the barnett shale report

7/29/2019 The Barnett Shale Report

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PICKERING ENERGY PARTNERS, INC.

The Barnett Shale

Visitors Guide to the

Hottest Gas Play in the US


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2 PICKERING ENERGY PARTNERS, INC.

r

Jeff Hayden

[email protected]

(713) 333-2971

Dave [email protected]

713-333-2962

The Barnett Shale

Visitors Guide to theHottest Gas Play in the US

October 2005


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This report is meant to help investors better understand the Barnett Shale and the future

development potential that exists in the core and non-core areas. Later in the report we will also

address which E&P companies have the most exposure to the play and what lessons learnedwe can apply to other emerging North American gas shale plays. Some key takeaways are

outlined below.

Play economics work well at $6/mcf gas At $6/mcf gas, Barnett drilling is full steam ahead. Economics workfor vertical wells (39% cash flow rate of return) and horizontal wells (113% and 70% returns for Tier 1 and2 non-core areas, respectively). Wells are still economic if gas falls to $5/mcf though vertical welleconomics are thin (12% return). Tier 1 and 2 horizontals still look good (73% and 38% returns).

Uncertainties remain for Tier 2 Not enough data exists to conclusively determine whether Tier 2 acreage(Erath, Jack, Palo Pinto, etc) will be successful. To date we have seen results from 6 wells (2 EOG, 4IFNY). While each produced gas, some liquids (oil & condensate) were seen in the EOG wells and theproduction rates from the majority of the IFNY wells were not impressive. Additional data points andlonger production history required to determine how prolific the play will be in Tier 2.

Two wordssize matters The Barnett Shale is a highly complex reservoir. Significant variability of wellresults exists even within concentrated areas. As the industry has yet to figure out how to identify the goodwells from the bad (yesthere are bad wells in the play), a large acreage position is a necessity in order tominimize the risks and allow the law of large numbers to take effect.

Not every Barnett well is a good one We know, we knowblasphemy. Just looking at the wells that weremechanical successes (i.e. gas producers), about 23% of the horizontal wells and 32% of the vertical wellsdrilled in 2004 would have been uneconomic if drilled at todays cost levels, assuming a $6/mcf long termgas price. That said, the good wells tend to be really good, making the average results economical.

Horizontal wells are superior to vertical wells Probably not a surprise given the increased industry focus onhorizontal wells, but the magnitude was surprising. Using $6/mcf as our benchmark gas price, the typical

horizontal well generates a 100%+ return while the typical vertical well generates only a 39% return. Johnson County acreage looking good Though the core area is commonly referred to as Denton, Wise, and

Tarrant counties, the true sweet spot has been the Newark East field, which has been extensively drilled.Results outside Newark East have not been as impressive. However another sweet spot appears to bedeveloping in Johnson County, which looks superior to much of the core acreage beyond Newark East.

Stock Thoughts Overall the value of Barnett Shale is appropriately discounted in the stocks. EOG looks theriskiest while CRZO looks interesting.

Broad resource play implications (beyond the Barnett): Size matters Expect variability of results Learning curve development progression takes time Location, location, location reservoir parameters, gas window, etc.

***IMPORTANT DISCLOSURES ON PAGE 51 OF THIS REPORT***


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Table of Contents

Barnett at a Glance..................................................................................................................................... 5Geological Backdrop ............................................................................................................................. 7

Geochemical Backdrop ......................................................................................................................... 9The Barnett Today ............................................................................................................................... 11

The Players ................................................................................................................................................ 13The Data.................................................................................................................................................... 14

Horizontal vs. Vertical wells............................................................................................................... 19Well Performance Analysis by Company ......................................................................................... 22

Barnett Economics The Bottom Line ............................................................................................... 24Vertical wells ......................................................................................................................................... 24Horizontal Wells................................................................................................................................... 26

Summing it Up...................................................................................................................................... 32Reserve Potential...................................................................................................................................... 34Whats an Mcf worth anyway? ........................................................................................................... 36Company-specific Barnett upside ...................................................................................................... 39EOG a closer look............................................................................................................................ 40

The Unknowns......................................................................................................................................... 42Summary/Conclusions............................................................................................................................ 44

Appendix A Gas Shale Terminology ................................................................................................. 45Appendix B Comparison of Organic Shales in the US .................................................................. 46Appendix C Example of Barnett NPV Model................................................................................. 47

Appendix D Generalized Company Acreage Maps ........................................................................ 48


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Barnett at a Glance

The Barnett Shale is one of the largest and most active domestic natural gas plays in the U.S. Production is~1.2bcf/d and there are ~100 rigs drilling. Its likely that most investors are already familiar with the play

background/basics, but we review them in the following pages. For a comparison of the Barnett to otherproductive shales, see Appendix B.

When most investors (ourselves included) hear about the Barnett Shale, they immediately think of the play inthe Fort Worth Basin, but other Barnett like resource plays are emerging in the Permian Basin to the west(Culberson/Reeves counties) and the Fayetteville Shale to the northeast. For the purpose of this report, BarnettShale will refer to the Fort Worth Basin play unless otherwise specified. The charts below illustrates where theBarnett is located and the key counties involved in the play. We also show the growth of the play in terms ofactive rigs, wells drilled and gas production.

Figure 1 . Location of Barnett Shale

Source: Humble Geochemical, Pickering Energy Partners


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Figure 2. Barnett Shale Production History

0

300

600

900

1,200

1,500

1990 1995 2000 2005

TotalGasProduction,mmcf/day

0

500

1,000

1,500

2,000

2,500

3,000

3,500

NumberActiveWells

Gas Production

Active Well Count

Source: IHS Energy and Pickering Energy Partners

Figure 3. Barnett Shale Rigcount History

0

10

20

30

40

50

60

70

80

90

100

1992 1994 1996 1998 2000 2002 2004

NumberofRigs

Source: Smith Bits and Pickering Energy Partners


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Geological BackdropThe Barnett is a Mississippian-aged Shale located at depths of 6,500-8,500 feet deep. The play could be quite

large, potentially spanning 10-15 counties in the Fort Worth Basin of north Texas (the shale is bordered to the

east by the Ouachita Thrust-fold Belt and the Muenster Arch and to the west by the Bend Arch). Figure 4shows the stratigraphy of the Forth Worth Basin. As we head northeast in the play, the Barnett is split into theupper and lower Barnett by the Forestburg limestone. Most of the development where this occurs has focusedon the Lower Barnett.

Figure 4. Fort Worth Basin Stratigraphic Column

Source: AAPG


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Other key formations to note in the basin include the Marble Falls limestone and the Viola limestone, whichprovide the upper and lower frac barriers for the Barnett, and the water-bearing Ellenburger formation. Thefrac barriers are important because the tight Barnett Shale needs to be hydraulically fractured in order to beproductive. Fracs that extend out of the Barnett Shale and into a water-bearing formation will result in an

uneconomic completion.

Figures 5 and 6 show the east-west and north-south cross sections of the Fort Worth Basin. The playthickens and deepens heading north and east. At its thickest (just south of the Muenster Arch), the Barnett is~1,000 feet thick, and thins to ~30-50 feet thick as it heads south. The figures also show roughly where thelower Viola frac barrier ends. Given these two factors, its easy to understand why the industry chose todevelop the northeast corner of the play first, especially since the play was being developed exclusively withvertical wells at the time.

Figure 5. East-West Cross Section

Source: Humble Geochemical

Figure 6. North-South Cross Section

Source: Humble Geochemical


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Geochemical BackdropThe Barnett Shale has been such a productive reservoir due to high proportion of total organic carbon (TOC)

despite having likely leaked much of its gas to surrounding formations/reservoirs over time. The TOC of the

Barnett averages ~4.5% (immature outcroppings indicate it was as high as 11-13%). This is important becausethere is a linear relationship between TOC values and gas content. A high TOC value suggests a large potentialto generate hydrocarbons.

The Barnett Shale is a thermogenic reservoir. In a thermogenic reservoir, hydrocarbons are created by thecombination of time, temperature and pressure. The thermal maturity of the reservoir can help determinewhether it contains oil, gas, or no hydrocarbons. Thermal maturity is measured in the lab using core samples byvitrinite reflectance (RO), with higher numbers indicating a greater likelihood of gas. A reading >1.0 usuallyindicates the gas window, while a reading >1.4 indicates dry gas. A reading


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Figure 8. Barnett Shale Isoreflectance Map

Source: AAPG


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The Barnett Today

The Barnett Shale has come a long way over the last 5-10 years, as light sand fracs and horizontal drilling havedriven an explosion of activity in the play, with over 3,800 wells drilled to date. The play has now expanded

well outside the original core area. Although most of the wells drilled thus far have been in the core, futureactivity will be focused on the non-core area.

