Continental Resources Group Management Discusses Q2 2013 Results - Earnings Call Transcript

Aug.11.13 | About: Continental Resources (CRGC)

Continental Resources Group, Inc. (OTC:CRGC) Q2 2013 Earnings Call August 8, 2013 11:30 PM ET

Executives

John Kilgallon - Director, IR

Harold Hamm - Founder, Chairman and COO

Rick Bott - President and COO

Rick Muncrief - SVP of Operations

John Hart - SVP and COO

Analysts

Drew Venker - Morgan Stanley

Leo Mariani - RBC Capital Markets

Doug Leggate - BofA Merrill Lynch

Pearce Hammond - Simmons and Company

Noel Parks - Ladenburg Thalmann & Company

Noel Parks - Ladenburg Thalmann

Ryan Todd - Deutsche Bank

Joe Allman - JPMorgan

Hsulin Peng - Robert Baird

Brian Corales - Howard Weil

Marshall Carver - Heikkinen Energy Advisors

Paul Griggle - Macquarie

Andrew Coleman - Raymond James

Matt Portillo - Tudor, Pickering, Holt

Ryan Oatman - SunTrust

Good morning and welcome to the Continental Resources second quarter 2013 earnings conference call. I would now like to turn the call over to John Kilgallon, please proceed.

John Kilgallon

Thanks Lacy, and good morning, and welcome to the Continental Resources Second Quarter 2013 Earnings, conference call. This is John Kilgallon Director, Investor Relations. Joining me on the call this morning with prepared remarks are Harold Hamm, Founder, Chairman and Chief Operating Officer, Rick Bott, President and Chief Operating Officer, Rick Muncrief, Senior Vice President of Operations, John Hart, Senior Vice President and Chief Operating Officer and also available during the Q&A session will be Jack Stark Senior Vice President of Exploration and Warren Henry, Vice President of Investor Relations.

A few housekeeping items that we'll cover before going into the forward looking statement. In conjunction with the earnings and our call this morning we have posted a summary presentation of the reference tool. This presentation could be found on our website in the For Investors section under presentation. The slides are also included in the webcast portal for your viewing during the call, if you have not printed yet I recommend you do so now, you may have also noticed we've added a few links to the home page in the upper left hand corner to make all the earnings data easier to find. Today's call will include forward-looking statements that address projections, assumptions and guidance. Actual results will likely differ from those contained in our forward-looking statements. Please refer to the Company's filings with the Securities and Exchange Commission for additional information concerning these statements and risks. In today's call, the Company will refer to EBITDAX and adjusted net income per diluted share. For reconciliation of EBITDAX to GAAP net income and operating cash flows and for a reconciliation of adjusted net income per diluted share to GAAP net income per diluted share, please refer to the section of non-GAAP financial measures in the second quarter earnings release, at the conclusion which is posted on our website at www.CLR.com. With that I'll turn the call over to Harold.

Harold Hamm

Good morning and thank you for joining us today, we're pleased to report strong performance for a second quarter ended June 30th, including record production and cash flow, the key of course was an excellent production growth, second quarter production averaged a 135,700 boe pd, up 43% from the second quarter of 2012. This production growth and additional operating efficiencies resulted in record EBITDAX of 708 million, up 14% from the first quarter of 2013, and 68% higher than the second quarter of 2012. You could refer to the first slide of our presentation, I won't go through each bullet point and be brief here, and then also on the second slide aside from increased production the other benefit over industry leading drilling program is increased proved reserves, our midyear estimate of 922 million barrels of oil equivalent in proved reserves represents a 17% increase over year end 2012 proved reserves of 785 million boe. Consistent with our value creation model and focus on crude oil these midyear reserves are 87% operated and 70% oil, in fact our estimate of proved reserves has more than doubled in the past 24 months.

Finally the Continental team is executing our growth program while improving capital efficiencies and staying within our 2013 capital budget, at June 30th we spent half of our non acquisition cap ex budget for the year, so first I give the team very high marks for their performance in the first half, they're executing at a very high level.

Second Continental is poised for strong performance in the second half of 2013 and extending into 2014, with the opportunity to create even greater shareholder value, we plan to maintain excellent performance completing 2013 as a great first year in a five year growth plan.

Last October you may remember we shared with you this new five year plan focused on building shareholder value by once again tripling production and proved reserves, key objectives for that are, on accelerating development of our oil rich inventory.

Two capitalizing on our excellent growth platforms in the Bakken and SCOOP play in Oklahoma.

Three, generating new opportunities to drive future growth for increasing cash flow growth by lowering operating cost and maximizing net back value of the oil and gas we sell.

And finally, preserving the flexibility and strength of the balance sheet by moderating our levels of spend. We set aggressive per share targets and as I said we expect to achieve them all, we're off to a great start.

Now I'll turn the presentation over to Rick Bott our President, Rick.

Rick Bott

Thanks Harold, I've got two objectives, I want to expand on our operating results a bit and then update you on several other key catalysts for the remainder of the year in early 2014. First, we've set a consistent pace through the first and second quarters of the year with 42% higher production growth compared to the first half of 2012, we're currently as of today maintaining our strong momentum with current production slightly in excess of a 140,000 barrels of oil equivalent per day.

Our third quarter production growth rate however is slowing slightly as planned as we and other operators shift to pad drilling and larger pads in the Bakken. The net effect should be to boost production significantly in the fourth quarter and early 2014, compared with a third quarter of 2013, in summary our 2013 production goal of 35-40% growth year over year can be tightened and moved upward. We're probably headed for the upper end of the target range and will likely generate 38% to 40% production growth this year compared to last year. Now, as Harold mentioned, this is with no increasing CapEx.

Next, we have spoken frequently in the past year about strategic importance of Continental's portfolio strategy in oil and gas marketing, especially the development of strong coastal markets for Bakken crude oil. As the production leader in the Bakken, we also led the way by increasing the use of rail and pipeline alternatives throughout North America, but especially in the U.S.

Our strategy has passed the test. We continue to balance medium term commitments with the ability to sell at spot prices. We continue to implement this portfolio approach to balance rail and pipe transport from the Williston. In August, rail is expected to account for approximately 75% of Bakken shipments. We continue to cultivate new rail customers on the east, west and Gulf Coast to capture the best price as their appetite increases for the premium Bakken barrel.

Finally, volatility will likely be an ongoing factor in oil markets and we will adapt to it.

Now, let's look at the key catalyst on the horizon primarily related to our Bakken exploration program and further delineation and new opportunities in skew. Let me start with the Bakken. You may want to refer to slide five in the deck as we discuss the Lower Three Forks exploration program. We're on target to have all of this year's 20 wells completed by year end, bringing the total program to 22 wells. To recap, our Lower Three Forks' exploration program was designed to one established commercial productivity from the TF2, TF3 and TF4 that means a second, third and fourth benches, secondly, do this over a broad area, and third try to determine that this production associated reserves are incremental to the field.

During 2013, we have completed 14 of the 22 well program and have four wells completing, one well drilling and three waiting to be drilled. It's also worth noting that other operators have completed five Lower Three Forks wells in the Bakken as well. All of these new wells in the Lower Three Forks define a productive footprint covering approximately 3,800 square miles of the play. Our operated TF2 wells have averaged 1,200 barrels of oil equivalent per day in their one day test and the TF3 wells have averaged 970,000 barrels of oil equivalent per day.

