S&P: How The Marcellus Shale Is Changing The Dynamics Of The U.S. Energy Industry

How The Marcellus Shale Is ChangingThe Dynamics Of The U.S. EnergyIndustry

Primary Credit Analysts:

Carin Dehne-Kiley, CFA, New York (1) 212-438-1092; [email protected]

William M Ferara, New York (1) 212-438-1776; [email protected]

Secondary Contact:

David C Lundberg, CFA, New York (1) 212-438-7551; [email protected]

Table Of Contents

What Is The Marcellus Shale?

How Much Production Could The Marcellus Add?

Gas Flows Are Changing Direction

The Appalachian Premium Has Collapsed And Will Likely Remain Minimal

More Northeast Pipeline Takeaway Capacity Will Be Needed

More NGL Processing And Pipeline Infrastructure Will Be Needed

Who Could Feel Pressure, And Who Stands To Benefit, From The

Development Of The Marcellus?

Related Criteria And Research

WWW.STANDARDANDPOORS.COM/RATINGSDIRECT OCTOBER 15, 2012 1

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How The Marcellus Shale Is Changing TheDynamics Of The U.S. Energy Industry

The U.S. natural gas industry is rapidly evolving, largely because of shifting supply dynamics. The Appalachian region

in the Northeast is one of the main proponents of change, as its Marcellus shale could contain recoverable resources

equal to almost half of the current proven natural gas reserves in the U.S. Exploration and production (E&P)

companies have only just started to develop this resource, spurred by the increased use of specialized technological

capabilities such as horizontal drilling and hydraulic fracturing. Yet the rapid increase in production has already

affected long-standing gas flows, reducing the area's reliance on natural gas imports from other regions and cutting

premiums that local producers could realize. Standard & Poor's Ratings Services believes many industry players will

benefit from the evolution of the Marcellus, but thinks others could face headwinds.

In terms of regional consumption, the Northeast is home to some of the biggest gas consuming cities in the country,

including Philadelphia, Boston, and New York City. In that regard, the location of the Marcellus formation, or "play,"

holds a significant advantage for producers and consumers of natural gas. Although producers in the Marcellus have

reined in drilling activity recently due to weak natural gas prices, we believe that lower all-in costs and a higher natural

gas liquids (NGL) component relative to other producing areas of the U.S. will ensure the Marcellus remains a key

contributor to U.S. natural gas supply.

Overview

• Development of the Marcellus shale will continue to boost natural gas and NGL production in the Northeast

U.S.

• Natural gas pipeline flows will continue to shift between U.S. regions (east-to-west versus west-to-east).

• Local producers will no longer receive a premium price for Appalachian natural gas.

• New natural gas and NGL pipeline infrastructure will be needed.

• Credit risks will increase for some natural gas producers and pipeline operators, while others will benefit.

We believe the development of the Marcellus will particularly benefit two groups of issuers that we rate: midstream

and pipeline companies that are building or expanding infrastructure in the Northeast; and E&P companies that

produce natural gas and NGLs in the region. Conversely, two groups of rated issuers could feel ratings pressure from

the development of the Marcellus if they don't modify their strategies to offset a potential increase in business risk or

reduce debt to limit the impact from potential cash flow declines on their financial risk profiles. These issuers include:

long-haul pipeline operators that are unlikely or unable to reverse their pipeline flows, face recontracting risk, or have

high asset concentration; and E&P companies producing natural gas in the U.S. Rockies or Canada that are currently

sending gas to the Northeast. Longer term, once sufficient takeaway capacity is in place, we expect low-cost

production in the Marcellus to displace higher-cost production in other U.S. regions.


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What Is The Marcellus Shale?

The Marcellus shale is a hydrocarbon-bearing formation that extends from southern New York to West Virginia and

spans most of Pennsylvania, the eastern part of Ohio, and parts of Maryland, Virginia, and Tennessee (see chart 1). To

date, developers have concentrated most of their activity in Pennsylvania and West Virginia, primarily because a

moratorium in New York has prevented them from using hydraulic fracturing, or fracking, to access the formation in

the Empire State. Horizontal drilling requires far more fracking fluid (e.g., water, sand, and chemicals) than vertical

wells, and New York's moratorium will prevent horizontal development of the Marcellus shale until regulators develop

more comprehensive environmental rules. (For more information on fracking, see "How Horizontal Drilling And

Fracking Have Reshaped The U.S. Energy Landscape," published on Sept. 17, 2012.)

The Marcellus currently accounts for about 6% of total U.S. natural gas production and about 20% of total U.S. gas

shale production. The U.S. Energy Information Administration (EIA) estimates that the Marcellus shale could hold up

to 141 trillion cubic feet (tcf) of technically recoverable natural gas resources. To put this into perspective, that's about

45% of the EIA's estimate of total current proven natural gas reserves in the U.S.


