EQT RE, LLC - FORM 10-Q - August 7, 2015

Attached files

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EX-31.2 - EXHIBIT 31.2 - EQT RE, LLC	exhibit312certification2q15.htm
EX-32.2 - EXHIBIT 32.2 - EQT RE, LLC	exhibit322certification2q15.htm
EX-31.1 - EXHIBIT 31.1 - EQT RE, LLC	exhibit311certification2q15.htm
EX-32.1 - EXHIBIT 32.1 - EQT RE, LLC	exhibit321certification2q15.htm

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 June 30, 2015

¨ 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 August 4, 2015: 136,393,834 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
Item 1. Financial Statements	5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	35
Item 3. Quantitative and Qualitative Disclosures about Market Risk	49
Item 4. Controls and Procedures	51

PART II
Item 1. Legal Proceedings	52
Item 1A. Risk Factors	52
Item 6. Exhibits	52

Signatures	53
Exhibit Index	54
Glossary of Oil and Natural Gas Terms	55

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 of 1933, as amended, 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 “may,” “assume,” “forecast,” “position,” “predict,” “strategy,” “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe,” “project,” “budget,” “potential,” or “continue,” and similar expressions are used 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. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. 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 our Annual Report on Form 10-K for the year ended December 31, 2014 (the “2014 Annual Report”) on file with the Securities and Exchange Commission (the “SEC”).

Forward-looking statements may include statements about our:


•	business strategy;


•	reserves;


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


•	realized natural gas, NGLs 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;


•	operations of Rice Midstream Partners LP;


•	general economic conditions;


•	credit and capital 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 2014 Annual Report.

Reserve engineering is a process of estimating underground accumulations of natural gas, NGLs and oil that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions 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;


•	“Rice Drilling B” refers to Rice Drilling B LLC, a wholly-owned subsidiary of Rice Energy;


•	“RMP” or the “Partnership” refer to Rice Midstream Partners LP (NYSE: RMP);


•	“Rice Midstream OpCo” refers to Rice Midstream OpCo LLC, a wholly-owned subsidiary of RMP;


•	“Midstream Holdings” refers to Rice Midstream Holdings LLC, a wholly-owned subsidiary of Rice Energy;


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


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

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements

Rice Energy Inc.

Condensed Consolidated Balance Sheets

(Unaudited)



(in thousands)	June 30, 2015		December 31, 2014
Assets
Current assets:
Cash	$	256,676	$	256,130
Accounts receivable	245,428		199,900
Prepaid expenses and other	6,358		3,427
Derivative assets	128,502		133,034
Total current assets	636,964		592,491

Gas collateral account	3,995		3,995
Property, plant and equipment, net	2,922,494		2,461,331
Deferred financing costs, net	31,220		25,103
Goodwill	334,050		334,050
Intangible assets, net	46,976		47,791
Derivative assets	55,507		63,188
Total assets	$	4,031,206	$	3,527,949

Liabilities and stockholders’ equity
Current liabilities:
Current portion of long-term debt	$	—	$	680
Accounts payable	110,375		152,329
Royalties payable	52,620		37,172
Accrued capital expenditures	131,177		108,290
Accrued interest	17,248		9,375
Leasehold payable	14,496		30,702
Deferred tax liabilities	51,805		54,688
Other accrued liabilities	44,672		43,439
Total current liabilities	422,393		436,675

Long-term liabilities:
Long-term debt	1,424,033		900,000
Leasehold payable	5,043		4,279
Deferred tax liabilities	210,638		209,218
Other long-term liabilities	14,898		12,609
Total liabilities	2,077,005		1,562,781

Stockholders’ equity:
Common stock, $0.01 par value; authorized - 650,000,000 shares; issued and outstanding - 136,372,658 shares and 136,280,766 shares, respectively	1,363		1,363
Preferred stock, $0.01 par value; authorized - 50,000,000 shares; none issued	—		—
Additional paid in capital	1,420,026		1,368,001
Accumulated earnings	83,816		153,346
Stockholders’ equity before noncontrolling interest	1,505,205		1,522,710
Noncontrolling interests in consolidated subsidiaries	448,996		442,458
Total liabilities and stockholders’ equity	$	4,031,206	$	3,527,949

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 June 30,						Six Months Ended June 30,
(in thousands, except share data)	2015			2014			2015			2014
Operating revenues:
Natural gas, oil and natural gas liquids (“NGL”) sales	$	100,890		$	88,524		$	197,802		$	178,990
Firm transportation sales, net	438			2,113			3,264			2,113
Gathering, compression and water distribution	11,566			1,303			21,367			1,314
Total operating revenues	112,894			91,940			222,433			182,417

Operating expenses:
Lease operating	11,090			6,667			22,681			11,853
Gathering, compression and transportation	16,842			8,014			31,262			14,471
Production taxes and impact fees	1,694			871			3,148			1,510
Exploration	356			473			1,095			959
Midstream operation and maintenance	2,801			1,162			6,132			1,835
Incentive unit expense	23,099			1,474			46,557			75,276
Stock compensation expense	4,212			1,125			7,467			1,216
General and administrative	20,425			14,845			37,914			26,275
Depreciation, depletion and amortization	76,140			32,552			138,721			58,059
Amortization of intangible assets	408			340			816			340
Other expense	1,998			—			3,889			—
Total operating expenses	159,065			67,523			299,682			191,794

Operating (loss) income	(46,171		)	24,417			(77,249		)	(9,377		)
Interest expense	(23,359		)	(15,941		)	(39,488		)	(22,983		)
Gain on purchase of Marcellus joint venture	—			—			—			203,579
Other income (loss)	1,035			(195		)	1,196			396
(Loss) gain on derivative instruments	(3,710		)	(11,198		)	57,657			(31,578		)
Amortization of deferred financing costs	(1,306		)	(532		)	(2,409		)	(1,021		)
Loss on extinguishment of debt	—			(3,001		)	—			(3,144		)
Write-off of deferred financing costs	—			(6,060		)	—			(6,896		)
Equity loss of joint ventures	—			—			—			(2,656		)
(Loss) income before income taxes	(73,511		)	(12,510		)	(60,293		)	126,320
Income tax benefit (expense)	9,992			4,593			1,462			(4,782		)
Net (loss) income	(63,519		)	(7,917		)	(58,831		)	121,538
Less: Net income attributable to noncontrolling interests	(6,164		)	—			(10,699		)	—
Net (loss) income attributable to Rice Energy Inc.	$	(69,683	)	$	(7,917	)	$	(69,530	)	$	121,538

Weighted average number of shares of common stock—basic	136,315,882			128,419,606			136,303,914			121,925,915
Weighted average number of shares of common stock—diluted	136,315,882			128,419,606			136,303,914			122,255,908
Earnings (loss) per share—basic	$	(0.51	)	$	(0.06	)	$	(0.51	)	$	1.00
Earnings (loss) per share—diluted	$	(0.51	)	$	(0.06	)	$	(0.51	)	$	0.99

Pro forma income tax benefit										$	5,560
Pro forma net income										$	127,098
Pro forma earnings per share—basic										$	1.04
Pro forma earnings per share—diluted										$	1.04

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

Rice Energy Inc.

Condensed Consolidated Statements of Cash Flows

(Unaudited)



	Six Months Ended June 30,
(in thousands)	2015			2014
Cash flows from operating activities:
Net (loss) income	$	(58,831	)	$	121,538
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	138,721			58,059
Amortization of deferred financing costs	2,409			1,021
Amortization of intangibles	816			340
Exploratory well costs	1,095			—
Incentive unit expense	46,557			75,276
Write-off of deferred financing costs	—			6,896
Loss on extinguishment of debt	—			3,144
Stock compensation expense	7,467			1,216
Derivative instruments fair value (gain) loss	(57,657		)	31,578
Cash receipts (payments) for settled derivatives	69,870			(20,953		)
Deferred income tax (benefit) expense	(1,462		)	4,782
Fair value gain on purchase of Marcellus joint venture	—			(203,579		)
Equity loss of joint ventures	—			2,656
Changes in operating assets and liabilities:
(Increase) in accounts receivable and receivable from affiliate	(45,531		)	(29,337		)
(Increase) in prepaid expenses and other assets	(2,912		)	(2,470		)
(Decrease) in accounts payable	(19,171		)	(10,774		)
Increase in accrued liabilities and other	8,114			22,153
Increase in royalties payable	15,448			13,683
Net cash provided by operating activities	104,933			75,229

Cash flows from investing activities:
Capital expenditures for property and equipment	(622,797		)	(441,650		)
Acquisition of Marcellus joint venture, net of cash acquired	—			(82,766		)
Acquisition of Momentum assets	—			(111,447		)
Proceeds from sale of interest in gas properties	10,201			11,542
Net cash used in investing activities	(612,596		)	(624,321		)

Cash flows from financing activities:
Proceeds from borrowings	538,932			900,000
Repayments of debt obligations	(16,091		)	(498,865		)
Restricted cash for convertible debt	—			8,268
Debt issuance costs	(8,526		)	(18,436		)
Offering costs related to the Partnership’s IPO	(129		)	—
Distributions to the Partnership’s public unitholders	(5,977		)	—
Costs relating to IPO	—			(1,405		)
Proceeds from conversion of warrants	—			948
Proceeds from issuance of common stock sold in IPO, net of underwriting fees	—			598,500
Net cash provided by financing activities	508,209			989,010

Net increase in cash	546			439,918
Cash at the beginning of the year	256,130			31,612
Cash at the end of the period	$	256,676		$	471,530

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

Rice Energy Inc.

Condensed Consolidated Statements of Equity

(Unaudited)



(in thousands)	Common Stock ($0.01 par)		Additional Paid-In Capital			Accumulated (Deficit) Earnings			Total
Balance, January 1, 2014	$	—	$	—		$	(65,108	)	$	298,647
Shares of common stock issued in corporate reorganization	880		362,875			—			—
Shares of common stock issued in IPO, net of offering costs	300		593,120			—			593,420
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	6		942			—			948
Incentive unit compensation	—		75,276			—			75,276
Stock compensation	—		1,216			—			1,216
Tax impact of initial public offering and corporate reorganization	—		(164,504		)	—			(164,504		)
Consolidated net income	—		—			121,538			121,538
Balance, June 30, 2014	$	1,287	$	1,133,735		$	56,430		$	1,191,452



(in thousands)	Common Stock ($0.01 par)		Additional Paid-In Capital		Accumulated (Deficit) Earnings			Stockholders Equity before Non-Controlling Interest			Non-Controlling Interest			Total
Balance, January 1, 2015	$	1,363	$	1,368,001	$	153,346		$	1,522,710		$	442,458		$	1,965,168
Incentive unit compensation	—		46,557		—			46,557			—			46,557
Stock compensation	—		5,468		—			5,468			1,945			7,413
Distributions to the Partnership's public unitholders	—		—		—			—			(5,977		)	(5,977		)
Offering costs related to the Partnership’s IPO	—		—		—			—			(129		)	(129		)
Consolidated net income	—		—		(69,530		)	(69,530		)	10,699			(58,831		)
Balance, June 30, 2015	$	1,363	$	1,420,026	$	83,816		$	1,505,205		$	448,996		$	1,954,201

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”) 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 Securities Exchange Act of 1934, as amended. 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 June 30, 2015 and December 31, 2014 and its condensed consolidated statements of operations for the three and six months ended June 30, 2015 and 2014 and of cash flows for the six months ended June 30, 2015 and 2014.

A corporate reorganization occurred concurrently with the completion of the Company’s initial public offering (“IPO”) on January 29, 2014. As a part of this corporate reorganization, the Company acquired all of the outstanding membership interests in Rice Energy Appalachia LLC (“Rice Appalachia”) and Rice Drilling B LLC (“Rice Drilling B”) (other than those already held by Rice Appalachia) in exchange for shares of the Company’s common stock. 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.

The consolidated financial statements of the Company include the accounts of its wholly-owned subsidiaries. Rice Midstream Holdings LLC, a wholly-owned subsidiary of the Company (“Rice Midstream Holdings”), owns a 50.0% interest in Rice Midstream Partners LP, a publicly-traded subsidiary of the Company (the “Partnership”). The financial results of the Partnership are consolidated and the remaining 50.0% interest in the Partnership is reflected as noncontrolling interest in the condensed consolidated financial statements. All intercompany transactions have been eliminated in consolidation.

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, 2014, as filed with the Securities and Exchange Commission (“SEC”) by the Company in its Annual Report on Form 10-K (the “2014 Annual Report”). Certain prior period financial statement amounts have been reclassified to conform to current period presentation.


2.	Accounts Receivable

Accounts receivable are primarily from the Company’s joint interest partners and natural gas marketers. The Company extends credit to parties in the normal course of business based upon management’s assessment of their creditworthiness. A valuation allowance is provided for those accounts for which collection is estimated as doubtful; uncollectible accounts are written off and charged against the allowance. In estimating the allowance, management considers, among other things, how recently and how frequently payments have been received and the financial position of the party. There was no allowance recorded for any of the periods presented in the condensed consolidated financial statements. Accounts receivable as of June 30, 2015 and December 31, 2014 are detailed below.



(in thousands)	June 30, 2015		December 31, 2014
Joint interest	$	142,552	$	125,300
Natural gas sales	83,631		72,206
Other	19,245		2,394
Total accounts receivable	$	245,428	$	199,900


3.	Long-Term Debt

Long-term debt consists of the following as of June 30, 2015 and December 31, 2014:



(in thousands)	June 30, 2015		December 31, 2014
Long-term Debt
Senior Notes Due 2022 ^(a)	$	900,000	$	900,000
Senior Notes Due 2023 ^(b)	397,033		—
Senior Secured Revolving Credit Facility ^(c)	—		—
Midstream Holdings Revolving Credit Facility ^(d)	97,000		—
RMP Revolving Credit Facility ^(e)	30,000		—
Other	—		680
Total debt	$	1,424,033	$	900,680
Less current portion	—		680
Long-term debt	$	1,424,033	$	900,000

Senior Notes

6.25% Senior Notes Due 2022 (a)

On April 25, 2014, the Company issued $900.0 million in aggregate principal amount of 6.25% senior notes due 2022 (the “2022 Notes”) in a private placement to eligible purchasers under Rule 144A and Regulation S of the Securities Act of 1933, as amended (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 2022 Notes will mature on May 1, 2022, and interest is payable on the 2022 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 2022 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 2022 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 2022 Notes), unless the Company has given notice to redeem the 2022 Notes, the holders of the 2022 Notes will have the right to require the Company to repurchase all or a portion of the 2022 Notes at a price equal to 101% of the aggregate principal amount of the 2022 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 2022 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.