Our lower Three Forks exploration program in the second quarter of 2013 also included two TF4 test, one in the Farver spacing unit in the north and another in the Colter spacing unit in the south. The Farver 2-29H4 is located in Divide County and it was completed 480 barrels of oil equivalent per day. This early production level is reasonable given the nearby (inaudible) later. The Farver TF4 well was drilled a 160 feet below the TF1 and provides further evidence that the Lower Three Forks reservoirs add to the volume of oil in place in the Bakken field, although it is too early to determine if the TF4 in this area will ultimately be commercial.

Continental has less than 120 days of production history on the majority of our Lower Three Forks well, but in general, early data indicates these wells are producing in line with typical TF1 producers in each of their respective areas. Some better, some worse, as you would expect comparing at the core data, but on average, they are in line with the TF wells in that area.

To-date, we've tested six areas in Lower Three Forks exploration program for productivity and production interference as shown on slide five. Five of these areas have shown no evidence of production interference. Charlotte spacing unit is one example of these. Slide six shows the location and wells drilled in the Charlotte unit where we drilled TF2 and TF3 producers and then came back and drilled the well in each of the middle Bakken TF1 and TF2 intervals to test for production interference.

The one exception is the Colter spacing unit in Dunn County. The Colter unit is shown on slide seven. On the east side of the Colter unit we see direct evidence of production interference between legacy wells in the middle Bakken and TF1 and the new wells drilled in TF2 and TF4 zones. As we completed the new TF2 and TF4 wells, the Colter 3-14 H2 and the 4-14 H4, we observed reduced reservoir pressure. We believe the pressure draw down is related to the middle Bakken and TF1 wells above them, which combined have already produced 530,000 barrels of oil equivalent to-date.

Slide seven gives us stylized representation of our interpretation. All four wells are vertically aligned within a 660 foot window. We believe this specific location is an anomaly and we postulate the natural vertical fracturing is connected to Bakken and Lower Three Forks reservoirs in this 1,280 acre spacing unit.

The Colter unit is an area of the Nesson Anticline where there has been more pronounced tectonic activity and therefore increased levels of natural vertical fracturing associated with this vaulting. The Colter TF2 and TF4 wells are being put on pump and we will need a few more months of production history to determine if these wells are commercial.

Now, finally, we completed a fifth Colter producer in June on the west side of the unit and it's a strong well. The Colter 5-14 H3 in the TF3 is flowing from Virgin reservoir producing 750 barrels of oil equivalent per day at 3,200 PSI in its initial test period. This shows you that this well 1,350 feet away was not connected to the fracture system.

As to our early conclusions, we expect relatively high recovery rates in the Colter unit and actually need fewer wells to effectively drain areas like this where there is enhanced natural fracturing.

So on summarizing our results to date versus what we set out to do in this program, firstly we have confirmed the resource tank i.e. the production capability of the reservoirs, we've confirmed it's filled with oil, we've confirmed it's not filled with water, it is looking commercial over a very large geographic area where we think that at least one in many areas two of these deeper benches two will be commercially productive.

And third, in some areas natural fracturing will enhance recovery and require less capital to actually develop. So looking ahead to the second half we have about a third of the program left, and you should expect us to complete the eight remaining wells and the lower Three Forks exploration program and then discuss the results with you.

The other significant part of our Bakken exploration program involves four density pilot projects comprising a total of 47 gross wells. These are testing full development at the middle Bakken TF1, TF2 and TF3 reservoirs on 320 acre spacing and three units and on 160 acre spacing and one unit. The location of these spacing tests is again shown in the map on slide five.

320 acre spacing of wells separated by 1,320 feet within zone and offset 660 feet from the joining zones above and below. In our 160 acre projects wells are 60 feet apart and offset 330 feet from adjoining zones. All four pilot projects are proceeding according to plan. Slide five also notes there are seven other density pilots of varying spacing announced by other operators which will help all of us better understand the optimal spacing in each area of the play.

The Hawkinson 320 spacing pilot is our first pilot to enter the completion space, all 11 wells on the pad are now drilled and we're starting the completion process. Completion efforts are being monitored by a cutting edge micro-seismic program, which promises to us additional data to understand how well we're accessing the reservoir.

The micro-seismic program has set many first for our industry and as far as we can confirm the largest monitoring program to date for unconventional reservoirs worldwide. As an example one of these first is the simultaneously monitoring of fracs through three surrounding horizontal well bores. This provides exceptional triangulation capability for accurately mapping fractures propagated by the fracture treatment.

We're also in the process of shooting 150 square miles of proprietary 3D seismic over the Hawkinson site, for further evaluation of the project. We expect to turn these wells to production in November and have our initial interpretation to micro-seismic results around the year-end.

Next will likely be the Tangsrud density project, a 12 well test on 320 acre spacing in Divide County, we expect to report initial results and add production from Tangsrud in January 2014.

Finally, we have the Wahpeton and Rollefstad projects. The Wahpeton pilot is a 13 well test on 160 acre spacing, so wells again are spaced 660 feet apart in zone or twice the well density of the other projects. The Wahpeton is in north central McKenzie County near the Charlotte unit.

The final 320 acre density pilot is the Rollefstad which involves 11 wells and is also located in McKenzie County. We expect to have initial results from both the Wahpeton wells projects in late first quarter 2014.

And finally referring to slide eight, let's discuss the upcoming catalyst in SCOOP play in Oklahoma. We generated very strong production growth in SCOOP this year a trend that should be sustained as we ramp up our drilling program from the current 10 operator rigs to 12 rigs this quarter. In total we've participated in completing 93 gross or 50 net wells. We are encouraged with the results and feel confident we have now confirmed a productive footprint approximately 40 miles north northwest to south southeast in the play.

Along with stellar well results in the second quarter we completed our first cross unit lateral well in the condensate fairway of SCOOP. The Singer 1-18-7XH well in Grady County, this Singer well had a ladder of approximately 90,400 feet in length. The Singer flow 1,915 barrels of oil equivalent per day in its initial 24 hour test, 37% of which was crude oil. Several other excellent wells are shown on the slide indicating a prolific trend.

SCOOP catalyst for rest of 2013 will include more long laterals and further delineation for another 40 miles south in the play. Rick Muncrief will now have more to say about the long laterals versus short lateral economics of SCOOP in just a moment. So in summary, as Harold mentioned we need to thank our employees for the great quarter and then looking into the future we'd clearly have multiple catalyst over the next 10 to 12 months and that means multiple opportunities to drive additional shareholder value for those who invested with us.

Now I will turn the call all over to our Senior VP of Operations to discuss further opportunities, well cost and enhance capital efficiency. Rick?

Rick Muncrief

Thanks Rick. As you know that recognized from our earnings report the Bakken, SCOOP, Red River Units and new venture teams are performing very well continuing to reduce well costs, strengthen our capital efficiency, manage our base assets and identifying new opportunities. The operating group is executing our growth plan at an exceptionally high level. But in addition to production growth and lower well cost, the Continental team is steadily improving our safety performance.

Continental safety program encompasses not only our own employees in the office and the field, but also the people who work for us as contractors in drilling, well completion, production and other key activities.

We also remain an industry leader in the Bakken with regard to reduce flaring consistently experience a rate that is one third of the industry average in North Dakota.

Now let's talk about improved operated well cost. Last October as you recall, we set a goal of achieving $8.2 million completed well cost by year end 2013. This compares to our 2012 average of $9.2 million completed well cost for a single Continental operated well and compares favorably with the $11.3 million per well that we experienced from outside operated wells.

We have now here at $8.2 million targets six months early and we anticipate consistently delivering operated wells for $8 million or less. Thus this is our revised target for yearend 2013. I would also like to note that our completed operated well cost include oil drilling, completion, facilities and artificial lift. Some operators who play don't include all of these in the well cost figures that they discuss with the analyst in Wall Street.