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How The Marcellus Shale Is Changing The Dynamics Of The U.S. Energy Industry

Although not a focus of this report, given the still limited public data on the play, the Utica shale appears poised to

become the next driver of production and reserves growth in the Appalachian region. Located in eastern Ohio along

the Pennsylvania border, the Utica shale underlies the Marcellus, and is prospective for liquids-rich natural gas and

crude oil.

How Much Production Could The Marcellus Add?

Current production volume from the Marcellus shale is a mere drop in the bucket compared with its potential reserves,

but it's growing rapidly. For example, the Pennsylvania Department of Environmental Production (DEP) says natural

gas production from the state's portion of the Marcellus shale increased to 4.4 billion cubic feet per day (bcf/d) in the

first half of 2012 from less than 0.5 bcf/d in 2009. This dramatic growth has boosted total production in the Northeast

to 7.8 bcf/d in July, compared with about 7.0 bcf/d in the first half of 2012. Startlingly, the average stood at just over

2.0 bcf/d in 2009. Energy market analytics company Bentek Energy LLC (Bentek, like Standard & Poor's, is a

subsidiary of The McGraw Hill Cos.) expects this rapid pace to continue and has projected that Northeast volumes will

increase to more than 10 bcf/d in 2013 and climb to 17 bcf/d in 2017. Bentek's forecast notes that the Marcellus (and

Utica) formations will account for 9.5 bcf/d of this production in 2013 and 16 bcf/d in 2017. In contrast, the EIA

projects that total U.S. natural gas production will grow by about 1% per year through 2017.

We believe the discrepancy between the growth projections for the Marcellus and the overall U.S. reflects the higher

returns associated with the Marcellus shale compared with those of other key natural gas-producing plays in the U.S.

Based on company-specific data and using Standard & Poor's long-term price deck assumptions of $3.50/mmBTU for

Henry Hub natural gas, we estimate that Marcellus "dry" gas (e.g., pipeline quality) generates an internal rate of return

of around 12%, while Marcellus "wet" gas (e.g., gas that contains NGLs) generates an internal rate of return (IRR) of

close to 30% due to the higher revenues associated with NGLs. These rates of return are significantly higher than for

the other key gas shale plays, including the Haynesville, Fayetteville, Barnett, Woodford, and Eagle Ford gas, due

primarily to the lower finding, development and production costs associated with the Marcellus.


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Chart 2

Spot natural gas prices are currently below our $3.50/mmBTU long-term price deck, so many operators have put

drilling activity for dry gas shale on hold, even in the Marcellus. However, the lower costs associated with

development and production of the Marcellus shale means operators are likely to resume drilling in that region first if

and when natural gas prices improve. Thus, we believe the Marcellus will be one of the first areas that operators will

return to if and when natural gas prices improve, as we expect they will over the next 12-18 months. (For more

information on Standard & Poor's pricing assumptions, see "Standard & Poor's Raises Its U. S. Natural Gas Price

Assumptions; Oil Price Assumptions Are Unchanged," published July 24, 2012.)

To date, independent E&P companies have led the growth in Marcellus production, while the major integrated oil

companies and national oil companies entered the play more recently through acquisitions and joint ventures (JVs).

Table 1 lists the top 15 Marcellus producers as of fourth-quarter 2011.

Table 1

Top 15 Marcellus Producers

As of fourth-quarter 2011

Company

Bloomberg estimated Marcellus

natural gas production, 4Q11

(mmcf/d)

Estimated marcellus natural

gas production, 4Q11

(mmcf/d)

% of company's total

production

Marcellus net

acres, 1Q12

Chesapeake Energy

Corp.

909.8 450.0 13 1,780,000

Talisman Energy Inc. 622.0 429.1 20 217,000


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Table 1

Top 15 Marcellus Producers (cont.)

Range Resources

Corp.

534.0 375.0 60 900,000

Cabot Oil & Gas

Corp.

460.3 300.0 50 188,000

EQT Corp. 232.7 268.5 47 532,000

Royal Dutch Shell

PLC

213.4 213.4 1 650,000

Anadarko Petroleum

Corp.

328.0 193.0 5 260,000

Chevron Corp. 140.3 140.3 1 714,000

Southwestern Energy

Co.

125.7 125.7 9 187,000

National Fuel Gas

Cp.

128.5 124.2 62 745,000

ExxonMobil Corp. 102.9 102.9 1 660,000

Consol Energy Inc. 173.3 70.0 16 361,000

EOG Resources Inc. 79.1 40.0 2 210,000

Exco Resources Inc. 74.5 40.0 7 140,000

Rex Energy Corp.* 45.5 35.0 71 69,700

*Total Appalachian production. Sources: Company Web sites, Bloomberg.

