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Cimarex Energy (NYSE:XEC)

Q3 2012 Earnings Call

November 02, 2012 1:00 pm ET

Executives

Mark Burford - Vice President of Capital Markets and Planning

Thomas E. Jorden - Chairman, Chief Executive Officer and President

Joseph R. Albi - Chief Operating Officer, Executive Vice President and Director

Paul Korus - Chief Financial Officer and Senior Vice President

Analysts

Mario Barraza - Tuohy Brothers Investment Research, Inc.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Ryan Todd - Deutsche Bank AG, Research Division

Andrew Coleman - Raymond James & Associates, Inc., Research Division

Operator

Good afternoon. My name is Leshanna [ph] , and I will be your conference operator today. At this time, I would like to welcome everyone to the Cimarex Energy's Third Quarter Results Conference Call. [Operator Instructions] After the speaker's remarks, there will be a question-and-answer session. [Operator Instructions] I would now like to turn the conference over to Mr. Mark Burford. Sir, you may begin.

Mark Burford

Thank you very much, Leshanna [ph] , and welcome, everyone. Thanks for joining us today on our third quarter conference call. And for those of you on the East Coast affected by super storm Sandy, we sincerely hope things get back to normal for you, and that we really appreciate you also taking the time to join us today.

Here, in Denver on today's call, we have Tom Jorden, President and CEO; Joe Albi, EVP and COO; Paul Korus, Senior Vice President and CFO; Bill [indiscernible], Vice President of Exploration and Jim Shonsey, Vice President and Controller.

We did issue our financial and operating results news release this morning, a copy of which can be found in our website. I need to remind you that today's presentation will contain forward-looking statements. However, a number of factors could cause actual results to differ materially from what we discuss. You should read our disclosures on forward-looking statements in our latest 10-K, other filings and press releases for the risk factors associated with our business.

So with that, I'll go ahead and just turn the call over to Tom.

Thomas E. Jorden

Thanks, Mark, and welcome, everyone. I do want to echo Mark's remarks for those of you living on the East Coast, certainly, our hearts go out to you with everything you're fighting and appreciate you joining us this morning.

We had a solid third quarter, reporting net income of $84.3 million or $0.97 per diluted share. Our adjusted cash flow from operations this quarter was $291 million, down from $357 million last year third quarter, but up from the $240 million in the second quarter of this year. And as those of you that have read our release, this release is all about execution.

We're pleased, very pleased with our organization, with the way it's developing the promised results. We have a number of very exciting things going on. But just as a preamble, we're very pleased and proud to deliver the results we promised, and we think that will be an ongoing story from Cimarex.

Our third quarter 2012 production volumes averaged 635 million cubic feet equivalent per day. That's up 7% from year ago of 592 million cubic feet equivalent per day. And it's up 8% sequentially from the second quarter. We're seeing strong growth in the Permian and Mid-Continent, which had a combined average 599 million cubic feet equivalent per day, and that's 18% over last year.

That growth includes a 42% increase in our Permian Basin oil volumes, which averaged 25,000 barrels of oil per day this quarter, so very, very nice Permian and Mid-Continent results.

Our total company oil production grew 23% to 32,456 barrels per day. Liquids accounted for 49% of our equivalent volumes and 79% of our $397 million of oil, gas and NGL revenue. So we're seeing an increasing liquids component to our overall production stream.

Gas prices were lower this quarter compared to last year. Realized gas prices averaged $2.79 per Mcf this quarter, and that's 39% lower as compared to the third quarter 2011 price of $4.57 per Mcf. sequentially, for the second quarter, gas price improved by 15% from second quarter 2000 [sic](2012) price of $2.42 per Mcf. We've all been encouraged and heartened by the recent uptick in natural gas prices.

Realized natural gas liquids prices were flat Q2 to Q3 at $28.29 per barrel but were down 34% as compared to the third quarter of 2011 price of $43.11 per barrel. And realized oil prices were flat, around $87 to $88 per barrel from this quarter, last year third quarter and the second quarter.

In the first 9 months of this year, we've drilled 253 gross, 138 net wells, investing $1.2 billion on exploration and development. Of total expenditures, 52% were invested in projects in the Permian Basin, 44% in the Mid-Continent and 4% in the Gulf Coast and other.