Looking ahead keeping around several key trends as we seek to achieve our $8 million target cost. On the positive side drilling cycle times in the Bakken continued to come down as we move to more pad drilling and as our record improves in key performance indicators like geosteering, down hole motor performance and bit technology.

We have reduced our drilling spud to TD cycle time or 20% or four days from the second quarter of last year to the second quarter of 2013. Our average lateral drilling time has improved by 30%. And the time and cost of rig moves has been reduced significantly as we have transitioned to more pad drilling.

We are also working to reduce cost in such areas as site construction, equipment tool rentals and completion material cost. We're focusing intently on our supply chain management as our activities continue to ramp up. With 70% of our operated rig fleet on multi-well pads we expect additional cycle time and cost improvements.

On top of our efforts, our mid-stream partners are doing a great job building out infrastructure ahead of large pad projects so we can maximize the delivery and sales of produced oil and gas. Those are the positive working in our favor. There are also trends in the other direction.

Completion of pricing are flattened, and in some cases we're seeing upward pressure. Thus we continue to look at our processes. We are definitely seeing incrementally higher cost as we experiment the innovations and completion methods primarily around slick water or gel-slick water hybrid-fracs with increased concentrations of ceramic proppant.

We believe that success of these jobs could have potentially little luck and novel technical solutions, it actually improved margins in this play. Similar gains will be made in SCOOP. We are seeing significant improvement in well cost mainly due once again to more efficient geosteering and other performance related improvements.

Average cost last year ranged from $9 million to $9.5 million per operated wells and both the oil and condensate windows respectively. Today we are seeing those cost in the range of $8.5 million to $9 million for our one mile lateral in SCOOP.

We are seeing an increasing opportunity to shift the cross unit wells over time. We are not completely there yet, but for $13 million to $14 million per well, we should generate twice the production in EUR or more on average for 55% to 60% of an incremental cost. That's a significant boost to our capital efficiency. I hope this gives you a better sense of how we are improving efficiency and reducing cost as we continue driving toward our 2013 production growth and other operating targets.

And with that I will pass the call to our CFO John Hart.

John Hart

Thanks, Rick. Let me run briefly through several mid-year financial metrics. Adjusted net income for the second quarter was a $1.33 per diluted share, beating the Street consensus by $0.08, largely on the back of higher production. EBITDAX also increased to a record of $708 million which was up 14% from the first quarter and 5% higher than the Street consensus.

Our cash flow for the second quarter was also considerably stronger and improving. Cash margin was 73% for the second quarter as we continued to lead our old concentrated EMP peers. Our hedge program is critical to our growth strategy to assure that oil price volatility which we're certainly seeing plenty of that doesn't disrupt the momentum of our drilling program. This is important in achieving our five year growth plan.

Our June 30th hedge position is laid out in the form 10-Q which was out last night. We took a slightly larger than usual one time impairment in this past quarter which relates primarily to our Niobrara exploration program, which hasn't met our expectations.

Second quarter 2013 production expense was $5.86 per boe, slightly higher than 2013 guidance but this mainly reflects slowdowns due to adverse weather in the Bakken and an increased number of work hours. The monthly trend improves sequentially through the quarter, in part due to improved weather in June. June production for instance, the expense for boe was below the midpoint of our annual guidance as we continued to focus on. Our other guidance metrics, production taxes, DD&A, G&A expense, and equity compensation per Boe are within guidance ranges for the year and trending towards the low end our ranges.

Total long-term debt was 4.4 billion at June 30th, so our net debt to EBITDAX ratio was 1.75 times on a trailing 12 months basis and 1.5 times if you annualize the second quarter's EBITDAX. As our spending in excessive cash flow continues to narrow, you should expect to see an even further improved net debt to EBITDAX ratio by the end of 2013.

First half non-acquisition CapEx was 1.8 billion in line with our disciplined growth strategy. The CapEx overspend versus cash flow continues to move in a positive direction. In fact, our expectations for outspend and excessive cash flow to continue to trend downward throughout the remainder of 2013 and throughout 2014. We are focused intently on capital discipline and growing production and proved reserves. Bottom lines were on track to achieve our guidance goals for 2013.

With that I would like to turn the call back over Harold.

Harold Hamm

Thank you, John. If I could just follow-through my own perspective of what we are currently involved in today for everyone very briefly. From my own experience over the past 4-6 year, we're witnessing first hand a great evolution of our industry due to horizontal tight oil development and multistage completions from previously bypass reservoir such as the Bakken, Woodford, Eagle Ford, and Permian Basin promotions. For companies such Continental that have been focused long term on oil development and well positioned to participate in its evolution, the future is extremely bright and enhancing.

We are very excited that Continental had to play a part in this renaissance. In closing I will summarize the first half of 2013. We're half way through a very successful first year of our five year plan and we're on track to achieve our 2013 goals. In the second half, you should expect more of the same in terms of operating and financial highlights further delineation of the lower Three Forks and SCOOP, strong production growth, increase cash flow, strong net income growth, capital discipline, and increased proved reserves as we further prove up reservoirs that we have in the Bakken and SCOOP.

We're getting it done and obviously Continental's achievements are reflected in increased share price and valuation. The entire team is focused on maintaining Continental as industry leading growth in our two premier oil plays. to that end we're currently working on our 2014 growth plan and look forward to sharing that with you in fall.

With that I will hand the call back to operation to being our Q&A. Thank you.

Question-and-Answer Session

Operator

Thank you. (Operator Instructions). And our first question will come from the line of Drew Venker with Morgan Stanley. Please proceed.

Drew Venker - Morgan Stanley

Good morning. John, if you could give us some clarification on the lower Three Forks exploration program and whether you had drilled all of your lower Three Forks wells below existing Bakken and Three Forks producers?

John Hart

Yes, we've got a table out there summarizing what targets we are shooting for you, but yes this whole program has been targeted to valuating the lower Three Forks, this includes TF2, TF3 and TF4. We do have four wells in there that are TF1 well that we're drilling they are basically in the program as interference test wells and essentially been ensuring as we as Rich had mentioned in here what we wanted to do with this program was first to lineate the productive footprint or if basically determine the productivity of these lower zones because before we started this there really was not production from these low benches.

And so we've succeeded really impart one of this that is demonstrating that we've got a productive footprint to cover at least to this point 3800 square miles and so part two this is to demonstrate the reserve for getting here and production or incremental to the pay that's been a big question out here, so we're 65% through drilling hole these wells and our just proceeding ahead as planned and the results we've got at this point are very encouraging because we're seeing consistency of results within areas with the TF1 production in the area and really just the widespread nature of the performance that you think about in this Basin when you combined with Continental has done. We have got 14 producers and then you add two to it.

The wells have been completed by other operators out here. There are total of actually 18 lower Three Forks and that would be TF2, TF3, and TF4 producers within a 3,500 square mile area and the odds of us getting out here and drilling that few wells in that large of an area and getting these kind of results that we've incurred is, I think gives us a lot of confidence in the overall extent for Continental to play.

Rick Bott

So Drew if I could just add one small point to make sure we answer your specific question for the wells that are being drilled in that program they are in units that already have a well in them, not necessarily both TF1 and the middle Bakken but there's another well in those units, and they're also very close to the core control that we had.

Drew Venker - Morgan Stanley

So I guess to clarify, was really getting at you know in the Colter unit you have I think that's definitely true on that eastern part of the basin, there's a lot of vertical fracturing, just curious if this is on a similar basis, the rest of tests you've done, whether they're relatively vertically stacked within 600 or 800 feet or so.