Gas Flows Are Changing Direction

The surge in production from the Marcellus is materially affecting natural gas flows throughout North America. In

particular, Marcellus production has diminished the Northeast region's need to receive natural gas from elsewhere in

the country, which has reduced natural gas flows along traditional west-to-east routes. This has effectively left some

pipeline capacity underutilized (see "The Shale Gas Boom Is Shaping U.S. Gas Pipelines' New Reality," published June

5, 2012).

The Northeast U.S.* has historically been a natural gas importer, due to its limited local supply and high demand from

New York, Boston, and Philadelphia. Nine main pipelines bring natural gas into the northeast from the major

producing regions of the Gulf Coast, Rockies, and Canada (see table 2). Although these pipelines have a combined

aggregate capacity of nearly 47 bcf/d, they have multiple delivery points along their routes with firm contracts to

deliver gas prior to reaching their endpoints in the Northeast.

*The Northeast U.S. includes Connecticut, Delaware, Massachusetts, Maine, New Hampshire, New Jersey, New York,

Pennsylvania, Rhode Island, Virginia, and West Virginia.

Table 2

Main Pipelines Into The Northeast

Pipeline name Pipeline owner Capacity mmcf/d

From the Gulf Coast

Columbia Gulf Transmission NiSource Inc. 9,350

Tennessee Gas Pipeline Co Kinder Morgan Energy Partners L.P. 7,500


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Table 2

Main Pipelines Into The Northeast (cont.)

Texas Eastern Transmission Spectra Energy Corp. 9,600

Transcontinental Gas Pipeline The Williams Cos. Inc. 8,500

Dominion Transmission Co. Dominion Resources Inc. 7,200

From the West

Rockies Express Pipeline Tallgrass Energy Partners L.P.* (50%), Sempra Energy (25%), Phillips 66 (25%) 1,800

From Canada

Iroquois Gas Transmission System TransCanada Corp., Dominion Resources Inc. (25%), National Grid PLC, Iberdrola SA

(5%), NJ Resources Corp. (5%)

1,500

Empire Pipeline National Fuel Gas Co. 750

Maritimes & Northeast Pipeline Spectra Energy Corp. (77%), Emera Inc. (13%), ExxonMobil Corp. (10%) 833

*In the process of acquiring this interest from Kinder Morgan Energy Partners L.P. Source: Company Web sites, Standard & Poor’s.

Increased production in Marcellus has affected decades-long gas flows from the Gulf Coast and Canada, and more

recently the Rockies, and Appalachia now faces infrastructure bottlenecks because pipeline takeaway solutions have

lagged drilling activities in certain pockets of the region.

Increased production in the Marcellus has caused a significant reduction in deliveries to the Northeast from other

natural gas producing areas along the long-haul pipelines. According to Bentek, long-haul pipelines have historically

supplied about 85% of the demand in the northeast (we estimate Northeast "imports" averaged 11 bcf/d-12 bcf/d

between 2005 and 2010).The supply dropped to 65% in 2011 and is on track to decline further in the coming years.

With the newfound capacity, these pipelines are now increasing deliveries to other markets, primarily the Midwest,

and in some cases, reversing gas flows through backhaul opportunities, which is partly offsetting the declining need to

pipe supply to the Marcellus region.

What's A Backhaul?

A transaction that results in the transportation of gas in a direction opposite of the aggregate physical flow of gas

in the pipeline. A backhaul condition will exist as long as the aggregate backhaul transactions total less than the

aggregate forward haul transactions.

For instance, Tennessee Gas Pipeline (TGP) expects its Marcellus backhaul volumes under contract to be nearly 1

bcf/d in 2012, up from 675 mmcf/d in 2011 and in stark contrast to only 10 mmcf/d in 2008. In addition, some

producers are negotiating "transportation exchange" deals whereby they swap natural gas volumes produced in the

Gulf Coast for volumes produced and delivered in the northeast—thereby avoiding pipeline transportation fees.

The Rockies Express (REX) pipeline is another interesting case study. The pipeline was completed in 2009 to deliver

1.8 bcf/d of gas from the Rockies to eastern markets, and its flow patterns have since shifted so that REX mainly

delivers gas into Chicago (rather than at its endpoint in Ohio). Appalachia gas is also now being backhauled to the

Chicago market, causing the region to be significantly oversupplied. This in turn, redirects more gas from the Rockies

to the West Coast, which displaces Canadian imports into that region.


