US Natural Gas Reservoir - Credit Suisse

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US Natural Gas Reservoir Connection Series

Premium Northeast gas market fizzles Our take: Breakneck Marcellus supply growth has caused a dramatic swing in NE

basis differentials relative to NYMEX (Henry Hub). Following the completion of the

first of many processing plants in June, daily basis differentials at the Dominion

South hub fell negative to lows of $0.60/Mcf. Based on our regional supply and

demand work, we expect wider NE disparities may continue indefinitely in

Appalachian gas markets, with longer-term differentials poised to be $0.25/Mcf to

$0.50/Mcf below NYMEX (versus the long-term premium of $0.20/Mcf). New York

and New England markets may be the next bubble to burst as they become

increasingly connected with Marcellus/Utica supplies.

Marcellus growth continues to outperform. Despite low levels of dry gas drilling

activity, natural gas production continues to climb, with YoY gas production up 3% or

2.0 Bcf/d. Pipeline flows suggest that total NE supply is up 4.0 Bcf/d, more than

offsetting declines in other key dry gas basins totaling 1.7 Bcf/d. Northeast supply is

bound to continue its growth pace, particularly with Utica shale activity ramping up.

Infrastructure has struggled to keep pace with supply, but a laundry list of

pipeline projects aim to increase connectivity with Appalachian production.

Over half of the 5.7 Bcf/d of pipeline capacity added in the US in 2012 was located

in the Northeast and could increase another 6.6 Bcf/d through 2014, helping to

further move Marcellus/Utica gas to market. In fact, 1.7 Bcf/d of pipeline

expansions alone target the New York/New Jersey markets in 2H13.

Natural gas processing capacity is adding to gas supplies, but may be

constrained by limited NGL demand and pipeline capacity. Natural gas

processing capacity in the wet-gas regions of the Marcellus and Utica is poised to

increase 2.4 Bcf/d and 2.1 Bcf/d of in 2013 and 2014 respectively, adding

substantially to gas and NGL supplies. However, limited northeast NGL demand

and ethane rejection is causing gas richness to exceed pipeline BTU

specifications in some areas. NGL pipeline capacity could increase nearly 1 mb/d

over the next three years to address this growing issue.

Meanwhile Northeast gas demand markets are transforming but not nearly

fast enough. With Northeast power demand only expected to see 450 MMcf/d of

cumulative gas demand growth through 2016, other options are needed to

synthetically create demand. Backhaul pipeline projects and access to US LNG

export terminals will help alleviate regional supply induced price pressures, but all

major projects go in service no earlier than 2H 2017.

Northeast basis markets, we think, will see sustained weakness. Over the

next 6-12 months, pipeline projects adding substantial import capacity to the

NJ/NY markets place TETCO M3, Transco Z6 (non-NY) and Transco Z6 NY at

additional risk to sell-off. For New England pricing points Algonquin and Iroquois,

the newly commissioned Deep Panuke offshore project in Nova Scotia and the

addition of 250 MMcf/d of pipeline capacity bringing Marcellus gas will help reduce

the size and occurrences of wintertime basis blowouts.

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[email protected]

13 August 2013

Securities Research& Analytics

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13 August 2013

US Natural Gas Reservoir 2

Table of Contents

Same old story on supply 3

Infrastructure – struggling to keep up with supply 7

Northeast gas demand options are limited until 2016 10

NE basis: Permanent dislocation or a short term anomaly? 11

Maps and complete project lists: 13

CS Supply Demand Model and Price Forecast 17

Pricing Trends and Trading Statistics 18

Supply 22

US Imports/Exports 26

US Gas Demand (Monthly) 27

US Gas Demand (Annual) 28

US Gas Demand (YTD) 30

Natural Gas Storage 32

North America Rig Count and Permits 33

North America Gas Basin-Level Trends 34

Competitive Fuel Sources 36

13 August 2013


Same old story on supply Exhibit 1 illustrates historical differential basis between Appalachia gas (Dominion South &

TCO) prices and NYMEX. Surging supply growth from the Marcellus Shale has caused a

dramatic swing in NE basis differentials relative to NYMEX (Henry Hub).

Exhibit 1: Appalachia differential (Average of Dominion South and TCO)

($/MMbtu)

1

Appalachia vs. NYMEX Differential

($0.4)

($0.2)

$0.0

$0.2

$0.4

$0.6

$0.8

$1.0

Feb

-06

Ju

n-0

6

Oc

t-0

6

Feb

-07

Ju

n-0

7

Oc

t-0

7

Feb

-08

Ju

n-0

8

Oc

t-0

8

Feb

-09

Ju

n-0

9

Oc

t-0

9

Feb

-10

Ju

n-1

0

Oc

t-1

0

Feb

-11

Ju

n-1

1

Oc

t-1

1

Feb

-12

Ju

n-1

2

Oc

t-1

2

Feb

-13

Ju

n-1

3

Appalachia - NYMEX Differential Average

3Q13 QTD Avg.Price differential

-$0.20 vs. $0.18 LTA

Source: Natural Gas Week, Credit Suisse

Exhibit 2 illustrates Lower 48 dry gas production implied by pipeline scrapes. Despite the

significant pullback in natural gas drilling activity, supply trends have been stubbornly sticky,

with YTD production through August up 2.0% or 1.3 Bcf/d. Meanwhile, YoY production

(August 2013 vs. August 2012) is up 3.1% or 2.0 Bcf/d.

Exhibit 2: US dry gas production

1

Dry Gas Production

53

.2

53

.9

54

.7

54

.3

54

.7

55

.5

55

.9

55

.5

48

.9 53

.6

55

.3

55

.5

55

.9

56

.6

56

.0

55

.8

55

.7

55

.7

55

.5

55

.3

53

.7

54

.5

54

.9

54

.1

54

.2

55

.5

56

.4

56

.1

56

.8

56

.3

56

.6

57

.6

57

.9

58

.2

58

.6

59

.2

58

.9

57

.7

60

.4

60

.8

61

.4

61

.1

61

.6

62

.2

62

.1

63

.0

63

.9

63

.6

63

.6

63

.1

63

.3

63

.3

63

.5

63

.4

63

.8

63

.3

63

.8

64

.6

65

.1

64

.9

64

.0

64

.3

64

.3

64

.8

64

.9

64

.6

65

.3

65

.2

10

20

30

40

50

60

70

Jan

-08

Ma

r-0

8

Ma

y-0

8

Ju

l-0

8

Se

p-0

8

No

v-0

8

Jan

-09

Ma

r-0

9

Ma

y-0

9

Ju

l-0

9

Se

p-0

9

No

v-0

9

Jan

-10

Ma

r-1

0

Ma

y-1

0

Ju

l-1

0

Se

p-1

0

No

v-1

0

Jan

-11

Ma

r-1

1

Ma

y-1

1

Ju

l-1

1

Se

p-1

1

No

v-1

1

Jan

-12

Ma

r-1

2

Ma

y-1

2

Ju

l-1

2

Se

p-1

2

No

v-1

2

Jan

-13

Ma

r-1

3

Ma

y-1

3

Ju

l-1

3

As of August 2013 Up 2.0% YTD (+1.27 Bcf/d) Up 3.1% Yr/Yr (+1.96 Bcf/d)

Source: Bentek Energy, Credit Suisse

13 August 2013


The key basin that continues to drive resilient production trends is the Marcellus Shale and

the Northeast more generally. Exhibit 3 and Exhibit 4 illustrate production trends in the

Marcellus relative to the remainder of the gas market. While production ex-Marcellus has

declined by 1.7 Bcf/d YoY, the Marcellus Shale has more than outweighed this decline,

growing 4.0 Bcf/d based on pipeline flows.

Exhibit 3: Northeast is keeping total supply afloat Exhibit 4: Northeast Supply—more than 12 Bcf/d

(Bcf/d) (Bcf/d)

0

5

10

15

20

25

30

35

40

45

50

Jan-10 Jan-11 Jan-12 Jan-13

Total Supply Ex-NE Supply NE Supply

0

2

4

6

8

10

12

14

Jan-05 Jan-06 Jan-07 Jan-08 Jan-09 Jan-10 Jan-11 Jan-12 Jan-13

Source: Bentek Energy, Credit Suisse Source: Bentek Energy, Credit Suisse

What has been driving significant increases in reserves and production has been

meaningful increases in Marcellus EURs per play, driven by sweet spot identification,

improved frac recipes, and the optimization of lateral lengths.

Since 2010, we estimate that average Marcellus EURs have increased from 3.9 to 6.6

Bcfe (69%).

Exhibit 5: Marcellus EURs

Marcellus Shale EURs

0.29 0.15 0.29 0.390.75

1.64

3.93

4.72

5.51

6.565

0.00

1.00

2.00

3.00

4.00

5.00

6.00

7.00

20

04

20

05

20

06

20

07

20

08

20

09

20

10

20

11

20

12

20

13

Bcfe

Source: HPDI, Credit Suisse estimates

13 August 2013


Improving ‘science’ is leading to bigger/better well results

Our estimates could prove conservative given the widespread use of Reduced Cluster

Spacing (RCS) and rotary steerables as we learned during our recent investor trip to

the Marcellus.

RCS completions (tighter spacing between fracs stages resulting in more perfs per lateral),

which was first discussed in early in 2012, has become almost universally adopted in the

Marcellus. Operators such as CNX have noted a 20% to 40% improvement in EURs after

15 months of production history. REXX reported that using ‘Super-Fracs’ (also RCS) on 20

wells in Butler County has also resulted in a flattening of the curve increasing EUR

estimates, and initial application of the completion technique in the Utica has resulted in

some of the best IP-rates on a lateral foot basis in the play. Operators are widely

implementing the technique across the basin with spacing varying from 150-225 feet

between stages.

Marcellus operators have also seen a big uptick in EURs from geo-steering and optimal

lateral placement. Rotary steerables enable producers to now keep 99% of the wellbore

within the targeted zone compared to 85% without the tool. In addition, the technology

allows for a sharper turn from the kick-off point to make a 90 degree turn; 500 feet vs. 1,000

ft, enabling the lateral to be exposed to an additional ~300 ft of net pay. These

improvements have enhanced well performance and effectively increased EUR’s by as

much as a 1 Bcf per 1,000 feet of lateral.

For example, Range Resources (RRC) raised their Southwest Pennsylvania dry gas EUR

by 63% to 12.2 Bcfe, while they raised their wet gas EUR by 41% to 12.3 Bcfe. Meanwhile,

the company estimates success with downspacing pilots to 500 acres, which would boost

their resources potential by an incremental 12 to 15 Tcfe.

Exhibit 6 - 9 illustrate the rigcount for the Marcellus as well as the key counties. Despite the

retrenchment in activity, improved well performance and rising productivity is more than

offsetting lower activity, which is yielding continued production strength.

Exhibit 6: Rich-gas rigs outnumber dry rigs today in the Marcellus

Exhibit 7: Pennsylvania rig counts by county

(rigs) (rigs)

0

20

40

60

80

100

120

140

160

Feb-11 Aug-11 Feb-12 Aug-12 Feb-13

Marcellus Total NE PA (Dry gas) SW PA (Wet-Gas)

-15

-10

-5

0

5

10

15

SU

SQ

UE

HA

NN

A

DO

DD

RID

GE

GR

EE

NE

LY

CO

MIN

G

WA

SH

ING

TO

N

WE

TZ

EL

BR

AD

FO

RD

HA

RR

ISO

N

WE

ST

MO

RE

LA

ND

BU

TL

ER

FA

YE

TT

E

MA

RS

HA

LL

FO

RE

ST

MA

RIO

N

OH

IO

WY

OM

ING

BA

RB

OU

R

CLE

AR

FIE

LD

TIO

GA

TY

LE

R

UP

SH

UR

Yoy delta Current Rig Count

Source: Baker Hughes, Credit Suisse Source: Baker Hughes, Credit Suisse

13 August 2013


Exhibit 8: Kickoff to TD in 5-6 days for 6000’ laterals Exhibit 9: Fewer rigs & quicker drill times = more

completions and higher productivities

Days from kickoff to TD versus directional feet drilled in Marcellus Monthly well completions per rig

Marcellus Productivity

0.0

1.0

2.0

3.0

4.0

5.0

6.0

Ja

n-0

4

Ma

y-0

4

Se

p-0

4

Ja

n-0

5

Ma

y-0

5

Se

p-0

5

Ja

n-0

6

Ma

y-0

6

Se

p-0

6

Ja

n-0

7

Ma

y-0

7

Se

p-0

7

Ja

n-0

8

Ma

y-0

8

Se

p-0

8

Ja

n-0

9

Ma

y-0

9

Se

p-0

9

Ja

n-1

0

Ma

y-1

0

Se

p-1

0

Ja

n-1

1

Ma

y-1

1

Se

p-1

1

Ja

n-1

2

Ma

y-1

2

Mo

nth

ly W

ell

Co

mp

leti

on

s p

er

Rig

Source: Rice Energy, Credit Suisse Source: HPDI, Smith Bits, Credit Suisse estimates

As a result of efficiencies and improving well performance, production per rig has increased

significantly, as illustrated in Exhibit 11

Exhibit 10: Time Series of Natural Gas Production Exhibit 11: Natural Gas Production per Rig

Gas Production (Bcf/ d)

0

1

2

3

4

5

6

7

8

9

0 12 24 36 48 60 72 84 96 108 120 132 144 156

Ga

s P

rod

ucti

on

(B

cf/

d)

Months

Barnett Fayetteville Marcellus Woodford Haynesville-TX/LA

Natural Gas Production per Rig

0

50,000

100,000

150,000

200,000

250,000

300,000

0 12 24 36 48 60 72 84 96 108 120 132 144 156

Ga

s P

rod

uc

tio

n p

er

Rig

Months

Barnett Fayetteville Marcellus Woodford Haynesville-TX/LA

Efficiency zone

Efficiency zone

MARCELLUS IS GETTING EFFICIENT!

