Transcript Presentation Title - Western Energy Alliance

Natural Gas
In the Production Growth Vortex
Energy Finance Discussion Group
Denver
November 11, 2008
David Pursell
*Important Disclosures on page 33 of this document.*
Oct-08
Aug-08
Jun-08
Apr-08
Feb-08
Dec-07
Oct-07
Aug-07
Jun-07
Apr-07
Feb-07
Dec-06
Oct-06
Aug-06
Jun-06
Apr-06
Feb-06
Dec-05
Oct-05
Aug-05
$/mcf
Natural Gas 12 Month Strip
$14
$13
$12
$11
$10
$9
$8
$7
$6
2
Futures – Are They Accurate?
StripToo High
30%
0%
Jan-09
Jan-07
Jan-05
Jan-03
Jan-01
Jan-99
% Differnece NYMEX 12 mo Strip and Actual
60%
-30%
(Strip Too Low)
-60%
3
Thoughts On Price
 Price range
□ 2001 :
 Marginal Cost Supply ~$3.50/mcf
 Marginal Consumption ~$8 to $10/mcf
□ 2008
 Marginal Cost Supply ~$8/mcf
 Marginal Consumption ~$10 to 12/mcf (assuming economy OK)
□ LNG
□ 2001 – N/A
□ 2008 - $12/mcf (moving target with oil)
4
Thoughts On Price – Long Term
 US Can grow demand…we have supply growth.
□ Economic expansion required
 Power demand is THE driver of natural gas demand growth
□ Need gas-fired backup (large capacity margin) to back stop
alternatives (wind, solar, and hydro).
□ Transportation fuels…I cant make the math work
 Carbon Legislation – should greatly benefit power generation demand
□ Gas >> Oil >> Coal
□ Concerns:
 Overall tax/cost of retail electricity may hinder economic growth
 Demand side management (incentive to consume less) will be
integral part of plan.
5
GOM Production
16
14
bcf/day
12
10
8
6
1996
1998
2000
2002
2004
2006
2008
“I can hardly remember how I built my bankroll, but I can't stop thinking about the way I lost it."
Mike….Rounders
6
Onshore Supply Growth!
2000
60
Onshore Gas Rig Count
Rig Count
55
1200
50
800
45
400
0
Onshore Gross Gas Production, bcf/day
Onshore Gas Production
1600
40
Jan-10
Jan-09
Jan-08
Jan-07
Jan-06
Jan-05
Jan-04
Jan-03
Jan-02
Jan-01
Jan-00
Jan-99
Jan-98
Jan-97
“Ohhhh, man I wish I could go back in time. I'd take state.”
Uncle Rico – Napoleon Dynamite
7
Gas Storage – Back to Normal
4,000
Projected Storage
Level on Nov 1st
Working Gas, bcf
3,000
2007
2,000
Max
1,000
Normal
Min
0
J
A
J
S
D
8
Shale Plays Improving Mix
Average First Year Production, mcf/day
1200
1995
1000
1996
1998
1999
800
1997
2000
2003
2002
600
2004
2007
2001
2005
400
2006
200
0
-
5,000
10,000
15,000
20,000
25,000
30,000
35,000
Onshore Gas Wells Drilled, Annually
9
Implications for Rig Count
Onshore Supply Growth (Decline), bcf/day
4
2
0
(2)
(4)
(6)
(8)
(10)
(12)
(14)
0
200
400
600
800
1000
1200
1400
1600
Onshore Gas Directed Rig Count
10
Capital Market Issues
 E&P companies can’t / won’t outspend cash flow
□ Raise Equity….nope
□ Debt…good luck
□ Sell assets…not so much
□ Cut spending/rig count…most likely
 Pipeline companies
□ How to fund new pipes?