7.25% Senior Notes Due 2023 (b)

On March 26, 2015, the Company issued $400.0 million in aggregate principal amount of 7.25% senior notes due 2023 (the “2023 Notes”) in a private placement to eligible purchasers under Rule 144A and Regulation S of the Securities Act, which resulted in net proceeds of $389.3 million, after deducting expenses and the initial purchasers’ discounts of approximately $10.7 million. The Company used a portion of the net proceeds for general corporate purposes, including capital expenditures, and intends to use the remaining net proceeds for general corporate purposes, including capital expenditures. The original issuance discount of $3.1 million related to the 2023 Notes is recorded as a reduction of the principal amount. For the three and six months ended June 30, 2015, the Company recorded $0.1 million and $0.1 million, respectively, of amortization of the debt discount as interest expense using the effective interest method and a rate of 7.345%.

The 2023 Notes will mature on May 1, 2023, and interest is payable on the 2023 Notes on each May 1 and November 1, commencing on November 1, 2015. At any time prior to May 1, 2018, the Company may redeem up to 35% of the 2023 Notes at a redemption price of 107.250% 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 2023 Notes remains outstanding after such redemption. Prior to May 1, 2018, 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 2023 Notes), unless the Company has given notice to redeem the 2023 Notes,

the holders of the 2023 Notes will have the right to require the Company to repurchase all or a portion of the 2023 Notes at a price equal to 101% of the aggregate principal amount of the 2023 Notes, plus any accrued and unpaid interest to the date of purchase. On or after May 1, 2018, the Company may redeem some or all of the 2023 Notes at redemption prices (expressed as percentages of principal amount) equal to 105.438% for the twelve-month period beginning on May 1, 2017, 103.625% for the twelve-month period beginning May 1, 2019, 101.813% for the twelve-month period beginning on May 1, 2020 and 100.000% beginning on May 1, 2021, plus accrued and unpaid interest to the redemption date.

In connection with the issuance and sale of the 2023 Notes, the Company and the Company’s restricted subsidiaries (the “Guarantors”) entered into a registration rights agreement with the initial purchasers, dated March 26, 2015. Pursuant to the registration rights agreement, the Company and the Guarantors have agreed to file a registration statement with the SEC so that holders of the 2023 Notes can exchange the 2023 Notes for registered notes with substantially identical terms. 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 2023 Notes. The Company and the Guarantors are required to pay additional interest if they fail to comply with their obligations to register the 2023 Notes within the specified time periods.

The 2022 Notes and the 2023 Notes (collectively, 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 Notes are jointly and severally, fully and unconditionally, guaranteed by the Guarantors. The indentures governing the Notes provide that the 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 indentures governing the Notes) 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 indentures governing the Notes;


•	upon legal defeasance or satisfaction and discharge of the indentures governing the Notes; 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 indentures governing the Notes) has occurred and is continuing.

The indentures governing the Notes restrict the Company’s ability and the ability of its restricted 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 the Company’s 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 indentures governing the Notes) has occurred and is continuing, many of such covenants will terminate and the Company and its restricted subsidiaries will cease to be subject to such covenants.

The indentures governing the Notes contain 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 indentures governing the Notes, 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 indentures governing the Notes) 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 indentures governing the Notes) 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.

Senior Secured Revolving Credit Facility (c)

In April 2013, the Company entered into a Senior Secured Revolving Credit Facility (the “Senior Secured Revolving Credit Facility”) with Wells Fargo Bank, N.A., as administrative agent, and a syndicate of lenders. As of June 30, 2015, the borrowing base under the Third Amended and Restated Credit Agreement (as amended, the “Amended Credit Agreement”) governing the Senior Secured Revolving Credit Facility was $650.0 million and the sublimit for letters of credit was $175.0 million. The Company had zero borrowings outstanding and $105.0 million in letters of credit outstanding under its Amended Credit Agreement as of June 30, 2015, resulting in availability of $545.0 million. The next redetermination of the borrowing base is scheduled for October 2015. The maturity date of the Senior Secured Revolving Credit Facility is January 29, 2019.

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, including Rice Midstream Holdings and its subsidiaries), as well as significant unproved acreage and substantially all of the personal property of the Company and such restricted subsidiaries, and the Company’s obligations under the Amended Credit Agreement are 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 June 30, 2015.

Midstream Holdings Revolving Credit Facility (d)

On December 22, 2014, Rice Midstream Holdings LLC entered into a revolving credit facility (the “Midstream Holdings Revolving Credit Facility”) with Wells Fargo Bank, N.A., as administrative agent, and a syndicate of lenders with a maximum credit amount of $300.0 million and a sublimit for letters of credit of $25.0 million. As of June 30, 2015, Rice Midstream Holdings had $97.0 million of borrowings outstanding and $0.1 million letters of credit under this facility. The credit facility is available to fund working capital requirements and capital expenditures and to purchase assets and matures on December 22, 2019.

Principal amounts borrowed are payable on the maturity date, and interest is payable quarterly for base rate loans and at the end of the applicable interest period for Eurodollar loans. Under the revolving credit facility, Rice Midstream Holdings may elect to borrow in Eurodollars or at the base rate. Eurodollar loans bear interest at a rate per annum equal to the applicable LIBOR Rate plus an applicable margin ranging from 225 to 300 basis points, depending on the leverage ratio then in effect. 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 125 to 200 basis points, depending on the leverage ratio then in effect. Rice Midstream Holdings also pays a commitment fee based on the undrawn commitment amount ranging from 37.5 to 50 basis points.

The Midstream Holdings Revolving Credit Facility is secured by mortgages and other security interests on substantially all of the properties of, and guarantees from, Rice Midstream Holdings and its restricted subsidiaries (which do not include the Partnership, Rice Midstream Management LLC, a Delaware limited liability company and general partner of the Partnership, or the Company and its subsidiaries other than Rice Midstream Holdings).

The Midstream Holdings Revolving Credit Facility limits the ability of Rice Midstream Holdings and its restricted subsidiaries to, among other things:


•	incur or guarantee additional debt;


•	redeem or repurchase units or make distributions under certain circumstances;


•	make certain investments and acquisitions;


•	incur certain liens or permit them to exist;


•	enter into certain types of transactions with affiliates;


•	merge or consolidate with another company; and


•	transfer, sell or otherwise dispose of assets.

The Midstream Holdings Revolving Credit Facility also requires Rice Midstream Holdings to maintain the following financial ratios:


•	an interest coverage ratio, which is the ratio of Rice Midstream Holding’s consolidated EBITDA (as defined within the Midstream Holdings Revolving Credit Facility) to its consolidated current interest expense of at least 2.50 to 1.0 at the end of each fiscal quarter; and


•	a consolidated total leverage ratio, which is the ratio of consolidated debt to consolidated EBITDA, of not more than 4.25 to 1.0.

Rice Midstream Holdings was in compliance with such covenants and ratios effective as of June 30, 2015.

RMP Revolving Credit Facility (e)

On December 22, 2014, Rice Midstream OpCo LLC, a wholly-owned subsidiary of the Partnership (“Rice Midstream OpCo”), entered into a revolving credit facility (the “RMP Revolving Credit Facility”) with Wells Fargo Bank, N.A., as administrative agent, and a syndicate of lenders with a maximum credit amount of $450.0 million with an additional $200.0 million of commitments available under an accordion feature subject to lender approval. The RMP Revolving Credit Facility provides for a letter of credit sublimit of $50.0 million. As of June 30, 2015, Rice Midstream OpCo had $30.0 million of borrowings outstanding and no letters of credit under this facility. The RMP Revolving Credit Facility is available to fund working capital requirements and capital expenditures, to purchase assets, to pay distributions and repurchase units and for general partnership purposes and matures on December 22, 2019.

Principal amounts borrowed are payable on the maturity date, and interest is payable quarterly for base rate loans and at the end of the applicable interest period for Eurodollar loans. Under the revolving credit facility, the Partnership may elect to borrow in Eurodollars or at the base rate. Eurodollar loans bears interest at a rate per annum equal to the applicable LIBOR Rate plus an applicable margin ranging from 175 to 275 basis points, depending on the leverage ratio then in effect. Base rate loans bears interest at a rate per annum equal to the greatest of (i) the agent bank’s reference rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the rate for one month Eurodollar loans plus 100 basis points, plus an applicable margin ranging from 75 to 175 basis points, depending on the leverage ratio then in effect. The Partnership also pays a commitment fee based on the undrawn commitment amount ranging from 35 to 50 basis points.

The RMP Revolving Credit Facility is secured by mortgages and other security interests on substantially all of the properties of, and guarantees from, the Partnership and its restricted subsidiaries.

The RMP Revolving Credit Facility limits the ability of the Partnership and its restricted subsidiaries to, among other things:


•	incur or guarantee additional debt;


•	redeem or repurchase units or make distributions under certain circumstances;


•	make certain investments and acquisitions;


•	incur certain liens or permit them to exist;


•	enter into certain types of transactions with affiliates;


•	merge or consolidate with another company; and


•	transfer, sell or otherwise dispose of assets.

The RMP Revolving Credit Facility also requires the Partnership to maintain the following financial ratios:


•	an interest coverage ratio, which is the ratio of the Partnership’s consolidated EBITDA (as defined within the RMP Revolving Credit Facility) to its consolidated current interest expense of at least 2.50 to 1.0 at the end of each fiscal quarter;


•	a consolidated total leverage ratio, which is the ratio of consolidated debt to consolidated EBITDA, of not more than 4.75 to 1.0, and after electing to issue senior unsecured notes, a consolidated total leverage ratio of not more than 5.25 to 1.0, and, in each case, with certain increases in the permitted total leverage ratio following the completion of a material acquisition; and


•	if the Partnership elects to issue senior unsecured notes, a consolidated senior secured leverage ratio, which is the ratio of consolidated senior secured debt to consolidated EBITDA, of not more than 3.50 to 1.0.

The Partnership was in compliance with such covenants and ratios effective as of June 30, 2015.

Expected Aggregate Maturities

Expected aggregate maturities of the notes payable as of June 30, 2015 are as follows (in thousands):



Remainder of Year Ending December 31, 2015	$	—
Year Ending December 31, 2016	—
Year Ending December 31, 2017	—
Year Ending December 31, 2018	—
Year Ending December 31, 2019 and Beyond	1,424,033
Total	$	1,424,033

Interest paid in cash was approximately $28.4 million and $28.5 million for the three and six months ended June 30, 2015, respectively, and $1.8 million and $8.8 million for the three and six months ended June 30, 2014, respectively.


4.	Derivative Instruments

The Company uses derivative commodity instruments that are placed with major financial institutions whose creditworthiness is regularly monitored. The Company’s derivative counterparties share in the Amended Credit Agreement collateral. The Company’s hedging activities are intended to support natural gas prices at targeted levels and to manage its exposure to natural gas price fluctuations. To mitigate the potential negative impact on the Company’s cash flow caused by changes in natural gas prices, the Company has entered into financial commodity derivative contracts in the form of swaps, zero cost collars, calls, puts and basis swaps to ensure that it receives minimum prices for a portion of its future natural gas production when management believes that favorable future prices can be secured.

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 June 30, 2015, 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 31, 2022, as summarized in the following table:



Swap Contract Expiration	MMBtu/day	Weighted Average Price
Year ending December 31, 2015:
NYMEX	194,000	$	4.07
TCO	41,000	$	3.30
Dominion South	71,000	$	2.49

Year ending December 31, 2016:
NYMEX	295,000	$	3.90
Dominion South	31,000	$	2.62

Year ending December 31, 2017:
NYMEX	80,000	$	4.01



Collar Contract Expiration	MMBtu/day	Floor/Ceiling
Year ending December 31, 2015:
NYMEX	158,000	$3.96/$4.65

Year ending December 31, 2016:
NYMEX	40,000	$2.89/$3.68

Year ending December 31, 2017:
NYMEX	180,000	$3.11/$3.64

Year ending December 31, 2018:	160,000	$3.20/$3.70
NYMEX



Basis Contract Expiration	MMBtu/day	Swap ($/MMBtu)
Year ending December 31, 2015:
TCO	33,000	$	(0.42	)
Dominion South	16,000	$	(1.12	)
M2	20,000	$	(0.94	)
TETCO ELA	30,000	$	(0.13	)
MichCon	1,000	$	(0.04	)

Year ending December 31, 2016:
TCO	17,000	$	(0.42	)
Dominion South	45,000	$	(1.10	)
M2	40,000	$	(1.08	)
TETCO ELA	10,000	$	(0.12	)
MichCon	4,000	$	(0.04	)
Chicago	20,000	$	(0.04	)
ANR SE	15,000	$	(0.13	)

Year ending December 31, 2017:
Dominion South	20,000	$	(0.96	)
MichCon	4,000	$	(0.04	)

Year ending December 31, 2018:
Dominion South	65,000	$	(0.69	)
MichCon	4,000	$	(0.04	)

Year ending December 31, 2019:
Dominion South	60,000	$	(0.61	)
MichCon	20,000	$	(0.12	)

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 (refer to Note 5 for derivative instruments at fair value):



	As of June 30, 2015
(in thousands)	Derivative instruments, recorded in the Condensed Consolidated Balance Sheet, gross		Derivative instruments subject to master netting arrangements			Derivative instruments, net
Derivative assets	$	245,141	$	(61,132	)	$	184,009

	As of December 31, 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	$	201,775	$	(5,553	)	$	196,222


5.	Fair Value of Financial Instruments

The Company determines fair value on a recurring basis for derivative instruments as these instruments are required to be recorded at fair value for each reporting amount. 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 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 4 for details relating to derivative instruments):



	As of June 30, 2015
			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	$	184,009	$	184,009	$	—	$	184,009	$	—
Total assets	$	184,009	$	184,009	$	—	$	184,009	$	—



	As of December 31, 2014
			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	$	196,222	$	196,222	$	—	$	196,222	$	—
Total assets	$	196,222	$	196,222	$	—	$	196,222	$	—

The carrying value of cash equivalents approximates fair value due to the short maturity of the instruments. The Company’s non-financial assets, such as property, plant and equipment, goodwill and intangible assets are recorded at fair value upon acquisition and are remeasured at fair value only if an impairment charge is recognized. To the extent necessary, the Company applies unobservable inputs and management judgment due to the absence of quoted market prices (Level 3) to the valuation methodologies for these non-financial assets.

