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Continental Resources (NYSE:CLR)

Q1 2012 Earnings Call

May 03, 2012 10:00 am ET

Executives

Harold G. Hamm - Executive Chairman, Chief Executive Officer and Member of Nominating & Corporate Governance Committee

John D. Hart - Chief Financial Officer, Principal Accounting Officer, Senior Vice President and Treasurer

Jeffery B. Hume - President and Chief Operating Officer

Jack H. Stark - Senior Vice President of Exploration

Analysts

Eli Kantor - Jefferies & Company, Inc., Research Division

Joanna Park

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

Jason Selch

Stephen P. Shepherd - Simmons & Company International, Research Division

Marshall H. Carver - Capital One Southcoast, Inc., Research Division

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

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

Operator

Good day, ladies and gentlemen, and welcome to the Continental Resources First Quarter 2012 Earnings Conference Call. This conference call is being recorded. Today's call will include projections, assumptions and guidance that are considered forward-looking statements. Actual results will likely differ from those contained in our forward-looking statements. Please refer to the company's filings with the Securities and Exchange Commission for additional information concerning these statements and risks.

Chairman and CEO, Harold Hamm, will begin this morning's call; followed by CFO, John Hart; and President and COO, Jeff Hume. After their remarks, we will have a question-and-answer period. Other members of management are available to answer your question.

Now I will turn the call over to Mr. Hamm. Please, sir.

Harold G. Hamm

Good morning, everyone. Thank you for joining us for Continental's first quarter earnings call from our new headquarters here in Oklahoma City. We began 2012 with tremendous production growth, 66% year-over-year.

Last night, we announced an excellent first quarter. We announced a reduction in rig count and an increase in our growth guidance for 2012.

First quarter 2012 production was 85,526 barrels of oil equivalent per day, 66% higher than the first quarter of 2011 and 14% higher than the 75,219 Boepd for the fourth quarter of 2011. We are currently exceeding 91,000 barrels of oil equivalent per day now.

Our strong production growth reflects increases in our major operating areas. Bakken production increased to 48,024 barrels of oil equivalent per day, 88% higher than the first quarter 2011. Bakken production represented 56% of our total first quarter 2012 production. North Dakota is the primary driver in our Bakken growth, as you saw in our press release last night. North Dakota Bakken production was 41,895 Boepd in the first quarter of 2012, more than double the production in the first quarter last year.

Montana Bakken production increased 16% in the first quarter 2012 compared with the first quarter of 2011.

The company's Anadarko Woodford production was 12,826 Boepd, almost 5x higher than production in the first quarter 2011.

As we've reported over the last 4 months, we've had a succession of strong well results in both the Southeast Cana in Grady County and in the Northwest Cana in Blaine County, Oklahoma. Production in the Red River Units was 10% higher in the first quarter 2012 than it was in the first quarter last year.

Our first quarter production growth was primarily organic through the drill bit. Three acquisitions have been completed since mid-2011, and we sold our Worland, Wyoming properties and associate production in early 2012.

The net combined effect of the acquisition and sale is an increase in production of approximately 800 Boepd going forward. Of greater significant, these acquisitions added 46,000 net acres of core Bakken acreage to our inventory, of which 60% is already HBP. These acquisitions have increased our ownership share in prime areas of the Bakken play, effectively increasing our production growth rate without increasing rig activity.

We simply own a greater interest in wells already scheduled for drilling during 2012. This magnifies the impact of both non-operated and operated well completions. Finally, we're seeing excellent results in terms of faster cycle times on drilling in the Bakken. We've cut spud-to-spud cycle times by 30% in the last 6 months. Again, this boosts both production results and CapEx spend rate.

Before leaving the subject of production, I'd like to note that there were no contribution from Wheatland Oil in the first quarter. In late March, we announced a proposed purchase agreement involving Wheatland, which is subject to a shareholder vote later this year.

We filed a preliminary prospectus on April 3, which discussed the details of the proposal. Given the pending shareholder vote, we will not comment today on the Wheatland proposal. Instead, we refer you to the preliminary prospectus for information on the proposal.

