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The McClatchy Company (NYSE:MNI)

Q1 2014 Results Earnings Conference Call

May 02, 2014, 11:00 AM ET

Executives

Jennifer Martin - VP, Investor Relations

Scot Woodall - CEO

Robert Howard - CFO

Analysts

Jason Wangler - Wunderlich Securities

Ryan Oatman - SunTrust

Brian Singer - Goldman Sachs

Pearce Hammond - Simmons & Co.

David Tameron - Wells Fargo

David Beard - Iberia

Jeff Robertson - Barclays

Ryan Oatman - SunTrust

Operator

Good day, ladies and gentlemen, and welcome to the First Quarter 2014 Bill Barrett Corporation Earnings Conference Call. My name is Janaid, and I will 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 Ms. Jennifer Martin, Vice President, Investor Relations. Please proceed.

Jennifer Martin

Thank you, Janaid. 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. The Form-Q was filed yesterday afternoon. You can find that 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 conversation, we make reference to non-GAAP measures, such as discretionary cash flow and adjusted net income. Reconciliations to the appropriate GAAP measures may be found in the earnings release, which is posted on the homepage of our website.

Lastly, yesterday we did post an updated investor presentation also available on our website. We may reference some of that data today, so you may want to take a look at that.

And with that, I’ll turn it over to Scot Woodall to get started. Scot?

Scot Woodall

Good morning, and thank you, Jennifer, and thank all of you guys for joining us today. I would jump right into our operations results where the first quarter proved to be a very good start to the year. Key highlights include, looking at the production metrics, production growth at our core programs was very strong. DJ production was up 137% year-over-year and 25% sequentially from the fourth quarter.

East Bluebell production was up 34% year-over-year. I will reiterate that our first quarter production was aligned with our internal plan. One metric that I think is very telling is discretionary cash flow generated per Boe. It is up 36% year-over-year. The transition to a commodity-balanced portfolio is successfully increasing profitability.

Our new well results in the DJ are both strong, consistent and predictable and within our expectations. Preliminary Chalk Bluffs results look good, and as a result, we plan to increase our activity there this year.

Execution in East Bluebell is exceeding expectations, both from a well performance and also from a drilling and completion cost. We’re also going to be expanding the number of wells drilled out there this year. We have initiated the sales process for the Powder River Deep program, which is at the right direction for our company to continue to improve our corporate focus and the balance sheet. And lastly, we are on track for all of our 2014 guidance metrics.

Now, let me discuss these points in a little bit more detail. Starting first with the DJ Basin. We are very pleased with our most recent well results. If you reference the table in the investor presentation posted last night, we have 30-day rates on 45 wells drilled since the beginning of 2013. These wells have averaged 426 barrels of oil equivalent per day over the first 30 days.

Results have generally been consistent between the B and the C benches across the acreage position. To-date, the performance in the Southern and Western blocks is slightly superior to the Northern block. In the Southern area, I will emphasize the consistency of the results as we continue to like what we see there.

All of our wells drilled in the Southern area continue to meet or exceed our published type curve. In the Western area, we reported results on two strong Codell wells. We tied in another six well pad in this area during the first quarter that includes C and Codell wells and preliminary results were positive and consistent on those wells also. I look forward to providing those 30-day rates shortly.

We currently have three rigs operating in the Northeast Wattenberg area. Two of these rigs are currently operating in the Southern area. Also, in this quarter, we spud our first extended reach lateral well. Given the upside exposure presented by a successful extended reach lateral well, we are looking forward to providing those test results in the coming months.

Up in Chalk Bluffs, we completed two Codell wells that very preliminarily are looking strong, and we have drilled two more that we are currently completing. Given the positive results to-date, we now anticipate drilling a few more wells in the Chalk Bluffs area in 2014.

Now, I’ll move over to the East Bluebell area where our execution and performance are excellent. We have brought four wells into production during the quarter which are exceeding our type curve. We have also reduced D&C costs by approximately 20%.

Also, in the IR presentation posted last night, we have charted well performance to-date against our type curve for the area. The majority of the wells to-date are following a curve, representing more than 250,000 barrels of oil equivalent EUR versus 212 MBoe published type curve.

