Rice Energy Reports First Quarter 2015 Results and Increases 2015 Production Guidance

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May 07, 2015, 07:30 ET

CANONSBURG, Pa., May 7, 2015 /PRNewswire/ -- Rice Energy Inc. (NYSE: RICE) ("Rice Energy") today reported first quarter 2015 financial and operational results. Highlights during the quarter include:

Production averaged 440 MMcfe/d, a 111% increase above pro forma⁽¹⁾ first quarter 2014
Adjusted EBITDAX⁽²⁾ of $84.3 million for the first quarter 2015, a 30% increase over pro forma first quarter 2014
Adjusted realized natural gas price⁽³⁾ of $3.20 per Mcf in the first quarter 2015
Turned to sales two operated Utica wells, each currently producing approximately 18 MMcfe/d
Achieved significant growth in average midstream throughput to 668 MDth/d, a 13% increase above fourth quarter 2014
Completed successful $400 million placement of 7.25% senior unsecured notes due 2023
Increased reserve-based credit facility by $100 million to $650 million in April 2015 with $536 million available pro forma as of March 31, 2015
Strong first quarter liquidity position of $1.2 billion, excluding RMP, pro forma for borrowing base re-determination

Commenting on the results, Daniel J. Rice IV, Chief Executive Officer, said, "We are off to a strong start in 2015, building off our successful year in 2014. We remain committed to diligently executing our plan and delivering top-tier results."

(1)	References to pro forma volumes throughout this earnings release give effect to our acquisition of the remaining 50% interest in our Marcellus joint venture from Alpha Natural Resources, Inc. on January 29, 2014.
(2)	Please see "Supplemental Non-GAAP Financial Measure" for a description of Adjusted EBITDAX.
(3)	Adjusted realized price includes our firm transportation sales, net, and the impact of hedging.

First Quarter 2015 Consolidated Results	Three Months Ended March 31, 2015

Total production (MMcfe)	39,621
Total production (MMcfe/d)	440
% Gas	99%

Average realized prices per Mcf:

Natural gas price before effects of hedges	$	2.42
Natural gas price after effects of hedges⁽¹⁾	3.12
Adjusted realized price	3.20
Average oil and NGL price per Bbl	24.71

Average costs per Mcfe:
Lease operating	$	0.29
Gathering, compression and transportation	0.36
Production taxes and impact fees	0.04
General and administrative	0.44
Depletion, depreciation and amortization	1.58

Adjusted EBITDAX (in thousands)	$	84,276

Total midstream throughput (MDth/d)	668
% Third party	17%


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

First Quarter Financial Results

During the first quarter 2015, our daily net production averaged 440 MMcfe/d, an 11% increase over fourth quarter 2014 volumes and 111% increase over pro forma first quarter 2014 production. Our first quarter 2015 realized natural gas price, before the effect of hedges, was $2.42 per Mcf. After giving effect to hedges, our first quarter 2015 average natural gas price was $3.12 per Mcf. Our average adjusted realized price, including our firm transportation sales and the impact of hedges, was $3.20 per Mcf. Our average realized oil and NGL price was $24.71 per Bbl. Per unit cash production costs (lease operating; gathering, compression and transportation; and production taxes and impact fees) were $0.69 per Mcfe. Adjusted EBITDAX for the quarter was $84.3 million. We reported an adjusted net loss of $3.1 million, or ($0.02) per share, after excluding unrealized gains on derivative contracts and other non-recurring income and expense items.

2015 Production Guidance Update

We are increasing our 2015 annual production guidance to 470 - 490 MMcfe/d, due to accelerated well timing from increased operational efficiencies. We are reaffirming our 2015 capital budget of $890 million including E&P and retained midstream investments.

Upstream Segment

Marcellus Shale

We turned to sales 8 gross (6 net) horizontal Marcellus wells during the first quarter with an average lateral length of approximately 6,225 feet and a 73% working interest. As of quarter end, our leasehold position consisted of 89,000 net acres in Washington and Greene Counties, Pennsylvania.

The following table provides certain operational data as of May 1, 2015, related to the 8 gross operated Marcellus wells brought online during the first quarter of 2015.

Wells per Pad	Average Lateral Length (Feet)	Periodic Flow Rates (MMcfe/d) 0-30 Days	D&C ($/Foot)
6	5,631	5.2	$	1,333
2	8,008	11.9	$	1,178
8	6,225	6.9	$	1,294

The following table provides operational data as of May 1, 2015 related to the 86 gross (77 net) operated Marcellus producing wells as of March 31, 2015.