□ Basis issues harder to solve via more pipes
□ Need to solve via lower production in near term
11
Rigcount By Operator Type
Mid-Cap E&P
1
119
114
116
124
Q3'07
200
138
143
144
145
140
134
Q4'08
4 Weeks Ago
Prior Week
10/31/08
72
74
75
73
Q3'08
Q2'08
Q1'08
Q4'07
10/31/08
4 Weeks Ago
Q4'08
Prior Week
57
59
60
59
59
59
Q2'08
54
Q1'08
60
Q4'07
80
Q3'07
41
Q2'07
41
64
20
Prior Week
10/31/08
4 Weeks Ago
Q4'08
2,306 2,335
2,374
2,287 2,264
2,138
10/31/08
Prior Week
4 Weeks Ago
Q4'08
Q3'08
Q2'08
Q1'08
Q4'07
1,896 1,917
1,988 2,020 1,976
Q3'07
1,992
Q2'07
2,500
2,300
2,100
1,900
1,700
1,500
Q1'07
1,029 1,031 1,009
Q4'06
1,002 1,028
10/31/08
925
Prior Week
825
Total U.S. Land
4 Weeks Ago
900
Q4'08
862
Q3'08
849
Q2'08
863
Q1'08
969
Q3'08
10/31/08
Prior Week
4 Weeks Ago
Q4'08
Q3'08
Q2'08
0
Q4'07
20
1,200
1,000
800
600
400
200
0
122
40
Q3'07
4 Weeks
Ago
19
Q4'08
44
Q1'07
29
42
21
Q2'07
30
121
Hybrid Utilities
Q4'06
29
28
Q1'07
32
26
Q2'08
Q3'08
45
Q4'06
31
21
Q4'07
18
Q2'07
Q4'06
17
18
32
283
Private E&P/Other
10/31/08
28
283
150
37
32
31
Q1'08
10/31/08
4 Weeks
Ago
Q4'08
Q2'08
Q4'07
Q2'07
137
50
40
30
20
10
0
Q4'07
148
Q3'07
155
153
Q2'07
153
MLP Public E&P
35
30
25
20
15
10
5
0
315
Stealth E&P
145
142
302
0
Q1'07
143
Q4'06
141
155
154
302
50
Q4'06
154
270
243
100
Integrated Oil
160
155
150
145
140
135
130
125
236
Q2'07
241
Q1'07
229
213
195
Q2'08
350
300
250
200
150
100
50
0
Q1'08
549
Q4'07
550
Q3'07
584
Q2'07
569
Q1'07
562
Q4'06
534
10/31/08
508
4 Weeks
Ago
490
Q4'08
510
Q2'08
481
Q4'07
468
Q2'07
470
Q4'06
700
600
500
400
300
200
100
0
Small-Cap E&P
Q4'06
Large-Cap E&P
Refer to page 74 in the Appendix for a listing of the publicly-traded E&P operators in each category.
12
Shale Comparison
12
10
8
Barnett
6
Woodford
Haynesville
4
Marcellus
2
0
IP's, mmcfd
EUR, bcf
NYMEX, $/mcf Well Cost, $mm
Source: CHK
13
Basin Breakeven Analysis
$3.31
Pinedale
$5.48
$3.65
East Texas Freestone
$4.48
Appalachia CBM
Average Well
$5.87
Fayetteville
$4.10
Haynesville Well 7.5mmpd IP
$4.16
$6.44
James Lime
$4.44
Marcellus Horizontal
$4.38
Core Barnett
$4.32
$6.85
$6.86
$7.01
$7.14
$4.42
Barnett Tier 1
Marginal Well
$6.37
$7.30
$4.76
Barnett Tier 2
$7.94
$5.13
Woodford Core
$8.45
$5.59
Carthage Field
$9.15
$5.72
Wolfcamp (Permian)
$9.65
$5.83
Woodford Fringe
$9.75
$6.39
Piceance
$10.45
$6.97
Gulf Coast LA
$11.40
$6.80
NE BC Shale
$11.61
$8.07
Gulf of Mexico Shelf
$-
$2
$4
$6
$8
$13.45
$10
$12
$14