In combination with continued improvement in drill time and reduced D&C costs, we have the potential to improve upon the approximately 60% rate of return published in our expected economics for the East Bluebell area.

In regards to marketing our unit to oil, just this past week we were able to lock in a new marketing agreement for approximately 4,500 barrels of oil per day at terms consistent with or slightly better than our current marketing arrangements. As a result, we are going to reallocate some capital from the Powder River Deep program to the East Bluebell program and expand our program out in East Bluebell by approximately nine wells. So I think we are well positioned to grow our production now that we have this capacity in place. East Bluebell is fast proving to be an excellent asset.

In the Powder River Deep, as you know, we are marketing this asset for sale. While this is an exciting area, we need to continue our aggressive portfolio management, focusing on fewer core programs and managing our balance sheet. The pre-marketing of this asset has gone extremely well and has generated a tremendous amount of interest. We are opening the data room in the coming weeks, and expect to complete this sale by year end.

I think that covers the most important aspects of our operations year-to-date, so I will turn this call over to Bob to cover our financial results in more detail along with our guidance.

Robert Howard

Thank you, Scot, and good morning, everyone. The first quarter was pretty straight forward in regards to operating and financial metrics. I’ll remind you that the Form 10-Q and the schedules in the earnings release provide detailed information about our results for the quarter. I’ll cover a few of these points in a little more detail this morning.

Starting with discretionary cash flow of $55.3 million, we realized $1.15 per share and $22.72 per Boe produced. Cash flow per Boe is in line with the fourth quarter of 2013 and up 36% from the first quarter of2013, which demonstrates the increased profitability and our focus on oil development.

Turning to production, first quarter production of 2.43 million barrels of oil equivalent were generally in line with our internal plan, which reflects the continued strong growth trajectory from our core development areas, including a 25% sequential growth in the DJ Basin.

Our internal plan consists of normal weather-related delays and the anticipated effect of third-party maintenance on infrastructure. It is worth nothing that during the first quarter our production was impacted by unusually cold weather and unusual drilling and completion delays had had a significant negative effect on production for the quarter.

To give a little color for these events, colder-than-normal weather in the DJ Basin caused fractials to freeze and equipment to break which delayed the completion timing of about 14 wells by about two weeks. In addition, unexpected remediation work on offset well bores prior to initiating drilling activities caused a 20-day delay of drilling and completing five wells.

Both of these events had negative impact on first quarter production even though we were still aligned with our internal expectations. We estimate the cumulative effect of the various delays in the DJ Basin during the quarter reduced our production volumes by approximately 60,000 barrels of oil equivalent.

First quarter NGL volumes of 4,900 barrels per day reflected lower processing plant recovery rates and a few days of plant downtime in the Piceance Basin during February. Plant recovery rates are controlled by plant operators and are difficult to project. These processing problems reduced our net production by approximately 25,000 barrels of oil equivalent for the quarter, reflecting the lower natural gas liquids volumes, offset by higher gas volumes due to a lower NGL recovery factor.

Assuming the NGL recovery rate rebound from the low levels in the quarter, we expect to see an increase in NGL volumes in the second quarter. As a reminder, NGL sales revenues, net of transportation and processing fees, tend to run at approximately 60% to 70% of blended Mont Belvieu prices due to our marketing agreements and the percent of proceeds contracts.

I’ll remind you that our first quarter production volumes were in line with our internal plan with the events I just summarized with about an additional 85,000 barrels of oil equivalent to our first quarter production. We’ve also had some questions regarding higher than consensus lease operating costs in the first quarter.

LOE for the quarter was in line with our internal expectations. LOE is generally higher in the first quarter due to operating in winter conditions, including higher fuel costs and other expenses that are associated with cold weather operations.

In addition, we had a number of well workovers that were incorporated into our annual guidance that were completed in the first quarter. We expect LOE to decline in the second quarter and we continue to be on track for full year guidance of $62 million to $67 million.

Moving onto the balance sheet, our balance sheet remains strong and we are well hedged through the remainder of the year to support our cash flow. For the remainder of 2014, we have approximately 2.8 million barrels of oil hedged at approximately $94 per barrel and 17.6 Bcf of natural gas hedged at a Rockies price of approximately $4.17 per Mcf.

