Chord Energy - Earnings Call - Q3 2011

Transcript

Speaker 5

Morning. My name is Robin, and I will be your conference operator today. At this time, I would like to welcome everyone to the third 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. If you would like to ask a question during that time, simply press star, then the number one on your telephone keypad. To withdraw your question, press the pound key. Thank you. Mr. Lou, you may begin your conference.

Speaker 3

Thank you, Robin. Good morning, everyone. This is Michael Lou. We are reporting our third quarter ending September 30, 2011, results today, and we are delighted to have you on our call. I'm joined today by Thomas Nusz and Taylor Reid, as well as other members of the team. 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 third quarter 10-Q tomorrow. During this conference call, we will also make references to adjusted EBITDA, which is a non-GAAP financial measure. Reconciliations to adjusted EBITDA to the applicable GAAP measures can be found in our earnings release or on our website. I will now turn the call over to Thomas.

Speaker 1

Good morning, and thank you for joining us this morning to discuss our third quarter financial results, recent operational activity, and our outlook for the rest of the year. I'll begin with an operational update and outlook, and then I'll turn it back over to Michael to cover financial highlights. We had a great quarter coming off the heels of two tough quarters that were largely influenced by weather. The 47% production increase quarter over quarter is a good indication that operations are getting back up to speed. As we announced in late October, we continue to grow production, and our operational reports have us around 14,300 BOE per day for the full month of October.

Included in that most recent production growth is about 2 million cubic feet per day of net incremental natural gas production above the 3Q average of 2.45 million cubic feet per day, which we attribute to new wells being connected to our gas infrastructure that we'll discuss more in a moment. The team did a great job ramping up production in the third quarter to get us back on track operationally. Although we had the obvious weather-related issues in the first half of the year, we have made some important strides this year in setting up our asset base for the most optimal, cost-efficient development going forward. We have significantly de-risked our acreage position, proven the impact of 36-stage completions, and have begun understanding the full potential of the Three Forks formation.

We've added two additional rigs in October, taking us to nine operated rigs, and we are ramping up our activity as planned going into 2012. We believe 2012 will be an even better year because of the actions that we've taken during the course of this year. We continue to make progress delineating and securing our acreage position, as well as consolidating in our core blocks. Counting our core de-risked acreage, which across the basin is about 250,000 to 260,000 net acres, we have an inventory of about 1,500 remaining operated locations and 2,400 total gross locations. On our nine-rig program, that equates to about 17 years of inventory. As we ramp up to 10 to 12 rigs, depending on the efficiency and market conditions, we would envision being able to do about 120 gross operated wells per year.

At the end of 2012, we'll have about 1,400 remaining locations and approximately 12 years of inventory. Remember when we talk about our inventory and our de-risked acreage, this is the acreage that's in the heart of the play and excludes any fringy stuff. All of the subsurface mapping indicates that these 250,000 to 260,000 net acres look to be within our tight curve ranges. Our team continues to upgrade our land position, increasing acreage in our core de-risked operated areas and dropping acres in geologically challenged areas. We continue to focus on increasing our working interest in our operating blocks so that each gross operated well that we bring onto production has more of an impact on our overall net production.

Additionally, we estimate that with this year's drilling program, we currently have approximately 160,000 net acres held by production. This is a little bit ahead of where we expected to be coming into the year and a function of the great job that our land group has done consolidating acres in our core drill blocks. As you know, we now have nine operated rigs in the basin. We have also secured the contracts that will allow us to go to 12 rigs by the end of 2012 and potentially as early as August. At the same time, we've managed our rig contracts so that we have the flexibility to scale back to five to six rigs in a soft oil price environment. We also have three frack crews now, as the third crew started in late June.

All three of our crews were running efficiently in September and all are dedicated only to us. At the end of September, we had 21 wells waiting on completion, which is down from 23 at the end of June. We brought 22 Middle Bakken and Three Forks wells on production in the third quarter with an average working interest of 79%. Nine of those were brought on in September. That brings our total operated wells brought on production this year to 46. With these wells and the new wells we expect to bring on production in the fourth quarter, we believe that we will be around the low end of our 2011 production guidance range, as we noted in late October. At the end of September, we had four wells that had been fracked but were waiting on clean-out.

This count grew to nine in October as we slowed clean-out activity. Our total wells waiting on completion increased from 21 to 26 in October, but we also added a third workover rig to focus on clean-outs and work through our backlog. As I mentioned earlier, we had about 14,300 BOEs per day of production in October, so we were still able to grow production considerably above our Q3 average. I want to now switch gears a bit and give you an update on our infrastructure development. On the gas side, as of November 1, we had connected 31 operated Bakken wells to gas gathering lines. A total of 29 of those were connected in the third quarter, 13 in South Cottonwood on the east side of the basin, and 16 of those on the West Williston side of the basin in Red Bank and Indian Hills.

