1)		60		988		2,365		3,735		15,543
Utica		—		360		—		397		45,731
Total		60		1,348		2,365		4,132		61,274

(1) Presented on a pro forma basis to give effect to our Marcellus JV Buy-In described under “Summary—Recent Developments—Marcellus JV Buy-In.” Substantially all of our Marcellus Shale acreage is also prospective for the Upper Devonian Shale. Excludes non-strategic properties in Fayette, Lycoming and Tioga Counties, Pennsylvania.

Drilling Activity

The following table describes the development wells drilled on our acreage by us during the years ended December 31, 2011 and 2012 on a pro forma basis to to give effect to our Marcellus JV Buy-In described under “Summary—Recent Developments—Marcellus JV Buy-In”:

	Productive Wells				Dry Wells				Total
	Gross		Net		Gross		Net		Gross		Net
2011		6.0		5.5		—		—		6.0		5.5
2012		10.0		10.0		—		—		10.0		10.0

We drilled no exploratory wells during 2011 and 2012.

Major Customers

For the nine months ended September 30, 2013, sales to Sequent and Dominion represented 93%, and 7% of our total sales, respectively, on a pro forma basis. For the year ended December 31, 2012, sales to Sequent accounted for 100% of our total sales. Although a substantial portion of production is purchased by these major

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customers, we do not believe the loss of one or both customers would have a material adverse effect on our business, as other customers or markets would be accessible to us. However, if we lose one or both of these customers, there is no guarantee that we will be able to enter into an agreement with a new customer which is as favorable as our current agreements.

Title to Properties

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 to verify the rightful owners of the oil and gas interests prior to payment of such lease bonus to the lessor. There is no certainty, however, that a lessor has valid title to their lease’s oil and gas interests. In those cases, such leases are generally voided and payment is not remitted to the lessor. As such, title failures may result in fewer net acres to us. As is customary in the industry, in the case of undeveloped properties, often cursory investigation of record title is made at the time of lease acquisition. Investigations are made before the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties. Individual properties may be subject to burdens that we believe do not materially interfere with the use or affect the value of the properties. Burdens on properties may include:

• customary royalty interests;

• liens incident to operating agreements and for current taxes;

• obligations or duties under applicable laws;

• development obligations under natural gas leases; or

• net profits interests.

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, certain 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.

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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 which may be drilled in an area, and the unitization or pooling of crude oil or natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas, and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells.

Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the industry increases the cost of doing business and affects profitability. Although we believe we are in substantial compliance with all applicable laws and regulations, such laws and regulations are frequently amended or reinterpreted. Therefore, we are unable to predict 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 FERC, and the courts. We cannot predict 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 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 oil, natural gas and NGLs within its jurisdiction.

We own interests in properties located onshore in three 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. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

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Regulation of Transportation and Sales of Natural Gas

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

In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the Natural Gas Policy Act, or NGPA, and culminated in adoption of the Natural Gas Wellhead Decontrol Act which removed controls affecting wellhead sales of natural gas effective January 1, 1993. 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 certain limited circumstances, intrastate transportation and wholesale sales of natural gas may also be affected directly or indirectly by laws enacted by Congress and by FERC regulations.

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

The Energy Policy Act of 2005, or EPAct 2005, is a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans, and significant changes to the statutory policy that affects all segments of the energy industry. Among other matters, the EPAct 2005 amends the NGA to add an anti-market manipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC, and furthermore provides FERC with additional civil penalty authority. The EPAct 2005 provides FERC with the power to assess civil penalties of up to $1,000,000 per day for violations of the NGA and increases FERC’s civil penalty authority under the NGPA from $5,000 per violation per day to $1,000,000 per violation per day. The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce. On January 19, 2006, FERC issued Order No. 670, a rule implementing the anti-market manipulation provision of the EPAct 2005. The rules make it unlawful: (1) in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; (2) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) to engage in any act or practice that operates as a fraud or deceit upon any person. The anti-market manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the annual reporting requirements under Order 704.

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

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

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

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

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

Our sales of natural gas are also subject to requirements under the Commodity Exchange Act, 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 FERC will take. We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other natural gas producers, gatherers and marketers with which we compete.

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Regulation of Pipeline Safety and Maintenance

We are subject to regulation by the Pipeline and Hazardous Materials Safety Administration, or PHMSA, of the Department of Transportation, or the DOT, pursuant to the Natural Gas Pipeline Safety Act of 1968, or the NGPSA, and the Pipeline Safety Improvement Act of 2002, or the PSIA, which was reauthorized and amended by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006. The NGPSA regulates safety requirements in the design, construction, operation and maintenance of gas pipeline facilities, while the PSIA establishes mandatory inspections for all U.S. oil and natural gas transportation pipelines and some gathering lines in high-consequence areas. The PHMSA has developed regulations implementing the PSIA that require transportation pipeline operators to implement integrity management programs, including more frequent inspections and other measures to ensure pipeline safety in “high consequence areas,” such as high population areas, areas unusually sensitive to environmental damage and commercially navigable waterways.

On January 3, 2012, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, or the Pipeline Safety Act, was signed into law. In addition to reauthorizing the PSIA through 2015, the Pipeline Safety Act expanded the DOT’s authority under the PSIA and requires the DOT to evaluate whether integrity management programs should be expanded beyond high consequence areas, authorizes the DOT to promulgate regulations requiring the use of automatic and remote-controlled shut-off valves for new or replaced pipelines, and requires the DOT to promulgate regulations requiring the use of excess flow values where feasible. Any new or amended pipeline safety regulations may require us to incur additional capital expenditures and may increase our operating costs. We cannot predict what future action the DOT will take, but we do not believe that any regulatory changes will affect us in a way that materially differs from the way they will affect other natural gas gatherers with which we compete.

States are largely preempted by federal law from regulating pipeline safety for interstate lines but most are certified by the DOT to assume responsibility for enforcing federal intrastate pipeline regulations and inspection of intrastate pipelines. In practice, because states can adopt stricter standards for intrastate pipelines that those imposed by the federal government for interstate lines, states vary considerably in their authority and capacity to address pipeline safety. We do not anticipate any significant difficulty in complying with applicable state laws and regulations. Our natural gas pipelines have continuous inspection and compliance programs designed to keep facilities in compliance with pipeline safety requirements.

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 (CERCLA), the Clean Water Act (CWA) and the Clean Air Act (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. Although future environmental obligations are not expected to have a material impact on the results of our operations or financial condition, there can be no assurance that future developments, such as increasingly stringent environmental laws or enforcement thereof, will not cause us to incur material environmental liabilities or costs.

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Public and regulatory scrutiny of the energy industry has resulted in increased environmental regulation and enforcement being either proposed or implemented. For example, EPA’s 2011 – 2013 National Enforcement Initiatives include “Assuring Energy Extraction Activities Comply with Environmental Laws.” According to the EPA’s website, “some techniques for natural gas extraction pose a significant risk to public health and the environment.” To address these concerns, the EPA’s goal is to “address incidences of noncompliance from natural gas extraction and production activities that may cause or contribute to significant harm to public health and/or the environment.” The EPA has emphasized that this initiative will be focused on those areas of the country where energy extraction activities are concentrated, and the focus and nature of the enforcement activities will vary with the type of activity and the related pollution problem presented. This initiative could involve a large scale investigation of our facilities and processes, and could lead to potential enforcement actions, penalties or injunctive relief against us.

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

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, such as Pennsylvania’s Hazardous Sites Cleanup Act, 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 (“RCRA”) regulates the generation and disposal of wastes. RCRA specifically excludes from the definition of hazardous waste “drilling fluids, produced waters and other wastes associated with the exploration, development or production of crude oil, natural gas or geothermal energy.” However, legislation has been proposed from time to time 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 (“NORM”) may affect our operations. For example, the Pennsylvania Department of Environmental Protection has asked operators to identify technologically enhanced NORM (“TENORM”) in their processes, such as hydraulic fracturing sand. Local landfills only accept such waste when it meets their TENORM permit 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.

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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, RCRA, and/or analogous state laws. Under such laws, we could be required to remove or remediate previously disposed wastes (including waste disposed of or released by prior owners or operators) or property contamination (including groundwater contamination by prior owners or operators), or to perform remedial plugging or closure operations to prevent future contamination.

Waste Discharges

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

Air Emissions

The CAA and its state analog and regulations restrict the emission of air pollutants from many sources, including oil and gas operations. New facilities may be required to obtain permits before construction can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. More stringent regulations governing emissions of toxic air pollutants and greenhouse gases (GHGs) have been developed by the EPA and may increase the costs of compliance for some facilities. In 2012, the EPA issued federal regulations affecting our operations under the New Source Performance Standards provisions (new Subpart OOOO) and expanded regulations under national emission standards for hazardous air pollutants, although implementation of some of the more rigorous requirements is not required until 2015. Also in 2012, seven states submitted a notice of intent to sue the EPA to compel the agency to make a determination as to whether standards of performance limiting methane emissions from oil and gas sources is appropriate and, if so, to promulgate performance standards for methane emissions from existing oil and gas sources. These are examples of continued push by EPA and others to further regulate air emissions associated with oil and natural gas drilling operations.

Oil Pollution Act

The Oil Pollution Act of 1990 (“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. 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 OPA. OPA imposes ongoing requirements on a responsible party, including the

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

Endangered Species Act and Migratory Bird Treaty Act

The Endangered Species Act (“ESA”) restricts activities that may affect endangered or threatened species of their habitats. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act While some of our operations may be located in areas that are designated as habitats for endangered or threatened species or that may attract migratory birds we believe that we are in substantial compliance with the ESA and the Migratory Bird Treaty Act, and we are not aware of any proposed ESA listings that will materially affect our operations. 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 (“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.

Safe Drinking Water Act

The Safe Drinking Water Act (“SDWA”) and comparable state provisions restrict the disposal, treatment or release of water produced or used during oil and gas development. Subsurface emplacement of fluids (including disposal wells or enhanced oil recovery) is governed by federal or state regulatory authorities that, in some cases, includes the state oil and gas regulatory authority or the state’s environmental authority. These regulations may increase the costs of compliance for some facilities.

Employees

As of December 31, 2013, we had 139 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

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

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MANAGEMENT

The following table sets forth the names, ages and titles of our directors, director nominees and executive officers as of December 1, 2013.

Name	Age		Position with Rice Energy
Daniel J. Rice IV		33	Director, Chief Executive Officer
Toby Z. Rice		31	Director, President and Chief Operating Officer
Derek A. Rice		28	Vice President of Exploration & Geology
Grayson T. Lisenby		27	Vice President and Chief Financial Officer
James W. Rogers		33	Vice President, Chief Accounting & Administrative Officer, Treasurer
William E. Jordan		33	Vice President, General Counsel and Corporate Secretary
Robert F. Vagt		66	Director Nominee (Chairman)
Daniel J. Rice III		62	Director
Scott A. Gieselman		50	Director
Chris G. Carter		35	Director
James W. Christmas		65	Director Nominee
Kevin S. Crutchfield		52	Director Nominee

The following table sets forth information regarding other key employees as of December 1, 2013.

Name	Age		Position with Rice Energy
Ryan I. Kanto		30	Vice President of Production
Michael J. Lauderbaugh		40	Vice President of Environmental Health and Safety
John P. LaVelle		58	Vice President of Drilling
Varun Mishra		33	Vice President of Completions
Robert R. Wingo		34	Vice President of Midstream

Set forth below is the description of the background of our directors, executive officers and other key employees. References to positions held at Rice Energy include positions held at Rice Drilling B prior to our corporate reorganization.

Daniel J. Rice IV has served as a member of our board of directors and our Chief Executive Officer since October 2013. Mr. Rice joined Rice Partners in October 2008 and served as the Vice President and Chief Financial Officer of Rice Energy from October 2008 through October 2012. From October 2012 through September 2013, Mr. Rice served as the Chief Operating Officer of Rice Energy. Prior to joining Rice Energy, he served as an investment banker for Tudor Pickering Holt & Co., LLC, an integrated energy investment bank in Houston, Texas, from February 2008 to October 2008. Prior to his employment at Tudor Pickering Holt, he served as a senior analyst of corporate planning for Transocean Inc., responsible for mergers and acquisitions and business development, from March 2005 to February 2008. He was appointed Chief Executive Officer in October 2013. Daniel J. Rice IV holds a BS in Finance from Bryant University. He is the son of Daniel J. Rice III and the brother of Toby Rice and Derek Rice.

The board believes that Mr. Rice’s considerable financial and operational experience brings important and valuable skills to the board of directors.

Toby Z. Rice has served as our President and Chief Operating Officer since October 2013. Mr. Rice joined Rice Partners in February 2007 and later joined Rice Energy as its President and Chief Executive Officer when it was formed in February 2008 through September 2013. He has also served as a Manager of Rice Energy since its formation. From September 2005 until March 2008, he also served as founder and president of ZFT LLC, a consulting company specializing in the application of new hydraulic fracturing technologies for unconventional shale and tight sandstone reservoirs. Toby Rice was appointed to his current role in October 2013. He holds a BS in Chemistry from Rollins College and is the son of Daniel J. Rice III and the brother of Daniel J. Rice IV and Derek Rice.

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The board believes that Mr. Rice’s considerable operational experience brings important and valuable skills to the board of directors.

Derek A. Rice has served as Rice Energy’s Vice President of Exploration & Geology since 2009 and is responsible for geologic and geophysical interpretations. Prior to joining Rice Partners and Rice Energy in August 2009, from June 2007 to September 2007 and from June 2008 until September 2008, he worked as a wellbore geologist for a large oilfield service company, where he analyzed the Marcellus, Haynesville, and Barnett shales. Derek Rice holds a BS in geological sciences from Tufts University and a MS in geology from the University of Houston. He is the son of Daniel J. Rice III and the brother of Daniel J. Rice IV and Toby Rice.

Grayson T. Lisenby has served as our Vice President and Chief Financial Officer since October 2013. Mr. Lisenby joined Rice Energy in February 2013, initially serving as our Vice President of Finance. Prior to joining Rice Energy, Mr. Lisenby was an investment professional at Natural Gas Partners from July 2011 to January 2013 and concentrated on transaction analysis and execution as well as the monitoring of active portfolio companies. Mr. Lisenby was involved in NGP’s original $100 million investment into Rice Energy and spent a significant amount of his time monitoring and advising the company during his tenure at Natural Gas Partners. Prior to his employment at NGP, he served an investment banker for Barclays Capital Inc.’s energy group in Houston from August 2009 to July 2011. Mr. Lisenby holds a BBA in Finance from the University of Texas, where he was a member of the Business Honors Program.

James W. Rogers has served as our Vice President, Chief Accounting & Administrative Officer and Treasurer, since October 2013. Mr. Rogers joined Rice Energy in April 2011 as Controller and subsequently served as our Vice President and Chief Accounting Officer from January 2012 through October 2012 and our Chief Financial Officer from November 2012 through September 2013. Prior to joining Rice Energy, Mr. Rogers served as a Financial Specialist with EQT Corporation, working in the Corporate Accounting Group, from May 2010 to March 2011. Prior to EQT, Mr. Rogers served as an assurance manager for Ernst & Young in their Pittsburgh office from September 2007 to April 2010. He began his career in 2002 as an auditor with PricewaterhouseCoopers LLP, in its Pittsburgh office. Mr. Rogers is a certified public accountant in the state of Pennsylvania and holds a BSBA in accounting from the University of Pittsburgh. He is also a member of the AICPA.

William E. Jordan has served as our Vice President, General Counsel and Corporate Secretary since January 2014. From September 2005 through December 2013, Mr. Jordan practiced corporate law at Vinson & Elkins, L.L.P., representing public and private companies in capital markets offerings and mergers and acquisitions, primarily in the oil and natural gas industry. He is a graduate of Davidson College with a BA in Mathematics and a graduate of the Duke University School of Law with a Doctor of Jurisprudence degree.

Robert F. Vagt will become the chairman of our board of directors in connection with the closing of this offering. Mr. Vagt served as a member of the board of directors of El Paso Corporation from May 2005 until June 2012, where he was a member of the compensation and health, safety and environmental committees. From January 2008 until January 2014, Mr. Vagt was also the President of The Heinz Endowments. Prior to his tenure at The Heinz Endowments, Mr. Vagt served as President of Davidson College from July 1997 to August 2007. Mr. Vagt served as President and Chief Operating Officer of Seagull Energy Corporation from 1996 to 1997. From 1992 to 1996, he served as President, Chairman and Chief Executive Officer of Global Natural Resources. Mr. Vagt served as President and Chief Operating Officer of Adobe Resources Corporation from 1989 to 1992. Prior to 1989, he served in various positions with Adobe Resources Corporation and its predecessor entities. Mr. Vagt previously served as a member of the board of directors of Cornell Companies until 2005.

The board believes that Mr. Vagt’s professional background in both the public and private sectors make him an important advisor and member of our board of directors. Mr. Vagt brings to the board operations and management expertise in both the public and private sectors. In addition, Mr. Vagt provides the board with a welcomed diversity of perspective gained from service as President of The Heinz Endowments, as well as from service as the president of an independent liberal arts college.

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Daniel J. Rice III has served as a member of our board of directors since October 2013. He has also served as Managing General Partner of Rice Partners. Since January 2013, Mr. Rice has served as Lead Portfolio Manager for GRT Capital’s energy division. From 2005 to December 2012, Mr. Rice served as a Managing Director and Portfolio Manager for BlackRock, Inc. and was a member of BlackRock, Inc.’s Global Resources team, responsible for Small Cap and All Cap Energy funds. Prior to joining BlackRock, Inc. in 2005, he was a Senior Vice President and Portfolio Manager at State Street Research & Management, responsible for the Small Cap Energy and All Cap Energy Global Resources Funds. Prior to joining State Street Research in 1984, he was a Vice President and Portfolio Manager with Fred Alger Management. Earlier in his career, Mr. Rice was a Vice President and Analyst with EF Hutton and an Analyst with Loomis Sayles and Co. He began his career in 1975 as an auditor with Price Waterhouse & Co. He earned a BS degree from Bates College in 1973 and an MBA degree from New York University in 1975. Mr. Rice has more than 30 years of experience in the oil and gas industry. He is the father of Toby Rice, Daniel J. Rice IV and Derek Rice.

The board believes that Mr. Rice’s considerable financial and energy investing experience brings important and valuable skills to the board of directors.

Scott A. Gieselman has served as a member of our board of directors since April 2013. Mr. Gieselman has been a managing director of Natural Gas Partners since April 2007. From 1988 to April 2007, Mr. Gieselman worked in various positions in the investment banking energy group of Goldman, Sachs & Co., where he became a partner in 2002. Mr. Gieselman received a BS from the Boston College Carroll School of Management in 1985 and a MBA from the Boston College Carroll Graduate School of Management in 1988.

The board believes that Mr. Gieselman’s considerable financial and energy investment banking experience, as well as his experience on the boards of numerous private energy companies, bring important and valuable skills to the board of directors.

Chris G. Carter has served as a member of our board of directors since October 2013. Mr. Carter is a managing director of Natural Gas Partners. Prior to joining Natural Gas Partners in 2004, Mr. Carter was an analyst with Deutsche Bank’s Energy Investment Banking group in Houston, where he focused on financing and merger and acquisition transactions in the oil and gas and oilfield services industries. Mr. Carter received a B.B.A. and an M.P.A. in Accounting, summa cum laude, in 2002 from the University of Texas, where he was a member of the Business Honors Program. He received an M.B.A. in 2008 from Stanford University, where he graduated as an Arjay Miller Scholar.

The board believes that Mr. Carter’s considerable financial and energy investing experience, as well as his experience on the boards of numerous private energy companies, bring important and valuable skills to the board of directors.

James W. Christmas will become a member of our board of directors in connection with the closing of this offering. Mr. Christmas has served as a member of the board of directors of Halcón Resources Corporation since February 2012. Mr. Christmas began serving as a director of Petrohawk Energy Corporation in July 2006, effective upon the merger of KCS Energy, Inc. (“KCS”) into Petrohawk. He continued to serve as a director, and as Vice Chairman of the Board of Directors, for Petrohawk until BHP Billiton acquired all of Petrohawk in August 2011. He also served on the Audit Committee and the Nominating and Corporate Governance Committee. Currently, Mr. Christmas serves as a member of the Board of Directors of Petrohawk, a wholly-owned subsidiary of BHP Billiton, and as chair of the Financial Reporting Committee of such board. He also serves on the Advisory Board of the Tobin School of Business of St. John’s University and as a Senior Financial Advisor to a private oil and gas company. He served as President and Chief Executive Officer of KCS from 1988 until April 2003 and Chairman of the Board and Chief Executive Officer of KCS until its merger into Petrohawk. Mr. Christmas was a Certified Public Accountant in New York and was with Arthur Andersen & Co. from 1970 until 1978 before leaving to join National Utilities & Industries (“NUI”), a diversified energy company, as Vice President and Controller. He remained with NUI until 1988, when NUI spun out its unregulated activities that ultimately became part of KCS. As an auditor and audit manager, controller and in his role as CEO of KCS, Mr. Christmas was directly or indirectly responsible for financial reporting

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and compliance with SEC regulations, and as such has extensive experience in reviewing and evaluating financial reports, as well as in evaluating executive and board performance and in recruiting directors.

The board believes that Mr. Christmas’s prior experience as an executive and director and his past audit, accounting and financial reporting experience provide significant contributions to our board of directors.

Kevin S. Crutchfield will become a member of our board of directors in connection with the closing of this offering. Mr. Crutchfield has served as the chairman of the board of directors (since May 2012) and chief executive officer (since July 2009) of Alpha Natural Resources, Inc., an international supplier of metallurgical and thermal coal. He has been with Alpha since its formation in 2003, serving as executive vice-president from November 2004 to January 2007, president from January 2007 to July 2009, and as a director since November 2007. Mr. Crutchfield is a 25-year coal industry veteran with technical, operating and executive management experience. He is currently the vice chairman of the National Mining Association and the American Coalition for Clean Coal Electricity. Prior to joining Alpha, Mr. Crutchfield was vice president of El Paso Corporation and president of Coastal Coal Company, an affiliate of El Paso. He previously served as president of AMVEST Corporation and held executive positions at AEI Resources, Inc., including president and chief executive officer. Earlier in his career, he held senior management positions at Pittston Coal Company and Cyprus Australia Coal Company, including a period in Australia as chairman of Cyprus Australia Coal Company. Mr. Crutchfield also serves on the board of directors of Coeur d’Alene Mines Corporation and previously served on the board of directors at King Pharmaceuticals, Inc. from February 2010 until the first quarter of 2011, when he resigned in connection with the acquisition of King Pharmaceuticals by Pfizer.

The board believes that Mr. Crutchfield’s prior experience in corporate leadership, financial and operational management, government and regulatory oversight, health and safety management, and industry expertise through his various executive roles in global natural resource businesses, in addition to experience in public company board leadership provide significant contributions to our board of directors.

Ryan Kanto has served as Rice Energy’s Vice President of Production since June 2011. Prior to Rice Energy, he worked at EnCana Oil & Gas (USA) Inc. from June 2007 to May 2011. During this time he served as a facilities engineer in the Deep Bossier from June 2007 to January 2008, a reservoir engineer in the Barnett Shale until February 2009, and completion engineer in the Haynesville Shale until his departure. Mr. Kanto graduated from the University of Arizona in 2007 with dual BS degrees in Chemical Engineering and Engineering Management.

Michael J. Lauderbaugh has served as our Vice President of Environmental Health and Safety since October 2011. Prior to Rice Energy, he worked at SUNPRO Environmental Services from September 2005 until September 2011. During this time he served as Regional Manager, responsible for oversight of the Marcellus Shale business in Pennsylvania. Prior to SUNPRO, he worked for Petroclean Environmental Services from April 1999 to August 2005. Mr. Lauderbaugh graduated from Texas A&M University in 1997 with a BS in Fire Science and Administration.

John P. LaVelle has served as Rice Energy’s Vice President of Drilling since February 2010 and manages its drilling and operations facets. From February 1994 until February 2010, Mr. LaVelle was president of Geological Engineering Services, Inc., a drilling and completion engineering consulting company specializing in unconventional reservoirs like the Marcellus Shale. He also has two years of practical engineering experience with Western Company of North America, a major oilfield services company and from March 1984 until February 1994 served as petroleum engineer and senior engineer with Snyder Brothers, Inc., an Appalachian-based E&P company. He has almost 30 years of Appalachian Basin experience. Mr. LaVelle received a BS degree in geological engineering from South Dakota School of Mines and Technology in 1980.

Varun Mishra has served as Rice Energy’s Vice President of Completions, overseeing our Marcellus development, since December 2008. Mr. Mishra specializes in shale gas horizontal well stimulation, reservoir characterization and production optimization. He served as a petroleum engineer for EOG Resources, Inc. (“EOG”) from June 2007 to November 2008, where he designed and executed well completions in the Barnett Shale. Prior to his service with EOG, Mr. Mishra served as an offshore production engineer for India’s Oil and

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Natural Gas Corporation Ltd (from November 2002 to July 2005) in their Bombay High Oil Field. Mr. Mishra graduated in 2002 with a BS in petroleum engineering from Indian School of Mines and in 2007 with a MS in petroleum engineering from Texas A&M University.

Robert R. Wingo has served as Rice Energy’s Vice President, Midstream and Marketing, since June 2013. Prior to joining Rice Energy, he served as Director, Corporate Development for Copano Energy, LLC, a Houston based midstream energy company, from January 2010 until May 2013 where he helped lead the company’s pursuit of mergers, acquisitions and greenfield projects. From March 2008 until January 2010 he served as Director, Business Development and Field Services in Copano’s Denver office and was responsible for acquisitions, business development and field services in the Rocky Mountain region. From 2006 to 2008 Mr. Wingo served as Manager, Corporate Development for Copano focusing on mergers and acquisitions. Mr. Wingo began his career in 2002 as a Project Engineer and Operations Manager for Copano and managed all engineering, construction and operations activities for over 1,400 miles of natural gas and NGL pipelines. Mr. Wingo holds a BS in Aerospace Engineering from the University of Texas.

Board of Directors

Our board of directors currently consists of five members, Daniel J. Rice IV, Toby Z. Rice, Daniel J. Rice III, Scott A. Gieselman and Chris G. Carter. In connection with the closing of this offering, we will enter into a stockholders’ agreement with Rice Holdings, Rice Partners, NGP Holdings and Alpha Natural Resources, Inc. Please see “Certain Relationships and Related Party Transactions—Stockholders’ Agreement.” Pursuant to the stockholders’ agreement, we and our principal stockholders will agree to appoint individuals designated by the principal stockholders to our board of directors and nominate such persons for election at each annual meeting of our shareholders. Prior to completion of this offering, Kevin S. Crutchfield will be designated by Alpha Natural Resources, Inc. as a nominee to our board of directors and Mr. Crutchfield will join our board of directors at the time we complete this offering.

At the time we complete this offering, Messers. Vagt and Christmas will join our board as independent directors, each of which will serve on our audit committee. Mr. Vagt will also serve as the chairman of the board of directors. We expect to add another independent director to our board of directors and audit committee within one year after the completion of this offering. We also expect that our board will review the independence of our current directors using the independence standards of the NYSE and, based on this review, determine that Messrs. Gieselman, Carter, Vagt and Christmas are independent within the meaning of the NYSE listing standards currently in effect. As a result, we expect that our board of directors will consist of nine members within one year after the completion of this offering, five of whom will be independent.

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

In connection with the completion of this offering, our directors will be divided into three classes serving staggered three-year terms. Class I, Class II and Class III directors will serve until our annual meetings of stockholders in 2015, 2016 and 2017, respectively. We anticipate that Messrs. Daniel J. Rice IV, Carter and Christmas will be assigned to Class I, Messrs. Toby Z. Rice, Crutchfield and Vagt will be assigned to Class II and Messrs. Daniel J. Rice III and Gieselman will be assigned to Class III. At each annual meeting of stockholders held after the initial classification, directors will be elected to succeed the class of directors whose terms have expired. This classification of our board of directors could have the effect of increasing the length of time necessary to change the composition of a majority of the board of directors. In general, 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.

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Status as a Controlled Company

Because Rice Holdings, Rice Partners NGP Holdings and Alpha Natural Resources, Inc. will collectively beneficially own a majority of our outstanding common stock following the completion of this offering and will be deemed a group as a result of the stockholders’ agreement to be entered into in connection with the closing of this offering, we expect to be a controlled company under NYSE corporate governance standards. A controlled company need not comply with NYSE corporate governance rules that require its board of directors to have a majority of independent directors and independent compensation and nominating and governance committees. Notwithstanding our status as a controlled company, we will remain subject to the NYSE corporate governance standard that requires us to have an audit committee composed entirely of independent directors. As a result, we must have at least one independent director on our audit committee by the date our common stock is listed on the NYSE, at least two independent directors within 90 days of the listing date and at least three independent directors within one year of the listing date.

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

Committees of the Board of Directors

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

Audit Committee

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

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

Compensation Committee

Because we will be a controlled company within the meaning of the NYSE corporate governance standards, we will not be required to have a compensation committee composed entirely of independent directors. However, we expect that we will have a compensation committee following the completion of this offering. This committee will establish salaries, incentives and other forms of compensation for officers and other employees. Our

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compensation committee will also administer our incentive compensation and benefit plans. We expect to adopt a compensation 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. Our compensation committee will initially consist of Messrs. Vagt (Chair), Christmas and Carter, each of whom will be independent under the rules of the NYSE.

Nominating and Corporate Governance Committee

Because we will be a controlled company within the meaning of the NYSE corporate governance standards, we will not be required to have a nominating and governance committee or, in the event we choose to establish one, a committee composed entirely of independent directors. However, we expect that we will have a nominating and governance committee following the completion of this offering. This committee will identify, evaluate and recommend qualified nominees to serve on our board of directors, develop and oversee our internal corporate governance processes and maintain a management succession plan. We expect to adopt a nominating and corporate governance committee charter defining the committee’s primary duties in a manner consistent with the rules of the SEC and applicable stock exchange or market standards. Our nominating and governance committee will initially consist of Messrs. Gieselman (Chair), Daniel J. Rice III and Daniel J. Rice IV.

Health, Safety and Environmental Committee

We expect that we will have a health, safety and environmental committee following the completion of this offering. This committee will assists the board in fulfilling its risk oversight responsibilities relating to health, safety and environmental-related matters, including environmental regulations, health and safety initiatives and accountabilities, and crisis response. Our health, safety and environmental committee will initially consist of Messrs. Toby Z. Rice (Chair), Vagt and Crutchfield.

Compensation Committee Interlocks and Insider Participation

None of our executive officers serve on the board of directors or compensation committee of a company that has an executive officer that serves on our board or compensation committee. No member of our board is an executive officer of a company in which one of our executive officers serves as a member of the board of directors or compensation committee of that company.

Code of Business Conduct and Ethics

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

Corporate Governance Guidelines

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

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EXECUTIVE COMPENSATION

Named Executive Officers

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

Daniel J. Rice IV	Chief Executive Officer / Vice President and Chief Operating Officer (1)
Toby Z. Rice	President and Chief Operating Officer / Chief Executive Officer (2)
Grayson T. Lisenby	Vice President and Chief Financial Officer / Vice President of Finance (3)
James W. Rogers	Vice President and Chief Accounting & Administrative Officer, Treasurer / Vice President and Chief Financial Officer (4)

(1) Mr. Daniel J. Rice IV’s role with our company changed during 2013. In 2013, he served as our Vice President and Chief Operating Officer from January through September and thereafter as our Chief Executive Officer.

(2) Mr. Toby Z. Rice’s role with our company changed during 2013. In 2013, he served as our Chief Executive Officer from January through September and thereafter as our President and Chief Operating Officer.

(3) Mr. Lisenby’s role with our company changed during 2013. Mr. Lisenby joined our company in February 2013, initially serving as our Vice President of Finance through September. Thereafter, Mr. Lisenby served as our Vice President and Chief Financial Officer.

(4) Mr. Rogers’s role with our company changed during 2013. In 2013, he served as our Vice President and Chief Financial Officer from January through September and thereafter as our Vice President and Chief Accounting & Administrative Officer, Treasurer.

Summary Compensation Table

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

Name and Principal Position	Year		Salary ($)		Bonus (1) ($)		Non-Equity Incentive Plan Compensation ($)(2)		All Other Compensation ($)(3)		Total ($)
Daniel J. Rice, IV (CEO/Vice President and COO)		2013	$	110,000	$	65,000	$	—	$	2,200	$	177,200
Toby Z. Rice (President and COO/CEO)		2013	$	110,000	$	65,000	$	—	$	3,850	$	178,850
Grayson T. Lisenby (Vice President and CFO/VP of Finance)		2013	$	140,833	$	145,000	$	—	$	108	$	285,941
James W. Rogers (Vice President and Chief Accounting and Administrative Officer, Treasurer/Vice President and CFO)		2013	$	149,063	$	126,750	$	—	$	—	$	275,813

(1) The amounts in this column represent the aggregate amount of annual discretionary cash bonuses paid to our Named Executive Officers for fiscal year 2013 performance.

(2) As discussed more fully below in the “Long Term Incentive Compensation” section of the narrative accompanying this table, each of the Named Executive Officers currently holds outstanding Incentive Units that are not classified as equity for accounting purposes. However, because the performance conditions related to these awards are not probable, no amounts have been treated as earned in 2013 for purposes of this table.

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(3) Amounts reported in the “All Other Compensation” column reflect company matching contributions to the Named Executive Officers’ 401(k) plan retirement accounts.

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

We have begun the process of reviewing our executive compensation program with the goal of modifying it to be more suitable for a public company. To aid in this process, we have engaged Alvarez & Marsal (“A&M”), a global professional services firm, as our compensation consultant. The process of modifying our executive compensation program is still underway, but we have received recommendations from A&M that we expect will be used to implement new compensation arrangements in connection with this offering. The following discussion describes the elements of our current executive compensation program and identifies any changes that are contemplated to be made in connection with this offering.

Base Salary

Each Named Executive Officer’s base salary is a fixed component of compensation for each year for performing specific job duties and functions. Historically, an informal compensation committee comprised of Messers. D. Rice IV, T. Rice, and D. Rice III (collectively, the “Committee”), has established the annual base salary rate for each of the Named Executive Officers at a level necessary to retain the individual’s services and reviews base salaries on an annual basis at the end of each year, with adjustments implemented at the beginning of the next year. The Committee has historically made adjustments to the base salary rates of the Named Executive Officers upon consideration of any factors that it deems relevant, including but not limited to: (a) any increase or decrease in the executive’s responsibilities, (b) the executive’s job performance, and (c) the level of compensation paid to executives of other companies with which we compete for executive talent, as estimated based on publicly available information and the experience of members of the Committee. Notwithstanding the foregoing, under the Limited Liability Company Agreement of Rice Appalachia, dated January 25, 2012, as amended from time to time (the “REA LLC Agreement”), annual compensation and benefits (except for Incentive Units granted by Rice Appalachia’s Board of Managers under the REA LLC Agreement) for our Named Executive Officers has historically required the approval of Natural Gas Partners, except to extent that such annual salaries do not exceed $150,000 for each of Messrs. T. Rice and D. Rice IV.

In connection with this offering, we anticipate that the Committee will analyze the appropriateness of the base salary for each of our Named Executive Officers in light of the base salaries of other executives in the peer group that we identify with the assistance of A&M, both on a stand-alone basis and as a component of total compensation. We expect that this review will result in the establishment of the following annual base salaries for each of our Named Executive Officers, to be effective upon the closing of the offering: $400,000 for each of Messrs. D. Rice IV and T. Rice and $300,000 for each of Messrs. Lisenby and Rogers.

Annual Cash Bonus

Historically, our annual cash bonus awards for Messers. T. Rice and D. Rice IV have been discretionary awards awarded by the Committee at the end of each fiscal year. The determination of the amount of these discretionary cash bonus awards, if any, has been made based on an overall assessment of our company’s performance in light of overall market conditions, along with these Named Executive Officers’ individual performance, for the fiscal year, and is not based on any one or more specific performance objective or criteria.

The amount of annual bonus for Messrs. Lisenby and Rogers for 2013 was determined under a separate award program that applies to certain of our key employees. This program is administered under the Rice Energy Management Bonus Plan (the “Bonus Plan”), as established in January 2010 and amended from time to time. Under the Bonus Plan, for 2013, a targeted bonus amount expressed as a percentage of annual base salary was established for each of Messrs. Lisenby and Rogers. The determination of the amount of annual bonus payable for 2013 for each of Messrs. Lisenby and Rogers was made in the discretion of the Committee. In making this

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determination, the Committee has historically considered each participating employee’s targeted bonus award amount (expressed as a percentage of the employee’s base salary) and the employee’s individual performance and contributions during the year, including his completion of job-specific duties, but the Committee retains full discretion to pay less than or more than the individual’s targeted bonus award amount. Due to our strong performance in 2013 and the contributions of Messrs. Lisenby and Rogers thereto, these two executives were awarded the full amount of their targeted bonus of $145,000, and $126,750, respectively. We intend to continue to provide annual incentive cash bonuses to reward achievement of financial or operational goals so that total compensation reflects actual company and individual performance. Following the conclusion of our Committee’s review of our compensation policies with data supplied by A&M, our annual bonus program may change. We expect that our new compensation committee may establish performance goals to be used following the offering in determining amounts the cash bonuses that may become payable for future performance periods. However, no decisions have yet been made regarding the bonus program structure that will be in place following our initial public offering, except that we expect targeted bonus amounts to be established for 2014 in the following amounts: $350,000 for each of Messrs. D. Rice IV and T. Rice, $250,000 for Mr. Lisenby and $200,000 for Mr. Rogers.

Long-Term Incentive Compensation

Incentive Units

Historically, the only long-term incentives offered to our Named Executive Officers have been through grants of Incentive Units, which are profits interests representing an interest in the future profits (once a certain level of proceeds has been generated) of our predecessor parent entity Rice Appalachia and granted pursuant to the REA LLC Agreement. These profits interests (the “REA Incentive Units”) represent interests in Rice Appalachia that have no value for tax purposes on the date of grant and are designed to gain value only after the underlying assets have realized a certain level of growth and return to those individuals who hold certain classes of Rice Appalachia’s equity. The REA Incentive Units are intended to provide the holders with the ability to benefit from the growth in our operations and business.

Each of the Named Executive Officers holds outstanding REA Incentive Units granted pursuant to the REA LLC Agreement. The profits interest awards are divided into seven tiered classes as follows: Legacy Tier I Units, Legacy Tier II Units, Legacy Tier III Units, New Tier I Units, New Tier II Units, New Tier III Units, and New Tier IV Units. A potential payout for each tier will occur only after a specified level of cumulative cash distributions has been received by Natural Gas Partners. Legacy Tier I Units are designed to vest in three equal annual installments, with such annual vesting occurring on the anniversaries of the grant date and with pro-rata monthly vesting between these annual anniversary dates. Legacy Tier II Units and Legacy Tier III Units will each vest only upon the payment threshold established for that tier (described below). New Tier I Units and New Tier II Units are designed to vest in five equal annual installments on each anniversary of the grant date of such awards and with pro-rata monthly vesting between these annual anniversary dates. New Tier III Units and New Tier IV Units will each vest only upon the payment threshold established for that tier (described below). In addition to the time-based vesting that applies to the Legacy Tier I Units, New Tier I Units, and New Tier II Units, such awards are also subject to accelerated vesting in full upon the occurrence of a “Fundamental Change” (as defined in the REA LLC Agreement and described below).

