Chord Energy - Earnings Call - Q1 2011
May 12, 2011
Transcript
Speaker 1
Good morning. My name is Tiffany, and I will be your conference operator today. At this time, I'd like to welcome everyone to the first quarter 2011 earnings release and operations update for Chord Energy. All lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question and answer session. Thank you. Mr. Lou, you may begin your conference.
Speaker 2
Thank you, Tiffany. Good morning, everyone. This is Michael Lou, Senior Vice President Finance. We're reporting our first quarter ending March 31, 2011, results today, and we're pleased to have you on our call. Joining me today from the Chord Energy team are Thomas Nusz, President, Chief Executive Officer, Taylor Reid, Chief Operating Officer, Roy Mace, Chief Accounting Officer, and Richard Robuck, Director of Investor Relations. This conference call is being recorded and will be available for replay approximately one hour after its completion. The conference call replay and our earnings release are available on our website at www.chordenergy.com. In addition, we have included our latest financial and operational results in our May investor presentation, which will be on our website after the call.
Additionally, much of the detail that we shared on our year-end call will now be included in the appendix of our investor presentation, particularly on specific pods in the West Williston Basin and details regarding infrastructure development, so feel free to refer to it for further clarification. Please be advised that our following remarks, including the answers to your questions, include statements that we believe to be forward-looking statements within the meaning of the Private Securities Litigation Reform Act. These forward-looking statements are subject to risks and uncertainties that could cause actual results to be materially different from those currently anticipated. Those risks include, among others, matters that we have described in our earnings release, as well as in our filings with the Securities and Exchange Commission, including our annual report on Form 10-K and our quarterly reports on Form 10-Q. We disclaim any obligation to update these forward-looking statements.
Please note that we expect to file our first quarter 10-Q tomorrow. During this conference call, we will also make references to adjusted EBITDA, which is a non-GAAP financial measure. Reconciliations of adjusted EBITDA to the applicable GAAP measures can be found in our earnings release or on our website. I'll now turn the call over to Thomas.
Speaker 0
Good morning, and thank you for joining us this morning to discuss our first quarter financial results and more recent operational activity. I'll dive right into our operational update and then hand the call back over to Michael to wrap up with a few comments on financial highlights. We grew our production from 7,500 BOE per day in the fourth quarter up to approximately 8,100 BOE per day in the first quarter, which is right where we thought we would be when we spoke back in March. Our operations team did a great job working through a brutal winter, and we managed to grow production by 8% this quarter over the fourth quarter of 2010. This growth came in spite of the fact that we had planned on completing 18 gross operated wells in the first quarter and actually completed only 8 gross operated wells.
That 8 gross operated wells translates into 5.5 net wells, which is only 12% of our target 47 net operated wells for the year, so we clearly have some catch-up work to do. In total, that is, including the non-operated wells, we placed on production 23 gross, 6.4 net Middle Bakken and three Three Forks wells in the quarter, and had 47 gross or 20.6 net wells drilling or in the process of completing at the end of the quarter. We ended the quarter with 23 gross operated wells waiting on completion, and we currently still have 23 gross operated wells waiting on completion as of May 10. A bit higher than we'd like to have, and I'll come back to that in a minute.
We now have seven rigs running with the delivery of a new rig from Nabors, which just spud and is drilling the Bay Creek Federal, one of our extensional tests on the west side of the basin in our Montauk area. We now have six rigs in the west and one in the east. We continue to upgrade our fleet to newer generation rigs that will help us to be more efficient once we start getting into more full-scale pad development. While we're still scheduling 10 wells per rig per year, we have continued improvement on our spud to rig release cycle times. In fact, we have 18 wells in our 2011 drilling program so far that have rig released, and of those, 7 were 22 days or less for spud to rig release. Our team's doing a great job improving our drilling efficiency.
The critical path item for us right now, though, is frac crews. Starting in mid-April, we secured our second dedicated crew. Since we're now transitioning to 36-stage completions as our base well design, our frac intensity is increasing. Said another way, we could typically do about three and a half to four wells per month with one crew with a 28-stage plug and perf job in decent weather, I might add. We now expect to complete three to three and a half wells per month with 36-stage completions. We definitely expect our two crews to become more efficient over time. We did have, as an example, before winter weather hit, our dedicated crew complete a 36-stage job in just five days, excluding move and setup time. With two crews, we're pretty much balanced with our seven-rig program, assuming we are completing all of our wells with 36 stages.
With that, we're not working down our wells waiting on completion to what we think is generally our base level of about 8 to 10 projects at any point in time waiting on completion. The simplest solution for us at this point is to lock up an additional dedicated frac crew, which is what we currently expect to do. We are currently in discussion with a few viable options for additional frac capacity and would expect to see a third dedicated crew within the next 12 months, but I'd not be surprised to see that show up as early as this summer. That new crew should be able to work off our remaining inventory in about a quarter or so. Once the inventory is worked down and given our significant cash position, we will then have a lot of flexibility to increase our rig count.
