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Bill Barrett Corporation (NYSE:BBG)

Q2 2014 Earnings Conference Call

August 1, 2014 11:00 AM ET

Executives

Jennifer Martin – VP, IR

Scot Woodall – CEO and President

Bob Howard – CFO and Treasurer

Analysts

Jason Wangler – Wunderlich Securities

Ryan Oatman – SunTrust

Brian Singer – Goldman Sachs

Brian Corales – Howard Weil

David Tameron – Wells Fargo

Pearce Hammond – Simmons & Co.

Chris Stevens – KeyBanc Capital Markets

Jeffrey Connolly – Mizuho Securities USA, Inc.

Jeff Robertson – Barclays

David Beard – Iberia Capital Partners

Operator

Good day, ladies and gentlemen. And welcome to the second quarter Bill Barrett Corporation’s earnings call. This call is – my name is Sarah, and I’ll be your operator for today. (Operator instructions)

I would now like to turn the conference over to Jennifer Martin, Vice-President of Investor Relations. Please proceed.

Jennifer Martin

Thank you, Sarah. Good morning everyone, thank you for joining us. Speaking today will be Chief Executive Officer, Scot Woodall, and Chief Financial Officer, Bob Howard. A few quick notes before we get started. Our form 10-Q was filled yesterday afternoon and it is available on our website under SEC filings.

Second, as usual, I need to remind everyone of the forward-looking and other cautionary statements provided in yesterday’s earnings release. In addition, during our discussion, we make reference to non-GAAP measures such us discretionary cash flow and adjusted net income, reconciliations to the appropriate GAAP measures may be found in the second quarter earnings release which is posted on the home page of our website.

With that, I will turn it over to Scot Woodall, to get started. Scot?

Scot Woodall

Thank you, Jennifer, and good morning everyone. We appreciate your interest. Second quarter results were straightforward and right on track with our internal plan. Total production with the upper-end of our guidance range for the quarter at 2.62 million BOE equivalence and oil production exceeds 1 million barrels this quarter.

We are right on track to deliver full year production between the 11 million and 12.2 million barrels of all the equivalent, and to deliver oil production growth of 30% over 2013 levels.

Oil production was up 25% in the second quarter of 2014 compared with the second quarter last year. And oil production was up 11% sequentially.

Our capital dollars have been focused in the DJ basin and in the East Bluebell area of the Uinta Basin where second quarter production was up 141% and 56% respectively year-over-year.

It was an exciting quarter in the Northeast Wattenberg as the team was able to accelerate the drilling of extended reach laterals. We now have 16 extended reach laterals that are in the process of getting those wells completed. We are pleased with the accuracy and the efficiency of the drilling phase of this program. Twelve of the wells have approximately 9,000 foot lateral lengths, and four wells have approximately 7,000 foot lateral lengths.

From a completion stand point, we’re using 40 fracture stimulation stages with around 9 million pounds of sand per well. Seven of the wells are in the Northern portion of the Northeast Wattenberg area, and nine are in the Southern block and they include a combination of Niobrara B and Niobrara C zones.

Going forward, we will continue to refine our completion designs as we will be testing plug-and-perf designs, different stimulation fluids, and varying quantities of sand. Our drilling program will be focused in the Northeast Wattenberg portion of the DJ Basin through the remainder of the year with a three-rig program.

In the Uinta Basin, last quarter we increased the number of wells we expected to drill due to drilling efficiencies and faster drilling time. And we’re going to do that again, now. We were increasing the 2014 two-rig program to include 54 gross wells, 34 net wells.

In general, we are very pleased with the operations in this area. Costs are stable and trending below our East Bluebell tight curve as we are drilling these wells in about 10 days. Production from the Uinta oil program is up 17% sequentially from the first quarter as overall well performance continues to be a published type curve which has an estimated #60% rate of return.

Third quarter activity in these core areas, it’s expected to include spudding approximately 15 wells in the DJ Basin, and completing approximately 10 and spudding approximately 13 wells in Uinta Oil Basin. And completing approximately 10 of those wells.