Breakeven Gas Price, $/mcf
14
Basis Differentials
Regional Gas Prices and Basis Differential to Henry Hub ($/mmbtu)
Weekly Weighted Average Prices ($/MMBtu)
Basis Differential
Henry Hub
Rockies
Appalachia
California
Mid-Con
AECO
Rockies
Appalachia
California
Mid-Con
AECO
2005
Q1
Q2
Q3
Q4
$6.29
$6.95
$9.57
$12.12
$5.62
$6.03
$7.66
$9.48
$6.55
$7.27
$9.95
$12.64
$5.86
$6.24
$7.96
$9.95
$5.98
$6.34
$8.34
$9.80
$5.53
$5.90
$7.40
$9.24
($0.66)
($0.92)
($1.91)
($2.64)
$0.26
$0.32
$0.38
$0.52
($0.43)
($0.71)
($1.61)
($2.18)
($0.31)
($0.61)
($1.23)
($2.33)
($0.76)
($1.05)
($2.17)
($2.88)
Year
$8.77
$7.27
$9.21
$7.57
$7.69
$7.09
($1.51)
$0.44
($1.20)
($1.09)
($1.69)
2006
Q1
Q2
Q3
Q4
$7.77
$6.56
$6.13
$6.61
$6.54
$5.33
$4.99
$4.68
$8.12
$6.79
$6.28
$6.78
$6.82
$5.69
$5.82
$6.13
$6.63
$5.58
$5.57
$5.92
$6.02
$4.81
$4.56
$5.55
($1.22)
($1.22)
($1.14)
($1.92)
$0.36
$0.23
$0.15
$0.18
($0.95)
($0.87)
($0.31)
($0.47)
($1.14)
($0.97)
($0.56)
($0.69)
($1.75)
($1.75)
($1.57)
($1.06)
Year
$6.77
$5.39
$6.99
$6.11
$5.92
$5.23
($1.38)
$0.23
($0.65)
($0.84)
($1.53)
2007
Q1
Q2
Q3
Q4
$7.08
$7.55
$6.16
$6.92
$5.67
$3.73
$2.80
$3.99
$7.27
$7.98
$6.36
$7.19
$6.54
$6.92
$5.78
$6.41
$6.39
$6.69
$5.58
$6.05
$5.90
$5.67
$4.16
$4.92
($1.42)
($3.81)
($3.37)
($2.93)
$0.18
$0.44
$0.20
$0.27
($0.54)
($0.63)
($0.38)
($0.51)
($0.70)
($0.86)
($0.58)
($0.87)
($1.18)
($1.88)
($2.00)
($2.00)
YTD
$6.93
$4.01
$7.20
$6.40
$6.17
$5.17
($2.92)
$0.27
($0.52)
($0.76)
($1.76)
2008
Q1
Q2
$8.47
$11.21
$7.62
$8.50
$8.88
$11.64
$8.09
$10.15
$7.83
$9.65
$6.28
$8.15
($0.85)
($2.71)
$0.41
$0.43
($0.38)
($1.06)
($0.64)
($1.56)
($2.19)
($3.06)
Q3
$9.34
$6.17
$9.60
$8.32
$7.29
$6.39
($3.17)
$0.27
($1.02)
($2.04)
($2.95)
Q4 td
$6.78
$3.11
$6.97
$4.34
$3.17
$5.30
($3.66)
$0.20
($2.44)
($3.61)
($1.47)
YTD
$9.29
$6.86
$9.63
$8.25
$7.58
$6.72
($2.43)
$0.35
($1.04)
($1.71)
($2.56)
Henry
Week of
Basis Differential
Hub
Rockies
Appalachia
California
Mid-Con
AECO
Rockies
Appalachia
California
Mid-Con
AECO
11/7/2007
$6.93
$2.31
$7.22
$6.24
$5.67
$4.58
($4.62)
$0.29
($0.69)
($1.26)
($2.35)
11/7/2008
$6.57
$3.19
$6.83
$4.00
$3.11
$5.17
($3.38)
$0.26
($2.57)
($3.46)
($1.40)
15
Demand – Can Improve Long Term
90
Actual Natural Gas Demand
NPC Long Term Projection
Demand, bcf/day
80
70
60
50
40
30
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
16
Demand and Basis Risk
 Northeast US
□ Natural Gas Demand ~8.5bcf/day over past eight years.