Now, I'd like to give you a region-by-region breakdown. Of course, our regions are the Mid-Continent, which would be Cana, Woodford Shale, Gulf Coast and Permian Basin. And I'll start with the Mid-Continent and save Permian Basin for last.

So moving on to the Mid-Continent. In the first 9 months of 2012, we drilled and completed 119 gross and 49 net Mid-Continent wells. Our year-to-date Mid-Continent exploration development capital has totaled $530 million or about 44% of our total exploration development capital.

Most of this year's Mid-Continent drilling activities has been in the Cana-Woodford shale play. Year-to-date, we've drilled and completed 113 gross or 47 net Cana wells. At quarter end, we had 54 gross, 24 net Cana wells waiting on completion. This compares with a total of 13 gross or 4.9 net wells waiting on completion at year end 2011. So the increase in wells awaiting completion is the result of commencing our infill development drilling in 2012.

Our operated Cana drilling infill has been along 7 east-west sections or along 7 miles in the core. Along this 7 section row, our infill drilling and completion activity has been progressing from the Eastern, liquids-rich side towards the West, drier side. We started our frac-ing on May 23. Our flowback began in late June and the first sales were in mid-July.

Our overall production volumes have exceeded our risk wedge and we're on target. We are always fascinated by Cana. Cana continues to be one of our most detailed science projects. We continually analyze the data. We're looking to see how we can optimize it and try to explain and improve.

One of the things I will say that we've seen this year, year-to-date is some of our early flowback wells are below our type curve. And that's been something we've been working on diligently. Overall, we've been exceeding our risk guidance and our risk production wedge, where we think we can do it a little better.

Our infill wells have flowed back at a little lower rate, but they're delivering higher oil yields and flatter decline. So we've been digging into that problem. We think we have it solved. We've tweaked our completions. We think we can actually remediate and improve our existing wells. But as always, just when you think you're in a production mode, you'd still have a lot of science to do. So Cana continues to be a great project. It's delivered our promised volumes and we're very optimistic going forward.

We've been talking about bringing our Cana rig count possibly to 0. We're tempering that, we're going to exit the year with 4 operated rigs in Cana. We're still seeing very good returns in Cana. We're seeing our cost come down, and we'd like to keep those 4 rigs running and that would give us a little optionality to gas prices.

We'd like to get into the winter. And before we drop our Cana fleet, just see how gas prices stabilize. So we'll exit the year and be at least into early February with 4 operated rigs in Cana.

And now the Mid-Continent, we've got a couple of rigs working in some oilier Anadarko Basin targets. They're new concepts that we're testing. And we're hopeful these could be, all these and even say significant incremental investments for 2013 if they work out as planned, but it's too early to discuss any of those results.

Moving on to the Gulf Coast. In the Gulf Coast, we began prospecting on some recently shot 3D, so now we have some new data, we're back to prospecting. We're currently building our inventory. We don't have any granularity to discuss on that. We'll have a definitive look soon, but we expect to be drilling some of our new prospects in 2013.

Moving on to the Permian. At Permian, the Permian, we drilled and completed 131 gross or 88 net Permian wells during the first 9 months of 2012. We completed 96% of those as producers. At quarter end, we had 18 gross or 11 net wells waiting on completion, and our year-to-date Permian exploration development capital has totaled $631 million or 52% of our total exploration development capital.

Very, very active Permian program and our team, both exploration and operations, marketing, they're working together, firing in all cylinders and really getting after it, very proud of the results we're posting in the Permian. Our most active Permian drilling program is our New Mexico second Bone Spring horizontal oil play. This year, we've drilled and completed 48 gross, 24 net New Mexico Bone Spring wells, and we're continuing to see excellent, excellent results in this program.

The per well 30-day gross production for the New Mexico Bone Spring wells drilled this year has averaged over 630 barrels equivalent per day. That's 30-day average, and of that, 86% is oil. The team has done a great job in this program maximizing well performance, stepping out into new areas and I'll add, also being opportunistic in capturing additional opportunity.

Moving on to the Texas Third Bone Spring, we drilled this year 28 gross, 18 net wells so far. We're in an outstanding area, bringing on really strong wells. The wells we've drilled this year have had per well 30-day average production rates in excess of 1,000 barrels equivalent per day, 80% of which is oil. And that was our 30-day average, it's not instantaneous rates. A couple of our wells had 30-day rates in excess of 2,000 barrels of oil equivalent per day. This is a great program, and our team is doing a great job.

