on 32 of the gross wells drilled. At year end 2006, 31 of the gross wells were producing and the remaining 15 wells were awaiting completion and/or pipeline connection.

We are continuing to expand our leasehold acquisition in this trend. Production at the end of 2006 and at March 20, 2007 was approximately 19 MMcfe/d and 21 MMcfe/d, respectively. Net proved reserves have grown by 79% from 82.1 Bcfe on December 31, 2005 to 146.6 Bcfe on December 31, 2006. We are drilling in this trend with four Carrizo operated rigs as of March 20, 2007.

East Texas Area

The East Texas area encompasses multiple objectives, including the Wilcox and Cotton Valley intervals. We are focused on the Camp Hill Field, a Wilcox steam flood project in Anderson County, and the Tortuga Grande Prospect, a Cotton Valley sand opportunity. We have licenses for over 511 square miles of 3-D seismic data in the East Texas area and 4,817 net acres under lease.

We expect to invest $4.6 million to drill 27 gross wells in this region in 2007.

Camp Hill Project. We own interests in approximately 750 gross acres in the Camp Hill Field in Anderson County, Texas. We currently operate all of these leases. During the year ended December 31, 2006, the project produced an average of 40.9 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, 2006 averaged $68.99 per barrel ($11.50 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, 2006) due to its suitability as a lube oil feedstock.

As of December 31, 2006, we had 6.2 MMBbls of proved oil reserves in this project, with 0.8 MMBbls of oil reserves currently developed. The proved undeveloped reserves at the Camp Hill Field constitute 16% of our proved reserves and account for 23% of our present value of net future revenues from proved reserves as of December 31, 2006. 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 have 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 49.8% recovery efficiency as of December 31, 2006 and is currently still producing.

Although in 2006 and 2005 we increased our development activities in the Camp Hill Field, 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 prices and to pursue a lower steam cost solution through our cogeneration negotiations. Thereafter, we drilled one well in 2001, seven wells in 2005 and ten wells (including six injection wells) in 2006.

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 to the 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 $91.0 million in steam costs compared to $18.8 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