As a result of the new wells coming online, daily gas production has increased almost 2 million cubic feet per day in October. We are anticipating an additional 70 to 75 wells to be connected to gas gathering infrastructure by the end of the year. We expect to have connected approximately 100 wells in 2011. In the first half of 2012, we expect to connect an additional 40 wells, including wells from North Cottonwood. This production all falls to the bottom line as there's minimal incremental capital costs associated with this incremental production. We've always forecasted pricing on the gas side approximately 110% to 115% of Henry Hub. Given the percent of proceeds contracts coupled with the high BTU content of the gas, this may prove to be a little bit conservative. Something along the lines of 150% of Henry Hub might be a bit more accurate for modeling purposes.

Additionally, the construction of the oil gathering infrastructure continues to make progress, and we continue to expect wells to be connected at the end of this year and early in 2012. So far, two wells have been physically connected to the system but have not yet made first delivery. We are anticipating connecting approximately 75 gross operated wells in Red Bank, Indian Hills, and Hebron to the gathering system. Substantially, all of the new wells completed in these areas will be connected to that system. The system will help us eliminate trucking costs of approximately $4 per barrel, which will immediately impact our realized prices and will keep oil flowing through tough winter conditions since trucks will no longer be required to pick up the oil. There is a fee associated with the production, which will show up as a new line item in our financial statements.

Net-net, we expect to improve our margins by approximately $1 to $2 a barrel. In addition, with the gathering system in place, we will have the flexibility to nominate our oil to different delivery points along the system. We have taken steps to transfer some of the marketing responsibility in-house to take advantage of this opportunity. The saltwater disposal system we are investing in this year and next will also be extremely valuable to overall operations. In the third quarter, our LOE was impacted by the cost to transport and dispose of water. On a per BOE basis, saltwater handling was about 28% of our costs in the first half of the year, and in Q3, saltwater handling was about 48% of our costs.

This is due primarily to increased waiting times by the trucks at SWD wells and to a lesser extent, increased costs per hour charged by trucking companies. We had this in mind when we increased our SWD budget in August to bring forward some of the 2012 capital and offset these costs. While not reflected in the third quarter numbers, we are already seeing a positive impact of our SWD system in the fourth quarter. The SWD system in the southern part of East Nessen is currently operational, and Chord Energy expects the SWD system in West Williston to begin operations in the first quarter of 2012 with more wells being connected throughout the year. This will eliminate the need for trucks, simplify logistics, and reduce costs in 2012 by $2 to $3 per BOE from current levels.

Now let's turn to well performance of our 36-stage completions and the Three Forks wells that we have on production. As you know, based on our findings, we have transitioned all future wells to 36-stage completions. We are encouraged by the results and see an approximate 20% to 30% increase in production compared to nearby wells completed with 28 stages. This supports the thesis that an increase in stages continues to increase production and is a very efficient use of our capital. We continue to be encouraged by what we're seeing out of the Three Forks at this stage of testing. While the geology is a bit different than the Bakken, we have some positive test results. We have now completed and brought online four wells in the Three Forks. We have not yet discussed the results of our Spratly well, which was completed with 36 stages in South Cottonwood.

The Spratly well produced 61,100 barrels of oil over the last 47 days, or an average daily production of 1,300 barrels of oil per day. This clearly is a good well, and we are in the process of drilling another well in the middle part of North Cottonwood to give us more Three Forks tests on the east side of our position. We also have another Three Forks well in Indian Hills that's waiting on completion, which will be close to the High Stead well that we've talked about previously. As we fine-tune our geosteering, we believe wells in this area will produce inside the range, especially as we increase to 36 stages. As we continue to test the formation, the data we gather should further demonstrate the evolution and the upside of the play.

Finally, as we continue to push the boundaries on our acreage, we're looking forward to getting production data on our wells in our target and Mondak areas. The Copper Well in Montana will provide good data in our target area as a western extension of what we've been seeing in Red Bank on the North Dakota side. Further to the south in our West Williston position, the Bay Creek Federal Well is a significant step to the south in our Mondak area. It is still early days for this 28-stage well, but the well appears to be around the low end of our tight curve range. We expect to get more data over the next few quarters on Mondak as we will drill and complete three more wells here. One well in the northern Mondak is waiting on completion, and another well in central Mondak is drilling.

The other well should be an offset to the Bay Creek Federal. With respect to well costs, we're maintaining our estimate of approximately $8.5 million for an all sand well and approximately $9.2 to $9.4 million for a well with a ceramic and sand mix based on our 36-stage plug and perf completions. With service cost escalation, learning in the Three Forks, and weather in the first half of the year, we did see our overall average ceramic sand combination wells more in the $9.6 to $9.8 million range. Going forward, well costs look to be coming back more into our $9.2 to $9.4 million range. All that being said, we continually look for ways to reduce overall well costs, and it will help as we get closer to the back half of 2012 and even more so in 2013 as we start to get into more full-scale mode.

