Continental Resources, Inc.
Q3 2013 Earnings Call Transcript

Published: 7 Nov 2013

[Operator:]

Good day, ladies and gentlemen, and welcome to the Continental Resources Third Quarter Earnings Conference Call. And I would now like to hand the conference over to Mr. John Kilgallon. Please proceed, sir.

[John Kilgallon:]

Good morning, and thank you. Welcome to the Continental Resources Third Quarter 2013 Earnings Conference Call. Joining me today with prepared remarks is Harold Hamm, Founder, Chairman and Chief Operating Officer; Rick Bott, President, Chief Operating Officer; John Hart, Senior Vice President and Chief Financial Officer. Also on the call today during the Q&A session will be other members of the management team, which includes Jeff Hume, Vice Chairman of Strategic Growth Initiatives; Jack Stark, Senior Vice President of Exploration, Rick Muncrief, Senior Vice President of Operations; Steve Owen, Senior Vice President of Land and Warren Henry, Vice President of Investor Relations. In conjunction with earnings in the call this morning, we have posted a third quarter earnings supplement presentation that's available on our website in the upper left-hand corner. Please look at that because we might make reference to that during the call. The slides are also available in the web portal if you're listening via the webcast. Today's call will include forward-looking statements and address projections, assumptions and guidance. Actual results may differ from those contained in these forward-looking statements. Please refer to the company's filings with the Securities and Exchange Commission for additional information concerning these statements and risks. Also in today's call, we will refer to EBITDAX adjusted net income per diluted share and cash margin. For a reconciliation of EBITDAX to GAAP net income and operating cash flows and a reconciliation of adjusted net income per diluted share to the GAAP net income per diluted share, and a description of our calculation of cash margin, please refer to the third quarter press release or the summary presentation that's found in our website. With that, I'll turn the call over to Harold.

[Harold G. Hamm:]

Good morning, everyone. Thank you for joining us for today's earnings call. The Continental team performed an exceptional level in the third quarter of 2013. I'd like to take this opportunity to thank our entire team here at Continental. We generated strong production and operating performance resulting in a record cash flow for the quarter. The third quarter 2013 marks the 13th consecutive quarter in which Continental has increased production sequentially. As expected, production is accelerating in the fourth quarter. Our current production rate is approximately 150,000 Boe per day, putting us at the high end of our guidance for the year. We're getting better performance for CapEx invested and because of that, we're on track to achieve our production earnings growth goals for 2013. The other highlight of last night's earnings release, of course, was the outstanding success of the Hawkinson density drilling pilot highlighted on Slide 4. Maximum one day production from the unit was a total of 14,850 Boe per day. Included in this was 13,400 Boe per day from 11 new density wells producing from the Middle Bakken and the first, second and third benches as a Three Forks zones. This number is their combined IPs. This new Middle Bakken and TF1 well IP-ed at 14,080 Boe per day and the 7 lower bench wells IP-ed at 1,070 Boe per day. Finally, in the 3 legacy wells, we had max one day production of 1,450 Boe per day. These wells, 2 in the Middle Bakken and 1 in the first benches of Three Forks have produced 1.3 million Boe since the earliest we've brought on in 2010. Let me focus on what this milestone means. Continental is defining what full development mode will look like in a Bakken. The roadmap at multiple wells for spacing unit in multiple zones included in the Middle Bakken, and in most cases, 2 to 3 benches of the Three Forks will add to fourth bench in some areas. Our success with the Hawkinson unit points to 2 key points about the play overall. The deeper benches will be important oil producers and we'll recover more oil per spacing unit than anyone in basin just few years ago. Based on everything we've learned this year, we're accelerating portfolio development. One of the first areas for this will be Continental Antelope area located between the Parshall and Sanish areas and the Nesson Anticline, which we've highlighted on Slide 5. Antelope is one of the most productive areas to be significantly drilled in the Bakken and the Continental team had divides an Ears Back plan to develop it. For you who didn't grow up on a farm Mack idea, the horse running Ears Back is just going all out, so you need to hang on pretty tight. We intend to increase to 4 operating rigs in Antelope next year. All the drilling will be on large multiple well pads with up to 30 wells on a pad. We will target the Middle Bakken in the first, second and third benches of the Three Forks. This will be the first area in the Bakken with Full field development including deeper benches and using these mega-pads. It's key to understand that Continental already has extensive success in Antelope with 40 gross wells already completed. Like our Angus wells, these are extremely good wells. Development of Continental's interest in Antelope area is expected to account for approximately 50,000 barrels of oil per day growth in production in the future. However, we also have a great deal of running room. With the total inventory of almost 350 gross wells to be drilled over the next 4 to 5 years, we plan to spend 51 wells in 2014. These are already in our CapEx budget. Given the size of these projects the resulting production ramp will be significant starting in 2015. From that point onward, Antelope's impact should be large. This is a huge impact project in an underdeveloped area, where we have been planning with our midstream vendors to build out sufficient infrastructure to handle this production prior to our work here. We're almost there, and we'll be by the time we'll begin. Continental's Bakken leadership has been a constant throughout the tenure basin history. And the recently completed Hawkinson density project and the planned Antelope full-field development will also be major milestones that join long list of Continental firsts. Those include one completing the first economic well in North Dakota Bakken that's both horizontally drilled and multistate frac that Robert well [ph] in March 2004. We made the early development of the Middle Bakken zone and followed by improving the productive potential of the upper Three Forks in 2008. In the past year, we pioneered the development of the Lower Three Forks benches. Along with the exploration, we've been a consistent leader in well cost reduction. We're now currently completing Bakken wells North Dakota for $8 million. These accomplishments are just a further realization of our vision at the Bakken. Let me say in summary what I've said many times, there's only one Bakken. It's the most important oil discovery in the past 50 years as shown on Slide 6. It's massive, one of the largest pure oil resource plays in the world and we've de-risked 3,800 square miles for multiple benches. It's onshore American, it's 85% oil, and Bakken is one of the most consistent, high quality crudes anywhere in the world. And it's just getting started. Bakken will soon surpass 1 million Boe per day of production, and I expect it to double again within 10 years. Given it's scope and importance to you U.S. Energy Security, I can't be more proud that Continental is Bakken's #1 leaseholder, #1 driller and #1 producer within it. With that, I'll ask Rick Bott now to talk about Continental's other third quarter achievements and our excitement about this group play in Oklahoma. Another operator this week announced a new stack play, which includes about 2/3 of our Northwest [ph] leasehold. So I'll turn it over to Rick.

