Eqt Re 8-K Rice Energy Reports Second Quarter 2015 Results, Adjusted EBITDAX of $97.4 Million and Increases Full-Year 2015 Production Guidance

Exhibit 99.1

FOR IMMEDIATE RELEASE

Rice Energy Reports Second Quarter 2015 Results, Adjusted EBITDAX of $97.4 Million and Increases Full-Year 2015 Production Guidance

CANONSBURG, Pa., – August 6, 2015 /PRNewswire/ –Rice Energy Inc.(NYSE: RICE) (“Rice Energy”) today reported second quarter 2015 financial and operational results. Highlights during the quarter include:

• Net production averaged 529 MMcfe/d for the second quarter, a 120% increase relative to second quarter 2014

• Record adjusted EBITDAX⁽¹⁾ of $97.4 million for the second quarter, a 93% increase from second quarter 2014

• Adjusted realized natural gas price⁽²⁾ of $2.98 per Mcf in the second quarter

• Completed first Pennsylvania Utica well in Greene County, Pennsylvania with production planned for late third quarter 2015

• Turned to sales 11 operated Ohio Utica and 14 operated Pennsylvania Marcellus wells, our most active quarter in our history

• Achieved significant midstream throughput growth to 887 MDth/d, a 33% increase relative to first quarter 2015

• Rice Midstream Partners (“RMP”) received a favorable private letter ruling from the IRS providing that income from certain water services constitutes qualifying income

• Increased 2016 hedge position to 389 BBtu/d at a weighted average floor price of $3.65 per MMBtu⁽³⁾

• Strong second quarter liquidity position of over $1 billion, excluding RMP

Commenting on the results, Daniel J. Rice IV, Chief Executive Officer, said, “We had a tremendous quarter operationally, significantly surpassing our expected production by consistently turning wells online on time or ahead of schedule. I am proud of our team’s collaborative efforts, evidenced by our strong quarterly results in spite of a challenging commodity price market.”

(1) Please see “Supplemental Non-GAAP Financial Measure” for a description of Adjusted EBITDAX.

(2) Adjusted realized price includes our firm transportation sales, net, and the impact of hedging.

(3) Excluding basis hedges.

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Second Quarter 2015 Consolidated Results	Three Months Ended June 30, 2015			Six Months Ended June 30, 2015
Total production (MMcfe)		48,099			87,720
Total production (MMcfe/d)		529			485
% Gas		99	%		99	%
% Operated		90	%		92	%
% Marcellus		77	%		80	%
Average realized prices per Mcf:
Natural gas price before effects of hedges	$	2.08		$	2.23
Natural gas price after effects of hedges(1)	$	2.97		$	3.04
Adjusted realized price	$	2.98		$	3.08
Average oil and NGL price per Bbl	$	22.24		$	23.46
Average costs per Mcfe:
Lease operating	$	0.23		$	0.26
Gathering, compression and transportation	$	0.35		$	0.36
Production taxes and impact fees	$	0.04		$	0.04
General and administrative	$	0.42		$	0.43
Depletion, depreciation and amortization	$	1.58		$	1.58
Adjusted EBITDAX (in thousands)	$	97,387		$	181,663
Total midstream throughput (MDth/d)		887			778
% Third-party		21	%		19	%

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

Second Quarter 2015 Financial Results

During the second quarter, our net daily production averaged 529 MMcfe/d, a 20% increase relative to first quarter 2015 volumes and a 120% increase from second quarter 2014 production. Our second quarter realized natural gas price, before the effect of hedges, was $2.08 per Mcf. After giving effect to hedges, our average natural gas price was $2.97 per Mcf. Our average adjusted realized price, including our firm transportation sales and the impact of hedges, was $2.98 per Mcf. Our average realized oil and NGL price was $22.24 per Bbl. Per unit cash production costs (lease operating; gathering, compression and transportation; and production taxes and impact fees) were $0.62 per Mcfe, a 10% decrease from the first quarter 2015. Adjusted EBITDAX for the quarter was $97.4 million. We reported adjusted net income of $4.4 million, or $0.03 per share, after excluding unrealized gains on derivative contracts and other non-recurring income and expense items.