The estimated fair value and carrying amount of long-term debt as reported on the condensed consolidated balance sheets as of June 30, 2015 and December 31, 2014 is shown in the table below (refer to Note 3 for details relating to the debt instruments). 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 June 30, 2015				As of December 31, 2014
Long-Term Debt (in thousands)	Carrying Value		Fair Value		Carrying Value		Fair Value
Senior Notes Due 2022	$	900,000	$	893,250	$	900,000	$	839,250
Senior Notes Due 2023	397,033		410,000		—		—
Senior Secured Revolving Credit Facility	—		—		—		—
Midstream Holdings Revolving Credit Facility	97,000		97,000		—		—
RMP Revolving Credit Facility	30,000		30,000		—		—
Other	—		—		680		680
Total	$	1,424,033	$	1,430,250	$	900,680	$	839,930


6.	Financial Information by Business Segment

The Company operates in two business segments: exploration and production and midstream. The exploration and production segment is responsible for the acquisition, exploration and development of natural gas, oil and NGL properties in the Appalachian Basin. The midstream segment is engaged in the gathering and compression of natural gas, oil and NGL production, and in the provision of water services to support the well completion activities, of Rice Energy and third parties. The midstream segment includes the financial results of the Partnership as well as the Company’s 50.0% limited partner interest and incentive distribution rights in the Partnership.

Business segments are evaluated for their contribution to the Company’s consolidated results based on operating income, which is defined as segment operating revenues less expenses. Other income and expenses, interest and income taxes are managed on a consolidated basis. The segment accounting policies are the same as those described in Note 1 to the Company’s Consolidated Financial Statements for the year ended December 31, 2014 contained in its 2014 Annual Report.

The operating results and assets of the Company’s reportable segments were as follows as of and for the three months ended June 30, 2015:



(in thousands)	Exploration and Production			Midstream		Elimination of Intersegment Transactions			Consolidated Total
Operating revenues:
Natural gas, oil and NGL sales	$	100,890		$	—	$	—		$	100,890
Firm transportation sales, net	438			—		—			438
Gathering, compression and water distribution	—			34,812		(23,246		)	11,566
Total operating revenues	$	101,328		$	34,812	$	(23,246	)	$	112,894

Operating expenses:
Lease operating	11,090			—		—			11,090
Gathering, compression and transportation	32,691			—		(15,849		)	16,842
Production taxes and impact fees	1,694			—		—			1,694
Exploration	356			—		—			356
Midstream operation and maintenance	—			2,801		—			2,801
Incentive unit expense	21,885			1,214		—			23,099
Stock compensation expense	3,011			1,201		—			4,212
General and administrative	16,115			4,310		—			20,425
Depreciation, depletion and amortization	73,342			3,330		(532		)	76,140
Amortization of intangible assets	—			408		—			408
Other expense	1,159			839		—			1,998
Total operating expenses	$	161,343		$	14,103	$	(16,381	)	$	159,065

Operating (loss) income	$	(60,015	)	$	20,709	$	(6,865	)	$	(46,171	)

Capital expenditures for segment assets	$	211,925		$	93,330	$	(6,866	)	$	298,389

The operating results and assets of the Company’s reportable segments were as follows for the three months ended June 30, 2014:



(in thousands)	Exploration and Production		Midstream			Elimination of Intersegment Transactions			Consolidated Total
Operating revenues:
Natural gas, oil and NGL sales	$	88,524	$	—		$	—		$	88,524
Firm transportation sales, net	2,113		—			—			2,113
Gathering, compression and water distribution	—		1,393			(90		)	1,303
Total operating revenues	$	90,637	$	1,393		$	(90	)	$	91,940

Operating expenses:
Lease operating	6,667		—			—			6,667
Gathering, compression and transportation	8,104		—			(90		)	8,014
Production taxes and impact fees	871		—			—			871
Exploration	473		—			—			473
Midstream operation and maintenance	—		1,162			—			1,162
Incentive unit expense	2,462		(988		)	—			1,474
Stock compensation expense	994		131			—			1,125
General and administrative	9,430		5,415			—			14,845
Depreciation, depletion and amortization	31,397		1,155			—			32,552
Amortization of intangible assets	—		340			—			340
Total operating expenses	$	60,398	$	7,215		$	(90	)	$	67,523

Operating income (loss)	$	30,239	$	(5,822	)	$	—		$	24,417

Capital expenditures for segment assets	$	229,015	$	32,847		$	—		$	261,862

The operating results and assets of the Company’s reportable segments were as follows as of and for the six months ended June 30, 2015:



(in thousands)	Exploration and Production			Midstream		Elimination of Intersegment Transactions			Consolidated Total
Operating revenues:
Natural gas, oil and NGL sales	$	197,802		$	—	$	—		$	197,802
Firm transportation sales, net	3,264			—		—			3,264
Gathering, compression and water distribution	—			64,259		(42,892		)	21,367
Total operating revenues	$	201,066		$	64,259	$	(42,892	)	$	222,433

Operating expenses:
Lease operating	22,681			—		—			22,681
Gathering, compression and transportation	60,367			—		(29,105		)	31,262
Production taxes and impact fees	3,148			—		—			3,148
Exploration	1,095			—		—			1,095
Midstream operation and maintenance	—			6,132		—			6,132
Incentive unit expense	44,383			2,174		—			46,557
Stock compensation expense	5,231			2,236		—			7,467
General and administrative	29,414			8,500		—			37,914
Depreciation, depletion and amortization	132,256			6,997		(532		)	138,721
Amortization of intangible assets	—			816		—			816
Other expense	3,050			839		—			3,889
Total operating expenses	$	301,625		$	27,694	$	(29,637	)	$	299,682

Operating (loss) income	$	(100,559	)	$	36,565	$	(13,255	)	$	(77,249	)

Capital expenditures for segment assets	$	452,642		$	183,942	$	(13,787	)	$	622,797

The operating results and assets of the Company’s reportable segments were as follows for the six months ended June 30, 2014:



(in thousands)	Exploration and Production		Midstream			Elimination of Intersegment Transactions			Consolidated Total
Operating revenues:
Natural gas, oil and NGL sales	$	178,990	$	—		$	—		$	178,990
Firm transportation sales, net	2,113		—			—			2,113
Gathering, compression and water distribution	—		1,459			(145		)	1,314
Total operating revenues	$	181,103	$	1,459		$	(145	)	$	182,417

Operating expenses:
Lease operating	11,853		—			—			11,853
Gathering, compression and transportation	14,616		—			(145		)	14,471
Production taxes and impact fees	1,510		—			—			1,510
Exploration	959		—			—			959
Midstream operation and maintenance	—		1,835			—			1,835
Incentive unit expense	70,564		4,712			—			75,276
Stock compensation expense	1,085		131			—			1,216
General and administrative	18,998		7,277			—			26,275
Depreciation, depletion and amortization	56,461		1,598			—			58,059
Amortization of intangible assets	—		340			—			340
Total operating expenses	$	176,046	$	15,893		$	(145	)	$	191,794

Operating income (loss)	$	5,057	$	(14,434	)	$	—		$	(9,377	)

Capital expenditures for segment assets	$	394,293	$	47,357		$	—		$	441,650



As of June 30, 2015: (in thousands)	Exploration and Production		Midstream		Elimination of Intersegment Transactions			Consolidated Total
Segment assets	$	3,215,138	$	829,855	$	(13,787	)	$	4,031,206
Goodwill	$	294,908	$	39,142	$	—		$	334,050



As of December 31, 2014: (in thousands)	Exploration and Production		Midstream		Elimination of Intersegment Transactions		Consolidated Total
Segment assets	$	2,935,814	$	592,135	$	—	$	3,527,949
Goodwill	$	294,908	$	39,142	$	—	$	334,050


7.	Commitments and Contingencies

On October 14, 2013, the Company entered into a Development Agreement and Area of Mutual Interest (“AMI”) Agreement (collectively, the “Utica Development Agreements”) with Gulfport Energy Corporation (“Gulfport”) covering approximately 50,000 aggregate net acres in the Utica Shale in Belmont County, Ohio. Pursuant to the Utica Development Agreements, the Company had approximately 68.7% 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 48.2% 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.

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 June 30, 2015 totaled $4,846.5 million (remainder of 2015 - $49.4 million, 2016 - $117.2 million, 2017 - $136.8 million, 2018 - $197.6 million, 2019 - $222.5 million, 2020 - $222.3 million and thereafter - $3,900.7 million).

The Company has three horizontal and two tophole drilling rigs under contract, of which two expire in 2016, two expire in 2017 and one expires in 2018. Future payments under these contracts as of June 30, 2015 totaled $64.6 million (remainder of 2015 - $21.3 million, 2016 - $28.9 million, 2017 - $12.2 million and 2018 - $2.2 million). Any other rig performing work for the Company 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 the Company is committed to pay without regard to its proportionate share based on its 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.


8.	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 Energy Holdings LLC (“Rice Holdings”), Rice Energy Family Holdings, LP (“Rice Partners”), NGP Rice Holdings, LLC (“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, the Company 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, the Company completed a public offering (the “August 2014 Equity Offering”) of 13,729,650 shares of common stock at $27.30 per share, which included 7,500,000 shares sold by the Company and 6,229,650 shares sold by NGP Holdings and an affiliate of Alpha Natural Resources, Inc. (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 were used to fund a portion of the Company’s 2014 capital budget.

On December 22, 2014, the Partnership completed an initial public offering (the “RMP IPO”) of 28,750,000 common units representing limited partner interests in the Partnership, which represented 50% of the Partnership’s outstanding equity. The Company retained a 50% limited partner interest in the Partnership, consisting of 3,623 common units and 28,753,623 subordinated units. In connection with the RMP IPO, the Company contributed to the Partnership 100% of Rice Poseidon Midstream, LLC (“Rice Poseidon”). A wholly-owned subsidiary of the Company serves as the general partner of the Partnership. The Company continues to consolidate the results of the Partnership and records an income tax provision only as to its ownership percentage. The Company records the noncontrolling interest of the public limited partners in its condensed consolidated financial statements.

On May 12, 2015, the Company and NGP Holdings entered into an Underwriting Agreement (the “Underwriting Agreement”) with Goldman, Sachs & Co. and Citigroup Global Markets Inc. (together, the “Underwriters”), relating to the offer and sale by NGP Holdings (the “Secondary Offering”) of 6,000,000 shares of common stock at a price to the public of $24.20 per share ($23.99 per share net of underwriting discounts and commissions). The Secondary Offering closed on May 15, 2015. The Company did not receive any proceeds from the sale of shares of common stock by NGP Holdings.

The Company’s Board of Directors did not declare or pay a dividend for the three or six months ended June 30, 2015 or 2014. A cash distribution to the Partnership’s unitholders of $0.1875 per common and subordinated unit was paid by the Partnership on May 14, 2015 related to the first quarter of 2015. On July 24, 2015, the Board of Directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders for the second quarter of 2015 of $0.1905 per common and subordinated unit. The cash distribution will be paid on August 13, 2015 to unitholders of record at the close of business on August 4, 2015.


9.	Incentive Units

In connection with the IPO and the related corporate reorganization, the Rice Appalachia incentive unit holders contributed their Rice Appalachia incentive units (except for those exchanged for shares of common stock in connection with the extinguishment of an incentive burden attributable to Mr. Daniel J. Rice III) to Rice Holdings and NGP Holdings in return for incentive units in such entities that, in the aggregate, were substantially similar to the Rice Appalachia incentive units they previously held (except with respect to the incentive burden attributable to Mr. Daniel J. Rice III). In the first quarter of 2014, NGP Holdings distribution thresholds with regard to certain classes (tiers) of incentive units were satisfied as a result of NGP Holdings’ distribution of net proceeds from its sale of the Company’s common stock, and NGP Holdings made cash distributions to its members including holders of incentive units in an aggregate amount 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.

Total compensation expense relative to these interests was $23.1 million and $46.6 million for the three and six months ended June 30, 2015, respectively, and $1.5 million and $75.3 million for the three and six months ended June 30, 2014, respectively. Of the compensation expense recognized for the three and six months ended June 30, 2015, approximately $1.9 million and $11.1 million, respectively, related to changes in certain service condition assumptions. The Company expects to recognize approximately $52.2 million of additional compensation expense over the remaining expected service period related to the Rice Holdings interests. The NGP Holdings interests are considered a liability-based award and will be adjusted to fair market value on a quarterly basis until all payments have been made. The recognized and unrecognized compensation expense related to the NGP Holdings interests is sensitive to certain assumptions, including the estimated timing of NGP Holdings’ sale of the Company’s common stock. As of June 30, 2015, the unrecognized compensation expense related to the NGP Holdings units is approximately $24.5 million. 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.

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 the Company’s common stock) to its members pursuant to the terms of its limited liability company agreement. As a result, over time, the shares of the Company’s common stock held by Rice Holdings will be transferred in their entirety to Rice Energy Irrevocable Trust and the incentive unitholders.

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

The sale of the Company’s stock by NGP Holdings in the Secondary Offering triggered a payment to holders of certain NGP Holdings incentive units in May 2015, which resulted in approximately $26.7 million expense for the three and six months ended June 30, 2015. See Note 8 for a discussion of the Secondary Offering.

Three tranches of the incentive units have a time vesting feature. A roll forward of those units from December 31, 2014 to June 30, 2015 is included below.