With that, we expect to reduce well costs by at least 10%. We are currently working on well configurations on our multi-well development pads to determine the optimum efficiency for well production and spacing. We will be testing four Bakken wells per spacing unit and six total wells, including Middle Bakken and Three Forks per spacing unit early next year. Additionally, we have been testing the impact of using 100% sand in the northern portions of Red Bank and North Cottonwood. We have chosen these areas primarily due to shallower depths and lower pressures. Our original assumption was in this environment, we would not compromise well performance by using all sand. Results to date confirmed our belief that the wells would perform in line with wells with ceramic and sand mix. We're saving $500,000 to $750,000 on these 100% sand wells.

Lastly, we continue to expect our in-house frack crew to save us approximately $16 million to $20 million in CapEx. We currently expect equipment to show up around the end of the year, and the new crew will begin completing stages in the first half of 2012. It's probably safe to assume that we will save about $10 million to $12 million in the calendar year 2012 with OWS. With that, I'll turn the call back over to Michael to discuss our financial results.

Speaker 3

Thanks, Tommy. Before I get into the financials, I'd like to first talk to you about our recent high-yield debt issuance. As we've discussed before, to fund our growth profile, we were always intending to opportunistically tap the debt markets. A window opened in the high-yield markets, and we prudently launched our deal to lock in record low rates. By taking funding risk off the table, we now expect to be able to fund our capital budget outspend, given an $80 per barrel WTI oil price environment, into the middle of 2013 without tapping our revolver. Including our revolver, which was recently increased to $350 million of borrowing-based capacity, we will have about $1 billion of liquidity when the 6.5% notes close on November 10th.

As Tommy mentioned, we had a record third quarter with adjusted EBITDA of $62.9 million on revenues of $88 million, fueled by nearly 50% quarter-over-quarter production growth. Differentials remained strong in the third quarter as we averaged a 6.3% differential to WTI. Pricing in Clearbrook and Guernsey, our primary delivery points, were at a premium to WTI during the quarter. On another note, as you know, we also used hedging to protect our drilling program. We continue to layer in hedges opportunistically as the market warrants. We now have 8,500 barrels per day hedged for the remainder of the year, 13,500 barrels per day hedged in 2012, and 7,000 barrels per day hedged in 2013.

Even with future oil price volatility similar to what we experienced in the third quarter, we feel comfortable that our drilling program is well protected based on our attractive floor prices, which average around $85 to $90 per barrel of WTI. On the cost side, Tommy discussed the impact of LOE costs and how SWD infrastructure will help alleviate these cost pressures in the future. G&A costs have trended a bit higher as we continue to grow our team to support a 12-rig program but are still in line on a dollar per BOE basis. Production taxes have also been a bit better than originally predicted. Our capital expenditures in the third quarter were $206 million and $414 million year to date out of our $627 million budget for the year.

In conclusion, we had a great quarter, and we had the right team in place to execute the increased drilling and completion activity. The team delivered production growth, all while implementing measures to reduce well costs, LOE, and other costs, as Tommy described. We also have locked in the cash and cash flow to keep extremely financially flexible in any type of commodity price environment, and we have matched that with our service contract flexibility. We're looking forward to a strong fourth quarter and setting the stage for additional growth in 2012. With that, we'll turn the call over to Robin to open the lines up for questions.

Speaker 5

At this time, I would like to remind everyone, if you would like to ask a question, please press star one on your telephone keypad. Again, press star one on your telephone keypad. As a reminder, please take your phones off speaker before asking your question. We'll pause for just a moment to compile the Q&A roster. Your first question comes from the line of Ron Mills.

Speaker 0

Good morning.

Speaker 3

Morning, Ron.

Speaker 0

Tommy, question, you started to test more of the Three Forks. Any comments as to what Continental has been saying about multiple benches in the Three Forks, or are your tests going to allow you to test multiple benches or even see, are you taking cores far enough or deep enough to determine the prospectivity of that to augment just the first bench of the Three Forks?

Speaker 1

Yeah, Ron, we haven't done any work on that so far. There are a few wells across the basin where we've taken cores before, but I don't think that we're in a position to, at this point, to augment anything else that's been said about the other benches in the Three Forks across the basin. I mean, we'll continue to watch what's going on there, but I don't think that we have anything to add to that.

Speaker 0

Okay. From an activity standpoint, it sounds like you're already at nine rigs, but you're maybe reading into this, but you're already talking to people about access to rigs to go to 10 to 12 by the end of next year. On the completion side, you obviously have the capacity with the three current crews plus your own frack spread. How about the infrastructure that is going in both east and west in terms of its capacity to handle that kind of ramp to 12 rigs, or are there more discussions about potential expansions there?

Speaker 1

I think we're in good shape. Taylor, you may want to provide a little more color on that. Yeah.