[Winston Frederick Bott:]

Thanks, Harold. As you said, I'll give a little more color in terms of Continental team's excellent results this past quarter. First, production increased 5% sequentially in the quarter to approximately 142,000 Boe per day, a 38% increase year-over-year. We achieved this despite the lag in production due to the transition to larger multi-well projects in some of these down spacing pilot. And as you noted, production growth has accelerated in the fourth quarter, currently 150,000 barrels of oil per day. Both operations and marketing are going extremely well, I'll give you a little more explanation. We expect production growth momentum to continue into 2014 and are very much on target or ahead of plan to achieve our 5-year goal. In terms of sales, our oil and gas marketing team continues to do an excellent job accessing high-value markets for our premium Bakken crude oil and liquids rich natural gas. Our third quarter oil differential was $7.80 per barrel, a considerable accomplishment given the volatility of commodity prices and the volatility of the WTI Brent spread. In the same manner, our gas marketing delivered a pricing premium of $1.65 per MCF over Henry Hub, $0.15 above their top range of annual guidance. The marketing team has efficiently managed pipe and rail transportation opportunities to markets on the East, West and Gulf Coast, as well as the Mid-Continent, fulfilling our objective of reaching premium markets for the oil and gas we produce. In terms of capital expenditures, we performed at a very high level while maintaining spending discipline in line with our $3.6 billion non-acquisition CapEx budget for the year. Through the first 3 quarters of 2013, we've invested non-acquisition CapEx of about $2.7 billion. Strong production and improved efficiencies have generated $2.1 billion in EBITDAX through the first 9 months. One of our top priorities is to grow cash flow more rapidly than capital expenditures, and that's exactly what the team is accomplishing. This preserves the strength and flexibility of our balance sheet while we deliver industry-leading production and proved reserve growth. Harold highlighted the Hawkinson density project. We have 3 more density projects in various stages of completion. These include the Rollefstad and Tangsrud, which are testing well space, 1,320 feet apart within zone similar to the Hawkinson. The other density pilot under way is the Wahpeton, which will test 660-foot spacing between wells in the zone. We expect to report the results in these in early 2014. From what we've learned, we're planning 3 more density pilot projects in 2014 in the Hartman, Lawrence and Mack spacing units to test tighter spacing and further validate our Full field development concept, including these deeper benches. As you know, we're not headed down this road alone. We're pleased to see other operators prosecute their own tighter density drilling pilot projects. The news in the Bakken, as Harold said, just keeps getting better. Apart from the density test, we have a growing list of exploration accomplishments since the beginning of the third quarter. We completed 7 more productivity and interference test in the Lower Three Forks exploration program. The 5 lower bench test had initial production in line with legacy wells in the same area, and average for those 5 are 500 barrels of oil equivalent per day in their 1 day test. These wells tend to have flatter, more gradual decline rates, so they're solid economic wells. Adding in the 7 lower bench test in the Hawkinson, the average IPs for all the Lower Three Forks wells in the quarter was 835 barrels of oil equivalent per day. Another story, another good new story's on the Montana side of the Bakken where we continue to demonstrate that great plays just keep getting better. We've gone back into Elm Coulee to drill section line wells and infill wells between pre-existing legacy wells, further expanding the productivity to the field. Along with incremental production from new wells, we're seeing significant uplift in the production by surrounding wells. The new well completions are stimulating production uplift and legacy wells on either side. The results were apparent in our strong Montana production growth, 17% sequentially in the third quarter after 18% sequentially growth in the second quarter. The state production in Montana is at all-time high, and we have doubled production in Montana over the last year. Combining what we're learning on our density pilots in real time with our latest completion results in older areas like Elm Coulee and Montana, we're seeing some exciting results. Future will not be about single well IPs, that will become the conventional thinking of yesterday. The unconventional thinking will be about production uplift using many different techniques for the entire unit. Now let me ship southwards to our Oklahoma SCOOP play, where we continued to delineate the play, East and South, expanding the de-risk footprint as you can see on Slide 8. Notable third quarter wells include 2 condensate farewell wells, the Charles 1-36H, which flow 1,361 barrels of oil equivalent per day in its 1 day test, and the Sympson 1-6H, which flowed 1,257 Boe per day. We also completed our second cross unit well, the Hansell 1-3-34XH, which produce 603 barrels of oil equivalent per day in its 1 day test, 84% of which was crude oil. Currently, 6 of our 12 operated rigs in the SCOOP are drilling cross unit wells with 9,500-foot lateral. We completed a notable SCOOP discovery well in third quarter, the Zelda 1-36H, which we drilled in Stephens County. The Zelda is at the boundary of the condensate oil fairway. It came in at 847 barrels of oil per day, with 38% oil. And the pressure in decline rates looks very promising. This is a great result in a new area of the play. Now let's touch on just a few final accomplishments. We continue to gain efficiencies and reduced completed well cost in both the Bakken and the SCOOP. We have achieved even our revised year end 2013 goal of an average of $8 million for completed well in North Dakota 2 months early. Referring back to Slide 7, our year end 2014 goal is now set at $7.5 million per well. Average completed well cost in SCOOP is $9 million for short laterals and $12.5 million to $13 million for cross-unit wells, but we are early in the process of bringing SCOOP well cost down compared with the Bakken. We expect significant improvement next year and beyond. So in summary, our team performed an exceptional level in the third quarter of 2013 with solid production growth, spending discipline and excellent cash flow generation. We're solidly on track to hit the high end of our production guidance for the year. We're also well placed to deliver an equally strong performance next year and on track to deliver on our 5-year plan. Underpinning these results is our differentiated subsurface view, a combination of our cost effective application of the technology with our operational excellence, as well as our growing marketing scale to help us relentlessly pursue the unlocking of shareholder value in these oily resources plays. With that, I'll turn it over to John.