Currently, more than 100 companies are active in the Barnett Shale, and the industry has expanded the rigcount in the play to ~100 rigs from only ~30 rigs in 2003. We believe the rig count in the play will only movehigher, as many of the larger players are adding rigs over the remainder of the year and will likely have toincrease their rig count further in the future in order to hold all of their leases. Production from the Barnett iscurrently ~1.2bcf/d, accounting for >2% of total domestic gas production. Public companies active in the playinclude BR, CHK, CRZO, DNR, DVN, ECA, EOG, IFNY, KWK, PLLL and XTO.

When thinking about the Barnett Shale, we not only split the play into the core and non-core area but alsofurther subdivide the non-core area into Tier 1 and Tier 2.

Figure 9. Barnett Shale County Map

Core

Tier 1

Tier 2

Newark East

Field

Wise Denton

Tarrant

Parker

HoodJohnson

Source: Pickering Energy Partners

Core Area. The vast majority of the Barnett Shale production has been from the Newark East Field in thecore area. The Newark East Field covers a portion of Denton, Wise and Tarrant Counties. Much of the initial


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development was performed by Mitchell Energy (now part of Devon Energy). Though the term core area istypically used to describe all three of these counties, the true sweet spot is Newark East.

The core area has been most commonly drilled with vertical wells and completed with large hydraulic fracture

treatments. The ability to execute a large fracture treatment is made possible by a limestone barrier (Viola lime)which separates the Barnett Shale from the underlying water-bearing Ellenberger formation. The Barnett Shaleis thickest and deepest in the core areawhich corresponds to the highest gas-in-place per section in theBarnett (see geological backdrop section).

Tier 1. Geographically, south and west of the core area (Johnson, Hood, and Parker Counties). This portionof the Barnett generally lacks the Viola Limestone which separates the Barnett from the underlying water-bearing formations. Vertical wells with large hydraulic fracture treatments risk communicating with the water-bearing Ellenburger formation. Horizontal drilling has been effectively employed (mainly in Johnson County)in conjunction with multiple (typically four or five) hydraulic fracture treatments along the horizontal wellsection. These smaller fracture treatments are designed to avoid communication with the adjacent water-bearing zones.

Tier 2. Geographically, west and south of Tier 1 (counties include Jack, Erath, Palo Pinto, Hill, etc). This isthe least developed area of the Barnett. Conventional analysis has suggested that much of the Barnett Shale inTier 2 has the likelihood to produce oil (uneconomic volumes) instead of gas. Development is slowly ongoingin Tier 2 as companies attempt to identify the western boundary of the oil-gas window. Production results sofar are inconclusive.

In addition to uncertainties surrounding the western extent of the gas window, the Barnett Shale thins and isshallower to the west and south. This results in lower amounts of gas-in-place and recovery per section thanthe Core or Tier 1 areas. Moreover, as in Tier 1, a competent fracture barrier does not exist at the base of theBarnett, driving most operators to utilize (more expensive) horizontal wells to develop the resource.

This is the riskiest area in the Barnett Shale. There is no long term production performance. Uncertaintiessurrounding the gas window and the lower resource potential due to thinner and shallower reservoir makewidespread commercial development less certain in Tier 2. These uncertainties increase significantly as theindustry tries to push the play even further west and south (into counties such as Comanche and Stephens).


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The Data

Within the Barnett, long-term recovery data are not available due to the immaturity of the play. We use peakmonthly production as an indicator of ultimate recovery and well quality. This analytical method is well

established for technical evaluation of unconventional gas reservoirs. As an example, the chart below highlightsdata gathered over a decade in the Carthage Field (tight gas) in East Texas.

Figure 10. Wells Performance of Carthage Tight Gas Wells

0

2000

4000

6000

8000

0 2000 4000 6000 8000

Peak Monthly Production, mcf/day

10YearCumu

lative,mmcf

R2

= 0.70


To assess the Barnett, we utilized IHS Energy production data to analyze peak monthly production forBarnett Shale wells completed in specific calendar years (i.e. well vintaging). The production data wassubdivided for various vintages and different operator classes.

The following bubble map shows the areal distribution of peak monthly production. The cluster of data inWise, Denton, and Tarrant Counties is the Newark East Field. This was the initial Mitchell Energy (nowDevon) development. The large dots represent high peak monthly gas production (and high expected recovery)and the small dots correspond to low peak monthly production (and low expected recovery). Even withinNewark East Field, the areal variation in peak production/well quality (size of the dots) is significant.


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Figure 11a. Areal Distribution of Peak Monthly Production 1996-2004



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Figure 11. Areal Distribution of Peak Monthly Production 1996-2004 (zoom-in)



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Figure 12. Areal Distribution of Peak Monthly Production 2001-2004



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Figure 13. Areal Distribution of Peak Monthly Production 1996-2000



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The figure below shows the trend in median initial well performance since 1999. Well performance peaked in2000 and has steadily trended down since then. Possible explanations include the Newark East field continuingto mature and companies attempting to expand the field outside of the sweet spot. We expect the productiontrend to reverse in future years as the focus in the play continues to shift to horizontal wells from vertical wells,

which have higher production rates.

Figure 14. Median Initial Peak Monthly Performance (Horizontal + Vertical)

833

978

825

729684

621

517

1999 2000 2001 2002 2003 2004 2005

mcf/d


Horizontal vs. Vertical wellsAlthough long-term (10+ years) production data are not available, there is sufficient production history to

determine the typical decline characteristics for Barnett wells during their first few years. Below we look at thedecline curves of the typical wells for both horizontal and vertical wells. We care about this because of itsimpact on time value of money and expected ultimate recovery (EUR), both of which influence well economics(not to mention the obvious production implications).

Exhibit 15 shows the decline curves for vertical Barnett wells drilled in 1999 through 2003. As expected, thegraph highlights the high initial decline rate followed by flatter decline rate in following years. In 1999 the initial

decline rate was only 52% but has since averaged 65%. We think the latter is a better estimate for futureforecasts as recent vintage decline rates have consistently been in the mid-60% range. Also as seen in Figure 15,decline rates typically level off around 10% in years 4-5. Sample size isnt an issue with our vertical well analysisas the lowest number of observations is 78 in 1999 and ranges from 171 to 788 in subsequent years.


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Figure 15. Vertical well decline curve (core + non-core)

0

200

400

600

800

1000

1200

Peak t+1 t+2 t+3 t+4 t+5

Years

Production(mcf/d)

1999

2000

2001

2002

2003


Horizontal wells appear to have a shallower decline curve than their vertical counterparts. However weshould note that the data is fuzzier for horizontal wells due to the lack of a significant sample size until 2003.We show both 2002 and 2003 data in the Exhibit 16 below but note that 2002 includes only 3 wells. The 2003sample size is better with 64 wells. Focusing on the 2003 numbers, the initial decline rate of horizontal wellsappears to be 50-55%. Longer-term decline rates for horizontal wells have yet to be established.

Figure 16. Horizontal well decline curve (core + non-core)

0

500

1000

1500

2000

2500

3000

Peak t+1 t+2

Years

Production(mcf/d)

2002

2003

3 Wells

64 Wells



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While this report focuses on well data from IHS, we realize that horizontal drilling in the Barnett is still in itsinfancy. Thus the calculated decline rates will likely change over time as additional wells are drilled and moreproduction history is available.

A recent example of this is KWKs update of its average well type curve for its acreage in Hood county(Tier 1). The companys old type curve assumed a shallower initial decline (~45%) than our data suggests. Itsupdated decline curve now forecasts a steeper initial decline (~65%) followed by a shallower decline in lateryears. Net-net the companys model still forecasts the same reserves per well, but the NPV is now lower. It isinteresting to note that KWKs new type curve is similar to the vertical decline curves seen in recent years. SeeFigure 17 for KWKs current decline curve assumptions compared to its prior assessment.

Figure 17. KWK Decline Curve (Hood county acreage)

0

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400

600

800

1000

1200

1400

1600

IP

Year

1

Year

2

Year

3

Year

4

Year

5

Year

6

Year

7

Year

8

Year

9

Year

10

Year

11

Year

12

Year

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Year

14

Year

15

Year

16

Year

17

Year

18

Year

19

Year

20

Year

21

Year

22

Year

23

Year

24

Year

25

mcf/d

OLD

NEW

Source: KWK and Pickering Energy Partners


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Well Performance Analysis by CompanyThe bubble graph earlier highlighted the large variability of well results within the Barnett, so it should come

as no surprise that a significant amount of variability exists between the results of different companies. Figure

18 graphs the well results of five of the largest producers in the Barnett, as well as the aggregate of the smalleroperators. Looking first at the vertical wells drilled in 2004, Antero (now XTO) appears to have had the bestresults, with median production of 960mcf/d and average production of 974mcf/d. Private player Chief camein second. It is interesting that the best two performers were private companies. Each of the larger producersdelivered better results than the aggregate of the smaller players (others).

While we will discuss well economics in more detail in the following section, our math suggests the breakevenmonthly peak production level for a vertical well in the core area is ~450mcf/d in a $6/mcf scenario. Usingthis as the bogey, the average well of each of the larger operators was economic in 2004 while the average of thesmaller producers was not.

