Seeking Alpha
We cover over 5K calls/quarter
Profile| Send Message|
( followers)  
TRANSCRIPT SPONSOR
Wall Street Breakfast

Bill Barrett Corp (BBG)

Q2 2007 Earnings Call

August 7, 2007 12:00 pm ET

Executives

Bill Crawford - IR

Fred Barrett - Chairman, CEO

Bob Howard - CFO

Joe Jaggers - President, COO

Analysts

David Tameron - Wachovia

Jeff Robertson - Lehman Brothers

Brian Singer - Goldman Sachs

Robert Lynd - Simmons

Eric Hagen - Merrill Lynch

Ray Deacon - BMO Capital Markets

Shawn Reynolds - Van Eck

Michael Scialla - AG Edwards

Presentation

Operator

I would like to welcome everyone to the Bill Barrett Corporation second quarter earnings conference call. (Operator Instructions) I'd now like to turn the call over to Bill Crawford, Manager of Investor Relations. Please go ahead, sir.

Bill Crawford

Thank you, Brandy. Good morning and welcome to Bill Barrett Corporation conference call to review second quarter 2007 operating and financial results, and to update you on current operating activity. My name is Bill Crawford. Presenting today are Fred Barrett, Chairman and Chief Executive Officer; Joe Jaggers, President and Chief Operating Officer; and Bob Howard, Chief Financial Officer.

Fred will begin by giving a brief overview of the key highlights for the quarter and then Bob will give an overview of our financial results. Joe will then provide an operational update on our development delineation and exploration programs. We expect these discussions to last 25 or 30 minutes and as Brandy said, we will follow with a question-and-answer session. We also plan to file our Form 10-Q with the SEC today. For this conference call we've also provided user-controlled slide show which may be found on our website at www.billbarrettcorp.com, and as an Exhibit to our Form 8-K which was filed with the SEC today.

Before we begin, please note that forward-looking statements and cautionary statement disclosures are on slide 2 of our presentation and were also included in our press release today. Please also note that today we will discuss and make reference to discretionary cash flow which is a non-GAAP measure. Reconciliation to the appropriate GAAP measure was provided in the press release today.

Fred Barrett

Thank you, Bill and again, thank you all for joining Bill Barrett Corporation today. I'd like to set the stage for a more detailed discussion by Bob Howard and Joe Jaggers by first referring you to slide 3 which illustrates a number of highlights for 2007. We produced 15.1 Bcfe in the second quarter of 2007, a 24% increase over the second quarter of 2006 and a 6% increase over the first quarter of 2007. West Tavaputs and Piceance continued to emerge as the primary drivers of this growth. As we’ve moved through the summer we've reached record production levels, over 175 million a day net to the company. We are raising our production guidance range to 61 to 64 Bcfe for 2007 which represents a 17% to 23% increase over 2006.

As we move through the first half of '07, we are extremely encouraged with our development assets in West Tavaputs and the Piceance and also the early signs of gas production in our Big George CBM blocks. On a standalone basis, these development assets give us visibility on significant economies of scale including low risk double-digit production and reserve growth, not only this year but in the years to come.

This is truly an exciting year for us via the exploration drill bit as well, as we pursue a number of projects. In addition to recently testing a large four-way structural closure at Woodside, we are also nearing TD in the Montana Overthrust Circus prospect and have reached TD at our third exploratory Gothic well in the Yellow Jacket area. Joe will expand on these areas, but let me just say I am encouraged up to this point based on the oil and gas shows we've seen in both of these latest exploration wells.

At the same time, I couldn't be more pleased with the results in our West Tavaputs Deep program. Since beginning as an exploration program in 2005, we've established initial rates averaging over 10 million a day in each of the first four wells we've completed and recently we have reached TD on our fifth delineation well. Combined with the shallow development program and future potential in other horizons and deep structures, West Tavaputs is the type of property that makes Bill Barrett Corporation a premier E&P company.

A few words on some of the challenges we face as we continue to execute our 2007 program. The most apparent challenges right now are short-term gas prices and the Rockies differential. We recognized early on the risk that both pipelines from the Rockies could effectively widen basis considerably through the summer and into the fall. We mitigated this risk by hedging through the basis over two-thirds of our '07 gas at over $6 Rockies realized price. We also look forward to Rockies Express West which is scheduled to be in service January 2008 and should significantly reduce the Rockies basis.

Like much the rest of the country, June and July were hot here in the Rockies, 95 to 100 degrees Fahrenheit most days and local demand has kept Rockies spot prices primarily in the $3.50 to $4 range, not bad given the pipeline situation from the Rockies. We expect gas prices in the Rockies to continue to be depressed over the next two to three months but we expect them to improve beginning in November or December given seasonal demand and Rockies Express West.

At current sales prices, we covered our cash operating costs and our hedges generate additional cash flow during this period of depressed sales prices. With our expectations for higher prices after the next several months, we continued to develop our core properties to increase production and generate returns that will exceed our cost of capital.

Another challenge is our higher than anticipated LOE gathering cost in the first half of the year, although Joe will discuss in more detail in the big picture of things, this is an issue that we believe is short lived and related to such things as water disposal efficiencies and labor costs. Given we have already implemented mitigation measures coupled with increasing economies of scale with our assets, we expect LOE to continue to decrease during the last half of '07 and beyond.