Following the normal semi-annual re-determination process, the borrowing base under our credit facility was just reaffirmed at $625 million. At quarter end, $180 million were drawn on the credit facility. After considering the $26 million letter of credit, we have $419 million of borrowing capacity under the facility.

At the end of the first quarter, our debt-to-trailing 12 months EBITDAX was 3 times. Our long-term objective continues to be to drive debt-to-EBITDAX towards 2.5 times. We expect that proceeds from the sale of our Powder Deep Oil Program assets during 2014 will fund a significant portion of our capital expenditure program requirements.

From a leverage perspective, proceeds from the sale of the Powder Deep assets will serve to keep our long-term debt in line, while the sale of an early-stage growing asset will have a relatively small impact on operating cash flow. In the first quarter, field level cash flow from Powder Deep is less than 10% of our total field level cash flow.

Looking forward, our 2014 guidance remains unchanged. Capital expenditure guidance for the year remains at $500 million to $550 million with about 75% of the capital allocated to the DJ Basin. Our 2014 development program assumes an average of three to four rigs in the DJ Basin and one to two rigs in the Uinta Basin, a drill will participate in approximately 190 gross or 100 net wells.

Production guidance for 2014 remains between 11 million and 12.2 million barrels of oil equivalent and is expected to include at least 30% growth in oil production. As a reminder, our production guidance reflects production growth that is weighted to the second half of 2014.

For the second quarter of 2014, we expect total production in a range between 2.4 million and 2.7 million barrels of oil equivalent and our internal plan assumes oil production to be approximately 38% to 40% of total second quarter production with yields approximately 1 million barrel of oil sales for the quarter.

Our second quarter production estimates incorporate a refinery maintenance turnaround in the Uinta Basin that began in late March and continued through late April. As a result, we are unable to find other markets for all of our black wax oil production, which caused eight to 10 wells, including some new wells to be shut-in for the better part of April.

However, as discussed by Scot, we have recently entered into a marketing agreement for an additional 4,500 barrels a day of black wax oil in the Uinta oil project which should alleviate this issue going forward.

With that, we have completed our prepared remarks and we’ll open up the line for questions.

Question-and-Answer Session

Operator

(Operator Instructions) Your first question comes from the line of Jason Wangler with Wunderlich Securities. Please proceed.

Jason Wangler - Wunderlich Securities

Scot, just curious in -- and obviously, with the weather issues, you give us the well spud during the quarter up in the DJ, specifically. Do you have an idea of what that number was from a completion standpoint, what were you able to complete during the quarter?

Scot Woodall

I’m looking around the room, Jason. They’ll get it here or either Jennifer will follow up with you, but it’s in the 15 to 20 range.

Jason Wangler - Wunderlich Securities

That's throughout the quarter? Was that more back-end loaded or I assume, because the weather obviously was pretty bad to start, was that mostly maybe even second half of the quarter or is there any idea?

Scot Woodall

Yes, absolutely.

Jason Wangler - Wunderlich Securities

And then just the contract in the Uinta, you say it’s kind of a similar type price. I assume that's that 15%-ish type discount and that just basically allows you to obviously have a firm place to put all the oil. Do you think that's enough for this year? Do you have a good line of sight as far as being able to put all the oil away up in the Uinta going forward?

Scot Woodall

Obviously, the 4,500 barrels is a good first step. We are in discussions for some additional capacity out there as well. Those deals just have not been consummated yet. We’re still in the negotiating phases there. We’re just trying to make sure that -- if we’re going to spend D&C capital dollars out there, that we have a market for the oil.

Looking at the East Bluebell results, they look great. The published type curve we had out there for -- with a 60% internal rate of return, and if you’re beating it from an EUR standpoint and you’re beating it from a cost standpoint, it’s going to improve upon that even further provided that we can market the oil. So the marketing seems like it’s coming together. This is the first contract and I’m pretty excited that is going to materialize into an excellent asset for us.

Jason Wangler - Wunderlich Securities

Sure, and maybe just a quick one. Is that oil still going to the Salt Lake market?

Scot Woodall

Yes, it is.