It would not be unrealistic under that scenario to see us get to eight to nine rigs by the end of 2011, assuming we pick up the third crew in the third quarter and start to work down our backlog. Just to be clear, even if we do add a rig or two in 2011, I wouldn't expect to have much new production from this acceleration in the 2011 calendar year due to the timing of the rigs showing up and subsequent completions. Like we said in March, the real immediate and most effective acceleration comes from moving the majority of our wells from 28 stages to 36 stages. As we get into 2012, depending on how efficient we are, you could see us potentially add one more frac crew and get into the 12-rig neighborhood later in that year.
From a cost standpoint, moving to 36 stages makes perfect sense as it's the most efficient capital that we can spend. That being said, as we make this shift, a portion of the economic benefit is being offset by continued upward pressure on overall well cost. Prior to the harsh winter, we were seeing about $7.5 million per well for a 28-stage plug and perf completion. More recently, we've seen this base cost escalate by about 10%. This is partially due to adverse operating conditions in the basin itself, as we experienced significant snowfall, ground thawing, and variable weather conditions. We're also seeing some real cost inflation associated with completion and pressure pumping services, and specifically in materials like proppant.
Obviously, some of this has to do with oil price, which has increased 45% just since our IPO last June. It's hard to break down all of the drivers to cost inflation, but we do think it's prudent at this stage to increase our routine well cost estimate for a 36-stage completion into the $8.5 to $9 million range. We will see where things go from here. Our team's done a great job of identifying ways to be more efficient and to mitigate cost creep, and we are furthering our relationships with our key service partners. We believe there may be some other creative solutions to optimize well costs as well in the future. One of the ways we've done this is by modifying our engineering design.
We're also taking over the reins on a few of the service input components to our capital cost structure, and we'll continue to look for more of that given current service cost escalation that, in effect, takes the economic benefit gained from our efficiencies and transfers that to the service companies and becomes an embedded part of our overall cost structure for years to come. Some of these costs are real, but some are just driven by market conditions, and we're looking for ways to mitigate that through the power of our inventory. We've now developed some key relationships to build out our oil and gas gathering infrastructure. As we went down the path of establishing gathering on our large contiguous acreage blocks, we were actually able to agree on some very balanced terms with third parties for both oil and gas gathering systems.
Based on agreements we put in place for gas gathering, we should expect to see natural gas sales from that gas gathering effort in the third quarter for Indian Hills, Red Bank, and Hebron, all on the west side of the basin, that will add about 4 to 5 million per day net to our gas volumes. Possibly, some of those wells could come on in as early as the second quarter. Later in the year, we should also expect to see gas sales from wells in the area we call Cottonwood and our East Nessen position. Given the high BTU content of the gas in the basin, we expect to still clear north of Henry Hub pricing for gas production, even after the % of proceeds that we will pay to third-party gatherers.
We should see our total net gas production increase to 8 to 10 million per day net, in the fourth quarter, but keep in mind we've already factored that into our annual guidance. Additionally, we recently executed an agreement with a midstream company to connect our wells in Indian Hills, Red Bank, and Hebron, again, all on the west side, to their oil gathering system. That project is expected to be in service the first quarter of 2012, possibly the fourth quarter of 2011, which would be ideal if we could have it in before next winter. We'll pay a fee per barrel on these lines, but we'll reduce net $1 to $2 per barrel of trucking cost to get our oil from the wellhead to multiple pipe and rail delivery points.
That will give us a lot of flexibility on optimizing price, and with that, we will likely start taking over more marketing responsibility internally. Conversely, but still focusing on infrastructure, we're investing most of our $20 million of infrastructure capital on saltwater disposal lines and disposal wells to reduce our LOE. We now have a total of two disposal wells tied into our disposal system. We just completed the drilling of a third, and we expect to have a total of six disposal wells by the end of the year. If you truck water, it typically costs about $2.50 to $3 per barrel of water. With this infrastructure, we can dispose of water for around $1 a barrel. We will see the effects of that over time, and we should see LOE trend down more into the $5 to $6 per BOE of production range.
That's also factored into our guidance. As for overall impact of everything that I've been talking about thus far, it's really too early to formally change our current $490 million E&P budget. With us going to all 36-stage completions and associated cost pressures, there's probably more upward pressure on that number than downward pressure. Given the variability and the timing of when new frac crews start and when new rigs show up, especially when none of those contracts are signed today, we don't want to put out a large range today. It is probably fair to say that if we can get a break on the weather front, we can secure a third dedicated frac crew this summer, and we add additional rigs prior to the end of the year, our capital spend could end up being somewhere in the $550 million range.