Source: HPDI, Credit Suisse estimates Source: HPDI, Baker Hughes, Credit Suisse estimates

Exhibit 12 illustrates our Basin production model for the Marcellus. Note we expect for

supply growth to continue at a breakneck pace through 2016. Northeast supply is bound to

continue its growth trajectory, particularly with Utica shale activity ramping up.

13 August 2013


Exhibit 12: Marcellus Production Forecast Model

Monthly forecast for PA section of Marcellus shale in MMcf/d

Marcellus Production Forecast Model

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

11,000

12,000

13,000

14,000

Jan

-06

Ju

l-06

Jan

-07

Ju

l-07

Jan

-08

Ju

l-08

Jan

-09

Ju

l-09

Jan

-10

Ju

l-10

Jan

-11

Ju

l-11

Jan

-12

Ju

l-12

Jan

-13

Ju

l-13

Jan

-14

Ju

l-14

Jan

-15

Ju

l-15

Jan

-16

Ju

l-16

MM

cf/

d

Forecasted ProductionHistorical Production

Source: HPDI, Credit Suisse estimates

Infrastructure – struggling to keep up with supply

A number of pipeline expansion and processing plants additions should help alleviate many

of the supply bottlenecks stemming from supply growth in the Northeast. Shown in

Exhibit 13, over half of the 5.7 Bcf/d of the pipeline capacity added in the US in 2012 was

located in the Northeast and based on current plans could increase another 6.6 Bcf/d

through 2014 helping to further move Marcellus/Utica gas to market.

Exhibit 13: Half of all added capacity in 2012 and 2013 is in the NE

(Bcf/d)

0

10

20

30

40

50

60

1996 1998 2000 2002 2004 2006 2008 2010 2012 2014 2016

Northeast Total US

Announced , planned or under construction

Source: EIA, Credit Suisse

We expect the remaining pipeline expansions in 2013 to place downward pressure on

NY/NJ basis prices. Of note, the NJ-NY expansion project, Northeast Upgrade project and

the Northeast Supply Link Project (Exhibit 22) add nearly 1.7 Bcf/d of added supply to the

New Jersey and New York Markets.

13 August 2013


The Northeast Upgrade project, which will flow 636 MMcf/d of gas from the Tennessee

Gas Pipeline’s 300 line to Algonquin, coincides with the NJ-NY project which brings

800 MMcf/d of gas to Algonquin and TETCO to the NJ/NY areas including a delivery

point onto Con-Edison’s distribution system in Manhattan.

The Northeast Supply Link project alleviates bottlenecks on Transco’s Leidy Line in

Pennsylvania by expanding Transco’s existing system by 250 MMcf/d to provide firm

transportation to delivery points in New Jersey and New York.

Transco zone 6 (both NY and non-NY) as well as TETCO M3 should feel

downward pressure on basis over the next 6-12 months.

At the same time, natural gas processing additions are helping to alleviate rich-gas

supply bottlenecks. Natural gas processing capacity in the wet-gas regions of the

Marcellus and Utica aim to increase 2.4 Bcf/d and 2.1 Bcf/d of in 2013 and 2014

(Exhibit 14).

Exhibit 14: Appalachian processing capacity additions

(capacity in MMcf/d)

Start-up Date (ISD) Status Plant State County

Capacity

(MMcf/d)

3/5/2013 Online Mobley I, II WV Wetzel 320

5/1/2013 Online Majorsville III WV Marshall 200

5/25/2013 Online Cadiz I OH Harrison 125

5/30/2013 Online Natrium/404 - Phase I WV Marshall 200

5/30/2013 Online Sherwood II WV Doddridge 200

7/1/2013 New Build Kensington OH Columbiana 200

7/1/2013 Expansion Fort Beeler III WV Marshall 200

9/1/2013 Expansion Natrium/404 - Phase II WV Marshall 200

9/1/2013 Expansion Sherwood III WV Doddridge 200

10/1/2013 New Build Hickory Bend OH Mahoning 200

12/1/2013 Expansion Majorsville V WV Marshall 200

12/31/2013 Expansion Mobley III WV Wetzel 200

2013 2445

1/1/2014 New Build Seneca I OH Noble 200

1/1/2014 Expansion Seneca II OH Noble 200

1/1/2014 New Build Seneca Interim OH Noble 45

3/1/2014 Expansion Bluestone II PA Butler 120

3/1/2014 Expansion Majorsville IV WV Marshall 200

3/1/2014 Expansion Seneca III OH Noble 200

3/1/2014 New Build Oak Grove I WV Marshall 200

6/1/2014 New Build Leesville OH Carroll 200

6/1/2014 Expansion Sherwood IV WV Doddridge 200

6/1/2014 Expansion Bluestone III PA Butler 200

6/1/2014 Expansion Majorsville VI WV Marshall 200

6/1/2014 Expansion Cadiz II OH Harrison 200

2014 2165


But limited local NGL demand and takeaway capacity is threatening Northeast

pipeline specifications. The 200 MMcf/d Natrium processing plant in Northeast West

Virginia became operational in late June and due to poor processing economics is fully

rejecting ethane, electing to keep as much as possible in the gas stream. Since this time,

Texas Eastern has issued two critical notices to shippers as ethane (C2+) levels reached

levels higher than the specification of 12.5%. To alleviate this rich-gas issue, purchases of

dry gas from REX (at the REX/Clarington flow point) onto TETCO increased 350 MMcf/d to

dilute the elevated C2+ levels and keep nearby power plants operational (Exhibit 15). The

influx of gas has caused Dominion South basis prices to collapse to daily lows nearly

70 cents under henry hub while also pressuring nearby TCO hub prices as well.

13 August 2013


Exhibit 15: REX flows onto TCO increased when Natrium became operational

(weekly average MMcf/d)

-$0.60

-$0.50

-$0.40

-$0.30

-$0.20

-$0.10

$0.00

$0.10

$0.20

0

50,000

100,000

150,000

200,000

250,000

300,000

350,000

400,000

25-May 8-Jun 22-Jun 6-Jul 20-Jul 3-Aug

Rex/Clarington (lhs) Dom S

200 MMcf/dNatrium processing plant becomes operational

Source: Range Resources, Credit Suisse

Needed NGL pipeline capacity should help alleviate rich gas issues. To help relieve

the now increasing northeast NGL-supply, ethane, propane and y-grade (raw NGL mix)

pipeline export capacity out of the Northeast is expected to increase ~240 kb/d, 70 kb/d and

400 kb/d respectively over the next three years (see Exhibit 24 - Exhibit 26).

Mariner West: 50 kb/d ethane pipeline from Houston, PA to the existing Sunoco Logistics

pipeline at Vanport, PA for shipment to the Sarnia, Ontario ethane market. The project

became operational in July 2013.

ATEX Express: 190 kb/d ethane pipeline from Houston, PA to the Texas Gulf Coast

region. Once complete, it will have direct access to Enterprise Products NGL storage

complex in Mont Belvieu, TX. Target in-service date is 1Q14.

Mariner East: 70 kb/d propane pipeline from Houston, PA to Delmont, PA where it will

reach an interconnection with an existing Sunoco Logistics Pipeline to be transported to

Marcus Hook, PA with the ability to reach both local and international NGL markets. The

first stage of the project is estimated to be in service by 2H14 while an additional ethane

option is targeted for 1H15.

Bluegrass: 200 kb/d y-grade pipeline would send NGLs from Ohio/West

Virginia/Pennsylvania to the US Gulf coast to access fractionation capacity and

petrochemical market with additional access to storage facilities. The project has the

potential to increase capacity to 400 kb/d and is projected to go in-service during 2H15

Markwest Energy/Kinder Morgan JV project: Recently announced 200 kb/d y-grade

pipeline directly competes with the Bluegrass project and sends NGLs from the

Marcellus/Utica Shales to the Gulf Coast. The raw mix pipeline, like Boardwalk, has the

option of being expanded to 400 kb/d and has a target in-service date of 2H15.

13 August 2013


Northeast gas demand options are limited until 2016

The Northeastern US, like much of the North American gas market, has generally increased

its reliance upon natural gas to meet its power, industrial and residential/commercial needs.

In fact, over the period from January to July from 2005-2013, as average US demand flows

increased ~12 Bcf/d, Northeastern US directed flows accounted for 20% of that growth or

2.6 Bcf/d. While impressive on its own, simultaneous supply gains of nearly 6 Bcf/d out of

the Marcellus Shale more than outweighed improvements in demand and only thanks to an

exceptionally cold spring (soon to be partially offset by a mild end of summer) is 2013

holding on to nearly 1 Bcf/d of gains yoy.

Most importantly, with Northeast gas supply reaching 12 Bcf/d it is nearly 100% self-

sufficient during the summertime and requires significantly less imports from the South,

Midcon and Canada to meet heating demand during the peak winter months.

Exhibit 16: Northeast annual natural gas demand Exhibit 17: Northeast seasonal ranges

(Bcf/d January through July) (Bcf/d)

9

10

11

12

13

14

15

16

2005 2006 2007 2008 2009 2010 2011 2012 2013

7

9

11

13

15

17

19

21

23

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

5-year range 2013 2012


It is well documented how growth in the gas power sector has led the lions share in total US

gas demand gains over the past decade. And while we think the power sector will continue

to be an important driver for the US and Northeast – particularly before LNG exports and

new manufacturing later this decade – cumulative power demand gains in the Northeast are

likely to be less than 0.5 from 2014 through 2016, less than many anticipate.

Wind additions and negative demand growth from energy efficiency targets

(A Thought... Energy Efficiency) outpace coal retirements until 2016. Factoring all the

moving parts of Northeast power demand, only 450 MMcf/d of gas demand growth is

expected through 2016. Using A Deep(er) Dive into Gas Demand from the Power Sector as

the backbone for the analysis, we conclude that:

PJM accounts for the entire 450 MMcf/d of growth as NEISO growth of 42 MMcf/d is

offset by 42 MMcf/d of declining demand in NYISO.

Coal retirements provide the largest uplift to demand growth in PJM where 269 MMcf/d

are due to be discharged. NYISO and NEISO are not anticipated to see any coal

retirements through 2016.

The installation of wind capacity offsets 155 MMcf/d in cumulative demand growth by

2016 with 114 MMcf/d located in PJM.

NYISO and NEISO see a cumulative uplift in gas demand of 216 MMcf/d in 2016 due to

risks of nuclear plant retirements, namely the Vermont Yankee and Ginna plants.

https://plus.credit-suisse.com/r/aFkzz1

https://plus.credit-suisse.com/r/LvblaA

13 August 2013


Exhibit 18: Power gas demand growth by ISO Exhibit 19: Wind additions and efficiency gains

restrict power demand growth in the Northeast

(cumulative starting in 2014 in MMcf/d per year)

-200

-100

0

100

200

300

400

500

600

2014 2015 2016

PJM NYISO NEISO Cumulative Net

-400

-200

0

200

400

600

800

2014 2015 2016

Gas Additions Wind Additions Nuclear Shifts

Demand Increases Coal Retirements Net Gas growth

Source: Credit Suisse Source: Credit Suisse

NE basis: Permanent dislocation or a short term anomaly?

