Seeking Alpha
We cover over 5K calls/quarter
Profile| Send Message|
( followers)  

Bill Barrett Corp. (NYSE:BBG)

Q3 2009 Earnings Call

November 3, 2009 12:00 pm ET

Executives

Jennifer Martin – Director, Investor Relations

Fred Barrett – Chairman and Chief Executive Officer

Bob Howard – Chief Financial Officer

Joe Jaggers – President and Chief Operating Officer

Analysts

[Mike Pena - Simmons]

Brian Singer – Goldman Sachs

David Tameron – Wells Fargo Securities

Andrew Gundlach – ASB

Jeff Robertson – Barclays Capital

Kristal Choy – Raymond James

Raymond Deacon – Pritchard Capital Partners

Brian Kuzma – Weiss Multi-Strategies

Operator

Welcome to the Third Quarter 2009 Bill Barrett Corporation Earnings Conference Call. (Operator Instructions) I would now like to turn the conference over to your host for today's call, Ms. Jennifer Martin Director of Investor Relations.

Jennifer Martin

Presenting today are Fred Barrett, Chairman and Chief Executive Officer who will open with an overview followed by Bob Howard, Chief Financial Officer, and Joe Jaggers, President and Chief Operating Officer.

I have a couple of items to mention before we get started. We have prepared a few slides for the company in our discussion, which are available with the webcast or it can be printed from the homepage of the website at billbarrettcorp.com. Look along the left side of the homepage under current events and you can click on the earnings call slide. In addition, our third quarter 10-Q was filed this morning and is also available on our website.

I would like to mention that we will be participating in a few upcoming east coast events. We will be at the Boenning & Scattergood SMID Cap Conference in Philadelphia this Monday, November 9, at the Bank of America Credit Conference in New York on December 3, and the Wells Fargo Exploration and Production, Energy Services and Utility Symposium in New York on December 9. We look forward to seeing many of you at those events.

I need to remind everyone to read the forward-looking and cautionary statement disclosures on slide two of our presentation, which were also included in our press release today. During our discussion, we will make reference to discretionary cash flow and adjusted net income which are non-GAAP measures reconciliations to the appropriate GAAP measures were also provided in the press release today.

And with that, I will turn it over to Fred Barrett to get started.

Fred Barrett

We'll go ahead and start out on slide number three. Our strong operating performance continued through the third quarter positioning the company to realize 13% to 15% production growth for the full year and delivered cash flows well in excess of the 2009 Exploration and Development Capital Program.

I'll summarize a few highlights that Bob and Joe will elaborate on here a little bit later. We have raised the top end of production guidance to 89 Bcfe, a production growth of 13% to 15% is now well ahead of our original expectations of 8% to 12%.

In the third quarter, we produced 22.8 Bcfe, our highest quarterly production to date. We continue to seek out and execute operating efficiencies that are driving down our LOE. While third quarter expenses were up sequentially as expected due to increased work-overs, our LOE guidance for the year is now reduced to $0.53 to $0.54 per Mcfe versus our original estimate of $0.60 to $0.66 per Mcfe.

We're also realizing operating efficiencies under our capital program, not just due to lower service costs industry-wide and have again increased the number of wells we expect to drill in the Piceance to 115 to 120 wells. We have expanded our companywide capital program of such for 2009 to between 170 and 180 wells while maintaining our targeted exploration and development budget of approximately $350 million. And our execution drove particularly strong cash flow in the third quarter at $108 million or $2.39 per share, which by the way was well ahead of our consensus estimates.

I'm very pleased with the strong performance in our key development programs, which remain our largest growth catalyst. In addition, it is the strategy of this company to identify and develop new resource placed through a balance of both the drill bit and through acquisitions when the right strategic opportunity presents itself.

And while exploration of the mainstay of the Bill Barrett culture, realistically it does come with ups and downs as part of the business, a risk that we effectively manage and mitigate through our partnerships and program sell-downs.

During the third quarter we saw a range of exploration results, which Joe will review in more detail. But in short, we met less encouraging results at both our Circus and Hook prospects. And we are currently assessing the future direction of these areas, whereas conversely at Yellow Jacket we're quite encouraged to date by the very large fracture stimulations used on the last two well completions.

These were about double the size of earlier fracs. We have to test these wells for a longer period of time and being careful not to put the cart before the horse, we are seeing better sustained flow rates than on previous wells. As a reminder and as we've said in the past, we only need one of these sizable growth catalysts in our portfolio to work in order to substantially add to the size and value of this company.

