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Bill Barrett (NYSE:BBG)

Q4 2005 Earnings Conference Call

March 2, 2006, 4:30 PM

Executives:

Robert W. Howard, Executive Vice President

William J. Barrett, Chairman & Chief Executive Officer

Thomas B. Tyree, Jr., Chief Financial Officer

Fredrick J. Barrett, Chief Operating Officer

Dominic J. Bazile II, Senior Vice President – Operations and Engineering

Terry R. Barrett, Senior Vice President – Exploration, Northern Division

Kurt M. Reinecke, Senior Vice President – Exploration, Southern Division

Lynn Boone Henry, Vice President – Reservoir Engineering

Analysts:

Brian Singer, Goldman Sachs & Co.

David R. Tameron, Jefferies & Co.

Larry C. Busnardo, Petrie Parkman & Co.

Raymond Deacon, Harris Nesbitt

Operator

Good afternoon. My name is Lisa and I will be your conference Operator today. At this time, I would like to welcome everyone to the Bill Barrett Corporation fourth quarter 2005 conference call. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks, there will be a questions and answers session. If you would like to ask a question during this time, simply press *1 on your telephone keypad. If you would like to withdraw your question, press *2 on your telephone keypad. Thank you. Mr. Howard, you may begin your conference.

Robert W. Howard, Executive Vice President

Thank you, Lisa. Good afternoon, and welcome to Bill Barrett Corporation’s conference call to review fourth quarter and full year 2005 financial results and to update our operating activity. I’m Bob Howard. With me today are Bill Barrett, Chairman, Chief Executive Officer and President and Tom Tyree our Chief Financial Officer.

Also with us are Dominic Bazile, Senior Vice President of Operations and Engineering, Terry Barrett and Kurt Reinecke, Senior Vice Presidents of Exploration for the Northern and Southern Divisions, and Lynn Boone Henry, Vice President of Reservoir Engineering. Tom will review our financial results for the fourth quarter and the full year.

Financial results were announced in a press release after the market closed today, and may be found on our website and through financial news sources. Form 10-K for 2005 is also being filed with the SEC this afternoon. Following the financial discussion, Fred will provide an operational update and outlook for 2006. We expect these discussions to last approximately 35 minutes. As Lisa said, we’ll follow with a question and answer session.

Before we start, please note that statements made in our presentation, other than historical facts, are forward looking statements. While the company believes these statements to be reasonable, they are subject to factors such as commodity prices, competition, technology and environmental and regulatory compliance, our building schedules and costs, capital plans and other factors that may cause our results to differ materially. Additional cautionary statements concerning these forward looking statements are contained in our filings with the SEC.

Also please note that during our discussion we make reference to discretionary cash flow, which is a non-GAAP measure. The reconciliation of the appropriate GAAP measure was provided in the earnings press release.

Before we turn the call over to Tom to review our financial results, I’d like to remind you that on Tuesday we announced that Fred Barrett has been named as our Chairman and Chief Executive Officer. Fred succeeds Bill, who’ll be retiring from the company and the Board of Directors after our annual meeting in May. Over the last six months, the Nominating and Corporate Governance Committee of our Board of Directors has engaged an executive search firm to help seek out candidates for the CEO position. Following a comprehensive and exhaustive search and evaluation, the Board determined that Fred, the father of the company, should continue the success he has created by being named Chairman and Chief Executive Officer.

We’re all very excited to continue to work with Fred in his expanded role. Of course, we greatly appreciate Bill’s leadership and guidance as our team of employees built the premier Rocky Mountain exploration company, and we wish Bill and Louise all the best in retirement. I will now turn the conference call over to Tom to discuss our company’s financial statements.

Thomas B. Tyree, Jr., Chief Financial Officer

Thanks very much, Bob, and good afternoon everyone.

We are very pleased to report that the fourth quarter was another record for Bill Barrett Corporation in terms of our production, our net income and cash flow. We produced 12.3 Bcfe in the quarter, with an average realized price of $8.89 per Mcfe.

We had net income of $23.3 million and EPS of $0.53 and we generated discretionary cash flow of $81.3 million. On a full year basis we produced 39.4 Bcfe in 2005, a 24% increase over the prior year. This production growth was achieved organically through our active exploration and development program. Our average realized price for the year was $7.21 net of the effects of hedging, a 38% increase from 2004.

We generated over $195 million in discretionary cash flow for the year, a 91% increase year over year, and on a fully (inaudible) basis, our 2005 cash flow was $4.50 per share. Our net income for 2005 was $23.8 million, a record for Bill Barrett Corporation, reflecting our strong growth in production and high realized prices. Our earnings did include impairments totaling $42.7 million, to reduce the carrying value of certain Wind River properties to their fair market value.

The largest impairment related to our Cooper Reservoir area and was recorded in the second quarter, as infill drilling did not result in sufficient economic reserves. We also recorded smaller impairments in our Talon and East Madden projects. The company recorded dry hole expense for two wells in the fourth quarter, one in the Williston Grand River area and the other in the Wind River Basin. Our cash operating costs for the quarter were $2.25 per Mcfe, the same as the third quarter of 2005. Excluding production taxes, our cash operating costs were $1.28 per Mcfe, a $0.13 improvement from the third quarter, as production increases offset higher gathering costs.

For the full year 2005, our cash operating costs were $2.27 per Mcfe, including production taxes of $0.85 per M. Excluding these production taxes, our cash operating costs increased by $0.20 per M from 2004, primarily due to higher costs in the Powder River Basin. The LOE there was higher due to equipment rentals and higher diesel costs for temporary power supplies while the gathering and transportation costs in the Powder were higher due to new firm transportation, cost of fuel use in compressors and costs to treat the increasing Carbon Dioxide levels.

