10-K 1 riceenergy1231201310k.htm 10-K Rice Energy 12/31/2013 10K

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
þ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 2013
or
¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
For the transition period from_______ to_______              
Commission File Number: 001-36273
Rice Energy Inc.
(Exact name of registrant as specified in its charter)
Delaware
 
46-3785773
(State or other jurisdiction of incorporation or organization)
 
(I.R.S. Employer Identification No.)
171 Hillpointe Drive, Suite 301
Canonsburg, Pennsylvania
 
15317
(Address of principal executive offices)
 
(Zipcode)
 
 
 
Registrant’s telephone number, including area code: (724) 746-6720

 
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
 
Name of each exchange on which registered
Common Stock, par value $0.01 per share
 
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
 
 
 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. ¨Yes þNo
 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. ¨Yes þNo
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ¨Yes þNo
 
 
 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). þYes ¨No
 
 
 
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ
 
 
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a small reporting company. See the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer ¨
 
Accelerated filer ¨
Non-accelerated filer þ
 
Smaller reporting company ¨
(Do not check if a smaller reporting company)
 
 
 
 
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ¨Yes þNo
 
 
 
As of June 30, 2013, the last business day of the registrant’s most recently completed second quarter, the registrant’s equity was not listed on a domestic exchange or over-the-counter market. The registrant’s common units began trading on the New York Stock Exchange on January 24, 2014.
The registrant had 127,958,611 shares of common stock outstanding at March 21, 2014.
Documents Incorporated by Reference: None




RICE ENERGY INC.
ANNUAL REPORT ON FORM 10-K
TABLE OF CONTENTS
 
 
Page
 
 
 
 
 
 
 
 


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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;
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.
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. We anticipate that we will cease to be an “emerging growth company” at the end of 2014.



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Cautionary Statement Regarding Forward-Looking Statements
This Annual Report on Form 10-K (the “Annual Report”) contains “forward-looking statements” within the meaning of Section 27A of the Securities Act and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact included in this Annual Report, regarding our strategy, future operations, financial position, estimated revenues and income/losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Annual Report, 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 “Item 1A. Risk Factors” included in this Annual Report.
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 Annual Report 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 “Item 1A. Risk Factors” in this Annual Report.
Reserve engineering is a process of estimating underground accumulations of natural gas, NGLs and oil that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of natural gas, and NGLs and oil that are ultimately recovered.
Should one or more of the risks or uncertainties described in this Annual Report 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 Annual Report 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 Annual Report.

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Commonly Used Defined Terms
As used in the Annual Report, unless the context indicates or otherwise requires, the following terms have the following meanings:
“Rice Energy,” the “Company,” “we,” “our,” “us” or like terms refer collectively to Rice Energy Inc. and its consolidated subsidiaries, including Rice Drilling B LLC;
“Rice Drilling B” refers to Rice Drilling B LLC and its consolidated subsidiaries;
“Rice Partners” refers to Rice Energy Family Holdings, LP (formerly known as Rice Energy Limited Partners), 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; and
“NGP Holdings” refers to NGP Rice Holdings, LLC.
Information presented in the Annual Report on a pro forma basis gives effect to (i) our initial public offering and the completion of the corporate reorganization in connection with our initial public offering completed in January 2014 and (ii) the consummation of our acquisition of Alpha Holdings’ 50% interest in our Marcellus joint venture (the “Marcellus JV Buy-In”), each as described under “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.” Part I of this Annual Report gives effect to the Marcellus JV Buy-In. The historical consolidated financial statements contained in this Annual Report relate to periods prior to the completion of our initial public offering on January 29, 2014. Consequently, the audited consolidated financial statements and related discussion contained in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Annual Report pertain to Rice Drilling B, our accounting predecessor.



5




PART I
Item 1. Business
The estimated proved reserve information for the properties of each of us and our Marcellus joint venture contained in this Annual Report are based on reserve reports relating thereto prepared by the independent petroleum engineers of Netherland Sewell & Associates Inc. (NSAI). 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. As of December 31, 2013, we held 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 the fourth quarter of 2010, our pro forma average net daily production has grown approximately 77 times to 154 MMcf/d for the fourth 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.

6


We have drilled and completed 37 pro forma horizontal Marcellus wells as of December 31, 2013 with a 100% success rate (defined as the rate at which wells are completed and produce in commercially viable quantities). As of December 31, 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 31, 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. 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 were 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 31, 2013, we had 753 gross (233 net) identified drilling locations in the Utica Shale.
As of December 31, 2013, our pro forma estimated proved reserves were 602 Bcf, all of which were in southwestern Pennsylvania, with 42% proved developed and 100% natural gas. In 2014, excluding $100 million cash paid with respect to the Marcellus JV Buy-In and approximately $110 million expected to be paid with respect to the Momentum Acquisition, each as described in “—Our Properties—Recent Developments,” we plan to invest $1,230.0 million in our operations as follows:
$430.0 million for drilling and completion in the Marcellus Shale;
$150.0 million for drilling and completion in the Utica Shale;
$385.0 million for leasehold acquisitions; and
$265.0 million for midstream infrastructure development.

7


This represents a 96% increase over our $629.0 million pro forma 2013 capital expenditures. Please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The following table provides a summary of our pro forma acreage, average working interest, producing wells and drilling locations as of December 31, 2013, projected 2014 gross wells drilled and projected 2014 drilling and completion capital budget as of March 21, 2014 and our average net daily production for the three months ended December 31, 2013
 
 
Acreage
 
Average Working Interest
 
Producing Wells
 
Identified Drilling Locations (1)
 
Q4 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

 
151

 
50

  
$
430

Utica Shale (3)
 
48,660

 
46,488

 
96
%
 

 
753

 
233

 

 
31

(4) 
150

Upper Devonian Shale (5)
 

 

 

 
3

 
211

 
194

 
3

 

  

Total (5)
 
94,222

 
89,839

 
 
 
40

 
1,313

 
752

 
154

 
81

  
$
580

(1)
Based on our reserve reports as of December 31, 2013, we had 44 gross (39 net) locations in the Marcellus Shale associated with proved undeveloped reserves and 13 gross (12 net) locations in the Marcellus Shale associated with proved developed not producing reserves. Please see “—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 “Item 1A. 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. Includes 1,338 net acres that were included as a leasehold payable on our balance sheet as of December 31, 2013.
(3)
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 “—Our Operations—Reserve Data—Determination of Identified Drilling Locations.”
(4)
Includes an estimated 20 projected gross wells to be drilled by Gulfport Energy Corporation. Please see “—Our Properties—Utica Shale—Development Agreement and Area of Mutual Interest Agreement.”
(5)
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 focused on the Marcellus and Utica Shales.
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.
Marcellus Shale
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

8


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 31, 2013.
We have experienced virtually no geologic complexity in our drilling activities through December 31, 2013, which has resulted in a fairly predictable band of expected recoveries per 1,000 feet of lateral length on our wells. We completed 9 gross (9 net) horizontal Marcellus Shale wells in 2012 and 22 gross (19.9 net) horizontal Marcellus Shale wells in 2013. As of December 31, 2013, we had a total of 37 gross (34.3 net) producing wells in the Marcellus Shale and an additional 47 gross (40.0 net) wells in progress. As of December 31, 2013, we had 349 gross (325 net) pro forma identified Marcellus drilling locations.
For the quarter ended December 31, 2013, we had average pro forma net daily production of 154 MMcf/d. As of December 31, 2013, we had two rigs operating in the Marcellus Shale (one tophole rig and one horizontal rig) and two rigs operating in the Utica Shale (one tophole rig and one horizontal rig).
The following table provides a summary of our current gross and net acreage by county in Pennsylvania on a pro forma basis as of December 31, 2013.
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 a third party in exchange for $7.0 million. There was no production or net proved reserves attributable to the interests sold. We incurred 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 to 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.
As of December 31, 2013, we owned 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 31, 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 as of December 31, 2013.
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.

