Shale Gas - Berman anuary 2011

8/6/2019 Shale Gas - Berman anuary 2011

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Slide1LabyrinthConsul4ngServices,Inc. HoustonSIPES

Shale GasAbundance or Mirage?

Arthur E. Berman

Labyrinth Consulting Services, Inc.

Houston, Texas

January 20, 2011

U.S. Shale Gas


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Chesapeake is the paragon of U.S. shale gas companies

Downgrade to hold.Earnings quality and management strategy raise concerns.Profligate spending.Desire to take a big stake in every significant resource play.Growing concerns about CHK's earnings quality.Desire to see management cut back on spending. We believe that the company's accounting policies and heavy useof off-balance-sheet leverage add unnecessary complexity andobscure its true financial position.


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SlideLabyrinthConsul4ngServices,Inc. HoustonSIPES

Energy realities: the journey down the resource pyramid

Unconventional gas plays becameimportant as better plays wereexhausted.Tight sandstone & coal-bedmethane were developed first.Shale gas is at a lower level on thepyramid.Economics are marginal.

"We sit on 10 [billion] to 15 billion barrels of

oil that will change the valuation of this

company over time."

-- Aubrey McClendon, Dow Jones

Newswires, October 14, 2010

He clearly does not understand the pyramid!


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There never was 100 years of natural gas because of shale plays

Potential Gas Committee (PGC) June 2009 Report misinterpreted.Technically recoverable resources are not reserves.

Probable shale gas component is 147 tcf.Thats a lot of gas but it is not 100-years of supply.

There is clearly sufficient North American gas supply to last for a bunch ofyears; 50 years at least. And there is clearly no need for us to import LNG

(liquefied natural gas) for multiple years to come.--Mark Papa, EOG CEO, November 2010

Except that there are only 20 years of supply according to the PGC!


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Shale plays have contracted to a fairway or core area:Haynesville Shale example

The emerging core area includes~110,000 acres or about 5Townships.

This represents approximately 10%of the play area in Louisiana definedby limits of drilling (1.5 million acres

or 65 Townships).A few years ago, this was promotedas the 4th largest gas field in theworld, and the largest in NorthAmerica.

All operators claim 6.5-7.5 bcf/wellbut HKs and Excos wells are 2xhigher than CHK and EOGtheycant all be right!

Data from HPDI.


7/34Slide7LabyrinthConsul4ngServices,Inc. HoustonSIPES

The Barnett Shale core areas

"There was a time you all were toldthat any of the 17 counties in theBarnett Shale play would be just asgood as any other county,"

McClendon said. "We found outthere are about two or two and ahalf counties where you really wantto be.

--Bloomberg News October 14,2009

CoreArea

CoreArea



What defines a core? An area where conditions provide the potential forcommercialsuccess

Even within the core, wellperformance is not uniform.Repeatability is a problem. IPs have improved but costs haveincreased.Complex natural system, not afactory.

Barnett H Wells 1st Year Cumulative Production

Data from HPDI.



Barnett Shale Update: The Tarrant County Core Area

Polygon shows thebest of the Tarrant core

based on first-yearcumulative production.1,337 horizontal wellsanalyzed.



The Tarrant County Core Area: type-well cumulative production

0

500,000

1,000,000

1,500,000

2,000,000

2,500,000

3,000,000

3,500,000

1 3 5 7 9 1113151719212325272931333537391357951535557596163656769717375777981838587

ThousandsofCubicFeetofGas

MonthsofProduc6on

Barne8TarrantCoreHorizontalTypeWellCumula6veProduc6on

2003 200 2005 2006 2007 2008 2009 2010

No vintage of wells isapproaching the 2.3-3.3bcf range claimed bymost operators for anaverage well.1.5 bcf is minimum forbreak even at $6.25/mcfnetback in the BarnettShale.NPV models indicatethat at least 70% of NPVin first 5 years.Too early to say muchabout 2010 or 2009wells.No clear evidence thatmore recently drilledwells are better thanpreviously drilled wells.



Vintaged comparison of 20-month cumulative production

0

50

100

150

200

250

300

350

00,000

50,000

500,000

550,000

600,000

650,000

2003 200 2005 2006 2007 2008 2009

NumberofWells

20-MonthCumula6veProduc6on(Mcf)

YearofFirstProduc6on

Barne8CoreHorizontalTypeWells

20-MonthCumula4veProduc4on NumberofWells

Best year was 2005.Progressivedeterioration of results2007-2009.20-month cumulativecomparison normalizesthe impact of high IPwells that do notmaintain high rates.



How are we doing on reaching reserve claims for an average well?

