Good day, ladies and gentlemen, and welcome to the Continental Resources First Quarter 2011 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 the President and COO, Jeff Hume, and then our question-and-answer period. Additional members of management are available to answer your questions.
Now we'll turn the call over to Mr. Hamm. Please proceed.
Good morning, everyone. Thank you for joining us on our conference call today. In North Dakota, hockey is by far the most popular sport up there. To win the cup, a team must be fast to seize opportunity and consistent in its execution to score goals. We think that Continental's first quarter performance shows that same consistency and will be a clear reflection of the rest of the year. In fact, I believe our next several earnings call will sound very similar.
We have almost a year and half under our belt in this 5-year plan to triple production and improve reserves from year-end 2009 to year-end 2014. And report this morning, we’re right on track. In fact, first quarter production was stronger than we expected it to be, thanks to improving well results in the Bakken and Oklahoma Woodford, and a great job done by our operating teams during the winter and spring months.
We reported average production of 51,663 Boepd for the first quarter of 2011, a 34% increase over the first quarter of 2010, and an 8% increase over the fourth quarter of last year. You'll recall that in late February, we reported our fourth quarter production was 27% higher on a year-over-year basis and 7% higher than the immediate previous quarter. So the pace of production growth is accelerating as we expected. Fourth quarter was strong, first quarter was stronger and we're continuing to grow production in the current quarter.
74% of our first quarter production was crude oil, but the liquids-rich natural gas production in the Anadarko Woodford has grown to the point that it’s starting to impact our overall results. We're feeling pretty positive about this higher percentage of gas, given the recent 20% increase in natural gas prices subsequent to the tragic earthquake and tsunami in Japan.
Bakken production was 25,523 Boepd in the quarter, an increase of 67% over the first quarter of 2010, and 13% on a consecutive quarter basis. Anadarko production -- Anadarko Woodford production growth was 190% on a year-over-year basis; but, of course, that's off a small base. We had only 3 operating drill rigs in play in May last year, and today, we're up to 10.
We keep talking about the Bakken and the Anadarko Woodford because that's where the CapEx and growth focus are in the company. However, it's useful to note that we're maintaining a very important basic production in the Red River Units, up slightly over the first quarter last year, and the Arkoma Woodford, where production was 4,065 Boepd in the first quarter of 2011. That's an increase of 17% over the first quarter last year. And we have only one rig running over there in that play.
In our earnings report last night, you saw a larger-than-normal group of Bakken wells in our notables list, and initial production rate tells the story. We were operator in completing 25 gross wells, 15.7 net in the first quarter 2011. And of those, we had 12 wells in North Dakota that tested over 1,000 barrels of oil equivalent per day. The strongest, the Bud 1-19H tested at almost 2,000 barrels. To repeat, we continued to restrict initial production on many of our wells to minimize flaring and to deliver as much of the rich gas in these wells as possible to market. Some of these wells initially produce for several days, reporting tubing pressures of more than 3,000 psi, though they could've tested double or more than announced rates as we mentioned in the release. The bottom line here is production growth. We grew production 67% year-over-year in the Bakken.
Next, let me point you to the fact that 6 of our 8 strongest wells in North Dakota were in what we call the Williston Prospect in western McKenzie and Williams County west of Nesson Anticline. This is exploratory country where we and other operators are still figuring out what we have over there. Just this week, we completed the Akron 1-27H, 57% working interest in this area. It tested at 1,407 Boepd flowing at 3,600 psi on a 16/64" choke. This is a very strong well.
Jeff has noted on previous conference calls that we expected this whole area from Nesson west to the Elm Coulee in Montana to be de-risked and built in over the next several years. And that's exactly what's happening, and it's happening very quickly.
Finally, you probably noted that we're talking more and more about the Bakken and less about North Dakota versus Montana. The 3 Montana wells we announced indicate why. There, initial test rates range from 836 Boepd to 1,163 Boepd. Sort of looks like North Dakota wells, don't they?