Before I hand it over to Bob and Joe, I want to reiterate our excitement about the second half of the year and beyond and we'll say a few more words about this at the end of our discussion, but I would add recently we did close the sale of our Williston properties and ended the second quarter with a net debt to cap ratio of 14%. We are financially secure and have the financial flexibility and liquidity to prosecute our development and exploration program.

Here to expand on this financial position is Bob Howard, our Chief Financial Officer.

Bob Howard

Thank you, Fred. Slide 4 has our key financial and operating highlights. We are generally pleased with second quarter results. We had a good quarter with a couple of challenges. Production continued to hit our growth objectives and we have raised our guidance for the year. We were challenged by lower gas prices in the Rocky Mountains compared to the rest of the country and compared to our price realizations in recent periods. Our hedging program effectively offset a substantial portion of the effect of these lower gas prices. We expect prices to recover late in the year and into 2008 due to renewed seasonal demand and the Rockies Express West Pipeline being placed in service.

Lease operating expenses were higher than we expected for several reasons that Joe will discuss later in this call. We've taken actions to reduce lease operating expenses to levels that are more acceptable.

The second quarter of 2007, we produced oil and gas at an average daily rate of 165 million cubic feet equivalent per day, which is a 5% increase on a daily basis over the first quarter of 2007 and a 24% increase over the second quarter of 2006. In the second quarter of 2007, our average sales price was $5.92 per Mcfe and we generated $55.1 million of discretionary cash flow which is $1.23 per share. This compares to the first quarter of 2007 when our average sales price was $6.84 per Mcfe and we generated $68.5 million of cash flow. For the first half of 2007, we've generated cash flow of $2.77 per share.

Reduction in average sales price is illustrated by the depressed Rockies prices. For example, the first of the month pricing for CIG averaged $3.77 per Mmbtu in the second quarter of 2007 compared to $5.58 per Mmbtu in the first quarter. Offsetting the price decline was $21.1 million of tax settlements in the second quarter, substantially more than the $7.4 million we received in the first quarter.

Our cash costs increased compared to the last quarter primarily due to the $0.33 per Mcfe increase in lease operating expenses. Production taxes decreased $0.05 per Mcfe due to lower sale prices and both gathering and transportation costs and general and administrative expenses decreased by $0.01 per Mcfe each, primarily due to our production increase. Our total cash operating cost for the second quarter was $2.14 per Mcfe and compared to $1.88 per Mcfe in the first quarter.

In June, we sold our Williston Basin properties, $41.5 million and realized an $11 million pre-tax gain. In the second quarter, we also recognized a $2.3 million impairment charge, to reduce the book value of our remaining properties held for sale to its estimated fair market value. We generated net income of $9.9 million or $0.22 per share in the second quarter, which compares to $14.2 million or $0.32 per share in the 2007 first quarter, and $8.2 million or $0.19 per share in the second quarter of last year.

If you go to slide 5, it illustrates our current hedge position for natural gas. With our significant capital expenditure program, we are maintaining a hedge position to support our cash flow from operations. Approximately 6% of our gas production for July-through December 2007 is hedged to a combined floor and swap price of $6.02 per Mmbtu and 32% of our 2008 gas production is hedged at a combined current swap price of $6.77. Our 2008 hedges are concentrated in the first quarter to mitigate risks and potential market volatility as a result of the next phase of the Rockies Express pipeline being placed in service in January. We intend to add additional hedges in 2008 and 2009 as market conditions warrant. Please recall that all of our gas hedges are settled at a CIG price in the Rockies to respond to our gas selling arrangements.

Our capital expenditures for the first six months were nearly $193 million and include $172 million to drill incomplete wells and to add facilities, $16 million for leasehold acquisitions, $4 million for geologic/geophysical costs and $1 million for furniture, fixtures and equipment. We are funding our 2007 capital expenditures with cash flow from operations, proceeds from the Williston properties sale, and debt availability.

Proceeds from the sale of the Williston properties were used to pay down the outstanding borrowings on our revolving credit facility. We ended the quarter with $132 million outstanding under our credit facility. After selling the Williston properties, our borrowing base is $340 million. We expect the borrowing base will increase after our bank group reviews our mid-year 2007 reserves. We have plenty of liquidity with our revolver and we may look to tap other debt markets if those markets begin to look attractive to us.

Our press release includes an update to our guidance numbers. We continue to budget $425 million to $450 million for capital expenditures. We have increased our production guidance to 61 to 64 Bcf for the year. This increase is due to increased confidence in our development program that includes production from the Williston properties through the June 22nd sale date. Comparing the full year guidance to actual production in the first half of the year indicates a production range of 31.8 to 34.8 Bcfe for the second half of the year compared to production of 28 Bcfe for the first half of the year, not including the Williston production.

After considering our higher lease operating expenses during the first two quarters we have increased our full year guidance numbers to $0.70 to $0.75 per Mcfe. That range of annual guidance compared to actual results for the first half of the year means that for the remainder of 2007 we expect LOE to be $0.60 to $0.65 per Mcfe. Our guidance for gathering and transportation and G&A are virtually unchanged.

I'll turn the call over to Joe Jaggers for the operating activity review.

Joe Jaggers

Thanks very much, Bob. From an activity perspective, we've accomplished a great deal during the quarter. I'll hit the highlights beginning at West Tavaputs, our largest development project. You can find these points on slide 6. We're currently operating three rigs at West Tavaputs, two shallow and one deep rigs. The third rig was added during May, on schedule as planned following the end of the winter drilling stipulation period. We plan to drill 29 shallow wells and four deep in 2007 and through June, we spud 13 shallow and two of the deep wells. We expect to spud the third deep well this week. We're currently producing 74 million cubic feet per day net and have six shallow and one deep well waiting on completion.