The difference between a vested and unvested unit is that once a unit is vested, the executive may retain all vested profits interest awards as non-voting interests, unless such executive’s employment is terminated for “Cause” (as defined below) or voluntarily resigns. All profits interest awards that have not vested according to their original vesting schedule at the time an executive’s employment is terminated for any reason will be forfeited without payment. If we terminate an executive for Cause, or the executive voluntarily terminates his or her employment, all vested profits interest awards will also be forfeited at the time of the termination. If distributions are made with respect to a tier of these profits interest awards, both vested and unvested units (to the extent not previously forfeited) will receive the distributions and the holder of such units would be entitled to keep any such distributions regardless of whether the units were subsequently forfeited.

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Under the REA LLC Agreement, the Legacy Tier I, Legacy Tier II and Legacy Tier III Units are entitled to 10%, 10% and 10%, respectively, of distributions to members only after Natural Gas Partners shall have received cumulative distributions in respect of their membership interests equal to two times, three times and four times, respectively, of the cumulative capital contributions made prior to April 18, 2013. The New Tier I Units and New Tier II Units are entitled to 20% and 5%, respectively, of distributions to members only after Natural Gas Partners shall have received cumulative distributions in respect of their membership interests equal to their cumulative capital contributions made on or after April 18, 2013, multiplied by (1.08)ⁿ and (1.20)ⁿ, respectively, where “n” is equal to a weighted average capital contribution factor determined as of the dates of the distributions. The New Tier III Units and New Tier IV Units will be entitled to 5% and 5%, respectively, of distributions to members only after Natural Gas Partners shall have received cumulative distributions in respect of their membership interests equal to two times and 2.5 times, respectively, their cumulative capital contributions made on or after April 18, 2013.

As used in the paragraphs above, a “capital contribution” to Rice Appalachia generally means, for any member thereof, the dollar amount of any cash and the fair market value of any property contributed to Rice Appalachia.

A termination for “Cause” will generally occur upon the individual’s (i) conviction of, or plea of nolo contendere to, any felony or crime causing substantial harm to us or our affiliates or involving acts of theft, fraud, embezzlement, moral turpitude or similar conduct; (ii) repeated intoxication by alcohol or drugs during the performance of the individual’s duties in a manner that materially and adversely affects the individual’s performance of such duties; (iii) malfeasance in the conduct of the individual’s duties; (iv) violation of any voting or transfer restriction agreement or a confidentiality and noncompete agreement that the individual has executed with us; and (v) failure to perform the duties of the individual’s service relationship with us or our affiliates, or failure to follow or comply with the reasonable and lawful written directives of our board of managers or the board of an affiliate employing or engaging the service of such individual, as applicable.

A “Fundamental Change” is generally deemed to occur when Rice Appalachia enters into any merger or consolidation with another entity, the outstanding interests in the company are sold or exchanged, or Rice Appalachia sells, leases, exchanges, or licenses all or substantially all of its assets, in each case other than with or to a related entity and only if Rice Appalachia’s existing board members do not continue to constitute at least a majority of the members of the board of the surviving or acquiring entity immediately following the transaction. A Fundamental Change is also deemed to occur if any single person or entity (or groups of such related persons or entities) purchases or acquires the right to vote or dispose of the company’s securities in an amount representing 50% or more of the total voting power of all the then outstanding voting securities of Rice Appalachia unless such transaction has been approved by Rice Appalachia’s board of managers (provided that no capital contribution by certain Natural Gas Partners entities shall constitute a Fundamental Change). This offering, and the transactions described under “Corporate Reorganization,” do not constitute a Fundamental Change.

Prior to this offering, no tier of the profits interest awards has received a payout. Since no amount of the outstanding REA Incentive Units held by our Named Executive Officers has been earned (as the performance conditions related to payout are not probable of occurring) and the awards are not accounted for under Financial Accounting Standards Board Accounting Standards Topic 718 (“FASB ASC Topic 718”), the value of these profits interests has not been included in our Summary Compensation Table. In connection with our corporate reorganization, approximately 143,661 shares of our common stock will be issued to certain of the incentive holders in exchange for the portion of their REA Incentive Units related to the incentive burden attributable to Mr. Daniel J. Rice III. As such, we expect that we will recognize a non-cash compensation expense in the first quarter of 2014.

In connection with this offering and the related corporate reorganization described under “Corporate Reorganization,” the Named Executive Officers (and other REA Incentive Unit holders) will contribute their REA Incentive Units (except for those related to the incentive burden attributable to Mr. Daniel J. Rice III) to

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Rice Holdings and NGP Holdings in return for substantially similar incentive units in such entities. As a result, the burden of the incentive units currently attributable to Rice Partners and Natural Gas Partners will be replicated in the limited liability company agreements of Rice Holdings and NGP Holdings, respectively. Following this offering, the limited liability company agreement of NGP Holdings will entitle holders of incentive units to a portion of distributions made by NGP Holdings. Generally, it is anticipated that such distributions will occur in connection with sales of our common stock by NGP Holdings. Accordingly, if the requisite cumulative cash distribution thresholds to Natural Gas Partners have been met, incentive unitholders would be entitled to cash distributions on any applicable class of incentive units at such time. Similarly, the limited liability company agreement of Rice Holdings will entitle holders of incentive units to a portion of distributions made by Rice Holdings. However, incentive unitholders in Rice Holdings are not entitled to receive distributions of distributable funds until the earlier of January 2, 2016, or 30 days following the date on which NGP Holdings has sold in excess of 50% of its Rice Energy Inc. common stock (including pursuant to this offering). On such date and each of the three anniversaries thereafter, Rice Holdings will distribute one-quarter of its distributable funds, including shares of our common stock, to its members. Accordingly, if requisite cumulative distribution thresholds to Rice Partners have been met, incentive unitholders would be entitled to distributions of either cash or our common stock on any applicable class of incentive units at such times. Because we will not be a party to the limited liability company agreements of Rice Holdings or NGP Holdings after the offering, we cannot assure you that the terms of the profits interest units will not change in the future.

Long-Term Incentive Plan

In order to incentivize management members following the completion of this offering, we anticipate that our board of directors will adopt an omnibus long-term incentive plan for employees, consultants, and directors. Once adopted, our Named Executive Officers will be eligible to participate in this plan, which we expect will become effective upon the consummation of this offering. We anticipate that the long-term incentive plan (“LTIP”) will provide for the grant of bonus stock, restricted stock, restricted stock units, options, stock appreciation rights, dividend equivalent rights, performance awards, annual incentive awards and other stock-based awards intended to align the interests of key employees (including the Named Executive Officers) with those of our stockholders. More specifically, we anticipate that in connection with or after the closing of this offering, our board of directors will grant 12,500 and 5,500 restricted stock units to Robert F. Vagt and James W. Christmas, respectively, pursuant to the LTIP described below. We anticipate that such equity awards granted to our outside directors will be subject to a one-year cliff vesting schedule. Following the closing of this offering, our board or the LTIP Committee may also grant restricted stock unit awards to certain of our employees (including the Named Executive Officers) that are key to our operations; however, the board has not yet made final determinations as to the number of awards to be granted, when the awards will be granted, or the schedule on which the awards will become vested. Separate forms of the award agreements - one for employees and one for outside directors - that are expected to be used for these grants of restricted stock units have been filed as exhibits to the registration statement of which this prospectus is a part.

The description of the LTIP set forth below is a summary of the expected material features of the plan. This summary, however, does not purport to be a complete description of all the provisions of the LTIP that we intend to adopt. This summary is qualified in its entirety by reference to the LTIP, a form of which has been filed as an exhibit to the registration statement of which this prospectus is a part. Because the LTIP has not yet been adopted, the description below merely reflects current expectations with respect to the terms and conditions of the LTIP. The terms and conditions described below should be read in that context and remain subject to change unless and until we adopt the LTIP.

The LTIP – Generally

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

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officers and employees of Rice Energy Inc. or our subsidiaries, as well as other individuals who provide services to us or our subsidiaries (including directors) will be eligible to receive awards under the LTIP. The LTIP will expire upon the earliest of (i) its termination by our board of directors, (ii) the date common stock is no longer available under the LTIP for grants of awards, or (iii) the tenth anniversary of the effective date of the LTIP.

Administration of LTIP

The LTIP will initially be administered by our board of directors or a subcommittee thereof (the “LTIP Committee”). Under the terms of the LTIP, the LTIP Committee will have the power to (1) adopt, amend, and rescind administrative and interpretative rules and regulations relating to the LTIP, (2) determine which eligible individuals will be granted awards under the LTIP and the time or times at which such awards will be granted, (3) determine the amount of cash and/or the number of shares of common stock that will be subject to each award under the LTIP, (4) determine the terms and provisions of each award agreement, (5) accelerate the time of vesting or exercisability of any award that has been granted under the LTIP, (6) construe the respective award agreements and the LTIP, (7) make determinations of the fair market value of the common stock pursuant to the LTIP, (8) 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 (9) subject to the terms of the LTIP, terminate, modify, or amend the LTIP, and (10) 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 LTIP Committee deems appropriate.

Shares Available for Awards Under the LTIP

Pursuant to the LTIP, we expect the aggregate maximum number of shares of our common stock that may be issued under the LTIP will not exceed 17,500,000. 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 LTIP Committee. Further, we expect that the following limitations will apply with respect to awards granted under the LTIP to the extent the awards will be subject to the restrictions under section 162(m) of the Internal Revenue Code of 1986, as amended (the “Code”), and granted to a “covered employee” as defined under section 162(m) of the Code:

• The maximum number of shares of our common stock that may be subject to awards denominated in shares of our common stock granted to any one individual during any one calendar year in the term of the LTIP (excluding awards granted in connection with this offering) may not exceed 2,500,000 shares; and

• A maximum amount of $50 million may be granted to any one individual during any calendar year with respect to awards either designated to be paid only in cash or for which the settlement is not based on a number of shares of our common stock (with such value determined on the date of grant).

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

Types of LTIP Awards

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

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

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

Restricted Stock. Pursuant to a grant of restricted stock, shares of our common stock may be issued or delivered to participants, subject to certain restrictions on the disposition thereof and certain obligations to forfeit the shares to us as may be determined in the discretion of the LTIP 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 LTIP 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 LTIP 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 LTIP Committee, the cash equivalent to the value of a share of our common stock. The LTIP Committee may determine to make grants of restricted stock units under the LTIP to participants containing such terms as it determines. The LTIP Committee will determine the period over which restricted stock units granted to participants will vest. Like restricted stock, restricted stock units may vest over time, pursuant to performance criteria, or based on a combination of service and performance.

Dividend Equivalents. The LTIP 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 LTIP Committee, the LTIP 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. The performance measures to which a performance award are subject will be determined by the LTIP Committee and will be based on one or more of the following performance measures: (1) earnings per share; (2) increase in revenues; (3) increase in cash flow; (4) increase in cash flow from operations; (5) increase in cash flow return; (6) return on net assets; (7) return on assets; (8) return on investment; (9) return on capital; (10) return on equity; (11) economic value added; (12) operating margin; (13) contribution margin; (14) net income; (15) net income per share; (16) pretax earnings; (17) pretax earnings before interest, depreciation and amortization; (18) pretax operating earnings after interest expense and before incentives, service fees, and extraordinary or special items; (19) total stockholder return; (20) debt reduction; (21) market share; (22) change in the fair market value of the stock; (23) operating income; (24) amount of oil and natural gas reserves; (25) oil and natural gas reserve additions; (26) cost of finding oil and natural gas reserves; (27) oil and natural gas reserve replacement ratios; (28) oil and natural gas

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production amounts; (29) oil and natural gas production sales amounts; (30) safety targets; (31) regulatory compliance; and (32) 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 LTIP Committee, including, but not limited to, the Standard & Poor’s 500 Stock Index or a group of comparable companies. 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 LTIP Committee. The LTIP Committee may establish a performance pool, which shall be an unfunded pool, for purposes of measuring the achievement of a performance goal or goals based on one or more criteria set forth above during the given performance period (which may be a single calendar year or multiple years). The LTIP 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 bear a strictly mathematical relationship 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 LTIP Committee may determine. They need not be subject to performance criteria or objectives or to forfeiture.

Other Stock-Based Awards. The LTIP 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.

Change in Control

The LTIP will provide that, upon a “change in control” (as defined in the LTIP), the LTIP 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 LTIP Committee will be permitted to fully vest any awards then outstanding (including restricted stock, restricted stock units, and performance awards) or make such other adjustments to awards as it deems appropriate.

Amendment and Termination of the LTIP

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

Other Compensation Elements

We also offer participation in broad-based retirement and health and welfare plans to all of our employees. We currently maintain a retirement plan intended to provide benefits under section 401(k) of the Code whereby employees, including our Named Executive Officers, are allowed to contribute portions of their compensation (which includes all compensation reported on Form W-2 for the year) to a tax-qualified retirement account. See “Additional Narrative Disclosure Regarding Retirement Benefits and Other Potential Payments Upon Termination or a Change in Control—Retirement Benefits” for more information.

Outstanding Equity Awards at 2013 Fiscal Year-End

None of our Named Executive Officers held any outstanding equity awards that were accounted for under FASB ASC Topic 718 as of December 31, 2013.

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

Retirement Benefits

We have not maintained, and do not currently maintain, a defined benefit pension plan or a nonqualified deferred compensation plan providing for retirement benefits. We currently maintain a retirement plan intended to provide benefits under section 401(k) of the Code, under which employees, including our Named Executive Officers, are allowed to contribute portions of their compensation to a tax-qualified retirement account. Under our 401(k) plan, we provide matching contributions equal to 100% of the first 1%, followed by 50% of the next 5%, of employees’ eligible compensation contributed to the plan. Effective February 1, 2014, our matching contributions will increase to 100% of the first 6% of employees’ eligible compensation contributed to the plan.

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

We historically have not maintained any employment, severance or change in control agreements with any of our Named Executive Officers. In addition, none of the Named Executive Officers are entitled to any payments or other benefits in connection with a termination of their employment or a change in control, except that in certain instances, (1) our employees may be entitled to receive, upon a sale of the company or substantially all of our assets, amounts of already earned annual bonus awards under our Bonus Plan to the extent such amounts have not yet been paid at the time such transaction occurs, and (2) a change in control (a “Fundamental Change,” as such term is defined in the REA LLC Agreement and summarized under “—Narrative Description to the Summary Compensation Table for the 2013 Fiscal Year–Long Term Incentive Compensation—Incentive Units” above may result in a cash distribution being made to holders of vested REA Incentive Units, in accordance with the distribution priority specified in the REA LLC Agreement (unvested REA Incentive Units do not become vested upon a change in control).

Although none of our Named Executive Officers currently has an employment agreement with us, we expect that our Named Executive Officers will enter into employment agreements with us in connection with this offering, based on the review performed by A&M. We anticipate that under these new employment agreements, each of our Named Executive Officers will be entitled to certain severance benefits upon a qualifying termination of employment and that the employment agreements will preclude the executives from soliciting employees or competing with us for a period of one year following termination of employment.

The description of the new employment agreements set forth below is a summary of the expected material features of the agreements regarding potential payments upon termination or a change in control. This summary, however, does not purport to be a complete description of all the provisions of the agreements that we intend to enter into with the executives. This summary is qualified in its entirety by reference to the employment agreements, a form of which for our Named Executive Officers has been filed as an exhibit of the registration statement of which this prospectus is a part. Because the employment agreements have not yet been executed, the description below merely reflects current expectations with respect to the terms and conditions of the employment agreements. The terms and conditions described below should be read in that context and remain subject to change unless and until the parties execute employment agreements.

Under the terms of the new employment agreements, we anticipate that each Named Executive Officer will be entitled to receive the following amounts (the “Accrued Rights”) upon a termination by the company for “cause” (as such term is defined below), upon a termination of employment by reason of death, disability, or expiration of the term of the employment agreement, or upon the executive’s termination without “good reason”

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(as such term is defined below): (a) payment of all accrued and unpaid base salary to the date of termination, (b) reimbursement of all incurred but unreimbursed business expenses to which the executive would have been entitled to reimbursement, and (c) benefits to which the executive is entitled under the terms of any applicable benefit plan or program. If the termination is due to death or disability, such Named Executive Officer will also be entitled to accelerated vesting of any outstanding LTIP awards.

Under the terms of the new employment agreements, we also expect that each Named Executive Officer will also be entitled to receive the following amounts upon a termination by the executive for “good reason” (as such term is defined below) or by the company without “cause” (as such term is defined below): (a) the Accrued Rights; (b) any earned but unpaid annual bonus for the prior year; (c) a prorated annual bonus for the year of termination; (d) a severance payment equal to one times (two times in the event of a qualifying termination within the 12-month period following a “change in control” as such term is defined below) the sum of the executive’s base salary on the date of termination and the average annual bonus for the three prior calendar years; and (e) accelerated vesting of any outstanding LTIP awards held by the executive as of the date of termination. We anticipate that Named Executive Officers will also be entitled to continued coverage under our group health plan for any COBRA period (up to 18 months) elected for the executive and the executive’s spouse and eligible dependents, at no greater premium cost than that which applies to our active senior executive employees.

We anticipate that the following terms will be defined under the new employment agreements for the Named Executive Officers, as described below:

• “Cause” means a determination by the board of directors (or its delegates) that the executive (a) has engaged in gross negligence, gross incompetence, or misconduct in the performance of the executive’s duties to us, (b) has failed without proper legal reason to perform the executive’s duties and responsibilities to us, (c) has breached any material provision of the employment agreement or any written agreement or corporate policy or code of conduct established by us, (d) has engaged in conduct that is, or could reasonably expected to be, materially injurious to us, (e) has committed an act of theft, fraud, embezzlement, misappropriation, or breach of a fiduciary duty to us, or (f) has been convicted of, pleaded no contest to, or received adjudicated probation or deferred adjudication in connection with a crime involving fraud, dishonesty, or moral turpitude or any felony (or a crime of similar import in a foreign jurisdiction).

• “Good Reason” means (a) a material diminution in the executive’s base salary (as defined in the employment agreements), other than as a part of one or more decreases that (i) shall not exceed, in the aggregate, more than 10% of the base salary as in effect on the date immediately prior to such decrease, and (ii) are applied similarly to all of our similarly situated executives; (b) a material diminution in the executive’s authority, duties, or responsibilities; or (c) the involuntary relocation of the geographic location of the executive’s principal place of employment by more than 75 miles from the location of the executive’s principal place of employment as of the effective date of the employment agreement.

• “Change in Control” generally means (a) a merger, consolidation, or sale of all or substantially all of our assets if (i) our shareholders do not continue to own at least 50% of the voting power of the resulting entity in substantially the same proportions that they owned our equity securities prior to the transaction or event or (ii) the members of our board immediately prior to the transaction or event do not constitute at least a majority of the board of directors of the resulting entity immediately after the transaction or event; (b) the dissolution or liquidation of the company; (c) when any person, entity, or group acquires or gains ownership or control of more than 50% of the combined voting power of the outstanding securities of the company, or (d) as a result of or in connection with a contested election of directors, the persons who were members of our board immediately before such election cease to constitute a majority of the board.

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Compensation of Directors

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

We are reviewing the non-employee compensation package paid by our peer group and are considering a non-employee director compensation program. We have reviewed with A&M the non-employee director compensation paid by our peers. Based on this review, following the consummation of this offering, except with respect to designees of Rice Holdings and NGP Holdings, we expect to implement (a) an annual cash retainer valued at approximately $250,000 for the chairman of our board, $60,000 for our committee chairmen and $50,000 for all other non-employee directors, and (b) an annual LTIP award valued at approximately $250,000 the chairman of our board and $110,000 for all other non-employee directors. We do not expect to pay any additional fees for attendance at board or committee meetings, but we do expect that each director will be reimbursed for travel and miscellaneous expenses to attend meetings and activities of our board or its committees. In addition, we expect that two of our non-employee directors will receive initial grants of restricted stock units upon the closing of this offering. For additional details regarding these restricted stock units, please read “Executive Compensation—Narrative Description to the Summary Compensation Table for the 2013 Fiscal Year—Long-Term Incentive Compensation—Long-Term Incentive Plan.” We expect that directors who are also our employees and directors who are designees of Rice Holdings and NGP Holdings will not receive any additional compensation for their service on our board of directors.

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PRINCIPAL AND SELLING STOCKHOLDERS

Beneficial Ownership

The following table sets forth information with respect to the beneficial ownership of our common stock as of December 1, 2013 after giving effect to our corporation reorganization and the Marcellus JV Buy-In by:

• each person known to us to beneficially own more than 5% of any class of our outstanding voting securities;

• each of our named executive officers;

• each of our directors and any director nominees;

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

• the selling stockholder (NGP Holdings).

Except as otherwise noted, the person or entities listed below have sole voting and investment power with respect to all shares of our common stock beneficially owned by them, except to the extent this power may be shared with a spouse. All information with respect to beneficial ownership has been furnished by the respective directors, officers or 5% or more stockholders, as the case may be. Unless otherwise noted, the mailing address of each person or entity named in the table is c/o Rice Energy Inc., 171 Hillpointe Drive, Suite 301, Canonsburg, Pennsylvania 15317. Please see “Certain Relationships and Related Party Transactions—Historical Transactions with Rice Drilling B” for a discussion of positions, offices and other material relationships which NGP Holdings has had with us, our predecessors or affiliates.

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

The selling stockholder has granted the underwriters the option to purchase up to 6,000,000 additional shares of common stock and will sell such shares only to the extent such option is exercised. NGP Holdings is deemed under federal securities laws to be an underwriter with respect to the common stock it may sell in connection with this offering.

	Shares Beneficially Owned Prior to the Offering					Shares Being Offered		Shares Beneficially Owned After the Offering (1)
Name and Address of Beneficial Owner	Number		Percentage					Number			Percentage
Selling Stockholder and 5% Stockholders:
Rice Partners (2)		20,000,000		20.4	%		—		20,000,000			15.6	%
Rice Holdings (3)		20,311,125		20.7			—		20,311,125			15.9
NGP Holdings (4)		43,463,549		44.4			10,000,000		33,463,549	(5)		26.1	(5)
Alpha Holdings (5)		10,000,000		10.2			—		10,000,000			7.8
Directors, Director Nominees and Named Executive Officers:
Daniel J. Rice IV		10,043		*			—		10,043			*
Toby Z. Rice		6,111		*			—		6,111			*
Grayson T. Lisenby		14,519		*			—		14,519			*
James W. Rogers		9,847		*			—		9,847			*
Robert F. Vagt		—		—			—		—			—
Daniel J. Rice III (2)		22,374,652		22.8			—		22,374,652			17.5
Scott A. Gieselman		—		—			—		—			—
Chris G. Carter		—		—			—		—			—
James W. Christmas		—		—			—		—			—
Kevin S. Crutchfield		—		—			—		—			—
All Directors, Director Nominees and Executive Officers as a Group (12 Persons) (7)		22,425,214		22.9			—		22,425,214			17.5

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* Less than one percent.

(1) Does not include common shares that may be purchased in the directed share program. Please see “Underwriting—Directed Share Program.”

(2) Rice Partners is the sole member of Rice Holdings. Rice Energy Management LLC is the general partner of Rice Partners. Rice Energy Management LLC is controlled by a board of managers, consisting solely of Daniel J. Rice III. By virtue of his relationship with Rice Partners, Daniel J. Rice III is deemed to have an indirect beneficial interest in the shares of common stock held by Rice Partners. Daniel J. Rice III directly owns 2,374,652 shares of our common stock. Rice Partners has indicated that it may pledge all or a portion of its shares of our common stock as collateral under a credit agreement it may enter into in the future.

(3) Rice Holdings is controlled by a board of managers consisting of Daniel J. Rice IV, Toby Z. Rice and Daniel J. Rice III.

(4) NGP Holdings is indirectly owned by Natural Gas Partners IX, L.P. and an affiliate thereof (“NGP IX”) and NGP Natural Resources X, L.P. and an affiliate thereof (“NGP X”). NGP IX and NGP X may be deemed to share voting and dispositive power over the reported securities, and, as such, may also be deemed to be the beneficial owner of these securities. NGP IX and NGP X disclaim beneficial ownership of the reported securities in excess of such entity’s respective pecuniary interest in the securities. G.F.W. Energy IX, L.P. and GFW IX, L.L.C. may be deemed to beneficially own the securities held by NGP IX by virtue of GFW IX, L.L.C. being the sole general partner of G.F.W. Energy IX, L.P. (which is the general partner of NGP IX). G.F.W. Energy X, L.P. and GFW X, L.L.C. may be deemed to beneficially own the securities held by NGP X by virtue of GFW X, L.L.C. being the sole general partner of G.F.W. Energy X, L.P. (which is the general partner of NGP X). David R. Albin and Kenneth A. Hersh, each an Authorized Member of GFW IX, L.L.C. and GFW X, L.L.C., may also be deemed to share the power to vote, or to direct the vote, and to dispose, or to direct the disposition, of the securities owned by NGP Holdings. Mr. Hersh and Mr. Albin disclaim beneficial ownership of the securities, except to the extent of their respective pecuniary interest therein. Neither Mr. Hersh nor Mr. Albin owns directly any such securities.

(5) Alpha Holdings is a wholly owned indirect subsidiary of Alpha Natural Resources, Inc., and as such, Alpha Natural Resources, Inc. will be deemed to be the beneficial owner of these securities. The mailing address for each of Alpha Holdings and Alpha Natural Resources Inc. is One Alpha Place, P.O. Box 16429, Bristol, Virginia. The number of securities reflected above is based on an assumed initial public offering price equal to the midpoint of the range set forth on the cover of this prospectus. Please see “Prospectus Summary—Recent Developments—Marcellus Joint Venture Buy-In” for a description of the impact of a change in initial offering price on the number of securities owned by Alpha Holdings before and after the offering.

(6) Assumes no exercise of the underwriters’ option to purchase additional shares of our common stock from the selling stockholder. If the underwriters’ option to purchase additional shares of common stock is exercised in full, NGP Holdings will own 27,463,549 shares (or 21.5%) of our common stock following the sale of such shares.

(7) Does not include 12,500, 5,500 and 25,000 restricted stock units (assuming an initial public offering price equal to the midpoint of the range set forth on the cover of this prospectus) that we will grant to each of Messrs. Vagt, Christmas and Jordan at the close of this offering pursuant to the Rice Energy Inc. 2014 Long-Term Incentive Plan. These restricted stock units will vest 100% on the first anniversary of the date of grant, in the case of Messrs. Vagt and Christmas, and on the third anniversary of the date of grant, in the case of Mr. Jordan.

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CORPORATE REORGANIZATION

The following diagrams indicate the current ownership structure of Rice Drilling B, LLC, our predecessor.

Current Ownership Structure

Pursuant to a master reorganization agreement among Rice Energy Inc., Rice Drilling B, Rice Appalachia, Rice Holdings, Rice Partners, NGP Holdings, Mr. Daniel J. Rice III and certain minority investors in Rice Drilling B, prior to or concurrent with the closing of this offering, a reorganization (which we refer to as our “corporate reorganization”) consisting of the following steps will occur:

• Rice Drilling B will transfer its interest in Rice Energy Inc. to Rice Appalachia in return for nominal consideration;

• Rice Partners will contribute a portion of its interests in Rice Appalachia to Rice Holdings, Natural Gas Partners will contribute its interests in Rice Appalachia to NGP Holdings, and the holders of incentive units in Rice Appalachia will contribute their incentive units (except for those related to the incentive unit burden attributable to Mr. Daniel J. Rice III) to Rice Holdings and NGP Holdings in return for substantially similar incentive units in such entities;

• NGP Holdings, Rice Holdings and Mr. Daniel J. Rice III will contribute their respective interests in Rice Appalachia to Rice Energy Inc. in exchange for 43,463,549, 20,311,125 and 2,374,652 shares of common stock of Rice Energy Inc.;

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• Rice Partners will contribute its remaining interest in Rice Appalachia to Rice Energy Inc. in exchange for 20,000,000 shares of common stock of Rice Energy Inc.;

• Certain of the incentive unitholders will contribute their respective remaining interests in Rice Appalachia to Rice Energy Inc. in exchange for 143,661 shares of common stock of Rice Energy Inc.; and

• Rice Drilling B will enter into an agreement and plan of merger with Rice Energy Inc. and a wholly-owned indirect subsidiary of Rice Energy Inc. (“Merger Sub”) pursuant to which:

^¡   Rice Drilling B will merge with Merger Sub with Rice Drilling B surviving;

^¡   The members of Rice Drilling B (other than Rice Appalachia) will receive an aggregate of 1,707,014 shares of common stock of Rice Energy Inc.; and

^¡   The limited liability company agreement of Rice Drilling B will be amended and restated to provide for, among other things, a single class of membership interest, wholly owned by Rice Appalachia.

In addition, in connection with the entry into the master reorganization agreement, we and certain of the holders of our 12.00% senior subordinated convertible debentures have entered into an amendment to the convertible debentures. As a result of such amendment, the convertible debentures, as well as the warrants issued in connection with the offering of the convertible debentures, will be convertible or exerciseable for shares of common stock of Rice Energy Inc. as opposed to units of Rice Drilling B. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operation—Capital Resources and Liquidity—Debt Agreements—Convertible Debentures and Warrants.”

The following diagram indicates our simplified ownership structure after giving effect to our corporate reorganization, the Marcellus JV Buy-In and this offering (assuming an initial public offering price equal to the midpoint of the range set forth on the cover of this prospectus and that the underwriters’ option to purchase additional shares is not exercised and excluding the impact of shares of common stock issuable upon the conversion or exercise of convertible debentures and warrants).

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Ownership Structure After Giving Effect to this Offering

(1) Two members of our board of directors, Scott A. Gieselman and Chris G. Carter, are Managing Directors of Natural Gas Partners, and Kevin S. Crutchfield will be designated by Alpha Natural Resources, Inc. Please see “Management—Board of Directors.”

(2) Following this offering, the convertible debentures and warrants of Rice Drilling B will be convertible or exercisable for 2,083,730 shares of common stock of Rice Energy Inc.

Rice Energy Inc. is a Delaware corporation that was formed for the purpose of making this offering. Our business will continue to be conducted through Rice Drilling B LLC, as a wholly owned subsidiary of Rice Energy Inc. See “Description of Capital Stock” for additional information regarding the terms of our certificate of incorporation and bylaws as will be in effect upon the closing of this offering.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Historical Transactions with Affiliates

Since its inception, Rice Drilling B has issued additional membership interests as consideration for capital contributions received from Rice Appalachia. Capital contributions for the nine months ended September 30, 2013 and the year ended December 31, 2012 were $198.2 million and $162.9 million, respectively. Rice Appalachia made no capital contributions to Rice Drilling B for the year ended December 31, 2011.

The capital contributions made by Rice Appalachia were the result of capital contributions made to Rice Appalachia by the following individuals and entities:

• Daniel J. Rice III: $0.2 million and $14.0 million for the nine months ended September 30, 2013 and the year ended December 31, 2012, respectively;

• Rice Partners: $49.9 million for the year ended December 31, 2012; and

• Natural Gas Partners $198.0 million and $99.0 million for the nine months ended September 30, 2013 and the year ended December 31, 2012, respectively.

In addition, Rice Drilling B has paid legal fees of Natural Gas Partners totaling approximately $30 thousand and $0.4 million for the nine months ended September 30, 2013 and the year ended December 31, 2012, respectively, in connection with these transactions.

NGP received a put right with respect to their equity investment at Rice Drilling B (indirectly, through its investment in Rice Appalachia) which is contingently exercisable upon the occurrence of certain events. The earliest date that this put right could be exercised is January 25, 2017. The fair value of this put right is de minimis given the accretion in fair value of Rice Appalachia and this put right will no longer be applicable following the completion of this offering.

In prior periods, we have reimbursed Rice Partners for expenses incurred on our behalf. General and administrative expenses incurred by Rice Partners and reimbursed by us were $4.8 million and $3.1 million for the years ended December 31, 2012 and 2011, respectively. At December 31, 2012, $2.5 million of general and administrative expenses was due to Rice Partners and is recorded as due to affiliate on the consolidated balance sheet. Prior to the closing of this offering, we intend to terminate our agreement to reimburse Rice Partners for expenses incurred on our behalf.

We are reimbursed for costs incurred on behalf of our Marcellus joint venture. General and administrative expenses incurred by us and reimbursed by our Marcellus joint venture were $1.3 million and $0 for the years ended December 31, 2012 and 2011, respectively. At December 31, 2012, we recorded a receivable from our Marcellus joint venture for $4.6 million representing leaseholds that were approved to be contributed to the joint venture.

In January 2010, Rice Energy Limited Partnership assigned its 100% membership interest in Rice Drilling C LLC (“Rice C”) to Rice Drilling B. At the date of the transfer of membership interest, Rice C’s assets consisted solely of approximately $0.9 million.

In November 2009, we entered into restricted unit agreements with an employee and certain consultants. Under separate and individual restricted unit agreements, the eligible employee and consultants were granted units which vest over a specified period of time. Each unit entitles the holder to an equity ownership in us. The restricted units are accounted for as liability awards, which require re-measurement each reporting period, as a result of the existence of a call option that permits us to repurchase the awards at a fixed amount that could be above or below fair market value of the units. We have estimated fair value of the restricted units using an income approach that estimates our fair value and the associated units which are discounted for a lack of marketability. The income approach requires use of internal business plans that are based on judgments and

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estimates regarding future economic conditions, costs, inflation rates and discount rates, among other factors. During 2011 and the nine months ended September 30, 2013, $0.2 million and $40.1 million, respectively, of restricted unit expense was recognized for these awards. During 2012, Rice Appalachia, as the designee of Rice Drilling B, exercised the option to repurchase certain restricted units from a consultant. In connection with this offering, the balance of the restricted units outstanding will be exchanged for 1,707,014 shares of our common stock.

On October 28, 2009, we entered into a subordinated working capital promissory note payable to Daniel J. Rice III in the amount of $4.0 million. The note accrued interest at a rate of 1.20% and interest only is due at maturity on February 1, 2018. This note was converted to equity in January 2012.

On February 1, 2009, the terms of a $10.0 million subordinated related party promissory note payable to Daniel J. Rice III were modified. For accounting purposes, the cash flows of the promissory note were considered substantially different resulting in extinguishment accounting. There were no financing fees recorded for the promissory note. The fair value of the modified promissory note was compared to the carrying value of the original promissory note with the difference resulting in a capital contribution from the related party of $3.6 million. The fair value was estimated based upon an estimate of market rates at the inception of the promissory note. The discount was amortized over the life of the instruments using an effective interest rate of 4.6%. This note was converted to equity in January 2012.

Marcellus JV Buy-In Transaction Agreement

On December 6, 2013, we entered into an agreement with Alpha Holdings, a wholly owned indirect subsidiary of Alpha Natural Resources, Inc. Pursuant to the Transaction Agreement, Alpha Holdings has agreed to transfer its 50% interest in our Marcellus joint venture to us in exchange for total consideration of $300.0 million, consisting of $100.0 million of cash and our issuance to Alpha Holdings of 10,000,000 shares of our common stock (assuming an initial public offering price equal to the midpoint of the range set forth on the cover of this prospectus). The number of shares of our common stock to be issued to Alpha Holdings will be equal to $200.0 million divided by the price per share at which shares of common stock of Rice Energy are initially offered in this offering. A $1.00 decrease (or increase) in the public offering price would result in our issuance of an additional 526,316 shares (or 476,190 less shares) to Alpha Holdings. Please see “Dilution.” The closing of the transactions pursuant to the Transaction Agreement is subject to the satisfaction of customary closing conditions and the execution of a registration rights agreement and a stockholders’ agreement, as described in “—Registration Rights Agreement” and “—Stockholders Agreement,” respectively. Assuming the satisfaction or waiver of the closing conditions, the closing of the transactions pursuant to the Transaction Agreement is expected to take place concurrently with, and is contingent upon, the consummation of this offering. The Transaction Agreement includes customary representations and warranties, covenants and indemnities from each of the parties thereto.

The Transaction Agreement is filed as an exhibit to the registration statement of which this prospectus forms a part, and the foregoing description of the Transaction Agreement is qualified by reference thereto.

Registration Rights Agreement

In connection with the closing of this offering, we will enter into a registration rights agreement with the Rice Holdings, Rice Partners, Daniel J. Rice III, NGP Holdings and Alpha Holdings, referred to herein as the Initial Holders. Pursuant to the registration rights agreement, we have agreed to register the sale of shares of our common stock under certain circumstances.

Demand Rights. At any time after the closing of this offering, subject to the limitations set forth below, any Initial Holder (or their permitted transferees) has the right to require us by written notice to prepare and file a registration statement registering the offer and sale of a number of their shares of common stock. Generally, we

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are required to provide notice of the request within five business days following the receipt of such demand request to all additional holders of our common stock, who may, in certain circumstances, participate in the registration. In no event shall more than one demand registration occur during any six-month period or within 180 days (with respect to this offering) or 90 days (with respect to any public offering other than this offering) after the effective date of a final prospectus we file. Further, we are not obligated to effect:

• (i) through December 31, 2016, more than a total of three demand registrations or (ii) on or after January 1, 2017, more than a total of one demand registration per calendar year at the request of Rice Holdings;

• more than one demand registration for Daniel J. Rice III;

• (i) through December 31, 2016, more than a total of three demand registrations or (ii) on or after January 1, 2017, more than a total of one demand registration per calendar year at the request of NGP Holdings; or

• more than one demand registration for Alpha Holdings.

We are also not obligated to effect any demand registration in which the anticipated aggregate offering price included in such offering is less than $30 million. Once we are eligible to effect a registration on Form S-3, any such demand registration may be for a shelf registration statement. Any demand for an underwritten offering pursuant to an effective shelf registration statement shall constitute a demand request subject to the limitations set forth above. We will be required to maintain the effectiveness of any such registration statement until the earlier of 180 days (or two years if a “shelf registration” is requested) after the effective date and the consummation of the distribution by the participating holders.

Piggy-back Rights. If, at any time, we propose to register an offering of common stock (subject to certain exceptions) for our own account, then we must give at least five business days’ notice to all holders of registrable securities to allow them to include a specified number of their shares in that registration statement.

Conditions and Limitations; Expenses. These registration rights are subject to certain conditions and limitations, including the right of the underwriters to limit the number of shares to be included in a registration and our right to delay or withdraw a registration statement under certain circumstances. We will generally pay all registration expenses in connection with our obligations under the registration rights agreement, regardless of whether a registration statement is filed or becomes effective.

Stockholders’ Agreement

In connection with the closing of this offering, we will enter into a stockholders’ agreement with Rice Holdings, Rice Partners, NGP Holdings and Alpha Natural Resources, Inc. Pursuant to the stockholders’ agreement, we and our principal stockholders will agree to appoint individuals designated by the principal stockholders to our board of directors and nominate such persons for election at each annual meeting of our shareholders, subject to the following:

• Rice Holdings will have the right to nominate three members of our board of directors, provided that such number of nominees shall be reduced to two and zero if Rice Holdings and its affiliates, which includes Rice Partners and Dan Rice III, collectively own less than 15% and 5%, respectively, of the outstanding shares of our common stock;

• NGP Holdings will have the right to nominate two members of our board of directors, provided that such number of nominees shall be reduced to one and zero if NGP Holdings and its affiliates collectively own less than 15% and 5%, respectively, of the outstanding shares of our common stock;

• Alpha Natural Resources, Inc. will have the right to nominate one member of our board of directors, provided that such number of nominees shall be reduced to zero if Alpha Natural Resources, Inc. and its affiliates collectively own less than 5% of the outstanding shares of our common stock.

