Exhibit 99.1

 

FOR IMMEDIATE RELEASE

Rice Energy Reports Third Quarter 2015 Results, Adjusted EBITDAX of $119 Million, Increases Borrowing Base to $750 Million and Closes Water Services Business Drop Down

CANONSBURG, Pa. – November 5, 2015 /PRNewswire/ – Rice Energy Inc. (NYSE: RICE) (“Rice Energy”) today reported third quarter 2015 financial and operational results. Highlights during the quarter include:

 

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Net production averaged 609 MMcfe/d for the third quarter, a 147% increase relative to third quarter 2014, including 30 MMcfe/d of positive working interest adjustments

 

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Adjusted EBITDAX(1) of $118.5 million for the third quarter, a 123% increase over the prior year quarter

 

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Adjusted realized natural gas price(2) of $3.18 per Mcf in the third quarter

 

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Average basis differential of ($0.38) supported by a strong FT portfolio, including three new projects on REX and TETCO providing access to favorable markets outside of Appalachia

 

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Turned to sales first Pennsylvania Utica well in Greene County that is currently flowing at a stabilized rate of 12 MMcf/d with approximately 8,000 psi flowing casing pressure

 

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Average gathering throughput of 990 MDth/d, a 12% increase relative to second quarter 2015

 

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Increased the borrowing base under our upstream credit facility by $100 million to $750 million in October

 

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Executed a letter of intent with Gulfport Energy to form a Utica Shale midstream joint venture in Ohio to develop natural gas gathering, compression and water services assets

 

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Subsequent to quarter end, closed successful drop down of water services business to Rice Midstream Partners for $200 million at closing plus a $25 million earn out upon achievement of certain increases in connected water sources

 

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Strong third quarter liquidity position of $1.2 billion, excluding RMP, pro forma for borrowing base redetermination increase and water services business drop down, assuming no earn out

Commenting on the results, Daniel J. Rice IV, Chief Executive Officer, said, “Our third quarter results demonstrate our ability to continue executing our development plan despite challenging commodity markets. The economic investment decisions we are making today will continue to deliver significant growth in the future. We are proud of our team’s strong initiative and collaboration this year, evidenced by our strong results, which positions us for continued success in 2016.”

 

(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.

 

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Third Quarter 2015 Consolidated Results		Three Months Ended September 30, 2015				Nine Months Ended September 30, 2015
Total production (MMcfe)			56,031				143,752
Total production (MMcfe/d)			609				527
% Gas			100	%			99	%
% Operated			92	%			93	%
% Marcellus			68	%			76	%
Average realized prices per Mcf:
Natural gas price before effects of hedges		$	2.32			$	2.27
Natural gas price after effects of hedges(1)		$	3.18			$	3.10
Adjusted realized price		$	3.18			$	3.12
Average oil and NGL price per Bbl		$	12.17			$	21.51
Average costs per Mcfe:
Lease operating		$	0.22			$	0.24
Gathering, compression and transportation		$	0.43			$	0.39
Production taxes and impact fees		$	0.03			$	0.04
General and administrative		$	0.43			$	0.43
Depletion, depreciation and amortization		$	1.59			$	1.59
Adjusted EBITDAX (in thousands)		$	118,522			$	300,186
Total midstream throughput (MDth/d)			990				850
% Third-party			23	%			21	%

 

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

Third Quarter 2015 Financial Results

During the third quarter, our net daily production averaged 609 MMcfe/d, a 15% increase relative to second quarter 2015 volumes and a 147% increase over third quarter 2014 production. The increase in net production for the quarter was the result of 30 MMcfe/d of working interest adjustments related to certain Ohio Utica operated wells, 8 net Marcellus wells that came online approximately 4 months ahead of schedule, as well as accelerated non-operated activity. Third quarter average realized natural gas price, before the effect of hedges, was $2.32 per Mcf. After giving effect to hedges, our average natural gas price was $3.18 per Mcf. The average adjusted realized price, including net firm transportation sales and the impact of hedges, was $3.18 per Mcf during the quarter. Our average realized oil and NGL price was $12.17 per Bbl. Per unit cash production costs (lease operating; gathering, compression and transportation; and production taxes and impact fees) were $0.68 per Mcfe. Adjusted EBITDAX for the quarter was $118.5 million. We reported adjusted net income⁽¹⁾ of $3.5 million, or $0.03 per share, after excluding unrealized gains on derivative contracts and other non-recurring income and expense items.

