sipes/hapl luncheon houston, tx david heikkinen [email protected] 713-333-2975...
TRANSCRIPT
SIPES/HAPL LuncheonHouston, TX
David Heikkinendheikkinen
@tudorpickering.com713-333-2975
*Disclosures on page 31* November 19, 2009
2
Commodities (before peak)CRUDE OIL NATURAL GAS COAL
WHEAT US DOLLAR GOLD
$20
$40
$60
$80
$100
$120
$140
$160
Jan-
06
Apr
-06
Jul-
06
Oct
-06
Jan-
07
Apr
-07
Jul-
07
Oct
-07
Jan-
08
Apr
-08
Jul-
08
$2
$4
$6
$8
$10
$12
$14
$16
Jan-
06
Apr
-06
Jul-
06
Oct
-06
Jan-
07
Apr
-07
Jul-
07
Oct
-07
Jan-
08
Apr
-08
Jul-
08
$20
$40
$60
$80
$100
$120
$140
$160
Jan-
06
Apr
-06
Jul-
06
Oct
-06
Jan-
07
Apr
-07
Jul-
07
Oct
-07
Jan-
08
Apr
-08
Jul-
08
$200
$400
$600
$800
$1,000
$1,200
$1,400
Jan-
06
Apr
-06
Jul-
06
Oct
-06
Jan-
07
Apr
-07
Jul-
07
Oct
-07
Jan-
08
Apr
-08
Jul-
08
$70
$75
$80
$85
$90
$95Ja
n-06
Apr
-06
Jul-
06
Oct
-06
Jan-
07
Apr
-07
Jul-
07
Oct
-07
Jan-
08
Apr
-08
Jul-
08
$500
$600
$700
$800
$900
$1,000
$1,100
Jan-
06
Apr
-06
Jul-
06
Oct
-06
Jan-
07
Apr
-07
Jul-
07
Oct
-07
Jan-
08
Apr
-08
Jul-
08
3
Commodities (to current)CRUDE OIL NATURAL GAS COAL
WHEAT US DOLLAR GOLD
$20
$40
$60
$80
$100
$120
$140
$160
Jan-
06
Jun-
06
Nov
-06
Apr
-07
Sep-
07
Feb-
08
Jul-
08
Dec
-08
May
-09
Oct
-09
$2
$4
$6
$8
$10
$12
$14
$16
Jan-
06
Jun-
06
Nov
-06
Apr
-07
Sep-
07
Feb-
08
Jul-
08
Dec
-08
May
-09
Oct
-09
$20
$40
$60
$80
$100
$120
$140
$160
Jan-
06
Jun-
06
Nov
-06
Apr
-07
Sep-
07
Feb-
08
Jul-
08
Dec
-08
May
-09
Oct
-09
$200
$400
$600
$800
$1,000
$1,200
$1,400
Jan-
06
Jun-
06
Nov
-06
Apr
-07
Sep-
07
Feb-
08
Jul-
08
Dec
-08
May
-09
Oct
-09
$70
$75
$80
$85
$90
$95Ja
n-06
Jun-
06
Nov
-06
Apr
-07
Sep-
07
Feb-
08
Jul-
08
Dec
-08
May
-09
Oct
-09
$500
$600
$700
$800
$900
$1,000
$1,100
$1,200
Jan-
06
Jun-
06
Nov
-06
Apr
-07
Sep-
07
Feb-
08
Jul-
08
Dec
-08
May
-09
Oct
-09
4
Futures – Are They Accurate?
"That's mathematics, son. You can argue with me, but
you can't argue with figures.“ Foghorn
Leghorn
-60%
-30%
0%
30%
60%
90%
120%
Jan-99
Jan-01
Jan-03
Jan-05
Jan-07
Jan-09
NYM
EX S
trip
, Pr
edic
ted
- Ac
tual
, %
Strip Too High
(Strip Too Low)
5
Shalemania
Long Term – ample gas supply
□ Need fewer rigs in fewer places
□ Shales will grow
□ Everywhere else declines
Near Term – declines kicking in
□ Current rig count unsustainable…too low
□ 2010 – activity pick-up…but service pricing?