Gas G&A costs were higher than last year by $0.05 per Mcfe due to Sarbanes Oxley costs, expenses relating towards successful secondary offering back in August and increased hiring to keep up with our growth. Our nNet capital expenditures were $334 million in 2005. We spent $28 million for land, $11 million for G&G and other exploration costs, $306 million for drilling and completing our exploration and development wells, that included related facilities, and nearly $3 million for equipment and other corporate expenditures.

We received nearly $14 million in proceeds from industry partners related to our joint exploration program, which is reflected in our net capex for the year. We ended 2005 with a very strong balance sheet. We had $86 million in debt outstanding under our credit facility, or $17.7 million net of cash on hand. In the next few weeks, we expect to finalize an amendment to our credit agreement, increasing the facility to $400 million with an initial borrowing base of $280 million with a five-year maturity, all with very competitive pricing.

Given that we have approximately 50% of our gas production hedged with a weighted average floor of $5.93, at Rockies pricing, and combined with our increased credit facility, we are in an excellent position to execute our capex program and maintain a comfortable level of debt. For 2006 our capital budget is set at $350 million. To further elaborate on the budget, as well as on our operations and future drilling plans, let me turn it over to our new Chairman, Chief Executive Officer, Fred Barrett.

Fredrick J. Barrett, Chief Operating Officer

All right, well thank you, Tom, and thanks all of you for joining us today.

As Tom reviewed with you, 2005 was a great year for us. When we completed the initial public offering at the end of 2004, we had lots of goals of what we wanted to accomplish in 2005. Those activities included continued drilling and our development projects, evaluating a substantial diversified exploration program via the drill bit, and continuing to assemble and evaluate new prospects for future activity and growth.

We completed virtually all of the activities that we had planned for the year, by spreading 323 wells, including two exploratory discoveries, increasing our year-end reserves by 17% to 341 Bcfes and increasing our undeveloped acreage position by 290,000 acres to over 1.2 million acres of net undeveloped leases and a number of distinct exploration projects.

We are proud to announce production growth for the year was 24% greater than 2004. We continue to produce approximately 139 million cubic feet of gas per day, comparable to December 2005. As we enter 2006, we’re enthused about our momentum and the activities planned for the year, including our most robust exploration program to date, with up to 38 exploration wells scheduled by the end of the year. We in essence plan to double our exposure to high impact company-maker type plays in 18 different project areas. More on this in a later section.

Our successes in 2005 include successfully drilling two significant exploration wells, one in the West Tavaputs prospect; the Peters Point 6-7, and another in the deep formations along the Waltman Arch, the Bullfrog 14-18. Both of these wells opened up the surrounding acreage position to multi-year development opportunities.

2005 also presented challenges, with increasing costs and delays in obtaining approvals and services. But we faced those challenges and still completed the work we’d planned for the year. These hurdles have not affected our expected recoveries from our wells, but rather only partially delayed the date that some of these wells come on sales. While we expect ongoing challenges to affect the work we wish to accomplish, we are confident that we will be able to find a solution to every problem to meet our objectives.

The 2005 results validate our strategy of focusing on the Rockies and building a successful company by assembling a meaningful acreage position in undeveloped prospects, and applying our geologic and operational expertise to evaluate those prospects, to create multi-year development programs. For the remainder of my prepared comments, I want to bring you up to date on recent developments in our core development and exploration projects throughout the Rockies, and share with you our plans for 2006.

We continue to maintain an active drilling program, with six conventional rigs that are currently drilling in three different basins and four coalbed methane rigs currently drilling in the Powder River basin. As we move through the year, we will utilize up to 11 conventional rigs, including two deep rigs. Starting in the West Tavaputs prospect area in the Uinta Basin in Utah, we drilled 15 shallow development wells and a successful deep exploration well to add 39 Bcfes of proved reserves.

Our 2005 reserve bookings do not include any proved undeveloped locations, offsetting our deep discovery wells. Further, at the end of the year, we were completing five wells which indicated additional reserves of 12 Bcfes. Four of these wells are now on sales, and finally, because of strong well performance from our shallow program, we gained an incremental 9 BCF of proved reserves here in 2005.

We are currently producing approximately 49 million per day gross, which yield approximately 40 million per day net to our interest. As previously recorded, the Peters Point 6-7 well successfully completed in the Navajo, Entrada and Dakota formations. The well had an initial production rate of 11 million per day and has gained[?] approximately 1 Bcfe. The well continues to produce an overall decline at a rate of over 6 million cubic feet per day. At present, we estimate this well will produce over 4 Bcfe, but expect that estimate to increase with more production history.

Additional shallow potential pay zones also remain behind pipe in this well. We have identified over 20 160-acre locations within the Eastern 3-D enclosure surrounding this well. We’ll drill at least two of these in 2006. Our 3-D seismic survey also indicates there are future locations we can drill offset to the Peters Point 6-7, where we can also target deeper Weeber[?] and Mississippian potential. We also recognize, based on our 3-D seismic work, a separate but similar deep structural closure to the west, which we will eventually test in late 2006 or in 2007.

Our West Tavaputs shallow program in the Wasatch, North Horn and Price River formations continues to exceed our expectations. These shallow wells are being completed with initial production rates ranging from 1 million per day to over 6.2 million per day. Day production rates we estimate the ultimate reserves to range from 0.5 BCF up to 5 BCF. However, these ranges continue to be reassessed because the wells are producing better than we originally forecasted. We anticipate a multi-year development program of up to 180 wells on 160 acre spacing.