Last night, we also announced a new capital expenditure budget for 2012 and a new production guidance, a growth range of 47% to 50% for the year. To explain our revised outlook, let's go back to last November, when we announced our original budget.

At that time, we were focused on a number of key issues. What were they? One, oil price. Prices have remained favorable in the past 6 months, and our outlook remains positive, although there was a lot of volatility in the first quarter.

Two, service costs. Service costs have held steady, and we have seen some softening due to many dry gas rigs being laid down nationwide.

Three, operating efficiencies and execution. We've consistently pointed out our focus on execution and recapturing efficiencies that we enjoyed 3 years ago, while we were running fewer rigs. The operation guys are doing a tremendous job reducing drilling cycle times in the Bakken, and we'll have additional opportunities for efficiency gains as we shift to more ECO-Pad drilling in 2013.

Four, the infrastructure. Six months ago, everyone recognized North Dakota faced infrastructure challenges, not only in terms of gathering systems and pipe and rail transport out of state, but in terms of basic city and county infrastructure needs for people: housing, roads, water treatment plants, schools, basically all the infrastructure you need for rapidly expanding communities in the northwest part of the state.

This remains a challenge, but North Dakota is making rapid progress, and the energy industry is doing a great job to help. My point is since November last year, on all these issues: oil price, service cost, operating environments and infrastructure, we've seen significant progress.

As a result, today, we have an excellent operating and financial environment within which to accelerate the development of Continental's growing Bakken inventory, and that is what we're doing.

We've announced a revised CapEx budget of $2.3 billion, excluding acreage acquisitions. We revised our 2012 production growth to a range of 47% to 50%. We plan to participate in completing 842 gross, 300 net wells this year. Company-operated wells represent 342 gross, 240 net wells in the revised plan. Nearly all of the additional 2012 company-operated wells will be in the Bakken. Again, this represents improved cycle times and increased ownership in wells.

Now a significant expansion of our rig fleet. We plan to add 1 or 2 more rigs by year end due in part to the acreage that we've acquired as we continue to fill the role of consolidator in the Bakken.

The other key trend to watch is Continental's shift over the next 18 months to more ECO-Pad drilling in North Dakota. This provides another opportunity for realizing efficiencies with the drilling program.

In a longer-term view, we continue to work on a new 5- and 10-year growth targets for Continental. We plan to roll those out by the time of our 2012 Investor Day, which will be here in Oklahoma City on October 9.

Before turning the call over to John and Jeff, I'd like to recap the last 6 months and exceptional performance delivered by the Continental teams. We faced the same challenges as other companies at various times in this growing play towards new trucks, completion crews, wireline units, frac sand, rail transport, pipe transport, gathering systems and all the rest. It's always changing.

But Continental has succeeded in spite of these challenges. Our teams have simply done an outstanding job, and the results show not only in our production growth and earnings but in the value they have created for the shareholders. It may seem counterintuitive to many of you. We dropped rigs and increased production to the extent that we did. It speaks volume for the strong team effort and the quality of our primary plays.

With that, I'd like to turn the call over to John for comments on cash flow, net earnings and cash management. John?

John D. Hart

Thank you, Harold. Strong cash flow growth was a key first quarter highlight. We reported EBITDAX of $455 million for the first quarter of 2012, a 69% increase over EBITDAX for the first quarter of 2011.

Please refer to our press release for the company's definition and our reconciliation of EBITDAX to net income.

After accounting for an unrealized mark-to-market loss on derivatives, we recorded net income of $69 million or $0.38 per diluted share for the first quarter of 2012. Net income included a $129 million pretax unrealized loss on mark-to-market derivative instruments, a $30 million pretax property impairment charge and a $50 million pretax gain on sale of assets related to our Worland, Wyoming divestiture.

Without the combined effects of these noncash items, we would have diluted net income of $0.76 per share for the first quarter of 2012.

