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Bill Barrett (NYSE:BBG)

Q3 2013 Earnings Call

November 01, 2013 11:00 am ET

Executives

Jennifer C. Martin - Vice President of Investor Relations

R. Scot Woodall - Chief Executive Officer, President and Chief Operating Officer

Robert W. Howard - Chief Financial Officer and Treasurer

Analysts

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Michael Kelly - Global Hunter Securities, LLC, Research Division

Jason A. Wangler - Wunderlich Securities Inc., Research Division

Andrew Venker - Morgan Stanley, Research Division

Ipsit Mohanty - Canaccord Genuity, Research Division

Pearce W. Hammond - Simmons & Company International, Research Division

Ryan Todd - Deutsche Bank AG, Research Division

Brian Singer - Goldman Sachs Group Inc., Research Division

David E. Beard - Iberia Capital Partners, Research Division

Joseph Patrick Magner - Macquarie Research

Operator

Good day, ladies and gentlemen, and welcome to the Third Quarter 2013 Bill Barrett Corporation Earnings Conference Call. My name is Phillip, and I'll be your operator for today. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes. I would now like to turn the conference over to your host for today, Ms. Jennifer Martin, Vice President of Investor Relations. Please proceed, ma'am.

Jennifer C. Martin

Thank you, Phillip. Good morning, everyone, and thank you for joining us. Sorry, we started a few minutes late. We had some technical difficulties at our end here.

Presenting today will be Chief Executive Officer, Scot Woodall; and Chief Financial Officer, Bob Howard.

A few quick notes before we get started. Our quarterly report on Form 10-Q was filed yesterday afternoon and is available on our website under SEC filings. I will remind you, as usual, that we have forward-looking statements and other cautionary statements provided in yesterday's earnings release.

In addition, during our discussion, we make reference to discretionary cash flow and adjusted net income, which are non-GAAP measures. Reconciliations to the appropriate GAAP measures may be found in the earnings release, which is posted on the homepage of our website.

Lastly, we will post an investor presentation this coming Monday at 5:00 before going on the road in Boston and we will post an updated presentation again on December 10 prior to participating in the Wells Fargo and Capital One and Southcoast conferences that week.

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

R. Scot Woodall

Good morning, and thank you, all, for joining us. Going into the second half of 2013, I have emphasized that our story is all about execution. We put forth a sizable second half program that included the sale of a major asset, completing our full year Uinta program, delineating the DJ Basin through a rigorous drilling program and testing a number of upside catalysts in the DJ.

I have also emphasized that the success on all these fronts is within our control. Our key message today is that we are right on track.

The West Tavaputs asset sale is expected to close next month. I think we took the right approach to the process by having 3 assets potentially for sale in order to maximize the value of the sale to our company.

I am pleased with the transaction, and doubly pleased that the proceeds not only meet our commitment to keep yearend debt flat with 2012, but we expect to exit 2013 with long-term debt over $150 million less than year end 2012.

At this point, we are no longer actively marketing Piceance or the Powder River basin.

I'll start first with the Uinta. In the Uinta, this year's program is nearly wrapped up with one well left to complete.

A few more details. I'll start first with the East Bluebell portion of our acreage, where we have recently been drilling. East Bluebell is on the eastern portion of our position and extends to the south, adjacent to the recent reported Ultra [ph] transaction and extends to the north up until Altamont/Bluebell.

Here, we have 20,000 net 35,000 gross acres. We drilled 20 wells in the year this year and in September, our production in East Bluebell averaged more than 3,000 barrels of oil equivalent per day.

The East Bluebell area differs from the Blacktail Ridge area. The geology out here is more matrix-dominated than naturally fractured, the wells are shallower and typically complete only through the Lower Green River formation.

The wells have consistent EURs, lower DNC cost, higher oil content and a lower tax structure. All of these things make the economics very competitive.

We are moving forward in this area with 80-acre spacing, and there is certainly potential for further down spacing.

Moving over to Blacktail Ridge. I will mention that we continue to be encouraged with our 80-acre pilot test. The first pilot has been on production about 200 days. This is the pilot area where we infill drill in the existing developed section, provide a well placement honors the right orientation, results are very encouraging.

The second pilot area where we drilled an undeveloped section on 80-acre spacing has only been on production approximately 30 days. IPs are encouraging. We should be in a position to discuss results on both pilot areas early next year.