We highlighted the fact that we're experimenting with a number of variables in our completions. For the first time in years, we're using some sliding-sleeve systems along with perf-and-plug. We're varying the number of stages, 24 standard, but designs range from 18 to 30 stages, depending on where it's at. And we just pumped our first highway frac, which pulses proppant into the frac zone instead of injecting it under continuous but increasing concentrations.
Twice as many variables, because we're still in the first or second round of the Bakken game. Technology continues to get better. Last year's most efficient completion approach is not the most efficient economic answer today. As we find better ways to complete these wells, we adapt and change, especially when there are tens of thousands of wells to be drilled in the Bakken play over the next 2 to 3 decades.
Finally, for Continental it comes down to cash flow. We reported $269 million in EBITDAX for the first quarter of 2011. This is 53% higher than cash flow generated in the first quarter of 2010, and an increase of 22% over the fourth quarter of 2010.
Here's one example of how well our teams are dealing with the challenging conditions that we have up there. In recent months, we've heard a lot of operators and investors worrying about the transportation capacity out of the Bakken. Not enough pipeline space, railroad shipping not coming on fast enough, et cetera. As a long-time operator in the basin up there, one of the first in fact, Continental has a number of competitive advantages that others lack. When the pipelines companies increase their capacity we're first in line for our share of it. We market our own oil, and we ship on all the Bakken pipeline systems. Plus, we're shipping by rail out of 3 separate facilities. So we can adapt when bottlenecks cause problems. Going east to Clearbrook or South Guernsey, we can fit capacity. The result, despite all the negative noise in the first quarter, we reported a differential of $9.21 per barrel for the first quarter of 2011, clearly above the midpoint of our full year guidance of $8 to $10.
Finally, we reported a net loss for the first quarter of 2011 of $0.80 per share. But this was primarily reflected in a non-cash unrealized loss on marked-to-market derivative instruments. That, with a small impairment loss and a small gain on sales of assets, reduced earnings by $1.33 per share. John Hart, our CFO, is here to provide additional color if needed. Though we've discussed our derivatives strategies every quarter for the past year, and I'm sure everyone understands this is an accounting impact, not a cash or EBITDAX impact related to the current high level of crude oil prices.
Our hedging activity over the past year, as we said, is a direct reflection of the long-term strategy to underpin our drilling activity as we triple production and prove reserves. Production growth is accelerating. We've layered in price hedges, primarily on oil, to provide a solid cash flow stream that will enable us to grow with what we believe will be very favorable returns despite oil pricing volatility.
For additional details on our derivative swaps and collars, please refer to the 10-K and the 10-Q that will be filed in the next few days, or feel free to ask John for more color on these trades.
Now in closing, let me step back and provide a 35,000-foot view of Continental's operations and our opportunities, especially in the Bakken and the Anadarko Woodford. Last week, at the request of Secretary of the Interior Salazar and Senator John Hoeven of North Dakota, members of our team met with the U.S. Geological Survey to update them on the developments in the Bakken field and to discuss a possible reevaluation of the scope of the play. As many of you may recall, the USGS published a report in April 2008 that estimated that the Bakken petroleum system contained up to about 4.3 billion barrels of technically recoverable oil, which we found reasonable at that time. Their estimate was based on data available as of June 2007 and reported in April 2008. Since June 2007, we've seen a complete technological revolution in the play up there, with more than 2,000 additional producing wells completed. Given the rapid growth of the Bakken field, the vast amount of new data and the technology in drilling and completion up there, we feel an updated estimate of the technically recoverable reserve for the Bakken field is warranted. Based on our engineers' analysis, we believe there are at least 24 billion barrels of oil equivalent technically recoverable from the Bakken field. And we hope the USGS chooses to update their report again.
