Upload
katina
View
19
Download
1
Tags:
Embed Size (px)
DESCRIPTION
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.*. Natural Gas 12 Month Strip. 2. Futures – Are They Accurate?. Thoughts On Price. Price range 2001 : - PowerPoint PPT Presentation
Citation preview
Natural GasIn the Production Growth Vortex
Energy Finance Discussion Group
Denver
November 11, 2008
David Pursell
*Important Disclosures on page 33 of this document.*
22
Natural Gas 12 Month Strip
$6
$7
$8
$9
$10
$11
$12
$13
$14Aug
-05
Oct
-05
Dec
-05
Feb-
06
Apr
-06
Jun-
06
Aug
-06
Oct
-06
Dec
-06
Feb-
07
Apr
-07
Jun-
07
Aug
-07
Oct
-07
Dec
-07
Feb-
08
Apr
-08
Jun-
08
Aug
-08
Oct
-08
$/m
cf
3
Futures – Are They Accurate?
-60%
-30%
0%
30%
60%
Jan
-99
Jan
-01
Jan
-03
Jan
-05
Jan
-07
Jan
-09
% D
iffe
rne
ce N
YM
EX
12
mo
Str
ip a
nd
Act
ua
l StripToo High
(Strip Too Low)
4
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
5
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
66
GOM Production
6
8
10
12
14
16
1996 1998 2000 2002 2004 2006 2008
bcf
/day
“I can hardly remember how I built my bankroll, but I can't stop thinking about the way I lost it."
Mike….Rounders
77
Onshore Supply Growth!
“Ohhhh, man I wish I could go back in time. I'd take state.”
Uncle Rico – Napoleon Dynamite
40
45
50
55
60
0
400
800
1200
1600
2000
Jan-97
Jan-98
Jan-99
Jan-00
Jan-01
Jan-02
Jan-03
Jan-04
Jan-05
Jan-06
Jan-07
Jan-08
Jan-09
Jan-10
Onshore G
ross Gas P
roduction, bcf/day
Rig
Cou
ntOnshore Gas Rig Count
Onshore Gas Production
8
Gas Storage – Back to Normal
8
0
1,000
2,000
3,000
4,000
J A J S D
Wo
rkin
g G
as,
bcf
Normal
Max
2007
Min
Projected Storage Level on Nov 1st
9
Shale Plays Improving Mix
9
0
200
400
600
800
1000
1200
- 5,000 10,000 15,000 20,000 25,000 30,000 35,000
Ave
rag
e F
irs
t Y
ea
r P
rod
uc
tio
n,
mc
f/d
ay
Onshore Gas Wells Drilled, Annually
2003
2000
20042001
1995
19981999
1996
1997
2002
20052006
2007
10
Implications for Rig Count
10
(14)
(12)
(10)
(8)
(6)
(4)
(2)
0
2
4
0 200 400 600 800 1000 1200 1400 1600
On
sho
re S
up
ply
Gro
wth
(D
ecl
ine
), b
cf/d
ay
Onshore Gas Directed Rig Count
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
12
Rigcount By Operator Type
1Refer to page 74 in the Appendix for a listing of the publicly-traded E&P operators in each category.
Large-Cap E&P
470 468 481 510 490 508 534 562 569 584 550 549
0100200300400500600700
Q4'
06
Q2'
07
Q4'
07
Q2'
08
Q4'
08
4 W
eeks
Ago
10/3
1/08
Mid-Cap E&P
195 213 229 241 236 243270
302 302 315283 283
050
100150200250300350
Q4'
06
Q1'
07
Q2'
07
Q3'
07
Q4'
07
Q1'
08
Q2'
08
Q3'
08
Q4'
08
4 W
eeks
Ago
Prio
r W
eek
10/3
1/08
Small-Cap E&P
119 114 116 124 121 122138 143 144 145 140 134
0
50
100
150
200
Q4'
06
Q1'
07
Q2'
07
Q3'
07
Q4'
07
Q1'
08
Q2'
08
Q3'
08
Q4'
08
4 W
eeks
Ago
Prio
r W
eek
10/3
1/08
Integrated Oil
141143
137142
154 154
145
155153 153
148
155
125130135140145150155160
Q4'
06
Q2'
07
Q4'
07
Q2'
08
Q4'
08
4 W
eeks
Ago
10/3
1/08
Stealth E&P
2821
29 29 31 3237
45 42 44 41 41
0
10
20
30
40
50
Q4'
06
Q1'
07
Q2'
07
Q3'
07
Q4'
07
Q1'
08
Q2'
08
Q3'
08
Q4'
08
4 W
eeks
Ago
Prio
r W
eek
10/3
1/08
Hybrid Utilities
54 57 59 60 59 59 59 6472 74 75 73
0
20
40
60
80
Q4'
06
Q1'
07
Q2'
07
Q3'
07
Q4'
07
Q1'
08
Q2'
08
Q3'
08
Q4'
08
4 W
eeks
Ago
Prio
r W
eek
10/3
1/08
MLP Public E&P
17 18 1821
2832 31 32
2630
19 20
05
101520253035
Q4'
06
Q2'
07
Q4'
07
Q2'
08
Q4'
08
4 W
eeks
Ago
10/3
1/08
Private E&P/Other
969863 849 862 900 825
925 1,0021,028 1,0291,0311,009
0200400600800
1,0001,200
Q4'
06
Q1'
07
Q2'
07
Q3'
07
Q4'
07
Q1'
08
Q2'
08
Q3'
08
Q4'
08
4 W
eeks
Ago
Prio
r W
eek
10/3
1/08
Total U.S. Land
1,9921,896 1,917
1,988 2,020 1,976