As we're now almost halfway through the second quarter, we have a little more visibility into this quarter's production. While we were pleased to get our production number in the first quarter, especially given the growth we delivered, it will no doubt be harder, but not out of the range of possibilities for us to be around the bottom end of the range or 9,800 BOEs per day for the second quarter, given the prolonged wet weather. Like I said earlier, we've had some tough conditions as winter turned into spring, and as a few late winter storms significantly disrupted operations for us and everyone else in the basin, as you've probably heard over the last week.
All that being said, we still think we'll be in good shape for the full year, but we plan on giving you more color regarding that back half of the year, both in terms of production and capital on our August call. With that, I'll turn the call back over to Michael to discuss our financial results.
Speaker 2
Thanks, Tommy. As you might expect, we spent substantially less capital in the first quarter than expected, with only $76 million of the $123 million budgeted for the first quarter. This delay in spending is due primarily to weather delays that Tommy discussed previously. We entered the quarter with $470 million of cash and short-term investments on the heels of raising $400 million of long-term debt. We have a strong balance sheet and will be rapidly delevering the business as we grow EBITDA in the coming years. We're in a great position to fund the third frac crew Tommy mentioned and the rigs that will potentially follow with the cash on the balance sheet as well as cash flow without needing to raise additional capital.
The near-term commodity environment has provided additional cash flow from operations, and we also have hedged a fair amount of production in 2011 and 2012 to protect a base-level drilling program that will protect our leases even in a lower oil price environment. We have about 8,500 barrels per day hedged in 2011 and another 6,500 barrels a day hedged in 2012. In the first quarter of 2011, we had a realized oil price of $82.33 per barrel, which included a 13% differential for the quarter. As many of you have noticed, the Bakken is currently experiencing better differentials at Clearbrook and Guernsey, which will result in higher realized prices in the second quarter. Production was up 8% in the quarter to 8,090 BOE per day.
LOE increased $0.24 to $8.16 per BOE in the first quarter compared to $7.92 per BOE in the fourth quarter, primarily due to the incremental costs that we incurred operating through the harsh winter. We continue to expect our full-year LOE to end up between $5 and $7 per BOE. In conclusion, we had a great first quarter and expect to deliver another year of production growth north of 100%. With that, we'll turn the call over to Tiffany to open the lines up for questions.
Speaker 1
At this time, in order to ask a question, please press star and the number one on your telephone keypad. We will pause for just a moment to compile the Q&A roster. Your first question comes from the line of Brian Lively. Please be sure your computer speakers are muted prior to asking your question.
Speaker 3
Morning, Brian.
Speaker 2
Good morning, guys. Tommy, just want to get some more color on the CapEx and the, I guess, the forward-looking potential $550 million number. Are you guys still planning to complete 53 net wells this year?
Speaker 3
Yeah. If you look at, if you'll recall, we had 47 net operated and 53 total in the first quarter. The difference is the non-OP. In the first quarter, we had about 1.5 net wells. If you annualize that, that gets us back to the 6. Let's focus on operated. 47 for the budget. Without the third dedicated frac crew, we're probably going to be somewhere in the 41 or 42 net well range. If we're able to get that third dedicated frac crew and get caught up, that'll put us back to the 47. For us, from a scheduling standpoint, we had 5.5 net operated wells in the first quarter. I would probably spread the difference out evenly over the next three quarters.
Speaker 2
Right. My question then on that is, if you are able to get that third frac crew in, you're able to wind down the number of uncompleted wells maybe by nine or so. It seems like within your, it's hard for me to see how you get to the $550 million of total CapEx even with $9 million well cost. Are there some other costs embedded in that estimate?
Speaker 3
Yeah. If we get the third crew this summer, and we're hedging a little bit because we don't know exactly when, but hopefully, we'll get it this summer. We don't know exactly if we're going to be able to secure that or when it'll show up. With going to all 36 stages on our completions and with cost creep, if we don't get the third crew, we're probably going to end up somewhere around our original budget number. If we get the third frac crew and we can work off the inventory, we'll be more in the $520 to $530 million range, call it. The difference between that and the $550 million would be incremental rigs. We don't have any contracts signed at this point. We have a lot of good options, but that will be dependent on when we get those contracts signed and when those rigs show up.
We have to get the frac crews first because it doesn't make any difference. It doesn't make any sense for us to pick up more rigs if we can't complete the wells.
Speaker 2
Right. You know, thinking about the 36-stage completions, what is the incremental production that you'll see over the first few months versus the 28-stage completions that you guys were completing previously?
Speaker 3
I don't know if we've got that incremental.
Speaker 4
I think what we're seeing, though, Brian, is that with the 30% more completions from a 28-stage to a 36-stage, we're expecting kind of 20 to 30% increase in EURs. That whole production curve we think is going to be moving up by 20 to 30% from where it's at currently.
Speaker 2
Is it fair to assume then for a $550 million budget or even $520 million budget, your production, even with weather issues in the first two quarters, wouldn't your production then most likely be at the high end of that range, that your full-year range that you've already guided to?