Figure 18. 2004 Vertical Well Performance by Company Peak Monthly Production

960974

666

789

618 622590

670

551584

321

418

Antero Chief ECA DVN BR Others

M

cf/da

Median Well

Average Well



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Looking at horizontal wells, Chief delivered the best results in 2004, with median production of 1.9mmcf/dand average production of 2.0mmcf/d. However unlike in the vertical well results, BR and ECAunderperformed the smaller-player aggregate. That said each companys average 2004 well would be economicin our $6/mcf gas price scenario (740mcf/d breakeven). Figure 19 shows the full results:

Figure 19. 2004 Horizontal Well Performance by Company Peak Monthly Production

19412,004

1585

1,786

13001,369

1285

1,657

1166

1,087 1008 1,041

Chief DVN Antero Others BR ECA

Mcf/d

ay

Median Well

Average Well



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Barnett Economics The Bottom Line

Just how economic is the Barnett Shale play? Public companies often list rates of return from the play inexcess of 100%...but is this reasonable? Are the economics better in some parts of the play than in others? Or

is the play a slam dunk no matter where a companys acreage lies? These are some of the questions we will tryto answer.

The Barnett is a highly complex play that spans a large area. Due to various factors such as depth, paythickness and optimal type of well drilled, the economics of the play are not uniform across all areas. As a resultwe will look at the economics for the three types of wells we expect to be most prevalent going forward Corearea vertical, Tier 1 horizontal and Tier 2 horizontal. We caution that the Barnett is a very complex play withlarge variability of results within each of these three regions as well. The following analysis is our best attemptto look for general trends to help analyze the play. Some operators will be able to deliver better results whileothers wont.

While the following sections detail our analysis of the well economics for various Barnett wells, the following

table summarizes the results, as well as shows the returns in two scenarios not detailed ($5/mcf and $7/mcfgas). In short horizontal wells are superior to vertical wells and Core/Tier 1 horizontal wells are superior toTier 2 horizontal wells.

Figure 20. Comparative Barnett Economics

Core Vertical Tier 1 Horiz. Tier 2 Horiz.

Peak Monthly Prod. (Mcf/d) 650 1520 900

Year 1 Decline 61% 53% 53%

EUR (MMcf) 733 2356 1395

Well Cost ($M) $1,000 $2,000 $1,500

F&D Cost ($/Mcfe) $1.71 $1.06 $1.34

Rate of Return:@ $5 12% 73% 38%

@ $6 39% 113% 70%

@ $7 65% 153% 101%

NPV per Well:

@ $5 $0.1 $1.5 $0.6

@ $6 $0.4 $2.3 $1.0

@ $7 $0.7 $3.1 $1.5


Vertical wells

The general consensus in the industry (which we agree with) is that vertical wells do not work in the non-corearea. As such our analysis of vertical well economics will focus on the core area. Over the last two years, theindustry has drilled over 1,100 vertical wells in the core area of the Barnett. The drilling pace did slownoticeably in 2004 relative to 2003 as industry focus shifted to drilling (theoretically) higher-return horizontalwells in the core and non-core.

Before we detail the well economics model, we need to discuss the proper inputs. Three of the mostimportant variables to consider are peak monthly production rate, decline rates (these two factors drive


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recovery) and well cost. We were able to calculate both the peak monthly production rate and the decline ratesfrom the IHS data set. We turned to operators (both public and private) to get a handle on well costs.

Heres what the typical vertical well looks like in the core area of the Barnett Shale:

Well cost about $1 million to drill and complete. Peak monthly production 650mcf/d. This is the median peak production of the total vertical wells drilled in

2003 and 2004. Of note, the median rate was ~690mcf/d in 2003 and only ~580mcf/d in 2004.

Decline curve 60% in year 1, 30% in year 2, 15% in year 3, 10% thereafter. The steepness of the declinessurprised us a little bit, but the data doesnt lie.

Reserves per well 0.7bcf gross; calculated from average decline curve, using a 30-year life. F&D cost- $1.71/mcf. (80% net revenue interest)

Figure 21 below shows our well economics calculation for the median core area vertical well. We estimatethat the median well (650mcf/d) will generate a 39% rate of return in a $6/mcf NYMEX price environment.

The average well looks better at ~725mcf/d, which would generate a return of 53%. (Note that the modelassumes core area gas receives a ~$0.50/mcf differential to NYMEX for transportation and btu content.)

Figure 21. Barnett Shale Core Area Vertical Well EconomicsSummary

Initial Production (Mcf/d) 650

Net Reserves (MMcf) 586

Discounted Cash F low ($MM) 1.4

Discounted Cash Flow ROR 39%

NPV ($MM) 0.4

NPV/Mcfe 0.66

Incremental F&D ($/Mcfe) 1.71

Year 1 Year 2 Year 3 Year 4 Year 5 Year 6 Year 7 Year 8 Year 9 Year 10 Years 11-30

Capital Cost ($M) 1,000

Gas Price ($/Mcf) 6.00 6.00 6.00 6.00 6.00 6.00 6.00 6.00 6.00 6.00 6.00

End Period Prod (Mcf/d) 251 181 151 134 119 105 93 83 73 65 6

Decline (% of Year 1) 95% 33% 18% 12% 12% 12% 12% 12% 12% 12% 12%

Net Production (MMcf) 123 63 48 42 37 33 29 26 23 20 164

Revenue ($MM) 0.67 0.34 0.27 0.23 0.20 0.18 0.16 0.14 0.13 0.11 0.90

LOE ($MM) 0.06 0.03 0.03 0.02 0.02 0.02 0.02 0.02 0.01 0.01 0.13

Production Tax ($MM) 0.01 0.01 0.01 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.02

Overhead ($MM) 0.02 0.02 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.08

DD&A ($MM) 0.21 0.11 0.08 0.07 0.06 0.06 0.05 0.04 0.04 0.03 0.28

Tax ($MM) 0.09 0.05 0.03 0.03 0.03 0.02 0.02 0.02 0.02 0.01 0.10

Cash Flow ($MM) 0.48 0.24 0.19 0.16 0.14 0.12 0.11 0.10 0.08 0.07 0.58

Cash Flow ($/Mcf) 3.95 3.87 3.83 3.81 3.79 3.77 3.75 3.73 3.70 3.68 3.52

P/T Disc. Cash Flow ($MM) 0.55 0.25 0.17 0.13 0.11 0.09 0.07 0.06 0.04 0.04 0.18

Discounted Cash Flow ($MM) 0.46 0.21 0.15 0.11 0.09 0.07 0.06 0.05 0.04 0.03 0.15


We can also see why vertical wells in the non-core area dont really work. Johnson County should have thebest vertical wells of the non-core area because the Barnett Shale is the thick and deep. The median Johnsoncounty vertical well had peak volumes of 500mcf/d, which is only slightly economic at $6/mcf gas (10% return;45-50% of the wells completed would not have been economic under this scenario). The average well, asexpected, looks better at 585mcf/d, generating a 26% return. But heres the rubthese numbers all assumemechanical success (i.e. a productive well). Any wells which did not flow (due to fracing into the water-bearingEllenburger, etc.) are not included in the data set. Thus these results should be viewed as a best case scenariosince its been well documented that penetrating the Ellenberger with a frac is a problem in the non-core area.


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Mean vs. Median. No it wasnt a typo when we used median production rate in our analysis. We view themedian production rate to be a better tool for analyzing what the average individualfuture well will deliver. Thisis because average production rates tend to be skewed upwards by a few very good wells, whereas median ratesdo not. However when looking at a total fieldwide drilling program in the Barnett, average production rates are

the better measure of the aggregate success.

Horizontal WellsHorizontal drilling technologies are a major part of the boom in Barnett activity that we see today, which is no

surprise when we look at the far superior economics of horizontal vs. vertical wells. In fact the magnitude ofthe difference is so large that the only vertical wells wed expect to see going forward are in areas that havealready been densely drilled (downspacing) or near lease lines.

Its difficult to nail down what an average horizontal well looks like, as factors such as lateral length andcompletion effectiveness will have a large impact on both reserves/production as well as cost. Though our datafocuses on the core area and Johnson County (where we have the best data), we will assume the results alsoapply to much of Parker and Hood counties, where the shale remains relatively deep and thick. We willexamine Tier 2 well economics later in this section.

Heres what the typical horizontal well looks like the core and Tier 1 non-core Barnett:

Well cost about $2 million to drill and complete. Peak monthly production 1,520mcf/d. This is the median peak production of the total horizontal wells drilled

in 2003 and 2004. Similar to the results from the vertical wells, rates in 2004 were lower than in 2003 ineach county except Johnson (2.1mmcf/d vs. 0.7mmcf/d).

Decline curve 55% in year 1, 25% in year 2, 15% in year 3, 10% thereafter. Not quite as steep as in thevertical wells.

