Continental Resources, Inc.

John Kilgallon - Vice President of Investor Relations Harold G. Hamm - Executive Chairman, Chief Executive Officer, Chairman of Finance Committee and Member of Nominating/Corporate Governance Committee Gary E.

Gould - Senior Vice President of Operations and Resource Development Winston Frederick Bott - President and Chief Operating Officer John D. Hart - Chief Financial Officer, Principal Accounting Officer, Senior Vice President and Treasurer Jack H.

Stark - Senior Vice President of Exploration Richard E. Muncrief - Former Senior Vice President of Operations and Resource Development

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division Brian Singer - Goldman Sachs Group Inc., Research Division Leo P. Mariani - RBC Capital Markets, LLC, Research Division Joseph D.

Allman - JP Morgan Chase & Co, Research Division Marshall H. Carver - Heikkinen Energy Advisors, LLC Pearce W.

Hammond - Simmons & Company International, Research Division Andrew Venker - Morgan Stanley, Research Division Brian M. Corales - Howard Weil Incorporated, Research Division Noel A.

Parks - Ladenburg Thalmann & Co. Inc., Research Division Phillips Johnston - Capital One Securities, Inc., Research Division Andrew Coleman - Raymond James & Associates, Inc., Research Division Matthew Portillo - Tudor, Pickering, Holt & Co.

Securities, Inc., Research Division Jason A. Wangler - Wunderlich Securities Inc., Research Division Gabriel Daoud - Jefferies LLC, Research Division Paul Grigel - Macquarie Research Gilbert K.

Yang - DISCERN Investment Analytics, Inc

Thanks, Brandon, and good morning. And welcome to the Continental First Quarter 2014 Earnings Conference Call.

Joining me today with prepared remarks will be: Harold Hamm, Founder, Chairman and Chief Executive Officer; Rick Bott, President and Chief Operating Officer; and John Hart, Senior Vice President and Chief Financial Officer. Also during the call, we'll have a Q&A session, and other members of management who will be joining us: Jeff Hume, Vice Chairman of Strategic Growth Initiatives; Jack Stark, Senior Vice President of Exploration; Gary Gould, Senior Vice President of Operations and Resource Development; and Steve Owen, Senior Vice President of Land.

In conjunction with the earnings press release and our call this morning, we have posted a summary presentation that can be found on our website at clr.com, underneath the Investor Relations section under Presentations. It's also available within the webcast portal for your quick ease.

Today's call will include forward-looking statements that address projections, assumptions and guidance. Actual results may differ from those contained in our forward-looking statements.

Please refer to the company's filings with the SEC for additional information concerning these statements and risks. Also in today's call, we may refer to EBITDAX, cash margin, adjusted net income per diluted share.

For a reconciliation of EBITDAX to GAAP net income and operating cash flows and a description of the calculation of cash margin and a reconciliation of adjusted net income per diluted share to GAAP net income per diluted share, please refer to the presentation materials I mentioned earlier that can be found on our website. With that, I'll turn the call over to Harold.

Thank you, John, and good morning, everyone. We appreciate you joining us on our call today.

Continental's first quarter of 2014 was characterized by strong financial results, solid execution in operations and the achievement of several significant milestones in our exploration programs in the Bakken and SCOOP plays. Continental generated EBITDAX of $775 million in the first quarter of 2014, benefiting from solid production growth, strong oil prices and strengthening natural gas prices.

The Continental team did a great job managing the operating cost during the quarter. And we expect continued solid performance throughout the year.

Our CFO, John Hart, will provide further detail on our financial results. I just want to congratulate the teams on their outstanding discipline and execution focus this last quarter.

We increased first quarter production 25% over the same quarter last year. During the first, we experienced production interruptions and rail transportation delays due to weather at various times in the quarter.

I assure you, we're almost done talking about North Dakota weather. Now that temperatures are finally climbing with the spring thaw, trucks are running with reduced load restrictions in several counties in Northwest North Dakota.

We anticipate much better operating conditions in the next several weeks. We're ready to shift into high gear.

As we noted in the press release, our annual guidance of 26% to 32% production growth remains in place. As you saw on our press release, we had plenty of downspacing news to announce.

Our first test, the Hawkinson, is still producing very strongly. The Rollefstad had very impressive early initial rates, led by enhanced completion designs.

And while the Tangsrud wasn't as big as we had hoped, the project was designed as a step-out to the North to further test the Lower Three Forks as well as 1,320-foot spacing. Looking to the remainder of the year, you should expect solid production results in the second quarter with growth accelerating in the second half as we get the full benefit of these multi-well density drilling pilots and as we bring additional density pilots and projects online.

Next, SCOOP production should continue to accelerate. We continue to expand the play through exploration held by production up on our acreage with our increased rig count.

Finally, we will remain focused on spending discipline in both CapEx and operating expenses and strong EBITDAX growth. 2014 is shaping up to be an excellent year.

Just before turning the call to Rick, I'd like to welcome Gary Gould to the call on his new role as Senior Vice President of Operations and Resource Development. As we announced last week, Gary is stepping up to a great opportunity and has already established himself as a valued member of the leadership team here at Continental.

Welcome to the table, Gary.

Thank you.

So with that, I'll turn the call over to Rick Bott. Rick?

Thanks, Harold. First of all, we apologize to the audience, I've got a bit of a cold.

So if my voice sounds under the weather, it's because I am. So I'll start with the Bakken.

Operating results in the Bakken were solid for the first quarter with 4% growth quarter-over-quarter and a 27% year-over-year growth in total production to roughly 97,500 barrels of oil equivalent per day. As Harold and other companies have mentioned, we've battled the weather since the beginning of the year, but we're getting past that.