Speaker 4

The infrastructures, we go to 12 rigs. The base infrastructure will be in place by the end of this year. We will add on to it in some of the areas. North Cottonwood, for example, we're expanding the gas gathering and processing. That area will be covered next year. Essentially, it'll just be expanding the gathering systems to pick up the new wells as we drill them in each area. We should be in good shape with respect to the infrastructure.

Speaker 1

Yeah, most of the big pipe will be in, especially as the North Cottonwood project gets done. It's just little pipe to get to the well sites.

Speaker 0

Okay. Lastly, just for Michael, maybe for you directionally, you talk about the financing getting you through, you know, kind of mid-2013 on your planned activity levels. Is that assuming you get to kind of a 12-rig run rate by the end of next year and you're holding it flat in 2013 as we just look for directional? We know the direction, but magnitude of CapEx increases.

Speaker 3

Yeah, that's right, Ron. We'll obviously come out with a little bit more detail when we set our capital budget for 2012 later this year. As we move towards that 12-rig program next year, that's assuming that we go in that direction as well as keeping that 12-rig program flat going forward.

Speaker 0

Okay, great. I'll jump back in queue. Thank you, guys.

Speaker 4

Thanks, Ron.

Speaker 5

Your next question comes from the line of Marty Bisco.

Speaker 2

Morning.

Speaker 1

Morning.

Speaker 2

Hi. Based on recent well results, could you update us on your EURs as to kind of what you're seeing and how that relates to the type curves estimates that you've given so far for East Nessen and also West Nessen?

Speaker 1

Yeah. East Nessen, as you know, on 28-stage wells, we were estimating 350 to 600. On the west side, 400 to 700. What we're seeing based on early data is a 20% to 30% uplift with 36-stage completions. In some of the more prolific areas, say South Cottonwood, Indian Hills, some of the wells, some of the performance is a bit above the 30%. In some of the lower productive areas, the northern part of Red Bank, North Cottonwood, we would expect it to be more in the 20%, maybe a bit less than that. I think with all those numbers, you should be able to get a pretty good sense for what the new ranges will be. At some point here in the not-so-distant future, we'll be able to make that switch to where it'll be a lot cleaner for everybody.

Speaker 2

How about as far as for the Three Forks wells? What are you expecting so far from those?

Speaker 1

At this point, it's a little bit early to tell. I mean, obviously, we don't have a whole lot of internal data points. Now, we've got some external data. What we've said consistently is that it is going to be a bit different. It may be, you know, and it may be, call it 20% less than the Middle Bakken. That being said, when you look at wells like the Spratly well, it looks pretty consistent with the Middle Bakken. It's going to be a bit variable, and we just need to get more data. They're all good. They're all within the tight curve bands, but we need more data. We've obviously talked about the two wells on the west side of the basin, the Strata-Lestate line over in Hebron, that are at the low end or below the low end of our tight curve bands for 28-stage wells.

Those two wells, one of them effectively had 23 stages, the other one effectively 18 to 20 stages, but per stage recoveries looked real good. They just didn't have enough stages.

Speaker 2

For your plans for drilling in 2012 of the gross number of wells, what % of those do you plan on having on pad drilling, and how many of those would be individual wells that would be holding on 1,200-acre units?

Speaker 1

Yeah, it's probably going to, I don't know. I don't know if we've got a number for that. It's probably a fairly low percentage. It's probably, Taylor, 10%, maybe 15%, and then it'll be pad wells for the calendar year.

Speaker 4

At least half the program is still drilling to hold acreage. Full pad wells where we're drilling out of a full infill pattern is a small subset, under 10%, but we will be drilling a number of just wells that have one well going north, one well going south like we have been. That total off of pads may be 30 to 40%. I don't have the immediate number in that range.

Speaker 1

Yeah, that would include full pad development, as we call it, wells, and then the smaller pad where we're hitting two 1280s with one small pad, but only getting one well in each 1280.

Speaker 2

You said that you were going to test up to four Bakken wells per 1,280-acre section, is that?

Speaker 1

Correct.

Speaker 2

Up to six wells for the spacing units. Does that assume that the other two are going to be in the Three Forks?

Speaker 1

I think the way Brett's got that laid out is that in that particular pilot, 1,280-acre pilot, it would be three and three.

Speaker 2

All right. Thank you.

Speaker 1

You bet.

Speaker 5

Your next question comes from a line of Marcus Talbert.

Speaker 2

Hi, guys. Good morning.

Speaker 1

Morning.

Speaker 2

Hey, Tommy. You briefly touched on your inventory during the opening comments here, and you mentioned that 10 to 12 rigs would imply, I think, approximately 120 gross operated wells next year. Thinking about some of the pad drilling efforts that Taylor just mentioned and some of these drilling efficiencies that you guys have picked up throughout the year, does that number, is there a buffer in that number for weather delays or any external factors? It just seems a little conservative, I guess.

