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Rice Energy 10Q - September 30, 2014

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2014

¨ 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.)
400 Woodcliff Drive Canonsburg, Pennsylvania		15317
(Address of principal executive offices)		(Zip code)

(724) 746-6720
(Registrant’s telephone number, including area code)

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. þYes ¨No

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 (§232.405 of this chapter) 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 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

Number of shares of the registrant’s common stock outstanding at November 10, 2014: 136,280,766 shares

RICE ENERGY INC.

QUARTERLY REPORT ON FORM 10-Q

TABLE OF CONTENTS



	Page
Cautionary Statement Regarding Forward-Looking Statements	3
Commonly Used Defined Terms	4

PART I - Financial Information	5
Item 1. Financial Statements	5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
Item 3. Quantitative and Qualitative Disclosures about Market Risk	37
Item 4. Controls and Procedures	38

PART II - Other Information	39
Item 1. Legal Proceedings	39
Item 1A. Risk Factors	39
Item 6. Exhibits	39

Signatures	40
Exhibit Index	41

Cautionary Statement Regarding Forward-Looking Statements

This Quarterly Report on Form 10-Q (the “Quarterly 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 Quarterly 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 Quarterly 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” in (i) our Annual Report on Form 10-K (the “2013 Annual Report”) for the year ended December 31, 2013 and (ii) our Quarterly Report (the “June 30, 2014 Quarterly Report”) for the quarter ended June 30, 2014, each on file with the Securities and Exchange Commission (the “SEC”), and in “Item 1A. Risk Factors” of this Quarterly 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, natural gas liquid (“NGL”) and oil prices;


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


•	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 Quarterly 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 the heading “Item 1A. Risk Factors” in our 2013 Annual Report, our June 30, 2014 Quarterly Report and this Quarterly 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 could 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 Quarterly 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 Quarterly 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 Quarterly Report.

Commonly Used Defined Terms

As used in the Quarterly 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, our wholly-owned subsidiary;


•	“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 Appalachia” refers to Rice Energy Appalachia, LLC, the parent company of Rice Drilling B prior to our initial public offering;


•	“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;


•	“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.

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements

Introduction to the Condensed Consolidated Financial Statements

The unaudited condensed consolidated financial statements have been prepared on the basis that Rice Energy Inc. is a corporation under the Internal Revenue Code subject to federal income tax. The unaudited condensed consolidated financial statements should be read in conjunction with the notes accompanying such unaudited condensed consolidated financial statements as well as “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” each included elsewhere in this Quarterly Report. Please see “—Notes to Condensed Consolidated Financial Statements (Unaudited)—5. Acquisitions” for further details on the purchase price allocations and resulting impact on the corresponding condensed consolidated balance sheet and for the related pro forma information.

The unaudited condensed consolidated financial statements as of and for the three and nine months ended September 30, 2014 reflect the following transactions:

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 NGP Holdings, the selling stockholder in our IPO, and 6,000,000 shares sold 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 $992.6 million, which resulted in net proceeds to us of $593.6 million after deducting expenses and underwriting discounts and commissions of approximately $36.4 million and the net proceeds to the selling stockholder of approximately $399.0 million after deducting expenses and 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 (as defined below) and to repay all outstanding borrowings under our Senior Secured Revolving Credit Facility (as defined below). We used the remainder of the net proceeds from our IPO to fund a portion of our capital expenditure plan.

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 and Rice Drilling B (other than those already held by Rice Appalachia) in exchange for shares of our common stock. Our business continues to be conducted through Rice Drilling B, now a wholly owned subsidiary. This reorganization constituted a common control transaction and the accompanying consolidated financial statements are presented as though this reorganization had occurred for the earliest period presented.

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, we had 127,523,810 shares of common stock outstanding.

Compensation Charge in Connection with the Reorganization

Rice Appalachia, as the parent company of Rice Drilling B, historically granted incentive units to certain members of management and other employees. The incentive units provided the holder with a performance bonus for fair value accretion of Rice Appalachia equity.

In connection with the IPO and the related corporate reorganization, the holders of incentive units in Rice Appalachia contributed their Rice Appalachia incentive units (except for those incentive units related to the incentive burden attributable to Mr. Daniel J. Rice III, which we acquired from the holder of such incentive units in exchange for the issuance of 160,831 shares of our common stock as described above) to Rice Holdings and NGP Holdings in return for substantially similar incentive units in such entities. In the first quarter of 2014, certain incentive units granted by NGP Holdings to certain employees triggered the pre-determined payout criteria, resulting in a cash payment by NGP Holdings of $4.4 million. No payments were made in respect of incentive units prior to the completion of the IPO. The exchange of incentive units and cash payment collectively resulted in non-cash compensation expense of $7.8 million being recorded in the first quarter of 2014 by the Company. As a result of the IPO, the payment likelihood related to the incentive units was deemed probable, requiring the Company to recognize expense.

During the nine months ended September 30, 2014, we recognized approximately $101.7 million of compensation expense relative to these incentive units. We expect to recognize approximately $79.8 million of additional compensation expense over the remaining expected service periods related to the Rice Holdings interests. The NGP Holdings interests are considered a liability-based award and will be adjusted on a quarterly basis until all payments have been made. As of September 30, 2014, the unrecognized compensation expense related to the NGP Holdings units is approximately $77.3 million, which will be recognized over the remaining expected service period. The compensation expense related to these interests is treated as additional paid in capital from Rice Holdings and NGP Holdings in our financial statements and is not deductible for federal or state income tax purposes. The compensation expense recognized is a non-cash charge, with the settlement obligation resting on NGP Holdings and Rice Holdings, and as such are not dilutive to Rice Energy Inc. As of September 30, 2014, approximately $19.8 million had been paid on the incentive units.

In August 2014, the triggering event for the Rice Holdings incentive units was achieved. As a result, in August of 2015, 2016 and 2017, Rice Holdings will distribute one third, one half and all, respectively, of its then-remaining assets (consisting solely of shares of our common stock) to its members pursuant to the terms of its limited liability company agreement. As a result, over time, the shares of our common stock held by Rice Holdings will be transferred in their entirety to Rice Partners (or its successors) and the incentive unitholders.

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, we completed our acquisition of Alpha Holdings’ 50% interest in our Marcellus joint venture in exchange for total consideration of $322.0 million, consisting of $100.0 million of cash and our issuance to Alpha Holdings of 9,523,810 shares of our common stock (the “Marcellus JV Buy-In”). This transaction resulted in a non-recurring gain of $203.6 million in the first quarter of 2014 due to the remeasurement of our previously recorded equity investment at fair value.

Rice Energy Inc.

Condensed Consolidated Balance Sheets

(Unaudited)



(in thousands)	September 30, 2014		December 31, 2013
Assets
Current assets:
Cash	$	131,978	$	31,612
Restricted cash	—		8,268
Accounts receivable	136,560		31,765
Receivable from affiliate	222		2,244
Deposits	760		601
Prepaid expenses and other	2,374		262
Derivative assets	8,546		—
Total current assets	280,440		74,752

Investments in joint ventures	—		49,814
Gas collateral account	3,995		3,700
Proved natural gas properties, net	1,023,603		270,523
Unproved natural gas properties	1,158,483		457,836
Property and equipment, net	13,637		5,972
Deferred financing costs, net	20,452		12,292
Goodwill	338,036		—
Intangible assets, net	48,199		—
Other non-current assets	386		—
Derivative assets	8,555		4,921
Total assets	$	2,895,786	$	879,810

Liabilities and stockholders’ equity
Current liabilities:
Current portion of long-term debt	$	1,006	$	20,120
Accounts payable	95,218		51,219
Royalties payable	28,906		9,393
Accrued interest	24,219		250
Accrued capital expenditures	176,087		16,753
Other accrued liabilities	19,378		8,283
Leasehold payable	24,940		18,606
Derivative liability	—		965
Payable to affiliate	—		6,148
Operated prepayment liability	1,886		1,201
Total current liabilities	371,640		132,938

Long-term liabilities:
Long-term debt	900,000		406,822
Leasehold payable	3,330		1,675
Deferred tax liabilities	199,040		—
Restricted units	—		36,306
Other long-term liabilities	9,218		3,422
Total liabilities	1,483,228		581,163
Stockholders' equity	1,412,558		298,647
Total liabilities and stockholders’ equity	$	2,895,786	$	879,810

The accompanying notes are an integral part of these Condensed Consolidated Financial Statements.

Rice Energy Inc.

Condensed Consolidated Statements of Operations

(Unaudited)



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(in thousands, except share data)	2014			2013			2014			2013
Operating revenues:
Natural gas, oil and natural gas liquids (NGL) sales	$	67,831		$	23,526		$	246,816		$	60,219
Firm transportation sales, net	9,733			—			11,851			—
Other revenue	1,563			163			2,878			580
Total operating revenues	79,127			23,689			261,545			60,799

Operating expenses:
Lease operating	4,553			1,777			16,406			5,794
Gathering, compression and transportation	9,597			3,365			25,904			6,951
Production taxes and impact fees	1,114			522			2,624			1,029
Exploration	747			338			1,706			1,784
Incentive unit expense	26,418			—			101,695			—
Restricted unit expense	—			32,381			—			40,087
Stock compensation expense	2,058			—			3,274			—
General and administrative	10,458			4,169			36,733			9,952
Depreciation, depletion and amortization	33,853			9,722			91,912			23,215
Acquisition expense	2,246			—			2,246			—
Amortization of intangible assets	408			—			748			—
Total operating expenses	91,452			52,274			283,248			88,812

Operating loss	(12,325		)	(28,585		)	(21,703		)	(28,013		)
Interest expense	(15,754		)	(5,943		)	(38,737		)	(13,033		)
Gain on purchase of Marcellus joint venture	—			—			203,579			—
Other income (loss)	(216		)	38			180			(408		)
Gain on derivative instruments	36,935			8,050			5,357			16,698
Amortization of deferred financing costs	(707		)	(958		)	(1,728		)	(4,760		)
Loss on extinguishment of debt	(790		)	(10,622		)	(3,934		)	(10,622		)
Write-off of deferred financing costs	—			—			(6,896		)	—
Equity in income (loss) of joint ventures	—			4,368			(2,656		)	19,297
Income (loss) before income taxes	7,143			(33,652		)	133,462			(20,841		)
Income tax expense	(14,005		)	—			(18,787		)	—

Net income (loss)	$	(6,862	)	$	(33,652	)	$	114,675		$	(20,841	)
Weighted average number of shares of common stock - basic	132,269,081			88,000,000			125,411,524			77,894,855
Weighted average number of shares of common stock - diluted	132,269,081			88,000,000			125,678,095			77,894,855
Earnings (loss) per share—basic	$	(0.05	)	$	(0.38	)	$	0.91		$	(0.27	)
Earnings (loss) per share—diluted	$	(0.05	)	$	(0.38	)	$	0.91		$	(0.27	)
Pro forma income tax benefit							$	5,560
Pro forma net income							$	120,235
Earnings per share—basic							$	0.96
Earnings per share—diluted							$	0.96

The accompanying notes are an integral part of these Condensed Consolidated Financial Statements.

Rice Energy Inc.

Condensed Consolidated Statements of Cash Flows

(Unaudited)



	Nine Months Ended September 30,
(in thousands)	2014			2013
Cash flows from operating activities:
Net income (loss)	$	114,675		$	(20,841	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	91,912			23,215
Amortization of deferred financing costs	1,728			4,760
Amortization of intangibles	748			—
Incentive unit expense	101,695			—
Write-off of deferred financing costs	6,896			—
Loss on extinguishment of debt	3,934			—
Restricted unit expense	—			40,087
Stock compensation expense	3,274			—
Derivative instruments fair value gain	(5,357		)	(16,698		)
Cash payments for settled derivatives	(20,782		)	(1,053		)
Deferred income tax expense	18,787			—
Fair value gain on purchase of Marcellus joint venture	(203,579		)	—
Equity in (income) loss of joint ventures	2,656			(19,297		)
(Increase) decrease in:
Accounts receivable	(89,443		)	(12,398		)
Receivable from affiliate	2,033			6,897
Gas collateral account	—			4,343
Prepaid expenses and other	(2,165		)	(270		)
Increase (decrease) in:
Accounts payable	2,845			(133		)
Royalties payable	11,605			5,916
Accrued interest	23,315			(1,324		)
Other accrued expenses	14,546			5,029
Payable to affiliate	(9,644		)	4,258
Net cash provided by operating activities	69,679			22,491

Cash flows from investing activities:
Capital expenditures for natural gas properties	(634,129		)	(341,347		)
Acquisition of Marcellus joint venture, net of cash acquired	(82,766		)	—
Acquisition of Momentum assets	(111,447		)	—
Acquisition of Greene County assets	(329,469		)	—
Capital expenditures for property and equipment	(8,279		)	(1,278		)
Proceeds from sale of interest in gas properties	11,542			—
Net cash used in investing activities	(1,154,548		)	(342,625		)

Cash flows from financing activities:
Proceeds from borrowings	900,000			321,003
Repayments of debt obligations	(498,983		)	(159,726		)
Restricted cash for convertible debt	8,268			(8,268		)
Debt issuance costs	(19,401		)	(9,480		)
Common stock issuance	—			197,987
Repurchase of common stock	—			(2,267		)
Costs relating to IPO	(1,412		)	—
Proceeds from conversion of warrants	1,975			—
Proceeds from issuance of common stock sold in IPO, net of underwriting fees	598,500			—
Costs relating to August 2014 Equity Offering	(784		)	—
Proceeds from issuance of common stock sold in August 2014 Equity Offering, net of underwriting fees	197,072			—
Net cash provided by financing activities	1,185,235			339,249

Net increase in cash	100,366			19,115
Cash at the beginning of the year	31,612			8,547
Cash at the end of the period	$	131,978		$	27,662

The accompanying notes are an integral part of these Condensed Consolidated Financial Statements.