In the DJ, we are right on track and very happy with the results to date. We have been focused on getting this year's program executed.

Since late August, we have had 4 rigs active drilling, both pads and single wells. Year-to-date, we have spud 43 of the wells in our 65-well program, and we have completed 26.

Of the 26 wells completed, the 30-day IP information for all of the wells averages 470 barrels of oil equivalent per day.

Completions in Q3 were 9 wells. In October, we completed 10 wells. Outside the 8 wells we reported today, the remaindering wells do not have 30 days of production yet.

As one can see, our completion activity is keeping pace with the drilling program, and we expect to have 50 wells completed by year end.

As we noted in our release yesterday, of the wells spud to date, 6 are in the C bench, 4 are in the Codell and 8 are in our southern acreage position.

At this time, it looks like we will spud the extended reach lateral test in our southern acreage block just after the start of the year. This was impacted by the road closures associated with the Colorado flooding.

We released results on 8 new wells yesterday. The 2 new individual wells in the southern area looked great. These wells are located near the Anschutz O'Brien well, that we show on our Investor Relations presentation map. The rates on the 2 new wells are stronger than the first Anschutz well.

The new wells were completed with significantly larger fracture stimulations and immediately put on gas lift. Both are B bench wells.

The 6-well pad is located near the earlier 4-well pad wells to the West, and includes 2 B bench, 2 C bench and 2 Codell wells. We are very pleased with the IP rates. We provided an average in the release and the individual well results range from 838 to 1,333 barrels oil equivalent per day for the 24-hour peak rates, all strong.

We noted in the release that we are going to substitute a 10-well pad in the core Wattenberg position for 2 smaller pads in the western portion parts of the Northeast Wattenberg area.

In the core Wattenberg area, where we have started the 10-well pad, we are drilling B, C, and Codell laterals.

There is an abundant well control in the area and we have confidence in the geology that all 3 of the intervals to move forward with the 10 wells. I think this is a helpful reminder to the Street that on top of the 40,000 acres in the Northeast Wattenberg area, we have 14,000 net acres in the core that's also prospected for horizontal drilling and is very low risk. I think it will be helpful to demonstrate that upside to the Street.

We get a number of questions on the impact of the flooding in Colorado, which really was very minimal for us. We were able to continue operations, get in our supplies and I had only nominal production from 4 vertical wells temporarily shut in.

We've been back to normal operations for several weeks, again, our execution in the DJ is right on track, and we expect to have a lot more information for everyone in the first quarter.

Why it is still early to speak to a 2014 budget, I will make a few general comments. Our success to date in the DJ clearly steers the capital program for next year towards a larger drilling program in the DJ. This will likely include drilling in Chalk Bluffs and the core Wattenberg area, as well as continued drilling in the Northeast Wattenberg area.

We will run rigs in the Uinta Oil Program, albeit a smaller program in 2013, and continue our work in the Powder River Deep oil program.

It is too early to give any direction on the total size of the capital program. The DJ, the Uinta Oil Program and the Powder River Deep program, all offer excellent opportunities for profitable growth in cash flow. We are working through a variety of scenarios to deliver solid growth in oil production and cash flow, considering this growth on a debt adjusted per-share basis and retaining our commitment to capital discipline.

Before I turn it over to Bob, I will briefly mention that the slight increase in production guidance relates to the modification of our accounting for NGL production year-to-date, and is otherwise effectively unchanged.

We do have an uptick in the LOE guidance related to some nonrecurring charges which are listed in the release.

Company-wide, we are on track to end 2013 with an exit rate that's approximately 40% oil and to have year-over-year growth in oil production of 30% to 35%.

Further, we will begin 2014 with a solid balance sheet and very well positioned for growth in the DJ.

Now I'll turn the call over to Bob Howard, our CFO.

Robert W. Howard

Thank you, Scot. Good morning, everyone. I'll start with a recap of a few key metrics from the quarterly earnings release.

For the quarter, 3-stream oil and gas and NGL productions was 21.4 Bcfe. Oil production for the quarter accounted for 25% of total production, was up 25% over the third quarter of 2012, which reflects an increase of 37% in the Uinta Oil Program and an increase of 100% in the DJ basin.

Oil sales for the third quarter accounted for 56% of our pre-hedged production revenue. Oil sales accounted for more than 1/2 of our production revenue for the first time in the company's history which marks a major milestone in our transition to become more oil-focused.

