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Bill Barrett Corporation (NYSE:BBG)

Q4 2008 Earnings Call Transcript

February 24, 2009 12:00 pm ET

Executives

Jennifer Martin – Director, IR

Fred Barrett – Chairman and CEO

Bob Howard – CFO and Treasurer

Joe Jaggers – President and COO

Analysts

Michael Hall – Stifel Nicolaus

Andrew Ganlet [ph] – AFB [ph]

Peter Seden [ph] – Marcson [ph]

Jeff Robertson – Barclays Capital

John Raguzino [ph] – Wachovia

Operator

Good day, ladies and gentlemen, and welcome to the Bill Barrett fourth quarter and full year 2008 results conference call. My name is Clarissa and I’ll be your coordinator for today. At this time, all participants are in a listen-only mode. We will facilitate a question-and-answer session towards the end of the call. (Operator instructions) I would now like to turn the presentation over to your host for today’s call, Miss Jennifer Martin, Director of Investor Relations. Please proceed.

Jennifer Martin

Thank you, Clarissa. Good morning and afternoon, and welcome to Bill Barrett Corporation’s fourth quarter and full year 2008 conference call. Presenting today are Fred Barrett, Chairman and Chief Executive Officer, who will open with an overview; followed by Bob Howard, Chief Financial Officer, who will review financial results; Joe Jaggers, President and Chief Operating Officer, who will discuss our year-end reserve and update you on our development in exploration activities; followed by brief closing comments from Fred Barrett.

A couple of items to mention before we get started. We have prepared a user-controlled slideshow that accompanies our discussion. It is available with the webcast or can be printed from the homepage of our Web site at www.billbarrettcorp.com. Look along the left of the page under Current Events and click on fourth quarter and full year results earnings call slides. In addition, we filed our 10-K this morning, which is also available on our Web site.

I do 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 make reference to discretionary cash flow, which is a non-GAAP measure. Reconciliation to the appropriate GAAP measure was also provided in the press release today.

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

Fred Barrett

All right. Thank you, Jennifer, and welcome, everyone. Our release this morning was entitled another record year. And despite the dramatic decline in commodity prices in the second half of the year and financial markets that effectively shut down, we were able to execute our development and exploration programs to achieve our targeted results while ending the year with a strong balance sheet and well positioned for the year ahead. As testament to our team, fourth quarter results provided record production and solid cash flow in earnings; superior results to many in our sector; and we achieved this against a backdrop of average regional prices of $3.61 per MMbtu for the quarter, and approximately 5 Bcf of shut-ins during the year.

Our company has demonstrated a very strong track record of delivering growth in good years and in bad, and 2008 was no different. In fact, since our company started up in 2002, we have successfully executed an increased cash flow annually, despite years when average regional natural gas prices were terrible, including 2002 when regional prices averaged $1.97 per MMbtu, and in 2007 when they averaged $3.97 per MMbtu. Since going public in 2004, we have increased discretionary cash flow at an average compounded growth rate of 43%.

In 2008, the strength of our company was again demonstrated by our achievements, which I will summarize. Production growth up 27% from 2007 to 77.6 Bcfe. Discretionary cash flow growth of 71% per share to $9.53. Earnings per share growth of 298%, including our impairment charge to $2.39. Reserved growth, fundamental to growth, and our value up 47%, including price related revisions, this equates to 435% production replacement.

Further, we accomplished this for a record low – all and finding and development cost of $1.76 per Mcfe, among the best in the sector, which translates to a three-year average cost of $1.99 per Mcfe. On top of this metrics, our team made an exciting shale gas discovery in the Paradox Basin, which Joe will update you on further. We continue to maintain our reputation as an exploration company with a full plate of prospects where we will continue to invest and make progress in 2009.

On the financial side during 2008, we set up a long range of production hedged positions; opportunistically closed on the convertible debt deal with attractive terms; and upsized our borrowing base with a strong, reliable syndicate; and, we continue to be in a solid financial position as we begin 2009. We are taking a cautious and calculated approach to 2009. As provided in the release this morning, we have refined our 2009 development program to delay certain completions, intending to gain better pricing exposure for these wells. As a result, our capital budget is now expected to be about $50 million lower and production growth will be reduced to 8% to 12%, compared with 2008. Joe will elaborate on this later as well.

I will now turn the call over to Bob Howard, our CFO. And with that, Bob?

Bob Howard

Thank you, Fred. I’ll reiterate that 2008 was an exceptional year for Bill Barrett in terms of operational and financial results. Clearly, the second half of the year brought challenges. However, we were well positioned to meet these challenges and deliver superior results.