Year to Date Financial Results

Net daily production for the six months ended June 30, 2015, averaged 485 MMcfe/d, a 116% increase as compared to the prior year period. Our realized natural gas price, before the effect of hedges, was $2.23 per Mcf. After giving effect to hedges, our 2015 average natural gas price was $3.04 per Mcf. Our average adjusted realized price was $3.08 per Mcf. Our average realized oil and NGL price was $23.46 per Bbl. Per unit cash production costs were $0.66 per Mcfe. Adjusted EBITDAX for the six months ended June 30, 2015 was $181.7 million. We reported an adjusted net loss of $21.6 million, or ($0.16) per share.

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2015 Production Guidance Update

Due to continued efficiency gains across our drilling, completion and midstream departments, our project cycle times have shortened, and we anticipate maintaining these efficiencies through the second half of the year. As a result, we are increasing our 2015 annual production guidance to 485 - 505 MMcfe/d and reaffirming our 2015 capital budget for E&P and retained midstream investments of $890 million.

Upstream Segment

Marcellus Shale

Marcellus net production averaged 403 MMcfe/d for the quarter, a 10% increase from the prior quarter and a 68% increase from second quarter 2014.

We turned to sales 14 gross (12 net) horizontal Marcellus wells with an average lateral length of 8,185 feet at an average development cost of $1,191 per lateral foot. These wells are currently producing approximately 150 MMcf/d on managed chokes. As of June 30, 2015, our Marcellus leasehold position in Washington and Greene Counties, Pennsylvania totaled approximately 88,600 net acres.

In July 2015, we turned to sales 6 gross (5 net) Marcellus wells with an average lateral length of approximately 6,400 feet.

The following table provides operational data through June 30, 2015, for Rice Energy’s operated Marcellus wells.

					Periodic Flow Rates (MMcfe/d)
Period	Gross Operated Wells Turned Into Sales		Average Lateral Length (Feet)		0-90		91-180		181-360		361-720		D&C ($/Foot)
2010-2011		6		3,279		5.7		6.0		4.4		2.7	$	2,363
2012		9		5,731		9.2		10.0		6.8		4.1	$	1,636
2013		22		6,320		11.2		10.6		7.6		4.8	$	1,440
2014(1)		41		7,272		10.6		9.4		6.8		N/A	$	1,236
Q1 2015		8		6,225		7.6		N/A		N/A		N/A	$	1,303
Q2 2015		14		8,185		N/A		N/A		N/A		N/A	$	1,191
Total(2)		100		6,729		10.0		9.6		6.9		3.9	$	1,384

(1) Excludes 7 acquired producing wells.

(2) With the exception of wells turned into sales, totals represent averages weighted by number of wells.

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Utica Shale - Ohio

Ohio Utica net production averaged 126 MMcfe/d for the quarter, a 74% increase from the prior quarter.

We turned to sales 11 gross (6 net) operated horizontal Utica wells with an average lateral length of 9,963 feet at an average development cost of $1,509 per lateral foot. These wells are currently producing approximately 185 MMcf/d on managed chokes. As of June 30, 2015, our leasehold position totaled approximately 55,500 net acres in southeast Ohio, primarily in Belmont County.

Our five operated Utica wells turned to sales prior to the second quarter continue to produce at a flat rate on a restricted choke, including our first well Bigfoot 9H, which has been producing since June 2014.

The following table provides operational data through June 30, 2015, for Rice Energy’s operated Ohio Utica wells.

					Periodic Flow Rates (MMcf/d)
Period	Gross Operated Wells Turned Into Sales		Average Lateral Length (Feet)		0-90		91-180		181-360		361-720		D&C ($/Foot)
Q2 2014		1		6,957		14.0		14.2		15.9		N/A	$	3,316
Q3 2014		2		8,879		14.5		15.9		N/A		N/A	$	2,027
Q4 2014		—		N/A		N/A		N/A		N/A		N/A		N/A
Q1 2015		2		8,639		16.0		N/A		N/A		N/A	$	1,890
Q2 2015		11		9,963		N/A		N/A		N/A		N/A	$	1,509
Total(1)		16		9,474		15.0		15.3		15.9		N/A	$	1,734

(1) With the exception of wells turned into sales, totals represent averages weighted by number of wells.

Utica Shale - Pennsylvania

We are currently developing our first Utica well in Pennsylvania, the John Briggs 50U, located in western Greene County. We have drilled and completed the 5,800 foot lateral section and are currently installing production facilities. Development is ahead of schedule and we anticipate first production occurring late in the third quarter of 2015.

