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Bill Barrett Corporation (NYSE:BBG)

Q1 2006 Earnings Conference Call

May 9th, 2006 4.30 PM

Executives:

William Crawford, Manager, Investor Relations

Fredrick Barrett, Chairman, Chief Executive, President

Thomas Tyree, Jr., Chief Financial Officer

Robert Howard, Executive Vice President - Finance and Investor Relations

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

Terry Barrett, Senior Vice President – Exploration, Northern Division

Kurt Reinecke, Senior Vice President – Exploration, Southern Division

Lynn Boone Henry, Vice President – Reservoir Engineering

Analysts:

Jeffrey Robertson, Lehman Brothers

David Tameron, Jefferies & Co.

Operator

Good afternoon. My name is Kristel, and I will be your conference operator today. Operator instructions. Mr. Crawford, you may begin your conference.

William Crawford, Manager, Investor Relations

Thank you, Kristel. Good afternoon and welcome to Bill Barrett Corporation's conference call to review Q1 2006 financial results, to discuss our recent Powder River Basin acquisition and to update our current operating activity. My name is Bill Crawford, Manager of Investor Relations. With me today are Fred Barrett, Chairman, Chief Executive and President, Tom Tyree, Chief Financial Officer, Bob Howard, our Executive Vice President, Finance and Investor Relations, 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 respectively, and Lynn Boone Henry, Vice President of Reservoir Engineering. Tom will begin by reviewing our financial results for Q1.

These were announced after the market closed today in a press release, which may be found on our website or through financial news sources. Our Form 10-Q for Q1 is also being filed with the SEC this afternoon. Following the financial review, Fred will discuss our recent CH4 acquisition and provide an operational update and outlook for the remainder of 2006. We expect these discussions to last about 30 minutes, and as Kristel said, we’ll follow with a question and answer session.

Before we start, please note that statements made in this conference call, 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, and that our drilling schedules, costs, capital plans and other factors 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 to the appropriate GAAP measure was provided in the earnings press release. I will now turn the conference call over to Tom for a company financial review.

Thomas Tyree, Jr., Chief Financial Officer

Thanks very much, Bill, and good afternoon everyone. Before I discuss our quarterly results, I would like to take a moment to thank Bob Howard. As many of you know, Bob has been presented with an opportunity to join a private start-up firm as CFO. I can't imagine why he would leave the fascinating world of public company accounting, compliance and investor relations, but for some reason he has decided to do just that. All of us here at Bill Barrett Corporation sincerely thank Bob for his significant contributions as we formed and grew the company and we wish him the best in his new endeavor. We are extremely pleased to report that Q1 2006 was another strong quarter for Bill Barrett Corporation. Exceptional performance from our West Tavaputs and Piceance operations enabled us to meaningfully exceed our guidance range for Q1 production.

These same factors, together with the impact of our CH4 acquisition, have caused us to materially increase production guidance for full year 2006. The CH4 acquisition which closed yesterday will enhance the value of our Powder River Basin operations and provides us with lower risk reserve and production growth at very attractive returns. In addition, we announced strong earnings and cash flow for Q1, and we had another exploration success at Lake Canyon. Fred will elaborate on all of this in just a few minutes. We produced an average of 146 million cubic feet equivalent per day in Q1, which represents 55% production growth over Q1 2005 and 10% growth over last quarter. We realized an average price of $7.42 per MCFE produced and we generated $71.3 million in cash flow, or $1.62 per share. Net income was $22.1 million or $0.50 per diluted share for the quarter. Our cash operating costs in Q1 were $1.97 per MCFE after reduction of $0.28 per MCFE from Q4 2005 and primarily relates to a decrease in production taxes due to lower prices and the increasing proportion of our production coming from lower-tax states including Colorado and Utah.

Our LOE and gathering were slightly higher on a unit basis than levels in Q4 2005, as operating and water handling costs in the winter months tend to be higher than the rest of the year. We spent $102 million net on capital expenditures in Q1 2006. Our capital budget for full year 2006 is expected not to exceed $430 million, including the $79 million for CH4 which is net of working capital. As of today, our debt outstanding under our line of credit is $195 million after paying for CH4 yesterday. We continue to be committed to maintaining a conservative balance sheet that provides us with flexibility and strong liquidity. We do review longer-term financing alternatives as a matter of course, but given the strong commodity outlook, our current hedge volumes and our existing bank capacity, we have sufficient availability under our bank line to finance our capital requirements to 2006 and beyond. However, we will be opportunistic about other financing options as the market presents them. I will now turn it over to Fred, to elaborate on the strong performance, on the CH4 acquisition and our company operations.