Slide four summarizes our results for the full year versus the prior year and for the fourth quarter, compared to both the fourth quarter of 2007 and the third quarter of 2008. Our quarterly results demonstrated a continued production growth achieving record levels, continued operating efficiencies, and our ability to sustain cash flows through our hedging programs despite declining prices.

Oil and gas production for the quarter of 224 million cubic feet equivalent per day was up 19% over the fourth quarter of 2007 and 5% sequentially. Fourth quarter commodity prices were weak. And during the quarter, first of month CIG Rocky Mountain natural gas prices averaged $3.61 per MMbtu, down from $5.90 per MMbtu in the third quarter.

Our realized price was significantly higher than the regional market price as we realized $6.86 per Mcf for the quarter. We were able to do this for a couple of reasons. First, our hedged positions increased natural gas revenues by $53.9 million, which increased our realized natural gas price by $2.77 per Mcf. And second, as a reminder, we have high BTU content gas, approximately 1.1 BTUs per Mcf, which increases the Mcf sales price of our gas. And just to note, in oil sales, our average realized sales price was $6.96 per Mcfe for the quarter, which compares favorably to the fourth quarter 2007 when our average realized price was $6.90 per Mcfe, but down from the third quarter of 2008 realized price of $7.86 per Mcfe.

Our production expenses consisting of these operating expenses, gathering and transportation costs, and production taxes improved to $1.39 per Mcfe, which is down 25% sequentially.

Lower fourth quarter costs are a result of increased efficiencies, fewer well workovers, and lower compressor maintenance costs as well as significant lower production taxes due to a lower well hedged or pre-hedged sales price. Total production expenses per unit were comparable to the fourth quarter of 2007.

A combination of increased production, strong realized prices, and lower production expenses drove solid discretionary cash flow for the quarter of $101.8 million or $2.28 per share. Discretionary cash flow was up 45%, compared with the fourth quarter of 2007 was down only slightly from the previous quarter despite a 39% reduction in CIG pricing.

Net income for the quarter was $6.9 million or $0.15 per share. Fourth quarter earnings included a net unrealized commodity gain of $3.2 million, and non-cash impairment charge of $25.3 million related to certain properties in the White River basin. Adjusting to these items, our income after tax was $20.7 million or $0.46 per share, which is up significantly compared with adjusted net income of $0.03 per share in the fourth quarter of 2007, down from $0.67 sequentially.

Last in summarizing the quarter, capital expenditures total $177 million, which equates to $601 million for the year, representing a record level of activity for the company, which generated refining and development cost that Joe will reveal in more detail.

Before I go into further detail on the full year results, which Fred has highlighted, and which is summarized on this slide and also in the earnings release, but still on slide five, I’d like to emphasize a few key points as we look forward in the 2009 and 2010. First, we are confident in our balance sheet and liquidity position. We ended the year with $254 million drawn on our bank revolver, providing $339 million of available borrowing capacity. Our year-end debt with capitalization is 32%. We have added approximately 111 Bcfe of approved reserves since our last bank client re-determination and we remain well hedged through 2009 and again to 2010 to support our current borrowing base level. We are well within our bank covenants and are comfortable with our well reversed supply bank group, which includes 17 banks and with a well reversed bi-counterpart tri-hedging program, which includes eight firms, all but one of which is a party to our credit facility. Secondly, at 73% to 76% of our forecast 2009 hedge, including basis on the gas blocks of 3.9 Bcf.

Our natural gas hedge positions are illustrated on slide six. Excluding the basis on these swaps, our 2009 hedges have a natural gas floor price of $7.89 per Mcf and oil floor price of $81.79 per barrel. Likewise, we have a solid start for our 2010 hedge position, with 56 Bcf being hedged, including basis on the gas swaps of 11.8 Bcf. Excluding the basis on these swaps, our 2010 hedges have a gas floor price of $7.63 per Mcf and oil floor price of $90 per barrel. To illustrate our 2010 hedge positions of our 2010 production is 10% higher than the midpoint of our guidance in 2009, our current 2010 hedges would be equal to about 6% of this assumed production. Our hedge position has basically bridged potential summer mass [ph] pipeline capacity constraints to 2010. By the summer of 2010, expansions of existing pipeline projects are expected to come on line and increase gas (inaudible) capacity of the Rockies by 2.4 Bcf per day.

