lessons from north american unconventional gas plays - art berman 2010

8/7/2019 Lessons From North American Unconventional Gas Plays - Art Berman 2010

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Acknowledgments

Mike BodellAllen Brooks

Perry Fischer

Robert Gray

Jim Halloran IHS

Lynn Pittinger

Keith Shanley


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Lessons Learned from Unconventional Gas Plays Unconventional gas is increasingly important in global energy supply mix

Two play types for tight sandstone gas plays in Rocky Mountains (Shanley)Widespread producing complexes (true resource plays) where trap definition is less

important than focus on pilot development projects & establishing an economic threshold

Unconventional reservoir plays where trap definition is critical and development areas

are more restricted (conventional trap plays)

Both involve large gas volumes & require a realistic assessment of charge potential but

require different approaches for commercial success

Drilling and fracturing methods differ & are critically important

Seismic is fundamental

Geology matters!


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4

Widespread belief that shale plays have ensured an

abundant supply of inexpensive natural gas

Little is known about the plays on which this belief is based While there is little doubt about the resource size, the cost

to produce it is probably much higher than assumed

ExxonMobil acquisition of XTO Energy makes shale players

feel they are on the right track

Why There is a Problem


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Exxon Mobil-XTO Energy Merger

Most analysts believe acquisition represents a dramatic shift bypremier global E&P company

Taken as a validation of shale plays

It is neither


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It is mostly about reserves

Consistent with the companys retreat from the international arena

A validation that natural gas is the short-term basis for North Americas

energy future: shale gas is an important component

Gas price will increase

An act of quiet desperation

Exxon Mobil-XTO Energy Merger


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Energy Realities: the resource pyramid Unconventional gas plays became

important as better plays wereexhausted

Tight sandstone, coal-bed

methane, & shale at the bottom

Economics are marginal

Mean & modal single-well

performance need to be placed in

context of Minimum Economic

Threshold (MET)

Companies whose stated strategy is

to find oil reserves onshore North

America dont understand the

resource pyramid or history


8/39

Shanleys synthesis of tight-gas experience in the U.S.

Producing complexes like Piceance Basin Mesaverde (Williams Fork): true

resource play

Conventional fields with low-quality reservoir like Green River Basin Almond:

conventional trap play

Both have very large resource volumes


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Green River basin: conventional fields, tight reservoirs Gas ubiquitous but only commercial where traps can be

defined High net-to-gross, low permeability, marine sandstone

Emphasis on discrete development areas

Petroleum system risk is important

3-D seismic driven: pilots have limited value

Minimum Economic Threshold >> background resource


10/39

Piceance basin: tight sandstone producing complex Development across 100s-1000s of

km2

Non-marine, low net-to-gross

sandstoneidentification of traps not

critical

Little petroleum-system risk

Reservoir characterization based on

areas and pilots

Manufacturing model

Minimum Economic Threshold ~=

background resource

From Shanle 2010

From Shanley 2010


11/39

Shale Manufacturing Paradigm born in the Barnett Shale play:

Shoot, ready, aim!

Indiscriminate leasing in anacreage rush

Announce success & resource

size

Lease-driven drilling campaign

Find the sweet spot by the

Braille Method after 12,000

wells drilled

Do the hard science

CHK has spent $1.2 MM/well

on acreage for shale plays

(Bernstein Research, January2010)

"There was a time you all were told that any of the 17 counties in the BarnettShale play would be just as good as any other county," McClendon said. "Wefound out there are about two or two and a half counties where you really wantto be. --Bloomberg News October 14, 2009


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It is unlikely that most operators will reach their claims for average well EUR in a time frame

in which NPV10is meaningful

Many operator EUR is based on assumption of 40-65 years of well life with terminal decline

rates of 4-6%

The main difference between our EUR and the operators is the time required to reach that

EUR

We do not feel there is much NPV in about of operator EUR We also suspect that liquid loading will limit well life to far less than 40-65 years!

Reserves are overstated


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Most Likely Horizontal Barnett EUR is 1.1 Bcf (0.09 P75 -1.1 P50 - 1.4 P25)

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CumulativePercent

Frequency(NumberofWells)

Bins of EUR

Barnett Shale Horizontal Well P50 EUR Histogram

Frequency Cumulative %

Mean EUR = 1.1 Bcf

Mode = 0.40 BcfMET = 1.5 Bcf @ $6.50 gas

Based on individual decline-

curve analysis of 1977

horizontal wells


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Barnett Type WellIncremental Net Present Value Added

by Time Periods of Production10% Discount Rate

How Important Is Assumed Well Life?

Used the CHK Type Curve for the Barnett Play

IP 2 MMscfd

D = 2.974/yr, b = 1.61

70% of Value produced in 1st 5 yrs

85% in 1st 10 yrs

Negligible value added after 20 yrs (


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Devon is the leading operator in the Barnett Shale with almost 4,000

wells (1/3 of all producing wells & dominates mid-stream)

Devon was first mover with Mitchell acquisition & later Chiefacquisition

"2009 was a pivotal year for Devon as we began repositioning the

company to focus entirely on our high-return, North American onshore

natural gas and oil portfolio."