 

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

 

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Year to Date Financial Results

Net daily production for the nine months ended September 30, 2015, averaged 527 MMcfe/d, a 126% increase as compared to the prior year period. Our average realized natural gas price, before the effect of hedges, was $2.27 per Mcf. After giving effect to hedges, our average natural gas price for the nine-month period was $3.10 per Mcf. The average adjusted realized price was $3.12 per Mcf and our average realized oil and NGL price was $21.51 per Bbl. Per unit cash production costs were $0.67 per Mcfe. Adjusted EBITDAX during the nine months was $300.2 million. We reported an adjusted net loss of $27.1 million, or ($0.20) per share.

2015 Net Production and Capital Budget Guidance Update

As we have continued to sustain efficiency gains throughout our operations in 2015, our productivity has continued to increase and our wells have consistently come online ahead of schedule. In addition, our non-operated Utica activity has increased, as one of our working interest partners has accelerated fourth quarter 2015 completion activity. As a result, we are increasing our 2015 annual production guidance range to 515 - 525 MMcfe/d to reflect this execution as well as positive working interest adjustments. In connection with our increased production guidance, we are updating our 2015 E&P capital budget to $730 million.

For our retained midstream investments, we are increasing our 2015 capital budget to reflect the water services business drop down, our anticipated Gulfport midstream joint venture and updated Ohio gathering project activity and cost.

 

2015 Capital Budget (in millions)
		Prior Guidance				Updated Guidance
E&P
Marcellus		$	340			$	330
Utica - Operated		$	155			$	200
Utica - Non-Operated		$	65			$	80
Total Drilling & Completion		$	560			$	610
Leasehold Acquisitions		$	120			$	120
Total E&P Capital Expenditures		$	680			$	730
Retained Midstream
Ohio Midstream and Water Systems		$	210			$	300
Total Capital Expenditures		$	890			$	1,030

For a summary of our 2015 revised guidance, including updates to well count, lease operating expense and general and administrative expense, please see slide 8 in the Third Quarter Supplemental presentation available on our website www.riceenergy.com.

 

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Upstream Segment

Marcellus Shale

Marcellus net production averaged 410 MMcfe/d for the quarter, a 2% increase from the prior quarter and a 77% increase relative to third quarter 2014.

We turned to sales 14 gross (13 net) horizontal Marcellus wells with an average lateral length of 6,940 feet at an average development cost of $1,029 per lateral foot. These wells are currently producing approximately 120 MMcf/d on managed chokes. As of September 30, 2015, our Marcellus leasehold position in Washington and Greene Counties, Pennsylvania, consisted of approximately 91,000 net acres.

In late October, we turned online two net wells in Washington County, one Marcellus and one Upper Devonian well with average laterals of approximately 3,700 feet each. These wells were designed as pilot test wells to better understand the interaction between the Marcellus and Upper Devonian reservoirs, as well as the interaction between existing producing wells on that pad we drilled three years ago.

As of October 31, 2015, we have placed online 38 gross (33 net Marcellus and 1 net Geneseo) producing wells during the year.

The following table provides operational data through September 30, 2015, for our 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			$	2,342
2012			9				5,731				9.2				10.0				6.8				4.1			$	1,583
2013			22				6,320				11.2				10.6				7.6				5.0			$	1,437
2014(1)			41				7,272				10.6				9.2				7.2				N/A			$	1,236
Q1 2015			8				6,225				7.6				7.3				N/A				N/A			$	1,312
Q2 2015			14				8,185				10.9				N/A				N/A				N/A			$	1,219
Q3 2015			14				6,940				N/A				N/A				N/A				N/A			$	1,029
Total(2)			114				6,754				10.1				9.1				7.0				4.1			$	1,338

 

(1)	Excludes 7 acquired producing wells.