Discretionary cash flow for the quarter was $74.9 million or $1.58 per share.

Last week, we announced an agreement to sell our West Tavaputs natural gas property for $371 million. The transaction is expected to close in December. Conjunction with the asset sale, we recorded a $201 million noncash impairment charge in the third quarter and the West Tavaputs assets were classified as assets held for sale at quarter end and the book value of those assets as of September 30 were reduced to the expected sales value.

Total impairment expense for the third quarter also included a $16 million rate down of certain assets in the Southern Alberta basin.

And just a reminder that our full year guidance numbers have not been adjusted for the West Tavaputs sales pending the actual closing date late in the year.

We ended the third quarter with $390 million drawn on our revolving credit facility and a long-term debt balance of $1.3 billion.

The West Tavaputs sale will reduce the capital lease financing obligation by $46 million related to the compressors included in the sale, will generate cash proceeds, which we adjusted from the $325 million as of the effective date of August 1 that will be applied to pay down the bank credit facility.

Pro forma for the sale, third quarter long-term debt would be reduced to approximately $950 million and debt to trailing 12-month EBITDAX is reduced from 3.3x to approximately 2.8x on a pro forma basis.

West Tavaputs proved reserves provided support for an estimated $225 million of our $825 million borrowing base. We expect the borrowing base reduction at the close of the sale will be partially offset by oil reserve additions, particularly in the DJ basin. And following a sale, we will continue to have adequate liquidity to fund our 2014 activities.

I'll provide an explanation on the change in reporting production volumes. As you all know, we changed to three-stream production reporting of oil, natural gas, NGL volumes at the beginning of this year. Due to low ethane prices, we have elected to not participate in the sale of ethane process from our Piceance natural gas volumes. This is a quarterly election that we can make.

Regardless of our ethane election, the gas plant continues to extract ethane from the processed gas, which is reflected in our share of the residue gas sales volumes.

We are then paid natural gas prices for the BTU value of the ethane volumes that are removed from the gas stream.

As a result, this ethane production receives natural gas pricing instead of ethane pricing. We have determined that these ethane revenues and previously unreported ethane volumes should be reported as part of the NGL stream, which will improve consistency in our reported NGL volumes and will provide better predictability of natural gas pricing.

To reflect this change, we updated production volumes and the classification of production revenues for the first and second quarters of 2013. We ask you to please use the table on Page 2 of the earnings release to reflect the updated volumes and to update your model.

Please refer to the earnings release and Form 10-Q for further details on third quarter results. I'll remind you that we are all very pleased to have executed the West Tavaputs purchase and sale agreement. We look forward to closing in December.

As we put together our 2014 capital expenditure program we'll continue to maintain capital discipline and balance with our objective to drive growth from our core oil programs. We plan to release our 2014 guidance in January.

That concludes our prepared remarks. We'll open up the line for questions.

Question-and-Answer Session

Operator

[Operator Instructions] And your first question comes from the line of Ryan Oatman with SunTrust.

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

Scot, I wanted to focus a little bit here on East Bluebell. Can you remind us your well costs in EURs and IRs that you're targeting over there?

R. Scot Woodall

I don't know if I have the current IRs sitting here in front of me. But the EURs are about 250 barrels of oil equivalent per day and the current cost is somewhere kind of a little bit north of $3 million.

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

Okay, got you. And then can you talk a little bit about these 80-acre spacing tests? It sounds like you're comfortable with that as a go-forward plan over there at East Bluebell with the potential to down space even tighter. What do you need to see before moving tighter at East Bluebell and then before declaring it fully successful over there Blacktail Ridge-Lake Canyon?

R. Scot Woodall

Yes. Definitely, the 80 acres in East Bluebell is working just fine. The 40 acres -- to go down to 40 acres, there's some things that we need to do from a spacing standpoint, and then just some logistical things that we've got to work out on the surface to make that happen. And we probably would like to look forward to getting those kind of wrapped up to where we can naturally go do a 40-acre pilot sometime in the next not-too-distant future over there. If you go back over to Blacktail Ridge, that 2 pilots that we have working over there, the one pilot that -- where we went and infill drilled an existing producing section, where we have a stayed out of the dominant fracture orientation, those were up, well results looked really good. And then the new area that we went and drilled a brand-new section on the 80-acre spacing, all of those wells are meeting our expectations. So the 80 acres over there definitely looks like it's starting to trend in the right direction. Obviously, we want to continue monitoring things for a period of time and take the production information and merge that with all of the other technical data that we've gathered before we speak to it much further. But I think we have all that wrapped up and be able to speak to that in January.