Crude oil
□ The Rod Tidwell of energy “You’re loving me now!”
□ Lots of desire to “get oily”…but harder to accomplish
6
Why Shale? Meet GOM Production
“I can hardly remember how I built my bankroll, but I can't stop thinking about the way I lost it." Mike….Rounders
6
8
10
12
14
16
1996 1998 2000 2002 2004 2006 2008 2010
bc
f/d
ay
US Major Producing Basins
7Source: TPH Estimates
32 separate production regions…including the 6 major shale plays
“According to the map we've only gone 4 inches.” Harry…Dumb and Dumber
TPH Natural Gas Wellhead Supply Model
Define basin area
Pull historical production data from HPDI
Review data and analyze vintage performance
Construct base & new well models
Develop theoretical type curves
Tie rig count to new production
Match new well type curve model to actual performance of wells completed in 2008
History match the base wedge model to actual basin production
Aggregate base and new well models
Check total history match
Combine rig count projection with forward type curve and base decline models
Run sensitivities
+ +
Base New Wells Forecast
=
Supply Model
8
Barnett Production
0
1,000
2,000
3,000
4,000
5,000
6,000
01/ 07 04/ 07 07/ 07 10/ 07 01/ 08 04/ 08 07/ 08 10/ 08 01/ 09 04/ 09 07/ 09 10/ 09
Nat
ural
Gas
Pro
duct
ion
(mm
cf/d
)
Historical Production Q108 Q208 Q308 Q408 Base Decline
Step I: Developing the Basin Type Curve
Base production (12/07) includes ~8,400 wells with total production of 3.7 bcf/d
2008 activity: 185 rigs drilled 2,930 new wells, increasing production by 32% or 1.2 bcf/d
726wells
791wells
728wells
685wells
~8,400 wellsin YE07 base
9
Q1 Q2
Q3 Q4
New Wells
Base Production
Barnett Shale
Source: Rig Count = Rig Data, Production History = HPDI and EIA, Forecast = TPH Estimates
Note: Wellhead production is wet gas
Step II: Quarterly Type Curve History Match
Barnett Shale: Q4'08 Type Curve Math
0
200
400
600
800
1,000
1,200
1,400
1,600
1,800
2,000
0 2 4 6 8 10 12 14 16 18 20 22 24
Month
Dai
ly P
rodu
ctio
n (m
cf/d
)
Forecast Actual Data
Barnett Shale: Q3'08 Type Curve Match
0
200
400
600
800
1,000
1,200
1,400
1,600
1,800
2,000
0 2 4 6 8 10 12 14 16 18 20 22 24
Month
Dai
ly P
rodu
ctio
n (m
cf/d
)
Forecast Actual Data
Barnett Shale: Q1'08 Type Curve Match
0
200
400
600
800
1,000
1,200
1,400
1,600
1,800
2,000
0 2 4 6 8 10 12 14 16 18 20 22 24
Month
Daily P
roduct
ion (m
cf/d
)
Forecast Actual Data
Barnett Shale: Q2'08 Type Curve Math
0
200
400
600
800
1,000
1,200
1,400
1,600
1,800
2,000
0 2 4 6 8 10 12 14 16 18 20 22 24
Month
Daily P
roduct
ion (m
cf/d
)
Forecast Actual Data
Peak Rate = 1,550 mcf/d1st Year Decline = -60%Hyperbolic factor = 1.5Final Decline = -5%EUR = 2,000 mmcf
Peak Rate = 1,550 mcf/d1st Year Decline = -60%Hyperbolic factor = 1.5Final Decline = -5%EUR = 2,000 mmcf
Peak Rate = 1,450 mcf/d1st Year Decline = -60%Hyperbolic factor = 1.5Final Decline = -5%EUR = 1,900 mmcf