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

Utica Shale

Utica net production averaged 199 MMcfe/d for the quarter, a 58% increase from the prior quarter and a 1,227% increase over third quarter 2014. Through September 30, 2015, we have turned to sales 14 gross (10 net) operated Utica wells, which encompasses our entire planned online activity for the year. As of September 30, 2015, our Ohio Utica leasehold position consisted of approximately 56,000 net acres, primarily in Belmont County.

 

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In late August 2015, we turned to sales our first operated Pennsylvania Utica well, John Briggs 50U, approximately three months ahead of schedule. Located in western Greene County, the 5,800 foot lateral was completed with a 41-stage frac. After a 60 day test period, the well is currently producing under our designed restricted choke rate of 12 MMcf/d with 8,000 psi of flowing casing pressure and favorable pressure declines. We are highly encouraged by the long-term production potential of the Pennsylvania Utica demonstrated by our initial results.

The following table provides operational data through September 30, 2015, for our 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				16.3				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				13.5				N/A				N/A			$	1,901
Q2 2015			11				9,963				15.4				N/A				N/A				N/A			$	1,608
Q3 2015			—				N/A				N/A				N/A				N/A				N/A				N/A
Total (1)			16				9,474				15.3				14.6				16.2				N/A			$	1,804

 

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

Firm Transportation and Realized Gas Pricing

In August 2015, we commissioned our interconnect to the Rockies Express (REX) pipeline two months ahead of schedule. We hold 175,000 Dth/d of firm capacity on REX, which provides access to more favorably priced markets in the Midwest and Gulf Coast. In addition, TETCO’s Union Town to Gas City and OPEN projects were placed into service in September, allowing us to deliver an additional 136,500 Dth/d to premium gas markets outside of Appalachia.

Approximately 76% of our third quarter production received favorable Gulf Coast, TCO and Midwest pricing, as compared to 61% of second quarter production, due to increasing premium market exposure through our firm transportation portfolio. Our average basis differential for the quarter was ($0.38) per MMBtu, while TETCO M2 and Dominion South averaged ($1.53) and ($1.52) per MMBtu, respectively, below NYMEX Henry Hub for the quarter. During the fourth quarter, we expect that approximately 87% 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 September 30, 2015 and estimated results for the remainder of 2015 through 2017.

 

		Basis Exposure
		Actual												Estimated
		1Q15				2Q15				3Q15				4Q15				FY 2015				FY 2016				FY 2017
Basis
Gulf Coast			27	%			35	%			36	%			51	%			38	%			51	%			46	%
TCO			23	%			17	%			18	%			16	%			18	%			11	%			6	%
Midwest/Dawn			1	%			9	%			22	%			20	%			14	%			15	%			8	%
DTI / M2 / M3			49	%			39	%			24	%			13	%			30	%			23	%			40	%

 

		Realized Price
		Actual												Estimated(1)
		1Q15				2Q15				3Q15				4Q15				FY 2015				FY 2016				FY 2017
NYMEX Henry Hub price ($/MMBtu)		$	2.87			$	2.72			$	2.73			$	2.36			$	2.67			$	2.67			$	2.94
Average basis impact ($/MMBtu)			(0.47	)			(0.61	)			(0.38	)			(0.28	)			(0.43	)			(0.32	)			(0.41	)
Firm transportation fuel & variables ($/MMBtu)			(0.09	)			(0.13	)			(0.14	)			(0.17	)			(0.13	)			(0.15	)			(0.12	)
Btu uplift (MMBtu/Mcf)			0.11				0.10				0.11				0.12				0.11				0.15				0.16
Pre-hedge realized price ($/Mcf)			2.42				2.08				2.32				2.03				2.22				2.35				2.57
Realized hedging gain (loss) ($/Mcf)			0.70				0.89				0.86				1.33				0.95				0.63				0.13
Post-hedge realized price ($/Mcf)			3.12				2.97				3.18				3.36				3.17				2.98				2.70
Net firm transportation sales ($/Mcf)			0.08				0.01				—				—				0.02				—				—
Adjusted realized price ($/Mcf)		$	3.20			$	2.98			$	3.18			$	3.36			$	3.19			$	2.98			$	2.70

 

(1)	NYMEX price as of 10/23/15.