Rice Energy Inc.

Statements of Condensed Consolidated Equity

(Unaudited)



(in thousands)	Common Stock ($0.01 par)		Additional Paid-In Capital		Accumulated Deficit			Total
Balance, January 1, 2013	$	622	$	166,901	$	(29,332	)	$	138,191
Capital contributions, net	258		197,732		—			197,990
Consolidated net loss	—		—		(20,841		)	(20,841		)
Balance, September 30, 2013	$	880	$	364,633	$	(50,173	)	$	315,340



(in thousands)	Common Stock ($0.01 par)		Additional Paid-In Capital			Accumulated (Deficit) Earnings			Total
Balance, January 1, 2014	$	880	$	362,875		$	(65,108	)	$	298,647
Shares of common stock issued in initial public offering, net of offering costs	300		593,113			—			593,413
Shares of common stock issued in purchase of Marcellus joint venture	95		221,905			—			222,000
Conversion of restricted units into shares of common stock at IPO	—		36,306			—			36,306
Conversion of convertible debentures into shares of common stock after IPO	6		6,599			—			6,605
Conversion of warrants into shares of common stock after IPO	7		1,968			—			1,975
Shares of common stock issued in August 2014 Equity Offering, net of offering costs	75		196,213			—			196,288
Incentive unit compensation	—		101,695			—			101,695
Stock compensation	—		3,274			—			3,274
Tax impact of IPO and corporate reorganization	—		(162,320		)	—			(162,320		)
Consolidated net income	—		—			114,675			114,675
Balance, September 30, 2014	$	1,363	$	1,361,628		$	49,567		$	1,412,558

The accompanying notes are an integral part of these Condensed Consolidated Financial Statements.

Rice Energy Inc.

Notes to Condensed Consolidated Financial Statements

(Unaudited)


1.	Basis of Presentation

The accompanying unaudited condensed consolidated financial statements of Rice Energy Inc. (the “Company,” “we,” “our,” and “us”) have been prepared by the Company’s management in accordance with generally accepted accounting principles in the United States (“GAAP”) for interim financial information and applicable rules and regulations promulgated under the Exchange Act. Accordingly, they do not include all of the information and footnotes required by GAAP for annual financial statements. The unaudited condensed consolidated financial statements included herein contain all adjustments which are, in the opinion of management, necessary to present fairly the Company’s financial position as of September 30, 2014 and its condensed consolidated statements of operations for the three and nine months ended September 30, 2014 and 2013 and of cash flows for the nine months ended September 30, 2014 and 2013. The condensed consolidated statements of operations for the three and nine months ended September 30, 2014 and 2013 are not necessarily indicative of the results to be expected for future periods. 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 and Rice Drilling B (other than those already held by Rice Appalachia) in exchange for shares of our common stock. Our business continues to be conducted through Rice Drilling B, now a wholly owned subsidiary. This reorganization constituted a common control transaction and the accompanying consolidated financial statements are presented as though this reorganization had occurred for the earliest period presented. These condensed consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes therein for the year ended December 31, 2013, as filed with the Securities and Exchange Commission by the Company in its 2013 Annual Report. Certain prior period financial statement amounts have been reclassified to conform to current period presentation.


2.	Long-Term Debt

Long-term debt consists of the following as of September 30, 2014 and December 31, 2013:



(in thousands)	September 30, 2014		December 31, 2013
Long-term Debt
Senior Notes Due 2022^(a)	$	900,000	$	—
Second Lien Term Loan Facility ^(b)	—		293,821
Senior Secured Revolving Credit Facility ^(c)	—		115,000
Debentures ^(d)	—		6,890
NPI Note	—		8,028
Other	1,006		3,203
Total debt	$	901,006	$	426,942
Less current portion	1,006		20,120
Long-term debt	$	900,000	$	406,822

6.25% Senior Notes Due 2022 (a)

On April 25, 2014, the Company issued $900.0 million (the “Senior Notes Offering”) in the aggregate principal amount of 6.25% senior notes due 2022 (the “Notes”) in a private placement to eligible purchasers under Rule 144A and Regulation S of the Securities Act, which resulted in net proceeds of $882.7 million, after deducting expenses and the initial purchasers' discounts of approximately $17.3 million. The Company used $301.8 million of the net proceeds to repay and retire the Second Lien Term Loan Facility (defined below), with the remainder having been used to fund a portion of the Company’s 2014 capital expenditure program.

The Notes will mature on May 1, 2022, and interest is payable on the Notes on each May 1 and November 1. At any time prior to May 1, 2017, the Company may redeem up to 35% of the Notes at a redemption price of 106.25% of the principal amount, plus accrued and unpaid interest to the redemption date, with the proceeds of certain equity offerings so long as the redemption occurs within 180 days of completing such equity offering and at least 65% of the aggregate principal amount of the Notes remains outstanding after such redemption. Prior to May 1, 2017, the Company may redeem some or all of the notes for cash at a redemption price equal to 100% of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date. Upon the occurrence of a Change of Control (as defined in the indenture governing the notes (the “Indenture”), unless the Company has given notice to redeem the Notes, the holders of the Notes will have the right to require the Company to repurchase all or a portion of the Notes at a price equal to 101% of the aggregate principal amount of the

Notes, plus any accrued and unpaid interest to the date of purchase. On or after May 1, 2017, the Company may redeem some or all of the Notes at redemption prices (expressed as percentages of principal amount) equal to 104.688% for the twelve-month period beginning on May 1, 2017, 103.125% for the twelve-month period beginning May 1, 2018, 101.563% for the twelve-month period beginning on May 1, 2019 and 100.000% beginning on May 1, 2020, plus accrued and unpaid interest to the redemption date.

The Notes are the Company’s senior unsecured obligations, rank equally in right of payment with all of the Company’s existing and future senior debt, and will rank senior in right of payment to all of the Company’s future subordinated debt. The Notes will be effectively subordinated to all of the Company’s existing and future secured debt to the extent of the value of the collateral securing such indebtedness.

The Company, as the parent company, has no independent assets or operations. The Notes are guaranteed on a senior unsecured basis by the Guarantors (as defined in the Indenture). The guarantees are full and unconditional, subject to customary exceptions pursuant to the Indenture, as discussed below. Other than the Guarantors, Company has no subsidiaries other than minor subsidiaries. In addition, there are no restrictions on the ability of the Company to obtain funds from its subsidiary by dividend or loan. Finally, the Company’s wholly-owned subsidiaries do not have restricted assets that exceed 25% of net assets as of the most recent fiscal year end that may not be transferred to the Company in the form of loans, advances or cash dividends by the subsidiary without the consent of a third party.

Guarantees of the Notes will be released under certain circumstances, including:


•	in connection with any sale or other disposition of all or substantially all of the assets of that Guarantor (including by way of merger or consolidation) to a person that is not (either before or after giving effect to such transaction) the Company or a Restricted Subsidiary (as defined in the Indenture) of the Company;

•

in connection with any sale or other disposition of the capital stock of that Guarantor (including by way of merger or consolidation) to a person that is not (either before or after giving effect to such transaction) the Company or a Restricted Subsidiary of the Company, such that, immediately after giving effect to such transaction, such Guarantor would no longer constitute a subsidiary of the Company;


•	if the Company designates any Restricted Subsidiary that is a Guarantor to be an unrestricted subsidiary in accordance with the Indenture;


•	upon legal defeasance or satisfaction and discharge of the Indenture; or


•	if such Guarantor ceases to guarantee any other indebtedness of the Company or a Guarantor under a credit facility, provided no Event of Default (as defined in the Indenture) has occurred and is continuing.

The Indenture restricts the Company’s ability and the ability of certain of its subsidiaries to: (i) incur or guarantee additional debt or issue certain types of preferred stock; (ii) pay dividends on capital stock or redeem, repurchase or retire our capital stock or subordinated debt; (iii) make certain investments; (iv) incur liens; (v) enter into transactions with affiliates; (vi) merge or consolidate with another company; (vii) transfer and sell assets; and (viii) create unrestricted subsidiaries. These covenants are subject to a number of important exceptions and qualifications. If at any time when the Notes are rated investment grade by both Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no default (as defined in the Indenture) has occurred and is continuing, many of such covenants will terminate and the Company and its subsidiaries will cease to be subject to such covenants.

The Indenture contains customary events of default, including:


•	default in any payment of interest on any Note when due, continued for 30 days;


•	default in the payment of principal of or premium, if any, on any Note when due;


•	failure by the Company to comply with its other obligations under the Indenture, in certain cases subject to notice and grace periods;


•	payment defaults and accelerations with respect to other indebtedness of the Company and its Restricted Subsidiaries (as defined in the Indenture) in the aggregate principal amount of $25.0 million or more;


•	certain events of bankruptcy, insolvency or reorganization of the Company or a Significant Subsidiary (as defined in the Indenture) or group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary;


•	failure by the Company or Restricted Subsidiary to pay certain final judgments aggregating in excess of $25.0 million within 60 days; and


•	any guarantee of the Notes by a Guarantor ceases to be in full force and effect, is declared null and void in a judicial proceeding or is denied or disaffirmed by its maker.

In connection with the issuance and sale of the Notes, the Company and certain of the Company's subsidiaries (the “Guarantors”) entered into a registration rights agreement with the Initial Purchasers, dated April 25, 2014. Pursuant to the registration rights agreement, the Company and the Guarantors have agreed to file a registration statement with the Securities and Exchange Commission so that holders of the Notes can exchange the Notes for registered notes that have substantially identical terms as the Notes. In addition, the Company and the Guarantors have agreed to exchange the guarantee related to the Notes for a registered guarantee having substantially the same terms as the original guarantee. The Company and the Guarantors will use commercially reasonable efforts to cause the exchange to be completed within 365 days after the issuance of the Notes. The Company and the Guarantors are required to pay additional interest if they fail to comply with their obligations to register the Notes within the specified time periods.

Second Lien Term Loan Facility (b)

On April 25, 2013, Rice Drilling B entered into a Second Lien Term Loan Facility (“Second Lien Term Loan Facility”) with Barclays Bank PLC, as administrative agent, and a syndicate of lenders in an aggregate principal amount of $300.0 million. Rice Drilling B estimated the discount on issuance of this instrument based upon an estimate of market rates at the inception of the instrument and recorded a discount of $4.5 million. The discount was being amortized over the life of the note using an effective interest rate of 0.284%. Approximately $7.4 million in fees were capitalized in connection with the Second Lien Term Loan Facility.

On April 25, 2014, the Company used a portion of the net proceeds from the Senior Notes Offering to repay and retire the Second Lien Term Loan Facility in the amount of $301.8 million. The payment was comprised of repayment of the principal balance of $297.0 million, a pre-payment penalty of $0.8 million and accrued but unpaid interest of $1.8 million. The pre-payment penalty is presented as loss on extinguishment of debt in the condensed consolidated statements of operations for the nine months ended September 30, 2014. The pre-payment also resulted in a debt extinguishment and subsequent write-off of the unamortized deferred finance costs of $6.9 million presented in the condensed consolidated statements of operations for the nine months ended September 30, 2014.

Senior Secured Revolving Credit Facility (c)

On April 25, 2013, Rice Drilling B entered into a Senior Secured Revolving Credit Facility (“Senior Secured Revolving Credit Facility”) with Wells Fargo Bank, N.A., as administrative agent, and a syndicate of lenders with a maximum credit amount of $500.0 million and a sublimit for letters of credit of $10.0 million. Concurrently with the closing of the IPO, on January 29, 2014, Rice Drilling B amended its Senior Secured Revolving Credit Facility to, among other things, allow for the corporate reorganization that was completed simultaneously with the closing of the IPO, add the Company as a guarantor, increase the maximum commitment amount to $1.5 billion and lower the interest rate on amounts borrowed under the Senior Secured Revolving Credit Facility. The Company used a portion of the net proceeds of the IPO to repay $115.0 million of borrowings under the Senior Secured Revolving Credit Facility. After giving effect to the amendment, the borrowing base under the Senior Secured Revolving Credit Facility was increased to $350.0 million as a result of the Marcellus JV Buy-In.