Finally, in the Permian, I'd like to discuss and give you a little update on our Wolfcamp program in the Delaware Basin. We're seeing very solid results from our Delaware Basin Wolfcamp drilling. We've primarily focused our drilling in Southern Eddy County, New Mexico and Northern Culberson County. We have increased our leasehold in this area, something we haven't discussed before. We had the opportunity to pick up an additional 28,000 acres in the heart of our play. That was a $21 million purchase. And that brought our overall position to over 100,000 net acres in the area we're currently developing.

Now we have an additional 32,000 acres that could be extensional. There've been some additional activity in Reeves County that sets us up. We're testing the Wolfcamp and the Reeves County, and that would be directly additive to that position. So we're very, very bullish on this play and when they're finished, I think you'll see why.

This year, we've drilled and completed 11 gross, 10 net Horizontal Wolfcamp wells, bringing our total wells in the play to 29 gross, 27 net wells. So very high working interest. Our per-well first 30-day production rates on all wells drilled to date have averaged 6.4 million cubic feet equivalent per day or over 1,000 barrels of oil equivalent per day. The equivalent production is comprised of 2.8 million cubic feet a day of gas, 275 barrels per day of oil and 330 barrels per day of NGLs. So assuming full NGL recovery, that's 43% gas, 26% oil, 31% natural gas liquids.

So this play certainly is susceptible to all 3 of our commodity pricing, gas, oil and natural gas liquids. But at current strip pricing, we're seeing very, very nice returns in this play. We're also seeing our costs come down. We've talked about wells costing $8 million to $8.5 million. Our most recent costs there are $7.6 million and moving downward.

We're very excited to be adding this additional acreage to our position, not only as the Wolfcamp perspective, but our current viewpoint in this position is that it more than likely will become a multi-pay zone, multiple objections, like so much of the Delaware Basin.

But first, starting with the Wolfcamp and I'll move on to other potential, of our 100,000 acres, if we said 80,000 of it would be developed for the Wolfcamp and we think based on our current viewpoint, that's a reasonable statement. At 160 acres per location, at $7.6 million a well, that project would generate, just the Wolfcamp, $3.8 billion of future investment potential, net to Cimarex.

If we were to go to 80-acre spacing in the Wolfcamp, and although we haven't tested it yet, we're early time. We don't have a pilot project yet, I think most of us would be surprised if it weren't 80-acre development, that would be $7.6 billion net to Cimarex of future development.

And then we add to that other locations. The Second Bone Spring is prospective over much of that acreage. We've recently had some offset wells being drilled in the Second Bone Spring that had very, very nice first 30-day oil rates. We're completing our first Second Bone Spring well here imminently, in fact, we'll be on it Monday. We have a second drilling with encouraging results. And based on shows in some offset wells, we're very optimistic. Our current position, we'd have at least 125 Second Bone Spring wells. And on top of that, we have the Delaware, a third zone that's yet to be tested. It does produce in the area, and we've had excellent shows.

So we like Culberson County. It's a nice add to our Permian program. It has capital investment in and of itself, sufficient to keep our Permian program alive at our current rate for many years to come. So we're very encouraged by that.

Overall, I'd just finish the Permian by saying our Permian program is doing very well. I think that was obvious from the numbers we posted this morning. We have a huge inventory in future drilling and an extremely talented exploration and operations team. And that last point is really the main one. Our program is homegrown. We didn't buy it, we generated it and built it. And our team is the one that makes that happen, and we're very, very proud of what they've been doing.

So in conclusion, as we look at our results to date, it's been a solid year so far. We're focused on execution. We're on track to deliver the guidance we promised. And I want to reiterate that we're proud of the operation and overall performance of our organization.

We're still pouring over our 2013 plans. We don't have any particular detail yet. I will say that we're opportunity rich. We have some great projects, with good returns. In 2011, we invested $1.58 billion. This year, we expect our capital to be similar, at about $1.6 billion. Both years we're a fair bit ahead of our cash flow. Last year, in 2011, most of the shortfall was funded by the Riley Ridge property sale. This year, we funded most of the shortfall with debt, which has increased $400 million to $500 million. That certainly hasn't impaired our balance sheet. We've put that capital to use on great array of return projects. And we think it served our shareholders.