Our drilled, but not producing inventory, is currently at 100 wells, down from February but still higher than our normal. We hope to work down the bulk of the excess during the second quarter, and we have 8 completion crews working to accomplish this.

Let's now talk about the 3 density tests that we've completed, all of which are on 1,320-foot spacings between wells within zones and including 4 zones: the Middle Bakken, TF1, TF2 and TF3. In the slide pack that John mentioned, if you want to see a graphic representation of each of these pilots, please refer to Slide 6, 7 and 8.

First, the Hawkinson. After 150 days of production, we're exceptionally pleased with the overall unit production in the Hawkinson density test.

Production remains strong and the wells are maintaining their trends. As we expected, when some of the wells were put on pump, production normalized.

Notably, half of the 14 wells in the unit are still flowing on natural pressure, including 1 of the original legacy wells, which shows just how prolific this area is. We continue to believe the Hawkinson will be an important template for our future density test and ultimately fulfill field development in the Bakken.

Next, the Rollefstad density test at McKenzie County, let's talk about that. In that, we had 3 legacy wells and 8 new wells in this test.

The location is in our Antelope field and was selected as kind of a kickoff for our Ears Back program in Antelope. Rollefstad was completing using enhanced completion methods, notably 2x the proppant in 7 of the wells and 3x the proppant in the eighth well.

The IPs for these wells range from 1,600 barrels of oil equivalent per day to as high as 4,000 barrels of oil equivalent per day. Given our belief that these wells would have very strong initial rates, we conducted the initial test in a high-volume vessel in order to see what these wells could really do, if not limited by infrastructure or facilities.

I mention this because Continental's philosophy typically is to standardize our completion in facilities. However, given the day that we have seen from our initial test and from competitors, we felt this was a unique opportunity to allow the wells to flow normally at maximum rates.

As a reminder, this test is in our Antelope area, which includes currently 4 rigs today and is planned for 6 rigs by the year end. Finally, the Tangsrud density test in Divide County.

I think it's important to characterize the Tangsrud density test as a true step-out, not for the Middle Bakken and TF1, which are productive in this area, but for the second and third benches of the Three Forks. It's outside of 3,800 square mile area of the productive footprint that we established with our exploration program yesterday and we've shown you in the past -- or last year and we've shown you in the past.

We were trying to extend the lower TF productive footprint to the North. And based on the results, we've got some work to do.

These wells were all completing using our standard well completion design with 30 stages and approximately 100,000 pounds of proppant per stage. The new Middle Bakken and TF1 wells in the Tangsrud unit are similar to existing wells in the area, which have lower initial rates, but flatter declines.

Future deeper bench development in this area will be assessed based on economic returns, any ideas that come out of our completion design test and commodity prices at the time. The other key headline in the first quarter involves our enhanced completion testing program.

Last year, we told you we are embarking on a large program to test a number of completion designs totaling 20% of our wells in the Bakken. We planned a pragmatic approach in several areas to test these new designs and in order to maximize returns.

If you refer to Slide 9 of our supplemental slide pack on our website, where we gave early results from 1 of these designs using slick water completions from 2 wells in Williams County, both wells are trending well above our standard expectation for completion in that area, consistent with what other companies have reported on this particular technique. We are continuing to test and evaluate other designs, primarily involving higher volumes in different types of proppant, different fluid types and different stage lengths.

Let me put this testing in context. As we indicated, this is a programmed approach and, therefore, we want to build a statistical database with adequate production history.

Our goal ultimately is to combine our completion design tests with our downspacing pilot results to maximize recoveries, accelerate production, and then thus drive higher-realized returns and greater net present value. Therefore, these tests will be important elements as we move forward into full-field development.

Although we are early in our program, we are encouraged by the uplift that we and other operators are experiencing. The impact of these efforts has potential to add significant upside to the field.

Now switching South to SCOOP. SCOOP production continues to grow, up 24% sequentially and 106% year-over-year.

We had the opportunity to high-grade part of our rig fleet in the first quarter and have done that, bringing in high-caliber rigs to drill this complex play and support our increasing desire to drill more extended laterals. For the quarter, about half of our wells were drilled in the condensate window and half in the oil window.

Referring to Slide 10 in our presentation, we highlighted 2 first quarter liquids-rich wells that IP-ed over 1,600 million cubic feet of equivalent a day and a third strong well in the oil window. The first quarter wells -- take all the wells in the first quarter, and the oil window had an average IP of about 800 barrels of oil equivalent per day and all the wells in the condensate window averaged about 1,400 barrels of oil equivalent per day.

So as you can see, the exploration program continues to be successful. In summary, the things to watch at Continental for the remainder of the year are: firstly, in SCOOP, we'll continue to explore an HBP with a larger percentage of our cross-unit laterals -- our wells drilling cross-unit wells, as well as starting a few spacing tests and a downspacing pilot; in the Bakken, we have 4 more density pilots as well as a large program to test completion designs that should be important data to guide full-field development; the Ears Back program in Antelope is underway, targeting the Middle Bakken first bench, second bench and third bench.

We'll have a lot to talk about at our Analyst Day in September that Harold mentioned to you last quarter. Now let me turn it over to John to discuss our financials.

Thanks, Rick. 2014 is off to a good start, setting the base for achievement of our annual goals.

During the first quarter, we maintained capital discipline with CapEx slightly in excess of $1 billion. This is in line with our expectations and supportive of our annual budget of $4.05 billion in nonacquisition CapEx for 2014.

Harold talked about our first quarter production. Our guidance for production growth remains 26% to 32% for 2014.

