Bill Barrett Q2 2006 Earnings Conference Call Transcript (BBG)

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Bill Barrett (NYSE:BBG)

Q2 2006 Earnings Conference Call

August 8th, 2006 4.30 pm EST

Executives:

William Crawford, Manager, Investor Relations

Fredrick Barrett, Chairman, Chief Executive, President

Thomas Tyree, Jr., Chief Financial Officer

Joe Jaggers, Chief Operating Officer, President

Terry Barrett, Senior Vice President – Exploration, Northern Division

Kurt Reinecke, Senior Vice President – Exploration, Southern Division

Lynn Boone Henry, Vice President – Reservoir Engineering

Analysts:

Larry Busnardo, Petrie Parkman

Brian Singer, Goldman Sachs

Jeffrey Robertson, Lehman Brothers

Eric Hagen, First Albaney Corp.

Robert Lind(?)

Leonard Benedetto, Howard Weil Inc

Operator

Good afternoon. My name is Christie, and I will be your conference operator today. At this time I would like to welcome everyone to the Bill Barrett Corporation Q2 2006 conference call. Operator instructions. Mr. Crawford, you may begin your conference.

William Crawford, Manager, Investor Relations

Thank you, Kristie. Good afternoon and welcome to Bill Barrett Corporation's conference call to review Q2 2006 financial results, and to update our current operating activity. My name is Bill Crawford, Manager of Investor Relations. With me today are Fred Barrett, Chairman, and Chief Executive Officer, Joe Jaggers, Chief Operating Officer and President, Tom Tyree, Chief Financial Officer, 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 Q2.

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 Q2 is also being filed with the SEC this afternoon. Following the financial review, Fred will provide an operational update and outlook for the remainder of 2006. We expect these discussions to last about 30 minutes, and as Kristie said, we’ll follow with a question and answer session.

Before we begin, 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, transportation, processing, 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. Tom?

Thomas Tyree, Jr., Chief Financial Officer

Thanks very much, Bill, and good afternoon everyone. We are again pleased to report strong results for Q2 2006. We met our production forecast, despite third party pipeline curtailments. We closed a strategic acquisition in the Powder River Basin, we continued executing our active exploration program with another success in the Wind River Basin and we added a key member to our management team, our COO and President, Joe Jaggers. In Q2, Bill Barrett Corporation produced an average of 134 million cubic feet equivalent per day. That represents 42% growth over Q2 2005 but an 8% reduction from our record Q1 2006 production, due to natural declines and curtailments. Our decline in Q2 was consistent with our guidance, as we have come off strong plus production in late 2005 and early 2006, from several key exploration successes in our Piceance and West Tavaputs new drills. Furthermore we were curtailed by 0.5 BCFE during the quarter, which Fred will expand on later in his discussion. I would note, however, that this curtailment came during a period of relatively low gas prices, so the NPV(?) impact of deferring that production is minimal to the company. With all of that said, we are still on track to meet our 2006 production guidance of 46.5-49.5 BCFE.

For the quarter, we realized an average price of $6.42 per MCFE produced, and we generated $51.6 million in cash flow, or $1.17 per share. Net income was $8.2 million, or $0.19 per diluted share. Our cash operating costs in Q2 were $2.04 per MCFE. That’s an increase of $0.07 per MCFE from Q1 2006, and primarily relates to higher LOE due to water handling expenses, combined with flat gathering and G&A costs on lower production volumes. These expenses were partially offset by a decrease in production taxes due to lower realized prices. Some of the water handling costs were up front expenditures that will benefit future production and we expect to see improvement beginning in Q3. Natural gas prices have softened significantly this year. We responded by adding hedges at opportunistic spikes in prices and by streamlining our planned 2006 capex. This should allow us to maintain excellent financial flexibility. Our capex totaled nearly $281 million for H1 2006, including $80 million from the CH4 acquisition. This does not include the nearly $41 million of non-cash deferred tax liability associated with the acquisition. Our 2006 capital budget is $350 million, excluding the CH4 acquisition, but we expect to spend approximately 5-10% less than our budget as we streamline our capital in our efforts to more closely align our cash flow and capex flat levels.

As a reminder, our capital budget is net of proceeds received from joint exploration programs. We are in final negotiations to receive $60 million in proceeds in 2006, of which only $7 million were received in H1. We ended Q2 with $205 million outstanding under our revolving credit facility. That is our current level of total debt as well. Our bank line has a total of $280 million in borrowing capacity and we expect this to increase over the next few weeks as our borrowing base is re-determined. We continue to be committed to maintaining a conservative balance sheet that provides us with flexibility and liquidity. We review longer-term financing alternatives as a matter of course, but given the reasonably strong commodity price outlook, our current hedge volumes and our existing bank capacity, we have sufficient availability under our bank lines to finance our capital requirements through 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 our company operations. Fred?

Fred Barrett, Chairman

Thank you, Tom, and thank you all for joining us today. Before I begin our operational update, I am pleased to introduce Joe Jaggers, our new Chief Operating Officer and President. He brings 25 years of operational experience to the company, his executive level of operational experience with Amoco, BP, Barrett Resources and the Williams Companies will be extremely valuable as the company grows and evolves. Joe Jaggers emulates our commitment to operational excellence and strategic value creation here in the Rocky Mountain region. On behalf of our Board of Directors and the company, we welcome you aboard.