In 2006, we will test the viability of 80-acre well spacing and you’ll recall these same formations are developed on 40-acre spacing in the Natural Buttes field northeast of West Tavaputs. We have experienced some delays in late 2005 completing wells primarily due to a shortage of CO2, which we utilized in this area to energize and clean up our hydraulic fracture treatments. We have taken steps to secure a more reliable source of CO2 for future completion operations and we don’t expect these delays to negatively impact our operations or ultimate recoveries in 2006.

Over the last several years, we have upgraded our surface facilities in anticipation of future increased production. The significant increase in production at West Tavaputs has created a compression bottleneck on the eastern basin of our field and we estimate somewhere around 8-10 million per day of production is currently constrained. We are scheduled to add one compressor in May which will give us an immediate increase in production, and two more compressors in August will collectively all three together, increase our throughput by 30 million per day.

The West Tavaputs area generally consists of federal lands, many of which are subject to winter stipulations that currently restrict our ability to conduct year round field operations. We have filed a notice of intent for an Environmental Impact Statement, or EIS, at West Tavaputs for coalfield development that would include year round activities if approved. We anticipate it will take around 1.5 years to complete the EIS to allow us to complete our development work in the area. In the meantime, we have applied for and expect approval from the BLM on interim drilling activity over the next two years.

We filed a proposal to exempt pay to these interim wells from the winter stipulations that typically restrict drilling and completion activities from December 1 to May 15. We are very pleased that we have received approval for the first three wells under this request, and we expect to begin drilling the first well in the next two weeks. We have earmarked $78 million of our 2006 budget to drill a total of 17 shallow and two deep wells. We plan to begin drilling the deep offsets to the Peters Point 6-7 well in May of 2006.

I’ll move North, onto our Lake Canyon exploration program area. Again, this is an area that covers over 340 square miles, a very, very large exploration program. Last year we drilled the DLB #1 as a 14,500ft test to test the tight gas sands of the Wasatch and the Mesaverde. Based on gas shows and live data, we ran casing to 11,539ft. We began the completion and testing on Monday and we will continue this process over the next 30 to 45 days. We have a 75% working interest in this test.

Also in the Lake Canyon area, our industry partner has begun producing two shallow Green River oil tests that were drilled to around 5,500ft. These wells had a combined initial production rate of approximately 160 barrels of oil equivalent per day and were recently producing at a combined rate of 130 barrels of oil equivalent per day. Gas production from these wells is currently restricted pending completion of gathering infrastructure into this area, which is expected in May. We have an 18.75% working interest in these initial tests.

During 2006 we expect to spend over $9 million in the Lake Canyon project area, where we’ll utilize our newly-acquired three component 3-D seismic to drill two additional deep gas wells and four additional shallow gas wells as we continue to explore this sizeable acreage block.

As I’ve mentioned before, we are very excited and encouraged about what we’ve seen to date in Lake Canyon, this is a multi-pay project over a very large area, with multi-TCF potential net to the company.

Moving into the Piceance area, in our Gibson Gulch program, we drilled 80 wells and completed 61 wells by December 31 of 2005. We continue to develop our properties in the area with the three rig drilling program. The first rig is being moved to the West Tavaputs field which we just talked about. At the end of the year, 19 wells will be completed with expected net reserves of 12.7 Bcfe, 7.9 BCF of which were booked as PDN reserves. As previously discussed, our improved completion techniques continue to yield positive results. Initial production has increased to between 1-3 million cubic feet of gas per day. We are seeing these improved initial production rates in virtually all areas of our Gibson Gulch area.

Once we have a provisional production history, we are optimistic that recoverable reserves will also increase. The Piceance Basin is a very competitive area for drilling rigs and field services. As a result, we have seen pre-well costs begin to approach $2 million as it relates to our operations. At these costs, compared to current commodity prices, we are being selective in the well locations that we are drilling. We will apply the results of our recently completed three component 3-D seismic survey to delineate natural fractures and optimize our program in the Piceance Basin.

Furthermore, we are running production lines in our producing wells so that we can be more selective in the formations that we stimulate. Our goal here is to reduce the number of stimulations per well by two jobs, which would significantly reduce costs with minimal effect on production or recoverable reserves.

We have 735 locations on 20-acre development in the Piceance. As we’ve said in the past; with continued success we view this area as a major gas manufacturing play for the company. Throughout 2005, we consistently increased the throughput capacity of our gas gathering system by adding compressor units. Since the first of the year, our production has been limited to a gross volume of 37 million per day, due to compressor constraints. We expect delivery of another compressor within a week to increase our deliverability. Throughout 2006 we will continue to add compressors to meet the ability to increase our production in the area.

Our 2006 budget; $126 million for Gibson Gulch, we’ll drill 69 gross wells and add three compressors to the field facilities. We’ll closely monitor well cost and performance in our development area to ensure that we only drill wells with acceptable rates of return. Production in the area is expected to continue to grow due to our three rig program.

Moving north into the Wyoming areas, I’d like to talk about our Wind River Basin operations. Our two high-profile Muddy wells, the Bullfrog 14-18 deep exploration discovery well and the Cave Gulch 129 recompletion well are currently producing 10 million a day and 11 million a day respectively. These production rates are within the expected decline. We have recently noted some increase in water lately in the 129; we don’t believe this is a problem at present, but we’ll continue to monitor it.