			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	3,281	5.7	6.0	4.4	2.7	$	2,341
2012	9	5,731	9.2	10.0	6.8	4.1	$	1,584
2013	22	6,286	11.2	10.6	7.6	5.9	$	1,442
2014	41	7,282	10.6	10.0	6.3	N/A	$	1,235
Q1 2015	8	6,225	N/A	N/A	N/A	N/A	$	1,294
Total ⁽¹⁾	86	6,488	10.2	9.8	6.8	3.8	$	1,407


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

In April 2015, we brought online 9 gross (8 net) Marcellus wells with an average lateral length of approximately 7,200 feet and an 89% working interest.

Utica Shale

We turned to sales 2 gross (1 net) horizontal Utica wells during the first quarter with an average lateral length of 8,879 feet and a 56% working interest. These wells are currently producing at a managed choke rate of 18 MMcf/d with flowing casing pressures of approximately 6,000 psi per well. As of March 31, 2015, we had 57,000 net acres in southeast Ohio, concentrated in Belmont County.

Our first well, the Bigfoot 9H has cumulatively produced 4.6 Bcf after 315 days online and continues to produce at a managed choke rate of 16 MMcf/d.

The Blue Thunder 10H and 12H, our second and third Utica wells, respectively, (average 9,000 foot lateral and 67% working interest) have each cumulatively produced 3.5 Bcf after approximately 225 days online. They each continue to produce at a managed choke rate of 16 MMcf/d.

The following table provides certain operational data as of May 1, 2015, related to the 2 gross operated Utica wells brought online during the first quarter of 2015.

Wells per Pad		Average Lateral Length (Feet)		Periodic Flow Rates (MMcfe/d) 0-30 Days		D&C ($/Foot)
2		8,879		12.5		$	1,837

The following table provides operational data as of May 1, 2015 related to the 5 gross (3 net) operated Utica producing wells as of March 31, 2015.

			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)
Q2 2014	1	6,957	14.0	14.2	N/A	N/A	$	3,316
Q3 2014	2	9,000	14.5	15.9	N/A	N/A	$	2,000
Q4 2014	—	N/A	N/A	N/A	N/A	N/A	N/A
Q1 2015	2	8,879	N/A	N/A	N/A	N/A	$	1,837
Total ⁽¹⁾	5	8,543	14.3	15.3	N/A	N/A	$	2,198


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

In April 2015, we brought online three additional Utica wells (average 9,411 foot lateral, 42% working interest), which were developed parallel to our fourth and fifth Utica wells.

We are currently completing eight additional wells with an average lateral length of approximately 10,200 feet. We are continuing to see cost and operational efficiency improvements and are on track to meet our year-end 2015 targeted well cost.

Firm Transportation and Realized Gas Pricing

Our firm transportation and firm sales portfolio underpins our anticipated production growth and enables us to access premium gas markets across the United States, including the Gulf Coast region, while reducing our pricing exposure to currently less than favorable local Appalachian markets. Approximately 51% of our first quarter 2015 production received favorable Gulf Coast, TCO and Midwest pricing, while the remaining production received local Appalachian markets pricing. For the remainder of 2015, we anticipate that approximately 66% of our production will be transported to these premium gas markets.

The following tables provide basis exposure as a percentage of our production and average differentials to NYMEX for actual results through March 31, 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%	36%	35%	49%	39%	48%
TCO	23%	19%	16%	9%	16%	8%
Midwest/Dawn	1%	—%	17%	18%	10%	13%
TETCO M2	10%	12%	12%	8%	11%	7%
Dominion South	39%	33%	20%	16%	24%	24%

	Realized Price
	Actual		Estimated⁽¹⁾
	1Q15		2Q15		Full Year 2015		Full Year 2016
NYMEX Henry Hub price ($/MMBtu)	$	2.87	$	2.54	$	2.73	$	3.06
Average basis impact ($/MMBtu)	(0.47)		(0.57)		(0.42)		(0.38)
Firm transportation fuel & variables ($/MMBtu)	(0.09)		(0.14)		(0.16)		(0.17)
Btu uplift (MMBtu/Mcf)	0.11		0.09		0.11		0.13
Pre-hedge realized price ($/Mcf)	2.42		1.92		2.26		2.64
Realized hedging gain (loss) ($/Mcf)	0.70		1.11		0.98		0.39
Post-hedge realized price ($/Mcf)	3.12		3.03		3.24		3.03
Net firm transportation sales	0.08		—		—		—
Adjusted realized price ($/Mcf)	$	3.20	$	3.03	$	3.24	$	3.03


(1)	NYMEX price as of 4/23/15.