Of note for – of note, we estimate the extended reach laterals in the DJ basin take about a month the flow back to clean up. Across our development area, our operations and technical teams will continue to optimize completion designs and continue to analyze data together and best assessed down spacing opportunities in the core area.

In the Powder River Deep, we participated in six non-op wells as we minimize our activity here during the sales process. We are actively engaged in negotiations. So I’ll not elaborate too much on the sale status here.

I will say couple of things. It appears that it is in the best interest of our shareholders for us to divide our position into several transactions. These transactions may include multiple buyers, swapping acreage and potentially retaining a portion of the acreage.

Negotiations and signing multiple agreements, obviously takes longer than working through one document. I am confident however, that all will be signed up by year-end and most likely in the third quarter.

Before I turn it over to Bob, I’ll comment on the Colorado ballot initiatives. I think most of you are aware that there two anti-industry initiatives, numbers 88 and 89. Initiative 88 would establish a state-wide setback of 2,000 seats from occupied buildings for new wells. Current regulation setbacks are 500 feet from houses, and a 1,000 feet from schools and hospitals. And initiative 89 would expand in local control of oil and gas development.

The supporters of the initiatives are currently collecting the signatures required for these proposals to be placed on the November ballot, and Monday is the deadline for these signatures. It will likely take several days for the accounts to be tallied, and to get confirmation whether each of these initiatives will actually be placed on the ballot.

Our company strives to maintain positive relationships with our host, land owners and communities. We work within the considerable authority already vested in the Colorado Oil and Gas Commission, and local governments to balance the interest of development and the community.

We believe that the ballots would disrupt this, carefully consider regulatory and legal framework. These measures would have an impact not just on the oil and gas industry in the state of Colorado, but on Colorado’s economic future as a whole.

Accordingly, a broad coalition of businesses, local governments and current and prominent political figures have rally in opposition to these ballots. This formal of cross-section [ph] of Colorado is working hard to educate the public about our industry and to spell a lot of the misinformation that is out there. If these measures make it to the ballot, count on a united campaign to defeat them.

We have generally reviewed our exposure to 2,000 foot setback requirement, and find that with our generally rural position, less than 3% of our DJ acreage position would be directly impacted.

With that, I’ll turn the call over to Bob.

Bob Howard

Okay. Thank you, Scot. We had a straightforward quarter in regards to operating and financial metrics. I’ll be brief in my comments. I’ll remind everybody that the form 10Q and the schedules to the earnings release provide detailed information about our results.

Once again, we post the solid quarter with operational and financial metrics consistent with our internal plan, and positioning us well for the remainder of 2014 and into 2015. As Scot mentioned, second quarter production came in at the upper – end of our guidance. And to reiterate some of the important metrics associated with production, oil accounted for 39% of total production which is up from 22% of total production just one year ago. And production growth from our key development programs in the DJ Basin and these Bluebell areas were 141% and 56% respectively year-over-year.

The transition to our oil projects are being reflected in our financial results with the discretionary cash flow of $67.3 million for the quarter or $1.40 per share which is an increase of $12 million from the first quarter and slightly beating consensus estimates.

Cash flow from the DJ Basin and all oil program [ph] properties, now account for two-thirds of total field level cash flow. Discretionary cash flow per barrel production was $25.66, up 47% from the year ago, demonstrating significant growth in our operating margin per equivalent barrel production compared with just one year ago.

DJ any rate [ph] increased by $2 per BOE in the second quarter compared to the first quarter, and is up $5 per BOE from the second quarter of 2013. [Indiscernible] increase production from our higher cost oil projects and the timing and interaction of development cost in Missouri growth areas [ph]. Our DD&A rates [ph] should begin stabilized so we continue to focus on our two core areas and become further long in our transition to these oil areas.

To summarize our oil focus, we expect to see a positive trending cash flow growth and profitability going forward as we drive higher oil production to achieve associated cost efficiencies with increasing scale.

I’ll wrap up my part [ph] with a couple of comments on the balance sheet. We ended the quarter with $1.1 billion in debt, in a trailing 12-month equity but as the ratio of 3.4 times [ph]. This is above where we would like to be through a combination of portfolio management and growing EBITDA, we will continue to work towards our long-term goal of debt levels that are not more than 2.5 times EBITDA.