Reserves per well 2.4bcf gross; calculated from average decline curve, using a 30-year life. F&D cost- $1.06/mcf. (80% net revenue interest)

Figure 22 shows our well economics calculation for the median core area or Tier 1 non-core horizontal well.We estimate that the median well (1,520mcf/d) will actually generate a >100% return in the Tier 1 non-corearea and a 93% return in the core area (in a $6/mcf NYMEX price environment)a big jump relative tovertical well economics! Much like we saw with vertical wells, the average horizontal well looks better than themedian well, producing ~1,685mcf/d, which would generate returns of 113% and 135% (for core and non-core, respectively). The returns from the core area wells are lower because the gas is dry (~50c lower realizedgas price), causing their production to receive a lower price than that of the non-core wells, which produce wetgas (higher btu content gets a higher price).


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Figure 22. Barnett Shale Core/Tier 1 Horizontal Well EconomicsSummary



Discounted Cash Flow ($MM) 4.3

Discounted Ca sh Flow ROR 113%NPV ($MM) 2.3

NPV/Mcfe 1.20

Incremental F&D ($/Mcfe) 1.06Year 1 Year 2 Year 3 Year 4 Year 5 Year 6 Year 7 Year 8 Year 9 Year 10 Years 11-30


Gas Price ($/Mcf) 6.00 6.00 6.00 6.00 6.00 6.00 6.00 6.00 6.00 6.00 6.00

End Period Prod (Mcf/d) 718 532 458 414 375 339 307 278 251 227 31

Decline (% of Year 1) 75% 30% 15% 10% 10% 10% 10% 10% 10% 10% 10%


Revenue ($MM) 1.87 1.09 0.87 0.76 0.69 0.62 0.57 0.51 0.46 0.42 3.86LOE ($MM) 0.25 0.09 0.08 0.07 0.07 0.06 0.06 0.05 0.05 0.05 0.52


Overhead ($MM) 0.07 0.05 0.04 0.04 0.04 0.04 0.03 0.03 0.03 0.03 0.31

DD&A ($MM) 0.33 0.19 0.15 0.14 0.12 0.11 0.10 0.09 0.08 0.07 0.68

Tax ($MM) 0.30 0.18 0.14 0.13 0.11 0.10 0.09 0.08 0.07 0.07 0.57

Cash Flow ($MM) 1.22 0.74 0.58 0.51 0.46 0.41 0.37 0.34 0.30 0.27 2.38

Cash Flow ($/Mcf) 3.92 4.07 4.04 4.01 3.99 3.97 3.95 3.93 3.91 3.88 3.70P/T Disc. Cash Flow ($MM) 1.45 0.80 0.57 0.46 0.37 0.30 0.25 0.20 0.17 0.14 0.73



The above well economics calculation assumes no drainage overlap between wells. Given new data releasedby EOG, it appears that well spacing down to 1000 feet will still result in the economics shown above. 1000-foot spacing coupled with a 4,500-foot lateral is equivalent to 100-acre spacing. Data from EOG suggests that a2,500-foot lateral may be optimal (still resulting in a 2.4bcf well); this would equate to 60-acre spacing.However, the industry is experimenting with even tighter spacing as EOG is drilling pilots on 500-foot spacing(30-acre spacing). Initial results imply that there is overlap of the frac networks on this denser pattern resultingin some rate acceleration. Thus doubling the locations does not double the reserves.

While its still too early to know precisely how much overlap exists on 30-acre spacing, our initial roughguesstimate is that the per-well reserves would fall ~25% to 1.8bcfe gross (the downspaced well would be 50%new reserves, 50% rate acceleration). Assuming the same well cost and decline rate characteristics, per wellreturns would only fall to 86% (obviously still attractive). Figure 23 shows our estimate of the well economicsfor a downspaced Tier 1 well.

Figure 23 Barnett Shale Core/Tier 1 Horizontal Well Economics Downspaced WellSummary





NPV ($MM) 1.7NPV/Mcfe 1.22



Running well economics for a Tier 2 well is more difficult, because we do not have enough production historyfrom the region to calculate meaningful median/mean production rates or decline curves. Thus the best we cando is work with the limited data we have from public companies and industry sources and assume decline rateswill be similar to horizontal wells in the core and Tier 1 non-core. As we mentioned earlier, Tier 2 Barnett


28/52


acreage has less gas-in-place (thinner and shallower) and questions persist regarding the western extent of thegas window. The biggest risks to Tier 2 economics are initial production and decline rate.

This is what we think the typical Tier 2 horizontal well in the Barnett looks like:

Well cost about $1.5 million to drill and complete; less than core/Tier 1 due to shallower target. Peak monthly production 900mcf/d. The calculated rate equivalent to an EUR of 1.4bcf/well when assuming

the same decline curve as seen in the core/Tier 1 horizontals.

Decline curve 55% in year 1, 25% in year 2, 15% in year 3, 10% thereafter. Data from core/Tier 1 wells. Reserves per well 1.4bcf gross; derived from both EOGs bottom-up estimate of reserves per well and our

top-down estimate of ~75bcf gas-in-place per section.

F&D cost- $1.34/mcf. (80% net revenue interest)Figure 23 shows our well economics calculation for the median Tier 2 non-core horizontal well, which are

strong, but not as favorable as in the Tier 1 and core horizontals. We estimate that the averagewell (900mcf/d)

will generate a 70% return in a $6/mcf NYMEX price environment. The median well return will likely bebelow this.

Figure 23. Barnett Shale Tier 2 Horizontal Well EconomicsSummary





NPV ($MM) 1.0

NPV/Mcfe 0.93


Year 1 Year 2 Year 3 Year 4 Year 5 Year 6 Year 7 Year 8 Year 9 Year 10 Years 11-30


Gas Price ($/Mcf) 6.00 6.00 6.00 6.00 6.00 6.00 6.00 6.00 6.00 6.00 6.00End Period Prod (Mcf/d) 425 315 271 245 222 201 182 164 149 135 18

Decline (% of Year 1) 75% 30% 15% 10% 10% 10% 10% 10% 10% 10% 10%


Revenue ($MM) 1.11 0.64 0.51 0.45 0.41 0.37 0.33 0.30 0.27 0.25 2.29LOE ($MM) 0.18 0.06 0.05 0.04 0.04 0.04 0.03 0.03 0.03 0.03 0.31


Overhead ($MM) 0.04 0.03 0.03 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.18

DD&A ($MM) 0.25 0.14 0.11 0.10 0.09 0.08 0.08 0.07 0.06 0.06 0.51

Tax ($MM) 0.15 0.10 0.08 0.07 0.06 0.06 0.05 0.04 0.04 0.04 0.31

Cash Flow ($MM) 0.71 0.44 0.35 0.31 0.28 0.25 0.22 0.20 0.18 0.16 1.44

Cash Flow ($/Mcf) 3.84 4.14 4.11 4.08 4.06 4.04 4.02 4.00 3.98 3.95 3.77

P/T Disc. Cash Flow ($MM) 0.82 0.47 0.34 0.27 0.22 0.18 0.15 0.12 0.10 0.08 0.43



We do have a small amount of data about the wells in Tier 2. EOG has announced flow rates from 2 wellsand IFNY has announced flow rates from 4 wells. We will ignore the EOG results for now (tested at 0.5 and0.9mmcf/d) as they were not drilled with full laterals. However the IFNY wells were drilled with full laterals.These wells have averaged 100, 210, 640, and 1,130mcf/d. Of these the last two wells look to be economic inour scenario (we have also heard well costs were >$2 million, higher than our assumptions). Although weexpect results to improve as companies improve the completion techniques in the area, wed be lying if we saidthe rates didnt give us some concern. So far most of the wells are noticeably below our assumed average.


29/52


How would the steeper decline curve seen in the KWK model impact our economics? For core/Tier 1horizontals, it would lower the return in our $6/mcf scenario to 85% from 113%. For Tier 2 wells, it wouldlower the average return to 47% from 70%. Clarity on the actual decline will occur over time with moreproduction history.

Peeling Back the OnionOne piece of data we found interesting is that the average production rate was consistently above the median

production rate. This implies that the well results are not normally distributedin fact the data appears to belog normally distributed.

A log normal distribution simplistically means that there are more below-average wells than above-average wells.However, the good wells tend to be really good, pulling up the average. As the average vertical and horizontalwell looks economic in our base case scenario, it is important to analyze the downside cases. Figures 24 and 25show the distributions of the vertical and horizontal well results for 2004.