Supporting our expectations are the growth in our inventory of wells awaiting completion, which will begin providing incremental production as they are completed in the second and third quarters. Accelerating growth should also result from our ongoing capital plans in the Bakken and SCOOP.

As noted in our release, our sales volumes were less than production during the quarter due to an incremental inventory build of 363,000 barrels. While this impacted the first quarter earnings per share negatively and largely accounts for the differences with consensus estimates, these volumes will positively benefit future periods as they are sold.

Future sale of these volumes will help to offset incremental pipeline fill that we expect through the remainder of the year. We anticipate this projected line fill could impact earnings per share by 5% to 10% over the remainder of the year -- $0.05 to $0.10 over the remainder of the year.

We note that inventory build and draws are a positive reflection of the infrastructure build-out of the Bakken. The average oil differential for the first quarter was a discount of $8.98 per barrel versus the NYMEX daily average.

And the average realized gas differential was a premium of $2.14 per Mcf. Our realized oil differential was towards the low end of our annual guidance of $8 to $11 per barrel while our gas differential was positively above our guidance of a premium of $1 to $1.50.

The strong differential performance was reflective of the productivity of our marketing efforts and the quality of the crude oil and rich natural gas we produce. Our other financial metrics, LOE, G&A and DD&A, to be specific, are in line with our expectations for the first quarter.

We expect DD&A will positively benefit from incremental SCOOP and higher-productivity Bakken oils as we move throughout the balance of the year. We expect these will provide a positive trend in DD&A.

Year-to-date, commodity prices have remained strong. This has provided us the opportunity to continue layering in hedges to support our capital plans and cash flow needs for 2014 and into 2015.

We will continue to layer in hedges as market opportunities allow, consistent with our long-term philosophy. We anticipate 2014 will be a strong year for Continental as we move forward in the growth and expansion of the company, not only in the execution of our current 5-year plan, but also with a view towards the development of our multi-decade asset base.

Continental is well positioned in repeatable, low-risk, oily resource plays, which generates industry-leading cash margins for our company. The first quarter is consistent with this trend and positions us to build on that success in the balance of 2014.

With that, operator, we're now ready to turn back over for any Q&A. Thank you.

I guess, the cost of the -- you described yourself as a fast follower in terms of stepping up the intensity of the completions, but the costs obviously is a little bit higher. So what I'm trying to understand is the results, early as they may be, have been confirmed across the industry, not just for Continental.

So how do you see yourself allocating capital as it relates to more aggressive on the fracs as opposed to the number of wells that you drill? And I've got a follow-up, please.

Sure, Doug. Let me take that, and I'll see if Gary has anything to add to it.

Yes, we are anticipating continued success from our teams in driving overall well costs down in the Bakken to achieve the goal that we talked about for 2014. And we're also seeing some positive signs in the supply chain for those additional completion designs.

So we're anticipating that -- we're hopeful and optimistic that, that cost savings will be applied to this testing program and into designing a new -- any new designs that come out of that. And of course, for us, the most important thing is that whatever we decide to do that we apply what you've seen us do over the past several years.

And we make sure that, that is scalable and we're able to drive down cost.

And that really -- go ahead, Gary, sorry.

Well, I was just going to say I think in any play, there's a natural time when you move from HBP to development drilling, where teams start looking together and working together to determine what the optimum density is and what the optimum completions are. And of course, the bottom line is the incremental economics associated with that.

And so what we've done is we've established some multidisciplined teams made up of geologists and completion engineers, and resource development engineers. And they're working together to try to figure out what is optimum for each area.

And that's going to vary area-by-area and possibly bench-by-bench. And so we have lots of good people working on that.

Okay. I appreciate those answers.

I guess, my follow-up is kind of related, Rick. I mean, what do you guys need to see to declare victory on the change in the completion design?

And again, I'm really basing this on the fact that a number of your competitors have kind of already done that, and not similar areas to where you guys are operating, so I'll leave it there.

Great question, Doug. I mean, I think as I said, we're taking a programmed approach.

We see quite a lot of uplift from us in the industry with a whole number of techniques. So we've tried a lot of things, and almost everything has been successful.

So as Gary sort of alluded to there, we think that we're going to go about testing this based on the particular area and the particular geology in that area and try to figure out what we think is optimal to be able to ultimately drive down cost in that given area, and then across the field. So I think that's perhaps the difference, is that our footprint is probably the largest in the play.

And I think that we've got 1.2 million acres out there. So what we do, we want to make sure it's applicable, as Gary said, apples-to-apples in an area, and then that we're able to expand that and leverage that across the play.

First, on SCOOP, you talked about a few wells here, where you gave 1-day rates. It may be too early, but could you characterize how the 30-day performance is looking, or how your expectations for the 3 wells that you mentioned, relative to your type curve and give any more color with regards to what you're looking for in your spacing and tests and density pilot?

Well, I'd say that we are really pleased with the outcomes, and these wells are holding up very nicely. And these are some of the best IPs we've seen in the play, these couple of gas wells -- I mean, the 2 condensate window wells.

And so really, we're assessing these results and saying if that is going to make us if we're going to move our type curve up. But at this point right now, we're sticking with where we're at and plan on having more discussion about that when we get to our investor conference here in September.

Let me add to that, Brian. I mean, I think the key takeaway for you is the production growth is up 26% quarter-on-quarter.

Almost all the wells in the play are holding up very, very nicely. These are just some good, strong areas -- these are good wells in an area.

They're close together, so it's a strong area. But it's a large acreage position we've built, and so there's a lot of exploration ahead of us.