With that, that completes our prepared comments. And I’ll turn it back over to – for question and answer.

Question-and-Answer Session

Operator

(Operator instructions) And our first question come from Jason Wangler from Wunderlich Securities. Please proceed.

Jason Wangler – Wunderlich Securities

Good morning everyone.

Scot Woodall

Hey, good morning Jason.

Jason Wangler – Wunderlich Securities

Curious on the operations update in the Niobrara as far as the two multi-well pads. Is there any way we could get a better sense of how those broke down, because obviously you had the mechanical issues on one of the pads, just maybe the differences in the two and how you’re seeing the production on each?

Scot Woodall

Sure, Jason. We went into a core, 648 core Wattenberg, 640 acres section. And we drilled a 10-well pad. And that’s called the “Merit Pad [ph].” And we really had a tremendous amount of operational issues. One, one of the wells is basically junked and abandoned because it’s a sliding sleeve type of a completion. And we lost a craw bar down in there.

And so, the remaining nine wells which you should think would take maybe two weeks to complete, probably took us closer to 40 days to complete with kind of a combination of a numerous weather related issues, and also partly numerous mechanical issues with our service provider.

And so, after we took about 40 days to complete the wells and put them on flow back, then we experience the fire on location which shutdown things for a number of weeks as well while we kind of redid the surface facilities. So that probably was not the company’s best effort all the way around. But those nine wells that are included in the 11-well total that you see. That was in the press release today, those nine wells on their 30-day IP average, 300 barrels of oil equivalent per day.

Now, next door in the adjacent 320 on that same 640, we drilled a six-well pad. And two of those wells have been online for 30 days and are included in that 11-well average that you saw in the press release, those two wells average for 30 days is 463 barrels of oil equivalent per day.

So I think it’s pretty clear that it is not a reservoir issue associated with that 640 acre section that the 320 merit pad [ph] really did is something that was kind of messed up by us and our service provider with a little bit of combination of weather issues there.

So the remaining six-well pad I think is on track. I’m sure the other four wells will reach their 30-day IPs later this month. And I’m sure they’ll be included in a subsequent release. But we feel pretty comfortable that it’s meeting or exceeding our expectations from that pad.

Jason Wangler – Wunderlich Securities

Okay. I appreciate the color Scot. And then one more, with obviously 16 extended reach laterals, I would think that that was pretty much the majority if not all of the drilling really done in the second quarter. It sounds like obviously we’re going to be getting close to getting those completed. And I think you said, it takes you a month or so to get them cleaned up. But do you have an idea of just in rough terms, the timing of how those wells will come online? And as far as over the next few months, is it going to be a couple each month or is it going to be very – is it going to be very lumpier? Just kind of how you see that playing out?

Scot Woodall

Most of those sit on three and four-well pads. So a little lumpy, I guess I would say, but not terrible. And so, it’s probably not that different than 640 pads coming online. But you’re right, some of the previous quarter is consumed in drilling those longer laterals, because obviously they take a little bit more time. But you’re hitting on a point that we’re obviously very excited about is to get those things drilled and operationally the drilling of those things went extremely well.

We have completed a four-well pad that is currently in the flow back stages. And the completion on that went very well. We’re finishing up the completions of a two-well pad as we speak right now.

So we feel like that we’re kind of ahead of the game or ahead of our internal plan on getting those things executed. And I’ve been pretty pleased with the execution. Obviously we’re anxious to see the results as well. But I really think that when you look at extended reach lateral economics in general compared to regular length economics, it definitely is an uptick.

So we’re pretty excited and think that we’ll have some pretty solid information over the coming weeks.

Jason Wangler – Wunderlich Securities

I appreciate it. I’ll turn it back.

Operator

Great. Our next question comes from Ryan Oatman from SunTrust.

Ryan Oatman – SunTrust

Hi. Good morning.

Scot Woodall

Hey, good morning, Ryan.

Ryan Oatman – SunTrust

In the DJ, it appears the net well as you all expect to drill this year declined from about 65 to 56, while even the plant increased [ph] from 26 to 34 net wells. Can you kind of speak to what’s behind that shift? Does that an allocation to capital from one play to another or more just a reflection of more of the laterals in the DJ being extended reach laterals?