Also, we have here our 2009 guidance in this morning’s release. Over the past month, natural gas prices have continued to decline. We are planning our 2009 activities so that the capital expenditures will be aligned with cash flow. We have continued to analyze our capital program with a number of scenarios. As a result, we now intend to slow completion activities and our key development properties. The effect of this delay would be to reduce capital expenditures by approximately $50 million from our earlier guidance, with production growth for 2009 being in the 8% to 12% range. We now expect capital expenditures of up to $350 million and production of 84 to 84 Bcfe. In summary, 2009 will be a challenging year regards to commodity prices, managing growth, or maximizing our return on capital. We are well positioned to operate in the current environment and we’ll remain cautious yet flexible until the broad economic circumstances improve.

And now, Joe will provide an update on our operating (inaudible).

Joe Jaggers

Thank you, Bob. I’ll being on slide number seven. With our reserve picture. Our reserve increases during 2008 are (inaudible) of several distinctive points in our overall performance driving improvement in F&D rate, which I’ll touch on, as well as our DD&A rate, which Bob touched on. The total increase, net of production, and negative revisions was 338 Bcf/d. This increased our reserve production ratio to 9.7 years from 7.7 years at year-end 2007. We’ll make a few brief explanations of major changes or in the case of price-related revisions, the lack of any major revision.

Our year-end prices were $4.61 per MMbtu and $41 per barrel, compared to $6.04 and $92.50 at year-end 2007. And despite the significant, resulting from price was only 7.3 Bcf/d, which, in my mind, speaks to the quality of our development projects, which comprise the majority of the reserve base.

It’s also worth noting that even if today has lower strip prices, the economics of our development projects on an incremental basis range from 15% to 20% rate of return. Our purchases are comprised of slow working interest increases in the West Tavaputs and Powder River Basin CBM areas. Revisions to performance result from both improved well performance in all our major development projects and increased density development in the Piceance and West Tavaputs areas.

We’re turning to slide number eight, which depicts our improvement in F&D. These reserve additions, as well as the improvements in capital efficiency have lead to another year of outstanding F&D cost. Our 2008 F&D was as Fred and Bob mentioned, and our capital weighted rolling three year average is now down to $1.99, an improvement of 50% since 2006 despite very challenging cost circumstances over this period.

Looking ahead to slide number nine, our 3P resources have increased to 2.9 trillion cubic feet for the year in 2007 level of trillion cubic feet, an increase of 45%. The majority of this increase is growing confidence in our ability to develop more of our Piceance acreage on 10 acre density. Over 80% of our yet to be booked resource is attributable to increased density with the West Tavaputs and the Piceance Basin. The majority of which we view as having a very high likelihood of becoming proof for further development. It’s worth noting that none of the prospective resource of Yellow Jacket, our Paradox basin shale gas discovery is (inaudible) cubic feet.

Turning now to slide ten, which highlights our development, I’ll make a few general comments and then get into some property specific comments. First, overall, our rig count, excluding the shale rigs of the Powder River Basin, has declined from 12 to 4 since October. So we’re doing our part in the overall rig decline Fred mentioned. We plan one further rig reduction in the next couple of weeks although this reduction will be offset by the arrival of a purpose filled rig for the Piceance. It’s now expected in the April/May timeframe.

Regionally, we believe the rig count decline may be beginning to impact gas supply. Our analysis of pipeline exports, regional storage draws, and heating degree days suggest the decline of production from December to February. Decline along with increased capacity on Rex effect were 50 million a day. Total storage project fill rates anticipated this summer up to 100 million a day. An expansion of the grasslands pipeline project from the Powder River Basin to Northern Waters pipeline to a tune of 75 million a day point towards a much improved transportation situation this summer than was previously expected.

A third point, and a very important point, we’re fortunately seeing widespread reductions in well construction cost. Examples of reduction are some 40% in high pressure pump in one of the major producing areas, we operate well perforating down 36%, directional work of 15%, cementing down some 20% to 30%, tubulars down some 15% to 25%.

And a final general comment, January production rates averaged 238 million cubic feet equivalent per day. With 40 as an accent rate from the year of 241 million cubic feet equivalent. So in large part, a (inaudible) profile for the year.

But with the year-on-year production increase, as Bob mentioned, of 8% to 12%, we do plan delayed completions throughout the year to match operational constraints in Piceance, this surround water management, in the West Tavaputs, related to CO2 obligations to purchase. We believe that should prices improve, this approach will allow us to quickly raise production by completing these incomplete inventories of wells that we’ll be growing throughout the year.