Fredrick J. Barrett, Chief Operating Officer

Thank you, Tom, and thank you all for joining us today. Building on our record year in 2005 for production growth and exploration discoveries, we continue to successfully execute our exploration and development strategy in the Rocky Mountains and the results of Q1 validate our efforts. We've exceeded our production expectations, leading to strong cash flow and net income and we have increased our production guidance in order to reflect our production successes. Furthermore, we believe we have yet another exploration success in one of our large-scale exploration projects, the Lake Canyon prospect of the Uinta Basin. Since inception in 2002 we have grown production at a compounded rate of 57% and we are proud to announce organic sequential growth production of 10% over Q4 2005 as the well performance in the West Tavaputs and the Piceance continues to improve. In fact, we grew production despite the fact that we were at maximum compressor capacity in both the Piceance and the West Tavaputs areas.

Additional compressors will be delivered and installed in May and June to alleviate the issue and after a busy summer drilling schedule, additional compressors will be delivered and installed late in Q3. By the way, April daily production was nearly as strong as the first quarter's, we produced approximately 145 million per day during April. We had this strong production growth in a period of volatile commodity prices. Natural gas prices in the Rockies have increased over the past several years, culminating with a $10.75 price last November. Since that time, prices have softened as warm weather reduced the demand for natural gas. These circumstances have reduced returns in the short-term, as they have for many operators, but because of long term supply and demand fundamentals we are still very bullish on Rockies gas.

May gas is selling for $5.61 CIG and the strip is nearly $6 for the remainder of 2006 and at least $8 for each of 2007 and 2008. As we plan to continue our breadth of exploration and development program, we continue to high-grade drilling prospects that generate returns in excess of the mid to high teens. We look to add hedges for 2007 and 2008 in the near future. Exposure is the name of the game in the Rockies. While growing our production we also continue to generate and build new projects and also continue to add acreage in our current exploration projects. We increased our net undeveloped acreage by 18% to 1.4 million since year-end by adding to our Circus, our Big Horn, Paradox, Tri-State and Wallace Creek positions. Furthermore, we have identified several new geologic concepts to pursue so that we can continue to fill our portfolio of prospects in the future. Another facet of our growth strategy relates to acquisitions. On occasion, when an opportunity presents itself, we will take advantage of acquisitions that provide significant upside at a financially disciplined price. The CH4 acquisition was one such opportunity.

Yesterday, we closed on our $80 million acquisition of CH4 properties on the Powder River Basin. We are very excited about this acquisition. In general, it increases our acreage position in the Powder River Basin by 69%, increases our upfront net production in the Basin by 35% in the Powder River Basin and it gives us greater operational scale and centralized efficiency. We acquired 11 BCF of proved reserves and 51,000 net acres with a current net production rate of about 6 million a day. The majority of this acquisition is central and complementary to our current acreage position in the south central area of the Basin, but we currently have 24.8 BCF of proved reserves, 80,000 net acres and a current net production rate of 19 million per day. It especially makes us a stronger player in the emerging Big George play with CH4's Hartzog Draw, Pumpkin Creek and Coal Gulch Big George assets, and also gives us additional Wyodack potential north and south of the main Wyodack fairway. We recognize that production on the acquired properties are in the early ramp up phase, especially in the Hartzog Draw and LX-Bar areas, and expect to see continued ramp up by year end as wells drilled last year continue to de-water.

Nearly 1.2 BCF of the production guidance increase is associated with production from the CH4 properties. We've booked about 11 BCFE of proved reserves related to the acquisition and see significant upside to this. Probable and possible reserves total another 50.4 BCFE that will require approximately $44.5 million to develop the total 3P reserves over the next 3-5 years. Additionally, we believe there are further potential reserve additions beyond 3P reserves, completion of certain secondary coals, development on certain acreage where the value is not attributed in the acquisition and upside related higher gas content could add additional reserves.