Scot Woodall

Yes. It doesn’t represent a capital switch at all, Ryan. It is the well count decreasing in the DJ is really just of switching to drilling more extended reach laterals. There’s obviously some working interest changes that go with that when you pull two sections say for example. And so, we’re still running the three rigs. So we haven’t change rig count at all in the DJ. It’s just a function of the extended reach laterals.

Conversely over in the Uinta Oil Play, we’re exceeding our estimated drilling time curves there which is a good thing. So we’re continuing to run the two rigs, but we’re just able to drill and complete more wells this year with the same two-rig program due to our cost efficiencies.

Ryan Oatman – SunTrust

Make sense, make sense. And then very quickly – I mean, as you mention in the press release, the year-over-year oil growth has accelerated from about 16% in the first quarter, 24% in the second quarter. You guys have reaffirmed expectations for 30% growth in oil output for the year. Can you speak to what provide you confidence that oil growth will continue to accelerate in the back half of the year?

Scot Woodall

I think it’s primarily due to our execution in terms of well spud, wells online is right on line with our internal expectations. And so, some of the hiccups say that we just talked about with the merit pad [ph] and some of those things, were all factored into our guidance growth rates. And I think those things are behind us. And we seem like we’re way on track to meeting those expectations.

Ryan Oatman – SunTrust

Very, good. I’ll turn it back. Thank you.

Operator

Great. Our next question comes from Brian Singer from Goldman Sachs.

Brian Singer – Goldman Sachs

Thank you. Good morning.

Scot Woodall

Hey, good morning, Brian.

Brian Singer – Goldman Sachs

On chalk Bluffs, can you just add a little bit more color on the change between your preliminary positive results from the two wells versus the more muted – more muted four-well rates? And how do you think about completion techniques in well and location selection going forward?

Scot Woodall

Sure. We were up there Brian and drill that [ph] four wells really probably in the Southeast corner of our acreage position. We completed those four wells. The initial probably week of production probably was more closer in lined to what our expectations were when subsequent to that, seems like they’re falling off a little bit. And so, those one month rate that you see us quoting there are probably less than what we’re hoping for.

You know, as we look at Chalk Bluffs, clearly in our minds we have that as an exploration area. I doubt that there’s probably much value on our stock because of that expiration nature of that play. I think we’ve gathered some data. We have some plans to gather some additional data. The play may trend more north in west from these initial wells which we do have a pretty significant acreage position to the north and west as where we are.

So I think we’re going to have to continue to monitor our results and monitor the industry’s results as well. You alluded to something that I think is important a little bit is we went up there probably with our normal Codell completion design that we do in the core part of the Wattenberg Field. And that’s a 4,000 foot lateral with, say, 4 million pounds of sand. There are others that are drilling longer laterals and three and four times the amount of sand volumes. And I think that’s something that we may have to consider in subsequent follow-up activity.

Brian Singer – Goldman Sachs

Great, thank you. And then shifting to the – you went to – you had a nice step up in production. Last year I recall a lot of the CapEx suspension in the first half; it doesn’t look like that’s the case. It seems more level loaded. But can you talk to that trajectory and then should we expect a similar step up in production from oil production from the basin in the third quarter and the fourth quarter as what we saw in Q2?

Scot Woodall

Yes. Well, you’re right. We do expect that the capital spending program would be flat for the remainder of the year. Last year, we did lay down rigs after we had met our desired budgeted number of wells. This year, we’re planning on just going ahead and exceeding that number of wells and continue to operate the two wells.

So capital spending should be flat. Yes, it would be my expectation that the East Bluebell area would continue to rise in production as we continue to put these things online and they continue to perform well.

Brian Singer – Goldman Sachs

Great. Thank you.

Operator

Great. Our next question comes from Brian Corales from Howard Weil. Please proceed.

Brian Corales – Howard Weil

Good morning, guys.

Scot Woodall

Good morning, Brian.

Brian Corales – Howard Weil

In the Niobrara, have you all brought on – I’m just trying to remember if you all brought on extended laterals in the first half of the year. And kind of secondarily, are all those 16 wells that you’re – or horizontal wells, are those – the extended lateral wells in Niobrara, are those all coming on in the second half of this year?