Speaker 4
Yeah. Just remember, Brian, that obviously, the production's moving to the second half of the year, but it takes a lot in those last couple of quarters to make up for the first half being lower. The exit rate will be higher than what we expected at the beginning of the year, but we'll have to make up some of the volumes that we lost the first part of the year.
Speaker 2
Getting that frac crew on early would really drive those volumes higher, I guess, is the takeaway from that.
Speaker 4
Correct.
Speaker 3
You bet.
Speaker 2
That's all I got. Thanks, guys.
Speaker 3
Thanks, Brian.
Speaker 1
Your next question comes from Michael Hall. Please be sure your computer speakers are muted prior to asking your question.
Speaker 3
Morning, Michael.
Speaker 2
Good morning, guys. Just curious, I guess, on the frac crew, can you give us any additional color on any sort of discussions you're already having or how far along you are in the process of securing a crew? Has there been one identified in particular that you're trying to contract for or just any additional color on that?
Speaker 3
Yeah, we're pretty far along in those conversations already. It's not like we're starting today from scratch. We've got a couple of very viable options, which, if you were to step back a couple of months ago, we were calling it 12 to 18 months. That's why, by virtue of those discussions that we're talking about, being able to hopefully line that up this summer. It's pretty far advanced.
Speaker 2
Okay. I guess the other piece, just curious, on the cost inflation, you know, can you kind of split out what the pieces of that cost inflation look like? I mean, is it predominantly materials in the basin, or is it still being dominated by pressure pumping, the actual, you know, contracting of that?
Speaker 3
Absolutely. The biggest single component is pressure pumping. Materials is a big piece of that.
Speaker 2
Okay, that's about all I got. Thanks.
Speaker 3
Thanks, Mike.
Speaker 1
Your next question is from Scott Hanold. Please make sure that your computer speakers are muted prior to asking your question.
Speaker 2
One question. Point of.
Speaker 0
How's it going?
Speaker 2
Point of clarification on the gas gathering on the West Williston, is that an incremental 4 to 5 million a day, or is that company-wide, and has that been included in guidance already?
Speaker 3
Yeah. That 4 to 5 is incremental, and that is in our guidance. The 8 to 10 that I mentioned at the end of the year would be total.
Speaker 2
Okay. Does that 8 to 10 include anything additional on the east side on gas gathering?
Speaker 3
A little bit, but not a whole lot, just due to the timing of that project.
Speaker 2
Okay.
Speaker 3
As far advanced as the other, there is a little bit in there.
Speaker 2
Okay, can you just lay out over the next couple of years your acreage hold by production and drilling schedule, what you guys kind of expect over the next couple of years?
Speaker 3
Yeah. What we've talked about in the past is, if you factor down of the 300,000 acres, that which is captured within our drill block inventory, it brings it down to about 220,000 acres or so. We've got 90,000 acres that was HVP at the end of last year, and we preserve about 60,000. With a seven-rig program, we preserve about 60,000 acres per year. By that, that would make it to where if you got to the end of 2012, right into the first quarter of 2013, we've basically got everything held.
Speaker 2
Okay, that's helpful.
Speaker 3
That's with seven rigs. If we start bumping that rig count up, it just starts pulling all that forward.
Speaker 2
Okay. Lastly, just what are your latest thoughts on potential bolt-on acquisitions?
Speaker 3
Yeah. I wouldn't necessarily count on a whole lot of that. We still participate in some block acres deals in and around our core positions, but that's getting more and more difficult as time goes on. It's just extremely difficult to predict. We try to be disciplined about it. Our probability of success is probably going to be a bit low. You just never know when you may be able to capture one of those things.
Speaker 2
What about thoughts on entering other basins outside of the Bakken?
Speaker 3
Yeah. We're not spending a whole lot of time outside the Williston at this point. We kind of got our hands full, especially as we start to look at adding a third frac crew and potentially additional rigs. At some point, it's going to make sense for us to get some people focused on that. That's probably, you know, and that's not five years from now. That's probably 12 months from now. That way, we can position ourselves to be able to be opportunistic if the right things present themselves.
Speaker 2
Okay. Great. Thanks, guys.
Speaker 3
You bet.
Speaker 1
Your next question is from Derrick Whitfield. Please make sure your computer speakers are muted before entering or prior to asking your question.
Speaker 5
Good morning, guys. Just a few questions for you on the development front. Tommy, based on your earlier comments, it appears that you guys are operating at an approximate, call it, three to four rigs per frac crew ratio. Really thinking that a little further, and outside of adding additional crews, are there any other initiatives you could affect that could push that towards a four to five per frac crew ratio?
Speaker 3
Yeah. Taylor may be able to provide more color on that. Keep in mind that we're transitioning basically all of our wells to 36-stage plug and perf. We are playing with a few combinations of plug and perf and sleeves. To really start, I think at this point, we've got to get these frac crews operating on a continual basis and operating efficiently before we're willing to say that we can bump that number up.