Firm Transportation and Realized Gas Pricing

Approximately 61% of our second quarter production received favorable Gulf Coast, TCO and Midwest pricing, while the remainder of our production was sold at local Appalachian prices. Our average basis differential for the quarter was ($0.61) per MMBtu, while TETCO M2 and Dominion South averaged ($1.26) and ($1.28) per MMBtu, respectively, below NYMEX Henry Hub for the quarter. For the remainder of 2015, we anticipate that approximately 84% of our production will be transported to premium gas markets outside of Appalachia.

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The following tables provide basis exposure as a percentage of our production and average differentials to NYMEX for actual results through June 30, 2015 and estimated results for the remainder of 2015 through 2016.

	Basis Exposure
	Actual						Estimated
	1Q15			2Q15			3Q15			4Q15			Full Year 2015			Full Year 2016
Basis
Gulf Coast		27	%		35	%		41	%		51	%		44	%		52	%
TCO		23	%		17	%		18	%		16	%		18	%		10	%
Midwest/Dawn		1	%		9	%		21	%		20	%		11	%		15	%
DTI / M2 / M3		49	%		39	%		20	%		13	%		27	%		23	%

	Realized Price
	Actual						Estimated(1)
	1Q15			2Q15			3Q15			4Q15			Full Year 2015			Full Year 2016
NYMEX Henry Hub price ($/MMBtu)	$	2.87		$	2.72		$	2.81		$	2.96		$	2.84		$	3.10
Average basis impact ($/MMBtu)		(0.47	)		(0.61	)		(0.39	)		(0.23	)		(0.42	)		(0.37	)
Firm transportation fuel & variables ($/MMBtu)		(0.09	)		(0.13	)		(0.16	)		(0.19	)		(0.16	)		(0.16	)
Btu uplift (MMBtu/Mcf)		0.11			0.10			0.15			0.17			0.14			0.17
Pre-hedge realized price ($/Mcf)		2.42			2.08			2.41			2.71			2.40			2.74
Realized hedging gain (loss) ($/Mcf)		0.70			0.89			0.94			0.88			0.86			0.40
Post-hedge realized price ($/Mcf)		3.12			2.97			3.35			3.59			3.26			3.14
Net firm transportation sales ($/Mcf)		0.08			0.01			—			—			0.02			—
Adjusted realized price ($/Mcf)	$	3.20		$	2.98		$	3.35		$	3.59		$	3.28		$	3.14

(1) NYMEX price as of 8/4/15.

Commodity Hedging Update

During the second quarter, we had 70% of our production hedged at an average price of $3.62 per MMBtu. For the remainder of the year, we have 465 BBtu/d of our production hedged at a weighted average floor price of $3.72 per MMBtu, representing 88% of our 2015 expected production, based on the midpoint of our updated production guidance. In addition, we have added to our 2016 derivatives portfolio and currently have 389 BBtu/d hedged at a weighted average floor price of $3.65 per MMBtu for calendar 2016. Please see the “Derivatives Information” table at the end of this press release for more detailed information about our derivatives positions.

Financial Position and Liquidity

As of June 30, 2015, we had approximately $1 billion in liquidity, consisting of $545 million available under our upstream credit facility⁽¹⁾, $203 million available under our retained midstream credit facility and $257 million of cash on hand. In addition, we hold approximately 29 million RMP common units with a current market value of approximately $475 million.

(1) $650 million undrawn credit facility, net of $105 million in letters of credit outstanding.

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Midstream Segment

For the second quarter, average daily throughput was 887 MDth/d, a 33% increase relative to first quarter 2015, with 21% attributable to third-party volumes. Gathering, compression and water distribution revenues totaled $34.8 million for the quarter. Operating and maintenance expenses totaled $2.8 million, 16% lower than first quarter 2015, and operating income was $20.7 million.

For the six month period ended June 30, 2015, average daily throughput was 778 MDth/d, with 19% attributable to third-party volumes. Gathering, compression and water distribution revenues totaled $64.3 million. Operating and maintenance expenses totaled $6.1 million and operating income was $36.6 million.

Rice Midstream Partners LP (NYSE: RMP) (“the Partnership”)

Pennsylvania Gathering System

Average daily throughput for the second quarter was 655 MDth/d, an 18% increase relative to first quarter 2015, with 15% attributable to third-party volumes. Operating revenues during the quarter were $19.7 million and operating and maintenance expenses totaled $0.9 million. The Partnership reported net income of $12.3 million, or $0.21 per limited partner unit.