[John D. Hart:]

Thank you, Rick. Let's take a brief moment to look at several of our financial measures. Adjusted net income for the third quarter was $1.61 per diluted share, beating the Street consensus by about 10%. Our GAAP net income as reported was $0.91 per share compared with $0.24 per share last year. This represents a 279% increase. EBITDAX increased to a record of $798 million, which was up 13% from the second quarter, 62% higher than the year ago third quarter and considerably higher than Street consensus. This was driven by strong production, strong commodity prices and favorable cost. Our cash margin was 76% or $59.54 per Boe for the third quarter as we continue to lead our oil concentrated E&P peers. Our exceptional margins enable us to very efficiently utilize capital and sustain improvement in our debt metrics. Third quarter production expense was $5.17 per Boe compared with an average of $5.79 per Boe for the first half of the year. We expect fourth quarter production expense per Boe to be more in line with our annual guidance especially given the challenges of winter weather. G&A expense was $1.81 per Boe for the third quarter, another area of improvement. This compared with $2.11 per Boe for the first half of the year and again it's below the bottom, favorable in of the range of our annual guidance. Total long-term debt was $4.4 billion at September 30, with strong third quarter growth in cash flow. Our net-debt-to-EBITDAX ratio was 1.6x on a trailing 12-month basis and 1.4x, if you annualize the third quarter. As our spending in excess of cash flow continues to narrow, you should expect to see a further improved net debt to EBITDAX ratio. We expect year end debt metrics to be relatively consistent with the third quarter. Non-acquisition CapEx was $2.7 billion for the first 9 months of the year. This is in line with our annual CapEx budget showing the continued focus on capital discipline as we continue to grow production improved reserves. Looking forward, we have supported our 2014 CapEx and production plans with an active hedging program. Currently, we have hedged approximately 60% of our forecasted oil production and 40% of our forecasted natural gas production. These hedges are at attractive prices, supporting our growth plans and financial discipline. We are on track to achieve our guidance goals for 2013 and look forward to moving into 2014. With that, we will now gladly address any questions that you may have, and we're turning it back over to the operator for those questions. Thank you.

[Operator:]

[Operator Instructions] And your first question comes from the line of Leo Mariani with RBC.

[Leo P. Mariani:]

Just a question on the Hawkinson pilot here. Just wanted to get your sense if you think you guys are seeing production communication between the different wells you've got there, amongst the difference zones?

[Richard E. Muncrief:]

Yes, good morning, Leo. This is a Rick Muncrief. Thanks for joining us. What we're really excited about is the results on the Hawkinson project. #1, the productivity is really something we're very happy with. We've been very proud of the team's execution. As you know, that we have brought this thing in probably 30 days ahead of schedule, and we're really happy to see -- what we think is the proving of successful commerciality of the lower bench testing. So our next steps, we're going to truly fully integrate our extensive microseismic project that we had with our frac modeling, do some additional post type testing and in tie that in with our actual production numbers. And we'll be doing that over the next several months, and so at the end of the day, we're extremely encouraged about what we see. Specifically on your question, we see, as we normally see with density test, you see some pressure impact from one well to the other, that's nothing that's anything that we're concerned about. So what we'll see over time is what that truly means. We've got quite a bit of data across the basin that suggest that even though you see pressure surges, if you will, during stimulation, that once these wells go in production over the long haul, you'll see that diminish.

[Leo P. Mariani:]

Okay, that's really helpful. And, I guess, just jumping over to SCOOP, obviously, you guys kind of highlighted well cost, talked about some potential improvements as we get into next year, can you guys kind of maybe put any type of magnitude in terms of what kind of well cost reductions you expect there, you have a 10% number over the next 12 months, is it 15%? Can you kind of help us out with that a little bit here?

[Richard E. Muncrief:]

Yes. Once again, Leo, I think that the 10% number is probably not totally out of the question, especially, in the fact that we're going to be having increasing cross unit wells. Currently, as Rick mentioned, 50% of our 12 rigs we have running, so 6 cross units wells are being drilled currently. And we have 40% to 45% of our program, I believe, for next year is cross-unit. So I think what you're going to find is not only the absolute cost, but certainly, on $1.00 per reservoir foot, you're going to see that really come down and we're very encouraged with -- not only the cost side of the equation, but also what we're getting from results.

[Leo P. Mariani:]

Okay, that's really helpful. I guess, you guys bought new acreage in the SCOOP as well, looks like your acreage total went up. I mean, where do you think that number can go over time? Is your still acreage available here?

[Winston Frederick Bott:]

Well, I think SCOOP's, it's one of those plays. It's like the Bakken. You look at -- we're continuing with new leasing over the Bakken. So every time, we have an area where we get more comfortable with. We sort of have a ongoing policy of building acreage in those plays. So we're happy that we've got a pretty good leasehold now, it's going to be material to the company, it covers all of the key areas and it's just a question of ongoing additions where we think we see potential.

[Operator:]

Your next question comes from the line of Ryan Todd with Deutsche Bank.

[Ryan Todd:]

I guess, a question for you on Antelope. It's great news, we appreciate that the quality of the acreage is great and it's great news that you're going to be probably the first Bakken operator to go to Full field development in the region. The question is, is there a potential that Antelope eventually moves tighter than the 1,300-foot basin that you assume in base plan, are you confident that at this point that that's a proper spacing for the region?

[Winston Frederick Bott:]

Ryan, that's a great question. Where we stand at this point in time is this is a very good area in the field, it's got a lot of enhanced geological benefits, natural fracturing and other things like that. Where we are right now is that we think as we get this program kicked off that, I think the headline here is that it is a very prolific area based on geologic factors, and we also see the potential in deeper benches. So this development would be the first Full field development that includes these deeper benches. And so I think that's the real headline here. The spacing that we're using is the 1,320 spacing that we're currently planning. We think that's a good place to start in an area that it's this prolific. Having said that, as we get into that program, we are pretty nimble and we may adjust that if we see different results, but it's kind of our current plan.

[Ryan Todd:]

Okay. So I guess, as you get data back and maybe more than 660-foot density test you're doing, you do have a possibility of tightening that up over time?