Northeast basis markets are set for a period of sustained weakness

As US Northeast supplies have continued their aggressive growth trends, the once

Northeast premium market has all but dissipated today. Shown in Exhibit 20, average basis

prices from the major NE trading hubs has fallen $0.35 YoY from an $0.11 premium to

Henry Hub last August to a $0.24 discount to Henry hub today.

As highlighted above, oversupply and pipeline spec issues stemming from wet-gas

production growth in Northwestern PA have led to heavy discounts at Dominion South as

well as nearby TCO pricing points.

Given the number of pipeline projects adding import capacity to the NJ/NY markets over

the next 6-12 months, TETCO M3, Transco Z6 (non-NY) and Transco Z6 NY may be next

to see sustained pricing discounts to Henry Hub.

New England markets see two minor projects pipeline bringing ~250 MMcf/d of capacity

while the recently started 300 MMcf/d Deep Panuke project in Nova Scotia may help

reduce occurrences of seasonal basis blowouts at Algonquin City gate.

Exhibit 20: Northeast basis prices have considerably weakened

($/MMbtu)

-$1.00

-$0.50

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

Apr-12 Jun-12 Aug-12 Oct-12 Dec-12 Feb-13 Apr-13 Jun-13 Aug-13

TETCO M3 Transco Z6 Non-NY Transco Z6 NYDominion S TCO AlgonquinNE Average

Source: the BLOOMBERG PROFESSIONAL™ service, Credit Suisse

13 August 2013


Backhauls to the rescue? With limited need for historically important Northeast pipeline

imports from the Gulf Coast, Midcontinent and the Rockies, a number of physical backhaul

pipelines have been announced to alleviate growing supply pressures. The announced

projects are unique because they aim to move physical gas along pipes in reverse direction

from what typically had been seen, something that has in recent times been done using a

financial agreement. We think this indicates a desire by producers to find a permanent

solution to what is likely to be acute oversupply in the Northeast gas market.

Texas Eastern Transmission Gulf Markets Expansion: 1 Bcf/d from NE to TX and LA, in

service 2H 2017.

Tennessee Gas pipeline’s Southwest Louisiana supply project: 1 Bcf/d moves gas to

Cameron Interstate Pipeline, the header system for the Cameron LNG terminal in

Cameron Parish, Louisiana starting 2H 2017.

Columbia gas transmission: already backhauls gas from KY to LA to serve storage hubs

and growing industrial demand in the Gulf region.

Kinder Morgan’s Elba Express Pipeline: Held open season to move 650 MMcf/d north to

south as well as to its proposed LNG export terminal at the Georgia terminal. Capacity

would phase in June 1 2016 and April 1, 2019.

The Rockies Express (REX) pipeline announced a physical backhaul agreement in July

with an unnamed Utica producer sending 200 MMcf/d of Utica gas to Midcon. An

increasing number of Marcellus/Utica producers have voiced desires to turn REX into a

bidirectional pipeline.

13 August 2013


Maps and complete project lists:

Exhibit 21: Major Interstate Northeast Pipeline Infrastructure Map

Source: Energy Velocity, Credit Suisse

13 August 2013


Exhibit 22: Northeast pipeline project list Project Name Pipeline Operator Name Project Type Status Completed Date Year In Service Date Region(s) Additional Capacity (MMcf/d)

2011 system expansion Eastern Shore Natural Gas Expansion Completed 2012 Northeast 6.25

Cecil County Expansion Eastern Shore Natural Gas Expansion Completed 2012 Northeast 4.07

Appalachian Gateway Project Dominion Transmission New Pipeline Completed 9/4/2012 2012 Northeast 484.26

Northeast Expansion Project Dominion Transmission Expansion Completed 10/31/2012 2012 Northeast 200

Inergy Marc I Hub Line Project Inergy Midstream, LLC Expansion Completed 11/14/2012 2012 Northeast 555

TETCO TEAM 2012 Expansion Texas Eastern Transmission Expansion Completed 10/31/2012 2012 Northeast 200

Bayonne Delivery Lateral Project Transcontinental Gas Pipe Line Lateral Completed 4/4/2012 2012 Northeast 250

Northern Access Expansion

Project National Fuel Gas Supply Corp Expansion Completed 10/31/2012 2012 Northeast 320

Line N 2012 Expansion National Fuel Gas Supply Corp Expansion Completed 10/31/2012 2012 Northeast 150

Philadelphia Lateral Expansion

Project Texas Eastern Transmission Expansion Completed 10/18/2012 2012 Northeast 27

Station 230C Project Tennessee Gas Pipeline Co Expansion Completed 10/16/2012 2012 Northeast 320

Northeast Supply Diversification

Project Tennessee Gas Pipeline Co Expansion Completed 10/19/2012 2012 Northeast 250

Sunrise Project Equitrans New Pipeline Completed 7/19/2012 2012 Northeast 313.56

Ellisburg to Craigs Project Dominion Transmission Lateral Completed 10/30/2012 2012 Northeast 250

2012 3,539

Hancock compressor project Millennium Pipeline Expansion Approved 2013 Northeast 107.5

Tioga County Extension Phase II Empire Pipeline Expansion Announced 2013 Northeast 260

Greenspring Expansion Project Eastern Shore Natural Gas Co Expansion Construction 2013 Northeast 15

Northeast Upgrade Project Tennessee Gas Pipeline Co Expansion Construction 2013 Northeast 636

Minisink Compressor Project Millennium Pipeline Expansion Completed 2013 Northeast 225

NJ-NY Project Spectra Energy Expansion Construction 2013 Northeast 800

Mid-Atlantic Connector

Expansion Transcontinental Gas Pipe Line Expansion Construction 2013 Northeast 142

MPP Project Tennessee Gas Pipeline Co Expansion Approved 2013 Northeast 240

Northeast Supply Link Project Transcontinental Gas Pipe Line Expansion Construction 2013 Northeast 250

Tioga Area Expansion Project Dominion Transmission Expansion Construction 2013 Northeast 270

Sabinsville to Morrisville Project Dominion Transportation Inc Expansion Applied 2013 Northeast 92

North-South II Capacity

Expansion and Extension Inergy LP Expansion Announced 2013 Northeast 325

Line MB extension phase 1 Columbia Gas Transmission Expansion Filed 2013 Northeast

2013 3,363

Line MB extension phase 2 Columbia Gas Transmission Expansion Filed 2014 Northeast

Transco power plant link Transcontinental Gas Pipe Line Lateral Announced 2014 Northeast

Downeast LNG Lateral Downeast LNG LLC Lateral Applied 2014 Northeast 500

Iroquois NY Marc Project Iroquois Pipeline Co New Pipeline Announced 2014 Northeast 500

Transco Rockaway Delivery

Project Transcontinental Gas Pipe Line New Pipeline Pre-Filed 2014 Northeast 647

TETCO TEAM 2014 Expansion Texas Eastern Transmission Expansion Pre-filed 2014 Northeast 600

Northeast Connector WILLIAMS Expansion Announced 2014 Northeast 100

VEPCO-Warren County Project Columbia Gas Transmission Expansion Approved 2014 Northeast 246

West Side Expansion Project

NiSource Gas Transmission &

Storage Expansion Announced 2014 Northeast 250

Texas Eastern Natrium Lateral

Project Texas Eastern Transmission Lateral Announced 2014 Northeast 400

2014 3,243 Source: EIA, Credit Suisse

13 August 2013


Exhibit 23: Marcellus and Utica gas processing additions

Source: Markwest, Credit Suisse

Exhibit 24: Mariner West Exhibit 25: Mariner East I and II

Source: Credit Suisse Source: Credit Suisse

13 August 2013


Exhibit 26: ATEX Express pipeline

Source: Enterprise Products, Credit Suisse

13 August 2013


CS Supply Demand Model and Price Forecast

Exhibit 27: US Natural Gas Supply/Demand Model

(Bcf/d)

(Bcfd) 2010 2011 2012 Q1/2013 Q2/2013 Q3/2013 Q4/2013 2013 Q1/2014 Q2/2014 Q3/2014 Q4/2014 2014 2015

Marketed Gas Production 61.3 65.8 69.2 69.3 70.1 70.5 70.9 70.2 71.3 71.9 72.4 73.2 72.2 74.6

Y-o-Y 2.0 4.5 3.4 0.5 1.2 1.4 1.1 1.0 2.0 1.8 1.9 2.2 2.0 2.4

Y-o-Y% 3.4% 7.4% 5.1% 0.7% 1.7% 2.0% 1.5% 1.5% 2.9% 2.6% 2.7% 3.1% 2.8% 3.4%

Dry Gas Production 58.4 62.7 65.7 65.8 66.6 67.2 67.6 66.8 67.9 68.4 69.0 69.7 68.7 71.0

Y-o-Y 1.9 4.3 3.0 0.4 1.1 1.4 1.2 1.0 2.1 1.9 1.8 2.1 2.0 2.3

Y-o-Y% 3.3% 7.4% 4.8% 0.6% 1.6% 2.1% 1.8% 1.6% 3.1% 2.8% 2.7% 3.1% 2.9% 3.4%

Conventional 31.9 31.2 32.9 31.4 32.1 32.0 31.9 31.9 31.6 31.5 31.3 31.3 31.4 31.1

Y-o-Y -2.6 -0.8 1.7 -1.8 -0.8 -0.9 -0.7 -1.0 0.2 -0.6 -0.7 -0.6 -0.4 -0.3

Y-o-Y% -7.4% -2.4% 5.5% -5.3% -2.3% -2.7% -2.2% -3.1% 0.7% -1.9% -2.1% -2.0% -1.3% -0.9%

Offshore (GOM) 6.3 5.1 4.3 4.2 4.0 3.9 3.8 4.0 3.7 3.7 3.6 3.6 3.6 3.4

Y-o-Y -0.6 -1.2 -0.9 -0.5 -0.2 0.0 -0.4 -0.3 -0.4 -0.4 -0.3 -0.2 -0.3 -0.2

Y-o-Y% -8.0% -18.7% -16.6% -10.2% -5.2% -1.1% -10.2% -6.8% -10.5% -9.1% -7.7% -6.3% -8.5% -5.8%

Unconventional 21.9 28.5 32.0 33.8 34.2 34.6 35.2 34.4 36.0 36.7 37.5 38.3 37.1 40.0

Y-o-Y 4.2 6.5 3.6 2.7 2.5 2.3 2.2 2.4 2.2 2.5 2.8 3.1 2.7 2.9

Y-o-Y% 24.0% 29.9% 12.5% 8.8% 7.8% 7.1% 6.7% 7.6% 6.5% 7.4% 8.2% 8.8% 7.7% 7.9%

Barnett 5.0 5.9 6.0 5.8 5.6 5.6 5.6 5.6 5.6 5.7 5.8 6.0 5.8 6.5

Y-o-Y 0.2 0.9 0.1 -0.3 -0.4 -0.4 -0.3 -0.4 -0.2 0.0 0.2 0.5 0.1 0.7

Y-o-Y% 3.5% 17.6% 1.4% -5.0% -7.2% -7.3% -5.2% -6.2% -3.3% 0.2% 4.0% 8.1% 2.2% 12.3%

Cana-Woodford 1.3 1.1 1.1 1.1 1.0 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1

Y-o-Y 0.0 -0.2 0.0 -0.1 -0.1 -0.1 0.0 -0.1 0.0 0.0 0.0 0.0 0.0 0.0

Y-o-Y% 1.3% -14.2% 2.7% -5.4% -6.7% -5.7% -2.3% -5.0% 1.4% 4.3% 4.6% 3.7% 3.5% 2.0%

Eagle Ford 0.3 1.0 2.1 2.9 3.2 3.4 3.6 3.3 3.8 4.0 4.2 4.3 4.1 4.7

Y-o-Y 0.2 0.8 1.1 1.3 1.3 1.2 1.1 1.2 0.9 0.8 0.7 0.7 0.8 0.6

Y-o-Y% 486.1% 274.4% 102.6% 80.0% 68.6% 52.5% 41.1% 58.1% 29.5% 23.7% 21.4% 19.4% 23.2% 15.8%