Figure 24. 2004 Vertical Well Distribution

0

20

40

60

80

100

120

140

250 500 750 1,000 1,250 1,500 1,750 2,000 2,250 2,500 More

Peak Monthly Production (mcf/d)

#

ofWells

0%

20%

40%

60%

80%

100%

120%

Frequency

Cumulative %

Average: 652mcf/d

Median: 571mcf/d



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Figure 25. 2004 Horizontal Well Distribution

0

5

10

15

20

25

30

35

40

45

50

500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 More

Peak Monthly Production (mcf/d)

#ofWells

0%

20%

40%

60%

80%

100%

120%

Frequency

Cumulative %

Average: 1,638mcf/d

Median: 1,402mcf/d


In a $6/mcf environment, we estimate the minimum peak monthly production necessary for a horizontal wellto break even to be ~650-750mcf/d (depending on richness of gas production). For a vertical well, the

minimum peak monthly production would need to be ~400-450mcf/d. Looking back at the wells drilled in2004, 23% of the horizontal wells and 32% of the vertical wells would be uneconomic in our $6/mcf gas pricescenario. Figure 26 shows the breakdown of this data for Denton, Tarrant, Wise and Johnson counties.


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Figure 26a. Well Performance Breakdown by County Vertical Wells

Vertical Wells

County Well Count Avg. Well Med. Well $5/mcf $6/mcf $7/mcfDenton 378 695 637 40% 24% 14%

Tarrant 130 937 874 24% 15% 11%Wise 297 772 682 39% 24% 16%Johnson 15 597 620 47% 40% 20%Total 820 759 690 37% 23% 14%

County Well Count Avg. Well Med. Well $5/mcf $6/mcf $7/mcf

Denton 180 614 559 52% 34% 23%Tarrant 126 785 685 34% 21% 14%

Wise 145 594 519 59% 35% 26%Johnson 24 578 428 54% 46% 38%

Total 475 652 573 50% 32% 22%

Production (mcf/d) % Wells Uneconomic

% Wells Uneconomic

2003

2004

Vertical Breakeven Economics mcf/d

Benchmark Price: Core Johnson

$5/mcf 570 500$6/mcf 445 400

$7/mcf 365 335

Production (mcf/d)


Figure 26b. Well Performance Breakdown by County Horizontal Wells

Horizontal Wells

County Well Count Avg. Well Med. Well $5/mcf $6/mcf $7/mcfDenton 30 1856 1625 13% 13% 10%

Tarrant 17 2134 1967 12% 12% 12%Wise 17 1756 1673 29% 18% 6%

Johnson 5 936 704 60% 40% 0%Total 69 1833 1654 20% 16% 9%

County Well Count Avg. Well Med. Well $5/mcf $6/mcf $7/mcf

Denton 62 1448 1336 29% 23% 15%

Tarrant 47 1990 1821 15% 11% 6%Wise 59 1208 902 53% 37% 34%Johnson 41 2139 2107 22% 17% 10%

Total 209 1638 1474 31% 23% 17%

Production (mcf/d)

Production (mcf/d)

% Wells Uneconomic2003

2004% Wells Uneconomic

Horizontal Breakeven Economics

Benchmark Price: Core Johnson

$5/mcf 950 830

$6/mcf 740 670$7/mcf 610 560

Production (mcf/d)



32/52


The prior tables also add color to our earlier discussions of sweet spots in the play. One thing jumps out at usimmediatelyproduction from both vertical and horizontal wells got worse in 2004 vs. 2003 in the core area.The poor core area trend likely results from some combination of two factors: the relative maturity and theindustrys continued downspacing of the Newark East field and an increased percentage of the wells drilled

outside of the sweet spot. Horizontal wells in Johnson County bucked the poorer year-over-year results as thecounty is less developed and the industry made significant strides in completion techniques.

Looking first at core area verticals, both the average well (656mcf/d) and the median well (581mcf/d) wereeconomic. In both 2003 and 2004, Tarrant County wells were superior to those in Denton and Wise. In 2004Wise County wells delivered the poorest performance. One possible explanation for this is that a large numberof the Wise wells in 2004 appear to be field extension wells well drilled outside of the sweet spot. However thiscould also indicate that the sweet spot of Wise is more mature than in Tarrant and Denton

If we lower our benchmark gas price assumption to $5/mcf, vertical wells become a lot dicier. In 2004 themedian well would have been economic only in Tarrant County. Roughly 50% of the vertical wells drilled inthe core area would be uneconomic at $5/mcf gas. If we bump our gas price assumption up to $7/mcf,its full steam ahead in the play, as both the average and median well are quite economic in everycounty.

As mentioned, horizontal wells look better than vertical wells. In our base case scenario, both the average andmedian well is economic in each of the four counties. Surprisingly, despite consistently hearing that the corearea is the best acreage in the play, the best wells are the Johnson County horizontals (2,139/mcf average rate),with superior economics to both core area horizontals and verticals. The best core area horizontals are inTarrant County.

Lowering our gas price to $5/mcf doesnt have the same impact to a horizontal drilling program, as averageand median wells for the most part remain economic. The exception is Wise County, where ~55% of the 2004

horizontal wells would have been uneconomic. Similar to what we see with the vertical wells, a $7/mcf gasprice means everything works.

Summing it UpTwo wordssize matters! The primary take-away from this data is that a large acreage position is necessary. The

Barnett Shale is a highly complex reservoir with economics that vary widely from well to well. The data showsthat a fair amount of the wells drilled are uneconomic in a $6/mcf environment, but the good wells make theaverage work. Since the industry has yet to figure out how to distinguish good wells from bad wells prior todrilling, a large, contiguous acreage position is desired in order to minimize the risks in the play. While its truethat a smaller acreage position could be entirely in a sweet spot, it could also miss it entirely

Horizontals rock. Horizontal wells have consistently generated better returns that verticals wells over the last 2years. If gas prices fall significantly, expect vertical wells to be the first to get cut back.

Overall, the play looks quite good. In a $6/mcf gas price environment, rates of return in the Barnett look quiteattractive. Of course, they look far better for horizontal wells than they do for vertical wells, regardless ofwhere they are drilled. Even in a $5/mcf gas price environment, average well returns remain attractive. Nowlets just hope drilling and completion costs dont go up any more


33/52


Johnson looks sweet. At this point in the plays development, wed take random acreage in Johnson County overthe core counties (Tarrant, Denton, Wise) any day of the week. The Newark East field looks relatively mature(which is consistent with statements from DVN that its core area production has peaked) and core area resultsoutside of Newark East havent been nearly as good. The Johnson horizontals, however, have been quite good,

and it appears that another sweet spot trend is emerging.

Tier 2 still too early to tell


34/52


Reserve Potential

There are two ways to calculate reserve potential net to the companies top down (reserves/section) orbottom up (reserves/well). As it is still unclear what the optimal spacing will need to be or how many stacked

laterals will be required to effectively develop the resource base, we choose to use the top down method toestimate reserves.

In order to estimate reserve exposure per company, we need five pieces of information: net acres, gas in placeper section, recovery factory, drillable acreage and royalty rate.

Reserve Potential = Net acres x Gas in place per acre x Recovery factor x % of acres that can be drilledx (1 - royalty rate)

Net acres. Self explanatory. How much acreage each company owns.

Gas in place. The total resource potential of the Barnett Shale is estimated by the USGS to be ~200tcf.

While this is certainly an impressive number, it does little to convey information about the resource potential ofan individual companys acreage position. A more useful number is gas in place per section. Studies on theplays resource potential have indicated that the Barnett can have gas in place ranging from 50-150bcf persection, depending on the thickness of the shale. Remember that 1 section = 640 acres (1 square mile).

Estimates for gas in place in the core area of the Barnett run ~140-145bcf per section. We use the midpointof this range. As the Barnett shale remains thick in much of the Tier 1 non-core, we will also use this gas inplace estimate for Tier 1.

As the play moves to the south and west, the Barnett shale gets quite thin and shallows significantly. Thisaffects reserves in place from two angles. First, there is less volume available for the gas to occupy. And

second, the shallower depth means there is less pressure, so a smaller quantity of gas will be crammed into anequivalent pore space when compared to the deeper sections. As a result, the gas in place in the Tier 2 non-core area is likely to be much lower than it is in Tier 1. We assume that 75bcf per section will be the average forTier 2 (the range is likely 50-125bcf per section). As there is little production data from this area, this estimate isquite rough. Our discussion with industry contacts and Barnett operators indicates this is a reasonable startingpoint given whats known about the area.

Recovery factor. The recovery factor (rf) for the core area of the Barnett Shale has been estimated at 10-15%, though recent data indicates this range may be too low. EOG recently announced that it expects to drill2.4bcf wells on 60-acre spacing in Johnson County. This implies an rfof 18%. That is, ultimate recovery willonly be 18% of the original gas in place. As this is the most recent datapoint we have, we use 18% as theaverage rf in the core and Tier 1 non-core areas for our analysis.

Any further increase in the overall recovery factor would be very significant to reserves. Some companies arecurrently working to further increase the rf by drilling downspaced pilot tests. Our initial take on EOGs 30-acre pilot implies an rf of 26% as the new wells are adding some incremental reserves. Admittedly, this numberseems high to us, but it is what it is. As there is still limited data on how extensively downspacing will work andjust how many new reserves it will add, we think its best to throw it in the unquantified upside category forthe time being.