On the facilities side we've installed an additional 40 million cubic feet of compression in the field bringing the field wide total to 135 million cubic feet. In addition, we've increased our contracted processing capacity to 110 million cubic feet per day and expect to be producing at this rate during August. Our next facilities target is the completion of additional processing in early 2008.

We continue to make progress on the 40 acre pilot with the most critical data gathered at this point. The remainder of the year will be used as an analysis of this data, gathering and analyzing production data with a goal of being in a position to begin booking 40 acre wells by year-end. Our most recent completion, deep completion, the 5-2D well is clearly the most productive well drilled to date. We produced the well at daily rates as high as 10.8 million cubic feet per day with flowing tubing pressure over 3800 PSI. After the 5-2 well was drilled, the next well we drilled was the 8-2 D well. The well reached total depth in 60 days, our fastest well yet, and reached this depth despite a 12-day rig repair period in that 60 days, indicating additional potential to reduce total days on these deep wells. The well is cased and will be completed during August.

We've averaged 68 days drilling over the last three deep wells, an improvement of some 50% over the time required to drill the first two deep wells. Finally, we expect the EIS to complete a record of decision to be reached during spring 2008. Our next milestone in the EIS process is the public comment period, expected to begin in September this year.

Turning now to the Piceance Basin. In the Piceance we continue to operate our four rigs and plan 102 wells for the year. Through June we had spud 45 of these wells. We're currently producing 56 million cubic feet per day net. We have contracted additional processing and local transportation of 70 million cubic feet per day which ties to our firm Rockies Express capacity and expected deliveries through that system.

We continue to make progress here as well on downspacing on the 10-acre pilot. 36 wells will be 10-acre wells this year. This is an increase of five from the 31 we reported last quarter. The data from these wells will put us in a position to begin booking 10-acre locations by year end.

In the Powder River Basin through June, we've spud 56 of our planned 245 wells. The program here is back-end loaded, as the first five months of the year have heavy wildlife stipulations. We're producing 16 million cubic feet per day and are very pleased with our early Big George results at Cat Creek, Willow Creek, and Dead Horse. Key company growth projects are moving forward. Unfortunately, we're currently experiencing constraints in the Fort Union gathering system which prevent us from producing at full rates. There are several projects under way to address the constraint over the next six to nine months and while we are constrained we continue to produce water. By doing this we expect a faster ramp up in production when sufficient gathering is in place.

Turning now to lease operating expense, I'll refer to slide 7, our first half LOE has been higher than we forecasted at $0.79 per Mcfe. There have been several contributing factors and we expect most of these to improve during the second half of the year. We expect second half LOE to range from $0.60 to $0.65 per Mcfe resulting in full year average of some $0.70 o $0.75 per Mcfe.

The first major contributing factor to higher first half LOE is the Williston Basin. This property is not included in our full year forecast due to uncertainty over timing of divestment and had LOE through divestment of over $2 per Mcfe. Including Williston cost, it caused a $0.06 increase of our $0.79 average.

A number of non-recurring charges occurred during the first half, largely workover and compression rental expenses. In the case of rental compression, we totally eliminated rentals in our fleet during the second quarter. This unfortunately appeared later than we had forecast as delays in our permit receipt caused the operation of the rentals to continue longer than we had anticipated. Workovers, we plan to reduce in the second half. Our first half results were impacted by aggressive programs in the Wind River and Powder River Basins.

Labor, and particularly overtime had a negative first half impact. Hiring additional staff did not keep pace with our increased activity and resulted in high overtime rates for existing staff. This area has been addressed by staff additions which will result in an overall lower labor charge in the second half.

Finally, on the water management side, Water management is the largest component of our lease operating expense representing some 18% of the total LOE. We've installed water management systems at West Tavaputs and in the Piceance Basin that are already yielding significantly lower costs. In the Piceance, this project entails a piping system to avoid third party trucking costs and two additional disposal wells to eliminate any third party injection charges. In West Tavaputs we've completed a disposal pit and purchased trucks which will be company-operated, again, with a view to eliminating third party charges. Both systems are now completely operational and should significantly reduce second half water charges.

The net result of these areas of emphasis and improvement in the second half LOE in the range of $0.60 to $0.65 and a full year average of $0.70 to $0.75.

Slide 8 provides an example of the driver behind the increased gathering and transportation charges. Fortunately, throughout the year, we've had the opportunity to access higher value markets with our production. This comes though with higher associated costs. The chart depicts our gross operated Piceance production. The red shading indicates deliveries to Questar. We're able to make these deliveries through a direct BBG owned line to the sales point. There's no cost obviously associated with this shipment but it does access markets that are typically $0.45 to $0.55 lower priced than the CIG index pricing.

Through arrangements we've made with another producer in the area, we're now able to send a large part of our production through their system to access another interstate markets on TransColorado, CIG, and Northwest Pipeline. These markets though have gathering and transportation costs ranging from $0.25 to $0.40 per Mcfe but they do yield improved margins up to $0.25 per Mcfe.

We have additional arrangements like this in place that will begin during August for access to the new enterprise system and arrangements at West Tavaputs beginning in 2008 that will allow access for Tavaputs production in the Northwest pipeline. Because deliveries and sales that have associated transportation costs are a growing part of our business and to avoid any confusion, likely this quarter we'll separate it from LOE for guidance purposes going forward.