Commodity Hedge Position

We had 66% of our third quarter production hedged at an average Henry Hub floor price of $4.02 per MMBtu. For the fourth quarter, we have 503 BBtu/d of our expected production hedged at a weighted average fixed floor price of $3.78 per MMBtu. In addition, we currently have hedged an average of 489 and 375 BBtu/d in 2016 and 2017, respectively, at a weighted average floor price of $3.51 and $3.34 per MMBtu. Please see the “Derivatives Information” table at the end of this press release for more detailed information about our derivatives positions.

Midstream Segment

For the third quarter, average daily throughput was 990 MDth/d, a 12% increase relative to second quarter 2015, with 23% attributable to third-party volumes. Gathering, compression and water distribution revenues totaled $38.8 million for the quarter. Operation and maintenance expenses totaled $4.8 million, and operating income was $21.5 million.

For the nine months ended September 30, 2015, average daily throughput was 850 MDth/d, with 21% attributable to third-party volumes. Gathering, compression and water distribution revenues totaled $103 million. Operation and maintenance expenses totaled $11 million, and operating income was $58.1 million.

 

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

Pennsylvania Gathering System

Average daily throughput for the third quarter was 671 MDth/d, a 3% increase relative to second quarter 2015, with 17% attributable to third-party volumes. Operating revenues during the quarter were $20.1 million, and operation and maintenance expenses totaled $1.7 million. The Partnership reported net income of $12.3 million, or $0.21 per limited partner unit.

For the nine months ended September 30, 2015, average daily throughput was 629 MDth/d, with 15% attributable to third-party volumes. Operating revenues were $56 million, and operation and maintenance expenses totaled $4 million. The Partnership reported net income of $33.7 million, or $0.59 per limited partner unit.

As of September 30, 2015, RMP had $100 drawn under its revolving credit facility and $19 million of cash on hand, resulting in $369 million of total liquidity, pro forma for the water services business acquisition and consummation of the RMP private placement.

On October 23, 2015, RMP declared its quarterly distribution of $0.1935 per unit for the third quarter 2015, an increase of $0.003 per unit relative to the second quarter 2015. The distribution will be payable on November 12, 2015 to unitholders of record as of November 3, 2015.

As previously announced, based on continued solid operational results and strong distributable cash flow coverage, RMP expects to increase distributions by $0.003 per unit in the fourth quarter 2015 to $0.1965 per unit, which represents a 5% increase above the minimum quarterly distribution of $0.1875 per unit.

Water Services Business Acquisition

On November 5, 2015, RMP announced that it acquired the water services business of Rice’s wholly-owned subsidiary, Rice Midstream Holdings LLC (“Midstream Holdings”), for $200 million at closing. The terms of the agreement include a one-time $25 million earn out payment by RMP, less any associated capital expenditures, if any, if Rice obtains an additional 5 MMgal/d of connected water sources in Ohio by December 31, 2017. This acquisition includes Midstream Holdings’ Pennsylvania and Ohio fresh water distribution systems and related facilities, as well as a right to provide fresh water for well completion operations and to collect, recycle or dispose of flowback and produced water for Rice in Washington and Greene Counties, Pennsylvania, and Belmont County, Ohio (the “Services Area”). In addition, RMP has been given the exclusive right to acquire and/or develop water treatment facilities in the Services Area.

RMP funded the $200 million purchase price through borrowings under its revolving credit facility. Upon completion of the Partnership’s private placement described below, the $175 million of gross proceeds will be used to repay borrowings outstanding under RMP’s revolving credit facility, resulting in $350 million of credit facility availability.

 

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RMP Private Placement

On November 4, 2015, the Partnership priced a private placement of 13,409,961 common units for gross proceeds of $175 million. The closing of the private placement is expected to occur on November 10, 2015, subject to certain customary closing conditions.

The securities offered in the private placement have not been registered under the Securities Act of 1933, as amended (the “Securities Act”), or any state securities laws, and may not be offered or sold in the United States absent registration or an applicable exemption from the registration requirements of the Securities Act and applicable state securities laws. This press release shall not constitute an offer to sell or a solicitation of an offer to buy the securities described above.