Peak Rate = 1,650 mcf/d1st Year Decline = -60%Hyperbolic factor = 1.5Final Decline = -5%EUR = 2,100 mmcf
Variation in production characteristics from quarter to quarter is small
10Source: Rig Count = Rig Data, Production History = HPDI and EIA, Forecast = TPH Estimates
Note: Wellhead production is wet gas
Barnett Production Forecast - 33% First Year Decline Rate
0
1,000
2,000
3,000
4,000
5,000
6,000
01/ 07 04/ 07 07/ 07 10/ 07 01/ 08 04/ 08 07/ 08 10/ 08 01/ 09 04/ 09 07/ 09 10/ 09
Nat
ural
Gas
Pro
duct
ion
(mm
cf/d
)
Historical Production Calibration
Step III: Understanding Base DeclineBiggest factor in calibrating the Barnett is the base production
decline
All wells completed prior to ‘08 used to calculate base decline
Calibration requires balancing hyperbolic factor, curve fit of base production, and performance of new wells completed
Assume: Hyperbolic factor for base production is the same as ‘08 new well groups. An important and realistic constraint for a ‘pure’ play region
Regression modeling suggests a -33% base decline rate
Base Decline Match
Historical Production
[wells completed prior to 2008]
11Source: Rig Count = Rig Data, Production History = HPDI and EIA, Forecast = TPH Estimates
Note: Wellhead production is wet gas
Step IV: Calibrating Base Decline
Known data points: 12/07 production (start = 3.7 bcf/d) and 12/08 production (exit = 4.9 bcf/d)
Layer in 2008 growth using 2,930 wells drilled and type curves
Given the 1.5 b-factor, solve for implied base decline rate…in this case -33% for the Barnett
Barnett Production Forecast - 33% First Year Decline
0
1,000
2,000
3,000
4,000
5,000
6,000
01/ 07 04/ 07 07/ 07 10/ 07 01/ 08 04/ 08 07/ 08 10/ 08 01/ 09 04/ 09 07/ 09 10/ 09
Nat
ural
Gas
Pro
duct
ion
(mm
cf/d
)
Actual Base Decline Historical Production Calibration Base Calibration
Known
3.7 bcf/d
Known
4.9 bcf/d
High confidence in production from new well “wedges”
R2 = 0.98
R2 = 0.98
12
α = decline in base production
α = 33%
Barnett Shale
Source: Rig Count = Rig Data, Production History = HPDI and EIA, Forecast = TPH Estimates
Note: Wellhead production is wet gas
US Wellhead Supply Forecast[Barnett Shale]
0.0
1.0
2.0
3.0
4.0
5.0
6.0
12/ 99 12/ 00 12/ 01 12/ 02 12/ 03 12/ 04 12/ 05 12/ 06 12/ 07 12/ 08 12/ 09 12/ 10 12/ 11 12/ 12 12/ 13
Nat
ural
Gas
Pro
duct
ion
(bcf
/d)
0
100
200
300
400
500
600
Rig Count
Historical Production Forecasted Production Rig Count
Barnett Scenario – Holding Rig Count Flat
‘09 exit rate down 0.6 bcf/d y/y
Production bottoms mid-2011 at 4.0 bcf/d and stays relatively flat through 2013 as drilling balances field declines
Rig Count
Production Forecast
Production History
13Source: Rig Count = Rig Data, Production History = HPDI and EIA, Forecast = TPH Estimates
Note: Wellhead production is wet gas.