Turning now to slide 9, I'll wrap it up with an update of our active delineation and exploration projects. In the Montana Overthrust Circus project, we're nearing TD on the first of two planned 2007 wells, the Draco well. Our current depth is 11,833 feet. We've extended our planned TD from 12,000 feet to at least 14,000 feet having encountered numerous gas and oil shows and plan to set production casing and begin test operations over the next several weeks. After drilling at Draco, we'll move the rig to our Leviathan structure directly West of Draco and drill the second of our planned 2007 Circus project wells.

In the Paradox basin the Yellow Jacket project, we've reached TD in the third exploration depth and today are running production casings. Like the previous two wells, this well is a vertical Gothic shale well. We've extensively cored the Gothic section and will complete the core analysis before we begin completion operations. These operations are expected to begin during September. We plan up to two additional tests of the Gothic shale including one horizontal test during the next six months.

In the Uinta Basin, Lake Canyon and Blacktail Ridge project, we'll spud the first of our eight Wasatch wells later this month and finally at our Woodside Project in the Paradox basin we've drilled and completed a gas discovery well in a large four-way closure. The well produced a rate of just over 3 million cubic feet per day, however the heat content was low as a result of high inert content on the order of 40 % with a majority of this being nitrogen. The high inert level, associated processing, and long distance to interstate transport make development here at Woodside challenging. We're in the process of conducting various development studies to determine project viability and at this point don't plan any further drilling. Our nearby Hope project to the North, should it be commercially productive may, provide an incentive for further drilling here at Woodside.

Now I'd like to turn things back over to Fred.

Fred Barrett

Thank you, Joe. As I close here just a few words on the remainder of 2007. Although the first half of '07 was a very busy time for us, the second half should prove to be our busiest and I would add most exciting time of the year with multiple rigs in full swing at all three development areas, exploration rigs working multiple project areas. As Joe pointed out, we do expect results from a number of projects as we move through the third and fourth quarters of '07 including additional wells in West Tavaputs Deep, Yellow Jacket, Lake Canyon, Blacktail Ridge, Circus, and potentially our hook area in Southern Uinta. These are truly exciting times for the company and we are poised to capitalize on one of the largest high quality positions in the Rocky Mountain region and expose our shareholders to consistent double digit development growth and world class exploration prospects. We'll continue to monitor the gas prices through the fall, but at the same time, we do look forward to improved gas prices with the next completion of the Rex West pipeline.

Thank you for joining us today and I'll turn it over to Q&A.

Question-and-Answer Session

Operator

(Operator Instructions) Your first question comes from David Tameron - Wachovia.

David Tameron - Wachovia

Joe, you mentioned it briefly, but can you talk more about Powder? It seems like there's been a number of companies, St. Mary's talked about compression issues, Anadarko's volumes are way off. They talked about infrastructure. Is this a late '07 once Anadarko gets to Fort Union, that water pipeline is taken care of? When can we expect to see an improvement out there?

Joe Jaggers

The situation on the infrastructure out there is full gathering on both the Fort Union and Thunder Creek systems and we produce into both of these. The fix for Fort Union is a series of expansions. October is the first one, the connection from Fort Union into MIGC, the regulated pipeline there that will provide some relief but this is on the order of 40 million to 50 million cubic feet basinwide, and isn't clearly the full answer.

The next two pieces are loopings on the Fort Union system, the second one of which will be finished and the project should be full capacity by the end of the first quarter, so we're looking for continued problems around gathering and compression throughout this year and probably into middle/late first quarter '08. The Anadarko pipeline, the water pipeline really doesn't have anything to do with this issue.

David Tameron - Wachovia

So do you expect your Powder volumes to stay relatively flat then over the next couple quarters? I mean, can you just kind of let these things build up and dewater?

Fred Barrett

Yes, it will be relatively flat for the year. We've got some capacity down in the Southern part of our Big George position where we can produce into Thunder Creek, but our real growth is Cat Creek, Willow Creek and Dead Horse and all of those are dependent on Fort Union capacity. We're seeing excellent results at Cat Creek. We've curtailed 3 million or 4 million a day. It's still early stages of ramping up but we've been very encouraged by the shape of that profile and we'll continue to dewater and build pressure on that system and when we do have the capacity to be able to bring those wells in at high initial rates. Down at the Willow Creek area, our initial drilling and completion there, we've seen very very quick turn to gas and pressure in those wells and likewise at Dead Horse, so we're looking for a big '08 out of the Powder.

David Tameron - Wachovia

Moving to production guidance, the 61 to 64 I'm just trying to make sure I've got apples-to-apples going. How does that compared to the 58 to 63/ What was assumed for Williston in those two numbers?

Bob Howard

In the original guidance we had we had nothing considered for the Williston, and the current numbers that we have about a little over a Bcf equivalent included, about 1.2 altogether included for the current guidance of 61 to 64.

David Tameron - Wachovia

Can you talk a little bit on some of the credit issues out there, is your lending based on reserves I would assume?

Bob Howard

Well, our bank line of credit is based on our proved reserves and every six months the banks look at our reserve before they run their pricing deck which they just increased slightly here recently to determine the amount of borrowing availability, and so every six months the banks get another look at it, we'll continue to work with them on what the borrowing base should be.

David Tameron - Wachovia

Okay so you don't anticipate any impact from that?