Before I turn the call over to Bob and Joe, I will make a few comments on natural gas prices. The fall did not bring the expected decline in Rockies natural gas prices. For October, spot prices have averaged $3.85, well above what we've seen in the past two years. At this point, CIG asked frac within $0.10 of NYMEX on average for the past couple of months. And of interest, the recently posted November CIG index price at $4.32 represents a premium to Henry Hub.

The forward strip indicates an average differential of $0.48 for 2010 and $0.67 for 2011. In short, the Rockies pipeline capacity issues are no longer with us for the foreseeable future. I would reiterate a very important point here, that we are a low cost producer. And combined with decidedly narrow differentials, we'll deliver margins and returns we believe competitive with our shale gas peers, which we hope to see reflected in our multiples going forward.

And with that, I will turn it over to Bob Howard our Chief Financial Officer.

Bob Howard

Following up on Fred's comments, we had very strong production in cash flow in the third quarter and we are on track to exceed our 2009 plan. Slides four and five summarize our results for the quarter. We won't got through the complete list, but I'll discuss a few points for better clarification to help with your modeling.

Production totaled 22.8 Bcfe, which is up 16% from last year and up 3% sequentially as producing activities in the Uinta, Piceance and Wind River Basins were all stronger than we had originally anticipated for the quarter.

Our averaged realized sales price was $7.03 per Mcfe, which was down as expected from last year at $7.86 per Mcfe but up $0.39 per Mcfe sequentially. The sequential increase was primarily due to two factors, increased liquid sales from both the Piceance and West Tavaputs Projects and higher prices for the unhedged portion of our production.

Lease operating expenses were down $0.07 per Mcfe from last year to $0.57 per Mcfe, primarily due to cost savings associated with improvements in water handling, and were up sequentially as expected as we performed more work-overs during the quarter.

The gathering and transportation charges were $0.71 per Mcfe for the quarter, which was increased from $0.52 per Mcfe last year and $0.58 per Mcfe sequentially. This increase relates to higher processing charges in the West Tavaputs and Piceance Projects, as well as higher firm transportation charges associated with the continued expansion of the Rockies Express Pipeline.

As a result, we are increasing guidance and I'll expect gathering and transportation charges to average $0.63 to $0.65 per Mcfe for the full year. As a reminder, the increased processing more than offset will increase revenues from the sales of the [inaudible]. Our DD&A rate was comparable to the second quarter was up compared to last year due to a reduction improved undeveloped reserves based on lower June 30 gas prices used for the mid-year calculation as we described last quarter.

During the current quarter, dry hole expenses were $17.7 million when I related to capital expenditures for eight wells in three project areas. After-tax our dry holes reduced earnings by $10.4 million or $0.23 per share. Interest expense including the amortization of financing cost was $9.7 million for the quarter compared to $5.1 million for the prior year quarter primarily due to higher effective interest rate on the senior notes that were issued in July.

The bottom line was that net income was $700,000 or $0.02 per share for the quarter and adjusted net income was $7.9 million or $0.18 per share, and discretionary cash flow was $107.7 million or $2.39 per share, which is a slight increase over last year, a 5% increase sequentially and well above the consensus estimate of $2.03 per share.

Regards to the balance sheet, we have clearly maintained a strong financial position. In October our borrowing base into the bank line of credit facility was increased to $630 million from $538 million, and commitments were restored to $593 million, returning the availability that we had prior to issuing the senior notes in July. We have paid down the balance on the credit facility [inaudible] million and currently at $573 million in liquidity.

As we plan our budget for next year we anticipate generally aligning capital expenditures with cash flow which will maintain our strong liquidity position. Including the credit facility, our 5% convertible notes of face amount and the principal amount of the bond offering, we have total debt of $443 million. Our debt-to-book capitalization rates was 32% which includes other comprehensive income and capitalization, and debt to total market capitalization is 24%.

As Fred mentioned, we have updated 2009 guidance to increase production to 88, 89 Bcfe and to reduce LOE to $0.53 to $0.54 per Mcfe. Gathering transportation guidance was increased as I just mentioned and we have narrowed and slightly reduced our G&A expense guidance to between $39 million and $40 million.