Now I’ll turn to some specific property updates. For the Piceance Basin, we’re operating two rigs and plans 65 to 70 wells for 2009. Our production is now 92 million cubic feet equivalent per day net. And importantly, we have all the permits in place for the 2009 program. We’re currently making application for 2010 wells under the NRM rules that are in place until full adoption of COGCCs slate for April 1st, in the case of (inaudible) land and May 1st, in the case of federal land.

We’ve opened Uinta Basin in West Tavaputs. We’re operating one rig, plans 16 wells for the first half of the year. As Fred mentioned, the EIS has been delayed. We have initiated discussions with the new administration. In present, we don’t have an indication for how long it will take for the new administration to become comfortable with the document. We currently are producing 89 million cubic feet per day net and plan to move this rig to Piceance after the completion of the 16 wells.

In Blacktail Ridge Lake Canyon, we’re not presently drilling. We’ve established oil capacity of 4000 barrels of oil per day out of 16 well and three wells are awaiting on completion. In Powder River Basin, we planned 55 to 60 wells of the year and are producing 26 million cubic feet per day.

Turning now to slide number eleven, I’ll wrap up with an update on our delineation and exploration activity. Beginning with our exciting Yellow Jacket and Green Jacket here, we’re operating one rig and plan 14 wells throughout the year. We got three wells drilled and completed with three wells awaiting on completion. Two of these are in Yellow Jacket. And our first Green Jacket well is also waiting on completion. We did begin production in December through facilities installed and operated by the Midstream affiliate of our partner Williams and are currently producing some 2 million cubic feet equivalent per day. We’ve began to climb the learning curve here on drilling and see ourselves reducing well cost down to the range of 3.5 million per well. Our first two wells in the area required an average of 26 days to drill to today [ph] in our most recent two wells, it averaged 15 days.

In the Uinta Basin Juan Lopez area in the Hook project, we have drilled and completed the first well, a vertical science well where we did and test gas and oil production. We’ll drill a second well reserve to determine reservoir extended rock properties, and again, this will be a vertical well planned for later this year. In the Wind River Basin at Cave Gulch, we’ve completed the Bullfrog 23-6 in the muddy and the coda [ph] formations. As a result of some operating issues though, we were unable to stimulate the muddy effectively, but are nonetheless producing at a rate of 6.5 million a day with what we believe is the majority of the muddy and all the Frontier potential yet to be realized in this well.

In Montana, the Circus project, we plan to follow the success that the Coolesk [ph] well, a well we drilled and completed in 2008 that produced some 1 million to 1.5 million cubic feet per day, with the completion of the three remaining wells from our 2008 program. These wells will provide us with the necessary information on plagues, that stimulation effectiveness to determine the commercial viability of the project.

And finally, the Big Horn Basin Red Point project test (inaudible) promising sands. This well will be completed and tested during May.

Now I turn things back over to Fred for wrap-up.

Fred Barrett

Thank you, Joe, and again, thank you all for your interest in the company. A few closing thoughts before Q&A. 2008 was a terrific year for Bill Barrett Corporation and we have an experienced and focused team and an asset base with a clear visibility to deliver industry related value growth into the future. 2009 presents new challenges. As we have discussed today and I hope that those joining us today will walk away from this call with a number of key ideas in mind. First, as Bob discussed, we are in secure financial position to weather the broader economic circumstances that confront us. We have a healthy balance sheet, strong liquidity; we’re well hedged for 2010. We also have credible and diversified parties in our bank line and hedge accounting parties. We believe we are financially secure.

Second, we are closely managing our 2009 capital program for development and exploration. We will continue to monitor and mine as necessary our program to maximize our long term investment returns and our development projects, yet maintain flexibility and strength for changing market conditions. We will continue to move forward with our exploration and delineation projects as we continue to process of bringing some of these projects to the early development phase, to best position our company for future success and growth as economic circumstances improve.

Third, we look forward to and we’ll work diligently with our new administration on the environmental impacts statement and the filing of the record of decision and we’ll communicate and expect a timeline as soon as we can.

Fourth, the macro economic environment is clearly presenting challenges to our industry. However, the company is taking steps to leverage the positive economic effects, such as declining service sector cost where possible. Like many, we expect the momentum of supply growth from 2008 to exert downward pressure through pricing in the winter and summer months of 2009. But as several of the cell site analysts on this call projected, we are optimistic that the 42% decline in drill rigs in the Rocky Mountain region and the 36% decline nationwide as of last Friday could potentially translate into production declines into 2010, reversing or at least moderating the current oversupply of natural gas.