--Larry Nichols, chairman and CEO of Devon Energy

How are we doing in the Barnett Shale?


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How are we doing in the Haynesville Shale?

Mean EUR = 2.6 Bcf, Mode = 2.0 Bcf

Minimum Economic Threshold = 5.0 Bcf: 10% of wells

Best wells are 8-9.5 Bcf EUR

A conventional trap play

Not a manufacturing play

MET


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14,000 wells to Cotton Valley before Haynesville Play began

Traps well defined by legacy production

Where to buy leases?


18/39

Fallacy of the Manufacturing Modeltraps matter!

Haynesville Shale

structure map

Fayetteville Shale

structure map

Traps are critical and best production is in discreet areas

Similar to Green River Basin Almond

Pilots appropriate to characterize reservoir and best-practice

completion methods

Southwestern Energy did extensive pilot work in Fayetteville Shale


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Fallacy of the Manufacturing Model.

Operators represent shale plays as low- to no-risk ventures

Gas is ubiquitous & success can be achieved and repeated thru horizontal drilling &fracture stimulation

Pilot programs were few and late in Barnett Play, were used in Fayetteville, not in

Haynesville

Fundamental elements of petroleum geologytrap, reservoir, charge, sealare not

critical

An appealing model not supported by results to date Over-riding problem with shale plays is lack of reservoirno effective porosity &

permeabilities 100s-1000s times lower than tight gas plays

Artifical reservoirsmust be created by engineering brute force

Much progress with completion methods, but long-term production is elusive


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Fallacy of the Manufacturing Model: Barnett Shale

Barnett may be a true manufacturing play

Problem: Minimum Economic Threshold is above most

wells

Mode is 0.4 Bcf, Median is 0.8 Bcf, Median is 1.1 Bcf

Late results are better but a lot of capital has been

destroyed in the process

Early pilot programs might have been a good idea!

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EstimatedUltimateRecovery(Bcfg)

Order of First Production

Barnett Shale Horizontal Well EUR by Order of First Production

Minimum Economic Threshold (MET) = 1.5 Bcf

Mean EUR = 1.1 Bcf

Mode = 0.4 Bcf

Median = 0.8 Bcf

MET

Barnett Shale Structure Map Showing

Horizontal Wells Above MET (< 30% of total)


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Pitfall: non-comparable analogues with dissimilar permeabilities

(0.00005-0.0003 millidarcies) & completion methods

And all have orders of magnitude better reservoir quality than current shale-play reservoirs: range of

permeability for shale plays is 0.00005-0.0003 md!

Few wells with > 10 years of production, none with 40-65 years, & few total wells Water-free production characterizes these examples but is a rare phenomenon

Shale that produces from natural fractures,

drilled vertically & not fracture-stimulated.Permeability range is 200-15,000 times

greater than current shale plays.

Sandstone that is drilled vertically & fracture-

stimulated. Permeability range is 100-167

times greater than current shale plays.

Limestone that is drilled vertically & not

fracture-stimulated. Permeability range is

1,000-1,667 times greater than current shale plays.

Chalk that is drilled horizontally & not

fracture-stimulated. Permeability range is

200-333 times greater than current shale plays.


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Operators claim that shale plays are low cost compared to conventional plays

Costs stated in investor presentations are less than those in public filings

Typically exclude sunk costs like land expense & geophysics, interest expense

Dont include dry holes (15% according to Bernstein)

Pitfall: Costs are understated


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Unit costs are understated

Companies state shale profitability at less than

$5/Mcf gas price, but their average unit cost ismore than that

Hedging has helped minimize losses since price

collapse, but difficult to find attractive hedge

prices for significant volumes in low-cost

environment

If the plays are so profitable, why cant thecompanies pay for drilling & leasing out of cash

flow? What about paying down debt?

Were losing money but making it up on

volume!

Company Market Cap $B EV $B Debt to Total Cap Capex to Cashflow

PetroHawk $7 $9 44% 385%

Range $8 $10 42% 163%

Chesapeake $17 $30 50% 161%

Devon $30 $37 32% 78%

XTO $28 $38 38% 52%

Southwestern $15 $16 30% 42%


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Pitfall: Higher gas prices will save the dayAverage inflation-adjusted

gas price since 1995 is

$5.50/Mcf Gas prices necessary to

make shale plays profitable

have only existed for brief

periods since deregulation

All previous gas price

spikes because of storage

shortfalls/decreased gas-

directed drilling

Opposite is occurring now:

storage surplus

If shale gas development

continues at current pace,

unlikely to get a new spike

to save the day

Why should the market

reward the lack of drilling

discipline by the shaleoperators?