Going into 2010 we have strong hedge positions in place for 56 Bcfe of production which will support cash flows and mitigate volatility that could occur in natural gas commodity prices, and a liquidity position that provides us the flexibility of desire to take advantage of new opportunities that may arise.

I'll turn the call over to Joe who will provide more detail on our operations.

Joe Jaggers

I'll begin on slide six and before I get into the details surrounding our development projects make a couple of general comments about operations and the operating environment. First in operations we continue to see improvement in our days to drill wells generally, in particular in the Piceance Basin where our 2009 average now stands at 6.6 days spud to spud versus 10.1 in 2008 in just under eight reported last quarter.

Continued improvements attributable to a combination of small adjustments to mud systems, bit selection, mud motors, and the like and we do expect further improvement as we move to generally pads with higher well counts, but that further improvement will be modest. Overall well construction cost continue to be low relative to 2008 peaks with the reduction we've seen being on the order of 35% across the entire suite of well construction services.

Our strategy over the next few months is to lock in service cost to the extent possible in order to continue realizing these lower costs through 2010. As Fred mentioned, our commodity pricing the narrowing basis we've seen over the last several months is generally widely recognized at this point. The strength though of daily cash prices perhaps not so well understood.

Over the past three months while CIG first a month has averaged $0.40 less than NYMEX, the daily cash is averaged just $0.16 less than NYMEX. Establishing a point we've made previously that Rockies gas trades are commonly clearing near the marginal cost of transportation. This is something we believe will impact other regional pricing as unused capacity becomes more prevalent and gas markets generally become more national as a result. Echoing Fred's comments, we do not see Rockies' transport picture changing for several years.

Our internal analysis of compared of project economics indicates that our Piceance and Uinta Basin projects compete very well with the current high profile producing areas, largely as a result of our favorable cost structure.

When you combine the greater pricing parody with the generally lower cost structure, lower lease cost, and generally provide higher nets, we got high heat content, high liquid yields, access to processing to take advantage of this yield, and adequate pipeline transport for both gas and liquids. We believe our projects are well positioned to continue to compete economically.

Turning now to the development projects in the Piceance at Gibson Gulch, we're continuing to operate three rigs and now expect to drill 115 to 120 wells. This is up from 105 to 110 reported last quarter largely as a result of improved drilling days. We're currently producing 102 million a day and expect to end the year at about 107 million a day. We're comfortable with the permit situation at Gibson Gulch, both this year and in 2010.

At West Tavaputs currently producing 83 million a day and expect to see decline through the remainder of the year to 74 million a day at year end. As results from earlier completion of our 2009 wells and the lack of additional activity, we continue to work with stakeholders to achieve a development approach that will achieve a recorded decision during 2010. And believe we're making tremendous progress of course the evidence of this progress will be a recorded decision when we ultimately do receive it.

Blacktail Ridge continues to meet our expectations. We're currently completing the three remaining incomplete wells from our late 2008 early 2009 program and plan to resume drilling operations during 2010. As a reminder, we established our EUR expectations for Blacktail Ridge at 325,000 barrels of oil equivalent in well cost of 3.4 million that we discussed on the second quarter call.

Powder River activity continues at relatively low levels. We're meeting offset drainage commitments, lease obligations and maintaining momentum in our de-watering operations. Production has increased to 35 million a day and expect to end the year at some 38 million cubic feet per day. All told our development operations are exceeding expectations as evidenced by our increased production guidance and our discretionary cash flow of $4.73 per Mcfe.

Turning now to our Delineation and Exploration Program on slide seven, we've completed our drilling and completion activity for the year. In the Paradox at our Yellow Jacket project currently producing 5.7 million a day from seven horizontal wells and our two most recent wells are producing over 4 million per day combined. These wells were completed using high volume and high rate stimulations very comparable to what's done in other shale plays.

We're concentrating on optimum stimulation and learning to void the operations issues presented by salt production. Our capillary string completions appear successful in avoiding salt deposition in our tubing wellheads and chokes. It's still early but as we'll see on the upcoming slide, these last two wells have producing encouraging early production results.

In the Uinta Basin Hook project the initial horizontal well is not commercial. We continue to do pressure and test work to determine next steps based on results and analysis, further work in 2010 will be decided.

In the Montana Overthrust project, we completed three of the four vertical wells that we drilled in 2008. And while they all produced hydrocarbons, they did so at low rates and pressures and with large volumes of associated water. Because we don't believe we currently have a scalable regional resource opportunity, we've discontinued the program while we consider our alternatives.

