EX-99.1 2 dex991.htm SUPPLEMENTAL INFORMATION Supplemental information

Exhibit 99.1

ASSET OVERVIEW

 

     (dollars in thousands)

Reserve Data as of June 30, 2007:

   

PV-10—SEC Case(1)

    $ 76,947

PV-10—Natural Gas Forward Pricing Case(2)

     110,081

Other Data as of September 30, 2007:

   

Cash(3)

    $ 101,121

Estimated Future Capital Costs to Develop Proved Reserves(4)

      (38,324)

Unproved properties, not being amortized (book value):

   

United States

    $ 44,679

Australia

      22,089

Domestic Asset Overview:

   

Net acreage—East Texas

      16,500

East Texas—Deep Bossier Data:

   

Identified Gross Drilling Locations

      115

Number of Producing Wells Drilled in 2006-2007

      13

Average Net Estimated Ultimate Recovery (“EUR”)(5) Per Well Drilled in 2006-2007 (Bcfe)

      2.3

Range of Drilling Depth (ft.)

      16,500-19,500

Average Days Drilling

      110

Average Days for Completion

      30

East Texas—Knowles Limestone Data:

   

Identified Gross Drilling Locations

      20

Number of Producing Wells Drilled in 2006-2007

      3

Average Net Estimated Ultimate Recovery (“EUR”)(5) Per Well Drilled in 2006-2007 (Bcfe)

      0.7

Range of Drilling Depth (True Vertical Depth, ft.)

      13,500-14,000

Average Days Drilling

      60

Average Days for Completion

      20

International Asset Overview:

   

PEL 238 Data:

   

Net Acreage

      786,000   

Estimated Economic Net Acreage with Identified SPE Definition Proved Reserves

      490   

Identified Net Proved Reserves—SPE Definition (Bcfe)(6)

      6.6   

Gastar Interest in PEL 238

      35.0%

Eastern Star Gas Limited Interest in PEL 238

      65.0%

(1)

Based on constant natural gas and oil pricing and costs in effect as of June 30, 2007 per SEC guidelines.

 

(2)

Present value discounted at 10% of future net revenues of proved reserves at June 30, 2007 using constant pricing based upon the October 24, 2007 average NYMEX forward natural gas sale pricing of $8.00 per MMBtu for calendar year 2008 and constant oil pricing and costs as of June 30, 2007. See “Gas Price Sensitivities—Forward Pricing Sensitivities” on page 19 for a further description of pricing assumptions.

 

(3)

As adjusted to give effect to this offering. See “Capitalization” on page 42.

 

(4)

Based on the reserve report of Netherland Sewell as of June 30, 2007 (the “June 30 Report”).

 

(5)

Cumulative production to June 30, 2007 plus proved reserves estimated in the June 30 Report.

 

(6)

Based on estimates as of September 1, 2007 of Netherland Sewell prepared using SPE definitions and guidelines for proved reserves. Reserves are not proved reserves under SEC definitions and guidelines.

 

1

RECENT DRILLING ACTIVITY

Since the end of 2005, we have drilled 10 wells in East Texas with a 100% success rate. We recently acquired a 3-D seismic survey, developed and planned jointly with Chesapeake Energy Corporation (“Chesapeake”), that covers 100% of our East Texas acreage, which provides additional information critical to refine our geologic and geophysical models for the deep Bossier and Knowles Limestone formations. We seek to capitalize on this data to improve the likelihood of repeating the recent successes we have had in our most recent deep Bossier and Knowles Limestone wells. Our last deep Bossier and Knowles Limestone wells drilled in the Hilltop area have estimated ultimate recoveries (“EURs”) of approximately 10.9 gross Bcfe (5.5 net Bcfe) and 1.8 gross Bcfe (0.7 net Bcfe) and cost $12.6 million gross and $6.8 million gross to drill and complete, respectively. We have identified 6 gross (4 net) additional deep Bossier locations directly offsetting the Donelson #3 well that represent approximately a two year drilling inventory. Further upside potential exists on our East Texas acreage through the exploitation of reserve potential in the Knowles Limestone formation. We believe we are the first company to establish commercial production in the Knowles Limestone formation in East Texas. We have drilled three wells with a 100% success rate in this formation and are in the process of drilling a fourth well. Wells drilled in the Knowles Limestone are characterized by lower drilling costs than the deep Bossier wells and a shorter drilling and completion cycle, with individual wells taking approximately 80 days from spud to sales.

 

2

INDEPENDENT ENGINEERING ESTIMATES

The estimates of our proved reserves and their present value are from the reserve report of Netherland Sewell as of June 30, 2007 using SEC pricing as of June 30, 2007.