For 2013, we're planning on decreasing the amount of capital funded by debt. I would expect that we would limit our borrowings next year to no more than $100 million to $200 million. We're looking and discussing the potential sale of some noncore mature long lived oil production in areas that we're not currently investing and which we don't see drilling and exploration upside.

This wouldn't be a material amount of production. Again it's, at this point, conversational. Probably something less than 3,000 barrels a day. But we can put those proceeds to work on a drilling program, chasing much stronger returns.

So very nice quarter. And with that, I'll turn the call over to Joe Albi, our Executive Vice President and Chief Operating Officer.

Joseph R. Albi

Thank you, Tom, and thank you, all of you for joining our call today, especially those of you, as both Tom and Mark mentioned, back East and the situation back there.

I'll be touching on our third quarter production, update you on our fourth quarter guidance projections and then follow-up with a few words on our operating and service costs.

Starting with our Q3 production, our third quarter volumes came in, as stated in our press release, at 635.1 million a day. That's above the midpoint of our guidance of 610 million to 640 million a day, up 7% from our Q3 '11 average of 592 million a day. And it set for us a new high mark as far as equivalent production for the company.

The big driver to our growth was our increased oil production, which grew 23% over Q3 '11 to a record 32,456 barrels per day. As compared to Q2, during Q3, we saw less downtime associated with plant facility shut-ins or maintenance, as we had in the previous 2 quarters. During Q3, we saw approximately 4 million to 6 million a day of downtime versus the 14 million to 16 million a day that we saw in Q2. We did see some ethane rejection, particularly in Cana during July and August, which impacted our Q3 volumes by approximately 4 million a day for the quarter.

But beginning in September, we saw the ethane recovery pick back up, and given current market conditions, we do not anticipate further ethane rejection for the remainder of the year.

This was a quarter of records for us. With us setting 19 new internal benchmark records. At the total company level, we set new high marks for equivalent, oil, NGL and total liquid production. In both Cana and the Mid-Continent, we set record marks for all product categories, gas, oil, NGL, total liquids and equivalent volumes. And in the Permian, we set new high marks for all production categories but gas. And when the dust settled, our total company Q3 liquid production mix came in at a record of 49% liquids. All of this pointing towards a strong evidence of our focus on an oil and liquids rich gas activities in both the Permian and the Mid-Continent.

If we dig a little bit deeper into the details, our Q3 '12 Permian net equivalent volume of 274 million a day was up 11% or 27 million a day from Q2 '12. And 33% or 68 million a day from Q3 '11. Oil growth was the real driver here, with our Q3 Permian oil coming in at, as Tom mentioned, 25,000 barrels of oil per day. That's up 15% from Q2 and a very healthy 42% from Q3 of last year.

We're drilling some excellent wells in the Permian, and it's showing up in our numbers, with strong production adds from our Texas and New Mexico Bone Spring wells, as well as our Wolfcamp program.

In the Mid-Continent, our record equivalent volume this quarter of 324 million a day was up 8% from last quarter and 7% from Q3 '11. Our Cana program continues to drive the increases that we're seeing in the Mid-Continent. With third quarter equivalent volumes averaging 184 million a day, we were up 28 million a day from last quarter and a very attractive 45 million a day from Q3 '11.

In a nutshell, our Q3 production tied very closely to our model, with volumes ramping as we had projected in the second half of the year as a result of strong production adds from both the Permian and the Mid-Continent.

As we look forward, with anticipated continued strong production growth in the Permian and Mid-Continent, our model is now projecting Q4 for us to see average net daily equivalent volumes in the range of 652 million to 677 million a day. That's up 8% to 13% from Q4 '11 volumes and projects into a record exit rate for the company.

With this projection, our resulting 4-year 2012 production guidance equated to 620 million to 626 million a day, gave us a midpoint of 623 million a day, which if you recall last quarter's full year guidance of 622 million. We're now looking at slightly higher midpoint, up 1 million a day from last quarter's guidance.

At a midpoint of 623 million a day, we'd fall in the 5% to 6% production growth range over our 2011 volumes.

Shifting gears over to OpEx, with the overall cost increases the industry has seen over the last year as we've talked about in previous calls, LOE has been an important focus for not only our production group, but our drilling and exploration teams as well.