Let me begin by saying I couldn’t be more pleased with the exploration and development performance we’ve achieved thus far in 2006. From a development standpoint, we are well underway to accomplishing a very successful program. Our Piceance Gibson Gulch area from a production standpoint is at an all-time high and even though we have been curtailed at West Tavaputs, we are poised for significant production ramp up there with new wells, new compressions and new third party processing facilities as we move through into Q3. From an exploration standpoint, we are one of, if not the, most active company this year for pursuing the vast Rocky Mountain resource base via the drill bit and I couldn’t be more encouraged with the results thus far. By successfully completing the Lakota and the Bullfrog 33-19, we are announcing exploration success in our fourth consecutive conference call, quite a track record, making this our second discovery this year – the other being the Wasatch discovery in Lake Canyon.

Yet we have a tremendous amount of potential exploration exposure ahead of us. For instance, we are currently drilling our first steep delineation well in West Tavaputs, which will take us a little longer than anticipated. We are drilling the Cooper Deep No. 1 wildcat in the Wind River Basin, where we are seeing instant gas flares and oil at the surface from some new, unexpected zones, and we jus finished drilling three vertical wells in Tri-State and are preparing for more drilling in that area. As we move forward through the remainder of the year, we are making final preparations to drill and test additional Wasatch and Green River wells in our Lake Canyon area, as well as a new Shale gas program in our Paradox Yellowjacket area. In addition, we are also preparing for exploration drilling in our Hook and Woodside areas in the Uinta, the Big Horn Basin and our expansive surface overthrust program. In virtually all of these exploration programs, we continue to build and add additional acreage positions. Since January of this year, we have added well over 200,000 net acres across the Rocky Mountain region, bringing our total exposure to over 1.4 million net undeveloped acres. As we always say, exposure is the name of the game.

We also continue to be leaders in technology. As part of our final prospects preparation in the relentless pursuit to mitigate risk, we are one of the most active companies on the seismic technology front. We are currently acquiring data in Circus, our Montana Overthrust program, drilling seismic shock holes in the Big Horn Basin Seller’s Draw area, we recently finished and interpreted five brand new 3D surveys in the Tri-State area, we just finished a new bolt-on survey at Cave Gulch and we’re in the planning stages for new 3D surveys in our Hook and Pine Ridge areas, not to mention a few new concept areas. Also with our Lake Canyon and Gibson Gulch three-component 3Ds, we are in the final data processing phases. These 3Ds are cutting edge technology and the first of their kind in the Piceance Uinta region. As we execute these development and exploration activities, we are very cognizant of the industry challenges before us, such as volatile gas prices without softening of drilling and services costs.

As Tom mentioned, we are monitoring the situation and making the necessary adjustments by adding hedges and deferring capital to ensure that we maintain financial flexibility. Natural gas prices fell significantly from a high in December 2005 to a low in early July due to a mild winter, which reduced natural gas demand, thus creating high storage levels. Recent hot weather has increased demand over the past few weeks and gas prices have somewhat rallied, but we will have to wait and see how gas prices react due to colder months in September, October and November. August’s midweek price is $5.77 CIG and the strip is nearly $7.00 CIG for the remainder of 2006 and at least $7.50 CIG for each of 2007 and 2008. We have recently added hedges that bring the weighted average floor in 2007 and 2008 to be $6.07 and $6.50 on 64,000 and 35,000 MMBTU per day respectively. The remainder of 2006 we have approximately 55% of our natural gas protected, with the weighted average $4-5.97 Rockies price. Thus we have the capacity to continue our active explorations and development program.

Another positive factor for us here at BBG is our joint exploration programs. We are one of the few companies that continue to add significant high quality acreage positions backed by in-depth geologic and geophysical studies, with an active exploration drilling program. Thus, we are able to attract well-known companies as joint exploration partners at top dollar. We expect to raise over $60 million in value this year in our joint exploration programs. This more than offsets our costs invested this far in assembling these exploration projects. This allows us additional capital to actively pursue our diverse exploration program and mitigate our risks, yet still retain operatorship and a 50% plus working interest. What we have received and expect to receive in the next few months continues to generate beneficial results, both in the amount of proceeds and the high quality of partners. The remainder of my prepared comments, I want to bring you up to speed on recent developments in our core development and exploration programs through the Rockies, and share with our plans for the remainder of 2006. I would like to reiterate, I’m very pleased with our progress to date in our development and exploration program.

We continue to maintain an active drilling program, currently with seven conventional rigs, that are drilling in four different basins, and also five coalbed methane rigs currently drilling in the Powder River Basin. I will being our operational update discussing our recent Lakota discovery in the Bullfrog 33-19. We have a 93% working interest in this well which was drilled to a total depth of 19,432 feet, with target formations coming in structurally higher than we had anticipated. We are excited about this well as it establishes the first production in the Lakota formation in the southern portion of the Bullfrog area and helps substantiate our deep multi-state program in the area. In the 33-19, the deepest formation – the Lakota – was tested first. It had encouraging gas shows and based on logs, the reservoir appeared better developed than the Lakota in the offset well, the Bullfrog 14-18. If you recall, the 14-18 is our Muddy discovery we established in 2005. Therefore, we completed the Lakota in our 33-19 first and were encouraged by the pressures, nearly 1,500 pounds of flowing tuning pressure and are currently producing the wells at about 4 million a day on a 22-64 choke, with about 70 barrels of water per day.