For the reconciliation of this result to GAAP earnings per share, see non-GAAP financial measures adjusted earnings per share at the end of our press release. There's a table in the press release to reconcile this.

Now let's take a moment to address our capital and funding plans for 2012. To begin, the dramatic increase in our oil-focused production base, coupled with strong commodity processes, is enabling us to generate higher levels of cash flows available to fund our capital program.

The current increase in our capital budget is consistent and comparable with our announced increase in production guidance. Incrementally generated cash flows will fund the majority of our increased capital spend to the extent that at the end of 2012, we do not anticipate that our debt metrics will materially differ from historical norms. We expect them to be relatively consistent with where they're at now.

Continental remains focused on generating long-term sustainable growth while preserving our financial strength and flexibility. The quality of our credit ratios and leverage levels are key aspects of our strategy that we intend to preserve.

Moody's and Standard & Poor's recently upgraded our corporate credit to one notch below investment grade. Our goal as a company is to transition Continental to an investment-grade credit. Continental is a unique and distinct company with clear operating advantages, a strong balance sheet and premium assets. Although we are increasing our level of capital spend, it is largely self-funding and focused on long-held organic growth crude oil opportunities. I believe this, along with the remainder of Continental's mission, is clearly understandable, reasonable and transparent.

With that, I'd like to turn it over to Jeff to review our operating results.

Jeffery B. Hume

Thank you, John. There has been a lot of interest in the last several months about differentials on pipe barrels delivered to Clearbrook Minnesota and Guernsey, Wyoming markets and how this market volatility is affecting our net wellhead price realizations.

So let's start today with how the transportation picture is changing, gathering systems, pipelines and rail. All of our Red River Unit oil is gathered at the wellhead and piped to Guernsey, Wyoming, where it is marketed. Roughly half of our Bakken oil is currently being railed to markets where it is priced against waterborne barrels, mainly Brent or Louisiana Light Sweet, which has been $17 to $23 higher than WTI during the first quarter of 2012.

Obviously, the rail transportation cost is much higher than pipe. It's been running about $20 to $22 per barrel all-in from the wellhead to the ultimate end market. But even though the rail transportation cost is higher than pipeline, delivery to the coastal markets has provided superior net pricing lately due to the recent high differentials experienced at Clearbrook and Guernsey, especially during March and April.

With the pipelines currently at full capacity, we anticipate our incremental growth over the next 18 to 24 months will be shipped by rail. And we're having no issues getting railcars and capacity.

We reported last night an average oil differential for the first quarter of 2012 of $12.27 per barrel below WTI, which is considerably above our guidance range of $7 to $9 for a year as a whole. Due to the spikes in oil differentials in early 2012 and continued supply-demand volatility at Clearbrook and Guernsey, we now expect average differentials for the year to be in the range of $9 to $11 per barrel. That's the long-haul transportation picture. Now let's talk about local gathering systems.

There's been significant progress over the past 6 months in expanding and connecting gathering systems to wells to transport oil, natural gas and flow-back water and an expanding gas processing capacity in the Bakken. As I said earlier, 100% of our Red River Units oil is gathered at the wellhead by pipe and shipped to the market.

Today, in the Bakken, about 25% of our oil is gathered by pipeline at the wellsite, which saves us approximately $1.50 per barrel versus trucking cost. And this local pipeline infrastructure continues to expand rapidly. We expect about 40% of our Bakken oil will be collected by gathering systems 6 weeks from today.

The remainder of our Bakken oil is trucked to the nearest pipeline or rail loading terminal, and we have no long-distance trucking operations going at this time.

Approximately 12% of our current Bakken natural gas production is being flared, and that's only because the gathering systems haven't reached our wellsites yet. This is a much lower percentage than what is being reported by the North Dakota Industrial Commission for the basin as a whole. So 88% of our national gas production in the Bakken is being gathered and processed, which you saw reflected in our oil-gas production mix for the quarter.

And finally, water. Freshwater for drilling and completion operations is trucked to the wellsite in the Bakken, and about 30% of our flow-back water is now being shipped by pipe from wells to the nearby disposal facilities.