Rice Midstream Holdings LLC

Water Services Business Drop Down

On November 5, 2015, as consideration for the sale of the water services business to RMP, Midstream Holdings received $200 million of proceeds, which was used to repay borrowings outstanding under its revolving credit facility, resulting in an undrawn credit facility with $300 million of availability. Subsequently, Midstream Holdings distributed $43 million to Rice to be used for general corporate purposes.

Ohio Utica Midstream Joint Venture

Subsequent to quarter end, Midstream Holdings executed a Letter of Intent with Gulfport Energy Corporation (“Gulfport”) to form a midstream joint venture (“JV”) to develop natural gas gathering, compression and water services assets to support Gulfport’s dry gas Utica Shale development in eastern Belmont County and Monroe County, Ohio. The joint venture will include a 77,000 acreage dedication from Gulfport. RMH will own 75% of the JV and will be responsible for constructing and operating the JV’s assets. RMH and Gulfport plan to invest approximately $520 million to develop gathering and compression assets and $120 million for water assets within the JV over the next six years, with each partner funding their respective share. The JV will significantly increase our leading midstream position in the core of the Utica Shale. By leveraging our existing footprint, we are able to grow third-party business and expand our relationship with Gulfport across Gulfport’s premier position in the dry gas Utica Shale. RMH and Gulfport plan to pursue third-party gas gathering and water services opportunities within a 340,000-acre area of mutual interest that will cover portions of eastern Belmont County and Monroe County, Ohio.

Ohio Gathering System

Average daily throughput for the third quarter of 2015 was 319 MDth/d, a 37% increase relative to second quarter 2015, with 36% attributable to third-party volumes. For the nine months ended September 30, 2015, average daily throughput was 221 MDth/d, with 38% attributable to third-party volumes.

The buildout of our Ohio gathering system has remained ahead of schedule, as we completed construction of our main trunkline last quarter. This extensive system is designed to gather 2.6 MMDth/d of gas and connects Rice and other customers to TETCO and REX, providing access to better priced markets outside of Appalachia.

 

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Financial Position and Liquidity

Effective October 30, 2015, the borrowing base under our upstream credit facility was increased by $100 million to $750 million, representing a 15% increase. On November 4, 2015, Rice Midstream Holdings received $200 million from RMP as consideration for the water services business acquisition.

As of September 30, 2015, our liquidity position pro forma for our borrowing base redetermination, water services business drop down and excluding RMP and the potential earn out, was $1.2 billion, consisting of $625 million available under our upstream credit facility⁽¹⁾, $300 million available under our retained midstream credit facility and $240 million of cash on hand.

 

(1)	$750 million undrawn credit facility, net of $125 million in letters of credit outstanding.

Conference Call

Rice Energy will host a conference call on November 5, 2015 at 9:30 a.m. Eastern time (8:30 a.m. Central time) to discuss third quarter 2015 financial and operating results. To listen to a live audio webcast of the conference call, please visit Rice Energy’s website at www.riceenergy.com. A replay of the conference call will be available for two weeks and can also be accessed from our homepage.

Please visit www.riceenergy.com to view a presentation containing supplemental third 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 at www.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 statements, other than historical facts included or incorporate herein 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 private placement by the Partnership, the midstream JV, 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

 