□ Growth Prospects?
□ Rockies Express = more gas
□ Shale Development in West Virginia and Kentucky = more gas
 Does the region need the Marcellus?
 Risk to basis?
17
Natural Gas – Power Generation
US GDP and Total Power Generation Load
US generation, thousand megawatthours
4,500,000
US Natural Gas Demand driven by
electricity sector expansion and
growth
4,000,000
3,500,000
3,000,000
2,500,000
2,000,000
5,000
6,000
7,000
8,000
9,000
10,000
11,000
12,000
US GDP, $billions (2000 dollars)
18
Got Shale?
 Rationale – Transition in Public Company E&P Mindset
□ 10 years ago - hard to find, but easy to produce
 Exploration focus
 Seismic / Geology driven
□ Now - easy to find, but hard to produce
 Shale plays – going to the source rock/formations
 Presence of gas not a big risk
 Engineering risk increase
19
Resource Triangle
Source: Holditch
20
Marcellus Shale Resource
Company Net Acres
Risk %
Risked Acres Total Wells
Reserves (bcfe)
CHK
1,200,000
20%
240,000
3,000
6,612
REXX
57,000
30%
17,100
201
442
RRC
800,000
30%
240,000
2,987
6,583
SWN
98,000
30%
29,400
355
781
XCO
276,403
30%
82,921
954
2,003
XTO
152,000
30%
45,600
570
1,256
UPL
145,000
30%
43,500
544
1,198
EQT
400,000
20%
80,000
987
2,113
TOTAL
3,128,403
778,521
10,447
22,861
2,500
2,000
CHK
REXX
RRC
SWN
XCO
XTO
UPL
EQT
1,500
1,000
500
0
2008 2013 2018 2023 2028 2033 2038 2043 2048 2053
60
50
40
Rig Count
Daily Production (mmcf/d)
3,000
CHK
REXX
RRC
SWN
XCO
XTO
UPL
EQT
30
20
10
0
2008
2010
2012
2014
2016
2018
2020
2022
2024
21
Marcellus Shale
“According to the map we've only gone 4 inches.”
Harry…Dumb and Dumber
22
Haynesville Shale
 The Good
□ Takes “froth” out of the Marcellus Shale
 The Bad
□ Pulls some of the necessary capital resources away from the region
 The Ugly
□ Creates a large amount of supply-side/production growth focus
23
Haynesville Shale Activity Overview
GDP – Vertical wells
HK – 1H 08 Announcements
Hall 5 No. 1 (50% WI non-op)
Caddo Parish; Central Pine Island Field
Completion Phase
Elm Grove Plantation #63 (100% WI)
Bossier Parish; T-R: 16N-11W, sec 9
IP ~ 16.8 MMcf/d (26/64 choke)
11,005 ft. TVD, 3,880 ft. lateral
Taylor Sealey No. 1 (100% WI)
Panola/Rusk Counties; Minden Field
IP ~ 2.6 MMcfe/d (22/64 choke)
Hutchinson 9-6 (91% WI)
Caddo Parish; T-R: 15N-12W, sec 9
IP ~ 16.7 MMcf/d (22/64 choke)
11,222 ft. TVD
Lutheran Church No. 4 (100% WI)
Panola/Rusk Counties; Beckville Field
IP ~ 1.6 MMcfe/d
Current Players
Berry (4,500 Net)
Cabot (135,000 Gross)
Chesapeake (440,000 Net) &
Plains E&P (110,000 Net)
Comstock (53,000 Net)
Devon (483,000 Net)
Ellora (70,600 Net)
El Paso (42,500 Net)
EnCana/Shell (370,000 Net)
Encore (21,200 Net)
EXCO (107,000 Net)
Forest (91,000 Net)
GMX Resources (38,500 Net)
Goodrich (60,500 Net)
J-W Operating (Acreage n/a)
Penn Virginia (60,000 Net)
Petrohawk (300,000 Net)
Questar (28,000 Net)
XTO (100,000 Net)
CHK (20% Plains E&P)
PVA – 5/30/08 Announcement
Fogle #5-H (100% WI)
Harrison County; South section
IP ~ 8 MMcf/d
11,378 ft. TVD, 3,861 ft. lateral
Source: Company Filings, Investor Presentations.