For the six months ended June 30, 2015, average daily throughput was 607 MDth/d, with 13% attributable to third-party volumes. Operating revenues were $35.9 million and operating and maintenance expenses were $2.3 million. The Partnership reported net income of $21.4 million, or $0.37 per limited partner unit. Maintenance capital expenditures totaled $2.2 million and interest expense was $0.9 million.

As of June 30, 2015, RMP had $30 million drawn under its revolving credit facility, providing $420 million of total liquidity.

On July 24, 2015, RMP declared its quarterly distribution of $0.1905 per common unit for the second quarter 2015, an increase of $0.003 per unit above the first quarter 2015. The distribution will be payable on August 13, 2015 to unitholders of record as of August 4, 2015.

RMP Distribution Guidance

In addition, based on RMP’s continued solid operational results and strong distributable cash flow coverage, RMP expects to increase its distributions by $0.003 per unit in each of the third and fourth quarters of 2015 and is raising its full-year 2015 forecasted distribution to $0.7680 per unit. RMP’s targeted fourth quarter 2015 distribution of $0.1965 per unit represents a 5% increase above its minimum quarterly distribution of $0.1875 per unit.

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Rice Midstream Holdings

Ohio Gathering System

Average daily throughput for the second quarter of 2015 was 232 MDth/d, a 109% increase from first quarter 2015, with 38% attributable to third-party volumes. For the six months ended June 30, 2015, average daily throughput was 172 MDth/d, with 39% attributable to third-party volumes.

Similar to our E&P development, the buildout of our Ohio gathering system has remained ahead of schedule. During the second quarter, we completed construction of our main trunkline, which was six months ahead of schedule. This trunkline has 2.6 MMDth/d of design capacity and connects Rice Energy and other customers to TETCO and Rockies Express (REX) Pipeline. In addition, we commissioned our first interconnect to REX during the second quarter, which was two months ahead of schedule, allowing Rice Energy and other customers to access better priced markets outside of Appalachia earlier than expected.

Fresh Water Distribution Systems

Continued buildout of our fresh water distribution systems remains on schedule. By year end 2015, these systems are expected to provide direct access to 9.2 MMGPD of fresh water from the Monongahela River and other regional water sources in Pennsylvania and 14.7 MMGPD of fresh water from the Ohio River and several other regional sources in Ohio. These systems provide tangible economic and operational benefits to us and our customers, while at the same time reducing local truck traffic in the communities where we and our customers operate.

Subsequent to quarter end, RMP received a favorable private letter ruling from the U.S. Internal Revenue Service providing that income earned by RMP from the delivery of water and the collection, treatment and transport of flowback, produced water and other fluids will constitute qualifying income.

Conference Call

Rice Energy will host a conference call on August 6, 2015 at 9:00 a.m. Eastern time (8:00 a.m. Central time) to discuss second quarter 2015 financial and operating results. To listen to a live audio webcast of the conference call, please visit Rice Energy’s website atwww.riceenergy.com. A replay of the conference call will be available for two weeks and can also be accessed from our homepage.

Please visitwww.riceenergy.com to view a presentation containing supplemental second quarter 2015 information.

About Rice Energy

Rice Energy Inc. is an independent natural gas and oil company engaged in the acquisition, exploration and development of natural gas and oil properties in the Appalachian Basin. For more information, please visit our website atwww.riceenergy.com.

Forward Looking Statements

This release includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. All

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statements, other than historical facts included in this release, that address activities, events or developments that we expect or anticipate will or may occur in the future, including such things as future capital expenditures (including the amount and nature thereof), projected operational results, production growth, basis exposure, hedging, the timing and number of well completions, forecasted gathering volumes, revenues, adjusted EBITDA, distribution growth, distributable cash flow, the timing of completion and nature of midstream projects, business strategy and measures to implement strategy, competitive strengths, goals, expansion and growth of our business and operations, plans, market conditions, references to future success, references to intentions as to future matters and other such matters are forward-looking statements. All forward-looking statements speak only as of the date of this release. Although we believe that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements.

We caution you that these forward-looking statements are subject to 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 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; and the timing of development expenditures. Information concerning these and other factors can be found in our filings with the Securities and Exchange Commission, including our Forms 10-K, 10-Q and 8-K. Consequently, all of the forward-looking statements made in this news release are qualified by these cautionary statements and there can be no assurances that the actual results or developments anticipated by us will be realized, or even if realized, that they will have the expected consequences to or effects on us, our business or operations. We have no intention, and disclaim any obligation, to update or revise any forward-looking statements, whether as a result of new information, future results or otherwise.