Scot Woodall

Yes. We have not put on any extended reach laterals yet. So the first half, we did not put on any. And so all of our extended reach lateral production will come on in the second half of the year. As I mentioned earlier, we do have four of them flowing back now but they’re still in the flow back dewatering stage right now.

Brian Corales – Howard Weil

Okay. And so we could see – I guess looking at the third quarter and fourth quarter the Niobrara volumes, we should see a pretty big uplift then compared to what we saw on the first half?

Scot Woodall

Yes, I would think so. Obviously, I think we’re in position with those extended reach laterals already drilled and the program pretty well outlined and on track. Yes, that would be our expectation.

Brian Corales – Howard Weil

Okay. All right, thank you.

Operator

All right. Our next question comes from David Tameron from Wells Fargo. Please proceed.

David Tameron – Wells Fargo

Hi, good morning. Scot, up in Chalk Bluffs, can you talk about – you said you didn’t get the well performance, I mean if you went ahead with 20 million pounds, how long some of your competitors – I mean, do you know exactly what went – why the reservoir didn’t act as you expected it, because like you said, the place is a little further north in west, I think is what you said earlier. Can you just possibly give us a little more detail there?

Scot Woodall

Sure. Well, I guess the impact to sand volumes is something that we may have to look at. But just in general, when you do the mapping geologically across there, we’re a little thinner. We’re about a 20 foot-ish Codell package versus, say, the wells that you’re referring to are probably more like 30 feet. So there is a thickness difference.

But does 20 feet work? I think that’s what we’re probably trying to understand. And as I mentioned earlier, most of our acreage now from where we drilled trends northwest which will go up into more like 25-foot thick type of an area.

Thickness is one piece of this. Obviously, the other reservoir parameters come into play with that too. So I think getting some of the core and looking at the core in our area versus the other areas is just other homework that our technical teams are going to have to do.

David Tameron – Wells Fargo

All right. Okay, well, that’s helpful. And if I think about the DJ, can you at least give us a snapshot – I know you’ve talked about the FX sales [ph], but you can give us a snapshot of where you’re headed over the next year, year and a half as far as development drilling, where are you planning – where the activities should take place? Just give us a big picture, a snapshot of what the drilling schedule looks like?

Scot Woodall

Sure. We’re planning on continuing to run these three rigs throughout the remainder of 2014, why it’s probably early to start talking about 2015 but that is probably at least a starting point to be thinking about 2015. I think that all of our activity will generally be in that Northeast Wattenberg area.

I mean I think we believe that that is the most profitable area that we have in the portfolio and we’re going to continue to exploit and develop it. I think these extended reach laterals from what we see and what others have done and then when you look at what others do in other plays, it seems like most of the time our industry heads toward extended reach laterals, more sand and that generates a more profitable economic model.

Our acreage is extremely blocky over there in the Northeast Wattenberg area and it lends itself to this type of development. And so if I was to look out over the next year, I would think that we’re going to continue to run three rigs in the Northeast Wattenberg area and continue to primarily develop through extra length laterals.

David Tameron – Wells Fargo

Okay. And then you talked on plug and perf, sliding sleeve and there’s been some wells that have tried one approach or the other, can you talk about that a little bit?

Scot Woodall

Sure. We have – on the 16 wells that we have already drilled, and I don’t have the numbers exactly here, but there are a few that are cased and are going to be trying the perf and plug route versus the sliding sleeve route, as well as I know on about three of them of the 16, we have plans on doing more like 12 million pounds of sand versus 9 million pounds of sand as our pseudo standard. So each of those variables I think will be tested in the 16-well package.

David Tameron – Wells Fargo

Okay. And then the last question. From time to time, you haven’t talked about it in a while. But the peance [ph], what’s your latest thinking as far as longer term – does that asset belong in the portfolio, does it not and if – just any thoughts around the peance [ph]?

Scot Woodall

Sure. I don’t think our position on the Piceance has really changed. We still don’t see that it competes for investment opportunities with East Bluebell or with the Northeast Wattenberg position. So I do not believe that we’ll be directing any capital towards the Piceance in the foreseeable future.