And as you see with lots of programs of this type, you'll have some areas that work real well and others that don't work so well. So as we told you all along, we're going to continue to explore this type of play, and then we follow on right quickly behind it, trying to HBP our acreage.

Great. And my follow-up goes to the Bakken.

I'm trying to just further hone in on how you're thinking about the variability in performance or expectations between the Three Forks 2, 3 versus the Middle Bakken, Three Forks 1. Just looking at some of the numbers that you talked about on the Tangsrud and the Hawkinson.

On the Tangsrud, you talked about a 50% haircut or so, it looks like, in just the rates, the 285 from the Three Forks 2 and the Three Forks 3 versus the 670 from the Middle Bakken and Three Forks 1. In the Hawkinson pad, you talk about 13 of the 14 wells producing 50% above the type curve.

I want to see if you could characterize a bit more of the variability you're seeing between the zones and how that impacts your thought process on relative EURs?

Well, I think I'm going to let Jack supplement here. But let me pick up Tangsrud.

Tangsrud was an attempt to extend the footprint of the deeper benches. It's a good area.

We've got lots of offset wells from Middle Bakken and TF1, so that wasn't a big step-out. But with TF2 and TF3, that was a step-out to see if we could establish commercial production.

The wells didn't work very well there. So as I said, we've got some planning.

And ultimately, we may have a different -- we still may drill in that area in the TF2 and TF3, but it may not be with as many wells per zone. We'll have to go back and figure that out for that area.

The Rollefstad and Hawkinson areas were very strong in all the benches. And so those are further into the basin, there's more pressure there, there's thicker interval.

And so we're quite pleased with the results of the second and the third bench. And as we've talked about in Antelope, we will be developing full-field development on the 1,320 feet spacing for those deeper benches.

And that's kind of in and around that Rollefstad area. Jack, do you have anything to add to that, or Gary?

No, that sounds good.

Great. And there was no variability between what we see in the Three Forks 2, 3 of the 13 to 14 wells...

Yes. There's always variability by wells.

There's a little bit of variability. But it's sort of characterized within that statistical average that we told you about.

I mean, there's nothing dramatically different about those.

No, in fact, we have a slide. Slide #7 just shows, for example, the Rollefstad.

You can see the comparison, Middle Bakken and TF1 to the TF2 and TF3, just based on initial rates there.

And that's early days.

Yes. They're very early.

And you can see they're very, very close. So we're not really seeing a significant difference there at least in the Rollefstad area there.

I just wanted to follow up on the Rollefstad here. You guys kind of mentioned these are sort of, I think, IP rates.

I mean, how long has this actually been producing here from these different wells?

They've been producing just in the range of about 30 days. And so what we've seen is some very good initial completions.

And we're excited about where they are. And they're all still flowing right now.

So that's a good sign and look forward to watching them as they continue on their trends.

Okay. And I guess, the rates that you guys provided as IPs, these are just 24-hour rates, I'm assuming?

Yes, that's correct.

Okay. And I guess, could you guys share any of the longer-term data, like the 7-day rates or the 30-day rates?

Have you got that available?

I don't have those available, but we can get those to you later.

Okay. And I guess, you guys talked about production downtime in first quarter and things came back on track in the Bakken in a number of weeks here.

Could you guys quantify what the production downtime was in 1Q and maybe give us a sense of how things have improved, maybe what current production is?

I don't know if there's any production downtime. I think it's just -- it is the pace of the completion crews completing new wells.

And basically, if you talk about drilling, we had 0 downtime on any rig. All rigs kept running and kept drilling, which as we talked about on our last call, built an inventory, and that inventory sort of peaked in February as we could not move trucks, couldn't move water and things like that because of the extremely cold conditions, January, February, March.

So that is -- and that's what I talked about. Now we've added back 3 additional crews, so we're at 8 crews now.

And that has essentially allowed us to work that inventory down, and we'll continue to work that inventory down. As we always talk about, the spring time has the thaw restrictions in several counties.

We're starting to see that, as Harold mentioned, so that essentially sort of delays that ramp-up when you can get those frac crews back to working. And so that's primarily the -- there's been no real production downtime.

In a couple areas, you may have to shut-in a few wells because of frozen valves and things like that. But it's really, Leo, pretty much a small factor.

I think Jeff talked about last quarter, occasionally we'll have delays in railcars showing up. And so that would mean that we're potentially at risk of shutting in production.

But that's -- some of the tanks that we've just talked about building is exactly to manage that type of issue, where we can keep producing to those tanks, and then sell it in future quarters if we have any crude logistic issues. So we're building that.

We talked about a portfolio approach to our marketing. We're building that and the infrastructure supports that portfolio approach.

So I hope that characterizes kind of the various elements of the weather slowdown that we've seen in North Dakota.

No, I think that's helpful. So I mean, I guess, should I interpret that to mean that you'll get more of a production bump in the Bakken in 2Q, and then it further accelerates in the second half?

Yes. That's exactly what Harold has outlined, exactly right.

And that's what gave us confidence, Leo, to basically say we're still on target to hit our overall yearly production targets. And remember, we don't guide quarter-to-quarter, we only guide year-to-year.

And we're in the second year of our 5-year plan, and we're well ahead of our 5-year plan.

So looking at the Rollefstad pilot and comparing that to the Hawkinson, how much of the improvement in production is geography? And how much do you think is the completion technique?

I think that's going to be a little bit hard to characterize at this point because we are early. Certainly, both areas are very good areas for us.

In general, in the Rollefstad area, we see very high ranges of EUR. So we also see that in the Hawkinson area also.