Rick Bott

Actually the answer to that is not necessarily for the exploration program for the deeper benched, that is essentially the proved commercial production of a broad area. When we get to understanding how they're vertically stacked, that's more aligned to the density projects and we're doing four of those and those are shown on the map as well, that's where we're getting that additional data to understand the actual, what's appropriate for full field development.

Drew Venker - Morgan Stanley

Okay, okay that helps. And on the eastern side where you are seeing this extensive vertical fracturing, can you give us an idea of how much acreage you think has similar vertical fracturing? Or how much acreage exposure you think you have?

Rick Bott

Drew, it's way too early to have a feel for that right now, I was trying to put in perspective here when you got 18 producers over a 3500 square mile area it's very, very difficult to go to that detail at this point.

Operator

And our next question will come from the line of Leo Mariani with RBC, please proceed.

Leo Mariani - RBC Capital Markets

Hey, guys just a question on the Charlotte unit. Trying to get a sense on a few of these wells where you have got a Three Forks one and a Three Forks two slightly offset and then a Three Forks two and a Three Forks three, can you give us the distance between those two well pairs?

Rick Bott

Yes, if you would look at slide six, I don't know if you happen to have that the distance between, okay, if you look at that you see the two pairs of wells that are circled there and on the left hand side on the west side of the unit you've got TF 1 and TF 2 producer and those are 660 feet apart laterally and vertically they're going to be about 50 foot apart - the two well bores. The same if you go to look on the east side of the unit there the two wells circled are TF 2 and a TF 3 producer and those are 37 feet apart vertically and 66 feet offset laterally.

Leo Mariani - RBC Capital Markets

I'm just trying to get a sense of how this differs on the spacing from what you saw at the Colter unit here.

Rick Bott

Yes, if you slide over to the Colter on the next slide on slide seven, there you can see that the TF 1 producer that had been there for two years, it produced 230,000 barrels of oil equivalent, it's 660 away from the TF 2 producer laterally and 68 feet vertically separated from that TF 2 producer. And so there is a common pair there that's very-very similar to what you have over in the Charlotte.

As far its distance between vertically and horizontally, and in the Charlotte you can see, we've seen no evidence of production interference, however in the Colter we have seen evidence of production interference. In fact it's direct evidence of production interference here and that direct evidence is, number one we, these wells the TF 2 and the TF 4 well were not capable of flowing.

So that indicated lower bottom hold pressure, and the second thing was that we actually saw frac sand show up in our middle Bakken producer, so that's direct evidence. Evidence here is that we have some more robust fracturing in this particular area here at the Colter that doesn't exist in the Charlotte and when we have this fracturing we've essentially, Mother Nature has enabled the communication of these various layers and benches.

Because historically we have over a hundred pairs of wells that have been drilled out in the basin between the middle Bakken and Three Forks 1, 660 offset and there's no evidence of communication, but here we've seen across the lower Bakken Shale all the way to the TF 2, we've seen communication between these wells and the evidence itself is what it is. I mean, you can see that's it's here, so why is the question and again I think we're on the (inaudible) here and this an area that's structurally more active and in those areas you're going to have areas of more intense fracturing in those areas, we're actually getting assistance from Mother Nature for connecting, multiple layers in here.

Leo Mariani - RBC Capital Markets

Another quick question for you guys. just looking at completions and looking at your numbers, I'm seeing that you guys did 138 completions in the Bakken in the first half of '13, you guys are guiding to 245 net for the year, so should we expect to see completions decelerate in the second half year? And then kind of the same question on the SCOOP, I'm seeing about 17 completions in the first half of the year and you guys are guiding to 55 for the year, so that kind of implies an acceleration, could you just walk us through sort of the dynamic there, am I looking at this right?

Rick Muncrief

You are. This is Rick Muncrief. We are, as you look at our pads Rick Bott mentioned earlier, we have the four density projects. You're going to see completion slowdown somewhat in the Bakken. And we currently have a backlog of about 75 wells that have been drilled and have not been completed yet. And that backlog will grow slightly throughout the second half of the year. And so you're looking at it property, and that's all a function of the pad drilling with our large pads.

Then over to SCOOP, you once again are looking at it correctly. In that we currently as of today we have 10 rigs running in SCOOP and we'll add a couple of more rigs. And we'll be working that inventory down. We typically will have somewhere between 6 and 10 wells waiting at any given time. Some of that is around infrastructure build-out and just trying to time that.

Harold Hamm

So this sets us up for larger completions going into the first half of 2014 from this backlog?

Rick Muncrief

That's correct.

Leo Mariani - RBC Capital Markets

And I guess just last question on crude by rail. You guys clearly are still railing quite a bit of your barrels here as you mentioned. Obviously we've seen a big compression in the Bahrain WTI spread which I guess clearly will hurt coastal pricing versus mid-con pricing. Just wanted to kind of get a sense of what you guys are doing on the marketing side to maybe address that what your ability is to maybe limit some of the volumes by rail and send more by pipe or other means?

Harold Hamm

Leo, we still have some markets. We'll have a pretty broad, biggest premium to the WTI yet. And certainly to those we're going to keep shipment going and when they railed get the volume roll out there so this premium we get is certainly happen as offset pricing cost.

Rick Bott

And also I will just add to Harold's point there is that's also keeping in perspective that both of these prices are nice prices, no matter what benchmark you're looking towards. The net back to the well is nice in terms of translating down at the bottom line.

Leo Mariani - RBC Capital Markets

All right, thanks guys.

Operator

And our next question will come from the line of Doug Leggate with Bank of America Merrill Lynch. Please proceed.

Doug Leggate - BofA Merrill Lynch

Thanks, good morning, everybody. I've got a couple if I may. My first question I guess is to Rick Muncrief. Rick as you've talking about connecting different benches on the eastern side of the play on the Colter unit, does that change your view of recovery rates on the Bakken wells in that side of the play versus your 600 type curve?

Rick Muncrief

I don't think it changes our global outlook on things. We're going to be, as we mentioned earlier, we're going to be learning a lot over the next 12 to 24 months. And what we're seeing and reporting thus far are some of the early indications and some of those indications hip in extremely positive, as Jack Stark mentioned earlier and we can't help a big side of (bad). So from our perspective I don't think it really changes our outlook on our 603 model over time. You may see that as you go to increase density that may come down a little bit. You would almost expect that. But we'll just see how that all plays out. Once again I think we're going to learn a lot not only with here at Continental but across the industry in the next 12 to 24 months.

Doug Leggate - BofA Merrill Lynch

Again it may be a little early but as it relates to the Three Forks test in the five other areas, can you give any indication as to how those type curves look relative to that 603 model also, I realize it in the Bakken model but…

Rick Muncrief

Right, well, it's actually a middle Bakken in the TF1 model. We really have the same model. We have looked across the base on some of the early indications and what you see is a real nice bracketing of those curves. In some cases we have wells that are considerably above the 603 model and then we have some that are quite honestly below that 603 model. But when you put those it layer those on and overlay those with a representation of the 603 from a rate time perspective, it's a real nice fit. It really is. So at this time we're really, really encouraged, but once again, we're 120 days into this.

Doug Leggate - BofA Merrill Lynch

And maybe for Rick Bott if I could squeeze another one, Rick, we've talked about you talking about your wells are at least having your IP rates obviously impacted by that. There is a lot of new infrastructure it seems coming on stream towards the turn of the year. I'm just curious as to what are you with slightly any change in philosophies, two stream maybe going to three stream and opening those all up a bit and, I'll leave it there. Thank you.