In April 2014, concurrently with the Senior Notes Offering, the Company, as borrower, and Rice Drilling B, as predecessor borrower, amended and restated its Senior Secured Revolving Credit Facility (“Amended Credit Agreement”) to, among other things, assign all of the rights and obligations of Rice Drilling B as borrower under the Senior Secured Revolving Credit Facility to the Company. Furthermore, the Amended Credit Agreement (i) allowed for the issuance of the Notes described below and (ii) provided that the Company did not incur an immediate reduction in the borrowing base under the Senior Secured Revolving Credit Facility as a result of the issuance of the Notes. As such, the borrowing base under the Amended Credit Agreement immediately following the issuance of the Notes remained at $350.0 million. The Amended Credit Agreement also extended the maturity date of the Senior Secured Revolving Credit Facility from April 25, 2018 to January 29, 2019. The amount available to be borrowed under the Amended Credit Agreement is subject to a semi-annual borrowing base redetermination that depends on, among other factors, the volumes of the Company’s proved oil and gas reserves. A redetermination occurred in May 2014, which increased the borrowing base to $385.0 million. As of September 30, 2014, the borrowing base was $385.0 million and the sublimit for letters of credit was $100.0 million. The Company had zero borrowings outstanding and $66.8 million in letters of credit outstanding under its Amended Credit Agreement as of September 30, 2014, resulting in availability of $318.2 million. In October 2014, a subsequent redetermination occurred which increased the borrowing base to $550.0 million. The next redetermination is scheduled for April 2015 based on the redetermination criteria as of January 1, 2015.

Eurodollar loans under the Senior Secured Revolving Credit Facility bear interest at a rate per annum equal to LIBOR plus an applicable margin ranging from 150 to 250 basis points, depending on the percentage of borrowing base utilized. Base rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank’s reference rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the rate for one month Eurodollar loans plus 100 basis points, plus an applicable margin ranging from 50 to 150 basis points, depending on the percentage of borrowing base utilized.

The Amended Credit Agreement is secured by liens on at least 80% of the proved oil and gas reserves of the Company and its subsidiaries (other than any subsidiary that is designated as an unrestricted subsidiary), as well as significant unproved acreage and substantially all of the personal property of the Company and such restricted subsidiaries, and the Amended Credit Agreement is guaranteed by such restricted subsidiaries. The Amended Credit Agreement contains restrictive covenants that limit the ability of the Company and its restricted subsidiaries to, among other things:


•	incur additional indebtedness;


•	sell assets;


•	make loans to others;


•	make investments;


•	enter into mergers;


•	make or declare dividends;


•	hedge future production or interest rates;


•	incur liens; and


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

The Amended Credit Agreement also requires the Company to maintain certain financial ratios, which are measured at the end of each calendar quarter:


•	a current ratio, which is the ratio of consolidated current assets (including unused commitments under the Amended Credit Agreement and excluding non-cash derivative assets) to consolidated current liabilities (excluding current maturities under the Amended Credit Agreement and non-cash derivative liabilities), of not less than 1.0 to 1.0; and


•	a minimum interest coverage ratio, which is the ratio of consolidated EBITDAX (as such term is defined in the Amended Credit Agreement) based on the trailing 12 month period to consolidated interest expense, of not less than 2.5 to 1.0.

The Company was in compliance with such covenants and ratios effective as of September 30, 2014.

Debentures (d)

In June of 2011, Rice Drilling B sold $60.0 million of its 12% Senior Subordinated Convertible Debentures due 2014 (the “Debentures”) in a private placement to certain accredited investors as defined in Rule 501 of Regulation D. The Debentures accrued interest at 12% per year payable monthly in arrears by the 15th day of the month and had a scheduled maturity date of July 31, 2014 (“Maturity Date”). The Debentures were Rice Drilling B’s unsecured senior obligations and ranked equally with all of Rice Drilling B’s then-current and future senior unsecured indebtedness.

From July 31, 2013 through August 20, 2013 (the “put redemption period”), any holder of Debentures had the right to cause Rice Drilling B to repurchase all or any portion of the Debentures owned by such holder at 100% of the portion of the principal amount of the Debentures as to which the right was being exercised, plus a premium of 20%. During the put redemption period, Rice Drilling B repurchased $53.1 million of outstanding Debentures and paid a put premium of $10.6 million in accordance with the terms of the agreements.

At any time after July 31, 2013 until the Maturity Date, Rice Drilling B had the right to redeem all, but not less than all, of the Debentures on 30 days prior written notice at a redemption price equal to 100% of the principal amount of the Debentures plus a premium of 50%. In connection with the IPO, the Debentures and warrants of Rice Drilling B were amended to become convertible or exercisable for shares of common stock of the Company. On February 28, 2014, Rice Drilling B issued a redemption notice on the remaining Debentures, which set a redemption date of March 28, 2014. Prior to the redemption date, $6.6 million of the Debentures were converted into 570,945 shares of the Company's common stock. The remaining principal balance of $0.3 million that was not converted will be paid upon request from holders of the remaining Debentures. The premium

of $0.1 million was recorded to expense in the nine months ended September 30, 2014. As of September 30, 2014, the remaining principal balance was $0.2 million.

In connection with the convertible debenture offering, Rice Drilling B granted warrants that were issued on August 15, 2011 to certain of the broker-dealers involved in the private placement. These warrants are considered to be separate instruments issued solely in lieu of cash compensation for services provided by the broker-dealers. Two separate classes of warrants were issued with the sole difference being the exercise price. At September 30, 2014, 90 warrants remain exercisable at a weighted average price of $11.57 per share of the Company's common stock. The 90 warrants are exercisable in exchange for up to 77,363 shares. For the three and nine months ended September 30, 2014, warrants were exercised in exchange for 126,240 and 686,006 shares of the Company's common stock, respectively.

Expected Aggregate Maturities

Expected aggregate maturities of notes payable as of September 30, 2014 are as follows (in thousands):



Remainder of Year Ending December 31, 2014	$	326
Year Ending December 31, 2015	680
Year Ending December 31, 2016	—
Year Ending December 31, 2017	—
Year Ending December 31, 2018 and Beyond	900,000
Total	$	901,006

Interest paid in cash was $30 thousand and $8.9 million for the three and nine months ended September 30, 2014, respectively, and $6.5 million and $17.2 million for the three and nine months ended September 30, 2013, respectively.


3.	Derivative Instruments

The Company uses derivative commodity instruments that are placed with major financial institutions whose creditworthiness is regularly monitored. Our derivative counterparties share in the Amended Credit Agreement collateral. The Company’s derivative commodity instruments have not been designated as hedges for accounting purposes; therefore, all gains and losses are recognized in income currently. As of September 30, 2014, the Company has entered into derivative instruments with various financial institutions, fixing the price it receives for a portion of its natural gas through December 1, 2017, as summarized in the following table:



Swap Contract Expiration	MMBtu/day	Weighted Average Price
Fourth quarter of 2014	173,000	$	4.15
2015	166,000	$	4.09
2016	214,000	$	4.14
2017	60,000	$	4.24



Collar Contract Expiration	MMBtu/day	Floor/Ceiling
Fourth quarter of 2014	10,000	$3.00/$5.80
2015	139,000	$3.96/$4.65



Basis Contract Expiration	MMBtu/day	Swap ($/MMBtu)
Fourth quarter of 2014	60,000	$	(0.46	)
2015	62,000	$	(0.57	)
2016	38,000	$	(0.63	)

The following tables present the gross amounts of recognized derivative assets and liabilities, the amounts offset under netting arrangements with counterparties, and the resulting net amounts presented in the condensed consolidated balance sheets for the periods presented, all at fair value:



	As of September 30, 2014
(in thousands)	Derivative instruments, recorded in the Condensed Consolidated Balance Sheet, gross		Derivative instruments subject to master netting arrangements			Derivative Instruments, net
Derivative assets	$	39,672	$	(22,571	)	$	17,101
Derivative liabilities	$	22,571	$	(22,571	)	$	—

	As of December 31, 2013
(in thousands)	Derivative instruments, recorded in the Condensed Consolidated Balance Sheet, gross		Derivative instruments subject to master netting arrangements			Derivative Instruments, net
Derivative assets	$	13,000	$	(4,700	)	$	8,300
Derivative liabilities	$	256	$	(4,600	)	$	(4,344	)

The following table presents the realized and unrealized gains or losses presented as gain or loss on derivatives in the condensed consolidated statements of operations for the periods presented:



	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2014		2013		2014			2013
Realized gain (loss)	$	171	$	788	$	(20,782	)	$	(1,053	)
Unrealized gain	$	36,764	$	7,262	$	26,139		$	17,751


4.	Fair Value of Financial Instruments

The Company determines fair value on a recurring basis for its liability related to restricted units and recorded amounts for derivative instruments as these instruments are required to be recorded at fair value for each reporting amount. Certain amounts in the Company’s financial statements were measured at fair value on a nonrecurring basis including discounts associated with long-term debt. Fair value is based on quoted market prices, where available. If quoted market prices are not available, fair value is based upon models that use as inputs market-based parameters, including but not limited to forward curves, discount rates, broker quotes, volatilities, and nonperformance risk.

The Company has categorized its fair value measurements into a three-level fair value hierarchy, based on the priority of the inputs to the valuation technique. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets and liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). The Company’s fair value measurements relating to restricted units are included in Level 3. The Company’s fair value measurements relating to derivative instruments are included in Level 2. Since the adoption of fair value accounting, the Company has not made any changes to its classification of financial instruments in each category.

Items included in Level 3 are valued using internal models that use significant unobservable inputs. Items included in Level 2 are valued using management’s best estimate of fair value corroborated by third-party quotes.

The following assets and liabilities were measured at fair value on a recurring basis during the period (refer to Note 3 for details relating to derivative instruments):



	As of September 30, 2014
(in thousands)			Fair Value Measurements at Reporting Date Using
(in thousands)	Carrying Value		Total Fair Value		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Assets:
Derivative instruments, at fair value	$	17,101	$	17,101	$	—	$	17,101	$	—
Total assets	$	17,101	$	17,101	$	—	$	17,101	$	—

Liabilities:
Derivative instruments, at fair value	$	—	$	—	$	—	$	—	$	—
Total liabilities	$	—	$	—	$	—	$	—	$	—



	As of December 31, 2013
			Fair Value Measurements at Reporting Date Using
(in thousands)	Carrying Value		Total Fair Value		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Assets:
Derivative instruments, at fair value	$	4,921	$	4,921	$	—	$	4,921	$	—
Total assets	$	4,921	$	4,921	$	—	$	4,921	$	—

Liabilities:
Restricted units, at fair value	$	36,306	$	36,306	$	—	$	—	$	36,306
Derivative instruments, at fair value	965		965		—		965		—
Total liabilities	$	37,271	$	37,271	$	—	$	965	$	36,306



	Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
(in thousands)	2014			2013
Balance as of January 1,	$	36,306		$	5,667
Total gain or losses:
Included in earnings	—			—
Transfers in and/or out of Level 3	—			—
Repurchase of restricted units	—			(2,267		)
Converted to shares of common stock	(36,306		)	—
Balance as of September 30,	$	—		$	3,400

Gains and losses related to restricted units included in earnings for the period are reported in operating expenses in the statements of consolidated operations.

The carrying value of cash equivalents approximates fair value due to the short maturity of the instruments.

The estimated fair value and carrying amount of long-term debt as reported on the condensed consolidated balance sheets as of September 30, 2014 and December 31, 2013 is shown in the table below (refer to Note 2 for details relating to the borrowing arrangements). The fair value was estimated using Level 2 inputs based on rates reflective of the remaining maturity as well as the Company’s financial position.



	As of September 30, 2014				As of December 31, 2013
Long-Term Debt (in thousands)	Carrying Value		Fair Value		Carrying Value		Fair Value
Senior Notes Offering	$	900,000	$	866,864	$	—	$	—
Second Lien Term Loan Facility	—		—		293,821		315,284
Senior Secured Revolving Credit Facility	—		—		115,000		115,000
Debentures	—		—		6,890		12,671
NPI Note	—		—		8,028		8,028
Other	1,006		1,006		3,203		3,203
Total	$	901,006	$	867,870	$	426,942	$	454,186


5.	Acquisitions

Marcellus JV Buy-In

Prior to the completion of the Marcellus JV Buy-In, the Company accounted for its 50% equity interest in the Marcellus joint venture under the equity method of accounting. Immediately prior to the completion of the Marcellus JV Buy-In, the fair value of the existing equity in the Marcellus joint venture was approximately $250.6 million. The acquisition date fair value of the existing equity investment was based on an income approach. The income approach, considered to be a Level 3 fair value method, calculated the present value of the future cash flows related to the natural gas properties as of the date of the transaction, utilizing a discount rate based upon market participant assumptions, natural gas strip prices as of the date of the transaction, and a decline curve consistent with our geographic peers. As a result of the Marcellus JV Buy-In, the Company was required to remeasure its equity investment at fair value, which resulted in a non-recurring gain of approximately $203.6 million during the nine months ended September 30, 2014. Based on valuations performed as of the acquisition date, the natural gas properties had a fair value of approximately $343.0 million. The acquisition consolidated the resources of the Company and the Marcellus joint venture, which enables management to optimize and prioritize the development of their combined natural gas properties. The management team of the Company historically served as the management team of the Marcellus joint venture, providing it with familiarity with its assets and operations. As a result of these factors, the excess purchase price over net assets and liabilities assumed of $338.0 million was allocated to goodwill.