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In October 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. We employed certain steps, including increasing our drilling mud weight, that successfully controlled the gas flow. However, certain uncased sections in the vertical portions 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 drilling 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 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 wrote off approximately $8.1 million of exploratory 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 “Item 1A. 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, as of December 31, 2013, 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.
Each quarter 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 year. 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

10


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 sold interests in noncore assets in Guernsey County, Ohio and Lycoming County, Pennsylvania in two separate transactions. In December 2013, we sold 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 addition, 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 incurred a loss of $4.2 million in the fourth quarter of 2013 as a result of the Lycoming transaction.
Operating Data
The following table provides certain operational data related to our proved developed producing Marcellus wells as of December 31, 2013. We are the operator of each of these wells.








Periodic Flow Rates (MMcf/d) (1)


Year(s)

 Wells Turned Into Sales

Average Wells per Rig Move

Average Lateral Length (Feet)

0-90

91-180

181-360

361-720

D&C ($/Foot) (2)
2010-2011

6

1.4

3,281

5.5

6.0

4.4

2.9

$
2,341

2012

9

2.0

5,731

9.0

10.0

6.8

N/A

$
1,609

2013

22

2.1

6,286

11.1

10.3

9.2

N/A

$
1,461

Total

37

1.9

5,664

9.7

9.3

6.3

2.9

$
1,640

 
(1)Based on production data through March 1, 2014.
(2)Development and completion (D&C) costs are shown gross of our working interest’s proportionate share.
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 enhances our ability to 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-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 $265.0 million on midstream infrastructure development (excluding amounts paid in connection with the Momentum Acquisition).
As of December 31, 2013, we owned and operated 27 miles of high-pressure gathering pipelines on our Marcellus Shale acreage in Washington County, Pennsylvania. Due to the high flow rates and flowing tubing pressures experienced with our Marcellus wells, none of our wells requires nor utilizes artificial lift or compression.
Our midstream infrastructure in Pennsylvania also includes 33 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 December 31, 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.

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On February 12, 2014, we entered into a purchase and sale agreement with M3 Appalachia Gathering LLC, a Delaware limited liability company (“M3”) to acquire certain gas gathering assets in eastern Washington and Greene Counties, Pennsylvania, for aggregate consideration of approximately $110.0 million in cash. Please see “—Recent Developments—Momentum Acquisition.”
Transportation and Takeaway Capacity
As of March 1, 2014, our average annual firm transportation contracts and firm sales arrangements for 2014, 2015 and 2016 were approximately 330,000 MMBtu/d, 654,000 MMBtu/d and 761,000 MMBtu/d, respectively. These amounts include approximately 115,000 MMBtu/d of firm sales contracted with a third party through October 2017, subject to annual renewal. Under firm transportation contracts, we are obligated to deliver minimum daily volumes or pay fees for any deficiencies in deliveries.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, ultimate recoveries and returns on investment. We leverage our technical expertise and analyze third-party data to be an early entrant into the core of a shale play. 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 31, 2013, we had drilled and completed 37 horizontal Marcellus wells that 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 31, 2013 with a goal of growing production, cash flow and reserves in an economically-efficient manner. We added 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. 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 construct, acquire and control 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:

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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. 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 construct and acquire 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 31, 2013 consisted of 1,313 gross (752 net) pro forma identified drilling locations, with 349 gross (325 net), 753 gross (233 net) and 211 gross (194 net) pro forma identified drilling locations in the Marcellus Shale, 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 31, 2013, we have drilled and completed 37 wells on our Marcellus Shale acreage with a 100% success rate. We began to test 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 31, 2013 on a pro forma basis, we have drilled 52 horizontal wells totaling approximately 336,000 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. Further, we are able to enhance our wellbore economics through multi-well pad drilling (one 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 31, 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 gas gathering pipeline system is currently designed to handle up to approximately 1.5 Bcf/d in the aggregate and, as of December 31, 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 plan to continue to build out our Pennsylvania gathering system congruent with our future development plans. We plan to replicate our strategy of constructing and controlling our own midstream system in Ohio and expect to have our gathering system in Belmont County substantially complete by the second quarter of 2015. We believe our commitment to constructing and controlling 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. 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 had cash on hand of approximately $347.0 million and availability under our revolving credit facility of approximately $317.1 million, as described in “—Recent Developments—Amendment to Senior Secured Revolving Credit Facility.” 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 31, 2013, we had entered into hedging contracts covering approximately 62.9 Bcf (172.0 MMcf/d) of natural gas production for 2014 at a weighted average index floor price of $4.05 per MMBtu. Furthermore, as of December 31, 2013, we had entered into hedging contracts covering approximately 59.1 Bcf (162.0 MMcf/d) of natural gas production for 2015 at a weighted average index floor price of $4.05 per MMBtu.

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Proven and Stockholder-Aligned Management Team. Our management team possesses extensive oil and natural gas acquisition, exploration and development expertise in shale plays. 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. 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 over time. For additional information regarding our incentive units, please read “Item 11. 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.
Recent Developments
Initial Public Offering
On January 29, 2014, we completed our initial public offering (“IPO”) of 50,000,000 shares of our $0.01 par value common stock, which included 30,000,000 shares sold by us, 14,000,000 shares sold by the selling stockholder and 6,000,000 shares subject to an option granted to the underwriters by the selling stockholder.
The net proceeds of our IPO, based on the public offering price of $21.00 per share, were approximately $993.5 million, which resulted in net proceeds to us of $594.5 million after deducting estimated expenses and underwriting discounts and commissions of approximately $35.5 million and the net proceeds to the selling stockholders of approximately $399.0 million after deducting underwriting discounts of approximately $21.0 million. We did not receive any proceeds from the sale of the shares by the selling stockholder. A portion of the net proceeds from our IPO were used to repay all outstanding borrowings under the revolving credit facility of our Marcellus joint venture, to make a $100.0 million payment to Alpha Holdings in partial consideration for the Marcellus JV Buy-In and to repay all outstanding borrowings under our revolving credit facility. The remainder of the net proceeds from our IPO will be used to fund a portion of our capital expenditure plan.
Our common stock is traded on the New York Stock Exchange (“NYSE”) under the symbol “RICE.”
Corporate Reorganization
A corporate reorganization occurred concurrently with the completion of our IPO on January 29, 2014. As a part of this corporate reorganization, we acquired all of the outstanding membership interests in Rice Appalachia in exchange for shares of our common stock. Our business continues to be conducted through Rice Drilling B, as a wholly owned subsidiary. As of January 29, 2014, upon (a) the completion of the IPO, (b) the issuance of (i) 43,452,550 shares of common stock to NGP Holdings, (ii) 20,300,923 shares of common stock to Rice Holdings, (iii) 2,356,844 shares of common stock to Daniel J. Rice III, (iv) 20,000,000 shares of common stock to Rice Partners, (v) 160,831 shares of common stock to the persons holding incentive units representing interests in Rice Appalachia and (vi) 1,728,852 shares of common stock to the members of Rice Drilling B (other than Rice Appalachia), each of which were issued by us in connection with the closing of the IPO, and (c) the issuance of 9,523,810 shares of common stock to Alpha Holdings in connection with the completion of the Marcellus JV Buy-In described below under “—Marcellus JV Buy-In,” we had 127,523,810 shares of common stock outstanding.
Marcellus JV Buy-In
On January 29, 2014, in connection with the closing of the IPO and pursuant to the Transaction Agreement between us and Alpha Holdings dated as of December 6, 2013 (the “Transaction Agreement”), we completed our acquisition of Alpha Holdings’ 50% interest in our Marcellus Joint Venture in exchange for total consideration of $300 million, consisting of $100 million of cash and our issuance to Alpha Holdings of 9,523,810 shares of our common stock.
Amendment to Senior Secured Revolving Credit Facility
On January 29, 2014, we, as parent guarantor, and Rice Drilling B, as borrower, entered into an amendment (the “Sixth Amendment”) to the Second Amended and Restated Credit Agreement, dated as of April 25, 2013 with Wells Fargo Bank, N.A., as administrative agent and the lenders and other parties thereto (the “Second Amended and Restated Credit Agreement”). Rice Drilling B is a wholly-owned subsidiary of us. Among other things, the Sixth Amendment (i) added us as a guarantor, (ii) increased the maximum commitment to $1.5 billion from $500.0 million, (iii) increased the borrowing base to $350.0 million from $200.0 million, (iv) lowered the interest rate on amounts borrowed, and (v) allowed for the corporate reorganization that was completed simultaneously with the closing of the IPO.