If Alpha Natural Resources, Inc. and its affiliates hold less than 5% of the outstanding shares of our common stock immediately upon the closing of this offering, Alpha Natural Resources, Inc. will have the right to

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nominate one member of our board of directors until the earlier to occur of (i) the first anniversary of the closing of this offering and (ii) the date on which Alpha Natural Resources, Inc. and its affiliates have divested more than 75% of their shares of common stock issued thereto in connection with the closing of this offering. In any event, the nominee designated by Alpha Natural Resources, Inc. must be either (i) the Chief Executive Officer of Alpha Natural Resources, Inc. at the time of designation or (ii) a member of senior management (with a title of Senior Vice President or greater) of Alpha Natural Resources, Inc. that is reasonably satisfactory to us.

The stockholders’ agreement will also require the stockholders party thereto to take all necessary actions, including voting their shares of common stock, for the election of the nominees designated by such principal stockholders.

Procedures for Approval of Related Party Transactions

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

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

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

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

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

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

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DESCRIPTION OF CAPITAL STOCK

Upon completion of this offering and our Marcellus JV Buy-In, the authorized capital stock of Rice Energy Inc. will consist of 650,000,000 shares of common stock, $0.01 par value per share, of which 128,000,000 shares will be issued and outstanding (assuming an initial public offering price equal to the midpoint of the range set forth on the cover of this prospectus), and 50,000,000 shares of preferred stock, $0.01 par value per share, of which no shares will be issued and outstanding. The number of outstanding shares of our common stock includes shares to be issued in a concurrent private placement to Alpha Holdings as a portion of the consideration for our Marcellus JV Buy-In, which is dependent upon the price per share at which shares of our common stock are initially offered in this offering. A $1.00 decrease (or increase) in the public offering price would result in an additional 526,316 shares (or 476,190 less shares) outstanding following the completion of this offering.

Following the completion of this offering, there will be approximately 752,039 shares of our common stock issuable upon conversion of our convertible debentures (assuming an initial public offering price equal to the midpoint of the range set forth on the cover of this prospectus). In addition, following the completion of this offering, there will be approximately 1,124,826 shares of our common stock issuable upon exercise of warrants to purchase common stock with an exercise price of approximately $9.28 per share and approximately 206,865 shares of our common stock issuable upon exercise of warrants to purchase common stock with an exercise price of approximately $5.80 per share (in each case, assuming a public offering price equal to the midpoint of the range set forth on the cover of this prospectus). Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity—Debt Agreements—Convertible Debentures and Warrants.”

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

Common Stock

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

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Warrants

On August 15, 2011, we issued warrants to certain of the broker-dealers involved in our private placement of convertible notes. Two separate classes of warrants were issued (normal and bonus), the sole difference being the exercise price per share. Following the completion of this offering the warrants will become exercisable for approximately 1,124,826 shares of our common stock with an exercise price of approximately $9.28 per share and approximately 206,865 shares of our common stock with an exercise price of approximately $5.80 per share (in each case, assuming a public offering price equal to the midpoint of the range set forth on the cover of this prospectus). The warrants may also be exercised on a cashless basis based on the average of the closing prices for the 20 trading days ended immediately preceding the date of such exercise.

Preferred Stock

Our amended and restated certificate of incorporation authorizes our board of directors, subject to any limitations prescribed by law, without further stockholder approval, to establish and to issue from time to time one or more classes or series of preferred stock, par value $0.01 per share, covering up to an aggregate of 50,000,000 shares of preferred stock. Each class or series of preferred stock will cover the number of shares and will have the powers, preferences, rights, qualifications, limitations and restrictions determined by the board of directors, which may include, among others, dividend rights, liquidation preferences, voting rights, conversion rights, preemptive rights and redemption rights. Except as provided by law or in a preferred stock designation, the holders of preferred stock will not be entitled to vote at or receive notice of any meeting of stockholders.

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

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

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

Delaware Law

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

• 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.

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

Amended and Restated Certificate of Incorporation and Amended and Restated Bylaws

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

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

• 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;

• 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 Rice Holdings, Daniel J. Rice III, NGP Holdings and NGP Energy Capital Management, L.L.C. and their respective affiliates (collectively, the “Sponsors”) 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 certificate of incorporation and bylaws may be amended by the affirmative vote of the holders of at least two-thirds of our then outstanding common stock (prior to such time, our certificate of incorporation and bylaws may be amended by the affirmative vote of the holders of a majority of our then outstanding common stock); 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);

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

• provide that we renounce any interest in the business opportunities of the Sponsors or 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 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 the Sponsors and their respective affiliates no longer collectively own more than 50% of the outstanding shares of our common stock, be upon the affirmative vote of at least 662/3% of the shares of common stock generally entitled to vote in the election of directors.

Forum Selection

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

• any derivative action or proceeding brought on our behalf;

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

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

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

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

Limitation of Liability and Indemnification Matters

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

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

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

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

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

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

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

Transfer Agent and Registrar

The transfer agent and registrar for our common stock is American Stock Transfer & Trust Company, LLC.

Listing

We have been approved to list our common stock on the NYSE under the symbol “RICE”, subject to official notice of issuance.

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SHARES ELIGIBLE FOR FUTURE SALE

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

Sales of Restricted Shares

Upon completion of this offering and our Marcellus JV Buy-In, we will have outstanding an aggregate of 128,000,000 shares of common stock (assuming an initial public offering price equal to the midpoint of the range set forth on the cover of this prospectus). Of these shares, all of the 40,000,000 shares of common stock to be sold in this offering or 46,000,000 shares (assuming the underwriters exercise the option to purchase additional shares in full) will be freely tradable without restriction or further registration under the Securities Act, unless the shares are held by any of our “affiliates” as such term is defined in Rule 144 under the Securities Act. All remaining shares of common stock will be deemed “restricted securities” as such term is defined under Rule 144. The restricted securities were, or will be, issued and sold by us in private transactions and are eligible for public sale only if registered under the Securities Act or if they qualify for an exemption from registration under Rule 144 or Rule 701 under the Securities Act, which rules are summarized below.

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

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

• 88,000,000 shares will be eligible for sale upon the expiration of the lock-up agreements beginning 180 days after the date of this prospectus and when permitted under Rule 144 or Rule 701.

In addition, following the completion of this offering, there will be approximately 2,083,730 shares of our common stock issuable upon conversion of our convertible debentures and exercise of our outstanding warrants (assuming a public offering price equal to the midpoint of the range set forth on the cover of this prospectus). Such shares will be eligible for sale not earlier than six months after the date of this prospectus and otherwise when permitted under Rule 144.

Lock-up Agreements

We, the Rice Owners, NGP Holdings, Alpha Holdings, all of our directors and executive officers and certain of our employees have agreed not to sell any common stock or securities convertible into or exchangeable for shares of common stock for a period of 180 days from the date of this prospectus, subject to certain exceptions. See “Underwriting (Conflicts of Interest)” for a description of these lock-up provisions.

Rule 144

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

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A person (or persons whose shares are aggregated) who is deemed to be an affiliate of ours and who has beneficially owned restricted securities within the meaning of Rule 144 for at least nine months would be entitled to sell within any three-month period a number of shares that does not exceed the greater of one percent of the then outstanding shares of our common stock or the average weekly trading volume of our common stock reported through the NYSE during the four calendar weeks preceding the filing of notice of the sale. Such sales are also subject to certain manner of sale provisions, notice requirements and the availability of current public information about us.

Rule 701

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

Stock Issued Under Employee Plans

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

Registration Rights

We expect to enter into a registration rights agreement with Rice Holdings, Rice Partners, Daniel J. Rice III, NGP Holdings and Alpha Holdings which will require us to file and effect the registration of our common stock held thereby (and by certain of their affiliates) in certain circumstances no earlier than the expiration of the lock-up period contained in the underwriting agreement entered into in connection with this offering. Please see “Certain Relationships and Related Party Transactions—Registration Rights Agreement.”

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MATERIAL U.S. FEDERAL INCOME AND

ESTATE TAX CONSIDERATIONS FOR NON-U.S. HOLDERS

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

This summary does not address all aspects of U.S. federal income or estate taxation that may be relevant to non-U.S. holders in light of their personal circumstances. In addition, this summary does not address the Medicare tax on certain investment income, U.S. federal gift tax laws, any state, local or foreign tax laws or any tax treaties. This summary also does not address tax considerations applicable to investors that may be subject to special treatment under the U.S. federal income tax laws, such as (without limitation):

• banks, insurance companies or other financial institutions;

• tax-exempt or governmental organizations;

• dealers in securities or foreign currencies;

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

• persons subject to the alternative minimum tax;

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

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

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

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

• real estate investment trusts or regulated investment companies; and

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

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

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Non-U.S. Holder Defined

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

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

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

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

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

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

Distributions

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

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

Gain on Disposition of Common Stock

A non-U.S. holder generally will not be subject to U.S. federal income tax on any gain realized upon the sale or other disposition of our common stock unless:

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

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

• our common stock constitutes a U.S. real property interest by reason of our status as a United States real property holding corporation (“USRPHC”) for U.S. federal income tax purposes.

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

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

Generally, a corporation is a USRPHC if the fair market value of its U.S. real property interests equals or exceeds 50% of the sum of the fair market value of its worldwide real property interests and its other assets used or held for use in a trade or business. We believe that we currently are, and expect to remain for the foreseeable future, a USRPHC for U.S. federal income tax purposes. However, as long as our common stock is considered to be regularly traded on an established securities market, only a non-U.S. holder that actually or constructively owns or owned at any time during the shorter of the five-year period ending on the date of the disposition or the non-U.S. holder’s holding period for the common stock, more than 5% of our common stock will be taxable on gain recognized on the disposition of our common stock as a result of our status as a USRPHC. If our common stock were not considered to be regularly traded on an established securities market, all non-U.S. holders generally would be subject to U.S. federal income tax on a taxable disposition of our common stock, and a 10% U.S. withholding tax would apply to the gross proceeds from the sale of our common stock by such non-U.S. holders.

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

U.S. Federal Estate Tax

Our common stock beneficially owned or treated as owned by an individual who is not a citizen or resident of the United States (as defined for U.S. federal estate tax purposes) at the time of death generally will be includable in the decedent’s gross estate for U.S. federal estate tax purposes and thus may be subject to U.S. federal estate tax, unless an applicable estate tax treaty provides otherwise.

Backup Withholding and Information Reporting

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

Payments of the proceeds from a sale or other disposition by a non-U.S. holder of our common stock effected by or through a U.S. office of a broker generally will be subject to information reporting and backup withholding (at the applicable rate) unless the non-U.S. holder establishes an exemption by properly certifying its non-U.S. status on an IRS Form W-8BEN or other appropriate version of IRS Form W-8 and certain other

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conditions are met. Information reporting and backup withholding generally will not apply to any payment of the proceeds from a sale or other disposition of our common stock effected outside the United States by a foreign office of a broker. However, unless such broker has documentary evidence in its records that the holder is a non-U.S. holder and certain other conditions are met, or the non-U.S. holder otherwise establishes an exemption, information reporting will apply to a payment of the proceeds of the disposition of our common stock effected outside the United States by such a broker if it has certain relationships within the United States.

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

Additional Withholding Requirements

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

Payments subject to withholding tax under this law generally include dividends paid on common stock of a U.S. corporation after June 30, 2014, and gross proceeds from sales or other dispositions of such common stock after December 31, 2016. Non-U.S. holders are encouraged to consult their tax advisors regarding the possible implications of these withholding rules.

THE FOREGOING DISCUSSION IS FOR GENERAL INFORMATION ONLY AND SHOULD NOT BE VIEWED AS TAX ADVICE. INVESTORS CONSIDERING THE PURCHASE OF OUR COMMON STOCK ARE URGED TO CONSULT THEIR OWN TAX ADVISORS REGARDING THE APPLICATION OF THE U.S. FEDERAL INCOME AND ESTATE TAX LAWS TO THEIR PARTICULAR SITUATIONS AND THE APPLICABILITY AND EFFECT OF U.S. FEDERAL GIFT TAX LAWS AND ANY STATE, LOCAL OR FOREIGN TAX LAWS AND TAX TREATIES.

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UNDERWRITING (CONFLICTS OF INTEREST)

Barclays Capital Inc. is acting as the representative of the underwriters and Barclays Capital Inc., Citigroup Global Markets Inc., Goldman, Sachs & Co., Wells Fargo Securities, LLC, BMO Capital Markets Corp. and RBC Capital Markets, LLC are the joint book-running managers of this offering. Under the terms of an underwriting agreement, which is filed as an exhibit to the registration statement, each of the underwriters named below has severally agreed to purchase from us and the selling stockholder the respective number of shares of common stock shown opposite its name below:

Underwriters	Number of Shares
Barclays Capital Inc.
Citigroup Global Markets Inc.
Goldman, Sachs & Co.
Wells Fargo Securities, LLC
BMO Capital Markets Corp.
RBC Capital Markets, LLC
Comerica Securities, Inc.
SunTrust Robinson Humphrey, Inc.
Tudor, Pickering, Holt & Co. Securities, Inc.
Capital One Securities, Inc.
FBR Capital Markets & Co.
Scotia Capital (USA) Inc.
Johnson Rice & Company L.L.C.
Sterne, Agee & Leach, Inc.
Total		40,000,000

The underwriting agreement provides that the underwriters’ obligation to purchase shares of common stock depends on the satisfaction of the conditions contained in the underwriting agreement including:

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

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

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

• we deliver customary closing documents to the underwriters.

Commissions and Expenses

The following table summarizes the underwriting discounts and commissions we and the selling stockholder will pay to the underwriters. These amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase additional shares. The underwriting fee is the difference between the initial price to the public and the amount the underwriters pay to us and the selling stockholder for the shares.

	No Exercise	Full Exercise
Per share	$	$
Total	$	$

The representative of the underwriters has advised us that the underwriters propose to offer the shares of common stock directly to the public at the public offering price on the cover of this prospectus and to selected dealers, which may include the underwriters, at such offering price less a selling concession not in excess of

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$         per share. After the offering, the representative may change the offering price and other selling terms. Sales of shares made outside of the United States may be made by affiliates of the underwriters. The offering of the shares by the underwriters is subject to receipt and acceptance and subject to the underwriters’ right to reject any order in whole or in part.

The expenses of the offering that are payable by us are estimated to be $4.0 million (excluding underwriting discounts and commissions). We have agreed to pay expenses incurred by the selling stockholder in connection with the offering, other than the underwriting discounts and commissions. We have also agreed to reimburse the underwriters for certain of their expenses in an amount up to $20,000.

Option to Purchase Additional Shares

The selling stockholder has granted the underwriters an option exercisable for 30 days after the date of the underwriting agreement, to purchase, from time to time, in whole or in part, up to an aggregate of 6,000,000 shares at the public offering price less underwriting discounts and commissions. This option may be exercised if the underwriters sell more than 40,000,000 shares in connection with this offering. To the extent that this option is exercised, each underwriter will be obligated, subject to certain conditions, to purchase its pro rata portion of these additional shares based on the underwriter’s underwriting commitment in the offering as indicated in the table at the beginning of this Underwriting Section.

Lock-Up Agreements

We, each of our directors and executive officers, certain of our employees, Rice Holdings, Rice Partners, NGP Holdings and Alpha Holdings have agreed that, subject to certain exceptions, without the prior written consent of Barclays Capital Inc., we and they will not directly or indirectly, (1) offer for sale, sell, pledge, or otherwise dispose of (or enter into any transaction or device that is designed to, or could be expected to, result in the disposition by any person at any time in the future of) any shares of common stock (including, without limitation, shares of common stock that may be deemed to be beneficially owned by us or them in accordance with the rules and regulations of the SEC and shares of common stock that may be issued upon exercise of any options or warrants) or securities convertible into or exercisable or exchangeable for common stock; provided, however, that (i) Rice Partners will be allowed, subject to certain restrictions, to pledge its shares of our common stock as collateral under a credit facility to be entered into in the future and (ii) we will be allowed to issue shares of our common stock upon the conversion or exercise of convertible debentures and warrants described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity—Debt Agreements—Convertible Debentures and Warrants,” (2) enter into any swap or other derivatives transaction that transfers to another, in whole or in part, any of the economic consequences of ownership of the common stock, (3) make any demand for or exercise any right or file or cause to be filed a registration statement, including any amendments thereto, with respect to the registration of any shares of common stock or securities convertible, exercisable or exchangeable into common stock or any of our other securities, or (4) publicly disclose the intention to do any of the foregoing for a period of 180 days after the date of this prospectus.

Barclays Capital Inc., in its sole discretion, may release the common stock and other securities subject to the lock-up agreements described above in whole or in part at any time with or without notice. When determining whether or not to release common stock and other securities from lock-up agreements, Barclays Capital Inc. will consider, among other factors, the holder’s reasons for requesting the release, the number of shares of common stock and other securities for which the release is being requested and market conditions at the time.

As described below under “Directed Share Program,” any participants in the Directed Share Program shall be subject to a 180-day lock up with respect to any shares sold to them pursuant to that program. This lock up will have similar restrictions as the lock-up agreement described above. Any shares sold in the Directed Share Program to our directors or officers shall be subject to the lock-up agreement described above.

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Offering Price Determination

Prior to this offering, there has been no public market for our common stock. The initial public offering price will be negotiated between the representative and us. In determining the initial public offering price of our common stock, the representative will consider:

• the history and prospects for the industry in which we compete;

• our financial information;

• the ability of our management and our business potential and earning prospects;

• the prevailing securities markets at the time of this offering; and

• the recent market prices of, and the demand for, publicly traded shares of generally comparable companies.

Indemnification

We and the selling stockholder have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act and liabilities incurred in connection with the directed share program referred to below, and to contribute to payments that the underwriters may be required to make for these liabilities.

Directed Share Program

At our request, the underwriters have reserved for sale at the initial public offering price up to 2,000,000 shares offered hereby for officers, directors, employees and certain other persons associated with us. The number of shares available for sale to the general public will be reduced to the extent such persons purchase such reserved shares. Any reserved shares not so purchased will be offered by the underwriters to the general public on the same basis as the other shares offered hereby. Any participants in this program shall be prohibited from selling, pledging or assigning any shares sold to them pursuant to this program for a period of 180 days after the date of this prospectus.

Stabilization, Short Positions and Penalty Bids

The representative may engage in stabilizing transactions, short sales and purchases to cover positions created by short sales, and penalty bids or purchases for the purpose of pegging, fixing or maintaining the price of the common stock, in accordance with Regulation M under the Exchange Act:

• Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.

• A short position involves a sale by the underwriters of shares in excess of the number of shares the underwriters are obligated to purchase in the offering, which creates the syndicate short position. This short position may be either a covered short position or a naked short position. In a covered short position, the number of shares involved in the sales made by the underwriters in excess of the number of shares they are obligated to purchase is not greater than the number of shares that they may purchase by exercising their option to purchase additional shares. In a naked short position, the number of shares involved is greater than the number of shares in their option to purchase additional shares. The underwriters may close out any short position by either exercising their option to purchase additional shares and/or purchasing shares in the open market. In determining the source of shares to close out the short position, the underwriters will consider, among other things, the price of shares available for purchase in the open market as compared to the price at which they may purchase shares through their

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option to purchase additional shares. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the shares in the open market after pricing that could adversely affect investors who purchase in the offering.

• Syndicate covering transactions involve purchases of the common stock in the open market after the distribution has been completed in order to cover syndicate short positions.

• Penalty bids permit the representative to reclaim a selling concession from a syndicate member when the common stock originally sold by the syndicate member is purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions.

These stabilizing transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of our common stock or preventing or retarding a decline in the market price of the common stock. As a result, the price of the common stock may be higher than the price that might otherwise exist in the open market. These transactions may be effected on the NYSE or otherwise and, if commenced, may be discontinued at any time.

Neither we nor any of the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of the common stock. In addition, neither we nor any of the underwriters make representation that the representative will engage in these stabilizing transactions or that any transaction, once commenced, will not be discontinued without notice.

Electronic Distribution

A prospectus in electronic format may be made available on the Internet sites or through other online services maintained by one or more of the underwriters and/or selling group members participating in this offering, or by their affiliates. In those cases, prospective investors may view offering terms online and, depending upon the particular underwriter or selling group member, prospective investors may be allowed to place orders online. The underwriters may agree with us to allocate a specific number of shares for sale to online brokerage account holders. Any such allocation for online distributions will be made by the representative on the same basis as other allocations.

Other than the prospectus in electronic format, the information on any underwriter’s or selling group member’s website and any information contained in any other website maintained by an underwriter or selling group member is not part of the prospectus or the registration statement of which this prospectus forms a part, has not been approved and/or endorsed by us or any underwriter or selling group member in its capacity as underwriter or selling group member and should not be relied upon by investors.

New York Stock Exchange

We have been approved to list our common stock for quotation on the NYSE under the symbol “RICE”. The underwriters have undertaken to sell the shares of common stock in this offering to a minimum of 2,000 beneficial owners in round lots of 100 or more units to meet the NYSE distribution requirements for trading.

Discretionary Sales

The underwriters have informed us that they do not intend to confirm sales to discretionary accounts without the prior specific written approval of the customer.

Stamp Taxes

If you purchase shares of common stock offered in this prospectus, you may be required to pay stamp taxes and other charges under the laws and practices of the country of purchase, in addition to the offering price listed on the cover page of this prospectus.

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Relationships

The underwriters and their respective affiliates are full service financial institutions engaged in various activities, which may include sales and trading, commercial and investment banking, advisory, investment management, investment research, principal investment, hedging, market making, brokerage and other financial and non-financial activities and services. The underwriters and their affiliates have in the past, and may in the future, perform investment banking, commercial banking, advisory and other services for us and our respective affiliates from time to time for which they have received, and may in the future receive, customary fees and expenses. In particular, affiliates of Wells Fargo Securities, LLC, Barclays Capital Inc., BMO Capital Markets Corp., Citigroup Global Markets, Inc. Comerica Securities, Inc. RBC Capital Markets, LLC and Goldman, Sachs & Co. are lenders under our revolving credit facility and may receive payments in connection with the repayment of our revolving credit facility. In addition, affiliates of Wells Fargo Securities, LLC and BMO Capital Markets Corp. are lenders under the revolving credit facility of our Marcellus joint venture and may receive payments in connection with the repayment of the revolving credit facility of our Marcellus joint venture. An affiliate of Barclays Capital Inc. is a lender under our second lien term loan credit facility. See “—Conflicts of Interest.” In addition, an affiliate of Barclays Capital Inc. is a limited partner in the general partner of each of Natural Gas Partners IX, L.P. and NGP Natural Resources X, L.P., which are both members of the selling stockholder, NGP Holdings, and such affiliate may receive a portion of the net proceeds to NGP Holdings from this offering.

In addition, in the ordinary course of their various business activities, the underwriters and their respective affiliates may make or hold a broad array of investments and actively trade debt and equity securities (or related derivative securities) and financial instruments (including bank loans) for their own account and for the accounts of their customers. Such investment and securities activities may involve securities and instruments of ours or our affiliates. The underwriters and their affiliates may also make investment recommendations or publish or express independent research views in respect of such securities or financial instruments and may hold, or recommend to clients that they acquire, long or short positions in such securities and instruments.

Conflicts of Interest

An affiliate of Wells Fargo Securities, LLC is a lender under each of our revolving credit facility and our Marcellus joint venture’s revolving credit facility and will receive more than 5% of the net proceeds of this offering in connection with the repayment of borrowings thereunder. Accordingly, this offering is being made in compliance with the requirements of Rule 5121 of the Financial Industry Regulatory Authority, Inc. In accordance with that rule, the appointment of a “qualified independent underwriter” is not required in connection with this offering because the underwriter primarily responsible for managing this public offering does not have a “conflict of interest” under Rule 5121, is not an affiliate of any underwriter that does have a “conflict of interest” under Rule 5121 and meets the requirements of paragraph (f)(12)(E) of Rule 5121. Any underwriter that has a conflict of interest pursuant to Rule 5121 will not confirm sales to accounts in which it exercises discretionary authority without the prior written consent of the customer.

Selling Restrictions

European Economic Area

This document is not a prospectus for the purposes of the Prospectus Directive (as defined below).

In relation to each Member State of the European Economic Area which has implemented the Prospectus Directive (as defined below) (each, a “Relevant Member State”) with effect from and including the date on which the Prospectus Directive is implemented in that Relevant Member State (the “Relevant Implementation Date”), an offer to the public of any shares of our common stock which are the subject of the offering contemplated by this prospectus supplement, may not be made in that Relevant Member State other than:

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

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

(c) in any other circumstances fully within Article 3(2) of the Prospectus Directive,

provided that no such offer of our common stock shall result in a requirement for the publication by us or any underwriter of a prospectus pursuant to Article 3 of the Prospectus Directive.

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

United Kingdom

This prospectus supplement is only being distributed to, and is only directed at, persons in the United Kingdom that are qualified investors within the meaning of Article 2(1)(e) of the Prospectus Directive, which we refer to as Qualified Investors, that are also (i) investment professionals falling within Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005, which we refer to as the Order, or (ii) high net worth entities, falling within Article 49(2)(a) to (d) of the Order, and (iii) any other person to whom it may lawfully be communicated pursuant to the Order, all such persons which we refer to together as relevant persons. This prospectus supplement and its contents are confidential and should not be distributed, published or reproduced (in whole or in part) or disclosed by recipients to any other persons in the United Kingdom. Any investment activity to which this prospectus supplement relates will only be available to, and will only be engaged with, relevant persons. Any person in the United Kingdom that is not a relevant person should not act or rely on this document or any of its contents.

All applicable provisions of the Financial Services and Markets Act 2000 (as amended) must be complied with in respect to anything done by any person in relation to our common stock in, from or otherwise involving the United Kingdom.

Switzerland

This document, as well as any other material relating to the shares which are the subject of the offering contemplated by this prospectus supplement, do not constitute an issue prospectus pursuant to Article 652a and/or 1156 of the Swiss Code of Obligations. The shares will not be listed on the SIX Swiss Exchange and, therefore, the documents relating to the shares, including, but not limited to, this document, do not claim to comply with the disclosure standards of the listing rules of the SIX Swiss Exchange. The shares are being offered in Switzerland by way of a private placement, i.e., to a small number of selected investors only, without any public offer and only to investors who do not purchase the shares with the intention to distribute them to the public. The investors will be individually approached by the issuer from time to time. This document, as well as any other material relating to the shares, is personal and confidential and do not constitute an offer to any other person. This document may only be used by those investors to whom it has been handed out in connection with the offering described herein and may neither directly nor indirectly be distributed or made available to other persons without express consent of the issuer. It may not be used in connection with any other offer and shall in particular not be copied and/or distributed to the public in (or from) Switzerland.

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Hong Kong

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

Singapore

This prospectus supplement has not been registered as a prospectus with the Monetary Authority of Singapore. Accordingly, this prospectus supplement and any other document or material in connection with the offer or sale, or invitation for subscription or purchase, of the shares of our common stock offered hereby may not be circulated or distributed, nor may the shares be offered or sold, or be made the subject of an invitation for subscription or purchase, whether directly or indirectly, to persons in Singapore other than (i) to an institutional investor under Section 274 of the Securities and Future Act, Chapter 289 of Singapore, which we refer to as the SFA, (ii) to a “relevant person” as defined in Section 275(2) of the SFA, or any person pursuant to Section 275 (1A), and in accordance with the conditions, specified in Section 275 of the SFA or (iii) otherwise pursuant to, and in accordance with the conditions of, any other applicable provision of the SFA.

Where the shares of our common stock offered hereby are subscribed and purchased under Section 275 of the SFA by a relevant person which is:

(a) a corporation (which is not an accredited investor (as defined in Section 4A of the SFA)) the sole business of which is to hold investments and the entire share capital of which is owned by one or more individuals, each of whom is an accredited investor; or

(b) a trust (where the trustee is not an accredited investor (as defined in Section 4A of the SFA)) whose sole whole purpose is to hold investments and each beneficiary is an accredited investor, shares, debentures and units of shares and debentures of that corporation or the beneficiaries’ rights and interest (howsoever described) in that trust shall not be transferable within six months after that corporation or that trust has acquired the shares under Section 275 of the SFA except

(i) to an institutional investor under Section 274 of the SFA or to a relevant person (as defined in Section 275(2) of the SFA) and in accordance with the conditions, specified in Section 275 of the SFA;

(ii) (in the case of a corporation) where the transfer arises from an offer referred to in Section 275(1A) of the SFA, or (in the case of a trust) where the transfer arises from an offer that is made on terms that such rights or interests are acquired at a consideration of not less than $200,000 (or its equivalent in a foreign currency) for each transaction, whether such amount is to be paid for in cash or by exchange of securities or other assets;

(iii) where no consideration is or will be given for the transfer; or

(iv) where the transfer is by operation of law.

By accepting this prospectus supplement, the recipient hereof represents and warrants that he is entitled to receive it in accordance with the restrictions set forth above and agrees to be bound by limitations contained herein. Any failure to comply with these limitations may constitute a violation of law.

158

Japan

The securities have not been and will not be registered under the Financial Instruments and Exchange Law of Japan (the Financial Instruments and Exchange Law) and each underwriter has agreed that it will not offer or sell any securities, directly or indirectly, in Japan or to, or for the benefit of, any resident of Japan (which term as used herein means any person resident in Japan, including any corporation or other entity organized under the laws of Japan), or to others for re-offering or resale, directly or indirectly, in Japan or to a resident of Japan, except pursuant to an exemption from the registration requirements of, and otherwise in compliance with, the Financial Instruments and Exchange Law and any other applicable laws, regulations and ministerial guidelines of Japan.

Australia

No prospectus or other disclosure document (as defined in the Corporations Act 2001 (Cth) of Australia (“Corporations Act”)) in relation to the common stock has been or will be lodged with the Australian Securities & Investments Commission (“ASIC”). This document has not been lodged with ASIC and is only directed to certain categories of exempt persons. Accordingly, if you receive this document in Australia:

(a) you confirm and warrant that you are either:

(i) a “sophisticated investor” under section 708(8)(a) or (b) of the Corporations Act;

(ii) a “sophisticated investor” under section 708(8)(c) or (d) of the Corporations Act and that you have provided an accountant’s certificate to us which complies with the requirements of section 708(8)(c)(i) or (ii) of the Corporations Act and related regulations before the offer has been made;

(iii) a person associated with the company under section 708(12) of the Corporations Act; or

(iv) a “professional investor” within the meaning of section 708(11)(a) or (b) of the Corporations Act, and to the extent that you are unable to confirm or warrant that you are an exempt sophisticated investor, associated person or professional investor under the Corporations Act any offer made to you under this document is void and incapable of acceptance; and

(b) you warrant and agree that you will not offer any of the common stock for resale in Australia within 12 months of that common stock being issued unless any such resale offer is exempt from the requirement to issue a disclosure document under section 708 of the Corporations Act.

159

LEGAL MATTERS

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

EXPERTS

The consolidated financial statements of Rice Drilling B LLC as of December 31, 2011 and 2012 and for each of the two years in the period ended December 31, 2012, appearing in this Prospectus and Registration Statement have been audited by Ernst & Young LLP, an independent registered public accounting firm, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

The balance sheet of Rice Energy Inc. as of October 1, 2013, appearing in this Prospectus and Registration Statement has been audited by Ernst & Young LLP, an independent registered public accounting firm, as set forth in their report thereon appearing elsewhere herein, and is included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

The financial statements of Countrywide Energy Services as of and for the periods ended December 31, 2011 and 2012 have been included in reliance upon the report of Grossman Yanak & Ford LLP, independent auditors, appearing elsewhere herein and upon the authority of said firm as experts in accounting and auditing.

The financial statements of Alpha Shale Resources, LP as of December 31, 2012 and for the year ended December 31, 2012, appearing in this Prospectus and Registration Statement have been audited by Ernst & Young LLP, independent auditors, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

The financial statements of Alpha Shale Resources, LP as of December 31, 2011 and for the year ended December 31, 2011, appearing in this Prospectus and Registration Statement have been audited by Schneider Downs & Co., Inc., independent auditors, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

Estimates of our oil and natural gas reserves, related future net cash flows and the present values thereof related to our properties as of December 31, 2011 and 2012 and as of September 30, 2013 included elsewhere in this prospectus were based upon reserve reports prepared by independent petroleum engineers, Netherland, Sewell and Associates, Inc. We have included these estimates in reliance on the authority of such firm as an expert in such matters.

Estimates of oil and natural gas reserves, related future net cash flows and the present values thereof related to the properties of Alpha Shale Resources, LP as of December 31, 2011 and 2012 and as of September 30, 2013 included elsewhere in this prospectus were based upon reserve reports prepared by independent petroleum engineers, Netherland, Sewell and Associates, Inc. and Wright & Company, Inc. We have included these estimates in reliance on the authority of such firm as an expert in such matters.

160

WHERE YOU CAN FIND MORE INFORMATION

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

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

161

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Rice Energy Inc.
Introduction	F-3
Unaudited Pro Forma Condensed Consolidated Balance Sheet as of September 30, 2013	F-5
Unaudited Pro Forma Condensed Consolidated Statement of Operations for the Year Ended December  31, 2012	F-6
Unaudited Pro Forma Condensed Consolidated Statement of Operations for the Nine Months Ended September 30, 2013	F-7
Notes to Unaudited Pro Forma Financial Data	F-8
Rice Drilling B LLC and Subsidiaries
Report of Independent Registered Public Accounting Firm	F-12
Consolidated Balance Sheets as of December 31, 2011 and 2012	F-13
Statements of Consolidated Operations for the Years Ended December 31, 2011 and 2012	F-14
Statements of Consolidated Members’ Capital for the Years Ended December 31, 2011 and 2012	F-15
Statements of Consolidated Cash Flows for the Years Ended December 31, 2011 and 2012	F-16
Notes to Consolidated Financial Statements	F-18
Consolidated Balance Sheets as of December 31, 2012 (Audited) and September 30, 2013 (Unaudited)	F-43
Statements of Consolidated Operations for the Nine Months Ended September  30, 2012 and 2013 (Unaudited)	F-44
Statements of Consolidated Members’ Capital for the Nine Months Ended September  30, 2012 and 2013 (Unaudited)	F-45
Statements of Consolidated Cash Flows for the Nine Months Ended September  30, 2012 and 2013 (Unaudited)	F-46
Notes to Consolidated Financial Statements (Unaudited)	F-47
Rice Energy Inc.
Report of Independent Registered Public Accounting Public Firm	F-60
Balance Sheet as of October 1, 2013	F-61
Notes to Balance Sheet	F-62
Countrywide Energy Services, LLC
Independent Auditors’ Report	F-63
Balance Sheets as of December 31, 2011 and 2012	F-64
Statements of Operations for the Period from May 9, 2011 to December  31, 2011 and for the Year Ended December 31, 2012	F-65
Statements of Members’ Capital for the Period from May 9, 2011 to December  31, 2011 and for the Year Ended December 31, 2012	F-66
Statements of Cash Flows for the Period from May 9, 2011 to December  31, 2011 and for the Year Ended December 31, 2012	F-67
Notes to Financial Statements	F-68
Alpha Shale Resources, LP
Report of Independent Auditors	F-71
Balance Sheets as of December 31, 2011 and 2012	F-72
Statements of Operations for the Years Ended December 31, 2011 and 2012	F-73
Statements of Changes in Partners’ Capital for the Years Ended December 31, 2011 and 2012	F-74
Statements of Cash Flows for the Years Ended December 31, 2011 and 2012	F-75
Notes to Financial Statements	F-76
Independent Auditors’ Report	F-85
Balance Sheet as of December 31, 2011	F-86
Statement of Operations for the Year Ended December 31, 2011	F-87
Statement of Changes in Partners’ Capital for the Year Ended December 31, 2011	F-88
Statement of Cash Flows for the Year Ended December 31, 2011	F-89
Notes to Financial Statements	F-90

F-1

Balance Sheets as of December 31, 2012 (Audited) and September 30, 2013 (Unaudited)	F-95
Statements of Operations for the Nine Months Ended September 30, 2012 and 2013 (Unaudited)	F-96
Statements of Changes in Partners’ Capital for the Nine Months Ended September 30, 2012 and 2013 (Unaudited)	F-97
Statements of Cash Flows for the Nine Months Ended September 30, 2012 and 2013 (Unaudited)	F-98
Notes to Financial Statements (Unaudited)	F-99

F-2

RICE ENERGY INC.

PRO FORMA CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Introduction

The following unaudited pro forma condensed consolidated financial statements of Rice Energy Inc. as of September 30, 2013, for the year ended December 31, 2012, and for the nine months ended September 30, 2013, are derived from the historical financial statements of Rice Drilling B LLC and Alpha Shale Resources, LP, set forth elsewhere in this prospectus and are qualified in their entirety by reference to such historical financial statements and related notes contained therein. These unaudited pro forma condensed consolidated financial statements have been prepared to reflect our pending acquisition of a 50% interest in our Marcellus joint venture, our corporate reorganization and our initial public offering, each of which is described below.

Marcellus JV Buy-In

On December 6, 2013, Rice Energy Inc. entered into a transaction agreement among Rice Energy Inc., Rice Drilling C, LLC and Foundation PA Coal Company, LLC (“Alpha Holdings”), a wholly owned indirect subsidiary of Alpha Natural Resources, Inc., pursuant to which Rice Energy Inc. will acquire (the “Marcellus JV Buy-In”) Alpha Holdings’ 50% equity interest in our Marcellus joint venture in exchange for aggregate consideration of approximately $300 million, consisting of common stock of Rice Energy Inc. and $100 million in cash. For additional information regarding the Marcellus JV Buy-In, please read “Summary—Recent Developments—Marcellus JV Buy-In.”

Reorganization and Offering

Pursuant to the terms of a corporate reorganization that will be completed immediately prior to the closing of this offering (the “Reorganization”), Rice Drilling B LLC will merge with a wholly owned indirect subsidiary of Rice Energy Inc., with Rice Drilling B LLC surviving the merger, and all limited liability company interests in Rice Drilling B LLC will be exchanged for common stock of Rice Energy Inc. For more information regarding the Reorganization, please read “Corporate Reorganization.”

For the purposes of the unaudited pro forma condensed financial statements, the initial public offering (the “Offering”) is assumed to consist of the issuance and sale to the public by us of shares of common stock for $600 million and our application of the net proceeds described in “Use of Proceeds” in this prospectus.

The unaudited pro forma condensed consolidated balance sheet and the unaudited pro forma condensed consolidated statement of operations were derived by adjusting the historical audited and unaudited financial statements of our predecessor. The adjustments are based upon currently available information and certain estimates and assumptions. Actual effects of the transactions may differ from the pro forma adjustments. Management believes, however, that the assumptions provide a reasonable basis for presenting the significant effects of the transactions as contemplated and that the pro forma adjustments are factually supportable and give appropriate effect to those assumptions and are properly applied in the unaudited pro forma financial data.