0

500,000

1,000,000

1,500,000

2,000,000

2,500,000

3,000,000

3,500,000

,000,000

1 3 5 7 9 11131517192123252729313335373913579515355575961636567697173757779818385

Cumula6veProdu

c6on(mcfg)

MonthsofProduc6on

CHK DVN ECA EOG KWK XTO

Range of Operator Average Well Claims

Data from HPDI.



Less than 6% of Barnett horizontal wells have reached economic threshold after7 years of production

Most of my oil and gas clients require payout in 2-3 years.



Chesapeake Type Well for the Barnett Play:

69% of value produced in 1st 5 years, and 85% in 1st 10 years, Negligible value added after 20 years yet operators claim significant

EUR comes after year 20,

Actual Barnett decline rates: 45% of EUR in Year 1, 65% by end of2nd, 75% by end of 3rd.

Barnett Shale: its about NPV, not EUR

16% 11%3% 1%

69%

85%

96% 99% 100% 100%

0%

10%

20%

30%

0%

50%

60%

70%

80%

90%

100%

0%

10%

20%

30%

40%

50%

0%

70%

0%

90%

100%

0-5Years

0-10Years

10-20Years

20-30Years

30-50Years

50-65Years

CumulativeP

ercentofNetPresentValu

e

PercentofNetPresentValue

Produc6onPeriod

Chesapeake Barnett Type Curve Incremental NPV10



Barnett Shale: testing the 40- To 65-year production life claim

19%

27%

32%

23%

35%

24%21%

9%10%

0%

5%

10%

15%

20%

25%

30%

35%

0%

2000 2001 2002 2003 200 2005 2006 2007 2008

Barnett Wells Producing < 1 MMcf/month or Dry

This cut-off only covers the cost of compression.True operating costs are approximately double.



0

10,000

20,000

30,000

0,000

50,000

60,000

70,000

1 2 3 5 6 7 8 9 101112131151617181920212223225262728293031323333536

MCFofGasPerMonth

MonthsofProduc6on

EnCanaHorizontalBarne8WellsDeclineData

P25 P50 P75 MEDIAN MEAN

Type curves are overly optimistic: probabilistic approach acknowledges uncertainty

420 Barnett Shale wells suggest considerable variance in type-curve methodology.Mean over-predicts EUR by 10-15%.



Hyperbolic decline model is not supportable: based on non-comparable analogues withpermeabilites that are orders of magnitude greater than shale reservoirs



1st12monthsdominatedbyinduced

andmajornaturalfractures

(highrate,rapiddeple



Super-Harmonic Decline: b-exponent >1.0

Super-harmonic decline reflects production from a system of continuously increasingvolume of contacted gas-in-place.

Berman/Pittinger shale gas analyses indicate late-time boundary dominated flow. Contacted gas-in-place stabilizes after initial year of steep decline. Hyperbolic decline should not model transient/transitional flow before boundary

conditions are reached.

Hyperbolic exponent > 1.0 generally reflects transient flow and may not be valid. Most SPE papers on decline-curve analysis caution against using b-exponents > 1.0. Root of hyperbole is exaggeration orjoke.



Inducedfractures,

regionalfractures

Inducedconjugatefractures,

clustersofnaturalfractures

Microfractures,joints

ShaleMatrix

Adsorbedgas&gasinpores

Decline rate decreases as the well depletes further down the fracture pyramid

PermeabilityDecreases

PoreVolumeIncreases

Thesetwolevels

dominatefirst12

monthsofproducFon

Thesetwolevels

dominatedeclinetrend

aGerfirst12months

(exponenFalor

moderatehyperbolic)

racture-enhancedpermeabilitymaybe

sufficienttoestablishboundary-dominated

flowwithin12months



Business results do not support enthusiasm for shale plays: these are not low-cost plays

Operator claims of profitability at sub-$5/Mcf gas prices exclude many costs. Interest expense and G&A (overhead), dry hole cost, P&A expense not considered.

$0.00

$2.00

$.00

$6.00

$8.00

$10.00

$12.00

$1.00

$16.00

Selected Company 5 Year Imputed Production Costs/Mcfe

Weighted Realized Price/Mcfe with Hedges 5 Year Calculated "Break-Even" Price

Data from company reports.



These are not low-cost plays: the truth is quietly acknowledged

They doubt that you will notice as the traveling circus moves to liquids-rich plays!CHKs 5-year average break-even cost is $6.50/Mcf (from previous slide).


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10,000

100,000

1,000,000

0 1 2 3 4 5 7 9 10 11 12 13 14

MonthlyGasR

ate,

Mscf

MonthsfromStartofProduc6on

Type Well Comparison

Chesapeake Type Curve: EUR = 6.5 Bcf, b=1.1

Average of 44 Wells with 12 Months of

Production: EUR = 2.4 Bcf, Exponential Decline

Type curve comparison: Haynesville Shale

The difference lies in forecasting future decline trends.Particularly the hyperbolic b exponent.