Speaker 1

Yeah, it is. You know, we have historically used 10 wells per rig per year. With 12 rigs, that would get you to 120. Given recent performance, we're generally, Taylor, spud to rig release about 25 days. We've had some as low as 20. When you count rig moves, it's not inconceivable that you could get, if everything goes right in decent weather, that you could get 11 to 12 wells per rig per year. Obviously, that improves a bit with pad drilling as well, but you're not going to see much of that in 2012. There could be, I mean, short answer is, yeah, it's a conservative number. There may be more upside to that. On a single small pad where we went one well north and one well south, the best we've done so far, rig release to spud of the next well was 12 hours.

You start doing a lot of that, then that number could grow.

Speaker 4

Right.

Speaker 1

Yeah, this year's average, 2011 aggregate average is 10.8 wells per rig per year.

Speaker 4

10.8. Okay, great.

Speaker 1

A bit above the conservative 10 that we've been using.

Speaker 3

Just to be clear, when we said 120 wells per year, that's when you get to a full 12 rigs. Next year, we'll be growing into the 12-rig program. You'll have an average of around 10.5 rigs running throughout the year. That 120 number for next year is actually maybe a little bit lower than that to have the consistent deal.

Speaker 2

Okay. Thanks for the color there, guys. You touched on the progression within the Three Forks. I guess in terms of your Bakken well results, as you move north into the Red Bank, it looks like they've been sort of variable there. Do you know how many of these producers have been completed with more than 30 stages out of the program that you've laid out for this year?

Speaker 1

36-stage completions in Red Bank so far this year?

Speaker 2

Yeah.

Speaker 1

Hold on. You got that. I think Tommy's sheet. We got the 11 so far.

Speaker 4

36 stages.

Speaker 1

Yeah. Yeah, 11 wells that have been done with 36-stage completions. Five of those have been on pump so far.

Speaker 2

Okay. Looking at some of the data for that Red Bank area, it looks like one of your strongest producers, I think it's the Logan Well, is a little bit east of where much of the activity has been there. Is there anything that you can tell from the interval as you move east to west? I understand that it shallows as you move north towards Divide County. Thinking about the position as you move east of the heart of the activity there, is there anything you're seeing different?

Speaker 1

Yeah, just, you know, generally, as you in Red Bank to the east and to the southeast, the results are better. The Logan's a good example. Another good example is the Andre Well. There's also an area in there where there's a little bit of a structure. Water cuts tend to be a little lower in that area, and we've seen better performance. As you trend to the west and more to the north and west, the water cuts tend to go up.

Speaker 4

Frankly, you're getting shallower.

Speaker 2

Okay.

Speaker 4

We see that pretty consistently as you start to shallow east or west, water cuts tend to go up.

Speaker 2

Okay. Super. Thanks for the color, guys. I'll get back in line here.

Speaker 1

Perfect. Thanks.

Speaker 5

The next question comes in line of William Butler.

Speaker 2

Good morning.

Speaker 1

Morning?

Speaker 2

Thinking about where your rigs could be added in 2012 on the nine-rig program, it's two in the east, looks like seven in the west. Where do you have any sense of where you're going to focus those added rigs in 2012?

Speaker 1

We're still working on the final plan, but we'll add a second rig in Hebron, drilling in the Montana area. We'll continue to run most likely two rigs on the east, and we're going to have, we talked about the infills, we're going to test some infill pilots where we're drilling anywhere from four to six wells back to back. We'll have those pilots going on in both Indian Hills and in Red Bank, so that will consume some of the rig time as well.

Speaker 2

Okay.

Speaker 1

It's probably somewhere in, you know, if you had 12 rigs running, it's probably eight to nine on the west side, you know, three to four on the east, just depending on, you know, how the program lays out.

Speaker 2

Okay. Have you got any commentary on how the fractures in place on your western versus your eastern properties could impact spacing of or the amount of Three Forks per section yet? I mean, or is there just not enough data on that? Can you talk a little bit more about prospectivity of Three Forks east versus west?

Speaker 1

Yeah. On the east side, in the south, I mean, especially if you anchor off of the Spratly well, it looks as good as the Middle Bakana wells. We'll get a data point here in the not-so-distant future with the well that we're drilling right in the middle of Cottonwood. On the west side, we still need to get some more data. We've got the High Stead. We've got the other well that is drilled but not yet completed that's right next to it. Those two over on the state line weren't completed with the high stages. We still need to get a bit more data, but probably, Taylor, probably fair to say that it is a bit more variable on the west side than on the east? Probably.

Speaker 4

Yeah, it's more variable. I'd say at this point, the most perspective, like Tommy talked about, on the east side is South Cottonwood. On the west side is Indian Hills. We've got the best data there. As you go to Red Bank and Hebron, we just need more wells drilled and more tests. We're encouraged by what we've seen so far. North Cottonwood, back on the east side, we've got some early wells that were drilled with short laterals, 5,000-foot, and eight-stage fracks. We need to continue to step longer laterals and more frac stages to the north, which we'll do.

Speaker 2

Okay. One last question. Is there, with the cash on the balance sheet, are there any alternative uses you all could see between now and just using that for drilling between now and 2013? How should we think about that money?