Declining supply combined with a return to a healthier demand-driven economy should improve commodity sales prices for natural gas nationwide, over time. More specifically, for the Rocky Mountain region, the expected incremental 2.4 Bcf of combined takeaway capacity, including Ruby by summer 2011 should bode well for improving differentials and realize pricing in the Rockies.

In the interim, we will be cautious, yet flexible with our capital program. We have the advantage of having approximately 75% of our 2009 production hedged and approximately 60% of 2010 production hedged to support our cash flow. During the periods of extremely low pricing, like we saw in the shoulder months of 2008 and 2007, we will exercise discipline on our hedged volumes, including the option to shut end and deploy production to better markets.

And lastly, we added significantly to our proven reserves and resources in 2008, with the understanding, as Joe pointed out, that future growing catalysts like Yellow Jacket have yet been realized on a 3P basis. We will seek to maximize the value of our asset base and expect that the market will eventually reward us for this substantial growth in our development programs and the future potential associated with our emerging plays.

Again, thank you for joining us. And with that, I’ll turn it back over to Jennifer. Jennifer?

Jennifer Martin

Thanks. Chris, I guess we are ready to start the Q&A.

Question-and-Answer Session

Operator

(Operator instructions) And your first question comes from the line of Michael Hall from Stifel Nicolaus, please proceed.

Michael Hall – Stifel Nicolaus

Thank you, good morning.

Fred Barrett

Good morning.

Jennifer Martin

Good morning.

Michael Hall – Stifel Nicolaus

First off, congrats on a solid 2008, and good luck as we head into 2009 here. Certainly set things up quite well though. Looking at the 2009 budget, can you talk about what exactly changed over the last month in terms of where that $50 million came out of?

Joe Jaggers

Michael, this is Joe Jaggers. Principally, that came from delaying the pace of completions throughout the year. The drilling rig activity stayed relatively constant in that exercise, of course, it had an impact on production as we described in the press release.

Michael Hall – Stifel Nicolaus

Okay. And then care to make any comments as to, in what sort of environment you might consider just producing down to your hedged volumes and what CAPEX might look like in that sort of environment? Have you looked at that or

Fred Barrett

Yes. I’ll just make a few comments and hand it over to Bob or Joe. I understand that this is a very volatile and dynamic market. I’m sure, as you’re well aware, I will just say that we’ve been watching this week to week literally for the past five months. Like many companies, we’ve adjusted our budget accordingly and we believe as per our company and the future valued capture on our asset as it relates to the environment. And we’ll continue to do that week to week as we move to the first and end of the second quarter.

We are – have – looked at scenarios in the future where – into the near future where prices are radically different from where they are now. And we’re prepared to make additional adjustments if we have to. And to that end right now, we’re still playing reasonable economics even with the $3 strip in price in ’09, and call it the $4 dollar strip price in 2010. With that, Joe, you got anything else you want to add to that?

Joe Jaggers

No. That captures it, Bob.

Fred Barrett

Michael, we certainly watch the prices and the economics. Most of our operating costs, these operating cost are fixed costs, and we have a tremendous resource base that I think I – especially as we get started earlier in the year, prices would have to, basically, probably almost go to zero in order for us to say we’re going to shut-in and expect that we’ll get better prices down the road. We do have a long term asset that we want to continue to evaluate.

We think we’ve cut very close to where we think the right budget for a long term. We do have some leeway there. We try to have, but this was – it’s running a going concern business. I think we have a little bit of flexibility at the end on the prices before we just take production down to hedged volumes. However, on a day to day basis, we don’t like prices, we will shut in from time to time, probably, throughout the summer, especially into the shoulder months of fall.

Michael Hall – Stifel Nicolaus

Okay. Thank you. And then certainly, your commentaries regarding Rockies production was encouraging. Would you care to quantify at all what sort of clients you’re talking about that you’ve seen December to February?

Fred Barrett

No, but I’ll describe what we did there Michael.

Michael Hall – Stifel Nicolaus

Yes.

Fred Barrett

You can run some numbers on your own. We looked for periods of equivalent heating degree days so we can be reasonably confident here in the Rockies. Local consumption was somewhat somewhere. We looked at pipeline exports and draws from storage here in the Rockies. And if you do make that HDD assumption that you’re fixing local demand with that, you can see some pretty market declines from early December through this most recent week.