Bob Howard

No, we've had conversations of course and I'm sure everyone is looking at the debt markets right now and we've had conversations with the elite banks and just to make sure they are comfortable with the asset backed financing that we use to finance our business and don't expect any reduction or any tightening under the bank credit or bank markets.

David Tameron - Wachovia

Just clarifying something you said, Joe. In the press release, I think it had a number of 63 million a day for current Piceance production. In your prepared remarks you said 56. Is that just a second quarter average versus a current number or can you clarify that a little bit?

Joe Jaggers

I'll try to clarify that. That's an earlier number. The 63 is our current producing rate and that referred to the average on the second quarter.

David Tameron - Wachovia

Okay so average, okay.

Joe Jaggers

So we're up now.

Operator

Your next question comes from Jeff Robertson - Lehman Brothers.

Jeff Robertson - Lehman Brothers

Joe, can you talk a little bit about the drilling plans at Tavaputs in light of the EIS expectation in spring of '08 and what you'll be able to do there both on the shallow program and the deep program until you get final approval on that?

Joe Jaggers

We've recently submitted our winter drilling program to the BLM and are in early stages of discussion with them, Jeff. Our submission was to continue to operate one deep rig through this '07/'08 winter and to operate one shallow rig through the winter, so that second shallow rig would have to leave in the November timeframe. Early comments are favorable. We've done some moving of locations and some avoidance of rig moves to accommodate the BLM and we think we're in a good position to get it and we've started working on it earlier this year so we really do expect it to be a winter program and not a late winter or early spring kind of program. With that activity, we'll roughly mirror our '07 winter activity.

Jeff Robertson - Lehman Brothers

On the deep wells, Joe, you mentioned a savings in terms of days. Can you put that into dollar terms of what it cost on the most recent wells to drill those?

Joe Jaggers

Yes, I can, Jeff. It will take me just a second to dig that up, but I believe I have that with me. We may want to go on to another question.

Jeff Robertson - Lehman Brothers

While you're looking for that my last question, Fred, maybe you can talk about the Woodside Project. Was the presence of the inerts a surprise to you and does that have an impact on how you think about Hook?

Fred Barrett

No. It was not a surprise. We knew earlier production in that area or test rates that had inerts associated with it. The strategy associated with that prospect was to come up whole into the Pennsylvania Paradox and look at zones that, based on earlier mud logs, indicated the presence of methane, and that's what we did. We're obviously hoping for lower inerts, an entirely different set of zones that we are targeting in the hook area includes that area in our geologic opinion from having any influence by inert. We're looking at a cretaceous zone in the Hook area and also in a deeper Mesa Verde zone, but again based on the mud logs and the gas shales we see in that area, our understanding right now is that inert should not be a problem in the Hook area.

Jeff Robertson - Lehman Brothers

Thank you.

Joe Jaggers

Jeff, on that cost question, the most recent completion 5-2 is coming in at about $8.3 million, and we've steered earlier towards a 10 million gross number on these wells, and the 8-2, of course was faster yet and we still haven't completed that well or set production facilities but I'd expect it to be less than that 8.3 number.

Jeff Robertson - Lehman Brothers

Thanks, Joe.

Operator

Your next question comes from Brian Singer - Goldman Sachs.

Brian Singer - Goldman Sachs

Can you talk in more detail about the Mississippian formations that you plan to drill? What your deep West Tavaputs well is down to, what are your expectation is in terms of drilling costs, what would you be looking for and over what swath of acreage do you think could exist?

Fred Barrett

Well, let me just add as it relates to the West Tavaputs area, there's an interesting set of developments in my opinion as you look at the deep structure in there. First off, the 5-2 well came in a little bit higher than we had anticipated, and we also ended up with a little bit better looking Navajo than we had originally anticipated and that means or suggests the likelihood that we have other sweet spots in the Navajo structure in addition to being on top of the structure. It means that the structure could be a little bit bigger than we had originally anticipated and keep in mind that we have yet to drill our highest locations.

As we look deeper into that into the ultra deep horizon, there's several key horizons down there that we're very interested in. One is the Weaver formation and the next zone then would be the Mississippian. We do see a number of things that are mappable on the 3D as it relates to the Mississippian section, and we have done quite an extensive mapping effort related to those horizons.

We have elected to move the ultra deep and the penetration of those zones in a well under the 2008 drilling season, given the APD that we received back from the BLM, but let me just say that we believe there is potential in the Mississippian down off the planks of the structure, we believe that there is significant potential in the Weaver up on top of the structure and so the likelihood is that it will take one to two wells to determine the full potential of the deeper Paleozoic in the West Tavaputs area.

Brian Singer - Goldman Sachs

That's helpful. Could you give some sense as to just initial thoughts on how sizeable you feel the various structures could be and what you think it might cost incrementally to get down there?

Fred Barrett

I'll ask Joe to help with some thoughts here, but I'll answer with the first part. The size of the structure right now is a proxy in the deep Dakota and Navajo section so we see 25 to 30 deep locations on a 160-acre pattern in that program. That does not include the Western structure which we have yet to drill. Again, that's a 2008 time event that we will drill that Western structure. There, again, assuming that we have a similar type situation in the Dakota Navajo formations, we see anywhere from 14 to 15 deep locations over there.

As to the number of locations potential in the Weaver and Madison, I think that remains to be seen until we get those wells drilled, but it adds a significant increment of potential future reserves to the overall West Tavaputs structure.