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The Appalachian Premium Has Collapsed And Will Likely Remain Minimal

Since Marcellus production has surged and the area has minimal takeaway capacity, the Appalachian premium has

collapsed (see chart 3). Local producers must now compete with supply shipped in from other regions, which is

typically delivered to customers under long-term contracts with midstream or pipeline companies. Because natural gas

utilities and gas distribution companies in the Northeast historically contracted for supply on long-haul pipelines from

the Gulf Coast, Rockies, and Canada, they ended up paying transportation and fuel charges along with the actual gas

charges. As a result, Appalachian producers could charge a premium for their gas, relative to other regions, as long as

it didn't exceed the all-in cost for the imported supply (regional gas price plus transportation plus fuel costs). Between

2005 and 2010, the Marcellus-to-Henry Hub premium averaged about $0.20 per mmBTU.

Although gas utilities and gas distribution companies could now theoretically switch to local natural gas suppliers, they

have not completely done so—in our view due to existing long-term contracts in place and perhaps some skepticism

about the reliability of shale gas, given it is still a fairly recent phenomenon. Consequently, we expect the northeast

region to remain well supplied with natural gas, and the historical northeast gas premium to remain minimal.

The flattening Appalachian premium was particularly evident in northeast Pennsylvania, one of the most highly

productive areas of the Marcellus play. Natural gas production has overwhelmed capacity on the TGP line at zone 4,

pushing prices down to $1.00/mmBTU, or about $2.00/mmBTU below Henry Hub, in July 2012. A number of pipeline


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projects are underway to alleviate this bottleneck.

The flattening of the historical Appalachian premium—along with the drop in benchmark natural gas prices—has

effectively clipped the economics of Marcellus dry gas (although the Marcellus still ranks above other gas shales in

terms of IRR). As a result, many operators—including large producers Chesapeake Energy (BB-/Negative/--),

Talisman Energy (BBB/Stable/A-2), Anadarko Petroleum Corp. (BBB-/Positive/--), Range Resources Corp.

(BB/Stable/--), EQT Corp. (BBB/Stable/A-2), and National Fuel Gas Co. (BBB/Stable/A-2)—have either cut the

number of dry gas rigs running in the Marcellus or moved them to the more liquids-rich areas of the play (which still

offers adequate returns).

Flat pricing differentials also limit earnings and cash flow potential for the long-haul pipeline companies and marketers

that could previously capitalize on price spreads between Gulf Coast and Northeast gas.

More Northeast Pipeline Takeaway Capacity Will Be Needed

Ultimately, we believe there will be more local natural gas supply than the Appalachian region can consume, so new

pipeline takeaway capacity will be needed to move the excess gas to other regions.

Between 2007 and 2011, Northeast natural gas demand averaged between 14 bcf/d and 15 bcf/d, but actual usage

varied widely from as low as 10 bcf/d in the summer to nearly 20 bcf/d in the winter due to gas-fired heating demand.

Based on our natural gas supply growth assumptions from the Marcellus/Utica (reaching 9.5 bcf/d in 2013 and 16

bcf/d in 2017), and assuming that regional demand grows at a rate of about 2% per year (which is in line with Standard

& Poor's economists' GDP growth forecast), we estimate that the region will need up to 10 bcf/d of additional

takeaway (or backhaul) capacity from the Marcellus by 2017—potentially more to handle the lower demand months.


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Chart 4

In looking at recent capacity trends, we expect pipeline companies will be working to address the growing need in

targeted areas. Southwest Pennsylvania has notably more access to long-haul pipelines than northeast Pennsylvania,

which has insufficient takeaway capacity because the extremely productive wells in the area have yielded significantly

more output than originally anticipated. Production volume is increasing so quickly, in fact, that space on takeaway

pipelines is limited or non-existent in certain areas. For instance, TGP's average load factor on two of its pipeline

sections that traverse from western Pennsylvania to the New York City and Boston areas were about 90% in the winter

of 2011-2012, well above the mid-50% area in 2009.

Standard & Poor's isn't alone in thinking that additional takeaway capacity is needed in Appalachia. In fact, several

new build and expansion projects are currently under way (see table 3). Four large new-build pipelines, which are quite

rare in the U.S. nowadays, have been proposed with a combined natural gas takeaway capacity of 5.5 bcf/d. However,

we don't expect these projects to be operational until late 2015.

Table 3

Proposed Pipeline Projects

Project Company Capacity (mmcf/d) Propsed in-service date

Appalachian Gateway Dominion Resources Inc. 484 9/1/2012

Northeast Expansion Dominion Resources Inc. 200 2H2012


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Table 3

Proposed Pipeline Projects (cont.)