Rick Bott

Well it all has to do with the line pressure for the gas you're putting into the line. At the end of the day we are getting better infrastructure built out there. I'd say the key for us in terms of that choking back the wells our goal is we're north and south rollaway across this play. Our goal is to get good engineering signs and good data to try to understand the ultimately best way to develop this field. Not to maximize an initial IP rate for a headline, and at the end of the day the line pressure which you can put the gas into the line is important for us and we make sure that we're able to sell gas first so we have our well hooked up when we test them and flow them. And that is the shift of the choke back that I was referring to in terms of making sure that we're able to capture and value that gas, not flare it and get it right into the line.

In terms of ultimately whether or not we have pretty much established a fairly standard choke size for a production across the basing and that's not really changed. So I don't see any real change to our strategy at this point in time.

Operator

And our next question will come from the line of Pearce Hammond with Simmons and Company. Please proceed.

Pearce Hammond - Simmons and Company

My first question is if you can provide a little more color on the acquisition capital expenditure in the quarter for about $101 million?

Rick Bott

Some of that has obviously gone into plays, so we're not really talking about. So we're going to have to leave part of that just unsaid at this point.

Pearce Hammond - Simmons and Company

And then on that longer lateral SCOOP well, what was the cost there?

Harold Hamm

Pearce that cost came in I believe $13.8 million and 9,500 foot lateral, is actually one of our areas that is little more in the fringe side. And we're very pleased with the results of that.

Pearce Hammond - Simmons and Company

Great and then, Rick, in the Bakken right now kind of a leading edge basis well cost, I know in the past you published that Florida alpha pad at sub $8 million per well. Where are you right now on a leading edge basis on your well costs in the Bakken?

Rick Muncrief

We have seen some individual well cost at $7.5 million on an individual well cost basis.

Pearce Hammond - Simmons and Company

And then last one for me, right now you have got about 70% of your rigs on pad in the Bakken. What do you think for '14 that percentage could be?

Rick Muncrief

It's probably going to be in that 70% to 75% range, at any given time maybe a little higher than that, but I think 70% to 75% is a good spot. We still have got some areas to HBP quite honestly.

Harold Hamm

If I could just pick up on two of the questions that you asked. That acquisition capital that we talked about, just in case you are wondering there wasn't any production associated with that. So that's one point, and the second point on well cost, Rick might want to comment, we're continuing to drive down cost all across the basin, and we've got some real edge game changers in Montana.

Rick Muncrief

Pearson the 7.5 million was a North Dakota well that we've seen on the Montana side we've seen 6.4 million on a completed well cost.

Operator

And our next question comes from the line of Noel Park with Ladenburg Thalmann. Please proceed.

Noel Parks - Ladenburg Thalmann

With the news off your Three Forks wells working, it makes me think as you go forward and you think about the time you are going to be developing across all the different benches, how do you prioritize locations where you might have say five producing zones versus others where you might have fewer but the process of just crowding a bunch of different wells onto the same section might be easier? Could we see a day where essentially in one part of the basin you are doing middle Bakken and second Three Forks and then in another part of the basin you are doing first and third?

Harold Hamm

It's a great question Noel and very insightful. I think it might a little bit too early to give you any guidance, but I can envisage that there once we get a little bit better understanding and get through the various testing programs we have for the Three Forks the deeper bench testing and also these pilot density projects is that you could have multiple wells and then might even have different spacing intervals in different intervals if we see more of that vertical connection that we see in fracturing.

But I'd say as we move in the full field development of the three primary drivers, maximizing the recovery and that will have to do also with the way you complete them. Operating efficiencies and of course the headline for all would be rate of return. Perhaps the next level will be being able to make sure that we get everything hooked up from a mid-stream perspective. So those are probably the four drivers that we'll put into our plan as we start rolling out full field development.

And we're doing a lot of work in some of these areas where we have these density pilot projects and these deeper bench testing to try to understand how we can move into that as quickly as possible.

Noel Parks - Ladenburg Thalmann

And just as a perspective on sort of legacy Bakken holdings you have, if you could refresh my memory, how much of the Three Forks or how many of the different Three Forks zones are in place say across Elm Coulee, for instance?

Richard Muncrief

No, over there you have a got a bit of Three Forks 1 and then you do have the 2, 3, and 4 present. But if you get out towards Elm Coulee, you know there are phases changes that go on in the third and fourth in particular where you really start getting anhydric. So those two become less perspective, but just still end up having TF1 and TF2 is possible candidates down the road.

Noel Parks - Ladenburg Thalmann

And I want to turn to the SCOOP for a minute. I think you mentioned a minute ago that the long lateral you did out there was actually in sort of a fringy area so it sounds like it actually performed because you may like soft going end. Can you sort of update us on your thoughts on the footprint of the SCOOP and where you think you pretty much have the definition established and where you think you are still a frontier to find out there?

Rick Bott

Sure, if you go to slide 8, that shows the SCOOP fairway and as Rick had mentioned earlier we've really focused most of our effort in a 40 miles stretch that's in the northwest part of this fairway and what we see in potential here is that we feel we can take this trend another 40 miles to the southeast. And on this slide 8 you can see there is green which is the oil window, the orange is a condensate window and then that pink color is the gas window as best we know it today, and we continue to work defining that and delineating it. As we get more data it becomes more well-defined, but that's really our visionary and so we are planning and are in process of beginning to test our lease blocks down in this southeast extension of our existing improvement in our de-risked area.

Richard Muncrief

And now with your permission I will just add a point of perspective, and we have talked about this on previous calls. This essentially represents our leasing. It is following essentially that the leasing pattern that we had, we understood to play first in this area and then lease it down to the south. So we're really essentially mainly testing these ideas and moving through an HBP program, a program here as we talked about before, is to really make sure that we follow on and hold these leases. So the point is we're just as excited about what we have in front of us as we have or about what we have already discovered.

Noel Parks - Ladenburg Thalmann

Great, just a last one. Could you comment on what you're seeing for first year declines in the SCOOP and how the economics look like they might stack up against the Bakken sort of over the long-term?

Richard Muncrief

Yes, we see some variability in the declines, we've seen somewhere between anywhere from 25% up to 60% in the first year of production. From an economic standpoint we think that the SCOOP economics are ranged from high 30s up to 80% type rate of return in numbers and so you compare that with the Bakken, in a lot of cases it compares quite favorably to the Bakken. And so we are just really excited about what we are seeing down there.

Earlier when I mentioned the Singer well as being somewhat in a fringy area, the fringy area was still in the 40% rate return. So in essence we think cross unit takes that from a 40 to a mid-60s kind of rate return.

Operator

(Operator Instructions) Our next question will come from the line of Ryan Todd with Deutsche Bank, please proceed.

Ryan Todd - Deutsche Bank

Great, thanks. Good morning, gentlemen. One question on the SCOOP, you talked about adding a couple rigs in the third quarter. How should we think about potential for continued acceleration in the year end and is there a type of run rate that we should think about in the medium-term?

Richard Muncrief

I don't think so. I think the 12 rigs is what we need to get to deliver this year's programs, stay within our capital guidance and then as Harold mentioned in some of his comments we will be laying out a 2014 plans sometime this fall.

Harold Hamm

Yes so in terms of the exit rate, I think as we have guided to the upper end of the guidance you might just look at where we started at the beginning of the year and 38% to 40% growth on that as we finish the year.