The purchase price allocation and resulting impact on the corresponding condensed consolidated balance sheet relating to the Marcellus JV Buy-In is as follows:



(in thousands)
Financial assets	$	34,242
Proved natural gas properties, net	288,000
Unproved natural gas properties	55,000
Goodwill	338,036
Financial liabilities	(49,313		)
Long-term debt	(75,400		)
Deferred tax liability	(17,933		)
Total identifiable net assets	$	572,632

Cash paid for acquisitions	$	100,000
Fair value of equity issued	222,000
Fair value of pre-existing equity investment	250,632
Total consideration	$	572,632

Subsequent to the completion of the Marcellus JV Buy-In and excluding the related gain of $203.6 million recorded at January 29, 2014, the 100%-owned Marcellus joint venture contributed the following to the Company’s consolidated operating results for the three and nine months ended September 30, 2014:



(in thousands)	Three Months Ended September 30, 2014		Nine Months Ended September 30, 2014
Revenue	$	30,689	$	103,290
Net income	$	12,008	$	57,419

Pro Forma Information (Unaudited)

The following unaudited pro forma combined financial information presents the Company’s results as though the Marcellus JV Buy-In had been completed at January 1, 2014 and January 1, 2013, respectively.



	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands, except per share data)	2014			2013			2014			2013
Pro forma net revenues	$	79,127		$	42,959		$	273,480		$	123,676
Pro forma net loss	$	(6,862	)	$	(29,088	)	$	(83,794	)	$	(1,540	)
Pro forma loss per share (basic)	$	(0.05	)	$	(0.33	)	$	(0.65	)	$	(0.02	)
Pro forma loss per share (diluted)	$	(0.05	)	$	(0.33	)	$	(0.65	)	$	(0.02	)

Momentum Acquisition

On February 12, 2014, the Company, through its indirect wholly-owned subsidiary Rice Poseidon Midstream LLC, a Delaware limited liability company (“Rice Poseidon”), entered into a purchase and sale agreement with M3 Appalachia Gathering LLC, a Delaware limited liability company (“M3”), to acquire (the “Momentum Acquisition”) certain gas gathering assets in eastern Washington and Greene Counties, Pennsylvania. On April 17, 2014, the Company completed the Momentum Acquisition for aggregate consideration of approximately $111.4 million (the “Purchase Price”). The Company funded the Purchase Price with cash on hand.

As of September 30, 2014, $48.9 million of the Purchase Price was allocated to intangible assets related to customer contracts on the condensed consolidated balance sheets and the remaining balance was recorded to proved and unproved natural gas properties. The customer contracts are amortized over 30 years using a straight line method and amortization expense recorded in the condensed consolidated statements of operations for the three and nine months ended September 30, 2014 was $0.4 million and $0.7 million, respectively. The estimated annual amortization expense over the next five years is as follows: remainder of 2014 - $0.4 million, 2015 - $1.6 million, 2016 - $1.6 million, 2017 - $1.6 million, and 2018 - $1.6 million.

The properties acquired in the Momentum Acquisition consist of a 28-mile, 6-16 inch gathering system in eastern Washington County, Pennsylvania, and permits and rights of way in Washington and Greene Counties, Pennsylvania, necessary to construct an 18-mile, 30 inch 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 billion cubic feet of natural gas per day.

Greene County Acquisition

On July 7, 2014, the Company entered into a definitive purchase and sale agreement to acquire 21,913 net acres and 12 developed Marcellus wells in southwestern Greene County, Pennsylvania from Chesapeake Appalachia, L.L.C. and its partners for approximately $329.5 million (the “Greene County Acquisition”). The purchase price was allocated to proved and unproved natural gas properties in the amounts of $151.3 million and $178.2 million, respectively. The transaction closed on August 1, 2014, with an effective date of February 1, 2014. The Company funded the Greene County Acquisition with cash on hand.


6.	Commitments and Contingencies

On October 14, 2013, the Company entered into a Development Agreement and Area of Mutual Interest (“AMI”) Agreement with Gulfport Energy Corporation (“Gulfport”) covering approximately 50,000 aggregate net acres in the Utica Shale in Belmont County, Ohio. The Company refers to these agreements as “Utica Development Agreements.” Pursuant to the Utica

Development Agreements, the Company had approximately 68.80% participating interest in acreage currently owned or to be acquired by the Company or Gulfport located within Goshen and Smith Townships (the “Northern Contract Area”) and an approximately 42.63% participating interest in acreage currently owned or to be acquired by the Company or Gulfport located within Wayne and Washington Townships (the “Southern Contract Area”), each within Belmont County, Ohio. The remaining participating interests are held by Gulfport. The participating interests of the Company and Gulfport in each of the Northern and Southern Contract Areas approximated the Company’s then-current relative acreage positions in each area.

Each quarter during the term of the Development Agreement, the Company and Gulfport will establish a work program and budget detailing the proposed exploration and development to be performed in the Northern and Southern Contract Areas, respectively, for the following 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.

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

The Company has commitments for gathering and firm transportation under existing contracts with third parties. Future payments under these contracts as of September 30, 2014 totaled $2,887.2 million (remainder of 2014 - $15.7 million, 2015 - $94.3 million, 2016 - $113.6 million, 2017 - $113.4 million, 2018 - $112.0 million, 2019 - $141.8 million and thereafter - $2,296.4 million).

As of September 30, 2014, the Company had seven drilling rigs (four horizontal and three tophole) under contract, of which five expire in 2015 and two expire in 2017. Future payments under these contracts as of September 30, 2014 totaled $85.9 million (remainder of 2014 - $12.2 million, 2015 - $46.0 million, 2016 - $20.8 million and 2017 - $6.9 million). Any other rig performing work for us is performed on a well-by-well basis and therefore can be released without penalty at the conclusion of drilling on the current well. These types of drilling obligations have not been included in the amounts above. The values above represent the gross amounts that we are committed to pay without regard to our proportionate share based on our working interest.

The Company is involved in various litigation matters arising in the normal course of business. Management is not aware of any actions that are expected to have a material adverse effect on its financial position or results of operations.


7.	Stockholders’ Equity

On January 29, 2014, pursuant to the Master Reorganization Agreement (the “Master Reorganization Agreement”) among the Company, Rice Drilling B, Rice Appalachia, Rice Holdings, Rice Partners, NGP Holdings, NGP RE Holdings, L.L.C., (“NGP RE Holdings”) NGP RE Holdings II, L.L.C. (“NGP RE II” and, together with NGP RE Holdings, “Natural Gas Partners”), Mr. Daniel J. Rice III, Rice Merger LLC (“Merger Sub”) and each of the persons holding incentive units representing interests in Rice Appalachia (collectively, the “Incentive Unitholders”) dated as of January 23, 2014, (i) (a) Rice Partners contributed a portion of its interests in Rice Appalachia to Rice Holdings, (b) Natural Gas Partners contributed its interests in Rice Appalachia to NGP Holdings and (c) the Incentive Unitholders contributed a portion of their incentive units to Rice Holdings and NGP Holdings, in each case in return for substantially similar incentive units in such entities; (ii) NGP Holdings, Rice Holdings and Mr. Daniel J. Rice III contributed their respective interests in Rice Appalachia to the Company in exchange for 43,452,550, 20,300,923 and 2,356,844 shares of common stock, respectively; (iii) Rice Partners contributed its remaining interest in Rice Appalachia to the Company in exchange for 20,000,000 shares of common stock; (iv) the Incentive Unitholders contributed their remaining interests in Rice Appalachia to the Company in exchange for 160,831 shares of common stock, each of which were issued by the company in connection with the closing of the IPO. In connection with the IPO, in the first quarter of 2014, we recognized non-cash compensation expense of $3.4 million for these 160,831 shares.

In addition, on January 29, 2014, pursuant to the Agreement and Plan of Merger (the “Merger Agreement”) among the Company, Rice Drilling B and Merger Sub dated as of January 23, 2014, the Company issued 1,728,852 shares of common stock to the members of Rice Drilling B (other than Rice Appalachia) in exchange for their units in Rice Drilling B.

In August 2014, we completed a public offering (“August 2014 Equity Offering”) of 13,729,650 shares of our common stock at $27.30 per share, which included 7,500,000 shares sold by us and 6,229,650 shares sold by affiliates of Natural Gas Partners and Alpha Natural Resources (the “Selling Stockholders”). After deducting underwriting discounts and commissions of $7.7 million and transaction costs, the Company received net proceeds of $196.3 million. The Company received no proceeds from the sale of shares by the Selling Stockholders. The net proceeds from this offering are being used to fund a portion of our 2014 capital budget.

The Company’s Board of Directors did not declare or pay a dividend for the three or nine months ended September 30, 2014 or 2013.


8.	Incentive Units

In connection with the IPO and the related corporate reorganization, the Rice Appalachia incentive unit holders contributed their Rice Appalachia incentive units to Rice Holdings and NGP Holdings in return for substantially similar incentive units in such entities (except for those incentive units related to the incentive burden attributable to Mr. Daniel J. Rice III, which we acquired from the holders of such incentive units in exchange for the issuance of 160,831 shares of our common stock). In the first quarter of 2014, certain incentive units granted by NGP Holdings to certain employees triggered the pre-determined payout criteria, resulting in a cash payment by NGP Holdings of $4.4 million. No payments were made in respect of incentive units prior to the completion of the Company’s IPO. These two transactions resulted in non-cash compensation expense of $7.8 million being recorded in the first quarter of 2014 by the Company. As a result of the IPO, the payment likelihood related to the incentive units was deemed probable, requiring the Company to recognize expense.

For the three and nine months ended September 30, 2014, we recognized approximately $26.4 million and $101.7 million of compensation expense, respectively, relative to these interests, of which $12.0 million and $19.8 million has been paid by Mr. Daniel J. Rice III and NGP Holdings for the three and nine months ended September 30, 2014, respectively. We expect to recognize approximately $79.8 million of additional compensation expense over the remaining expected service periods, related to the Rice Holdings interests. The NGP Holdings interests are considered a liability-based award and will be adjusted on a quarterly basis until all payments have been made. As of September 30, 2014, the unrecognized compensation expense related to the NGP Holdings units is approximately $77.3 million which will be recognized over the remaining expected service period. The compensation expense related to these interests is treated as additional paid in capital from Rice Holdings and NGP Holdings in our financial statements and is not deductible for federal or state income tax purposes. The compensation expense recognized is a non-cash charge, with the settlement obligation resting on NGP Holdings and Rice Holdings, and as such are not dilutive to Rice Energy Inc.

As a result of our August 2014 Equity Offering, NGP Holdings paid approximately $12.0 million to holders of certain NGP Holdings incentive units.

Three tranches of the incentive units have a time vesting feature. A rollforward of those units from IPO to September 30, 2014 is included below.



Vested Units Balance, January 29, 2014	853,630
Vested During Period	565,881
Forfeited During Period	(214,869	)
Granted During Period	214,869
Cancelled During Period	—
Vested Units Balance, September 30, 2014	1,419,511

Four tranches of the incentive units do not have a time vesting feature, and their payouts are triggered upon a future payment condition. The fair value of the incentive units was estimated using a Monte Carlo simulation valuation model with the following assumptions:



Rice Holdings
Valuation Date	1/29/2014
Dividend Yield	0.00	%
Expected Volatility	47.00	%
Risk-Free Rate	1.11	%
Expected Life (Years)	4.0



Rice Holdings
Valuation Date	4/14/2014
Dividend Yield	0.00	%
Expected Volatility	45.19	%
Risk-Free Rate	1.13	%
Expected Life (Years)	3.8



Rice Holdings
Valuation Date	4/16/2014
Dividend Yield	0.00	%
Expected Volatility	44.32	%
Risk-Free Rate	1.18	%
Expected Life (Years)	3.8



NGP Holdings
Valuation Date	9/30/2014
Dividend Yield	0.00	%
Expected Volatility	40.20	%
Risk-Free Rate	0.58	%
Expected Life (Years)	2.0


9.	Stock Compensation

During the nine months ended September 30, 2014, the Company granted stock compensation awards to certain non-employee directors and employees. The awards consisted of restricted stock units, which vest upon the passage of time, and performance units, which vest based upon attainment of specified performance criteria. Stock compensation expense related to these awards was $2.1 million and $3.3 million for the three and nine months ended September 30, 2014, respectively. As of September 30, 2014, the Company has unrecognized compensation expense related to these equity awards of $17.5 million.