Speaker 3

You know, the cash we raised is primarily for our drilling program, but obviously, it gives us some flexibility if we see good bolt-on acquisitions. We've been pretty clear on that too, that if we find good positions inside our drill blocks that we can operate, we'll look at those opportunistically.

Speaker 2

Okay. Would that have to come with production versus being raw acreage? Would that be?

Speaker 1

Yeah, as a general rule, a lot of times they may come with production. It's primarily acreage, just like the deals we did at the end of last year, right? Now, there was, I think, out of those two deals, we spent $80 million. And I, as I recall, we picked up 300 to 500 barrels a day, something like that.

Speaker 2

Okay, is there a lot of deal flow still going on?

Speaker 1

There is, but it's starting to taper off a bit. I mean, at least for things of any size.

Speaker 2

Okay, that does it for me. Thank you all.

Speaker 1

You bet.

Speaker 5

Your next question comes from the line of Dave Kessler.

Speaker 2

Morning, Dave.

Speaker 4

Good morning, guys. Real quickly here, you guys had mentioned on the last call kind of a CapEx outlook for 2024, very, you know, kind of a wide swath, but $750 to $800 million. I know you can't indicate if that's changed or bigger or higher, but can you indicate what % of that is drill bit?

Speaker 3

Yeah. Of our capital program, we were assuming around $700 million of drilling and completion capital there. What we were saying on top of that, Dave, was that if you had about $20 million of lease expense, which we kind of think of as our land load every year, you add about $10 million for geologic work, about $20 million for additional infrastructure and a little bit of OWS, and you put some contingency dollars in there, that's how you get to the $750 to $800 million number.

Speaker 4

Perfect. That's helpful. In thinking about that, I'm guessing you're reflecting the benefits of OWS and the cost savings there. Tommy, you highlighted some of the potential well cost savings going forward. Is that factored into that number, or are we assuming that we're not really moving to kind of a lower development well cost at that point?

Speaker 1

Yeah. For next year, we're not baking that much of that in just because of the percentage of wells that are in full pad. When we talk about the 10%+, that's assuming that you're getting into full big pad development mode, not the small pads where we do one north, we do one south, like we've been doing for the last couple of years. Really, I mean, it's 2013 before you start doing that in any meaningful way.

Speaker 3

Dave, just so you know, those numbers are based off of some pretty high-level numbers at this point. We're going to get to our full capital program a little bit later this year when it's approved by the board in December, and we'll come out with a little bit more granularity. What we were assuming there was around 75 net wells, and we were just multiplying it by around $9.2 million on average for the wells, which gets you to your $700 million of drilling completion budget.

Speaker 4

That's very helpful. Just kind of thinking about when you brought in the new frac crew, it took a little bit of time to get them up the learning curve and more efficient. As you bring in a new frac spread, are you guys kind of factoring how that learning curve will take place, or are there things that you digested and understood that you think you can drive the efficiency gains of that crew faster? Any kind of color around learnings that took place and how you think about that for moving forward in kind of production forecast?

Speaker 1

Yeah, I'll add, I'll let Taylor add a little bit of color to it. Keep in mind that the three frac crews that we've got running for us right now all came from outside the basin. We've got a pretty good bit of data on this so far.

Speaker 4

We think that it's going to take us a little bit of time to get the equipment and the crew up and running efficiently. What we factor in is, you know, we say by 2Q, we will be fracking our own wells, doing it efficiently. We think by within first quarter, or very early 2Q, that we'll be starting some fracs, and we'll start out doing 12-hour operations and then ramp up to 24-hour operations to get more efficient. We've taken some of that same approach with some of the crews that have come in from outside the basin. Great. That.

Speaker 2

That's helpful. Just one last one, as you guys bring the marketing efforts in-house, can you talk a little bit about what that might represent in terms of cost savings or benefit to your realizations, and anything that you guys are doing to make sure that you have some workarounds on this LLS WTI spread?

Speaker 1

Yeah, I think that bringing the marketing in-house, as we've talked about, the early savings is really in the gathering system. Eliminating trucking and being able to take our oil by pipe to delivery points will cut $1 to $2 a barrel. It'll be a net benefit to us of $1 to $2 a barrel. From a marketing standpoint, what we'll then be able to do is sell to third parties further downstream rather than just at the wellhead. It does increase our flexibility and allows us to get to more markets outside of places like Guernsey and/or Clearbrook. We think we'll get some more attractive netbacks, but we're still working through all that, David. I just can't tell you how much we'll have that's not directly WTI-based, but we will have some sold at other markets. It could be places other than LLS.

It could be East Coast, could be West Coast, places that have better pricing.

Speaker 4

Okay, that's helpful. Isn't there a fee that you're paying your marketers or a percentage spread that they take just off the top? Would that get removed as well, I would imagine.

