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The Barnett

Visitors Guide to the

Hottest Gas Play in the US

October 2005

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Jeff Hayden [email protected] (713) 333-2971

Dave Pursell [email protected] 713-333-2962

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Barnett at a Glance The Barnett Shale is one of the largest and most active domestic plays in the U.S. Production is ~1.2bcf/d and there are ~100 rigs drilling. It’s 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 other productive , see Appendix B.

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

Figure 1 . Location of Barnett Shale

Source: Humble Geochemical, Pickering Energy Partners

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The figure below shows the trend in median initial well performance since 1999. Well performance peaked in 2000 and has steadily trended down since then. Possible explanations include the Newark East field continuing to mature and companies attempting to expand the field outside of the sweet spot. We expect the production trend 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)

978

833 825 729 684 621 517 mcf/d

1999 2000 2001 2002 2003 2004 2005

Source: IHS Energy and Pickering Energy Partners

Horizontal vs. Vertical wells Although 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 the decline curves of the typical wells for both horizontal and vertical wells. We care about this because of its impact 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, the graph 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 future forecasts 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 isn’t an issue with our vertical well analysis as 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)

1200 1999 2000 1000 2001 2002 2003 800

600

Production (mcf/d) 400

200

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

Source: IHS Energy and Pickering Energy Partners

Horizontal wells appear to have a shallower decline curve than their vertical counterparts. However we should 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 2003 sample size is better with 64 wells. Focusing on the 2003 numbers, the initial decline rate of horizontal wells appears 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)

3000 2002 2003 2500

3 Wells

2000

1500

64 Wells

Production (mcf/d) 1000

500

0 Peak t+1 t+2 Years

Source: IHS Energy and Pickering Energy Partners

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

A recent example of this is KWK’s update of its “average well” type curve for its acreage in Hood county (Tier 1). The company’s old type curve assumed a shallower initial decline (~45%) than our data suggests. Its updated decline curve now forecasts a steeper initial decline (~65%) followed by a shallower decline in later years. Net-net the company’s model still forecasts the same reserves per well, but the NPV is now lower. It is interesting to note that KWK’s new type curve is similar to the vertical decline curves seen in recent years. See Figure 17 for KWK’s current decline curve assumptions compared to its prior assessment.

Figure 17. KWK Decline Curve (Hood county acreage)

1600 OLD 1400 NEW 1200

1000

800 mcf/d 600

400

200

0

P 3 2 3 6 7 0 1 2 4 5 I r 1 r r 4 r 5 r 8 10 1 1 14 1 1 2 2 2 2 2 a a a r r 15 r r 19 r r 23 r ea ear 2 ea ear 6 ear 9 a a a a a a a Y Y Ye Ye Y Y Year 7 Ye Y ear ear ear Year Year 11 Ye Year Year Ye Ye Y Year 18 Ye Ye Y Year Ye Ye Y

Source: KWK and Pickering Energy Partners

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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 in excess 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 company’s acreage lies? These are some of the questions we will try to answer.

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

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/mcf gas). In short horizontal wells are superior to vertical wells and Core/Tier 1 horizontal wells are superior to Tier 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

Source: Pickering Energy Partners

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

Before we detail the well economics model, we need to discuss the proper inputs. Three of the most important 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 rates from the IHS data set. We turned to operators (both public and private) to get a handle on well costs.

Here’s what the typical vertical well looks like in the core area of the Barnett Shale:

ƒ Well cost – about $1 million to drill and complete. ƒ 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. ƒ Decline curve – 60% in year 1, 30% in year 2, 15% in year 3, 10% thereafter. The steepness of the declines surprised us a little bit, but the data doesn’t lie. ƒ Reserves per well – 0.7bcf gross; calculated from average decline curve, using a 30-year life. ƒ 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 estimate that 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 model assumes core area gas receives a ~$0.50/mcf differential to NYMEX for transportation and btu content.)

Figure 21. Barnett Shale Core Area Vertical Well Economics Summary Initial Production (Mcf/d) 650 Net Reserves (MMcf) 586 Discounted Cash Flow ($MM) 1.4 Discounted Cash Flow ROR 39% NP V ( $ 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

Source: Pickering Energy Partners

We can also see why vertical wells in the non-core area don’t really work. Johnson County should have the best vertical wells of the non-core area because the Barnett Shale is the thick and deep. The median Johnson county 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, as expected, looks better at 585mcf/d, generating a 26% return. But here’s the rub…these numbers all assume mechanical success (i.e. a productive well). Any wells which did not flow (due to fracing into the water-bearing Ellenburger, etc.) are not included in the data set. Thus these results should be viewed as a best case scenario since it’s 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 wasn’t a typo when we used median production rate in our analysis. We view the median production rate to be a better tool for analyzing what the average individual future well will deliver. This is because average production rates tend to be skewed upwards by a few very good wells, whereas median rates do 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 Wells Horizontal 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 of the difference is so large that the only vertical wells we’d expect to see going forward are in areas that have already been densely drilled (downspacing) or near lease lines.

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

Here’s what the typical horizontal well looks like the core and Tier 1 non-core Barnett:

ƒ Well cost – about $2 million to drill and complete. ƒ 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 in each county except Johnson (2.1mmcf/d vs. 0.7mmcf/d). ƒ Decline curve – 55% in year 1, 25% in year 2, 15% in year 3, 10% thereafter. Not quite as steep as in the vertical wells. ƒ Reserves per well – 2.4bcf gross; calculated from average decline curve, using a 30-year life. ƒ 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-core area and a 93% return in the core area (in a $6/mcf NYMEX price environment)…a big jump relative to vertical well economics! Much like we saw with vertical wells, the average horizontal well looks better than the median 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 realized gas price), causing their production to receive a lower price than that of the non-core wells, which produce wet gas (higher btu content gets a higher price).

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