Financial Position and Liquidity

In March 2015, we completed a successful $400 million placement of 7.25% senior unsecured notes due 2023 with net proceeds of $389 million for general corporate purposes, including capital expenditures.

In April 2015, the borrowing base of our reserve-based credit facility was increased by $100 million to $650 million, representing an 18% increase.

As of March 31, 2015, our liquidity position pro forma for our borrowing base re-determination, excluding RMP, was $1.2 billion, consisting of $536 million available under our upstream credit facility, $283 million available under our retained midstream credit facility and $340 million of cash on hand.

Commodity Hedging Update

The weighted average floor price of our 432 BBtu/d 2015 hedge portfolio, including our basis swaps, is $3.46 per MMBtu, representing 83% 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 305 BBtu/d hedged at a weighted average floor price of $3.54 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.

Midstream Segment

Average daily throughput for the first quarter of 2015 was 668 MDth/d consisting of 17% third party volumes. Our first quarter total revenue was $29.4 million. Operating expenses were $13.6 million and operating income was $15.9 million.

In the first quarter, we finalized our Utica midstream arrangements with Gulfport Energy and MarkWest Energy Partners. As a result, we will provide gas gathering and compression services to Gulfport for a majority of their dry gas acreage within our joint development area. Similarly, MarkWest will provide midstream services for our wet acreage, as well as gathering and compression services for a portion of our dry gas acreage in Ohio. All agreements have a term of 15 years.

Rice Midstream Partners LP (NYSE: RMP)

Pennsylvania Gathering System

Average daily throughput for the first quarter of 2015 was 557 MDth/d consisting of 11% third party volumes. Operating revenues for the first quarter 2015 were $16.2 million and total operating expenses were $6.6 million. We reported net income of $9.1 million, or $0.16 per limited partner unit. During the first quarter, adjusted EBITDA was $12.5 million. Maintenance capital expenditures were $1.1 million and cash interest expense was $0.4 million, which generated distributable cash flow (DCF) of $10.9 million.

As of March 31, 2015, RMP's liquidity position of $459 million consisted of $450 million available under its senior secured revolving credit facility and $9 million of cash on hand.

On April 24, 2015, RMP declared its quarterly distribution of $0.1875 per unit for the first quarter 2015. The distribution will be payable on May 14, 2015 to unitholders on record as of May 5, 2015.

Rice Midstream Holdings

Ohio Gathering System

Average daily throughput for the first quarter of 2015 was 111 MDth/d consisting of 44% third party volumes. Construction of our Ohio gathering system continues, which is expected to provide total throughput capacity of 2.6 MMDth/d by year end 2015.

Fresh Water Distribution Systems

Construction of our fresh water distribution systems is in progress and by year end 2015 is expected to provide direct access to 10.6 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 for our well completion operations.

Conference Call

Rice Energy will host a conference call on May 7, 2015 at 9:00 a.m. Eastern time (8:00 a.m. Central time) to discuss first 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 first 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 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, 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.

Rice Energy Inc.
Condensed Consolidated Statements of Operations
(Unaudited)

	Three Months Ended
	March 31,
(in thousands, except per share data)	2015		2014
Natural gas production (MMcf)	39,089		16,390
Oil and NGL production (MBbls)	89		—
Total production (MMcfe)	39,621		16,390

Operating revenues:
Natural gas, oil and natural gas liquids ("NGL") sales	$	96,912	$	90,466
Firm transportation sales, net	2,826		—
Gathering, compression and water distribution	9,801		11
Total operating revenues	109,539		90,477

Operating expenses:
Lease operating	11,591		5,187
Gathering, compression and transportation	14,420		6,456
Production taxes and impact fees	1,454		639
Exploration	739		486
Midstream operation and maintenance	3,331		674
Incentive unit expense	23,458		73,802
Stock compensation expense	3,255		91
General and administrative	17,490		11,430
Depreciation, depletion and amortization	62,581		25,507
Amortization of intangible assets	408		—
Contract termination fees	1,892		—
Total operating expenses	140,619		124,272