Speaker 1

Yeah, the third-party arrangements generally, it's just a deduct. You don't know what amount there is, but yeah, sure, they've got some charge that they have to cover their work and their overhead. That would then go away.

Speaker 4

Okay, that's helpful, guys. I appreciate the added color there.

Speaker 1

All right, Dave.

Speaker 5

Your next question comes from the line of Andrew Coleman.

Speaker 2

Thank you very much. I had a question on, as you move to bringing on more of the gas wells, do you expect to see much of a change in the oil weighting there for the company in 2012?

Speaker 1

No, it's not going to, I mean, it's not a big enough number really to move the needle that much on overall oil weighting. If we're at 92% oil on an equivalent basis right now, it may move it by a point, but it's not going to be meaningful.

Speaker 2

Okay. All right, sounds good. Getting your comments on the water disposal system, you said it was 48% of cost in the third quarter. How much do you think that could kind of fall down to once you get all your disposal wells and pipes all set up?

Speaker 3

Yeah, Andrew, it was closer to 25% in the first half. I think that's an initial bogey that you get to, and you'll continue to move costs down from there with the saltwater disposal system. It should remove quite a bit of capital costs and a lot of the increases that we saw here in the third quarter.

Speaker 2

Okay, target back to like the 25% range then?

Speaker 3

Yeah, 25%, and then ultimately moving probably a little bit lower than that.

Speaker 2

Okay, thank you very much. A couple of easy questions.

Speaker 1

Yeah, thanks.

Speaker 5

Your next question comes from the line of Jason Wengler.

Speaker 2

Hey, good morning, guys.

Speaker 1

Morning, Jason.

Speaker 2

All right, just on the well completions, it looks like you're getting the backlog down. What do you think, you know, in a perfect world, would you have as far as the backlog? Would it be in the 15 to 20 range? Is there a little bit still that you're working off with the three crews now?

Speaker 1

Yeah, I think, you know, historically, what we've been talking about is that it's somewhere around 10 to 12 when you're running seven or eight rigs. When you start running 12 rigs, Taylor, that number is going to grow to 18s, maybe 16 to 18, something like that.

Speaker 2

Okay.

Speaker 1

Of course, it also, I mean, we've talked a little bit about this before, but you know, as our drilling gets more efficient, we're adding to the inventory a little bit faster than what we thought as well.

Speaker 2

Right. As you're getting all this stuff put in, as we get to the year end, about how much of the production do you see will be going into pipes, you know, as we get it to year end when the weather starts getting really bad, so that if we do have another bad winter, what we're looking at as far as what would still have to be trucked?

Speaker 1

On the oil production side?

Speaker 2

Yeah.

Speaker 1

On oil production going into pipe at year end, we think most of the wells will be hooked up by year end. We probably won't be flowing into pipe until first quarter, which partially has to do with nominating and, you know, surety of having the wells hooked up and being able to move that oil. We'll have the system in place, some moving prior to year end, but I expect most of that impact to come January and in the first quarter.

Speaker 2

Perfect. Go ahead, guys. Thank you.

Speaker 1

That.

Speaker 5

Your next question comes from the line of Scott Hanold. Scott, your line is open.

Speaker 2

I'm sorry about that. I had it on mute. You mentioned one of the rigs that you're going to add is going to go over to the Hebron area. Is that because you need to capture the acreage, or do you just want to sort of accelerate some of the activity out there?

Speaker 1

That's more associated with continuing to extend or test some of the acreage. For example, we acquired LUFS position last year, and that was about 10,000 acres. In almost all of that, it's held by production. With the second rig, we'll go ahead and start to drill some of that acreage. It's a little south of where we've been drilling, but we think in a good area. We'll start drilling one Bakken well per spacing unit within that area next year.

Speaker 2

That's all south of the river?

Speaker 1

All south of the river.

Speaker 2

Okay. Okay. Up in Target, when does that northwestern extension well get tested? Remind me again the lease times that you have up there and how active in 2024 you could be in Target.

Speaker 1

The well that's drilled and it's actually fracked is called the Copper Well, and it will be tested probably this month. It's just waiting to be cleaned out. Hopefully, in the coming weeks, we'll begin to test that well. In 2012, we've got three additional wells that we will drill in Target, and those are dealing with lease expiration. We've got a program in place that will be able to hold all the leases there.

Speaker 2

Okay. Okay. Am I mistaken? Was there another well that you had planned up in the far northwest corner? Am I mistaken? Oh, you know what? That's just an open acreage block I'm looking at here. I apologize.

Speaker 1

That's okay.

Speaker 5

Your next question comes from the line of David Snow.

Speaker 4

Yeah, hi. There have been one or two 7,000 barrel a day wells. Can you give us any ideas as to what's going on there? Not yours, but.

Speaker 1

Yeah, you're referring to the Whiting well that was announced a few weeks ago. There was a 7,000 barrel a day well, and it was to the southeast of our Indian Hills position.