14


Momentum Acquisition
On February 12, 2014, we, through our indirect wholly-owned subsidiary, Rice Poseidon Midstream LLC, a Delaware limited liability company (“Rice Poseidon”), entered into a purchase and sale agreement (the “Purchase Agreement”) with M3 to acquire (the “Momentum Acquisition”) certain gas gathering assets in eastern Washington and Greene Counties, Pennsylvania, for aggregate consideration of approximately $110.0 million in cash (the “Purchase Price”), subject to customary purchase price adjustments. We expect the Momentum Acquisition to close in the second quarter of 2014, subject to customary closing conditions. The effective date for the Momentum Acquisition is March 1, 2014.
The properties to be acquired in the Momentum Acquisition consist of a 28-mile, 6”-16” gathering system in eastern Washington County, Pennsylvania (the “northern system”), and permits and rights of way in Washington and Greene Counties, Pennsylvania, necessary to construct an 18-mile, 30” gathering system connecting the northern system to the Texas Eastern pipeline. The northern system is supported by long-term contracts with acreage dedications covering approximately 20,000 acres from third parties. Once fully constructed, the acquired systems are expected to have an aggregate capacity of over 1 Bcf/d.
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 U.S. Securities and Exchange Commission (“SEC”).
Reserves Presentation
Our estimated proved reserves and PV-10 as of December 31, 2013 and 2012 are based on evaluations prepared by our independent reserve engineers, NSAI. Copies of the summary reports of NSAI with respect to our reserves as of December 31, 2013 are filed as exhibits to this Annual Report. 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, 2013 and 2012
 
 
Natural Gas
 
 
Estimated Net Reserves (Bcf) (1)
 
 
As of December 31, 2013
 
As of December 31, 2012
 
 
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
 
602

 
382

 
110

 
561

 
304

 
128

Total proved developed reserves
 
250

 
144

 
53

 
131

 
61

 
35

Total proved developed producing reserves
 
177

 
91

 
43

 
101

 
57

 
22

Total proved developed non-producing reserves
 
73

 
53

 
10

 
30

 
4

 
13

Total proved undeveloped reserves
 
352

 
238

 
57

 
430

 
243

 
93

Percent proved developed
 
42
%
 
38
%
 
48
%
 
23
%
 
20
%
 
27
%
PV-10 of proved reserves (in millions) (3)
 
$
709

 
$
417

 
$
146

 
$
245

 
$
102

 
$
71



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(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, 2013
 
3.67

 
3.67

 
3.67

 
3.90

 
3.91

 
3.90

December 31, 2012
 
2.76

 
2.76

 
2.76

 
2.85

 
2.86

 
2.84

(2)
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 revenues. However, the respective historical PV-10s and standardized measures of us and our Marcellus joint venture are equivalent because as of December 31, 2013 and 2012, 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 our IPO, as a result of our corporate reorganization, we became a corporation subject to federal income tax and, as such, 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, 2013, would have been approximately $444 million, $269 million and $175 million, respectively, as adjusted to give effect to the present value of approximately $265 million, $148 million and $117 million, respectively, of future income taxes as a result of our being treated as a corporation for federal income tax purposes. 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 2013 and 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

 
43,629

Conversions into proved developed reserves
 
(33,908
)
 
(15,120
)
 
(9,394
)
Extensions
 
330,851

 
164,561

 
83,145

Price and performance revisions
 
(162,543
)
 
(113,993
)
 
(24,275
)
Proved undeveloped reserves, December 31, 2012
 
429,257

 
243,047

 
93,105

Conversions into proved developed reserves
 
(156,136
)
 
(79,266
)
 
(38,435
)
Extensions
 
105,366

 
65,744

 
19,811

Price and performance revisions
 
(25,510
)
 
8,826

 
(17,168
)
Proved undeveloped reserves, December 31, 2013
 
352,977

 
238,351

 
57,313

(1)
Amounts presented for our Marcellus joint venture give effect to our 50% equity investment in our Marcellus joint venture.
During 2013, on a pro forma basis, extensions, discoveries, and other additions of 105,366 MMcf proved undeveloped reserves were added through the drillbit in the Marcellus Shale. The negative revision was primarily due to four Marcellus joint venture wells being removed from our current development plan. 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 2013, on a pro forma basis, we incurred costs of approximately $156.0 million to convert 156,136 MMcf of proved undeveloped reserves to proved developed reserves. During 2012, on a pro forma basis, we incurred costs of approximately $36.0

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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 as of December 31, 2013 on a pro forma basis are approximately $313.0 million over the next five years, which we expect to finance through proceeds from our IPO, cash flow from operations, borrowings under our revolving credit facility and other sources of capital financing. Our drilling programs are focused on proving our undeveloped leasehold acreage through delineation drilling. While we will continue to drill leasehold delineation wells and build on our current leasehold position, we will also focus on drilling our proved undeveloped reserves. Based on our reserve reports as of December 31, 2013, we had 44 gross (39 net) pro forma locations in the Marcellus Shale associated with proved undeveloped reserves and 13 gross (12 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 “Item 1A. 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 anticipate. Therefore, our estimated proved undeveloped reserves may not be ultimately developed or produced.”
Preparation of Reserve Estimates
Our pro forma reserve estimates as of December 31, 2013 and 2012 included in this Annual Report were based on evaluations prepared by the independent petroleum engineering firm of NSAI 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 Operations, 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 serves as our Vice President of Operations. 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, 2013 and 2012 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 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

17


Annual Report, 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.
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 31, 2013. With respect to our Ohio acreage, as of December 31, 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 31, 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 31, 2013, we had 116 gross (41 net) estimated risked Utica locations. Estimated locations include ununitized locations that have been risked (50% in the Marcellus, 37% in the Utica) to take into account the risk of forming drilling units.
Net Unrisked Locations - Consist of Drillable Locations and Estimated Locations without applying our risking factor. We assume 450 net unrisked Marcellus locations (200 pro forma net drillable Marcellus locations and 250 pro forma net estimated unrisked Marcellus locations). We assume 304 net unrisked Utica locations (192 pro forma net drillable Utica locations and 112 net estimated unrisked Utica locations).
Net Risked Locations - Consist of Drillable Locations and Estimated Locations. We assume 325 net risked Marcellus locations (200 pro forma net drillable Marcellus locations and 125 pro forma net estimated risked Marcellus locations). We assume 233 net risked Utica locations (192 pro forma net drillable Utica locations and 41 net estimated risked Utica locations).
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 “Item 1A. 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

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business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.”
The following table sets forth information regarding production, revenues and realized prices and production costs on a historical basis for the years ended December 31, 2013, 2012 and 2011, for us and our Marcellus joint venture on a standalone basis and on a pro forma basis for the year ended December 31, 2013. Amounts shown for our Marcellus joint venture give effect to the 50% equity investment we held therein as of December 31, 2013. For additional information on price calculations, see information set forth in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.” 
 