Northeast Supply Diversification Project Kinder Morgan Energy Partners L.P. 250 11/1/2012

Northern Access Expansion National Fuel Gas Co. 320 11/1/2012

TEAM 2012 Spectra Energy Corp. 200 2H2012

Philadelphia Lateral Expansion Spectra Energy Corp. 27 2H2012

MPP Project Kinder Morgan Energy Partners L.P. 240 11/1/2013

NorthEast Upgrade Project Kinder Morgan Energy Partners L.P. 637 11/1/2013

New Jersey-New York Expansion Spectra Energy Corp. 800 2H2013

Northeast Supply Link The Williams Cos. Inc. 250 11/1/2013

Northeast Connector The Williams Cos. Inc. 100 2014

Rockaway Delivery Lateral Project The Williams Cos. Inc. 647 2014

East Side Expansion Project NiSource Inc. 500 Late 2014

West Side Expansion Project NiSource Inc. 444 Late 2014

Rose Lake Expansion Kinder Morgan Energy Partners L.P. 230 11/1/2014

TEAM 2014 Spectra Energy Corp. 600 2H2014

Keystone Connector Dominion Resources Inc. TBD TBD

Ohio Pipeline Energy Network (Open) Spectra Energy Corp. 1000 2014/15

Commonwealth Pipeline UGI Corp., Inergy L.P., WGL Holdings Inc. 1200 2015

Nexus Pipeline Spectra Energy Corp., Enbridge Inc., DTE

Energy Co.

1000 Nov-15

Atlantic Access Williams Partners L.P. 2300 Dec-15

Leidy Southeast Expansion The Williams Cos. Inc. 800 Late 2015

Northeast Expansion Kinder Morgan Energy Partners L.P. 500-1700 2016/17

Source: Company Web sites, Standard & Poor’s.

More NGL Processing And Pipeline Infrastructure Will Be Needed

While dry gas production in northeast Pennsylvania has driven much of the play's growth to date the wide price

discrepancy between natural gas and NGLs has prompted E&P companies to shift their drilling activity toward the

NGL-rich (i.e., wet gas) areas in southwest Pennsylvania.

We estimate that based on current one-year futures strip prices ($3.50/mmBTU for Henry Hub natural gas, $92.50/bbl

for WTI crude oil, and assuming NGLs at 50% of WTI), internal rates of return for Marcellus wet gas would be over

30%, compared with around 10% returns for dry gas. Therefore, it's not surprising that producers are shifting rigs to

the wet gas areas of the Marcellus.

According to Bentek, current Marcellus NGL production is running at about 40 thousand barrels per day (mbbls/d),

and the company projects that output will increase to 250 mbbls/d in 2017. Because of limited ethane processing

capacity in Appalachia, the area is primarily producing NGLs such as propane and butane. These NGLs are either

consumed in local markets or trucked/railed out to other regions. Ethane, which requires a pipeline for transport, is for

the most part being rejected (i.e., left in the natural gas stream) and sold as natural gas (effectively boosting the volume

of natural gas produced). We believe the returns for wet gas will improve above 30% level once ethane infrastructure is


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built out and producers can strip out and sell the ethane separately.

Based on current NGL prices at Mt. Belvieu, we estimate that gas producers could increase their revenue for wet gas

versus dry gas by about $3.00/mcf for extracting propane and butane and gain another $0.50/mcf for stripping ethane.

Midstream companies are well aware of the need for additional infrastructure in Appalachia, and material processing

capacity additions and new ethane takeaway pipeline projects are currently underway. We expect these efforts to keep

essentially keep pace with local production increases. A few midstream companies are handling the build out of the

new infrastructure, and the developments are backed by relatively low-risk fee-based contracts. Gathering and

processing contracts typically have minimum volume commitments (such as Crestwood Midstream Partners L.P.'s

(B/Stable/--) recent deal with Antero Resources (B+/Stable/--)), which mitigates cash flow risk; although, pipelines

still need to transport higher volumes to generate adequate economic returns.

Beyond the scope of the signed contracts for these developments, which are moderate to long term in length (e.g., a

15-year, 275 mmcf/d gathering deal between subsidiaries of midstream company Boardwalk Pipeline Partners L.P.

(BBB/Stable/--) and producer Southwestern Energy Co. (BBB-/Stable/--)), recontracting risk could arise down the

road depending on the production success of the region.

We view the NGL pipeline projects as a positive for the prospects of the Marcellus shale because producers need

confidence that future volume flows will be handled before making capital investments. However, midstream

companies are typically seeking new projects and are almost always willing to lock in long-term cash flows. Currently

in the Marcellus, however, most E&P companies are rejecting ethane because of the region's lack of processing

capacity. That's because the natural gas stream can contain only a specified amount of ethane before it fails to meet

pipeline design specifications. This should change over time, though, given the list of processing projects being

contemplated, as new capacity will ultimately allow producers to capture incremental revenues per mcf produced as

they strip ethane and sell it separately.

Existing ethane takeaway pipelines are in heavy competition among one another due to the advantages that the

pipeline owners can obtain by leveraging existing pipeline infrastructure and available fractionation capacity. Project

costs are lower and timetables are shorter because of these pipeline companies' use of existing right-of-ways and

upgrades and conversions of existing lines. A few pipelines that will facilitate ethane takeaway to fractionators on the

Gulf Coast and Canada are forthcoming, while Kinder Morgan Energy Partners L.P. (BBB/Stable/A-2) and Spectra

Energy Corp. (BBB+/Stable/--) dropped a proposed JV ethane pipeline because it didn't receive sufficient shipper

interest. We list current ethane projects in table 4.