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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; the availability of capital on an economic basis; inflation; lack of availability of drilling and production equipment and services; environmental risks; drilling and other operating risks; legislative and regulatory changes adversely affecting the industry; transportation capacity constraints and interruptions; 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. Furthermore, the acquisition of the water services business by the Partnership, the concurrent private placement by the Partnership and related transactions may not be completed as described or at all. 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 September 30, 2015								Nine Months Ended September 30, 2015
(in thousands, except per share data)		2015				2014				2015				2014
Natural gas production (MMcf)			55,806				22,740				142,454				61,096
Oil and NGL production (MBbls)			37				3				216				3
Total production (MMcfe)			56,031				22,757				143,752				61,116
Operating revenues:
Natural gas, oil and natural gas liquids (“NGL”) sales		$	130,145			$	67,831			$	327,947			$	246,816
Firm transportation sales, net			88				9,733				3,353				11,851
Gathering, compression and water distribution			13,388				1,563				34,755				2,878
Total operating revenues			143,621				79,127				366,055				261,545
Operating expenses:
Lease operating			12,325				4,553				35,006				16,406
Gathering, compression and transportation			24,248				7,992				55,510				22,464
Production taxes and impact fees			1,955				1,114				5,103				2,624
Exploration			830				623				1,925				1,582
Midstream operation and maintenance			4,831				1,729				10,963				3,564
Incentive unit (income) expense			(686	)			26,418				45,870				101,695
Stock compensation expense			4,214				2,058				11,681				3,274
Acquisition expense			—				2,246				—				2,246
General and administrative			24,113				10,458				62,028				36,733
Depreciation, depletion and amortization			89,275				33,853				227,996				91,912
Amortization of intangible assets			408				408				1,224				748
Other (income) expense			(265	)			—				3,624				—
Operating loss			(17,627	)			(12,325	)			(94,875	)			(21,703	)
Interest expense			(23,949	)			(15,754	)			(63,437	)			(38,737	)
Gain on purchase of Marcellus joint venture			—				—				—				203,579
Other income (loss)			698				(216	)			1,894				180
Gain on derivative instruments			127,072				36,935				184,729				5,357
Amortization of deferred financing costs			(1,313	)			(707	)			(3,722	)			(1,728	)
Loss on extinguishment of debt			—				(790	)			—				(3,934	)
Write-off of deferred financing costs			—				—				—				(6,896	)
Equity loss of joint ventures			—				—				—				(2,656	)
Income before income taxes			84,881				7,143				24,589				133,462
Income tax expense			(19,797	)			(14,005	)			(18,335	)			(18,787	)
Net income (loss)			65,084				(6,862	)			6,254				114,675
Less: Net income attributable to noncontrolling interests			(6,134	)			—				(16,833	)			—
Net income (loss) attributable to Rice Energy Inc.		$	58,950			$	(6,862	)		$	(10,579	)		$	114,675

 

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Adjusted net income(1)		$	3,491			$	(11,130	)		$	(27,104	)		$	47,536
Adjusted EBITDAX(1)		$	118,522			$	53,236			$	300,186			$	159,152
Weighted average shares-basic			136,381,909				132,269,081				136,330,198				125,411,524
Weighted average shares-diluted			136,521,828				132,269,081				136,330,198				125,678,095
Earnings (loss) per share—basic		$	0.43			$	(0.05	)		$	(0.08	)		$	0.91
Earnings (loss) per share—diluted		$	0.43			$	(0.05	)		$	(0.08	)		$	0.91
Adjusted earnings (loss) per share—basic		$	0.03			$	(0.08	)		$	(0.20	)		$	0.38
Adjusted earnings (loss) per share—diluted		$	0.03			$	(0.08	)		$	(0.20	)		$	0.38

 

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

 

12

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Rice Energy Inc.

Segment Results of Operations

(Unaudited)

Exploration and Production Segment

 

		Three Months Ended September 30,								Nine Months Ended September 30,
(in thousands, except volumes)		2015				2014				2015				2014
Operating volumes:
Natural gas production (MMcf)			55,806				22,740				142,454				61,096
Oil and NGL production (MBbls)			37				3				216				3
Total production (MMcfe)			56,031				22,757				143,752				61,116
Operating revenues:
Natural gas, oil and NGL sales		$	130,145			$	67,831			$	327,947			$	246,816
Firm transportation sales, net			88				9,733				3,353				11,851
Total operating revenues			130,233				77,564				331,300				258,667
Operating expenses:
Lease operating			12,325				4,553				35,006				16,406
Gathering, compression and transportation			41,654				8,049				102,021				22,666
Production taxes and impact fees			1,955				1,114				5,103				2,624
Exploration			830				623				1,925				1,582
Incentive unit (income) expense			(453	)			19,468				43,930				90,032
Stock compensation expense			2,657				1,786				7,889				2,871
General and administrative			18,592				10,342				48,007				29,340
Depreciation, depletion and amortization			84,408				32,854				216,665				89,316
Other (income) expense			(71	)			—				2,979				—
Acquisition costs			—				762				—				762
Total operating expenses			161,897				79,551				463,525				255,599
Operating (loss) income		$	(31,664	)		$	(1,987	)		$	(132,225	)		$	3,068
Average costs per Mcfe:
Lease operating		$	0.22			$	0.20			$	0.24			$	0.27
Gathering and compression			0.39				—				0.37				—
Transportation			0.36				0.35				0.34				0.37
Production taxes and impact fees			0.03				0.05				0.04				0.04
Exploration			0.01				0.03				0.01				0.03
Incentive unit expense			(0.01	)			0.86				0.31				1.47
Stock compensation expense			0.05				0.08				0.05				0.05
General and administrative			0.33				0.45				0.33				0.48
Depreciation, depletion and amortization			1.51				1.44				1.51				1.46