As a reminder, both of these wells have Frontier potential behind pipe, and the Bullfrog 14-18 tested productive in the Lakota, which is also currently behind pipe. We are currently drilling an offset to the Bullfrog 14-18 discovery well. The Bullfrog 33-19 was started January of this year, and is currently drilling at approximately 12,500ft on its way to a proposed total depth of 19,810ft. We own a 93% working interest in this well. We should finish drilling this well approximately mid-April, completing the well will then take another 5-6 weeks; June timeframe.

We believe there are 30 additional locations within the Cave Gulch/Bullfrog area with deep potential, and we expect to drill 1-3 wells each year over the next 10-12 years. We are initiating a 3-D survey on the north side of Cave Gulch field to further refine the development locations in this deep development play. In our shallow Lance program, we do hope we did drill one dry hole last quarter. This was a step out from Lance production in the Waltman field south of Cave Gulch. It simply didn’t have the pay that we were hoping for. We’re also in the final phases of preparing our deep Cave Gulch 5-30 with a working interest of 92% for a restimulation in the Muddy formation similar to the 129. Again like our other rough wells, we have Frontier behind pipe in this well. Again, this well is an offset to our prolific 129 Muddy producer. In 2006, we’ll plan to recomplete two additional deep wells for a total of three deep recompletions for the year.

We control the majority of acreage along this deep overpressured resource play, not only in the Cave Gulch/Bullfrog area, but regionally in a trim that we believe extends for over 20 miles north and south along the Waltman Arch, from Cave Gulch well south of the Cooper Reservoir area.

Utilizing our full 3-D seismic coverage along the Waltman Arch, we have been assessing, and continue to assess, the Muddy and Frontier potential in [this canyon and plan to set?] our first deep exploratory task at Cooper Reservoir in the late second quarter 2006. We’re finalizing a joint exploration agreement in which we plan to bring in an industry partner to jointly test the Cooper deep potential.

I’d now like to discuss our CBM operations in the Powder River basin. We are currently producing about 20 million per day, and have oil rigs drilling in our Palm Tree Big George development project and in our Deadhorse Big George pilot area. Last year, we drilled about 182 wells and plan to drill about 220 wells in 2006, the majority of which are in the Big George. As a reminder, the Big George coal seam tends to be deeper than the Wyodak, and the dewatering time is expected to be 12-18 months. So again, this is a bread and butter CBM play for the company.

Moving northward into the Williston, we have been pleased with our results of our horizontal drilling program, and have been actively drilling over the last few months. In fact, we plan to nearly double our capital budget in 2006 in the Williston to almost $30 million. Much of our activity is focused in the target Red Bank and Red Bank Extension area. We have established production in the target Red Bank areas and plan to drill five development wells there, as well as an additional three exploration wells in the Red Bank Extension area.

We participated in a non-operated wildcat well on the south band of the Red Bank Extension area, the 14-23 Sigma Lee well, which targeted and was completed in the Bakken formation . It is producing at a rate of approximately 85 barrels of oil equivalent per day, but initially was producing at rates as high as 200 barrels of oil per day. Although we only have a 6.5% working interest, the results of the Sigma Lee well could help us to find the presence of a number of Bakken locations in our exploratory Redbank Extension where we have an average 60% working interest. In addition to the Bakken potential, we also believe there is a Mission Canyon Ratcliff play in this area, and we recently reached total depth on the first of two Ratcliff tests planned for this year.

This first well, the (Ericcson 44-15H) was drilled to a measured depth of 15,199ft and has approximately 5,700ft of lateral in the rack club. We expect to start testing this well in approximately one month. We are currently rigging up on our second exploratory Ratcliff well, the Miller 44-19H. Combining the Ratcliff and Bakken plays in the Red Bank Extension could mean up to 140 locations for the company.

In our Redwater play, which lies on the western edge of the prolific Bakken trend in Montana, our Bakken exploratory test, the McCrea 11-27H, was recently completed. We have seen oil tests that the well is currently blowing fresh water, this is very unusual for the Bakken and we are evaluating the potential for mechanical problems.

On the southern end of the Williston Basin, along the border of north and south Dakota in a project we call Grand River, we drilled our first horizontal Red River B Test in Nygaard 41-32 where we have a 60% working interest. The Nygaard has not shown traces of oil yet and is blowing water. We’re testing the water to determine if the well deviated from the production formation and clipped a fault. The company did report a dry hole expense for this well, but is testing to determine what further activities are warranted.

In our Mondak area along the eastern portion of the Bakken fairway, we’ve participated in a trilateral Bakken test; the McKenzie Federal 14-31, which is producing about 138 barrels of oil per day. We have a 22% working interest in this well. We also reentered an older well bore, the (Pinzel State 1-16) in this area, to cut a window and drill a lateral along the Bakken, and this well is testing at around 152 barrels of oil per day. Our acreage position sits adjacent to several key Bakken producers that have shown very promising results. We recognize 16 potential locations in this area.

We drilled two other Ratcliff tests, one in our Indian Hills area, and another in our Nameless area, both areas are southeast of the Redbank development area. The Schmitz 44-30 and the Indian Hills East has tested at production rates from 70–150 barrels of oil per day. In the Nameless area, the length is in the process of completion. We believe the Indian Hills East area holds an additional 18 potential locations for the company.

Now, just a quick note about Williston differentials. The company has typically sold its oil to various counter parties who truck the oil from the wall site and pay a 3-5% devac from the prevailing WTA price. Recently, due to refineries that have shut down in the Midwest, and large amounts of oil being transported into the area in the Enbridge pipeline for blending, there has been a drop in realized prices for Williston oil. The company believes that the oil differential may be as high as $10 per area, or $10 per barrel for at least the next few months.