Slide eight provides additional detail on the two Yellow Jacket Gothic wells that I mentioned previously. Both stimulated with high volume treatments as an example, the Koskie well was completed with 123,000 barrels of water over a 3,240 foot horizontal section pumped at an average pump rate of 67 barrels a minute and included 1.8 million pounds of sand, by a factor of two our largest completion to date there.

The plot shows production rates since tubing was installed in the early flow back has been up casing. We've produced the Koskie well for a total of 38 days, it's averaged 2.1 million a day and currently produces 2.4 million a day. The Neely well is half a lateral just under 2,000 feet and has produced a total of 12 days at an average rate of 2.3 million a day, has had tubing installed just this past week and is currently producing 2.1 million a day.

The plot compares these early rates post-tubing installation with expected performance from type wells producing 2.0 and 3.0 Bcf and the early production falls in this range between 2.0 and 3.0 B's, and is just that. Its early projection data and the EUR will clearly depend on the decline rate and point at which these wells stabilize and begin a terminal decline.

Several more months of production are needed before EUR will be firmly established, and when we hold our year end call in February we'll be in a much better position to judge long-term well performance. If we're fortunate enough to achieve results in the 2.0 to 3.0 Bcf range, the lower chart provides result in economics.

At current strip pricing, the rate of return for wells between 2.0 and 3.0 Bcf ranges from just over 20% at the low end to 50% for the 3.0 Bcf well. And these economics are based on our expected $3.2 million well costs in development operations where we'll being in a position to share pads, infrastructure, and have integrated water disposal facilities available.

As a reminder, we've got 100 sections that lie between the two wells that have provided these encouraging results that has a thickness in the Gothic section over 100 feet and some 29,000 net acres, much of which is [fee land]. In 2010, we'll continue to refine completions, modifying potentially lateral placement, lateral length, and pump schedules, but nonetheless, we're encouraged by these early results.

With that, I'll turn things back over to Fred.

Fred Barrett

I'll wrap up with just a few brief comments using slide number nine with comments that I hope you'll takeaway with you today. One, our operations group continues to execute on all fronts, 2009 to date we have sizably reduced our operating costs. We have significantly improved drilling times and we're delivering double-digit production growth despite the difficult market environment.

Secondly, we're well positioned to move into 2010 on a number of fronts. One, with our low risk repeatable growth platform from our long-term development portfolio. We also have a positive outlook for natural gas prices. That, combined with our strong hedge positions, will deliver reliable cash flows.

We'll also move into 2010 with the financial strength and flexibility necessary to manage our growth and take advantage of the opportunities as they arise. And we will continue to work hard and stay focused to deliver the next development asset whether it's through the drill bit regulatory processes or, as I mentioned, the next potential opportunity here in the Rockies.

More specifically, we are working closely with stakeholders in the West Tavaputs and Cottonwood Gulch projects to resolve outstanding issues and move forward and will keep you up to date there as we learn going forward. We are putting together our 2010 operations plan right now and our outlook is a very optimistic. We look forward to providing you with more details on that program in late January.

With that, again, thank you all and I'll turn it back over to Jennifer.

Jennifer Martin

Operator, I think there are a few question in the queue if we want to go ahead and get started with the Q&A session.

Question-and-Answer Session

Operator

(Operator Instructions) Your first question comes from [Mike Pena - Simmons].

[Mike Pena - Simmons]

Joe, question for you. In these two recent Gothic shale completions, what specifically allowed you to better mitigate the salt issues you had previously while still achieving large fracs?

Joe Jaggers

The early efforts with what I've called the boutique fracs, the small fracs using combinations of sand sizes to try to establish barriers to isolate from the salt, weren't entirely effective. There were some limited success with avoiding salt, but generally we continued to produce salt saturated brine on flow back. But what we decided to do simply in these last two well completions was ignore that possibility of contacting salt and work on optimum stimulation of the reservoir and learn to live with salt.

So most of that learning to live with salt has been the installation of these capillaries strings, just a small stainless steel continuous tubing that's banded to the 2-3/8 where we inject fresh water down hole and that, as you can see from the plot there, has produced our most stable results to date. We've had no issues with salt deposition at all in tubing wellhead, chokes, production, equipment, that sort of thing.

[Mike Pena - Simmons]

Then the program there going forward is to continue?