 

     Reserve Category
     PDP    PDNP    PUD    Total

Net reserves:

            

Natural gas (MMcf)

      14,916      9,625      11,795      36,336

Oil (MBbls)

      15      —      —      15

Future net revenues (000’s):

            

Natural gas

    $ 86,085    $ 54,668    $ 66,903    $ 207,656

Oil

      1,017      —      —      1,017
                           

Total revenues

    $ 87,102    $ 54,668    $ 66,903    $ 208,673

Production and ad valorem taxes

      4,210      2,616      3,239      10,065

Operating expense

      30,390      8,198      15,576      54,164

Capital costs

      2,358      4,971      30,995      38,324
                           

Future net revenues

    $ 50,144    $ 38,883    $ 17,093    $ 106,120
                           

Future net revenues discounted at 10% (“PV-10”)

    $ 40,585    $ 28,805    $ 7,557    $ 76,947
                           

 

3

SUMMARY RESERVE AND PRODUCTION DATA

The following table summarizes our estimates of our domestic net proved natural gas and oil reserves and the present value attributable to the reserves as of June 30, 2007 (using SEC prices as of June 30, 2007 and NYMEX prices as of October 24, 2007), discounted at 10% per annum. Estimates of our net proved natural gas and oil reserves at June 30, 2007 were prepared by Netherland, Sewell & Associates, Inc., our independent petroleum engineers.

 

     As of
June 30, 2007		  

Proved Reserves:

   

Natural gas (MMcf)

      36,336  

Oil and condensate (MBbls)

      15  

Natural gas equivalent (MMcfe)

      36,425  

Proved developed reserves

     67.6 %

PV-10(1) (SEC Case)(000’s)

    $ 76,947  

PV-10(2) (Natural Gas Forward Pricing Case)(000’s)

    $ 110,081  

Reserve life index (in years)(3)

      7.1  

(1)

Present value discounted at 10% of future net revenues of proved reserves at June 30, 2007 using constant pricing and costs in accordance with SEC guidelines.

 

(2)

Present value discounted at 10% of future net revenues of proved reserves at June 30, 2007 using constant pricing based upon the October 24, 2007 average calendar year 2008 NYMEX forward natural gas sale pricing of $8.00 per MMBtu and constant oil pricing and costs as of June 30, 2007. See “Natural Gas Pricing Sensitivities” on page 17 for a further description of pricing assumptions.

 

(3)

Calculated by dividing net proved reserves by net production volumes for the 12-month period ended June 30, 2007.

The following table summarizes our net production volumes, natural gas and oil sales, and average sales prices for the periods indicated:

 

     Year ended December 31,    Nine months ended
September 30,
     2004    2005    2006        2006            2007    

Net production volumes:

               

Natural gas (MMcf)

      1,108      3,810      4,646      3,411      4,696

Oil (MBbls)

      2      2      12      8      7
                                  

Combined (MMcfe)

      1,119      3,821      4,716      3,457      4,736

Natural gas and oil sales (000’s):

               

Natural gas

    $ 5,987    $ 27,345    $ 26,014    $ 19,457    $ 24,842

Oil

      72      97      751      531      404
                                  

Total

    $ 6,059    $ 27,442    $ 26,765    $ 19,988    $ 25,246
                                  

Average sales prices:

               

Natural gas (per Mcf)

    $ 5.40    $ 7.18    $ 5.60    $ 5.70    $ 5.29

Oil and condensate (per Bbl)

      40.08      50.85      64.66      68.19      61.01

Lease operating, transportation and selling expenses taxes (per Mcfe)

      1.78      1.81      1.82      1.92      1.43

PV-10 of proved reserves (SEC case) is not a substitute for the standardized measure of discounted future net cash flows, which is calculated at year end under accounting rules. Our PV-10 measures and the standardized measure of discounted future net cash flows do not purport to present the fair value of our natural gas and oil reserves.

 

4

NATURAL GAS PRICING SENSITIVITIES

The following are estimates of our future net revenues for the year ending December 31, 2008 and PV-10 of all future net revenues based on our proved reserves as of June 30, 2007 shown under SEC mandated constant pricing and at various alternate natural gas pricing scenarios. Estimates of production, costs and expenses are derived from our reserve report dated June 30, 2007 prepared by Netherland Sewell (the “June 30 Report”). The June 30 Report was prepared using constant oil and gas pricing and costs in effect on June 30, 2007, in accordance with the guidelines of the Securities and Exchange Commission.

In order to demonstrate the effects of natural gas pricing changes on our estimates of future net revenues from proved reserves and PV-10 values of such future net revenues, we have prepared estimates of future net revenues and PV-10 using assumed natural gas prices that are 20 and 10 percent higher and 20 and 10 percent lower than the June 30, 2007 spot market gas prices utilized in the June 30 Report. Gas prices used in the June 30 Report were based on Henry Hub spot market price of $6.795 per MMbtu for Texas and Kansas production; Colorado Interstate Gas (“CIG”) Rocky Mountains spot market price of $3.98 per MMBtu for Montana and Wyoming production; and Columbia Gas Appalachia spot market price of $7.28 per MMbtu for West Virginia production. Appropriate adjustments were made to these prices for quality, transportation and other infield price adjustments. In each case, oil prices were held constant based on the June 30, 2007 West Texas Intermediate posted price of $67.25 per barrel.