Speaker 5
Okay. Maybe taking part of that answer a little further, have you guys evaluated any of the new sliding sleeve technologies?
Speaker 3
Yeah. We're familiar with what's going on there. Our completions guys are looking at it, but we haven't done any of that yet. We'll watch it and see if it makes sense. At this point, though, we're still focusing on plug and perf because at least inside the pump, inside the pipe, we know where the fluid is going.
Speaker 5
Okay. Staying on the development topic for a moment, Tommy, in ballpark terms, could you remind me as to how many locations you guys have that are suitable for orientation or pad drilling orientation, and that would be north to south?
Speaker 3
I don't have that off the top of my head. Brad or Taylor may have that.
Speaker 5
Yeah, in total, I think it's over half. I don't know the exact number, somewhere between 50% to 60%.
Speaker 3
We had 246 operated drill blocks that we talked about in the IPO. We've got 472 total. With the Hebron deal at the end of the year, we're probably more like 270 plus or minus total operated drill blocks if you were to backdate it. Half of those.
Speaker 5
About half. One thing I would add is that while most of them are north-south, we do have some that are east-west just because of surface configuration where we're along the river or something similar to that. Okay, it's very helpful. One last question, if I could, guys. Any updates on the Wilson and Morris three forks wells?
Speaker 3
The Wilson well is currently fracking, currently completing that well. Hopefully, we'll have some results here this quarter. The Morris well should be fracked likely in the June time frame.
Speaker 5
Perfect. That's all for me, guys.
Speaker 3
Thanks.
Speaker 1
Your next question is from Ron Mill. Please be sure your computer speakers are muted prior to asking your question.
Speaker 2
Guys, actually, this is Don, Chris. Taylor, can you give us an update on Montana, and with a rig running out there continuously for a while now, can you give us any well results or anything you're seeing differently from the North Dakota side than the Montana side?
Speaker 3
Results that we've seen so far are in line with what we've seen in the North Dakota side. The wells, the early wells that were 23-stage completions, are within the 400 to 700-type curve band that we put out. We have early results on 28-stage completions, which looks very encouraging, but everything continues to be within that type of band that we put out.
Speaker 2
Okay. You talked about potentially going eight, nine rigs by year-end and maybe 12 at some point in 2012. Can you talk about the timing going into 2012 of how you think you're going to add those? Is there going to be one every quarter, or is it going to be faster or slower than that? Obviously, it's dependent on frac availability.
Speaker 3
Yeah, that's probably not a bad way to model it. It would be one a quarter.
Speaker 2
Okay. Just two smaller ones from me, from Michael. Can you talk about the differential more or add a little bit of color around it in Q2 and how we should model that? Is it still going to be 13%, give or take, or is it going to come down significantly?
Speaker 4
Yeah. What we've been saying, Don, is you know 12% to 15% is a pretty good number for the next little while here before the big pipe comes on in 2013. That being said, first quarter is in the 13% range. Fourth quarter of last year was in 14%. In that range, the differentials at Clearbrook and Guernsey have been extremely positive. It's hard to tell exactly where the quarter will come out, but at least for the first couple of months, you'll probably be more in a, call it, 6% to 10% range as opposed to the 12% to 15%. We do think this is kind of a shorter-term deal and will end up going back towards the 12% to 15%.
Tommy also mentioned some oil gathering that will help reduce that differential by a dollar or two when that oil infrastructure comes on first quarter of next year or maybe for fourth quarter of this year.
Speaker 2
Okay. From an LOE standpoint, obviously, it's going to be dependent on timing, but how should we model quarter to quarter on LOE going forward throughout this year? Should there be just a large drop-off in Q4, or will it be gradual throughout the second, third quarters as well?
Speaker 4
It'll be pretty gradual, Don. You know the newer Bakken production comes on at, you know, around $5 to $6, especially when the saltwater disposal system's in. We're probably towards the lower end of that, and we'll continue to blend downwards towards that $5 to $7 for the rest of the year. It's not totally unexpected that we're kind of at this level for the first quarter, given the harsh winter and had some additional work because of that. We always thought the first quarter was going to be fair and it would be working down throughout the year.
Speaker 2
Okay. Just to confirm, you think the EURs could increase 20 to 30% going to 36 stages from the 28? Did I hear that right?
Speaker 3
Based on what we're seeing so far, we're thinking 20 to 30.
Speaker 2
Okay. All right. That's all for me. Thanks, guys.
Speaker 3
Thanks, Don.
Speaker 1
Your next question is from Irene Haas. Please make sure your computer speakers are muted prior to asking your question.
Speaker 5
Hello, can you hear me?
Speaker 3
Hello, Irene.
Speaker 5
Hi.
Speaker 3
I got you.