Let me change ears here and say a few words about some of our other exploratory projects that we have ongoing. Starting with the Tri-State, let me just say we are encouraged and excited about this program. Our Tri-State biogenic gas play along the Eastern Denver Basin recently began production down sales line from seven shallow wells, six vertical and one horizontal, in what we call our Prarie-Star field area. On a combined basis, these wells have gross daily production of 450 MCF. We will need sustained production data to better understand the potential, but we are encouraged with the results to date.

Due to the shallow nature of the Niobrara formation, the well costs are relatively inexpensive and are economic at current production volumes. We currently own 1,500 miles of 2-D seismic and 24 square miles of 3-D seismic in the Tri-State area. We believe that we are dealing with a significant regional gas deposit in the Tri-State area. Our plans for 2006 include capex of $8 million to shoot an additional 60 square miles of 3-D seismic and drill up to 26 Niobrara wells. As a reminder, we have a 50% working interest in nearly 380,000 gross acres and we recognize an unrisked upside potential in this play area of 300-500 Bcfe net to the company.

Another large exploration project that we’ll evaluate in 2006 is in the Paradox Basin of Utah and Colorado. We continue to assemble a high-quality concentrated acreage position in the Yellowjacket shell gas prospect. We currently have over 80,000 net acres under lease in this prospect. Our objective in this area is to evaluate the shell gas potential from the fractured gothic formation that is 100-150ft thick at depths of 5,500-7,500ft.

Our initial evaluation indicates widespread potential for gas in this area. Our 2006 plans include continuing our leasing program, obtaining a joint venture partner and drilling four exploratory tests by the end of the year. Conservatively, this play is a gross unrisked 500-1 TCF-type Company Maker play for Bill Barrett Corporation.

Further to the North, in the Montana Overthrust area, our Circus project is emerging as a major structural exploration position for our company, with close to 160,000 net contiguous undeveloped acres. We are in the process of interpreting 68 square miles of 3-D seismic that we recently acquired. Due to Winter weather, we are only two-thirds done with this seismic program but look to complete that in the Spring time. We may bring in a partner to jointly explore in the area, and drill at least two exploratory wells this year.

From a regional standpoint, in the Montana Overthrust Circus area, this region lies between the prolific Wyoming and Canadian thrust belt producing regions, where approximately 19 TCF of proven recoverable reserves exist. Circus is a direct analogue to these areas, and thus also has multi-TCF potential net to the company.

Finally, in the Big Horn Basin in north central Wyoming, we are testing an unconventional basin center gas concept here. Again we recognize large-scale multi-TCF potential. We have assembled nearly 140,000 net undeveloped acres in this area, a portion of this position in our Sellers Draw area covers what we believe is a significant structural feature. During 2006 we plan to reenter our Sellers Draw #1 which has produced over 3 BCF out of the deep Muddy formation, and re-complete that well in the overpressured Mesaverde formation.

Additional plans in the Big Horn call for a 3-D seismic chute and one exploratory test during 2006. In addition to the exploratory prospects that we discussed in detail in this call, exploration activities are being conducted in a number of other areas including the Hook and Whipside prospects in the Uinta Basin, and the Pine Ridge prospect in the Paradox. In the interest of time, I will not review the activities during this call, but rest assured activities are continuing and we are excited about the potential across all of our areas.

We’ve given you a significant amount of information here about our core development and exploration basins. We have a number of exploration projects across the Rockies that we will continue to assemble and evaluate throughout 2006. In 2006 we intend to spend at least $80 million on exploration and lease acquisition work, including the drilling of 38 wells to evaluate 18 prospects. Although our exploration efforts will be extremely busy throughout the year, our exploratory drilling will be concentrated towards the end of the year.

As our company has grown and expanded, we have developed a better understanding of the challenges we face and the commitment that we are willing to make to meet those challenges. For example, our success in the West Tavaputs and Piceance areas allow us to understand the amount of compression that will be needed to maximize throughput in our development fields. The lead time to secure compressors has increased up to 14-16 months. Recognizing our repeated need to add compressors in our development programs, we have entered into a contract to acquire 10 compressors during 2007. These compressors are capable of being used at various areas of our development and exploration.

Based on our anticipated activities and expected long-term growth, we have determined that it is also prudent to ensure that we have firm transportation to deliver a portion of our gas production from the Rocky Mountain region sales point out by the area. In February we committed to firm transportation for up to 25 million per day for 12 years on the Kinder Morgan/Sempra Rockies Express pipeline that is scheduled to begin limited service by early 2008.

When all construction is completed, that pipeline will deliver gas from the Rocky Mountains to Eastern Ohio, giving this company market penetration in the high demand eastern corridor.

Our approved budget for 2005 is $350 million. This amount is net of proceeds that we expect to collect through the year from joint venture participants in our exploratory projects. We will carefully evaluate our activities and the results throughout the year to determine whether our capital expenditures are being invested prudently, with the goal of maximizing reserves and production in a cost effective manner. As previously reported, we expect our production for the year to be 43.5-46 BCF and our first quarter production to between 11.5 and 12.1 BCF. This production guidance is our best estimate of the results of our activities, after considering normal delays in the timing of our field operations in 2005. Throughout the year, we will update our guidance as we obtain additional clarity of what we are able to accomplish.

During recent weeks, gas prices have declined throughout the U.S., including the Rockies. Current forward prices for April are at that level. Even though our development activities are economic at current prices, continued prices in the $5-6 range may cause us to consider delaying development in certain areas to maintain a healthy balance sheet and focus on activities to maximize returns.