I'll add one more point on the Jurassic section, the Navajo, these wells obviously high feed for high rates, they have an average of over 10 million a day on our wells so the economics now that we've reduced our costs are very, very good on these Navajo wells. To the question on the cost to deepen it, we'll drill a Mississippian test in 2008. We've got the location identified and the approach that we'll take is we'll line it up with a good Navajo location, we'll case through the Navajo and that will be the bail out and then we'll have 4,000 to 5,000 feet to deepen beyond that in test, so we're looking at incremental costs of $3 million to $4 million on the initial one with lots of associated testing. Just like we've done with the 14,000 foot program to the Navajo, I'd expect in the future as we continue to drill those wells we'll get more efficient and drive those costs down as well.

Brian Singer - Goldman Sachs

Great, thanks. Could you refresh us in the Piceance in terms of some of the well costs and more importantly EURs that you're seeing on the 10-acre wells drilled year-to-date?

Fred Barrett

Well, on the question of EUR for the 10-acre wells, it's too early. We're completing some of the initial ones now, have the first few weeks and months of production, so it will be in the next quarter's call that we'll have some idea EURs on those, and probably year-end before most of them have EURs assigned to them. Cost trends and initial production rates, nothing really out of line with our previous guidance. We're in the range of $2 million per well and we're looking at EURs in the 1.2 to 1.4 range.

Operator

Your next question comes from Robert Lynd - Simmons.

Robert Lynd - Simmons

Joe, can you give me an estimate of what volumes are currently constrained at West Tavaputs?

Joe Jaggers

We can process now 110 million cubic feet per day. This morning’s rate was 100 million cubic feet per day, so we're not constrained presently. We've got the six shallow wells and one deep well yet to complete. We're reloading CO2 and launching into those completions. I'd expect within the next week or two we will be back at the 110 and be constrained again.

Robert Lynd - Simmons

So the 5-2D well, was that constrained due to I guess wellhead equipment?

Joe Jaggers

Well, it was constrained initially because of the processing. We just recently got this increased to 110.

Joe Jaggers

Okay, so it is now wide open?

Joe Jaggers

Well, this morning it hadn't yet been opened up. We're running a PLT log. We haven't drilled out plugs in the well or set tubing on it. We really haven't produced it at a maximum rate. I think this morning it was making about 8 million a day. It is capable in excess of 10 million.

Robert Lynd - Simmons

Moving on to the Circus prospect, are you seeing in your mud log, did you see hydrocarbon shows in the Cretaceous, Mississippian Devonian are you able to kind of tell what the sand quality is? Can you give us a little more detail?

Fred Barrett

Sure. We are limited at this point because we haven't tested in any of these zones but based on the information from drilling operations and well logs that we obtained down through the intermediate hole down to 7,000 feet, let me just say that we are seeing quite a few oil and gas shows, live oil cuts and gas shows on the mud log. We see gas shows down through the Cretaceous Montana and Colorado Group and those include the Cody Frontier Maury, the Graybolt Sands. We see shows down through Mississippi and Madison, Mission Canyon and the Lodge Pole Formations, we do see shows down through the Devonian and Jefferson Group and also more recently in the Cameron section.

We do have logs down to 7,000 feet. We ran in a full suite of logs, the initial review on those logs did show numerous zones of interest. We are currently conducting a more detailed petro/physical log analysis associated with those logs and we do see zones of interest up and down in the Cretaceous section. In fact, those logs went down to the Jurassic section and we then drilled out from intermediate casing and came into the Paleozoic section.

Right now, all we have are cuttings coming out of the well bore and the corresponding oil and gas shows. The type of fit that we were using didn't provide for the best of cuttings but it does give us enough to assess and analyze the various oil cuts and gas shows, and at this point, let me just say that we're not going to know the true meaning of these shows until we get each of these zones tested and we do look forward to a number of interesting zones below the Jurassic, and once we get those logs cased and tested, we'll provide more information.

Operator

Your next question comes from Eric Hagan - Merrill Lynch.

Eric Hagen - Merrill Lynch

Good morning, Fred. On the timing of Leviathan, when do you think you'll spud that?

Fred Barrett

I would put up a tentative estimate, we'll have finished drilling this over the next two-and-a-half to three weeks and then rig moves, I would say some time in early to mid-September.

Joe Jaggers

Yes, it obviously depends on how deep we decide to take the rigs. It's a very short rig move location, it's right next door.

Eric Hagen - Merrill Lynch

These are separate structures, right? What's the relative size then of these two?

Fred Barrett

Good question, and I think that as you begin to learn the Circus area, I think it's important to begin to understand that relationship. Draco is an interesting feature in that we see structural closure from top to bottom. From a vertical standpoint, we see shows up and down this feature and so we see quite a bit of potential in the Draco feature, but I would note that we see other separate structures including Leviathan that are even larger in size than Draco aerially, just from a geographic standpoint. Leviathan is two to three times the size of what we see here in the Draco area and it's kind of split up into a couple of substructures. So we see a range of sizes and structures in the Circus area, but each one holds up obviously otherwise we wouldn't be drilling it but each one holds its own characteristics in terms of reserve potential.

Eric Hagen - Merrill Lynch

Moving back to the Uinta on the Deep program in West Tavaputs, when do you think you'll drill a test well on the Western structure? I think it's Prickly Pear?