Operating loss	(31,080)		(33,795)
Interest expense	(16,129)		(7,042)
Gain on purchase of Marcellus joint venture	—		203,579
Other income	162		591
Realized gain (loss) on derivative instruments	27,396		(11,158)
Unrealized gain (loss) on derivative instruments	33,971		(9,222)
Amortization of deferred financing costs	(1,103)		(489)
Loss on extinguishment of debt	—		(143)
Write-off of deferred financing costs	—		(836)
Equity loss of joint ventures	—		(2,656)
Income before income taxes	13,217		138,829
Income tax expense	(8,530)		(9,375)
Net income	4,687		129,454
Less: Net loss attributable to noncontrolling interests	(4,535)		—
Net income attributable to Rice Energy Inc.	$	152	$	129,454

Adjusted net income⁽¹⁾	$	(3,094)	$	62,611

Adjusted EBITDAX⁽¹⁾	$	84,276	$	64,803

Weighted average shares-basic	136,291,814		124,646,324
Weighted average shares-diluted	136,347,810		125,192,398

Earnings per share—basic	$	—	$	1.04
Earnings per share—diluted	$	—	$	1.03

Adjusted earnings per share - basic	$	(0.02)	$	0.50
Adjusted earnings per share - diluted	$	(0.02)	$	0.50


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

Rice Energy Inc.
Segment Results of Operations
(Unaudited)

Exploration and Production Segment

	Three Months Ended
	March 31,
(in thousands, except volumes)	2015		2014

Operating volumes:
Natural gas production (MMcf)	39,089		16,390
Oil and NGL production (MBbls)	89		—
Total production (MMcfe)	39,621		16,390

Operating revenues:
Natural gas, oil and NGL sales	$	96,912	$	90,466
Firm transportation sales, net	2,826		—
Total operating revenues	99,738		90,466

Operating expenses:
Lease operating	11,591		5,187
Gathering, compression and transportation	27,676		6,456
Production taxes and impact fees	1,454		639
Exploration	739		486
Incentive unit expense	22,498		68,101
Stock compensation expense	2,220		91
General and administrative	13,299		9,569
Depreciation, depletion and amortization	58,914		25,064
Contract termination fees	1,892		—
Total operating expenses	140,283		115,593

Operating loss	$	(40,545)	$	(25,127)

Average costs per Mcfe:
Lease operating	$	0.29	$	0.32
Gathering and compression	0.35		—
Transportation	0.35		0.39
Production taxes and impact fees	0.04		0.04
Exploration	0.02		0.03
Incentive unit expense	0.57		4.16
Stock compensation expense	0.06		0.01
General and administrative	0.34		0.58
Depreciation, depletion and amortization	1.49		1.53

Midstream Segment

	Three Months Ended
	March 31,
(in thousands, except volumes)	2015		2014

Operating volumes:
Gathering volumes (MDth/d)	668		250
Compression volumes (MDth/d)	64		—
Water distribution volumes (MMGal)	185		—

Operating revenues:
Gathering revenues	$	18,745	$	66
Compression revenues	357		—
Water distribution revenues	10,345		—
Total operating revenues	29,447		66

Operating expenses:
Midstream operation and maintenance	3,331		674
Incentive unit expense	960		5,701
Stock compensation expense	1,035		—
General and administrative	4,191		1,861
Depreciation, depletion and amortization	3,667		443
Amortization of intangible assets	408		—
Total operating expenses	13,592		8,679

Operating income (loss)	$	15,855	$	(8,613)

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 contract termination fees. Adjusted EBITDAX is not a measure of net income as determined by United States generally accepted accounting principles, or GAAP.

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 March 31, 2015
Adjusted EBITDAX reconciliation to net income (loss):
Net income	$	4,687
Interest expense	16,129
Depreciation, depletion and amortization	62,581
Amortization of deferred financing costs	1,103
Amortization of intangible assets	408
Gain on derivative instruments⁽¹⁾	(61,367)
Net cash receipts on settled derivative instruments⁽¹⁾	27,396
Non-cash stock compensation expense	3,255
Non-cash incentive unit expense	23,458
Income tax expense	8,530
Exploration expenses	739
Noncontrolling interest	(4,535)
Contract termination fees	1,892
Adjusted EBITDAX	$	84,276

(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.

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 contract termination fees. Adjusted net income (loss) is not a measure of net income as determined by United States generally accepted accounting principles, or GAAP.