10.	Earnings Per Share

Basic earnings per share (“EPS”) is computed by dividing net income (loss) by the weighted-average number of shares of common stock outstanding during the period. Diluted earnings per share takes into account the dilutive effect of potential common stock that could be issued by the Company in conjunction with stock awards that have been granted to directors and employees. In accordance with FASB ASC Topic 260, awards of nonvested shares shall be considered to be outstanding as of the grant date for purposes of computing diluted EPS even though their issuance is contingent upon vesting. The following is a calculation of the basic and diluted weighted-average number of shares of common stock outstanding and EPS for the three and nine months ended September 30, 2014 and 2013. As indicated in Note 1, our corporate reorganization was considered a transaction amongst entities under common control. Therefore, the weighted average shares used in our EPS calculation assume that the Rice Energy Inc. corporate structure was in place for all periods presented.



	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands, except share data)	2014			2013			2014		2013
Income (loss) (numerator):
Net income (loss)	$	(6,862	)	$	(33,652	)	$	114,675	$	(20,841	)

Weighted-average shares (denominator):
Weighted-average number of shares of common stock - basic	132,269,081			88,000,000			125,411,524		77,894,855
Weighted-average number of shares of common stock - diluted	132,269,081			88,000,000			125,678,095		77,894,855

Earnings (loss) per share:
Basic	$	(0.05	)	$	(0.38	)	$	0.91	$	(0.27	)
Diluted	$	(0.05	)	$	(0.38	)	$	0.91	$	(0.27	)

Due to the net loss for the periods presented herein, loss per share excludes dilution for 76,800 shares and 1,671,800 shares for the three months ended September 30, 2014 and for the three and nine months ended September 30, 2013, respectively.


11.	Income Taxes

We are a corporation under the Internal Revenue Code subject to federal income tax at a statutory rate of 35% of pretax earnings and, as such, our future income taxes will be dependent upon our future taxable income. We did not report any income tax benefit or expense for periods prior to the consummation of our IPO because Rice Drilling B, our accounting predecessor, is a limited liability company that was not and currently is not subject to federal income tax. The reorganization of our business in connection with the closing of the IPO, such that it is now held by a corporation subject to federal income tax, required the recognition of a deferred tax asset or liability for the initial temporary differences at the time of the IPO. The resulting deferred tax liability of approximately $162.3 million was recorded in equity at the date of the completion of the IPO as it represents a transaction among shareholders. Additionally, the pro forma EPS for the nine month period ending September 30, 2014 disclosed in the accompanying condensed consolidated statements of operations assumes a statutory tax rate. The components of the income tax provision are as follows:



(in thousands)	Three Months Ended September 30, 2014		Nine Months Ended September 30, 2014
Current tax expense:
Federal	$	—	$	—
State	—		—
Total	—		—
Deferred tax expense:
Federal	11,813		15,847
State	2,192		2,940
Total	14,005		18,787
Total income tax expense	$	14,005	$	18,787

Tax expense for the three months ended September 30, 2014 is approximately $14.0 million resulting in an effective tax rate of 196%. Tax expense for the nine months ended September 30, 2014 is approximately $18.8 million resulting in an effective tax rate of 14%. The Company estimates an annual effective income tax rate based on projected results for the year and applies this rate to income before taxes to calculate income tax expense. The effective tax rate for the three and nine months ended September 30, 2014 differ from the statutory rate due principally to non-deductible incentive unit expense and for the nine months ended September 30, 2014 pre-tax income prior to the IPO. The Company recognizes deferred tax liabilities for temporary differences between the financial statement and tax basis of assets and liabilities. The deferred tax liabilities reflected above primarily relate to intangible drilling costs, depletion, and depreciation. The effect of changes in the tax laws or tax rates is recognized in income in the period such changes are enacted.

Based on management’s analysis, the Company did not have any uncertain tax positions as of September 30, 2014 and December 31, 2013.


12.	New Accounting Pronouncements

In May 2014, the FASB issued ASU, No. 2014-09, “Revenue from Contracts with Customers (Topic 606),” or ASU No. 2014-09. The FASB created Topic 606 which supersedes the revenue recognition requirements in Topic 605, “Revenue Recognition,” and most industry-specific guidance throughout the Industry Topics of the Codification. ASU 2014-09 will enhance comparability of revenue recognition practices across entities, industries and capital markets compared to existing guidance. Additionally, ASU 2014-09 will reduce the number of requirements to which an entity must consider in recognizing revenue as this update will replace multiple locations for guidance. The FASB and International Accounting Standards Board initiated this joint project to clarify the principles for recognizing revenue and to develop a common revenue standard for both U.S. GAAP and International Financial Reporting Standards. ASU 2014-09 is effective for fiscal and interim periods beginning after December 15, 2016 and should be applied retrospectively. Early adoption of this standard is not permitted. The Company is currently evaluating the impact of the provisions of ASU 2014-09.

Item 2. 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 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained in our 2013 Annual Report, as well as the condensed consolidated financial statements and related notes appearing elsewhere in this Quarterly 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 Quarterly 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 Quarterly Report. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.

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.

As of September 30, 2014, we held approximately 82,626 net acres in the southwestern core of the Marcellus Shale, primarily in Washington County and Greene 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 53,816 net acres as of September 30, 2014 in the southeastern core of the Utica Shale, primarily in Belmont County, Ohio. We believe this area to be in 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.

Our average net daily production for the third quarter of 2014 is 247 million cubic feet equivalent per day. We brought five operated net horizontal Marcellus wells and one operated net Utica well online during the third quarter of 2014.

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.

We use commodity derivative instruments, such as swaps, puts 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 3. 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 will 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.

Corporate Reorganization and Marcellus JV Buy-In. Information presented in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for the period from January 1, 2014 through January 29, 2014, as contained within the three and nine months ended September 30, 2014, and for the three and nine months ended September 30, 2013, pertain to the historical financial statements and results of operations of Rice Energy Inc., which reflects the 50% equity investment in our Marcellus joint venture owned by Rice Drilling B prior to January 29, 2014. The reorganization constituted a common control transaction and the discussion herein is contemplated as though this reorganization had occurred for the earliest period presented herein. As a result, the historical financial data may not give you an accurate indication of what our actual results would have been had the IPO transactions 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 January 29, 2014, the complete results of operations of our Marcellus joint venture are consolidated into our results of operations, as opposed to periods prior to January 29, 2014, for which the results of operations of our Marcellus joint venture are not consolidated but rather reflected as equity in income (loss) from our 50% equity investment therein.

Income Taxes. We are a corporation under the Internal Revenue Code subject to federal income tax at a statutory rate of 35% of pretax earnings, and, as such, our future income taxes will be dependent upon our future taxable income. We did not report any income tax benefit or expense for periods prior to the consummation of our IPO because Rice Drilling B, our accounting predecessor, is a limited liability company that was not and currently is not subject to federal income tax. The reorganization of our business in connection with the closing of the IPO, such that it is now held by a corporation subject to federal income tax, required the recognition of a deferred tax asset or liability for the initial temporary differences at the time of the IPO. The resulting deferred tax liability of approximately $162.3 million was recorded in equity at the date of IPO. Because we anticipate that our deductions primarily related to intangible drilling costs (“IDCs”) will exceed 2014 earnings, we expect to generate significant net operating loss assets and deferred tax liabilities. No current tax expense was recorded as of the date of the IPO. For periods following completion of the IPO, we began recording a federal and state income tax liability associated with our status as a corporation. Please see “Item 1. Financial Statements—Notes to Condensed Consolidated Financial Statements—11. Income Taxes.”

Increased Drilling Activity. In the third quarter of 2014, we brought online five net horizontal Marcellus wells and one net horizontal Utica well and we expect to bring online 15 net horizontal Marcellus wells in the fourth quarter of 2014. From 2010 through June 2013, we ran a one-horizontal rig drilling program. In June 2013, we began operating a two-horizontal rig drilling program on our Marcellus Shale properties. In the first quarter of 2014, we operated a three-horizontal rig program, one of which operated in the Utica Shale. In the second and third quarters of 2014, we averaged two horizontal rigs. In the fourth quarter of 2014, we plan to average three horizontal rigs, with an average of one rig operating in the Utica Shale and two rigs operating in the Marcellus Shale. 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. During the third quarter of 2014, our capital expenditures were financed with proceeds from our August 2014 Equity Offering, Senior Notes Offering and net cash provided by operating activities. In the future, we may incur additional indebtedness and issue additional equity to fund our acquisition and development activities. Please read “Capital Resources and Liquidity—Debt Agreements” below for additional discussion of our financing arrangements.

On April 25, 2014, we issued $900.0 million (our “Senior Notes Offering”) of 6.25% senior notes due 2022 (the “Notes”) in a private placement to eligible purchasers under Rule 144A and Regulation S of the Securities Act, which resulted in net proceeds to us of $882.7 million after deducting estimated expenses and initial purchasers' discounts of approximately $17.3 million. We used $301.8 million of the net proceeds to repay and retire the Second Lien Term Loan Facility (defined below), with the remainder expected to be used to fund a portion of our capital expenditures program.

In April 2013, we entered into our $300.0 million Second Lien Term Loan Facility agreement (“Second Lien Term Loan Facility”). Net proceeds of our Second Lien Term Loan Facility of $288.3 million after offering fees and expenses were 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. On April 25, 2014, the Company used a portion of the net proceeds from the Senior Notes Offering to repay and retire the Second Lien Term Loan Facility in the amount of $301.8 million.

In April 2013, we entered into our $500.0 million Senior Secured Revolving Credit Facility (“Senior Secured Revolving Credit Facility”). Concurrently with the closing of our IPO, on January 29, 2014, the Senior Secured Revolving Credit Facility was amended to, among other things, allow for the corporate reorganization that was completed simultaneously with the closing of the IPO, add us as a guarantor, increase the maximum commitment amount to $1.5 billion, increase the borrowing base to $350.0 million as a result of the Marcellus JV Buy-In and lower the interest rate owed on amounts borrowed under the Senior Secured Revolving Credit Facility. We used a portion of the net proceeds of the IPO to repay $115.0 million of borrowings under our Senior Secured Revolving Credit Facility and $75.4 million of borrowings outstanding under the revolving credit facility of our Marcellus joint venture. Concurrently with the Senior Notes Offering (described below), we, as borrower, and Rice Drilling B, as predecessor borrower, amended the Senior Secured Revolving Credit Facility (“Amended Credit Agreement”) to, among other things, assign all of Rice Drilling B’s rights and obligations under the Senior Secured Revolving Credit Facility to us, and we assumed all such rights and obligations as borrower under the Amended Credit Agreement. As of September 30, 2014, the borrowing base under our Senior Secured Revolving Credit Facility was $385.0 million with zero borrowings outstanding and $66.8 million of letters of credit outstanding. Availability under the borrowing base of our Senior Secured Revolving Credit Facility was $318.2 million as of September 30, 2014. In October 2014, we had a redetermination of the borrowing base under our Senior Secured Revolving Credit Facility which increased the borrowing base to $550.0 million.

Sources of Revenues

The substantial majority of 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. The following table provides detail of our operating revenues from the condensed consolidated statements of operations for the three and nine months ended September 30, 2014 and 2013.



	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2014		2013		2014		2013
Natural gas sales	$	67,625	$	23,526	$	246,583	$	60,219
Oil and NGL sales	206		—		233		—
Firm transportation sales, net	9,733		—		11,851		—
Third party gathering revenue	1,563		24		2,878		61
Other revenue	—		139		—		519
Total operating revenues	$	79,127	$	23,689	$	261,545	$	60,799

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.



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
NYMEX Henry Hub High ($/MMBtu)	$	4.44		$	3.79		$	7.94		$	4.38
NYMEX Henry Hub Low ($/MMBtu)	$	3.74		$	3.27		$	3.74		$	3.08

NYMEX Henry Hub Price ($/MMBtu)	$	3.94		$	3.55		$	4.47		$	3.69
Less: Average Basis Impact ($/MMBtu) ⁽¹⁾	(1.11		)	(0.17		)	(0.62		)	(0.04		)
Plus: Btu Uplift (MMBtu/Mcf)	0.14			0.17			0.19			0.18
Pre-Hedge Realized Price ($/Mcf)	$	2.97		$	3.55		$	4.04		$	3.83

(1)

Differential is calculated by comparing the average NYMEX Henry Hub price to our volume weighted average realized price per MMBtu before hedges, including 50% of the volumes sold by our Marcellus joint venture for the period from January 1, 2014 through January 28, 2014, contained within the three and nine months ended September 30, 2014 and for the three and nine months ended September 30, 2013. The remainder of the three and nine months ended September 30, 2014 reflect (i) the completion of the corporate reorganization in connection with our IPO and (ii) the consummation of the Marcellus JV Buy-In, each on January 29, 2014 and as described under “Item 1. Financial Statements—Introduction to the Condensed Consolidated Financial Statements.”