US Wellhead Supply Forecast[South Texas]
0.0
1.0
2.0
3.0
4.0
5.0
6.0
12/ 99 12/ 00 12/ 01 12/ 02 12/ 03 12/ 04 12/ 05 12/ 06 12/ 07 12/ 08 12/ 09 12/ 10 12/ 11 12/ 12 12/ 13
Nat
ural
Gas
Pro
duct
ion
(bcf
/d)
0
100
200
300
400
500
600
Rig Count
Historical Production Forecasted Production Rig Count
South Texas Scenario – Holding Rig Count Flat
Declines already occurring in this basin
‘09 exit rate down 0.9 bcf/d y/y
‘10 exit rate down 0.6 bcf/d y/y
This a mature basin!Rig Count
Production Forecast
Production History
14Source: Rig Count = Rig Data, Production History = HPDI and EIA, Forecast = TPH Estimates
Note: Wellhead production is wet gas
You don't need to be thinking immortality -- you need to be thinking hit the 7 iron! Romeo Posar: Tin Cup
What Does it Mean?Current
Rig count unsustainably low
□ 2010 production declines 10%...2011 an additional 5%
□ Gas Prices need to rise to entice more drilling
Gas Production is falling…now!
Longer Term
Fewer rigs in fewer places
□ 1500 total rigs in 2011…compared to 2350 peak in 2008
□ Marginal cost of supply matters…$6.5/mcf medium/long term
Asset values (service and E&P) will reflect growth and non-growth areas (i.e, GOM analogy)
15
US Wellhead Supply Forecast[Onshore + Offshore]
0
10
20
30
40
50
60
70
80
12/ 99 12/ 00 12/ 01 12/ 02 12/ 03 12/ 04 12/ 05 12/ 06 12/ 07 12/ 08 12/ 09 12/ 10 12/ 11 12/ 12 12/ 13
Nat
ural
Gas
Pro
duct
ion
(bcf
/d)
0
500
1000
1500
2000
2500
3000
3500
4000
Rig Count
Historical Production Flat Rig Count ForecastFlat Rig Count + Shale Growth Forecast Flat Rig + Shale Growth + Non-Shale Growth ForecastRig Count
Step 3 – Add Non-Shales (Our Base Case)
Rig Count
Production Forecast
Production History
16
~1,500 total rigs long term
2010 rig count build (peaking at 1,640 rigs)
Pullback (~120 rigs) in 2011 as market is oversupplied
Shift to unconventional (shale) drilling is key
Only ~1,500 rigs needed to balance market longer term…shales and non-shales
US Wellhead Supply Forecast[Shale Production]
0
5
10
15
20
25
12/ 99 12/ 00 12/ 01 12/ 02 12/ 03 12/ 04 12/ 05 12/ 06 12/ 07 12/ 08 12/ 09 12/ 10 12/ 11 12/ 12 12/ 13
Nat
ural
Gas
Pro
duct
ion
(bcf
/d)
0
500
1,000
1,500
2,000
2,500
Rig Count
Historical Production Forecasted Production Rig Count
Production History
Shales – Fueling The Engine Of Growth
Rig Count
Production Forecast
17
Shale gas 12/08
□ Production = 8 bcf/d (12% of US)
□ Rig Count = 357 rigs (18% of US)
Shale gas 12/13
□ Production = 22 bcf/d (35% of US)
□ Rig Count = 614 rigs (41% of US)
Shale Basin 12/08a 7/09e 12/13e
Barnett 5.0 4.7 5.5
Woodford 0.9 0.9 1.5
Fayetteville 1.3 1.5 2.8
Haynesville 0.2 1.0 6.3
Marcellus 0.0 0.2 4.4
Eagle Ford 0.0 0.0 0.7
Antrim 0.4 0.4 0.3
Total 7.8 8.7 21.5
Daily Gas Volumes, bcf/d
The only thing better than one crawfish dinner is five crawfish dinners. Coach Red Beaulieu – The Waterboy
U.S. Gas Supply Growth (TPH & Non-TPH E&P Companies)
-15.0%
-10.0%
-5.0%
0.0%
5.0%
10.0%
15.0%
20.0%
25.0%
30.0%
2005 2006 2007 2008 2009E 2010E
% G
row
th
U.S. Supply TPH Coverage Universe Non-TPH E&P Companies
E&P Sector Implications: TPH & Non-TPH E&P Companies
18
Production from the TPH coverage universe has consistently outpaced