[Winston Frederick Bott:]

Yes, sir, most definitely. We'll let data drive that.

[Ryan Todd:]

Great. And then in SCOOP, on the cross unit wells you're talking about, you've given us some, I guess some clarity in terms of what part of the program that might be next year. I mean, what are your expectations right now in terms of the capital efficiency gain that you're seeing from the long lateral in terms of the productivity improvement that you see per incremental CapEx spent?

[Richard E. Muncrief:]

Well, we think it's very capital-efficient to go with the 2-model laterals, that's why we're doing that. So what we're seeing is if you look at well cost, as we've stated, you go from $9 million to maybe even $13 million on the high end, so you're adding up $4 million for that extra miles, it's only about a 50% increase in your cost to get double, and actually a little bit more than double the reservoir benefit when you start thinking about your hard lines, that sort of thing. So we're real pleased. We only have 2 of the long laterals that we've operated that -- or the 9,000-foot or 9,500-foot laterals and we're extremely pleased with the results thus far. One is in the gas condensate area and one is in the oil window.

[Winston Frederick Bott:]

So, Ryan, if I can add a little bit of additional point there. Just to keep it in perspective. Remember, as we've guided before, next year will also be a very important year for us in HBP acreage. So we will still have rigs out there focusing on HBP acreage. And to do that most efficiently sometime is the one mile lateral program. So we have that in balance, but ultimately, as Rick talked about, we're moving towards the type of development that can benefit from cross units.

[Operator:]

Your next question comes from the line of Drew Venker with Morgan Stanley.

[Andrew Venker:]

You guys talked about moving into Full development in your Antelope area. Do you have an idea or sense of when you think you'll move into development mode for the entire play? Is that on the horizon at this point?

[Winston Frederick Bott:]

Well, great question. We will move in full development in the entire play, but there's probably not enough rigs in the world to be able to handle that, so we'll probably do that in a staged approach. And we'll be focusing on areas where we've got a good data set, where we think the uplift is going to have significant bank for the buck and where we have a material acreage position. So those are probably the end of the infrastructure, so those are probably the 4 criteria to help us guide into Full field development. It'll also give you a hand of where that's going to be. It's going in these areas where we density pilots and these deeper bench testing. And so we know that we can maximize recovery from the spacing unit and continue to drive down costs. So that's kind of the thought process as it goes behind deciding on where we're going to go next in terms of Full field development of Bakken. As you know from Continental's inventory, we've got several decades out here of inventory, so like you, we're excited about starting to progress this into Full field development and the Antelope is one of the areas that Harold talked about where we want to just have the team full there is back.

[Andrew Venker:]

Okay. And then in terms of completions, can you talk about what kind of experimentation you expect on your completions -- your plan test in 2014?

[Richard E. Muncrief:]

Yes, it's good question. One of the things we've done is we've locked in on a completion design has worked really well for us, and that design has really evolved, if you will, over the last 4, 5 years. And it's -- because of that, we've been able to get extremely efficient, and we've been able to drive the well cost down and the results. That being said, if you look at our standard design today, we have perked [ph] in plug, we have packer type -- swell packer type completions, 30 stage jobs. So things we've done recently and really over the last year, we've done some slick water jobs, and we've seen some variable results thus far. We've got a few jobs where we've gone in and if you think about the Hawkinson, we actually cemented 4 of our minors there. So we'll be ascertaining, do we see any difference in productivity with the submitted liner versus our traditional approach. But to answer your question spot on, that is if you look at 2014, we're going to carve out about 20% of our planned well count to try some different approaches. One of the things you have to be careful about is changing too many variables, and so we've got a very measured approach that we're going to take and we currently have about 50 wells in inventory of different things we're going to try, and that's going to range from more slick water jobs, it's going to range from cemented liners, all the way up to some very significant increases in our project size.

[Andrew Venker:]

So is the idea there to perform side-by-side tests or directly off setting tests so you can really measure the difference?

[Richard E. Muncrief:]

Absolutely, absolutely.

[Winston Frederick Bott:]

I think one another key point, please don't lose that point, is to change one variable at the time. So as you can see where is the uplift coming from and build the database across -- again, remember, we're all the way across the play of what's going to be impactful across the play, as well as an area specific type cocktail, if you will.

[Andrew Venker:]

Right, right. And what is the incremental cost for those cemented liners or if you're going to go to, say 40 stage versus 30?

[Richard E. Muncrief:]

Well, there's several additional costs. Cementing liner is, where we do currently to go in and clean out make sure top of your PVR is clean and get out in your lateral. We we've been seeing a $200,000 to $300,000 incremental costs. As you know, some of the slick water jobs, you maybe adding $1 million, $1.5 million per well cost. And then depending on what the increased profit, just how large you go, that can go up pretty dramatically. One of the good things about the Continental in our acreage position is we get a chance to look at a lot of, not only what we operate, but in our non-operated activities as well. And we typically average about 100 wells per quarter or about 400 gross wells per year that we get a chance to see what others are doing. And so we can truly -- we really benefit from that. We can see not only what the actual results are, but also what the actual cost is, as well.

[Operator:]

Your next question comes from the line of Noel Parks with Lindenberg Thalmann.

[Noel A. Parks:]

Have a couple of questions. One of them was, I was curious with oil prices. Since last quarter, we dipped back below 100 for now. I was wondering if that have any impact as far as maybe you're persuading folks to lease, that maybe have been holding out and making it harder to [indiscernible] the position?

[Winston Frederick Bott:]

I don't -- we are not seeing that. We're progressing very steadily on leasing within our key areas here, so we're not seeing a whole lot particularly. I think it's almost the same.

[Noel A. Parks:]

And sort of related question. Just looking at this persistent backwardation of the future curve. And you look out a couple of years towards 2015 to '16, and it looks like maybe it's possible to hedge with not a lot of liquidity, of course, in low-80s per $1. All the supply coming on, different plays in the country, how much do you think you need the downside protection as you look out a few years?