 
For the Year Ended December 31,
 
 
2013
 
2012
 
2011
Natural gas sales (in thousands):
 
 
 
 
 
 
Pro Forma Rice Energy Inc.
 
$
178,525

 
 
 
 
Rice Drilling B
 
87,847

 
$
26,743

 
$
13,972

Marcellus Joint Venture
 
45,339

 
13,142

 
2,872

Production data (MMcf):
 
 
 
 
 
 
Pro Forma Rice Energy Inc.
 
45,881

 
 
 
 
Rice Drilling B
 
22,995

 
8,769

 
3,392

Marcellus Joint Venture
 
11,443

 
4,296

 
697

Average prices before effects of hedges per Mcf:
 
 
 
 
 
 
Pro Forma Rice Energy Inc.
 
$
3.89

 
 
 
 
Rice Drilling B
 
3.82

 
$
3.05

 
$
4.12

Marcellus Joint Venture
 
3.96

 
3.06

 
4.12

Average realized prices after effects of hedges per Mcf (1):
 
 
 
 
 
 
Pro Forma Rice Energy Inc.
 
$
4.01

 
 
 
 
Rice Drilling B
 
3.85

 
$
3.15

 
$
4.29

Marcellus Joint Venture
 
4.16

 
3.07

 
4.12

Average costs per Mcf (2):
 
 
 
 
 
 
Pro Forma Rice Energy Inc.:
 
 
 
 
 
 
Lease operating
 
$
0.36

 
 
 
 
Gathering, compression and transportation
 
0.55

 
 
 
 
General and administrative
 
0.44

 
 
 
 
Depletion, depreciation and amortization
 
1.57

 
 
 
 
Rice Drilling B:
 
 
 
 
 
 
Lease operating
 
$
0.36

 
$
0.42

 
$
0.48

Gathering, compression and transportation
 
0.43

 
0.43

 
0.16

General and administrative
 
0.74

 
0.87

 
1.54

Depletion, depreciation and amortization
 
1.43

 
1.61

 
1.76

Marcellus Joint Venture:
 
 
 
 
 
 
Lease operating
 
$
0.36

 
$
0.39

 
$
0.51

Gathering, compression and transportation
 
0.68

 
0.78

 
0.04

General and administrative
 
0.14

 
0.24

 
0.26

Depletion, depreciation and amortization
 
1.09

 
1.10

 
1.57

(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 “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Principal Components of our Cost Structure.”
Productive Wells
As of December 31, 2013, we had a total of 37 gross (34.3 net) producing wells in the Marcellus Shale. We did not have interests in any wells producing oil or NGLs as of December 31, 2013.

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Acreage
The following table sets forth certain information regarding the pro forma total developed and undeveloped acreage in which we owned an interest as of December 31, 2013. Approximately 48% of our pro forma Marcellus acreage and none of our Utica acreage was held by production at December 31, 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
 
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

Undeveloped Acreage Expirations
The following table sets forth the number of pro forma total undeveloped acres as of December 31, 2013 that will expire in 2014, 2015, 2016, 2017 and 2018 and thereafter 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
 
2014
 
2015
 
2016
 
2017
 
2018+
Marcellus—Southwestern Pennsylvania Core
 
1,054

 
2,365

 
3,735

 
2,622

 
12,915

Utica
 

 

 
397

 
33,017

 
15,246

Total
 
1,054

 
2,365

 
4,132

 
35,639

 
28,161

Drilling Activity
The following table describes our drilling activity on our acreage during the years ended December 31, 2013, 2012 and 2011 on a pro forma basis:
 
 
Productive Wells
 
Dry Wells
 
Total
 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
2013
 
23.0

 
20.9

 

 

 
23.0

 
20.9

2012
 
10.0

 
10.0

 

 

 
10.0

 
10.0

2011
 
6.0

 
5.5

 

 

 
6.0

 
5.5

During 2013, we began drilling our Bigfoot 7H well, our first exploratory well in the Utica Shale. Please see “—Utica Shale.” We drilled no exploratory wells during 2012 or 2011.
Major Customers
For the year ended December 31, 2013, sales to Sequent Energy Management, LP (“Sequent”) and Dominion Field Services (“Dominion”) represented 94% and 6% 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 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 its lease’s oil and gas interests. In those cases, such leases are generally voided and payment is not remitted to the lessor. As such, title failures may result in fewer net acres to us. 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

20


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.
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.

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

22


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 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.
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,

23


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 than 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 emissions, water discharges, 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.
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 2014 – 2016 National Enforcement Initiatives include “Assuring Energy Extraction Activities Comply with Environmental Laws.” According to the EPA’s website, “some techniques for natural gas extraction pose a significant risk to public health and the environment.” To address these concerns, the EPA’s goal is to “address incidences of noncompliance from natural gas extraction and production activities that may cause or contribute to significant harm to public health and/or the environment.” The EPA has emphasized that this initiative will be focused on those areas of the country where energy extraction activities are concentrated, and the focus and nature of the enforcement activities will vary with the type of activity and the related pollution problem presented. This initiative could involve a large scale investigation of our facilities and processes, and could lead to potential enforcement actions, penalties or injunctive relief against us.
Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal fines and penalties and the imposition of injunctive relief. Accidental releases or spills may occur in the course of our operations, and we cannot be sure that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons. Although we believe that we are in substantial compliance with

24


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 potentially 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.” Instead, these wastes are regulated under RCRA’s less stringent non hazardous solid waste provisions, state laws or other federal laws. 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.
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 were 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. Federal spill prevention, control and countermeasure requirements 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

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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 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 or 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 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. Furthermore, in response to alleged seismic events near underground injection wells used for the disposal of oil and gas-related wastewaters, some agencies have imposed moratoria on the use of such injection wells. If new regulatory initiatives are implemented that restrict or prohibit the use of underground injection wells in areas where we rely upon the use of such wells in our operations, our costs to operate may significantly increase.

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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.
Available Information
We are required to file annual, quarterly and current reports, proxy statements and other information with the SEC. You may read and copy any documents filed by us with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Our filings with the SEC are also available to the public from commercial document retrieval services and at the SEC’s website at www.sec.gov.
Our common stock is listed and traded on the New York Stock Exchange under the symbol “RICE.” Our reports, proxy statements and other information filed with the SEC can also be inspected and copied at the New York Stock Exchange, 20 Broad Street, New York, New York 10005.
We also make available on our website at www.riceenergy.com all of the documents that we file with the SEC, free of charge, as soon as reasonably practicable after we electronically file such material with the SEC. Information contained on our website is not incorporated by reference into this Annual Report on Form 10-K.


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Item 1A. Risk Factors
Investing in our common stock involves risks. You should carefully consider the information in this Annual Report, 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 affecting 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 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.
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 differentials, 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.

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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 $100.0 million cash paid with respect to the Marcellus JV Buy-In and approximately $110.0 million expected to be paid with respect to the Momentum Acquisition, we plan to invest $1,230.0 million in our operations, including $430.0 million for drilling and completion in the Marcellus Shale, $150.0 million for drilling and completion in the Utica Shale, $385.0 million for leasehold acquisitions and $265.0 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 our IPO. 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 reserve reports. 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 facility; however, our financing needs may require us to alter or increase our capitalization substantially through the issuance of debt or equity securities or the sale of assets. The issuance of additional indebtedness would require that a portion of our cash flow from operations be used for the payment of interest and principal on our indebtedness, thereby reducing our ability to use cash flow from operations to fund working capital, capital expenditures and acquisitions.
Our cash flow from operations and access to capital are subject to a number of variables, including:
our proved reserves;
the level of hydrocarbons we are able to produce from existing wells;
our access to, and the cost of accessing end markets for our production;
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.