We sell a substantial majority of our production to a single natural gas marketer, Sequent Energy Management, LP (“Sequent”). For the three and nine months ended September 30, 2014, sales to Sequent represented 83% and 87% 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 this customer, we do not believe the loss of this customer would have a material adverse effect on our business, as other customers or markets would be accessible to us.

Results of Operations

Below are some highlights of our financial and operating results for the three and nine months ended September 30, 2014 compared to the three and nine months ended September 30, 2013:


•	Our natural gas, oil and NGL sales were $67.8 million and $23.5 million in the three months ended September 30, 2014 and 2013, respectively and $246.8 million and $60.2 million in the nine months ended September 30, 2014 and 2013, respectively.


•	Our production volumes were 22,757 MMcfe and 6,618 MMcfe in the three months ended September 30, 2014 and 2013, respectively and 61,116 MMcfe and 15,728 MMcfe in the nine months ended September 30, 2014 and 2013, respectively.


•	Our firm transportation sales, net were $9.7 million and zero in the three months ended September 30, 2014 and 2013, respectively and $11.9 million and zero in the nine months ended September 30, 2014 and 2013, respectively.


•	Our per unit cash production costs were $0.67 per Mcfe and $0.86 per Mcfe in the three months ended September 30, 2014 and 2013, respectively and $0.73 per Mcfe and $0.88 per Mcfe in the nine months ended September 30, 2014 and 2013, respectively.


•	Our G&A expenses were $10.5 million and $4.2 million in the three months ended September 30, 2014 and 2013, respectively and $36.7 million and $10.0 million in the nine months ended September 30, 2014 and 2013, respectively.

The following tables set forth selected operating and financial data for the three and nine months ended September 30, 2014 compared to the three and nine months ended September 30, 2013:



	Rice Energy Inc.							Rice Energy Inc.
	Three Months Ended September 30,							Nine Months Ended September 30,
	2014		2013		Change			2014		2013		Change
Natural gas sales (in thousands):	$	67,625	$	23,526	$	44,099		$	246,583	$	60,219	$	186,364
Oil and NGL sales (in thousands):	206		—		206			233		—		233
Natural gas, oil and NGL sales (in thousands):	$	67,831	$	23,526	$	44,305		$	246,816	$	60,219	$	186,597

Firm transportation sales, net (in thousands):	$	9,733	$	—	$	9,733		$	11,851	$	—	$	11,851

Natural gas production (MMcf):	22,740		6,618		16,122			61,096		15,728		45,368
Oil and NGL production (Bbls):	2,841		—		2,841			3,390		—		3,390
Total production (MMcfe)	22,757		6,618		16,139			61,116		15,728		45,388

Average natural gas prices before effects of hedges per Mcf:	$	2.97	$	3.55	$	(0.58	)	$	4.04	$	3.83	$	0.21
Average realized natural gas prices after effects of hedges per Mcf ⁽¹⁾:	2.98		3.67		(0.69		)	3.70		3.76		(0.06		)
Average oil and NGL prices per Bbl:	72.48		—		72.48			68.82		—		68.82

Average costs per Mcfe:
Lease operating	$	0.20	$	0.27	$	(0.07	)	$	0.27	$	0.37	$	(0.10	)
Gathering, compression and transportation	0.42		0.51		(0.09		)	0.42		0.44		(0.02		)
Production taxes and impact fees	0.05		0.08		(0.03		)	0.04		0.07		(0.03		)
General and administrative	0.46		0.63		(0.17		)	0.60		0.63		(0.03		)
Depreciation, depletion and amortization	1.49		1.47		0.02			1.50		1.48		0.02

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



	Rice Energy Inc.									Rice Energy Inc.
	Three Months Ended September 30,									Nine Months Ended September 30,						Change
(in thousands, except per share data)	2014			2013			Change			2014			2013			Change
Operating revenues:
Natural gas, oil and NGL sales	$	67,831		$	23,526		$	44,305		$	246,816		$	60,219		$	186,597
Firm transportation sales, net	9,733			—			9,733			11,851			—			11,851
Other revenue	1,563			163			1,400			2,878			580			2,298
Total operating revenues	79,127			23,689			55,438			261,545			60,799			200,746

Operating expenses:
Lease operating	4,553			1,777			2,776			16,406			5,794			10,612
Gathering, compression and transportation	9,597			3,365			6,232			25,904			6,951			18,953
Production taxes and impact fees	1,114			522			592			2,624			1,029			1,595
Exploration	747			338			409			1,706			1,784			(78		)
Incentive unit expense	26,418			—			26,418			101,695			—			101,695
Restricted unit expense	—			32,381			(32,381		)	—			40,087			(40,087		)
Stock compensation expense	2,058			—			2,058			3,274			—			3,274
General and administrative	10,458			4,169			6,289			36,733			9,952			26,781
Depreciation, depletion and amortization	33,853			9,722			24,131			91,912			23,215			68,697
Acquisition expense	2,246			—			2,246			2,246			—			2,246
Amortization of intangible assets	408			—			408			748			—			748
Total operating expenses	91,452			52,274			39,178			283,248			88,812			194,436

Operating loss	(12,325		)	(28,585		)	16,260			(21,703		)	(28,013		)	6,310
Interest expense	(15,754		)	(5,943		)	(9,811		)	(38,737		)	(13,033		)	(25,704		)
Gain on purchase of Marcellus joint venture	—			—			—			203,579			—			203,579
Other income (loss)	(216		)	38			(254		)	180			(408		)	588
Gain on derivative instruments	36,935			8,050			28,885			5,357			16,698			(11,341		)
Amortization of deferred financing costs	(707		)	(958		)	251			(1,728		)	(4,760		)	3,032
Loss on extinguishment of debt	(790		)	(10,622		)	9,832			(3,934		)	(10,622		)	6,688
Write-off of deferred financing costs	—			—			—			(6,896		)	—			(6,896		)
Equity in income (loss) of joint ventures	—			4,368			(4,368		)	(2,656		)	19,297			(21,953		)
Income (loss) before income taxes	7,143			(33,652		)	40,795			133,462			(20,841		)	154,303
Income tax expense	(14,005		)	—			(14,005		)	(18,787		)	—			(18,787		)

Net income (loss)	$	(6,862	)	$	(33,652	)	$	26,790		$	114,675		$	(20,841	)	$	135,516
Weighted average number of shares of common stock - basic	132,269			88,000			44,269			125,412			77,895			47,517
Weighted average number of shares of common stock - diluted	132,269			88,000			44,269			125,678			77,895			47,783
Earnings per share—basic	$	(0.05	)	$	(0.38	)	$	0.33		$	0.91		$	(0.27	)	$	1.18
Earnings per share—diluted	$	(0.05	)	$	(0.38	)	$	0.33		$	0.91		$	(0.27	)	$	1.18

Three Months Ended September 30, 2014 Compared to Three Months Ended September 30, 2013

Total operating revenues. The $44.3 million increase in natural gas, oil and NGL sales was mainly a result of an increase in production in the third quarter of 2014 compared to the third quarter of 2013. The increase in production was a result of increased drilling and completion activity, mainly in Washington County, Pennsylvania and Belmont County, Ohio and production from seven wells acquired in our Greene County Acquisition on August 1, 2014. Production volume increases were partially offset by approximately, 60 days of capacity restricted volumes from four pads as a result of longwall coal undermining. The impact of increased production volumes on operating revenues was partially offset by a decrease in realized prices in 2014 compared to 2013. In addition, operating revenues for the third quarter of 2014 were positively impacted by approximately $8.5 million in firm transportation sales, net, from the sale of unutilized capacity in September 2014 to a third party.

Lease operating expenses. The $2.8 million increase in lease operating expenses is attributable to an increase in the number of producing wells in 2014 as compared to the prior year. However, lease operating expenses per unit of production decreased due to improved efficiencies, primarily due to more producing wells per pad and lower fixed costs per well.

Gathering, compression and transportation. The $6.2 million increase in gathering, compression and transportation expenses is primarily attributable to increased firm transportation contracts in the third quarter of 2014 compared to the third quarter of 2013.

Incentive unit expense. The $26.4 million increase in incentive unit expense was due to $14.4 million of non-cash compensation expense recognized in relation to the incentive unit awards based on fair market value assumptions as of September 30, 2014. Additionally, NGP Holdings paid approximately $12.0 million to holders of certain NGP Holdings incentive units as a result of our August 2014 Equity Offering. See “Item 1. Financial Statements-Notes to Condensed Consolidated Financial Statements-8. Incentive Units” for additional information.

G&A. The $6.3 million increase was primarily attributable to the additions of personnel to support our growth activities and related salary and employee benefits. At September 30, 2014, we had 250 employees as compared to 116 employees at September 30, 2013.

DD&A. The $24.1 million increase was a result of an increase in production and greater number of producing wells in the third quarter of 2014 compared to 2013. This is consistent with our expanded drilling program and increased production during the period.

Interest expense. The $9.8 million increase was a result of higher levels of average borrowings outstanding during the third quarter of 2014 in order to fund our capital programs.

Gain on derivative instruments. The $36.9 million gain on derivative contracts in the third quarter of 2014 was comprised of $36.8 million in unrealized gains and $0.1 million of cash receipts on the settlement of maturing contracts. In the third quarter of 2013, the $8.0 million gain was comprised of $7.3 million in unrealized gains and $0.8 million of cash receipts made on the settlement of maturing contracts. The gain in the third quarter of 2014 as compared to the gain in the same period in 2013 was attributable to a decrease in market prices.

Nine Months Ended September 30, 2014 Compared to Nine Months Ended September 30, 2013

Total operating revenues. The $186.6 million increase in in natural gas, oil and NGL sales was mainly a result of an increase in production in the nine months ended 2014 compared to the nine months ended 2013. The increase in production was a result of increased drilling and completion activity, primarily in Washington County, Pennsylvania and Belmont County, Ohio, and production from seven wells acquired in our Greene County Acquisition on August 1, 2014. Production volume increases were partially offset by approximately 60 days of capacity restricted volumes from four pads as a result of longwall coal undermining. The impact of increased production volumes on operating revenues was partially offset by a decrease in realized prices in 2014 compared to 2013. In addition, operating revenues for the nine months ended September 30, 2014 were positively impacted by approximately $8.5 million in firm transportation sales, net, from the sale of unutilized capacity for the month of September 2014 to a third party.

Lease operating expenses. The $10.6 million increase in lease operating expenses is attributable to an increase in the number of producing wells in 2014 as compared to the prior year. However, lease operating expenses per unit of production decreased due to improved efficiencies, primarily due to more producing wells per pad and lower fixed costs per well.

Gathering, compression and transportation. The $19.0 million increase in gathering, compression and transportation expenses is primarily attributable to increased firm transportation contracts in 2014 compared to 2013.

Incentive unit expense. The $101.7 million increase in incentive unit expense was due to approximately $81.9 million of non-cash compensation expense related to incentive units still outstanding which related to the service period from date of grant through September 30, 2014. In addition, the increase was due to approximately $12.0 million paid to holders of certain NGP Holdings incentive units by NGP Holdings as a result of our August 2014 Equity Offering, payment by NGP Holdings of approximately $4.4 million related to payments made at IPO due to the New Tier I payout multiple being achieved and the payment by Daniel J. Rice III of approximately $3.4 million related to his incentive unit burden. See “Item 1. Financial Statements-Notes to Condensed Consolidated Financial Statements-8. Incentive Units” for additional information.

G&A. The $26.8 million increase was primarily attributable to the additions of personnel to support our growth activities and related salary and benefit expenses. At September 30, 2014, we had 250 employees as compared to 116 employees at September 30, 2013.

DD&A. The $68.7 million increase was a result of an increase in production and a greater number of producing wells in 2014 compared to 2013. This is consistent with our expanded drilling program and increased production during the period.

Interest expense. The $25.7 million increase was a result of higher levels of average borrowings outstanding during 2014 in order to fund our capital programs.

Gain on purchase of Marcellus joint venture. The $203.6 million gain on acquisition in the first quarter of 2014 was attributable to the Marcellus JV Buy-In transaction. As a result of our acquiring the remaining ownership in our Marcellus joint venture, we are required to remeasure our equity investment at fair value, which resulted in a non-recurring gain of approximately $203.6 million during the nine months ended September 30, 2014.

Gain on derivative instruments. The $5.4 million gain on derivative contracts in 2014 was comprised of $26.1 million in unrealized gains and $20.8 million of cash payments on the settlement of maturing contracts. In 2013, the $16.7 million gain was comprised of $17.8 million in unrealized gains and $1.1 million of cash payments made on settlement of maturing contracts. The gain in 2014 as compared to the gain in 2013 was attributable to an increase in market prices accompanied by a greater hedged volume of our natural gas production.