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

Okay. And then the transaction you mentioned just to the south of your East Bluebell position, just trying to understand how analogous your position is to that. I mean, do you see the same thickness in the Travis sand that your peers see? Is that an interval you're targeting? Any color on kind of the differences or lack thereof that you see between your position in that Three Rivers asset?

R. Scot Woodall

Yes. It's very similar geology. The transaction that was to the south of us is a little bit shallower, about 1,500 feet shallower than where we are. The interval in -- at Green River formation is a little bit skinnier, and so there's less completion stages. And so their cost are a little bit less than our cost over there. But in general, it's the same target, it's kind of the same concepts that's being played.

Operator

Your next question comes from the line of David Tameron with Wells Fargo.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Just circling back. At West Tavaputs, can you talk about -- is the Ruby obligation, as far as pipeline goes, can you talk about what your financial obligation is for that to close out if there'll be a cost impact going forward?

Robert W. Howard

We are retaining the Ruby transportation at this time, and we'll use it to the extent we can to market our gas. But the numbers are included in our GTP guidance numbers and we'll continue to manage that accordingly going forward.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Okay. And right now, it's in fourth quarter is what you're saying, Bob?

Robert W. Howard

Well, we have -- we continue to keep -- the GTP guidance we have includes Ruby in the fourth quarter. We, of course, continue to add the results from West Tavaputs through the sale date.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Okay, okay. Let me go back to the ethane reporting. How should we -- is Piceance -- where exactly are we rejecting ethane? Is it just Piceance or is that -- obviously that's a large share in that? And then how do we think about how to model that going forward as far as when we start to kind of true up '14 and '15? Can you give us any guidance there?

Robert W. Howard

Well, the Piceance is where we have the election to reject the ethane or does not participate in the ethane recovery on a quarterly basis. And when we do that, it's still processed and comes out of gas plant as processed gas, and then we get a credit for the BTUs that were computed to being lost from the ethane that was pulled out of the gas were a credit to that. Basically, that should keep our NGL volumes and dry gas volumes more consistent. There will be a decline to -- some natural declines and of course, you're following the Piceance. We also have an agreement where we have a 3% less working interest starting January 1 from the sale we did late last year. But from a modeling perspective going forward, then the dry gas should be -- continue on a normal decline and liquid should be -- continue to be somewhat the same proportion to that gas production. And we'll give more guidance on all those numbers as we get into late January for 2014.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Okay. Let me ask one more. I'll tip off that from -- I may come back to that at some point after the call. But just thinking about the DJ and whoever wants to answer, but what these recent wells, what percentage of your acreage do you think you have de-risked at this point? Obviously, the core Wattenberg is the core Wattenberg, but in the northeast area, what -- how much of your acreage have you de-risked in your opinion?

R. Scot Woodall

That's a hard one to answer, David. But we have most -- if you look at that 40,000 acres clearly the acreage on the west, I would say it's de-risked. In the northern half, if you're looking at like a north, south, we probably have walked 2/3 or so towards the east with actual well results to date. And then the southern half, we probably have -- in the wells that we have completed, albeit it's something like 3 or 4 wells we've completed, most of those, I would say, are in the northern half of the southern half. And then we clearly have spud a handful of other wells that are in various stages of being completed. So it's kind of hard to put percentages on all that. Still stick by -- of all -- we'll have most of all of the acreage de-risked by year end, has been the kind of common theme that I've been speaking to over the last several months with the 15 tests in the south and the 15 fees and the number of Codell tests or even still have -- are still on track to gather all that information between now and year end.

Operator

And your next question comes from the line of Mike Kelly from Global Hunter.

Michael Kelly - Global Hunter Securities, LLC, Research Division

Scot, the 470 barrel day rate, the 30-day rate that you quoted in your prepared remarks in the Niobrara, just want to be clear on this, how many wells did that cover of your 26 completions year-to-date?

R. Scot Woodall

It would be all the ones that have 30 days. If somebody can count up that number right here for a second, Mike, but it's every single well that has 30 days worth of information. They just handed me a piece of paper, Mike. So it's 16 of the 26 have 30 days worth of information on them. And then you have to remember -- I'll make one more, comment, Mike. So that still includes some wells that were stimulated at various sizes and all kinds of our experimenting that goes through this delineation process, but that's all-in number of all 16 wells that have 30 days of information.