Vested Units Balance, December 31, 2014	1,800,911
Vested During Period	559,590
Forfeited During Period	—
Granted During Period	—
Canceled During Period	—
Vested Units Balance, June 30, 2015	2,360,501

Four tranches of the incentive units do not have a time vesting feature, and their payouts are triggered upon a future payment condition. As such, none of these awards have legally vested as of June 30, 2015. 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	6/30/2015
Dividend Yield	0.00	%
Expected Volatility	47.29	%
Risk-Free Rate	0.37	%
Expected Life (Years)	1.25


10.	Stock-Based Compensation

During the year ended December 31, 2014 and the six months ended June 30, 2015, the Company granted stock compensation awards to certain non-employee directors and employees under the Company’s long-term incentive plan. The awards consisted of restricted stock units, which vest upon the passage of time, and performance stock units, which vest based upon attainment of specified performance criteria. Stock compensation expense related to these awards was $3.2 million and $5.5 million for the three and six months ended June 30, 2015, respectively, and $1.1 million and $1.2 million for the three and six months ended June 30, 2014, respectively. As of June 30, 2015, the Company has unrecognized compensation expense related to these equity awards of $26.0 million.

Stock compensation expense also includes phantom unit awards granted in connection with the closing of the Partnership’s IPO to certain non-employee directors of the Partnership and executive officers and employees of Rice Energy. The Partnership recorded $1.0 million and $2.0 million of stock compensation expense related to these awards in the three and six months ended June 30, 2015, respectively. As of June 30, 2015, the Partnership has unrecognized compensation expense related to these awards of $4.9 million.


11.	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. 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 six months ended June 30, 2015 and 2014. As indicated in Note 1, the Company’s corporate reorganization was considered a transaction amongst entities under common control. Therefore, the weighted average shares used in the Company’s EPS calculation assume that the Rice Energy Inc. corporate structure was in place for all periods presented.



	Three Months Ended June 30,						Six Months Ended June 30,
(in thousands, except share data)	2015			2014			2015			2014
Income (numerator):
Net (loss) income	$	(69,683	)	$	(7,917	)	$	(69,530	)	$	121,538

Weighted-average number of shares of common stock (denominator):
Basic	136,315,882			128,419,606			136,303,914			121,925,915
Diluted	136,315,882			128,419,606			136,303,914			122,255,908

Earnings (loss) per share:
Basic	$	(0.51	)	$	(0.06	)	$	(0.51	)	$	1.00
Diluted	$	(0.51	)	$	(0.06	)	$	(0.51	)	$	0.99

For the three and six months ended June 30, 2015, 284,829 and 170,413 shares, respectively, attributable to equity awards were not included in the diluted earnings per share calculation as the Company incurred a net loss for the periods presented herein.

For the three months ended June 30, 2014, 109,593 shares were not considered dilutive as the Company incurred a net loss for the periods presented herein.


12.	Income Taxes

The Company is a corporation subject to federal income tax at a statutory rate of 35% of pretax earnings and, as such, its future income taxes will be dependent upon its future taxable income. The Company did not report any income tax benefit or expense for periods prior to the consummation of its IPO because Rice Drilling B, the Company’s accounting predecessor, is a limited liability company that was not subject to federal income tax. The reorganization of the Company’s 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 six months ended June 30, 2014 disclosed in the accompanying condensed consolidated statements of operations assumes a statutory tax rate.

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. All of the Partnership’s earnings are included in the Company’s net income; however, the Company is not required to record income tax expense with respect to the portion of the Partnership’s earnings allocated to its noncontrolling public limited partners, which reduces the Company’s effective tax rate. Any refinements made due to subsequent information that affects the estimated annual effective income tax rate are reflected as adjustments in the current period.

The tax benefit for the three and six months ended June 30, 2015 was $10.0 million and $1.5 million, respectively, resulting in an effective tax rate of approximately 14% and 2%, respectively. A tax benefit of $4.6 million was recorded for the three months ended June 30, 2014, resulting in an effective tax rate of approximately 37%. Tax expense of $4.8 million was recorded for the six months ended June 30, 2014, resulting in an effective tax rate of approximately 4%. The effective tax rate for the three and six months ended June 30, 2015 and 2014 differs from the statutory rate due principally to nondeductible incentive unit expense, pre-tax income prior to the IPO and the portion of the Partnership’s earnings allocated to its noncontrolling public limited partners.

Based on management’s analysis, the Company did not have any uncertain tax positions as of June 30, 2015.


13.	New Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“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. In July 2015, the FASB deferred the effective date of the ASU to interim and annual periods beginning after December 15, 2017. The Company has not yet selected a transition method and is currently evaluating the standard and the impact on its consolidated financial statements and footnote disclosures.

In February 2015, the FASB issued ASU, 2015-02, “Consolidation (Topic 810): Amendments to the Consolidation Analysis.” ASU 2015-02 affects reporting entities that are required to evaluate whether they should consolidate certain legal entities. ASU 2015-02 is effective for periods beginning after December 15, 2015 with early adoption permitted. The Company is currently evaluating the new guidance and has not determined the impact this standard may have on its financial statements.

In April 2015, the FASB issued ASU, 2015-03, “Interest—Imputation of Interest (Subtopic 835-30): Simplification of Debt Issuance Costs.” ASU 2015-03 was issued to simplify the presentation of debt issuance costs by requiring debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of the related debt liability, consistent with debt discounts. ASU 2015-03 is effective for periods beginning after December 15, 2015 with early adoption permitted. The Company is currently evaluating the impact of the provisions of ASU 2015-03.


14.	Subsequent Events

On July 17, 2015, the Company entered into the Fifth Amendment to its Third Amended and Restated Credit Agreement and Amendment to Limited Consent and Second Amendment (the “Fifth Amendment”) to its Amended Credit Agreement. The Fifth Amendment expanded the Company’s hedging capabilities with respect to physical sales contracts. The Fifth Amendment, among other things, (i) revised the aggregate notional volume limitations for the Company’s hedging arrangements contained in the Amended Credit Agreement for the five year period following the date of the Amendment, (ii) provided a limited consent by the lenders to hedge additional volumes of natural gas with respect to calendar months of 2015 in which the Company is not calculated to exceed the notional volume limitations for such month and (iii) allowed the Company to enter into certain sales contracts with its lenders and their affiliates that are secured by the collateral under the Amended Credit Agreement, thereby reducing the Company’s need to post letters of credit with respect to certain firm transportation obligations.


15.	Guarantor Financial Information

On April 25, 2014, the Company issued $900.0 million in aggregate principal amount of the 2022 Notes and on March 26, 2015, the Company issued $400.0 million in aggregate principal amount of the 2023 Notes. The obligations under the Notes are fully and unconditionally guaranteed by the Guarantors, subject to release provisions described in Note 3. The Company’s subsidiaries that constitute its midstream segment, including the Partnership, are unrestricted subsidiaries under the indentures governing the Notes and consequently are not Guarantors. In accordance with positions established by the SEC, the following shows separate financial information with respect to the Company, the Guarantors and the non-guarantor subsidiaries. The principal elimination entries eliminate investment in subsidiaries and certain intercompany balances and transactions.



Condensed Consolidated Balance Sheet as of June 30, 2015
(in thousands)	Parent			Guarantors		Non-Guarantors		Eliminations			Consolidated
Assets
Current assets:
Cash	$	162,358		$	88,732	$	5,586	$	—		$	256,676
Accounts receivable	322			227,853		17,253		—			245,428
Receivable from affiliates	37,082			—		26,424		(63,414		)	92
Prepaid expenses and other assets	3,218			2,391		657		—			6,266
Derivative assets	36,668			91,834		—		—			128,502
Total current assets	239,648			410,810		49,920		(63,414		)	636,964

Investments in subsidiaries	2,496,157			118,094		—		(2,614,251		)	—
Gas collateral account	—			3,995		—		—			3,995
Property, plant and equipment, net	10,193			2,236,277		689,279		(13,255		)	2,922,494
Deferred financing costs, net	26,681			—		4,539		—			31,220
Goodwill	—			294,908		39,142		—			334,050
Intangible assets, net	—			—		46,976		—			46,976
Derivative assets	7,900			47,607		—		—			55,507
Total assets	$	2,780,579		$	3,111,691	$	829,856	$	(2,690,920	)	$	4,031,206

Liabilities and stockholders’ equity
Current liabilities:
Accounts payable	1,962			64,535		43,878		—			110,375
Royalties payables	—			52,620		—		—			52,620
Accrued capital expenditures	—			77,729		53,448		—			131,177
Accrued interest	17,108			—		140		—			17,248
Leasehold payables	—			14,496		—		—			14,496
Deferred tax liabilities	11,393			40,412		—		—			51,805
Payable to affiliate	—			63,414		—		(63,414		)	—
Other accrued liabilities	9,827			33,033		1,812		—			44,672
Total current liabilities	40,290			346,239		99,278		(63,414		)	422,393

Long-term liabilities:
Long-term debt	1,297,033			—		127,000		—			1,424,033
Leasehold payable	—			5,043		—		—			5,043
Deferred tax liabilities	(65,496		)	255,239		20,895		—			210,638
Other long-term liabilities	3,091			9,013		2,794		—			14,898
Total liabilities	1,274,918			615,534		249,967		(63,414		)	2,077,005
Stockholders’ equity before noncontrolling interest	1,505,661			2,496,157		130,893		(2,627,506		)	1,505,205
Noncontrolling interest	—			—		448,996		—			448,996
Total liabilities and stockholders’ equity	$	2,780,579		$	3,111,691	$	829,856	$	(2,690,920	)	$	4,031,206



Condensed Consolidated Balance Sheet as of December 31, 2014
(in thousands)	Parent		Guarantors		Non-Guarantors		Eliminations			Consolidated
Assets
Current assets:
Cash	$	181,835	$	41,934	$	32,361	$	—		$	256,130
Accounts receivable	1,773		196,974		1,153		—			199,900
Receivable from affiliates	634		55		2,198		(2,799		)	88
Prepaid expenses and other assets	1,296		1,702		341		—			3,339
Derivative assets	47,291		85,743		—		—			133,034
Total current assets	232,829		326,408		36,053		(2,799		)	592,491

Investments in subsidiaries	2,177,895		86,148		—		(2,264,043		)	—
Gas collateral account	—		3,995		—		—			3,995
Property, plant and equipment, net	10,348		1,986,856		464,127		—			2,461,331
Deferred financing costs, net	20,081		—		5,022		—			25,103
Goodwill	—		294,908		39,142		—			334,050
Intangible assets, net	—		—		47,791		—			47,791
Other non-current assets	8,290		54,898		—		—			63,188
Total assets	$	2,449,443	$	2,753,213	$	592,135	$	(2,266,842	)	$	3,527,949

Liabilities and stockholders’ equity
Current liabilities:
Current portion of long-term debt	$	—	$	680	$	—	$	—		$	680
Accounts payable	19,231		101,132		31,966		—			152,329
Royalties payables	—		37,172		—		—			37,172
Accrued capital expenditures	1,515		89,858		16,917		—			108,290
Accrued interest	9,375		—		—		—			9,375
Leasehold payables	—		30,702		—		—			30,702
Deferred tax liabilities	54,688		39,197		—		(39,197		)	54,688
Other accrued liabilities	16,652		27,502		2,086		(2,801		)	43,439
Total current liabilities	101,461		326,243		50,969		(41,998		)	436,675

Long-term liabilities:
Long-term debt	900,000		—		—		—			900,000
Deferred tax liabilities	12,497		237,155		10,660		(51,094		)	209,218
Leasehold payable	—		4,279		—		—			4,279
Other long-term liabilities	3,068		7,641		1,900		—			12,609
Total liabilities	1,017,026		575,318		63,529		(93,092		)	1,562,781
Stockholders’ equity before noncontrolling interest	1,432,417		2,177,895		86,148		(2,173,750		)	1,522,710
Noncontrolling interest	—		—		442,458		—			442,458
Total liabilities and stockholders’ equity	$	2,449,443	$	2,753,213	$	592,135	$	(2,266,842	)	$	3,527,949



Condensed Consolidated Statement of Operations for the Three Months Ended June 30, 2015
(in thousands)	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
Operating revenues:
Natural gas, oil and NGL sales	$	—		$	100,890		$	—		$	—		$	100,890
Firm transportation sales, net	—			438			—			—			438
Gathering, compression and water distribution	—			—			34,812			(23,246		)	11,566
Total operating revenues	—			101,328			34,812			(23,246		)	112,894

Operating expenses:
Lease operating	—			11,090			—			—			11,090
Gathering, compression and transportation	—			32,691			—			(15,849		)	16,842
Production taxes and impact fees	—			1,694			—			—			1,694
Exploration	—			212			144			—			356
Midstream operation and maintenance	—			—			2,801			—			2,801
Incentive unit expense	—			21,885			1,214			—			23,099
Stock compensation expense	—			3,011			1,201			—			4,212
General and administrative	—			16,116			4,309			—			20,425
Depreciation, depletion and amortization	—			73,119			3,553			(532		)	76,140
Amortization of intangible assets	—			—			408			—			408
Other expense	—			1,159			839			—			1,998
Total operating expenses	—			160,977			14,469			(16,381		)	159,065

Operating (loss) income	—			(59,649		)	20,343			(6,865		)	(46,171		)
Interest expense	(22,381		)	(18		)	(960		)	—			(23,359		)
Other income	261			774			—			—			1,035
(Loss) gain on derivative instruments	(4,866		)	1,156			—			—			(3,710		)
Amortization of deferred financing costs	(1,054		)	—			(252		)	—			(1,306		)
Equity income (loss) in affiliate	(62,845		)	912			—			61,933			—
Income (loss) before income taxes	(90,885		)	(56,825		)	19,131			55,068			(73,511		)
Income tax (expense) benefit	9,992			(6,020		)	(5,189		)	11,209			9,992
Net income (loss)	(80,893		)	(62,845		)	13,942			66,277			(63,519		)
Less: Net loss attributable to the noncontrolling interests	—			—			(6,164		)	—			(6,164		)
Net income (loss) attributable to Rice Energy	$	(80,893	)	$	(62,845	)	$	7,778		$	66,277		$	(69,683	)



Condensed Consolidated Statement of Operations for the Three Months Ended June 30, 2014
(in thousands)	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
Operating revenues:
Natural gas, oil and NGL sales	$	—		$	88,524		$	—		$	—		$	88,524
Firm transportation sales, net	—			2,113			—			—			2,113
Gathering, compression and water distribution	—			—			1,448			(145		)	1,303
Total operating revenues	—			90,637			1,448			(145		)	91,940