Michael Hall – Stifel Nicolaus

Okay. So that’s kind of more of a weather adjusted production, I guess in a sense, or–?

Fred Barrett

No, it’s trying to get the demand constant. Population waited heating degree days, and looking at how much gas is leaving and how much gas is coming out of storage. The balance we included has to be a decrease in local production. Now, that may be some amount of shut-in production resulting from pricing, but we believe prices were strong enough throughout both of those periods that producers would have had an incentive to go ahead and produce.

Michael Hall – Stifel Nicolaus

Okay. That’s helpful. Thank you. And then finally, 2009 F&Ds, would you care to comment as to you think you’ll continue to see the three-year trend, continue to see declines particularly given the cost environment?

Fred Barrett

We were hopeful nobody would try to extrapolate that three-year–

Michael Hall – Stifel Nicolaus

That thing we do, though.

Fred Barrett

I know you do. So we went in with the annual, and there –I think, we’d expect comparable results through our annual 2008

Michael Hall – Stifel Nicolaus

Okay. So (inaudible).

Fred Barrett

Yes.

Michael Hall – Stifel Nicolaus

Okay. Thank you. Congrats again.

Operator

And your next question comes from the line of Andrew Ganlet [ph] of AFB [ph]. Please proceed.

Andrew Ganlet – AFB

Good morning. Could you please elaborate on the sentence in the release on Colorado beyond space and new rules? And specifically, the additional cost and delays in the operations. Could you just elaborate a little bit on what that could mean and perhaps quantify the (inaudible)?

Joe Jaggers

Andrew, we wanted to clarify that with the presentation day, we made the point we’re taking care of ’09. Permanent shelf life on this permanent is a year. So we’re well ahead of things, but as you can see with rules going into effect April 1st, sometime in 2010, we’ll become governed by the new rules. It’s yet to be seen exactly what the ways and cost associated with the new rules. Certainly, there’s a far bigger record keeping, reporting, application, preparation part of the process. And there are some real changes that affect operations, particularly, around drilling pits, and completion pits, and flow back arrangements.

We estimate now that the incremental costs, depending on our success or lack of success, and being able to contained systems and eliminate pits is around $50,000 per well. So on a $1.8 million well, currently not a tremendous improvement, and hopefully, that we can offset with other service cost sector reductions that we’re seeing.

The ability of the commission to process permits to speak of the timing hadn’t really been established yet since the new rules aren’t in effect. We’re operating under some interim rules that are a great deal different than the old rules right now. Does that help?

Andrew Ganlet – AFB

Yes. Thank you very much. Second operating questions probably also for you, Joe, is on the Powder River. You talk about that with all the wells that you drilled this past year and the year before, they started to de-water. And therefore, even if you drill last production can still rise quite a bit, I guess, so if you’re doing 26 or so a day today, that can still grow somewhat. And I’m curious how much we might see production there at the Powder River.

Joe Jaggers

Give us a second, Andrew, I’ll come up with an exit rate on that. But you’re right. We’ve got of laid the foundation for production increase this year despite really low activity. And that production increase in the Powder will allow us to be flat largely through the year. Okay, we’re 26 now, and we exited just under 40.

Andrew Ganlet – AFB

Okay. Thanks so much.

Operator

Your next question comes from the line of Peter Seden [ph] of Marcson [ph]. Please proceed.

Peter Seden – Marcson

Yes. Actually, my question was about Colorado as well, but on your Web site these fourth quarter slides aren’t showing up, these are third quarter slides that are showing up.

Fred Barrett

Okay. We’ll get those up there. Thanks for letting us know.

Peter Seden – Marcson

Okay. Yes.

Operator

(Operator instructions) And your next question comes from the line of Jeff Robertson from Barclays Capital. Please proceed.

Jeff Robertson – Barclays Capital

Thank you. Joe, at West (inaudible), will you all be through until you get the EIS release for rig in June?

Joe Jaggers

No. We plan to go back out there and drill. We’ve got more locations on state sections there that are available to us. We’ll continue to seek Federal permits. This year’s program is comprised of about ten Federal locations and six state locations. Those ten came under the categorical exclusions of what we try to process of more of those for 2010 as well.

Jeff Robertson – Barclays Capital

Okay. In Piceance space in New York, the 10-acre wells, can you compare the reserves per well recoveries you all are anticipating on 10s versus the 20s?

Joe Jaggers

More like on a marginal differences on the order of 10%. We’re looking at an average GEUR [ph] of 1.2 to 1.3 on a parent well, and maybe 10% less than that from some communication and depletion in the 10-acre offsets.