Ryan Todd - Deutsche Bank

And then if I could ask one of the Bakken and I apologize I missed it, I wasn't sure if anybody has referenced this, but how much work are you doing on adjusting your well completions in the Bakken on experimental type completions, any thoughts or takeaways there yet and is there much of an impact on well costs would do you imagine?

Richard Muncrief

Yes, we're going to experiment with some slick-water jobs and also some hybrid jobs but just the slick-water jobs, some of the numbers we've seen could be as much as a million dollars or well higher, depends on the size of job. It's just not the pumping cost, but it's the all in cost and our team is looking at pumping a few of those and see if we see any difference in productivity and that's the thing about our business and it's all about continuing to improve your processes and your approaches and as we'll keep you posted as we learned more.

Rick Bott

And laying back to herald's comments, I mean, this is still very-very early days in understanding this horizontal oil renaissance and addressing its reservoirs that's never been producible before, so it's very early days and as we're optimistic that there is lots of technology and lots of great ideas yet to come.

Operator

And our next question will come from the line of Joe Allman with JPMorgan.

Joe Allman - JPMorgan

It's just a question on interference in general. So when we think about interference you are seeing among the various intervals, what are the positives of interference and what are the negatives of interference?

And then following up with that for Rick Bott, what have you seen in the lower Three Forks testing that is encouraging to you and then what so far has been disappointing?

Richard Muncrief

I might just comment briefly on what the positives of interference and some of this area of course on Nesson Anticline, tremendous produce ability in some of wells. We have seen wells 2 million barrels EUR or greater so the connectivity more the nature can give you can be very good. You need to understand it from increased density perspective and so that's the data that we're getting in regards here. Other areas don't have this, you know, all the movement perhaps that causes fracturing and that we need to understand it and that's what some of this is about the second part somewhat.

Joe Allman - JPMorgan

Do you want to address the negatives?

John Hart

Well, the negatives would that if you go out and you have unplanned in appearance, you'd probably have spent some capital that you don't have a preferred rate of return on and you a positive is the inverse of that, that you may be able to understand your reservoir, optimize your capital spend overtime as you develop this and deliver the great program economics.

Richard Muncrief

Yes, Joe, let me then just add to both of those points and also think it in a longer term in a big picture, so there on the Nesson Anticline, we have enhanced fracturing, predicting is important, what that means is as Rick and Harold both alluded to, on a primary recovery, we can probably get that oil with less capital, fewer wells less capital, ultimately you may also want to locate at where we go to for enhanced recovery secondary and tertiary recovery, and you may still need density of wells drilled. If you drill those and get the recovery in primary, the economics for enhance recovery always look better.

But at the end of the day we're looking at maximizing this recovery we've talked before about what the ultimate recoverable is from this play Continental has put out there some numbers using recovery factor of only getting 3.5% of the oil out if we get that up to 5% to 7% of oil where some of these enhanced recovery ideas that are in the future for yet to be tested then there is a large price for us to capture, so part of our efforts we're doing now is for now near term understanding and primary development but also building out understanding for the future.

Then you've asked about lower Three Forks, the encouraging and disappointing, well I'll say in terms of disappointing first, we would have been really nice to be surprised if the core data ended up being anomalous and we had better reservoirs that we saw that was out there but it actually looks like if you take it on a percentage basis though the core program that the exploration guys designed really did give us a pretty good understanding of the Basin and so quite a bit of this is coming in.

In terms of our model, and I am not really disappointed by the lower production rates in the Three Forks for it looks that way now but again back to Harold's point and that vision he's got is that this is the few years in a multi-decade understanding of how the developed and conventional oil in horizontal well play, tight oil pay, and so I'm quite confident that we will in time figure out both the terms efficiencies and in terms of technology to be applied ways to produce that oil.

The big takeaway and what we try to determine in this program is, is a full of oil all way across play or should we expect water in those intervals and the good news is it's full of oil, the second good news is, is there are these good producible goals in mind that we already know how to frac pre-well in all of those intervals.

There will be heterogeneity within them across areas but the change is relatively gradual and so we think it's going to be quite predicable and so we're upbeat we just know we've got a lot of work to do there.

Joe Allman - JPMorgan

And do the data you've gathered, in particular the interference data, does it cause you to rethink your drilling and completions of your primary wells on your acreage?

Richard Muncrief

Well, there is a couple of things that we probably are going to look at and think about testing and it's probably really too early to layout that out there for you because we need let the engineers and the geoscientist do a little more thinking, but we're always challenging even our own internal conventional wisdom to make sure that we're pushing the envelope and making sure we're getting the right data to be able to answer those questions.

So I'm very excited about these density pilots. We're doing some new things there. We talked only about the micro seismic but there's a lot of things we're doing in the completions that if they prove out will, may cause us to go back and think about how we develop and that's why the headline we use is, we lump it into that statement full field development but that's what we mean is, how we're going to prosecute the development of a given area and we're thinking about a sort of a township development. How do you do, what's the most efficient and effective and cost effective way to responsibly produce within that township and that covers a large area and so the guys are working on that, they're coming up with a lot of ideas all the way from what's going on in the sub surface to how they operate and how they, and even down the road end up working these wells over, so there's a huge effort going into understanding this and the planning that will come out of that. Rick, you want to add anything to that. Jack, would you like to add.

Jack Stark

One thing I might add there quickly Joe, is that in those areas we have an appearances of great area for acceleration of production and also not only, it's impactful in two different ways, the first of course production the other one is the information we're getting on reserves, as we go forward with this increased density, so very impactful in both those areas.

Joe Allman - JPMorgan

And just a quick one for Rick Muncrief. I think, Rick, you mentioned completion cost increasing, were you specifically talking about completion costs increasing because of the way you're doing things or are you also citing some pressures and service cost pressure just because of capacity or what have you?

Rick Muncrief

I think you have two components there and the first is we think in a lot of cases some of the pricing has bottomed out and so what it causes us and our service providers to do is look at unique ways to work more closely together to drive out inefficiencies and thus we'll see lower cost from that. The second part is where we've seen the opportunities for us to try some of these different approaches to our stimulation. For instance I mentioned slick water fracs up in the Bakken, where we would use a 100% ceramic, versus our traditional 60-40 where we're pumping you know 60% sand, 40% ceramic, you'll see some additional cost on those particular jobs, and then we'll just evaluate the results of those jobs and adjust or not, based on those results.

Operator

And our next question comes from the line of Hsulin Peng with Robert Baird, please proceed.

Hsulin Peng - Robert Baird

Good morning, everyone. So I have a quick follow-up to the type of experimentation you're doing with completion stimulation. So how much experimentation have you done and have you seen evidence of better production EUR from your experimentation? Just trying to understand it in terms of the cost versus incremental return from that experimentation.

Rick Bott

Hsulin, we have not done many of those yet, we're still early on, we're going to be pumping a few more, actually the team was meeting again today to finalize some additional design parameters and this is just something we'll just have to share with you in the future, we really don't have a lot of data today.

Hsulin Peng - Robert Baird

Okay, that's fair and then the second question is on the SCOOP. So on your first cross level well, the 1915 IP rate, given that you mentioned that you expect production to double I was just wondering for modeling purposes, is the 1915 a good IP rate or do you expect that number to increase given that it's also in the fringy area like you said?