Our plan is to continue to test and produce the Lakota before moving up coal to the Muddy and the Frontier which are behind pipe. Based on logs, the Muddy in the 33-19 does not appear to be as well developed as the Muddy in the 14-18. But keep in mind, the company still plans to complete the Muddy at a later date in the future. The Muddy is a channel reservoir and tends to be variable across our position and I might add that the Frontier looks exceptionally well-developed in our 33-19. We have identified at least 30 additional locations within the Cave Gulch and Bullfrog are, with deep potential in the Frontier, the Muddy and the Lakota formations. We expect to drill one to three deep wells each year over the next 10-12 years. We have acquired and processes the north extension to the Cave Gulch 3D seismic surveys and are currently interpreting this 3D with the objective of imaging the north side of the field and to better refine our deep locations in this part of the Cave Gulch area. Our other two high profile Muddy wells, the Bullfrog 14-18, our initial deep discovery well last year, and the Cave Gulch 129 recompletion well, continued to produce along their expected decline curves and are currently producing 4.2 million a day and 5.6 million a day gross respectively.

As a reminder, these wells both have Frontier potential behind the pipe and the Bullfrog 14-18 tested productive in the Lakota, which is currently behind pipe. In our Cooper Reservoir area, which lies along the Waltman Arch, south of the Cave Gulch Bullfrog area, the company is utilizing over 375 square miles of 3D seismic coverage to assess the deep potential in the same productive intervals that exist in the Cave Gulch area. We have had our first exploratory deep test, the Cooper Deep #1, and are currently drilling at around 15,660 feet. We expect to reach a planned TD of 16,265 feet in the next several weeks. We have a 50% working interest in this well and plan to test the Frontier, Muddy and Lakota formations.

Preliminary results on this well are expected to be released within the next few months. As I mentioned before, while drilling this well, we had several encouraging gas flares and oil in the pits from a zone above our targeted pay interval. We have also seen encouraging gas shows as we recently began drilling into the Frontier, the first of our target pay zones. Moving on to the Uinta, we continue to be upbeat regarding our discover of Wasatch oil production in the Number 1 BLB discovery well. The well has culmed(?) over 15,000 barrels of oil per day since coming online as a flowing oil well in mid April, and continues to produce between 100-150 barrels of oil per day. The oil is a 42 degree gravity black wax, which is a lighter crude than the typical black wax for this area. We plan to drill four additional Wasatch wells in Q4. These wells will be built to offset and step out the number one BLB. Our present interpretation suggests over 75,000 acres of prospective lease holds where we control between 56-75% working interest.

Nearby fields, such as the giant Altamont-Bluebell complex, producing from the Wasatch are developed on 320 acre well spacing and individual wells producing anywhere from 100,000 to over 300,000 barrels of oil. So you can see, the company has tremendous development potential from this key Wasatch oil discovery. As a reminder, we also have between an 18-25% working interest in the shallower Green River formation, the original two discovery wells completed in mid-December 2005 continue to produce at a combined rate of over 160 barrels of oil equivalent per day. Drilling has begun on the six Green River offset wells, or step out wells, that are planned for the remainder of 2006. Our optimism remains extremely high for the West Tavaputs project, where we generally control 100% working interests here in the Uinta Basin. We continue on our timeline for completion of our environmental impact statement in late 2007 or early 2008. Currently we have two shallow rigs and one deep rig drilling in the field. We expect to drill 24 shallow and two deep wells this year. We have spud 17 shallow and one deep well thus far and have been very encouraged with the completions and the gas shows to date.

We’ve produced a net 32 million a day in West Tavaputs in Q2, under a mandated curtailment from a third party gas processor because of unexpected delays in the final construction of a facility to handle natural gas liquids. We estimate that our production in the West Tavaputs would have been approximately 0.5 BCF higher for this period had we not been curtailed. We have been informed by the third party that they will complete the upgrade by August 15th, which will alleviate the current curtailment. With our successful 2006 development program, and additional compression which is currently being installed, we will have a gross 70 million per day of capacity from West Tavaputs by late Q3 or early Q4. We have identified over 150 locations on 160 acre spacing in the shallower zone in West Tavaputs. Many fields in the area have been developed on 80s and then on 40s. We will have one 80-acre pilot this year and look to test 40s in the future. If successful, we recognize over 500 locations on 40-acre spacing targeting the Mesa Verde, North Horn and Wasatch formations. The Peter’s Point 6-7b, our successful 2005 deep discovery test, continues to produce the longest expected decline curve at nearly 5 million per day as of the end of July. As a reminder, we have identified over 20 160-acre locations on the seismically defined Peter’s Point closure, which is the eastern structure surrounding this well.