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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, including or as a result of the application of these techniques, 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, including or as a result of the application of these techniques, include, but are not limited to, the following:
the ability to fracture stimulate the planned number of stages;
the ability to run tools the entire length of the wellbore during completion operations; and
the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage.
Drilling for and producing natural gas 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 or 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;

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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.
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 $35.8 million and $19.3 million for the year ended December 31, 2013 and 2012, respectively. 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 $1.5 billion first lien secured revolving credit facility (as amended from $500.0 million, effective January 29, 2014) and our $300.0 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 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.
As of March 20, 2014, the borrowing base under our $1.5 billion revolving credit facility was $350.0 million (as amended from $500.0 million and $200.0 million, respectively, effective January 29, 2014). 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. As of December 31, 2013 and 2012, all of our total estimated proved reserves were attributable to properties located in this area. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by

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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 and changes in regional and local political regimes and regulations. Such conditions 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. For example, third parties may engage in subsurface mining operations near or under our properties, which could cause subsidence or other damage to our properties, adversely impact our drilling or adversely impact our midstream activities or those on which we rely. In such event, our operations may be impaired or interrupted, and we may not be able to recover the costs incurred as a result of temporary shut-ins, the plugging and abandonment of any of our wells or the repair of our midstream facilities. Furthermore, the existence of mining operations near our properties could require coordination to avoid adverse impacts as a result of drilling and mining in close proximity. In connection with entering into the Marcellus JV Buy-In, we 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.
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 more developed and have a longer history of established production. 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. We have since spud our second well in the Utica Shale and expect to obtain an initial production test from this well in the second quarter of 2014. 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.
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 “Item 1. 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.

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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 was added in 2013 and 2012, 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 complete the Momentum Acquisition or unable to secure additional gathering and compression capacity and long-term firm takeaway capacity on major pipelines that are in existence or 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.
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 March 1, 2014, our average annual contractual firm transportation and firm sales obligations for 2014, 2015 and 2016 were approximately 330,000 MMBtu/d, 654,000 MMBtu/d, and 761,000 MMBtu/d, respectively, which are in excess of our pro forma average daily gross operated production of approximately 231,000 MMBtu/d for December 2013. 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.

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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 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. As of December 31, 2013, we did not 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. As of March 20, 2014, the borrowing base under our revolving credit facility was $350.0 million (as amended from $200.0 million, effective January 29, 2014). 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 31, 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 62.9 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.
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

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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 31, 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 “Item 1. 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 acres. As of December 31, 2013, on a pro forma basis, we had leases representing 1,054 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, 35,639 undeveloped acres scheduled to expire in 2017 and 28,161 undeveloped acres scheduled to expire in 2018 and thereafter. 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, 2013, 2012 and 2011, 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;

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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 are 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 Annual Report 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 to 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 its lease’s oil and gas interests. In those cases, such leases are generally voided and payment is not remitted to the lessor. As such, title failures may result in fewer net acres to us. Prior to the drilling of an oil or natural gas well, however, it is the normal practice in our industry for the person or company acting as the operator of the well to obtain a preliminary title review to ensure there are no obvious defects in title to the well. Frequently, as a result of such examinations, 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 anticipate. Therefore, our estimated proved undeveloped reserves may not be ultimately developed or produced.
As of December 31, 2013, on a pro forma basis, approximately 58% of our total estimated proved reserves were classified as proved undeveloped. Our approximately 352 Bcf of pro forma estimated proved undeveloped reserves will require an estimated $313 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 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

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our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire sufficient additional reserves to replace our current and future production. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations would be adversely affected.
Conservation measures and technological advances could reduce demand for oil and natural gas.
Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows.
Our derivative activities could result in financial losses or could reduce our earnings.
To achieve more predictable cash flows and reduce our exposure to adverse fluctuations in the prices of natural gas, we enter into derivative instrument contracts for a significant portion of our natural gas production, including fixed-price swaps. As of December 31, 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 62.9 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 December 31, 2013, the estimated fair value of our commodity derivative contracts was approximately $4.0 million. Any default by the counterparties to these derivative contracts, Wells Fargo Bank N.A. and Bank of Montreal, when they become due would have a material adverse effect on our financial condition and results of operations. In addition to the counterparties above at December 31, 2013, subsequent to December 31, 2013, we also executed hedging transactions with Barclays Bank PLC.
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 ($6.4 million at December 31, 2013) and the sale of our natural gas production ($16.5 million in receivables as of December 31, 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 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 year ended December 31, 2013 purchased approximately 94% 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 of 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 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 2014 to 2016, 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.

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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 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. A final rule is expected some time in 2014.
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 final permitting guidance in February 2014 addressing the performance of such activities using diesel fuels in those states where EPA is the permitting authority. Also, in November 2011, the EPA announced its intent to develop and issue regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing 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. Although the Pennsylvania legislature passed legislation to make regulation of drilling uniform through the state, the Pennsylvania Supreme Court in Robinson Township v. Commonwealth of Pennsylvania

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struck down portions of that legislation. 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.
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. For example, the Obama administration recently announced its Climate Action Plan, which, among other things, directs federal agencies to develop a strategy for the reduction of methane emissions, including emissions from the oil and gas sector.
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

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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.
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.

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Since hydraulic fracturing activities are a large part of our operations, they are covered by our insurance against claims made for bodily injury, property damage and clean-up costs stemming from a sudden and accidental pollution event. However, we may not have coverage if we are unaware of the pollution event and unable to report the “occurrence” to our insurance company within the time frame required under our insurance policy. We have no coverage for gradual, long-term pollution events. In addition, these policies do not provide coverage for all liabilities, and we cannot assure you that the insurance coverage will be adequate to cover claims that may arise, or that we will be able to maintain adequate insurance at rates we consider reasonable. A loss not fully covered by insurance could have a material adverse effect on our financial condition, results of operations and cash flows.
We may elect not to obtain insurance for any or all of these risks if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.
Properties that we decide to drill may not yield natural gas, NGLs or oil in commercially viable quantities.
Properties that we decide to drill that do not yield natural gas, NGLs or oil in commercially viable quantities will adversely affect our results of operations and financial condition. Our project areas are in various stages of development, ranging from project areas with current drilling or production activity to project areas that consist of recently acquired leasehold acreage or that have limited drilling or production history. If the wells in the process of being completed do not produce sufficient revenues to return a profit or if we drill dry holes in the future, our business may be materially affected. In addition, there is no way to predict in advance of drilling and testing whether any particular prospect will yield natural gas, NGLs or oil in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of micro-seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether natural gas, NGLs or oil will be present or, if present, whether natural gas, NGLs or oil will be present in commercial quantities. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects. Further, our drilling operations may be curtailed, delayed or cancelled as a result of numerous factors, including:
unexpected drilling conditions;
title problems;
pressure or lost circulation in formations;
equipment failure or accidents;
adverse weather conditions;
compliance with environmental and other governmental or contractual requirements; and
increase in the cost of, 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, such as the Momentum Acquisition. However, we may not be able to identify attractive acquisition opportunities. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms.
The success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions. No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations.

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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, NGLs 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 “Item 1. Business—Regulation of Environmental and Occupational Safety and Health Matters” for a further description of laws and regulations that affect us.
The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our exploration and development plans within our budget and on a timely basis.
The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with natural gas and oil prices, causing periodic shortages. We intend to continue our four-rig drilling program in the Marcellus Shale and 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.

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A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.
Section 1(b) of the Natural Gas Act of 1938, (“NGA”), exempts natural gas gathering facilities from regulation by the Federal Energy Regulatory Commission (“FERC”), as a natural gas company under the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress. If the FERC were to consider the status of an individual facility and determine that the facility 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.
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 more than doubled our employee workforce during 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:

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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 six-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.
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 Commodities 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.