Operator

Your next question comes from the line of Ryan Oatman with SunTrust. Please proceed.

Ryan Oatman - SunTrust

In the press release, you mentioned that production was impacted by unexpected delays associated with the remediation of offset well bores in the DJ Basin. Can you provide some more color on those delays and how that regulation impacted you in the first quarter and how it impacts you moving forward?

Scot Woodall

Sure. It is a regulation in the state of Colorado now that has to do with the kind of ensuring the mechanical integrity of old offset wells, some of which have already previously been plugged. And so if you are going to go and drill a horizontal well in and amongst, say, an old plugged vertical well, you’ve got to reconfirm the mechanical integrity of that well bore. And that’s just a new regulation that we have to deal with.

And of course, you plan for that and you move as part of building a location you go out there and find those old P&A wells and re-enter them and ensure that mechanical integrity. Unfortunately, sometimes you run into some wells that you can’t find them or they have a lot of junk debris in the well bore that just causes you a few weeks of delay, and so you cannot proceed with your completion operations until you have secured that integrity.

So, it’s just going to be a course of business going forward. It’s something that we plan for. We just had a couple that were just kind of big headaches in the first quarter and contributed to those delays.

Ryan Oatman - SunTrust

Scot, when we talked in February, I guess, we talked about a pad that will eventually be 20 wells in a section. At that time, you mentioned you are completing 10 wells and would be drilling the remainder of those 10 wells on that 20-well pad. Can you provide us a status update on those 20 wells?

Scot Woodall

Sure. It’s still a working progress. Obviously, that is coincidentally your previous question was directly attributable to this pad that you are describing. It got delayed a little bit but we are in the process of drilling and completing those wells now.

Ryan Oatman - SunTrust

And is there any sort of ballpark estimate that you can provide for kind of the capital that's been kind of sunk into those wells that we haven't really seen the production update from at this point?

Scot Woodall

We disclosed something around $135 million of capital in the quarter. There are -- I don’t know what will be a good number, but probably $40 million or something is associated with the work that’s taken place on those wells.

Ryan Oatman - SunTrust

One final one for me, just kind of a housekeeping deal. On the Powder River Basin, from kind of a modeling standpoint, is that going to be reported as discontinued ops next quarter? I.e., should we take it out of our estimates or should we leave it in at this point?

Robert Howard

I’d leave it within the estimates until we announce something with respect to a purchase and sale agreement. We are looking for market values for those properties, but if we’re going to get the right price, then we’ll see what we do until that event happens; it’s still part of our ongoing operations.

Operator

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

Brian Singer - Goldman Sachs

Just wanted to touch a bit on the cost guidance for the year, which was maintained. The operating costs per unit were higher, which I assume was related to a number of these shutdowns. Can you just talk about the trajectory as we go through the year? And in the absence of any of the shutdowns how you think -- where you think your operating cost per unit stand relative to, say, where you were in 2013?

Scot Woodall

Sure. I’ll make an attempt at all that, Brian. Clearly, we internally forecast Q1 to be higher operating costs than any of the other three quarters really just based on the impact of weather. And so when you think about, say, for example in our Utah operations, if you have any type of weather shutdowns for weather related or marketing related, just the nature of that waxy crude cause you to spend some additional dollars.

Similarly, we are trying to get ahead of the curve in terms of production by doing a lot of our workover activity in Q1 versus some of the other quarters. So we generally front-end load Q1 and then the other remaining three quarters are generally much more flatter. So I would expect expenses in Q2 to be less than expenses in Q1.

In terms of your question about 2013 per unit costs versus 2014 per unit costs, 2014 will be higher. When you think about selling the West Tavaputs field in Q4 of last year, I believe that asset was a -- and on combining things, that’s probably, it was a $0.42 per Mcfe asset, so times six, you’re getting to $2.40 on a Boe equivalent and we probably run something more than double that as a company in terms of just the oil operations. So it’s going to be a natural progression as we continue to get more and more oilier for those per unit costs to go up.

Brian Singer - Goldman Sachs

And then moving to Chalks Bluff or Chalk Bluffs, could you add any more color to what you've seen so far from these two wells and how they compare to what you're seeing in your Northern and Southern Wattenberg acreage?