In 2006, we plan to drill two deep Peter’s Point locations. The first well, the 4-12, reached a total depth of 15,542 feet and had very encouraging gas shows in the Navajo sandstone, the primary pay. But before completion casing could be run, we encountered mechanical difficulties. Operationally, our best solution is to plug back and sidetrack the well bore, which is what we’re doing. We expect the re-drill to take 30-45 days before we can test and complete the well, and expect to report results from this well over the next few months. On a positive note, in addition to the gas shows through our primary targets, we now know we are structurally high to our original prognosis for this well. On the exploration front, in the Uinta we continue to build acreage in our Hook and Woodside areas. At Hook, we expect to bring in a partner for the rest of this year and then drill two shale gas tests early next year. At Woodside, we plan to drill a 6,500 foot well targeting the Pennsylvanian(?) sandstones on the seismically defined structural closure, either late in 2006 or early 2007.

The Woodside well will essentially resume(?) a well drilled in 1962 that reported gas shows in the target formation. Moving on to the Piceance in north west Colorado, we currently have two rigs operating in our Gibson Gulch area. We produced nearly 38 million a day net in Q2. In July we produced nearly the same. Our well performance continues to improve due to the fine-tuning of our completion practices. We consistently have 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 is a competitive area for drilling rigs and field services. As a result, our pre-well drill and completion costs are approaching $2 million. At these costs, compared to current commodity prices, we are being highly selective in the well locations that we choose and are modifying our drill schedules accordingly. Our program for the remainder of 2006 and into 2007 has high graded locations that we plan to drill (inaudible) to return in excess of our cost capital at gas prices of $6, the approximate level at which we are pitched.

We hope to be using our three component 3D by Q4 to further enhance our location selection. Currently we plan to exit 2006 with one rig operating in the field, and are currently evaluating our activity levels for 2007. The Piceance is an important area for the company because it has significant gas in place and provides a valuable area for low-risk, year round drilling. However, since the Piceance is the focus of several M&A transactions, oil prices being paid are occurring at an equivalent rate of nearly 41,000 per acre. The company is evaluating the merits of divesting some of its selective non-core acreage outside the core Gibson Gulch area.

Moving now to our CBM operations in the Powder River Basin where we have been extremely actively enhancing our position, we divest our share of (Long Horn?) position in the basin, we acquired CH4 and did announce plans to divest several of those properties to Storm Cat. We have become one of the top 10 producers in the basin and a major player in the Big George fairway. We are focusing our efforts in development on the giant emerging Big George play. As such an opportunity arose to divest of 17,000 net acres outside the Big George fairway, with Wyodack and other cold targets to Storm Cat for $30.7 million. These properties were located in the northern portion of the basin and sit well with Storm Cat’s position. We view this as a win/win for both companies. We will divest an estimated seven BCFE of proved reserves that are currently producing about 3 million per day net. The effective date is set for July 1, we expect to close by the end of Q3. In 2006, we plan to drill 259 with a total capital budget of about $30 million, excluding the acquisition price for CH4.

The integration of CH4 is going well. We have been actively drilling in the Hartzog Draw area over the last few months and have nearly completed our 2006 program there. Many of the wells recently drilled and hooked up in Hartzog are already seeing early gas production with overall production from the area ramping up nicely. Our plans this year also include drilling the Big George and our Cat Creek, Pumpkin Creek, Deadhorse and Palm Tree areas. We view the CBM development play as a low-risk portion of our portfolio. CBM gives us our best rates of return on our incremental drilling dollars. We have a four to five 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, where we have been actively drilling over the last few months, we have been pleased with our development in Red Bank and Target. However, we have not yet shown production in the exploratory programs at Red Bank extension from the Ratcliffe or the Grand River from the Red River B formation. Our two most recently completed development wells, the 11-5H Briske and the 11-34H Piccard to the Ratcliffe formation in the target Red Bank area are in a process of cleaning up and had good oil shows and have had variable test rates of up to 170 barrels of oil per day. In Q2, in the exploratory Red Bank extension area, we did report dry hole expenses of $2.9 million to date, for the 44-15 Ericsson, which was plugged and abandoned and the 44-19 Miller, which is currently still pumping water without any oil shows. These wells were drilled to the Ratcliffe. We have a 50% working interest in the area and we recognize both the Bakken and Ratcliffe potential. We do plan to drill a Bakken test in 2007 based on the results of the successful wild drill by Tri-C last year.

At Grand River, we recently finished drilling our second exploration well, the 14-19 (Birch Trust?) which is currently testing. This well had good shows while drilling but is recovering formation water with a small gas flare. At Indian Hill West, we are in the process of completing our exploratory test to the Ratcliffe, the 44-35 Schmidt. At Red Water, the (Macrae?) 11-27 well has had encouraging oil shows from the Bakken in parts of the well bore, but has encountered water production attributable to a small fault encountered in the later that has restricted oil flow. We are attempting to seal off the fault area.