At this point, I'd like to shift gears and talk about key operating themes as we go into mid-2012: execution, economics and expansion.

First, execution. We've been intently focused on improving execution to improve well economics. We've been rotating underperforming rigs to the yard where they have been upgraded with increased horsepower, walking hydraulics and other improvements. The upgraded rigs are then reintegrated into our drilling programs. We're also improving crew effectiveness through extensive training. The result is reduced cycle times you saw highlighted in our press release last night.

Second, economics. We've been shifting drilling activity to oil and high-liquids areas, where we have the best well economics in the current commodity environment. This means maintaining our 24-rig program in the Bakken, dropping 6 rigs in the Woodford and concentrating our 10 remaining Anadarko Woodford rigs in the high-liquids Southeast Cana and the oil window of the Northwest Cana.

In the Niobrara/DJ Basin, we completed the Buchner 1-2 in Weld County, Colorado during the first quarter of 2012. The Buchner produced 910 barrels of oil equivalent per day, and that's 90% oil, in its initial one-day test period. We're currently assessing results for our first 9 Niobrara wells and preparing to initiate the second phase for development program.

In Anadarko Woodford, we completed our first multiunit well, the Tom's 1-21XH, in the first quarter and have drilled and completed frac operations on the second multiunit well. We should have results from that well for you by early summer. We've demonstrated successfully that the multiunit well approach reduces costs and improves the economics for Anadarko Woodford overall.

Our third key operating theme is expansion of our plays. We are very pleased with the performance of our first 2 second-bench Three Forks producers, the Charlotte 2-22H and the Sunline 11-1. The Charlotte has produced 64,000 barrels of oil equivalent in 5.5 months and the Sunline has produced 48,000 barrels of oil equivalent in 2.8 months, and both wells continue to produce in line with the typical first-bench Three Forks producers.

By year end, we plan to drill 8 additional wells to test not only the second bench of the Three Forks, but also the third bench as well. Our first third-bench well will be drilled in the 1,280-acre Charlotte unit. This well will be located 0.5 mile east of the Charlotte 2-22 second-bench producer and 660 feet east of the Charlotte 1-22 Middle Bakken producer. In addition to this third-bench test, we also plan to drill a first-bench Three Forks well between the 1-22 Middle Bakken well and the 2-22 second Three Forks well. When finished, this will be the first 1,280-acre unit in the play with wells completed in 4 different members of the Bakken petroleum system.

We also have a 320-acre development project underway for the Middle Bakken and first bench of the Three Forks. The Midnight Run project, as it is called, consists of 3 Middle Bakken producers and 3 Three Forks producers within one 1,280-acre unit. The wells in each horizon are spaced 1,320 feet apart, with the Middle Bakken wells offset 660 feet from centerlines of the Three Forks. These wells began producing in the first quarter with average IPs of 1,300 barrels of oil equivalent per day per well. Interference testing is underway, and results will help guide future drilling density for the play.

With that, I think we're ready to start the Q&A portion of the call. Operator?

Question-and-Answer Session

Operator

[Operator Instructions] And our first question is coming from the line of Eli Kantor from Jefferies.

Eli Kantor - Jefferies & Company, Inc., Research Division

In the Niobrara, with the impressive rate from the Bakken area, do you plan to resume drilling later this year? And if so, how many rigs and wells should we expect? And is that development plan factored into the $2.3 billion budget?

Jeffery B. Hume

Yes, Eli, we've had the one well program, and we released that rig. It was actually kind of scheduled to go away, and we completed the wells and have caught up with that rig now. It will be coming back, and I believe we'll be drilling 3 or 4 wells testing those. And we're continuing to identify the sweeter areas within that oil window and continue to high-grade our projects. So for the rest of the year, it'll be a one-rig program that will come and go. And we drill those wells very quickly, and it takes longer to complete them than to drill them, actually. So that's kind of how we plan to do it and kind of step into that program. We're seeing very good results, and we think we've identified some things that can improve that, and we'll be testing that in the next series of wells.