COG – 11 Vertical wells
Rusk County; Minden Field
IP ~ 650-2,300 Mcf/d
11,596 ft. TVD
Trawick: 3.3 MMcf/d test
County Line test - 4Q 08
Caddo Parish; T-R: 15N-15W
1) Feist 28-#01 (section 28)
IP ~ 2.6 MMcf/d (9/64 choke)
11,596 ft. TVD
2) Milton Crow 27-1H (section 27)
IP ~ 14 MMcf/d (24/64 choke)
11,744 ft. TVD
ECA (50% Shell)
Sabine Parish: IP ~ 8 MMcf/d
Red River Parish*: IP ~ 15 MMcf/d
24
*T-R: 13N-9W
24
Haynesville Shale Resource Summary
Company
DVN
CHK
HK
XCO
PXP
APC
XTO
GDP
GMXR
TOTAL
Net Acres
Risk %
483,000
440,000
300,000
125,000
110,000
100,000
100,000
56,000
38,400
1,752,455
50%
50%
50%
50%
50%
50%
50%
50%
50%
Risked Acres Total Wells
Reserves (bcfe)
241,500
2,421
9,931
220,000
2,558
10,905
150,000
1,875
8,526
62,500
781
3,035
55,000
496
2,112
50,000
433
1,846
50,000
576
2,046
28,000
350
1,466
19,228
240
1,025
876,228
9,730
40,892
XTO
9,000
XTO
180
APC
PXP
8,000
APC
7,000
GMXR
GDP
140
GMXR
XCO
GDP
6,000
120
HK
XCO
5,000
HK
4,000
DVN
Rig Count
Daily Production (mmcf/d)
160
PXP
100
DVN
CHK
80
CHK
3,000
60
2,000
40
1,000
20
0
2008
0
2013
2018
2023
2028
2033
2038
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
25
Shale Development Issues
 Macro Environment/Credit Markets Matter
 Pipeline Infrastructure – Who builds the pipelines?
 Onshore Production Growth:
□ Implications to overall gas price
□ Implications to basis differential
 Growth Companies (i.e., deficit spenders) looking for
partners/sell assets
 Location Matters – Shale plays have lots of good and bad
acreage
26
Emerging Shales
 Canada
□ Utica (Eastern Canada)
□ Montney-Doig – NE BC
□ Horn River Basin – NE BC
 United States
□ Haynesville
□ Marcellus
 Lots of other shales in Appalachia
□ Utica (NY)
□ Pearsall – S. TX
□ Some shales in Rockies…but basis differential an issue
27
Not All Shales Work
 Palo Duro Canyon
□ Texas Panhandle
 New Albany Shale – Indiana
□ Antrim look-alike…except no natural fractures
 West Texas Barnett
□ Too early to stick a fork in….but results les than impressive
 Mississippi / Alabama Shales – still early but…
□ Lots of wells with no positive well news
28
2009 Free Cash Flow at Different Commodity Prices
$5,000
$7 gas, $70 oil
$6 gas, $60 oil
$3,000
$5 gas, $50 oil
Free Cash Flow ($mm)
$1,000
($1,000)
($3,000)
($5,000)
($7,000)
($9,000)
($11,000)
Large-Caps
Mid-Caps
Sm all-Caps
29
Gating Items - People - Revenge Of the Nerds!