Joe Jaggers

It's currently being developed, but it will depend a lot on these next few months of production, but we do plan to resume activity in 2010. It's just a matter of how many wells and what the timing is. I think I've mentioned this previously, but this area has got a pretty well developed system of irrigation ditches. And those open late in the spring and we want to be in a position to use that water when it's available, particularly when we're doing these high, high volume frac jobs it allow us to avoid a lot of trucking expense that you generally have.

[Mike Pena - Simmons]

Then you guys mentioned earlier your view of kind of Rockies basis going forward. If you look at the forward curve, how does that impact your hedging strategy going forward? Does that keep you from going as far out in hedging or is it that's still the plan to protect cash flow?

Bob Howard

We would expect we'll certainly pay attention to the basis as we enter into our hedges, but we still feel it's appropriate to protect our cash flow by hedging at prices that work well at that net Rockies prices. And so when we set our hedging targets, we do set those targets at a CIG equivalent price which is where we sell our gas and try to match it up to the economics that we see from development of properties.

[Mike Pena - Simmons]

So more driven by the threshold price rather than trying to time the market or anything?

Bob Howard

We aren't trying to really hedge the basis more just the absolute price that we get that matches up with what we'll be able to sell our gas to so, yes, try to match it up to the local price.

[Mike Pena - Simmons]

One more question, just given the results from this quarter from the mostly shale dry holes, how does that impact or alter your strategy going forward with Rockies shale gas? Is there anything in particular that's made it structurally maybe more difficult geologically just relative to the Gulf Coast and Mid-Con shale plays? And then, how would you consider maybe a Mancos shale pilot program going forward?

Fred Barrett

The shale programs in the Rockies just in general with this industry are still very early in the game. I think there's still a lot to learn. I think in my opinion there's going to be a number of very attractive prolific shale plays that emerge in the Rockies. It's a matter of getting the right technologies applied and following through on those technologies. As it relates to Bill Barrett Corporation, we'll continue with monitoring and assessing Yellow Jacket, as Joe mentioned. We'll continue to follow up there in 2010.

When you look at, for example, Hook, I think the big question there is do we want to follow through with another horizontal there, apply a different type of frac technology or a larger size frac? The Circus area, we still think there's actually a resource play in the Circus area but given their early results, one of our business options is to bring in either a partner or eventually divest of that area, so we still have a few things to do there as well.

When you look within our portfolio, we do continue to evaluate other new opportunities that we do maintain a full pipeline of ideas. But we can afford to be extremely selective on any new plays that we move forward with just simply because of the size of the resource base that we've put underneath the company which wasn't there in the early days of the company.

So we can afford to be very selective. We'll still maintain our sell-down strategy, but we'll able to rigorously manage the size, the timing and the phasing of our activity moving forward. And so when you peer into the portfolio, yes, we recognize a number of areas where we do have Cody or Mancos shale gas a potential in some areas, for example like West Tavaputs, it's a matter of testing the Cody.

We have seen gas rates in the West Tavaputs area. We have Cody potential or Mancos potential underneath our Cottonwood Gulch area, as well as a number of other areas, and I think through time, you'll probably see us test that. But again, we'll be very selective and rigorous on where we do that.

But just remember, when it comes to the Rockies there's a tremendous amount of new opportunities that exist. And with our portfolio, we think we're right there in the thick of it in terms of establishing the next play. We'll certainly stay focused on Yellow Jacket. But I think it's just a matter of time before we get these horizontal technologies really implanted into the Rockies before you begin to really see the next shale play emerge in this region.

Operator

Your next question comes from Brian Singer – Goldman Sachs.

Brian Singer – Goldman Sachs

I wondered if you could provide a little bit more color on Yellow Jacket following some of the new stimulation methods. Does that at all change your spacing assumptions given that you're using longer or larger fracs and do you have some sense as to whether there's any changes or your own estimates for prospectivity of your acreage position?

Joe Jaggers

Brian, this is Joe, I'll take a stab at that. It's really too early to tell what the spacing situation will be. We're continuing to sort of conceptually think about this in terms of 160 acres per well so you got four in a section.

In terms of prospectivity, we find that really for the entire acreage position, we find it encouraging that there's some eight or nine miles between these two wells and their early production data looks very similar. And it's clearly too early to conclude that everything in the middle produces. The consistency of this deposition and this rock would certainly lead you to begin thinking in that direction.