35/52


As there is still little information available on the Tier 2 non-core, we are not comfortable assuming the higherrf at this time. As a result, we are using an rf of 12% for the acreage until we know whether tighter spacing orshorter laterals will be successful in Tier 2.

Drillable acreage. The Barnett Shale is a very complex reservoir. Geologic features such as karsts(sinkholes in laymans terms) and faults can cause wells to be wet or unproductive. As a result, E&P companiesmust use 3-D seismic defensively to avoid these structures. This complexity implies that 600%), KWK (200%), and EOG (>60%).


36/52


Figure 27. Barnett Shale Upside CalculationBR CHK CRZO DNR DVN ECA EOG IFNY KWK PLLL XTO

Core/Tier 1

Net acres 72,000 48,000 35,750 20,800 535,000 38,100 90,000 0 67,500 2,300 116,000

Sections 113 75 56 33 836 60 141 0 105 4 181

Bcf/Section 143 143 143 143 143 143 143 143 143 143 143Gas in place (Bcf) 16,031 10,688 7,960 4,631 119,121 8,483 20,039 0 15,029 512 25,828

Recoverable gas (Bcf; @ 18%) 2,822 1,881 1,401 815 20,965 1,493 3,527 0 2,645 90 4,546

Net reserves (Bcf, @ 80%) 2,257 1,505 1,121 652 16,772 1,194 2,822 0 2,116 72 3,637

Tier 2

Net acres 17,000 0 29,250 22,700 18,000 88,900 400,000 60,700 162,500 0 39,000

Sections 27 0 46 35 28 139 625 95 254 0 61

Bcf/section 75 75 75 75 75 75 75 75 75 75 75

Gas in place (Bcf) 1,992 0 3,428 2,660 2,109 10,418 46,875 7,113 19,043 0 4,570

Recoverable gas (Bcf; @ 12%) 239 0 411 319 253 1,250 5,625 854 2,285 0 548

Net reserves (Bcf, @ 80%) 191 0 329 255 203 1,000 4,500 683 1,828 0 439

Total

Net acres 89,000 48,000 65,000 43,500 553,000 127,000 490,000 60,700 230,000 2,300 155,000

Net reserves (Bcf) 2,448 1,505 1,450 907 16,975 2,195 7,322 683 3,944 72 4,075

85% drillable acreage 2,081 1,279 1,232 771 14,429 1,865 6,223 580 3,353 61 3,464

50% drillable acreage 1,224 752 725 454 8,487 1,097 3,661 341 1,972 36 2,038

Upside Reserve Potential

Total Barnett potential (Bcf) 1,224 752 725 454 8,487 1,097 3,661 341 1,972 36 2,038

Barnett proved reserves (Bcf)* 290 175 32 64 1,940 300 136 0 36 0 550Cumulative Barnett production (Bcf)* 35 7 0 2 752 12 3 0 0 0 13

Upside reserves (Bcf) 899 570 693 387 5,795 785 3,522 341 1,936 36 1,475

% of total proved reserves 7% 12% 634% 50% 47% 6% 62% 3711% 200% 28% 25%

Total proved reserves (Bcfe) 12,007 4,902 109 776 12,462 13,467 5,647 9 968 130 5,860

Source: IHS Energy and Pickering Energy Partners*estimated

Two of these companies have made a large bet on the western edge of the play. ~80% of EOGs acreage islocated in Tier 2, primarily in Jack, Erath, and Palo Pinto counties, while all of IFNYs acreage is located inErath and Comanche counties. This increases the risk associated with these assets as it is still unclearwhether or not the western counties are truly in the gas window.

Of these four companies, KWK appears to have the lowest risk acreage position as its acreage is concentratedin the eastern portion of Hood and Somervell counties. CRZO actually has a greater percentage of its acreagein the Core/Tier 1 than KWK, but it is more fragmented while KWKs is more contiguous. EOG and IFNYboth get a qualitative ding for the high percentage of western county acreage.

DNR, DVN, PLLL, XTO and CHK also have significant upside reserve potential from the Barnett (~50%,50%, 30%, 25%, and 10% respectively). PLLL, however, has a relatively small acreage position (which is aconcern given prior discussion). BR and ECA each have


37/52


Exhibit 28. Core Vertical Well Value ($MM)

0.39 500 650 800 950

$3.00 ($0.5) ($0.4) ($0.3) ($0.2)

$4.00 ($0.3) ($0.1) $0.0 $0.2$5.00 ($0.1) $0.1 $0.3 $0.6

$6.00 $0.1 $0.4 $0.7 $1.0

$7.00 $0.3 $0.7 $1.0 $1.3

$8.00 $0.5 $0.9 $1.3 $1.7

$9.00 $0.7 $1.2 $1.7 $2.1GasPrice($/M

cf)

Peak Monthly Production (Mcf/d)


Average well = 650 mcf/d; $0.4MM NPV @ $6/mcf

Exhibit 29. Tier 1 Horizontal Well Value ($MM)

2.26 1000 1500 2000 2500

$3.00 ($0.7) ($0.1) $0.4 $1.0

$4.00 ($0.2) $0.6 $1.5 $2.3

$5.00 $0.4 $1.4 $2.5 $3.6

$6.00 $0.9 $2.2 $3.5 $4.9

$7.00 $1.4 $3.0 $4.6 $6.2

$8.00 $1.9 $3.8 $5.6 $7.5

$9.00 $2.4 $4.6 $6.7 $8.8GasPrice($/Mcf)




Exhibit 30. Tier 2 Horizontal Well Value ($MM)

1.04 700 900 1100 1300

$3.00 ($0.6) ($0.4) ($0.1) $0.1

$4.00 ($0.2) $0.1 $0.4 $0.7

$5.00 $0.1 $0.6 $1.0 $1.4

$6.00 $0.5 $1.0 $1.6 $2.1

$7.00 $0.9 $1.5 $2.1 $2.8

$8.00 $1.2 $2.0 $2.7 $3.5

$9.00 $1.6 $2.5 $3.3 $4.1GasPrice($/Mcf)




However, even with these figures, it is not a simple extrapolation process to determine the value to anindividual E&P companys acreage position. The primary reason for this is time value of money. The NPV ofthe acreage position is highly sensitive to the number/location of wells drilled each year, so the analysis isclouded by assumptions of future rig counts, location of the rigs, type of well drilled (horizontal/vertical), etc.


38/52


Lets take KWK for instance. The company has 230,000 acres in the Barnett play. Assuming 50% drillableacreage and just 100-acre spacing, KWK has ~1,285 locations in its inventory. With the two rigs its currentlyusing, it would take >40 years to drill its entire acreage position (15 wells per rig-year). Even if the companyimmediately accelerates to its targeted 6 rigs, it would still take KWK almost 15 years to fully drill its acreage.

Clearly, the NPV of the companys Barnett assets would be different in a 40-year versus a 15-year drillingscenario.


39/52


Company-specific Barnett upsideHaving highlighted the challenges of the analysis, lets look at the results.

Exhibit 31. Value of Barnett Upside Potential


BR

CHK

CR

ZO

DNR

DVN

ECA

EOG

IFNY

KWK

PLLL

XTO

StockPrice

$81.3

2

$38.2

5

$29.2

7

$50.4

4

$68.6

4

$58.3

1

$74.9

0

$8.1

5

$47.7

9

$13.9

9

$45.3

2

BaseCase($6/m

cfgas,50%drillableacreage,60-acrespa

cing):

ProvedReserve

NAV

$53

$26

$44

$31

$15

$27

BarnettPotentia

l

$2

$2

$

26

$6

$10

$1

$10

$17

$15

$1

$4

NAVw/Barnett

Potential

$55

$32

$53

$41

$30

$32

Deltavs.

CurrentPrice

-$26

-$18

-$15

-$33

-$18

-$14

%o

fcurrentsto

ckprice

-32%

-36%

-22%

-45%

-38%

-30%

UpsideCase1($

6/mcfgas,85%drillableacreage,60-acre

spacing):

ProvedReserve

NAV

$53

$26

$44

$31

$15

$27

BarnettPotentia

l

$4

$3

$

37

$10

$13

$1

$14

$24

$19

$2

$7

NAVw/Barnett

Potential

$56

$36

$57

$45

$33

$35

Deltavs.

CurrentPrice

-$25

-$14

-$12

-$30

-$15

-$11

%o

fcurrentsto

ckprice

-31%

-28%

-17%

-40%

-30%

-23%

UpsideCase2($


spacing):

ProvedReserve

NAV

$53

$26

$44

$31

$15

$27

BarnettPotentia

l

$4

$3

$

39

$11

$14

$1

$11

$17

$19

$2

$8

NAVw/Barnett

Potential

$57

$37

$57

$42

$33

$35

Deltavs.