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The Dodd-Frank Act authorized the CFTC to establish rules and regulations setting position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. The CFTC’s initial position limits rules were vacated by the U.S. District Court for the District of Columbia in September 2012. However, on November 5, 2013, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this time.
The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing. The CFTC has not yet proposed rules designating any other classes of swaps, including physical commodity swaps, for mandatory clearing. Although we expect to qualify for the end-user exception from the mandatory clearing and trade execution requirements for swaps entered to hedge its commercial risks, the application of the mandatory clearing and trade execution requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. In addition, for uncleared swaps, the CFTC or federal banking regulators may require end-users to enter into credit support documentation and/or post initial and variation margin. Posting of collateral could impact liquidity and reduce our cash available for capital expenditures, therefore reducing our ability to execute hedges to reduce risk and protect cash flows. The proposed margin rules are not yet final, and therefore the impact of those provisions to us is uncertain at this time.
The Dodd-Frank Act and regulations may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. The Dodd-Frank Act and regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, and reduce our ability to monetize or restructure our existing derivative contracts. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures.
Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and regulations is lower commodity prices.
Any of these consequences could have a material 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 2012, the state legislature of Pennsylvania passed a new natural gas impact fee in Pennsylvania. The legislation imposes an annual fee on natural gas and oil operators for each well drilled for a period of fifteen years. The fee is on a sliding scale set by the Public Utility Commission and is based on two factors: changes in the Consumer Price Index and the average NYMEX natural gas prices from the last day of each month. There can be no assurance that the impact fee will remain as currently structured or that new or additional taxes will not be imposed.
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 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 are required 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 were 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 are required 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, while we anticipate that we will cease to be an “emerging growth company” at the end of 2014, 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 constituted a material weakness in internal controls over financial reporting. If we fail to establish and maintain effective internal control over financial reporting, our ability to accurately report our financial results could be adversely affected.
Prior to the completion of our IPO, we were 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 previously relied on our accounting personnel for its accounting processes. Historically, we and our Marcellus joint venture had not maintained effective internal control environments in that the design and execution of such controls had 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 concluded that these control deficiencies constituted material weaknesses in our control environment for the year ended December 31, 2012. 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 “Item 9A. Controls and Procedures—Material Weaknesses in Internal Control over Financial Reporting.”

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To address these control deficiencies, we have hired additional accounting and financial reporting staff, implemented additional analysis and reconciliation procedures and increased the levels of review and approval. Additionally, we have begun taking steps to comprehensively document and analyze our system of internal control over financial reporting in preparation for our first management report on internal control over financial reporting in connection with our annual report for the year ended December 31, 2014. Due to the recent implementation of these changes to our control environment, management continues to evaluate the design and effectiveness of these control changes in connection with its ongoing evaluation, review, formalization and testing of our internal control environment over the remainder of 2014. We will not complete our review until the second half of 2014 and we cannot predict the outcome of our review at this time. Based upon the status of our review, we and our independent auditors have concluded that the material weakness previously identified had not been remediated as of December 31, 2013. 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 weakness previously identified. Our remediation efforts may not enable us to remedy or avoid material weaknesses or significant deficiencies in the future.
For the year ended December 31, 2013, we were not required to comply with the SEC’s rules implementing Section 404 of the Sarbanes Oxley Act of 2002, which require a formal assessment of the effectiveness of our internal control over financial reporting. As a public company, we are required to comply with the SEC’s rules implementing Section 302 of the Sarbanes Oxley Act of 2002, which 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 have upgraded our systems, including information technology, implemented additional financial and management controls, reporting systems and procedures and hired 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, while we anticipate that we will cease to be an “emerging growth company” at the end of 2014, 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. We can provide no assurance that our independent registered public accounting firm will be satisfied with the level at which our controls are documented, designed, or operating at the time it issues its report.
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.
Rice Holdings, Rice Partners and NGP Holdings collectively hold a substantial majority of our common stock.
Upon the completion of our IPO, Rice Holdings, Rice Partners and NGP Holdings held approximately 15.9%, 15.6% and 18.3% of our common stock, respectively. As such, Rice Holdings, Rice Partners and NGP Holdings 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 are 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.

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The stockholders’ agreement entered into in connection with the completion of our IPO permits our principal stockholders to designate a majority of the members of our board of directors.
In connection with the completion of our IPO, we entered into a stockholders’ agreement with Rice Holdings, Rice Partners, NGP Holdings and Alpha Natural Resources, Inc., pursuant to which Rice Holdings, NGP Holdings and Alpha Natural Resources, Inc. have certain rights relative to designated director nominees and agreed to vote their shares of common stock in accordance with the stockholders’ agreement, including as it relates to the election of directors.

Conflicts of interest could arise in the future between us and one or more of our sponsors concerning among other things, potential competitive business activities or business opportunities. Any actual or perceived conflicts of interest could have an adverse impact on the trading price of our common stock.

Our sponsors include other participants in the energy industry, including Natural Gas Partners, affiliates of Daniel J. Rice III (the Lead Portfolio Manager in the energy division at GRT Capital Partners) and Alpha Natural Resources Inc. Certain of our sponsors and/or their affiliates make investments in the U.S. oil and gas industry from time to time. As a result, our sponsors and/or their affiliates may, from time to time, acquire interests in businesses that directly or indirectly compete with our business, as well as businesses that are significant existing or potential customers. In certain circumstances, they may acquire or seek to acquire assets that we seek to acquire and, as a result, those acquisition opportunities may not be available to us or may be more expensive for us to pursue. Under our certificate of incorporation, certain of our sponsors and/or one or more of their respective affiliates are permitted to engage in business activities or invest in or acquire businesses which may compete with our business or do business with any client of ours.
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.
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, for which there is no guarantee.
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. 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.

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We are a controlled company within the meaning of the NYSE rules and, as a result, qualify for and avail ourself of exemptions from certain corporate governance requirements.
Rice Holdings, Rice Partners, NGP Holdings and Alpha Holdings collectively beneficially control a majority of the combined voting power of all classes of our outstanding voting stock. In connection with the completion of our IPO, we entered 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. have 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. As a result, we are 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 do not apply to us as long as we remain a controlled company. We have elected to utilize some 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.
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 anticipate that we will cease to be an “emerging growth company” at the end of 2014.
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.
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.

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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 designates the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.
Our amended and restated certificate of incorporation provides that unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, 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 is 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.
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
The information required by Item 2 is contained in Item 1. Business.
Item 3. Legal Proceedings
Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not a party to any material legal proceedings. In addition, we are not aware of any material legal or governmental proceedings against us, or contemplated to be brought against us.
Item 4. Mine Safety Disclosures
Not applicable.