So they're both good areas. As we would expect when we frac-ed with a larger design with a 200,000 pounds of proppant per stage, and the 300,000 pounds we saw higher results.

And so that encourages us on the completion technique side.

Okay, that's helpful. And then in the SCOOP, are you trying any of the new completion designs there?

And if so, have you seen any results and what do those results look like?

We're trying a few things in SCOOP, but they're not big material-type things. The SCOOP fracs, in general, are already essentially 3x the Bakken.

They are a slick water frac, so we're already doing that on a routine basis in those areas. More of the things we're doing are trying to optimize the drilling and completion and integration of that as we drill in more complex areas and with higher pressure.

So that's the story in SCOOP. And we'll see -- we anticipate that we'll have future uplifts as we sort of get through this exploration phase, and then start in focusing on optimizing, as Gary talked about, the evolution of the play in the Bakken, the SCOOP will follow behind that.

You usually give a current production rate on your conference calls. Do you have that for your company for right now?

Currently, we're between 155,000 and 160,000 a day. You have variability at any given time, but we're right in that range.

Okay. And one other question, how much of your loss in acreage, the 1.2 million acres, would you say has been condemned or is unlikely to be developed in the Three Forks 2 and Three Forks 3?

Marshall, I think it's really too early to talk about that. I mean, there's only -- I'm going to let Jack comment on that.

But I think what we've said is there's a program here to try to determine the commercial productivity in those intervals. We know there's oil, we know there's good rock in that oil.

It's just a question of whether or not you can get it out at commercial rates. We've outlined a 3,800 square mile productive footprint and we drilled about 25 exploration wells in those deeper benches last year.

This year, we'll have about the same number, and that's more going in and trying to confirm area by area. So I think it's really pretty early.

The Tangsrud was, as I talked about, trying to extend that, see if we'd extend that. And so that -- and we kind of drew a hard line, but as you know, the geologists like to have a fuzzy line there, and so that line can move back-and-forth and so, but we are optimistic that in these deeper benches where -- in the right part of the basin, you have good pressure and good rock, that is going to be a very significant contributor.

Let me let Jack comment.

Marshall, this is Jack. And yes, that's a good question.

And we're obviously working towards that end, but you got to keep in perspective of where we're at in the play right now with these lower benches in particular. I mean, there are 54 producers right now in the basin as a whole.

That's not even 1% of the wells that have been drilled to date. And so -- we've got I guess, another 68 up, I've got it written down right here, in progress right now.

So the data is building, but it's way too early to be able to do the things that be able to sit and really categorize our acreage at this point. But that's exactly what our exploration program is designed to do and others are doing it as well.

We're seeing them also targeting second, third benches of the Three Forks. And so in the next 12 months, we're going to see a lot of data build that's going to help us get down that road.

But I can reiterate what we have said before, Marshall, if this helps you, I hope this is helpful. Within that 3,800-square-mile footprint, we have said, we believe, there will be at least 1 deeper bench productive, i.e.

one of either 2 or 3, in some of that area you'll have both of those deeper benches productive. And then in some -- maybe in some sweet spots, you might find the TF4 productive, but it won't necessarily be -- it will be a sweet spot-only type thing.

So that's the kind of guidance we've given before within that 3,800 square mile area, and that if you want to refer to our slide on the website, currently, it's Slide 5 in that.

And I'll just add on to that, this is Rick, because it's an important point. But we're seeing -- let's not lose sight of what's actually happening here.

Right now, evidence is building that supports not only 320-foot inter-well spacing, I mean -- and people are even working it tighter, but we're also seeing evidence, not just from Continental's work, but from others' work, that the lower benches are contributing, and that -- we've got a much broader footprint that's evolving now with these density tests. And so right now, our density test from the South to the North is about 100 miles between the one in the South and the one in North and it's about 30 miles between the East and West.

And when you combine everyone else's in there, we're really -- I'm real encouraged of what we're seeing from a results of the test in these density projects that are going on right now, results from these lower benches.

I wanted to follow up on Brian Singer's question from earlier. But given the better IP rates from these new completion techniques and strong results from Rollefstad and Hawkinson, but also taking into consideration Tangsrud, do you still believe the 603,000 Boe EURs is appropriate across the basin for the Middle Bakken and the benches of the Three Forks?

Well, Pearce, I appreciate the question, that's a good question. We -- I mean, the database for us, as we talked about on these new completions, is really very sparse, even on a industry basis, and there's a lot of options out there that people have been testing and a lot of those have been successful.

So I would say that -- but they haven't had a long production history. So if you're going to change an EUR model, you really need to be able to understand that you can look forward -- to have enough production history to look forward and be able to predict what that decline curve is going to do.

And so I think it's probably a little bit early time for us to think about adjusting that EUR model, and we've got approaching 10,000 wells in the basin that we have access to in the database, and then of course, all our operated, non-operated wells. We probably have the largest database there, and we don't see any real reason yet to move our 603 model, but let me remind you, 603 model is for North Dakota.

We have a 430 model in Montana, because it's a bit shallower and a little bit less pressure, but of course cheaper to drill. So we've kind of -- I guess, at this point, we don't really see any reason to move that.

The completion designs, if anything, probably increase your MVB [ph] because you're getting that oil back faster. And so that's the real benefit of continuing to pursue this testing program.

But it's probably way too early to say whether or not that EUR moves, at least for the data set we've seen.

And then my follow-up is just a housekeeping item. But in Q1, it looked like DD&A ticked up a little bit.

What was behind that?

It's actually down a little bit. It's just the focus of where we drilled last year.

If you look to the fourth quarter, you would have seen that it went up a bit as we were testing some of the fringe areas in the Upper Bakken Shale and some areas and some other concepts. We saw a little bit of a tick up in DD&A.