Operating expenses:
Lease operating	—			6,667			—			—			6,667
Gathering, compression and transportation	—			8,159			—			(145		)	8,014
Production taxes and impact fees	—			871			—			—			871
Exploration	—			473			—			—			473
Midstream operation and maintenance	—			126			1,036			—			1,162
Incentive unit expense	—			2,387			(913		)	—			1,474
Stock compensation expense	—			994			131			—			1,125
General and administrative	—			8,106			6,739			—			14,845
Depreciation, depletion and amortization	—			31,157			1,395			—			32,552
Amortization of intangible assets	—			—			340			—			340
Total operating expenses	—			58,940			8,728			(145		)	67,523

Operating loss	—			31,697			(7,280		)	—			24,417
Interest expense	(10,252		)	(5,689		)	—			—			(15,941		)
Other income (expense)	19			(226		)	12			—			(195		)
Loss on derivative instruments	—			(11,198		)	—			—			(11,198		)
Amortization of deferred financing costs	(532		)	—			—			—			(532		)
Loss on extinguishment of debt	—			(3,001		)	—			—			(3,001		)
Write-off of deferred financing costs	—			(6,060		)	—			—			(6,060		)
Equity in income (loss) of affiliate	3,629			1,610			—			(5,239		)	—
Income (loss) before income taxes	(7,136		)	7,133			(7,268		)	(5,239		)	(12,510		)
Income tax (expense) benefit	4,593			(3,504		)	8,878			(5,374		)	4,593
Net income (loss)	(2,543		)	3,629			1,610			(10,613		)	(7,917		)
Less: Net income attributable to the noncontrolling interests	—			—			—			—			—
Net income (loss) attributable to Rice Energy	$	(2,543	)	$	3,629		$	1,610		$	(10,613	)	$	(7,917	)



Condensed Consolidated Statement of Operations for the Six Months Ended June 30, 2015
(in thousands)	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
Operating revenues:
Natural gas, oil and NGL sales	$	—		$	197,802		$	—		$	—		$	197,802
Firm transportation sales, net	—			3,264			—			—			3,264
Gathering, compression and water distribution	—			—			64,259			(42,892		)	21,367
Total operating revenues	—			201,066			64,259			(42,892		)	222,433

Operating expenses:
Lease operating	—			22,681			—			—			22,681
Gathering, compression and transportation	—			60,367			—			(29,105		)	31,262
Production taxes and impact fees	—			3,148			—			—			3,148
Exploration	—			951			144			—			1,095
Midstream operation and maintenance	—			—			6,132			—			6,132
Incentive unit expense	—			44,383			2,174			—			46,557
Stock compensation expense	—			5,231			2,236			—			7,467
General and administrative	—			29,414			8,500			—			37,914
Depreciation, depletion and amortization	—			132,256			6,997			(532		)	138,721
Amortization of intangible assets	—			—			816			—			816
Other expense	—			3,050			839			—			3,889
Total operating expenses	—			301,481			27,838			(29,637		)	299,682

Operating (loss) income	—			(100,415		)	36,421			(13,255		)	(77,249		)
Interest expense	(37,806		)	(50		)	(1,632		)	—			(39,488		)
Other income	355			832			9			—			1,196
Gain on derivative instruments	9,099			48,558			—			—			57,657
Amortization of deferred financing costs	(1,906		)	—			(503		)	—			(2,409		)
Equity income (loss) in affiliate	(69,570		)	60			—			69,510			—
Income (loss) before income taxes	(99,828		)	(51,015		)	34,295			56,255			(60,293		)
Income tax (expense) benefit	1,462			(18,555		)	(10,279		)	28,834			1,462
Net income (loss)	(98,366		)	(69,570		)	24,016			85,089			(58,831		)
Less: Net loss attributable to the noncontrolling interests	—			—			(10,699		)	—			(10,699		)
Net income (loss) attributable to Rice Energy	$	(98,366	)	$	(69,570	)	$	13,317		$	85,089		$	(69,530	)



Condensed Consolidated Statement of Operations for the Six Months Ended June 30, 2014
(in thousands)	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
Operating revenues:
Natural gas, oil and NGL sales	$	—		$	178,990		$	—		$	—		$	178,990
Firm transportation sales, net	—			2,113			—			—			2,113
Gathering, compression and water distribution	—			—			1,459			(145		)	1,314
Total operating revenues	—			181,103			1,459			(145		)	182,417

Operating expenses:
Lease operating	—			11,853			—			—			11,853
Gathering, compression and transportation	—			14,616			—			(145		)	14,471
Production taxes and impact fees	—			1,510			—			—			1,510
Exploration	—			959			—			—			959
Midstream operation and maintenance	—			515			1,320			—			1,835
Incentive unit expense	—			70,564			4,712			—			75,276
Stock compensation expense	—			1,085			131			—			1,216
General and administrative	—			18,998			7,277			—			26,275
Depreciation, depletion and amortization	—			56,461			1,598			—			58,059
Amortization of intangible assets	—			—			340			—			340
Total operating expenses	—			176,561			15,378			(145		)	191,794

Operating loss	—			4,542			(13,919		)	—			(9,377		)
Interest expense	(10,252		)	(12,731		)	—			—			(22,983		)
Gain on purchase of Marcellus joint venture	—			203,579			—			—			203,579
Other income (expense)	20			376			—			—			396
Loss on derivative instruments	—			(31,578		)	—			—			(31,578		)
Amortization of deferred financing costs	(532		)	(489		)	—			—			(1,021		)
Loss on extinguishment of debt	—			(3,144		)	—			—			(3,144		)
Write-off of deferred financing costs	—			(6,896		)	—			—			(6,896		)
Equity loss of joint ventures	—			(2,656		)	—			—			(2,656		)
Equity in income (loss) of affiliate	130,617			(7,507		)	—			(123,110		)	—
Income (loss) before income taxes	119,853			143,496			(13,919		)	(123,110		)	126,320
Income tax (expense) benefit	(4,782		)	(12,879		)	6,412			6,467			(4,782		)
Net income (loss)	115,071			130,617			(7,507		)	(116,643		)	121,538
Less: Net income attributable to the noncontrolling interests	—			—			—			—			—
Net income (loss) attributable to Rice Energy	$	115,071		$	130,617		$	(7,507	)	$	(116,643	)	$	121,538



Condensed Consolidated Statement of Cash Flows for the Six Months Ended June 30, 2015
(in thousands)	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
Net cash provided by (used in) operating activities	$	(70,784	)	$	182,183		$	7,321		$	(13,787	)	$	104,933

Capital expenditures for property and equipment	(1,341		)	(451,301		)	(183,942		)	13,787			(622,797		)
Proceeds from sale of interest in gas properties	—			10,201			—			—			10,201
Investment in subsidiaries	(335,385		)	(28,973		)	—			364,358			—
Net cash (used in) provided by investing activities	(336,726		)	(470,073		)	(183,942		)	378,145			(612,596		)

Proceeds from borrowings	411,932			—			127,000			—			538,932
Repayments of debt obligations	(15,394		)	(697		)	—			—			(16,091		)
Debt issuance costs	(8,505		)	—			(21		)	—			(8,526		)
Offering costs related to the Partnership’s IPO	—			—			(129		)	—			(129		)
Distributions to the Partnership’s public unitholders	—			—			(5,977		)	—			(5,977		)
Parent distributions, net	—			335,385			28,973			(364,358		)	—
Net cash provided by (used in) financing activities	388,033			334,688			149,846			(364,358		)	508,209

Increase (decrease) in cash	(19,477		)	46,798			(26,775		)	—			546
Cash, beginning of year	181,835			41,934			32,361			—			256,130
Cash, end of period	$	162,358		$	88,732		$	5,586		$	—		$	256,676



Condensed Consolidated Statement of Cash Flows for the Six Months Ended June 30, 2014
(in thousands)	Parent				Guarantors				Non-Guarantors				Eliminations			Consolidated
Net cash provided by (used in) operating activities	$	4,798			$	78,502			$	(8,071	)		$	—		$	75,229

Capital expenditures for property and equipment	—			—	(394,293		)	—	(47,357		)	—	—			(441,650		)
Investment in subsidiaries	(1,083,844		)		(179,871		)		—				1,263,715			—
Acquisition of Marcellus JV, net of cash acquired	—				(82,766		)		—				—			(82,766		)
Acquisition of Momentum assets	—				—				(111,447		)		—			(111,447		)
Proceeds from sale of interest in gas properties	—				11,542				—				—			11,542
Net cash provided by (used in) investing activities	(1,083,844		)		(645,388		)		(158,804		)		1,263,715			(624,321		)

Proceeds from borrowings	900,000				—				—				—			900,000
Repayments of debt obligations	—				(498,865		)		—				—			(498,865		)
Restricted cash for convertible debt	—				8,268				—				—			8,268
Debt issuance costs	(20,726		)		2,290				—				—			(18,436		)
Shares of stock in IPO, net of costs	600,244				(3,149		)		—				—			597,095
Proceeds from conversion of warrants	—				948				—				—			948
Parent contributions, net	—				1,083,844				179,871				(1,263,715		)	—
Net cash provided by (used in) financing activities	1,479,518				593,336				179,871				(1,263,715		)	989,010

Increase (decrease) in cash	400,472				26,450				12,996				—			439,918
Cash, beginning of year	—				31,408				204				—			31,612
Cash, end of period	$	400,472			$	57,858			$	13,200			$	—		$	471,530

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 2014 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. 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

Rice Energy is an independent natural gas and oil company engaged in the acquisition, exploration and development of natural gas, oil and NGL properties in the Appalachian Basin. We operate in two business segments: exploration and production and midstream. The exploration and production segment is responsible for the acquisition, exploration and development of natural gas, oil and NGL properties in the Appalachian Basin. The midstream segment is engaged in the gathering and compression of natural gas, oil and NGL production, and in the provision of water services to support the well completion activities, of Rice Energy and third parties.

On January 29, 2014, we completed our initial public offering and related transactions (the “IPO”), including our reorganization and concurrent acquisition of Alpha Holdings’ 50% interest in our Marcellus joint venture. On December 22, 2014, RMP completed its initial public offering and related transactions (the “RMP IPO”), including our contribution to it of certain gas gathering and compression assets.

As a result of the reorganizations that occurred during 2014, our historical financial condition and results of operations for the periods presented in this Quarterly Report may not be comparable, either from period to period or going forward. For example, information for the period from January 1, 2014 through January 29, 2014, pertains to the historical financial statements and results of operations of our accounting predecessor. Whereas our accounting predecessor, Rice Drilling B, was not subject to federal income tax during this period, we are a corporation subject to federal income tax at a statutory rate of 35% of pretax earnings. In addition, such period reflects only our 50% equity investment in our Marcellus joint venture. From and after our acquisition of the remaining 50% interest from Alpha Holdings on January 29, 2014, the results of operations of our Marcellus joint venture are consolidated into our results of operations.

In connection with the RMP IPO in December 2014, we contributed to RMP all of our gas gathering and compression assets in Washington and Greene Counties, Pennsylvania in exchange for, among other things, common and subordinated units representing a 50.0% limited partner interest and all of the incentive distribution rights in RMP. In addition to these interests, RMP distributed to us approximately $414.4 million of the net proceeds of the RMP IPO raised from the sale of common units representing the remaining 50.0% limited partner interest in RMP. Indirectly through Midstream Holdings, we own and control the general partner of RMP. As such, the results of operations of RMP and the assets we contributed to it remain consolidated into our results of operations following the RMP IPO and concurrent contribution. However, for the periods after December 22, 2014, our results of operations give effect to the noncontrolling interest in RMP attributable to the 50.0% limited partner interest of its public unitholders.

Also in connection with the RMP IPO, we entered into various gas gathering and compression agreements and water distribution services agreements, both intercompany and, in the case of certain gas gathering and compression services in Pennsylvania, with RMP. Prior to December 22, 2014, with certain limited exceptions, our midstream segment did not charge fees for providing such services to our exploration and production segment.

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 realized prices. Our gathering, compression and water distribution revenues are primarily derived from our gathering and compression contracts with third parties in addition to fees charged to outside working interest owners.

The following table provides detail of our operating revenues from the condensed consolidated statements of operations for the three and six months ended June 30, 2015 and 2014.



	Three Months Ended June 30,				Six Months Ended June 30,
(in thousands)	2015		2014		2015		2014
Natural gas sales	$	98,885	$	88,492	$	193,605	$	178,958
Oil and NGL sales	2,005		32		4,197		32
Firm transportation sales, net	438		2,113		3,264		2,113
Gathering, compression and water distribution	11,566		1,303		21,367		1,314
Total operating revenues	$	112,894	$	91,940	$	222,433	$	182,417

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 June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
NYMEX Henry Hub High ($/MMBtu)	$	3.07		$	4.84		$	3.30		$	7.94
NYMEX Henry Hub Low ($/MMBtu)	$	2.49		$	4.35		$	2.49		$	3.96

NYMEX Henry Hub Price ($/MMBtu)	$	2.72		$	4.58		$	2.80		$	4.86
Less: Average Basis Impact ($/MMBtu) ⁽¹⁾	(0.74		)	(0.74		)	(0.67		)	(0.42		)
Plus: Btu Uplift (MMBtu/Mcf)	0.10			0.19			0.10			0.22
Pre-Hedge Realized Price ($/Mcf)	$	2.08		$	4.03		$	2.23		$	4.66

(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 six months ended June 30, 2014. The remainder of the three and six months ended June 30, 2014 reflects 100% of the volumes sold by our Marcellus joint venture.

Consolidated Results of Operations

Below are some highlights of our financial and operating results for the three and six months ended June 30, 2015 compared to the three and six months ended June 30, 2014:


•	Our natural gas, oil and NGL sales were $100.9 million and $88.5 million in the three months ended June 30, 2015 and 2014, respectively, and $197.8 million and $179.0 million in the six months ended June 30, 2015 and 2014, respectively.


•	Our production volumes were 48,099 MMcfe and 21,969 MMcfe in the three months ended June 30, 2015 and 2014, respectively, and 87,720 MMcfe and 38,359 MMcfe in the six months ended June 30, 2015 and 2014, respectively.