As we've mentioned in our previous calls, our primary focus has been in reducing the saltwater disposal cost, particularly in the Permian, as well as to implement measures to control our workover costs companywide. Well, with our cost control efforts showing up on the books, our Q3 lifting costs came in at $1.07 per Mcfe. That's down $0.09 or 7.8% from Q2, and it's a $0.07 lower lifting cost than we had in Q3 '11.

We'll continue our focus on LOE, and as such, as we look forward into Q4 with our projected volumes, we have been able to revise our full year LOE guidance downward to the range of $1.11 to $1.16. We're very proud of the progress that our production exploration drilling, the permitting teams have done and with regard to saltwater disposal costs, they've certainly made a big impact in our net income statement.

On the service cost side, in general, we're seeing most drilling-related costs be staying somewhat flat. But we are starting to see some evidence of a slightly softening market. As far as rigs are concerned, 1,500 horsepower top drives are still in demand but some recently quoted day rates for new rigs have reflected up to a 5% drop from the rates that we've seen in prior quarters.

Our completion costs are seeing a similar type of market, especially in the Permian, where improved pump time efficiencies and competition amongst various vendors have helped to reduce our frac-related service costs.

In Cana, our improved drilling efficiencies continue to benefit the program. Our current Cana core AFE of $7.4 million is down $100,000 from the number we quoted last quarter, $200,000 from the quarter prior and $600,000 from where we began the year.

In the Permian, second and third Bone Spring programs, our drilling and completion costs are again staying fairly flat. Depending on debt, our 8,500 to 11,000-foot TVD second Bone Spring wells with 4,000-foot laterals, continue to run in the $6.5 million to $7.1 million range, while our 11,500-foot TVD West Texas Third Bone Spring wells with similar length laterals our AFEing in the $7.5 million range.

In the Third Bone Spring program, as you may recall, we're down about $500,000 on our AFEs from where we began the year. In our Wolfcamp program, our current completed well AFEs are now running closer to $7.5 million to $7.7 million, as Tom alluded to. We're proud of getting that number down from the $8 million to $8.5 million level we quoted last call and it's basically as a result of improvements in both drilling efficiencies and design.

In addition to our gained operational efficiencies, just as an example, we now have 1 rig in Culberson running on dual fuel, burning both natural gas and diesel, and we'll soon be taking that number up to 2. Each rig will therefore, equate to about $60,000 per well in reduced fuel costs with the implementation of that system.

So in summary, we had another good quarter. Our Q3 production came in a bit better than planned, setting numerous records along the way. Our projection for Q4 results in a slightly higher projection for Q2 -- or for 2012 production than our last estimate. Our efforts to reduce LOE are reflected in a significantly reduced lifting cost. And with service costs flat, we're making good strides to further reduce our overall drilling and completion costs.

With that, I think I'll turn the call over to questions. Paul had thought most of the material he'd be talking about would be included in the discussions we've already had. So we'd turn the call over to questions.

Question-and-Answer Session

Operator

[Operator Instructions] We have a question from Mario Barraza with Tuohy Brothers.

Mario Barraza - Tuohy Brothers Investment Research, Inc.

Mario Barraza, Tuohy Brothers. Could you guys just talk a little bit more about looking ahead to '13? What are you really looking for in the next few months on the Cana side, where you're thinking of holding the rig count firm at 4 rigs? What kind of gas price are you thinking about to keep it at 4 rigs or what else would you like to see if you were to pull back further?

Thomas E. Jorden

Yes, Mario, this is Tom. What we're looking for right now is a little bit of flexibility. I will say that we're very pleased with where Cimarex is in terms of an asset mix. We're seeing, as always, a fair amount of volatility in the commodity, and we're not sure where it's going to go. There are reasonable viewpoints out there that, with a little bit of winter, we could see significant strengthening in gas prices, and of course oil is anybody's guess. So we like having that flexibility. We have projects in Cana that are generating very nice returns. In fact, I will say the section that those 4 rigs are moving to generates returns in the mid-30s, after-tax at current costs and current commodity pricing. So those are acceptable to us. They're good rigs, they are performing rigs, and it gives us a little optionality to get into the winter and see what gas prices are before we laid our rig fleet down. So what we're looking for, first and foremost, are returns, but our decision to keep the 4 rigs running at least through, I would say, late January, early February, is to give us a little flexibility so that we wouldn't stop, start and be herky-jerky with that program.

