We currently operate four rigs that are drilling horizontal wells in the Barnett Shale and we have contracted for a fifth rig inthis area that will commence drilling beginning in April 2008. One of these rigs is dedicated to drilling our lease on The University of Texas at Arlington and adjacent areas. The drilling of the first well on The University of Texas at Arlington campus is complete, and a second well was spud on January 2, 2008. Once six wells have been drilled, all six will be fracture stimulated and, if successful, begin sales before additional drilling begins.

Gulf Coast Area

Our Gulf Coast area generally contains geologically complex as well as amplitude and amplitude versus offset supported natural gas objectives well-suited for drilling using 3-D seismic evaluation.

In our Gulf Coast area, we have a total inventory of 69 leased exploratory drillsites, 26 of which are field extension wells based on initial drilling success. We are pursuing acreage on an additional 67 seismically defined prospects. We plan to spendapproximately $22.7 million on drilling expenditures in 2008, comprised of approximately 15 gross wells (5.8 net). We also plan to spend $1.9 million to purchase and reprocess 3-D seismic surveys during 2008.

We have licenses for approximately 8,396 square miles of 3-D seismic data and 50,312 net acres of leasehold in the Gulf Coast area. From January 1, 2003 through December 31, 2007, we drilled and completed 96 wells (28.1 net) on 113 attempts in this area. In 2007, we incurred capital drilling expenditures of $22.8 million and drilled 8 gross (2.3 net) wells, four ofwhich were in Southeast Texas and included the Doberman #1 well.

Camp Hill Field

We own interests in approximately 2,611 gross acres in the Camp Hill Field in Anderson County, Texas. We currently operate all of these leases. During the year ended December 31, 2007, the project produced an average of 26 Bbls/d of 19 API gravity oil. The wells produce from a depth of 500 feet and have utilized and plan to utilize a tertiary steam drive as an enhanced oil recovery process. Although efficient at maximizing oil recovery, the steam drive process is relatively expensive to operate because natural gas or produced crude is burned to create the steam injectant. Lifting costs during the year ended December 31, 2007 averaged $96.70 per barrel ($16.12 per Mcfe). Costs were high, as expected, because oil production response typically lags the startup of steam injection. The oil produced, although viscous, commands a comparable price to West Texas Intermediate crude (an average premium of $0.15 per Bbl to Koch WTI during the year ended December 31, 2007) due to its suitability as a lube oil feedstock.

As of December 31, 2007, we had 8.0 MMBbls of proved oil reserves in this project, with 1.6 MMBbls of oil reserves currently developed. The proved undeveloped reserves at the Camp Hill Field constitute 11% of our proved reserves and account for 17% of our present value of net future revenues from proved reserves as of December 31, 2007. We have an average working interest of approximately 92.1% in this field and an approximate net revenue interest of 71.0%.

Prior to 2003, we estimated an ultimate recovery efficiency (i.e. the percentage of the oil in the ground that we would be able to produce economically) after steam drive of 45% of the original oil in place in the Camp Hill Field. As of January 1, 2003, we raised our estimate to an ultimate recovery of 55% of the estimated original oil in place based upon our review of recovery efficiencies from prior projects by other companies in both the Camp Hill Field as well as in nearby projects that we considered to have similar geologic and hydrocarbon attributes. We lowered our estimated recovery efficiency as of December 31, 2005 to 49% of the estimated original oil in place in the field. We believe this revised recovery efficiency is reasonable, particularly in light of the fact that a project that we have operated in the Camp Hill Field since 1993 has a current 49% recovery efficiency as of December 31, 2007 and is currently still producing.

Although we have increased our development activities in the Camp Hill Field since 2005, this follows an extended period during which we deferred development in the field. We deferred development (1) to optimize returns by awaiting an economic entry point for developing a cogeneration plant as further explained below, (2) to pursue other opportunities in both our onshore Gulf Coast and later, Barnett Shale areas with higher rates of return and (3) to continue increasing our net acreage position in the field in a competitive environment. Although we at all times believed that we could develop this field on a profitable basis, we nonetheless believed that we were optimizing our economic position by deferring development. We acquired our initial interests in the Camp Hill Field in 1993. We performed remedial work on the existing wells and steam generators and began injecting steam in March 1994. From 1994 through 1998 and during the first nine months of 2000, we injected steam in 31 patterns. In the fourth quarter of 2000, we suspended steam injection in response to high fuel gas pricesand to pursue a lower steam cost solution through our cogeneration negotiations. Thereafter, we drilled one well in 2001, seven wells in 2005, ten wells (including six injection wells) in 2006 and 30 wells (including 13 injection wells) in 2007.