the industry over the last five years (+15%)
Expect trend to expand in 2010 because of our bias towards shale-
oriented E&Ps in our research coverage
TPH Coverage
□ 2009E Production Growth: 8%
□ 2010E Production Growth: 7%
Non-TPH Universe
□ 2009E Production Decline: -3%
□ 2010E Production Decline: -13%
TPH Coverage
All Companies
Non-TPH Companies
Source: Production History = HPDI and company data, Forecast = TPH Estimates•Includes gas production from E&P segment of midstream coverage
•Non-TPH Coverage includes other public and private E&P companies
Annual Supply Growth
Total US TPH Coverage Non-TPH Coverage Delta
TPH Coverage* ∆ change ∆ change ∆ change ∆ change
Year % total %/yr %/yr %/yr TPH vs Non-TPH
2005A 20% -3% 3% -5% 8%2006A 22% 2% 17% -1% 18%2007A 26% 4% 19% 0% 19%2008A 29% 3% 15% -1% 16%2009E 31% 0% 8% -3% 10%2010E 35% -7% 7% -13% 19%
19
The US Recovery Will Not Look The Same
Source: RigData, TPH19
2359 1171 1476
Peak '08 Current Long Term
Lower 48 Onshore Rigcount
476 213 205
Peak '08 Current Long Term
Mid-Continent
883 426 556
Peak '08 Current Long Term
TX/LA/Gulf Coast372 208 241
Peak '08 Current Long Term
W.Coast / NM / W.TX
480 185 233
Peak '08 Current Long Term
Rockies
148 139 241
Peak '08 Current Long Term
Appalachia
Regional Production
20
Grouped basins together to examine regional supply dynamics.
Helped to insure that we were not modeling production that could not be physically delivered.
Note: South Region includes GOM
US Wellhead Supply Forecast[Central Region]
0
2
4
6
8
10
12
14
16
18
20
12/ 99 12/ 00 12/ 01 12/ 02 12/ 03 12/ 04 12/ 05 12/ 06 12/ 07 12/ 08 12/ 09 12/ 10 12/ 11 12/ 12 12/ 13
Nat
ural
Gas
Pro
duct
ion
(bcf
/d)
0
200
400
600
800
1,000
1,200
Rig Count
Historical Production Forecasted Production Rig Count
Production History
Regional Breakdown: Central Region
Rig Count
Production Forecast
21
Minimal production growth in ’08 while rig count increased 12%
Significant 2010 volume declines (-1.6 bcf/d annual average)
Cana Woodford / Granite Wash horizontal plays = Wild Cards…but unlikely to arrest regional decline
Source: Rig Count = Rig Data Onshore/Baker Hughes Offshore, Production History = HPDI and EIA, Forecast = TPH Estimates
Note: Wellhead production is wet gas. Rig count is total rig count gas/oil and onshore/offshore, as applicable.
US Wellhead Supply Forecast[South Region]
0
5
10
15
20
25
30
35
40
12/ 99 12/ 00 12/ 01 12/ 02 12/ 03 12/ 04 12/ 05 12/ 06 12/ 07 12/ 08 12/ 09 12/ 10 12/ 11 12/ 12 12/ 13
Nat
ural
Gas
Pro
duct
ion
(bcf
/d)
0
500
1,000
1,500
2,000
2,500
Rig Count
Historical Production Forecasted Production Rig Count
Production History
Regional Breakdown: South Region
Rig Count
Production Forecast
22
South region includes rollup of:
□ Shales: Barnett, Fayetteville, Haynesville, Woodford, Eagle Ford
□ Legacy: South Texas, East Texas, Arkoma North Louisiana, Gulf Coast
□ Offshore: GOM Shelf and Deepwater
Historically, peak production ~30 bcf/d. We forecast region growing to 32 bcf/d by 2013
Source: Rig Count = Rig Data Onshore/Baker Hughes Offshore, Production History = HPDI and EIA, Forecast = TPH Estimates
Note: Wellhead production is wet gas. Rig count is total rig count gas/oil and onshore/offshore, as applicable.