Table 4

Proposed Ethane Projects

Project Company Capacity (mbbls/d) Proposed in-service date

Mariner West Markwest Energy Partners L.P./Sunoco Logistics

Partners L.P.

50-65 Jul-13

Mariner East Markwest Energy Partners L.P./Sunoco Logistics

Partners L.P.

70 Mid-2013

Appalachia to Texas (ATEX) Enterprise Products Partners L.P. 190 1Q2014


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Table 4

Proposed Ethane Projects (cont.)

New ethane cracker in

Pennsylvania

Royal Dutch Shell PLC TBD 2017+

Source: Company Web sites, Standard & Poor's

Who Could Feel Pressure, And Who Stands To Benefit, From The DevelopmentOf The Marcellus?

We have identified two groups we believe stand to lose from the development of the Marcellus if they don't modify

their strategies to offset a potential increase in business risk or reduce debt to limit the impact from potential cash flow

declines on their financial risk profiles:

• Long-haul pipeline companies that transport gas to the Northeast that are unlikely or unable to take backhaul

volumes; and

• E&P companies producing natural gas in the Rockies and/or Canada that are currently transporting gas to the

Northeast.

Long-haul pipeline companies

Rockies Express Pipeline LLC (REX; BB/Stable/--): REX is being notably negatively affected by sustained compression

in the low basis spread environment and the potential recontracting risk related to a lessening need to ship gas out of

the Rockies all the way to its terminus in Clarington, Ohio. As such, we lowered our corporate credit rating on REX in

January 2012 to 'BB' from 'BBB-'. In addition to these factors, we acknowledged the company's somewhat aggressive

financial metrics. REX's recontracting risk could be high and cause substantially lower cash flow when the vast

majority of its contracts expire in 2019 (contracts on about 10% of capacity expire in late-2014). REX's contracted

transportation rate of about $1.05/mcf is dramatically above recent basis spreads on the route ranging from about

$0.10-$0.40/mcf. While the company could generate additional value by reversing the flow (east to west), we have

provided minimal credit at this point in our view on the company's credit quality unless contracts of a meaningful

nature occur.

TransCanada Pipeline Ltd. (A-/Stable/A-2): TransCanada is in the midst of a major rate restructuring application with

the National Energy Board for the Canadian Mainline. The pipeline has experienced declining throughput volumes

over the past several years from changes to the competitive environment, which has meant substantial increases in the

per-unit tolls it charges shippers to meet its regulated revenue requirement. Increasing gas supply from basins like the

Marcellus has contributed to the volume decline because it has displaced eastern demand for Western Canadian

Sedimentary Basin (WCSB) gas. Due to the regulated nature of the pipeline, we believe there is little near-term

business or financial profile risk; in the longer term, however, we believe two specific factors from increasing Marcellus

production could affect the pipeline's viability, and ultimately its approximate 40% contribution to consolidated

EBITDA in 2012. The first is the risk of displacement, whereby imported Marcellus production would be consumed

instead of volumes from the WCSB, thus exacerbating the shift from long-term firm transport to short term, which

increases toll variability. The second risk is bypass, whereby gas transmission companies/LDC's contract to import gas

on its network directly, bypassing the TCPL system entirely, which would result in higher tolls on the remaining


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lowered volumes. Both of these scenarios, if they materialize, will pressure tolls and TCPL's ultimate ability to earn a

return on and recovery of the capital invested in the mainline.

Maritimes & Northeast LLC (BBB-/Stable/--; U.S. pipeline) and Maritimes & Northeast L.P. (A/Stable/--; Canadian

pipeline): While not at risk in the near to medium term, the Maritimes & Northeast pipeline system routing from

Northeast Canada to the Boston area could be at risk in the long term. Increasing Marcellus supplies could be routed

to the Boston market, which would entail a shorter shipping distance and likely lower shipping tariff. This could

circumvent the need to import the traditional off-shore Canada supplies that have supported the pipeline. Capacity

looping projects, such as those by TGP, could extenuate this risk, albeit these projects and their associated planning,

permitting, and construction process takes years to execute. As such, the risk for Maritimes & Northeast exists in the

long term. Maritimes' U.S. debt comes due in the near term (2014) and is fully supported by existing contracts that

have an average contract life of roughly 20 years. On the Maritimes Canada system, the two tranches of debt (one is

economically defeased) come due in 2019, but ExxonMobil provides a backstop agreement for them that provide cash

flow support through the maturity of both debt issues.