•	Our firm transportation sales, net, were $0.4 million and $2.1 million in the three months ended June 30, 2015 and 2014, respectively, and $3.3 million and $2.1 million in the six months ended June 30, 2015 and 2014, respectively.


•	Our gathering, compression and water distribution revenues were $11.6 million and $1.3 million in the three months ended June 30, 2015 and 2014, respectively, and $21.4 million and $1.3 million in the six months ended June 30, 2015 and 2014, respectively.


•	Our per unit cash production costs were $0.62 per Mcfe and $0.70 per Mcfe in the three months ended June 30, 2015 and 2014, respectively, and $0.66 per Mcfe and $0.73 per Mcfe in the six months ended June 30, 2015 and 2014, respectively.


•	Our general and administrative expenses were $20.4 million and $14.8 million in the three months ended June 30, 2015 and 2014, respectively, and $37.9 million and $26.3 million in the six months ended June 30, 2015 and 2014, respectively.

The following tables set forth selected operating and financial data for the three and six months ended June 30, 2015 compared to the three and six months ended June 30, 2014:



	Three Months Ended June 30,							Six Months Ended June 30,
	2015		2014		Change			2015		2014		Change
Natural gas sales (in thousands):	$	98,885	$	88,492	$	10,393		$	193,605	$	178,958	$	14,647
Oil and NGL sales (in thousands):	2,005		32		1,973			4,197		32		4,165
Natural gas, oil and NGL sales (in thousands):	$	100,890	$	88,524	$	12,366		$	197,802	$	178,990	$	18,812

Firm transportation sales, net (in thousands):	$	438	$	2,113	$	(1,675	)	$	3,264	$	2,113	$	1,151

Natural gas production (MMcf):	47,559		21,966		25,593			86,647		38,356		48,291
Oil and NGL production (MBbls):	90		1		89			179		1		178
Total production (MMcfe)	48,099		21,969		26,130			87,720		38,359		49,361

Average natural gas prices before effects of hedges per Mcf:	$	2.08	$	4.03	$	(1.95	)	$	2.23	$	4.66	$	(2.43	)
Average realized natural gas prices after effects of hedges per Mcf ⁽¹⁾:	2.97		3.59		(0.62		)	3.04		4.11		(1.07		)
Average oil and NGL prices per Bbl:	22.24		57.57		(35.33		)	23.46		57.57		(34.11		)

Average costs per Mcfe:
Lease operating	$	0.23	$	0.30	$	(0.07	)	$	0.26	$	0.31	$	(0.05	)
Gathering, compression and transportation	0.35		0.36		(0.01		)	0.36		0.38		(0.02		)
Production taxes and impact fees	0.04		0.04		—			0.04		0.04		—
General and administrative	0.42		0.68		(0.26		)	0.43		0.69		(0.26		)
Depreciation, depletion and amortization	1.58		1.48		0.10			1.58		1.51		0.07

Total gathering, compression and water distribution (in thousands):	$	11,566	$	1,303	$	10,263		$	21,367	$	1,314	$	20,053

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



	Three Months Ended June 30,									Six Months Ended June 30,
(in thousands, except per share data)	2015			2014			Change			2015			2014			Change
Operating revenues:
Natural gas, oil and NGL sales	$	100,890		$	88,524		$	12,366		$	197,802		$	178,990		$	18,812
Firm transportation sales, net	438			2,113			(1,675		)	3,264			2,113			1,151
Gathering, compression and water distribution	11,566			1,303			10,263			21,367			1,314			20,053
Total operating revenues	112,894			91,940			20,954			222,433			182,417			40,016

Operating expenses:
Lease operating	11,090			6,667			4,423			22,681			11,853			10,828
Gathering, compression and transportation	16,842			8,014			8,828			31,262			14,471			16,791
Production taxes and impact fees	1,694			871			823			3,148			1,510			1,638
Exploration	356			473			(117		)	1,095			959			136
Midstream operation and maintenance	2,801			1,162			1,639			6,132			1,835			4,297
Incentive unit expense	23,099			1,474			21,625			46,557			75,276			(28,719		)
Stock compensation expense	4,212			1,125			3,087			7,467			1,216			6,251
General and administrative	20,425			14,845			5,580			37,914			26,275			11,639
Depreciation, depletion and amortization	76,140			32,552			43,588			138,721			58,059			80,662
Amortization of intangible assets	408			340			68			816			340			476
Other expense	1,998			—			1,998			3,889			—			3,889
Total operating expenses	159,065			67,523			91,542			299,682			191,794			107,888

Operating (loss) income	(46,171		)	24,417			(70,588		)	(77,249		)	(9,377		)	(67,872		)
Interest expense	(23,359		)	(15,941		)	(7,418		)	(39,488		)	(22,983		)	(16,505		)
Gain on purchase of Marcellus joint venture	—			—			—			—			203,579			(203,579		)
Other income (loss)	1,035			(195		)	1,230			1,196			396			800
(Loss) gain on derivative instruments	(3,710		)	(11,198		)	7,488			57,657			(31,578		)	89,235
Amortization of deferred financing costs	(1,306		)	(532		)	(774		)	(2,409		)	(1,021		)	(1,388		)
Loss on extinguishment of debt	—			(3,001		)	3,001			—			(3,144		)	3,144
Write-off of deferred financing costs	—			(6,060		)	6,060			—			(6,896		)	6,896
Equity loss of joint ventures	—			—			—			—			(2,656		)	2,656
(Loss) income before income taxes	(73,511		)	(12,510		)	(61,001		)	(60,293		)	126,320			(186,613		)
Income tax benefit (expense)	9,992			4,593			5,399			1,462			(4,782		)	6,244
Net (loss) income	(63,519		)	(7,917		)	(55,602		)	(58,831		)	121,538			(180,369		)
Less: Net income attributable to noncontrolling interests	(6,164		)	—			(6,164		)	(10,699		)	—			(10,699		)
Net (loss) income attributable to Rice Energy Inc.	$	(69,683	)	$	(7,917	)	$	(61,766	)	$	(69,530	)	$	121,538		$	(191,068	)

Weighted average number of shares of common stock - basic	136,315,882			128,419,606			7,896,276			136,303,914			121,925,915			14,377,999
Weighted average number of shares of common stock - diluted	136,315,882			128,419,606			7,896,276			136,303,914			122,255,908			14,048,006
Earnings per share - basic	$	(0.51	)	$	(0.06	)	$	(0.45	)	$	(0.51	)	$	1.00		$	(1.51	)
Earnings per share - diluted	$	(0.51	)	$	(0.06	)	$	(0.45	)	$	(0.51	)	$	0.99		$	(1.50	)

Three Months Ended June 30, 2015 Compared to Three Months Ended June 30, 2014

Total operating revenues. The $21.0 million increase in total operating revenues was mainly a result of an increase in natural gas, oil and NGL production in the second quarter of 2015 compared to the second quarter of 2014 which was the result of increased drilling and completion activity, mainly in Washington County, Pennsylvania and Belmont County, Ohio. The impact of increased production volumes on operating revenues was offset by a decrease in realized prices. Our realized price in the second quarter of 2015 was $2.08 per Mcf compared to $4.03 per Mcf in the second quarter of 2014, in each case before the effect of hedges. Additionally, operating revenues were positively impacted by a $10.3 million increase in gathering, compression and water service revenues period-over-period. This increase primarily relates to increased third-party volumes and related revenues on gathering contracts as well as additional third-party volumes and revenues on new gathering contracts. Firm transportation sales, net, decreased period-over-period from $2.1 million in the second quarter of 2014 to $0.4 million in the second quarter of 2015 as we further utilized existing contracts for our operated production.

Lease operating expenses. The $4.4 million increase in lease operating expenses was attributable to an increase in the number of producing wells in the second quarter of 2015 as compared to the prior period. However, lease operating expenses per unit of production decreased period-over-period due to improved operating efficiencies, primarily relating to more producing wells per pad and lower rental and service costs.

Gathering, compression and transportation. Gathering, compression and transportation expense for the second quarter of 2015 is mainly comprised of $13.3 million of transportation contracts with third parties, $1.3 million of gathering charges from third parties and $1.4 million of charges from our working interest partners on our non-operated wells. The $8.8 million increase in the expense was primarily attributable to increased firm transportation expense in the second quarter of 2015 compared to the second quarter of 2014.

Midstream operation and maintenance. The $1.6 million increase in midstream operation and maintenance expense period-over-period was primarily due to additional contract labor and maintenance costs as well as additional leases on compression equipment.

Incentive unit expense. Incentive unit expense increased $21.6 million period-over-period. In the second quarter of 2014, incentive unit expense primarily consisted of $5.4 million of non-cash compensation expense related to the Rice Holdings incentive units, offset by $3.9 million of non-cash income related to the quarterly fair market value adjustment for the NGP Holdings incentive units. In the second quarter of 2015, the $23.1 million expense consisted of $7.0 million of non-cash compensation expense related to the Rice Holdings incentive units and $26.7 million related to payments made to certain holders of NGP Holdings incentive units, offset by $10.6 million of non-cash income related to the quarterly fair market value adjustment for the NGP Holdings incentive units. See “Item 1. Financial Statements—Notes to Condensed Consolidated Financial Statements—9. Incentive Units” for additional information.

General and administrative expenses. The $5.6 million increase period-over-period was primarily attributable to the addition of personnel to support our growth activities and related salary and employee benefits. At June 30, 2015, we had 337 employees as compared to 223 employees at June 30, 2014. Additionally, general and administrative expenses increased period-over-period as a result of the costs associated with our accounting system implementation. The increase in general and administrative expenses was offset by approximately $1.3 million of acquisition costs in the prior period.

DD&A. The $43.6 million increase was primarily a result of an increase in production driven by a greater number of producing wells in the second quarter of 2015 compared to second quarter of 2014, which is consistent with our expanded drilling program. In addition, the increase was the result of an increase in midstream assets placed in service in the second quarter of 2015 as compared to the second quarter of 2014 and the related depreciation on those assets. The increase in DD&A expense per unit of production period-over-period is consistent with a greater number of non-producing midstream assets placed in service.

Interest expense. The $7.4 million increase period-over-period was a result of higher levels of average borrowings outstanding during the second quarter of 2015 in order to fund our capital programs.

Gain (loss) on derivative instruments. The $3.7 million loss on derivative contracts in the second quarter of 2015 was due to cash receipts of $42.5 million on the settlement of maturing contracts and a $46.2 million unrealized loss in the second quarter of 2015. The $11.2 million loss on derivative contracts in the second quarter of 2014 was due to cash payments of $9.8 million on the settlement of maturing contracts and a $1.4 million unrealized loss.

Income tax benefit (expense). The $5.4 million increase in the income tax benefit period-over-period was attributable to a decrease in taxable income in addition to a lower estimated annual effective state tax rate.

Six Months Ended June 30, 2015 Compared to Six Months Ended June 30, 2014

Total operating revenues. The $40.0 million increase in total operating revenues was mainly a result of the gathering, compression and water service revenues for the six months ended June 30, 2015 as compared to the same period in 2014. In addition, an increase in natural gas, oil and NGL production for the six months ended June 30, 2015 compared to 2014 was the result of increased drilling and completion activity, mainly in Washington County, Pennsylvania and Belmont County, Ohio. The impact of increased production volumes on operating revenues was offset by a decrease in realized prices. Our realized price for the six months ended June 30, 2015 was $2.23 per Mcf compared to $4.66 per Mcf for the six months ended June 30, 2014, in each case before the effect of hedges. Additionally, operating revenues were positively impacted by a $20.1 million increase in gathering, compression and water service revenues period-over-period. This increase primarily relates to increased third-party volumes and related revenues on existing gathering contracts as well as additional third-party volumes and revenues on new gathering contracts. Operating revenues for the six months ended June 30, 2015 were also positively impacted by approximately $3.3 million in firm transportation sales, net, from the sale of unutilized capacity compared to $2.1 million in the same period in 2014.

Lease operating expenses. The $10.8 million increase in lease operating expenses was attributable to an increase in the number of producing wells in the six months ended June 30, 2015 as compared to the prior period. However, lease operating expenses per unit of production decreased period-over-period due to improved operating efficiencies, primarily relating to more producing wells per pad and and lower rental and service costs.

Gathering, compression and transportation. Gathering, compression and transportation expense for the six months ended June 30, 2015 is mainly comprised of $24.0 million of transportation contracts with third parties, $4.2 million of charges from our working interest partners on our non-operated wells and $1.6 million of gathering charges from third parties. The $16.8 million increase in the expense period-over-period was primarily attributable to increased firm transportation expense in the six months ended June 30, 2015 compared to the same period in 2014.

Midstream operation and maintenance. The $4.3 million increase in midstream operation and maintenance expense period-over-period was primarily due to additional contract labor and maintenance costs as well as additional leases on compression equipment.

Incentive unit expense. Incentive unit expense decreased $28.7 million period-over-period. In the six months ended June 30, 2014, incentive unit expense primarily consisted of $27.9 million and $39.6 million of non-cash compensation expense related to the Rice Holdings and NGP Holdings incentive units, respectively, as well as $3.4 million of non-cash compensation expense for stock issuances to Rice Holdings incentive unit holders and $4.4 million related to payments made to certain holders of NGP Holdings incentive units. In the six months ended June 30, 2015, the $46.6 million expense consisted of $20.7 million of non-cash compensation expense related to the Rice Holdings incentive units and $26.7 million related to payments made to certain holders of NGP Holdings incentive units, offset by $0.8 million of non-cash income related to the fair market value adjustment for the NGP Holdings incentive units. See “Item 1. Financial Statements—Notes to Condensed Consolidated Financial Statements—9. Incentive Units” for additional information.

General and administrative expenses. The $11.6 million increase period-over-period was primarily attributable to the addition of personnel to support our growth activities and related salary and employee benefits. At June 30, 2015, we had 337 employees as compared to 223 employees at June 30, 2014. Additionally, general and administrative expenses increased period-over-period as a result of the costs associated with our accounting system implementation. The increase in general and administrative expenses was offset by approximately $1.8 million of acquisition costs in the prior period.

DD&A. The $80.7 million increase was primarily a result of an increase in production driven by a greater number of producing wells in the six months ended June 30, 2015 compared to the same period in 2014, which is consistent with our expanded drilling program. In addition, the increase was the result of an increase in midstream assets placed in service in the six months ended June 30, 2015 as compared to the same period in 2014 and the related depreciation on those assets. The increase in DD&A expense per unit of production period-over-period is consistent with a greater number of non-producing midstream assets placed in service.