As we indicated on the call, we expect that to trend down throughout the balance of the year with our focus on SCOOP and higher productivity areas in the Bakken.

And just going back to the Rollefstad pad. The higher initial rates on the bigger proppant volumes give you confidence to create more wells with much greater proppant volumes?

And have you seen that initial improvement sustained over the early production history you've seen, I guess, roughly double the rate in most of your wells?

Well, as Gary said, we've only got 15 to 30 days production on that, so it's probably a little bit too early to tell. In terms of whether or not we're going to do more, yes, we are.

As we said, we've got a 60-well program out there in 20% of our completions and we're looking at whether or not we will upsize that based on the particular testing methodologies that seem to work in a given area. So I think the point is, we have a big program there, it's just very early days for us to say what any additional results are.

We just think the results that we had from the slick water compared to some of the end, combining with some of the other results industry has put out there, that the industry is testing a number of these things and that is going to be significant and impactful for the basin.

So was this performance uplift, due to the higher proppant volumes, a surprise to you? It's -- maybe I'm remembering it correctly, but I thought you had tasted much bigger proppant volumes in the past prior to this year.

So is this uplift meaningfully different from what you had seen in prior tests?

We're pleased.

These were some of our first large proppant amounts that we tasted. And so it was not a surprise for us, that's why we went out and got a larger vessel to test them through.

So we were expecting these type of significant results.

Just kind of a follow-up to similar type question. I mean, what's the main different in costs?

Is it just more proppant and more horsepower, or is this something that the incremental cost could be decreased going forward?

The main cost for the incremental horsepower like you said, the incremental water and then also the incremental proppant. So those are 3 largest drivers.

And certainly, there's additional cost efficiencies that we can see, part of it will come from doing pad completions along with the pad drilling and then part of it will be just continue to optimize as we continue to test various -- different methodologies.

Okay. And then just on the SCOOP.

You all talked about doing some sort of density pilot, I'm assuming just aerially. Are there multiple zones that you all plan to test in the SCOOP play?

I think it's a pretty thick section, so is that part of the test you'll be doing this year, or is that down the road?

Well, good call, Brian. Actually, as we talked about the Woodford -- this is the Woodford interval where we'll do a spacing test.

It's a very thick. Again, it will be up to 400 feet thick, and it has got 2 sort of main zones in it, but it's all within -- we call it within the Woodford Shale.

And so that is one things we'll be looking at, it's how you optimize and where you place the wells in that pilot. We've talked about a pilot when we first enrolled our 2014 program, but the team is still working on what that design will look like.

So I'm going to let them finish their work before we sort of characterize it for you.

As you begin to accumulate a bit more data on the Lower Three Forks, I was wondering, do you have a sense at this point that you might have areas of the play where the completion -- well the ideal completion method could vary substantially between the Middle Bakken and maybe the deepest Three Forks that works?

We are working on that, you're exactly right. And I think Gary alluded to that in his previous comment, that the completion design may vary by zone and it will certainly vary by area -- it may vary by area, say it that way.

And so even within a particular pad, for instance, you might be, I don't know, slick water frac in one formation and something different in another?

Yes, that's a possibility. I don't want to rule that out, let me say it that way.

Sure, sure, fair enough. And could you -- I'm sorry, if this was touched on earlier, I did get on a little late.

Could you talk a little bit about gas takeaway in the SCOOP, just how the status of the infrastructure build-out is in the various parts of the play?

No, we have very good gas takeaway out of the SCOOP. There's several proposed pipelines to move gas to the Southeast that will be coming on if built, and I'm sure they will because they're getting a lot of interest from the industry.

So it should stay ahead of our growth rate that we've got projected. We, as a company, have secured ample takeaway capacity to move out of the basin, as well as furnish gas to our intrastate market that we've developed.

And so we feel real well on keeping up with our growth as we move forward.

And just to clarify, so to sort of what horizon of looking forward would you say you're pretty much set where the capacity is committed and -- there are you good for sure through '15, for instance?

Yes, yes. We're real solid through '15.

We'll be making decisions on other opportunities over the next 6 months to 1 year and new opportunities are coming in everyday. I had a call this morning with another opportunity, so lots of interest in building pipe out of Oklahoma as we continue to grow as an industry and a state.

And so I think we're going to be well ahead of it. And as I said, I'll reiterate, Continental has already secured good space to get out of the state and should take us out through '15 easily.

You talked about how your completion design might vary by zone. In terms of your completions on the Wahpeton unit and the 3 other 660 units later in the year, are those planned for standard completion designs?

Or are those -- are you planning on using enhanced completion techniques on any of the units like you did in the Rollefstad?

It will be a variety. We want to test a variety of different completion techniques in a variety of different areas, and so that will be part of our analysis to test multiple different types of designs in those areas.

So, yes. We'll be testing some new ones, yes.

Okay. And if you look at the 5 Tangsrud wells in both the Middle Bakken and Three Forks 1, as you mentioned those weren't step-outs given other wells you drilled in an area, but how does the 670 IP rate for those 5 wells compare to other Middle Bakken and Three Forks 1 wells nearby in Divide County?

And just as a follow-up, what sort of EUR would you expect for those wells based on other nearby wells that have a longer production history?

Nearby wells in that area tend to IP around 500 barrels of oil equivalent per day. So it's pretty close to the range of what we're in.

And as far as the EURs, it's just real early to be able to tell. So we're just too early to be able to quantify that.

Okay. But I guess, as of now, there's really no sign that there's any communication between any of the 4 zones there, right?