Capital Resources and Liquidity

Our primary sources of liquidity have been the proceeds from our IPO, August 2014 Equity Offering, Senior Notes Offering, equity contributions from our sponsors, our Amended Credit Agreement and net proceeds from the sale of Rice Drilling B’s convertible debentures. Our primary use of capital has been the acquisition and development of natural gas properties. As we pursue reserve and production growth, we monitor which capital resources, including equity and debt financings, are available to us to meet our future financial obligations, planned capital expenditure activities and liquidity requirements. We also expect to fund a portion of these requirements with cash flow from operations as we continue to bring additional production online.

Our future success in growing proved reserves and production will be highly dependent on the capital resources available to us. In 2014, excluding (i) $100.0 million paid with respect to the Marcellus JV Buy-In, (ii) approximately $111.4 million paid with respect to the Momentum Acquisition and (iii) approximately $329.5 million paid with respect to the Greene County 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 $385.0 million for leasehold acquisitions. This represents a 96% increase over our $629.0 million pro forma 2013 capital expenditures. Without giving pro forma effect to the Marcellus JV Buy-In, our 2013 capital budget was $578.0 million. We expect to fund the remainder of our 2014 capital expenditures with cash generated by operations, a portion of the net proceeds of our Senior Notes Offering, the net proceeds of our IPO and August 2014 Equity Offering and borrowings under our Senior Secured Revolving Credit Facility. 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 December 31, 2013 reserve report. The failure to achieve projected production and cash flows from operations from such wells could result in a reduction to our 2014 capital budget. Our 2014 capital budget may be further adjusted as business conditions warrant. The amount, timing and allocation of capital expenditures is largely discretionary and within our control. If natural gas prices decline to levels below our acceptable levels, or costs increase to levels above our acceptable levels, we could choose to defer a significant portion of our budgeted capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity and prioritize capital projects that we believe will have the highest expected rates of return and potential to generate near-term cash flow. We routinely monitor and adjust our capital expenditures in response to changes in commodity prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in drilling activities, contractual obligations, internally generated cash flow and other factors both within and outside our control.

We believe that operating cash flows and available borrowings under our Senior Secured Revolving Credit Facility should be sufficient to meet our current cash requirements, including normal operating needs, debt service obligations, capital expenditures, and commitments and contingencies. However, to the extent that we consider market conditions favorable, we may access the capital markets to raise capital from time to time to fund acquisitions, pay down our Senior Secured Revolving Credit Facility and for general working capital purposes.

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

Cash Flow Provided by Operating Activities

Net cash provided by operating activities was $69.7 million for the nine months ended September 30, 2014, compared to $22.5 million of net cash provided by operating activities for the nine months ended September 30, 2013. The change in operating cash flow was primarily the result of higher production in 2014 at a higher realized gas price, along with net decreases in per unit production costs.

Cash Flow Used In Investing Activities

During the nine months ended September 30, 2014 cash flows used in investing activities increased to $1,154.5 million from $342.6 million for the nine months ended September 30, 2013. This was primarily related to increased capital expenditures for drilling, development and acquisition costs. The acquisitions of our Marcellus Shale joint venture, Momentum and Greene County resulted in a net cash outflow of $523.7 million.

Cash Flow Provided By Financing Activities

Net cash provided by financing activities of $1,185.2 million during the nine months ended September 30, 2014 was primarily the result of the proceeds from our Senior Notes Offering, our IPO and August 2014 equity offering (net of offering costs) which was offset by repayments of debt. Net cash provided by financing activities of $339.2 million during the nine months ended September 30, 2013 was primarily related to borrowings under our Second Lien Term Loan facility.

Debt Agreements

6.25% Senior Notes Due 2022

On April 25, 2014, we offered $900.0 million in aggregate principal amounts of the Notes due 2022 in a private placement to eligible purchasers under Rule 144A and Regulation S of the Securities Act, which resulted in net proceeds to us of $882.7 million after deducting estimated expenses and underwriting discounts and commissions of approximately $17.3 million. We used $301.8 million of the net proceeds to repay and retire the Second Lien Term Loan Facility and expect to use the remainder to fund our capital expenditure plan.

The Notes will mature on May 1, 2022, and interest is payable on the Notes on each May 1 and November 1. At any time prior to May 1, 2017, we may redeem up to 35% of the Notes at a redemption price of 106.25% of the principal amount, plus accrued and unpaid interest to the redemption date, with the proceeds of certain equity offerings so long as the redemption occurs within 180 days of completing such equity offering and at least 65% of the aggregate principal amount of the Notes remains outstanding after such redemption. Prior to May 1, 2017, we may redeem some or all of the notes for cash at a redemption price equal to 100% of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date. Upon the occurrence of a Change of Control (as defined in the Indenture), unless we have exercised our optional redemption right in respect of the Notes, the holders of the Notes will have the right to require us to repurchase all or a portion of the Notes at a price equal to 101% of the aggregate principal amount of the Notes, plus any accrued and unpaid interest to the date of purchase. On and after May 1, 2017, we may redeem some or all of the Notes at redemption prices (expressed as percentages of principal amount) equal to 104.688% for the twelve-month period beginning on May 1, 2017, 103.125% for the twelve-month period beginning May 1, 2018, 101.563% for the twelve-month period beginning on May 1, 2019 and 100.000% beginning on May 1, 2020, plus accrued and unpaid interest to the redemption date.

The Notes are our senior unsecured obligations, rank equally in right of payment with all of our existing and future senior debt, and will rank senior in right of payment to all of our future subordinated debt. The Notes will be effectively subordinated to all of our existing and future secured debt to the extent of the value of the collateral securing such indebtedness.

The Indenture restricts our ability and the ability of certain of our subsidiaries to: (i) incur or guarantee additional debt or issue certain types of preferred stock; (ii) pay dividends capital stock or redeem, repurchase or retire our capital stock or subordinated debt; (iii) make certain investments; (iv) incur liens; (v) enter into transactions with affiliates; (vi) merge or consolidate with another company; (vii) transfer and sell assets; and (viii) create unrestricted subsidiaries. These covenants are subject to a number of important exceptions and qualifications. If at any time when the Notes are rated investment grade by both Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no Default (as defined in the Indenture) has occurred and is continuing, many of such covenants will terminate and we and our subsidiaries will cease to be subject to such covenants.

The Indenture contains customary events of default, including:


•	default in any payment of interest on any Note when due, continued for 30 days;


•	default in the payment of principal of or premium, if any, on any Note when due;


•	failure by us to comply with its other obligations under the Indenture, in certain cases subject to notice and grace periods;


•	payment defaults and accelerations with respect to other indebtedness of us and our Restricted Subsidiaries (as defined in the Indenture) in the aggregate principal amount of $25.0 million or more;


•	certain events of bankruptcy, insolvency or reorganization of us or a Significant Subsidiary (as defined in the Indenture) or group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary;


•	failure by us or a Restricted Subsidiary to pay certain final judgments aggregating in excess of $25.0 million within 60 days; and


•	any guarantee of the Notes by a Guarantor ceases to be in full force and effect, is declared null and void in a judicial proceeding or is denied or disaffirmed by its maker.

In connection with the issuance and sale of the Notes, we and the Guarantors entered into a registration rights agreement with the Initial Purchasers, dated April 25, 2014. Pursuant to the registration rights agreement, we and the Guarantors have agreed to file a registration statement with the Securities and Exchange Commission so that holders of the Notes can exchange the Notes for registered notes that have substantially identical terms as the Notes. In addition, we and the Guarantors have agreed to exchange the guarantee related to the Notes for a registered guarantee having substantially the same terms as the original guarantee. We and the Guarantors will use commercially reasonable efforts to cause the exchange to be completed within 365 days after the issuance of the Notes. We and the Guarantors are required to pay additional interest if they fail to comply with their obligations to register the Notes within the specified time periods.

Senior Secured Revolving Credit Facility

Concurrently with our Senior Notes Offering, we, as borrower, and Rice Drilling B, as predecessor borrower, entered into the Amended Credit Agreement to, among other things, assign all of the rights and obligations of Rice Drilling B as borrower under its Senior Secured Revolving Credit Facility to us. Furthermore, the Amended Credit Agreement (i) allowed for the Senior Notes Offering and (ii) provided that we did not incur an immediate reduction in the borrowing base under the Senior Secured Revolving Credit Facility as a result of the Senior Notes Offering. The Amended Credit Agreement also extended the maturity date of the Senior Secured Revolving Credit Facility from April 25, 2018 to January 29, 2019.

The Amended Credit Agreement is secured by liens on at least 80% of the proved oil and gas reserves of us and our subsidiaries (other than any subsidiary that is designated as an unrestricted subsidiary), as well as significant unproved acreage and substantially all of the personal property of us and such restricted subsidiaries, and the Amended Credit Agreement is guaranteed by such restricted subsidiaries. The Amended Credit Agreement contains restrictive covenants that limit the ability of us and our restricted subsidiaries to, among other things:


•	incur additional indebtedness;


•	sell assets;


•	make loans to others;


•	make investments;


•	enter into mergers;


•	make or declare dividends;


•	hedge future production or interest rates;


•	incur liens; and


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

The Amended Credit Agreement also requires us to maintain certain financial ratios, which are measured at the end of each calendar quarter:


•	a current ratio, which is the ratio of consolidated current assets (including unused commitments under the Amended Credit Agreement and excluding non-cash derivative assets) to consolidated current liabilities (excluding current maturities under the Amended Credit Agreement and non-cash derivative liabilities), of not less than 1.0 to 1.0; and


•	a minimum interest coverage ratio, which is the ratio of consolidated EBITDAX (as such term is defined in the Amended Credit Agreement) based on the trailing twelve month period to consolidated interest expense, of not less than 2.5 to 1.0.

We were in compliance with such covenants and ratios as of September 30, 2014.

Second Lien Term Loan Facility

On April 25, 2013, Rice Drilling B entered into a Second Lien Term Loan Facility with Barclays Bank PLC, as administrative agent, and a syndicate of lenders in an aggregate principal amount of $300.0 million. Rice Drilling B estimated the discount on issuance of this instrument based upon an estimate of market rates at the inception of the instrument and recorded a discount of $4.5 million. The discount was being amortized over the life of the note using an effective interest rate of 0.284% using the effective yield method. On April 25, 2014, we used a portion of the net proceeds from our Senior Notes Offering to repay and retire the Second Lien Term Loan Facility, in the amount of $301.8 million. The $301.8 million included the outstanding principal balance of $297.0 million, a prepayment premium in the amount of approximately $3.0 million, and accrued but unpaid interest of $1.8 million.

Convertible Debentures

In connection with the IPO, the Debentures and warrants of Rice Drilling B were amended to become convertible or exercisable for shares of our common stock. On February 28, 2014, Rice Drilling B issued a redemption notice on the remaining Debentures, which set a redemption date of March 28, 2014. Prior to the redemption date, $6.6 million of the Debentures were converted into 570,945 shares of Rice Energy Inc. common stock. The remaining principal balance of $0.3 million that was not converted will be paid upon request from holders of the remaining Debentures. The premium of $0.1 million was recorded to expense in the nine months ended September 30, 2014. As of September 30, 2014, the remaining principal balance was $0.2 million.

Commodity Hedging Activities

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

To mitigate the potential negative impact on our cash flow caused by changes in oil and natural gas prices, we have entered into financial commodity derivative contracts in the form of swaps, zero cost collars, calls, puts and basis swaps to ensure that we receive minimum prices for a portion of our future oil and natural gas production when management believes that favorable future prices can be secured. We typically hedge the NYMEX Henry Hub price for natural gas. The Amended Credit Agreement adjusted our hedging limitation. In the prior Senior Secured Revolving Credit Facility agreement, we were permitted to hedge volumes based on a percentage of expected production from proved reserve volumes. We are now permitted to hedge the greater of (i) the percentage of internally forecasted production (Column A) and (ii) the percentage of proved reserve volumes (Column B) according to the table below.



Months next succeeding the time as of which compliance is measured	Column A		Column B
Months 1 though 12	75	%	85	%
Months 13 through 24	50	%	85	%
Months 25 through 36	40	%	85	%
Months 37 through 48	25	%	65	%
Months 49 through 60	15	%	65	%

Our hedging activities are intended to support natural gas prices at targeted levels and to manage our exposure to natural gas price fluctuations. The counterparty is required to make a payment to us for the difference between the floor price specified in the contract and the settlement price, which is based on market prices on the settlement date, if the settlement price is below the floor price. We are required to make a payment to the counterparty for the difference between the ceiling price and the settlement price if the ceiling price is below the settlement price. These contracts may include price swaps whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty and zero cost collars that set a floor and ceiling price for the hedged production. For a description of our commodity derivative contracts, please see “Item 1. Financial

Statements—Notes to Condensed Consolidated Financial Statements—3. Derivative Instruments and 4. Fair Value of Financial Instruments” included elsewhere in this Quarterly Report.