Eli Kantor - Jefferies & Company, Inc., Research Division

Okay. Further, for the Western Colorado, it looks like you permitted your first Weld County well. Can you talk about activity there? How much acreage do you have? Are you guys still leasing? And are you chasing the same Niobrara horizon that you're developing in the DJ Basin?

Jack H. Stark

Eli, this is Jack. And we do have plans to drill a well out there. We are targeting essentially the same equivalent zone in the Niobrara there. And this section is thicker out there. It's a little bit different. It has a little more shale content to it and probably has a little bit more fracture content as well to the economics of the play. But we see a large petroleum system out there, and we've got approximately 20,000 acres in the play right now. And this will be our first test. We'll see how things work.

Eli Kantor - Jefferies & Company, Inc., Research Division

Okay, that's helpful. With regards to the CapEx increase, you mentioned in the press release that the incremental operated wells will be largely drilled and completed in the Williston. Is it safe to assume that incremental non-op activity is also planned for the Bakken?

Jeffery B. Hume

That is correct. We're seeing the additional rigs coming into the basin are affecting us, and we're also -- with acquisitions we've made, we enriched our ownership in a lot of the non-op wells. We're looking at about a 50% higher average ownership on non-op than we had when we set our budget back in November.

Eli Kantor - Jefferies & Company, Inc., Research Division

Okay. Last one for me. Just a follow-up on the CapEx. So you've announced a $550 million increase to the budget, which equates to 51 net incremental completions, which implies roughly $10.8 million per completion. I'm just trying to reconcile that $10.8 million per well completion with roughly $7.2 million to $8 million well cost you're seeing in the play.

Jeffery B. Hume

Sure. Eli, you can't do that math exactly because -- it's close, but the number is less than that. What you have is the second half year will have more and more rigs going to pad drilling, and that's going to carry up into next year's cost, and that's completions. But the costs will happen this year for the drilling. And so we won't -- we're not counting those wells. The well count you see is when we complete a well, not when we spud it. So it's when we complete a well. So the well count, we'll actually be spudding and drilling more wells than that count. And that money is being spent -- part of that money is being spent in 2012 that will carry into next year. So we'll be having more ECO-Pads, developing more wells for completion in the first quarter of 2013.

Operator

Our next question is coming from the line of Neal Dingmann from SunTrust.

Joanna Park

This is Joanna for Neal. Can you tell us just what your appetite with these larger non-operated or operated acreage package is? And then secondly, just maybe give us more color on your view of differentials, maybe how it goes, how it's going to track quarterly.

Jeffery B. Hume

Well, we're obviously participating in all the acreage sales in our key plays, mainly the Bakken. And so we feel like we'll compete with any-size sale in that area. We're also looking at opportunities in the oil area of the Woodford and other areas in the United States where we have strong oil productions. So the 2 -- right now, we're very concentrate -- very focused on consolidating acreage in the Bakken. And there's always, at any one time, multiple packages, anywhere from a few thousand acreage to very high numbers of acreage available, and we participate in that process to try to -- just to buy that.

Joanna Park

[Indiscernible] acreage position?

Jeffery B. Hume

I missed your question. Could you repeat, please?

Joanna Park

All right. For my second question, can you just tell us about how you're expecting the differentials to track quarterly?

Jeffery B. Hume

Well, right now, what we're seeing is -- for June, we're pricing June as we speak and haven't priced it. But we're seeing the Clearbrook price back in around the $2 range and coming in. Out into the future, if you look at the future strip, Brent and WTI are closing on each other. We're seeing the differential currently around $14, and by the end of the year, at the current strip, and it changes every day, is down in the $9 range. And so that's where our strip is between -- or WTI and Brent. And the differential at hot barrels is coming down. So I think we'll see a fairly consistent $9 to $10 range. It could improve. There's room for improvement there. And we'll just have to see where the market is. But as we said in the call, earlier part of the call, there is tremendous amount of volatility in the market. We've seen the differential between WTI and Brent spike as high as $23 during the first quarter. That upsets the pricing at the markets in the U.S., and I think that will become more and more stable as we see the Seaway pipe come on, which is going to start in about 2 weeks. And that will start closing this differential and smoothing out the takeaway capacity from Cushing. I think we'll see the markets continue to improve over the next 24 months and that differential getting very stable and get back into the $7 to $9 range.

