The Rocky Mountain Region comprises approximately 95% of our estimated proved reserves as of December 31, 2008. The majority of our undeveloped acreage and drilling inventory is located in this region, where our drilling efforts and capital expenditures have been focused.

In the Rocky Mountains, although we have significant acreage in four basins, we have dedicated the majority of our development efforts to our position in the Piceance Basin.

Piceance Basin.
Since 2005 we have dedicated significant financial capital and human resources to the development of our Vega Unit and surrounding leasehold in Mesa County, Colorado, which in combination is referred to as the Vega Area. In 2008 we acquired an additional 17,300 net acres, which increased our position to approximately 22,150 net acres, which has over 2,000 net drilling locations on 10-acre spacing. We also have a non-operated working interest in the Garden Gulch Field in Garfield County, Colorado. These fields are consistent with our strategy of targeting reservoirs that demonstrate predictable geology over large areas. The Williams Fork member of the Mesaverde formation is the primary producing interval and has been successfully developed throughout the Piceance Basin.

Vega Area.
The Vega Area includes the Vega Unit, the North Vega leasehold, the Buzzard Creek Unit, and North Buzzard Creek leasehold. Our working interest in the Vega Area varies between 95-100%. During fiscal 2008 we increased proved reserves in the Vega Area over 295% to 719.9 Bcfe. During 2008 production increased from approximately 25 Mmcf/d at the beginning of the year to approximately 48 Mmcf/d at the end of 2008. The Collbran Valley natural gas pipeline provides us with approximately 60 Mmcf/d of pipeline takeaway capacity. A new pipeline is currently under construction that will provide us with takeaway capacity up to 60 Mmcf/d. We ended 2008 with 155 wells producing. Despite our large inventory of over 2,000 drilling locations and efficient reserve growth, we have decreased our drilling program from four rigs to one rig at year end 2008, primarily due to the decrease of natural gas prices and liquidity concerns. Since 2005 we have experienced significant reductions in drill time, and drilling and completion costs, which have allowed us to grow reserves even in a depressed commodity price environment. We expect to continue completion activities in 2009 on wells awaiting completion, and to resume its more aggressive drilling program once commodity prices recover. Our drilling and completion capital budget is $35 – $45 million for the year ending December 31, 2009.

Garden Gulch.
We have an interest in approximately 6,000 gross (2,000 net) acres with a 31.1% non-operated working interest. The operator of the project has temporarily ceased drilling activity, but expects to complete an inventory of approximately 20 wells that were drilled, but not completed in 2008. Our capital budget for the year ending December 31, 2009 is approximately $4 - $6 million.


Paradox Basin.
In the Paradox Basin we have five prospect areas: Greentown, Salt Valley, Fisher Valley, Gypsum Valley and Cocklebur Draw. Over the past three years we focused primarily on the Greentown prospect, in Grand County, Utah. The targeted objectives in these prospects are reliant upon various geologic models, which include multiple stacked clastic intervals imbedded within an evaporate salt in the Paradox formation, and unconventional shales.

Greentown.
We have drilled a total of eight wells in the Greentown project area. The first two wells flow tested at rates between 2.0 Mmcf/d with 40 Bo/d and 4.0 Mmcf/d with 800 Bo/d, primarily from the 21st clastic interval, or “O” zone. These first two exploration wells were located approximately along the axis of the anticline, about seven miles apart. Even though these wells are widely spaced, they exhibited very consistent electric log characteristics and appear analogous and mapable over a large area. Although these first two exploration wells were lost due to casing failure, the flow rates and log characteristics drove our initial assessment was that the geology was consistent and predictable over much of our leasehold. We revised our casing design in the subsequent wells, and continued to experience multiple hydrocarbon-bearing zones while drilling. Each of the subsequent wells tested gas and oil, two of which tested at significant rates of up to 10 Mmcf/d. Most of the gas and oil tested in these wells came from the “O” interval, but some also produced from the 23rd clastic interval, also known as the Cane Creek. Despite the indications of economically productive reserves during drilling and initial completion activity, the wells failed to produce at the flow-tested rates after casing and completion activities. We assessed that the limited productivity was primarily due to a lack of naturally occurring fractures in the clastics. In order to encounter more naturally occurring fractures we drilled multiple laterals in three of the wells, within the “O” and Cane Creek intervals. In one of the first laterals in the Greentown Federal 26-43D well, in the “O” interval, we encountered significant hydrocarbon accumulation with high pressures. While trying to complete the lateral we encountered significant mechanical problems that made the potentially productive section inaccessible. The other laterals encountered limited hydrocarbon accumulations. Based upon the results from the laterals and limited production on the western portion of the acreage, we have determined that despite good correlation of the clastic intervals along the crest of the Greentown anticline, there exists discontinuity in the clastic intervals, which may limit the hydrocarbon drainage area on the western portion.
We have a 70% working interest in 43,700 gross acres, 30,400 net acres. We believe the eastern portion of its acreage, where the wells with letter drilling shows were located, remains prospective. We have not budgeted any significant activity in Greentown for the year ending December 31, 2009.