The pro forma adjustments have been prepared as if the Marcellus JV Buy-In, the Reorganization and the Offering had each taken place on September 30, 2013, in the case of the unaudited pro forma condensed consolidated balance sheet, and as if the Marcellus JV Buy-In, the Reorganization and the Offering had each taken place as of January 1, 2012, in the case of the unaudited pro forma condensed consolidated statements of operations for the year ended December 31, 2012 and for the nine months ended September 30, 2013. The unaudited pro forma condensed consolidated financial statements have been prepared on the assumption that Rice Energy Inc. will be treated as a corporation for federal income tax purposes. The unaudited pro forma condensed consolidated financial statements should be read in conjunction with the notes accompanying such

F-3

RICE ENERGY INC.

PRO FORMA CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

unaudited pro forma financial statements and with the historical audited and unaudited financial statements of Rice Drilling B LLC and Alpha Shale Resources, LP and related notes, as well as “Use of Proceeds” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” each included elsewhere in this prospectus.

The unaudited pro forma condensed consolidated financial statements give pro forma effect to the following adjustments, among others:

• the acquisition of a 50% interest in our Marcellus joint venture from our joint venture partner in return for 10,000,000 shares of common stock of Rice Energy, Inc. and $100 million in cash;

• the repayment of all outstanding borrowings under the revolving credit facility of our Marcellus joint venture;

• the contribution by Rice Holdings, NGP Holdings and Daniel J. Rice III of their respective interests, and by Rice Partners of its remaining interest, in Rice Appalachia to Rice Energy Inc. in exchange for an aggregate of 86,149,326 shares of common stock of Rice Energy Inc.;

• the contribution by certain of the incentive unitholders of their respective remaining interests in Rice Appalachia to Rice Energy Inc. in exchange for 143,661 shares of common stock of Rice Energy Inc.;

• the issuance of 1,707,014 shares of common stock of Rice Energy Inc. to certain existing members of Rice Drilling B in exchange for their outstanding membership interests in Rice Drilling B; and

• the issuance by the Rice Energy Inc. of 30,000,000 shares of common stock in the offering and the use of the net proceeds therefrom as described in “Use of Proceeds.”

Please see “Use of Proceeds” to see how certain aspects of the offering would be affected by an initial public offering price per share of common stock at higher or lower prices than indicated on the front cover of this prospectus.

The unaudited pro forma condensed consolidated statement of operations excludes certain transaction costs, such as costs associated with this offering that are not capitalized as part of this offering. The unaudited pro forma condensed consolidated financial data are presented for illustrative purposes only and do not purport to indicate the financial condition or results of operations of future periods or the financial condition or results of operations that actually would have been realized had the transactions described above been consummated on the dates or for the periods presented.

The unaudited pro forma condensed consolidated financial statements constitute forward-looking information and are subject to certain risks and uncertainties that could cause actual results to differ materially from those anticipated. See “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements.”

F-4

RICE ENERGY INC.

PRO FORMA CONDENSED

CONSOLIDATED BALANCE SHEET AS OF SEPTEMBER 30, 2013

(Unaudited)

(in thousands)	Historical Rice Drilling B		Consolidation of Marcellus JV Pro Forma Adjustments(a)			Reorganization and Offering Pro Forma Adjustments			Pro Forma Rice Energy Inc.
Assets
Current assets:							600,000	(c)
Cash	$	27,661	$	(96,168	)(b)	$	(34,000	)(d)	$	425,493
							(72,000	)(e)
Restricted cash		8,268		—			—			8,268
Accounts receivable		20,954		3,581			—			24,535
Receivable from affiliate		4,982		252			—			5,234
Prepaid expenses and other		592		87			—			679
Derivative asset		7,507		9,619			—			17,126
Total current assets		69,964		(82,629	)		494,000			481,335
Investment in joint ventures		49,819		(49,730	)(b)		—			89
Proved natural gas properties, net		217,809		335,000	(b)		—			552,809
Unproved natural gas properties		391,772		—			—			391,772
Property and equipment, net		4,121		85			—			4,206
Deferred financing costs, net		9,928		828			—			10,756
Other non-current assets		7,984		333,162	(b)		—			341,146
Total assets	$	751,397	$	536,716		$	494,000		$	1,782,113
Liabilities and members’ /stockholders’ capital
Current liabilities:
Current portion of long-term debt	$	19,510	$	—		$	—		$	19,510
Accounts payable		24,577		6,401			—			30,978
Royalties payable		7,876		4,696			—			12,572
Accrued interest		325		—			—			325
Accrued capital expenditures		18,745		3,381			—			22,126
Other accrued liabilities		6,813		973			—			7,786
Leasehold payables		6,354		69			—			6,423
Payable to affiliate		6,740		307			—			7,047
Operated prepayment liability		5,324		—			—			5,324
Total current liabilities		96,264		15,827			—			112,091
Long-term liabilities:
Long-term debt		292,804		72,000			(72,000	)(e)		292,804
Leasehold payables		762		69			—			831
Deferred tax liability				69,897	(b)		110,441	(f)		180,338
Other long-term liabilities		46,230		653			—			46,883
Total liabilities		436,060		158,446			38,441			632,947
Members’ / stockholders’ capital		315,337		378,270			455,559	(c)(d)(f)		1,149,166
Total liabilities and members’ / stockholders’ capital	$	751,397	$	536,716		$	494,000		$	1,782,113

See accompanying Notes to Pro Forma Financial Data (Unaudited).

F-5

RICE ENERGY INC.

PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS

YEAR ENDED DECEMBER 31, 2012

(Unaudited)

(in thousands, except per share data)	Historical Rice Drilling B			Consolidation of Marcellus JV Pro Forma Adjustments(a)			Reorganization and Offering Pro Forma Adjustments			Pro Forma Rice Energy Inc.
Revenues:
Natural gas sales	$	26,743		$	26,284		$	—		$	53,027
Other revenue		457			—			—			457
Total revenues		27,200			26,284			—			53,484
Operating expenses:
Lease operating		3,821			3,331			—			7,152
Gathering, compression and transportation		3,621			6,671			—			10,292
Production taxes and impact fees		1,382			869			—			2,251
Exploration		3,275			—			—			3,275
General and administrative		7,599			2,058			—			9,657
Depreciation, depletion and amortization		14,149			14,193	(b)		—			28,342
Amortization of deferred financing costs		7,220			15			—			7,235
Write-down of abandoned leases		2,253			—			—			2,253
Total expenses		43,320			27,137			—			70,457
Operating loss		(16,120	)		(853	)		—			(16,973	)
Interest expense		(3,487	)		(372	)		—			(3,859	)
Other income		112			—			—			112
Loss on derivatives		(1,381	)		(74	)		—			(1,455	)
Equity in income of joint ventures		1,532			(1,741	)		—			(209	)
Loss before income taxes		(19,344	)		(3,040	)		—			(22,384	)
Income tax benefit		—			—			9,288	(c)		9,288
Net income (loss)	$	(19,344	)	$	(3,040	)	$	9,288		$	(13,096	)
Earnings per share—basic										$	(0.10	)
Earnings per share—diluted(e)										$	(0.10	)

See accompanying Notes to Pro Forma Financial Data (Unaudited).

F-6

RICE ENERGY INC.

PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS

NINE MONTHS ENDED SEPTEMBER 30, 2013

(Unaudited)

(in thousands, except per share data)	Historical Rice Drilling B			Consolidation of Marcellus JV Pro Forma Adjustments(a)			Reorganization and Offering Pro Forma Adjustments			Pro Forma Rice Energy Inc.
Revenues:
Natural gas sales	$	60,219		$	62,938		$	—		$	123,157
Other revenue		519			—			—			519
Total revenues		60,738			62,938			—			123,676
Operating expenses:
Lease operating		5,794			6,098			—			11,892
Gathering, compression and transportation		6,951			11,044			—			17,995
Production taxes and impact fees		1,029			662			—			1,691
Exploration		1,784			—			—			1,784
Restricted unit expense		40,087			—			—			40,087
General and administrative		9,952			2,000			—			11,952
Depreciation, depletion and amortization		23,215			29,621	(b)		—			52,836
Amortization of deferred financing costs		4,760			107			—			4,867
Total expenses		93,572			49,532			—			143,104
Operating income (loss)		(32,834	)		13,406			—			(19,428	)
Interest expense		(13,033	)		(477	)		850	(d)		(12,660	)
Other expense		(347	)		(902	)		—			(1,249	)
Gain on derivatives		16,698			13,928			—			30,626
Income (loss) on extinguishment of debt		(10,622	)		—			—			(10,622	)
Equity in income of joint ventures		19,297			(19,300	)		—			(3	)
Income (loss) before income taxes		(20,841	)		6,655			850			(13,336	)
Income tax benefit		—			—			5,534	(c)		5,534
Net income (loss)	$	(20,841	)	$	6,655		$	6,384		$	(7,802	)
Earnings per share—basic										$	(0.06	)
Earnings per share—diluted(e)										$	(0.06	)

See accompanying Notes to Pro Forma Financial Data (Unaudited).

F-7

RICE ENERGY INC.

NOTES TO PRO FORMA FINANCIAL DATA

(Unaudited)

1. Basis of Presentation, Transactions and this Offering

The historical financial information is derived from the historical financial statements of our predecessor. The pro forma adjustments have been prepared as if the Marcellus JV Buy-In, the Reorganization and the Offering described in this prospectus had each taken place on September 30, 2013, in the case of the unaudited pro forma condensed consolidated balance sheet, and as of January 1, 2012, in the case of the unaudited pro forma condensed combined statement of operations for the year ended December 31, 2012, and as of January 1, 2013, in the case of the unaudited financial statements for the nine months ended September 30, 2013. The adjustments are based on currently available information and certain estimates and assumptions and therefore the actual effects of these transactions will differ from the pro forma adjustments.

2. Unaudited Pro Forma Condensed Consolidated Balance Sheet Adjustments and Assumptions

The adjustments are based on currently available information and certain estimates and assumptions and therefore the actual effects of these transactions will differ from the pro forma adjustments. A description of these transactions and adjustments is provided as follows:

(a) Reflects the consolidation of Alpha Shale Resources, L.P. and elimination of the investment in joint ventures associated therewith as a result of the Marcellus JV Buy-In.

(b) Reflects the impact of applying purchase accounting to the acquisition of Alpha Shale Resources, L.P. The assigned fair values are subject to final purchase accounting valuation adjustments under GAAP and may change. Reflects the impact of the transfer by Alpha Holdings of its 50% interest in Alpha Shale Resources, L.P. in exchange for $100.0 million of cash and the issuance of 10,000,000 shares of common stock (assuming an initial public offering price equal to the midpoint of the range set forth on the cover of this prospectus) to Alpha Holdings. The number of shares of common stock to be issued to Alpha Holdings will equal $200.0 million divided by the price per share at which shares of common stock are initially offered to the public in the Offering.

(c) Reflects the receipt of $600 million of gross proceeds from the Offering from the issuance and sale of shares of common stock at the initial public offering price of $20.00 per share (assuming an initial public offering price equal to the midpoint of the range set forth on the cover of this prospectus).

(d) Reflects the payment of estimated underwriting discounts totaling $30 million and additional estimated expenses related to the Offering of approximately $4 million.

(e) Reflects the use of a portion of the net proceeds of the Offering to repay $72 million of borrowings outstanding under the revolving credit facility of Alpha Shale Resources, L.P. For further discussion on the application of the net proceeds from the Offering, please read “Use of Proceeds.”

(f) Reflects the estimated change in long-term deferred tax liabilities for temporary differences between the historical cost basis and tax basis of the Company’s assets and liabilities as the result of its change in tax status to a subchapter C corporation. A corresponding charge to earnings has not been reflected in the unaudited pro forma combined statements of operations as the charge is considered non-recurring.

F-8

RICE ENERGY INC.

NOTES TO PRO FORMA FINANCIAL DATA – (Continued)

(Unaudited)

3. Unaudited Pro Forma Condensed Consolidated Statements of Operations Adjustments and Assumptions

The adjustments are based on currently available information and certain estimates and assumptions and therefore the actual effects of these transactions will differ from the pro forma adjustments. A description of these transactions and adjustments is provided as follows:

(a) Reflects the consolidation of Alpha Shale Resources, L.P. and elimination of the investment in joint ventures associated therewith as a result of the Marcellus JV Buy-In.

(b) Reflects the impact of applying purchase accounting to the acquisition of Alpha Shale Resources, L.P. The assigned fair values are subject to final purchase accounting valuation adjustments under GAAP and may change.

(c) Reflects estimated incremental income tax provision assuming the earnings of Rice Drilling B, LLC and Alpha Shale Resources, L.P. had been subject to federal income tax as a subchapter C Corporation using an effective tax rate of approximately 41%. This rate is inclusive of federal, state and local income taxes.

(d) Reflects the elimination of interest expense related to the revolving credit facilities of Rice Drilling B, LLC and Alpha Shale Resources, L.P., which will be repaid in full in connection with the Offering, partially offset by an increase in unused commitment fees related to the revolving credit facility of Rice Drilling B, LLC.

(e) Reflects basic and diluted income per common share giving effect to (i) the conversion of restricted units in Rice Drilling B, LLC into shares of common stock in Rice Energy Inc. in connection with the corporate reorganization, (ii) the issuance of 10,000,000 shares of common stock (assuming an initial public offering price equal to the midpoint of the range set forth on the cover of this prospectus) to Alpha Holdings as partial consideration of the Marcellus JV Buy-In and (iii) the issuance of 30,000,000 shares of common stock in the Offering. The number of shares of common stock to be issued to Alpha Holdings will equal $200.0 million divided by the price per share at which shares of common stock are initially offered to the public in the Offering.

4. Supplemental Information on Gas-Producing Activities

The historical pro forma supplemental natural gas disclosure is derived from the combined financial statements of Rice Drilling B and our Marcellus Joint Venture included elsewhere in this prospectus and valuations prepared by the independent petroleum engineering firm of Netherland, Sewell and Associates, Inc. for us and our Marcellus joint venture. For information regarding our independent petroleum engineers and the basis and assumptions for our reserve estimates, please see Note 5 to the consolidated financial statements of Rice Drilling B and Note 3 to the financial statements for Alpha Shale Resources, LP as of and for the year ended December 31, 2012. The unaudited pro forma combined supplemental natural gas disclosures of the Company reflect the combined historical results of Rice Drilling B and Alpha Shale Resources, LP, on a pro forma basis to give effect to the transactions, described above, as if they had occurred on December 31, 2012 for pro forma supplemental natural gas disclosure purposes.

In accordance with SEC regulations, reserves at December 31, 2012 were estimated using the unweighted arithmetic average first-day-of-the-month price for the preceding 12-month period. Reserve estimates are inherently imprecise and estimates of new discoveries are more imprecise than those of producing natural gas properties. Accordingly, the estimates may change as future information becomes available.

F-9

RICE ENERGY INC.

NOTES TO PRO FORMA FINANCIAL DATA – (Continued)

(Unaudited)

4. Supplemental Information on Gas-Producing Activities – (Continued)

Pro forma reserve quantity information for the year ended December 31, 2012 is as follows (in millions of cubic feet, MMcf):

	Historical Rice Drilling B			Consolidation of Marcellus JV Pro Forma Adjustments			Pro Forma Rice Energy Inc.
Proved developed and undeveloped reserves:
Beginning of year		232,996			116,206			349,202
Revisions of previous estimates		(96,911	)		(47,616	)		(144,527	)
Extensions and discoveries		176,956			196,238			373,194
Production		(8,769	)		(8,592	)		(17,361	)
End of year		304,272			256,236			560,508
Proved developed reserves:
Beginning of year		25,397			28,948			54,345
End of year		61,225			70,026			131,251
Proved undeveloped reserves:
Beginning of year		207,599			87,258			294,857
End of year		243,047			186,210			429,257

Extensions, Discoveries and Other Additions

On a pro forma basis, the Company added 560,838 MMcf through its drilling program in the Marcellus Shale in 2012.

Revision of Previous Estimates

In 2012, on a pro forma basis, the Company had net negative revisions of 192,110 MMcf, due primarily to declines in natural gas pricing.

Information with respect to our pro forma estimated discounted future net cash flows related to proved natural gas reserves as of December 31, 2012 is as follows (in thousands):

	Historical Rice Drilling  B			Consolidation of Marcellus JV Pro Forma Adjustments			Reorganization and Offering Pro Forma Adjustments			Pro Forma Rice Energy Inc.
Future cash inflows	$	869,882		$	728,314		$	—		$	1,598,196
Future production costs		(323,855	)		(254,172	)		—			(578,027	)
Future development costs		(262,084	)		(172,426	)		—			(434,510	)
Future income tax expenses		—						(287,443	)		(287,443	)
Future net cash flows		283,943			301,716			(287,443	)		298,216
10% discount for estimated timing of cash flows		(181,725	)		(159,562	)		153,506			(187,781	)
Standardized measure of discounted future net cash flows	$	102,218		$	142,154		$	(133,937	)	$	110,435

For information on our assumptions regarding pricing, please see Note 5 to the consolidated financial statements of Rice Drilling B and Note 3 to the financial statements for Alpha Shale Resources, LP as of and for the year ended December 31, 2012.

F-10

RICE ENERGY INC.

NOTES TO PRO FORMA FINANCIAL DATA – (Continued)

(Unaudited)

4. Supplemental Information on Gas-Producing Activities – (Continued)

The following are the principal sources of changes in our pro forma standardized measure of discounted future net cash flows for 2012 (in thousands):

	Historical Rice Drilling  B			Consolidation  of Marcellus JV Pro Forma Adjustments			Reorganization and Offering Pro Forma Adjustments			Pro Forma Rice Energy Inc.
Balance at beginning of period	$	269,320		$	141,174		$	(218,333	)	$	192,161
Net change in prices and production costs		(83,873	)		(53,710	)		—			(137,583	)
Net change in future development costs		(31,811	)		(524	)		—			(32,335	)
Natural gas net revenues		(18,376	)		(15,414	)		—			(33,790	)
Extensions		38,937			76,262			—			115,199
Revisions of previous quantity estimates		(108,209	)		(57,846	)		—			(166,055	)
Previously estimated development costs incurred		17,036			25,724			—			42,760
Changes in taxes		—			—			84,396			84,396
Accretion of discount		26,932			14,118			—			41,050
Changes in timing and other		(7,738	)		12,370			—			4,632
Balance at end of period	$	102,218		$	142,154		$	(133,937	)	$	110,435

Gains on sales of interests in gas properties are not included in the information set forth above. We have also allocated certain general and administrative expenses to our results of operations as these expenses relate to production activities.

F-11

Report of Independent Registered Public Accounting Firm

The Members of

Rice Drilling B LLC and Subsidiaries

We have audited the accompanying consolidated balance sheets of Rice Drilling B LLC and Subsidiaries (the Company) as of December 31, 2011 and 2012, and the related consolidated statements of operations, members’ capital, and cash flows for each of the two years in the period ended December 31, 2012. 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, and 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 consolidated financial position of Rice Drilling B LLC and Subsidiaries at December 31, 2011 and 2012, and the consolidated results of their operations and their cash flows for each of the two years in the period ended December 31, 2012, in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP

Pittsburgh, Pennsylvania

April 10, 2013 (except for Note 5 and Note 12, as to which the date is October 3, 2013)

F-12

RICE DRILLING B LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

	December 31,
(in thousands)	2011		2012
Assets
Current assets:
Cash	$	4,389	$	8,547
Accounts receivable		4,729		8,557
Receivable from affiliate		76		11,879
Prepaid expenses and other		111		321
Total current assets		9,305		29,304
Investments in joint ventures		19,486		30,976
Gas collateral account		207		5,843
Proved natural gas properties, net		84,112		159,988
Unproved natural gas properties		65,886		111,030
Property and equipment, net		648		2,622
Deferred financing costs, net		10,596		5,208
Total assets	$	190,240	$	344,971
Liabilities and members’ capital
Current liabilities:
Current portion of long-term debt	$	6,697	$	8,814
Accounts payable		10,851		19,793
Royalties payable		1,185		1,960
Accrued interest		1,049		2,004
Accrued capital expenditures		5,936		2,359
Other accrued liabilities		818		5,585
Leasehold payables		5,054		3,954
Derivative liabilities		—		2,260
Payable to affiliate		2,058		2,482
Operated prepayment liability		—		11,553
Total current liabilities		33,648		60,764
Long-term liabilities:
Long-term debt		101,098		140,506
Leasehold payables		483		106
Asset retirement obligations		835		1,381
Other long-term liabilities		7,355		4,023
Total liabilities		143,419		206,780
Members’ capital		46,821		138,191
Total liabilities and members’ capital	$	190,240	$	344,971

See accompanying Notes to Consolidated Financial Statements.

F-13

RICE DRILLING B LLC AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED OPERATIONS

	Year Ended December 31,
(in thousands)	2011			2012
Revenues:
Natural gas sales	$	13,972		$	26,743
Other revenue		—			457
Total revenues		13,972			27,200
Operating expenses:
Lease operating		1,630			3,821
Gathering, compression and transportation		527			3,621
Production taxes and impact fees		—			1,382
Exploration		660			3,275
Restricted unit expense		170			—
General and administrative		5,208			7,599
Depreciation, depletion and amortization		5,981			14,149
Amortization of deferred financing costs		2,675			7,220
Write-down of abandoned leases		109			2,253
Gain from sale of interest in gas properties		(1,478	)		—
Total operating expenses		15,482			43,320
Operating loss		(1,510	)		(16,120	)
Other income (expense):
Interest expense		(531	)		(3,487	)
Other income		161			112
Gain (loss) on derivative instruments		574			(1,381	)
Equity in income of joint ventures		370			1,532
Total other income (expense)		574			(3,224	)
Net loss	$	(936	)	$	(19,344	)

See accompanying Notes to Consolidated Financial Statements.

F-14

RICE DRILLING B LLC AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED MEMBERS’ CAPITAL

(in thousands)	Preferred Units			Warrants		Accumulated Deficit			Total
Balance as of December 31, 2010	$	45,615		$	—	$	(9,052	)	$	36,563
Capital contributions		7,900			—		—			7,900
Issuance of warrants		—			3,294		—			3,294
Net loss		—			—		(936	)		(936	)
Balance as of December 31, 2011		53,515			3,294		(9,988	)		46,821
Capital contributions		100,182			—		—			100,182
Return of capital		(800	)		—		—			(800	)
Conversion of related-party notes payable		11,332			—		—			11,332
Net loss		—			—		(19,344	)		(19,344	)
Balance as of December 31, 2012	$	164,229		$	3,294	$	(29,332	)	$	138,191

See accompanying Notes to Consolidated Financial Statements.

F-15

RICE DRILLING B LLC AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED CASH FLOWS

	Year Ended December 31
(in thousands)	2011			2012
Cash flows from operating activities:
Net loss	$	(936	)	$	(19,344	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		5,981			14,149
Amortization of deferred financing costs		2,675			7,220
Gain from sale of interest in gas properties		(1,478	)		—
Restricted unit expense		170			—
Equity in income of joint ventures		(370	)		(1,532	)
Write-down of abandoned leases and other leasehold costs		109			2,253
(Increase) decrease in:
Accounts receivable		(4,310	)		(3,828	)
Receivable from affiliate		(76	)		(8,403	)
Gas collateral account		(207	)		(4,137	)
Prepaid expenses and other		73			(212	)
Increase (decrease) in:
Accounts payable		(125	)		(30	)
Royalties payable		1,117			775
Other accrued expenses		746			7,391
Derivative liability		—			2,260
Payable to affiliate		1,762			424
Net cash provided by (used in) operating activities		5,131			(3,014	)
Cash flows from investing activities:
Capital expenditures for natural gas properties		(69,077	)		(109,149	)
Investment in joint ventures		(15,205	)		(9,957	)
Capital expenditures for property and equipment		(673	)		(867	)
Proceeds from sale of interest in gas properties		5,710			—
Net cash used in investing activities		(79,245	)		(119,973	)
Cash flows from financing activities:
Proceeds from borrowings		82,972			44,361
Repayments of debt obligations		(7,726	)		(10,152	)
Debt issuance costs		(9,699	)		(1,913	)
Capital contributions		7,900			96,782
Repurchase of profit interest		—			(1,133	)
Return of capital		—			(800	)
Net cash provided by financing activities		73,447			127,145
Net (decrease) increase in cash		(667	)		4,158
Cash at the beginning of the year		5,056			4,389
Cash at the end of the year	$	4,389		$	8,547

See accompanying Notes to Consolidated Financial Statements.

F-16

RICE DRILLING B LLC AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED CASH FLOWS – (Continued)

	Year Ended December 31,
(in thousands)	2011		2012
Supplemental disclosure of noncash investing and financing activities
Capital expenditures for natural gas properties financed by accounts payable	$	10,529	$	18,083
Capital expenditures for natural gas properties financed by other accrued liabilities		5,936		2,359
Natural gas properties financed through borrowings		1,016		18,328
Gas collateral financed by accounts payable		—		1,500
Property and equipment financed through borrowings		—		1,270
Natural gas properties financed through deferred payment obligations		5,314		3,577
Natural gas properties financed through other liabilities		—		8,261
Recognition of legal liability for asset retirement obligations		493		382
Warrants issued in exchange for services		3,294		—
Conversion of related-party note payable to equity		—		11,332

See accompanying Notes to Consolidated Financial Statements.

F-17

RICE DRILLING B LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies and Related Matters

Organization, Operations and Principles of Consolidation

The consolidated financial statements of the Company include the accounts of Rice Drilling B LLC (the Company or Rice Drilling) and its wholly owned subsidiaries, Rice Drilling C LLC (Rice C), Rice Drilling D LLC (Rice D), RDB Real Estate Holdings LLC (RDB Real Estate) and Blue Tiger Oilfield Services LLC (Blue Tiger). All significant intercompany accounts have been eliminated in consolidation.

The Company was organized as a Delaware limited liability company on February 12, 2008. Prior to the Company’s amended and restated LLC agreement dated November 13, 2009, Rice Partners was the Company’s sole member. Effective November 13, 2009, separate classes of member units were authorized (see Note 11).

On January 25, 2012, Rice Partners, the sole owner of the Company’s preferred units and owner of 90% of the total units outstanding in the Company, assigned its preferred units in the Company to its wholly owned subsidiary, Rice Energy Appalachia LLC (REA). Concurrent with Rice Energy’s assignment of its units to REA, REA and Natural Gas Partners (NGP), a private equity firm, finalized a $100.0 million equity commitment from NGP of which $75 million of NGP’s commitment was funded at closing on January 25, 2012. Cash proceeds from the investments were utilized by Rice Drilling, and there were no restrictions to maintain the funds at REA. NGP received a put right with respect to their equity investment at REA which is contingently exercisable upon the occurrence of certain events. The earliest date that this put right could be exercised is January 25, 2017. The fair value of this put right is de minimis given the accretion in fair value of REA. In conjunction with the equity investment in NGP, Daniel J. Rice III converted his outstanding promissory notes into equity of REA. On August 30, 2012, NGP funded the remaining $25 million of its commitment at REA.

The Company is engaged in the acquisition, exploration, and development of natural gas and properties in the Appalachian Basin.

Effective January 22, 2010, Rice Partners assigned its 100% membership interest in Rice Drilling C LLC (Rice C) to the Company. Rice C was formed to hold an investment in a joint venture described in Note 2. At the date of the transfer of membership interest, Rice C had only cash of $0.9 million.

RDB Real Estate was organized as a Pennsylvania limited liability company on May 27, 2010. RDB Real Estate was formed to own, operate, and otherwise deal in or with various parcels of real estate and other investments in real estate.

Rice D was formed as a Delaware limited liability company on December 14, 2011 to hold exploration and potential investments in the Ohio Utica Shale formation.

Blue Tiger was formed as a Delaware limited liability company on February 17, 2012 to purchase, maintain, and provide rental services of oilfield services equipment to the Company and its affiliates.

The Company has experienced operating losses since its inception, and the Company’s current liabilities exceed its current assets at December 31, 2012. Given the continued depression in natural gas prices, start-up nature of the entity and capital intensive business model, operating cash flows are not adequate to support the Company’s drilling plans. Capital availability is significant to the Company’s ability to continue to execute on its drilling plan and sustain operations. The Company regularly evaluates potential sources of capital and its development plan is dependent upon the ability to raise additional capital.

F-18

RICE DRILLING B LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

1. Summary of Significant Accounting Policies and Related Matters – (Continued)

Use of Estimates

The preparation of consolidated financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates and changes in these estimates are recorded when known.

Revenue Recognition

Sales of natural gas are recognized when natural gas has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured, and the sales price is fixed or determinable. Natural gas is sold by the Company under contract with the Company’s natural gas marketer and only customer as of December 31, 2012. Pricing provisions are tied to the Platts Gas Daily market prices.

Cash

The Company maintains cash at financial institutions which may at times exceed federally insured amounts and which may at times significantly exceed consolidated balance sheet amounts due to outstanding checks. The Company has no other accounts that are considered cash equivalents.

Accounts Receivable

Accounts receivable are primarily from the Company’s sole gas marketer. The Company extends credit to parties in the normal course of business based upon management’s assessment of their creditworthiness. 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. There was no allowance recorded for any of the periods presented in the consolidated financial statements.

Investments in Joint Ventures

The Company accounts for its Alpha Shale Resources, LP (“Marcellus joint venture”) and oilfield service company joint venture investments under the equity method of accounting as the Company has significant influence, but not control, over the joint ventures.

Under the equity method of accounting, investments are carried at cost, adjusted for the Company’s proportionate share of the undistributed earnings or losses and reduced for any distributions from the investment. The Company also evaluates its equity method investments for potential impairment whenever events or changes in circumstances indicate that there is an other-than-temporary decline in value of the investment. Such events may include sustained operating losses by the investee or long-term negative changes in the investee’s industry. These indicators were not present, and as a result, the Company did not recognize any impairment charges related to its equity method investments for any of the periods presented in the consolidated financial statements.

F-19

RICE DRILLING B LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

1. Summary of Significant Accounting Policies and Related Matters – (Continued)

Gas Properties

The Company uses the successful efforts method of accounting for gas-producing activities. Costs to acquire mineral interests in gas properties, to drill and equip exploratory wells that result in proved reserves, are capitalized. Costs to drill exploratory wells that do not identify proved reserves as well as geological and geophysical costs and costs of carrying and retaining unproved properties are expensed.

Unproved gas properties that are individually significant are periodically assessed for impairment of value, and a loss is recognized at the time of impairment by providing an impairment allowance. Capitalized costs of producing gas properties and support equipment directly related to such properties, after considering estimated residual salvage values, are depreciated and depleted by the units of production method. Support equipment and other property and equipment not directly related to gas properties are depreciated over their estimated useful lives.

Management’s estimates of proved reserves are based on quantities of natural gas that engineering and geological analysis demonstrates, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic conditions. External engineers prepare the annual reserve and economic evaluation of all properties on a well-by-well basis. Additionally, the Company adjusts natural gas reserves for major well rework or abandonment during the year as needed. The process of estimating and evaluating natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering, and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, revisions in existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates represent the Company’s most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates over time. Because estimates of reserves significantly affect the Company’s depreciation, depletion, and amortization expense, a change in the Company’s estimated reserves could have a material effect on the Company’s net income or loss.

On the sale of an entire interest in an unproved property for cash, a gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained unless the proceeds received are in excess of the cost basis which would result in gain on sale.

Gas Collateral

The Company had deposits of $0.2 million and $5.8 million at December 31, 2011 and 2012, respectively. The deposits are required by the Company’s natural gas marketer.

F-20

RICE DRILLING B LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

1. Summary of Significant Accounting Policies and Related Matters – (Continued)

Interest

The Company capitalizes 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. The following table summarizes the components of the Company’s interest incurred for the periods indicated (in thousands):

	2011		2012
Interest incurred:
Interest capitalized	$	5,405	$	7,695
Interest expensed		531		3,487
Total incurred	$	5,936	$	11,182

Property and Equipment

Property and equipment are recorded at cost and are being depreciated over estimated useful lives of three to forty years on a straight-line basis. Accumulated depreciation was $0.1 million and $0.6 million at December 31, 2011 and 2012, respectively. Depreciation expense was $0.1 million and $0.6 million for the years ended December 31, 2011 and 2012, respectively, and is included in depreciation, depletion, and amortization expense in the accompanying statements of consolidated operations.

Long- Lived Assets

Long-lived assets to be held and used or disposed of other than by sale are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. When required, impairment losses on assets to be held and used or disposed other than by sale are recognized based on the fair value of the asset. Long-lived assets to be disposed of by sale are reported at the lower of their carrying amount or fair value less selling costs.

Deferred Financing Costs

Deferred financing costs are amortized on a straight-line basis, which approximates the interest method, over the term of the related agreement. Accumulated amortization was $2.7 million and $9.9 million at December 31, 2011 and 2012, respectively. Amortization expense was $2.7 million and $7.2 million for the years ended December 31, 2011 and 2012, respectively. The annual amortization of deferred financing costs for years subsequent to December 31, 2012, is expected to be approximately $4.8 million in 2013 and $0.4 million in 2014.

Operated Prepayment Liability

The Company receives cash advances of costs from joint interest owners. Cash advances received from joint interest owners were $0 and $4.5 million at December 31, 2011 and 2012, respectively.

F-21

RICE DRILLING B LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

1. Summary of Significant Accounting Policies and Related Matters – (Continued)

Delay Rental Agreements

The Company has leased drilling rights under agreements which specify additional payments for the privilege of deferring drilling operations for another year. Costs incurred to extend such agreements were $3.1 million for the year ended December 31, 2012.

Asset Retirement Obligations

The Company records the fair value of a legal liability for an asset retirement obligation in the period in which it is incurred. For gas properties, this is the period in which a gas well is acquired or drilled. The Company’s retirement obligations relate to the abandonment of gas-producing facilities and include costs to reclaim drilling sites and dismantle and relocate or dispose of gathering systems, wells, and related structures. Estimates are based on historical experience in plugging and abandoning wells and estimated remaining lives of those wells based on reserve estimates.

When a new liability is recorded, the Company capitalizes the costs of the liability by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value each period and the capitalized cost is depreciated over the units of production basis.

Equity Incentives

The cost of employee and consultant services received in exchange for an award of equity instruments, such as restricted units, is measured based on the fair value of those instruments. Management established an estimated fair value for issued units based upon an income approach for all periods presented. The restricted units are subject to a call option held by the Company which requires liability accounting for the restricted units. Details related to the restricted units are included in Notes 10 and 11.

Income Taxes

The Company is treated as a partnership for federal and state income tax purposes. Consequently, the Company is not subject to income taxes; instead its members include the income in their tax returns.

Reclassifications

Certain reclassifications have been made to the accompanying financial statements for the year ended December 31, 2011, to conform to the current year’s presentation.

Correction of Errors

The Company’s net income for the year ended December 31, 2012 included expense of approximately $1.7 million that related to prior periods. These corrections resulted in additional exploration expense of approximately $1.1 million, lease operating expense of $0.5 million, and other expense of $0.1 million recorded in 2012. These errors were not material to prior periods, individually or in the aggregate, and were not material to the current period. These errors did not impact debt covenant compliance nor distort operating results. Therefore, these items were corrected in fiscal 2012.

F-22

RICE DRILLING B LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

2. Investments in Joint Ventures

On February 3, 2010, Rice C acquired a 50% ownership in Alpha Shale Holdings LLC, a joint venture between Rice C and a subsidiary of Alpha Natural Resources, Inc., which owns 0.1% of and serves as the general partner of Alpha Shale Resources, LP (“Marcellus joint venture”).

On February 3, 2010, Rice C also acquired a 49.95% ownership interest in Alpha Shale Resources, LP, which was formed to develop and commercialize certain Marcellus Shale gas assets and to engage in all phases of the oil and gas business in Greene County. Condensed audited financial information for the Company’s Marcellus joint venture as of December 31, 2011 and 2012 and for the years then ended is as follows (in thousands):

	2011			2012
Cash	$	6,111		$	4,445
Accounts receivable		649			5,716
Prepaid expenses and other assets		189			791
Natural gas properties		48,222			114,219
Total assets	$	55,171		$	125,171
Accounts payable	$	8,366		$	18,953
Accrued expenses		9,222			15,717
Notes payable		—			29,200
Asset retirement obligations		307			542
Partners’ capital		37,276			60,759
Total liabilities and partners’ capital	$	55,171		$	125,171
Revenue:
Natural gas sales	$	5,744		$	26,284
Operating expenses:
Lease operating		704			3,331
Gathering, compression and transportation		53			6,671
Production taxes and impact fees		—			869
General and administrative expenses		359			2,058
Depreciation, depletion and amortization		2,184			9,411
Amortization of deferred financing costs		—			15
Loss on impairment of oil and natural gas properties		2,592			—
Total expenses		5,892			22,355
Operating income (loss)		(148	)		3,929
Other expense:
Interest expense		—			(372	)
Loss on derivatives		—			(74	)
Total other expenses		—			(446	)
Net income (loss)	$	(148	)	$	3,483
Rice C’s interest in net income (loss)	$	(74	)	$	1,741

F-23

RICE DRILLING B LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

2. Investments in Joint Ventures – (Continued)

On May 9, 2011, the Company acquired a 50% ownership in an oilfield services company which provides water transfer and roustabout services to oil and gas companies, including Rice Drilling, in Pennsylvania, West Virginia, and Ohio. This joint venture is accounted for under the equity method of accounting as the Company has significant influence, but not control, over the entity. Financial information for this entity is not presented as the results are not significant to the Company’s operations during the periods presented.

3. Capitalized Costs Relating to Gas-Producing Activities

Proved and unproved capitalized costs related to the Company’s gas-producing activities are as follows (in thousands):

	2011		2012
Capitalized costs:
Unproved properties	$	65,886	$	111,030
Proved, producing properties		53,123		119,374
Proved, nonproducing properties		38,285		61,434
Total		157,294		291,838
Accumulated depreciation and depletion amortization		7,296		20,820
Net capitalized costs	$	149,998	$	271,018
Entity’s share of equity method investees’ net capitalized costs	$	24,111	$	57,110

4. Sale of Interests in Gas Properties

In March 2011, Rice Drilling entered into a joint operating agreement with US Energy Development Corporation (US Energy) covering those certain properties whereby Rice Drilling sold a 50% non-operated working interest in the properties to US Energy. Subsequent to this transaction, Rice Drilling owns a 50% working interest in approximately 1,000 acres in the Whipkey field and has retained operatorship. Rice Drilling received cash consideration of $1.7 million and recorded a gain of $1.5 million on this transaction in the accompanying consolidated statements of operations.

In April 2011, Rice Drilling sold 75% of its interest in oil and gas leases comprising approximately 6,800 leasehold acres in Lycoming County, Pennsylvania to Inflection Energy LLC (Inflection). Inflection has agreed to pay for 100% of Rice’s future costs incurred related to exploration, well development and leasehold acquisitions until $10.0 million has been spent on Rice Drilling’s behalf. Rice Drilling and Inflection have executed a joint operating agreement, which among other things, designates Inflection as the joint venture operator and defines an area of mutual interest, which includes Rice Drilling’s Lycoming properties. Rice Drilling received cash consideration of $4.0 million at closing, and no gain or loss resulted as the cash proceeds received did not exceed Rice Drilling’s book basis of the assets sold.