I’d like to follow up my prepared comments here with a couple of comments about the recent announcement that I have been named to succeed Bill Barrett as the Chairman and the Chief Executive Officer of your company. It is truly an honor to be selected to lead Bill Barrett Corporation and the great employees we have working here. Bill has set a high standard of excellence that we will strive to build on. Now that the board has completed its CEO search, we will begin a similar search process of selecting our Chief Operating Officer to take over those duties so that we can continue our goal of operational excellence.

Our team has assembled a great set of assets of tremendous upside. Across the company we have limitless confidence, enthusiasm and excitement for the industry and what we have accomplished. Our teams have done an outstanding job in a short period of time. This was a benchmark year in terms of exploration success, production growth and cash flow, that speaks volumes about our ability to establish a legacy track record. I truly believe this is just the starting point for years of continued growth. The Rockies are a tremendous resource base of natural gas and oil for this country’s energy needs, and we have the people and the assets to fully participate in the expected growth in the Rockies production.

With that, I turn it back over to the conference facilitator for questions, and thank you.

Question-and-Answer Session

Operator:

At this time, I would like to remind everyone if you would like to ask a question, please press *1 on your telephone keypad. Your first question comes from Brian Singer with Goldman Sachs.

Brian Singer, Goldman Sachs & Co.

Good afternoon.

Fredrick J. Barrett, Chief Operating Officer

Hi Brian.

Brian Singer, Goldman Sachs & Co.

Congratulations on your promotion.

Fredrick J. Barrett, Chief Operating Officer

Hey, thanks.

Brian Singer, Goldman Sachs & Co.

What is your outlook for costs in the Piceance beyond where they are presently, and in light of your comments on $5 or $6 gas being kind of a key floor. Would that be the first area you’d consider slowing drilling? In light of what you mentioned with regards to signing a firm transport and compressor contract, would you also consider buying rigs?

Fredrick J. Barrett, Chief Operating Officer

Okay, let’s see. I’ll try and get all of that here. Let me start with the first part of your question and I’ll get to the rig part there. You know, the first thing everybody needs to understand as it relates to our production streams coming out of this company; I’ll get to Piceance here in just a second. Our average BTU content is 1,200 MBTU, and when you look at that in terms of a price adjustment, we get a nice bump, a nice premium at this company. Take for example a [525 gas?], you’re getting a 20% bump bringing you up to 625, somewhere in that range. So you need to factor that in when you look at this company. Having said that, to the extent that we believe gas prices will continue at these lower levels, you know we will continue to look at hydrating the positions that we have across the Rocky Mountain region. In particular, as you mentioned, Brian, the Piceance Basin. We are selectively drilling in that area specifically in what we believe are higher rate of return areas. In terms of what we learned during the 2005 program, and I might add we’re doing that regardless of gas prices. But as I said, to the extent that we believe that this would continue, and we can begin to understand that as we move through the first half of the year, you know we would continue to hydrate. You know, we do have select positions in there where we know we can get premium EURs and so you could potentially go down to a one route program.

Right now, our plan is to drill a comparable program compared to what we had in 2005. As I mentioned, we are focused on the high rate of return locations. But at this point, at the current prices, even though we’re inching down there, this has not materially impacted our current decision making processes here. We’ll continue to monitor that as we move through the first six months. We continue to mitigate the decrease in gas prices and the increase in costs across all of our fields, and in particular in the Piceance. We’re focused always on our efficiencies, our drilling completion, LOE and gathering. We continue to work with the service companies on the best pricing portfolios that we can put forward. But keep in mind that this company is 53% hedged through 2006. We have stemmed somewhat the volatility in the gas prices. It allows us to operate in the valleys. As far as drilling rigs, you know I’d like to think we’re in the drilling business but we’re not, we are an oil and gas exploration company. You know, that’s a departure from our current strategy. I know other companies have done it, but again one of the first mantras of our strategy here is to stay focused on what it is we’re doing. That’s building up, finding and developing oil and gas. So no, we’re not going to be purchasing rigs.

Brian Singer, Goldman Sachs & Co.

Thanks. Could I just also quickly ask on the Ratcliff area, from the 140 locations, how much would the resource potentially you see be, or the resource per location?

Fredrick J. Barrett, Chief Operating Officer

That’s a resource area that I would say you’re going to get… Our goal would be to recover about 375,000-400,000 barrels of oil per well, and we average a 60% working interest in there, so you know you can do the math there. I think it is somewhere, 15-20 million barrels, somewhere there.

Brian Singer, Goldman Sachs & Co.

Thank you very much.

Fredrick J. Barrett, Chief Operating Officer

In terms of Bcfe, Brian, it’s about 100 Bcfe net to the company.

Brian Singer, Goldman Sachs & Co.

Great, thank you.

Operator

Your next question comes from the line of David Tameron with Jefferies & Company.

David R. Tameron, Jefferies & Co.

Good afternoon. Quick question, going back to Piceance real quick, then I got another question, but what type of EURs are you seeing out there? Is it sort of the 14/15 ECF or what are you targeting out there? Or what are you seeing?