Fayetteville 2.1 2.6 2.7 2.9 2.8 2.7 2.7 2.8 2.7 2.7 2.6 2.6 2.6 2.7

Y-o-Y 0.7 0.5 0.2 0.2 0.1 0.0 -0.1 0.0 -0.1 -0.2 -0.1 -0.1 -0.1 0.0

Y-o-Y% 48.1% 22.7% 6.5% 7.6% 2.5% -0.9% -2.2% 1.7% -5.2% -5.5% -4.3% -3.0% -4.5% 1.2%

Haynesville 4.1 6.9 6.0 5.2 5.0 4.9 4.9 5.0 5.0 5.1 5.1 5.1 5.1 5.3

Y-o-Y 2.7 2.8 -0.9 -1.6 -1.2 -0.7 -0.4 -1.0 -0.2 0.1 0.2 0.2 0.1 0.2

Y-o-Y% 184.8% 66.8% -12.8% -23.2% -19.9% -13.0% -8.0% -16.5% -3.8% 1.1% 3.6% 4.3% 1.2% 4.9%

Marcellus 1.0 2.8 5.7 7.4 7.8 8.2 8.6 8.0 8.9 9.3 9.6 10.0 9.5 10.8

Y-o-Y 0.7 1.8 2.8 2.8 2.6 2.1 1.8 2.3 1.6 1.5 1.4 1.4 1.5 1.4

Y-o-Y% 259.6% 184.8% 100.4% 62.7% 48.4% 34.7% 26.1% 40.9% 21.4% 18.6% 17.0% 16.0% 18.1% 14.7%

Mississippian 0.2 0.2 0.2 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3

Y-o-Y 0.0 0.0 0.0 0.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Y-o-Y% -0.6% -3.8% 25.1% 35.5% 19.8% 17.6% -5.3% 14.9% 2.0% 4.9% 6.2% 6.5% 4.9% 5.9%

Denver-Julesburg 0.8 0.8 0.8 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.6 0.6 0.6 0.6

Y-o-Y 0.0 0.1 0.0 -0.1 -0.1 -0.1 -0.1 -0.1 -0.1 -0.1 -0.1 -0.1 -0.1 -0.1

Y-o-Y% 0.6% 10.2% -2.5% -14.4% -13.0% -11.7% -10.6% -12.5% -9.7% -9.4% -9.2% -8.9% -9.3% -8.1%

Niobrara 0.0 0.0 0.1 0.2 0.2 0.3 0.3 0.2 0.3 0.4 0.5 0.5 0.4 0.6

Y-o-Y 0.0 0.0 0.1 0.1 0.1 0.1 0.2 0.1 0.2 0.2 0.2 0.2 0.2 0.2

Y-o-Y% #DIV/0! 1733.3% 274.4% 92.3% 101.8% 110.9% 108.3% 104.3% 90.9% 83.0% 76.7% 71.2% 79.1% 52.0%

Permian 4.7 4.4 4.6 4.7 4.8 4.8 4.8 4.8 4.9 4.9 5.0 5.0 4.9 4.6

Y-o-Y -0.4 -0.3 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.1 0.1 0.1 0.2 -0.4

Y-o-Y% -7.9% -5.8% 3.8% 4.0% 4.1% 3.5% 3.6% 3.8% 4.2% 3.1% 2.8% 2.8% 3.2% -7.5%

Granite Wash 2.4 2.6 2.6 2.7 2.6 2.6 2.7 2.7 2.7 2.7 2.7 2.8 2.7 2.8

Y-o-Y 0.2 0.2 0.0 0.1 0.1 0.0 0.0 0.0 0.0 0.1 0.1 0.1 0.1 0.1

Y-o-Y% 6.7% 7.7% -0.5% 3.8% 2.0% 0.8% -1.0% 1.4% -0.2% 3.0% 3.7% 3.7% 2.6% 2.8%

Canadian Imports (Net) 7.0 6.0 5.4 5.0 4.9 5.0 4.5 4.9 4.7 4.6 4.8 4.4 4.6 4.3

Y-o-Y -0.1 -1.0 -0.5 -0.4 -0.7 -1.0 -0.2 -0.6 -0.4 -0.3 -0.2 -0.2 -0.3 -0.3

Y-o-Y% -1.2% -14.2% -8.9% -7.7% -12.9% -17.2% -3.3% -10.7% -7.2% -5.5% -4.8% -3.5% -5.3% -5.6%

Mexican Exports (Net) -0.8 -1.4 -1.7 -2.1 -2.0 -2.4 -2.3 -2.1 -2.5 -2.7 -3.1 -3.1 -2.8 -3.6

Y-o-Y 0.0 -0.5 -0.3 -0.7 -0.3 -0.5 -0.6 -0.4 -0.4 -0.7 -0.7 -0.7 -0.7 -0.7

Y-o-Y% -2.3% 63.6% 24.5% 48.4% 15.1% 26.4% 32.4% 25.2% 20.1% 37.2% 30.3% 31.0% 34.2% 25.6%

LNG Imports (Net) 1.0 0.8 0.4 0.4 0.2 0.3 0.2 0.3 0.3 0.1 0.2 0.2 0.2 -0.1

Y-o-Y -0.1 -0.2 -0.4 -0.1 -0.1 -0.2 -0.1 -0.1 -0.1 -0.1 -0.1 -0.1 -0.1 -0.3

Y-o-Y% -12.3% -24.4% -47.3% -25.0% -31.3% -39.3% -30.5% -31.6% -30.5% -30.5% -30.5% -30.5% -30.5% -174.9%

Total Supply 68.4 71.2 73.3 72.6 73.2 73.4 73.4 73.2 73.7 73.9 74.3 74.6 74.1 75.2

Y-o-Y 1.8 2.8 2.1 -0.7 0.1 -0.4 0.2 -0.1 1.1 0.8 0.8 1.3 0.9 1.1

Y-o-Y% 2.7% 4.0% 3.0% -1.0% 0.2% -0.5% 0.3% -0.1% 1.5% 1.0% 1.1% 1.7% 1.2% 1.5%

Industrial 18.7 18.9 19.5 21.7 19.2 18.6 20.6 20.0 22.1 19.9 19.2 21.4 20.7 21.3

Y-o-Y 1.8 0.2 0.6 1.0 0.5 0.0 0.5 0.5 0.5 0.8 0.6 0.8 0.6 0.6

Y-o-Y% 10.7% 1.1% 3.1% 5.0% 2.5% 0.0% 2.7% 2.6% 2.1% 3.9% 3.1% 3.7% 3.2% 3.0%

Electric Power 20.2 20.7 24.9 20.0 21.3 27.4 19.4 22.0 18.6 19.9 26.0 18.0 20.6 21.2

Y-o-Y 1.4 0.5 4.2 -1.7 -5.3 -4.1 -0.5 -2.9 -1.4 -1.4 -1.4 -1.4 -1.4 0.6

Y-o-Y% 7.5% 2.5% 20.4% -7.9% -20.0% -13.0% -2.7% -11.7% -7.1% -6.7% -5.2% -7.3% -6.4% 3.0%

Res/Comm 21.7 21.7 19.4 40.1 13.3 7.5 27.6 22.1 35.4 12.9 7.5 27.3 20.8 20.7

Y-o-Y 0.0 -0.1 -2.3 7.4 1.6 -0.5 2.3 2.7 -4.7 -0.4 0.0 -0.3 -1.3 -0.1

Y-o-Y% -0.1% -0.2% -10.4% 22.5% 14.0% -6.7% 9.3% 13.9% -11.7% -3.1% -0.2% -1.0% -6.1% -0.3%

Other (Lease Fuel, Pipeline Distribution) 5.5 5.6 5.9 6.4 5.7 5.9 6.1 6.0 6.6 5.8 6.0 6.3 6.2 6.4

Y-o-Y 0.0 0.1 0.3 0.2 0.0 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2

Y-o-Y% 0.8% 2.5% 4.7% 3.6% 0.8% 3.0% 3.0% 2.6% 3.0% 3.0% 3.0% 3.0% 3.0% 3.0%

Total Demand 66.1 66.9 69.7 88.2 59.4 59.4 73.7 70.2 82.7 58.5 58.7 72.9 68.2 69.6

Y-o-Y 3.2 0.8 2.8 6.9 -3.2 -4.5 2.5 0.5 -5.5 -0.9 -0.7 -0.7 -1.9 1.4

Y-o-Y% 5.1% 1.2% 4.2% 8.5% -5.1% -7.0% 3.6% 0.6% -6.2% -1.5% -1.2% -1.0% -2.8% 2.0%

Source: Bentek Energy, EIA, HPDI, Credit Suisse Commodities Research

13 August 2013


Pricing Trends and Trading Statistics

Exhibit 28: Natural gas futures chart

($/Mmbtu)

$3.4

6

$3.3

1

$3.3

4 $3.4

7

$3.6

5

3.7

27

3.7

29

3.6

92

$3.7

4

$3.7

4

$3.7

0

$3.6

5

$3.6

7

$3.7

3

$3.7

4

$3.7

7

$3.7

6

$3.7

8

$3.8

6

$4.0

3

$4.1

2

$4.1

1

$4.0

6

$3.8

9

$3.8

9

$3.8

8

$3.9

1

$3.9

3

$3.9

3

$3.9

8

$4.0

3

$4.2

3

$2.50

$2.70

$2.90

$3.10

$3.30

$3.50

$3.70

$3.90

$4.10

$4.30

$4.50

FY 2013: $3.59 FY 2014: $3.76 FY 2015: $3.99

Source: Credit Suisse, the BLOOMBERG PROFESSIONAL™ service

Exhibit 29: Day ahead gas price by major US trading hub – Pricing as of 8-9-13

($/Mmbtu)

Source: Energy Velocity, ICE, Credit Suisse

13 August 2013


Exhibit 30: NYMEX Spot, futures, and CS forecast Exhibit 31: NYMEX futures curve

($/Mmbtu) ($/Mmbtu)

$2.0

$2.5

$3.0

$3.5

$4.0

$4.5

$5.0

12/1/201512/1/201412/1/201312/1/201212/1/2011

NG Actual NG Quarterly Current Futures Forecast

$3.20

$3.40

$3.60

$3.80

$4.00

$4.20

$4.40

$4.60

$4.80

$5.00

Sep-13 Mar-14 Sep-14 Mar-15 Sep-15 Mar-16 Sep-16 Mar-17 Sep-17

Current Last week Last month 6 months

Source: Credit Suisse Commodities Research, the BLOOMBERG PROFESSIONAL™ service Source: Credit Suisse, the BLOOMBERG PROFESSIONAL™ service

Exhibit 32: NYMEX nat gas futures and options: disaggregated CFTC data

Exhibit 33: NYMEX nat gas 30-day realized and implied volatilities

-200,000

-100,000

0

100,000

200,000

300,000

400,000

500,000

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

Jan-11 May-11 Sep-11 Jan-12 May-12 Sep-12 Jan-13 May-13

NG1 MM Net Length (rhs) Producer Net Length (rhs)

0

20

40

60

80

100

120

140

Jan-09 Jul-09 Jan-10 Jul-10 Jan-11 Jul-11 Jan-12 Jul-12 Jan-13 Jul-13

30D Vol Implied Vol

Source: Credit Suisse, the BLOOMBERG PROFESSIONAL™ service Source: Credit Suisse, the BLOOMBERG PROFESSIONAL™ service

Exhibit 34: US natural gas composite spot prices

($/Mmbtu)

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Average 1Q 2Q 3Q 4Q

1996 $2.34 $3.27 $2.51 $2.24 $2.03 $2.20 $2.33 $1.96 $1.66 $2.06 $2.68 $3.66 $2.41 $2.71 $2.16 $1.98 $2.80

1997 $3.46 $2.37 $1.72 $1.83 $2.03 $2.07 $2.03 $2.24 $2.64 $2.85 $3.08 $2.22 $2.38 $2.52 $1.98 $2.30 $2.72

1998 $2.02 $2.02 $2.11 $2.30 $2.07 $1.99 $2.13 $1.79 $1.78 $1.85 $1.95 $1.64 $1.97 $2.05 $2.12 $1.90 $1.81

1999 $1.75 $1.66 $1.64 $1.93 $2.14 $2.16 $2.12 $2.62 $2.50 $2.53 $2.41 $2.38 $2.15 $1.68 $2.08 $2.41 $2.44

2000 $2.26 $2.50 $2.62 $2.87 $3.26 $4.16 $3.97 $4.13 $4.82 $4.95 $5.20 $8.12 $4.07 $2.46 $3.43 $4.31 $6.09