Brian Singer – Goldman Sachs

On a totally separate question, could you give us any of your current thoughts on potential pursuit of assets or a core area outside of the Rockies?

Fred Barrett

Brian, as I've said in the past, we're very focused on the Rockies, that's what we know best. And I think two things there is that we have very strong financial position right now as you're well aware, over $575 million in liquidity. But we also have a number of catalysts that we hope to see emerge through 2010 with which we can use that liquidity on.

But we also see the potential for a lot of new opportunities to emerge in the Rocky Mountain region. I think the competition in the Rockies is in a state of flux where a lot of companies are focusing more and more on these other shale gas plays. Now we've looked at those shale plays in reference to the shale plays that we're looking at in the Rockies. We're aware that there are opportunities out there.

But I would just say at this point, Brian, that as we continue to move along here that it's going to take a very special opportunity out there for us to engage in an asset outside the Rockies. But never say never in this business.

Operator

Your next question comes from David Tameron – Wells Fargo Securities.

David Tameron – Wells Fargo Securities

Can you guys talk about the well costs on the Piceance? I know you had been talking about costs were coming down. What's the current completed well cost?

Bob Howard

Currently, David, we're looking at about $1.7 million per well. And as I mentioned when I talked about well construction costs, we see them significantly down, but we don't see them continuing to go down. And we think it's the right time tactically to start locking in 2010 to assure we continue this cost structure through next year's program.

David Tameron – Wells Fargo Securities

Will the service companies lock in rates right now, Joe?

Joe Jaggers

Well, what we'll need to do is get through the rest of our planning cycle here and we've got a board meeting in November. We'll get a plan developed and we'll go to the market in December/January. And yes, some of them I think will lock in for the year, some of the services.

The rig contractors have been reluctant to take over six months at a time. I think we can lock in the pumping service side of things. And most of the other things like mud systems and directional work and bits we can do pretty well locking in, but the rig contractors haven't been willing to take more than six months at a time right now.

David Tameron – Wells Fargo Securities

Piceance in general, we're hearing positive things from the [oxys] all the way down to the berries, as far as market cap. People seem to be focusing more on that going forward in 2010. Is that similar to what you're hearing? Do you see activity picking up out there? Is that just a function of service costs coming down in Rockies differential? Or any color you can add there.

Bob Howard

Well, I think that's it exactly, David. Yes, we do see some rig activity increases ourselves these early days. But in some of our thinking about planning for next year, we're thinking about increasing the number of wells here because the economics are so good for us. Those 1.7 million per well costs give us a sort of mid-50 rate of return pre-tax at the current strip.

So it's a place where we're mostly on fee land permits are well in hand and understood, and then we've got the infrastructure situation that's improved so much out there with the White River hub, with Williams new processing plant coming on, it looks like a good place to be active next year.

David Tameron – Wells Fargo Securities

Going to the Paradox, what was the cost with the, I guess the frac job you did? What does that bring the total well cost to or can you give us the targeted well cost going forward?

Bob Howard

Well, the target is the $3.2 million that I mentioned earlier and that does include that large stimulation treatment, but it also includes being able to access those ditches and avoid a lot of the hauling cost. It's really a cost target that's with a development in mind that we're on pads where we share the pad with two or four wells. We've got the advantage of existing infrastructure. We've got a water management and disposal system in place.

We've got capacity out there to produce and process about 20 million a day now between the two Williams plants. So whatever we do in 2010 will be with that constraint in mind. Currently when we do an exploratory well in a new area, no infrastructure and some additional data gathering we're running about 4 million to 4.5 million.

David Tameron – Wells Fargo Securities

Finally, regulatory front, can you talk about, I think you have a mediation hearing this month for the Rome Plateau and then I believe you had something in October as far as the Uinta Basin. Can you just give us the latest and greatest update on both of those?

Joe Jaggers

Well, I'll talk a little bit about the West Tavaputs EIS. Having the Cottonwood Gulch project, given the sensitivity of that and the pending litigation/mediation, I'd prefer not to say anything about Cottonwood Gulch until a later date. But the Tavaputs EIS, we've continued to meet with stakeholder groups.

And if you generally think of those groups representing three constituencies, the cultural artifact groups, the wildlife groups and sort of the wilderness groups, we have essentially closed the loop with the former two, the wildlife and cultural artifact groups. We're continuing to work with the wilderness groups represented by [SUA] and we think we're well along in terms of establishing a compromise we can both support there. So that's the primary activity in that area right now.