Fred Barrett

That will be a 2008 event, and once we're able to bring that rig over from the Peters Point area, after the winter drilling timeframe, which is up in the May timeframe, we would then have the flexibility to move that deep rig over into the Prickly Pear area to drill that Western structure.

Joe Jaggers

Originally we had intended it to be the fourth well of the 2007 program but in these discussions with the BLM on the winter drilling program they asked if we wouldn't leave that rig on the East structure and not try a wintertime move, and of course we agreed in exchange for the locations that we were talking about so that's what puts it into a May '08 timeframe.

Operator

Your next question comes from Ray Deacon - BMO Capital Markets.

Ray Deacon - BMO Capital Markets

On the deep West Tavaputs wells, my recollection was you did not have a lot in the 2 P number, 2 Tcf for those deep wells. Do you have any kind of range of how much you could convert from the 3 P number based on the results you've seen in the last couple of wells?

Fred Barrett

First off, you're correct. Not a lot of the 3 P resources in the West Tavaputs area have a lot of contribution from the deep plays, none of the Western structure yet obviously is inclusive in that 3 P number, nor have we booked a lot of offsets associated with the current deep wells that we've drilled to date.

Again, let me just say that, I'll let you do that math, but we're seeing 4 to 5 Bcfe type wells. I think the average is somewhere between 5 and 6 Bcfe. In my opinion I think these wells could be larger. We've got 25 to 30 deep locations on the East structure that we've drilled and we've got 15 plus locations on the West structure. So you can begin to see the upside there. That does not include the ultra deep in there, but I think when all is said and done, the deep horizon could provide growth anywhere from 200 to 400 Bcf conservatively, especially if that ultra deep works; and again, that would be a conservative number. As to what currently contributes to the 3 P, I would put it what, Joe, in the 20, about 30 Bcfe contributed from the Deep Horizons, 20 to 30 in the 3 P.

Ray Deacon - BMO Capital Markets

What would be the next data points on the Gothic shale play? Will you test the well before you drill more?

Fred Barrett

No, I believe this rig will move to the next Yellow Jacket exploration well -- hang on. I've got some heads shaking.

Joe Jaggers

We took that rig right on just a one well basis to get it drilled.

Fred Barrett

We do have additional drilling planned for the year, one additional exploration well, but one of the key data points I think to look for this year is the offsetting horizontal that we planned for the Koskie/Brumley, but my point is that those wells will be drilled this year, and the horizontal will be drilled this year and they are shaking their head yes on that one.

Operator

Your next question comes from Shawn Reynolds - Van Eck.

Shawn Reynolds - Van Eck

I wonder if you could just expand a little bit more. I know we've been talking about Circus quite a bit but in terms of these shows that you've had, are the apparent thicknesses giving you a volume that would be exciting? I mean, you can get a lot of gas shows and oil shows that kind of just come up the pipe that don't mean a whole lot. Is there anything you saw in the initial logs or anything in terms of the zones you've been drilling through that give you a sense of optimism with regards to thickness?

Fred Barrett

There are a number of zones in the log intermediate portion that do give us encouragement and they do correspond to oil and gas shows, but I've got to tell you first off, we were a little surprised on the number of oil cuts and the number of gas shows that we are seeing when you look at the well bore as a whole. Let me just stress again that we're not going to really know the true meaning of these shows until we get them tested.

Frankly, I don't know if you consider these shows as excellent or are they horse shows or are they excellent shows? All we know is we are seeing hydrocarbon in the well bores. We did drill the first part of the hole that's heavily over balanced and so the shows may have even been more depressed. We don't know, but this is a critical data point for this area as we gauge reservoir, as we gauge the shows and then ultimately what the completion information is going to render. This will be a big learning curve for us.

Right now, we know we have sourcing. We know we have migration into the area. We know we have structural closure in here. I think the big question is going to be and will be answered by the completion, as we move beyond this point of how much containment do we have in this structure? Do we have the seals to hold the hydrocarbon in its place?

Secondly, was there reservoir preservation particularly down in the deep horizon in the Paleozoic, the Mississippian Madison, and the Devonian and the Cambrian sections. There, we don't have a log on those wells yet. We do have cuttings, we do look at the porosity in those cuttings, we are seeing porosity developments on occasion but boy, you're just not going to know until we get in here and get this thing tested.

Shawn Reynolds - Van Eck

Fair enough. How about the reason for going 2,000 feet deeper? Did you touch on that?

Fred Barrett

There are several things. One is the section that we drill through and as we begin to delineate the specific tops that we are able to use and assess the overall structure vis-à-vis the 3D seismic, those horizons have actually increased in structural elevation and so we're able to readjust our 3D seismic interpretation. In other words, the horizons in our structure ended up being higher than we had anticipated so that our projected TD was much more closer to a number of zones down below our originally anticipated TD. That is the first part.

The second part is the shows. Given that we continue to see shows as we drill deeper, every now and then you run into quiet zones but we've consistently have seen some significant shows. We believe that there's a deeper thrust fault through which we would penetrate and come into either kind of a repeat of the Cretaceous section or a repeat of the Madison section. Given that we would drill more wells in the future, should this one be successful, and given that the overall structure was higher than we had anticipated, we felt it prudent to take that extra step to go ahead and drill into those horizons. That 14,000 feet would take us down into that lower sub thrust block and so that's what we're doing.

Shawn Reynolds - Van Eck

Presuming incremental cost is insignificant or de minimus?

Fred Barrett

Well, at this point, we're so far ahead of the drilling time curve, that we're not recognizing any additional cost from going from 12 to 14.