For the remainder of my prepared comments, I want to bring you up to speed on recent developments in our core development and exploration projects throughout the Rockies and share with you our plans for the remainder of 2006. I would like to reiterate that I am very pleased with our progress to date in our developments in exploration programs. We continued to maintain an active drilling program currently with nine conventional rigs that are drilling in five different basins and also four coalbed methane rigs currently drilling in the Powder River Basin. I will begin our operational update in the Uinta Basin with a brief status report of our exploration success in the #1 DLB well at Lake Canyon in which we have a 75% working interest and where we are the operator. Within the last two weeks, we have finished up our completion operations on this well and have established oil production at an average rate of 315 barrels of oil per day during the first 13 days of production from the Wasatch formation. The DLB well will require a long-term and stable period in order to better quantify its potential, but we are encouraged and excited with the results so far.

As a reminder, we control a very large position in this area with over 229,000 gross and over 155,000 net acres surrounding this well and again we have a 75% working interest in this well. We continue to analyze our new 3D seismic to better guide the locations for selection for two exploratory tests that will be drilled later in 2006. There is a strong likelihood one of these wells would offset our DLB #1 well's success. Because this well was so recently completed, I will have no further comments during this call, but please be assured that we will pass additional information along to you as we learn more. Also in the Lake Canyon area are two shallow Green River oil tests that were drilled in 2005 that continue to produce. True well performance will soon be determinable with the completion last week of the gas-gathering infrastructure into this area. Results have been sufficiently encouraging that we and our partners plan to drill at least four additional wells in late Q2 and at least 10 additional wells by year end. We have approximately 18.75-25% working interest in the shallower Green River program.

Before I leave Lake Canyon, let me remind everyone that our Lake Canyon block is a very, very large area, over 340 square miles in size. As we have stated before and more recently confirmed with our exploration success, we believe there is tremendous potential upside in this project.

Moving on to West Tavaputs, our optimism remains extremely high for our West Tavaputs project, where we generally have a 100% working interest. Currently, we have two shallow rigs and one deep rig drilling in the field. The environmental situation eased somewhat this past winter, when we were granted precedent-setting approval to drill eight wells during the winter season. We continue to push forward on our EIS, which will ultimately allow us greater flexibility in the number of wells we can drill as well as more uniformity in their timing. We expect the EIS to be completed over the next 1.5 years. We've produced a net 45 million per day from West Tavaputs in Q1 2006. Production from our West Tavaputs shallow program in the Wasatch, North Horn and Price River formations continues to exceed our expectations. In fact, about 1.5-2 BCF of the increase in 2006 production guidance was attributed to better than anticipated well performance from our shallow wells in West Tavaputs.

Overall this year, we plan to spend nearly $100 million to drill a total of 25 shallow, two deep wells and also four additional compressions in the West Tavaputs area. Pending EIS approval, our shallow program will be a multi-year development program with up to 180 wells on 160-acre spacing for the shallow program. In 2006, we will test the viability of 80-acre spacing. You'll recall that the same shallow formations are developed on 40-acre spacing in the natural butes field north east of West Tavaputs. Our successful deep discovery test of the Dakota, Navajo, Entrada formation continues to produce along its expected decline curve. The Peter's Point 6-7D was producing in excess of 5 million per day as of the end of April. As a reminder, we have identified over 20 160-acre locations in the Peter's Point 3D closure, the eastern structure surrounding this well.

We will drill at least two of these deep locations in 2006. In fact, the first well, the 4-12D, is currently drilling. Our 3D seismic survey also indicates there are future locations which we can drill (up dip?) of the Peter's Point 6-7D where we also are targeting ultra-deep Weeber(?) and Mississippian potential. Finally, based on our 3D seismic work, we also recognize significant potential in a separate but very similar deep structural closure on our western Prickly Pear Mesa that we plan to test in 2007. Elsewhere in the Uinta Basin on the exploration front, we continue to add acreage to our Hook and Woodside areas. We expect to drill three exploration tests in Hook, a shallow expanse of shale gas play in the Ferin(?) formation in late Q3. We also plan a 6,500 foot well in Q4 at our Woodside project to test Pennsylvanian-aged sandstone on a seismically identified structural closure. The Woodside well will offset a well drilled in 1962 that recorded gas shows in the target formations.