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PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Market Information. Our common stock is listed on the NYSE under the symbol “RICE.” As of December 31, 2013, our common stock was not listed on a domestic exchange or over-the-counter market. Our common stock began trading on the NYSE on January 24, 2014.
On March 20, 2014, the last sales price of our common stock, as reported on the NYSE, was $26.11 per share.
Holders. The number of shareholders of record of our common stock was approximately 46 as of March 17, 2014. The number of registered holders does not include holders that have shares of common stock held for them in “street name,” meaning that the shares are held for their accounts by a broker or other nominee. In these instances, the brokers or other nominees are included in the number of registered holders, but the underlying holders of the common stock that have shares held in “street name” are not.
Dividends. We have not paid any cash dividends since our inception. Covenants contained in our revolving credit facility restrict the payment of cash dividends on our common stock. We intend to retain all future earnings for the development and growth of our business, and we do not anticipate declaring or paying any cash dividends to holders of our common stock in the foreseeable future.
Securities Authorized for Issuance under Equity Compensation Plans. See “Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” for information regarding our equity compensation plans as of December 31, 2013.
Unregistered Sales of Securities. There were no sales of unregistered securities during the year ended December 31, 2013.
Use of Proceeds from Registered Securities.
On January 29, 2014, we completed our IPO of common stock pursuant to our registration statement on Form S-1 (File 333-192894) declared effective by the SEC on January 23, 2014. Barclays Capital Inc. acted as 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 acted as the joint book-running managers in the offering. Pursuant to the registration statement, we registered the offer and sale of 50,000,000 shares of our $0.01 par value common stock, which included 30,000,000 shares sold by us, 14,000,000 shares sold by the selling stockholder and 6,000,000 shares subject to an option granted to the underwriters by the selling stockholder. The sale of the shares in our IPO and the sale of shares covered by the option closed on January 29, 2014. Our IPO terminated upon completion of the closing.
The net proceeds of our IPO, based on the public offering price of $21.00 per share, were approximately $993.5 million, which resulted in net proceeds to us of $594.5 million after deducting estimated expenses and underwriting discounts and commissions of approximately $35.5 million and the net proceeds to the selling stockholders of approximately $399.0 million after deducting underwriting discounts of approximately $21.0 million. We did not receive any proceeds from the sale of the shares by the selling stockholder. No fees or expenses have been paid, directly or indirectly, to any officer, director or 10% stockholder or other affiliate. A portion of the net proceeds from our IPO were used to repay all outstanding borrowings under the revolving credit facility of our Marcellus joint venture, to make a $100.0 million payment to Alpha Holdings in partial consideration for the Marcellus JV Buy-In and to repay all outstanding borrowings under our revolving credit facility. The remainder of the net proceeds from our IPO will be used to fund a portion of our capital expenditure plan.
Issuer Purchases of Equity Securities. Neither we nor any “affiliated purchaser” repurchased any of our equity securities in the quarter ended December 31, 2013.


52



Item 6. Selected Financial Data
Set forth below is our selected historical consolidated financial data as of and for the years ended December 31, 2013, 2012 and 2011. The selected historical consolidated financial data set forth below is not intended to replace our historical consolidated financial statements. You should read the following data along with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and related notes, each of which is included in this report. We believe that the assumptions underlying the preparation of our historical consolidated financial statements are reasonable.
 
 
Rice Drilling B
 
 
Year Ended December 31,
(in thousands)
 
2013
 
2012
 
2011
Statement of operations data:
 
 
Revenues:
 
 
 
 
 
 
Natural gas sales
 
$
87,847

 
$
26,743

 
$
13,972

Other revenue
 
757

 
457

 

Total revenues
 
88,604

 
27,200

 
13,972

 
 
 
 
 
 
 
Operating expenses:
 
 
 
 
 
 
Lease operating
 
8,309

 
3,688

 
1,617

Gathering, compression and transportation
 
9,774

 
3,754

 
540

Production taxes and impact fees
 
1,629

 
1,382

 

Exploration
 
9,951

 
3,275

 
660

Restricted unit expense
 
32,906

 

 
170

General and administrative
 
16,953

 
7,599

 
5,208

Depreciation, depletion and amortization
 
32,815

 
14,149

 
5,981

Write-down of abandoned leases
 

 
2,253

 
109

(Gain) loss from sale of interest in gas properties
 
4,230

 

 
(1,478
)
Total operating expenses
 
116,567

 
36,100

 
12,807

 
 
 
 
 
 
 
Operating loss
 
(27,963
)
 
(8,900
)
 
1,165

Interest expense
 
(17,915
)
 
(3,487
)
 
(531
)
Other income (expense)
 
(357
)
 
112

 
161

Gain (loss) on derivative instruments
 
6,891

 
(1,381
)
 
574

Amortization of deferred financing costs
 
(5,230
)
 
(7,220
)
 
(2,675
)
Loss on extinguishment of debt
 
(10,622
)
 

 

Equity in income of joint ventures
 
19,420

 
1,532

 
370

Net loss
 
$
(35,776
)
 
$
(19,344
)
 
$
(936
)
 
 
 
 
 
 
 
Balance sheet data (at period end):
 
 
 
 
 
 
Cash
 
$
31,612

 
$
8,547

 
$
4,389

Total property and equipment, net
 
734,331

 
273,640

 
150,646

Total assets
 
879,810

 
344,971

 
190,240

Total debt
 
426,942

 
149,320

 
107,795

Total members’ capital
 
298,647

 
138,191

 
46,821

Net cash provided by (used in):
 
 
 
 
 
 
Operating activities
 
$
33,672

 
$
(3,014
)
 
$
5,131

Investing activities
 
(458,595
)
 
(119,973
)
 
(79,245
)
Financing activities
 
447,988

 
127,145

 
73,447

Other financial data (Unaudited):
 
 
 
 
 
 
Adjusted EBITDAX
 
$
41,636

 
$
11,768

 
$
7,342


53



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 joint ventures; derivative fair value (gain) loss, excluding net cash receipts on settled derivative instruments; non-cash compensation expense; (gain) loss from sale of interest in gas properties; and exploration expenses. Adjusted EBITDAX is not a measure of net income as determined by United States generally accepted accounting principles, or GAAP.
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.
The following table presents a reconciliation of the non-GAAP financial measure of Adjusted EBITDAX to the GAAP financial measure of net income (loss).
 
Rice Drilling B
 
Year Ended December 31,
(in thousands)
2013
 
2012
 
2011
Adjusted EBITDAX reconciliation to net loss:
 
 
 
 
 
Net loss
$
(35,776
)
 
$
(19,344
)
 
$
(936
)
Interest expense
17,915

 
3,487

 
531

Depreciation, depletion and amortization
32,815

 
14,149

 
5,981

Amortization of deferred financing costs
5,230

 
7,220

 
2,675

Equity in income of joint ventures
(19,420
)
 
(1,532
)
 
(370
)
Write-down of abandoned leases

 
2,253

 
109

Derivative fair value (gain) loss (1)
(6,891
)
 
1,381

 
(574
)
Net cash receipts on settled derivative instruments (1)
676

 
879

 
574

Restricted unit expense
32,906

 

 
170

(Gain) loss from sale of interest in gas properties
4,230

 

 
(1,478
)
Exploration expenses
9,951

 
3,275

 
660

Adjusted EBITDAX
$
41,636

 
$
11,768

 
$
7,342


(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.


54



Item 7. 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 Annual Report. 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 Annual Report, 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 Annual Report. 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) the completion of the corporate reorganization in connection with our initial public offering completed in January 2014 and (ii) the consummation of the Marcellus JV Buy-In, each as described under “Item 1. Business—Recent Developments.”
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.
As of December 31, 2013, we held 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 77 times to 154 MMcf/d for the fourth quarter of 2013. We have drilled and completed 37 pro forma horizontal Marcellus wells and 3 pro forma horizontal Upper Devonian wells as of December 31, 2013 with a 100% success rate (defined as the rate at which wells are completed and produce in commercially viable quantities). As of December 31, 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) pro forma in the Utica Shale and 211 gross (194 net) pro forma in the Upper Devonian Shale.
As of December 31, 2013, our pro forma estimated proved reserves were 602 Bcf, all of which were in southwestern Pennsylvania, with 42% proved developed and 100% natural gas.
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. In the coming years, we expect to derive an increasing amount of our revenues from the sale of natural gas and, in a more limited amount, NGLs, that are produced from our interests in properties located in the Utica 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.