Data from HPDI.


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10,000

100,000

1,000,000

0 12 1 24 30 3 42 4

MonthlyGasRate

,Mscf

MonthsfromStartofProduc6on

Normalized Haynesville Production Rate DeclineAverage of 44 Wells With 12 Months or More of Data

b=1.1

b=1.0

b=0.5

b=0.25

b=0.0

EUR=4.4 Bcf

EUR=3.0 Bcf

EUR=2.6 BcfEUR=2.4 Bcf

EUR=6.5 Bcf

Group type curve analysis

EUR entirely dependent on b factorEUR = 2.4 Bcf with b = 0.0,EUR = 2.6 Bcf with b = 0.25,EUR = 3.0 Bcf with b = 0.5,EUR = 4.4 Bcf with b = 1.0,EUR = 6.5 Bcf with b = 1.1.

Insufficient data to determine b factor from group average

Trust us that the P56.5 bcfcase will be the average EUR!


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Haynesville Shale Average Cumulative Production by Operator

All operators claim EUR in the 5.0-7.5 bcfrange.

It is difficult to see how any but Petrohawkand Exco justify their claim.

Cheapeakes average well will produce lessthan 3.0 bcf which is non-commercial (need$8.70/mcf to break even).

Yet CHK continues to run 33 rigs in the play!

2.9 2.92.7

2.4

1.7 1.9 1.81.91.6

1.5

0

1

2

3

4

5

6

7

1 2 3 4 5 6 7 8 9 1 0 1 1 1 2 1 3 1 4 1 5 1 6 1 7 1 8 19 20 21 22 23 24 25 26 27 28 29 30 31

CumulativeProductionbyOperator(Bcfg)

NormalizedMonthsofProduction

EXCO HK-KCS EP ECA EOG

CHK GOODRICH J-W COMSTOCK FOREST

Data from HPDI.


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An increase in proved undeveloped reserves (PUD) thanks to SEC changes

80% of reserves are undeveloped.

Companies exploit new SECrules to book PUDs



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Discounted value of proved reserves has decreased over time

Realized prices were upwardly adjusted from SEC standard to reflecttrue monthly & annual prices.Prices reflect hedges.



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Pursuit of low-value assets has hurt the shareholder



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Chesapeake presents its value proposition

From 2009 10-K.It will take almost $9billion to develop CHKsproved undevelopedreserves.

This does not includeG&A ($0.38/mcfe) or debt

service ($0.88/mcfe).The present value of theestimated future netrevenue is just over $1

billion.Would you spend morethan $9 billion to net $1 B,

or less than 12%?Since we know that halfof CHKs reserves thatcome after Year 20 add nonet present value, the truereturn is probably about

$0.5 billion.Data from company reports.


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If these shale plays are so profitable, why do their promoters have towrite down their assets every quarter?

Based on 2009 10-K SEC filings


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The Big Short& shale gas plays

The companies were allowed to book as profit the expectedfuture value of those loans. The accounting rules allowed

them to assume the loans would be repaid.

The companies were allowed to book as assets the expected

future value of those reserves. The accounting rules allowedthem to assume the reserves would be developed.

All these subprime lending companies were growing so

quickly that they could mask the fact that they had no realearnings.

All the shale gas production was growing so quickly

that they could mask the fact that they had no real earnings.

To maintain the fiction that they were profitable enterprises,they needed more and more capital to create more and more

subprime loans.

To maintain the fiction that they were profitable enterprises,they needed more and more capital to drill more and more

gas wells.


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Natural gas abundance or mirage?The bubble is the landgas is a by-product. Recent Eagle Ford transactionsunderscore this.

Land Grab strategy anticipates growing dependency on natural gas as the primaryfuel option for North America.Push out smaller independents that cannot compete for land costs.Force policy decisions in favor of natural gas vs. coal and other options.Future price will be a surprise compared to present claims.Drilling adds value to the land by proving reserves.Near-zero intererest rates always cause bad investments.Drilling will continue as long as there is a market for tradable land & capital isavailable.The shareholder is the loser & is subsidizing cheap gas.


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Acknowledgments

Mike BodellAllen BrooksPerry FischerRobert GrayJim Halloran IHSLynn PittingerKeith Shanley


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Shale GasAbundance or Mirage?

Arthur E. Berman

Labyrinth Consulting Services, Inc.

Houston, Texas

January 20, 2011

U.S. Shale Gas

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Shale Gas - Berman anuary 2011

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