Fredrick J. Barrett, Chief Operating Officer

Over the past seven months, as we continued with our optimization program, and it was an intensive optimization program, where we finally dialed into the correct and optimal way to pump our cracks and flow them back, we have brought our wells up, on average, above 0.65-0.7 Bcfe and within that range on an average. Our goal, this year, again is selectively targeting the sweet spot areas. We don’t know it yet, but we’d love to land somewhere between 0.7-0.9. Right now, 0.7 is just economic enough for us to continue drilling and as I mentioned, we haven’t materially changed our program because of that. But we’re seeing some very good initial production rates, certainly over the last 10 wells that we drilled here in the early part of 07, rates that are anywhere between 1-3 million per day. We also look forward to finishing up our 3-D program in here. We’re kind of on the tail end of understanding what the 3-D three component type technology is going to do to help us understand where the natural fractures are. Once we get that all put together, we’ll also use that in addition to our knowledge base on the current sweet spots, to further hydrate what we’re doing and so, again, we’re focused specifically on the 0.7 BCF or higher locations in the Piceance Basin are.

David R. Tameron, Jefferies & Co.

Okay, and let me jump to the DJ, you mentioned you drilled like seven wells you said.

Fredrick J. Barrett, Chief Operating Officer

Right.

David R. Tameron, Jefferies & Co.

I mean, all of these shallow wells, what are these costs, I mean what are you kind of targeting out there?

Fredrick J. Barrett, Chief Operating Officer

Yes, we’re drilling these down about 1,800-2,000ft. These are $150,000 wells, so they’re pretty cheap. When you drill a horizontal well you’re going to span anywhere from $300,000-350,000. Interestingly enough, although we’re very pleased with the vertical wells, the horizontal well is giving us our highest daily rates, upwards of 150-170 Mcfe. So, it’s a matter of continuing to drill both vertical and horizontal. You’d like to understand whether or not – you know, if you don’t need to drill horizontals, you don’t want to go there, but we’re still in that early phase where we’re trying to determine what’s going to be the best economic way. Is it going to be a vertical program or is it going to be a horizontal program, we’ve not yet made that final determination.

David R. Tameron, Jefferies & Co.

Okay. You’re going through seven wells. I mean, have these been in one location? How much of the BCF has kind of proved up?

Fredrick J. Barrett, Chief Operating Officer

Yes, right. The seven wells that we drilled, David, are in what we call a Prarie-Star. This is an area where we shot a 24 square mile 3-D seismic survey and we were then able to model in, tie in from an analogue basis, what the seismic attributes were that defined other producing fields in the area. We recognized the same sweet spot characteristics on the 3-D. We also recognized the presence of subtle structural features that help enhance the production here. So these types of wells were focused on a 3-D anomaly associated with the Prarie-Star area. Now, as we move forward in time, based on our 2-D, what we recognize is that the gas saturation in this area actually covers a very, very large fetch area on the order of hundreds of square miles. So what we’re doing is we’re going in there and shooting 3-D seismic kind of off of the original 2-D seismic leads. Then we’ll be following that up with exploration and delineation drilling during 2006. You’re going to see us move away from the Prarie-Star area. We’ll probably drill additional wells but you’re going to see us also move away as we try to explore over what is a pretty large area. We’re looking at over 360,000 gross acres that we own here. It also covers portions of Kansas, Colorado and Nebraska. But the big area, the big exploration program, you know it’s important because it’s one of the largest biogenic gas deposits in the U.S. Our goal is to come in here, establish a way to drill and complete these wells, and we use nitrogen foam cracks on these. Figure out how to crack that nut and we believe this is going to turn into a big, big play. The wells that we drilled this year, the way we drill them, the way we completed them, we’re encouraged with so we’re going to continue this year with 3-D, follow that up with additional exploration drilling.

David R. Tameron, Jefferies & Co.

Okay. Then one more question, I promise. We’re hearing a lot of positive talk coming out of Weston and Williams etc. about the Big George. What do you guys think, what are your expectations thus far?

Fredrick J. Barrett, Chief Operating Officer

Well, my opinion on the big George is that that is a sleeping giant. Even though they had the problems with the EIS, even though they had problems with water disposal and there still are water disposal issues, you got a thick coal seam that covers a huge area that has two to three times the gas content of the Wyodak. It was just a matter of time before the state and the government allowed people to get in there and really start continuing to develop it. Our approach right now, we have four main Big George blocks, we’re developing one which has just been wonderful for us, the Palm Tree area, we’ve more than doubled our production coming out of there over the past 12 months. We have fully drilled up our Cat Creek block, further to the north, and that’s currently de-watered. 12-18 months possibly longer, we hope to see gas break through some time in Q3/Q4. We’ll continue to drill on our Dead Horse block, we have about 25-30 wells drilled in there I believe. We have another block that we’ll continue to drill called the Willow Creek area. We also have other plans, other pieces that we’re assembling right now that we can’t talk about that will continue to add to our reserve and production growth in the Powder River Basin.

David R. Tameron, Jefferies & Co.

Okay, I’ll jump off, thanks.

Operator

Once again, if you would like to ask a question, please press *1 on your telephone keypad. Your next question comes from Larry Busnardo with Petrie Parkman.

Larry C. Busnardo, Petrie Parkman & Co.

Hey, good afternoon. Could you go over what the impairment was associated with?

Thomas B. Tyree, Jr., Chief Financial Officer

You want to get that?

Fredrick J. Barrett, Chief Operating Officer

Yes. The fourth quarter impairment, or the total… Bob have you got that?

Larry C. Busnardo, Petrie Parkman & Co.

The total.

Robert W. Howard, Executive Vice President

This is Bob Howard. The fourth quarter impairment included some costs in the East Madden area and also further impairment in the Talon area.

Larry C. Busnardo, Petrie Parkman & Co.

Okay, the one in Talon, was that associated with your earlier impairment?