2,138
2,306 2,335 2,3742,287 2,264
1,500
1,700
1,900
2,100
2,300
2,500
Q4'
06
Q1'
07
Q2'
07
Q3'
07
Q4'
07
Q1'
08
Q2'
08
Q3'
08
Q4'
08
4 W
eeks
Ago
Prio
r W
eek
10/3
1/08
13
Shale Comparison
13
0
2
4
6
8
10
12
IP's, mmcfd EUR, bcf NYMEX, $/mcf Well Cost, $mm
Barnett
Woodford
Haynesville
Marcellus
Source: CHK
1414
Basin Breakeven Analysis
$13.45
$11.61
$11.40
$10.45
$9.75
$9.65
$9.15
$8.45
$7.94
$7.30
$7.14
$7.01
$6.86
$6.85
$6.44
$6.37
$5.87
$5.48
$8.07
$6.80
$6.97
$6.39
$5.83
$5.72
$5.59
$5.13
$4.76
$4.42
$4.32
$4.38
$4.44
$4.16
$4.10
$4.48
$3.65
$3.31
$- $2 $4 $6 $8 $10 $12 $14
Gulf of Mexico Shelf
NE BC Shale
Gulf Coast LA
Piceance
Woodford Fringe
Wolfcamp (Permian)
Carthage Field
Woodford Core
Barnett Tier 2
Barnett Tier 1
Core Barnett
Marcellus Horizontal
J ames Lime
Haynesville Well 7.5mmpd IP
Fayetteville
Appalachia CBM
East Texas Freestone
Pinedale
Breakeven Gas Price, $/mcf
Average Well
Marginal Well
Basis Differentials
15
Henry Hub Rockies Appalachia California Mid-Con AECO Rockies Appalachia California Mid-Con AECO
2005
Q1 $6.29 $5.62 $6.55 $5.86 $5.98 $5.53 ($0.66) $0.26 ($0.43) ($0.31) ($0.76)
Q2 $6.95 $6.03 $7.27 $6.24 $6.34 $5.90 ($0.92) $0.32 ($0.71) ($0.61) ($1.05)
Q3 $9.57 $7.66 $9.95 $7.96 $8.34 $7.40 ($1.91) $0.38 ($1.61) ($1.23) ($2.17)
Q4 $12.12 $9.48 $12.64 $9.95 $9.80 $9.24 ($2.64) $0.52 ($2.18) ($2.33) ($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 $7.77 $6.54 $8.12 $6.82 $6.63 $6.02 ($1.22) $0.36 ($0.95) ($1.14) ($1.75)
Q2 $6.56 $5.33 $6.79 $5.69 $5.58 $4.81 ($1.22) $0.23 ($0.87) ($0.97) ($1.75)
Q3 $6.13 $4.99 $6.28 $5.82 $5.57 $4.56 ($1.14) $0.15 ($0.31) ($0.56) ($1.57)
Q4 $6.61 $4.68 $6.78 $6.13 $5.92 $5.55 ($1.92) $0.18 ($0.47) ($0.69) ($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 $7.08 $5.67 $7.27 $6.54 $6.39 $5.90 ($1.42) $0.18 ($0.54) ($0.70) ($1.18)
Q2 $7.55 $3.73 $7.98 $6.92 $6.69 $5.67 ($3.81) $0.44 ($0.63) ($0.86) ($1.88)
Q3 $6.16 $2.80 $6.36 $5.78 $5.58 $4.16 ($3.37) $0.20 ($0.38) ($0.58) ($2.00)
Q4 $6.92 $3.99 $7.19 $6.41 $6.05 $4.92 ($2.93) $0.27 ($0.51) ($0.87) ($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 $8.47 $7.62 $8.88 $8.09 $7.83 $6.28 ($0.85) $0.41 ($0.38) ($0.64) ($2.19)
Q2 $11.21 $8.50 $11.64 $10.15 $9.65 $8.15 ($2.71) $0.43 ($1.06) ($1.56) ($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 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) ($1.40)
Basis Differential
Regional Gas Prices and Basis Differential to Henry Hub ($/mmbtu)Weekly Weighted Average Prices ($/MMBtu) Basis Differential
16
Demand – Can Improve Long Term
16
30
40
50
60
70
80
90
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
De
ma
nd
, bcf
/da
y
Actual Natural Gas Demand
NPC Long Term Projection
17
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
1818
Natural Gas – Power Generation
2,000,000
2,500,000
3,000,000
3,500,000
4,000,000
4,500,000
5,000 6,000 7,000 8,000 9,000 10,000 11,000 12,000
US GDP, $billions (2000 dollars)
US
gen
erat
ion
, th
ou
san
d m
egaw
atth
ou
rs
US GDP and Total Power Generation Load
US Natural Gas Demand driven by
electricity sector expansion and
growth
19
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
20
Resource Triangle
Source: Holditch
21
Marcellus Shale ResourceCompany 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
0
500
1,000
1,500
2,000
2,500
3,000
2008 2013 2018 2023 2028 2033 2038 2043 2048 2053
Dai
ly P
rod
uct
ion
(m
mcf
/d)
CHK REXX
RRC SWN
XCO XTO
UPL EQT
0
10
20
30
40
50
60
2008 2010 2012 2014 2016 2018 2020 2022 2024
Rig
Co
un
t
CHK REXX
RRC SWN
XCO XTO
UPL EQT
2222
Marcellus Shale
“According to the map we've only gone 4 inches.”