Interest expense. The $16.5 million increase was a result of higher levels of average borrowings outstanding during the six months ended June 30, 2015 in order to fund our capital programs.

Gain (loss) on derivative instruments. The $57.7 million gain on derivative contracts in the six months ended June 30, 2015 was due to cash receipts of $69.9 million on the settlement of maturing contracts and a $12.2 million unrealized loss in 2015. The $31.6 million loss on derivative contracts in the six months ended June 30, 2014 was due to cash payments of $21.0 million on the settlement of maturing contracts and a $10.6 million unrealized loss.

Income tax benefit (expense). The $6.2 million decrease in income tax expense period-over-period was attributable to a decrease in taxable income in addition to a lower estimated annual effective state tax rate.

Business Segment Results of Operations

We operate in two business segments: exploration and production and midstream. The exploration and production segment is responsible for the acquisition, exploration and development of natural gas, oil and NGL properties in the Appalachian Basin. The midstream segment is engaged in the gathering and compression of natural gas, oil and NGL production of, and in the provision of water services to support the well completion activities of Rice Energy and third parties. The midstream segment includes the financial results of the Partnership as well as the Company’s 50.0% limited partner interest and incentive distribution rights in the Partnership.

We evaluate our business segments based on their contribution to our consolidated results based on operating income. Please see “Item 1. Financial Statements—Notes to Condensed Consolidated Financial Statements—6. Financial Information by Business Segment” for a reconciliation of each segment’s operating income to our consolidated operating income.

The following tables set forth selected operating and financial data for each business segment during the three and six months ended June 30, 2015 compared to the three and six months ended June 30, 2014:

Exploration and Production Segment



	Three Months Ended June 30,								Six Months Ended June 30,
(in thousands, except volumes)	2015			2014		Change			2015			2014		Change
Operating revenues:
Natural gas, oil and NGL sales	$	100,890		$	88,524	$	12,366		$	197,802		$	178,990	$	18,812
Firm transportation sales, net	438			2,113		(1,675		)	3,264			2,113		1,151
Total operating revenues	101,328			90,637		10,691			201,066			181,103		19,963

Operating expenses:
Lease operating	11,090			6,667		4,423			22,681			11,853		10,828
Gathering, compression and transportation	32,691			8,104		24,587			60,367			14,616		45,751
Production taxes and impact fees	1,694			871		823			3,148			1,510		1,638
Exploration	356			473		(117		)	1,095			959		136
Incentive unit expense	21,885			2,462		19,423			44,383			70,564		(26,181		)
Stock compensation expense	3,011			994		2,017			5,231			1,085		4,146
General and administrative	16,115			9,430		6,685			29,414			18,998		10,416
Depreciation, depletion and amortization	73,342			31,397		41,945			132,256			56,461		75,795
Other expense	1,159			—		1,159			3,050			—		3,050
Total operating expenses	161,343			60,398		100,945			301,625			176,046		125,579

Operating (loss) income	$	(60,015	)	$	30,239	$	(90,254	)	$	(100,559	)	$	5,057	$	(105,616	)

Operating volumes:
Natural gas production (MMcf):	47,559			21,966		25,593			86,647			38,356		48,291
Oil and NGL production (MBbls):	90			1		89			179			1		178
Total production (MMcfe)	48,099			21,969		26,130			87,720			38,359		49,361

Three Months Ended June 30, 2015 Compared to Three Months Ended June 30, 2014

Total operating revenues. The $12.4 million increase in natural gas, oil and NGL sales was mainly a result of an increase in production in the second quarter of 2015 compared to the second quarter of 2014 as discussed above. The impact of increased production volumes on operating revenues was offset by a decrease in realized prices. Our realized price in the second quarter of 2015 was $2.08 per Mcf compared to $4.03 per Mcf in the second quarter of 2014, in each case before the effect of hedges. The increase in operating revenues for the second quarter of 2015 were offset by a $1.7 million decrease period-over-period in firm

transportation sales, net, from the sale of unutilized capacity as we further utilize our existing contracts for our own operated production.

Lease operating expenses. The $4.4 million increase in lease operating expenses was attributable to an increase in the number of producing wells in 2015 as compared to the prior period. However, lease operating expenses per unit of production decreased due to improved operating efficiencies, primarily due to more producing wells per pad and lower rental and service costs.

Gathering, compression and transportation. Gathering, compression and transportation expense for the second quarter of 2015 includes $17.1 million of affiliate and third party gathering fees, $13.3 million of transportation contracts with third parties and $1.4 million of charges from our working interest partners on our non-operated wells. The $24.6 million increase in gathering, compression and transportation expenses was mainly due to the gathering agreements with the midstream segment as well as increased firm transportation expense in the second quarter of 2015 compared to the second quarter of 2014.

General and administrative expenses. The $6.7 million increase in segment general and administrative expense period-over-period was primarily attributable to the additions of personnel to support our growth activities and related salary and employee benefits.

DD&A. The $41.9 million increase was a result of an increase in production and greater number of producing wells in the second quarter of 2015 compared to 2014, which is consistent with our expanded drilling program.

Six Months Ended June 30, 2015 Compared to Six Months Ended June 30, 2014

Total operating revenues. The $18.8 million increase in natural gas, oil and NGL sales was mainly a result of an increase in production in 2015 compared to 2014 as discussed above. The impact of increased production volumes on operating revenues was offset by a decrease in realized prices. Our realized price in 2015 was $2.23 per Mcf compared to $4.66 per Mcf in 2014, in each case before the effect of hedges. In addition, operating revenues for 2015 were positively impacted by an increase period-over-period of $1.2 million in firm transportation sales, net, from the sale of unutilized capacity.

Lease operating expenses. The $10.8 million increase in lease operating expenses was attributable to an increase in the number of producing wells in 2015 as compared to the prior period. However, lease operating expenses per unit of production decreased due to improved operating efficiencies, primarily due to more producing wells per pad and lower rental and service costs.

Gathering, compression and transportation. Gathering, compression and transportation expense for 2015 is primarily comprised of $30.7 million of affiliate and third party gathering fees, $24.0 million of transportation contracts with third parties and $4.2 million of charges from our working interest partners on our non-operated wells. The $45.8 million increase in gathering, compression and transportation expenses was mainly due to the gathering agreements with the midstream segment as well as increased firm transportation expense in 2015 compared to 2014.

General and administrative expenses. The $10.4 million increase in segment general and administrative expense period-over-period was primarily attributable to the additions of personnel to support our growth activities and related salary and employee benefits.

DD&A. The $75.8 million increase was a result of an increase in production and greater number of producing wells in 2015 compared to 2014, which is consistent with our expanded drilling program.

Midstream Segment



	Three Months Ended June 30,								Six Months Ended June 30,
(in thousands, except volumes)	2015		2014			Change			2015		2014			Change
Operating revenues:
Gathering revenues	$	25,164	$	1,237		$	23,927		$	43,910	$	1,303		$	42,607
Compression revenues	818		156			662			1,174		156			1,018
Water distribution revenues	8,830		—			8,830			19,175		—			19,175
Total operating revenues	34,812		1,393			33,419			64,259		1,459			62,800

Operating expenses:
Midstream operation and maintenance	2,801		1,162			1,639			6,132		1,835			4,297
Incentive unit expense	1,214		(988		)	2,202			2,174		4,712			(2,538		)
Stock compensation expense	1,201		131			1,070			2,236		131			2,105
General and administrative	4,310		5,415			(1,105		)	8,500		7,277			1,223
Depreciation, depletion and amortization	3,330		1,155			2,175			6,997		1,598			5,399
Amortization of intangible assets	408		340			68			816		340			476
Other expense	839		—			839			839		—			839
Total operating expenses	14,103		7,215			6,888			27,694		15,893			11,801

Operating income (loss)	$	20,709	$	(5,822	)	$	26,531		$	36,565	$	(14,434	)	$	50,999

Operating volumes:
Gathering volumes (MDth/d):	887		369			518			778		310			468
Compression volumes (MDth/d):	58		25			33			61		13			48
Water distribution volumes (MMgal):	163		—			163			348		—			348

Three Months Ended June 30, 2015 Compared to Three Months Ended June 30, 2014

Total operating revenues. The $33.4 million increase in total operating revenues was mainly the result of the gathering and water service contracts between the upstream and midstream segments as well as an increase third-party gathering revenue related to the acquisition of certain gas gathering assets in eastern Washington and Greene Counties, Pennsylvania in the second quarter of 2014.

Midstream operation and maintenance. Midstream operation and maintenance expense for the second quarter of 2015 includes $1.8 million of expense relative to our fresh water distribution assets and $1.0 million of expense relative to our gathering assets. The $1.6 million increase in expense period-over-period was primarily due to contract labor and maintenance costs as well additional leases on compression equipment.

General and administrative expenses. The $1.1 million decrease in general and administrative expense period-over-period was attributable to approximately $1.2 million related to costs associated with the Momentum Acquisition in the prior period and a decrease in allocated general and administrative expenses to the midstream segment.

DD&A. The $2.2 million increase was mainly the result of an increase in midstream assets placed in service in the second quarter of 2015 as compared to the second quarter of 2014 and the related depreciation on those assets.

Six Months Ended June 30, 2015 Compared to Six Months Ended June 30, 2014

Total operating revenues. The $62.8 million increase in total operating revenues period-over-period was mainly the result of the gathering and water service contracts between the upstream and midstream segments as well as an increase in third-party gathering revenue related to the acquisition of certain gas gathering assets in eastern Washington and Greene Counties, Pennsylvania in 2014.

Midstream operation and maintenance. Midstream operation and maintenance expense for 2015 includes $3.3 million of expense relative to our fresh water distribution assets and $2.8 million of expense relative to our gathering assets. The $4.3 million increase in expense period-over-period was was primarily due to contract labor and maintenance costs as well additional leases on compression equipment.

General and administrative expenses. The $1.2 million increase in general and administrative expense period-over-period was primarily attributable to the additions of personnel to support our growth activities and related salary and employee benefits, which was offset by approximately $1.5 million related to costs associated with the Momentum Acquisition in the prior period.

DD&A. The $5.4 million increase was mainly the result of an increase in midstream assets placed in service in 2015 as compared to 2014 and the related depreciation on those assets. Additionally, the increase was the result of a $0.8 million disposal of a water asset and the related write-off of the net book value of the asset in accordance with successful efforts accounting.

Capital Resources and Liquidity

Our primary sources of liquidity have been the proceeds from equity and debt financings and borrowings under our Senior Secured Revolving Credit Facility (defined below). Our primary use of capital has been the acquisition and development of natural gas properties and associated midstream infrastructure. 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.

Cash Flow Provided by Operating Activities

Net cash provided by operating activities was $104.9 million for the six months ended June 30, 2015, compared to $75.2 million of net cash provided by operating activities for the six months ended June 30, 2014. The increase in operating cash flow was primarily due increases in operating income including cash receipts on settled derivatives, offset by increases in the accounts receivable balance, which is consistent with production growth.

Cash Flow Used In Investing Activities

During the six months ended June 30, 2015 cash flows used in investing activities consisted of $612.6 million for capital expenditures for property and equipment, while the $624.3 million of cash flows used in investing activities for the six months ended June 30, 2014 primarily consisted of $441.7 million of capital expenditures for property and equipment and $194.2 million related to acquisition activity.

Capital expenditures for exploration and production were $452.6 million and $394.3 million for the six months ended June 30, 2015 and 2014, respectively. The increase of $58.3 million was primarily attributable to the acquisition and development of our natural gas properties.

Capital expenditures for midstream operations totaled $183.9 million and $47.4 million for the six months ended June 30, 2015 and 2014, respectively. The increase of $136.6 million was attributable to the expansion of the Company’s midstream infrastructure.

Cash Flow Provided By Financing Activities

Net cash provided by financing activities of $508.2 million during the six months ended June 30, 2015 was primarily the result of the proceeds from our 2023 Notes offering (discussed below) and borrowings on the Midstream Holdings Revolving Credit Facility and the RMP Revolving Credit Facility. Net cash provided by financing activities of $989.0 million during the six months ended June 30, 2014 was primarily the result of proceeds from our 2022 Notes offering (discussed below) and our IPO, which was offset by repayments of debt.

Debt Agreements

Senior Notes

On April 25, 2014, we issued $900.0 million in aggregate principal amount of 6.25% senior notes due 2022 (the “2022 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 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 with Barclays Bank PLC, as administrative agent, and a syndicate of lenders in an aggregate principal amount of $300.0 million, and expect to use the remainder to fund our capital expenditure plan.

The 2022 Notes will mature on May 1, 2022, and interest is payable on the 2022 Notes on each May 1 and November 1. At any time prior to May 1, 2017, we may redeem up to 35% of the 2022 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 2022 Notes remains outstanding after such redemption. Prior to May 1, 2017, we may redeem some or all of the 2022 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 2022 Notes), unless the Company has given notice to redeem the 2022 Notes, the holders of the 2022 Notes will have the right to require the Company to repurchase all or a portion of the 2022 Notes at a price equal to 101% of the aggregate principal amount of the 2022 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 2022 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.

On March 26, 2015, we issued $400.0 million in aggregate principal amount of 7.25% senior notes due 2023 (the “2023 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 $389.3 million after deducting estimated expenses and underwriting discounts and commissions of approximately $10.7 million. The Company used a portion of the net proceeds for general corporate purposes, including capital expenditures, and intends to use the remaining net proceeds for general corporate purposes, including capital expenditures.

The 2023 Notes will mature on May 1, 2023, and interest is payable on the 2023 Notes on each May 1 and November 1, commencing on November 1, 2015. At any time prior to May 1, 2018, we may redeem up to 35% of the 2023 Notes at a redemption price of 107.250% 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 2023 Notes remains outstanding after such redemption. Prior to May 1, 2018, 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 governing the 2023 Notes, unless the Company has given notice to redeem the 2023 Notes, the holders of the 2023 Notes will have the right to require the Company to repurchase all or a portion of the 2023 Notes at a price equal to 101% of the aggregate principal amount of the 2023 Notes, plus any accrued and unpaid interest to the date of purchase. On and after May 1, 2018, we may redeem some or all of the 2023 Notes at redemption prices (expressed as percentages of principal amount) equal to 105.438% for the twelve-month period beginning on May 1, 2018, 103.625% for the twelve-month period beginning May 1, 2019, 101.813% for the twelve-month period beginning on May 1, 2020 and 100.000% beginning on May 1, 2021, plus accrued and unpaid interest to the redemption date.