In terms of does it fit in the portfolio, not fit in the portfolio, is that something that we’d monetize at some point, I think the answer to that is yes. I think it’s probably just the timing of when we may or may not choose to do that. And I think that’s something that we talk about internally pretty frequently.

David Tameron – Wells Fargo

Okay. And that five-year law – or however many year lawsuit that’s out there, would that change your thinking at all if that gets resolved?

Scot Woodall

Say that again. I didn’t quite understand the question –

David Tameron – Wells Fargo

Of the lawsuit that’s – with the BLM] (inaudible) number of years, is that acreage you’re not allowed to drill right now, that’s in out there – if that were to be resolved, would that change any of your outlook for the Piceance?

Scot Woodall

No. I really don’t think so because I still think that the Piceance asset doesn’t compete financially with the rate of returns that we’re generating in DJ and East Bluebell. So, no, I don’t think it changes our position.

David Tameron – Wells Fargo

Okay, okay. That’s all I got, thanks.

Operator

Right. Our next question comes from Pearce Hammond from Simmons & Co.

Pearce Hammond – Simmons & Co.

Good morning.

Scot Woodall

Good morning, Pearce.

Pearce Hammond – Simmons & Co.

Scot, I apologize. I think I missed your prepared remarks when you were talking about the setback provisions and the anti-energy ballot initiatives here in Colorado. Did you mention what percentage of your locations could be affected by that?

Scot Woodall

Yes. When we look at it from an acreage perspective, the 2,000-foot setback in the DJ basin probably impacts about 3% of our acreage.

Pearce Hammond – Simmons & Co.

Great. Thank you for that. And then in the southern end of the Northeast Wattenberg extension area, how is infrastructure development coming along?

Scot Woodall

There is some that’s being put in right there. We went down there and we have drilled a couple of wells down there and they’re currently in the stages of getting online. But there are some expansions to infrastructure that needs to happen that’s being permitted is not yet in place.

Pearce Hammond – Simmons & Co.

Great. And the last one from me, I think a few years ago when BBG had acquired that acreage up in Chalk Bluffs, you all drilled a few wells there. How would you compare and contrast the well performance versus the four that you announced with the release and then those of a few years ago, and I know that probably the drilling and completion design are very different from then to now, but love to get your thoughts on a compare and contrast.

Scot Woodall

Sure. The ones we did a couple years ago were horizontal in the Niobrara B. The ones that we just drilled these last four were horizontal in the Codell. So you’re kind of in different formations. And so that’s not probably a direct comparison.

The original Niobrara B ones that we drilled had quite a bit of range. Some of those ranges 30-day IPs were probably above what we’re quoting today in our press release and some would be below.

Pearce Hammond – Simmons & Co.

Thank you, Scot.

Operator

All right. Our next question comes from Chris Stevens from KeyBanc.

Chris Stevens – KeyBanc Capital Markets

Hey, good morning, guys.

Scot Woodall

Good morning.

Chris Stevens – KeyBanc Capital Markets

With the wellbore spacing out in Niobrara with Bonanza right next door testing 40 acres in each zone, is that something you guys think is viable and are you guys planning on testing any tighter spacing?

Scot Woodall

It seems like it’s something that needs to be tested. And we’ve tested – well, we have plans to test spacing of that level in various, like 320s. And so I think you’ll see us do that probably more on a 320 or a 160 versus an entire 640.

You have to remember, on our acreage position, particularly in the southern block, probably the two perspective formations that sit there is the Niobrara B and the Niobrara C. So I think you could see us do the design where you’re doing alternating Bs and Cs at that type of spacing.

Chris Stevens – KeyBanc Capital Markets

Okay. And on the extended reach laterals, can you just talk a little bit about the cycle times on drilling there and how that compares to the 4,000-foot laterals?

Scot Woodall

Yes. We would probably drill on the 4,000-foot ones in eight or nine days. And we’re probably in the 15 to 16 days in the extended reach laterals. Completion times, obviously when you’re doing 40 stages or 45 stages versus 18 to 25 stages, that extends that out a little bit.