Moving on to the Piceance, we currently have three rigs operating in our Gibson Gulch areas. We produced nearly 31 million a day in Q1 and 37 million a day in April. Thus we are seeing the production growth that this area is capable of. Our well performance continues to improve, having consistently established IPs(?) in the 1-3 million a day range. About 1-1.5 BCF of our increase in production guidance relates to the improvement in Piceance well performance. The Piceance Basin continues to be a competitive area for drilling rigs and field services. As a result our pre-well drilling complete costs are approaching about $2 million. At these costs, compared to current commodity prices, we are being highly selective in the well locations that we choose. In the near future, we will be able to apply the results of our three component 3D seismic survey to delineate areas prone to natural fractures in order to optimize our program in the Piceance Basin. Data quality of this 3D survey appears to be excellent. We are also applying the results of a systematic production log program in our existing wells and we are now being more selective in the formations that we stimulate.

Our goal here is to reduce the number of stimulations per well by two jobs, especially those zones that give a higher water contribution. This reduction in the number of completed intervals should reduce pre-well costs by $100,000-200,000, with minimal effect on production or recoverable reserves. The Piceance is an important area for the company because it has significant gas in place and allows for year-round drilling. We also have a relatively bullish view on long-term commodity prices so we plan to continue development of this program. In 2006 we plan to drill about 60 wells and spend nearly $125 million in this program. Moving north into the Wyoming area, I'd like to talk about our One River Basin operations, where we produce nearly 39 million a day in Q1. We are currently drilling an offset to the high volume Bullfrog 14-18 discovery well in the Cave Gulch/Bullfrog area. The Bullfrog 33-19 was spud in January and should reach a total depth of about 19,500 feet this week. We have a 93% working interest in this well. Gas shows while drilling in the Muddy, Frontier and Lakota are all encouraging and structurally, we ended up higher than we had anticipated.

Testing and completion of the wells is expected to take place over the next 30-60 days. We believe there are over 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 have acquired, and are currently processing a north extension to the Cave Gulch 3D survey, with the objective of imaging the north side of the field and to better refine our deep locations in the Cave Gulch area. Our other two high-profile Muddy wells, the Bullfrog 14-18 which was our initial deep discovery well last year, and the Cave Gulch 129 recompletion well were producing along their expected decline curves and are currently producing 7.2 million a day and 6 million a day respectively. As a reminder, these wells have Frontier potential behind the pipe, and Bullfrog 14-18 tested productive in the Lakota, which is also currently behind the pipe. I might add we are also continuing with our recompletion program at our Cave Gulch 5-30 well as well as those other wells, targeting the Muddies and the front-tier formations.

Moving south along the Waltman Arch, away from the Cave Gulch/Bullfrog area, is the Cooper Reservoir area, again located just to the south of the Bullfrog area. Utilizing our 375 square miles of our 3D seismic coverage along the Waltman Arch, we have been assessing the Muddy and Frontier potential in this trend and plan to spud and operate our first deep exploratory test at Cooper Reservoir in the next few weeks. We have a 50% working interest in this well that will test the Frontier, Muddy and Lakota formations at a total depth of about 16,500 feet. Returning to the Powder River Basin which we talked about earlier, I'd like to say a few words about our CBM operations. We've produced about 19 million a day during the first four months from our legacy properties and acquired approximately 6 million per day of production related to the CH4 properties. In 2006 we plan to drill 337 wells with a total capital budget of about $30 million, excluding the acquisition price for CH4. The majority of the capital program will be focused on the Hartzog Draw, Willow Creek, Pumpkin Creek, Deadhorse and Palm Tree areas, each of which targets the Big George coals. We have become the major player in this part of the Basin.

Again, we view this as a low-risk bread and butter CBM development play. We now have a 4-5 year drilling inventory and economies of scale that makes us a major producer and operator in this area. Between our legacy properties and those acquired from CH4, we have the majority of the water discharge and other required drilling permits to execute our 2006 drilling program. Moving northward into the Williston Basin area, we have been pleased with our results so far in our horizontal drilling program, and have been actively drilling over the last few months. We plan to spend approximately $30 million in 2006. Much of our activity is focused in the target Red Bank development area and Red Bank extension exploration area. We recently drilled three wells to the Ratcliffe formation in the target Red Bank area.