Jeff Robertson- Barclays Capital

Then lastly, at Yellow Jacket, the three wells that you planned this year, I think you said you think you’ll pretty much know how the play on folds after those wells. Can you talk a little bit about what you’re doing with respect to infrastructure needs to develop that?

Joe Jaggers

I’ll let Fred talk about the delineation. I’ll have to come back. Talk about the infrastructure.

Fred Barrett

Well, 2009 is going to be characterized by a number of things, Jeff. One is, Joe mentioned, we’ve got a 14 well program. We’ve got three wells completed in there. We have about three wells that are waiting on completion out of the initial group that we’ve drilled. And part of – part of the efforts right now is an optimization in terms of what we’re doing. The frac and pull back designs and our drilling. How long we’re drilling these laterals. And we’ve been experimenting, if you will, with the – with various stimulation techniques in that program.

I would – I would say, up to this point we’re extremely excited about the area. We just finished acquiring our first 3-D seismic in the Koskie Area to the south. And so that gives us two 3-Ds in the area. We’ll continue permitting additional 3-D acquisitions through 2009. The program will also be characterized by continuing to obtain permits to drill. Right now we’ve got about 12 permits in various stages. We’ve got another eight in the queue that we’ll be moving forward on. So we’ve got a full population of permits to work with.

I would also just mention that – that 95% of the activity will take place in – in the Yellow Jacket proper. But over in Green Jacket I would highlight that the horizontal we drilled there, our 3,500 foot horizontal in Hovenweep. We’re very, very excited about the gas shows. I think we’ve seen some of the best gas shows in the region. In Hovenweep – in that Green Jacket well we haven’t completed it yet. We’ll complete that, I think, in April or – or May. So it’s a continuous program. We’re focused on bringing this to a point where we understand how we want to drill in terms of the cost, how we want to complete them in terms of the number of stages in frac and stimulation procedures. And I think it’s going to be towards the end of the year before we really get our arms around exactly what we want to do there.

Now, in terms of the infrastructure, I’ll hand it back over to – over to Joe.

Joe Jaggers

Okay, Jeff. It’s pretty straightforward at this point. We’ve got two small temporary facilities located in a northern area we call the Johnson Area and a southern area we call the Koskie Area. And these – these provide hydrocarbon dew point and connect directly to Northwest Pipeline. We’ve got inlet compression, outlet compression, capacity of about 10,000 million a day, each. Expandable to 20,000 a day. And by the end of the year, when we’ve got a firmer idea of what the resource potential is in the area, we’ll make a decision about which way to go for the next phase of facilities.

Jeff Robertson – Barclays Capital

Joe, is there much – are there many capacity constraints on either TransColorado or Northwest?

Joe Jaggers

Well, yes. They’re both full at this point. So we’re selling directly into the pipeline. Our preferred alternative, given enough size and scale to this play, would be a dedicated line to the San Juan Basin where we can access the two major pipelines. El Paso’s and Enron’s old line to Southern California. And that would take care of any issues with either TransColorado or Northwest.

Jeff Robertson – Barclays Capital

Okay. Lastly, Joe, will this area be any more or any easier or any more difficult to work with, with the new Colorado rules in the Piceance Basin?

Joe Jaggers

Well it’s a – it’s about 50% fee. So it will be under the jurisdiction of COGCC for that acreage. It’s a much smaller impact development than, for example, the ten acre density in the Piceance. At 80 acres, even a well, you’re only talking about eight per section which we could probably get on two to four pads.

It’s agricultural land primarily. So it’s laid out beautifully on east-west, north-south grids that allow us to put pads just directly adjacent to these unpaved county roads and provide for easily accessed right of ways for pipelines up and down these roads. So I think COGCC rules would be much less impactful here than in some of the more intense developments and – and challenged topography in the Piceance.

Jeff Robertson – Barclays Capital

Thank you.

Operator

And your next question comes from the line of Michael Hall of Stifel Nicolaus. Please proceed.

Michael Hall – Stifel Nicolaus

Thanks. This is just a quick follow up. From what you’re hearing on your side of things, everything’s still going Ruby? No indications of El Paso pushing that out or anything along those lines?

Fred Barrett

As far as – as far as we know (inaudible) to build their pipeline. They reported they’re done with their arc [ph] work, their subsurface work along the right of way for the pipeline. And, as far as we know, and given just their public financial activities, we believe that they’re – they’ve got plenty of capacity under their facility. As far as we know, everything is a go. Can you confirm that Joe?