 Horizontal Drilling
□ Proper Azimuth
□ Optimum Length
 Completion – Hydraulic Fracture…can’t boilerplate
□ Multiple Stages, Simultaneous Fracturing
□ Slickwater vs. Gelled Fracs
□ Regionally Specific
□ Surfactant, 100 mesh, proppant transport etc.
 Well Spacing - will drive ultimate recovery
□ Depends on Completions and Reservoir
□ Fracture Mapping with Micro-seismic helps
 Reservoir Modeling difficult
□ Natural fracture spacing/orientation
□ Isotherm, gas-in-place, free gas porosity
“No one will really be free until nerd persecution ends.”
Gilbert – Revenge of the Nerds
30
Change!
Gas Market Implications
 Carbon Tax (er….Legislation) is Coming
□ Natural Gas should benefit
 Lower carbon than oil and coal
□ Drilling
 Wait and see
□ Magnitude of Tax?
 Skeptic says taxing fossil fuels last great gov’t revenue
source
□ Demand side management
 Expect legislation to encourage lower consumption
"Oh, uh, there won't be any money, but when you die, on your
deathbed, you will receive total consciousness." So I got that goin'
for me, which is nice
Caddyshack - Carl Spackler
31
Conclusion
Formula for success:
“Rise early, work hard, strike oil.”
J. Paul Getty
Formula for success - 2008:
“Rise early, work hard, buy acreage.”
Formula for success - 2009:
“Rise early, work hard, survive.”
32
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other tax analyses) related to those benefits, with no limitations imposed by Tudor, Pickering, Holt & Co.
The information contained herein is confidential (except for information relating to United States tax
issues) and may not be reproduced in whole or in part.
Tudor, Pickering, Holt & Co. assumes no responsibility for independent verification of third-party
information and has relied on such information being complete and accurate in all material respects. To
the extent such information includes estimates and forecasts of future financial performance (including
estimates of potential cost savings and synergies) prepared by, reviewed or discussed with the
managements of your company and/ or other potential transaction participants or obtained from public
sources, we have assumed that such estimates and forecasts have been reasonably prepared on bases
reflecting the best currently available estimates and judgments of such managements (or, with respect to
estimates and forecasts obtained from public sources, represent reasonable estimates). These materials
were designed for use by specific persons familiar with the business and the affairs of your company and
Tudor, Pickering, Holt & Co. materials.
Under no circumstances is this presentation to be used or considered as an offer to sell or a solicitation of
any offer to buy, any security. Prior to making any trade, you should discuss with your professional tax,
accounting, or regulatory advisers how such particular trade(s) affect you. This brief statement does not
disclose all of the risks and other significant aspects of entering into any particular transaction.
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Tudor, Pickering, Holt & Co., LLC is an integrated energy investment and merchant banking boutique, providing high
quality advice and services to institutional and corporate clients. Through the company’s broker-dealer, Tudor,
Pickering, Holt & Co. Securities, Inc., the company offers securities and investment banking services to the energy
community.
The firm, headquartered in Houston, Texas, was formed through the 2007 combination of Tudor Capital and Pickering
Energy Partners, Inc. and today has approximately 70 employees. Pickering Energy Partners was founded in 2004 and
has quickly grown to be one of the most highly regarded equity research, sales and trading firms covering the
upstream, midstream and oilfield service sectors. This expertise was complemented by the addition of Tudor´s
investment banking team, which provides focused advisory and financing services to its clients.
Contact Us
Houston (Research, Sales and Trading): 713-333-2960
Houston (Investment Banking): 713-333-7100
Denver (Sales): 303-300-1902
Denver (Investment Banking): 303-300-1905
www.TudorPickering.com
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