2001 $8.72 $5.63 $5.01 $5.05 $4.00 $3.52 $2.96 $2.83 $2.09 $2.28 $2.31 $2.21 $3.88 $6.45 $4.19 $2.63 $2.27

2002 $2.14 $2.11 $2.74 $3.16 $3.24 $3.01 $2.92 $2.87 $3.13 $3.69 $3.86 $4.35 $3.10 $2.33 $3.14 $2.97 $3.97

2003 $5.15 $6.91 $7.14 $4.94 $5.48 $5.63 $4.87 $4.88 $4.46 $4.50 $4.33 $5.88 $5.35 $6.40 $5.35 $4.74 $4.90

2004 $5.90 $5.11 $5.28 $5.62 $6.17 $6.11 $5.82 $5.37 $4.84 $5.97 $5.81 $6.58 $5.72 $5.43 $5.97 $5.34 $6.12

2005 $2.14 $2.11 $2.74 $3.16 $3.24 $3.01 $2.92 $2.87 $3.13 $3.69 $3.86 $4.35 $3.10 $2.33 $3.14 $2.97 $3.97

2006 $5.15 $6.91 $7.14 $4.94 $5.48 $5.63 $4.87 $4.88 $4.46 $4.50 $4.33 $5.88 $5.35 $6.40 $5.35 $4.74 $4.90

2007 $5.90 $5.11 $5.28 $5.62 $6.17 $6.11 $5.82 $5.37 $4.84 $5.97 $5.81 $6.58 $5.72 $5.43 $5.97 $5.34 $6.12

2008 $7.83 $8.30 $9.03 $9.86 $10.47 $11.97 $10.81 $7.83 $6.75 $5.87 $6.01 $5.61 $8.36 $8.39 $10.77 $8.46 $5.83

2009 $4.96 $4.22 $3.64 $3.32 $3.58 $3.57 $3.30 $3.12 $2.86 $3.93 $3.57 $5.27 $3.78 $4.27 $3.49 $3.09 $4.26

2010 $5.85 $5.31 $4.28 $3.94 $4.05 $4.66 $4.53 $4.21 $3.81 $3.39 $3.64 $4.24 $4.33 $5.15 $4.22 $4.18 $3.76

2011 $4.42 $4.23 $3.93 $4.15 $4.25 $4.51 $4.38 $4.04 $3.84 $3.46 $3.21 $3.18 $3.97 $4.19 $4.30 $4.09 $3.28

2012 $2.65 $2.48 $2.11 $1.92 $2.35 $2.40 $2.90 $2.82 $2.77 $3.27 $3.50 $3.29 $2.71 $2.41 $2.22 $2.83 $3.35

2013 $3.30 $3.29 $3.74 $4.20 $3.97 $3.73 $3.51 $3.68 $3.44 $3.97 $3.51

Avg $4.22 $4.09 $4.04 $3.95 $4.11 $4.25 $4.01 $3.75 $3.55 $3.81 $3.86 $4.44 $4.00 $4.11 $4.10 $3.77 $4.03

High $8.72 $8.30 $9.03 $9.86 $10.47 $11.97 $10.81 $7.83 $6.75 $5.97 $6.01 $8.12 $8.36 $8.39 $10.77 $8.46 $6.12

Low $1.75 $1.66 $1.64 $1.83 $2.03 $1.99 $2.03 $1.79 $1.66 $1.85 $1.95 $1.64 $1.97 $1.68 $1.98 $1.90 $1.81


13 August 2013


Exhibit 35: Henry Hub bid-week natural gas prices

($/Mmbtu)

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Average 1Q 2Q 3Q 4Q

1996 $2.92 $4.41 $3.00 $2.71 $2.21 $2.43 $2.57 $2.12 $1.84 $2.27 $2.82 $3.78 $2.76 $3.44 $2.45 $2.18 $2.96

1997 $3.47 $2.55 $1.88 $2.00 $2.19 $2.21 $2.17 $2.40 $2.80 $3.03 $3.23 $2.37 $2.53 $2.63 $2.13 $2.46 $2.88

1998 $2.10 $2.17 $2.23 $2.45 $2.18 $2.14 $2.25 $1.90 $1.91 $1.93 $2.06 $1.69 $2.08 $2.17 $2.26 $2.02 $1.89

1999 $1.87 $1.78 $1.78 $2.07 $2.27 $2.30 $2.23 $2.74 $2.63 $2.63 $2.54 $2.36 $2.27 $1.81 $2.21 $2.53 $2.51

2000 $2.37 $2.66 $2.75 $2.99 $3.47 $4.30 $4.10 $4.35 $5.01 $5.11 $5.52 $8.08 $4.23 $2.59 $3.59 $4.49 $6.24

2001 $9.13 $5.73 $5.12 $5.23 $4.18 $3.78 $3.18 $3.01 $2.24 $2.44 $2.45 $2.33 $4.07 $6.66 $4.40 $2.81 $2.41

2002 $2.29 $2.26 $2.85 $3.44 $3.54 $3.23 $3.06 $3.05 $3.45 $4.06 $4.09 $4.65 $3.21 $2.47 $3.40 $3.19 $4.08

2003 $5.30 $7.35 $8.06 $5.27 $5.78 $5.84 $5.04 $5.01 $4.62 $4.63 $4.46 $6.14 $5.63 $6.90 $5.63 $4.89 $5.08

2004 $6.09 $5.37 $5.36 $5.70 $6.29 $6.25 $5.94 $5.49 $4.95 $6.22 $5.89 $6.64 $5.85 $5.61 $6.08 $5.46 $6.25

2005 $6.13 $6.11 $6.96 $7.28 $6.48 $7.09 $7.56 $9.29 $11.73 $13.36 $10.36 $13.08 $8.79 $6.40 $6.95 $9.53 $12.27

2006 $9.92 $8.41 $7.39 $7.09 $7.03 $5.93 $5.89 $7.04 $6.82 $4.20 $7.16 $8.34 $7.10 $8.57 $6.68 $6.58 $6.57

2007 $5.84 $6.92 $7.55 $7.56 $7.51 $7.59 $6.93 $6.11 $5.43 $6.43 $7.28 $7.21 $6.86 $6.77 $7.55 $6.16 $6.97

2008 $7.13 $7.99 $8.93 $9.58 $11.29 $11.93 $13.11 $9.23 $8.40 $7.48 $6.47 $6.91 $9.04 $8.02 $10.93 $10.25 $6.95

2009 $6.13 $4.49 $4.07 $3.63 $3.32 $3.54 $3.96 $3.38 $2.83 $3.72 $4.28 $4.49 $3.99 $4.90 $3.50 $3.39 $4.16

2010 $5.82 $5.28 $4.81 $3.84 $4.27 $4.16 $4.72 $4.78 $3.64 $3.84 $3.29 $4.27 $4.39 $5.30 $4.09 $4.38 $3.80

2011 $4.22 $4.32 $3.79 $4.24 $4.38 $4.33 $4.36 $4.37 $3.85 $3.76 $3.52 $3.37 $4.04 $4.11 $4.32 $4.19 $3.55

2012 $3.08 $2.67 $2.44 $2.19 $2.03 $2.42 $2.77 $3.01 $2.63 $3.03 $3.47 $3.71 $2.79 $2.73 $2.21 $2.80 $3.40

2013 $3.35 $3.23 $3.43 $3.98 $4.16 $4.15 $3.71 $3.45 $3.68 $3.34 $4.10 $3.58

Avg $4.84 $4.65 $4.58 $4.51 $4.59 $4.65 $4.64 $4.49 $4.40 $4.60 $4.64 $5.26 $4.63 $4.69 $4.58 $4.49 $4.82

High $9.92 $8.41 $8.93 $9.58 $11.29 $11.93 $13.11 $9.29 $11.73 $13.36 $10.36 $13.08 $9.04 $8.57 $10.93 $10.25 $12.27

Low $1.87 $1.78 $1.78 $2.00 $2.03 $2.14 $2.17 $1.90 $1.84 $1.93 $2.06 $1.69 $2.08 $1.81 $2.13 $2.02 $1.89


Exhibit 36: Henry Hub differential Exhibit 37: Mid-continent differential

1

Henry Hub vs. NYMEX Differential

($0.4)

($0.3)

($0.2)

($0.1)

$0.0

$0.1

$0.2

$0.3

$0.4

$0.5

Feb

-06

Ju

n-0

6

Oc

t-0

6

Feb

-07

Ju

n-0

7

Oc

t-0

7

Feb

-08

Ju

n-0

8

Oc

t-0

8

Feb

-09

Ju

n-0

9

Oc

t-0

9

Feb

-10

Ju

n-1

0

Oc

t-1

0

Feb

-11

Ju

n-1

1

Oc

t-1

1

Feb

-12

Ju

n-1

2

Oc

t-1

2

Feb

-13

Ju

n-1

3

Henry Hub - NYMEX Differential Average


$0.00 vs. -$0.02 LTA

1

Mid-Continent vs. NYMEX Differential

($4.0)

($3.0)

($2.0)

($1.0)

$0.0

$1.0

$2.0F

eb

-06

Ju

n-0

6

Oc

t-0

6

Feb

-07

Ju

n-0

7

Oc

t-0

7

Feb

-08

Ju

n-0

8

Oc

t-0

8

Feb

-09

Ju

n-0

9

Oc

t-0

9

Feb

-10

Ju

n-1

0

Oc

t-1

0

Feb

-11

Ju

n-1

1

Oc

t-1

1

Feb

-12

Ju

n-1

2

Oc

t-1

2

Feb

-13

Ju

n-1

3

Mid-Continent - NYMEX Differential Average


-$0.16 vs. -$0.64 LTA

Source: Natural Gas Week, Credit Suisse Source: Natural Gas Week, Credit Suisse

Exhibit 38: South Texas differential Exhibit 39: AECO differential

1

South Texas vs. NYMEX Differential

($1.2)

($1.0)

($0.8)

($0.6)

($0.4)

($0.2)

$0.0

$0.2

$0.4

Feb

-06

Ju

n-0

6

Oc

t-0

6

Feb

-07

Ju

n-0

7

Oc

t-0

7

Feb

-08

Ju

n-0

8

Oc

t-0

8

Feb

-09

Ju

n-0

9

Oc

t-0

9

Feb

-10

Ju

n-1

0

Oc

t-1

0

Feb

-11

Ju

n-1

1

Oc

t-1

1

Feb

-12

Ju

n-1

2

Oc

t-1

2

Feb

-13

Ju

n-1

3

South Texas - NYMEX Differential Average


-$0.06 vs. -$0.28 LTA

1

AECO vs. NYMEX Differential

($2.5)

($2.0)

($1.5)

($1.0)

($0.5)

$0.0

$0.5

$1.0

Feb

-06

Ju

n-0

6

Oc

t-0

6

Feb

-07

Ju

n-0

7

Oc

t-0

7

Feb

-08

Ju

n-0

8

Oc

t-0

8

Feb

-09

Ju

n-0

9

Oc

t-0

9

Feb

-10

Ju

n-1

0

Oc

t-1

0

Feb

-11

Ju

n-1

1

Oc

t-1

1

Feb

-12

Ju

n-1

2

Oc

t-1

2

Feb

-13

Ju

n-1

3

AECO - NYMEX Differential Average


-$0.86 vs. -$0.75 LTA


13 August 2013


Exhibit 40: Waha differential Exhibit 41: Carthage differential

1

Waha vs. NYMEX Differential

($3.5)

($3.0)

($2.5)

($2.0)

($1.5)

($1.0)

($0.5)

$0.0

$0.5

$1.0

$1.5

Feb

-06

Ju

n-0

6

Oc

t-0

6

Feb

-07

Ju

n-0

7

Oc

t-0

7

Feb

-08

Ju

n-0

8

Oc

t-0

8

Feb

-09

Ju

n-0

9

Oc

t-0

9

Feb

-10

Ju

n-1

0

Oc

t-1

0

Feb

-11

Ju

n-1

1

Oc

t-1

1

Feb

-12

Ju

n-1

2

Oc

t-1

2

Feb

-13

Ju

n-1

3

Waha - NYMEX Differential Average


-$0.07 vs. -$0.49 LTA

1

Carthage vs. NYMEX Differential

($1.4)

($1.2)

($1.0)

($0.8)

($0.6)

($0.4)

($0.2)