The first of these, the 11-31H Riddle, has been completed and is currently producing at 173 barrels of oil per day. The second and third wells, the 11-5H Briske and the 11-34H Piccard(?), are in the process of being completed. Both had good hydrocarbon shows while drilling. In the Red Bank extension area, we recognized the potential in the Bakken as well as in the Ratcliffe formations that could mean up to 140 locations for the company. We recently reached total depth and began testing two Ratcliffe wells. The 44-19 Miller is being completed having had good shows while drilling, the second test well, the 44-15 Ericsson, has been completed and is in the early stages of testing, and is currently pumping water. It is not atypical to see significant volumes of water in this area prior to oil cut.

Now just a quick note about Williston differentials. In the past, the company has typically sold its oil to various parties and is paid based upon the (Cope Debbie?) pricing, which is about a $3.20 deduct. Currently, our contracts moved to a month to month and are calculated using Nymex pricing less the deduction. In April and May our stated deduct was about $7.50. The contract changes and increased deducts are the result of the inflow of Canadian oil and transportation constraints from the basins that are being addressed by the various pipeline companies. These factors are expected to continue for the long term. We have not yet had any constraints selling our oil production from the Williston.

For the last part of my discussion, I would like to bring you up to date on a number of our other high-potential exploration programs. As I've said before, we have one of the richest and most diverse exploration portfolios in the Rocky mountain region. Compared to 2005, this year should prove to be our most robust and aggressive exploration program to date. We are on track to test 16 different exploration projects in 2006, nearly twice what we did in 2005. Starting in Tri-State in the eastern Denver basin, we established production from seven Niobrara wells drilled in 2005 in the first prospect, where we own a 50% working interest. On a combined basis, these wells are currently producing a gross 206 DMCF/D(?). We will need sustained production data to better understand the potential of these wells but we are encouraged at the results to date. Because of the shallow nature of the Niobrara formation at depths of around 1,800 feet, well costs are relatively inexpensive and are economic at the current producing volumes.

We recently acquired a total of 62 square miles of 3D seismic in four separate survey areas. Preliminary results implied significant areas of gas saturation on parts of these surveys. We plan to drill up to 26 Niobrara wells in 2006. This play has a net end risk potential upside for the company of 300-400 BCFE. Another large exploration project that we will evaluate in 2006 is in the Paradox basin in Colorado. Let me interject here that it is one of our objectives, at Bill Barrett Corporation, to be a leader in shale gas plays in the Rocky Mountain region. We are in the process of (inaudible) more drill sites in our Yellowjacket shale gas project for exploration activity in late 2006 and early 2007. Our objective in this area is to obtain a 45% joint venture partner and evaluate the shale gas potential from the fractured gothic shale at depths of 5,500 to 7,500 feet. Shale gas plays, as you know, can be widespread resource plays. We currently have over 96,000 net acres under lease in this prospect and still growing. Conservatively, this play has a gross unrisked upside of 500 B/TCF(?)

Further to the north, in the Montana overthrust are, our Circus project is emerging as a major structural exploration position for our company. With over 200,000 net patigulus(?) undeveloped acres. We are in the process of interpreting 68 square miles of 3D seismic that we recently acquired. We are extremely excited with initial interpretations that may show several large four-way structural closures. We plan to acquire an additional 90+ square miles of 3D seismic once weather conditions allow. We may bring in a partner to jointly explore in the area and plan to drill two exploratory wells in late Q4 or in Q1 2007. Several established thrust plays north and south of Circus in the southern Canada area and also down in Wyoming have produced multiple TCF. We're going after the same type of potential here in our Circus project. Just to the south east in the Big Horn Basin in north central Wyoming, we will be testing an unconventional basin-centered gas concept. Again, we recognize large-scale multiple TCF potential in this play.

We have assembled over 155,000 net undeveloped acres in this area. In Q3 2006 we plan to re-enter our Sellers Draw #1 well which has produced over three BCF out of the deep Muddy formation and recomplete that well (up whole?) in the overpressured Mesaverde formation. We believe that Sellers Draw well is located on a substantial deep-seated structure which we plan to delineate with the new 42 square mile 3D survey this summer. Additional plans in the Big Horn call for one exploratory test in late 2006, early 2007, in our Redpoint(?) prospect area further to the north.