Michael Kelly - Global Hunter Securities, LLC, Research Division

Okay. So that could include some wells drilled end of 2012 that didn't have much sand, et cetera, that really don't even include kind of the new improved completion approach. Is that the way to read that?

R. Scot Woodall

That's correct. And then also, building on that a little bit, it could include, before we had all the infrastructure in place to immediately put things on gas lift.

Michael Kelly - Global Hunter Securities, LLC, Research Division

Okay, great. And could you give where you guys are now in terms of production in the Niobrara? You've got a big ramp in completions in September, October, just wondering what production -- oil production has risen to today?

R. Scot Woodall

We did a quote in there, no it was an East Bluebell quote. So no, I guess, I don't have that number sitting here in front of me at the moment, Mike. But you're right, it's still a pretty large ramp. You think about doing 10-well completions in October and we will do double-digit completions in November and December, as well.

Michael Kelly - Global Hunter Securities, LLC, Research Division

Okay. And one more, just a quick one for me. Just -- it sounds like the sale of Powder River is off the table now. Just what are the plans in terms of development of that asset, just kind of overall big picture thoughts there would be great.

R. Scot Woodall

I think as it remains in the portfolio, we will obviously have some level of a program out there in 2014. We continue to participate in a number of non-op wells the second half of this year, driven by our drilling program was the first half of 2013. Next year, we would be active on some levels out there. Still, there's an awful lot technical work that we're doing in house, there's an awful lot of land work that we're doing in-house. And so there's just a lot of effort kind of switching gears over into that program now internally.

Operator

Your next question comes from the line of Jason Wangler from Wunderlich Securities.

Jason A. Wangler - Wunderlich Securities Inc., Research Division

Just curious, just one housekeeping item. I'm sorry, I may have missed it, Scot. Was the range 838 to 1,333 on the IP rates on the Niobrara wells?

R. Scot Woodall

Yes, exactly.

Jason A. Wangler - Wunderlich Securities Inc., Research Division

Okay, sorry, I just want to make sure. And, Bob, just for you, curious as far as the West Tavaputs sale, what you think it looks like as far as the availability on the credit facility. Do you see that moving around better? Are you going to able to have some production and reserves from the other places kind of picking up where that leaves off?

Robert W. Howard

Well, I think we were estimating that the West Tavaputs gas reserves support about $225 million of our borrowing base. We do expect that to be offset with oil. Oil reserves coming on the DJ basin is the same completions that are driving our production increase should drive the PDP reserves in the DJ and we'll get credit for that at oil prices instead of gas prices. Will it offset our whole amount? Doubtful, but it should offset some of it and keep our borrowing base very adequate and I won’t say ample, but very adequate for 2014 plans.

Jason A. Wangler - Wunderlich Securities Inc., Research Division

Sure. And then, obviously, still kind of early for the Niobrara and you still kind of do the delineation. But as you start to do that, do you have a feeling what the rigs, as far as how many you're going to go on pad versus how many you're going to kind of have moving around kind of getting all the areas kind of figured out the rest of this year, and I guess into '14?

R. Scot Woodall

Really, most of it is switching to pads. We have a handful of single wells that we will do the remainder of 2013. But almost everything is switching to pads, which is really, I think, speaks to the confidence that we're seeing in our results. And it also just makes things more economic as the costs are actually cheaper when you do things on pads. And then there's a lot of people that also think that when you do pad drilling and you go to stimulate multiple wells that you actually get a kind of a more rubblized stimulation and actually get better results. So most of our program is trending in that direction now.

Operator

And your next question comes from the line from Drew Venker from Morgan Stanley.

Andrew Venker - Morgan Stanley, Research Division

Following up on that comment you just made, Scot. Could you talk about what density of spacing you think you need to see that positive interference or rubblizing the rock like you were calling it?

R. Scot Woodall

Yes, Drew. It's probably a little bit early for us to speak too much to spacing. Most of our work has just happened in the last 30 days or so. So those results are just kind of early to see all those effects. I probably like to wait a couple of months and my reservoir guy over here is shaking his head like he probably would like to wait a few more months. So maybe that's more of first quarter discussion is the actual spacing thing.

Andrew Venker - Morgan Stanley, Research Division

So, Scot, I guess, the higher density drilling you're going to be doing is 80-acre space to start with, is that right?