Contact:

Julie Danvers, Director of Investor Relations

(832) 708-3437

Julie.Danvers@RiceEnergy.com

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Rice Energy Inc.

Condensed Consolidated Statements of Operations

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
(in thousands, except per share data)	2015			2014			2015			2014
Natural gas production (MMcf)		47,559			21,966			86,647			38,356
Oil and NGL production (MBbls)		90			1			179			1
Total production (MMcfe)		48,099			21,969			87,720			38,359
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			—
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

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Adjusted net income(1)	$	4,351		$	(943	)	$	(21,608	)	$	58,666
Adjusted EBITDAX(1)	$	97,387		$	50,391		$	181,663		$	105,916
Weighted average shares-basic		136,315,882			128,419,606			136,303,914			121,925,915
Weighted average shares-diluted		136,315,882			128,419,606			136,303,914			122,255,908
Earnings per share—basic	$	(0.51	)	$	(0.06	)	$	(0.51	)	$	1.00
Earnings per share—diluted	$	(0.51	)	$	(0.06	)	$	(0.51	)	$	0.99
Adjusted earnings per share - basic	$	0.03		$	(0.01	)	$	(0.16	)	$	0.48
Adjusted earnings per share - diluted	$	0.03		$	(0.01	)	$	(0.16	)	$	0.48

(1) Please see “Supplemental Non-GAAP Financial Measures” for a description of Adjusted EBITDAX and Adjusted net income.

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Rice Energy Inc.

Segment Results of Operations

(Unaudited)

Exploration and Production Segment

	Three Months Ended June 30,					Six Months Ended June 30,
(in thousands, except volumes)	2015			2014		2015			2014
Operating volumes:
Natural gas production (MMcf)		47,559			21,966		86,647			38,356
Oil and NGL production (MBbls)		90			1		179			1
Total production (MMcfe)		48,099			21,969		87,720			38,359
Operating revenues:
Natural gas, oil and NGL sales	$	100,890		$	88,524	$	197,802		$	178,990
Firm transportation sales, net		438			2,113		3,264			2,113
Total operating revenues		101,328			90,637		201,066			181,103
Operating expenses:
Lease operating		11,090			6,667		22,681			11,853
Gathering, compression and transportation		32,691			8,104		60,367			14,616
Production taxes and impact fees		1,694			871		3,148			1,510
Exploration		356			473		1,095			959
Incentive unit expense		21,885			2,462		44,383			70,564
Stock compensation expense		3,011			994		5,231			1,085
General and administrative		16,115			9,430		29,414			18,998
Depreciation, depletion and amortization		73,342			31,397		132,256			56,461
Other expense		1,159			—		3,050			—
Total operating expenses		161,343			60,398		301,625			176,046
Operating (loss) income	$	(60,015	)	$	30,239	$	(100,559	)	$	5,057
Average costs per Mcfe:
Lease operating	$	0.23		$	0.30	$	0.26		$	0.31
Gathering and compression		0.37			—		0.36			—
Transportation		0.31			0.37		0.32			0.38
Production taxes and impact fees		0.04			0.04		0.04			0.04
Exploration		0.01			0.02		0.01			0.03
Incentive unit expense		0.45			0.11		0.51			1.84
Stock compensation expense		0.06			0.05		0.06			0.03
General and administrative		0.34			0.43		0.34			0.50
Depreciation, depletion and amortization		1.52			1.43		1.51			1.47

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Midstream Segment

	Three Months Ended June 30,					Six Months Ended June 30,
(in thousands, except volumes)	2015		2014			2015		2014
Operating volumes:
Gathering volumes (MDth/d)		887		369			778		310
Compression volumes (MDth/d)		58		25			61		13
Water distribution volumes (MMGal)		163		—			348		—
Operating revenues:
Gathering revenues	$	25,164	$	1,237		$	43,910	$	1,303
Compression revenues		818		156			1,174		156
Water distribution revenues		8,830		—			19,175		—
Total operating revenues		34,812		1,393			64,259		1,459
Operating expenses:
Midstream operation and maintenance		2,801		1,162			6,132		1,835
Incentive unit expense		1,214		(988	)		2,174		4,712
Stock compensation expense		1,201		131			2,236		131
General and administrative		4,310		5,415			8,500		7,277
Depreciation, depletion and amortization		3,330		1,155			6,997		1,598
Amortization of intangible assets		408		340			816		340
Other expense		839		—			839		—
Total operating expenses		14,103		7,215			27,694		15,893
Operating income (loss)	$	20,709	$	(5,822	)	$	36,565	$	(14,434	)

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Rice Energy Inc.