Just a quick update on Williston differentials: we still have not yet had any constraints selling our oil production from the Williston and continue to sell month to month. In May, it was (Nymex west of 50?), although recently it has improved to (Nymex west about $5?). 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 have said before, we have one of the richest and most diverse exploration portfolios in the Rocky Mountain region. Starting in Tri-State in the Eastern Denver Basin, we’ve established four horizontal and six vertical Niobrara wells in the Ferry Star Prospect where we own 50% working interest. On a combined basis, these wells are currently producing a gross 190 MCFD after six months of production. We recently acquired a total of 62 square miles of 3D seismic in four separate survey areas. Preliminary results imply significant areas of gas factoration across these areas. Put another way, a large portion of our 506,000 gross acres lie within a region where we now, based on our 2D and 3D seismic, recognize a significant shallow gas deposit in the Niobrara formation. We liken this play to a CBM play without the dewatering phase. We plan to drill up to 30 Niobrara wells in 2006 with working interests ranging from 10-50%. Some of these wells are planned to be horizontal because preliminary results from our Furry Star horizontal well indicate enhanced economic returns over vertical wells.

This play has a net and potential upside for the company of 300-400 BCF. The potential shale gas plays are another core focus for us because this kind of resource play can be widespread and repeatable. We recognize significant potential in several key areas of the Rockies and have already built large positions on some, such as the Hook area in the Uinta and at the Yellowjacket area in the Paradox Basin. We have assembled nearly 100,000 acres at Yellowjacket and are in the process of finalizing the sale of 45% working interest to a well-known industry partner. We are currently staking eight locations for depths of 5,500 to 7,500 feet and two of these locations will be drilled during Q4. Extensive coring and geologic evaluations will be performed on these initial wells with test results not being known until some time during H1 2007. Conservatively this play has a gross unrisked upside of 0.5-1 TCF. Further to the north, in the Montana overthrust area, our Circus project is emerging as a major structural exploration position for a company with over 234,000 gross undeveloped acres. We can continue interpreting 68 square miles of 3D seismic that we acquired last year and are extremely excited with the initial interpretations showing the potential for several large four-way structural exposures.

We are currently acquiring an additional 109 square miles of 3D seismic that should be completed by the end of Q3, processing and interpretation will then take an additional several months. We plan to spud our first exploratory tests in Circus, utilizing our 3D seismic, in early 2007. We recently sold a 50% working interest in Circus to a well-respected industry partner for cash and property in the Powder River Basin. Several established thrust plays north and south of Circus in the Canadian and Wyoming thrust belts have produced multiple TCFs. We’re going after the same general formations and type of potential here in our Circus project. Moving to the Big Horn Basin in North Central Wyoming, we’ll be testing an unconventional Basin-centered gas concept. Again, we recognize large-scale multi-TCF potential in this play. We have assembled over 159,000 net undeveloped acres in this area and we are in the process of selling a 25% interest to one party, and plan to sell an additional 25% interest to another partner in the next few months. After completing the sales process, we plan to re-enter our Seller’s Draw #1 well, which has produced over three BCFs out of the deep Muddy formation and then recomplete that well in the over-pressured Mesa Verde formation.

We believe that the Seller’s Draw well is located on a substantial deep-seated structure, which we plan to delineate with a new 42-square-mile 3D survey. We are currently drilling shot holes for this survey and expect to begin acquiring data in late August. We have given you a significant amount of information here about our core developments and exploration basins and we look to continue the momentum of production growth that we have achieved since inception. I would like to close by reiterating that we are very pleased with our execution and the results of H1 2006. Production growth, increased guidance, two new exploration discoveries, key additions to management and a strategic acquisition are a great way to start the year and we look forward to continuing this momentum throughout the year.

Thank you, and I’ll turn it over to the operator for questions.

Questions and Answers

Operator

Operator instructions. Your first question comes from Larry Busnardo.

Q – Larry Busnardo, Petrie Parkman

Good afternoon. You know, up in the Bullfrog area, looking at the 33-19 well and with the Muddy not being as well developed as you found in the first well, how is that going to change your drilling plans going forward in terms of what you’re targeting, and also, what will your activity level be there for the remainder of this year?

A – Fredrick Barrett

Great question. The Muddy formation in the Bullfrog 14-18 as I mentioned was less developed – let’s put it that way – than what we saw in the 14-18. And what I perceive there, Larry, the Muddy developed real nicely in certain areas and then it becomes less developed and more ratty in other areas. But because it’s less developed doesn’t necessarily mean that it’s non-productive. There’s a number of good well examples, our Cave Gulch number 16, the (TB Flats?) number 16-1, as well as a number of other wells that have been completed in less developed Muddy zones and we’ve seen EURs come out of those wells in the 2-3 BCFE range. So to that end, we will definitely complete the Muddy in this well. The nice thing about this program is that it is a deep, multi-pay program. We have built into our program right now, as we move out over the next three to five years, a number of locations that target specifically the Frontier formation. The Frontier formation is very widespread across this area. It’s highly over pressured. We believe we can average three to five BCFE out of the Frontier formation. We think on average, we’ll be able to have at least two producers per well bore out of the three zones in this area. Along the way, what you hope to do is run into a well that’s going to give you 20-30 BCFE on a per-well basis. But on average, we think that by the time we’re done with this program, where we believe we have 25-30 deep locations, we believe we’re going to be able to, on average, see 6-9 BCFs on a per well basis. And so, we’re going to continue drilling on an annual basis. For the rest of this year we are currently drilling with the same rig at the Cooper Deep #1. We will likely spud another deep Cave Gulch Bullfrog test, probably some time in 2007 but we do not have plans to do so this year. We are recently finishing up the 3D program on the north side, on the back side of Cave Gulch and we wanted to get that done before we finalized any further locations. We should have than done, processed and interpreted probably by the end of September and into October. At which point, we’ll begin making our 2007 plans.