R. Scot Woodall

Yes. That's primarily what we're doing is 80 acres. I'll just kind of follow up a little bit, Drew. So that's looking at like some 80s in the B and some 80s in the C is kind of what I'm speaking to.

Andrew Venker - Morgan Stanley, Research Division

Okay. And then you talked about some of your 2013 Niobrara completions falling into next year. We work off some of that backlog you have between now and first quarter or is it just kind of going to be kind of rolling forward, that backlog you have right now?

R. Scot Woodall

It'd probably be kind of rolling forward if the numbers I've been speaking to is 65 spuds and 50 completions, so that kind of implies that you have about 15 that are rolling into 2014. And if we're doing somewhere between 10, 12 wells a month, you probably have a rolling one month of inventory or something like that.

Andrew Venker - Morgan Stanley, Research Division

Okay. You mentioned earlier about using larger stimulations. Can you talk about if there's other things you're trying to do in terms of your completion design and how you expect the well designed to evolve over time?

R. Scot Woodall

Sure. Of course, I'll preface some of my comments, is obviously we're new to the play and one of the smaller people in the play. So we definitely keep our eyes and ears on some of the larger operators and kind of follow some of the drilling and completion practices that they do. I would say, one of the things that is ongoing internally right now is most of the wells that we have completed to date have been taking that 4,000 -- plus or minus 4,000-foot lateral and breaking that up into 18 completion intervals. We are slated to do a handful of wells that take that up to 24 stages per 4,000-foot lateral. And so they'll be doing that sometime in Q4, and we look forward to those results as well.

Operator

Your next question comes from the line of Ipsit Mohanty from Canaccord.

Ipsit Mohanty - Canaccord Genuity, Research Division

Just a couple of questions. One, a little broader and then if I could dig a little deeper on a follow-up. But just talking going through the quarter and looking at your year end guidance. If I'm reading it right, it probably looks kind of like a flat -- if I take the midpoint of it, it looks like a flat or a slightly lower fourth quarter compared to the third quarter unless I'm getting the timing of the Tavaputs sale right. But the completions that you're doing in the DJ, is there a reason why you would at best have a flat quarter, fourth quarter compared to the third?

Robert W. Howard

Well, we're still working with some clients of our gas production and closing the West Tavaputs sale in December means we'll get much of the production throughout the quarter. And so as we're looking -- we still have a range within that for that purpose, but we'll see gas production to continually decline, but we'll see the oil production, I think -- look to some of the numbers, would be increasing in the fourth quarter.

Ipsit Mohanty - Canaccord Genuity, Research Division

All right, got you. And then just -- I know you've talked about early days in the southern acreage of the DJ basin. And if I look at the fact that -- if you could give us sort of a broad timing of when you're going to step out of that Anschutz lease and sort of go more into the south, southwestern portion of your southern lease, when are you going to delist that?

R. Scot Woodall

Some of that activity is in the fourth quarter and some of it will fall into 2014.

Ipsit Mohanty - Canaccord Genuity, Research Division

Great. And my last one, you said pad drilling is the way to go, and that's what you're going to do going forward. What's the cost reduction you'll see? Do you still -- what's your current well cost in the DJ and what do you see it trending down to?

R. Scot Woodall

It's -- all in, I saw some of those numbers earlier this week. I think everything that we've drilled and completed to date is about a $4.3 million number. So that does include some pad wells and it includes some single wells. We still do think that there's somewhere between a $300,000 and $500,000 difference between a single well and a pad well. So the more that we shift to pad wells, the more that those numbers continue to drive down. So I hate to kind of lob out exactly what the well cost we expect going forward, but we have several hundred thousand dollars worth of a range to work on as we go more and more towards pads.

Operator

Your next question comes from the line of Pearce Hammond from Simmons & Company.

Pearce W. Hammond - Simmons & Company International, Research Division

Scot, can you provide an oil production exit rate for 2013?

R. Scot Woodall

We'll probably not disclose that at this time, Pearce.

Pearce W. Hammond - Simmons & Company International, Research Division

Okay. And then on the well completions, you mentioned earlier 9 well completions in Q3 in the DJ. Of those well completions, were most of those towards the end of the quarter?

R. Scot Woodall

Well, obviously, we had 8 that we released results on of the 9. So I guess, that we had 30 days on those. So I guess, the last one has to be towards the end of the quarter, yes.