F-24

RICE DRILLING B LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

5. Supplemental Information on Gas-Producing Activities (Unaudited)

Costs incurred for property acquisitions, exploration and development for the years ended December 31, 2011, and 2012 are as follows for Rice Drilling B (in thousands):

	For the years ended December 31,
	2011		2012
Acquisitions:
Unproved leaseholds	$	16,877	$	47,396
Development costs		72,776		89,307
Exploration costs:
Geological and geophysical		660		3,275
Total costs incurred	$	90,313	$	139,978

The following table presents the results of operations related to natural gas and oil production for Rice Drilling B (in thousands):

	For the years ended December 31,
	2011		2012
Revenues	$	13,972	$	26,743
Production costs		2,157		8,824
Exploration costs		660		3,275
Depreciation, depletion and accretion		5,920		13,329
Write-down of abandoned leases		109		2,253
General and administrative expenses		2,212		3,050
Results of operations from producing activities	$	2,914	$	(3,988	)

Reserve quantity information for the years ended December 31, 2011 and 2012 is as follows for Rice Drilling B:

	Natural Gas (Millions of Cubic Feet, MMcf)
	2011			2012
Proved developed and undeveloped reserves:
Beginning of year		12,230			232,996
Extensions and discoveries		223,538			176,956
Revision of previous estimates		620			(96,911	)
Production		(3,392	)		(8,769	)
End of year		232,996			304,272
Proved developed reserves:
End of year		25,397			61,225
Proved undeveloped reserves:
End of year		207,599			243,047

Extensions, Discoveries and Other Additions

The Company added 223,538 MMcf and 176,956 MMcf through its drilling program in the Marcellus Shale in 2011 and 2012, respectively.

F-25

RICE DRILLING B LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

5. Supplemental Information on Gas-Producing Activities (Unaudited) – (Continued)

Revision of Previous Estimates

In 2012, the Company had net negative revisions of 96,991 MMcf, as 32 proved undeveloped locations were removed from its estimate of reserves at December 31, 2011 due primarily to declines in natural gas pricing and changes to the Company’s drilling plans with regards to horizontal drilling.

The reserve quantity information is limited to reserves which had been evaluated as of December 31, 2012. Proved developed reserves represent only those reserves expected to be recovered from existing wells and support equipment. Proved undeveloped reserves are expected to be recovered from new wells after substantial development costs are incurred. Netherland, Sewell and Associates, Inc. reviewed 100% of the total net gas proved reserves attributable to the Company’s interests as of December 31, 2012 and 100% of the total net gas proved reserves attributable to our Marcellus joint venture as of December 31, 2012. Wright & Company, Inc. reviewed 100% of the total net gas proved reserves attributable to our Marcellus joint venture as of December 31, 2011. All of the Company’s proved reserves are located in the United States.

The information presented represents estimates of proved natural gas reserves based on evaluations prepared by the independent petroleum engineering firms of Netherland, Sewell and Associates, Inc. and Wright & Company in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Evaluation Engineers and definitions and guidelines established by the SEC. Our independent reserve engineers were selected for their historical experience and geographic expertise in engineering unconventional resources. Since 1961, Netherland, Sewell and Associates, Inc. has evaluated oil and gas properties and independently certified petroleum reserves quantities in the United States and internationally. Wright & Company was founded in 1988 and performs consulting petroleum engineering services under the Texas Board of Professional Engineers.

Certain information concerning the assumptions used in computing the standardized measure of proved reserves and their inherent limitations are discussed below. The Company believes such information is essential for a proper understanding and assessment of the data presented. Future cash inflows are computed by applying the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through, respectively, to the period-end quantities of those reserves. Gas prices are held constant throughout the lives of the properties.

The assumptions used to compute estimated future net revenues do not necessarily reflect the Company’s expectations of actual revenues or costs, or their present worth. In addition, variations from the expected production rates also could result directly or indirectly from factors outside of the Company’s control, such as unintentional delays in development, changes in prices, or regulatory controls. The standardized measure calculation further assumes that all reserves will be disposed of by production. However, if reserves are sold in place, this could affect the amount of cash eventually realized.

Future development and production costs are computed by estimating the expenditures to be incurred in developing and producing the proved natural gas reserves at the end of the year, based on period-end costs and assuming continuation of existing economic conditions.

An annual discount rate of 10% was used to reflect the timing of the future net cash flows relating to proved natural gas reserves.

F-26

RICE DRILLING B LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

5. Supplemental Information on Gas-Producing Activities (Unaudited) – (Continued)

Information with respect to Rice Drilling B’s estimated discounted future net cash flows related to its proved natural gas reserves as of December 31, is as follows (in thousands):

	2011			2012
Future cash inflows	$	1,015,589		$	869,882
Future production costs		(208,733	)		(323,855	)
Future development costs		(206,612	)		(262,084	)
Future net cash flows		600,244			283,943
10% annual discount for estimated timing of cash flows		(330,924	)		(181,725	)
Standardized measure of discounted future net cash flows (1)	$	269,320		$	102,218

(1) Does not include the effects of income taxes on future revenues at December 31, 2011 and 2012 because as of December 31, 2011 and 2012, the Company was a limited liability company not subject to entity-level taxation. Accordingly, no provision for federal or state corporate income taxes has been provided because taxable income was passed through to the Company’s equity holders.

For 2012, the reserves for Rice Drilling B were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2012, adjusted for energy content and a regional price differential. For 2012, this adjusted gas price was $2.86 per Mcf.

For 2011, the reserves for Rice Drilling B were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2011, adjusted for energy content and a regional price differential. For 2011, this adjusted gas price was $4.36 per Mcf.

The following are the principal sources of changes in the standardized measure of discounted future net cash flows for Rice Drilling B (in thousands):

	2011			2012
Balance at beginning of period	$	46,422		$	269,320
Net change in prices and production costs		(15,929	)		(83,873	)
Net change in future development costs		(3,695	)		(31,811	)
Natural gas net revenues		(11,815	)		(18,376	)
Extensions		243,003			38,937
Revisions of previous quantity estimates		(14,259	)		(108,209	)
Previously estimated development costs incurred		3,040			17,036
Accretion of discount		4,642			26,932
Changes in timing and other		17,911			(7,738	)
Balance at end of period	$	269,320		$	102,218

Gains on sales of interests in gas properties are not included in the information set forth above. We have also allocated certain general and administrative expenses to our results of operations as these expenses relate to production activities.

F-27

RICE DRILLING B LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

5. Supplemental Information on Gas-Producing Activities (Unaudited) – (Continued)

Costs incurred for property acquisitions, exploration and development for the years ended December 31, 2011, and 2012 related to our Marcellus joint venture are as follows (represents Rice Drilling B’s proportionate share, in thousands):

	For the years ended December 31,
	2011		2012
Acquisitions:
Unproved leaseholds	$	519	$	—
Development costs		21,700		46,725
Exploration costs:
Geological and geophysical		—		—
Total costs incurred	$	22,219	$	46,725

The following table presents Rice Drilling B’s share of the results of operations related to natural gas and oil production of our Marcellus joint venture (represents Rice Drilling B’s proportionate share, in thousands):

	For the years ended December 31,
	2011		2012
Revenues	$	2,872	$	13,142
Production costs		379		5,436
Impairment of oil and gas properties		1,296		—
Depreciation, depletion and accretion		1,092		4,702
General and administrative expenses		—		986
Results of operations from producing activities	$	105	$	2,018

Reserve quantity information for the years ended December 31, 2011 and 2012 is as follows for our Marcellus joint venture (represents Rice Drilling B’s proportionate share, in thousands):

	Natural Gas (MMcf)
	2011			2012
Proved developed and undeveloped reserves:
Beginning of year		—			58,103
Extensions and discoveries		58,800			98,119
Revision of previous estimates		—			(23,808	)
Production		(697	)		(4,296	)
End of year		58,103			128,118
Proved developed reserves:
End of year		14,474			35,013
Proved undeveloped reserves:
End of year		43,629			93,105

Rice Drilling B’s 50% equity interest in our Marcellus joint venture added 58,800 MMcf and 98,119 MMcf through its drilling program in the Marcellus Shale in 2011 and 2012, respectively. In 2012, Rice Drilling B’s 50% equity interest in our Marcellus joint venture had net negative revisions of 23,808 MMcf, due primarily to declines in natural gas pricing.

F-28

RICE DRILLING B LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

5. Supplemental Information on Gas-Producing Activities (Unaudited) – (Continued)

Information with respect to Rice Drilling B’s share of our Marcellus joint venture’s estimated discounted future net cash flows related to its proved natural gas reserves as of December 31, is as follows (in thousands):

	2011			2012
Future cash inflows	$	252,384		$	364,157
Future production costs		(29,683	)		(127,086	)
Future development costs		(51,882	)		(86,213	)
Future net cash flows		170,819			150,858
10% annual discount for estimated timing of cash flows		(100,232	)		(79,781	)
Standardized measure of discounted future net cash flows (1)	$	70,587		$	71,077

For 2012, the reserves for our Marcellus joint venture were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2012, adjusted for energy content and a regional price differential. For 2012, this adjusted gas price was $2.84 per Mcf.

For 2011, the reserves for our Marcellus joint venture were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2011, adjusted for energy content and a regional price differential. For 2011, this adjusted gas price was $4.34 per Mcf.

The following is for our Marcellus joint venture (represents Rice Drilling B’s proportionate share, in thousands), the principal sources of changes in the standardized measure of discounted future net cash flows:

	2011			2012
Balance at beginning of period	$	—		$	70,587
Net change in prices and production costs		—			(26,855	)
Net change in future development costs		—			(262	)
Natural gas net revenues		(2,494	)		(7,707	)
Extensions		73,081			38,131
Revisions of previous quantity estimates		—			(28,923	)
Previously estimated development costs incurred		—			12,862
Accretion of discount		—			7,059
Changes in timing and other		—			6,185
Balance at end of period	$	70,587		$	71,077

F-29

RICE DRILLING B LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

6. Long-Term Debt

Long-term debt consists of the following at December 31, 2011 and 2012 (in thousands):

	2011		2012
Pre-funded drilling loan (Pre-funded Drilling Loan) from an individual; accrues interest at the applicable federal rate; all outstanding principal and interest due December 31, 2013; net of $92 and $0 discount at December 31, 2011 and 2012, respectively (see below)	$	2,374	$	—
Note payable to an individual (Note Payable to Individual) beginning on dates ranging from January 31, 2010 to January 31, 2011, and monthly thereafter; all unpaid balances are due December 31, 2013; net of $142 and $0 discount at December 31, 2011 and 2012, respectively (see below)		4,090		—
Senior Subordinated Convertible Debentures (Debentures) due 2014. The Debentures accrue interest at 12% per year payable monthly in arrears by the 15th day of the month and mature on July 31, 2014 (see below)		60,000		60,000
Promissory note payable (Wells Fargo Credit Facility) to Wells Fargo Energy Capital, Inc. (Wells Fargo) with maximum borrowings not to exceed $40,000; payable in monthly installments equal to the greater of 90% of the net proceeds of production on the subject properties or accrued interest at the higher of the prime rate plus 4% or the federal funds rate plus 4.5% (the effective rate was 7.25% at December 31, 2011), with such amount being applied first to accrued interest and the remainder to principal; all unpaid balances are due June 1, 2013; secured by substantially all assets and interests of the subject properties (see below)		30,000		—
Promissory note payable (Wells Fargo Energy Capital Credit Facility) with maximum borrowings not to exceed $200,000; borrowing base of $90,000 at December 31, 2012; interest payable monthly in arrears at prime rate plus 4% per year, with prime having a floor of 4% (the effective rate was 8.0% at December 31, 2012); all unpaid balances are due April 30, 2014; secured by substantially all assets and interests of the subject properties (see below)		—		70,000
Equipment loan payable (Equipment Loan) to PNC Equipment Finance, LLC (PNC) with principal and interest at 3.10% payable in twenty-four monthly installments of $14; final installment is due May 31, 2014 (see below)		—		227
Subordinated promissory note payable to Wells Fargo (NPI Note) with principal only due in installments; $8,500 due by June 30, 2013; all unpaid balances are due June 30, 2014; net of $1,718 discount at December 31, 2012 (see below)		—		15,282
Equipment loan payable (Equipment Loan) to PNC with principal and interest at 3.05% payable in twenty-four monthly installments of $9; final installment is due November 8, 2014 (see below)		—		204
Equipment loan payable (Equipment Loan) to PNC with principal and interest at 3.33% payable in thirty-six monthly installments of $22; final installment is due March 28, 2015 (see below)		—		561
Note payable to an individual (Second Note Payable to Individual) payable in thirty monthly installments of $116 beginning on January 31, 2013, and monthly thereafter; all unpaid balances are due June 30, 2015; net of $441 discount at December 31, 2012 (see below)		—		3,046
Subordinated promissory note payable to a related party (Related-Party Note) with interest only at 1.65% due annually; matures on February 1, 2018; secured by substantially all assets of the Company; net of $2,691 discount at December 31, 2011 (see below)		7,309		—
Subordinated promissory note payable to a related party (Related-Party Working Capital Note) with interest only at 1.20% due at maturity; matures on February 1, 2018		4,022		—
Total debt		107,795		149,320
Less current portion		6,697		8,814
Long-term debt	$	101,098	$	140,506

F-30

RICE DRILLING B LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

6. Long-Term Debt – (Continued)

Pre-funded Drilling Loan and Note Payable to Individual

On December 31, 2009, the Company entered into purchase agreements for oil and gas leases and related notes with an individual that became effective on June 30, 2010, after due diligence and other matters included in the agreements were addressed. A closing prepayment, in the amount of $1.0 million, was made on December 31, 2009, and was classified as unproved gas properties. Notes payable with a principal of $29.3 million was assumed on June 30, 2010, when the rights were obtained by the Company and there was an unconditional obligation to the seller. A pre-funded drilling loan in the amount of $3.1 million was assumed and is included within the $29.3 million referenced above. Approximately $11.8 million was repaid to the note holder in a single payment in 2010 in addition to monthly payments. The note payable was secured by the related property, hydrocarbons and proceeds there from, as well as any associated receivables. The seller had the right to acquire up to 15% working interests in wells drilled by the Company on the leasehold estate in exchange for payment by the seller of the proportionate share of the actual costs.

The interest rates on the note payable and associated pre-funding drilling loan were considered below market rates. As a result, the Company estimated the discount on issuance of these instruments based upon an estimate of market rates at the inception of the instruments and recorded a discount of $1.6 million. The discount was amortized over the life of the note payable and associated pre-funded drilling loan using effective interest rates of 5.27% and 6.31%, respectively, using the effective yield method.

Both of these loans were repaid as of December 31, 2012.

Wells Fargo Credit Facility

The Wells Fargo Credit Facility (Wells Fargo Credit Facility) provides for borrowings to be used for drilling, completing, equipping for production, plugging, and abandoning wells on the subject properties. The Wells Fargo Credit Facility is subject to a maximum borrowing base equal to the maximum value, for credit purposes, of the subject properties as determined by Wells Fargo in accordance with its customary lending practices.

In addition to principal and interest payments, the Company assigned a 30% net profits interest (NPI) in the future production of hydrocarbons from the subject properties to Wells Fargo. The NPI was to be due monthly in perpetuity once the outstanding debt has been repaid and does not begin to accrue on the properties until such debt has been repaid. After Wells Fargo achieves a 25% internal rate of return, the NPI was to be reduced to 7.5%.

The Wells Fargo Credit Facility is subject to certain covenants which are ordinary to such credit facilities and include, among other things, restrictions as to additional debt and changes to the Company’s structure.

This Wells Fargo Credit Facility was amended during 2012. In addition to the amendment of the note, the Company also repurchased the associated NPI for $26.5 million; $9.5 million in cash and $17.0 million in the form of a note and related increase in proved properties (see NPI Note description below).

NPI Note

In November of 2012, in connection with the amendment of the Wells Fargo Credit Facility, the Company repurchased the NPI it had previously assigned to Wells Fargo for $26.5 million, of which $9.5 million was paid

F-31

RICE DRILLING B LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

6. Long-Term Debt – (Continued)

at the closing of the Wells Fargo Energy Capital Credit Facility and $17.0 million was financed by a note to Wells Fargo. The Company accounted for this as the acquisition of a mineral right and therefore capitalized this amount in proved properties and will amortize using the units of production method. There is no stated interest rate associated with this note and as a result, this note was considered below market rates. The Company estimated the discount on issuance of this instrument based upon an estimate of market rates at the inception of the instrument and recorded a discount of $2.0 million. The discount is being amortized over the life of the note using an effective interest rate of 10.54% in the effective yield method.

Wells Fargo Energy Capital Credit Facility

In November of 2012, the Company amended and restated its existing credit facility with Wells Fargo, as discussed above. In connection with the amendment and restatement, a lender was added to the new facility. The amendment and restatement was accounted for as a modification of the debt, resulting in $0.2 million of third-party costs associated with the amendment and restatement being expensed. The Wells Fargo Energy Capital Credit Facility (Wells Fargo Energy Capital Credit Facility) is subject to a maximum borrowing base equal to $200 million, as determined unanimously by the lenders, in accordance with customary lending practices. The borrowing base is determined by the lenders on a semiannual basis and such determination is primarily based upon the value of Rice Drilling’s proved developed reserves. If the lenders were to decrease the borrowing base below the amounts outstanding under the facility, the Company would have to repay these amounts within 30 days, repay these amounts in five monthly installments, or add sufficient collateral value. The borrowing base at December 31, 2012, was $90.0 million with approximately $20.0 million undrawn at that date.

The Wells Fargo Energy Capital Credit Facility is subject to certain covenants which are ordinary to such credit facilities and include, among other things, requirements regarding liquidity and restrictions as to changes to the Company’s structure. As of December 31, 2012, certain financial covenants specified by the credit agreement had not been met. The lenders have waived such noncompliance at December 31, 2012. Based upon current projections, the Company believes it will be in compliance with all debt covenants through January 1, 2014.

Second Note Payable to Individual

On December 31, 2012, the Company entered into a purchase agreement relating to the acquisition of certain producing shallow natural gas wells and unproved properties (see Note 16). A portion of the consideration for the purchase was accounted for in the form of a note payable for $3.5 million; payable in thirty monthly installments of $0.1 million.

The interest rate on the note payable was considered to be below market rates. As a result, the Company estimated the discount on issuance of this instrument based upon an estimate of market rates at the inception of the instrument and recorded a discount of $0.4 million. The discount is to be amortized over the life of the note payable using an effective interest rate of 10.11% using the effective yield method.

Related-Party Note

On February 1, 2009, the terms of the $10.0 million subordinated promissory note payable to a party (promissory note) were modified. For accounting purposes, the cash flows of the promissory note were considered substantially different resulting in extinguishment accounting. There were no financing fees recorded for the promissory note. The fair value of the modified promissory note was compared to the carrying value of

F-32

RICE DRILLING B LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

6. Long-Term Debt – (Continued)

the original promissory note with the difference resulting in a capital contribution from the related party of $3.6 million. The fair value was estimated based upon an estimate of market rates at the inception of the promissory note. The discount was amortized over the life of the instruments using an effective interest rate of 4.6%. This note was converted to equity in January 2012.

Related-Party Working Capital Note

On October 28, 2009, the Company entered into a subordinated promissory note payable to a related party in the amount of $4.0 million. The note accrued interest at a rate of 1.20% and interest only is due at maturity on February 1, 2018. This note was converted to equity in January 2012.

Equipment Loans

On March 20, 2012, Blue Tiger entered into a loan and security agreement with PNC to finance the acquisition of equipment to be used in the ordinary course of business. Advances were made during the year ended December 31, 2012, as follows: on March 28, 2012, an advance of $0.7 million was made to finance the purchase of light plants and generators; on May 31, 2012, an advance of $0.3 million was made to finance the purchase of vertical sand separators; on November 8, 2012, an advance of $0.2 million was made to finance the purchase of additional vertical sand separators. All loans have fixed payment terms and interest rates as stated above.

Debentures

In June of 2011, Rice Drilling sold $60.0 million of its 12% Senior Subordinated Convertible Debentures due 2014 (the Debentures) in a private placement to certain accredited investors as defined in Rule 501 of Regulation D. The Debentures accrue interest at 12% per year payable monthly in arrears by the 15th day of the month and mature on July 31, 2014. The Debentures are Rice Drilling’s unsecured senior obligations and rank equally with all of Rice Drilling’s current and future senior unsecured indebtedness.

Under the terms of the Debentures and the Subscription Agreements, the holders of the Debentures have agreed not to receive any payments of any kind owed by the Company under the Debentures (except for regularly scheduled interest payments) until the Wells Fargo Energy Capital Credit Facility has been repaid in full.

From July 31, 2013 through August 20, 2013, any holder of Debentures shall have the right to cause Rice Drilling to repurchase all or any portion of the Debentures owned by such holder at 100% of the portion of the principal amount of the Debentures as to which the right is being exercised plus a premium of 20%.

Any partial repurchase must be for a minimum amount of at least $50 thousand with additional integral multiples of $10 thousand. At any time after July 31, 2013, until the Maturity Date, Rice Drilling has the right to redeem all, but not less than all, of the Debentures on 30 days prior written notice at a redemption price equal to 100% of the principal amount of the Debentures plus a premium of 50%. Otherwise, no Debentures may be prepaid by Rice Drilling without the written consent of the holders thereof. At any time on or before July 31, 2013, each holder shall have a one-time right to convert part or all of the principal amount of the Debentures held by such Holder into Conversion Units of Rice Drilling at a conversion price of $10 thousand per Conversion Unit (the Conversion Price) with a minimum conversion of five units. In the event that such holder elects to convert Debentures into Conversion Units, such holder will be required to become a party to the Operating Agreement of Rice Drilling, as amended from time to time. At any time from August 1, 2013, until the Maturity Date, each holder shall have an unlimited right to convert part or all of the

F-33

RICE DRILLING B LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

6. Long-Term Debt – (Continued)

principal amount of the Debentures held by such Holder into Conversion Units from time to time at the Conversion Price. In the event that such holder elects to convert Debentures into Conversion Units, such holder will be required to become a party to the Operating Agreement of Rice Drilling, as amended from time to time.

If a holder is unable to exercise the put right because of the subordination provisions of the Debenture, then the put exercise period shall be extended by the number of days during which the holder was unable to exercise the put rights. If the maturity date of the Wells Fargo Energy Capital Credit Facility is extended beyond the put exercise period, the holders of the Debenture will have the right to exercise the put right once the Wells Fargo Energy Capital Credit Facility is repaid in full.

In the event that the holder would be entitled to receive payment of the Principal Amount hereunder (whether upon maturity or by acceleration) but such payment is prohibited as a result of the subordination provisions, then the rate of interest shall increase as of the first day of the payment blockage to 16% per annum (based on a 360-day year) and such increased rate shall remain in effect until this Debenture is paid in full.

No bifurcation was required to account for the embedded conversion feature, put right and call right, as these were deemed to not be separable at the date of consummation of the debt.

In connection with the convertible debt offering, Rice Drilling granted warrants that were issued on August 15, 2011, to certain of the broker-dealers involved in the private placement. These warrants are considered to be separate instruments issued solely in lieu of cash compensation for services provided by the broker-dealers. Two separate classes of warrants were issued (Normal and Bonus), the sole difference being the exercise price.

The fair value of these warrants at the date of grant was estimated using the Black-Scholes valuation model with the following assumptions:

Dividend yield		0.0	%
Expected volatility		72.1	%
Risk-free rate		0.96	%
Expected life		5 years
“Normal” warrant
Number of warrants issued		1,044
Exercise price	$	10,000
Grant date fair value	$	2,569
Weighted average contractual life		5 years
“Bonus” warrant
Number of warrants issued		192
Exercise price	$	6,250
Grant date fair value	$	3,184
Weighted average contractual life		5 years

The fair value of $3.3 million of the above warrants were recorded as a deferred financing cost during the year ended December 31, 2011, and is being amortized over the term of the Debentures.

F-34

RICE DRILLING B LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

6. Long-Term Debt – (Continued)

Expected aggregate maturities of notes payable subsequent to December 31, 2012, are as follows (in thousands):

2013	$	8,814
2014		139,763
2015		743
Total	$	149,320

Interest paid in cash was $4.0 million and $10.2 million for years ended December 31, 2011 and 2012, respectively. See Note 1 for information on capitalized interest.

7. Fair Value of Financial Instruments

The Company determines fair value on a recurring basis for its liabilities related to restricted units and derivative instruments as the liabilities are required to be recorded at fair value for each reporting amount. Certain amounts in the Company’s financial statements are measured at fair value on a nonrecurring basis including discounts associated with long-term debt. Fair value is based on quoted market prices, where available. If quoted market prices are not available, fair value is based upon models that use as inputs market-based parameters, including but not limited to forward curves, discount rates, broker quotes, volatilities, and nonperformance risk.

The Company has categorized its fair value measurements into a three-level fair value hierarchy, based on the priority of the inputs to the valuation technique. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets and liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). The Company’s fair value measurements relating to restricted units are included in Level 3. The Company’s fair value measurements relating to derivative instruments are included in Level 2. Since the adoption of fair value accounting, the Company has not made any changes to its classification of financial instruments in each category.

Items included in Level 3 are valued using internal models that use significant unobservable inputs. Items included in Level 2 are valued using third-party quotes that result in management’s best estimate of fair value.

The following liabilities were measured at fair value on a recurring basis during the period (in thousands):

			Fair Value Measurements at Reporting Date Using
Description	December 31, 2011		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Liabilities
Restricted units, at fair value	$	6,800	$	—	$	—	$	6,800
Total liabilities	$	6,800	$	—	$	—	$	6,800

F-35

RICE DRILLING B LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

7. Fair Value of Financial Instruments – (Continued)

			Fair Value Measurements at Reporting Date Using
Description	December 31, 2012		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Liabilities
Restricted units, at fair value	$	5,667	$	—	$	—	$	5,667
Derivative Instruments, at fair value		2,260		—		2,260		—
Total liabilities	$	7,927	$	—	$	2,260	$	5,667

	Fair Value Measurements Using
	Significant Unobservable Inputs (Level 3)
Balance at December 31, 2010	$	6,630
Total gain or losses:
Included in earnings		170
Transfers in and/or out of Level 3		—
Balance at December 31, 2011		6,800
Total gain or losses:
Included in earnings		115
Transfers in and/or out of Level 3		—
Repurchase of restricted units		(1,133	)
Settlement		(115	)
Balance at December 31, 2012	$	5,667

Gains and losses related to restricted units included in earnings for the period are reported in operating expenses in the statements of consolidated operations.

As described in Note 6, the Company recorded nonrecurring fair value adjustments to the carrying values of certain loans. The fair value adjustments were primarily based upon Level 3 inputs resulting in a reduction at issuance to the stated face value of the notes of approximately $2.5 million. If the interest rates used in the fair value estimate changed by 1% it would have impacted the debt discount by approximately $0.2 million.

The carrying value of cash equivalents and short-term loans approximates fair value due to the short maturity of the instruments.

F-36

RICE DRILLING B LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

7. Fair Value of Financial Instruments – (Continued)

The estimated fair value of long-term debt on the consolidated balance sheets at December 31, 2011 and 2012 is shown in the table below. The fair value was estimated using Level 3 inputs based on rates reflective of the remaining maturity as well as the Company’s financial position.

Description	2011		2012
(in thousands)
Long-term debt, at fair value
Pre-funded drilling loan	$	2,369	$	—
Note payable to individual		3,546		—
Debentures		69,600		70,220
Wells Fargo credit facility		39,809		—
Wells Fargo Energy Capital credit facility		—		70,000
NPI note		—		15,282
Equipment loans		—		992
Second note payable to individual		—		3,046
Related-party note		4,099		—
Related-party working capital note		1,928		—
Total	$	121,351	$	159,540

8. Lease Obligations

The Company leases drilling rights under agreements which expire at various times. The following represents the future minimum lease payments under the agreements at December 31, 2012 (in thousands):

2013	$	3,954
2014		44
2015		21
2016 and future		41
Total future minimum lease payments	$	4,060

These lease payments are included as leasehold payables in the accompanying consolidated balance sheets.

Additionally, the Company has leased drilling rights under agreements which specify additional payments due in the event that the Company does not meet predetermined criteria within a specified period of time. The Company could be required to pay up to approximately $2.7 million in 2013 and 2014, under these agreements.

F-37

RICE DRILLING B LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

9. Asset Retirement Obligations

The Company is subject to certain legal requirements which result in recognition of a liability related to the obligation to incur future plugging and abandonment costs. The Company records a liability for such asset retirement obligations and capitalizes a corresponding amount for asset retirement costs. The liability is estimated using the present value of expected future cash flows, adjusted for inflation and discounted at the Company’s credit adjusted risk-free rate. No wells were plugged or abandoned during 2012, nor were there any changes to assumptions. A reconciliation of the beginning and ending aggregate carrying amount of asset retirement obligations for the years ended December 31, 2011 and 2012 is as follows (in thousands):

Balance at December 31, 2010	$	289
Liabilities incurred		493
Accretion expense		53
Balance at December 31, 2011		835
Liabilities incurred		382
Accretion expense		164
Balance at December 31, 2012	$	1,381

10. Members’ Capital

Members include consultants and employees of the Company as well as REA. The liability of the members of the Company is limited to each member’s total capital account. Subsequent to a 4:1 stock split on June 22, 2011, authorized capital consisted of 36,000 preferred units, 2,000 Class A units, and 2,000 Class B units as of December 31, 2011. The consolidated financial statements have been adjusted to reflect the impact of the stock split for all periods presented, where applicable.

As of December 31, 2012, all units of Class A units were reserved for issuance pursuant to a Restricted Unit Agreement (see Note 11). As discussed in Note 1, the founding member, Rice Partners, assigned its 36,000 preferred units to REA. Additionally, in connection with NGP’s $100 million equity investment into REA in 2012, of which 100% of the net proceeds were invested into Rice Drilling, Rice Drilling issued 15,998 preferred units to REA. Operating profits and losses are to be allocated in proportion to the members’ interest.

Liquidation Preference

In the event of any liquidation, dissolution or winding up of the Company, distributions will first be made to members holding senior preferred units until such members have received cumulative distributions in an amount equal to the preferred return as defined in the REA agreement, second to the members holding preferred units in the amount of $49.9 million, then, until the Company has achieved breakeven operations, as defined, to the members holding preferred and Class A common units in proportion to their ownership interests and thereafter to the members in proportion to their ownership units.

Repurchase Option

Up until the third anniversary of the grant of Class A and B restricted units, the Company or a member of its affiliates has the right to repurchase all of the units from the member at $1,700 per unit, as defined and in accordance with the Company’s LLC agreement. Subsequent to the third anniversary of the grant of Class A and B restricted units, the Company or a member of its affiliates has the right to repurchase all of the units from the member at fair market value, not less than $1,700 per unit, in accordance with the Company’s LLC agreement.

F-38

RICE DRILLING B LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

10. Members’ Capital – (Continued)

During 2012, REA exercised the option to repurchase all units of the 2,000 Class B restricted units for $3.4 million. In December 2012, a payment of $1.1 million was made by the Company to the member on behalf of REA. Additional payments of $2.3 million were made by the Company on behalf of REA in 2013.

Voting Rights

Preferred units have voting rights whereas the restricted units (Class A and B common units) are nonvoting.

11. Restricted Unit Agreements

Effective November 13, 2009, the Company entered into restricted unit agreements with an employee and consultants. Under separate and individual restricted unit agreements, the eligible employee and consultants are granted units which vest over a specified period of time. Each unit entitles the holder to an equity ownership in the Company. The restricted units are accounted for as liability awards, which require remeasurement each reporting period, as a result of the existence of a call option that permits the Company to repurchase the awards at a fixed amount that could be above or below fair market value of the units. Prior to November 13, 2012, the Company had the ability to exercise the call option at a specified amount. Subsequently, the Company’s call right is at fair market value. At December 31, 2012, the remaining liability recorded for the restricted units represented fair value. The Company has estimated fair value of the restricted units using an income approach that estimates the fair value of the Company and the associated units which are discounted for a lack of marketability. To the extent available, market transactions are factored into the fair value estimate. The income approach requires use of internal business plans that are based on judgments and estimates regarding future economic conditions, costs, inflation rates and discount rates, among other factors.

A summary of activity during 2011 was as follows:

	Restricted Units
Nonvested restricted units at December 31, 2010		100
Vested during 2011		(100	)
Nonvested restricted units, December 31, 2011		—

During 2011, $0.2 million of restricted unit expense was recognized in these awards.

During 2012, REA exercised its option to repurchase all of the 2,000 Class B restricted units. A summary of the change in vested restricted units is as follows:

	Restricted Units
Class A and Class B restricted units
Vested restricted units		4,000
Repurchased Class B restricted units		(2,000	)
Vested restricted units at December 31, 2012		2,000

F-39

RICE DRILLING B LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

12. Incentive Units

Rice Energy Appalachia LLC (REA), as the parent company of Rice Drilling B LLC, granted Incentive Units to certain members of management. The Incentive Units are not accounted for as equity instruments as the Incentive Units do not have the characteristics of a substantive class of equity. Rather, the Incentive Units provide the holders with a performance bonus for fair value accretion. In connection with the January 2012 NGP investment in REA, 100,000 Tier 1 Legacy units, 13,000 Tier II Legacy units, and 17,000 Tier III Legacy units were issued. The Incentive Units will only be paid in cash and payout for each tier occurs when a specified level of cumulative cash distributions has been received by NGP.

During 2012, no payments were made in respect of Incentive Units. The Company has not recognized compensation cost on the Incentive Units because the payment conditions, which relate to a liquidity event, are not considered probable at December 31, 2012. The estimated payout under these awards at December 31, 2012 is approximately $8.1 million if a liquidity event were to occur. This estimate is based upon an option pricing model with various Level 3 assumptions including internal business plans that are based on judgments and estimates regarding future economic conditions, costs, inflation rates and discount rates among other factors. To the extent market transactions are known this information is factored into fair value estimates.

13. Derivative Instruments

The Company uses derivative commodity instruments that are placed with major financial institutions whose creditworthiness is regularly monitored. As of December 31, 2012, the Company entered into derivative instruments with Wells Fargo Bank, N.A. fixing the price it receives for natural gas through December 31, 2014. The derivative commodity instruments used by the Company are composed of a $3.225 fixed rate swap contract for 20,000 MMBtu per day expiring on December 31, 2013, and a collar contract with a ceiling of $5.800 and a floor of $3.000 for 10,000 MMBtu per day expiring on December 31, 2014. All derivative contracts are carried at their fair value on the consolidated balance sheet. Both realized and unrealized gains and losses are recorded as a gain or loss on derivatives in the consolidated statement of operations under other income/expense. Unrealized losses were $0 million and $2.3 million for the years ended December 31, 2011 and 2012, respectively. The Company had realized gains related to contract settlements of $0.6 million and $0.9 million for the years ended December 31, 2011 and 2012, respectively.

14. Commitments and Contingencies

The Company is involved in various litigation matters arising in the normal course of business. Management is not aware of any actions that are expected to have a material adverse effect on its financial position or results of operations.

The Company has drilling commitments which management expects to meet in the ordinary course of business.

The Company acquired certain unproved properties on December 31, 2012. The seller has the right to participate in the development of such unproved properties and the Company has committed to fund an additional $3.2 million relating to these activities (see Note 16).

As part of the leasehold arrangements with the landowners, the Company will pay royalties of 12.5% to 20%.

F-40

RICE DRILLING B LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

14. Commitments and Contingencies – (Continued)

The Company guarantees certain debt and lease agreements of its oilfield service company joint venture. The maximum exposure under these guarantees is equivalent to the future payments of approximately $0.4 million due under the agreements.

During 2012, the Company subscribed to Columbia Gas Transmission’s West Side Expansion Project. As part of the subscription, the Company has committed to 100,000 Dth/d of Firm Transportation Capacity at $0.44/Dth. The contract is for a period of ten years.

15. Related-Party Transactions

The Company reimburses Rice Partners for expenses incurred on behalf of the Company. General and administrative expenses incurred by Rice Partners and reimbursed by the Company were $3.1 million and $4.8 million for the years ended December 31, 2011 and 2012, respectively. At December 31, 2012, $2.5 million of general and administrative expenses was due to Rice Partners and is recorded as due to affiliate on the consolidated balance sheet.

The Company is reimbursed for costs incurred on behalf of the Company’s Marcellus joint venture. General and administrative expenses incurred by the Company and reimbursed by the Company’s Marcellus joint venture were $0 million and $1.3 million for the years ended December 31, 2011 and 2012, respectively. At December 31, 2012, the Company recorded a receivable from its Marcellus joint venture for $4.6 million representing leaseholds that were approved to be contributed to the joint venture.

16. Acquisitions

On December 31, 2012, the Company entered into a transaction to acquire certain producing shallow natural gas wells and unproved properties (the Acquisition). Total firm consideration in the Acquisition was approximately $10.0 million of which $3.3 million was paid to the seller in January 2013. The remaining consideration will be transferred to the seller from 2013 to 2015. In addition to the firm consideration, the seller has the right to participate in the development of the unproved properties and the Company is responsible for funding $3.7 million of these activities. The Company has recorded the $10.0 million pending purchase price with the offset to proved and unproved properties. As the Company has not completed its accounting for the Acquisition of this business, adjustments to the initial allocation could occur.

17. Subsequent Events

As described in Notes 10 and 11, REA exercised its option to repurchase all units of the 2,000 Class B Incentive Units for $3.4 million during 2012. Payments of $2.3 million were made by the Company on behalf of REA during 2013 as follows: a payment of $1.1 million in January 2013, and $1.1 million in February 2013. As of December 31, 2012, the Company has recorded a receivable from REA for $3.4 million; reimbursement for this receivable is expected to occur during the second quarter of 2013.

In January 2013 and March 2013, the Company drew an additional $15.0 million and $10.0 million, respectively, from its Wells Fargo Energy Capital Credit Facility. The borrowing base was increased to $120.0 million; availability is approximately $25.0 million.

In November 2012, Rice D entered into an agreement with a landowner group in Ohio to purchase leaseholds for Utica Shale development for approximately $240.0 million. As of the date of financial statement

F-41

RICE DRILLING B LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

17. Subsequent Events – (Continued)

issuance, Rice D is in the process of clearing title related to this leasehold acquisition. Under the terms of the agreement, Rice D is obligated to pay a break-up fee of $1,000 per acre once 25,000 acres clears title if Rice D does not close on the transaction. As of date of issuance, less than 25,000 acres have cleared title. Rice D expects more than 25,000 acres to ultimately clear title and anticipates purchasing these leaseholds in accordance with contract terms.

Except for Note 5 and Note 12, subsequent events have been considered for disclosure and recognition through April 10, 2013, the same date the consolidated financial statements were available to be issued.

F-42

RICE DRILLING B LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)	December 31, 2012		(Unaudited) September 30, 2013
Assets
Current assets:
Cash	$	8,547	$	27,661
Restricted cash		—		8,268
Accounts receivable		8,557		20,954
Receivable from affiliate		11,879		4,982
Prepaid expenses and other		321		592
Derivative assets		—		7,507
Total current assets		29,304		69,964
Investment in joint ventures		30,976		49,819
Gas collateral account		5,843		—
Proved natural gas properties, net		159,988		217,809
Unproved natural gas properties		111,030		391,772
Property and equipment, net		2,622		4,121
Deferred financing costs, net		5,208		9,928
Derivative assets		—		7,984
Total assets	$	344,971	$	751,397
Liabilities and members’ capital
Current liabilities:
Current portion of long-term debt	$	8,814	$	19,510
Accounts payable		19,793		24,577
Royalties payable		1,960		7,876
Accrued interest		2,004		325
Accrued capital expenditures		2,359		18,745
Other accrued liabilities		5,585		6,813
Leasehold payables		3,954		6,354
Derivative liabilities		2,260		—
Payable to affiliate		2,482		6,740
Operated prepayment liability		11,553		5,324
Total current liabilities		60,764		96,264
Long-term liabilities:
Long-term debt		140,506		292,804
Leasehold payables		106		762
Other long-term liabilities		5,404		46,230
Total liabilities		206,780		436,060
Members’ capital		138,191		315,337
Total liabilities and members’ capital	$	344,971	$	751,397

See accompanying Notes to Consolidated Financial Statements (Unaudited).