Shawn Reynolds - Van Eck

You've sounded extremely comfortable with your financial situation. How high will you allow your debt to cap ratio get to?

Fred Barrett

I'll let Bob chime in, but in general we feel comfortable going as high as 30% or 35% debt to cap but as we go beyond that, that we do have a risk tolerance level that prevents us from going much higher than that 30% to 35% level. We are in a very sound position right now with a fairly low debt to cap. We've got the liquidity that we need. We're going to redetermine our borrowing base, and we have the hedging position to ensure good sound cash flow position this year and so we're in a good position.

Bob Howard

I agree with what Fred said. We're very comfortable with our forecast of results or what we expect to develop over the next two to three years. We've done extensive modeling and we'll stay well within our comfort level of no more than 30% debt to total capitalization and looking at some other metrics of debt per Mcfe and other multiples and if we have some other exploration success we need to develop we'll address that with additional financing, but we want to keep our debt fairly modest compared to overall capital structure.

Shawn Reynolds - Van Eck

So you do think you'll stay below 30% then for the next couple of years?

Bob Howard

From what we've seen, it will be driven somewhat by gas prices and some of our results but what we're modeling today, yes.

Operator

Your next question comes from Michael Scialla - AG Edwards.

Michael Scialla - A.G. Edwards

I think you've answered all of my questions on Circus. I guess just one last one, given what you've seen so far have you been adding any acreage along that trend anywhere?

Fred Barrett

In the Circus area?

Michael Scialla - A.G. Edwards

Well, Circus or along the whole Overthrust hedge line trend?

Fred Barrett

Yes, we're primarily focused in what we call the Circus area, but it's a fairly substantial area in terms of our acreage position. We own well over 300,000 gross acres in this region, and yes, we are doing some clean-up work on a number of leases, bits and pieces. There are certain areas we know that we want to be in.

The Circus area, our strategy there was in addition to the 3D seismic that we've shot in there -- and which by the way we continue to shoot 3D in there. We've got 70 some square miles this year we're going to shoot. Our strategy was to provide a large enough East/West look at the play as well as the North/South look at the play and when you look at the analog areas of Wyoming Overthrust and the Canadian Overthrust, it took a number of wells before they finally found the big structures. But we do keep our eyes open up and down along thrust belt not only in Montana but down into the Wyoming area but we don't have any specific new plays outside or along the same trend to the North or South of Circus at this point in time.

Operator

You have a follow-up question from David Tameron - Wachovia.

David Tameron - Wachovia

Back to Circus. After Shawn's question you mentioned that you decided to go deeper. Did you say you're still targeting the Devonian or is there another pay zone beneath that?

Fred Barrett

No, the pay zone, if you look at the pay zones in general, you have a fairly thick cretaceous section down around 6,000 feet. As you move through the Jurassic section, we think coming into the Mississippian section we have several zones in the Mississippian. We have a zone down below that in the Devonian and then we have a key zone down in the Cambrian section as well. We're currently drilling, actually we believe in the pre-Cambrian as we speak, the pre-Cambrian fault rocks is what they're called and we'll keep our eyes open in that section, but yes, there's a number of zones that we're targeting.

David Tameron - Wachovia

Devon has got the other 50% and there's nobody else in it?

Fred Barrett

That's correct.

David Tameron - Wachovia

One final question. Paradox, what do you say as far as timing? Are you going to do core analysis? When will we expect to hear more?

Fred Barrett

I would anticipate kind of in the first two weeks of September we'll have information and after which we'll then commence operations.

Operator

You have a follow-up question from Ray Deacon - BMO Capital Markets.

Ray Deacon - BMO Capital Markets

A question on the Piceance. In your last presentation you showed your expectation this year was you'd net about a Bcf including the 10 and the 20-acre spaced locations. I guess I know it's early on the 10-acre spacing locations but any reason to think that might be high and if yes, your breakeven gas prices is 4.50; suppose it's a little disappointing, what do you think the number would need to be for you to get good rates of return on these 10-acre spaced wells?

Joe Jaggers

On the 10 acre EURs, the data is just too early Ray. At least based on initial results, we don't have any reason to think we'll be surprised with the downside. In terms of economics, a 1b well EUR net revenue interest of 0.81 and costs of $2 million, when we run that at the current strip, we're looking and with our current cost structure, we're looking at a 30% plus rate of return. So we feel real comfortable with results and economics at this point.

Ray Deacon - BMO Capital Markets

So if you were to see any upside to this 64 Bcf this year, where might that come from, if you were trying to guess where you might see some better than expected results than what you have there?

Joe Jaggers

Well, we're still encouraged by the deep program. We're drilling them much faster and there may be additional wells completed this year. They may be late in the year and not significant contributors to that 64 but we feel real comfortable about our guidance and really at this stage of the year being August, I think we recognized most of the upside and don't have a lot of months really to add to that 64 even if we do get surprised with an exceptionally good well.

Operator

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

Bill Crawford

Yes there are, thank you. Thank you all for participating in today's second quarter 2007 conference call. As I mentioned earlier, we will be filing our Form 10-Q with the SEC today and I encourage you all to read it for a more complete review of our results. Thank you again.

Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited.

THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.

If you have any additional questions about our online transcripts, please contact us at: transcripts@seekingalpha.com. Thank you!

Source: Bill Barrett Q2 2007 Earnings Call Transcript
This Transcript
All Transcripts