Speaker 5
Good to hear that you guys got the gas gathering operation going on. I just want to have a little confirmation. You know, how should we look at the differential? I mean, thus far, historically, you guys earn a really nice premium to Henry Hub. With the new contracts as such getting in place, would that be sort of smaller than what you have been experiencing historically, but still better? I just want to have a little more granularity to that particular piece of the guidance.
Speaker 4
Sure, Irene. We've consistently said that, you know, because of the liquids content here that will be above Henry Hub, we'll kind of have to watch how it comes in. I know that we're pretty substantially above where Henry Hub is this quarter, but we'll continue to watch it as it actually comes online and how that plays out. Right now, we think kind of modeling a little bit above Henry Hub is probably the right place to go.
Speaker 5
Are we talking about 120% or 150% over Henry Hub or more? You know.
Speaker 4
10% to 15% is probably a good starting point.
Speaker 5
Okay. Great. Thank you.
Speaker 1
Your next question is from Jason Wengler.
Speaker 3
Morning, guys.
Speaker 2
Morning, Jason.
Speaker 3
Just curious, as you look at the rig program, you have the six on the west, the one on the east. Is that the plan with those seven for the rest of this year? As you add the eighth and ninth, would you look at adding any to the east, or would you be primarily going and developing the west?
Speaker 2
I think the way that the guys have got it scheduled out right now, as you go to eight and nine, we would likely add a rig in Montana and Hebron. The ninth one would be over on the east side. We'd be two east and seven west.
Speaker 3
Okay. This is just kind of more curious than anything. How much longer does it take you to get the frac crew over to the east from the west? Does that take an extra day or two? Just kind of curious on how the schematics of that works.
Speaker 2
No, it's a pretty quick move. Once you got them rigged out and truck over, it's not a real long move for them.
Speaker 3
Perfect. Thanks, guys. I'll turn it back.
Speaker 2
All right, Jason. Thanks.
Speaker 1
Your next question is from Gail Nicholson.
Speaker 5
Hi, guys. How are you?
Speaker 2
Great.
Speaker 5
Just a couple of quick questions. When going to the 36-stage completions, do you expect your Indian Hills wells to be a little higher than what you're modeling for EURs right now?
Speaker 3
It'll be higher than the 28-stage completions model that we've been using. Like we said, 20% to 30% bump going from the 28 to the 36.
Speaker 5
Okay. Because right now, you said that they're mid to high on that four to seven range. We can assume it could be a little bit higher than seven then, perhaps?
Speaker 3
Correct.
Speaker 5
Okay. With the existential tests that you're going to be drilling this year, do you know when you should have results on those?
Speaker 3
Yeah. The first one that we've got is that one in Montauk. It's probably, I mean, we just fed the thing. That's probably third quarter.
Speaker 2
Third quarter, correct.
Speaker 3
We have another one on the southern end and one in Target, but that's probably the end of the year.
Speaker 2
End of the year.
Speaker 5
Will all of those be completed using 36-stage completions?
Speaker 3
Correct.
Speaker 5
Okay. Great. Thank you.
Speaker 3
You bet.
Speaker 5
Your next question is from Marty Bisco.
Speaker 4
Morning, guys.
Speaker 3
Morning.
Speaker 4
You had mentioned that it looks as if, though, you might be able to get a third frac crew earlier than previously expected. What's really kind of changing as to moving that up? You know.
Speaker 3
I think it's just, you know, we kind of touched on it earlier. It's just the evolution of the discussions and availability. You know, continue to see more people move equipment into the basin. Now, you know, equipment's one part of that equation. The other part is people. I think it's just how far advanced the discussions are.
Speaker 4
With your discussions with the service providers, where are they seeing most of the hang-up right now? Is it on the crew side or on the equipment side?
Speaker 3
Tanner may be able to add a little bit more color to it, but I think it's a little bit of both, really. To split that out, it's hard to say. Let's see if we got any other.
Speaker 5
Yeah, it's some of both, for sure.
Speaker 4
Okay. All right. Thank you. Most of my other questions have been answered.
Speaker 3
All right. Thanks.
Speaker 1
Your next question is from Peter Mahan.
Speaker 2
Yeah. Morning, guys. Just had one follow-up question. You guys gave a full-year production guidance range of 11,000 to 12,500 BOE per day. You know, where's your comfort level with the bottom end of that range with respect to, you know, adding that third frac crew? I mean, does adding that third frac crew give you comfort in the bottom point of that range, or does that migrate you higher towards maybe the mid or high point of that guidance range?
Speaker 4
What we've said on guidance ranges is that the second quarter, you know, we're going to be towards the low end, around the low end of the range, but we haven't changed our year guidance, and we'll be within that range.
Speaker 2
Okay. Adding the third frac crew is not critical to hitting that range?