Operator

Our next question is coming from the line of Noel Parks from Ladenburg Thalmann.

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

Just a couple of things. I had some trouble getting on at the beginning, so I'm sorry if you covered this already. The impairment you had in the quarter, what was the source of that? Was that just gas pricing?

Jeffery B. Hume

It's just normal leasehold impairment. We amortize the leasehold over the life, and we review that quarterly. So it's our normal historical leasehold amortization. No anomalies or unusual events.

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

Okay, great. And as a I was hearing you giving more detail on the ECO-Pads and how you plan to roll those out, is there -- give us a sense of how much of your acreage in the Bakken is, just because the blocks are too isolated and so forth, is not really suitable for ECO-Pad drilling.

Jeffery B. Hume

I think we're going to see most of our acreage is going to be suitable for ECO-Pad. Where we have operations, we've got this very large blocks put together. I think as we continue our work in driving cost down, I think we'll be able to expand our operation and work with other operators near us to bring that savings to everyone involved. Right now, if I had to make a guess to it, I'd say 90% of our acreage would be susceptible to ECO-Pad development. And even where we just have a single 1,280 spacing unit, we can do multiple wells from a common pad. So we can probably do 3 wells in 1 horizon for a pad. So I think just about everywhere we're going to have operations, we'll be able to do that.

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

And just a follow-up. So I mean, I guess the land work on that other 10%, is that enough of a burden that you're inclined to, I don't know, either package some of that up and dispose of it or just back burner for the really long term?

Jeffery B. Hume

Well, no, we'll just go ahead and develop it. I don't think that will be a problem at all, Noel. As I said, as we learn more and more about these lower benches of the Three Forks, even on that 10%, we'll probably be able to do pad drilling on multiple horizons. So I may just have a single 1,280 by itself that I'd be developing, but I'll be able to drill multiple wells from one pad in that 1,280. So I think we'll be able to get that cost savings on probably all of our acreage force finally finished here.

Operator

Our next question is coming from the line of Jason Selch from Helios Advisors.

Jason Selch

Harold, I understand that you don't want to discuss the Wheatland on the conference call because there's information in the proxy. But there's all this controversy with the Chesapeake plan, given how it's being financed. And I was wondering whether you're going to update the information in your proxy to provide disclosure on how the Wheatland Oil plan was financed?

Harold G. Hamm

Well, first of all, this is subject to approval by shareholders and have preliminary proxy on file. I think it's complete now. I don't see it being updated. I can't -- I don't know about Chesapeake, what the arrangements were. I don't study them. I don't have a comment on that. I wouldn't comment on it. So anyway...

Jason Selch

Okay. I just was wondering whether Wheatland Oil was borrowing money from the same companies that were financing Continental.

Harold G. Hamm

Not at all.

Operator

Our next question is coming from the line of Stephen Shepherd from Simmons.

Stephen P. Shepherd - Simmons & Company International, Research Division

Real quick. I'm sorry if you've already gone over this. The $550 million CapEx increase, what's the breakdown of where that increase will be allocated across your various areas?

Jeffery B. Hume

Well, that's the drilling CapEx, and it's all entirely going to be in the Bakken.

Stephen P. Shepherd - Simmons & Company International, Research Division

Entirely in the Bakken. Okay, great. So it looks like on the Buchner well in the Niobrara, you all had a better IP on that well than you did on the Staudinger well. Did you do anything differently on the completion, lateral length, frac stages? How did the well cost of that well compare as well?