Scot Woodall

Sure. The target in Chalks Bluffs has been the Codell. Codell is thick up there. We seem like we’re sitting in a pretty thick area, and so the four wells that we have drilled are all targeting the Codell. Two of those wells that we have online and they are very preliminary, it’s been a handful of days or so. But just the initial few days has made it very encouraging from a production standpoint. Those wells are more like 85% of oil.

And so they have a pretty high oil content, and so we’re pretty excited about the opportunities that sit there. We have around 20,000 acres up there. So, I think completing two more wells which we expect to do in the quarter, having four wells of results will kind of drive the future activity as we kind of look forward to the rest of the year.

Brian Singer - Goldman Sachs

And are the oil rates exceeding those that you've drilled that you talked about earlier in the call from -- to the Western area or are they similar? Can you characterize the Chalk Bluffs versus your Western portion to the South?

Scot Woodall

I probably don’t want to do that yet. Like I say, it’s only been a few days. All the operations people are frowning at me right now. So, I guess they want a few more days before we start speaking to rates. So I would think we should be able to provide an update on the next call.

Operator

(Operator Instructions) Your next question comes from the line of Pearce Hammond with Simmons & Co. Please proceed.

Pearce Hammond - Simmons & Company

Scot, just following up on Ryan's question, the large well, the 10-well pad, that's in the interior Wattenberg, is where that's drilled?

Scot Woodall

Yes, it is.

Pearce Hammond - Simmons & Company

Okay. And then you've got a second 10-well pad there as well? Would that be all the drilling in the interior Wattenberg for this year under your plan?

Scot Woodall

No. We are probably going to do another interior pad as well.

Pearce Hammond - Simmons & Company

But the results from that first 10-well pad, those will be the first results that you guys have put out on horizontal drilling for you guys in the interior Wattenberg. Is that correct?

Scot Woodall

Yes, it sure would be.

Pearce Hammond - Simmons & Company

Okay. And then, next question, assuming success of these super extended laterals across that you'll be testing, how do you see those being employed across your acreage? Do you think you could make 60% of your locations or do you feel comfortable putting a percentage on -- by that, as far as what your acreage could support on these extended laterals?

Scot Woodall

In terms of the percentage where it’s going to be the most applicable is going to be in the Northeast Wattenberg area in that 40,000 acre chunk, and it’s probably all pretty perspective for extended reach laterals.

It’s a pretty blocky acreage position. And so, I think there is -- if it’s successful, and we are basing the reason why we are drilling the extended reach laterals on some nearby wells that have been drilled by others a couple of miles away from us, the economic returns look superior to the 4,000-foot laterals.

So, we’re kind of anxious to try it, but I would think that if it is successful, a significant portion of that Northeast Wattenberg would be developed with the extended reach laterals.

Pearce Hammond - Simmons & Company

And then last one for me. If you can catch us up on the ballot initiative there in Colorado that would give the municipalities or the local authorities more control over drilling and fracking. Where does that stand and what's the company's view on the likelihood of something happening in November on that front?

Scot Woodall

Sure. In terms of just the process, we are still in the process. I think there is like one more week left in the legislative section here in Colorado that would see the final language of any type of ballot initiatives or any type of legislation that could govern our industry. So I think we’ll have some more clarity at the end of next week.

If, for example, some of those ballot initiatives move forward, they have to go through a signature process and they have until, say, August to get through the signature process, and then they would be the ballot in November. So we will know a whole lot more in a couple of weeks in terms of if there are some of these type proposals and what the language of those proposals are.

From the company’s perspective, obviously I think us along with a lot of our other industry partners in Colorado, have really done a pretty good job of trying to get our message out through education and outreach about what our industry is all about, what is fracking all about, what is drilling about, and are trying to provide a lot of educational material to say that we can do it responsibly and we can coexist with our other stakeholders. So, I’m optimistic that with the educational programs that we will be able to if we go to an election, convince voters that we do provide a valuable service to the state of Colorado.

Operator

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

David Tameron - Wells Fargo

Hi, couple of questions. Scot, we've talked about Chalk Bluffs a number of times, but if we go back to -- was it industry results that got you guys out there and start drilling wells, which in turn lead to you increasing the number for this year? But can you just talk about -- I know we've had some big industry results up there. Is that kind of what lead you back out there? Can you just talk about that, how this evolved?