[Harold G. Hamm:]

Well, the curve has been backwardated now for -- when you look at it, for the last 6, 7 years out there, pretty tough, a couple of years out. And so we've not been aggressive at hedging out there. We had with a bit of -- at least of all the upside of -- at $110 per barrel this last year or so. So we haven't been real aggressive in doing that. The other -- there are supplies coming on. But we're also seeing in the world, demand is still up, increasing 1%, 2%. So we think that as the economies improve, that, that number could go up as well. So other countries and other production didn't gain a whole lot. We're not seeing the shale revolution or this Renaissance occur in a lot of other countries. America is seeing it, but not a lot of other places. So it's a fungible commodity, and we believe we're in pretty good shape for the future.

[John D. Hart:]

Noel, with also -- on your price that you referenced, that's really closer to 5 years out on a WTI basis. If you're looking a couple of years out you're closer to 90 in WTI, in Brent, where we're selling a large percentage of our production based on the Brent prices in the closer to 100 range, so we've got a lot of strength there. And I agree with everything Harold added on the way the markets are working.

[Noel A. Parks:]

Great. and then, just one other quick one I wanted to ask. The Hawkinson pad, if I heard right, it sounds like it came on, on about 30 days sooner than was originally scheduled. That was interesting to hear. How did you achieve that?

[John D. Hart:]

? A lot of that was just on our cycle times. The drilling -- our drilling organization did a phenomenal job and as did been our completions operations, our facilities design group. Just the whole project has really clicked. And as I said in my remarks earlier, I couldn't be prouder of the team of what they accomplished.

[Winston Frederick Bott:]

I'll brag on one more part there now since you asked and opened the doors. It's also about the really tight integrated work between the production guys and our marketing guys to make sure the infrastructure was there and to make sure we weren't flaring, to make sure that this gas was going right in the line and that we were able to bring that oil on stream as efficiently possible and maximize the value of every molecule that came out of there.

[Operator:]

Your next question comes from the line of Pearce Hammond with Simmons & Company.

[Pearce W. Hammond:]

One question I had is differentials right now at Clearbrook has widened out quite a bit relative to WTI. And I know you've already given your guidance for '14 of about $8 to $11 discount to WTI for the '14 guidance. But what do you see going on right now that's kind of contributed to that widening of that discount? And how do you see that may be coming down so that we can get within that guidance range for '14?

[Jeffery B. Hume:]

Pearce, this is Jeff Hume. What we're seeing is the Syncrude units in Canada are back online, so we have a large supply of oil pressuring from Canada. We've also seen some refineries going through a turnaround. A couple of them were early in that area, one at Chicago and one at Minneapolis that went into early turnaround. Do to some -- I think they had some fires or some problems there. So for safety, they went ahead with that. So you had the combination of Syncrude climbing very rapidly and refineries going down. So that phenomenon has pressured Clearbrook. We're putting virtually no oil into Clearbrook because we have opportunities to put it in other places. And while we're talking about that, one thing we need to look at is we're really improving getting our oil from the field to the -- either the pipeline or the railhead. And the rail transit time to and from the market is improving because of increased infrastructure at the refinery end. We've got very good infrastructure in the field. That's been there for some time now. But on the refinery -- and we're seeing turnarounds now where we're getting an easy 2 trips a month to the East Coast and increasing that. So that's improving greatly, and we still have a lot of foreign oil on the East Coast that we can displace. So we see a good future for us there on growing that market and moving and working with a lot of refinery partners to fill that need.

[Pearce W. Hammond:]

And then my follow-up, taking up on some of Rick Muncrief's comments earlier on some of the new frac techniques. How do you handle, internally, the tension between focusing on full-field development and moving the manufacturing mode and cost reduction, while on the other side, giving consideration for this newer techniques that might result in much higher cost at the well?

[John D. Hart:]

Great question, Pearce. We do debate that internally. But I think that we just -- when you look at the size of the prize here and we're still in the second inning, we think we have it right. However, we're also open-minded enough to know that there might be a better way. And if you really think about continuously improving your processes, you need to do that. And we are -- I can tell you, we have those debates. But we are absolutely aligned internally to try to find a better way. And we give credit where it's due, and that's on the cost control. And we know that it is from incremental cost. But if you can, on average, you may spend $1 million, $1.5 million more on 20% of your wells. We'll just stay efficient. We'll figure out a way to make that work.

[Operator:]

Your next question comes from the line of Marshall Carver with Heikkinen Energy Advisors.

[Marshall Carver:]

You commented about the flatter well declines from the lower benches. Now that you have some production history -- well, additional production history on those wells, how do you think the EURs compare versus the Middle Bakken and Three Forks 1?

[John D. Hart:]

What we've seen thus far on our lower benches is we have a range, and we actually chart that against our 603 model, which is our standard model. We're still seeing some scattering. If you look at some of our lower bench wells, you have EURs in the 390 to 440 range. You also have some that -- for instance, our Angus well is going to be approaching 900,000 barrels equivalent. So we do have a pretty good scattering thus far. It's probably, in all reality, just below our 603 model, but not substantially. And there again, I'd caution you, but we just don't have a lot of test thus far. Something we'll learn over time. But at the end of the day, we're very pleased with what we're seeing.

[Winston Frederick Bott:]

And Marshall, I'm not sure if you're asking specifically about the Hawkinson, but the Hawkinson has only been on for, basically, 1 week to do the testing and just now getting back online. So it's really too early to say one way or the other. I mean, we're just basically reporting initial IP rates. And remember, we don't flare. We put everything in down the line. And so -- and we use the standard choke size. So it's probably a little too early to talk about whether or not there is an EUR adjustment or anything like that if you're speaking specifically about some of these large density pilots.

[Marshall Carver:]

Right, right. I was thinking -- I was talking more about the other areas outside of Hawkinson.

[Winston Frederick Bott:]

Okay, perfect.

[Marshall Carver:]

My -- just follow-up would be, do you have -- how many net acres do you have -- net acres do you have in the Antelope area and also in the Northwest Cana?

[Winston Frederick Bott:]

Yes, Steve? Steve Owen?

[Steven K. Owen:]

Yes. In the Antelope prospect area, we have a little over 32,000 acres. Northwest Cana, we have 147,000 acres. And as Harold mentioned earlier, about 2/3 of that is located within the Merrimack play or stacked play.

[Operator:]

Your next question comes from the line of Doug Leggate with Bank of America Merrill Lynch.