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What is the premise of 100 years of natural gas supply? Potential gas committee report: 1,836 Tcf technically recoverable resources (P3) + 238

(P1) Tcf proved (~90 years supply @ current demand of 23 Tcf/year)

616 Tcf (about 1/3) is shale gas (27 years of supply @ current demand)The probable component (P2) of total resource is 441 Tcf (~ 19 years supply)

About 147 Tcf (1/3) of that is shale gas

Approximately 6.5 years of P2 shale gas supply at current consumption rates

Thats a lot of gas from shale, but not what is generally perceived

Operators claim more than that in both the Haynesville and Marcellus plays

Shale gas is 15-20% of total U.S. supply

Reserve Category Definitions

Proved P1 - reasonable certainty

Probable P2 - more likely than notPossible P3 - less likely than probable


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ExxonMobil Acquisition of XTO Energy

$31 billion in stock & assumption of $10 billion of debt--25%

premium above XTO stock price (XTO P/E ratio =12.8) Condition that Congress does not restrict hydraulic fracturing

Viewed as a dramatic shift by premier IOC to bet on U.S.

unconventional gas

Taken as a validation of shale gas plays


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2007, 2008, & 2009 were the companys worst years ever for reserve additions

2008 additions reported as 103% Without Canadian oil sands, replacement would have been less than 100%

2/3 of 2009 reserve additions are from gas discovered in Australia & Papua New

Guinea years ago

Just added because processing facilities completed in 2009

Unconventional gas represents the only remaining scalable resource

SEC revisions more liberal & allow appropriate technology for proved reserves

Acquisition driven by XOMs need to add reserves


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XTO has gas production and positions in many plays

XTO has great representation in the shale plays, but 83% of production is from

tight gas, conventional gas, and coal-bed methane


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Long-term natural gas price will rise Price will accommodate marginal cost of production eventually

Energy demand will grow & natural gas will fill a larger proportion ofenergy mix

Percent of unconventional gas will increase compared to conventional

Shale gas the best of a bad lot for majors

XOM is betting that technology, efficiency, & increased demand & price

will lead to commercial success


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Only a dramatic shift to those not paying attention

Winners Curse speech by Kurt

Rudolf at AAPG Annual Meeting inLong Beach, 2007-- few new

opportunities not already captured

in international arena

XOM applied petroleum

system/basin analysis methods toNorth American basins

XTO positions were a good fit

Opposite approach to Gold Rush

Showcased Piceance Basin tight

gas sand play: Multi-zonestimulation technology

Most resources currently in

Americas


32/39

Only a dramatic shift to those not paying attention

Tight gas play in Hungary (Pannonian Basin Mako Trough)

Shale play in Horn River Basin (Canada) Leased 20,000 acres in Pennsylvania Marcellus in August, 2008

290,000 acres in Marcellus with Pennsylvania General Energy

Ongoing commitment to Canada oil sands


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Unlocking Tight Gas

Use technology to crack the code first with tight sandstone reservoirs,

then with shale

Use the Multi-zone stimulation technology to produce shale in vertical wellsthat cost less


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Conclusions

Approach to shale plays in U.S destroys capital

Reserves are overstated Costs are understated

Why it is important


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Implications Shale gas plays will be a permanent & important part of the E&P landscape

They require peak market conditions to be commercial based on historical

gas prices

Companies that bet everything on shale plays (or any single play-type) will

have a competitive disadvantage through 80% of the price cycle

Tight sandstone plays are preferable because of better reservoir & matrix

storage capacity: shale players should learn from 3 decades of experience

Focus on trap definition (seismic) and best fracture technology for the play Seismic attribute mapping to define optimum reservoirs


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Troubling implications Massive capital investment & debt load in projects that have not yet

demonstrated sustainable value Undisciplined drilling & resulting over-supply keeps prices low

Ongoing asset sales, share offerings & new debt: present level of

drilling & leasing cannot be paid from cash flow

High decline rates mean the drilling treadmill must continue

A potential bubble when the music stops: tighter credit, higher interest

rates

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Horizontal Barnett Wells Completed


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Closing thoughtsXTO approached XOM about merger

implications about cost, competitiveness,environmental & legal battles pending

Hungary play failed & XOM exited

Piceance basin play is non-commercial to date

XOM feels that it needs to learn from XTO, but

may not be able to retain employees

ExxonMobil came late to the shale party & paid

a high price of admission (diluted shareholders)

May have overvalued high-decline rate wells

XOM overhead structure and cost may not fit

with operating 1000s of low-rate gas wells


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Closing thoughts ExxonMobil understands the technical risks &

uncertainties in unconventional plays Made realistic projections about reserves and

costs

XOM bet is that efficiency, science & technology

will bring commercial success

Bring abundant capital and little debt to plays

dominated by highly leveraged companies

Bet is based on assumption that price will rise

Less clear that XOM appreciates the business

risks from undisciplined competitors who over-

produce and keep prices low as long as the

market provides capital

We are awash in gas today because the market continues to distribute funds to companies

that destroy the capital they are given. There is no type of skillful way to differentiate a

positive shale well from a negative one. I believe this is the dilemma you should focus on.

CEO of a public gas E&P company, personal communication (January 2010)


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Lessons from North American Unconventional Gas Plays

Ohi Oil & G A i i

Thoughts about ExxonMobilsacquisition of XTO Energy

lessons from north american unconventional gas plays - art berman 2010

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