F-43

RICE DRILLING B LLC AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED OPERATIONS

(Unaudited)

(in thousands)	Nine Months Ended September 30, 2012			Nine Months Ended September 30, 2013
Revenues:
Natural gas sales	$	15,527		$	60,219
Other revenue		—			519
Total revenues		15,527			60,738
Operating expenses:
Lease operating		2,226			5,794
Gathering, compression and transportation		2,413			6,951
Production taxes and impact fees		1,165			1,029
Exploration		2,850			1,784
Restricted unit expense		—			40,087
General and administrative		5,374			9,952
Depreciation, depletion and amortization		10,209			23,215
Amortization of deferred financing costs		5,540			4,760
Write-down of abandoned leases		2,223			—
Total expenses		32,000			93,572
Operating loss		(16,473	)		(32,834	)
Other income (expense):
Interest expense		(1,801	)		(13,033	)
Other income (expense)		76			(347	)
Gain (loss) on derivative instruments		(3,407	)		16,698
Loss on extinguishment of debt		—			(10,622	)
Equity in income (loss) of joint ventures		(136	)		19,297
Total other income (expense)		(5,268	)		11,993
Net loss	$	(21,741	)	$	(20,841	)

See accompanying Notes to Consolidated Financial Statements (Unaudited).

F-44

RICE DRILLING B LLC AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED MEMBERS’ CAPITAL

(Unaudited)

(in thousands)	Preferred Units			Warrant		Accumulated Deficit			Total
Balance as of December 31, 2011	$	53,515		$	3,294	$	(9,988	)	$	46,821
Capital contributions		97,168			—		—			97,168
Return of capital		(800	)		—		—			(800	)
Conversion of related-party notes payable		11,332			—		—			11,332
Net loss		—			—		(21,741	)		(21,741	)
Balance as of September 30, 2012 (Unaudited)	$	161,215		$	3,294	$	(31,729	)	$	132,780
	Preferred Units			Warrant		Accumulated Deficit			Total
Balance as of December 31, 2012	$	164,228		$	3,294	$	(29,331	)	$	138,191
Capital contributions		197,987			—		—			197,987
Net loss		—			—		(20,841	)		(20,841	)
Balance as of September 30, 2013 (Unaudited)	$	362,215		$	3,294	$	(50,172	)	$	315,337

See accompanying Notes to Consolidated Financial Statements (Unaudited).

F-45

RICE DRILLING B LLC AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED CASH FLOWS

(Unaudited)

(in thousands)	Nine Months Ended September 30, 2012			Nine Months Ended September 30, 2013
Cash flows from operating activities:
Net loss	$	(21,741	)	$	(20,841	)
Adjustments to reconcile net loss to net cash (used in) provided by operating activities:
Depreciation, depletion and amortization		10,209			23,215
Amortization of deferred financing costs		5,540			4,760
Restricted unit expense		—			40,087
Derivative instruments fair value loss (gain)		3,407			(16,698	)
Equity in loss (income) loss of joint ventures		136			(19,297	)
Write-down of abandoned leases and other leasehold costs		2,223			—
(Increase) decrease in:
Accounts receivable		(1,283	)		(12,398	)
Receivable from affiliate		(7,460	)		6,897
Gas collateral account		(4,000	)		4,343
Prepaid expenses and other		(13	)		(270	)
Cash receipts (payments) for settled derivatives		1,398			(1,053	)
Increase (decrease) in:
Accounts payable		(1,326	)		(133	)
Royalties payable		108			5,916
Other accrued expenses		4,313			3,704
Repurchase of restricted units		—			(2,267	)
Payable to affiliate		650			4,258
Net cash (used in) provided by operating activities		(7,839	)		20,223
Cash flows from investing activities:
Capital expenditures for natural gas properties		(75,263	)		(341,347	)
Investment in joint venture		(10,000	)		—
Capital expenditures for property and equipment		(328	)		(1,278	)
Net cash used in investing activities		(85,591	)		(342,625	)
Cash flows from financing activities:
Restricted cash		—			(8,268	)
Proceeds from borrowings		8,264			321,003
Repayments of debt obligations		(8,593	)		(159,726	)
Debt issuance costs		(31	)		(9,480	)
Capital contributions		97,168			197,987
Return of capital		(800	)		—
Net cash provided by financing activities		96,008			341,516
Net increase in cash		2,578			19,114
Cash at the beginning of the period		4,389			8,547
Cash at the end of the period	$	6,967		$	27,661

See accompanying Notes to Consolidated Financial Statements (Unaudited).

F-46

RICE DRILLING B LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Basis of Presentation

The accompanying unaudited consolidated financial statements of Rice Drilling B LLC and subsidiaries (“the Company”) have been prepared by the Company’s management in accordance with generally accepted accounting principles in the United States for interim financial information and applicable rules and regulations promulgated under the Securities Exchange Act of 1934, as amended. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles in the United States for annual financial statements. The unaudited consolidated financial statements included herein contain all adjustments (consisting of normal recurring adjustments) which are, in the opinion of management, necessary to present fairly the Company’s financial position as of September 30, 2013 and its consolidated statements of operations for the nine months ended September 30, 2012 and 2013 and of cash flows for the nine months ended September 30, 2012 and 2013. The consolidated statements of operations for the nine months ended September 30, 2012 and 2013 are not necessarily indicative of the results to be expected for future periods. These consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included elsewhere in this prospectus and registration statement.

The consolidated financial statements of the Company include the accounts of Rice Drilling B LLC (“the Company” or “Rice”) and its wholly owned subsidiaries, Rice Drilling C LLC (“Rice C”), Rice Drilling D LLC (“Rice D”), RDB Real Estate Holdings LLC (“RDB Real Estate”), and Blue Tiger Oilfield Services LLC (“Blue Tiger”), Rice Poseidon Midstream LLC (“Rice PM”), and Rice Olympus Midstream LLC (“Rice OM”).

Rice Poseidon Midstream LLC (Rice PM) was formed as a Delaware limited liability company on July 1, 2013. Rice PM was formed to hold investments relating to the Company’s Pennsylvania midstream operations.

Rice Olympus Midstream LLC (Rice OM) was formed as a Delaware limited liability company on July 1, 2013. Rice OM was formed to hold investments relating to the Company’s Ohio midstream operations.

2. Investments in Joint Ventures

On February 3, 2010, Rice C acquired a 50% ownership in Alpha Shale Holdings LLC, a joint venture between Rice C and a subsidiary of Alpha Natural Resources, Inc., which owns 0.1% of and serves as the general partner of Alpha Shale Resources, LP (“Marcellus joint venture”).

F-47

RICE DRILLING B LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

2. Investments in Joint Ventures – (Continued)

On February 3, 2010, Rice C also acquired a 49.95% ownership interest in Alpha Shale Resources, LP, which was formed to develop and commercialize certain Marcellus Shale gas assets and to engage in all phases of the oil and gas business in Greene County. Condensed financial information for the Company’s Marcellus joint venture as of December 31, 2012 and September 30, 2013 and for the nine month periods ended September 30, 2012 and 2013 is as follows (in thousands):

	December 31, 2012			(Unaudited) September 30, 2013
Cash	$	4,445		$	3,832
Accounts receivable		5,716			8,006
Prepaid expenses and other assets		791			13,863
Natural gas properties		114,219			166,631
Total assets	$	125,171		$	192,332
Accounts payable	$	18,953		$	6,401
Accrued expenses		15,717			13,920
Notes payable		29,200			72,000
Asset retirement obligations		542			653
Partners’ capital		60,759			99,358
Total liabilities and partners’ capital	$	125,171		$	192,332
	(Unaudited)			(Unaudited)
	September 30, 2012			September 30, 2013
Revenue:
Natural gas sales	$	14,456		$	62,938
Operating expenses:
Lease operating		1,490			6,098
Gathering, compression and transportation		3,376			11,044
Production taxes and impact fees		728			662
General and administrative		1,337			2,000
Depreciation, depletion and amortization		7,089			16,977
Amortization of deferred financing costs		—			107
Total expenses		14,020			36,888
Operating income		436			26,050
Other income (expense):
Interest expense		(271	)		(477	)
Other income (expense)		4			(902	)
Gain on derivatives		—			13,928
Total other income (expense)		(267	)		12,549
Net income	$	169		$	38,599
Rice C’s interest in net income	$	85		$	19,300

F-48

RICE DRILLING B LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

2. Investments in Joint Ventures – (Continued)

The Company accounts for this joint venture under the equity method of accounting as the Company has significant influence, but not control, over the entity. Under the equity method of accounting, investments are carried at cost, adjusted for the Company’s proportionate share of the undistributed earnings or losses and reduced for any distributions from the investee. The Company also evaluates its equity method investments for potential impairment whenever events or changes in circumstances indicate that there is an other-than-temporary decline in value of the investment. Such events may include sustained operating losses by the investee or long-term negative changes in the investee’s industry. These indicators were not present, and as a result, the Company did not recognize any impairment charges related to the equity method investment for the nine months ended September 30, 2012 and 2013.

On May 9, 2011, the Company acquired a 50% ownership in an oilfield services company which provides water transfer and roustabout services to oil and gas companies, including Rice, in Pennsylvania, West Virginia, and Ohio. This joint venture is accounted for under the equity method of accounting as the Company has significant influence, but not control, over the entity. Financial information for this entity is not presented as the results are not significant to the Company’s operations during the periods presented.

3. Long-Term Debt

The Company had long-term debt outstanding as follows at December 31, 2012 and September 30, 2013 (in thousands):

Description	December 31, 2012		(Unaudited) September 30,  2013
Long-term Debt
Debentures (a)	$	60,000	$	6,890
Wells Fargo Energy Capital Credit Facility (b)		70,000		—
Second Lien Term Loan Facility (c)		—		294,361
NPI Note (d)		15,282		7,771
Equipment Loans (e)		992		1,067
Second Note Payable to Individual (f)		3,046		2,225
Total debt	$	149,320	$	312,314
Less current portion		8,814		19,510
Long-term debt	$	140,506	$	292,804

Debentures (a)

In June of 2011, the Company sold $60.0 million of its 12% Senior Subordinated Convertible Debentures due 2014 (“the Debentures”) in a private placement to certain accredited investors as defined in Rule 501 of Regulation D. The Debentures accrue interest at 12% per year payable monthly in arrears by the 15th day of the month and mature on July 31, 2014. The Debentures are the Company’s unsecured senior obligations and rank equally with all of the Company’s current and future senior unsecured indebtedness.

From July 31, 2013 through August 20, 2013 (“the put redemption period”), any holder of Debentures had the right to cause the Company to repurchase all or any portion of the Debentures owned by such holder at 100% of the portion of the principal amount of the Debentures as to which the right was being exercised, plus a premium of 20%. During the put redemption period, the Company repurchased $53.1 million of outstanding Debentures and

F-49

RICE DRILLING B LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

3. Long-Term Debt – (Continued)

paid a put premium of $10.6 million in accordance with the terms of the agreements. The put redemption period expired in the nine months ended September 30, 2013 and the Company recorded the premium of $10.6 million as a loss on extinguishment of debt in the statement of consolidated operations for the nine months ended September 30, 2013.

At any time after July 31, 2013 until the Maturity Date, the Company has the right to redeem all, but not less than all, of the Debentures on 30 days prior written notice at a redemption price equal to 100% of the principal amount of the Debentures plus a premium of 50%. Otherwise, no Debentures may be prepaid by the Company without the written consent of the holders thereof. At any time on or before July 31, 2013, each holder had the one-time right to convert part or all of the principal amount of the Debentures held by such holder into Conversion Units of the Company at a conversion price of $10,000 per Conversion Unit (the Conversion Price) with a minimum conversion of five units. At any time from August 1, 2013 until the Maturity Date, each holder shall have an unlimited right to convert part or all of the principal amount of the Debentures held by such holder into Conversion Units from time to time at the Conversion Price. In the event that such holder elects to convert Debentures into Conversion Units, such holder will be required to become a party to the Operating Agreement of the Company, as amended from time to time. None of the debenture holders have converted into Conversion Units.

Wells Fargo Energy Capital Credit Facility (b)

In November of 2012, the Company amended and restated its existing credit facility with Wells Fargo. In connection with the amendment and restatement, a lender was added to the new facility. The amendment and restatement was accounted for as a modification of the debt, resulting in $0.2 million of third-party costs associated with the amendment and restatement being expensed. The Wells Fargo Energy Capital Credit Facility (“Wells Fargo Energy Capital Credit Facility”) was subject to a maximum borrowing base equal to $200.0 million, as determined unanimously by Wells Fargo Energy Capital, in accordance with customary lending practices. This loan was repaid using proceeds from the Second Lien Term Loan Facility during the second quarter of 2013.

Second Lien Term Loan Facility (c)

On April 25, 2013, the Company entered into a Second Lien Term Loan Facility (“Second Lien Term Loan Facility”) with Barclays Bank PLC, as administrative agent, and a syndicate of lenders in an aggregate principal amount of $300.0 million. As of September 30, 2013, the Company had a balance of $294.4 million relating to the Second Lien Term Loan Facility, this includes borrowings outstanding of $298.5 million less an original issue discount of $4.1 million. The Second Lien Term Loan Facility matures October 25, 2018. Approximately $7.3 million in fees were capitalized in connection with the Second Lien Term Loan Facility.

Principal amounts borrowed under the Second Lien Term Loan Facility are payable in an amount equal to 0.25% of the initial principal amount at the end of each quarter with the remainder payable on the maturity date. Interest is payable in arrears at the end of each quarter and on the maturity date. The Company has the choice to borrow in Eurodollars or at the base rate. Eurodollar loans bear interest at a rate per annum equal to LIBOR plus 725 basis points. Base rate loans bear interest at a rate per annum equal to the greatest of (i) 2.25%, (ii) the agent bank’s reference rate, (iii) the federal funds effective rate plus 50 basis points and (iv) the rate for one month Eurodollar loans plus 100 basis points, plus 625 basis points. The Company may prepay the borrowings under the Second Lien Term Loan Facility at any time, provided that any prepayments of principal amounts during the first year following the closing date are subject to a 2% premium and any prepayments of principal during the second year following the closing date are subject to 1% premium.

F-50

RICE DRILLING B LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

3. Long-Term Debt – (Continued)

The Second Lien Term Loan Facility is secured by liens on substantially all of the Company’s properties that are subordinated to the liens securing the revolving credit facility and guarantees from the Company’s subsidiaries other than any subsidiary that have been designated as an unrestricted subsidiary. The Second Lien Term Loan Facility contains restrictive covenants that may limit the Company’s ability to, among other things:

• incur additional indebtedness;

• sell assets;

• withdraw funds from specified restricted account;

• make loans to others;

• make investments;

• enter into mergers;

• make or declare dividends;

• hedge future production or interest rates;

• incur liens; and

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

The Second Lien Term Loan Facility also requires the Company to maintain an asset coverage ratio, which is the ratio of the present value of oil and gas reserves (discounted at 10% per annum) to the sum of all secured debt (including any debt incurred by the Company’s Marcellus joint venture under its credit facility or any replacement or refinancing of its credit facility) of not less than 1.5 to 1.0.

The Company was in compliance with such covenants and ratios as of September 30, 2013.

NPI Note (d)

In November of 2012, in connection with the amendment of the Wells Fargo Credit Facility, the Company repurchased the NPI it had previously assigned to Wells Fargo for $26.5 million, of which $9.5 million was paid at the closing of the Wells Fargo Energy Capital Credit Facility and $17.0 million was financed by a note to Wells Fargo. The Company accounted for this as the acquisition of a mineral right and therefore capitalized this amount in proved properties and will amortize using the units of production method. There is no stated interest rate associated with this note and as a result, this note was considered to have below market financing rates. The Company estimated the discount on issuance of this instrument based upon an estimate of market rates at the inception of the instrument and recorded a discount of $2.0 million. The discount is being amortized over the life of the note using an effective interest rate of 10.54% using the effective yield method. As part of the use of proceeds from the Second Lien Term Loan Facility, the Company repaid $8.5 million of this note during the second quarter of 2013. A final payment of $8.5 million is due to be repaid in June of 2014.

Equipment Loans (e)

On March 20, 2012, Blue Tiger entered into a loan and security agreement to finance the acquisition of equipment to be used in the ordinary course of business. An advance of $0.5 million was made during the second quarter of 2013 to fund the purchase of additional equipment. All loans have fixed payment terms and interest rates.

F-51

RICE DRILLING B LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

3. Long-Term Debt – (Continued)

Second Note Payable to Individual (f)

On December 31, 2012, the Company entered into a purchase agreement relating to the acquisition of certain producing shallow natural gas wells and unproved properties. A portion of the consideration for the purchase was accounted for in the form of a note payable for $3.5 million; payable in thirty monthly installments of $0.1 million.

The interest rate on the note payable was considered to be below market rates. As a result, the Company estimated the discount on issuance of this instrument based upon an estimate of market rates at the inception of the instrument and recorded a discount of $0.4 million. The discount is to be amortized over the life of the note payable using an effective interest rate of 10.11% using the effective yield method.

Senior Secured Revolving Credit Facility

On April 25, 2013, the Company entered into a (“Senior Secured Revolving Credit Facility”) with Wells Fargo Bank, N.A., as administrative agent, and a syndicate of lenders with a maximum credit amount of $500.0 million and a sublimit for letters of credit of $10.0 million. The amount available to be borrowed under the Senior Secured Revolving Credit Facility is subject to a borrowing base that is redetermination semiannually each April and October and depends on the volumes of the Company’s proved oil and gas reserves and estimated cash flows from these reserves and the Company’s commodity hedge positions. The borrowing base increased from $75.0 million to $140.0 million as redetermined on August 7, 2013 and the sublimit for letters of credit increased from $10.0 million to $25.0 million effective August 20, 2013. The next redetermination is scheduled to occur in April 2014. As of September 30, 2013, the Company had no borrowings and $1.4 million in letters of credit outstanding under the Senior Secured Revolving Credit Facility. Subsequent to September 30, 2013, the Company had borrowings of $115.0 million outstanding under the Senior Secured Revolving Credit Facility. The Senior Secured Revolving Credit Facility matures April 25, 2018. Approximately $0.5 million in fees was capitalized in connection with the Senior Secured Revolving Credit Facility.

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

The Senior Secured Revolving Credit Facility is secured by liens on substantially all of the Company’s properties and guarantees from the Company’s subsidiaries other than any subsidiary that designated as an unrestricted subsidiary. The Senior Secured Revolving Credit Facility contains restrictive covenants that may limit the ability to, among other things:

• incur additional indebtedness;

• sell assets;

• make loans to others;

• make investments;

F-52

RICE DRILLING B LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

3. Long-Term Debt – (Continued)

• enter into mergers;

• make or declare dividends;

• hedge future production or interest rates;

• incur liens; and

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

The Senior Secured Revolving Credit Facility also requires the Company to maintain the following three financial ratios, which are measured at the end of each quarter:

• a current ratio, which is the ratio of consolidated current assets (including unused commitment under the credit facility and excludes derivative assets) to consolidated current liabilities, of not less than 0.75 to 1.0 as of March 31, 2013 and 1.0 to 1.0 at the end of each fiscal quarter thereafter;

• a minimum interest coverage ratio, which is the ratio of consolidated EBITDAX based on the trailing twelve month period to consolidated interest expense, of not less than 2.5 to 1.0; and

• an asset coverage ratio, which is the ratio of the present value of oil and gas reserves (discounted at 10% per annum) to the sum of all secured debt (including any debt incurred by the Company’s Marcellus joint venture under its credit facility or any replacement or refinancing of its credit facility) of not less than 1.5 to 1.0 so long as any debt is outstanding under the term loan facility.

The Company was in compliance with such covenants and ratios as of September 30, 2013.

4. Derivative Instruments

The Company uses derivative commodity instruments that are placed with major financial institutions whose creditworthiness is regularly monitored. The Company’s derivative commodity instruments have not been designated as hedges for accounting purposes; therefore, all gains and losses were recognized in income currently. As of September 30, 2013, the Company entered into derivative instruments with Wells Fargo Bank, N.A. and Bank of Montreal fixing the price it receives for natural gas through November 28, 2017, as summarized in the following table:

Swap Contract Expiration	MMbtu/day		Weighted Average Price
2013		51,985	$	3.814
2014		87,219	$	4.112
2015		58,781	$	4.153
2016		68,514	$	4.233
2017		30,000	$	4.343

Collar Contract Expiration	MMbtu/day		Floor/Ceiling
2014		10,000	$	3.000/$5.800
2015		45,000	$	4.000/$4.500

F-53

RICE DRILLING B LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

4. Derivative Instruments – (Continued)

The following is a summary of the Company’s derivative instruments, which are recorded in the consolidated balance sheets as of December 31, 2012 and September 30, 2013 (in thousands):

	December 31, 2012			(Unaudited) September 30,  2013
Current derivative assets	$	46		$	8,189
Long-term derivative assets		—			8,145
	$	46		$	16,334
Current derivative liabilities	$	2,306		$	682
Long-term derivative liabilities		—			161
	$	2,306		$	843
Net current value of derivative assets (liabilities)	$	(2,260	)	$	7,507
Net long-term value of derivative assets	$	—		$	7,984

The following tables present the gross amounts of recognized derivative assets and liabilities, the amounts offset under netting arrangements with counterparties, and the resulting net amounts presented in the consolidated balance sheets for the periods presented, all at fair value (in thousands):

	December 31, 2012
Description	Gross Amounts of Recognized Assets		Gross Amounts Offset on Balance Sheet			Net Amounts of Assets  (Liabilities) on Balance Sheet
Derivative assets	$	416	$	(370	)	$	46
Derivative liabilities	$	—	$	(2,306	)	$	(2,306	)

	(Unaudited) September 30, 2013
Description	Gross Amounts of Recognized Assets		Gross Amounts Offset on Balance Sheet			Net Amounts of Assets  (Liabilities) on Balance Sheet
Derivative assets	$	22,626	$	(6,292	)	$	16,334
Derivative liabilities	$	—	$	(843	)	$	(843	)

Both realized and unrealized gains and losses are recorded as a gain or loss on derivatives in the consolidated statement of operations under other income/expense. Unrealized losses were $4.8 million for the nine months ended September 30, 2012 and unrealized gains were $17.8 million for the nine months ended September 30, 2013. The Company had realized gains related to contract settlements of $1.4 million for the nine months ended September 30, 2012 and realized losses of $1.1 million for the nine months ended September 30, 2013.

5. Fair Value of Financial Instruments

The Company determines fair value on a recurring basis for restricted units and derivative instruments as the financial instruments are required to be recorded at fair value for each reporting amount. Certain amounts in the

F-54

RICE DRILLING B LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

5. Fair Value of Financial Instruments – (Continued)

Company’s financial statements are measured at fair value on a nonrecurring basis including discounts associated with long-term debt. Fair value is based on quoted market prices, where available. If quoted market prices are not available, fair value is based upon models that use unobservable inputs.

The Company has categorized its fair value measurements into a three-level fair value hierarchy, based on the priority of the inputs to the valuation technique. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets and liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). The Company’s fair value measurements relating to restricted units are included in Level 3. The significant unobservable inputs used to calculate fair values related to the restricted units, which were issued in November 2009, are internal business plans that are based on judgments and estimates regarding future economic conditions, costs, inflation rates and discount rates, among other factors. To the extent market transactions are known, this information is factored into the fair value estimate obtained by management each reporting period. For the period ended September 30, 2013, the Company estimated the fair value of the restricted units resulting in expense for the period ended September 30, 2013 of $40.1 million. The increase in fair value can be attributed to continued positive drilling results, market transactions and recent acreage acquisitions. The Company’s fair value measurements relating to derivative instruments are included in Level 2. Since the adoption of fair value accounting, the Company has not made any changes to its classification of financial instruments in each category.

The following financial instruments were measured at fair value on a recurring basis during the period (refer to Note 4 for details relating to the derivative instruments) (in thousands):

			Fair Value Measurements at Reporting Date Using
Description	December 31, 2012		Quoted Prices in Active Markets for Identical Assets        (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Liabilities
Derivative Instruments, at fair value	$	2,260	$	—	$	2,260	$	—
Restricted Units, at fair value		5,667		—		—		5,667
Total liabilities	$	7,927	$	—	$	2,260	$	5,667
Description	(Unaudited) September 30,  2013		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Assets
Derivative Instruments, at fair value	$	7,507	$	—	$	7,507	$	—
Total current assets	$	7,507	$	—	$	7,507	$	—
Derivative Instruments, at fair value	$	7,984	$	—	$	7,984	$	—
Total non-current assets	$	7,984	$	—	$	7,984	$	—
Liabilities
Restricted Units, at fair value	$	43,487	$	—	$	—	$	43,487
Total liabilities	$	43,487	$	—	$	—	$	43,487

F-55

RICE DRILLING B LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

5. Fair Value of Financial Instruments – (Continued)

	Fair Value Measurements  Using
	Significant Unobservable Inputs  (Level 3)
Balance as of December 31, 2011	$	6,800
Total gain or losses:
Included in earnings		—
Transfers in and/or out of Level 3		—
Balance as of September 30, 2012 (Unaudited)	$	6,800
Balance as of December 31, 2012	$	5,667
Total gain or losses:
Included in earnings		40,087
Transfers in and/or out of Level 3		—
Repurchase of restricted units		(2,267	)
Balance as of September 30, 2013 (Unaudited)	$	43,487

The liability of $43.5 million is included within other long-term liabilities.

The estimated fair value of long-term debt on the consolidated balance sheets at December 31, 2012 and September 30, 2013 is shown in the table below. The fair value was estimated using Level 3 inputs based on rates reflective of the remaining maturity as well as the Company’s financial position (refer to Note 3 for details relating to long-term debt) (in thousands).

Description	December 31, 2012		(Unaudited) September 30,  2013
(in thousands)
Long-term Debt, at fair value
Debentures	$	70,220	$	11,083
Wells Fargo Energy Capital Credit Facility		70,000		—
Second Lien Term Loan Facility		—		294,361
NPI Note		15,282		7,771
Equipment Loans		992		1,067
Second Note Payable to Individual		3,046		2,225
Total	$	159,540	$	316,507

The carrying value of cash equivalents and short-term loans approximates fair value due to the short maturity of the instruments.

6. Commitments and Contingencies

The Company is involved in various litigation matters arising in the normal course of business. Management is not aware of any actions that are expected to have a material adverse effect on its financial position or results of operations.

F-56

RICE DRILLING B LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

6. Commitments and Contingencies – (Continued)

The Company has drilling commitments which management expects to meet in the ordinary course of business.

As part of the leasehold arrangements with the landowners, the Company will pay royalties of 12.5% to 20% of realized natural gas sales.

The Company has commitments for gathering and firm transportation under existing contracts with third parties. Future payments for these items as of September 30, 2013 totaled $286.2 million (remainder of 2013 – $5.1 million, 2014 –$19.6 million, 2015 – $24.6 million, 2016 – $26.5 million, 2017 – $26.5 million, and thereafter – $183.9 million).

In relation to the above commitments, the Company had deposits of $5.8 million at December 31, 2012, as required by the Company’s natural gas marketer. Deposits of $2.1 million were refunded during the current period, with the remaining $3.7 million recorded as a receivable as of September 30, 2013. As of September 30, 2013, the Company issued letters of credit with Wells Fargo Bank, N.A. of $1.4 million in lieu of these deposits due to increased pipeline capacity needs.

7. Capital Contributions

During 2013, the Company finalized a $300.0 million equity commitment from Natural Gas Partners (“NGP”) of which approximately $200.0 million of NGP’s commitment was funded at closing in April 2013. Cash proceeds from the investment were used to fund Utica Shale leasehold acquisitions in southeastern Ohio.

8. Incentive Units

Rice Energy Appalachia LLC (REA), as the parent company of Rice Drilling B LLC, granted Incentive Units to certain members of management. The Incentive Units are not accounted for as equity instruments as the Incentive Units do not have the characteristics of a substantive class of equity. Rather, the Incentive Units provide the holders with a performance bonus for fair value accretion. In connection with the January 2012 NGP investment in REA, 100,000 Tier I Legacy units, 13,000 Tier II Legacy units, and 17,000 Tier III Legacy units were issued. The Incentive Units will only be paid in cash and payout for each tier occurs when a specified level of cumulative cash distributions has been received by NGP.

In connection with the April 2013 NGP investment in REA, an additional 900,000 Tier I Legacy units, 987,000 Tier II Legacy Units and 983,000 Tier III Legacy Units were issued. In addition, 100,000 New Tier I Units, 100,000 New Tier II Units, 100,000 New Tier III Units, and 100,000 New Tier IV Units were issued. In June 2013, an additional 717,546 New Tier I Units, 577,546 New Tier II Units, 577,546 New Tier III Units, and 577,546 New Tier IV Units were issued to certain members of management. Similar to above, there is no payout of the awards until specified level of cumulative cash distributions has been received by NGP.

During 2012 and 2013, no payments were made in respect of Incentive Units. The Company has not recognized compensation cost on the Incentive Units because the payment conditions, which relate to a liquidity event are not probable at September 30, 2013. The estimated payout under these awards at September 30, 2013 is approximately $146.1 million if a liquidity event were to occur. This estimate is based upon an option pricing model with various Level 3 assumptions including internal business plans that are based on judgments and estimates regarding future economic conditions, costs, inflation rates and discount rates, among other factors. To the extent market transactions are known, this information is factored into the fair value estimate.

F-57

RICE DRILLING B LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

9. Restricted Cash

In accordance with the terms of the Second Lien Term Loan Facility, the Company is prohibited from using $72.0 million in cash designated as restricted for any purposes other than funding the repayment of outstanding Debentures, until the principal amount of the Debentures has been reduced to $5.0 million or less. Restricted cash of $8.3 million is recorded as a current asset as of September 30, 2013, which remains classified as restricted as greater than $5.0 million of principal remains outstanding.

10. Utica Shale Leaseholds

As discussed above, the Company used proceeds from NGP’s equity commitment in the second quarter of fiscal 2013 to fund additional Utica Shale leasehold acquisitions in southeastern Ohio. The Company holds approximately 49,000 net acres in the southeastern core of the Utica Shale, consisting of 43,996 net acres in Belmont County, 1,727 net acres in Guernsey County and 765 net acres in Harrison County. Approximately $232.1 million of the equity commitment has been used to fund leasehold acquisitions in this region as of September 30, 2013.

11. Subsequent Events

On October 14, 2013, the Company entered into a Development Agreement and Area of Mutual Interest (“AMI”) Agreement with Gulfport Energy Corporation (“Gulfport”) covering approximately 50,000 aggregate net acres in the Utica Shale in Belmont County, Ohio. The Company refers to these agreements as “Utica Development Agreements.” Pursuant to the Utica Development Agreements, the Company had approximately 68.80% participating interest in acreage currently owned or to be acquired by the Company or Gulfport located within Goshen and Smith Townships (the “Northern Contract Area”) and an approximately 42.63% participating interest in acreage currently owned or to be acquired by the Company or Gulfport located within Wayne and Washington Townships (the “Southern Contract Area”), each within Belmont County, Ohio. The remaining participating interests are held by Gulfport. The participating interests of the Company and Gulfport in each of the Northern and Southern Contract Areas approximate the Company’s current relative acreage positions in each area.

Every six months during the term of the Development Agreement, the Company and Gulfport will establish a work program and budget detailing the proposed exploration and development to be performed in the Northern and Southern Contract Areas, respectively, for the following six months. The number of horizontal wells proposed to be drilled in each of the Northern Contract Area and Southern Contract Area is limited by the Development Agreement as follows: in 2014, between eight and 40 wells; in 2015, between eight and 50 wells; and thereafter, unlimited.

The Utica Development Agreements have terms of ten years and are terminable upon 90 days’ notice by either party; provided that, with respect to interests included within a drilling unit, such interests shall remain subject to the applicable joint operating agreement and the Company and Gulfport shall remain operators of drilling units located in the Northern AMI and Southern AMI, respectively, following such termination.

On October 15, 2013, the sublimit for letters of credit on the Company’s Senior Secured Revolving Credit Facility with Wells Fargo Bank, N.A. increased from $25.0 million to $50.0 million. This sublimit was then increased to $100.0 million, effective November 5, 2013. On October 23, 2013, the borrowing base on this credit facility was increased from $140.0 million to $155.0 million (refer to Note 3 for further details on the Senior

F-58

RICE DRILLING B LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

11. Subsequent Events – (Continued)

Secured Revolving Credit Facility). There were no other changes to the terms of the agreement. In November and December 2013, the Company drew $50.0 million and $65.0 million, respectively from its Senior Secured Revolving Credit Facility, resulting in availability of approximately $0.5 million.

Subsequent to September 30, 2013, the Company issued additional letters of credit with Wells Fargo Bank, N.A. of $38.1 million (refer to Note 6 for further details on letters of credit as required by the Company’s natural gas marketer).

Subsequent to September 30, 2013, the Company entered into additional contracts with third parties for gathering and firm transportation. Future payments for these items totaled $77.1 million (remainder of 2013 – $0.3 million, 2014 – $5.4 million, 2015 – $6.4 million, 2016 – $11.1 million, 2017 – $11.0 million, and thereafter – $42.9 million).

On December 6, 2013, Rice Energy Inc. entered into a transaction agreement among Rice Energy Inc., Rice C and Foundation PA Coal Company, LLC (“Alpha Holdings”), a wholly owned indirect subsidiary of Alpha Natural Resources, Inc., pursuant to which Rice Energy Inc. will acquire (the “Marcellus JV Buy-In”) Alpha Holdings’ 50% equity interest in our Marcellus joint venture in exchange for aggregate consideration of approximately $300.0 million, consisting of common stock of Rice Energy Inc. and $100.0 million in cash. The Marcellus JV Buy-In is contingent upon the completion of the Rice Energy Inc. initial public offering.

Subsequent events have been considered for disclosure and recognition through December 9, 2013, which is the date the financial statements were available to be issued.

F-59

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholder

Rice Energy Inc.

We have audited the accompanying balance sheet of Rice Energy, Inc. as of October 1, 2013. This balance sheet is the responsibility of the Company’s management. Our responsibility is to express an opinion on this balance sheet based on our audit.

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

In our opinion, the balance sheet referred to above presents fairly, in all material respects, the financial position of Rice Energy, Inc. at October 1, 2013, in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP

Pittsburgh, Pennsylvania

October 3, 2013

F-60

RICE ENERGY INC.

BALANCE SHEET

	October 1, 2013
Assets
Cash and cash equivalents	$	—
Total assets	$	—
Shareholders’ equity
Common stock, $0.01 par value; authorized 1,000 shares; 1,000 issued and outstanding at October 1, 2013	$	10
Less receivable from Rice Drilling B LLC		(10	)
Total shareholders’ equity	$	—

F-61

RICE ENERGY INC.

NOTES TO BALANCE SHEET

1. Nature of Operations

Rice Energy Inc. (“Rice Energy” or “Company”) was formed on October 1, 2013, pursuant to the laws of the State of Delaware to become a holding company whose sole material asset is an equity interest in Rice Drilling B LLC.

2. Summary of Significant Accounting Policies

Basis of Presentation

This balance sheet has been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). Separate Statements of Income, Changes in Stockholder’s Equity and of Cash Flows have not been presented because Rice Energy has had no business transactions or activities to date.

F-62

Independent Auditors’ Report

To the Members of

Countrywide Energy Services, LLC

We have audited the accompanying financial statements of Countrywide Energy Services, LLC, a Pennsylvania limited liability company, (the “Company”), which comprise the balance sheets as of December 31, 2011 and 2012, and the related statements of operations, members’ capital, and cash flows for the period from May 9, 2011 to December 31, 2011 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.

Auditors’ 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 audits 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 auditors’ 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 auditors consider 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 Countrywide Energy Services, LLC as of December 31, 2011 and 2012, and the results of its operations and its cash flows for the period from May 9, 2011 to December 31, 2011 and the year ended December 31, 2012 in accordance with accounting principles generally accepted in the United States of America.

Pittsburgh, Pennsylvania

February 20, 2013

F-63

Countrywide Energy Services, LLC

Balance Sheets

December 31, 2011 and 2012

(in thousands)	NOTES	2011		2012
Assets
Current assets:
Cash	1	$	22	$	152
Accounts receivable, net (less allowance for doubtful accounts of $0.1 million and $0.1 million)	1,5		3,333		1,731
Prepaid expenses and other			65		65
Total			3,420		1,948
Equipment, net	1,2		3,233		2,453
Deposits			107		112
Total		$	6,760	$	4,513
Liabilities and members capital
Current liabilities:
Current maturities of notes payable	3	$	118	$	105
Current maturities of lease obligations	1,4		1,308		665
Accounts payable			1,953		494
Accrued interest	3		9		14
Accrued payroll and related expenses			194		134
Total			3,582		1,412
Long-term liabilities:
Notes payable	3		152		48
Lease obligations	1,4		217		152
Total			3,951		1,612
Members’ capital	1		2,809		2,901
Total		$	6,760	$	4,513

See accompanying Notes to Financial Statements.

F-64

Countrywide Energy Services, LLC

Statements of Operations

For the Period from May 9, 2011 to December 31, 2011 and for the

Year Ended December 31, 2012

(in thousands)	NOTES	2011			2012
Net revenue	1,5	$	9,724		$	8,560
Cost of revenue	4		6,721			6,535
Gross profit			3,003			2,025
Selling, general and administrative expenses	1		1,137			1,623
Income from operations			1,866			402
Other income (expense):
Interest expense	3,4		(16	)		(218	)
Gain (loss) on disposal of equipment			20			(82	)
Other income (expense), net			4			(300	)
Net income		$	1,870		$	102

See accompanying Notes to Financial Statements.

F-65

Countrywide Energy Services, LLC

Statements of Members’ Capital

For the Period from May 9, 2011 to December 31, 2011

and For the Year Ended December 31, 2012

(in thousands)	Contributed Capital		Accumulated Income			Receivable from Member		Total
Balance as of May 9, 2011	$	359	$	586			$         (400)	$	545
Receipt from member		—		—			400		400
Net income		—		1,870			—		1,870
Distributions		—		(6	)		—		(6	)
Balance as of December 31, 2011		359		2,450			—		2,809
Net income		—		102			—		102
Distributions		—		(10	)		—		(10	)
Balance as of December 31, 2012	$	359	$	2,542			$            —	$	2,901

See accompanying Notes to Financial Statements.