We've given you a significant amount of information here about our core development and exploration basin and we look to continue the momentum of production growth that we have achieved since going public 1.5 years ago. We also recognize the need for capital discipline to ensure we maintain liquidity and conservative balance sheets. Excluding the CH4 acquisition price, our approved net capital budget for 2006 is $350 million. Our budget is net of proceeds that we expect to collect through the year from joint venture participants in various exploratory projects. We will carefully evaluate our activities and our 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.

We will also opportunistically add hedges for 2007 and 2008 production. We currently believe we may spend approximately $15-25 million less than the $350 million budget without sacrificing production growth in 2006 and continuing our exploration program. The reduction comes from increased expected proceeds from joint exploration programs and slight reduction in the Piceance, Williston and One River development programs. Our budget strategy also allows us to expose our investors to numerous large-scale, high-impact exploration programs this year, some of which as you heard today already look very encouraging. I would like to close by reiterating that we are very pleased with our execution and results of Q1. Production growth, increased guidance, exploration success and a strategic acquisition are a great way to start the year, and we look forward to continuing its momentum throughout the year. Thank you and I'll turn it over to the operator.

Questions and Answers

Operator

Operator instructions. Your first question comes from Jeff Robertson with Lehman Brothers.

Q - Jeffrey Robertson, Lehman Brothers

Thanks. Fred, or Tom, can you talk about the natural declines that you all are building in to your production outlook? It looks like the midpoint of full year - or it looks like the full year guidance is about 127-136 million a day. Are you building in some conservatism with the existing wells and also can you talk a little about how you're modeling contribution from new wells that you may be drilling over the course of the year?

A - Fredrick Barrett

I'll jump in there. I think if you look at our production guidance, our revised production guidance, and you look at that on a full year basis, we take into consideration a number of factors, including what we believe are the correct types of declines associated with these wells. The reason that it's a little bit of a difficult question to answer is because we're producing from five different regions, all of which have five different types of declines. As the Piceance starts out at 60-80% decline, and then after a year or so falls into a much lower decline in the 10-15% range, it's typical hyperbolic (tight gas sand decline?), the West Tavaputs decline a little bit differently, they're more linear, although they do have a hyperbolic shape to them. Our deep Cave Gulch area, where we're producing out of the Muddy, those are a little bit like the Gulf Coast, where we're seeing tremendous rates come out of those wells, in overpressured environment with significant declines during the first seven years. Of course, the Powder River Basin, as you're well aware, has to go through the de-watering phase for about 12-18 months in the Powder River Basin, then within capping those out, we think anywhere from 200-300 MCFE for about 12-18 months. Then those begin declining. Then you have horizontal oil production up in the Williston. So when we put together our decline program and we come up with a resulting forecast for the year, there's a large number of factors that go into that. We also risk our production to a certain extent by about 3-6% on a per-well basis. But right now, we have a lot of flushed production coming out of Q4 2005 and Q1 2006 with a lot of depleted(?) wells, but we think we have a pretty good handle on what each area has in terms of the type well curve. Does that answer your question?

Q - Jeffrey Robertson, Lehman Brothers

Kind of. It looks like, Fred, in Q1, you all outperformed your estimates so I want to know is it fair to say that maybe the declines built in, at least in Q1, turned out to be a little bit more conservative than they should have been?

A - Fredrick Barrett

Well, when will built our forecast in Q1, we were actually right on a curve. What happened there was the flushed production out of Q4 and the flushed production in Q1 that we had there, particularly out of the West Tavaputs area, as we continued through February we learned that that was actually still on an incline, even though we were done completing a number of the wells. We were somewhat constrained by the compression in that area. We had a little bit of a similar type situation in the Piceance area, where as we continued to add compression we continued to see a bump-up in production and so once we made it through March and we made it into April, it became very apparent that those forecasts as related to the flushed production and our compression and capacity situation in the Piceance and the West Tavaputs, that we were a little conservative on that compared to what we were seeing in April.

Q - Jeffrey Robertson, Lehman Brothers

Two other questions. At Lake Canyon, Fred, with the 75% interest, is that subject to the 25% I guess back in the reversion, for the Utes, so it could be reduced to 56% if they decide to start participating?

A - Fredrick Barrett

Let me explain what's going on there. In the Lake Canyon area, the Utes have the right to participate for their 25% working interest and can make that election on the first two wells, within what, on average is about a 2,500 or so acre drilling block in there. If they don't elect to participate by the time the second well is being drilled, then they're essentially out of that block. In this particular case, the Utes did not elect to participate in our first DLB #1 well. If we drill a second well in here which is highly likely, they do have the option to participate for their 25% working interest.