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

(in thousands)	Three Months Ended March 31, 2015
Reconciliation to net income (loss):
Net income	$	4,687
Gain on derivative instruments, net of tax⁽¹⁾	(41,670)
Net cash receipts on settled derivative instruments, net of tax⁽¹⁾	18,603
Incentive unit expense, net of tax	14,001
Contract termination fees, net of tax	1,285
Adjusted net income	$	(3,094)

(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.

Rice Energy Inc.
Derivatives Information
(Unaudited)

The table below provides data associated with our derivatives at May 7, 2015 for the periods indicated:

All-In Fixed Price Derivatives	Remainder of 2015		2016		2017

NYMEX Natural Gas Swaps:
Volume Hedged (BBtu/d)	178		274		80
Weighted Average Swap Price ($/MMBtu)	$	4.08	$	3.95	$	4.01

NYMEX Natural Gas Collars:
Volume Hedged (BBtu/d)	144		—		50
Weighted Average Floor Price ($/MMBtu)	$	3.96	$	—	$	3.00
Weighted Average Collar Price ($/MMBtu)	$	4.65	$	—	$	3.78

NYMEX Volume Hedged (BBtu/d)	322		274		130
Swap + Collar Floor ($/MMBtu)	$	4.03	$	3.95	$	3.62

Dominion Natural Gas Swaps
Volume Hedged (BBtu/d)	72		31		—
Weighted Average Swap Price ($/MMBtu)	$	2.50	$	2.62	$	—

TCO Natural Gas Swaps
Volume Hedged (BBtu/d)	38		—		—
Weighted Average Swap Price ($/MMBtu)	$	3.30	$	—	$	—

Total Fixed Price Derivatives
Volume Hedged (BBtu/d)	432		305		130
Weighted Average Swap Price ($/MMBtu)	$	3.71	$	3.82	$	3.62

Basis Contract Derivatives
TCO Basis Swaps
Volume Hedged (BBtu/d)	36		17		—
Weighted Average Swap Price ($/MMBtu)	$	(0.42)	$	(0.42)	$	—

Dominion Basis Swaps
Volume Hedged (BBtu/d)	17		30		10
Weighted Average Swap Price ($/MMBtu)	$	(1.12)	$	(1.08)	$	(0.99)

M2 Basis Swaps
Volume Hedged (BBtu/d)	27		10		—
Weighted Average Swap Price ($/MMBtu)	$	(0.94)	$	(1.08)	$	—

MichCon Basis Swaps
Volume Hedged (BBtu/d)	1		4		4
Weighted Average Swap Price ($/MMBtu)	$	(0.04)	$	(0.04)	$	(0.04)

ELA Basis Swaps
Volume Hedged (BBtu/d)	30		10		—
Weighted Average Swap Price ($/MMBtu)	$	(0.13)	$	(0.12)	$	—

Chicago Basis Swaps
Volume Hedged (BBtu/d)	—		20		—
Weighted Average Swap Price ($/MMBtu)	$	—	$	(0.04)	$	—

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)	$	(0.79)	$	(0.79)	$	—

MichCon Fixed Basis (Physical)
Volume Hedged (BBtu/d)	2		10		10
Weighted Average Swap Price ($/MMBtu)	$	0.05	$	0.05	$	0.05

Gulf Coast Fixed Basis (Physical)
Volume Hedged (BBtu/d)	81		100		100
Weighted Average Swap Price ($/MMBtu)	$	(0.17)	$	(0.17)	$	(0.17)

Total Basis Swaps (Financial + Physical)
Volume Hedged (BBtu/d)		219		237		124
Weighted Average Swap Price ($/MMBtu)	$	(0.44)	$	(0.37)	$	(0.21)

The table below provides supplemental balance sheet data as of March 31, 2015.

Supplemental Balance Sheet data (in thousands)	March 31, 2015
Cash and cash equivalents	$	349,071
Long-term debt
6.25% Senior Notes Due April 2022	$	900,000
7.25% Senior Notes Due May 2023	396,938
Senior Secured Revolving Credit Facility	—
Midstream Holdings Revolving Credit Facility	17,000
RMP Revolving Credit Facility	—
Total long-term debt	$	1,313,938
Net debt	$	964,867

The table below outlines our firm transportation capacity by pipeline for the projects to which we are committed as anchor shipper.

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	June-15	175,000	20 Yrs	Midwest/Gulf Coast
Union Town to Gas City	TETCO	Nov-15	86,500	10 Yrs	Midwest/Gulf Coast
OPEN	TETCO	Nov-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