F-66

Countrywide Energy Services, LLC

Statements of Cash Flows

For the Period from May 9, 2011 to December 31, 2011 and

For the Year Ended December 31, 2012

(in thousands)	2011			2012
Cash flows from operating activities:
Net income	$	1,870		$	102
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation		276			910
(Gain) loss on sale of equipment		(20	)		82
(Increase) decrease in:
Accounts receivable		(2,252	)		1,603
Prepaid expenses and other assets		(65	)		(6	)
Increase (decrease) in:
Accounts payable		1,088			(1,459	)
Other accrued liabilities		155			(56	)
Net cash provided by operating activities		1,052			1,176
Cash flows from investing activities:
Purchase of equipment		(1,117	)		(152	)
Proceeds from sale of equipment		152			148
Net cash used in investing activities		(965	)		(4	)
Cash flows from financing activities:
Deposit related to capital lease		(107	)		—
Repayment of capital lease obligations		(330	)		(916	)
Repayment of debt		(73	)		(116	)
Receipt from member		400			—
Distributions to members		(6	)		(10	)
Net cash used in financing activities		(116	)		(1,042	)
Net increase (decrease) in cash		(29	)		130
Cash, beginning of period		51			22
Cash, end of period	$	22		$	152
Supplemental disclosures of cash flow information:
Cash paid during the period for interest	$	7		$	213

Supplemental disclosure of noncash investing and financing activities:

During the period from May 9, 2011 to December 31, 2011, the Company financed equipment acquisitions of $2,072 with a note payable of $275 and capital leases of $1,797. Additionally, equipment purchases of $298 were unpaid and included in accounts payable as of December 31, 2011.

During the year ended December 31, 2012, the Company financed equipment acquisitions of $208 with capital leases.

F-67

Countrywide Energy Services, LLC

Notes to Financial Statements

1. Summary of Significant Accounting Policies and Related Matters

Organization and Activity—The Company was organized as a Pennsylvania limited liability company on January 21, 2010. The Company offers a wide-range of roustabout and oil field services to enterprises that are exploring and extracting Pennsylvania’s Marcellus Shale natural gas. These services include logistics, site preparation, maintenance, water transfer, land reclamation and production services.

Prior to the Company’s amended and restated operating agreement dated May 9, 2011, the Company had a sole member. Effective May 9, 2011, a 50% membership interest in the Company was purchased by Rice Drilling B LLC (“Rice Drilling”).

Basis of Accounting—The Company maintains its accounting records on the accrual basis of accounting. Revenues are recognized for services provided or equipment on site based upon daily rates as specified in master service agreements with customers. Expenses are recognized as incurred.

Use of Estimates—The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates. The most significant estimate included in the financial statements relates to the allowance for doubtful accounts. While this estimate incorporated management’s assessment at December 31, 2011 and 2012, it is at least reasonably possible that the allowances will be further revised in the near term and actual results could differ from these estimates.

Comprehensive Income—Comprehensive income consists of net income plus changes in other equity accounts. The Company had no comprehensive income beyond its net income for the period from May 9, 2011 to December 31, 2011 and for the year ended December 31, 2012.

Cash—The Company maintains cash at financial institutions which may at times exceed federally insured amounts and which may at times significantly exceed the balance sheet amount due to outstanding checks.

Accounts Receivable—The Company regularly extends credit to customers for purchases made in the normal course of business based upon management’s assessment of their creditworthiness. 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. Increases in the allowance are charged to general and administrative expenses. Accounts are judged to be delinquent principally based on contractual terms. In estimating the allowance, management considers, among other things, how recently and how frequently payments have been received and the financial position of the customer.

Equipment—Equipment is recorded at cost or the estimated fair market value at date of contribution. Expenditures for major renewals and betterments that extend the useful lives of equipment are capitalized. Expenditures for maintenance and repairs are charged to expense as incurred. Provision for depreciation is computed using the straight-line method based on the estimated useful lives of the assets which range from two to ten years. Equipment under capital lease obligations is depreciated on the straight-line method over the shorter of the lease term or the estimated useful life of the equipment.

The carrying values of long-lived assets, which are limited to equipment, are evaluated periodically in relation to the operating performance of the underlying assets. Adjustments are made if the sum of expected future cash flows is less than book value and, if required, such adjustments would be measured based on discounted cash flows.

F-68

Countrywide Energy Services, LLC

Notes to Financial Statements – (Continued)

1. Summary of Significant Accounting Policies and Related Matters – (Continued)

Income Taxes—The Company is treated as a partnership for federal and state income tax purposes. Consequently, the Company is not subject to income taxes; instead its members include the income in their tax returns.

Subsequent Events—Management has evaluated subsequent events for recognition and disclosure purposes through February 20, 2013, the date the financial statements were available to be issued.

2. Equipment

Equipment consists of the following at December 31, 2011 and 2012 (in thousands):

	2011		2012
Field equipment:
Machinery	$	1,892	$	1,916
Pipe		1,315		1,149
Vehicles and trailers		311		519
Leasehold improvements		29		28
Furniture and fixtures		8		8
Construction in progress		5		—
Total		3,560		3,620
Less accumulated depreciation		327		1,167
Equipment, net	$	3,233	$	2,453

Depreciation expense was $276 and $901 for the period from May 9, 2011 to December 31, 2011 and for the year ended December 31, 2012, respectively. The cost of equipment held under capital leases and accumulated depreciation was $1,773 and $114, respectively, at December 31, 2011, and $1,817 and $458, respectively, at December 31, 2012.

3. Long-Term Debt

Notes payable consist of the following at December 31, 2011 and 2012 (in thousands):

	2011		2012
Promissory note payable due in monthly installments of $8 through June 2014, including interest at 4.41%; secured by vehicles and guaranteed by both members and an individual	$	232	$	142
Vehicle loan payable in monthly installments of $1 through September 2013, including interest at 9.48%; secured by vehicle		19		8
Unsecured promissory note payable to two individuals in monthly installments of $2, including interest at 8%, through February 2013		19		3
Total		270		153
Less current portion		118		105
Long-term notes payable	$	152	$	48

F-69

Countrywide Energy Services, LLC

Notes to Financial Statements – (Continued)

3. Long-Term Debt – (Continued)

Expected aggregate maturities of notes payable subsequent to December 31, 2012 are as follows (in thousands):

2013	$	105
2014		48
Total	$	153

4. Leases

The Company leases equipment under capital leases which expire at various times through October 2015. The following represents the future minimum lease payments under the capital leases and their present value at December 31, 2012 (in thousands):

2013	$	748
2014		64
2015		97
Total minimum lease payments	$	909
Less amount representing interest		92
Present value of net minimum lease payments (including $665 classified as current)	$	817

The capital lease obligations are guaranteed by one or both of the members of the Company.

The Company also leases a garage and the surrounding land under an operating lease that expires in May 2013. Rent expense for this lease was $20 and $31 for the period from May 9, 2011 to December 31, 2011 and for the year ended December 31, 2012, respectively. Future minimum lease payments under this operating lease will be $15 over the next year.

Additionally, the Company rents equipment and vehicles under various short term arrangements. Rental expense for these items was approximately $1,245 and $861 for the period from May 9, 2011 to December 31, 2011 and the year ended December 31, 2012, respectively.

5. Concentrations

The Company provides services to related companies (including Rice Drilling, one of its investees, and one of its subcontractors) which accounted for approximately 60% of revenues for the period from May 9, 2011 to December 31, 2011 and 40% of accounts receivable at December 31, 2011 and 85% of revenues for the year ended December 31, 2012 and 98% of accounts receivable at December 31, 2012.

Two additional customers accounted for approximately 26% of the Company’s revenues for the period from May 9, 2011 to December 31, 2011 and 38% of the Company’s accounts receivable at December 31, 2011.

6. Contingencies

The Company is involved in various litigation matters arising in the normal course of business. Management is not aware of any actions that are expected to have a material adverse effect on its financial position or results of operations.

F-70

Report of Independent Auditors

The Partners of

Alpha Shale Resources, LP

We have audited the accompanying financial statements of Alpha Shale Resources, LP, which comprise the balance sheet as of December 31, 2012, and the related statements of operations, changes in partners’ capital and cash flows for the year then ended, 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 conformity with U.S. generally accepted accounting principles; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free of 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 audit. We conducted our audit in accordance with auditing standards generally accepted in the 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.

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 Alpha Shale Resources, LP at December 31, 2012 and the results of its operations and its cash flows for the year then ended in conformity with U.S. generally accepted accounting principles.

Report of Other Auditors on December 31, 2011 Financial Statements Not Reissued

The financial statements of Alpha Shale Resources, LP for the year ended December 31, 2011, were audited by other auditors whose report dated April 20, 2012, expressed an unqualified opinion on those statements.

/s/ Ernst & Young LLP

Pittsburgh, Pennsylvania

April 19, 2013 (except for Note 3, as to which the date is December 9, 2013)

F-71

ALPHA SHALE RESOURCES, LP

BALANCE SHEETS

	December 31,
(in thousands)	2011		2012
Assets
Current assets:
Cash	$	6,111	$	4,445
Accounts receivable		649		5,716
Receivable from affiliate		26		1
Prepaid expenses and other current		163		108
Total current assets		6,949		10,270
Gas collateral account		—		295
Proved natural gas properties, net		44,383		114,128
Unproved natural gas properties		3,751		—
Property and other equipment, net		88		91
Deferred financing costs, net		—		387
Total assets	$	55,171	$	125,171
Liabilities and partners’ capital
Current liabilities:
Accounts payable	$	8,366	$	18,953
Royalties payable		348		2,082
Accrued capital expenditures		8,823		3,489
Other accrued liabilities		51		1,277
Leasehold payables		—		331
Payable to affiliate		—		8,538
Total current liabilities		17,588		34,670
Long-term liabilities:
Long-term debt		—		29,200
Asset retirement obligations		307		542
Total liabilities		17,895		64,412
Partners’ capital		37,276		60,759
Total liabilities and partners’ capital	$	55,171	$	125,171

See accompanying Notes to Financial Statements.

F-72

ALPHA SHALE RESOURCES, LP

STATEMENTS OF OPERATIONS

	Year Ended December 31,
(in thousands)	2011			2012
Revenue:
Natural gas sales	$	5,744		$	26,284
Operating expenses:
Depreciation, depletion and amortization		2,184			9,411
Amortization of deferred financing costs		—			15
Gathering, compression and transportation		53			6,671
Lease operating		704			3,331
Production taxes and impact fees		—			869
Loss on impairment of natural gas properties		2,592			—
General and administrative expenses		359			2,058
Total expenses		5,892			22,355
Operating income (loss)		(148	)		3,929
Other expenses:
Loss on derivatives		—			(74	)
Interest expense		—			(372	)
Total other expenses		—			(446	)
Net income (loss)	$	(148	)	$	3,483

See accompanying Notes to Financial Statements.

F-73

ALPHA SHALE RESOURCES, LP

STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL

YEARS ENDED DECEMBER 31, 2011 AND 2012

(in thousands)	Managing General Partner		Limited Partners			Total
Balance as of December 31, 2010	$	8	$	7,816		$	7,824
Capital contributions		30		29,570			29,600
Net loss		—		(148	)		(148	)
Balance as of December 31, 2011		38		37,238			37,276
Capital contributions		20		19,980			20,000
Net income		3		3,480			3,483
Balance as of December 31, 2012	$	61	$	60,698		$	60,759

See accompanying Notes to Financial Statements.

F-74

ALPHA SHALE RESOURCES, LP

STATEMENTS OF CASH FLOWS

	December 31,
(in thousands)	2011			2012
Cash flows from operating activities:
Net (loss) income	$	(148	)	$	3,483
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation, depletion and amortization		2,184			9,411
Amortization of deferred financing costs		—			15
Loss on impairment of natural gas properties		2,592			—
(Increase) decrease in:
Accounts receivable		(623	)		(5,067	)
Receivable from affiliate		(26	)		25
Gas collateral account		—			(295	)
Prepaid expenses and other		(123	)		55
Increase (decrease) in:
Accounts payable		7			347
Royalties payable		337			1,734
Other accrued expenses		16			1,188
Payable to affiliate		—			2,499
Net cash provided by operating activities		4,216			13,395
Cash flows from investing activities:
Capital expenditures for natural gas properties		(29,499	)		(63,847	)
Capital expenditures for property and other equipment		—			(12	)
Net cash used in investing activities		(29,499	)		(63,859	)
Cash flows from financing activities:
Proceeds from borrowings		—			29,200
Debt issuance costs		—			(402	)
Capital contributions		29,600			20,000
Net cash provided by financing activities		29,600			48,798
Net increase (decrease) in cash		4,317			(1,666	)
Cash at the beginning of the year		1,794			6,111
Cash at the end of the year	$	6,111		$	4,445
Supplemental disclosure of non-cash investing and financing activities:
Capital expenditures for natural gas properties financed by accounts payable	$	8,357		$	18,597
Capital expenditures for natural gas properties financed by other accrued liabilities		8,823			3,489
Capital expenditures for natural gas properties financed by affiliate payable		—			6,038
Natural gas properties financed through deferred payment obligations		—			331
Recognition of legal liability for asset retirement obligations		68			138

See accompanying Notes to Financial Statements.

F-75

ALPHA SHALE RESOURCES, LP

NOTES TO FINANCIAL STATEMENTS

DECEMBER 31, 2011 AND 2012

1. Summary of Significant Accounting Policies and Related Matters

Organization and Operations

These financial statements present the activities for Alpha Shale Resources, LP (hereinafter referred to as the “Partnership”). The Partnership was organized as a limited partnership in accordance with the laws of the State of Delaware on February 3, 2010 (date of inception) through funding from its limited partners, Foundation PA Coal Company, LLC (“Alpha Holdings”), and Rice Drilling C, LLC (“Rice C”) which is a wholly owned subsidiary of Rice Drilling B, LLC (“Rice Drilling B”), and its managing general partner, Alpha Shale Holdings, LLC (“Holdings”). According to the terms of the limited partnership agreement, revenues, costs and cash distributions of the Partnership are allocated 49.95% each to Alpha Holdings and Rice C and 0.10% to Holdings.

The Partnership is engaged primarily in the acquisition, exploration, development, production and sale of natural gas in the Marcellus Shale region of Southwestern Pennsylvania. The Partnership sells its natural gas products solely to a natural gas marketing customer, which accounts for 100% of its accounts receivable as of December 31, 2011 and 2012, and 100% of its sales for the years ended December 31, 2011 and 2012. Natural gas sales included in the statements of operations consist of sales from six horizontal wells.

Use of Estimates

The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates and changes in these estimates are recorded when known.

Revenue Recognition

Sales of natural gas are recognized when natural gas has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured, and the sales price is fixed or determinable. Natural gas is sold by the Partnership under contract with the Partnership’s natural gas marketer and only current customer. Pricing provisions are tied to the Platts Gas Daily market prices.

Cash

The Partnership maintains cash at financial institutions which may at times exceed federally insured amounts and which may at times significantly exceed balance sheet amounts due to outstanding checks. The Partnership has no other accounts that are considered cash equivalents.

Accounts Receivable

Accounts receivable are primarily from the Partnership’s sole gas marketer. The Partnership extends credit to parties in the normal course of business based upon management’s assessment of their creditworthiness. 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. There was no allowance recorded for any of the periods presented in the financial statements.

F-76

ALPHA SHALE RESOURCES, LP

NOTES TO FINANCIAL STATEMENTS – (Continued)

1. Summary of Significant Accounting Policies and Related Matters – (Continued)

Natural Gas Properties

The Partnership uses the successful efforts method of accounting for gas-producing activities. Costs to acquire mineral interests in natural gas properties, to drill and equip exploratory wells that result in proved reserves are capitalized. Costs to drill exploratory wells that do not identify proved reserves as well as geological and geophysical costs and cost of carrying and retaining unproved properties are expensed.

Unproved natural gas properties that are individually significant are periodically assessed for impairment of value, and a loss is recognized at the time of impairment by providing an impairment allowance. Management determined that no impairment allowance was necessary at December 31, 2011 and 2012. Capitalized costs of producing natural gas properties and support equipment directly related to such properties, after considering estimated residual salvage values, are depreciated and depleted by the unit-of-production method. Support equipment and other property and equipment not directly related to natural gas properties are depreciated over their estimated useful lives.

The Partnership assesses its proved natural gas properties for possible impairment on an annual basis, as events or changes in circumstances indicate that the carrying amount of an asset might not be recoverable. During 2011, it was decided by the Operating Committee of the Partnership not to complete two vertical wells that had previously commenced drilling. As such, an impairment charge of approximately $2.6 million was recorded during the year ended December 31, 2011. Management determined that no impairment allowance was necessary at December 31, 2012.

Partnership estimates of proved reserves are based on quantities of natural gas that engineering and geological analysis demonstrates, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic conditions. External engineers prepare the annual reserve and economic evaluation of all properties on a well-by-well basis. Additionally, the Partnership adjusts natural gas reserves for major well rework or abandonment during the year as needed. The process of estimating and evaluating natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, revisions in existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates represent the Partnership’s most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates over time. Because estimates of reserves significantly affect the Partnership’s depreciation, depletion and amortization expense, as well as its impairment assessment of proved properties, a change in the Partnership’s estimated reserves could have a material effect on the Partnership’s net income or loss.

On the sale of an entire interest in an unproved property for cash, a gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained unless the proceeds received are in excess of the cost basis which would result in gain on sale.

F-77

ALPHA SHALE RESOURCES, LP

NOTES TO FINANCIAL STATEMENTS – (Continued)

1. Summary of Significant Accounting Policies and Related Matters – (Continued)

Interest

The Partnership capitalizes interest on expenditures for significant exploration and development projects while activities are in progress to bring the assets to their intended use. The following table summarizes the components of the Partnership’s interest incurred for the year indicated (in thousands):

	2012
Interest capitalized	$	143
Interest expensed		372
Total incurred	$	515

Property and Other Equipment

Property and other equipment is recorded at cost and is being depreciated over estimated useful lives of five to fifteen years on a straight-line basis. Accumulated depreciation was $1 thousand and $9 thousand at December 31, 2011 and 2012, respectively. Depreciation expense was $1 thousand and $8 thousand for the years ended December 31, 2011 and 2012, respectively, and is included in depreciation, depletion and amortization expense in the accompanying statements of operations.

Long-Lived Assets

Long-lived assets to be held and used or disposed of other than by sale are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. When required, impairment losses on assets to be held and used or disposed other than by sale are recognized based on the fair value of the asset. Long-lived assets to be disposed of by sale are reported at the lower of their carrying amount or fair value less selling costs.

Deferred Financing Costs

Deferred financing costs are amortized on a straight-line basis over the term of the related agreement. Accumulated amortization was $0 and $15 thousand at December 31, 2011 and 2012, respectively. Amortization expense was $0 and $15 thousand for the years ended December 31, 2011 and 2012, respectively. The annual amortization of deferred financing costs for years subsequent to December 31, 2012 is expected to be $82 thousand through 2016 and $59 thousand in 2017.

Asset Retirement Obligations

The Partnership records the fair value of a legal liability for an asset retirement obligation in the period in which it is incurred. For gas properties, this is the period in which a gas well is acquired or drilled. The Partnership’s retirement obligations relate to the abandonment of gas-producing facilities and include costs to dismantle and relocate or dispose of the production platforms, gathering systems, wells and related structures. Estimates are based on historical experience in plugging and abandoning wells and estimated remaining lives of those wells based on reserve estimates.

When a new liability is recorded, the Partnership capitalizes the costs of the liability by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value each period and the capitalized cost is depreciated over the units of production basis.

F-78

ALPHA SHALE RESOURCES, LP

NOTES TO FINANCIAL STATEMENTS – (Continued)

1. Summary of Significant Accounting Policies and Related Matters – (Continued)

Lease Obligations

The Partnership leases drilling rights under agreements which expire at various times. As of December 31, 2012, future minimum lease payments under these agreements expected to be paid during 2013 are $0.3 million and are included as leasehold payables in the accompanying balance sheets.

Income Taxes

The Partnership is treated as a limited partnership for federal and state income tax purposes. Consequently, the Partnership is not subject to income taxes; instead its partners include the income in their tax returns.

2. Capitalized Costs Relating to Natural Gas-Producing Activities

Proved and unproved capitalized costs related to the Partnership’s natural gas-producing activities are as follows (in thousands):

	December 31,
	2011		2012
Capitalized costs:
Unproved properties	$	3,752	$	—
Proved, producing properties		18,728		50,437
Proved, non-producing properties		27,898		75,338
Total		50,378		125,775
Accumulated depreciation, depletion and amortization		2,244		11,647
Net capitalized costs	$	48,134	$	114,128

3. Supplemental Information on Gas-Producing Activities (Unaudited)

Costs incurred for property acquisitions, exploration and development for the years ended December 31, 2011 and 2012 are as follows (in thousands):

	For the years  ended December 31,
	2011		2012
Acquisitions:
Unproved leaseholds	$	1,038	$	—
Development costs		43,400		93,450
Exploration costs:		—		—
Geological and geophysical		—		—
Total costs incurred	$	44,438	$	93,450

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ALPHA SHALE RESOURCES, LP

NOTES TO FINANCIAL STATEMENTS – (Continued)

3. Supplemental Information on Gas-Producing Activities (Unaudited) – (Continued)

The following table presents the results of operations related to natural gas production (in thousands):

	For the years  ended December 31,
	2011		2012
Revenues	$	5,744	$	26,284
Production costs		758		10,872
Impairment of gas properties		2,592		—
Depreciation, depletion and accretion		2,184		9,404
General and administrative expenses		—		1,972
Results of operations from producing activities	$	210	$	4,036

Reserve quantity information for the years ended December 31, 2011 and 2012 is as follows (in thousands):

	2011			2012
Proved developed and undeveloped reserves:
Beginning of year		—			116,206
Extensions and discoveries		117,600			196,238
Revision of previous estimates		—			(47,616	)
Production		(1,394	)		(8,592	)
End of year		116,206			256,236
Proved developed reserves:
End of year		28,948			70,026
Proved developed reserves:
End of year		87,258			186,210

The Partnership added 117,600 MMcf and 196,238 MMcf through its drilling program in the Marcellus Shale in 2011 and 2012. In 2012, the Partnership had net negative revisions of 47,616 MMcf, due primarily to declines in natural gas pricing.

Information with respect to estimated discounted future net cash flows related to its proved natural gas reserves as of December 31, is as follows (in thousands):

	2011			2012
Future cash inflows	$	504,768		$	728,314
Future production costs		(59,366	)		(254,172	)
Future development costs		(103,764	)		(172,426	)
Future net cash flows		341,638			301,716
10% annual discount for estimated timing of cash flows		(200,464	)		(159,562	)
Standardized measure of discounted future net cash flows	$	141,174		$	142,154

For 2012, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2012, adjusted for energy content and a regional price differential. For 2012, this adjusted gas price was $2.84 per Mcf.

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ALPHA SHALE RESOURCES, LP

NOTES TO FINANCIAL STATEMENTS – (Continued)

3. Supplemental Information on Gas-Producing Activities (Unaudited) – (Continued)

For 2011, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2011, adjusted for energy content and a regional price differential. For 2011, this adjusted gas price was $4.34 per Mcf.

The following is the principal sources of changes in the standardized measure of discounted future net cash flows (in thousands):

	2011			2012
Balance at beginning of period	$	—		$	141,174
Net change in prices and production costs		—			(53,710	)
Net change in future development costs		—			(524	)
Natural gas net revenues		(4,988	)		(15,414	)
Extensions		146,162			76,262
Revisions of previous quantity estimates		—			(57,846	)
Previously estimated development costs incurred		—			25,724
Accretion of discount		—			14,118
Changes in timing and other		—			12,370
Balance at end of period	$	141,174		$	142,154

4. Long-Term Debt

The Partnership had long-term debt outstanding as of December 31, 2012 as follows (in thousands):

Promissory note payable (“Wells Fargo Credit Facility”) to Wells Fargo Bank, N.A. (“Wells Fargo”) with maximum borrowings not to exceed $200.0 million; borrowing base of $35.0 million at December 31, 2012; payable at maturity with interest only due in monthly installments at the higher of the prime rate, the federal funds rate plus 0.5% or the adjusted LIBOR plus 1% (the effective rate was 2.46% at December 31, 2012); all unpaid balances are due September 7, 2017; secured by substantially all assets of the Partnership (see below)	$	29,200
Total long-term debt	$	29,200

Wells Fargo Credit Facility

On September 7, 2012, the Partnership entered into a credit agreement with Wells Fargo. The maximum credit amount allowed under the promissory note agreement is $200.0 million. The Wells Fargo Credit Facility provides for borrowings to be used for the purpose of funding capital expenditures related to the Partnership’s drilling program, providing working capital for lease acquisitions, exploration and production operations, and development (including the drilling and completion of producing wells), and for general business purposes, including fees and expenses. The Wells Fargo Credit Facility is subject to a maximum borrowing base equal to the maximum value, for credit purposes, of the subject properties as determined by Wells Fargo in accordance with its customary lending practices. The borrowing base is determined by the lenders on a quarterly basis and such determination is primarily based upon the value of the Partnership’s proved developed reserves. If the lenders were to decrease the borrowing base below the amounts outstanding under the facility, the Partnership would have to repay these amounts within 30 days, repay these amounts in six monthly installments, or add sufficient collateral value. The borrowing base as of December 31, 2012 was $35.0 million with approximately $5.8 million undrawn at that date.

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ALPHA SHALE RESOURCES, LP

NOTES TO FINANCIAL STATEMENTS – (Continued)

4. Long-Term Debt – (Continued)

The Wells Fargo Credit Facility is subject to certain covenants which are ordinary to such credit facilities and include, among other things, minimum financial ratios, restrictions as to additional debt and changes to the Partnership’s structure. As of December 31, 2012, certain financial covenants specified by the credit agreement had not been met. Wells Fargo has waived such non-compliance as of December 31, 2012. Based upon current projections, the Partnership believes it will be in compliance with all debt covenants through January 1, 2014.

Interest paid in cash was $0 and $0.1 million for the years ended December 31, 2011 and 2012, respectively. See Note 1 for information on capitalized interest.

5. Fair Value of Financial Instruments

The Partnership determines fair value on a recurring basis for its liability related to its derivative instruments as the liability is required to be recorded at fair value each reporting period. Fair value is based on quoted market prices, where available. If quoted market prices are not available, fair value is based upon models that use as inputs market-based parameters, including but not limited to forward curves, discount rates, broker quotes, volatilities, and nonperformance risk.

The Partnership has categorized its fair value measurements into a three-level fair value hierarchy, based on the priority of the inputs to the valuation technique. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets and liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). All of the Partnership’s fair value measurements are included in Level 2. Since the adoption of fair value accounting, the Partnership has not made any changes to its classification of financial instruments in each category.

Items included in Level 2 are valued using third-party quotes that result in management’s best estimate of fair value.

The following items were measured at fair value on a recurring basis during the period (in thousands):

	December 31, 2012		Fair Value Measurements at Reporting Date Using
Description			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Liabilities:
Derivative Instruments, at fair value	$	138	$	—	$	138	$	—
Total liabilities	$	138	$	—	$	138	$	—

The carrying amount of cash, receivables and accounts payable approximate their fair value due to the short-term nature of such instruments.

The Partnership reviews long-lived assets, including natural gas properties, for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets might not be recoverable. If the estimated undiscounted cash flows for a particular asset are not sufficient to cover the asset’s carrying value, it is impaired and the carrying value is reduced to the asset’s current fair value. These fair value measurements fall within Level 3 of the fair value hierarchy. During 2011, the Partnership determined that certain natural gas properties were impaired, resulting in an impairment charge of approximately $2.6 million. The impairment charge reduced the remaining carrying value of these properties to their aggregate fair value of $0. No impairment was recorded during 2012.

F-82

ALPHA SHALE RESOURCES, LP

NOTES TO FINANCIAL STATEMENTS – (Continued)

5. Fair Value of Financial Instruments – (Continued)

The estimated fair value of long-term debt on the balance sheet at December 31, 2012 is shown in the table below (in thousands). The fair value was estimated using Level 3 inputs based on rates reflective of the remaining maturity as well as the Partnership’s financial position.

Description	December 31, 2012
Long-term debt, at fair value:
Wells Fargo Credit Facility	$	29,200
Total	$	29,200

6. Asset Retirement Obligations

The Partnership is subject to certain legal requirements which result in recognition of a liability related to the obligation to incur future plugging and abandonment costs. The Partnership records a liability for such asset retirement obligations and capitalizes a corresponding amount for asset retirement costs. The liability is estimated using the present value of expected future cash flows, adjusted for inflation and discounted at the Partnership’s credit adjusted risk-free rate. No wells were plugged or abandoned during 2012, nor were there any changes to assumptions. A reconciliation of the beginning and ending aggregate carrying amount of asset retirement obligations for the years ended December 31, 2011 and 2012 is as follows (in thousands):

Balance at December 31, 2010	$	235
Liabilities incurred		67
Accretion expense		5
Balance at December 31, 2011		307
Liabilities incurred		138
Accretion expense		97
Balance at December 31, 2012	$	542

7. Partners’ Capital

The Partnership consists of three partners: Holdings, which is the managing general partner, and Alpha Holdings and Rice C, the limited partners. The Partnership authorized and issued 10,000 units during 2010. In February 2010, Holdings contributed $6 thousand for 10 units, or a 0.10% ownership, and Alpha Holdings and Rice C each contributed $3.0 million for 4,995 shares, or 49.95% ownership each.

Since inception, the three partners have continued to make additional contributions into the Partnership, in accordance with ownership percentages, and no additional units were issued as depicted on the statements of changes in partners’ capital.

8. Derivative Instruments

The Partnership uses derivative commodity instruments that are placed with major financial institutions whose creditworthiness is regularly monitored. As of December 31, 2012, the Partnership has a $3.465 swap contract for 10,000 MMBTU per day and a $3.580 swap contract for 10,000 MMBTU per day with Wells Fargo. Both contracts have an expiration date of December 31, 2013. All derivative contracts are carried at their fair value on the balance sheets. Both realized and unrealized gains and losses are recorded as a gain or loss on

F-83

ALPHA SHALE RESOURCES, LP

NOTES TO FINANCIAL STATEMENTS – (Continued)

8. Derivative Instruments – (Continued)

derivatives in the statements of operations under other income/expense. Unrealized losses were $138 thousand for the year ended December 31, 2012. The Partnership had realized gains related to contract settlements of $64 thousand for the year ended December 31, 2012.

9. Commitments and Contingencies

The Partnership is involved in various litigation matters arising in the normal course of business. Management is not aware of any actions that are expected to have a material adverse effect on its financial position or results of operations.

The Partnership has drilling commitments which management expects to meet in the ordinary course of business.

As part of the leasehold arrangements with landowners, the Partnership will pay royalties of 12.5% to 20%.

10. Related-Party Transactions

During 2011, management services were provided by related entities; however, the partners agreed to waive charging a fee to the Partnership for these services for 2011. During the year ended December 31, 2012, the Partnership was billed for management services provided in the amount of $1.3 million, which is included with general and administrative expenses on the statements of operations. At December 31, 2012, $8.5 million of costs were due to related entities and are recorded as payable to affiliate on the balance sheets. Included in this amount is $6.0 million relating to capitalized costs that were approved to be contributed from related entities.

11. Subsequent Events

In January 2013, the Partnership borrowed an additional $4.5 million under its Wells Fargo Credit Facility. Subsequent to this transaction the borrowing base was increased by $45.0 million to $80.0 million and the Partnership borrowed an additional $19.3 million in March 2013.

Except for Note 3, subsequent events have been considered for disclosure and recognition through April 19, 2013, the same date the financial statements were available to be issued.

F-84

INDEPENDENT AUDITORS’ REPORT

To the Partners of

Alpha Shale Resources, LP

Canonsburg, Pennsylvania

We have audited the accompanying balance sheet of Alpha Shale Resources, LP (Partnership) as of December 31, 2011 and the related statements of operations, changes in partners’ capital and cash flows, for the year ended December 31, 2011. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

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

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Alpha Shale Resources, LP as of December 31, 2011 and the results of its operations and its cash flows for the year ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America.

/s/ Schneider Downs & Co., Inc.

Pittsburgh, Pennsylvania

April 20, 2012

F-85

ALPHA SHALE RESOURCES, LP

BALANCE SHEET

(in thousands)	December 31, 2011
Assets
Current assets:
Cash and cash equivalents	$	6,111
Accounts receivable		649
Due from general partner		26
Prepaids and other current assets		163
Total current assets		6,949
Natural gas properties, net		48,222
Total assets	$	55,171
Liabilities and partners’ capital
Current liabilities:
Accounts payable	$	8,366
Accrued capital expenses		8,823
Revenues payable		348
Other accrued expenses		51
Total current liabilities		17,588
Long-term liabilities:
Asset retirement obligations		307
Partners’ capital
Managing general partner		38
Limited partners		37,238
Total partners’ capital		37,276
Total liabilities and partners’ capital	$	55,171

See accompanying Notes to Financial Statements.

F-86

ALPHA SHALE RESOURCES, LP

STATEMENT OF OPERATIONS

FOR THE YEAR ENDED DECEMBER 31, 2011

(in thousands)	2011
Revenues:
Natural gas sales	$	5,744
Costs and expenses:
Natural gas production costs		757
Depreciation, depletion and amortization		2,184
Loss on impairment of oil and gas properties		2,592
General and administrative expenses		359
		5,892
Net loss	$	(148	)

See accompanying Notes to Financial Statements.

F-87

ALPHA SHALE RESOURCES, LP

STATEMENT OF CHANGES IN PARTNERS’ CAPITAL

FOR THE YEAR ENDED DECEMBER 31, 2011

(in thousands)	Managing General Partner		Limited Partners			Total Capital
Balance as of December 31, 2010	$	8	$	7,816		$	7,824
Capital contributions		30		29,570			29,600
Net loss		—		(148	)		(148	)
Balance as of December 31, 2011	$	38	$	37,238		$	37,276

See accompanying Notes to Financial Statements.

F-88

ALPHA SHALE RESOURCES, LP

STATEMENT OF CASH FLOWS

FOR THE YEAR ENDED DECEMBER 31, 2011

(in thousands)	2011
Cash flows from operating activities:
Net loss	$	(148	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		2,184
Loss on impairment of natural gas properties		2,592
Changes in assets and liabilities:
Accounts receivable		(649	)
Prepaid and other assets		(123	)
Accounts payable		7
Accrued expenses		353
Net cash provided by operating activities		4,216
Cash flows from investing activities:
Purchase and development of natural gas properties		(29,499	)
Cash flows from financing activities:
Capital contributions		29,600
Net Increase In Cash And Cash Equivalents		4,317
Cash and cash equivalents:
Beginning of year		1,794
End of year	$	6,111
Supplemental schedule of noncash investing and financing activities
Capital expenditures for natural gas properties financed by accounts payable and accrued expenses	$	14,939
Asset retirement obligation, with a corresponding increase to natural gas properties	$	68

See accompanying Notes to Financial Statements.

F-89

ALPHA SHALE RESOURCES, LP

NOTES TO FINANCIAL STATEMENTS

DECEMBER 31, 2011

1.   Organization and Operations

These financial statements present the activities for Alpha Shale Resources, LP (hereinafter referred to as the Partnership). The Partnership was organized as a limited partnership in accordance with the laws of the State of Delaware on February 3, 2010 (date of inception) through funding from its limited partners, Foundation PA Coal Company, LLC (Alpha Holdings), and Rice Drilling C, LLC (Rice Drilling C) and its managing general partner, Alpha Shale Holdings, LLC (Holdings). According to the terms of the limited partnership agreement, revenues, costs and cash distributions of the Partnership are allocated 49.95% each to Alpha Holdings and Rice Drilling C and 0.10% to Holdings.

Alpha is engaged primarily in the acquisition, exploration, development, production and sale of natural gas. Drilling is engaged in the tendering of natural gas wells in the Marcellus Shale region of Southwestern Pennsylvania. The Partnership sells its natural gas products solely to a natural gas marketing customer, which accounts for 100% of its accounts receivable as of December 31, 2011, and 100% of its sales for the year ended December 31, 2011. Natural gas sales included in the statement of operations consist of sales for one horizontal well, which was in production from May 2011 through December 31, 2011.

2.   Summary of Significant Accounting Policies

A summary of significant accounting policies consistently applied by management in the preparation of the accompanying financial statements follows:

Use of Estimates. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Natural Gas Properties. The Partnership uses the successful efforts method of accounting for gas-producing activities. Costs to acquire mineral interests in natural gas properties, drill and equip exploratory wells that find proved reserves, and drill and equip development wells and related asset retirement costs are capitalized. Depletion is based on cost less estimated salvage value using the unit-of-production method. The process of estimating and evaluating natural gas reserves is complex, requiring significant decisions in the evaluation of geological, geophysical, engineering and economic data. Costs to drill exploratory wells that do not find proved reserves, geological and geophysical costs, and costs of carrying and retaining unproved properties are expensed.

Partnership estimates of proved reserves are based on quantities of natural gas that engineering and geological analysis demonstrates, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic conditions. The petroleum engineers prepare the annual reserve and economic evaluation of all properties on a well-by-well basis. Additionally, the Partnership adjusts natural gas reserves for major well rework or abandonment during the year as needed. The process of estimating and evaluating natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, revisions in existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates represent the Partnership’s most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates over time. Because estimates of reserves significantly affect the Partnership’s depreciation, depletion and amortization expense, a change in the Partnership’s estimated reserves could have a material effect on the Partnership’s net income.

F-90

ALPHA SHALE RESOURCES, LP

NOTES TO FINANCIAL STATEMENTS

DECEMBER 31, 2011 – (Continued)

2.   Summary of Significant Accounting Policies – (Continued)

Unproved natural gas properties that are individually significant are periodically assessed for impairment of value, and a loss is recognized at the time of impairment by providing an impairment allowance. Management determined that no impairment allowance was necessary at December 31, 2011. Unproved natural gas properties approximated $3.8 million at December 31, 2011. Capitalized costs of producing natural gas properties, after considering estimated residual salvage values, are depreciated and depleted by the unit-of-production method. Support equipment and other property and equipment are depreciated over their estimated useful lives. Wells in progress approximated $27.8 million at December 31, 2011.

The Partnership assesses its proved natural gas properties for possible impairment on an annual basis, as events or changes in circumstances indicate that the carrying amount of an asset might not be recoverable. During 2011, it was decided by the Operating Committee of the Partnership not to complete two vertical wells that had previously been drilled. As such, an impairment charge of approximately $2.6 million was recorded during the period ended December 31, 2011.

On the sale of an entire interest in an unproved property for cash or cash equivalent, gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained.

Revenue Recognition. Sales of natural gas are recognized when natural gas has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured, and the sales price is fixed or determinable. Natural gas is sold by the Partnership under contract with the Partnership’s natural gas marketer and only current customer. All of the Partnership contracts’ pricing provisions are tied to Platts Gas Daily market prices. As a result, the Partnership’s revenue from the sale of natural gas will suffer if market prices decline and benefit if they increase. The Partnership believes that the pricing provisions of its natural gas contracts are customary in the industry.

Cash and Cash Equivalents. The Partnership maintains cash that might exceed federally insured amounts at times. The Partnership considers all items purchased with a maturity of three months or less and all interest-bearing money market funds to be cash and cash equivalents.

Accounts Receivable. The Partnership performs ongoing credit evaluations of its customer and does not require collateral. Provisions are made for estimated uncollectible trade accounts receivable. The Partnership’s estimate is based on historical collection experience, a review of current status of trade receivables and judgment. Decisions to charge-off receivables are based on management’s judgment after consideration of facts and circumstances surrounding potential uncollectible accounts. Management determined that no allowance was necessary at December 31, 2011.