[Douglas George Blyth Leggate:]

I have to tell you, ears back is not an expression you hear in Scotland very much. But let me ask you, given that this is really the outcome, I guess, of the successful down spacing and cross testing, I guess, you guys have been doing. Was this already baked into your guidance for 2014 and at the longer-term plan that you presented last October? And I guess, what I'm really try to figure out is there are no upside from the acceleration to your production targets? And I've got a follow up, please.

[Winston Frederick Bott:]

Sure. Doug, to answer the simple question, yes, it is baked into our 2014 capital program. And as we told you when we announced that a couple of months ago, that we'd start -- as we came closer in end of the year, we'd give you more color around that program. So I think the takeaway for the Antelope is that we're moving into full-field development in an area we have a lot of data like. We've got the infrastructure there already. We're moving into that quicker. So yes, we're accelerating. Is there upside to accelerating? Yes, I believe there's considerable upside to accelerate both within Antelope. Harold talked about what that production uplift might look like in the next 2 years. It could go even higher if you start to drill that out and if we continue to see the great results and drive down costs as Rick Muncrief is challenged with doing, as well as increasing the stimulation efficiencies. So we do see considerable upside. And you said you had a follow-up?

[Douglas George Blyth Leggate:]

Yes. So I wanted to go back to the question on differentials because it appears or at from our point of view that waiting BP's refinery is now taking heavy crudes and releasing, I guess, a lot more light sweet into the -- they are backing a lot more light sweet into the region. I'm just curious, what do you think to your earlier comments if what we're seeing currently were these very light differentials relative to WTI is something that is relatively temporary? And if you could just remind us, I think you touched on this earlier. But just remind us where you're marketing stands as your ability to basically avoid getting the explorers to what's happening in the refinery. I'll leave it there.

[Jeffery B. Hume:]

Doug, that's a great question. The BP refinery is switching to the heavy Canadian crude. We didn't put much there, but that is the pressure I've just described that's on the Clearbrook market. And we're not putting any barrels in there and haven't for quite some time. We're moving more and more barrels to the East and West Coast, and that's where we have room to displace light sweet crude. We have the Bakken crude is in such quality, the refiners are really looking at do they want to switch to this heavy oil because we're getting very good yields out of the Bakken, very good cost. And I think we're going to go over the next year or 2 through a lot of replumbing, if you will, of the North America delivery systems. We're seeing more pipelines coming in. Pony Express announced they're going forward, and they're building their line into Cushing from the Bakken. We just heard this morning that Enbridge is going to go out with their Sandpiper line for an open season on that, and that will take oil to the East and put it past the area and get it up into the Ohio River Valley and up into Canada. And so that would be a couple of years out. They'll be expanding that. The East Coast refiners have built -- spent quite a bit of money now getting rail terminals in as have the West Coast and that keeps expanding and the refiners are improving in winning the Bakken crude. You see them talk about that in their releases. We have great relationships with these refiners. Well, we need them, they need us, so we're working in contracts that take care of both of us. And so we're going to move together forward and find good markets for this crude and continue to grow. And we have the premium crude in United States right now. We're going to continue to find premium markets for it and continue to grow this asset.

[Douglas George Blyth Leggate:]

So you feel pretty comfortable with your differential guidance, currently?

[Richard E. Muncrief:]

We do. We're going to have some hiccups right now. We're in a shoulder month, where refining's down. But I want to note that it is higher than normal, and that's because refiners have also redefined themselves. We're exporting more product out of the United States as refines. We're way ahead this past week to report some AI gasoline exports really took off. And so we're finding markets outside of the United States, and we're growing that. And so that all goes into the bucket of the reestablishment of the petrochemical industry, and we're going to have just, I think, more wonderful news than bad news over the next 2 to 3 years as we replumb this and get everything moving. And it all ties together, and it's going to grow. And there's going to be some months or maybe quarters that things are a little tough, but we're going to work through that. And it's going to be very strong long term.

[Operator:]

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

[Andrew Coleman:]

When you look at plenty years back there at Antelope, I guess, how much time will it take or how much of the facility's expansion is complete at this point?

[Winston Frederick Bott:]

The -- how long will it take? Well, this is a really long program because there's a lot of acreage and a lot to do. So this is all the way through 2017, probably, program and seeing the maximum production uplift. So -- and we're kind of a just-in-time delivery sort of company in terms of what needs to be done, when it needs to be done. So the infrastructure and the takeaway capacity is there now. As Harold said, it's almost there for 2014 activity, and then we'll be working to make sure that, that the 2015, '16, '17 ramp-up is all in place and that everything is ready to go when we bring these larger and larger pads on. I think that's -- another takeaway is these mega-pads, this is a topographically very challenging area to work in. And so the team has done some tremendous engineering and some tremendous ideas on how to tie these things together, working with the midstream vendors to make sure that we get that takeaway capacity in there. And then -- we're then able to launch forward and really add some value here.

[Andrew Coleman:]

Okay, so that's just for the 33,000 acres of Antelope there, I just want to take -- just 2017, then?

[Winston Frederick Bott:]

Correct.

[Andrew Coleman:]

Okay. All right. And then the follow-up was do you have any update on, I guess, your views on secondary recovery and any pilots that you might have in the back of your mind for 2014, 2015?

[Winston Frederick Bott:]

Yes, we're working on a couple of those. Let's let Rick talk about that.

[Richard E. Muncrief:]

Yes, Andrew. We have plans that -- it will probably be just after the first of the year. We may get it done early -- late December. But more than likely, right at the first of year, we'll have our first injectivity test, which will be underway in our Elm Coulee area in Montana.

[Andrew Coleman:]

Okay, we'll watch for more of that, I guess, in the year end call.

[Winston Frederick Bott:]

Another area that doesn't catch much focus from you guys, but we're also doing a pilot project in our Red River Units, too, which we're going to be kicking off here very, very shortly. Building some infrastructure, and we're interested in seeing those results. And I think that'll have a little bit of application into the Bakken.

[Richard E. Muncrief:]

Yes. And to be clear, that is a CO2 pilot in our Red River Units area.

[Andrew Coleman:]

Where is the CO2 supply coming from?