Mario Barraza - Tuohy Brothers Investment Research, Inc.

Okay. And Cana, you'd hinted that or you'd said that some of the Cana wells were tracking a little below your type curve. What did you encounter with the first batch of wells and how have you tweaked your drilling and completion techniques to get an improvement in the production rates there?

Thomas E. Jorden

Well, they're completion techniques, not drilling techniques. They are underperforming our type curve. We've been studying it. We think we have the answer and we are implementing them now in some wells we complete. So we'll have some more detail in the next few weeks as to whether that is indeed the case. We're remediating some of our existing wells. It's still in the throes of technical discussions and I don't want to get too granular on particular details and what we're doing, but we have made some adjustments. And we think we have the problem fixed but the proof will be in the flowback.

Operator

Your next question comes from the line of Matt Portillo with Tudor, Pickering, Holt.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Just a couple of quick questions for me. In terms of the Cana, could you talk a little bit about the, I guess, the returns that you're currently looking at in the Cana versus your Wolfcamp wells? And how you think about that capital allocation? So as you're running these 4 flex rigs in the Cana, how did that compete for capital against your Wolfcamp position heading into 2013?

Thomas E. Jorden

Yes, Matt, this is Tom. I will say that the projects that we're moving those 4 rigs on are competing heads-up. They're nice fairly liquids rich and compete nicely with the Wolfcamp. The Wolfcamp we're seeing currently, we're in a little bit of a depressed oil and natural gas liquids, but still we're seeing roughly a 30% after-tax on that Wolfcamp well. And we've got a fair amount of upside there as our drilling costs come down, and our results continue to be high-graded. But also in that Culberson County, we do have a lease exploration issue that we're managing through. It's not severe, but we like it enough that we're going to hold every acre that we control there with very few exceptions. So Culberson's going to see a fair amount -- we'll probably have 2 rigs running. We may go to more but no fewer than 2 to 3 rigs running continuously on that play through 2013. So my short answer -- actually, that's a long answer. But that section that we're putting those 4 rigs on competes heads-up. But for the rest of Cana, it's held by production. I think if we don't see any relief in some of our product pricing, we're more likely to slow down further in Cana, possibly, and going to 0 operated rigs.

Paul Korus

It's Paul. But we'll also have a significant non-operating expenditure next year in Cana.

Thomas E. Jorden

Yes.

Paul Korus

Production adds.

Thomas E. Jorden

Yes. No, we'll have a very active program Cana next year. The situation, and we've described this in the past, there are a lot of operators working in Cana now and we have a significant exposure to non-operated interest. So that gives us -- it's good news, bad news. The good news is we'll still have a significant Cana position and we'll have the opportunity to move our swing capital to Permian.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Great. And then I guess, just in regards to the second and third Bone Springs, as we think about your rig count there, as we head into 2013, can you talk a little bit about your inventory visibility and kind of should we think about that as a relatively flat program or could that potentially accelerate further?

Thomas E. Jorden

We haven't forward [ph] our 2013 plans or at least, they haven't gelled. I will tell you that I would expect our second and third Bone Spring programs to be roughly comparable to what we did this year. And so that -- just those 2 programs alone would probably be somewhere in the $450 million to $650 million of drilling, and that's about flat to what we did this year. But again, we're still working through our 2013 capital plans.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Great. And then just a last question for me, in terms of the Cana itself, just wanted to -- if we could get an idea of kind of where the backlog on the uncompleted wells will be at year end? And how you guys are thinking about just working down that backlog over time?

Joseph R. Albi

Yes, this is Joe. Our current frac schedule, we're looking at both us, as well as operator and then and then as a non operator. But right now, we're looking at ending the year, getting into 2013 with a total of 21 net wells that would still be in need of frac, and 18 of those would be our operated wells and then 5 non op and again that's a projection based on an ever moving frac schedule. But as of the end of this quarter, to just give you an idea as of September 30, we still had 28 Cana net wells waiting on frac, and that number is not moving down a heck of a lot by the end of the year because we've got continued drilling through the end of the year and then as we then take those 4 rigs down south to another section, we'll slowly catch up on this. So our current schedule called us to be in that late second quarter timeframe by the time we were done frac-ing most all of the Cana wells.

Operator

[Operator Instructions] You have a question from the line of Ryan Todd with Deutsche Bank.