Joe Jaggers

That’s my understanding as well. We’ve got a meeting planned next week with El Paso executives. They’ll take us on the project and have several conversations with them. We’re setting up those meetings and they’ve indicated no issues with schedule or financing at this point.

Michael Hall – Stifel Nicolaus

Great. Good to hear. And then, I know it’s way out there, but looking at 2010 you’ve brought the rig count in 2009 way in. At what point does the low rig count in 2009 start to impact your ability to grow in 2010?

Fred Barrett

Joe said we’re flat just production [ph] wise through to 2010. Bear in mind that we’ve strategically placed a number of completions further out into the year and into 2010. Which I think will be a good cushion and base production support for 2010. We don’t – I think, like everybody else, we’re waiting to see what the markets and the environment’s going to be like as we approach 2010. I would like to think it’s going to be better than ’09. But who knows? So I think just stay tuned for more clarity on that as we move forward.

Now, Joe may have more on the –

Joe Jaggers

But just a little additional detail, Fred. We do continue to grow at these levels in 2010. It’s modest growth but we do expect to continue.

Michael Hall – Stifel Nicolaus

Okay. That’s (inaudible). Thanks for the color.

Operator

And you have a follow up from the line of Andrew Ganlet of AFB. Please proceed.

Andrew Ganlet – AFB

Yes. Thanks for letting me ask a follow up. By the way, the slides are up on the – on the Web site. Fourth quarter. Someone said that (inaudible) have said that gas could start flowing into the San Juan as early as 2010. In the later half of the 2010. Is that a time table that you’re comfortable with?

Joe Jaggers

Well, it currently flows into the San Juan through the Northwest Pipeline. But now my point on 2010 was we’d be in a position to make that decision for the dedicated line. It’s still depending on which plant we terminate at in San Juan, 40 to 50 miles away and probably a two year construction period.

Andrew Ganlet – AFB

Got you. Thank you.

Operator

(Operator instructions). And your next question comes from the line of John Raguzino [ph] of Wachovia. Please proceed.

John Raguzino – Wachovia

Hi. Good morning, everybody.

Joe Jaggers

Good morning.

Jennifer Martin

Hi, John.

John Raguzino – Wachovia

You spoke about the significant decline in Piceance rig count recently. Can you talk a little bit about the pricing and day rates you’re seeing out there? And then, maybe, where they’re off as far as on their peak this summer?

Joe Jaggers

John, this is Joe Jaggers. They’re down. I understand about half from the peak of the summer. From 90 rigs to 40 some odd rigs. The day rate improvement for a conventional mechanical rig, we’re looking at probably something around $12,000 a day. Down from $16,000 to $17,000 a day. And then those – those service sector reductions that I quoted earlier, they apply to the Piceance as well.

John Raguzino- Wachovia

Okay. Great. And then a different way to ask Mike’s question. If you look at the continued delay in the EIS and considering the new administration, what kind of a question mark that puts in front of the situation? What kind of impact do you see in 2010 if, worst case scenario, it’s not approved? How does your capital allocation look in 2010 as a result if you want to go ramp up in your other core development projects?

Fred Barrett

Yes. I would – just a couple of comments here and more specifics on operations from Joe. But I – we have additional locations and state plans and what not. We have close to 2,000 acres of state lands and (inaudible) and we continue like we’ve been doing under the – within the interim EIS, if you will, to come up with a valid drilling inventory from year to year. So we’ll continue with that process. We do have swing areas. Especially if Yellow Jacket really begins to emerge, and I think it is, as a swing area to – especially if prices improve and likewise over in the Piceance Basin. But, again, we’ll give you a timeline on that as soon as – as soon as we know. But, Joe, any further details?

Joe Jaggers

Well, Fred, I think you hit it well. We would respond to that situation with applying capital in these other areas.

John Raguzino- Wachovia

All right. Well, that’s very helpful. Thanks very much and congratulations on a great year.

Operator

And there are no further questions. At this time I’d like to turn the call back to Ms. Jennifer Martin for closing remarks.

Jennifer Martin

Well, thank you all for joining us today. Peter will be happy to forward those slides to you and anybody else who may have any trouble. Just feel free to drop me a note, give me a call, or something. We’ll make sure you have what you need. And that concludes our call. Thank you again.

Operator

Thank you for your participation in today’s conference. This concludes the presentation. You may now disconnect. Good day.

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Source: Bill Barrett Corporation Q4 2008 Earnings Call Transcript
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