Harry…Dumb and Dumber
23
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
24
Haynesville Shale Activity Overview
24
Source: Company Filings, Investor Presentations.
24
GDP – Vertical wellsHall 5 No. 1 (50% WI non-op)Caddo Parish; Central Pine Island FieldCompletion Phase
Taylor Sealey No. 1 (100% WI)Panola/Rusk Counties; Minden FieldIP ~ 2.6 MMcfe/d (22/64 choke)
Lutheran Church No. 4 (100% WI)Panola/Rusk Counties; Beckville FieldIP ~ 1.6 MMcfe/d
ECA (50% Shell)Sabine Parish: IP ~ 8 MMcf/dRed River Parish*: IP ~ 15 MMcf/d*T-R: 13N-9W
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)Caddo Parish; T-R: 15N-15W1) 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
PVA – 5/30/08 AnnouncementFogle #5-H (100% WI)Harrison County; South sectionIP ~ 8 MMcf/d11,378 ft. TVD, 3,861 ft. lateral
HK – 1H 08 AnnouncementsElm Grove Plantation #63 (100% WI)Bossier Parish; T-R: 16N-11W, sec 9IP ~ 16.8 MMcf/d (26/64 choke)11,005 ft. TVD, 3,880 ft. lateral
Hutchinson 9-6 (91% WI)Caddo Parish; T-R: 15N-12W, sec 9IP ~ 16.7 MMcf/d (22/64 choke)11,222 ft. TVD
COG – 11 Vertical wellsRusk County; Minden FieldIP ~ 650-2,300 Mcf/d11,596 ft. TVDTrawick: 3.3 MMcf/d testCounty Line test - 4Q 08
2525
Haynesville Shale Resource Summary
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
9,000
2008 2013 2018 2023 2028 2033 2038
Dai
ly P
rodu
ctio
n (m
mcf
/d)
XTO
PXP
APC
GMXR
GDP
XCO
HK
DVN
CHK
0
20
40
60
80
100
120
140
160
180
2008 2009 2010 2011 2012 2013 2014 2015 2016 2017
Rig
Cou
nt
XTO
APC
GMXR
GDP
XCO
HK
PXP
DVN
CHK
Company Net Acres Risk % Risked Acres Total Wells Reserves (bcfe)DVN 483,000 50% 241,500 2,421 9,931 CHK 440,000 50% 220,000 2,558 10,905 HK 300,000 50% 150,000 1,875 8,526 XCO 125,000 50% 62,500 781 3,035 PXP 110,000 50% 55,000 496 2,112 APC 100,000 50% 50,000 433 1,846 XTO 100,000 50% 50,000 576 2,046 GDP 56,000 50% 28,000 350 1,466 GMXR 38,400 50% 19,228 240 1,025 TOTAL 1,752,455 876,228 9,730 40,892
26
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
27
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
28
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
2929
2009 Free Cash Flow at Different Commodity Prices
($11,000)
($9,000)
($7,000)
($5,000)
($3,000)
($1,000)
$1,000
$3,000
$5,000
Large-Caps Mid-Caps Small-Caps
Fre
e C
ash
Flo
w (
$mm
)
$7 gas, $70 oil
$6 gas, $60 oil
$5 gas, $50 oil
3030
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
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
31
"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
32
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
3333
Disclaimer
Tudor, Pickering, Holt & Co. does not provide accounting, tax or legal advice. In addition, we mutually agree that, subject to applicable law, you (and your employees, representatives and other agents) may disclose any aspects of any potential transaction or structure described herein that are necessary to support any U.S. federal income tax benefits, and all materials of any kind (including tax opinions and 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.
3434
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 UsHouston (Research, Sales and Trading): 713-333-2960
Houston (Investment Banking): 713-333-7100Denver (Sales): 303-300-1902
Denver (Investment Banking): 303-300-1905
www.TudorPickering.com