Q – Larry Busnardo, Petrie Parkman

Okay, so the next well wasn’t planned for this year initially?

A - Fredrick Barrett

Yes, originally, you know, we had a contingency budget. We say in our script that you know, we’re streamlining our capital budget, we’re decreasing by 5-10%. Part of that stems from an original contingency budget that we had earlier in the year. Part of that contingency budget had additional potential deep wells in Cave Gulch, additional wells in the Williston, potential ramp up in the Piceance – we’ve elected not to do that at this point in time. We will likely continue with those programs in 2007.

Q – Larry Busnardo, Petrie Parkman

I guess the seismic also helps you pick a better location as well on the next one, where you can put it in a more optimal spot within the field?

A - Fredrick Barrett

Yes. You know, we have a number of locations we know we can go to right now. But we wanted, because of the discovery in the Lakota formation, we wanted to see what this well was going to do and also get that well integrated into the 3D, look at the Lakota versus the Muddy versus the Frontier and each well you drill out there, you want to be absolutely sure where you’re putting the drill bit. So we’re being very, very cognizant of the deeper risks associated with this play. Each location we drill, we want it to be somewhat of a slam dunk and so we’re taking a little bit of our time here in picking the next location.

Q – Larry Busnardo, Petrie Parkman

Okay. In terms of the capital budget, if I understand it correctly, the budget was net of any proceeds received for any other prospects. Correct?

A - Fredrick Barrett

That’s correct.

Q – Larry Busnardo, Petrie Parkman

So if you were originally targeting $350 million and you’re somewhere now in let’s say the $330 million range, actual spending for the year would be closer to $400 million. Is that correct?

A - Fredrick Barrett

Well, approximately, yes.

Q – Larry Busnardo, Petrie Parkman

All I’m doing is taking the 330 plus you know, the $60 million that you expect. Now, how does that say 400 – let’s just call it $400 million – how does that relate back to what you were initially planning on spending? Is there a reduction? Is the reduction 10-15% off that amount there?

A - Fredrick Barrett

Well, if you look – there’s not a real material change in the number of wells that we drilled this year, Larry. If you look at the Piceance, we say that we’re, you know, we’re going down to one rig by Q4 this year. If you compare that to where we originally were at the beginning of the year, we’re only reducing the Piceance by say, you know, six or seven wells. There’s a couple of other minor changes across some of the other assets, but it’s not a real material impact or change compared to what we originally planned.

Q – Larry Busnardo, Petrie Parkman

Okay. That’s it for now. I’ll jump back in if I have something else. Thanks.

Operator Your next question comes from Brian Singer.

Q – Brian Singer, Goldman Sachs

Thank you very much, good afternoon. Just following up on a previous question, with regards to the Bullfrog 33-19, what do you expect that you’ll recover from the Lakota formation at this point? And therefore, I guess, what would you then need from the Frontier to get into that 6-9 BCF window? And could you also talk about your expected well costs there?

A - Fredrick Barrett

We’re not disclosing yet what we think the reserve levels on the Lakota are going to be at this point, Brian, but you know, we think on average you know, any given deep well – and this well isn’t any different – when you look at the total population of wells in the Bullfrog and Cave Gulch areas, statistically a good way to look at it is that we think you can average 2-3 BCF in a Lakota, you can average anywhere from 3-7 or 8 BCF in the Muddy formation and you can average 3-4 BCF in the Frontier formation. We have several very good looking zones in the Frontier formation. They’re exceptionally well developed, we’re not going to disclose what we think we’re going to get reserve-wise there. The big question is what are you going to end up getting out of the Muddy, I think, in order to answer that question. But right now, I think I’ll kind of answer that question again with what our statistical information tells us, and that is that by the time we’re done with this program, we think we can average 6-8 BCF on a pre-well basis.

Q – Brian Singer, Goldman Sachs

And what are your expected well costs?

A - Fredrick Barrett

Expected well costs up around $13-14 million.

Q – Brian Singer, Goldman Sachs

Switching to Lake Canyon, you talked about the additional Wasatch well that you plan to drill. Is that in lieu of or in addition to a new well that will test deeper than the Wasatch over the next year?

A - Fredrick Barrett

Over the next how many years?

Q – Brian Singer, Goldman Sachs

Over the next – call it six months to a year. I think you were planning one additional deep test in the Q4 type time period.

A - Fredrick Barrett

Yes. We have increased the number of wells in Lake Canyon this year from two to four. And we’ve also, the other change there is that we – because of what we’re seeing in the DLB number one, the Wasatch formation, we’ve got something we think is very, very good here. And so we are focusing our efforts in that particular place, the Wasatch play. Now, as we move out over the next couple of years, Brian, we also recognize a potential deep gas play in the Mesa Verde formation. As we learn more from the other deep wells that have been drilled say further to the north as well as the one well we drilled here, and as we finish up with our 3D seismic, we believe that there are other deep plays, deeper gas plays if you will, that are developing further to the west. And so what you’re going to see this company do is focus over the next 12 months primarily on the Wasatch formation. And that’s not a bad thing, given where oil commodity prices are at this point in time.