Rick Bott

Well that was the actual production average for the first several days of that particular well, we think that's pretty indicative of that area and we've also have some, if you look at the map on page eight, we can see where that senior well which is the northwest piece of our acreage in that particular area, central part of our acreage. If you go to the southeast you see a number of black dots, those are producers that we have drilled and completed and that's a very nice area for us and those rates, we've had several 640, so one mile laterals that had rigs so similar to that. I mentioned you'll see that Vanarkle right above that is Ersky and right below that is 2000 boe per day rate from 640, so we've encouraged by what we're seeing in that area and we're also encouraged by the fact that we were able to drill that first nearly 10,000 foot lateral from spud to TD in 53 days and the job went very well, so we're encouraged about what our cross unit opportunities in the future look like.

Hsulin Peng - Robert Baird

Okay and then the last question just on crude by rail marketing given the compression we have seen with Brent and WTI, I was just actually wondering are you seeing lower rail costs to sort of make up for that compression, just can you comment on that? Thanks.

Rick Bott

We have not seen any reduced rail cost yet, however, we anticipate as we talked about that those differentials will be volatile and they will have probably moved considerably when the additional pipelines that have already been planned and published when those come out. So you'll probably see those things move around quite quickly when those things come on stream and the market re-adjusts.

To handle that volatility, we have adapted this portfolio approach and we try to maximize what we can do on spot as often as we can so that we can take advantage of those and be as agile and nimble in the market as we possibly can. As well as continuing our efforts working with end user refiners, helping them understand the value of the Bakken crude, the consistency of the Bakken crude and our ability now as the largest producer to get them a growing supply also our ability by rail to get them a barrel that is unblended and therefore they can count on the quality.

So, in the future, we do anticipate that the whole package of rail cost will come down because we think rail has a long term home in the distribution of crude within North America because of the differences and optionality that it provides you but it will have to cost competitive with the pipelines as those come on and as they reach to major refining centers.

Operator

Our next question comes from the line of Brian Corales with Howard Weil. Please proceed.

Brian Corales - Howard Weil

Just a question on the pilot programs, when do those come on and also have you all seen anything I know where you are on the drilling side. But have any of those wells you've seen not over pressured reservoirs like you may have seen in Colter?

Rick Bott

To your first point, the Hawkinson comes on in the fourth quarter and then the other three density pilot projects will come on from the beginning of the year through the end of the first quarter. We have not seen any interference issues yet and that is because we are drilling these all at one time on each pad and then we will clean them all at once and put them all to production at once. So we won't have that data Brian until we actually go to production and put everything through and then get it all along. So it will be sort of come in big batches of information as well as production if you will.

So unfortunately there is no information yet in terms of interference. I will say that in all those units as we drill them we're getting good shows, the type of shows that we expect. And so it's a type of thing that makes you confident that you're on the right track.

Brian Corales - Howard Weil

Okay and so you all should get a real big surge of production kind of throughout first quarter of next year?

Rick Bott

That's correct.

Unidentified Company Representative

Yes sir.

Brian Corales - Howard Weil

Okay…

Rick Muncrief

Brian, its Rick Muncrief. One other pad I may mentioned is one that is not either a lower bench test of is an interference test that's our Atlanta pad, which is in a nice area as well and they are in Williams County. It's a 14 well pad. We've got the first 11 wells drilled. Actually the first two wells we drilled are now on production. We did simultaneous operations there. We actually got chance to host Secretary of Interior earlier this week and real proud of what we're doing there. And so that's another pad that you're going to see coming on about first year and we will see some nice production growth coming out of all those.

Brian Corales - Howard Weil

Is that going to be the new norm, 14 well pads?

Rick Muncrief

Well, we've got pads that go from four well pads all the way up to couple of design that have a two on the front of them, we're still trying to finalize those, so pretty exciting.

Operator

And our next question will come from the line of Marshall Carver with Heikkinen Energy Advisors. Please proceed.

Marshall Carver - Heikkinen Energy Advisors

So the well costs in the Bakken are coming down a little more than expected, faster than expected. In the past you talked about using some of that savings to accelerate in the SCOOP but we're not seeing any changes to the SCOOP completions per the press releases from Q1 to Q2. Do you think there is some downside potential to the CapEx guidance for the year or an uptick to the SCOOP completions number or is it more that you're going to be drilling wells in the SCOOP but not completing?

Rick Bott

Well, we've been for sure making sure that we're right on target with our budgets, and that's working out very well. There is some adjustment among other than problem beyond our savings in the Bakken has allowed us to do some more longer laterals (inaudible) and SCOOP and drill another well or two in SCOOP and we are seeing production ramp up accordingly in the SCOOP area. So anyway if there is some adjustments and the problem then that's why our production guidance has moved up.

Unidentified Company Representative

I guess one point too Marshall. I think we gave you all those net well additions last quarter when we talked about the major savings we achieved in the Bakken to get more net wells and we were going to ramp up pressure in SCOOP so as that news is kind of already out there. we told you about that last quarter. And so…

Marshall Carver - Heikkinen Energy Advisors

In the Nesson Anticline area, about what percentage of your Bakken acreage is in that area where you would expect to see the more pressured rock?

Harold Hamm

We have pressured rocks across most of the Basin, what we're seeing on this (inaudible) of course is more natural fracturing due to this structure. So Jack do you want to answer that?

Jack Stark

If you go to say like slide six, there you can see the Nesson Anticline, this is a structure map and it shows the Nesson Anticline along that arrow. And that is the area of more intense structuring. And you can see where our acreage lies along that. So right now you can look and it's a small percentage of our total acreage when you look at what we have into the North and to the West of there. But what I want to caution about is that in here when we look at these like a culture we have an area here we have fracturing but taking into consideration the well to the west that was drilled here the Three Forks producer that was completed in the culture unit and is producing from Virgin reservoir pressured rock. And so these areas of fracturing might be very localized and I expect that they are.

And therefore you will have some of these areas that we had linear in nature and could run for several miles, but they may only be a half mile wide. And so you are fortunate when you get into these, but the question we have right now is just how pervasive are they? And so we're acquiring 150 square mile of 3D data as we speak right across our Hawkinson and culture area and hopefully that will help us be better define types of fracture plays. I just mentioned there is a well out here that kind of depicts, is kind of poster child for fractured producers out here, it's the USA 2D-3 that drilled very early in the early in the play, and that well has produced 1.4 million barrels and are still doing I think 200 to 300 barrels a day. And that well was never fractured stimulated, it was producing from a natural fracture zone.

However there is a bunch of wells drilled around there that have never seen any production like that. So these fracture trends can be very localized and very sweet, so we have got a lot to learn, we have only got 18 producing wells out here as I said before in these lower benches. And so we have got a long way to go but we're seating ahead.

Operator

And our next question will come from Paul Griggle with Macquarie. Please proceed.

Paul Griggle - Macquarie

On the down spacing front, as you guys look to the back half of the year and into the first quarter of 2014, what do you need to see to confirm the success or the challenges in terms of micro seismic and production history and what level of EUR decrease would be acceptable for the program?

Rick Muncrief

There is a lot of questions in there, we may miss some of them, but let's try. Well success of course is going to be a nice big production bump as the near term success. I think the key for us then is to look at that over probably half year and just look between the various wells and see if there is any difference and then try to tie that back to the way we understand the fracture system and the completion technology. Now the micro seismic and the 3D seismic are going to play into that because that's going to help us then.

As I said with this really interesting way we've designed the micro seismic we're now able to triangulate and watch these fractures grow and look at the length as well as the direction. And then you got to model that over time as the pressure comes down as you produce these, so there is going to be a lot of information here for us to pull together to determine how best and this is all really trying to determine how best we then go out and plan kind of fulfill development in the areas that I talked about before, that have the best rate of return in nationalizing our operating efficiencies.

So we're quite bullish on that but we just away for those results. I think Harold has something to add.