Ryan Todd - Deutsche Bank AG, Research Division

A couple of quick questions for you. On the -- I know you haven't come out with the 2013 capital budget yet. I know you've talked at various times in the past about keeping flexibility around the range of maybe in the $1.2 billion to $1.5 billion type of range. When you look at cash flow and you're willingness to outspend with the balance sheet by $100 million to $200 million and then the potential for an asset sale. I know, you're preserving flexibility. But is it safe to say that at this -- I mean, in the current environment you're probably leaning towards the higher end of that range?

Mark Burford

Yes, Ron, this is Mark. Yes, that'd be correct. If we have cashflows in the $1.2 billion and we're talking about $1 billion as part of that $100 million to $200 million and at that point further property sales, yes, we'll be in the upper end of that range of the $1.2 billion to $1.5 billion. So yes.

Thomas E. Jorden

But Ryan, a budget has a loose guideline, and we will adapt depending on our own success, market conditions and other factors.

Ryan Todd - Deutsche Bank AG, Research Division

Great. And then one more, if I might. In the Wolfcamp, I know you had talked about potential for 2 to 3 rigs there, as well as some of the leaseholding requirements. Is there an upper limit in terms of how many rigs that you think you could run there? And how -- what's the infrastructure looking like out there in Culberson County? And are there other bottlenecks that we should be aware of?

Thomas E. Jorden

We're in pretty good shape there. I mean, there are always bottlenecks. And any Permian operator, certainly in the Delaware Basin, will tell you that you have to manage carefully both your oil, gas and natural gas liquids takeaways. We do have, though, the infrastructure built. Our operations team has done a fantastic job of putting in an infrastructure that gives us flexibility. We could handle more activity than I quoted. Whether we will or not, we'll see. I mean, certainly, if we have some really nice results in that second Bone Spring. We have the potential to accelerate that. And so I don't think we're constrained. That said, we have so much opportunity around our organization that our challenge, it's a wonderful problem to have, but it's a difficult problem because you can't do it all. I mean, we really do want to preserve the flexibility of our balance sheet, and if there were to be some downstream opportunity that we don't foresee.

Ryan Todd - Deutsche Bank AG, Research Division

And can you remind me -- I think you may have said it earlier but did you say how much of the 100,000 acres you feel like you have in the core there in the Wolfcamp, the second Bone Spring is prospective across how much of that?

Thomas E. Jorden

Well, I didn't quote acreage. I did say we have about 125 locations, and those are on maps we've made with thicknesses mapped, where we think it could be prospective. And that's -- we're excited about that. We need to test it. One of the things we don't know, we do have some -- there's been an offset [ph] operator that's drilled a well, that's come in very oily with great rates, and we're very excited about it because it sets us up. But this is a big area. And gas-oil ratios change. Before we just move in a rig and drill all those, we need to sample it, understand where it -- does it get gassy, does it stay oily, a lot of unknowns there, but it sure looks something to be excited about.

Operator

Your next question comes from the line of Andrew Coleman with Raymond James.

Andrew Coleman - Raymond James & Associates, Inc., Research Division

I just had one question on the [indiscernible]. Kind of looking at your gross completed -- or your gross wells for the quarter, it looks like it took a step down in the Permian there in the third quarter from the second quarter. I guess what's driving that? Do you have a lot and will that I guess have some pull throughs into the fourth quarter as you finish the year?

Mark Burford

Yes. Andrew, it's Mark Burford here. We do have some -- but there's always some fluctuations in the number of [ph] wells because [indiscernible] any one period. And even like in the Paddock program where we have a rig and a completion crew that can add a lot of net wells in a short period of time. But we went from 27 in the first quarter, 37 in the second, and 24 in the third. But that run rate in the 20s is probably the way you would expect, but there's going to be always fluctuations, Andy, from quarter-to-quarter, which is depending on the rigs and smaller wells like the Paddock and whatnots.

Thomas E. Jorden

And frac schedules.

Mark Burford

And frac schedules, right.

Operator

At this time, there are no additional questions.

Thomas E. Jorden

Great. Thank you very much, everyone, for joining us today. We really appreciate it and we look forward to reporting back to you again next quarter. Thank you. Take care.

Operator

Ladies and gentlemen, this does conclude today's conference. You may now disconnect.

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