Pearce W. Hammond - Simmons & Company International, Research Division

Okay, perfect. And then last one for me. Any update on any takeaway capacity agreements out of the Uinta?

R. Scot Woodall

No. Really no additional update there, Pearce.

Operator

Your next question comes from the line of Ryan Todd from Deutsche Bank.

Ryan Todd - Deutsche Bank AG, Research Division

A couple of questions. I know you haven't drilled a ton of different wells yet in the DJ, but how do your results compare so far between the B, the C and the Codell? Have they looked fairly similar? Any noticeable differences?

R. Scot Woodall

Really pretty similar. I haven't really seen a big difference one way or the other.

Ryan Todd - Deutsche Bank AG, Research Division

Okay. And I know you won’t provide a visual CapEx guidance for 2014 until early next year, but in terms of broadly thinking about levels of spend, what will be the determining factor on how much you're willing to outspend next year? Is it a balance sheet metric and is there a threshold that we can think about you trying to stay under?

R. Scot Woodall

I hate to lob out a threshold really. It's just going to be a balance of looking at cash flow, cash flow growth, debt-to-EBITDAX, kind of all of those things kind of factor into how we shape that program. I would just say, there's still just an underlying emphasis that I think in 2013, we demonstrated this company does have capital discipline and we stuck to the capital discipline that we outlined in January and not have those same expectations for 2014.

Ryan Todd - Deutsche Bank AG, Research Division

Okay, that's great. And I guess, finally, given -- I mean, I guess, I would assume the returns, the relative returns look better in the PRB we've seen so far versus the Uinta. I don't know if you'd agree, but if that's true, what are the obstacles and what needs to happen in the PRB for you to be able to allocate more capital in that direction?

R. Scot Woodall

There's still a lot of things we need to do in the PRB. Infrastructure is some issues there and we make sure that we're not having to flare a lot of gas and things. So infrastructure clearly plays a role in that. I think some work on the land side to consolidate some of our working interest and improve our working interest in some areas, I think, has to be done. So those are probably a couple of drivers that need to -- kind of things that we need to control and work out internally. And we got people in place to kind of working through that right now.

Ryan Todd - Deutsche Bank AG, Research Division

Okay. And I guess, one last one. Do you think you'll get -- I mean, I see that you're -- you reallocated some capital towards the core Wattenberg area. Do you think in 2014, that we'll see some capital spend up in the Northern DJ area, the acreage near Silo?

R. Scot Woodall

Sure could be. When you think about it, we have almost 20,000 acres that sits up there on the border, and then we've got the 14,000 acres that sits in the core. And at some point, all of those deserve some capital investments. This year was really all about the 40,000 acres in the northeast area. At some point, more than likely '14, those other 2 areas deserve some capital as well.

Operator

Your next question comes from the line of Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc., Research Division

I want to follow up on a couple of Ryan's question you just talked to. With regards to next year's capital spend, just very broadly, this year, I think you said, look, we're willing to spend above cash flow, we're going to try to sell assets to keep our debt relatively flat. You did that. How are you thinking about the dynamic of total debt levels next year? Are you willing to outspend capital and how we should think about both additional asset sales or equity?

R. Scot Woodall

All that will go -- will factor into some of the decisions when we put out our final capital. You're right. We want to make sure that we made good on our '13 promise, which I think that we just did. And so we will think about '14 promises maybe in Q1 next year and see if we're making promises then probably about as far as I can elaborate for right now.

Brian Singer - Goldman Sachs Group Inc., Research Division

Okay, great. And then going to the Northeast Wattenberg area, you mentioned the C wells and the Codell wells were looking similar to the B wells. What's the aerial extent that -- where you tested Codell and the C? Is that as extensive as where you tested the B or can you make some comments on aerial extent there?

R. Scot Woodall

Sure, a little bit. Obviously, we think the entire 40,000 acres is prospective for the B. The Codell is definitely a smaller subset of that. It's going to be predominantly more on the western portion of our acreage, and I don't think we've yet defined what those boundaries are. The C actually covers a more significant portion of our acreage, and as I have said before in the past, the C actually continues to thicken as you get across the southern acreage and there's places that is as thick as the B, if not thicker than the B. So the C is a very strong looking resource in the southern portion of the acreage.

Operator

[Operator Instructions] And your next question comes from the line of David Beard from Iberia.