Harold Hamm

I might add something you mentioned to EURs and what was acceptable to us. You have to understand within those units that number one, you are drilling on acreage already paid for them by the first well. Number two, you have got facilities already in place that that's there by the first well. So obviously you could feel tensed from low EURs. We don't expect that and these lower benches, very early results show similar type production, and this is the national thrust of producing these lower benches, we obviously had a lot of production in Three Forks 1, lot of history with it now, since we first drilled our first well there and started by on this course.

The second and third benches I think we'll get just as efficient in those completions as we have in the first one. So we expect I wouldn't say decreasing results, decreasing EUR is going to occur here.

Paul Griggle - Macquarie

And then just a quick follow-up on the Three Forks four test. Only doing a couple in this program, would it be fair to assume that in 2014 there would be additional either three or fourth bench test occurring as well.

Jack Stark

Yes there sure is we will obviously monitor results but we're also continuing to put together our stratigraphic model across the basin here and mapping of these various benches and what we feel is warranted, we will probably have a few more test, to test the viability of the fourth bench.

Operator

And our next question comes from the line of Andrew Coleman with Raymond James, please proceed.

Andrew Coleman - Raymond James

Good morning, folks and thanks for taking my question. The question I had was as you think about the design of the micro seismic, could you elaborate just on the number or locations that you're putting all the different monitor wells or monitoring devices to get a sense of how complex that grid is going to be on all these different pads?

Harold Hamm

Well, we are probably going to talk more about that next quarter and a quarter after actually we have to, we have some results. But Jack can you answer that?

Jack Stark

I think you might be asking how often or how regularly we going to be using this but we've got other plans in mind. But I can speak specifically right now to the Hawkinson, if you like to do that.

Andrew Coleman - Raymond James

Yes. Please.

Jack Stark

Sure, and then in Hawkinson, we went in here and we had - we are drilling 11 wells and four of those wells were actually micro seismic monitoring horizontal well bores that ultimately we will be completing as producers. And we had one in the middle Bakken, one in the TF2 and two of them in the TF3 and the idea here is that, and we have done this and are doing this right now. We would monitor the fracture stimulation of a well from three vantage points. We had three well bores that were being micro seismic, that were three micro seismic monitoring well bores active at one time.

And by doing so we end up with just an exceptional database that allows us to really triangulate and properly place the fractures that are propagated from these fracture stimulation treatments. And so we've done that. We've mentioned before, this is probably the largest micro seismic project that's going on worldwide. We've have had folks all over the world involved trying to design and get this in place. And so we are setting a lot of records as far as what's being done here mechanically but bottom line is that we could have upwards of 300 stimulations monitored in this basically 1280 unit. And so we are going to get a lot of data here and that is in turn going to allow us to, as Rick has said what we're trying to do here is, we're really trying to determine what is the optimum well pattern, what's the optimum well density and what's the optimum way to develop basically the container of oil that's here. When you think about it, we initially thought that the oil container was middle Bakken and Three Forks one only, now we recognize as Three Forks 2, 3 and 4 and so the container is bigger and we are trying to find the most efficient way to get the maximum amount of oil out of these units.

Andrew Coleman - Raymond James

Okay. Great. As you think about getting these wells and once they all start producing, have you thought about, 40 as a possibility or how could you extend the life on that micro seismic to kind of accomplish same sort of thing?

Jack Stark

These micro seismic well bores are being converted to producers and so we won't be doing any more monitoring right here. But that's down the road maybe.

Andrew Coleman - Raymond James

Okay, all right and how much of the potential, the new information from all of these testing is factored in or it is to risk numbers that you all talked about in your analyst meeting last year?

Harold Hamm

Not sure we understood your question Andrew.

Andrew Coleman - Raymond James

You have all given a total well count for the Bakken and Three Forks locations. How conservative were the risking factors you used on those well counts last year or should we just wait till closer to year end and the start of next year to kind of get a refresher on and what some of those numbers could look like?

Jack Stark

Yes we're are working at refreshing it as we speak here; I have got some additional information here from the wells that are being drilled so we continually are looking at that. So as far as risking, essentially the risking that was done was just what percentage of the acreage we thought was respective at the time.

Operator

Our next question comes from the line of Matt Portillo with Tudor, Pickering, Holt, please proceed.

Matt Portillo - Tudor, Pickering, Holt

Good afternoon, guys. Just one quick question for me, in terms of the Three Forks wells you've drilled, I was hoping to get a little bit of color on how you think about the productivity and the EURs versus the middle Bakken and kind of on average in the play?

Richard Muncrief

Matt, this is Rick Muncrief. What we mentioned earlier is we have had a nice range. If you look at our 603 model, we've actually overlaid the actual performance of our lower benches from the - primarily the TF2s and TF3s so far, and what we've seen is really a nice fit. It does bracket, we have got wells that are well above that 603 model, and we got some that are below it. But when you put it in a graphical representation it gives you a fairly high level of confidence that on average we're just 603s, it's a pretty good number.

Matt Portillo - Tudor, Pickering, Holt

Well just asking a different way, if I just completely separated the Three Forks versus the middle Bakken, could you give us a little bit of color on how you think about the relative economics of those two plays and maybe where they stack up in terms of the productivity on that Three Forks well on average versus the productivity of a middle Bakken well on average? Is there a big difference or do you guys see that pretty similar? Just trying to get a picture on that.

Rick Bott

Yes, there is really no difference on that and we've got areas where clearly the middle Bakken are stronger than nearby Three Forks and we've got the inverse also true. We got so much stronger Three Forks wells in the middle Bakken, so we really don't see an aggregate significant difference.

Matt Portillo - Tudor, Pickering, Holt

Thank you and then just lastly in terms of the SCOOP play, as you guys delineate this acreage position, I was hoping to get a little bit better picture on maybe how you think about the acceleration case here and with that acreage delineation you have at the moment, how do you think about the optimal rig count? Or is it a little too early to talk about that?

Rick Bott

I think we're going to release some of plans out later in the fall when we talk about our 2014 budget and our top priority number one is SCOOP as put together a very large acreage position in similar what we have to do few years ago in the Bakken is our top priority will be to HBP that acreage.

Operator

And our final question will come from the line of Ryan Oatman with SunTrust. Please proceed.

Ryan Oatman - SunTrust

Good morning. I wanted to talk a little bit more about these SCOOP wells, the initial rates were up pretty good quarter over quarter. Normalizing and kind of excluding the extended reach lateral, can you talk about what you are doing there and what you're seeing from 30, 60, 90 day rates on these wells? I understand some others in the play seeing these wells pretty flat over initial production periods.

Rick Muncrief

I do agree with some of the early assessments. We do have variability but by and large we're very pleased with the 30, 60, 90, and 120 day rates on these wells. We have had some, actually where the 90 day rate is an essence flat to the 30 days rate and so you're not seeing tremendous amount of decline, there is some reasons for that. Sometimes that may be infrastructure related. Sometimes it's just the fact that you've got these are great wells.

And so we're real pleased with what we're seeing thus far and the board is sharing more in the future.

Operator

Ladies and gentleman, this concludes our question and question portion for today's call. I would now like to turn it over Mr. Kilgallon. Please proceed.

John Kilgallon

Thank you Ashley and thank you all for joining the call this morning, we did run a bit long today but we didn't see others had calls behind us, so we appreciate you saying with us and we appreciate all the great questions. If you have additional follow-up, please reach out the Warren and I. Thank you for this morning and this concludes our call.

Operator

Thank you for your participation in today's conference. This concludes the presentation. You may all disconnect. Good day everyone.

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