CurrentPrice

-$25

-$14

-$11

-$33

-$15

-$10

%o

fcurrentsto

ckprice

-30%

-27%

-17%

-43%

-31%

-22%

UpsideCase3($


spacing,50%higherrigcount):

ProvedReserve

NAV

$60

$27

$49

$37

$18

$33

BarnettPotentia

l

$8

$7

$

83

$24

$28

$3

$28

$41

$40

$4

$18

NAVw/Barnett

Potential

$68

$51

$77

$65

$58

$52

Deltavs.

CurrentPrice

-$13

$1

$8

-$10

$11

$6

%o

fcurrentsto

ckprice

-16%

2%

12%

-13%

22%

14%

BarnettValueSensitivites(fromBaseCase):

$1/Mcfchangeingasprice

$0.8

1

$0.5

7

$9

.38

$2.3

9

$3.4

4

$0.3

0

$3.99

$7.8

3

$5.7

9

$0.3

8

$1.5

3

5%in

creaseind

rillableacreage

$0.2

3

$0.1

7

$1

.96

$0.6

4

$0.7

4

$0.0

8

$0.67

$1.2

2

$0.7

3

$0.1

0

$0.5

1

1%in

creaseinr

ecoveryfactor

$0.1

4

$0.1

0

$1

.23

$0.4

1

$0.4

4

$0.0

5

$0.46

$1.0

0

$0.4

8

$0.0

5

$0.3

0

1additionalrig

$0.0

5

$0.0

2

$1

.02

$0.1

2

$0.1

9

$0.0

2

$0.19

$1.1

8

$1.0

8

$0.0

3

$0.0

1

1%in

creaseininitialdecline

-$0.0

5

-$0.0

4

-$0.6

4

-$0.1

4

-$0.2

9

-$0.0

2

-$0.33

-$0.6

7

-$0.5

9

$0.0

0

-$0.0

9

10%in

creasein

drillingcosts

-$0.1

8

-$0.1

2

-$2.1

2

-$0.5

6

-$0.7

5

-$0.0

7

-$0.98

-$2.1

4

-$1.3

7

-$0.0

6

-$0.3

4


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The previous table shows the NAV impact of the Barnett in four scenarios. We view our base case as themost likely, but provide three more aggressive scenarios for perspective (and to account for companies likeCHK and CRZO arguing that 85% drillable is more likely on their acreage). The delta relative to the currentstock price represents the per share value that must come from future growth outsidethe Barnett Shale to justify

the current stock price. For instance, DNR has a large delta in our base case, but it is straightforward to identifyadditional value in the companys tertiary recovery potential.

We should highlight two of our assumptions. We use a 25% cash tax rate in the analysis. Some companies(such as KWK) have corporate tax shields which will allow them to pay a lower percentage of cash taxes overthe next few years. For number of wells drilled per year, we use companies expected rig count over the next 12months and assume each rig can drill 15 Barnett wells per year.

The four scenarios we provide obviously dont cover all the possible or even likely scenarios. For example, itis highly probable that many of the Barnett operators will continue to expand their rig count in subsequentyears. As a result, we have included sensitivities to many of the key variables used in the analysis. Thesensitivities are calculated from the upside Barnett potential in our base case scenario.

Our primary takeaway from this analysis is that Barnett upside is already priced into most of these stocks(with some priced to perfection). An investor has to use aggressive assumptions about the play (not tomention higher commodity prices) to justify buying most of these names on Barnett upside alone.

The stock which looks the most interesting as a Barnett play at current stock prices is CRZO (not on ourofficial coverage list). CRZOs upside Barnett value in our base case is $26/share, not far below its currentstock price. Make some more aggressive assumptions about drillable acreage, etc, and you might not need toknow much about its other assets.

While it appears that IFNY has significant upside potential from the Barnett as well, we caution that it has the

riskiest acreage position among the companies listed (100% Tier 2, ~50% in Comanche County). For thepurpose of this analysis, we assigned value to all of a companys acreage position, even if it we viewed it as lowprobability. We doubt the Barnett will be productive in Comanche County (an opinion we view to be validatedby IFNYs announcement that it will develop this acreage with vertical wells to test the Marble Falls as well),and thus a more prudent way to look at IFNY might be to cut the numbers in the prior table in half. Itsremaining acreage position is not without risk either, being concentrated in Erath County. IFNY has a lot ofupside potential if its acreage works but at this point thats a big if.

The stock whose valuation concerns us the most is EOG (we exclude BR as it is not really a Barnett story).Even in our most aggressive scenario, the company would still need a significant amount of NAV growthoutside of the Barnett to warrant its current stock price. At current levels, EOGs Barnett position appears fullyvalued and, perhaps, even overvalued.

EOG a closer lookThat EOG was still ~$10/share shy of its current price even in our aggressive upside case has made us take a

closer look at its valuation. The following table breaks down a fair value for EOG given our Barnettcalculations, as well as the assumptions that would be required to justify the current stock price. (Note theanalysis assumes EOG operates 9 rigs in 2005 and 16 rigs thereafter. Also, each rig is assumed to drill 15 wellsper year.)


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Exhibit 32. EOG Value CalculationEOG ($74.90)Proved Reserve NAV @ $6 and $45/bbl $31Appropriate NAV Multiple 1.1xStock Value of Proved Reserves $35

Barnett Upside Value @ Base Case $10Base Case EOG Stock Value $45

Required Assumptions to justify current stock price:Proved Reserve NAV @ $7/mcf and $50/bbl $38Appropriate NAV Multiple 1.1xStock Value of Proved Reserves $42Barnett Upside Value @ $7/mcf gas $1430-acre Spacing in Johnson (26% recovery) +$185% Barnett acreage drillable +$4150% higher rigcount than base case +$1118% Recovery factor for Tier 2 +$3

Stock Value $75


As EOG is a well-run company, we believe 1.1x is a fair multiple to place on its proved reserve NAV toaccount for its going concern value. This multiple generates a per share value for EOG of $35 excludingBarnett upside. Adding this to our base case $10 per share value for EOGs unbooked Barnett potential yields$45 per share, ~40% below the current stock price.

In order to justify the current stock price, we have to make a number of aggressive assumptions. First, weneed to increase our benchmark gas price assumption to $7/mcf (in line with what peers are currentlydiscounting). We also have to assume that 30-acre spacing works on all of its Johnson acreage, that 85% of thecompanys acreage is productive, that EOG more than doubles its rig count from our forecast 2006 level (to 40rigs from 16), and that the recovery factor in the Tier 2 non-core can be increased to 18%.

We should note that EOGs well cost assumptions are at the low end of the industry range, and below theaverage well cost we are using in our model. EOG is assuming a well cost of $1.6 million for its JohnsonCounty acreage (Tier 1) and $1.1 million for its Tier 2 acreage (vs. our assumptions of $2.0 million and $1.5million). Using the EOG well cost assumptions would increase the NPV of a Tier 1 well to $2.6 million from$2.3 million and the NPV of a Tier 2 well to $1.4 million from $1.0 million.

The impact of this cost structure on the above analysis would be to increase the Barnett upside value in ourbase case to $12 per share from $10, resulting in a base case stock value of $47. In the second case, the lowercost structure would result in a stock value of $81, or $6 higher than with the Pickering Energy costassumptions. With EOG currently trading at $75, it certainly feels to us that even the most aggressive EOG

assumptions are already priced into the stock.

Could we be wrong? Of course, as our analysis is based on imperfect data and a number of assumptions. Ifinvestors are willing to make more aggressive assumptions than those in the table above (or assume a highercommodity price deck), buying EOG at current levels still makes sense. However, even if one was willing tomake those assumptions, we still think it wiser to buy one of the cheaper Barnett players which could offersignificantly higher upside potential in such a scenario.


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The Unknowns

Although the industry has been developing the Barnett shale for quite some time now, a number of questionstill remain, especially in the non-core area. We will not try to discuss all of these, but will highlight five issues

that will have an impact on the play economics and reserve potential: drillable acreage, recovery factor, oil/gaswindow, decline rates, and retrograde reservoir.

The first two topics were discussed earlier. As the industry shoots more seismic over the area and gets morewell control, it will be able to refine its rough estimate of drillable acreage. For now, thats just what it isarough estimate. As the earlier table shows, if drillable acreage is indeed closer to 85%, we are materiallyunderestimating the upside reserve potential of the play (and Barnett valuations look more palatable).

Recovery factory could also continue to improve over time. New data from E&P companies implies therecovery factor may be closer to 18% (well up from the 12% estimate we were using when we started writingthis report). Further increases are possible due to downspacing, improvements in technology, etc. That said, itwont be easy. Recovery improvements could boost both upside reserve potential and drilling returns (if the per

well recovery is improved; not the case with downspacing) beyond what our analysis suggests.

Oil/gas window. A key question that has yet to be fully answered is where the gas window ends.Conventional wisdom in the industry indicated that the gas window did not extend into the western counties(Jack, Erath, Palo Pinto). Currently, companies such as EOG and IFNY are trying to prove the viability ofthese counties.