Q - Jeffrey Robertson, Lehman Brothers

So it's basically a drilling unit that you put together and they're either in or out?

A - Fredrick Barrett

Right. Remember, you're looking at a very large area here. We have about 229,000 gross acres in the Lake Canyon area and as I mentioned, on average, these drilling blocks will average somewhere in the order of 2,500-2,600 acres. So there's a number of areas that we're going to plan on drilling that would eventually define distinct drilling blocks, roughly of that size. The Utes know what we're doing, it's almost like a plan in development that we pursue as we continue to drill on the Lake Canyon acreage block and then they would have - as I mentioned - they make the elections whether or not they're going to participate in the first and or the second well in those distinct and individual blocks. As I mentioned, in this case, they did not elect to participate in DLB #1 well. They may elect to participate in an offset to that well. They did, however, participate… let me back up here. When they do participate in the zones that Barrett is operating, the Wasatch and the Mesaverde, our working interest then reverts back to a 56.25% working interest. So in essence, when you look at the deep and intermediate program in Lake Canyon, which we operate, the Wasatch and the Mesaverde, we have in general a working interest that ranges from 56.25% to 75% working interest. In the shallow formation, where Berry operate, again our working interest is pro-rated back as it related to the Ute participation. We have a working interest range of 18.75-25% working interest. They elected to participate in the first two shallow wells in the Lake Canyon area and therefore, our working interest in the shallow is about 18.75%.

Q - Jeffrey Robertson, Lehman Brothers

OK. And lastly, in the Piceance Basin, you talked about optimizing completion. Is that a matter of just being a lot more careful, picking the zones? Or is it a combination of a little bit different crack technique.

A - Fredrick Barrett

It really is a combination of things. When you look at the Piceance, there's really two phases that we've gone through, we've gone through one phase and we're in the middle of the second phase, put it that way. The first phase was optimizing how we crack these wells, the fluids that we were using and the amount of sand that we were using. We think we've got that down. We have done quite a bit of production logging in the Piceance area. We've identified what we believe are the zones where we know your best production is coming from. In combination with increasing the crack sizes, the amount of profit volumes as well as the fluid volumes, in addition to having drilled 80 wells during the 2005 season, we now have a better understanding of where some of the sweet spots are and so, as we're drilling right now, we've drilled about 26 wells to date during 2006. A lot of our focus is on those higher return areas. So both optimizations from a completion standpoint and where we're putting the drill bit, I think is what really defines and explains why we're seeing a lot better production rates coming out of the Piceance Basin.

Q - Jeffrey Robertson, Lehman Brothers

Thank you, Fred.

Operator

Your next question comes from David Tameron with Jefferies & Co.

Q - David Tameron, Jefferies & Co.

Good afternoon, Fred. Congratulations on a great quarter. I'm headed back to Lake Canyon. I know in your preferred remarks you said you didn't want to discuss it, but have you guys publicly said what the well costs are? I know the shallow formations are more like, I guess Berry was calling it a tight oil, can you give us a little color on what you expect the production profile to look like and what your well costs are running out there? Or what your targeted well costs are?

A - Fredrick Barrett

It's going to be limited as to what I can give you. Berry has their costs, and I'll let you hang your hat on what Berry has given out in terms of information, but the types of wells based on the production that we're seeing out of, for example, our DLB #1 well, we're continuing to drill those types of wells - they would be anywhere from $1.8-2 million type wells for drilling and complete.

Q - David R. Tameron, Jefferies & Co.

OK. And the typical Wasatch-type decline profile? Is that…

A - Fredrick Barrett

You know, right now we can't disclose that type of information. We only have about 2.5-3 weeks of production information and so once we get our arms around that we'll disclose that information.

Q - David R. Tameron, Jefferies & Co.

OK. Fair enough. We get impatient on this side of the phone, as you know.

A - Fredrick Barrett

Yes.

Q - David R. Tameron, Jefferies & Co.

Going up to the Williston, stepping back from your operations, what's your overall take on the play? I mean, everybody's up there, the core obviously works, but people trying to extend it etc. Can you talk a little bit about what you got up there?