Robert W. Howard, Executive Vice President

Yes it was.

Thomas B. Tyree, Jr., Chief Financial Officer

…reserve evaluation and just had a little bit more that we needed to record as an impairment in the fourth quarter.

Larry C. Busnardo, Petrie Parkman & Co.

Yes okay, all right. With regard to Yellowjacket, I know you’re looking for a partner there, is there any scenario where you would go ahead and drill that at 100% yourself, or are you set on finding a partner before that’s drilled?

Fredrick J. Barrett, Chief Operating Officer

You know, our intentions are to find a partner. We’re not fully there in terms of our lease position. Right now, we’re going to probably move to bring in a partner during second quarter of 2006. If we elect not to do so we’ll certainly let everyone know about it.

Larry C. Busnardo, Petrie Parkman & Co.

If you get those wells drilled in the second half of this year, provided they’re successful, does that go to a much broader program next year? Yes, you may have difficulty in finding anyone with the tight market out there, have you given any thought of how you’ll go about doing that? I know…

Fredrick J. Barrett, Chief Operating Officer

We think we’ve got, knock on wood, our rig situation under control. You know, we have our rig program completely laid out through the end of 2006 and into the early part of 2007. If it requires a shallow to intermediate depth rig, I don’t perceive or foresee any material issues associated with procuring a rig to do that program should we continue to follow up with it in 2007.

Larry C. Busnardo, Petrie Parkman & Co.

Switching over to Cave Gulch, the 5-30 restimulation well, what’s going to be the timing of that?

Fredrick J. Barrett, Chief Operating Officer

Very soon. We’re trying to knock out or drill out what we call a seal assembly plug in there. We’ve got that pushed all the way to bottom. We should be completing that well some time over the next several weeks.

Larry C. Busnardo, Petrie Parkman & Co.

Okay. So you should get results on that fairly quickly thereafter, correct?

Fredrick J. Barrett, Chief Operating Officer

Yes. Dominic’s shaking his head yes.

Larry C. Busnardo, Petrie Parkman & Co.

Okay, so that doesn’t take too long to complete those? How many more recompletions do you have in Cave Gulch?

Fredrick J. Barrett, Chief Operating Officer

Well, if you look at the total program, we have really somewhere in the order of 6-7 wells that we could reenter and recomplete. Kind of vis-à-vis what we did in the 1-29. We have three scheduled this year, and should we continue with the type of success that we had in the 1-29, we could potentially add to that and recomplete additional wells beyond those three.

Larry C. Busnardo, Petrie Parkman & Co.

Okay, great. That’s it for me. Thanks.

Operator

Your next question comes from Ray Deacon with Harris Nesbitt.

Raymond Deacon, Harris Nesbitt

Hey guys. I was wondering if you guys had committed to any firm capacity on the Kinder Morgan pipeline that’s going to get built? How much basis have you locked in? Are you concerned about basis at all going forward?

Fredrick J. Barrett, Chief Operating Officer

Yes. We have committed, if I understand your question right, we have committed to 25 million on the Rockies Express. That gives us about a dollar or two differential to get our gas into the eastern markets.

Raymond Deacon, Harris Nesbitt

Right, okay great.

Fredrick J. Barrett, Chief Operating Officer

And that, you know that…yes.

Raymond Deacon, Harris Nesbitt

Got it. That’s all I got, thanks.

Operator

Your next question comes from David Tameron with Jefferies and Company.

David R. Tameron, Jefferies & Co.

Hi, just one follow-up question, Fred.

Fredrick J. Barrett, Chief Operating Officer

Sure.

David R. Tameron, Jefferies & Co.

In the Lake Canyon area, could you review what you said about the Wasatch, the deep tests you guys did? Or you’re doing?

Fredrick J. Barrett, Chief Operating Officer

Sure. In our deep tests, as it stands right now, we’re currently completing in the Mesaverde formation. In fact, it’s the upper part of the Mesaverde formation, and we refer to that part of the section as the price rubber section. Right above that is the Wasatch formation. The Wasatch is very prolific in both the Altamont/Bluebell area to the north, also very prolific in the Natural Buttes area to the east, and it’s also very prolific in our West Tavaputs area to the south. We believe that somewhere in the Lake Canyon area, there’s a pretty sizeable reserve target associated with the Wasatch. We’ve not yet gotten to it in this well, we will get to it. We will test what sort of gas and liquids exist in the Wasatch formation . Once we have those results, we’ll certainly let you know. We also, as we move through time, particularly over the next two years, we’re going to drill additional Mesaverde Wasatch wells this year. We’re going to drill additional Masaverde Wasatch wells next year. Again this is a 340 square mile area and it’s going to take us a while to find out what we have here in terms of not only the Wasatch but the Mesaverde. I’m not sure if I’m answering your question.

David R. Tameron, Jefferies & Co.

No, that’s good. And when do you expect to have results on this particular well?

Fredrick J. Barrett, Chief Operating Officer

I would say, you know, some time over the next 4-6 weeks.

David R. Tameron, Jefferies & Co.

All right, thanks.

Fredrick J. Barrett, Chief Operating Officer

You got it.

Operator

At this time there are no further questions.

Fredrick J. Barrett, Chief Operating Officer

Okay, thank you for participating in our year-end conference call. As I mentioned earlier, we are filing a form 10-K with the SEC today. I encourage you to read the 10-K for a more complete view of our 2005 results. That concludes our conference call.

Operator

This concludes today’s conference call, you may now disconnect.

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Source: Bill Barrett Q4 2005 Earnings Conference Call Transcript (BBG)
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