[Richard E. Muncrief:]

We have -- we're having -- coming off the flue gas, if you will, or exhaust gas, if you will, off of one hydro pressure, 2 or more plants.

[Winston Frederick Bott:]

Local supply -- it's just a local supply, Andrew, just to summarize there. It's just one of the plants within the area.

[Operator:]

Your next question comes from the line of Eli Kantor.

[Eli J. Kantor:]

Sorry if I missed this, but I was wondering what the configuration would be for the 3 new high density tests you announced last night. What zones you'll be targeting with these 18 wells? Will all 18 wells be new drills? And are there any existing producers that will contribute to the scale of each pilot that will be spaced 660 feet from the inter-wells installments you're drilling.

[Jack H. Stark:]

And yes, on these projects, we're going to be targeting the Middle Bakken first bench, second bench and third bench, and we've got a total of 18 wells. And we're going to have 660 inter-spacing here, and our plan is -- we're, right now, monitoring our results from Hawkinson and our other wells or units that we'll be bringing on, Tangsrud and Wahpeton. And from what we gain as knowledge from there will help us define exactly what pad we'd decide to go with.

[Richard E. Muncrief:]

But there are -- just to be clear, there are existing wells that would be part of this.

[Jack H. Stark:]

Yes, there are existing wells. It's similar to what we've been doing here with the Hawkinson.

[Eli J. Kantor:]

So the actual number of wells are going to be targeting each individual bench. It sounds like that number is yet to be decided.

[Jack H. Stark:]

I don't have those numbers just right in front of me, but we'll end up probably having in, I guess, we'd say, 6 existing we'll probably be having 2? 2 to 3?

[Richard E. Muncrief:]

2 to 3.

[Jack H. Stark:]

2? Yes, probably 2. In other words, one that would pair in each of these zones.

[Winston Frederick Bott:]

So to be clear there, Eli, we're not -- because we don't want to wait for the time to drill out all of the whole spacing unit, we'll basically take a portion of that. But the 660 for offset is the key point. That's how far apart the wells will be, and so that we can get results there and then be able to scale up beyond that quickly.

[Eli J. Kantor:]

And timing on results again for these rigs?

[Jack H. Stark:]

Well, those are going to be in second half, towards year end. We'll be getting the results from our other density pilots. The other 3 that we have right now, we'll be getting those results here in the first half of next year.

[Winston Frederick Bott:]

So I guess the summary there is you should expect 6 density pilot announcements in 2015 results.

[Richard E. Muncrief:]

'14.

[Winston Frederick Bott:]

'14. Sorry, '14. I'm already working on '15.

[Richard E. Muncrief:]

I know.

[Operator:]

Your next question comes from the line of Gil Yang with DISCERN.

[Gilbert K. Yang:]

Can you -- in the density test, did the pretty the preexisting wells do anything peculiar when you turn them back on after the other wells have been frac-ed?

[John D. Hart:]

One thing we saw there, Gill, is an increase of several hundred barrels a day in those wells. Part of that was, I want to guess, is a function of being shut in for a while, that testing. But it's apparent that we did get some charge from that work. So that's why when Rick mentioned earlier that we're going to -- I think the proper way to look at this is going to be gross uplift by interest at the unit level because not only here, but on the Montana side, as we mentioned earlier, we do see some charge from our stimulation.

[Gilbert K. Yang:]

Okay, great. And can you remind me, I don't recall at this point, but what other 660 good spacings have you tested or have you done that or not necessarily within the density test but just straight lateral spacing test, and what were the results of those?

[Winston Frederick Bott:]

I don't believe we...

[John D. Hart:]

I don't think we have.

[Winston Frederick Bott:]

We've not done any. We've done a few early on. We did a few experiments wells that were even closer that kind of overlaying each other. And that was between Middle Bakken in the first bench. But well, no, we haven't gone out and done any program of a 660 sort of offset. So there isn't much data. The Wahpeton is the first one. And we'll expect those results to have that completed in April. So as soon as we can after that, we will be giving you those results.

[John D. Hart:]

In fact, the closest thing that we would have to a 660 is actually on the Montana side, where we have about 800 feet of inter-well distance there, and we've seen some great results there. And that's what's helped drive these volume increases that Rick referred to earlier where we actually doubled Montana's volumes in the last 12 months.

[Winston Frederick Bott:]

And to bring in that data set there, that's pretty consistent where those parent wells have had significant uplift and have held at a better decline rate. And so that leaves us to starting to conceptually think about what is the uplift for the unit -- what's the uplift for the entire unit. Interference is not really the issue. We will be uplifting for the entire unit.

[Gilbert K. Yang:]

Right, right, okay. And then last thing about that is these net aligners, I know you want to test them for a while. But what's sort of the initial -- what were sort of the initial rate differences versus uncemented well?

[John D. Hart:]

Yes, we can't really tell any differences thus far in the cemented versus uncemented.

[Winston Frederick Bott:]

That is way [indiscernible].

[Operator:]

Your next question comes from the line of Paul Grigel with Macquarie.

[Paul Grigel:]

On Ears Back project, what consideration was given to a balancing of spud-to-sales timing versus getting results online a little bit sooner?

[Winston Frederick Bott:]

What a great question. Thanks, Paul. There are a number of things we're doing to make sure we don't inventory capital and to make sure we're getting that production on as quickly as possible. First of all, within that program, there are a lot of 6-well pads and 8-well pads that we can drill much quicker and drill pairs, doing our typical zipper fracs, all those sorts of things. So we're doing -- we're continuing wit that base knowledge to make sure we deliver our production guidance. And as we've alluded to earlier in some of our detailed discussions and presentations, as we go to these larger and larger pads, we're segregating those into subareas that we can batch drill, batch complete and SIMOPs operations then as we move to the next one. So that you're talking about 7 or 8 wells at a time to be able to bring on part of these mega-pads. And then you sequentially go through that to bring on the whole mega-pad. So exactly to your point, we are doing everything we can to make sure we get that production on as quickly as possible. And that just gives you the opportunity to monitor results and get that production history match as well for a lot of the tests we're doing.

[Jeffery B. Hume:]

And plus having pipelines there, oil, water zone and gas, particularly, large gas lines.