Other long-haul gas pipelines to the Northeast: Recontracting risk and potentially declining volumes, especially on the

pipelines' southern zones, is a potential risk to cash flows in the near term. Abundant and rising production in close

proximity to the terminus of these pipeline routes is also a general concern. However, there are some mitigants. These

pipelines are increasing cash flows via looping and lateral projects in the region to meet producers' needs, which will

enhance their competitive positions. In addition, backhaul volumes to the south from the north are increasing. Overall,

we expect the impact on consolidated credit quality for each pipeline's owner to be minor given the relatively modest

size of the pipelines relative to each company's much larger asset bases. Some of the larger long-haul pipelines are

owned by:

• Dominion Resources Inc. (A/Stable/A-2)-Dominion Gas Transmission;

• Kinder Morgan Energy Partners L.P.-Tennessee Gas Pipeline;

• NiSource Inc. (BBB-/Stable/A-3)-Columbia Gas Transmission;

• Spectra Energy Corp.-Texas Eastern Transmission; and

• The Williams Cos. (BBB/Stable/--)-Transcontinental Gas.

Exploration and production companies

EnCana Corp. (BBB/Stable/--): About 25% of Canadian E&P company EnCana's production is in the U.S. Rockies, a

region that is already seeing its deliveries to Appalachia affected by Marcellus gas. EnCana is the largest firm capacity

holder on the Rockies Express pipeline, as it has 500 mmcf/d contracted through 2019. Given the minimal spread

between Appalachian and Rockies natural gas prices and the likely high transportation costs on REX (we estimate

about $1.05/mcf plus fuel charges), we believe EnCana is generating marginal economic returns on its natural gas

shipped along this pipeline. Importantly though, EnCana's REX commitment equates to just 15% of its total natural gas

production, so poor returns on just this amount are unlikely to move the overall rating. In addition, the company is

working to transition to a more oil and liquids-rich portfolio, and our stable outlook incorporates a successful

transition.

Bill Barrett Corp. (BB-/Negative/--): Bill Barrett is a U.S. E&P company focused exclusively in the Rocky Mountain

region. The company holds 25 mmcf/d of firm capacity on the Rockies Express pipeline, which equates to about 8% of


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its current total equivalent production. We estimate transportation costs on REX are about $1.05/mcf plus fuel

charges. Given the current minimal spread between Appalachian and Rockies natural gas prices, we estimate that Bill

Barrett is generating marginal economic returns on its natural gas shipped along the pipeline. However, Bill Barrett

also has 50 mmcf/d of firm capacity, contracted through mid-2021, on the Ruby pipeline, which runs from the Rockies

to the West Coast. Transportation costs on this line are much lower than on REX, which should allow Bill Barrett to

generate positive economic returns.

We have also identified two key groups of companies that we believe stand to benefit from future development of the

Marcellus:

• Midstream and pipeline companies that are building/expanding infrastructure in the region; and

• E&P companies that produce natural gas and NGLs in the region.

Midstream and pipeline companies

MarkWest Energy Partners L.P. (BB/Stable/--): MarkWest's strategy and growth plans are heavily influenced by its

suite of new projects throughout the midstream energy value chain in the Marcellus. We believe new projects in the

region will notably increase the company's cash flows and, relative to the debt expected to be incurred, will help

reduce its debt-to-EBITDA ratio. The new projects will also further diversify the company's cash flow stream. While

these are all credit positives for the company in the long term, risks related to construction and securing sufficient

capital to build-out its infrastructure capacity in 2012-2013 limit near-term ratings improvement. The company expects

to increase processing capacity at its Majorsville complex to 670 mmcf/d (up from 270 mmcf/d currently—half of

which was built in second-quarter 2011), another 200 mmcf/d is under construction at Sherwood Complex to be

completed in the second half of 2012 (with another 200 mmcf/d announced at the same complex for 2013, another

320 mmcf/d under construction in Mobley, W.V., and has 355 mmcf/d existing capacity at the Houston Complex

(which increased by 200 mmcf/d in second-quarter 2011. MarkWest is also a JV partner with Sunoco Logistics

Partners L.P. on two ethane takeaway pipelines.

Sunoco Logistics Partners L.P. (BBB-/Stable/--): Sunoco Logistics (SXL) is a JV partner in two key Marcellus ethane

takeaway pipelines that will help boost cash flows and further embed its competitive position in the Northeast. SXL's

growing NGL business, as well as its refined products and crude logistics assets, are a primary reason Energy Transfer

Partners L.P. (BBB-/Stable/--) announced the $5.3 billion acquisition of Sunoco Inc., SXL's general partner, in April

2012. We expect to rate SXL in-line with ETP when the transaction is complete, although SXL's integration into ETP is

key as it seeks to extend its scale and enhance its competitive position across the natural gas, oil, and NGL value

chain.