Jeffery B. Hume

Well, the well costs are very consistent up there, and I think we just fell into an area where we had better permeability due to fracture swarms. We believe we can identify those areas now and better place our well bores, and that's what we'll be doing in the next phase of drilling. Then we've identified quite a bit with 3 seismic that we have, and we'll be working in that direction. So we feel that we can make a very strong step change in the performance of our wells and the consistency of that performance, and that will be our next goal in that play.

Stephen P. Shepherd - Simmons & Company International, Research Division

Okay, great. And last question for me. Can you provide just any kind of color or your updated thoughts on the second bench at the Three Forks and what you're seeing there, what you're thinking?

Jeffery B. Hume

Well, on the second bench, we've noted that in our previous talk, but we have very strong production in both wells have drilled thus far. It looks like we're going to be having around -- those 2 wells are going to probably average around 650,000 EURs from early data, from early curves. So it looks very strong right now. The additional work that we described that we'll be doing the rest of this year and into 2013 will approve or disapprove that there's interference between those horizons. Right now, we don't believe there is, but we're going to do the works, spend the money to do that. I believe we just have a larger petroleum storage system than we previously thought, and the reserves will increase as we get that data in hand, and that will be later this year.

Operator

Our next question is coming from the line of Marshall Carver from Capital One Southcoast.

Marshall H. Carver - Capital One Southcoast, Inc., Research Division

Just a couple of questions. First, on the production guide up, how much of that is additional wells being drilled and wells you'll put online, I guess, versus well performance? Are you giving any -- are you using any higher EURs there per well, or was it purely more wells going on production this year?

Jeffery B. Hume

Well, there's predominantly more wells coming on production. We are seeing better performance as we're doing more stages. We're spending more money on the wells than we did a year ago at this time. And last fall, we shifted from a 24-stage completion to a 30-stage completion. We're sprinkling in a few 40-stage completions at this time. We are seeing very strong production from the 30-stage wells. I believe we'll have an upgrade in our reserves. I don't have a quantifiable number to give you at this time, but the budget was built on the 603,000 model that we had at that time with our trailing history. We removed any waiting, risking that we had on it. We talked about that in the last conference call. And we're fitting that fairly well right now with our growth. So there's still upside out there, and we're still working on that. And I think you'll see that and all the resource plays exhibit that characteristic. The more wells we drill, the more that we complete, the better the results. And as we start doing more density drilling, we'll get more effective fracture swarms around the well bores and build better drainage patterns for the well bores. So that's been the history. In other resource plays, we feel that we'll carry on in the Bakken, and that's a future upside that we hope to bring to this play. But we're not there yet.

Marshall H. Carver - Capital One Southcoast, Inc., Research Division

Would you expect to update that 603,000 barrels a well number on the 2Q call?

Jeffery B. Hume

We will.

Marshall H. Carver - Capital One Southcoast, Inc., Research Division

Okay, that's helpful. And then one more question on the guidance. So you talked about taking out any -- so there's no risking in the current guidance for the year. You had various risks before, but now it's...

Jeffery B. Hume

Well, we have some risk in there, and that's mainly weather-related risk that we have in there. For the next 3 or 4 months, we have the rainy season up there, so have some risk on that. So we just have some minor risking in there, so nothing major. Most of the areas we're drilling in are -- bulk of the rigs, we're drilling in areas that have been de-risk now. We do have some risks on a few other wells that are out in the expanding areas, but that's minority of the well -- rigs at this time.

Marshall H. Carver - Capital One Southcoast, Inc., Research Division

Okay. And the new production assumes 603,000 barrels of EURs?

Jeffery B. Hume

That's where we built our model on. That is correct.

Operator

Our next question is coming from the line of Andrew Coleman from Raymond James.

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

Yes, I have a question. I got on the call here halfway through it, but you guys were talking about increasing your working interest through -- I guess by buying, I guess, some non-op partners similar to Wheatland. How much additional acreage or, I guess, working interest do you think you can bolt on? Do you have a line of sight on any of that? And would you consider asset swaps in that to try to harmonize your acreage?