No signs that we've seen at this point.

Okay. And just as a follow-up, did the results of Tangsrud change your thinking at all in terms of how you're going to approach the Lawrence pilot?

Well, as far as our various tests, we're just going to look at these results. We're going to test multiple options and the Tangsrud, we used more the standard design, the classic design, we're -- historically, we've used 100,000 pounds per stage and so as we move forward, we're going to test some of these new designs that have had better results.

First, can you just give us a little bit of color, just refresh my memory on maybe the difference in the thickness of the shale kind of across those 3 different pilots, the interbedded shales? And I guess, if you can speak to -- if you've given any thought or you can give review on whether maybe it's pay thickness or water saturation kind of driving some of the performance if you're using the same fracs as you look at across those pilots?

This is Jack, and I was just going to say that Rollefstad and Hawkinson, the thickness is -- I know you're asking specifically about the thickness between -- of shale between the Three Forks benches, is that correct?

Yes.

Okay, it's pretty comparable then in an area. I can't tell you exactly.

I'm going to say it's 25-foot thick, just my best estimate right now. But the distance between well bores is typically in that 65 foot range.

And so really I don't see a big difference there. What was your other -- what was the second part of your question?

If you're using the same frac effectively methodology, frac recipe, I mean, is it possible or have you seen in your core studies that there's any difference in water saturation or other data that might speak to some of the performance differences that you all saw between...?

Sure, yes. We've said before we see the second bench looks very much like the first bench, as far the dolomite development and the uniformity of it and the fact that saturation could be very similar in many of these areas to the TF1.

But the third bench, as we've always said too, it's a thicker zone. It has more shale interbeds, and as a result, we're seeing -- I think we see lower permeability in there, and I think we do also see a bit higher water saturation in it.

But that's irreducible water, doesn't necessarily mean it's going to be producible. So right now, there are characteristic differences between them that we're working on to determine just how does that influence production, and that's what this exploration program, again, is all about is.

We're trying to assess just exactly what you're saying here, is how would these wells perform? But keep in mind, these are all part of this Bakken petroleum system, and that's what's key here, is that we've defined that there are more oil in place.

And because of the oil in these lower benches and so we're assessing how do we incorporate this in the total development of these drilling and spacing units. I mean, just ride with us here and more information will come as we get more data and more wells drilled.

Okay. All right, good.

I guess the second question I had is obviously the Rollefstad wells were very nice. And I guess, how close is that to the Colter unit?

I guess the Colter unit it looks like it's kind of between the Hawkinson and the Rollefstad pads and, I guess, if you saw some communication that the Colter, I guess, obviously those are different fracs and some different kinds of wells drilled, but, I guess, give me a little bit of color on I guess how you underscore the confidence that I guess putting the bigger fracs in that area that has more natural fractures? I guess, still works and I guess, if that's a clear question, sorry about that.

I'll start. I think it's a good question as far as how will larger fracs affect areas with more natural fractures.

And I guess one thing I would say is the way we're viewing these fracs right now is that its incremental profit that helps connect natural fractures that's out there. And so if you got an area of high productivity, we think those have a great chance to be even more successful by just connecting up the natural fractures that are out there and keeping them propped.

And so we're very optimistic about doing the larger fracs in the better productivity areas.

Okay. So still -- it definitely sounds like a work in progress across the entire basin, but you guys have good results there and we'll keep watching to see what comes out down the road.

Just a quick follow-up question. I know that you guys had a number of pilots on stream in 2013, such as the Charlotte pad and some of the others testing kind of the second and third bench, and I know there's been a quite a few questions on the call so far around this.

But just hoping to get an update as to how you guys are thinking about the productivity there with the data you've seen so far and just wanted to see how that compares to the first bench, if that's still kind of holding to your trends?

Charlotte bench, can you answer that?

I really can't tell you. It's just right now off the top of my head.

I know that the wells are performing very nicely in the Charlotte. We've been always very pleased with the outcomes that we've seen there, both in all the benches.

And so quite frankly, I just can't tell you right now. But I can sure follow-up, we can follow-up and get you the comparison there, but they are strong wells.

Perfect. And then just a second follow-up question in regards to the SCOOP.

I was wondering if you could provide maybe some context around how you think about the percentage of your acreage that you've de-risked so far? And then as you think about this large footprint and the relative economics of this play, how should we think about the long-term kind of drilling potential here from kind of the 18 rigs today?

How large of a program could this potentially become for you?

Well, let me answer the last question first. It's a little bit too quick, too soon to determine how big of a drilling program.

It all depends on the exploration results. So I think it's probably kind of where we sit at the moment.

In terms of what we've de-risked, I think we put out there, that essentially, it's kind of Northwest to Southeast, but we've got about 100, 110-mile play fairway where we're concentrating on the condensate and oil windows of this transition play. And as we move South, we're about 60 miles of that 100 miles, so you might -- you could almost generalize that to 60% de-risk, but that's a little bit over optimistic because we're still exploring in some of those areas because you have sub basins in there where you've got a little bit different complexity there and we're moving -- kind of we're moving East a little bit more into the oil window.

We've yet to test some of that. So I'd say, if I'm characterizing it, we're in that 50% to 60% de-risked on the play, but let me ask Jack if he would...

I agree, that's my number as well, and we're pushing it South.

Just had one quick question on the SCOOP. Going to the spacing tests and the density pilot, are those going to be started off as 1 mile wells or are you going to look to maybe extend your reach on those or maybe that to come down the line?

As much as we can, we're going to the 2-mile laterals.

Just wanted to go back to the SCOOP. It looks like the Green Acres well had a higher oil cut, I guess, than what the type curve indicates.