[Winston Frederick Bott:]

Yes. And I want to make sure you guys don't miss that headline. All of this has been in our 2014 budget plan. So our capital is set, and we're going to deliver this with the capital we told you.

[Paul Grigel:]

Great. And if this is kind of the way to move forward in the play, what are you kind of from a strategic sense see? Is it being impact of the play? I mean, does it really create an increase of consolidation opportunities given the large capital investment moving forward?

[Winston Frederick Bott:]

Say that last part again?

[Paul Grigel:]

Does it create an opportunity with the large capital investment that has to go into these mega-pads for essentially consolidating opportunities into the larger player such as yourselves from smaller independents?

[Winston Frederick Bott:]

Oh wow, I think that's exactly the case. I think that's very important. I think if you -- and I'll let Harold comment on the back of my comments, but if you take the Hawkinson and look at the big picture, this is the culmination of a lot of very small pieces of understanding and very small tests, including the lower benches where we've proven we have commercial. It's going to be a significant component of the oil produced in that core of the play. The down spacing density pilots have given us a lot of encouragement, and we're starting to think about the uplift for the whole section. Because we're all -- the whole thing we're focusing on here is how you maximize the commercial recovery of the oil that's in this rock, and we're creating the permeability here with the stimulation. How do you stimulate there most effectively? How do you go back and restimulate so that you're going to accelerate in the Full-field development? But the whole thing is trying to -- we think we've made the pie bigger with the -- in the Bakken with these proving the productive -- commercial product capacity of the deeper benches at Three Forks. And these density pilots essentially increase the recovery factor expectations of the field. So now we've -- now that we've created the pie bigger, we're also going to eat more of the pie.

[Harold G. Hamm:]

And I think as far as the acquisitions, we have seen some of the smaller players basically sell their acreage to other larger operators. We've seen some of that in the past, and I'm sure that will continue to be.

[Operator:]

Your next question comes from the line of Ryan Oatman with SunTrust.

[Ryan Oatman:]

I hopped on the call a little late, so I apologize if you mentioned this. But on this Hawkinson test, did you provide the well rates by zone?

[John D. Hart:]

Yes, we gave you averages out there for the individual and all the TF2 and TF3. They can model 1,070 barrels equivalent a day and the...

[Richard E. Muncrief:]

From Slide 4 in the presentation.

[John D. Hart:]

Yes, I was going to I'm just trying to find that one for you.

[Ryan Oatman:]

I got you, I got you. But are there any rates available between the Three Forks 2 and Three Forks 3? Or I guess, more broadly speaking, did you see similar type performance between those 2 benches?

[John D. Hart:]

Yes, we did, actually, and they are remarkably similar. And really, Ryan, at this point, when we were at this stage of the program here, we can get kind of lost in the individual results and what's really important, I think, at this stage of the game is really step back and look at the big picture here of what's actually happened between our exploratory Lower Three Forks program and now these density tests in the Lower Three Forks. And right now, we've got 27 wells at Lower Three Forks that we've drilled and tested. And this includes 20 in the exploratory and 7 in the density. And we're looking at about 300 square mile footprint of proven productivity now in the lower benches. And as you'd expect, results vary in these zones by area and even by zone a bit. But in general, they're in line with the nearby producers. And what the bottom line is as it appears, we have substantial increase that won't be recovered from this field. And really in support of this is that out of the 27, we've only seen 3 wells right now that have shown influence from offsetting legacy wells. So it's really like really 10% of the wells. And so in saying this, it looks like that's really -- the interference is not really the big issue, as had Rick said. It's really about what kind of uplift do we ultimately going to get out of these units. And one of the things we are seeing is that the legacy wells are showing an increase in productivity. And with that, it really does help focus us down to where we're right now. I think going forward here, the shift needs to really change from focusing on individual well outcomes to really the unit performance and unit uplift. And that's really where we're headed here. Because you'll see some wells when may come on, they may not be as strong. But yet you're seeing lots of wells increase. And so the net effect is the unit has an uplift, and you're getting -- essentially, that stimulation is influencing production somewhere in that unit. So all that said, we could get into the granularity on individual wells, and I think I've got a list here, and we could go through these IPs. But that's really kind of the end game right there. The story is -- fortunately, we feel if we look down the road, and we're really transitioning into this Full-field development model now. And the big deal now is just defining what is the proper density, what is the proper spacing to maximize oil recovery out of this just more class oil field.

[Ryan Oatman:]

Right. I mean, there has been a fascinating evolution here and certainly very interesting to watch from our perspective over here. Moving over to the SCOOP, it does look like the acreage footprint improved pretty significantly quarter-over-quarter, picking up a little over 40,000 net acres. Where was that acreage, I guess, first? And then secondly, how do you feel about what you've delineated so far in terms of what percent of the acreage do you feel like is de-risked at this point with the latest Zelda step out?

[Winston Frederick Bott:]

Yes, Ryan. We actually answered that earlier in the call. We talked about our acreage position in the SCOOP. And yes, we've added acreage there. Like we've done in the Bakken, we just continue in the areas that we like. We continue to build positions and do some trades and things like that and sort of maximize the position in areas we like. So that's kind of an ongoing program in every play we're in. Specifically about the de-risk area, I think the Zelda well was pretty important. I'll refer you to Slide 8 in our presentation. It shows you where Zelda was, and it adds about another 20 miles or so of a step out. And so it brings us into an area that -- So we're extending the play down to the Southeast as we've talked about. So our whole goal year for this year and next year has been to HBP our acreage and continue to extend the parts of the play that we think have de-risked. I can't give you an actual percentage, maybe Jack can, maybe it's at 60-30, 60-40 sort of split, but that's probably just a guess.

[John Kilgallon:]

Well, we have gone past our allotted time for the call this morning. I want to appreciate all the participation we've had. If you have any additional follow up, please reach out to Warren Henry and myself, and we'll be happy to do so. Our contact information is at the end of the release. Thank you for joining our call.

[Winston Frederick Bott:]

Thank you.

[Operator:]

Ladies and gentlemen, that concludes today's conference. Thank you for your participation. You may now disconnect. Have a great day.