David Tameron – Wells Fargo Securities

And still first half 2010?

Joe Jaggers

That's our thinking

Operator

Your next question comes from Andrew Gundlach – ASB.

Andrew Gundlach - ASB

Congratulations on the improved results in Paradox. How does that affect the Green Jacket in any way?

Joe Jaggers

Well, the Green Jacket well we've only drilled the one. It produced gas at about 500 Mcf a day. It was again one of the early fracs where attempts were being made to avoid salt. So, our thinking is we won't understand Green Jacket until we do one of these large stimulations, but we still see it as an add-on to Yellow Jacket. And we feel like we've got the benefit of most of our leases held by production over there and can afford the luxury of working through Yellow Jacket before we commit ourselves to large expenditures and work programs in Green Jacket.

Andrew Gundlach - ASB

So, more a 2011 reexamination than 2010. Is that the way to think about it?

Joe Jaggers

Yes, Andrew, that's exactly the way I'd think about it.

Andrew Gundlach - ASB

Then obviously you don't want to comment, as you said earlier, on the November 6 mediation, but you were highlighted quite visibly in the New York Times on October 30 this issue and I'm curious about two things. First of all, does that attention do you feel help you or hurt you? Where is the press coming from? And the second thing is what should one expect on November 6? Is the issue whether or not to go back to the environmental groups or proceed? What's the outcome?

Joe Jaggers

Well, Andrew, again we all saw the article. It didn't particularly paint us in a favorable light, but again we don't want to comment on what to expect or what our reaction to that might have been. Please just respect that the litigation and mediation process and when we know news and we're in a position to talk about it, we'll be issuing something.

Operator

Your next question comes from Jeff Robertson – Barclays Capital.

Jeff Robertson – Barclays Capital

Joe, a question on a costs that you all are working on locking in. Can you talk about what the contract service companies are willing to offer or what you all are willing to negotiate versus where costs are currently to lock things in for up to a year on some of the different things you're using?

Joe Jaggers

Jeff, we really haven't begun that process because we're doing that planning step that I mentioned earlier. It will be December/January before we get programs issued to these guys and it'll be late January is our thinking that we'd get prices back in. But absence of marked improvement and increases in rig count, my expectation is we'll be able to assure something close to what we're seeing here in 2009.

Jeff Robertson – Barclays Capital

Secondly at West Tavaputs, if you get [SUA] on board do you then just go to the BLM and present the plan and they sign off on it or is there more involved than just that?

Joe Jaggers

Well, our simple thinking, Jeff, is that yes we go arm-in-arm with these other stakeholders and jointly say that we agree to wave forward here. Whether there are additional steps in here, it wouldn't surprise me at all if there were. Nothing's ever quite as straightforward and simple as we'd hope.

Jeff Robertson – Barclays Capital

Will your drilling at Tavaputs then, Joe, be in 2010 will it have to wait until the winter restrictions have ended and you all can go back out there and work, and how much of it is also going to be related to the EIS process?

Joe Jaggers

Well, that program in Tavaputs on state lands we can resume activity there in January and that's our current thinking is we've got a number of permits in hand that we can go back to Tavaputs and drill beginning in early 2010.

The federal lands though, the EIS preferred alternative says, and I think I've mentioned this before, that you can't move dirt build locations install pipelines until those winter big game stips get lifted in May. So, on federal lands it's sort of we could get the EIS record decision today and not be able to do anything until May/June next year. So, we've got a bit of a cushion here to work with.

Operator

Your next question comes from Kristal Choy – Raymond James.

Kristal Choy – Raymond James

Trying to tie up some of the operating stuff in the Powder River Basin it's smaller, but can you give us some detail on what you're seeing on your re-perfs and that initial Koskie test?

Joe Jaggers

Kris, I think perhaps Powder and Paradox got confused there, but in the Powder we're not doing and re-perf work. We occasionally work wells over for pump failures and coal finds and that sort of thing. Does that help at all?

Kristal Choy – Raymond James

Yes it does. Thanks for the clarification. Then kind of bigger picture, I was wondering if you could talk about maybe shut-in volumes. I know you brought on some, maybe some detail on what wells you have on inventory and the timing of those.