Salt Valley.
The Salt Valley project area has had one exploratory well drilled. Additional drilling plans are not expected in 2009. We have a 70% working interest in 7,100 gross acres, 4,900 net acres.

Fisher Valley, Gypsum Valley and Cocklebur Draw.
We have three remaining prospects in the Paradox Basin located in San Miguel and Dolores Counties, Colorado and Grand County, Utah. We have a 70% working interest in 46,500 gross acres, 32,800 net acres, all of which were undeveloped at December 31, 2008.

Wind River Basin.
The Wind River Basin is characterized by a depositional environment that resulted in thick packages of tight gas sands producing at depths that range from 7,000 to 20,000 feet. We have focused our efforts on the shallower Lower Fort Union Formation which produces in numerous fields throughout the Wind River Basin.

Howard Ranch.
During 2008 we performed a reevaluation of our acreage position in the Howard Ranch project area. We have determined that much of our leasehold is likely prospective in the Waltman shale formation, which is an unconventional play. At year end we owned an interest in 47,100 net acres with an average working interest of 50%. We have not budgeted any capital in the Wind River Basin for 2009.

Denver-Julesburg (“D-J”) Basin.
Our leasehold in the Denver Julesburg Basin focuses on the “J” sand formation at depths of between 7,000 feet and 8,000 feet. In 2007 we drilled an exploratory well, the Cowboy 35-21 well, which was a discovery that began production at a rate of 200 Bo/d. Subsequent development of the Cowboy field included ten additional wells which allowed production to peak at approximately 1,100 barrels of oil per day. We have identified numerous seismically defined structures, similar in size to the Cowboy field. We have an interest in 21,800 net acres with a 100% working interest. There is no drilling capital budgeted for the D-J Basin for 2009.

Central Utah Hingeline.
The central Utah Hingeline Region is an overthrust belt located in central Utah. We have an average 65% working interest in approximately 130,000 net acres. We have drilled three wells, the Joseph #1, the Federal 23-44, and the Beaver Federal 21-14. The Federal 23-44 provided us with positive indications of hydrocarbon-bearing zones, and critical geologic information, however all three wells were plugged and abandoned as dry holes.

We and our partners control approximately 200,000 gross acres (130,000 net acres) within this play and numerous structural features have been identified on our leasehold. We have a 110-mile seismic program covering previously generated prospects, which in our interpretation appear to confirm and enhance original expectations. We have not budgeted any drilling capital for this area in 2009. The Central Utah Hingeline project is an exploratory area for us and does not account for any of our proved reserves at December 31, 2008.

Columbia River Basin.
The Columbia River Basin is located in southeast Washington and northeast Oregon. The basin is characterized by over-pressured, gas sandstone formations. We are currently drilling the Gray 31-23 well in Klickitat County, Washington. Completion activities are expected to begin after reaching total depth. Drilling results have been encouraging and we have begun permitting a well near the Gray well. We have an interest in approximately 424,000 net acres in the basin, all of which are undeveloped. The Columbia River Basin is an exploration project area and does not account for any of our proved reserves as of December 31, 2008. Our budget for the Columbia River Basin is $7 – $10 million in 2009.