David E. Beard - Iberia Capital Partners, Research Division

Maybe just to ask the CapEx question in a different way. Could you kind of talk about how many rigs you would plan on having running next year?

R. Scot Woodall

That's still part of the details we haven't worked out yet, David. I think the big take away, David, and I will probably elaborate on this a little bit, when you think about our program in 2013, we spent about 50% of our capital in Utah, about 40% of our capital in DJ, and maybe 10% of our capital in the Powder River basin kind of roughly. I definitely think you'll see money move from the Uinta Basin into the DJ Basin based on the results that we've seen today.

Operator

Your next question comes from the line of Joe Magner from Macquarie.

Joseph Patrick Magner - Macquarie Research

I just wanted to get ahead on gas declines based on the restated volumes, it looks like it was down about 12% in the third quarter versus the second quarter. Is that sort of trajectory that we should expect to continue?

R. Scot Woodall

Roughly, that's probably right for the remainder of this year, Joe. I still think things will continue to flatten out as we get into 2014 a little bit.

Joseph Patrick Magner - Macquarie Research

Is that -- would that be flattening prior to the reduction of the position on Piceance working interest?

R. Scot Woodall

Yes. And you're right, we will take a 3% reduction in volume out of Piceance effective in January. I'm just thinking about kind of the shape curve a little bit. You have to remember, we still were drilling some of these gas assets in '12, so you're still on kind of the steeper part of that tight gas decline. And I think that overall decline will start to flatten. You're right, we've got some ins and outs with the West Tavaputs exiting in December, and the 3% in Piceance exiting in January.

Joseph Patrick Magner - Macquarie Research

Okay. In terms of the restatement, is it -- now that you're including ethane volumes, is there an effective reduction of prior guidance because those are now being layered in? And if that's the case, I think it's about 4 to 5 Bcfe swing. Is that in the ballpark?

Robert W. Howard

Well, the guidance numbers that we published today were updated for the additional ethane. In the past, the gas volumes coming out of the plant were recorded in the first and second quarter, and the ethane volumes that were removed. And you know they had already been removed from the gas streams, hence, the gas streams reduced were just not reflected. And so when we upped our guidance for the -- or adjusted our guidance, or updated our guidance is probably the best way to say that in this current press release, that added those volumes back, those ethane volumes back that just weren't reflected before in the dry gas or the tail gate gas that we sold.

Joseph Patrick Magner - Macquarie Research

If I look at the restated NGL volumes for the first and second quarter, there's about a 4 bcf or 3 bcf change from how they had been reported to how they're now being reported, there were no other changes in the underlying gas production volumes. And so it looks like if you're not layering those in and they weren't in before, it seems like there was -- there's some sort of an offset to what was being guided to before and what's being guided to now.

Robert W. Howard

No, I don't think -- we're probably just pulling our numbers closer together as we get to the end of the year. I guess, if there's anything that's offset to that, I'm not aware of anything. More just getting close to the end of the year and starting narrow and get just better, comfortable with the numbers. We may look into that a little more for you, Joe. I'm just not aware of anything that's really offsetting that or changing it more, just showing it up for the current reporting.

Joseph Patrick Magner - Macquarie Research

Okay, great. Is there any way to get a break down in terms of -- have you provided the average 30-day rate for the wells where you had those rates in terms of oil, NGL and gas volumes from the DJ wells?

R. Scot Woodall

Sure. I think you could probably follow up with Jennifer and she probably could help you out there, Joe.

Joseph Patrick Magner - Macquarie Research

Okay. And just last one. You mentioned some changes to your gas lift in the quarter. Can you elaborate on that and talk about what the cost impact might be?

R. Scot Woodall

I don't really look at too much of the cost impact. I look of it more as a production enhancement. We've been through a variety of artificial lift techniques over the last 12 or 18 months, and really think that putting these things on gas lift really immediately upon drill out, seems like it's a better way to go, and I think we're just getting ahead of all of the infrastructure issues and are able to put things on gas lift immediately. And I think that's also positively impacting our results.

Operator

Ladies and gentlemen, this concludes the question-and-answer portion of today's call. I would now like to turn it back over to Jennifer Martin for closing remarks.

Jennifer C. Martin

Thank you, everyone, for joining us today. And always feel free to give us a call with any follow-up questions. I think we've had a great day, and a good report. And thanks for joining us.

Operator

And ladies and gentlemen, that will conclude today's conference. Thank you for your participation. You may now disconnect. Have a wonderful day.

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