The tremendous advances in drilling and completion technology now allows us to routinely produce oil with economic rates from tight reservoir rocks that make up this resource play. Speaking to you as a geologist now, this is not a shale play. We're not drilling the shale layers themselves. We're actually drilling and producing from conventional reservoir rocks, both in the middle Bakken and at Three Forks, that have very low porosity and permeability, and that have been charged from those adjacent Bakken shale layers. What is unconventional is the technology required to extract the oil.
Through advanced horizontal drilling and fracture stimulation technology, we are enhancing the natural fractures in these tight conventional reservoir rocks by packing them with sand under hydraulic pressure to obtain commercial flow rates of oil and natural gas. This technology, once considered to be unconventional, has certainly become conventional, not only in the Bakken Play, but in resource plays throughout the United States.
Thus far, the industry has drilled and completed about 4,000 horizontal wells in the Bakken, and there are 170-plus rigs drilling more than 2,000 new wells in this field this year. The Bakken Play has rapidly become a conventional play with increasingly predictable well results. The entire scope of the Bakken, all 15,000 square miles of it, is now considered by the industry to be viable for development.
The Anadarko Woodford isn't as far along as the Bakken of course, but frankly, its repeatability is starting to feel very similar. Drilling times are coming down, well results are strong and the economics are solid, even at today's natural gas prices, because of the richness of the gas and liquids in it. Especially with the recent increase in natural gas prices, the economics are excellent.
Together, Continental's acreage in the Bakken and the Oklahoma Woodford represent a multi-decade growth platform for our company. We have the platform in hand for tripling our production in the proved reserves from year-end 2009 to year-end 2014 and for decades of rapid growth after that. Our job today at the company is simply to execute the plan and deliver the results. We're on track, we're focused and we're excited for the rest of the year to keep performing at a high level.
As I said earlier, I'll be pleased in the next few earnings calls to start on the same note. No surprises, it just keeps getting better and better. I want to thank all the team members here at Continental who continue to drive the needle doubles [ph], both in and on the ice. And thanks to all of you who have invested in us, for your continued support.
So with that, I'll turn over to our President, Jeff Hume.
Thanks, Harold. Instead of my usual review of past quarter highlights, I'd like to note this morning some of the changes and key themes that we expect to carry us through the remainder of the year.
We're on track with CapEx. The first quarter's CapEx investment of $413 million was in line with our budget of $1.75 billion for the year. Along with our growing EBITDAX, we have plenty of liquidity to carry us into 2012. We're running a total of 37 operated rigs, with 24 in the Bakken and 10 in the Oklahoma Woodford. In the Anadarko Woodford, we've begun to phase in heavier rigs, several at 2,500-horsepower, to enable us to reduce drilling times and in preparation for drilling the longer, 9,000-foot laterals under the new cross-unit spacing law passed by the Oklahoma legislature.
We're on track with our production growth, as we said. We have substantial backlog, currently with 63 wells drilling or awaiting completion in the Bakken. In just the next 2 weeks, we expect to bring 13 new North Dakota Bakken wells online. In the next 30 days, we expect to bring 8 new Anadarko wells online. Another important factor in the Bakken is the start-up of new gathering facilities that I mentioned on our fourth quarter call in February. Hiland Partners plans to commence operations of its 30 million cubic feet per day plant on May 15.
On the crude oil side, we are filling the pipes right now on a gathering system that will enable us to pipe oil directly out of the Norse prospect which will reduce transportation costs and free trucks to serve newly drilled wells. Especially because of the timing of ECO-Pad projects, we expect that our production growth trend through the remainder of 2011 will be lumpy. We currently have 3 ECO-Pads that have been fracked and will come online within the next few weeks.
The rate of production growth will vary from month to month, but we are on target and expect to achieve 2011 production growth in the range of 35% to 37% over 2010. We do not plan to add more than a couple of additional drilling rigs by year end to get this accomplished. We're about where we need to be, including the distribution of rigs between the Bakken and the Oklahoma Woodford. The key now is to regain some of the efficiencies lost during the period when we ramped from 12 operator rigs in January of 2010 to 37 rigs today. We continue to see upward pressure on cost and our outside operators' wells are running at a somewhat higher rate than we had planned.