$0.0

$0.2

$0.4

$0.6

Fe

b-0

6

Ju

n-0

6

Oct-

06

Fe

b-0

7

Ju

n-0

7

Oct-

07

Fe

b-0

8

Ju

n-0

8

Oct-

08

Fe

b-0

9

Ju

n-0

9

Oct-

09

Fe

b-1

0

Ju

n-1

0

Oct-

10

Fe

b-1

1

Ju

n-1

1

Oct-

11

Fe

b-1

2

Ju

n-1

2

Oct-

12

Fe

b-1

3

Ju

n-1

3

Carthage - NYMEX Differential Average


-$0.06 vs. -$0.29 LTA


Exhibit 42: East Texas differential Exhibit 43: Appalachia differential

1

East Texas vs. NYMEX Differential

($2.0)

($1.5)

($1.0)

($0.5)

$0.0

$0.5

$1.0

Feb

-06

Ju

n-0

6

Oc

t-0

6

Feb

-07

Ju

n-0

7

Oc

t-0

7

Feb

-08

Ju

n-0

8

Oc

t-0

8

Feb

-09

Ju

n-0

9

Oc

t-0

9

Feb

-10

Ju

n-1

0

Oc

t-1

0

Feb

-11

Ju

n-1

1

Oc

t-1

1

Feb

-12

Ju

n-1

2

Oc

t-1

2

Feb

-13

Ju

n-1

3East Texas - NYMEX Differential Average


-$0.06 vs. -$0.34 LTA

1

Appalachia vs. NYMEX Differential

($0.4)

($0.2)

$0.0

$0.2

$0.4

$0.6

$0.8

$1.0

Feb

-06

Ju

n-0

6

Oc

t-0

6

Feb

-07

Ju

n-0

7

Oc

t-0

7

Feb

-08

Ju

n-0

8

Oc

t-0

8

Feb

-09

Ju

n-0

9

Oc

t-0

9

Feb

-10

Ju

n-1

0

Oc

t-1

0

Feb

-11

Ju

n-1

1

Oc

t-1

1

Feb

-12

Ju

n-1

2

Oc

t-1

2

Feb

-13

Ju

n-1

3

Appalachia - NYMEX Differential Average


-$0.20 vs. $0.18 LTA


13 August 2013


Supply Exhibit 44: US dry gas production (indicated by pipeline scrapes)

(Bcf/d)

1

Dry Gas Production

53

.2

53

.9

54

.7

54

.3

54

.7

55

.5

55

.9

55

.5

48

.9

53

.6

55

.3

55

.5

55

.9

56

.6

56

.0

55

.8

55

.7

55

.7

55

.5

55

.3

53

.7

54

.5

54

.9

54

.1

54

.2

55

.5

56

.4

56

.1

56

.8

56

.3

56

.6

57

.6

57

.9

58

.2

58

.6

59

.2

58

.9

57

.7 6

0.4

60

.8

61

.4

61

.1

61

.6

62

.2

62

.1

63

.0

63

.9

63

.6

63

.6

63

.1

63

.3

63

.3

63

.5

63

.4

63

.8

63

.3

63

.8

64

.6

65

.1

64

.9

64

.0

64

.3

64

.3

64

.8

64

.9

64

.6

65

.3

65

.2

40

45

50

55

60

65

70

Jan

-08

Ma

r-0

8

Ma

y-0

8

Ju

l-0

8

Se

p-0

8

No

v-0

8

Jan

-09

Ma

r-0

9

Ma

y-0

9

Ju

l-0

9

Se

p-0

9

No

v-0

9

Jan

-10

Ma

r-1

0

Ma

y-1

0

Ju

l-1

0

Se

p-1

0

No

v-1

0

Jan

-11

Ma

r-1

1

Ma

y-1

1

Ju

l-1

1

Se

p-1

1

No

v-1

1

Jan

-12

Ma

r-1

2

Ma

y-1

2

Ju

l-1

2

Se

p-1

2

No

v-1

2

Jan

-13

Ma

r-1

3

Ma

y-1

3

Ju

l-1

3


Exhibit 45: Year-over-year US dry gas production (indicated by pipeline scrapes)

(Bcf/d)

1

Y-o-Y Dry Gas Production

4.3

4.4

4.3

3.9

3.5

4.4

4.7

3.8

(3.0

)

1.1

1.8

1.7

2.6

2.7

1.4

1.5

1.0

0.2

(0.3

)

(0.2

)

4.8

1.0

(0.4

)

(1.5

)

(1.7

) (1.1

)

0.3

0.3

1.1

0.7

1.0

2.3

4.1

3.7

3.8

5.2

4.7

2.2

4.0

4.7

4.6

4.8

5.1

4.6

4.3

4.7

5.3

4.4

4.7

5.4

2.9

2.5

2.1

2.2

2.2

1.1

1.7

1.7

1.2

1.4

0.4

1.2

1.0

1.5

1.4

1.3

1.4

2.0

(4)

(3)

(2)

(1)

-

1

2

3

4

5

6

Jan

-08

Ma

r-0

8

Ma

y-0

8

Ju

l-0

8

Se

p-0

8

No

v-0

8

Jan

-09

Ma

r-0

9

Ma

y-0

9

Ju

l-0

9

Se

p-0

9

No

v-0

9

Jan

-10

Ma

r-1

0

Ma

y-1

0

Ju

l-1

0

Se

p-1

0

No

v-1

0

Jan

-11

Ma

r-1

1

Ma

y-1

1

Ju

l-1

1

Se

p-1

1

No

v-1

1

Jan

-12

Ma

r-1

2

Ma

y-1

2

Ju

l-1

2

Se

p-1

2

No

v-1

2

Jan

-13

Ma

r-1

3

Ma

y-1

3

Ju

l-1

3


Exhibit 46: US lower 48 natural gas production

U.S. Lower 48 Natural Gas Production (Bcf/d)

60.4

61.0

61.7

61.4

61.8

62.3

63.3

63.1

56.2

61.0 63.0

62.5

62.9

63.5

63.2

63.2

62.7

62.9

62.3

62.8

61.3

62.4

62.5

62.0

62.4

63.4

64.4

64.5

64.6

63.7

64.1

65.4

65.9

65.8

66.6

67.0

66.8

65.5 68.3

69.3

69.4

69.4

69.6

69.7

70.3

71.7

72.7

72.5

72.7

72.0

71.9

72.4

72.6

72.3

72.7

72.6

73.3

73.5

73.5

72.8

72.3

73.1

72.7

73.4

73.4

40

45

50

55

60

65

70

75

80

Jan-0

8

Mar-

08

May-0

8

Jul-

08

Sep

-08

Nov-0

8

Jan-0

9

Mar-

09

May-0

9

Jul-

09

Sep

-09

Nov-0

9

Jan-1

0

Mar-

10

May-1

0

Jul-

10

Sep

-10

Nov-1

0

Jan-1

1

Mar-

11

May-1

1

Jul-

11

Sep

-11

Nov-1

1

Jan-1

2

Mar-

12

May-1

2

Jul-

12

Sep

-12

Nov-1

2

Jan-1

3

Mar-

13

May-1

3


13 August 2013


Exhibit 47: Onshore natural gas production

Onshore Natural Gas Production (Bcf/d)52.5

53.1

53.9

54.5

55.0

54.9

55.8

56.1

53.9 56.4

57.4

56.6

56.5

57.0

56.6

56.4

56.1

55.8

55.0

56.0

54.6

55.7

56.2

55.6

55.9

56.6

57.6

58.0

58.3

57.8

58.3

59.2

60.0

59.9

60.9

61.1

60.9

60.0 6

2.8

63.8

64.1

64.3

64.8

64.9

66.2

67.1

68.1

67.8

68.1

67.5

67.2

67.8

68.3

68.3

68.6

69.0

69.6

69.5

69.4

68.6

68.2

69.1

68.8

69.5

69.7

40

45

50

55

60

65

70

75

Jan-0

8

Mar-

08

May-0

8

Jul-

08

Sep

-08

Nov-0

8

Jan-0

9

Mar-

09

May-0

9

Jul-

09

Sep

-09

Nov-0

9

Jan-1

0

Mar-

10

May-1

0

Jul-

10

Sep

-10

Nov-1

0

Jan-1

1

Mar-

11

May-1

1

Jul-

11

Sep

-11

Nov-1

1

Jan-1

2

Mar-

12

May-1

2

Jul-

12

Sep

-12

Nov-1

2

Jan-1

3

Mar-

13

May-1

3


Exhibit 48: Offshore natural gas production

Offshore Natural Gas Production (Bcf/d)

7.9

7.9

7.8

6.9

6.7 7

.4 7.5

7.0

2.2

4.6

5.6 5.8 6

.3 6.5 6.7 6.8

6.6

7.1 7

.36.9

6.7

6.7

6.4

6.4 6.5 6.8

6.8

6.5

6.3

6.0

5.8 6.2

5.9

6.0

5.7 5.9

5.9

5.5

5.5

5.5

5.3

5.1

4.8 4.8

4.1 4

.64.6 4.7

4.6

4.5 4.7

4.5

4.3

4.0 4.1

3.6

3.7 4.0 4.1

4.2

4.1

4.0

3.9 3.9

3.7

0

1

2

3

4

5

6

7

8

9

10

Jan-0

8

Mar-

08

May-0

8

Jul-

08

Sep

-08

Nov-0

8

Jan-0

9

Mar-

09

May-0

9

Jul-

09

Sep

-09

Nov-0

9

Jan-1

0

Mar-

10

May-1

0

Jul-

10

Sep

-10

Nov-1

0

Jan-1

1

Mar-

11

May-1

1

Jul-

11

Sep

-11

Nov-1

1

Jan-1

2

Mar-

12

May-1

2

Jul-

12

Sep

-12

Nov-1

2

Jan-1

3

Mar-

13

May-1

3


Exhibit 49: Year-over-year change in US lower 48 natural gas production

YoY Change in U.S. Lower 48 Natural Gas Production (Bcf/d)

4.7

5.5

4.9

4.5

4.5

4.5

5.8

5.2

-2.1

2.6 3

.22.0 2

.42.5

1.6 1.8

0.9

0.6

-1.0 -0

.35.2

1.4

-0.4

-0.4

-0.5 -0.1

1.1 1.3 1

.90.8

1.8 2

.54.6

3.5 4

.15.0

4.4

2.1

4.04.8

4.8

5.6

5.4

4.3 4.4

5.9 6.1

5.5 6

.0 6.5

3.6

3.1

3.2

2.9 3.1

2.9

3.0

1.8

0.9

0.3

-0.4

1.1

0.8 1.0

0.8

-3

-2

-1

0

1

2

3

4

5

6

7

Jan-0

8F

eb-0

8M

ar-

08A

pr-

08

May-0

8Jun

-08

Jul-

08

Aug

-08

Sep

-08

Oct-

08

Nov-0

8D

ec-0

8Jan-0

9F

eb-0

9M

ar-

09A

pr-

09

May-0

9Jun

-09

Jul-

09

Aug

-09

Sep

-09

Oct-

09

Nov-0

9D

ec-0

9Jan-1

0F

eb-1

0M

ar-

10A

pr-

10

May-1

0Jun

-10

Jul-

10

Aug

-10

Sep

-10

Oct-

10

Nov-1

0D

ec-1

0Jan-1

1F

eb-1

1M

ar-

11A

pr-

11

May-1

1Jun

-11

Jul-

11

Aug

-11

Sep

-11

Oct-

11

Nov-1

1D

ec-1

1Jan-1

2F

eb-1

2M

ar-

12A

pr-

12

May-1

2Jun

-12

Jul-

12

Aug

-12

Sep

-12

Oct-

12

Nov-1

2D

ec-1

2Jan-1

3F

eb-1

3M

ar-

13A

pr-

13

May-1

3


13 August 2013


Exhibit 50: Year-over-year change in onshore natural gas production

YoY Change in Onshore Natural Gas Production (Bcf/d)4.65.3

4.8 5

.3 5.5

4.8

5.7

5.5

3.1

5.5

5.2

4.4

4.0

3.9

2.6

1.9

1.0

0.9

-0.8

-0.2

0.7

-0.8

-1.2

-1.1

-0.7

-0.4

1.0 1

.7 2.3

1.9

3.3

3.2

5.4

4.2 4

.75.6

5.1

3.4

5.2 5

.85.7 6

.6 6.5

5.6 6.2

7.2

7.2

6.7 7

.27.5

4.4

4.0 4.2

4.0

3.8 4.1

3.4

2.3

1.3

0.8

0.1

1.6

1.6

1.6

1.4

-2

-1

0

1

2

3

4

5

6

7

8

Jan-0

8F

eb-0

8M

ar-

08A

pr-

08

May-0

8Jun

-08

Jul-

08

Aug

-08

Sep

-08

Oct-

08

Nov-0

8D

ec-0

8Jan-0

9F

eb-0

9M

ar-

09A

pr-

09

May-0

9Jun

-09

Jul-

09

Aug

-09

Sep

-09

Oct-

09

Nov-0

9D

ec-0

9Jan-1

0F

eb-1

0M

ar-

10A

pr-

10

May-1

0Jun

-10

Jul-

10

Aug

-10

Sep

-10

Oct-

10

Nov-1

0D

ec-1

0Jan-1

1F

eb-1

1M

ar-

11A

pr-

11

May-1

1Jun

-11

Jul-

11

Aug

-11

Sep

-11

Oct-

11

Nov-1

1D

ec-1

1Jan-1

2F

eb-1

2M

ar-

12A

pr-

12

May-1

2Jun

-12

Jul-

12

Aug

-12

Sep

-12

Oct-

12

Nov-1

2D

ec-1

2Jan-1

3F

eb-1

3M

ar-

13A

pr-

13

May-1

3


Exhibit 51: Year-over-year change in offshore natural gas production

YoY Change in Offshore Natural Gas Production (Bcf/d)