Jeffery B. Hume

Well, we've always tried to do asset swaps to -- we'd like to operate acreage that we own, so we're always working that. Other operators have the same similar mindset. So in areas of commonality, it's fairly reasonable to do that. But what we've been able to do is we've made various acquisitions we've talked about and, through some leasing, picked up additional acreage that's underneath non-op wells. We've built the budget on approximately an 8% ownership in the non-ops, and you can do the math on what we've put out, and we've got -- we're seeing about 12% now. And part of that may be just the wells that the other -- the non-ops are selecting to drill at this time, and part of it’s increase in our ownership from acquisitions we've made. But that's our experience. That's what we're seeing today.

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

Okay. And do you think it's, I guess, the climate here is easier or harder to kind of do some of those things? Given where oil prices are, is there more appetite now that, perhaps, gas is -- you guys seem to be a little bit more positive, I guess, here for the immediate short term, so there might be a window here.

Jeffery B. Hume

Andrew, surprisingly, there's always Bakken acreage available. You think this is the last package, and there's always 6 or 8 packages out there of various sizes to compete for, and we compete for all of those and we evaluate. We obviously can't buy every one of those, but we're always competing for acreage in the Bakken. We've got our cost structure down. We're probably the lowest-cost operator and best performance up there right now just due to our size and the team we've put together. And so we're very bullish on consolidating acreage in the Bakken. And we'll, I think, be able to continue doing that into the future. It's what it appears right now.

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

Okay. And then looking at the lower spend for the current year, and it looks like the CapEx, at least for the first quarter, is pretty front end-loaded. Do you think as you go through the year, and I think that was Marshall who asked on the previous set of questions, if you have revisions to some of your EURs that you could find that CapEx and activity could pick up there in the second half of the year? Or is that just a reflection of conservatism on your part, given the oil prices right now?

Jeffery B. Hume

Well, Andrew, that's a great question. Earlier in the year, when we're talking about our CapEx and our plan, we were talking about adding rigs to the Bakken play as we went through the year. We've -- the teams have just done such a great job capturing efficiencies. We've been able -- as Harold said earlier, we're getting more completions per rig, and so we're getting a better capital spend due to that. So we're doing more fracs per drilling rig in a year. So we've kind of accomplished part of that goal already. Now that being said, we have the personnel put together and the capacity to expand that rig count going into 2013 and '14. And with our inventory and if the commodity prices hold in, I fully expect this to continue to expand our activity going forward. Over the next several years, not just the remainder of 2012, but over the next several years, I expect us to continue to grow our count if the economic environment holds as it is right now.

Operator

We have another question. It's coming from the line of Hsulin Peng from Robert W. Baird.

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

The first question is regarding the 30% reduction in drilling cycle time, can you talk about on a per-well basis what kind of cost funding -- cost savings did you see from that?

Jeffery B. Hume

Well, if you look at an average of about $20,000 just on day rate of your rigs and you can shave a week off, you're talking about $300,000 net per well.

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

Okay, got it. And then the second question is regarding -- I was wondering if you can comment on the per unit cost guidance with the remainder of 2012 because it looks like the OE was lower than -- it was lower than previous items. So I was wondering if that trend will continue or if that should ramp up?

Jeffery B. Hume

I think you can see variability between quarter to quarter on the per unit guidance. Obviously, our production is increasing significantly. For now, I would continue to utilize our guidance that we have out, and we'll continue to monitor that. We may have some positive revisions on that as we move forward, but for now, I would continue to look towards our guidance.

Operator

And that was the last question. I would like now to turn the call over to Mr. Hamm, please.

Harold G. Hamm

I just want to thank everybody for joining us. I know we have a lot -- you have a lot of calls, a lot of business right now, and we appreciate your attention to Continental Resources. So thank you very much.

Operator

Thank you very much for your participation in today's conference. This concludes the presentation. You may now disconnect. Have a good day.

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Source: Continental Resources Management Discusses Q1 2012 Results - Earnings Call Transcript
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