And then the other thing is, as I’ve kind of mentioned a little bit before, because of the huge volumes that you pump in and 40 to 55 stages of completions, it’s going to take maybe closer to a month to flow all the water back. And so that will just kind of delay a little bit before you start cutting hydrocarbons.

Chris Stevens – KeyBanc Capital Markets

All right, thanks.

Operator

Okay. Our next question comes from Jeffrey Connolly from Mizuho Securities.

Jeffrey Connolly – Mizuho Securities USA, Inc.

Thanks for taking my questions. Are you guys seeing any high line pressures in the DJ and were there any midstream constraints to production in the second quarter?

Scot Woodall

Sure. In general in our Northeast Wattenberg area, we’re kind of at the tail-end of the infrastructure. And so the infrastructure is being put in place as we’re drilling. And so, yes, we do see pretty high line pressure. We do see line pressures in the 300 pounds to 350 pounds or so kind of as a norm right now.

In regards to other infrastructure issues or things that may have plagued this in the second quarter, there really weren’t any. Most of our production is new production, not old vertical production. So really, we don’t experience like some operators where their old production gets knocked off when they have infrastructure issues.

But clearly, we always would like for our line pressures to be less when you think about oil wells. And so we’re always working with our gatherer there to try to lay additional infrastructure and additional compression to try to get those line pressures down.

Jeffrey Connolly – Mizuho Securities USA, Inc.

Thanks. That’s helpful. And then can you talk a little bit about use of proceeds from a potential PRB sale in terms of balancing debt reduction with accelerated drilling in the DJ as a means to reaching your leverage goals?

Scot Woodall

I think for the immediate things, I think any proceeds from the Powder River Basin will just go against the balance sheet.

Jeffrey Connolly – Mizuho Securities USA, Inc.

All right. Thank you very much.

Operator

All right. And our next question comes from Jeff Robertson from Barclays.

Jeff Robertson – Barclays

Thanks, Scot. Just a question on the Chalk Bluffs. Do you all do not have any capital allocated to that project for the remainder of 2014, do you?

Scot Woodall

Probably not. I think we’re going to observe those results, redo our technical work and probably would not go back up there in ‘14.

Jeff Robertson – Barclays

Do you have any lease issues up there that you need to deal with?

Scot Woodall

There is –

Jeff Robertson – Barclays

I guess that wouldn’t give you time to do the technical study you want?

Scot Woodall

No, none that will impair that. We’re not – they – we have some over the next few years but nothing that would say we’ve got to go out there and spend capital on ‘14.

Jeff Robertson – Barclays

Okay, thank you.

Operator

All right, great. And our next question comes from David Beard from Iberia.

David Beard – Iberia Capital Partners

Good morning, everyone.

Scot Woodall

Good morning.

David Beard – Iberia Capital Partners

A question on your guidance. Should we assume the acceleration in the oil growth rate is primarily due to delayed tie-ins? And if so, can you maybe quantify tie-ins first half, second half and maybe the core areas, try to guesstimate the uplift from extended reach laterals?

Scot Woodall

No, I think that the reason our production is kind of backend loaded, if that’s kind of what you’re inferring, is the big multi-well pads that we drilled in Q1 and then also we did not – in the DJ. And then also we did not get the rigs out in the unit to oil until, say, the middle of Q1. So that’s why I think you’re seeing the ramp wasn’t real strong in Q1 but becomes more and more pronounced as you get out throughout the remainder of the year.

David Beard – Iberia Capital Partners

Okay, good. Thank you.

Operator

All right. Looks like there are no further questions in queue, so I’ll turn the call back over to Jennifer for closing remarks.

Jennifer Martin

I apologize to anyone who tried to tap into the webcast first thing. Apparently, the link that we were provided took everyone to the wrong conference call. So hopefully, everybody was able to quickly call in.

Thank you all for joining us and always feel free to give me a call with any follow-up questions.

Operator

Okay. Ladies and gentlemen, this concludes today’s conference. Thanks for your participation. You can disconnect and have a wonderful day.

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Source: Bill Barrett's (BBG) CEO Scot Woodall on Q2 2014 Results - Earnings Call Transcript

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