Supplemental Non-GAAP Financial Measure

(Unaudited)

Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. We define Adjusted EBITDAX as net income (loss) before non-controlling interest; interest expense; income taxes; depreciation, depletion and amortization; amortization of deferred financing costs; amortization of intangible assets; derivative fair value (gain) loss, excluding net cash receipts on settled derivative instruments; non-cash stock compensation expense; non-cash incentive unit expense; exploration expenses; and other non-recurring items. Adjusted EBITDAX is not a measure of net income as determined by United States generally accepted accounting principles, or GAAP.

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

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The following table presents a reconciliation of the non-GAAP financial measure of Adjusted EBITDAX to the GAAP financial measure of net income (loss).

(in thousands)	Three Months Ended June 30, 2015			Six Months Ended June 30, 2015
Adjusted EBITDAX reconciliation to net income (loss):
Net loss	$	(63,519	)	$	(58,831	)
Interest expense		23,359			39,488
Depreciation, depletion and amortization		76,140			138,721
Amortization of deferred financing costs		1,306			2,409
Amortization of intangible assets		408			816
Loss (gain) on derivative instruments(1)		3,710			(57,657	)
Net cash receipts on settled derivative instruments(1)		42,474			69,870
Non-cash stock compensation expense		4,212			7,467
Non-cash incentive unit expense		23,099			46,557
Income tax expense		(9,992	)		(1,462	)
Exploration expense		356			1,095
Other expense		1,998			3,889
Noncontrolling interest		(6,164	)		(10,699	)
Adjusted EBITDAX	$	97,387		$	181,663

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

14

Rice Energy Inc.

Supplemental Non-GAAP Financial Measure

(Unaudited)

Adjusted net income (loss) is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. We define adjusted net income (loss) as net income (loss) before derivative fair value (gain) loss, excluding net cash receipts on settled derivative instruments incentive unit expense and other non-recurring items. Adjusted net income (loss) is not a measure of net income as determined by United States generally accepted accounting principles, or GAAP.

We believe that many investors use adjusted net income in making investment decisions and in evaluating our operational trends and our performance relative to other oil and gas producing companies.

The following table presents a reconciliation of the non-GAAP financial measure of adjusted net income (loss) to the GAAP financial measure of net income (loss).

(in thousands)	Three Months Ended June 30, 2015			Six Months Ended June 30, 2015
Reconciliation to net income (loss) attributable to Rice Energy Inc:
Net loss attributable to Rice Energy Inc.	$	(69,683	)	$	(69,530	)
Loss (gain) on derivative instruments, net of tax(1)		4,639			(72,095	)
Net cash receipts on settled derivative instruments, net of tax(1)		53,110			87,366
Incentive unit expense, net of tax		13,787			27,788
Other expense, net of tax		2,498			4,863
Adjusted net income (loss) attributable to Rice Energy Inc.	$	4,351		$	(21,608	)

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

15

Rice Energy Inc.

Derivatives Information

(Unaudited)

The table below provides data associated with our derivatives at August 6, 2015 for the periods indicated:

All-In Fixed Price Derivatives	Remainder of 2015			2016			2017			2018
NYMEX Natural Gas Swaps:
Volume Hedged (BBtu/d)		194			308			115			5
Weighted Average Swap Price ($/MMBtu)	$	4.07		$	3.87		$	3.81		$	3.60
NYMEX Natural Gas Collars:
Volume Hedged (BBtu/d)		158			50			220			220
Weighted Average Floor Price ($/MMBtu)	$	3.96		$	2.91		$	3.13		$	3.20
Weighted Average Collar Price ($/MMBtu)	$	4.65		$	3.60		$	3.61		$	3.69
NYMEX Volume Hedged (BBtu/d)		353			358			335			225
Swap + Collar Floor ($/MMBtu)	$	4.02		$	3.74		$	3.36		$	3.21
Dominion Natural Gas Swaps
Volume Hedged (BBtu/d)		71			31			—			—
Weighted Average Swap Price ($/MMBtu)	$	2.49		$	2.62		$	—		$	—
TCO Natural Gas Swaps
Volume Hedged (BBtu/d)		41			—			—			—
Weighted Average Swap Price ($/MMBtu)	$	3.30		$	—		$	—		$	—
Total Fixed Price Derivatives
Volume Hedged (BBtu/d)		465			389			335			225
Weighted Average Swap Price ($/MMBtu)	$	3.72		$	3.65		$	3.36		$	3.21
Basis Contract Derivatives
TCO Basis Swaps
Volume Hedged (BBtu/d)		53			34			17			—
Weighted Average Swap Price ($/MMBtu)	$	(0.32	)	$	(0.33	)	$	(0.34	)	$	—
Dominion Basis Swaps
Volume Hedged (BBtu/d)		16			45			50			75
Weighted Average Swap Price ($/MMBtu)	$	(1.12	)	$	(1.10	)	$	(0.98	)	$	(0.70	)
M2 Basis Swaps
Volume Hedged (BBtu/d)		20			40			60			—
Weighted Average Swap Price ($/MMBtu)	$	(0.94	)	$	(1.08	)	$	(1.01	)	$	—

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MichCon Basis Swaps
Volume Hedged (BBtu/d)		1			24			4			4
Weighted Average Swap Price ($/MMBtu)	$	(0.04	)	$	(0.01	)	$	(0.04	)	$	(0.04	)
ELA Basis Swaps
Volume Hedged (BBtu/d)		30			60			30			30
Weighted Average Swap Price ($/MMBtu)	$	(0.13	)	$	(0.10	)	$	(0.08	)	$	(0.09	)
Chicago Basis Swaps
Volume Hedged (BBtu/d)		—			40			10			10
Weighted Average Swap Price ($/MMBtu)	$	—		$	(0.05	)	$	(0.16	)	$	(0.19	)
ANR SE Basis Swaps
Volume Hedged (BBtu/d)		—			15			—			—
Weighted Average Swap Price ($/MMBtu)	$	—		$	(0.13	)	$	—		$	—
Physical Triggered Basis
Appalachian Fixed Basis (Physical)
Volume Hedged (BBtu/d)		25			21			—			—
Weighted Average Swap Price ($/MMBtu)	$	(0.72	)	$	(0.79	)	$	—		$	—
MichCon Fixed Basis (Physical)
Volume Hedged (BBtu/d)		3			10			10			8
Weighted Average Swap Price ($/MMBtu)	$	0.05		$	0.05		$	0.05		$	0.05
Gulf Coast Fixed Basis (Physical)
Volume Hedged (BBtu/d)		87			100			100			100
Weighted Average Swap Price ($/MMBtu)	$	(0.17	)	$	(0.17	)	$	(0.17	)	$	(0.17	)
Total Basis Swaps (Financial + Physical)
Volume Hedged (BBtu/d)		235			389			281			227
Weighted Average Swap Price ($/MMBtu)	$	(0.38	)	$	(0.38	)	$	(0.48	)	$	(0.33	)

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The table below provides supplemental balance sheet data as of June 30, 2015.

Supplemental Balance Sheet data (in thousands)		June 30, 2015
Cash and cash equivalents		$	256,676
Long-term debt
6.25% Senior Notes Due April 2022		$	900,000
7.25% Senior Notes Due May 2023			397,033
Senior Secured Revolving Credit Facility	��		—
Midstream Holdings Revolving Credit Facility			97,000
RMP Revolving Credit Facility			30,000
Total long-term debt		$	1,424,033
Net debt		$	1,167,357

The table below outlines our firm transportation capacity by pipeline.

Project	Pipeline	Start Date	Volume (Dth/d)		Term		Market
TEAM South	TETCO	Sept-14		270,000		38 Yrs	Gulf Coast
Westside Expansion	TCO	Nov-14		125,000		10 Yrs	TCO/Gulf Coast
Rockies Express Reversal	REX	Aug-15		175,000		20 Yrs	Midwest/Gulf Coast
Union Town to Gas City	TETCO	Sept-15		86,500		10 Yrs	Midwest/Gulf Coast
OPEN	TETCO	Sept-15		50,000		20 Yrs	Gulf Coast
ET Rover	Rover	July-17		100,000		15 Yrs	Canada
Access South	TETCO	Nov-17		320,000		25 Yrs	Gulf Coast

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