The indentures governing the 2022 Notes and the 2023 Notes (collectively, the “Notes”) restrict 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 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 indentures) has occurred and is continuing, many of such covenants will terminate and we and our subsidiaries will cease to be subject to such covenants.

Senior Secured Revolving Credit Facility

In April 2013, we entered into our $300.0 million Senior Secured Revolving Credit Facility (the “Senior Secured Revolving Credit Facility”). In April 2014, we, as borrower, and Rice Drilling B, as predecessor borrower, amended and restated the credit agreement governing the Senior Secured Revolving Credit Facility (as amended, the “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 June 30, 2015, the borrowing base was $650.0 million and the sublimit for letters of credit was $175.0 million. We had zero borrowings outstanding and $105.0 million in letters of credit outstanding under the Amended Credit Agreement as of June 30, 2015, resulting in availability of $545.0 million. The maturity date of the Senior Secured Revolving Credit Facility is January 29, 2019.

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 us and our subsidiaries (other than any subsidiary that is designated as an unrestricted subsidiary including Midstream Holdings and its subsidiaries), 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 also contains certain financial covenants and customary events of default. If an event of default occurs and is continuing, the lenders may declare all amounts outstanding under the Amended Credit Agreement to be immediately due and payable. We were in compliance with such covenants and ratios as of June 30, 2015.

Midstream Holdings Revolving Credit Facility

On December 22, 2014, Midstream Holdings entered into a revolving credit facility (“Midstream Holdings Revolving Credit Facility”) with Wells Fargo Bank, N.A., as administrative agent, and a syndicate of lenders with a maximum credit amount of $300.0 million and a sublimit for letters of credit of $25.0 million. As of June 30, 2015, Midstream Holdings had $97.0 million borrowings outstanding and $0.1 million letters of credit under this facility. The Midstream Holdings Revolving Credit Facility is available to fund working capital requirements and capital expenditures and to purchase assets and matures on December 22, 2019.

Principal amounts borrowed are payable on the maturity date, and interest is payable quarterly for base rate loans and at the end of the applicable interest period for Eurodollar loans. Under the revolving credit facility, Midstream Holdings may elect to borrow in Eurodollars or at the base rate. Eurodollar loans bear interest at a rate per annum equal to the applicable LIBOR Rate plus an applicable margin ranging from 225 to 300 basis points, depending on the leverage ratio then in effect. 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 125 to 200 basis points, depending on the leverage ratio then in effect. Midstream Holdings also pays a commitment fee based on the undrawn commitment amount ranging from 37.5 to 50 basis points.

The Midstream Holdings Revolving Credit Facility is secured by mortgages and other security interests on substantially all of the properties of, and guarantees from, Midstream Holdings and its restricted subsidiaries (which do not include RMP or Rice Midstream Management LLC, a Delaware limited liability company and general partner of RMP, or Rice Energy and its subsidiaries other than Midstream Holdings).

The Midstream Holdings Revolving Credit Facility also contains certain financial covenants and customary events of default. If an event of default occurs and is continuing, the lenders may declare all amounts outstanding under the Midstream Holdings Revolving Credit Facility to be immediately due and payable. Midstream Holdings was in compliance with such covenants and ratios as of June 30, 2015.

RMP Revolving Credit Facility

On December 22, 2014, Rice Midstream OpCo entered into a revolving credit facility (the “RMP Revolving Credit Facility”) with RMP, Wells Fargo Bank, N.A., as administrative agent, and a syndicate of lenders with a maximum credit amount of $450.0 million with an additional $200.0 million of commitments available under an accordion feature subject to lender approval. The RMP Revolving Credit Facility provides for a letter of credit sublimit of $50.0 million. As of June 30, 2015, Rice Midstream OpCo had $30.0 million borrowings outstanding and no letters of credit under this facility. The RMP Revolving Credit Facility is available to fund working capital requirements and capital expenditures, to purchase assets, to pay distributions and repurchase units and for general partnership purposes.

Principal amounts borrowed are payable on the maturity date, and interest is payable quarterly for base rate loans and at the end of the applicable interest period for Eurodollar loans. Under the revolving credit facility, Rice Midstream OpCo may elect to borrow in Eurodollars or at the base rate. Eurodollar loans bear interest at a rate per annum equal to the applicable LIBOR Rate plus an applicable margin ranging from 175 to 275 basis points, depending on the leverage ratio then in effect. Base rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank’s reference rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the rate for one month Eurodollar loans plus 100 basis points, plus an applicable margin ranging from 75 to 175 basis points, depending on the leverage ratio then in effect. Rice Midstream OpCo also pays a commitment fee based on the undrawn commitment amount ranging from 35 to 50 basis points.

The RMP Revolving Credit Facility is secured by mortgages and other security interests on substantially all of RMP’s properties and guarantees from RMP and its restricted subsidiaries.

The RMP Revolving Credit Facility also contains certain financial covenants and customary events of default. If an event of default occurs and is continuing, the lenders may declare all amounts outstanding under the RMP Revolving Credit Facility to be immediately due and payable. RMP was in compliance with such covenants and ratios as of June 30, 2015.

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. Pursuant to our Amended Credit Agreement, we are now permitted to hedge the greater of (A) the percentage of internally forecasted production (Column A) and (B) the lesser of (i) the percentage of proved reserve volumes (Column B) according to the table below and (ii) 140% of the monthly average production for the most recent period of three consecutive months.



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

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—4. Derivative Instruments and 5. 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 eight different counterparties. As of June 30, 2015, our contracts with Wells Fargo Bank N.A. accounted for 39% 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 June 30, 2015 and December 31, 2014, we did not have any past due receivables from counterparties.

Critical Accounting Policies and Estimates

Our critical accounting policies are described in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates” in our 2014 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.

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 “Item 1. Financial Statements—7. Commitments and Contingencies” 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

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

To mitigate some of the potential negative impact on our cash flow caused by changes in commodity prices, we enter into financial commodity swap contracts to receive fixed prices for a portion of our natural gas, NGLs, and oil production to mitigate the potential negative impact on our cash flow.

Our financial hedging activities are intended to support natural gas, NGLs, and oil prices at targeted levels and to manage our exposure to natural gas, NGLs, and oil price fluctuations. The counterparty is required to make a payment to us for the difference between the fixed price and the settlement price if the settlement price is below the fixed price. We are required to make a payment to the counterparty for the difference between the fixed price and the settlement price if the fixed price is below the settlement price. These contracts may include financial price swaps whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty, cashless price collars that set a floor and ceiling price for the hedged production, or basis differential swaps. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, we and the counterparty to the collars would be required to settle the difference.

As of June 30, 2015, we have entered into derivative instruments with various financial institutions, fixing the price we receive for a portion of our natural gas through December 31, 2022. Our commodity hedge position as of June 30, 2015 is summarized in Note 4 to our condensed consolidated financial statements included elsewhere in the Quarterly Report. Our financial hedging activities are intended to support natural gas, NGLs and oil prices at targeted levels and to manage our exposure to price fluctuations.

By removing price volatility from a portion of our expected natural gas production through December 31, 2022, we have mitigated, but not eliminated, the potential effects of changing prices on our operating cash flow for those periods. While mitigating negative effects of falling commodity prices, these derivative contracts also limit the benefits we would receive from increases in commodity prices above the hedge prices.

Interest rate risks

Our primary interest rate risk exposure results from our credit facilities.

As of June 30, 2015, we had zero borrowings and approximately $105.0 million in letters of credit outstanding under our Senior Secured Revolving Credit Facility. As of June 30, 2015, we had availability under our Senior Secured Revolving Credit Facility of approximately $545.0 million and a borrowing base of $650.0 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, 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, depending on the percentage of our borrowing base utilized.

As of June 30, 2015, Rice Midstream Holdings had $97.0 million of borrowings and $0.1 million letters of credit outstanding under the Midstream Holdings Revolving Credit Facility. Under the revolving credit facility, Rice Midstream Holdings may elect to borrow in Eurodollars or at the base rate. Eurodollar loans bear interest at a rate per annum equal to the applicable LIBOR Rate plus an applicable margin ranging from 225 to 300 basis points, depending on the leverage ratio then in effect. 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 125 to 200 basis points, depending on the leverage ratio then in effect.

The average annual interest rate incurred on the Midstream Holdings Revolving Credit Facility during the six months ended June 30, 2015 was approximately 2.4%. A 1.0% increase in the applicable average interest rates for the six months ended June 30, 2015 would have resulted in an estimated $0.2 million increase in interest expense.

As of June 30, 2015, Rice Midstream OpCo had $30.0 million of borrowings and no letters of credit outstanding under the RMP Revolving Credit Facility. Under the RMP Revolving Credit Facility, Rice Midstream OpCo may elect to borrow in Eurodollars or at the base rate. Eurodollar loans will bear interest at a rate per annum equal to the applicable LIBOR Rate plus an applicable margin ranging from 175 to 275 basis points, depending on the leverage ratio then in effect. Base rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank’s reference rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the rate for one month Eurodollar loans plus 100 basis points, plus an applicable margin ranging from 75 to 175 basis points, depending on the leverage ratio then in effect.

The average annual interest rate incurred on the RMP Revolving Credit Facility during the six months ended June 30, 2015 was approximately 1.9%. A 1.0% increase in the applicable average interest rates for the six months ended June 30, 2015 would have resulted in a less than $0.1 million estimated increase in interest expense.

As of June 30, 2015, 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 ($142.6 million as of June 30, 2015) and the sale of our natural gas production ($83.6 million in receivables as of June 30, 2015), 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 have minimal ability to choose who participates in our wells. We are also subject to credit risk due to concentration of our natural gas receivables with three natural gas marketing companies. We do not require our customers to post collateral. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) under the Securities Exchange Act of 1934, as amended (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) and 15d-15(e) under the Exchange Act) as of June 30, 2015. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of June 30, 2015.

Changes in Internal Control over Financial Reporting

During the quarter ended June 30, 2015, we completed the implementation of a new accounting application. We have taken the necessary steps to monitor and maintain appropriate internal controls during this period of change, including procedures to preserve the integrity of the data converted during the application implementation. Additionally, we provided training related to this application to individuals using the application to carry out their job responsibilities. We believe the new application will enhance our internal controls over financial reporting due to enhanced automation and integration of related processes. We are modifying the design and documentation of internal control processes and procedures relating to the new application and modules to supplement and complement existing internal control over certain respective job areas. The application change was not undertaken in response to any deficiencies in our internal control over financial reporting. Testing of the controls related to the new application and accounting functions is ongoing and is included in the scope of our assessment of our internal control over financial reporting for 2015. We will continuously monitor controls through and around the application to provide reasonable assurance that controls are effective.

There were no other changes in our internal control over financial reporting (as defined in rules 13a-15(f) and 15d-15(t) under the Exchange Act) during our most recently completed fiscal quarter 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—7. 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 2014 Annual Report. For a discussion of our potential risks and uncertainties, see the information in “Item 1A. Risk Factors” in our 2014 Annual Report.

Item 6. Exhibits



Exhibit Number		Exhibit
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		Fourth Amendment to Third Amended and Restated Credit Agreement, dated as of April 30, 2015, 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 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on May 1, 2015).
10.2		Rice Energy Inc. Annual Incentive Bonus Plan (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on June 5, 2015).
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 of 1934, as amended (“Exchange Act”), or otherwise subject to the liability of Section 18 of the Exchange Act, 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:	August 7, 2015	By:	/s/ Daniel J. Rice IV
			Daniel J. Rice IV
			Director, Chief Executive Officer
			(Principal Executive Officer)

Date:	August 7, 2015	By:	/s/ Grayson T. Lisenby
			Grayson T. Lisenby
			Senior Vice President and Chief Financial Officer
			(Principal Financial Officer)

EXHIBIT INDEX



Exhibit Number		Exhibit
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		Fourth Amendment to Third Amended and Restated Credit Agreement, dated as of April 30, 2015, 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 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on May 1, 2015).
10.2		Rice Energy Inc. Annual Incentive Bonus Plan (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on June 5, 2015).
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.

GLOSSARY OF OIL AND NATURAL GAS TERMS

The following are abbreviations and definitions of certain terms used in this document, which are commonly used in the oil and natural gas industry:

“Barrel” or “Bbl.” 42 U.S. gallons measured at 60 degrees Fahrenheit.

“Btu.” One British thermal unit, the quantity of heat required to raise the temperature of a one-pound mass of water by one degree of Fahrenheit.

“Basin.” A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.

“Completion.” The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

“DD&A.” Depreciation, depletion, amortization and accretion.

“Dry hole.” A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

“Formation.” A layer of rock which has distinct characteristics that differs from nearby rock.

“Horizontal drilling.” A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.

“MBbls.” One thousand barrels.

“Mcf.” One thousand cubic feet of natural gas.

“Mcfe.” One thousand cubic feet of natural gas equivalent, determined by using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate of natural gas liquids.

“MDth/d.” One thousand dekatherms per day.

“MMBbls.” One million barrels.

“MMBtu.” One million Btu.

“MMGal.” One million gallons.

“MMcf.” One million cubic feet of natural gas.

“MMcfe.” One million cubic feet of natural gas equivalent, determined by using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate of natural gas liquids.

“NGLs.” Natural gas liquids. Hydrocarbons found in natural gas which may be extracted as liquefied petroleum gas and natural gasoline.

“NYMEX.” The New York Mercantile Exchange.

“Net acres.” The percentage of total acres an owner has out of a particular number of acres, or a specified tract. An owner who has 50% interest in 100 acres owns 50 net acres.

“Prospect.” A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

“Proved reserves.” The estimated quantities of oil, natural gas and NGLs which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.

“Reservoir.” A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.

“Working interest.” The right granted to the lessee of a property to explore for and to produce and own natural gas or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.

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