A - Fredrick Barrett

I suspect you're talking about the Bakken play up in Williston. I think the Bakken play, whether you're in the core 'heart of a sleeping giant' trend or outside the trend, when you look at the amount of oil that's in place in the Williston basin, it's a giant play. I think as you step out away from the core trend of sleeping giant, granted, we haven't seen the types of rates that you see in that trend, nonetheless for example the well that Tri-C(?) drilled adjacent to our Red Bank extension area, you know, that drilled 9,000 feet of lateral in the Bakken and during the first 2-3 weeks of production they were producing 200-300 barrels of oil per day. We think that that trend actually builds and develops in thickness and reservoir content. I don't think there's enough drilling yet and enough information to say that, you know, the rest of the Bakken play does not work. In fact, I would suspect if there's - and this is just my own geologic opinion - that there's a significant Bakken play to be made outside the sleeping giant area and that's what Bill Barrett Corporation is working on right now. We've built a number of significant positions in that play, we have established wells that - we know of wells that have good, solid production rates coming out of the Bakken in those areas. But there needs to be a lot more drilling to determine exactly what we've got there.

Q - David R. Tameron, Jefferies & Co.

OK. I take it you're talking about up to the north west orb of the sleeping giant?

A - Fredrick Barrett

Exactly, yes. We're kind of north of sleeping giant. We have some positions along sleeping giant in our Mondak area that we'll be drilling on here later in the year, but there's a number of trends that develop as more of a (inaudible) that we're looking at there, north of sleeping giant but that’s where I'm talking about.

Q - David R. Tameron, Jefferies & Co.

OK. One last question and I'll let somebody else jump on. Maybe I missed it, did you talk about Circus at all?

A - Fredrick Barrett

Yes I did.

Q - David R. Tameron, Jefferies & Co.

I guess, since I didn't hear it, could you recap what you said about it?

A - Fredrick Barrett

Sure. Our Circus play, located up in the Montana overthrust, we have posted 200,000 net acres that we've put together in that area. It's become a very large structural exploration play for us. We control the area, basically, and we're targeting very large-scale north-south trending structural features, similar to what they find up in the Canadian overthrust and also down in the Wyoming overthrust. We also are looking at key older wells that were drilled in there that have live oil, live gas shows, but do not have the benefit of modern day 3D seismic technology to guide where they're drilling. We've recently shot about 65 square miles in here. We're very encouraged by the anomalies that we're seeing and the 3D survey. In fact, we can see why some of the wells did what they did on these surveys and we're going to follow that up as we move through the summer, with about another 95 or so square miles of 3D survey as the weather permits us to do so.

Once we finish that up, which should be by late Q3 this year, we will then commence to drill at least one well by year end and drill at least another well probably during Q1 2007.

Q - David R. Tameron, Jefferies & Co.

OK. And are you still on acreage in Hingeline?

A - Fredrick Barrett

We do have acreage in Hingeline.

Q - David R. Tameron, Jefferies & Co.

My understanding was you were adding to that position. Are you still adding acreage there?

A - Fredrick Barrett

Yes, it's been a little bit slower than up in the Circus area, but that is a bona fide project. We're still currently assessing what we're going to do with that.

Q - David R. Tameron, Jefferies & Co.

All right. I'll jump off. Thanks, I appreciate it.

Operator

You have a follow up question from Jeff Robertson with Lehman Brothers.

Q - Jeffrey Robertson, Lehman Brothers

Fred, can you talk a little about the oil quality you're seeing on that deep Lake Canyon discovery?

A - Fredrick Barrett

You know, we can't, there's a certain amount of information here that we right now believe is proprietary to our company, for various and sundry reasons. We're electing not to disclose that information at this point in time.

Q - Jeffrey Robertson, Lehman Brothers

OK. Thank you.

Operator

At this time, there are no further questions. Gentlemen, are there any closing remarks?

William Crawford

Thank you all for participating in our Q1 conference call. As I mentioned earlier, we are filing a form 10-Q with the SEC today. I encourage you to read it for a more complete review of our Q1 2006 results. I would also like to mention that our annual shareholder meeting is scheduled for Wednesday, May 17th, at 9.30 AM mountain daylight time, in Denver. The meeting and subsequent company overview will be webcast and posted on our website, www.billbarrettcorp.com, at that time. This concludes our conference call. Thanks.

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