0.1

0.2

0.1

-0.8

-1.0 -0

.30.0

-0.4

-5.2

-3.0 -2

.0-2

.4 -1.6

-1.4

-1.1 -0

.1-0

.1-0

.3-0

.2-0

.14.5

2.2

0.8

0.6

0.2 0.3

0.1

-0.4

-0.3

-1.1

-1.5 -0

.7-0

.8-0

.8-0

.7-0

.6-0

.7-1

.3-1

.3-1

.0-1

.0-0

.9

-1.1

-1.3

-1.8

-1.4

-1.1

-1.2

-1.2

-1.0

-0.8

-0.9

-1.0

-1.1

-0.7

-1.2 -0

.4-0

.6-0

.4-0

.5-0

.6-0

.5-0

.8-0

.6-0

.6

-8

-6

-4

-2

0

2

4

6

Jan-0

8F

eb-0

8M

ar-

08A

pr-

08

May-0

8Jun

-08

Jul-

08

Aug

-08

Sep

-08

Oct-

08

Nov-0

8D

ec-0

8Jan-0

9F

eb-0

9M

ar-

09A

pr-

09

May-0

9Jun

-09

Jul-

09

Aug

-09

Sep

-09

Oct-

09

Nov-0

9D

ec-0

9Jan-1

0F

eb-1

0M

ar-

10A

pr-

10

May-1

0Jun

-10

Jul-

10

Aug

-10

Sep

-10

Oct-

10

Nov-1

0D

ec-1

0Jan-1

1F

eb-1

1M

ar-

11A

pr-

11

May-1

1Jun

-11

Jul-

11

Aug

-11

Sep

-11

Oct-

11

Nov-1

1D

ec-1

1Jan-1

2F

eb-1

2M

ar-

12A

pr-

12

May-1

2Jun

-12

Jul-

12

Aug

-12

Sep

-12

Oct-

12

Nov-1

2D

ec-1

2Jan-1

3F

eb-1

3M

ar-

13A

pr-

13

May-1

3


13 August 2013


Exhibit 52: Texas natural gas production Exhibit 53: Louisiana natural gas production

1

Texas Natural Gas Production (Bcf/d)

0

5

10

15

20

25

30

35

Jan

-08

Ap

r-08

Ju

l-0

8

Oc

t-0

8

Jan

-09

Ap

r-09

Ju

l-0

9

Oc

t-0

9

Jan

-10

Ap

r-10

Ju

l-1

0

Oc

t-1

0

Jan

-11

Ap

r-11

Ju

l-1

1

Oc

t-1

1

Jan

-12

Ap

r-12

Ju

l-1

2

Oc

t-1

2

Jan

-13

Ap

r-13

As of May 2013Up 0.0% YTD (+0.00 Bcf/d)Up 0.7% Yr/Yr (+0.15 Bcf/d)

1

Louisiana Natural Gas Production (Bcf/d)

0

1

2

3

4

5

6

7

8

9

Jan

-08

Ap

r-08

Ju

l-0

8

Oc

t-0

8

Jan

-09

Ap

r-09

Ju

l-0

9

Oc

t-0

9

Jan

-10

Ap

r-10

Ju

l-1

0

Oc

t-1

0

Jan

-11

Ap

r-11

Ju

l-1

1

Oc

t-1

1

Jan

-12

Ap

r-12

Ju

l-1

2

Oc

t-1

2

Jan

-13

Ap

r-13

As of May 2013Down 16.1% YTD (-1.35 Bcf/d)Down 19.6% Yr/Yr (-1.63 Bcf/d)

Source: EIA, Credit Suisse Source: EIA, Credit Suisse

Exhibit 54: Oklahoma natural gas production Exhibit 55: New Mexico natural gas production

1

Oklahoma Natural Gas Production (Bcf/d)

0

1

2

3

4

5

6

7

8

Jan

-08

Ap

r-08

Ju

l-0

8

Oc

t-0

8

Jan

-09

Ap

r-09

Ju

l-0

9

Oc

t-0

9

Jan

-10

Ap

r-10

Ju

l-1

0

Oc

t-1

0

Jan

-11

Ap

r-11

Ju

l-1

1

Oc

t-1

1

Jan

-12

Ap

r-12

Ju

l-1

2

Oc

t-1

2

Jan

-13

Ap

r-13


1

New Mexico Natural Gas Production (Bcf/d)

0

1

2

3

4

5

6

Jan

-08

Ap

r-08

Ju

l-0

8

Oc

t-0

8

Jan

-09

Ap

r-09

Ju

l-0

9

Oc

t-0

9

Jan

-10

Ap

r-10

Ju

l-1

0

Oc

t-1

0

Jan

-11

Ap

r-11

Ju

l-1

1

Oc

t-1

1

Jan

-12

Ap

r-12

Ju

l-1

2

Oc

t-1

2

Jan

-13

Ap

r-13

As of May 2013Down 4.0% YTD (-0.15 Bcf/d)Down 0.0% Yr/Yr (+0.00 Bcf/d)


Exhibit 56: Wyoming natural gas production Exhibit 57: Other states natural gas production

1

Wyoming Natural Gas Production (Bcf/d)

0

2

4

6

8

10

Jan

-08

Ap

r-08

Ju

l-0

8

Oc

t-0

8

Jan

-09

Ap

r-09

Ju

l-0

9

Oc

t-0

9

Jan

-10

Ap

r-10

Ju

l-1

0

Oc

t-1

0

Jan

-11

Ap

r-11

Ju

l-1

1

Oc

t-1

1

Jan

-12

Ap

r-12

Ju

l-1

2

Oc

t-1

2

Jan

-13

Ap

r-13

As of May 2013Down 9.6% YTD (-0.62 Bcf/d)Down 9.0% Yr/Yr (-0.56 Bcf/d)

1

Other States Natural Gas Production (Bcf/d)

0

5

10

15

20

25

Jan

-08

Ap

r-08

Ju

l-0

8

Oc

t-0

8

Jan

-09

Ap

r-09

Ju

l-0

9

Oc

t-0

9

Jan

-10

Ap

r-10

Ju

l-1

0

Oc

t-1

0

Jan

-11

Ap

r-11

Ju

l-1

1

Oc

t-1

1

Jan

-12

Ap

r-12

Ju

l-1

2

Oc

t-1

2

Jan

-13

Ap

r-13



13 August 2013


US Imports/Exports

Exhibit 58: Monthly net natural gas imports (Bcf/d) Exhibit 59: Monthly imports from Canada (Bcf/d)

1

Net Imports

-

1

2

3

4

5

6

7

8

9

10

Jan

-08

Ap

r-08

Ju

l-0

8

Oc

t-0

8

Jan

-09

Ap

r-09

Ju

l-0

9

Oc

t-0

9

Jan

-10

Ap

r-10

Ju

l-1

0

Oc

t-1

0

Jan

-11

Ap

r-11

Ju

l-1

1

Oc

t-1

1

Jan

-12

Ap

r-12

Ju

l-1

2

Oc

t-1

2

Jan

-13

Ap

r-13

Ju

l-1

3

As of August 2013 Down 20.3% YTD (-0.91 Bcf/d) Down 32.6% Yr/Yr (-1.49 Bcf/d)

1

1

Canadian Imports

-

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

9.0

10.0

Jan

-08

Ap

r-08

Ju

l-0

8

Oc

t-0

8

Jan

-09

Ap

r-09

Ju

l-0

9

Oc

t-0

9

Jan

-10

Ap

r-10

Ju

l-1

0

Oc

t-1

0

Jan

-11

Ap

r-11

Ju

l-1

1

Oc

t-1

1

Jan

-12

Ap

r-12

Ju

l-1

2

Oc

t-1

2

Jan

-13

Ap

r-13

Ju

l-1

3

As of August 2013 Down 8.0% YTD (-0.44 Bcf/d)

Down 18.2% Yr/Yr (-1.07 Bcf/d)


Exhibit 60: Monthly LNG imports (Bcf/d)

Exhibit 61: Monthly Mexican exports (Bcf/d)

1

1

LNG Imports

-

0.5

1.0

1.5

2.0

2.5

Jan

-08

Ap

r-08

Ju

l-0

8

Oc

t-0

8

Jan

-09

Ap

r-09

Ju

l-0

9

Oc

t-0

9

Jan

-10

Ap

r-10

Ju

l-1

0

Oc

t-1

0

Jan

-11

Ap

r-11

Ju

l-1

1

Oc

t-1

1

Jan

-12

Ap

r-12

Ju

l-1

2

Oc

t-1

2

Jan

-13

Ap

r-13

Ju

l-1

3


1

Mexican Exports

(2.0)

(1.8)

(1.6)

(1.4)

(1.2)

(1.0)

(0.8)

(0.6)

(0.4)

(0.2)

-

Jan

-08

Ap

r-08

Ju

l-0

8

Oc

t-0

8

Jan

-09

Ap

r-09

Ju

l-0

9

Oc

t-0

9

Jan

-10

Ap

r-10

Ju

l-1

0

Oc

t-1

0

Jan

-11

Ap

r-11

Ju

l-1

1

Oc

t-1

1

Jan

-12

Ap

r-12

Ju

l-1

2

Oc

t-1

2

Jan

-13

Ap

r-13

Ju

l-1

3



13 August 2013


US Gas Demand (Monthly)

Exhibit 62: Total US gas demand Exhibit 63: Residential/commercial demand

(Bcf/d) (Bcf/d)

1

Total Demand

-

20

40

60

80

100

120

Jan

-08

Ap

r-08

Ju

l-0

8

Oc

t-0

8

Jan

-09

Ap

r-09

Ju

l-0

9

Oc

t-0

9

Jan

-10

Ap

r-10

Ju

l-1

0

Oc

t-1

0

Jan

-11

Ap

r-11

Ju

l-1

1

Oc

t-1

1

Jan

-12

Ap

r-12

Ju

l-1

2

Oc

t-1

2

Jan

-13

Ap

r-13

Ju

l-1

3

As of August 2013 Up 1.2% YTD (+0.84 Bcf/d)


1

Residential/Commercial Demand

-

10

20

30

40

50

60

70

Jan

-08

Ap

r-08

Ju

l-0

8

Oc

t-0

8

Jan

-09

Ap

r-09

Ju

l-0

9

Oc

t-0

9

Jan

-10

Ap

r-10

Ju

l-1

0

Oc

t-1

0

Jan

-11

Ap

r-11

Ju

l-1

1

Oc

t-1

1

Jan

-12

Ap

r-12

Ju

l-1

2

Oc

t-1

2

Jan

-13

Ap

r-13

Ju

l-1

3



Exhibit 64: Industrial demand Exhibit 65: Electric power demand

(Bcf/d) (Bcf/d)

1

Industrial Demand

10

12

14

16

18

20

22

24

Jan

-08

Ap

r-08

Ju

l-0

8

Oc

t-0

8

Jan

-09

Ap

r-09

Ju

l-0

9

Oc

t-0

9

Jan

-10

Ap

r-10

Ju

l-1

0

Oc

t-1

0

Jan

-11

Ap

r-11

Ju

l-1

1

Oc

t-1

1

Jan

-12

Ap

r-12

Ju

l-1

2

Oc

t-1

2

Jan

-13

Ap

r-13

Ju

l-1

3

As of August 2013 Up 2.0% YTD (+0.37 Bcf/d)