 

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Midstream Segment

 

		Three Months Ended September 30,								Nine Months Ended September 30,
(in thousands, except volumes)		2015				2014				2015				2014
Operating volumes:
Gathering volumes (MDth/d)			990				392				850				338
Compression volumes (MDth/d)			39				32				54				19
Water distribution volumes (MMGal)			227				—				575				—
Operating revenues:
Gathering revenues		$	28,414			$	1,409			$	72,324			$	2,712
Compression revenues			420				211				1,594				368
Water distribution revenues			9,932				—				29,107				—
Total operating revenues			38,766				1,620				103,025				3,080
Operating expenses:
Midstream operation and maintenance			4,831				1,729				10,963				3,564
Incentive unit (income) expense			(233	)			6,950				1,940				11,663
Stock compensation expense			1,557				272				3,792				403
General and administrative			5,521				116				14,021				7,393
Depreciation, depletion and amortization			5,345				999				12,341				2,596
Amortization of intangible assets			408				408				1,224				748
Acquisition costs			—				1,484				—				1,484
Other (income) expense			(194	)			—				645				—
Total operating expenses			17,235				11,958				44,926				27,851
Operating income (loss)		$	21,531			$	(10,338	)		$	58,099			$	(24,771	)

 

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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 September 30, 2015				Nine Months Ended September 30, 2015
Adjusted EBITDAX reconciliation to net income (loss):
Net income		$	65,084			$	6,254
Interest expense			23,949				63,437
Depreciation, depletion and amortization			89,275				227,996
Amortization of deferred financing costs			1,313				3,722
Amortization of intangible assets			408				1,224
Gain on derivative instruments(1)			(127,072	)			(184,729	)
Net cash receipts on settled derivative instruments(1)			47,809				117,680
Non-cash stock compensation expense			4,214				11,681
Non-cash incentive unit (income) expense			(686	)			45,870
Income tax expense			19,797				18,335
Exploration expense			830				1,925
Other (income) expense			(265	)			3,624
Noncontrolling interest			(6,134	)			(16,833	)
Adjusted EBITDAX		$	118,522			$	300,186

 

(1)

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

 

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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 September 30, 2015				Nine Months Ended September 30, 2015
Reconciliation to net income (loss) attributable to Rice Energy Inc:
Net income (loss) attributable to Rice Energy Inc.		$	58,950			$	(10,579	)
Gain on derivative instruments, net of tax(1)			(87,959	)			(127,869	)
Net cash receipts on settled derivative instruments, net of tax(1)			33,094				81,458
Incentive unit (income) expense, net of tax			(410	)			27,378
Other (income) expense, net of tax			(184	)			2,508
Adjusted net income (loss) attributable to Rice Energy Inc.		$	3,491			$	(27,104	)

 

(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.

 

17

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Rice Energy Inc.