US Wellhead Supply Forecast[Rockies Region]
0
2
4
6
8
10
12
14
12/ 99 12/ 00 12/ 01 12/ 02 12/ 03 12/ 04 12/ 05 12/ 06 12/ 07 12/ 08 12/ 09 12/ 10 12/ 11 12/ 12 12/ 13
Nat
ural
Gas
Pro
duct
ion
(bcf
/d)
0
100
200
300
400
500
600
700
800
Rig Count
Historical Production Forecasted Production Rig Count
Production History
Regional Breakdown: Rockies Region
Rig Count
Production Forecast
23
Production has grown significantly since 1999 (~6 bcf/d)
2008 rig count (+13%) outpaced production growth (+8%)
No need to ramp activity from 2010-2013
2% per year long-term decline
Source: Rig Count = Rig Data Onshore/Baker Hughes Offshore, Production History = HPDI and EIA, Forecast = TPH Estimates
Note: Wellhead production is wet gas. Rig count is total rig count gas/oil and onshore/offshore, as applicable.
US Wellhead Supply Forecast[East Region]
0
2
4
6
8
10
12
12/ 99 12/ 00 12/ 01 12/ 02 12/ 03 12/ 04 12/ 05 12/ 06 12/ 07 12/ 08 12/ 09 12/ 10 12/ 11 12/ 12 12/ 13
Nat
ural
Gas
Pro
duct
ion
(bcf
/d)
0
100
200
300
400
500
600
700
800
Rig Count
Historical Production Forecasted Production Rig Count
Production History
Regional Breakdown: East Region
Rig Count
Production Forecast
24
East region includes rollup of Marcellus, Appalachia conventional
Marcellus ramp from ~0.2 bcf/d to 4.4 bcf/d by 2013
3 bcf/day of East Region supply growth more than offsets Rockies 1.6bcf/day decline
Source: Rig Count = Rig Data Onshore/Baker Hughes Offshore, Production History = HPDI and EIA, Forecast = TPH Estimates
Note: Wellhead production is wet gas. Rig count is total rig count gas/oil and onshore/offshore, as applicable.
Onshore Production – Is Declining
25
0
10
20
30
40
50
60
70
Jan-05 Jan-06 Jan-07 Jan-08 Jan-09 Jan-10
Ons
hore
Gas
Pro
ducti
on, b
cf/d
ay
Declining is happening...NOW!
26
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
27
Wild CardsShale Performance
Officer and a Gentleman
□ “I got nowhere else to go”
Gas Macro Variables
□ LNG
□ Renewables
□ Canada Imports
□ Demand
High-Grading/Well efficiency
Shut-Ins/Uncompleted Wells
Infrastructure Build-Out
28
Natural Gas
Ample gas supply in almost any demand scenario – long term
□ Shale gas
1 bcf/day net demand growth assumed
Shale, Shale and more Shale
Fewer rigs required (~1500)
Lower equilibrium natural gas price
□ $7.50/ mcf in 2010 – lower rig count matters
□ $6.50/mcf in 2011 +
Implications for all energy subsectors/stocks
Expect “Have’s” and “Have Not’s” to emerge
Shale, Shale and more Shale
2010 = strong; 2011= outlook dims
Shale envy = consolidation
Good trade; Mediocre Investment
Focus on Being/Owning a “Have”
29
North American Natural Gas Implications
30
Don’t Believe $7.5/mcf gas in 2010?
Anything is Possible…Scoreboard!Texas A&M 52…Texas Tech 30
Yeeeeesssssssssssssss! Napoleon Dynamite
31
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.
32
RESEARCH
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Jeff [email protected]
E&PDavid [email protected]
Mike [email protected]
Brian [email protected]
Brad [email protected]
MacroDave [email protected]
Gas/PowerBecca [email protected]
Brandon [email protected]
Jessica [email protected]
MLPAnson [email protected]
TRADING 800.507.2400SALES
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