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of December 31, 2005, we had 7.1 MMBbls of proved oil reserves in this project,
with 740 MBbls of oil reserves currently developed. The proved undeveloped reserves
at the Camp Hill Field constitute 25.3% of our proved reserves and account for
26.0% of our present value of net future revenues from proved reserves as of December
31, 2005. 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 48.7% recovery
efficiency as of December 31, 2005 and is currently producing at a rate of approximately
0.8% of original oil in place per year, even without steam injection. Our estimated
proved reserves for the Camp Hill Field as of year-end 2005 were adversely impacted
by this revision in the recovery efficiency estimate; resulting in a reduction
of 991,515 net Bbls of oil as of December 31, 2005. We made other negative revisions
to our December 31, 2005 Camp Hill reserves totaling 483,418 net Bbls of oil as
a result of new well data and additional analysis. Although
in 2005 we accelerated 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
and seven wells in 2005. 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 $139 million in steam costs compared to $22
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 in discussions
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
in the Barnett Shale, starting in 2003, that we believed offered us potentially
higher rates of return. These other projects have been 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 leases in 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 2005, 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 greater immediacy. We did, however,
drill seven gross wells (7.0 net) on four leases in the Camp Hill field in 2005,
all of which are apparent successes and currently producing. 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 that there
continues to be overcapacity of electricity in the regional market and that overcapacity
is not likely to reverse itself in the near term and that | |