Derivatives Information

(Unaudited)

The table below provides data associated with our derivatives as of November 5, 2015 for the periods indicated:

 

All-In Fixed Price Derivatives		Fourth Quarter 2015				2016				2017				2018				2019
NYMEX Natural Gas Swaps:
Volume Hedged (BBtu/d)			220				408				155				5				20
Weighted Average Swap Price ($/MMBtu)		$	4.08			$	3.65			$	3.64			$	3.60			$	3.23
NYMEX Natural Gas Collars:
Volume Hedged (BBtu/d)			183				50				220				280				130
Weighted Average Floor Price ($/MMBtu)		$	3.97			$	2.91			$	3.13			$	3.16			$	3.09
Weighted Average Collar Price ($/MMBtu)		$	4.65			$	3.60			$	3.61			$	3.62			$	3.60
NYMEX Volume Hedged (BBtu/d)			403				458				375				285				150
Swap + Collar Floor ($/MMBtu)		$	4.03			$	3.57			$	3.34			$	3.16			$	3.11
Dominion Natural Gas Swaps
Volume Hedged (BBtu/d)			58				31				—				—				—
Weighted Average Swap Price ($/MMBtu)		$	2.45			$	2.62			$	—			$	—			$	—
TCO Natural Gas Swaps
Volume Hedged (BBtu/d)			42				—				—				—				—
Weighted Average Swap Price ($/MMBtu)		$	3.30			$	—			$	—			$	—			$	—
Total Fixed Price Derivatives
Volume Hedged (BBtu/d)			503				489				375				285				150
Weighted Average Swap Price ($/MMBtu)		$	3.78			$	3.51			$	3.34			$	3.16			$	3.11
Basis Contract Derivatives
TCO Basis Swaps
Volume Hedged (BBtu/d)			40				44				27				19				10
Weighted Average Swap Price ($/MMBtu)		$	(0.33	)		$	(0.32	)		$	(0.33	)		$	(0.40	)		$	(0.38	)
Dominion Basis Swaps
Volume Hedged (BBtu/d)			11	(1)			45				83				155				140
Weighted Average Swap Price ($/MMBtu)		$	(1.12	)		$	(1.10	)		$	(0.93	)		$	(0.67	)		$	(0.63	)

 

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M2 Basis Swaps
Volume Hedged (BBtu/d)			12				40				65				—				—
Weighted Average Swap Price ($/MMBtu)		$	(0.94	)		$	(1.08	)		$	(1.01	)		$	—			$	—
MichCon Basis Swaps
Volume Hedged (BBtu/d)			3				24				4				4				20
Weighted Average Swap Price ($/MMBtu)		$	(0.04	)		$	(0.01	)		$	(0.04	)		$	(0.04	)		$	(0.12	)
ELA Basis Swaps
Volume Hedged (BBtu/d)			73				110				80				40				10
Weighted Average Swap Price ($/MMBtu)		$	(0.11	)		$	(0.10	)		$	(0.09	)		$	(0.08	)		$	(0.10	)
Chicago Basis Swaps
Volume Hedged (BBtu/d)			13				40				10				10				—
Weighted Average Swap Price ($/MMBtu)		$	0.17			$	(0.05	)		$	(0.16	)		$	(0.19	)		$	—
ANR SE Basis Swaps
Volume Hedged (BBtu/d)			—				35				—				—				—
Weighted Average Swap Price ($/MMBtu)		$	—			$	(0.10	)		$	—			$	—			$	—
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)			7				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)			103				100				100				100				92
Weighted Average Swap Price ($/MMBtu)		$	(0.17	)		$	(0.17	)		$	(0.17	)		$	(0.17	)		$	(0.16	)
Total Basis Swaps (Financial + Physical)
Volume Hedged (BBtu/d)			288				469				380				336				272
Weighted Average Swap Price ($/MMBtu)		$	(0.27	)		$	(0.33	)		$	(0.47	)		$	(0.40	)		$	(0.40	)

 

(1)	4Q15 does not include ~40 MDth/d of financial Dominion Basis Swaps and ~10 MDth/d of Henry Hub Swaps Rice purchased.

 

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

 

Supplemental Balance Sheet data (in thousands)		September 30, 2015
Cash and cash equivalents		$	216,084
Long-term debt
6.25% Senior Notes Due April 2022		$	900,000
7.25% Senior Notes Due May 2023			397,128
Senior Secured Revolving Credit Facility			—
Midstream Holdings Revolving Credit Facility			152,000
RMP Revolving Credit Facility			72,000
Total long-term debt		$	1,521,128
Net debt		$	(1,305,044	)

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

 

20