Speaker 3
What I would say is that if we don't get that frac crew, it's going to, obviously just by virtue of timing and being at the low end, around the low end of the range for the first two quarters, pressure us to the lower end. Getting the third frac crew obviously helps us get back on track. Again, if you're, every day that goes by, it's harder to catch up. To really push to the high end on annual average when you're around the low end of the first two quarters, it gets more difficult by the day.
Speaker 2
Okay. Perfect. Thanks a lot, guys.
Speaker 3
You bet.
Speaker 1
Our next question comes from the line of Michael Hall.
Speaker 2
Thanks for the follow-up. Just a couple of things I was curious on. The backlog you currently have, how many of those are 36-stage completions planned to be 36-stage completions?
Speaker 3
Yeah. Most of them right now are 28-stage completions. We have some 36-stage in there. We've really transitioned more recently to the 36-stage wells.
Speaker 2
Okay. Fair to say the majority of them are 28-stage.
Speaker 3
Yes.
Speaker 2
Okay. I guess, kind of following up on a couple of the prior questions on that, a question about kind of, you know, rig to frac crew ratio. I mean, is that partly a function or going to be a function of, you know, you're not quite on pads yet, and you know, you'll be limited to the extent that you need to, you know, transition from site to site and slows down the frac crew in that sense? Is that kind of the key variable there?
Speaker 3
Yeah. That's part of it. I mean, part it's two things, really. One is kind of sticking to plug and perf completions. Like I say, we've done a few where we've used, I don't know, Taylor, 5 to 10 sleeve stages out in the toe, and we'll monitor those. Part of it's just continuing to base our plan on, you know, 36 plug and perf stages. Clearly, as you start getting into full-scale pad drilling, we're going to be a lot more efficient. For us, that doesn't really start happening until 2013.
Speaker 2
Sure.
Speaker 3
Because we're through the first half of 2013. We're doing the one well for 1280 to capture our blocks. In some instances, as Taylor mentioned, maybe half of those are where we do north-south or adjacent. That gives us some efficiency.
Speaker 2
I was also just curious from a full basin standpoint, you know, if others start shifting towards pads and as that starts happening more and more throughout the basin, if perhaps frac crews will become more available as, you know, people can run fewer fleets per rig.
Speaker 3
That would stand to reason. Keep in mind that rig count's going up at the same time.
Speaker 2
Sure. Okay. I guess just one other, crews. Did you see a lot of turnover with the kind of nasty winter that was experienced up there? Do you think you've gotten, were you able to hold on to the crews that you had on your existing rigs and fleets?
Speaker 3
We did see some of that. Taylor, you want to?
Speaker 5
Yeah. I definitely saw some turnover, probably more on the frac crew side. Rigs may tend to hold them a little bit better, but that's definitely happened early on in the winter.
Speaker 2
I appreciate the extra color, guys. Thanks.
Speaker 3
You bet.
Speaker 1
Your next question comes from Noah Hungness.
Speaker 5
Yeah. I remain confused a little bit about how we get from the $450 million to the $520, $530 million. The $450 million, I appreciate, was seven rigs, 53 net wells, and 28-stage completions. I wondered if you could just briefly take us through, when I add 36-stage completions and remain at seven rigs, what is the increment? Obviously, I'm increasing the number of rigs, I think, to nine and 36. What is the increment? Finally, where is inflation coming to play? Because the well cost from being something like maybe high, high $7 million went to about $8.3 million thereabouts in the call for Q4, and now it's closer to $9 million. It's just not clear to me how much of that is reflecting from the stage differential and how much is just inflation coming to play.
Speaker 4
A couple of things. One, our current budget is $490 million, as a starting point. What we were talking about before is that with the seven-rig program and two frac crews, and the cost inflation and moving to 36-stage completions, essentially, our capital will stay flat for the year. Obviously, we'll have completed less wells in that type of situation. Now, $7.5 million is what we were saying on a 28-stage completion. Now you're moving, if you go to the middle of the $8.5 to $9 million range, you're $8.75 million for a 36-stage completion. Previously, we were saying in that $8.3 million range. There's your inflation on those wells. You can go anywhere in that range of $8.5 to $9 million for that.
If you use that kind of midpoint and with a third frac crew, you'll get back to the 47 net operated wells being completed for the year. That'll kind of get you back to that $525 million with the additional wells that are going to 36 stages at that kind of midpoint level, will get you to that $525 million number. As you get to the $550 million, the reason for that is if you add a couple of rigs, call it rigs eight and nine, depending on when you might add them, that could bring you up to the $550 million. You're not going to get much benefit on a production basis from that, because they'll be added later in the year.
Speaker 5
Yeah. I mean, the $490 million includes a bunch of infrastructure spend. When you think about just drilling wells, it's sort of closer to $450 million, is not operated and non-operated.
Speaker 4
Sure. The $441 million was our drilling completion budget. If you want to go off of that starting point, you can do the same math and show the increase into our budget. If our budget increased $60 million, the drilling budget, it's enough on the drilling budget side, right?