Speaker 4

Actually, I suppose we're over towards the end of 2021.

Speaker 1

Yeah, it's directly to the east, maybe a little south of Indian Hills, but in a good position. We don't have any more data on that well other than what was announced.

Speaker 4

I think there's a difference in the way they completed it, or is it just the rocks? Hard to tell at this point. I mean, you are getting closer to the anticline over there, but I don't know that we have enough data to tell us whether it's rocks or completion. All right. Thank you very much.

Speaker 1

You bet.

Speaker 5

Your final question comes from the line of Peter Mahan.

Speaker 0

Morning, guys. Just two final questions. You talked about having 160,000 acres held by production. Where do you kind of see that growing to by the end of the year? Maybe by the end of 2012, you talked about having 250,000 to 260,000 core net acres. What kind of percentage of that will be held by production by maybe the end of 2012?

Speaker 1

Yeah, so what we've been saying earlier is that we come into the year with 90,000, and we thought we would convert through this year about 60,000. That was kind of a little bit of high-level math. What ends up happening is as you drill some of these drill blocks, those leases actually will slop over onto adjacent drill blocks, so you end up capturing a bit more. Through this year, we thought we might be at 150 at the end of this year. We're at 160 already with a couple of months yet to go. Probably at the end of the year, it's probably going to be somewhere, maybe another 5,000 or 10,000 acres or something like that. If you start thinking about that and you say, okay, if with ramping rig activity next year is, call it 70, then we're at 240.

We're getting pretty close to being balanced. It's probably still going to be first quarter of 2013, but we think we're in good shape and getting everything held.

Speaker 0

All right, great. Kind of jumping piggybacking on that, you really don't see problems with lease expiration, especially in the core areas that you're working on. It sounds like most of the core areas will be covered before any expiration issues.

Speaker 1

Yeah, I think we're in real good shape and holding the acres that we want to hold.

Speaker 0

Perfect. Great. Thanks a lot, guys.

Speaker 1

Yeah.

Speaker 5

The next question comes from the line of David Deckelbaum.

Speaker 0

I'm sorry if you all can't hear me. I must be having some technical difficulties.

Speaker 1

No problem.

Speaker 4

Okay, we got you now.

Speaker 0

All right. Glad I figured that out. Back to the questions then. You talked about using 100% sand and testing that in Red Bank, North Cottonwood. Any other areas you think that might make sense to, you know, squeeze a little bit of cost savings out, or is it risk-rewards is not really compelling?

Speaker 1

Taylor may want to comment on it, but I think as you get over to the western or southwestern portion of Hebron, it may make a little bit of sense as you get down into Mondak. Maybe those would probably be the two, the far southern part of Mondak. Those are two areas where it may make a little bit of sense.

Speaker 0

I guess to put it another way, do you think that we have enough data yet on the entire inventory or wells drilled in inventory to date that suggests that you would see enough of a difference in EURs using that 65/35 ceramic sand mix?

Speaker 1

In the core areas where we're using it now?

Speaker 0

Yes.

Speaker 1

We don't have enough data yet.

Speaker 0

Yeah.

Speaker 1

I don't think to say, I mean, generally, my guess is it's probably four or five years before you really could say, "Hey, here's what the, you know, I can quantify what the difference may be.

Speaker 0

Great. Could you just refresh me quickly as the OWS spread comes in? Should we be thinking about a differential on cost there? I know that you have to charge a third party to yourselves, but you know, would there be any cost savings from using an internal spread just on the per well basis?

Speaker 1

Yeah, that's the roughly $20 million, an $18 to $20 million on an annual basis reduction of CapEx.

Speaker 0

Okay.

Speaker 1

As we talked about, there's two components of it. There's the CapEx reduction because it's just intercompany transfer, but then there's a component of third party as well.

Speaker 0

Right. Lastly, just to, you know, on the saltwater disposal impact to lifting costs, how do we think about the timing? I know that you've all guided a $2 to $3 decrement in the cost blended next year. Should we see that bite in, you know, pretty immediately in the first quarter of 2012, or do you see that sort of trending gradually over the year?

Speaker 3

It's going to be pretty gradual throughout the year. Dave, you're going to see it start to happen in that first quarter of next year, but you'll see that kind of gradually come in. It's going to be a couple of things. One, it's the saltwater disposal side of it, and the other is just as you get more Bakken production, it's just going to continue to help that.

Speaker 0

Great. I think that's all I have for now. Thanks, guys.

Speaker 1

Great. Thanks, Dave.

Speaker 5

There are no further questions at this time.

Speaker 4

Okay. Thanks again for everyone's participation in our call today. I appreciate all the hard work and focus on continuous improvement on the part of all the employees of Chord Energy and our key contractors in the office and in the field. We appreciate the support that we continue to get from our strong shareholder base. We look forward to sharing with you in December our capital plans for 2012 as we continue to execute on our tremendous inventory.

Speaker 5

This does conclude today's conference call. You may now disconnect.