We are very focused on drilling and completion efficiencies, continuing to improve our well results and completing the move to Oklahoma City in the next year or so with as little distraction as possible. We're all very excited about the move, and recruiting interest has significantly accelerated. We started getting a much higher inflow of resumes submitted to us as soon as we made our announcement on March 21. We're going to need a lot more professional firepower to accomplish our tripling goal by year-end 2014. We have premier positions in 2 of the hottest plays in the United States, the Bakken and Anadarko Woodford, and that's where professional talent wants to be, on the cutting-edge, in the most exciting, developing crude oil and liquids-rich gas plays.
With that, let's start the Q&A.
[Operator Instructions] Your first question comes from the line of Michael Bodino from Global Hunter Security.
Michael Bodino - Global Hunter Securities, LLC
Just a couple quick questions on some of the operation. I know in the Niobrara well, you completed the horizontal and it was a cleaning up. Are your plans there to get a flow test out of that well before you proceed on additional wells in that basin. And then I do have a follow-up.
Michael, we will have that information before we have the rig back in to continue drilling. That rig will be here in mid-to-late June, and we will run it through the end of the year, is our current plan. We are currently recovering load. We're at the early stages of recovering load, we're expecting the well to be cutting oil in the next week to 10 days, based on what offset operations -- operators have done at this level. So we should have a pretty good indication at this location. And we do plan to bring that other rig in, regardless of what we see here, to continue drilling.
Michael Bodino - Global Hunter Securities, LLC
Okay. And my follow-up, and a little bit bigger macro picture, could you walk us through the next several quarters in terms of your anticipated ramp-up and rig count by basin?
Ramp-up in rigs?
Michael Bodino - Global Hunter Securities, LLC
Basically, we'll be holding the same -- pretty much the same rig count through the year. We'll be bringing in a Niobrara rig, as I just said, in June. We have a rig currently drilling in the Texas Panhandle on some Cleveland wells that will be finished up about that time. So it will remain around 37. In the late third quarter, early fourth quarter, we have plans right now to bring in a couple of more rigs in the Bakken and potentially be ramping up in the Anadarko Woodford. And so, for now, it just looks like it's going to be pretty much a 37-rig program for the next 2 quarters.
[Operator Instructions] Your next question comes from the line of Noel Parks from Ladenburg Thalmann.
Noel Parks - Ladenburg Thalmann & Co. Inc.
Just a couple things. I'm sorry if I missed this in the early commentary, I think you said that, in the press release, that 2 of the 3 Montana wells you did around Elm Coulee were 320-acre infills. Where was the third well? I think it's the Amestoy, it's called.
The Amestoy well is -- actually, it's on the northwest side of the edge of the field. There were 3 that we announced here, the Amestoy, the Big Sky and the Clayton. Big Sky and Amestoy, both actually are on the north side of the Elm Coulee field. And that's what's exciting about those wells, is that they are on the fringe of the known producing field and are showing us that there is room to expand the field to the north on 166,000 net acres that we have undeveloped to the north. The Clayton, on the other hand, is on the south side of the field where you're heading towards the Bakken pinch out, but it was an infill on that edge. And it came on for 1,100 barrels of oil a day, and much better than the surrounding wells. So it shows there's quite a bit of oil to be recovered down on that end with this newer technology than what had previously been recovered.
Noel Parks - Ladenburg Thalmann & Co. Inc.
Okay. Great. And are we at the point now -- if you look at your remaining undeveloped locations and infill opportunities at Elm Coulee, that we can start to think about a higher EUR going forward, because of the new completions as opposed to sort of the historic number you used in Elm Coulee?