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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 accomplished through over-the-counter commodity derivative contracts with large financial institutions. We use a combination of fixed price natural gas swaps; zero cost collars and deferred puts 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. During the fourth quarter of 2013 we began hedging 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 “Item 7A. 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;
our access to, and the cost of accessing end markets for our production;
the availability of attractive acquisition opportunities and our ability to execute them;
the amount of capital we invest in the leasing and development of our properties;
facility or equipment availability and unexpected downtime;
delays imposed by or resulting from compliance with regulatory requirements; and
the rate at which production volumes on our wells naturally decline.
Factors That Significantly Affect Comparability of Our Financial Condition and Results of Operations
Our historical financial condition and results of operations for the periods presented may not be comparable, either from period to period or going forward, for the following reasons:
Public Company Expenses. As a result of our IPO, we 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 Annual Report are based on the financial statements of Rice Drilling B, our accounting predecessor, prior to our reorganization in connection with our IPO as described in “Item 1. Business—Recent Developments” 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 corporate

56



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 our IPO, we acquired Alpha Holdings’ 50% interest in our Marcellus joint venture and, as a result, for periods following the completion of our IPO, the results of operations of our Marcellus joint venture will be included in our results of operations.
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 did not report any income tax benefit or expense for periods prior to the consummation of our IPO. 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. We drilled 26 horizontal wells in 2013, and we expect to drill approximately 60 gross operated 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. In the first quarter of 2014, we increased to a six-rig drilling program (consisting of three tophole rigs and three horizontal rigs), two of which are operating in the Utica Shale. 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. In April 2013, we entered into our $500.0 million senior secured revolving credit facility, which we refer to as our revolving credit facility, and our $300.0 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 December 31, 2013, the borrowing base under our revolving credit facility was $200.0 million with $115.0 million in borrowings outstanding and $22.5 million of letters of credit outstanding. As of December 31, 2013, the borrowing base under our Marcellus joint venture’s credit facility was $145.0 million. As of December 31, 2013, our Marcellus joint venture had $75.4 million of borrowings and $10.4 million of letters of credit outstanding under the revolving credit facility. The Marcellus joint venture revolving credit agreement was terminated in connection with the closing of the Marcellus JV Buy-In. The primary components of our outstanding debt as December 31, 2013 were $293.8 million outstanding on the term loan. In connection with the completion of our IPO, we entered into an amendment to our revolving credit facility pursuant to which, among other things, the commitment amount was increased to $1.5 billion and the borrowing base was increased to $350.0 million. As of December 31, 2013, on a pro forma basis, we had availability under our revolving credit facility of approximately $317.1 million, as described in “—Recent Developments—Amendment to Senior Secured Revolving Credit Facility.”
During 2013, our capital expenditures were financed with capital contributions from NGP, 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,
 
2013
 
2012
 
2011
NYMEX Henry Hub High
$4.46
 
$3.90
 
$4.85
NYMEX Henry Hub Low
3.11
 
1.91
 
2.99
Differential to Average NYMEX Henry Hub (1)
(0.01)
 
0.08
 
(0.12)

57



(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 a substantial majority of our production to a single natural gas marketer, Sequent. For the year ended December 31, 2013, sales to Sequent and Dominion represented 94% and 6% of our total sales, respectively. 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.
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, delay rental payments and costs incurred in the development of an unsuccessful exploratory well.
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 hold incentive units in Rice Holdings and NGP Holdings that entitle the holder to a portion of distributions by Rice Holdings and NGP Holdings. Please see “Item 11. 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.
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 $8.0 million, $7.7 million and $5.4 million of interest expense for the years ended December 31, 2013, 2012 and 2011, respectively.
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 date with changes in fair value recognized as a gain or

58



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.
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 our IPO, we acquired Alpha Holdings’ 50% interest in our Marcellus joint venture and, as a result, for periods following the completion of our IPO, the results of operations of our Marcellus joint venture will be included in our results of operations.
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 did not report any income tax benefit or expense until the consummation of our IPO. 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 costs, 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 joint ventures; derivative fair value (gain) loss, excluding net cash receipts on settled derivative instruments; non-cash compensation expense; (gain) loss from sale of interest in gas properties; and exploration expenses. Adjusted EBITDAX is not a measure of net income as determined by United States generally accepted accounting principles, or GAAP. For a reconciliation of Adjusted EBITDAX to net income (loss), see “Item 6. Selected Financial Data—Non-GAAP Financial Measures.”
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 31, 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 3.0 Bcf per 1,000 feet, with an average of 1.9 Bcf per 1,000 feet.

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Results of Operations
Year Ended December 31, 2013 Compared to Year Ended December 31, 2012
Below are some highlights of our financial and operating results for the year ended December 31, 2013:
Our production volumes, including our 50% share of the production in our Marcellus joint venture, increased 164% to 34,438 MMcf in the year ended December 31, 2013 compared to 13,065 MMcf in the year ended December 31, 2012.
Our natural gas sales increased 229% to $87.8 million in the year ended December 31, 2013 compared to $26.7 million in the year ended December 31, 2012.
Our per unit cash production costs decreased 15% to $1.60 per Mcf in the year ended December 31, 2013 compared to $1.88 per Mcf in the year ended December 31, 2012. Cash production costs include amounts paid for Pennsylvania impact fees of $0.07 per Mcf and $0.16 per Mcf for the year ended December 31, 2013 and December 31, 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 $0.16 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 relates to wells spud in 2012.
Our general and administrative expenses increased 124% to $17.0 million in the year ended December 31, 2013 compared to $7.6 million for the year ended December 31, 2012.

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The following tables set forth selected operating and financial data for the year ended December 31, 2013 compared to the year ended December 31, 2012:
 
Rice Drilling B
 
 
 
For the Year Ended December 31,
 
Amount of Change
(in thousands)
2013
 
2012
 
Revenues:
 
 
 
 
 
Natural gas sales
$
87,847

 
$
26,743

 
$
61,104

Other revenue
757

 
457

 
300

Total revenues
88,604

 
27,200

 
61,404

 
 
 
 
 
 
Operating expenses:
 
 
 
 
 
Lease operating
8,309

 
3,688

 
4,621

Gathering, compression and transportation
9,774

 
3,754

 
6,020

Production taxes and impact fees
1,629

 
1,382

 
247

Exploration
9,951

 
3,275

 
6,676

Restricted unit expense
32,906

 

 
32,906

General and administrative
16,953

 
7,599

 
9,354

Depreciation, depletion and amortization
32,815

 
14,149

 
18,666

Write-down of abandoned leases

 
2,253

 
(2,253
)
Loss from sale of interest in gas properties
4,230

 

 
4,230

Total operating expenses
116,567

 
36,100

 
80,467

Operating loss
(27,963
)
 
(8,900
)
 
(19,063
)
 
 
 
 
 
 
Other income (expense):
 
 
 
 
 
Interest expense
(17,915
)
 
(3,487
)
 
(14,428
)
Other income (expense)
(357
)
 
112

 
(469
)
Gain (loss) on derivative instruments
6,891

 
(1,381
)
 
8,272

Amortization of deferred financing costs
(5,230
)
 
(7,220
)
 
1,990

Loss on extinguishment of debt
(10,622
)
 

 
(10,622
)
Equity in income of joint ventures
19,420

 
1,532

 
17,888

Total other income (expense)
(7,813
)
 
(10,444
)
 
2,631

Net loss
$
(35,776
)
 
$
(19,344
)
 
$
(16,432
)

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Rice Drilling B
 
 
 
For the Year Ended December 31,
 
Amount of
Change
 
2013
 
2012
 
Natural gas sales (in thousands):
 
 
 
 
 
Rice Drilling B
$
87,847

 
$
26,743

 
61,104

Marcellus Joint Venture (1)
45,339

 
13,142

 
32,197

Production data (MMcf):
 
 
 
 
 
Rice Drilling B
22,995

 
8,769

 
14,226

Marcellus Joint Venture (1)
11,443

 
4,296

 
7,147

Average prices before effects of hedges per Mcf:
 
 
 
 
 
Rice Drilling B
3.82

 
3.05

 
0.77

Marcellus Joint Venture
3.96

 
3.06

 
0.90

Average realized prices after effects of hedges per Mcf