Why do we care about oil vs. gas? Simple Given the larger size of its molecules, oil will not flow very well(if at all) in the ultra-tight Barnett. This means that any gas trapped behind the liquids will not flow either.Currently, adsorbed gas is estimated to be ~25% of the gas in place, but we caution that this is still a very roughestimate. Wells fully in the oil window are easy to identify, as early production will be mostly oil. Where it gets

trickier is in the transition zone, where oil and gas could both be present in the reservoir.

Early production from a well in the transition zone will be mostly gas, as the oil molecules will not flow aseasily. This does not necessarily mean that the well is in the gas window. The well may initially look like a gaswell, only to have future production decline more rapidly than expected (resulting in lower than anticipatedreserves) as the free gas is exhausted. Basically, assuming the above free gas/adsorbed gas ratio is correct, thewell would yield 25% lower than expected reserves and lower returns (breakeven production level would jumpto 735mcf/d from 670mcf/d in $6/mcf gas scenario). The returns figures also assume that all the lostproduction comes at the end (ie. production curve looks the same, then drops to zero after free gas isproduced), which is probably not a conservative enough assumption.

Possibility of retrograde condensate reservoir. Is the rich gas stream in the non-core Barnett a blessing or

a curse? Companies currently benefit from the increased heat content created by the liquids in the gas stream,but this does pose a potential problem down the road. Some industry experts postulate that portions of theBarnett transition zone are a retrograde condensate reservoir. This means that liquids drop out of the gasstream while still in the reservoir, rather than once they reach the surface. This could pose a problem similar tothe oil/gas window as it could reduce eventual recovery. Its too early to know one way or the other, but it issomething that investors should keep an eye on.


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Decline rates. We touched on this earlier in the report with the KWK example. The decline rates that willbe seen in the non-core area of the play are not precisely known at this time. We have estimates at this point,but these will most likely change as the industry gets more production data. While a changing shape of thedecline curve might not impact the reserves in the play (as in the KWK example), it may have a significant

impact on economics. Only time will tell if current expectations of the typical Barnett decline curve prove tobe too conservative or too aggressive.


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Summary/Conclusions

Not all acreage is created equally. Significant variability of results exists even within concentrated areas. Early mover advantage. On average, the companies that were early entrants into the play got the best

acreage and have the best results.

Size matters. For this type of a statistical play (highly variable) to work, a large enough acreage position isrequired for the law of large numbers to take effect.

Not all acreage is created equally (part 2). The Barnett Shale does appear to have sweet spots that willbe far more productive than the average acreage position.

This resource play takes a continuous technical feedback loop to maintain optimal wellperformance. Operators shouldnt let the drilling program get ahead of well performance.

Not all wells are economic. However the statistical nature of the Barnett suggests that, in aggregate, goodwell more than offset bad wells.

Unknowns remain, especially in the non-core area. The industry still does not have definitive proof ofwhere the gas window ends, nor what the decline rates or recovery factor will be. Each of these items willmeaningfully impact the plays ultimate potential.

On average, Barnett upside potential appears to be fully reflected in stock prices. More aggressiveassumptions (higher gas prices, more drillable acreage, higher recovery factor, etc) are needed to findsignificant upside from current levels.

Barnett stock picks CRZO (not officially covered) looks interesting while EOG looks riskiest.


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Appendix A Gas Shale Terminology

Gas Shales Natural gas is generated and stored in a shale in two forms 1) free gas which occupies the pore

space (similar to conventional gas reservoirs) and 2) adsorbed gas which is stored on the organic matter. Gasshales are organic-rich, fine-grained sedimentary rocks containing a minimum Total Organic Carbon (TOC) of0.5% with varying degrees of thermal maturity as measured by vitrinite reflectance RO.

TOC in the Barnett Shale is ~4.5%. Generally, RO values 1.0% are thought to be gas productive. Shales may have varying degrees of thermal maturity ranging from0.4-0.6% RO (marginal) to 0.6 to 2.0% RO (mature). Barnett Shale RO values vary widely from >1.5% in the corearea to


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Appendix B Comparison of Organic Shales in the US

Comparison of Organic Shale PropertiesBarnett Ohio Antrim New Albany Lewis Fayetteville

Depth, ft 6,500-8,500 2,000-5,000 600-2,200 500-2,000 3,000-6,000 1,500-6,500

Gross Thickness, ft 150-700 300-1,000 160 180 500-1,900 50-325

Net Thickness, ft 100-600 30-100 70-120 50-100 200-300 20-200

Bottomhole Temp, F 200 100 75 80-105 130-170

TOC, % 4.5 0.0-4.7 1-20 1-25 0.45-2.5 4.0-9.5

Total Porosity, % 4-5 4.7 9 10-14 3.0-5.5 2-8

Gas Filled Porosity, % 2.5 2 4 5 1-3.5

Water Filled Porosity, % 1.9 2.5-3.0 4 4-8 1-2

Flow Capacity - kh, md-ft 0.01-2 0.15-50 1-5,000 6-400

Gas Content, scf/ton 300-350 60-100 40-100 40-80 15-45 60-220

Adsorbed Gas, % 25 50 70 40-60 60-85 50-70

Reservoir Pressure, psi 3,000-4,000 500-2,000 400 300-600 1,000-1,500 600-2,000

Pressure Gradient, psi/ft 0.43 0.15-0.40 0.35 0.43 0.20-0.25

Water Production, Bwpd 0 0 5-500 5-500 0

Well Spacing, Acres 60-160 40-160 40-160 80 80-320

Recovery Factors, % 10-20 10-20 20-60 10-20 5-15

Gas-In-Place, Bcf/Section 50-150 5-10 6-15 7-10 8-50 25-60

Reserves, MMcf 500-4,000 150-600 200-1,200 150-600 600-2,000 Source: GTI and Pickering Energy Partners

2005 Estimated Gas Production from US Shales

SanJuan: 55

3%

Barnett: 1,233

58%Antrim: 384

18%

Units: mmcf/day

Appalachia/Ohio: 438

21%

Source: GTI and Pickering Energy Partners


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Appendix C Example of Barnett NPV Model

Below we show an example of our Barnett Shale NPV model. The model assumes that the companies focus

their drilling efforts on Core/Tier 1 acreage (higher value) until they run out of locations, then move the rigs totheir Tier 2 acreage. The discount rate used in the analysis is 10%.

EOG Barnett Shale NPV model


Total Year 1 Year 2 Year 3 Year 4 Year 5 Year 6 Year 7 Year 8 Year 9 Year 10 Year 11 Year 12

Core/Tier 1 # Rigs 8 14 14 9 0 0 0 0 0 0 0 0

Wells/rig-yr 15 15 15 15 15 15 15 15 15 15 15 15

# Wells 675 120 210 210 135 0 0 0 0 0 0 0 0

Value/well ($MM) 2.3 2.3 2.3 2.3 2.3 2.3 2.3 2.3 2.3 2.3 2.3 2.3

Value ($MM) 272 475 475 306 0 0 0 0 0 0 0 0

NPV ($MM) 1326 272 432 393 230 0 0 0 0 0 0 0 0

Tier 2 # Rigs 1 2 2 7 16 16 16 16 16 16 16 16

Wells/rig-yr 15 15 15 15 15 15 15 15 15 15 15 15

# Wells 2016 15 30 30 105 240 240 240 240 240 240 240 156

Value/well ($MM) 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0

Value ($MM) 16 31 31 110 250 250 250 250 250 250 250 163

NPV ($MM) 1125 16 28 26 82 171 155 141 128 117 106 97 57

Total Value 2451

FD Shares 243.4

$/share $10.07


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Appendix D Generalized Company Acreage Maps

BR

CHK

CRZO

DNR


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DVN

ECA

*Note ECA has acreage in Montague and Cooke counties(North of Wise and Denton; indicated by upper shading)

EOG

IFNY


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KWK

PLLL

XTO


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Analyst Certification:I, Jeff Hayden and Dave Pursell, do hereby certify that, to the best of my knowledge, the views and opinions inthis research report accurately reflect my personal views about the company and its securities. I have not nor

will not receive direct or indirect compensation in return for expressing specific recommendations orviewpoints in this report.

______________________________________________________________________________________Important Disclosures:The analysts involved in creating or supervising the content of this message (or members of their households)do not own the securities mentioned. This communication is based on information which Pickering EnergyPartners, Inc. believes is reliable. However, Pickering Energy Partners, Inc. does not represent or warrant itsaccuracy. The viewpoints and opinions expressed in this communication represent the views of Pickering

Energy Partners, Inc. as of the date of this report. For detailed rating information, please visit our disclosurewebsite atwww.pickeringenergy.com/disclosure.asp. These viewpoints and opinions may be subject to changewithout notice and Pickering Energy Partners, Inc. will not be responsible for any consequences associated withreliance on any statement or opinion contained in this communication. This communication is confidential andmay not be reproduced in whole or in part without prior written permission from Pickering Energy Partners,Inc.______________________________________________________________________________________Ratings: B = buy,A= accumulate, H = hold,T = trim, S = sell, NR= not rated


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