Speaker 5
Yeah. When we go to 2012, if we are at that point, hopefully at about eight or nine rigs, and we have seen in the newer wells a 20% to 30% increase in EURs, it's setting the stage for some, even if we again have a weather thing, which by that point is an anniversary. One would imagine there should be some pretty nice production growth coming out of 2012 for which you all are quite well hedged already. Am I correct?
Speaker 4
Correct. Yeah, correct. We'll see a lot of the impact of this 36-stage completions program, given that most of them will be in the second half of the year. We'll see a lot of that impact in 2012 as well as our program in 2012. You'll see the impact there as well.
Speaker 5
Thank you. Congratulations.
Speaker 4
Thank you.
Speaker 1
Your next question comes from Noah Hungness.
Speaker 5
Morning, Jack. Good morning, Tommy. Most of my question already answered, but if you move from plug and perf to sliding sleeve, what kind of saving, you know, how much more a frac crew could do? Why are you not moving to it sooner than later?
Speaker 3
If you move from plug and perf to sliding sleeve, you could probably, let's talk about a 28-stage frac. For us, it's probably a seven-day range, plug and perf, five to seven days. Sliding sleeve, maybe you could get it done in three or four days, so you're a little more efficient. We remain with plug and perf from a well performance standpoint and for surety of placement of our frac. We monitor results. We've done some sliding sleeves, and we'll monitor the results of those. At this point, we're committed to staying with plug and perf, and we'll revisit that as we go.
Speaker 5
How much saving you could accomplish if you would go to sliding sleeve?
Speaker 3
I don't have an exact number for you, but it's not.
Speaker 5
Yeah. Part of the problem, Jack, is that when we started into this, we were using all sleeves. Based on the performance and recoveries per stage, we shifted to plug and perf and saw noticeable improvement, and then more stages in plug and perf. I understand a lot of people are starting to use sleeves and these more exotic arrangements on sleeves. For us, we're not really confident in reversing on what we've learned so far or doing it to save time and dilute our first-stage recoveries. That, I think, is why we're a bit hardheaded about it. Okay. Thanks a lot.
Speaker 3
You bet, Jack.
Speaker 5
Thanks.
Speaker 1
Your next question is from David Snow.
Speaker 5
What is your thinking on ultimate spacing for 1280? What are you going to do to explore that?
Speaker 3
Yeah. You know, the way we've got it scheduled out right now, David, is three Middle Bakken wells and three Three Forks wells. Focus more on the Middle Bakken right now just because, you know, we got a lot more data on it than we do on the Three Forks. Keep in mind, with three, based on our calculations, three Middle Bakken wells per 1280, we think we're getting 12% to 15% recovery of original oil in place. That's a relatively low number. As we look at some of the data, the Brigham guys have talked about it a good bit. They've got three wells in that Olsen unit, and I think two of the three of those are effectively spaced on four wells per 1280. I think the three may be a bit conservative. We're probably going to end up being more like four.
We're going to watch what other people are doing. We don't have any current plans internally to test that, but certainly enough industry activity out there, especially if you start looking at Whiting-Sanish, for us to get some good data on that and to be able to plan our 1280 full-scale development optimally once we get to that and end of 2012 into 2013.
Speaker 2
What is the spacing at Whiting-Sanish?
Speaker 3
They've got a lot of wells that have been second well per 1280, probably 18-plus months of production there. Now they're going to the third in a 1280 or three wells per. Rock, keep in mind, rock quality there is a little bit higher, which is why you have higher recoveries than some of the other parts of the basin, at least based on the completion techniques that they're using right now. Now, some of the other parts of the basin, we're starting to catch up on recoveries because we're using higher stages.
Speaker 2
Yeah. When are you going to really start to hit your full manufacturing efficiencies? That'll come after 2012 when you start to.
Speaker 3
Yeah, that's probably the end of the first half of 2013.
Speaker 2
Okay. Will it kind of take place over a couple of years starting then, or will it hit all at once? You know.
Speaker 3
As you look at, as we go into probably 2014, I would suspect that a large percentage of our activity will be on pad drilling.
Speaker 2
Yeah.
Speaker 3
We'll pick up efficiencies as we go. You know, we'll continue to improve the process. Like Tommy said, more full-scale development is going to be 2013, 2014.
Speaker 2
Yep.
Speaker 3
2013 is kind of a transition year where we capture all of our drill blocks and start to transition to full pad development.
Speaker 2
Great. Thank you very much.
Speaker 3
You bet. Thank you.
Speaker 1
There are no further questions at this time.
Speaker 2
Great. Thanks again for everybody's participation in the call today. I appreciate all the hard work from the employees at Chord Energy. I appreciate the support that we've got from our strong shareholder base. We'll be on the road quite a bit over the next few months and look forward to catching up with many, many of you along the way. Thank you.
Speaker 1
This does conclude today's conference call. You may all disconnect.