Iroquois Gas Transmission System L.P. (A-/Stable/--): Iroquois is strategically located within the Marcellus region and

stands to benefit from new infrastructure coming online over the next few years. While opportunities are limited in the

near term, projects targeted for 2015, such as the Constitution Pipeline (a JV between Williams Partners L.P.

(BBB/Stable/--) and Cabot Pipeline Holdings LLC) and Spectra Energy's Algonquin Incremental Market Project (AIM),

will enhance Iroquois' competitive position by offering additional supply diversity to its shippers. New interconnects

will allow Iroquois to replace disadvantaged volumes that TransCanada's Mainline currently supplies with cheaper

Marcellus gas.


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E&P companies

Range Resources Corp.: Range Resources is one of the largest natural gas and NGL producers in the Marcellus. Our

ratings incorporate Range's aggressive production growth plans from the Marcellus shale, which are now primarily

focused on the wet gas areas. Range's Marcellus production reached 500 mmcfe/d net at the end of the second quarter

of 2012, accounting for about 70% of its total equivalent production, and the company remains on track to reach 600

mmcfe/d by year-end (up from 300 mmcfe/d on average in 2011). The company holds over 750,000 net acres in the

Marcellus fairway, about 45% of which are in the liquids-rich southwest regions. The company is directing more than

85% of its $1.6 billion 2012 capital budget toward the Marcellus shale, which will be Range's primary growth driver for

the next several years. Range also holds 190,000 net acres in the Utica shale, which could add further liquids growth

over the medium term. Although Range's expected Marcellus production growth provides positive momentum for the

rating, our stable outlook also incorporates the company's high exposure to weak natural gas prices.

EQT Corp.: EQT is a diversified energy company exclusively focused on the Appalachian region. Our ratings on EQT

incorporate the company's aggressive production growth plans from the Marcellus shale, along with its development

of infrastructure to facilitate this growth. EQT's Marcellus production averaged 295 mmcf/d during the three months

ended March 31, 2012, which represented 50% of its total equivalent production. The company holds 530,000 net

acres prospective for the Marcellus, about 35% of which is in the liquids rich areas. While the company decided to

suspend drilling in its dry gas Huron shale acreage (also in Appalachia) in January due to low natural gas prices, it

continues to drill in the Marcellus as reduced service costs, better performance, and a liquids component keep drilling

in the play economic. EQT's midstream business is also benefitting from the development of the play, with the

company on track to add 445 mmcf/d of gathering capacity (85% of its year-end 2011 total) in 2012. The company

also plans to expand its Equitrans Pipeline this year by 70%, as this pipeline runs right through the Marcellus shale and

is operating near full capacity.

National Fuel Gas Co.: National Fuel Gas (NFG) is a diversified energy company primarily focused in the Appalachian

region. Our ratings on NFG primarily reflect the cash flow diversification and stability benefits of the company's

regulated pipeline and storage and utility businesses, which mitigate its exposure to higher-risk oil and gas E&P

activities through its subsidiary, Seneca Resources Corp. NFG has a long operating history in the Appalachian region

and holds one of the largest positions in our rated company universe in the Marcellus play—745,000 net acres. NFG's

net Marcellus production reached 200 mmcf/d in July 2012, accounting for over 65% of the company's total volumes.

As a result of low natural gas prices, NFG has reduced its fiscal 2013 cap-ex budget in the Marcellus. Despite a

reduced drilling program, the company still expects its Marcellus production to increase by 35% in fiscal 2013.

Although most of the company's acreage is in the dry gas window, and is therefore not currently generating strong

returns on the upstream side, the company is benefitting from midstream opportunities. NFG has nearly 2.0 bcf/d of

pipeline and gathering system expansions underway, which would more than double its current capacity in the area.

These expansions are primarily geared toward third-party volumes rather than the company's own use, given that its

dry gas economics are currently challenged.


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Related Criteria And Research

• How Horizontal Drilling And Fracking Have Reshaped The U.S. Energy Landscape, Sept 17, 2012

• The Shale Gas Boom Is Shaping U.S. Gas Pipelines' New Reality, June 5, 2012

• Standard & Poor's Raises Its U.S. Natural Gas Price Assumptions; Oil Price Assumptions Are Unchanged, July 24,

2012

• Standard & Poor's Revises Its Natural Gas Liquids Price Assumptions For 2012, 2013, And 2014, June 11, 2012

• Key Credit Factors: Criteria For Rating The Global Midstream Energy Industry, April 18, 2012

• Key Credit Factors: Global Criteria For Rating The Oil And Gas Exploration And Production Industry, Jan. 20, 2012

Additional Contact:

Jack R Kilgallen, New York (1) 212-438-3303; [email protected]


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News & Politics

S&P: How The Marcellus Shale Is Changing The Dynamics Of The U.S. Energy Industry