Q – Brian Singer, Goldman Sachs

Great. Very quickly, in the Big Horn Basin, is the only impediment to commencing drilling and that re-entry into Seller’s Draw selling the two 25% stakes? Or is there additional seismic (inaudible) position that you’re looking at before doing this?

A - Fredrick Barrett

Brian, I can barely hear you.

Q – Brian Singer, Goldman Sachs

I’m sorry – in the Big Horn Basin, is the only impediment to the re-entry of Seller’s Draw and additional drilling, your decision to sell the two 25% stakes? Or is there additional seismic or any other activity you’re looking at doing prior to drilling?

A - Fredrick Barrett

You know, the re-entry, as soon as we consummate our agreement with the additional partner or partners brought in there and re-enter that well bore. Now, as far as drilling, we do want to finish this 3D survey. It’s a 40 plus square mile survey, we’re currently shooting drill holes, we should be done after acquiring this survey, probably mid October and be interpreting that survey through the end of the year. Which means probably our first well isn’t until the early part of next year, but you’re right, we would move into that well bore prior to finishing up the 3D.

Operator

Your next question comes from Jeffrey Robertson.

Q - Jeffrey Robertson, Lehman Brothers

Good afternoon, Fred. A question for you on the Piceance Basin, where you’ve mentioned potentially selling a few bits of your acreage out there. Can you talk about how that acreage is situated relative to the block in Grand Valley that went for such a high price, that you referenced?

A - Fredrick Barrett

Our positions are primarily north and east of where we’re at, which makes it way east of that block that PDC sold.

Q - Jeffrey Robertson, Lehman Brothers

How much of your acreage which is away from the main Gibson Gulch block?

A - Fredrick Barrett

Well, all of it. I mean, all of that acreage is different than our Gibson Gulch, put it that way.

Q - Jeffrey Robertson, Lehman Brothers

Okay. Then secondly, at Tavaputs, where you’re talking about the drilling locations, how far along as you on some of the environmental work that’s needed to get approval to move forward with the expanded development program out there?

A - Fredrick Barrett

Yes, we’re about halfway through the environmental impact statement phase. We expect the first draft of the EIS in early 2007, if not before then by year end. We would expect to see a record of decisions, at least what we’re pushing for, by Q3 or possibly Q4 of next year. The upshot there would be to have this thing done by, say, August 15 of next year and be in there drilling at our own pace in the September time frame.

Operator

Your next question comes from Eric Hagen.

Q - Eric Hagen, First Albaney Corp.

Good afternoon, Fred. Out in the Lake Canyon area in the Wasatch oil play, what’s the infrastructure out there? What would we need to actually hook up those wells, or you know, sell the oil?

A - Fredrick Barrett

Well, right now the one well we have is actually tied into a facility gathering system that Berry Petroleum recently finished up with their two shallow Green River wells. That system then is tied back into the Brundage Canyon area to the east. Now that’s primarily as it relates to the natural gas produced in that area. But most of what we’re producing is black wax, but that black wax is trucked and delivered off site via oil trucks, into the Salt Lake City markets. Right now, we’re having no problems selling that oil. Should there be significant ramp ups in production as we move out over the next two, three or four years, there has been in the rumor mill, the potential possibility for future increased processing capacities. We’re talking with the native American tribe there in the Uinta on possible increased and new processing facilities and also looking at expansions in the Salt Lake City area.

Q - Eric Hagen, First Albaney Corp.

What kind of a price do you get relative to say Nymex on that oil?

A - Fredrick Barrett

Right now it’s minus 14. Now, I know that it used to be 14 and the Williston used to be about seven. We’re now about $11 differential. We’ve seen differential change over the past month or so. What I was trying to say there is I know our differential has gone down to about $5 in the Williston, right? And down to about $11 in the Uinta on black wax.

Q - Eric Hagen, First Albaney Corp.

In terms of getting drilling permits, how difficult is it there? Are there any kind of environmental studies that need to be done, or is it on tribal lands or…?

A - Fredrick Barrett

No, you know, that’s the nice thing about this area and one of the reasons why we were so excited to get this exploration agreement put together. We not only can drill year round, but the Utes, who recently have formed an energy division, they want us to be in their drilling. So they’re very, very receptive to what we want to do and in fact we could probably do just about whatever we wanted to do drilling wise whenever we want to do it during the year. So that’s a big, big plus in the Lake Canyon area.

Operator

Your next question comes from Robert Lind(?).

Q – Robert Lind(?)

Good afternoon. Fred, I’ve got a general question for you. You’ve got a lot going on with respect to exploration and based on your recent discoveries, which one do you see becoming the next Gibson Gulch, or even the next shallow West Tavaputs, in terms of getting a development plan in place for commercialization?