Scot Woodall

Sure. That’s part of, I guess, David. That was some of the original acreage that our company got a couple of years ago and is actually the very first horizontal wells that we drilled as a company. And we were out there and drilled some Niobrara B horizontal wells and got kind of somewhat mixed results.

And so, after that, we moved into the Northeast Wattenberg and started drilling while our technical team was able to acquire some seismic to go through all of the normal stuff they do in terms of calibrating that seismic with the well results and the drilling penetrations that we did. And I think have a much better technical understanding of the reservoir and of the geology up there than what we had a couple of years ago.

And then, when you really kind of start to map it out, really the Codell stands out as probably the better target than say the Niobrara B. We did see that supported with some other industry results in the area. And so it just kind of makes sense to go back up there and drill a few wells.

And so it looks like that our operations and technical team get a much better job of keeping the wells in zone, in target, stimulations went fine on those first two wells, and so think we’re seeing some really positive results. And like I say, it is a fairly significant acreage chunk that could be impactful to the company if these preliminary results hold up.

David Tameron - Wells Fargo

Let me move to the Uinta. If I just look at your well cost, your type curve, you mentioned in the presentation, 2013 wells are holding up or exceeding 250, which is above your type curve. Sounds like the recent wells have been good. Can you just talk about -- you have a 212 type curve, is that conservative? And then well costs, I know you have -- I'll just cite Ultra. They talked about a $1.5 million well cost. You guys are at $2.5 million. I know you're a little deeper, but can you just talk about, is that $2.5 million conservative as well? Could you be lower than that? Can you just give us some color on that?

Scot Woodall

The type curve, you’re right, we’ve got a 212 that we put out at the last industry event and it looks like we’re tracking above that. The big, I would say, variable in the type curve is how long do the wells stay flat. We’re modeling two or three months of relatively flat production and then we put it on some sort of normal decline.

If the wells hold flatter than that, then you’re going to see a pretty significant increase in the EUR. But if you look at the results that we’re posting in there from our 2013 wells, that’s what we’re saying that they are up above 250.

And if you look at those four wells that we drilled in 2014, it looks like they are even above the 250 curve, so obviously there is some room to move upward in the EUR thing. In terms of costs, we’re, in that type curve, we have out there $2.5 million. Every single year, I think, I put out the challenge to our operations team of 10% or 15% reduction in D&C costs across the board and that’s what I expect to happen out there for this year as well.

There is going to be some inherent differences kind of hit on a little bit, David, with the Ultra being at a $1.5 million, there is probably more than $500,000 or $600,000 probably different just in depth, and that’s in drilling costs, that’s in completion costs, that’s in tubulars, that’s in pumping units, so there is going to be a delta just based on depth of something in that magnitude.

David Tameron - Wells Fargo

And then final question, and I've been toggling back and forth between conference calls, so if you missed this feel free to skip it and I will read it in the transcript. Just that -- the Street focus on the Southern DJ wells, these wells were a little bit lighter than the previous, I guess, average, if you will. Can you just talk about variability or why there would be variability what you're seeing out there and just address that issue?

Scot Woodall

Sure. Maybe I’ll first kind of say that the type curve that we have published for the Northeast Wattenberg area that generates a 47% rate of return is based on a 30-day IP of 400 barrels of oil equivalent per day. So, whether you’re at 420 or 480, that just means that you are something north of 47% rate of return, which I will invest in that every single day of the week.

So, I think those results are very strong, very acceptable and I’m willing to put our company’s money in there as evident by that we’re drilling with two rigs out there in the Southern area right now. I think when you are talking about such a small well count where we’re adding five wells to an existing dataset of eight wells, you’re going to continue to see some variability and those averages may move around.

Once we’ve drilled 50 or 100 wells in the Southern area and we add in another batch of wells, I don’t think you’re going to see those averages move at all. It seems like it is being very consistent, very repeatable and I think it’s within our acceptance and tolerance ranges.

And like I said, I’d reiterate it again, I’m pleased with the results, and we’re moving forward pretty hard on the Southern area and as I said in my opening comments, it seems like the Southern area and the Western area are going to prove to be our strongest two areas.

