The most important reason for our delay in both resuming steam injection and moving to full development was the potential for significantly improved profitability that would result from the construction of a nearby cogeneration plant. Cogeneration plants typically provided steam at less than half the cost of small steam generators. Steam costs are critical tothe economics of the development of the field. Expected steam costs far outweigh the capital costs for the development of the Camp Hill Field. We currently estimate approximately $129.3 million in steam costs compared to $21.4 million for drilling and development capital that is needed to fully develop the proved undeveloped reserves in this field. Previously, our management believed that the demand for electricity in the East Texas area would increase in the future such that it would become lucrative for us or a third party to build a cogeneration plant in the area. In this cogeneration plant, a gas turbine would be used to generate electricity, and the waste heat would be used to produce steam. The steam would be captured for injection in the Camp Hill Field, while the electricity would be sold into the Texas electric power grid. In 2000, we engaged indiscussions with another party regarding the building of a cogeneration facility, but we ultimately did not reach acceptable terms with that party. We subsequently continued to explore the possibility of a cogeneration facility in the Camp Hill Field and worked with electricity industry consultants in 2002 and 2005.

During the time we were continuing to assess the relative attractiveness of building a cogeneration plant, and in light of relatively high fuel gas costs at that time, we pursued other exploration projects primarily along the onshore Gulf Coast and inthe Barnett Shale, starting in 2003, that we believed offered us potentially higher rates of return. These other projects havebeen the primary focus of our operations over the last several years. Our timing of Camp Hill development has also been impacted by our leasing activities in the field by which we increased our working interest and net revenue interest in our leasesin the field so that we would own a greater share of these properties when we later developed them. We believe that we were able to increase our interests on more favorable terms by deferring the full scale development of the field. The addition of working interests in the Camp Hill leases further improved the economics of the development of this field as well as favorably affect the development plan for the steam drive patterns in the field.

In mid-2005, we reengaged an electricity industry consultant with cogeneration experience to further investigate the feasibility of establishing a cogeneration plant in the area. After extensive discussions with the consultant, we concluded thatthere continued to be overcapacity of electricity in the regional market and that overcapacity was not likely to reverse itself in the near term and that the capital expenditures associated with building a cogeneration plant were not likely to be warranted for a period of several years. As a result, we determined that, rather than awaiting the construction of a cogeneration plant, we would instead further develop our Camp Hill properties with the existing steam generators.

In August 2005, management proposed the acceleration of the Camp Hill development to our board of directors. Accordingly, a development plan was formally approved by the board for increased drilling activity in the Camp Hill Field, beginning with an initial 60-well drilling program. In February 2006, our board of directors formally approved a multi-year plan to fully develop the entire Camp Hill Field. In furtherance of this plan, we expect to drill 40 gross wells (40.0 net), including 17 service wells, in this area at an estimated cost of $5.6 million during 2008. To fully develop the field, we expectto drill approximately 296 gross wells (including 135 injection wells) from 2008 through 2024, at a total cost of approximately$21.4 million and total operating costs including steam of approximately $148.8 million. The precise timing and amount of our expenditures on additional well drilling and increased steam injection to develop the proved undeveloped reserves in this project will depend on several factors including the relative prices of oil and natural gas.

In 2007, we continued to invest the majority of our budgeted capital expenditures in our Barnett Shale and onshore Gulf Coast areas where the rates of return are traditionally higher and our leases expire sooner, which gives these projects greaterimmediacy. We did, however, drill 17 gross wells (17 net) and 13 gross injection wells in the Camp Hill Field in 2007.

During 2007, we experienced delays in our development plan of the Camp Hill Field. Our 2007 drilling program in the Camp Hill Field was delayed primarily due to the unavailability of the rig we use to drill in the field. However, during the fourth quarter of 2007, we received a firm commitment from our drilling contractor to drill exclusively for us through February2008 with options to extend the contract for four additional three-month periods, providing us the expected rig availability needed to execute our 2008 drilling plan. The steam generators we expected to use were not available due to delays in repairs and permitting issues. We injected steam in the Camp Hill Field through one of our generators until it encountered operationaldamage in January 2007. We expect to receive a replacement generator in March 2008 and expect this generator to commence steam injection in April 2008. Our other two generators have not been available for injection due to unexpected permitting issues and the need for repair work. We currently expect that these two generators will be ready to inject steam by the end ofJuly 2008 with respect to one generator and by the end of October 2008, with respect to the other. In addition, we plan to obtain a small portable generator by October 2008. We received the permits for these two generators to recommence injection in the fourth quarter of 2007. Although these permits will only allow us to inject steam at 80% of the rate that we had anticipated, based upon the rate under the prior permits for these same generators, we expect to continue to appeal to the regulatory authorities to reinstate the 100 % rate of generation allowed under the original permits. The impact of a lower generation rate assumption (incorporated into our December 31, 2007 proved reserves), does not reduce our proved reserves,