1

Electric Power

-

5

10

15

20

25

30

35

40

Jan

-08

Ap

r-08

Ju

l-0

8

Oc

t-0

8

Jan

-09

Ap

r-09

Ju

l-0

9

Oc

t-0

9

Jan

-10

Ap

r-10

Ju

l-1

0

Oc

t-1

0

Jan

-11

Ap

r-11

Ju

l-1

1

Oc

t-1

1

Jan

-12

Ap

r-12

Ju

l-1

2

Oc

t-1

2

Jan

-13

Ap

r-13

Ju

l-1

3



13 August 2013


US Gas Demand (Annual) Exhibit 66: Total US demand for natural gas (Bcf/d) Exhibit 67: Natural gas demand (2013 vs. 2012) (Bcf/d)

Total U.S. Demand for Natural Gas

63.2 61.2 61.3 60.4 59.5 63.5 63.6 62.9

66.1 66.9 69.7

77.1

0

10

20

30

40

50

60

70

80

90

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

20

10

20

11

20

12

20

13

Natural Gas Demand (2013 YTD vs. 2012 YTD)

0.9

(3.4)

3.8

1.8

3.2

-6.0

-5.0

-4.0

-3.0

-2.0

-1.0

0.0

1.0

2.0

3.0

4.0

5.0

Industrial Electric Power Residential Commercial Total


Exhibit 68: Industrial demand for natural gas (Bcf/d) Exhibit 69: Industrial demand (% of total)

U.S. Industrial Natural Gas Demand (Bcf/d)

20.6

19.6 19.8

18.1 17.9

18.3 18.2

16.9

18.7 18.9

19.5

20.8

15

16

17

18

19

20

21

22

200

2

200

3

200

4

200

5

200

6

200

7

200

8

200

9

201

0

201

1

201

2

201

3

1

Industrial Demand (% of Total)

33% 33% 33%

31% 30%

29% 29%

28%

29% 29%28%

28%

20%

22%

24%

26%

28%

30%

32%

34%

36%

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

20

10

20

11

20

12

20

13


Exhibit 70: Electric utility demand for natural gas (Bcf/d) Exhibit 71: Electric utility demand (% of total)

1

Electric Utility Demand for Natural Gas

15.5

14.0 14.9

16.0

17.0

18.7 18.2

18.8

20.2 20.8

24.9

19.7

10

12

14

16

18

20

22

24

26

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

20

10

20

11

20

12

20

13

1

Electric Utility Demand (% of Total)

26%25%

26%28%

30%31% 30%

32% 32% 33%

37%

26%

0%

5%

10%

15%

20%

25%

30%

35%

40%

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

20

10

20

11

20

12

20

13


13 August 2013


Exhibit 72: Residential demand for natural gas (Bcf/d)

Exhibit 73: Residential demand (% of total)

1

Residential Demand for Natural Gas (Bcf/d)

13.5 14.0 13.3 13.3

12.0 13.0 13.4 13.2 13.2 13.0

11.4

19.1

0

5

10

15

20

25

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

20

10

20

11

20

12

20

13

1

Residential Demand (% of Total)

20%

21%

20%20%

19% 19%19% 19%

18% 18%

15%

23%

12%

14%

16%

18%

20%

22%

24%

26%

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

20

10

20

11

20

12

20

13


Exhibit 74: Commercial utility demand for natural gas (Bcf/d)

Exhibit 75: Commercial utility demand (% of total)

Commercial Demand for Natural Gas (Bcf/d)

8.6 8.9 8.6

8.2 7.8

8.3 8.6 8.6 8.5 8.7

8.0

11.4

0

2

4

6

8

10

12

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

20

10

20

11

20

12

20

13

1

Commercial Demand (% of Total)

13%14%

13% 13% 13% 12%13% 13%

12% 12%

11%

14%

0.0%

2.0%

4.0%

6.0%

8.0%

10.0%

12.0%

14.0%

16.0%

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

20

10

20

11

20

12

20

13


13 August 2013


US Gas Demand (YTD) Exhibit 76: Total YTD US demand for natural gas (Bcf/d)

Exhibit 77: Natural gas YTD demand (2013 vs. 2012)

Total U.S. Demand for Natural Gas (YTD)

69.6 70.9 69.9

68.1

64.1

70.2 71.9

69.6 71.4

73.4 73.9

77.1

40

45

50

55

60

65

70

75

80

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

20

10

20

11

20

12

20

13

Natural Gas Demand (2013 YTD vs. 2012 YTD)

0.9

(3.4)

3.8

1.8

3.2

-6.0

-5.0

-4.0

-3.0

-2.0

-1.0

0.0

1.0

2.0

3.0

4.0

5.0

Industrial Electric Power Residential Commercial Total


Exhibit 78: Industrial YTD demand for natural gas (Bcf/d)

Exhibit 79: Industrial YTD demand (% of total)

U.S. Industrial Natural Gas Demand YTD (Bcf/d)

21.4 20.4 20.5

19.6 18.4 19.0

19.7

17.3

19.4 19.7 19.9 20.8

0

5

10

15

20

25

200

2

200

3

200

4

200

5

200

6

200

7

200

8

200

9

201

0

201

1

201

2

201

3

1

Industrial Demand YTD (% of Total)

31%

30%30%

30% 29%

28% 28%

26%

28%28%

27%28%

20%

22%

24%

26%

28%

30%

32%

34%20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

20

10

20

11

20

12

20

13


Exhibit 80: Electric utility YTD demand for natural gas (Bcf/d)

Exhibit 81: Electric utility demand YTD (% of total)

Electric Utility Demand for Natural Gas (YTD)

12.9 12.1

13.1 12.7 13.2

14.9 15.6 15.9

16.6 17.2

23.1

19.7

0

5

10

15

20

25

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

20

10

20

11

20

12

20

13

Electric Utility Demand YTD (% of Total)

19%18%

20% 20%

22%22% 23%

24% 25% 25%

32%

26%

10%

15%

20%

25%

30%

35%

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

20

10

20

11

20

12

20

13


13 August 2013


Exhibit 82: Residential YTD demand for natural gas (Bcf/d)

Exhibit 83: Residential YTD demand (% of total)

Residential Demand for Natural Gas (YTD)

19.0

21.1 19.9 19.7

17.3

19.7 19.7 19.3 18.8 19.3

15.3

19.1

0

5

10

15

20

25

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

20

10

20

11

20

12

20

13

1

Residential Demand YTD (% of Total)

26%

28%

27%28%

26%27%

26% 26%

25% 25%

20%

23%

12%

14%

16%

18%

20%

22%

24%

26%

28%

30%

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

20

10

20

11

20

12

20

13


Exhibit 84: Commercial utility YTD demand for natural gas (Bcf/d)

Exhibit 85: Commercial utility YTD demand (% of total)

Commercial Demand for Natural Gas YTD (Bcf/d)

11.1

12.3 11.7

11.1

10.2

11.3 11.6 11.4 11.0

11.5

9.6

11.4

0

2

4

6

8

10

12

14

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

20

10

20

11

20

12

20

13

1

Commercial Demand YTD (% of Total)

16%

17%

16% 16% 15% 16% 16% 16%15% 15%

13%

14%

0%1%2%3%4%5%6%7%8%9%

10%11%12%13%14%15%16%17%18%

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

20

10

20

11

20

12

20

13


13 August 2013


Natural Gas Storage

Exhibit 86: Natural gas storage

(Bcf)

Region 8/2/2013 7/26/2013 8/2/2012 5 YR AVG 5YR CHG

East 1,408 1,350 58 4.3% 1,631 223 -13.7% 1,513 105

West 484 461 23 5.0% 498 14 -2.8% 435 49

Producing 1,049 1,034 15 1.5% 1,109 60 -5.4% 973 76

Total 2,941 2,845 96 3.4% 3,238 297 -9.2% 2,921 20

W-O-W Y-O-Y


Exhibit 87: Total US working gas storage Exhibit 88: East working gas storage

(Bcf) (Bcf)

2,941

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

Jan Mar May Jul Sep Nov

5-YR Range 2012 2013

1,408

500

700

900

1,100

1,300

1,500

1,700

1,900

2,100

2,300


5-YR Range 2012 2013


Exhibit 89: West working gas storage Exhibit 90: Producing working gas storage

(Bcf) (Bcf)

484

150

200

250

300

350

400

450

500

550

600


5-YR Range 2012 2013

1,049

400

500

600

700

800

900

1,000

1,100

1,200

1,300

1,400


5-YR Range 2012 2013


13 August 2013


North America Rig Count and Permits

Exhibit 91: US rig count trend (oil vs. gas) Exhibit 92: US rig count trend (land vs. offshore)

0

500

1000

1500

2000

2500

Feb-11 Jun-11 Oct-11 Feb-12 Jun-12 Oct-12 Feb-13 Jun-13

Gas Oil

0

200

400

600

800

1000

1200

1400

1600


Gas Oil


Exhibit 93: Vertical – Oil vs. gas rig count Exhibit 94: Horizontal – Oil vs. gas rig count

0

100

200

300

400

500

600


Gas Oil

0

100

200

300

400

500

600

700

800

900


Gas Oil


13 August 2013


North America Gas Basin-Level Trends

Exhibit 95: Eagle Ford rig count Exhibit 96: Bakken rig count

0

50

100

150

200

250


Gas Oil

100

120

140

160

180

200

220

240


Gas Oil


Exhibit 97: Haynesville (core) rig count Exhibit 98: Utica rig count

0

20

40

60

80

100

120

140

160

180


Gas Oil

0

5

10

15

20

25

30

35


Gas Oil


Exhibit 99: Barnett rig count Exhibit 100: Fayetteville rig count

0

10

20

30

40

50

60

70


Gas Oil

0

5

10

15

20

25

30

35

40


Gas Oil


13 August 2013


Exhibit 101: Mississippian rig count Exhibit 102: Granite Wash rig count

0

10

20

30

40

50

60

70

80

90

100


Gas Oil

0

10

20

30

40

50

60

70

80


Gas Oil


Exhibit 103: Woodford rig count Exhibit 104: Permian rig count

0

10

20

30

40

50

60

70


Gas Oil

0

100

200

300

400

500

600


Gas Oil


Exhibit 105: Marcellus rig count Exhibit 106: DJ-Niobrara rig count

60

70

80

90

100

110

120

130

140

150


Gas Oil

0

5

10

15

20

25

30

35

40


Gas Oil


13 August 2013


Competitive Fuel Sources

Exhibit 107: Total US nuclear output Exhibit 108: Prompt month parity CAPP coal/gas

(Weekly Avg MW) ($/Mmbtu)

65,000

70,000

75,000

80,000

85,000

90,000

95,000

100,000

105,000

Jan-13 Mar-13 May-13 Jul-13 Sep-13 Nov-13

Prior 10-yr Range Prior 10-yr average 2013 2012

$(3.0)

$(2.0)

$(1.0)

$-

$1.0

$2.0

$3.0

$1.0

$2.0

$3.0

$4.0

$5.0

$6.0

$7.0

Jan-09 Jul-09 Jan-10 Jul-10 Jan-11 Jul-11 Jan-12 Jul-12 Jan-13 Jul-13

CAPP-HH (rhs) Nat Gas CAPP Coal

Natural Gas = NYMEX + ($0.50 Basis)Coal = ((Coal+Rail $/ton)/(12*2)+O&M($3/MWh/10HR))*HR conversion: (10/7.2))

Source: NRC, Credit Suisse Source: the BLOOMBERG PROFESSIONAL™ service, Credit Suisse

Exhibit 109: Natural gas - PRB coal price spread Exhibit 110: Natural gas – CAPP prices spread

(Henry Hub prompt minus PRB coal adjusted for delivery in $/MMbtu) (Henry Hub prompt minus CAPP coal adjusted for delivery in $/MMbtu)

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

$3.50

$4.00

$4.50


2009 2010 2011 2012 2013

-$2.00

-$1.50

-$1.00

-$0.50

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

$3.50


2009 2010 2011 2012 2013

Source: the BLOOMBERG PROFESSIONAL™ service, Credit Suisse Source: the BLOOMBERG PROFESSIONAL™ service, Credit Suisse

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US Natural Gas Reservoir - Credit Suisse

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