Operator

Your next question comes from the line of David Beard with Aviva. Please proceed.

David Beard - Iberia

It’s David Beard with Iberia. When I look at the type curves that you have in your presentations, I guess they're illustrative economics. When do you think you'd be comfortable putting out yours either timeframe or number of wells?

Scot Woodall

We probably do that in a year-end type of process, I guess, David, is what I would probably say.

David Beard - Iberia

And I also toggled off to another call, but were you able or would you care to share what your drilling program is for the remainder of the years in terms of wells drilled in the Western block, Northern block and Southern block?

Scot Woodall

I’m not sure I have that split sitting right here in front of me, David, but I would think that the majority of the remaining activity of the company will be in that Northeast Wattenberg area primarily focused on the Southern and the Western blocks, but I’m sure maybe Jennifer you can follow up and give you more detail or something later.

David Beard - Iberia

And then, last question, with a potential sale of your PR Deep, when we look out into next year, the following year, is it reasonable for us to expect you'd add rigs to your program?

Scot Woodall

That’s something that will go through the planning cycle next fall, but I think that the general use of proceeds that we’re thinking about in the Powder River sale is either to pay down debt or accelerate in East Bluebell or DJ.

Operator

Your next question comes from the line of Jeff Robertson with Barclays. Please proceed.

Jeff Robertson - Barclays

Scot, at Chalk Bluffs is there anything logistically that would have an impact on how quickly you could put capital to work there if you decided these wells required -- fit your curves and you wanted to follow-up on them?

Scot Woodall

I would think just mostly the normal stuff, Jeff, we go to get permits, which permits in Wyoming seem to go pretty smoothly. There are some infrastructure issues. We have a small little gathering system there and we probably would have to upsize that gathering system, so I think kind of just your normal logistical things, I can’t think of a big hurdle.

Jeff Robertson - Barclays

Is your acreage there conducive to the length of laterals that you think would make the most sense in the Codell or would you have land work to do?

Scot Woodall

We probably have a little bit of land work to do. We probably could go up there and drill some extended reach laterals but we’re not as blocky as what we are in the Northeast Wattenberg, so we would have to try to consolidate up that position if we thought the extended reach laterals was the direction to go. And obviously, we have to do a little bit of commission work as well.

Operator

Your next question is from the line of Ryan Oatman with SunTrust. Please proceed.

Ryan Oatman - SunTrust

A quick follow-up. Just wanted to go back to that 20-well pad just very quickly. Are the first 10 wells flowing yet or are they shut in as you drill the nearby wells?

Scot Woodall

They are producing.

Ryan Oatman - SunTrust

Okay. And have they been producing since when would you say?

Scot Woodall

I don’t know. They’ve been kind of off and on a little bit as we’ve had some of these operational delays that Bob has spoke to. So they came online in the end of the quarter.

Ryan Oatman - SunTrust

Okay. In the end of the first quarter?

Scot Woodall

Correct.

Ryan Oatman - SunTrust

And that was the first 10. And then, what about the next 10, when should we expect production from those?

Scot Woodall

We haven’t drilled all of those 10 wells yet, so there will still be a little bit time.

Ryan Oatman - SunTrust

Just as I'm thinking about, the lag in production there. Kind of separately, in the Powder River Basin, there was another deal announced this week by another operator. I was just wondering if you can kind of speak to the similarities and differences between the two positions as we try and think through valuation there? And I will leave it at that. Thanks.

Scot Woodall

Sure, Ryan. In terms of where the acreage was located, it’s an exact overlay to our acreage position. I think that deal was all acreage. I don’t think there was any existing production at all. So it fit very nicely with a portion of our area that we actually Tyson. And we have a little bit larger acreage position obviously.

Operator

That concludes the question-and-answer session for today. I would now like to turn the call back over to Ms. Jennifer Martin for any closing remarks.

Jennifer Martin

No closing remarks. Just thank you all for joining us. And feel free to give me a call with any follow-up questions.

Operator

Ladies and gentlemen that concludes today’s conference. Thank you for your participation. You may now disconnect. Have a great day.

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