No, I think we're moving towards that. We're not announcing that at this time, but as Harold mentioned in his dialogue, we are seeing improved results. We're seeing production ahead of where we had it modeled. We will be doing our midyear reserve forecast over the next couple of months. And at the end of that, as we've always done, we'll review trailing results. We like to have enough data on a curve to have a good solid performance forecast based on fact before we announce. But everything's trending for a higher model. And I believe at the next quarterly call, we'll be announcing a higher model based on the results we're seeing at this time. But today, we're not changing our model. We're sticking with our 518 average model across the play. The good news is, as Harold mentioned, the performance west of the Anticline, out in unproven areas is, those wells are coming on very strong. They're holding in there very nicely. Our oldest well in there is only a few months old, so by the end of the quarter, we'll kind of see how those wells look, and it will really help underpin that model. As you are well aware, we give a single model, average model for the entire play, and our acreage covers just about the entire Bakken play. So it's a good model for the entire resource, and that's what we'll be looking at. But I do believe it will be increasing from what we're seeing today. I just cannot quantify it at this time.
Your next question comes from the line of John Freeman from Raymond James.
John Freeman - Raymond James & Associates, Inc.
First question, congratulations on getting the legislature to pass, the cross-unit spacing, I know that's something you all have been working on pretty hard for a couple of years. I'm curious on how sort of your completion technique and design is going to change once you go to the 1280s there, in terms of number of frac stages you think you'll plan, what the well costs are going to look like with the 1280 versus what you all have been doing?
Well, the 1280, we're going to be -- our costs are going to be running about, as compared to 2 wells, it's going to be running about $3 million less than at 2 wells we're planning to have. Our reserves will double. We're currently, at today's market price for gas, we're seeing around a 34% internal rate of return on our current drilling that we're doing. That should kick it up to around a 48% to 50% internal rate of return on that type of drilling. So we're excited to get started with that work. We have several applications in, and they're just pending. The Corporation Commission of Oklahoma is setting rules at this time, and once those rules are set, application permits will be awarded. And we feel like we could be possibly drilling our first cross-unit well by mid- to late-third quarter, and rolling with that. Another thing I'll point out, John, as we mentioned last quarter, we've got 2 large, 3D shoot spreads going at this time, one in the Northwest Cana over 300 square miles, another in the Southeast Cana. So we have close to 500 square miles of 3D that we're -- have joint shoots going with other companies. 40% is finished in that Northwest Cana, so we're getting good information on where to place these cross-unit wells. The timing couldn't be more perfect for this law to come into fruition and give us the ability to improve our results. So I think by the fourth quarter, we'll be seeing, hopefully, some early results on that work.
John Freeman - Raymond James & Associates, Inc.
Great. Just one more question for me. On Red River, I had anticipated that, that was going to start to just continually decline after reaching its peak level, over 15,000 barrels a day in the second quarter of last year. And it seems like after it declined for a couple of quarters, we've now had a couple of quarters of sort of steady growth. I'm just curious what your outlook is for the remainder of the year for Red River.
We feel like we're going to be able to hold that flat. What we're doing, John, in the older areas, the Medicine Pole hills and the Buffalo, we have increased our air injection capacity. We've moved in some machines that we had in Cedar Hills, as we converted it to water flood with a tighter well density. We redeployed that machinery, and we're going to be seeing results from increased injection in those areas. We're also seeing very good results on the water flood patterns in North Dakota. We did a review, those early -- the earliest water flood patterns, which you would expect to start the early decline and give you an indication, are still on a nice, level field. We're seeing the water cut come up, as it should, but we're not seeing -- we're seeing an overall production increase, so very good response. We feel like we'll be able to carry this production level through this year and into 2012 when we start seeing a decline on Cedar Hill. So very, very good news. It's much better than we thought.
[Operator Instructions] And gentlemen, I take that we have no more questions at this time.
Thank you very much. Appreciate everybody joining the call today. And as we go forward, if you have any questions, please give each one of us a call. Thank you.
Thank you for your participation. That concludes today's presentation. You may now disconnect. Have a great day.
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