Future production will vary from the estimates in the June 30 Report when different pricing assumptions are made due to changes in economic limits of production, which primarily affects our Montana and Wyoming reserves. Actual production from properties with proved reserves may vary significantly from those estimated in the June 30 Report or in the other pricing cases reflected in this analysis, which will affect actual net revenues received in the indicated year.

 

5

PV-10 Gas Pricing Sensitivities

 

     As of June 30, 2007
    

June 30
Gas Prices

Minus 20%

    June 30
Gas Prices
Minus 10%		   

June 30
Report

SEC
Constant
Pricing

   

June 30
Gas
Prices

Plus 10%

   

June 30
Gas Prices

Plus 20%

Average natural gas price ($/Mcf)

    $ 4.48    $ 5.11    $ 5.71    $ 6.23    $ 6.79

Average oil and condensate prices ($/Bbl)

    $ 68.29    $ 68.30    $ 68.30    $ 68.29    $ 68.30

PV-10 of future net revenues from proved reserves (000s)

    $ 47,985    $ 61,902    $ 76,947    $ 92,579    $ 108,601

Future Net Revenue Pricing Sensitivities

    

Year Ending

December 31, 2008

    

June 30
Gas Prices

Minus 20%

    June 30
Gas Prices
Minus 10%		   

June 30
Report

SEC
Constant
Pricing

   

June 30
Gas
Prices

Plus 10%

   

June 30
Gas Prices

Plus 20%

     (dollars in thousands, except per unit amounts)

Net oil and condensate production (MBbls)

      4.0      4.1      4.2      4.2      4.3

Net natural gas production (MMcf)

      5,912      8,423      8,789      9,078      9,173

Average natural gas price ($/Mcf)(1)

    $ 4.34    $ 5.04    $ 5.63    $ 6.17    $ 6.74

Average oil and condensate prices ($/Bbl)(2)

     68.20      68.20      68.21      68.22      68.21

Future gross revenue natural gas

    $ 25,691    $ 42,473    $ 49,492    $ 55,975    $ 61,809

Future gross revenue oil and condensate

      274      280      285      288      291
                                  

Future gross revenue total

      25,965      42,753      49,777      56,263      62,100

Production and ad valorem taxes

      1,286      1,942      2,273      2,657      2,960

Operating expenses

      7,066      8,805      9,212      9,695      9,900

Capital costs(3)

      2,063      16,016      23,039      23,550      23,954
                                  

Future net revenues from proved reserves

    $ 15,550    $ 15,990    $ 15,253    $ 20,361    $ 25,286
                                  

(1)

Weighted average of gas price for estimated production after adjustments for delivery point differentials, energy content, quality, transportation and other infield price adjustments.

 

(2)

West Texas Intermediate oil prices posted price as of June 30, 2007.

 

(3)

Substantially all capital costs are incurred in the drilling of proved undeveloped reserves.

 

6

Forward Pricing Sensitivities

At October 24, 2007, the average of NYMEX forward sale natural gas price for Henry Hub deliveries for the twelve months in the calendar year 2008 was $8.00 per MMBtu, and the average of the monthly basis differentials for CIG Rocky Mountains forward deliveries in 2008 from NYMEX was $1.50 per MMBtu, as quoted to us by derivatives traders at a major investment bank. After applying these natural gas pricing and Rocky Mountains differential assumptions on a constant basis, holding oil prices and costs constant at the prices and costs reflected in the June 30 Report and further adjusting the differential for natural gas prices received for our estimated Rocky Mountains (Wyoming and Montana) production in the second half of 2007 to reflect monthly actual and forward delivery discounts for CIG Rocky Mountains, our estimated proved reserves, future net revenues from our proved reserves and related PV-10 – Natural Gas Forward Pricing Case as of June 30, 2007 would have been as set forth in the table as below.

 

     Reserve Category
     PDP    PDNP    PUD    Total

Net proved reserves:

            

Natural gas (MMcf)

      15,908      9,662      17,851      43,421

Oil (MBbls)

      16      —        —        16

Future net revenues (000’s):

            

Natural gas

    $ 107,787    $ 67,565    $ 120,347    $ 295,699

Oil

      1,085      —        —        1,085
                           

Total revenues

    $ 108,872    $ 67,565    $ 120,347    $ 296,784

Production and ad valorem taxes

      5,783      3,485      9,025      18,293

Operating expense

      35,705      9,082      30,075      74,862

Capital costs

      2,378      4,971      41,679      49,029
                           

Future net revenues

    $ 65,006    $ 50,027    $ 39,568    $ 154,600
                           

PV-10—Natural Gas Forward Pricing Case

    $ 51,441    $ 37,014    $ 21,626    $ 110,081
                           

 

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