Just wondering if you anticipate the GUR increasing over time? And how does the Green Acre oil mix compare to the other completions in the other oil window during the quarter?

Well, the Green Acre well is the oil fairway, so that's the first statement. The second statement is, we kind of put out in our general slide pack what the percentage of oil is in the oil window, but that's an average.

So there's a range of oil cuts within that overall window, and that's just the area with a high oil cut. Jack, you want to add to that?

As far as GUR.

Yes, GUR.

GUR increasing over time, we're just going to have to watch. There's going to be a variation throughout the play whether -- what gas there or oil.

So there'll be variations across that, and we'll just watch the GURs to understand how it performs.

Got you. That's helpful.

And that's black oil flowing in the oil window, correct?

We don't talk about condensate, that's in -- we talk about condensate I can tell you that it's pretty transparent within that black oil.

Realizing you don't want to give quarterly guidance, but could you speak, just given the weather issues, to the number of wells completed in the first quarter versus the expectations for the second and third quarter in the Bakken?

Let's see, if we've got it to hand, we will.

Yes, so for the first quarter, for the Bakken, we completed 70 wells. And most of those were completed in the last part of the quarter in March.

And December last year, we went from 6 frac crews to 8 and so the combination of the increased frac crews, as well as the better weather that we expect as summer approaches in the North Dakota, is going to help us complete more wells going forward.

Would it be fair to say in the 90 range would be a fair expectation?

I don't have an exact number.

Okay. Perfect.

Could you guys elaborate on the drivers of the productions versus sales issue, as well if it has to do with filling Continental infrastructure and if this is kind of a more permanent requirement to have these barrels in storage almost like a working capital need going forward?

Well, the storage growth in the first quarter was due to the weather constraints and the increased stricter requirements on rail transport. We're doing a lot more inspection on rail cars and the combination of that and -- so it had fewer unit trains running due to that, plus weather constraints clogged up a lot of that traffic going to the East Coast and back due to the winter.

So when the trains didn't show up, we put the oil in storage, we kept the field 100% producing, we had no -- 0 production curtailment from that end, but we put the oil into storage. That will come out this quarter.

Most of it will be out by the end of this month. So we have that capacity and as we talked -- put in our press release, we built increased storage that we totally control, that compliments what we have that we have leased from, at both the rail terminals and [indiscernible], so we have lots of space now that we can work with.

So weather interruption shouldn't hurt us at all on the marketing end of it, so we'll absorb it maybe during -- just depends how it falls from month-to-month, if it falls on a quarter end or not. But we'll see that go up and down, and we have that capacity to do that.

We can also work market a little bit that way also. So we will, as John spoke to, we will be adding line fill.

There's more and more infrastructure being built out of the basin, and to the extent that we're participating in that infrastructure, we'll have obligatory line fill with that, and that will breath. It will be up and down.

It's not an exact number, but it will be significant throughout the year because there's quite a bit of infrastructure coming in, which is very good news.

And are those line fill barrels sold by Continental before they're in the pipe, or is the third-party marketing company purchase those for the line fill?

No, they are Continental Resources barrels.

Okay. And then last one if I could sneak it in.

On the Hawkinson down spacing test you mentioned, it's 50% above the 603 type curve. Could you compare that to other wells in the area on where their EURs are heading?

It's pretty hard to do that, but I think -- I mean, that's a good area to start with, but I think they are a little better than other wells in the area.

You said there is acceleration clearly in some of the results you had recently with the bigger fracs. If there's no EUR benefit, so just acceleration, does that pay on an NPV return basis for the higher costs?

Definitely.

So you don't even need to see any EUR to make it worthwhile doing?

Correct. The rate of return on that is -- most of the ones that we've done is we've looked at some of the things we've had a little bit better results, like the slick water and some of these larger prospects [ph], the rate of return is quite attractive.

I think we should let Gary maybe talk to the EURs here too.

I'm going to say one more thing. Acceleration means different things, different people.

I think one thing that Rick was talking about just accelerating and bringing forward the complete recovery within a unit to where we're developing in a quicker time. As far as EUR performance and accelerating production from an offset well to a new well, it's way too early in the data to be able to measure those things.

Those things take years to evaluate and we'll certainly be watching for those type of things.

Okay. So basically you're -- effectively your sort of -- that's an inconclusive at this point, but the acceleration makes it worth doing at this point?

Yes. In other words, regardless of the EURs in the well, your rate of return and cash flow economics are really driven by what's produced in the first 6 or 7 wells.

So even if you were to have a significant acceleration component, the significant rates we're seeing right now still results in very good well economics.

Great, great. And for just sake of [indiscernible] , if I could quickly.

For the Tangsrud well, the Middle Bakken and Three Forks results were a little disappointing versus the existing wells. Is there a -- do you have an explanation for that at this point?

No, I'd say that they are really not that out far off line at all with the surrounding wells. What you see up here is you have lower IPs, but much flatter declines.

And so these wells just they perform differently. The permeability is higher here in these rocks, and so they're not -- and the pressure is a bit lower.

So they perform differently than the wells that are right down more near the kitchen [ph].

I just meant that the existing wells, as you said, were 1,015 barrels a day and the new ones were 670 for the Middle Bakken, Three Forks -- for Three Forks, is that not a significant difference or...?

Maybe I didn't understand your question. Part of that also have -- we've talked a little bit about IPs, and how -- it depends how you test them and I'm not sure how those original wells were tested, but the real measurements is going to be more of a long-term production over time rather than just comparing IPs.

Well, thanks everybody for joining our call this morning, and I appreciate very much.