Joe Jaggers

Well, in terms of shut-in because of the strong pricing through the fall that Fred mentioned, we haven't shut-in any of our production. In terms of inventory on incomplete wells, I don't have those numbers at my fingertips, but we'll circle back later in the call and provide those if you're interested.

Operator

Your next question comes from Ray Deacon – Pritchard Capital.

Raymond Deacon – Pritchard Capital Partners

Joe, I was wondering a couple of companies this quarter have mentioned that they thought they could sort of duplicate growth in 2010 with less capital than they expended in 2009. I guess, when do you expect to put out your 2010 forecast on production, and I guess do you have any comments on that in terms of efficiency and ability to grow in 2010 versus 2009 with maybe less capital out there?

Joe Jaggers

Well, we'll be issuing our production guidance in January along with our year end reserve totals. As far as growth in 2010 goes, I think we've said before, we expect to continue to grow. We're in the middle of that planning process capital allocation and production forecasting, so it's early for us to say exactly how much.

Raymond Deacon – Pritchard Capital Partners

I guess can you just remind me, I'd heard you mention once going to drilling more wells per pad and that might give you more efficiency in the Piceance. Just how many wells are you drilling now and where do you think that could go?

Joe Jaggers

Well, our 2010 plan does have higher well counts per pad, we're generally around 12 right now, some of our pads next year we're going to be up to 19 wells per pad and you're right. In terms of rig moves, you save some costs there. In terms of laying gathering systems and water management systems out to these pads you save money there. So there is increase efficiency with these higher well counts.

And to the earlier question about the incomplete wells, I think Kris asked we're 59 in the Piceance right now and eight at wet Tavaputs. And really the 59 is not unusually high given how quickly we've been drilling these and we're not planning a real campaign at year end to try to take advantage of higher gas prices. That's just sort of our routine number right now.

Operator

Your next question comes from Brian Kuzma – Weiss Multi-Strategies.

Brian Kuzma - Weiss Multi-Strategies

These recent Yellow Jacket wells with the bigger fracs, how much did they cost?

Bob Howard

They cost on the order of $4 million to $4.5 million, Brian.

Brian Kuzma - Weiss Multi-Strategies

How much of that is completion costs?

Joe Jaggers

It's about half and half is where we are.

Brian Kuzma - Weiss Multi-Strategies

Then just on the economics of Yellow Jacket, what is the cost to get gas do you think from the well site to CIG fully processed and everything. What kind of numbers should we be using there?

Joe Jaggers

Well, what physically happens out there is Williams gathers for us. They have a couple of small [Dupoint] control plants and then we tie directly into Northwest pipeline. So what we're selling gas for is more of a Northwest pipeline San Juan price than a CIG price. It's on the order of $0.35 gathering in compression and then we're splitting liquids with our gatherer there, Williams.

Brian Kuzma - Weiss Multi-Strategies

Then help me understand on the salt issue, the salt is down below. You're putting bigger fracs on it. If you were getting salt before, you're clearly going to get it now. And is the idea here that you're just getting a lot more gas with it that it becomes less of an issue or help explain that?

Joe Jaggers

You're absolutely right. We got it before with the small fracs, we're clearly getting it with these larger fracs and the operating improvement is this capillary string that we've begun to install and we install it early on. Wells will typically flow back 10, 12 days we get the water volumes down to where we can handle it on our equipment. We'll install tubing, we'll go to our production equipment and it's become just more of a task in learning about how to live with the salt rather than how to avoid the salt.

Our early wells were very erratic in production performance and, as you can see on that Koskie 13-H plot, it's very smooth, largely because we've avoided any deposition of the salt. And that capillary string, just one other point of clarification, we're pumping fresh water down the string at rates of 20, 30 barrels a day and that's enough, because its entirely fresh water, to dilute that saturated brine and cause it to continue to flow and not to precipitate salt.

Brian Kuzma - Weiss Multi-Strategies

The issue is the salt in the well borer, precipitating in the well bore not precipitating in the formation?

Joe Jaggers

That has been the problem in the past is in the tubing, not in the formation.

Operator

There are no further questions at this time. I'd like to turn the call back to Jennifer Martin for closing remarks.

Jennifer Martin

Well, just thank you everyone for joining us today and as usual, if you have additional questions or thoughts just give us a call. Thank you.

Operator

Thank you for attending in today's conference. This concludes your presentation. You may now disconnect.

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 Corp. Q3 2009 Earnings Call Transcript
This Transcript
All Transcripts