A - Fredrick Barrett

Well you know, there’s a – we’ve recently put together a diagram that kind of shows the stage of exploration and/or development of each of our assets. Let me answer that question in the context of that diagram. Right now, we have five key development programs. Most of those development programs are in the early stages of development, for example, Gibson Gulch and West Tavaputs and slowly emerging into kind of a manufacturing kind of harvesting mode type development program. In addition to those development programs, then, we’ve made a series of discoveries where we’re now drilling delineation wells. And those delineation wells are helping us understand exactly, you know, where we’re headed to with those assets as it relates to the amount of capital we want to put into those programs and how quickly we want to drill them. I would say you know, out of that group of discoveries, the Lake Canyon discovery, the Bullfrog Cave Gulch discovery, the Tri-State discovery that we’ve made and we may potentially have one up in the Williston. I would put – in terms of kind of a brand new exploration program – the Lake Canyon area as number one. I would put the Cave Gulch Bullfrog area kind of right in line with that, except for the fact that it’s deep and you’re going to over drill, as I mentioned, one to three deep wells this year, so that’s kind of a consistent program from year to year. Then thirdly, you know, the Tri-State area I think is in the initial phases of potential ramp up depending on what we see this year. And so I would group those three into kind of the exploration programs that are really beginning to emerge. And then of course the other programs – we’ve yet to get drill bits into the Yellowjacket area, the Hook Woodside area, the Big Horn Basin, the Circus project, there’s a couple of programs up in the Williston that they’re also putting together.

Q – Robert Lind(?)

That’s helpful, thanks. With respect to West Tavaputs, I was under the impression that you owned some of the processing facilities there, was I mistaken?

A - Fredrick Barrett

We gather and compress our own gas, we have I believe it’s eight compressors in a central facility in what we call the direct canyon compression facility. That gas is then compressed and delivered to the processing facilities in Price, Utah that is owned by Questar Transportation Services, where it is then processed to liquid.

Q – Robert Lind(?)

Okay, I see. And just one final question, digging a bit deeper into the Williston, can you talk about – are these wells drilled laterally and then you watch the wells produce – I’m sorry, drilled vertically, you watch them produce and then you drill the lateral extension – are they single laterals? Based on what you’re seeing today, have you grown a little less optimistic about this play?

A - Fredrick Barrett

Come again on what area you’re talking about?

Q – Robert Lind(?)

Well, Target Red Bank at 75 barrels per day, it seems to me that you probably need a little higher rate than that?

A - Fredrick Barrett

Well a number of the wells that we’ve drilled in there are actually as high as 250 to 260 barrels of oil per day. The Target Red Bank is in the kind of early stages of development and we’re trying to define the limits of the field. You’re absolutely right, we need to see higher than 50, 60, 70 barrels per day, but in that area, it’s an interesting reservoir because you can see, well it’s producing 60-70 barrels of oil per day, but doing so for a very extended amount of time, such that you’re getting 200,000-300,000 barrels of oil out of those wells. When you get a 250 barrel per day well, you know you’ve got a good well, but it’s the 70-75 barrels per day wells that you need to be patient with and watch over time.

Q – Robert Lind(?)

And these are single laterals, correct?

A - Fredrick Barrett

Yes, these are single laterals.

Q – Robert Lind(?)

So you’re probably approaching this are more of a statistical play?

A - Fredrick Barrett

A little bit.

Operator

Your next question comes from Larry Benedetto.

Q – Leonard Benedetto, Howard Weil Inc

Fred, good afternoon. Could you elaborate a little bit more on the Yellowjacket play at the Paradox Basin?

A - Fredrick Barrett

Sure. This is a play where we own close to 100,000 gross acres. It’s a play where we’re targeting a shale gas concept out of the gothic formation down around 5,500 feet. It is a very expansive, large-scale kind of pro-delta type rock face that we’re going after here from a geologic standpoint and a lot of – well, not a lot, but a number of wells have been drilled in this area over the past several decades. It penetrated the gothic formation, targeting zones below the gothic. When you go in and you look at the thermal elements associated with this area, which you need to understand in order to get your arms around the potential for a gas resource play, you’ll see a lot of gas shows in here. In fact, the number of wells tested the gothic at rates of 2-3 million cubic feet of gas per day. It’s rumored that a number of wells north of our position are actually producing out of the gothic formation. And so what we’re going to do is come in here, we’re going to drill several wells this year, vertical wells, we’re going to take cores and we’re going to look and understand a little bit better the rock properties of the gothic shale in here. We understand right now that the gothic sits within a thermal window that’s conducive to the generation of dry gas and so it has the initial elements you want to see for a shale gas type program. It also is a very light spread, which is another key characteristic that you want to see in these shale gas programs. So we do want to gather more information beyond that with the cores that we’ll take and the two wells we’ll drill. We’ll also want to look at, as we move forward in time, the natural fracture systems in this area. We’ll be looking at those as we drill the first several wells. If encouraged by the first several wells, we would likely drill additional wells, several of which would be horizontal wells to test the feasibility of horizontal drilling in the gothic shale.

Q – Leonard Benedetto, Howard Weil Inc

So probably the horizontal wells would be some time H2 2007?

A - Fredrick Barrett

Yes, definitely next year.

Operator

There are no further questions. Are there any closing remarks?

William Crawford

Thank you all for participating in our Q2 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 Q2 2006 results. This concludes our conference call. Thank you again.

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