Asset Retirement Obligations. The Partnership accounts for its asset retirement obligations, plugging costs, as required by the Asset Retirement and Environmental Obligations topic of the Financial Accounting Standards Board (FASB) Accounting Standards Codification (Codification or ASC), which requires that the fair value of an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The present value of the estimated asset retirement costs is capitalized as part of the carrying amount of the long-lived asset. For the Partnership, asset retirement obligations primarily relate to the abandonment of natural gas-producing facilities and are accreted over the estimated life of the related asset, for

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ALPHA SHALE RESOURCES, LP

NOTES TO FINANCIAL STATEMENTS

DECEMBER 31, 2011 – (Continued)

2.   Summary of Significant Accounting Policies – (Continued)

the change in present value. The initial capitalized costs are depleted over the useful lives of the related asset, through charges to depreciation, depletion and amortization expense. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from revisions of estimated inflation rates, escalating retirement costs and changes in the estimated timing of settling asset retirement obligations.

The estimated liability is based on historical experience in plugging and abandoning wells, estimated remaining lives of those based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future, and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted, risk-free interest rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs or remaining lives of the wells, or if federal or state regulations enact new plugging and abandonment requirements. The Partnership has a $25 thousand bond deposit, legally restricted for purposes of settling asset retirement obligations in the Commonwealth of Pennsylvania. This bond deposit is included in prepaid and other assets.

A reconciliation of the Partnership’s liability for well plugging and abandonment costs as of December 31, 2011 is as follows (in thousands):

Asset retirement obligations, beginning of year	$	235
Additions		67
Accretion expense		5
Asset retirement obligations, end of year	$	307

The accretion expense relative to the asset retirement obligations is included on the statements of operations under the caption depreciation, depletion and amortization.

Income Taxes. The Partnership is organized as a limited partnership and is not subject to federal or state income taxes. Accordingly, no provision has been made for current or deferred income taxes in these financial statements. The taxable income of the Partnership is included in the tax return of the individual partners. In addition, the Partnership has not identified any material uncertain tax positions requiring an accrual or disclosure in the financial statements. The Partnership accrues interest and penalties related to unrecognized tax benefits in income tax expense. Additionally, the Partnership’s U.S. Federal income tax return filed for 2010 remains subject to examination by the Internal Revenue Service (IRS).

Recent Accounting Pronouncements. In January 2010, the FASB issued the Accounting Standards Update (ASU), Fair Value Measurements Disclosures, to require new disclosures for fair value measurements and to provide clarification for existing disclosure requirements. More specifically, this update will require (1) an entity to disclose separately the amounts of significant transfers in and out of Levels I and 2 fair value measurements and to describe the reasons for the transfers; and (2) information about purchases, sales, issuances and settlements to be presented separately on a gross basis rather than net, in the reconciliation for fair value measurements using significant unobservable inputs (Level 3 inputs). The ASU clarifies existing disclosure requirements for the level of disaggregation used for classes of assets and liabilities measured at fair value and requires disclosures about the valuation techniques and inputs used to measure fair value for both recurring and nonrecurring fair value measurements using Level 2 and Level 3 inputs. The adoption of the ASU by the Partnership did not materially impact or expand its financial statement footnote disclosures.

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ALPHA SHALE RESOURCES, LP

NOTES TO FINANCIAL STATEMENTS

DECEMBER 31, 2011 – (Continued)

3.   Natural Gas Properties

Natural gas properties at December 31, 2011 consist of the following (in thousands):

	2011
Unproved properties	$	3,843
Proved and producing		18,691
Natural gas properties, successful efforts method, at cost		22,534
Less—Accumulated depreciation, depletion and amortization		2,210
		20,324
Natural gas properties in progress		27,898
Total Natural Gas Properties	$	48,222

Included in proved and producing are the estimated costs associated with the Partnership’s asset retirement obligations discussed in Note 2, which approximated $0.3 million at December 31, 2011.

4.   Partners’ Capital

The Partnership consists of three partners: Holdings, which is the managing general partner, and Alpha Holdings and Rice Drilling C, the limited partners. The Partnership authorized and issued 10,000 units during 2010. In February 2010, Holdings contributed $6 thousand for 10 units, or a 0.10% ownership, and Alpha Holdings and Rice Drilling C each contributed $3.0 million for 4,995 shares, or 49.95% ownership each.

In November 2010, the Partnership had an additional capital call amounting to $4.0 million, of which $4 thousand was contributed by Holdings; and Alpha Holdings and Rice Drilling C contributed $2.0 million each, in line with ownership percentages; and no additional units were issued.

During 2011, the three partners continued to make contributions into Alpha, in line with ownership percentages, and no additional units were issued as depicted on the Statement of Changes in Partners’ Capital.

5.   Contingencies

The Partnership is involved in various legal proceedings arising out of the normal conduct of its business. In the opinion of management, the ultimate resolution of such matters will not have a material effect on the financial position or results of operations of the Partnership.

The Partnership is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Partnership has established procedures for the ongoing evaluation of its operations, to identify potential environmental exposures and to comply with regulatory policies and procedures.

The Partnership accounts for environmental contingencies in accordance with the Contingencies topic of the FASB Codification. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, and do not contribute to current or future revenue generation, are expensed. Liabilities are recorded when environmental assessment and/or cleanup is probable, and the costs can be reasonably estimated. The Partnership maintains insurance that may cover in whole or in part certain environmental expenditures. At December 31, 2011, the Partnership had no environmental contingencies requiring specific disclosure or accrual.

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ALPHA SHALE RESOURCES, LP

NOTES TO FINANCIAL STATEMENTS

DECEMBER 31, 2011 – (Continued)

6.   Related-Party Activity

During 2011, management services were provided by related entities to the Partnership; however, the partners agreed to waive charging a fee to Alpha for these services for 2011.

During the year ended December 31, 2011, the Partnership incurred expenses relative to the development and production of natural gas properties with related parties amounting to approximately $0.5 million.

Amounts due to partners and related parties approximated $33 thousand at December 31, 2011.

7.   Fair Value Measurements

Fair value measurement requires disclosures that categorize assets and liabilities measured at fair value into one of three different levels depending on the assumptions (i.e., inputs) used in the valuation. Level 1 provides the most reliable measure of fair value, while Level 3 generally requires significant management judgment: Financial assets and liabilities are classified in their entirety based on the lowest level of input significant to the fair value measurement. The fair value hierarchy is defined as follows:

Level 1—Valuations are based on unadjusted quoted prices in active markets for identical assets or liabilities.

Level 2—Valuations are based on quoted prices for similar assets or liabilities in active markets, or quoted prices in markets that are not active for which significant inputs are observable, either directly or indirectly.

Level 3—Valuations are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. Inputs reflect management’s best estimate of what market participants would use in valuing the asset or liability at the measurement date.

At December 31, 2011, the Partnership’s financial instruments consist primarily of cash, accounts receivable and accounts payable. The carrying amount of cash, receivables and accounts payable approximate their fair value due to the short-term nature of such instruments.

The Partnership reviews long-lived assets, including natural gas properties, for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets might not be recoverable. If the estimated undiscounted cash flows for a particular asset are not sufficient to cover the asset’s carrying value, it is impaired and the carrying value is reduced to the asset’s current fair value. These fair value measurements fell within Level 3 of the fair value hierarchy. During 2011, the Partnership determined that certain natural gas properties were impaired, resulting in an impairment charge of $2.6 million. The impairment charge reduced the remaining carrying value of these properties to their aggregate fair value of approximately $0 at December 31, 2011.

8.   Subsequent Events

Subsequent events are defined as events or transactions that occur after the balance sheet date, but before the financial statements are issued or are available to be issued. Management has evaluated subsequent events through April 20, 2012, the date on which the financial statements were available to be issued and noted that there was an additional capital contribution in February 2012 in the amount of $12.0 million.

F-94

ALPHA SHALE RESOURCES, LP

BALANCE SHEETS

			(Unaudited)
(in thousands)	December 31, 2012		September 30, 2013
Assets
Current assets:
Cash	$	4,445	$	3,832
Accounts receivable		5,716		8,006
Receivable from affiliate		1		252
Prepaid expenses and other		108		87
Derivative assets		—		9,619
Total current assets		10,270		21,796
Proved natural gas properties, net		114,128		166,546
Property and other equipment, net		91		85
Deferred financing costs, net		387		828
Other non-current assets		295		3,077
Total assets	$	125,171	$	192,332
Liabilities and partners’ capital
Current liabilities:
Accounts payable	$	18,953	$	6,401
Royalties payable		2,082		4,696
Accrued capital expenditures		3,489		3,381
Other accrued liabilities		1,277		973
Leasehold payables		331		69
Payable to affiliate		8,538		4,732
Total current liabilities		34,670		20,252
Long-term liabilities:
Long-term debt		29,200		72,000
Leasehold payables		—		69
Other long-term liabilities		542		653
Total liabilities		64,412		92,974
Partners’ capital		60,759		99,358
Total liabilities and partner’s capital	$	125,171	$	192,332

See accompanying Notes to Financial Statements (Unaudited).

F-95

ALPHA SHALE RESOURCES, LP

STATEMENTS OF OPERATIONS

(Unaudited)

(in thousands)	Nine Months Ended September 30, 2012			Nine Months Ended September 30, 2013
Revenue:
Natural gas sales	$	14,456		$	62,938
Operating expenses:
Lease operating		1,490			6,098
Gathering, compression and transportation		3,376			11,044
Production taxes and impact fees		728			662
General and administrative		1,337			2,000
Depreciation, depletion and amortization		7,089			16,977
Amortization of deferred financing costs		—			107
Total expenses		14,020			36,888
Operating income		436			26,050
Other income (expense):
Interest expense		(271	)		(477	)
Other income (expense)		4			(902	)
Gain on derivative instruments		—			13,928
Total other income (expense)		(267	)		12,549
Net income	$	169		$	38,599

See accompanying Notes to Financial Statements (Unaudited).

F-96

ALPHA SHALE RESOURCES, LP

STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL

(in thousands)	Managing General  Partner		Limited Partners		Total
Balance as of December 31, 2011	$	38	$	37,238	$	37,276
Capital contributions		20		19,980		20,000
Net income		—		169		169
Balance as of September 30, 2012 (Unaudited)	$	58	$	57,387	$	57,445
	Managing General  Partner		Limited Partners		Total
Balance as of December 31, 2012	$	61	$	60,698	$	60,759
Net income		38		38,561		38,599
Balance as of September 30, 2013 (Unaudited)	$	99	$	99,259	$	99,358

See accompanying Notes to Financial Statements (Unaudited).

F-97

ALPHA SHALE RESOURCES, LP

STATEMENTS OF CASH FLOWS

(Unaudited)

(in thousands)	Nine Months. Ended September 30, 2012			Nine Months Ended September 30, 2013
Cash flows from operating activities:
Net income	$	169		$	38,599
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		7,089			16,977
Amortization of deferred financing costs		—			107
Derivative instruments fair value gain		—			(13,928	)
(Increase) decrease in:
Accounts receivable		(1,777	)		(2,290	)
Receivable from affiliate		(124	)		—
Gas collateral account		(295	)		—
Prepaid expenses and other		52			21
Cash receipts for settled derivatives		—			1,390
Increase (decrease) in:
Accounts payable		256			125
Royalties payable		624			2,614
Other accrued expenses		708			(160	)
Payable to affiliate		2,088			2,227
Net cash provided by operating activities		8,790			45,682
Cash flows from investing activities:
Capital expenditures for natural gas properties		(40,167	)		(88,547	)
Capital expenditures for property and equipment		(12	)		—
Net cash used in investing activities		(40,179	)		(88,547	)
Cash flows from financing activities:
Proceeds from borrowings		8,000			42,800
Credit facility costs		(131	)		(548	)
Capital contributions		20,000			—
Net cash provided by financing activities		27,869			42,252
Net decrease in cash		(3,520	)		(613	)
Cash at the beginning of the period		6,111			4,445
Cash at the end of the period	$	2,591		$	3,832

See accompanying Notes to Financial Statements (Unaudited).

F-98

ALPHA SHALE RESOURCES, LP

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

1.   Organization and Operations

These financial statements present the activities for Alpha Shale Resources, LP (hereinafter referred to as the “Partnership”). The Partnership was organized as a limited partnership in accordance with the laws of the State of Delaware on February 3, 2010 (date of inception) through funding from its limited partners, Rice Drilling C, LLC (“Rice C”) which is a wholly owned subsidiary of Rice Drilling B, LLC (“Rice Drilling B”), which is a wholly owned subsidiary of Rice Energy Inc. (“Rice Energy Inc.”), and Foundation PA Coal Company, LLC (“Alpha Holdings”), which is a wholly owned indirect subsidiary of Alpha Natural Resources, Inc. (“ANR Inc.”), and its managing general partner, Alpha Shale Holdings, LLC (“Holdings”). According to the terms of the limited partnership agreement, revenues, costs and cash distributions of the Partnership are allocated 49.95% each to Alpha Holdings and Rice C and 0.10% to Holdings.

The Partnership is engaged primarily in the acquisition, exploration, development, production and sale of natural gas in the Marcellus Shale region of Southwestern Pennsylvania. The Partnership sells its natural gas products solely to a natural gas marketing customer, which accounts for 100% of its accounts receivable as of December 31, 2012 and September 30, 2013 and 100% of its sales for the nine months ended September 30, 2012 and September 30, 2013. Natural gas sales included in the statements of operations consist of sales from thirteen horizontal wells.

2.   Long-Term Debt

The Partnership had long-term debt outstanding as of December 31, 2012 and September 30, 2013 as follows (in thousands):

Description	December 31, 2012		(Unaudited) September 30,  2013
Long-Term Debt
Wells Fargo Credit Facility	$	29,200	$	72,000
Total long-term debt	$	29,200	$	72,000

Wells Fargo Credit Facility

On September 7, 2012, the Partnership entered into a credit agreement (“Wells Fargo Credit Facility”) with Wells Fargo Bank, N.A. (“Wells Fargo”). The maximum credit amount allowed under the promissory note agreement is $200.0 million, payable at maturity with interest only due in monthly installments at the higher of the prime rate, the federal funds rate plus 0.5% or the adjusted LIBOR plus 1%; all unpaid balances are due September 7, 2017; secured by substantially all assets of the Partnership. As of September 30, 2013, the Partnership issued letters of credit of $13.5 million with Wells Fargo as required by the Partnership’s natural gas marketer. The borrowing base at December 31, 2012 and September 30, 2013 was $35.0 million and $130.0 million, respectively with approximately $5.8 million and $44.5 million, respectively, undrawn at that date.

The Wells Fargo Credit Facility provides for borrowings to be used for the purpose of funding capital expenditures related to the Partnership’s drilling program, providing working capital for lease acquisitions, exploration and production operations, and development (including the drilling and completion of producing wells), and for general business purposes, including fees and expenses. The Wells Fargo Credit Facility is subject to a maximum borrowing base equal to the maximum value, for credit purposes, of the subject properties as determined by Wells Fargo in accordance with its customary lending practices. The borrowing base is determined by the lenders on a quarterly basis and such determination is primarily based upon the value of the

F-99

ALPHA SHALE RESOURCES, LP

NOTES TO FINANCIAL STATEMENTS – (Continued)

(Unaudited)

2.   Long-Term Debt – (Continued)

Partnership’s proved developed reserves. If the lenders were to decrease the borrowing base below the amounts outstanding under the facility, the Partnership would have to repay these amounts within 30 days, repay these amounts in six monthly installments, or add sufficient collateral value.

The Wells Fargo Credit Facility is subject to certain covenants which are ordinary to such credit facilities and include, among other things, minimum financial ratios, restrictions as to additional debt and changes to the Partnership’s structure. The Partnership was in compliance with such covenants and ratios as of September 30, 2013.

3.   Derivative Instruments

The Partnership uses derivative commodity instruments that are placed with major financial institutions whose creditworthiness is regularly monitored. The Partnership’s derivative commodity instruments have not been designated as hedges for accounting purposes; therefore, all gains and losses were recognized in income currently. As of September 30, 2013, the Partnership entered into derivative instruments with Wells Fargo fixing the price it receives for natural gas through December 31, 2015, as summarized in the following table:

Swap Contract Expiration	MMbtu/day	Weighted Average Price
2013	75,612	$3.972
2014 2015	74,137 10,139	$4.122 $4.235
Collar Contract Expiration	MMbtu/day	Floor/Ceiling
2015	2,123	$3.750/$5.000

The following is a summary of the Partnership’s derivative instruments, which are recorded in the balance sheet as of December 31, 2012 and September 30, 2013 (in thousands):

	December 31, 2012			(Unaudited) September 30,  2013
Current derivative assets	$	141		$	9,754
Long-term derivative assets		—			3,100
	$	141		$	12,854
Current derivative liabilities	$	278		$	135
Long-term derivative liabilities		—			318
	$	278		$	453
Net current value of derivative assets (liabilities)	$	(137	)	$	9,619
Net long-term value of derivative assets	$	—		$	2,782

The net current value of derivative liabilities of $137 thousand is included within other accrued liabilities as of December 31, 2012. The net long-term value of derivative assets of $2.8 million is included within other non-current assets as of September 30, 2013.

F-100

ALPHA SHALE RESOURCES, LP

NOTES TO FINANCIAL STATEMENTS – (Continued)

(Unaudited)

3.   Derivative Instruments – (Continued)

The following tables present the gross amounts of recognized derivative assets and liabilities, the amounts offset under netting arrangements with counterparties, and the resulting net amounts presented in the consolidated balance sheets for the periods presented, all at fair value (in thousands):

	December 31, 2012
Description	Gross Amounts of Recognized Assets		Gross Amounts Offset  on Balance Sheet			Net Amounts of Assets  (Liabilities) on Balance Sheet
Derivative assets	$	324	$	(183	)	$	141
Derivative liabilities	$	122	$	(400	)	$	(278	)
	(Unaudited) September 30, 2013
Description	Gross Amounts of Recognized Assets		Gross Amounts Offset on Balance Sheet			Net Amounts of Assets  (Liabilities) on Balance Sheet
Derivative assets	$	14,523	$	(1,669	)	$	12,854
Derivative liabilities	$	31	$	(484	)	$	(453	)

Both realized and unrealized gains and losses are recorded as a gain or loss on derivatives in the consolidated statement of operations under other income/expense. The Partnership did not have any derivative instruments as of September 30, 2012. Unrealized gains were $12.5 million for the nine months ended September 30, 2013. Realized gains related to contract settlements of $1.4 million for the nine months ended September 30, 2013.

4.   Fair Value of Financial Instruments

The Partnership determines fair value on a recurring basis for its derivative instruments as the instruments are required to be recorded at fair value each reporting period. Fair value is based on quoted market prices, where available. If quoted market prices are not available, fair value is based upon models that use as inputs market-based parameters, including but not limited to forward curves, discount rates, broker quotes, volatilities, and nonperformance risk.

The Partnership has categorized its fair value measurements into a three-level fair value hierarchy, based on the priority of the inputs to the valuation technique. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets and liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). All of the Partnership’s fair value measurements are included in Level 2. Since the adoption of fair value accounting, the Partnership has not made any changes to its classification of financial instruments in each category.

F-101

ALPHA SHALE RESOURCES, LP

NOTES TO FINANCIAL STATEMENTS – (Continued)

(Unaudited)

4.   Fair Value of Financial Instruments – (Continued)

The following financial instruments were measured at fair value on a recurring basis during the period (refer to Note 3 for details relating to the derivative instruments) (in thousands):

	December 31, 2012		Fair Value Measurements at Reporting Date Using
Description			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Liabilities
Derivative Instruments, at fair value	$	137	$	—	$	137	$	—
Total current liabilities	$	137	$	—	$	137	$	—
			Fair Value Measurements at Reporting Date Using
Description	(Unaudited) September 30,  2013		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Assets
Derivative Instruments, at fair value	$	9,619	$	—	$	9,619	$	—
Total current assets	$	9,619	$	—	$	9,619	$	—
Derivative Instruments, at fair value	$	2,782	$	—	$	2,782	$	—
Total long-term assets	$	2,782	$	—	$	2,782	$	—

The carrying amount of cash, receivables and accounts payable approximate their fair value due to the short-term nature of such instruments.

The Partnership reviews long-lived assets, including natural gas properties, for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets might not be recoverable. If the estimated undiscounted cash flows for a particular asset are not sufficient to cover the asset’s carrying value, it is impaired and the carrying value is reduced to the asset’s current fair value. These fair value measurements fall within Level 3 of the fair value hierarchy. No impairment was recorded during 2012 or 2013.

The estimated fair value of long-term debt on the consolidated balance sheets as of December 31, 2012 and September 30, 2013 is shown in the table below (in thousands). The fair value was estimated using Level 3 inputs based on rates reflective of the remaining maturity as well as the Partnership’s financial position (refer to Note 2 for details relating to long-term debt).

Description	December 31, 2012		(Unaudited) September 30,  2013
Long-Term Debt
Wells Fargo Credit Facility	$	29,200	$	72,315
Long-term debt	$	29,200	$	72,315

F-102

ALPHA SHALE RESOURCES, LP

NOTES TO FINANCIAL STATEMENTS – (Continued)

(Unaudited)

5.   Partners’ Capital

The Partnership consists of three partners: Holdings, which is the managing general partner, and Alpha Holdings and Rice C, the limited partners. The Partnership authorized and issued 10,000 units during 2010. In February 2010, Holdings contributed $6 thousand for 10 units, or a 0.10% ownership, and Alpha Holdings and Rice C each contributed $3.0 million for 4,995 shares, or 49.95% ownership each. In 2012, the managing partner contributed an additional $20 thousand and the limited partners contributed an additional $20.0 million.

Since inception, the three partners have continued to make additional contributions into the Partnership, in accordance with ownership percentages, and no additional units were issued as depicted on the statements of changes in partners’ capital.

6.   Commitments and Contingencies

The Partnership is involved in various litigation matters arising in the normal course of business. Management is not aware of any actions that are expected to have a material adverse effect on its financial position or results of operations.

The Partnership has drilling commitments which management expects to meet in the ordinary course of business.

7.   Related Party Transactions

During the nine months ended September 30, 2013, the Partnership was billed for management services provided in the amount of $1.4 million, which is included with general and administrative expenses on the statements of operations. As of September 30, 2013, $4.7 million was due to related entities and recorded as payable to affiliate on the balance sheets. Included in this amount are management service fees as described above as well as fees for gathering and transportation incurred by the Partnership that were billed to related parties.

8.   Subsequent Events

On October 23, 2013, the borrowing base on the Partnership’s Wells Fargo Credit Facility with Wells Fargo increased from $130.0 million to $145.0 million. There were no other changes to the terms of the agreement. In October 2013, the Partnership drew an additional $3.4 million from its Wells Fargo Credit Facility, with remaining availability approximating $59.2 million.

On December 6, 2013, Rice Energy Inc. entered into a transaction agreement among Rice Energy Inc., Rice C and Alpha Holdings, pursuant to which Rice Energy Inc. will acquire (the “Marcellus JV Buy-In”) ANR Inc.’s 50% interest in the Partnership in exchange for aggregate consideration of approximately $300.0 million, consisting of common stock of Rice Energy Inc. and $100.0 million in cash. The Marcellus JV Buy-In is contingent upon the completion of the Rice Energy Inc. initial public offering.

Subsequent events have been considered for disclosure and recognition through December 9, 2013, which is the date the financial statements were available to be issued.

F-103

ANNEX A

GLOSSARY OF OIL AND NATURAL GAS TERMS

The following are abbreviations and definitions of certain terms used in this document, which are commonly used in the oil and natural gas industry:

“Bcf.” One billion cubic feet of natural gas.

“Btu.” One British thermal unit, the quantity of heat required to raise the temperature of a one-pound mass of water by one degree of Fahrenheit.

“Basin.” A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.

“Completion.” The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

“DD&A.” Depreciation, depletion, amortization and accretion.

“Delineation.” The process of placing a number of wells in various parts of a reservoir to determine its boundaries and production characteristics.

“Developed acreage.” The number of acres that are allocated or assignable to productive wells or wells capable of production.

“Development well.” A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

“Dry gas.” A natural gas containing insufficient quantities of hydrocarbons heavier than methane to allow their commercial extraction or to require their removal in order to render the gas suitable for fuel use.

“Dry hole.” 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.

“EUR.” Estimated ultimate recovery.

“Exploratory well.” A well drilled to find and produce natural gas or oil reserves not classified as proved, to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir or to extend a known reservoir.

“Field.” An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

“Formation.” A layer of rock which has distinct characteristics that differs from nearby rock.

“Gross acres” or “gross wells.” The total acres or wells, as the case may be, in which a working interest is owned.

“Gross (net) identified drilling locations.” Gross (net) identified drilling locations are those drilling locations identified by management based on the following criteria:

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• Drillable Locations – These are mapped locations that our Vice President of Exploration & Geology has deemed to have a high likelihood as being drilled or are currently in development but have not yet commenced production. With respect to our Pennsylvania acreage, we had 224 gross (200 net) pro forma drillable Marcellus locations and 134 gross (117 net) pro forma drillable Upper Devonian locations as of December 1, 2013. With respect to our Ohio acreage, we have 637 gross (192 net) drillable Utica locations, all of which are located within the contract areas covered by our Development Agreement and AMI Agreement with Gulfport.

• Estimated Locations – These remaining estimated locations are calculated by taking our total acreage, less acreage that is producing or included in drillable locations, and dividing such amount by our expected well spacing to arrive at our unrisked estimated locations which is then multiplied by a risking factor. We assume these Marcellus locations have 6,000 foot laterals and 600 foot spacing between Marcellus wells which yields approximately 80 acre spacing. We assume these Upper Devonian locations have 6,000 foot laterals and 1,000 foot spacing between Upper Devonian wells which yields approximately 140 acre spacing. We assume these Utica locations have 8,000 foot laterals and 600 foot spacing between Utica wells which yields approximately 110 acre spacing. With respect to our Pennsylvania acreage, we multiply our unrisked estimated Marcellus and Upper Devonian locations by a risking factor of 50% to arrive at total risked estimated locations. As a result, we have 125 gross (125 net) pro forma estimated risked Marcellus locations, 77 gross (77 net) pro forma estimated risked Upper Devonian locations as of December 1, 2013. With respect to our Ohio acreage, we multiply our unrisked estimated locations by a risking factor of approximately 37% to arrive at total risked estimated locations. We then apply our assumed working interest for such location, calculated by applying the impact of assumed unitization on the underlying working interest as well as, in the case of locations within the AMI with Gulfport, the applicable participating interest. As a result, as of December 1, 2013, we had 116 gross (41 net) estimated risked Utica locations.

“Horizontal drilling.” A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.

“Identified drilling locations.” Total gross (net) resource play locations that we may be able to drill on our existing acreage. 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.

“Mcf.” One thousand cubic feet of natural gas.

“MMcf.” One million cubic feet of natural gas.

“MMBtu.” One million Btu.

“NGLs.” Natural gas liquids. Hydrocarbons found in natural gas which may be extracted as liquefied petroleum gas and natural gasoline.

“NYMEX.” The New York Mercantile Exchange.

“Net acres.” The percentage of total acres an owner has out of a particular number of acres, or a specified tract. An owner who has 50% interest in 100 acres owns 50 net acres.

“Productive well.” A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

“Prospect.” A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

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“Proved developed reserves.” Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

“Proved reserves.” The estimated quantities of oil, natural gas and NGLs which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.

“Proved undeveloped reserves (“PUD”).” 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.

“PV-10.” When used with respect to natural gas and oil reserves, PV-10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production, future development and abandonment costs, using prices 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.

“Recompletion.” The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.

“Reservoir.” A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.

“Spacing.” The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.

“Standardized measure.” Discounted future net cash flows estimated by applying year-end prices to the estimated future production of year-end proved reserves. Future cash inflows are reduced by estimated future production and development costs based on period-end costs to determine pre-tax cash inflows. Future income 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.

“Total depth.” The planned end of a well, measured by the length of pipe required to reach the bottom.

“Undeveloped acreage.” Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether such acreage contains proved reserves.

“Unit.” The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.

“Wellbore.” The hole drilled by the bit that is equipped for natural gas production on a completed well. Also called well or borehole.

“Working interest.” The right granted to the lessee of a property to explore for and to produce and own natural gas or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.

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40,000,000 Shares

Rice Energy Inc.

Common Stock

Prospectus

                    , 2014

Barclays

Citigroup

Goldman, Sachs & Co.

Wells Fargo Securities

BMO Capital Markets

RBC Capital Markets

Comerica Securities

SunTrust Robinson Humphrey

Tudor, Pickering, Holt & Co.

Capital One Securities

FBR

Scotiabank / Howard Weil

Johnson Rice & Company L.L.C.

Sterne Agee

Through and including                     , 2014 (the 25th day after the date of this prospectus), all dealers effecting transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to a dealer’s obligation to deliver a prospectus when acting as an underwriter and with respect to an unsold allotment or subscription.

Part II

INFORMATION NOT REQUIRED IN PROSPECTUS

Item 13. Other expenses of issuance and distribution

The following table sets forth an itemized statement of the amounts of all expenses (excluding underwriting discounts and commissions) payable by us in connection with the registration of the common stock offered hereby. With the exception of the Registration Fee, FINRA Filing Fee and New York Stock Exchange listing fee), the amounts set forth below are estimates.

SEC Registration Fee	$	124,420
FINRA Filing Fee		145,400
New York Stock Exchange listing fee		250,000
Accountants’ fees and expenses		1,050,000
Legal fees and expenses		1,500,000
Printing and engraving expenses		553,000
Transfer agent and registrar fees		50,000
Miscellaneous		327,180
Total	$	4,000,000

Item 14. Indemnification of Directors and Officers

Our amended and restated certificate of incorporation will provide that a director will not be liable to the corporation or its stockholders for monetary damages to the fullest extent permitted by the DGCL. In addition, if the DGCL is amended to authorize the further elimination or limitation of the liability of directors, then the liability of a director of the corporation, in addition to the limitation on personal liability provided for in our certificate of incorporation, will be limited to the fullest extent permitted by the amended DGCL. Our amended and restated bylaws will provide that the corporation will indemnify, and advance expenses to, any officer or director to the fullest extent authorized by the DGCL.

Section 145 of the DGCL provides that a corporation may indemnify directors and officers as well as other employees and individuals against expenses, including attorneys’ fees, judgments, fines and amounts paid in settlement in connection with specified actions, suits and proceedings whether civil, criminal, administrative, or investigative, other than a derivative action by or in the right of the corporation, if they acted in good faith and in a manner they reasonably believed to be in or not opposed to the best interests of the corporation and, with respect to any criminal action or proceeding, had no reasonable cause to believe their conduct was unlawful. A similar standard is applicable in the case of derivative actions, except that indemnification extends only to expenses, including attorneys’ fees, incurred in connection with the defense or settlement of such action and the statute requires court approval before there can be any indemnification where the person seeking indemnification has been found liable to the corporation. The statute provides that it is not exclusive of other indemnification that may be granted by a corporation’s certificate of incorporation, bylaws, disinterested director vote, stockholder vote, agreement or otherwise.

Our amended and restated certificate of incorporation will also contain indemnification rights for our directors and our officers. Specifically, our amended and restated certificate of incorporation will provide that we shall indemnify our officers and directors to the fullest extent authorized by the DGCL. Further, we may maintain insurance on behalf of our officers and directors against expense, liability or loss asserted incurred by them in their capacities as officers and directors.

We have obtained directors’ and officers’ insurance to cover our directors, officers and some of our employees for certain liabilities.

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We will enter 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.

The underwriting agreement provides for indemnification by the underwriters of us and our officers and directors, and by us of the underwriters, for certain liabilities arising under the Securities Act or otherwise in connection with this offering.

Item 15. Recent Sales of Unregistered Securities

In connection with its formation, on October 1, 2013, Rice Energy Inc. issued 1,000 shares of its common stock, par value $0.01 per share, to Rice Drilling B LLC in exchange for consideration of $10.00. The issuance of such shares of common stock did not involve any underwriters, underwriting discounts or commissions or a public offering, and we believe that such issuance was exempt from the registration requirements pursuant to Section 4(2) of the Securities Act of 1933, as amended (the “Securities Act”).

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 to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

The undersigned registrant hereby undertakes that, for the purpose of determining liability of the registrant under the Securities Act to any purchaser in the initial distribution of the securities, 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 this offering required to be filed pursuant to Rule 424;

(ii) Any free writing prospectus relating to this offering prepared by or on behalf of the undersigned registrant or used or referred to by the undersigned registrant;

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(iii) The portion of any other free writing prospectus relating to this 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 this offering made by the undersigned registrant to the purchaser.

The undersigned registrant hereby undertakes that:

(1) For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.

(2) For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Canonsburg, State of Pennsylvania, on January 13, 2014.

By:	/s/ Daniel J. Rice IV
	Daniel J. Rice IV
	Director, Chief Executive Officer

Pursuant to the requirements of the Securities Act of 1933, as amended, this Registration Statement has been signed below by the following persons in the capacities and the dates indicated.

Signature	Title	Date
/s/ Daniel J. Rice IV	Director, Chief Executive Officer		January 13, 2014
Daniel J. Rice IV	(Principal Executive Officer)
*	Director, President and		January 13, 2014
Toby Z. Rice	Chief Operating Officer
*	Vice President and Chief Financial Officer		January 13, 2014
Grayson T. Lisenby	(Principal Financial Officer)
*	Vice President, Chief Accounting &		January 13, 2014
James W. Rogers	Administrative Officer, Treasurer
	(Principal Accounting Officer)
*	Director		January 13, 2014
Daniel J. Rice III
*	Director		January 13, 2014
Scott A. Gieselman
*	Director		January 13, 2014
Chris G. Carter

*By:	/s/ Daniel J. Rice IV
	Daniel J. Rice IV
	Attorney-in-Fact

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INDEX TO EXHIBITS

Exhibit number			Description
	**1.1		Form of Underwriting Agreement
	**3.1		Form of Amended and Restated Certificate of Incorporation of Rice Energy Inc.
	**3.2		Form of Amended and Restated Bylaws of Rice Energy Inc.
	4.1		Form of Common Stock Certificate
	**4.2		Form of Registration Rights Agreement
	**4.3		Form of Stockholders’ Agreement by and among Rice Energy Inc., Rice Energy Holdings LLC, Rice Energy Family Holdings, LP, NGP Rice Holdings LLC and Alpha Natural Resources, Inc.
	5.1		Form of Opinion of Vinson & Elkins L.L.P. as to the legality of the securities being registered
	**10.1		Second Amended and Restated Credit Agreement, dated as of April 25, 2013, among Rice Drilling B LLC, as borrower, Wells Fargo Bank, N.A., as administrative agent and the lenders and other parties thereto.
	**10.2		First Amendment to Second Amended and Restated Credit Agreement, dated as of August 7, 2013, among Rice Drilling B LLC, as borrower, Wells Fargo Bank, N.A., as administrative agent and the lenders and other parties thereto.
	**10.3		Second Amendment to Second Amended and Restated Credit Agreement, dated as of August 20, 2013, among Rice Drilling B LLC, as borrower, Wells Fargo Bank, N.A., as administrative agent and the lenders and other parties thereto.
	**10.4		Third Amendment to Second Amended and Restated Credit Agreement, dated as of October 15, 2013, among Rice Drilling B LLC, as borrower, Wells Fargo Bank, N.A., as administrative agent and the lenders and other parties thereto.
	**10.5		Fourth Amendment to Second Amended and Restated Credit Agreement, dated as of November 5, 2013, among Rice Drilling B LLC, as borrower, Wells Fargo Bank, N.A., as administrative agent and the lenders and other parties thereto.
	**10.6		Limited Consent and Waiver and Fifth Amendment to Second Amended and Restated Credit Agreement, dated as of December 27, 2013, among Rice Drilling B LLC, as borrower, Wells Fargo Bank, N.A., as administrative agent and the lenders and other parties thereto.
	**10.7		Form of Sixth Amendment to Second Amended and Restated Credit Agreement, dated as of January     , 2014, among Rice Drilling B LLC, as borrower, Wells Fargo Bank, N.A., as administrative agent and the lenders and other parties thereto.
	**10.8		Senior Secured Term Loan Credit Agreement, dated as of April 25, 2013, among Rice Drilling B LLC, as borrower, Barclays Bank PLC, as administrative agent and the lenders party thereto.
	**10.9		Form of Master Reorganization Agreement
	**10.10		Transaction Agreement by and among Rice Energy Inc., Rice Drilling C LLC and Foundation PA Coal Company, LLC, dated as of December 6, 2013.
	**10.11	†	Amended and Restated Limited Liability Company Agreement of Rice Energy Appalachia, LLC
	**10.12	†	Form of Amended and Restated Limited Liability Company Agreement of Rice Energy Holdings LLC
	**10.13	†	Form of Amended and Restated Limited Liability Company Agreement of NGP Rice Holdings LLC

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Exhibit number			Description
	**10.14	†	Form of Employment Agreement (Executive Officers)
	**10.15	†	Form of Indemnification Agreement
	**10.16	†	Form of Rice Energy Inc. 2014 Long-Term Incentive Plan
	**10.17	†	Rice Energy Management Bonus Plan
	`**10.18	†	Form of Restricted Stock Unit Agreement (Employees)
	**10.19	†	Form of Restricted Stock Unit Agreement (Directors)
	**10.20		Form of Senior Subordinated Convertible Debentures due 2014
	**10.21		Amendment, Consent and Parent Guaranty to Senior Subordinated Convertible Debentures due 2014
	**10.22		Form of Warrant Agreement
	**10.23		Form of Bonus Warrant Agreement
	**21.1		List of Subsidiaries of Rice Energy Inc.
	23.1		Consent of Ernst & Young LLP (Rice Drilling B LLC and Rice Energy Inc.)
	23.2		Consent of Grossman Yanak & Ford LLP (Countrywide Energy Services, LLC)
	23.3		Consent of Ernst & Young LLP (Alpha Shale Resources, LP)
	23.4		Consent of Schneider Downs & Co., Inc. (Alpha Shale Resources, LP)
	23.5		Consent of Netherland, Sewell and Associates, Inc.
	23.6		Consent of Wright & Company, Inc.
	23.7		Consent of Vinson & Elkins L.L.P. (included as part of Exhibit 5.1 hereto)
	**24.1		Power of Attorney (included on the signature page of the initial filing of the Registration Statement)
	**99.1		Netherland, Sewell and Associates, Inc., Summary of Reserves at December 31, 2011 (Rice Energy Inc.)
	**99.2		Netherland, Sewell and Associates, Inc., Summary of Reserves at December 31, 2012 (Rice Energy Inc.)
	**99.3		Netherland, Sewell and Associates, Inc., Summary of Reserves at September 30, 2013 (Rice Energy Inc.)
	**99.4		Netherland, Sewell and Associates, Inc., Summary of Reserves at December 31, 2012 (Alpha Shale Resources, LP)
	**99.5		Netherland, Sewell and Associates, Inc., Summary of Reserves at September 30, 2013 (Alpha Shale Resources, LP)
	**99.6		Wright & Company, Inc., Summary of Reserves at December 31, 2011 (Alpha Shale Resources, LP)
	99.7		Consent of Robert F. Vogt, as Director Nominee
	99.8		Consent of James W. Christmas, as Director Nominee
	99.9		Consent of Kevin S. Crutchfield, as Director Nominee

** Previously filed.

† Compensatory plan or arrangement.

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