By using derivative instruments to hedge exposures to changes in commodity prices, we expose ourselves to the credit risk of our counterparties. Credit risk is the potential failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty is expected to owe us, which creates credit risk. To minimize the credit risk in derivative instruments, it is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. The creditworthiness of our counterparties is subject to periodic review. We have derivative instruments in place with six different counterparties. As of September 30, 2014, our contracts with Wells Fargo Bank N.A. accounted for 60% of the net fair market value of our derivative assets. We believe Wells Fargo Bank N.A. is an acceptable credit risk. We are not required to provide credit support or collateral to Wells Fargo Bank N.A. under current contracts, nor are they required to provide credit support or collateral to us. As of September 30, 2014 and December 31, 2013, we did not have any past due receivables from counterparties.

Critical Accounting Policies and Estimates

Our critical accounting policies are described in the notes to our Consolidated Financial Statements for the year ended December 31, 2013 contained in our 2013 Annual Report. Any new accounting policies or updates to existing accounting policies as a result of new accounting pronouncements have been included in the notes to our Condensed Consolidated Financial Statements contained in this Quarterly Report. The application of our critical accounting policies may require management to make judgments and estimates about the amounts reflected in the Condensed Consolidated Financial Statements. Management uses historical experience and all available information to make these estimates and judgments. Different amounts could be reported using different assumptions and estimates.

Incentive units. We recognize non-cash compensation expense for incentive units awarded to certain of our employees by NGP Holdings and Rice Holdings. In connection with our IPO and related corporate reorganization, the holders of incentive units in Rice Appalachia contributed a portion of their incentive units to Rice Holdings and NGP Holdings in return for substantially similar incentive units in such entities. This resulted in the incentive units being deemed to have been modified, and the performance conditions were considered to be probable of occurring. Therefore, their fair values were measured and compensation expense from the date of initial grant through September 30, 2014 has been recognized in the nine months ended September 30, 2014.

It is currently expected that the NGP Holdings incentive units will be satisfied in cash and the Rice Holdings incentive units will be satisfied in shares of our common stock held by Rice Holdings. As a result of these different manners of payment satisfaction, the incentive units are accounted for differently, with the NGP Holdings incentive units being accounted for as liability awards and the Rice Holdings incentive units being accounted for as equity awards. For the NGP Holdings incentive units, for the nine months ended September 30, 2014, the fair value was measured as of September 30, 2014. For future reporting periods, the fair value used to determine the applicable compensation expense will be re-measured at each reporting period. For the Rice Holdings incentive units, the fair value of the incentive units was measured as of January 29, 2014, the date of modification. This fair value will underlie compensation expense charges for future reporting periods.

Determination of the fair value of the awards requires judgments and estimates regarding, among other things, the appropriate methodologies to follow in valuing the incentive units and the related inputs required by those valuation methodologies. The fair values underlying the compensation expense for both types of incentive units were estimated using a Monte Carlo simulation. The Monte Carlo simulation projected the share price for our common stock using the expected volatility, the risk free rate and other variables. The service period, which began on the date of grant and continues through final distribution, has been estimated primarily based upon our assumptions regarding the timing and size of secondary offerings of shares of our common stock by NGP Holdings and/or other liquidity events.

Future results of operations for any particular quarterly or annual period could be materially affected by changes in the Company’s assumptions. Any change in inputs or number of inputs to this calculation could impact the valuation and thus the non-cash compensation expense recognized. See “Item 1. Financial Statements—Notes to Condensed Consolidated Financial Statements— 8. Incentive Units” for additional information. Non-cash compensation expenses related to the incentive units is included in incentive unit expense within the Condensed Consolidated Statement of Operations.

Income taxes. We are a corporation under the Internal Revenue Code subject to federal income tax at a statutory rate of 35% of pretax earnings and, as such, our future income taxes will be dependent upon our future taxable income. We did not report any income tax benefit or expense for periods prior to the consummation of our IPO because Rice Drilling B, our accounting predecessor, is a limited liability company that was not and currently is not subject to federal income tax. The reorganization of our business in connection with the closing of the IPO, such that it is now held by a corporation subject to federal income tax,

required the recognition of a deferred tax asset or liability for the initial temporary differences at the time of the IPO. The resulting deferred tax liability of approximately $162.3 million was recorded in equity at the date of the completion of the IPO as it represents a transaction among shareholders. Additionally, we have presented pro forma EPS for the nine month period ending September 30, 2014 assuming a statutory rate as disclosed in the accompanying condensed consolidated statements of operations.

Based on management’s analysis, the Company did not have any uncertain tax positions as of September 30, 2014 and December 31, 2013.

Income taxes are accounted for under the asset and liability method, which requires recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. Under this method, deferred tax assets and liabilities are determined based on the differences between the financial statements and tax basis of assets and liabilities using enacted tax rates in effect for the year in which differences are expected to be recovered or settled pursuant to the provisions of ASC 740-Income Taxes. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date.

We will record a valuation allowance if it is deemed more likely than not that all or a portion of its deferred income tax assets will not be realized. In addition, income tax rules and regulations are subject to interpretation and the application of those rules and regulations require judgment by us and may be challenged by the taxation authorities. We follow ASC 740-10-25, which requires the use of a two-step approach for recognizing and measuring tax benefits taken or expected to be taken in a tax return and disclosures regarding uncertainties in income tax positions. Only tax positions that meet the more likely than not recognition threshold are recognized.

Business Combinations. For acquisitions of working interests that are accounted for as business combinations, the results of operations are included in the Condensed Consolidated Statement of Operations from the date of acquisition. Purchase prices are allocated to assets acquired based on their estimated fair values at the time of acquisition. Fair value is the price that would be received to sell an asset or would be paid to transfer a liability in an orderly transaction between market participants at the measurement date. The fair value measurement is based on the assumptions of market participants and not those of the reporting entity. Therefore, entity-specific intentions do not impact the measurement of fair value. The fair value of natural gas properties is determined using a risk-adjusted after-tax discounted cash flow analysis based upon significant inputs including gas prices; projections of estimated quantities of natural gas reserves, including those classified as proved, probable and possible; projections of future rates of production; timing and amount of future development and operating costs; projected reserve recovery factors; and weighted average cost of capital.

Off-Balance Sheet Arrangements

Currently, we do not have any off-balance sheet arrangements as defined by the SEC. In the ordinary course of business, we enter into various commitment agreements and other contractual obligations, some of which are not recognized in our consolidated financial statements in accordance with GAAP. See Note 6 to our unaudited condensed consolidated financial statements for a description of our commitments and contingencies.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

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

Commodity price risk and hedges

For a discussion of how we use financial commodity derivative contracts to mitigate some of the potential negative impact on our cash flow caused by changes in natural gas prices, see “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Commodity Hedging Activities.”

Interest rate risks

As of September 30, 2014, we had zero borrowings and approximately $66.8 million in letters of credit outstanding under our Senior Secured Revolving Credit Facility. Concurrently with the closing of our IPO, we amended our Senior Secured Revolving Credit Facility to, among other things, increase the maximum commitment amount to $1.5 billion and lower the interest rate owed on amounts borrowed under the Senior Secured Revolving Credit Facility. After giving effect to the amendment, the borrowing base under our Senior Secured Revolving Credit Facility was increased to $350.0 million as a result of the Marcellus JV Buy-In. As of September 30, 2014, we had availability under the borrowing base of our Senior Secured Revolving Credit Facility of approximately $318.2 million and the borrowing base was $385.0 million. In October 2014, we had a redetermination of the borrowing base under our Senior Secured Revolving Credit Facility which increased the borrowing base to $550.0 million. We have a choice of borrowing in Eurodollars or at the base rate. Eurodollar loans bear interest at a rate per annum equal to LIBOR plus an applicable margin ranging from 150 to 250 basis points following the closing of our IPO, depending on the percentage of our borrowing base utilized. Base rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank’s reference rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the rate for one month Eurodollar loans plus 100 basis points, plus an applicable margin ranging from 50 to 150 basis points following the closing of our IPO as a result of the Marcellus JV Buy-In, depending on the percentage of our borrowing base utilized. The interest rate did not change under the Amended Credit Agreement.

As of September 30, 2014, we did not have any derivatives in place to mitigate the effects of interest rate risk. We may implement an interest rate hedging strategy in the future.

Counterparty and customer credit risk

Our principal exposures to credit risk are through joint interest receivables ($82.2 million as of September 30, 2014) and the sale of our natural gas production ($52.3 million in receivables as of September 30, 2014), which we market to multiple natural gas marketing companies. Joint interest receivables arise from billing entities who own partial interest in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we wish to drill. We can do very little to choose who participates in our wells. We are also subject to credit risk due to concentration of our natural gas receivables with one natural gas marketing company. 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.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) under the Exchange Act) as of September 30, 2014. In light of the previously identified material weakness as described in “Item 9A. Controls and Procedures—Material Weakness in Internal Control over Financial Reporting” of our 2013 Annual Report, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were not effective at the reasonable assurance level as of September 30, 2014. Notwithstanding the existence of the material weakness, management concluded that the financial statements and other financial information included in this Quarterly Report presents fairly, in all material respects, the financial condition, results of operations and cash flows for all periods presented.

Changes in Internal Control over Financial Reporting

As described in “Item 9A. Controls and Procedures—Material Weakness in Internal Control over Financial Reporting” of our 2013 Annual Report, management continues to evaluate the design and effectiveness of these control changes in connection with its ongoing evaluation, documentation, review, formalization and testing of our internal control environment over the remainder of 2014. As such, there were changes in our system of internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during the three and nine months ended September 30, 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION

Item 1. Legal Proceedings

See “Part I—Item 1. Financial Statements—Notes to Condensed Consolidated Financial Statements—6. Commitments and Contingencies” which is incorporated in this item by reference.

Item 1A. Risk Factors

Our business faces many risks. Any of the risks discussed elsewhere in this Quarterly Report and our other SEC filings could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operations.

There have been no material changes in our risk factors from those described in our 2013 Annual Report and our June 30, 2014 Quarterly Report. For a discussion of our potential risks and uncertainties, see the information in “Item 1A. Risk Factors” in our 2013 Annual Report and our June 30, 2014 Quarterly Report.

Item 6. Exhibits



Exhibit Number		Exhibit
2.1		Purchase and Sale Agreement, dated July 11, 2014, by and among Rice Drilling B LLC, Chesapeake Appalachia, L.L.C. and Statoil USA Onshore Properties Inc. (incorporated by reference to Exhibit 3.2 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on August 7, 2014).
3.1		Amended and Restated Certificate of Incorporation of Rice Energy Inc. (incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on February 4, 2014).
3.2		Amended and Restated Bylaws of Rice Energy Inc. (incorporated by reference to Exhibit 3.2 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on February 4, 2014).
10.1		First Amendment to Third Amended and Restated Credit Agreement, dated as of October 20, 2014, among Rice Energy Inc., as borrower, Wells Fargo Bank, N.A., as administrative agent, and the lenders and other parties thereto (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the Commission on October 22, 2014).
31.1*		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**		Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**		Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*		XBRL Instance Document.
101.SCH*		XBRL Schema Document.
101.CAL*		XBRL Calculation Linkbase Document.
101.DEF*		XBRL Definition Linkbase Document.
101.LAB*		XBRL Labels Linkbase Document.
101.PRE*		XBRL Presentation Linkbase Document.


*	Filed herewith.

Filed herewith. Pursuant to SEC Release No. 33-8212, this certification will be treated as “accompanying” this Quarterly Report on Form 10-Q and not “filed” as part of such report for purposes of Section 18 of the Securities Exchange Act, as amended, or otherwise subject to the liability of Section 18 of the Securities Exchange Act, as amended, and this certification will not be deemed to be incorporated by reference into any filing under the Securities Exchange Act of 1933, as amended, except to the extent that the registrant specifically incorporates it by reference.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.



		RICE ENERGY INC.

Date: November 12, 2014	By:	/s/ Daniel J. Rice IV
		Daniel J. Rice IV
		Chief Executive Officer
		(Principal Executive Officer)

Date: November 12, 2014	By:	/s/ Grayson T. Lisenby
		Grayson T. Lisenby
		Vice President and Chief Financial Officer
		(Principal Financial Officer)

EXHIBIT INDEX



Exhibit Number		Exhibit
2.1		Purchase and Sale Agreement, dated July 11, 2014, by and among Rice Drilling B LLC, Chesapeake Appalachia, L.L.C. and Statoil USA Onshore Properties Inc. (incorporated by reference to Exhibit 3.2 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on August 7, 2014).
3.1		Amended and Restated Certificate of Incorporation of Rice Energy Inc. (incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on February 4, 2014).
3.2		Amended and Restated Bylaws of Rice Energy Inc. (incorporated by reference to Exhibit 3.2 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on February 4, 2014).
10.1		First Amendment to Third Amended and Restated Credit Agreement, dated as of October 20, 2014, among Rice Energy Inc., as borrower, Wells Fargo Bank, N.A., as administrative agent, and the lenders and other parties thereto (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the Commission on October 22, 2014).
31.1*		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**		Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**		Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*		XBRL Instance Document.
101.SCH*		XBRL Schema Document.


*	Filed herewith.