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Continental Resources (NYSE:CLR)

Q4 2012 Earnings Call

February 28, 2013 10:00 am ET

Executives

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

Winston Frederick Bott - President and Chief Operating Officer

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

Richard E. Muncrief - Senior Vice President of Operations

Jeffery B. Hume - Vice Chairman of Strategic Growth Initiatives

Jack H. Stark - Senior Vice President of Exploration

J. Warren Henry - Vice President of Investor Relations

Analysts

Ryan Todd - Deutsche Bank AG, Research Division

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

Abhishek Sinha - BofA Merrill Lynch, Research Division

Gilbert K. Yang - DISCERN Investment Analytics, Inc

Brian M. Corales - Howard Weil Incorporated, Research Division

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

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

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

Rudolf A. Hokanson - Barrington Research Associates, Inc., Research Division

Sven Del Pozzo - IHS Herold, Inc.

Eli J. Kantor - Iberia Capital Partners, Research Division

Gail A. Nicholson - KLR Group Holdings, LLC, Research Division

William Richards Kindig - Keeley Asset Management Corp.

Operator

Good day, ladies and gentlemen, and welcome to the Continental Resources Fourth Quarter 2012 Earnings Conference Call. This conference call is being recorded.

Today’s call will include projections, assumptions and guidance that are considered forward-looking statements. Actual results will likely differ from those contained in our forward-looking statements. Please refer to the company’s filings with the Securities and Exchange Commission for additional information concerning these statements and risks.

Chairman and CEO, Harold Hamm, will begin this mornings call; followed by President and CEO, Rick Bott; and Chief Financial Officer, John Hart. After their remarks, we'll have a question and answer period. Other members of management are available to answer your questions.

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

Harold G. Hamm

Good morning, and thank you for joining us today for Continental's fourth quarter 2012 earnings call. One year ago, I spoke with you on our 4th quarter 2011 conference call about our company's move to Oklahoma City and my vision of Continental's future as an exceptional company. I know that our world-class asset positions, the world-class operating results and I spoke of our world-class team of people at Continental and how we were rapidly building out and strengthening that team across the board at all levels, adding key skill sets to take the organization to the next level of growth.

Finally, I laid out a growth plan for 2012 that we believe would generate exceptional value for shareholders. Well, we've completed 2012, and it was without a doubt a transformational year in Continental's 46-year history. As I look back on what we accomplished this past year, I'm more excited than ever at Continental's growth opportunities. We're the leading leasehold owner and producer in the Bakken and an unmatched opportunity in the nation's most exciting oil play. The massive crude oil resource that is literally changing the world, therefore, world-class.

The Bakken is the lynchpin of the American energy renaissance. Because of the Bakken, for the first time in memory, we are having realistic conversations about North American energy independence across the continent.

Then there's SCOOP. At our October Investor Day, we unveiled our latest exploratory gem and there's a massive new oil resource play in Southern Oklahoma with all the trademarks of a classic Continental discovery. Therefore, it's oil rich, a contrarian and challenging geologic concept, an opportunity to leverage Continental's unique expertise in horizontal drilling stimulation and again, decades of running room.

As excited as we are at what we've accomplished this past year in SCOOP, we just barely begun to scratch the surface there.

One year ago, this play was hardly more than conceptual. Today, it's one of the most exciting in Oklahoma. I repeat, Continental is better positioned today for growth and exceptional value creation than at any time in our past history.

Let me review 8 of Continental 2012 accomplishments to show you what I mean, especially as last year's achievements set the stage for 2013.

Number one, as we announced last night, we generated record production, growing production 58% in 2012 and propelling Continental to be the largest oil producer in North Dakota and the #1 producer in the Rocky Mountain region. Record EBITDAX and record net earnings for 2012, the strongest operating and financial results in our history. That growth momentum continues in early 2013.

Number two, aside from strong production growth, the key driver of 2012's higher earnings was increased operating efficiencies, as we transition to multi-well ECO-Pad drilling in the Bakken and even faster cycle times. Continental continues to lead as a low-cost operator in our key plays.

Number three, another critical accomplishment was the tremendous progress we made in marketing our royalty premium markets on the east, gulf and West Coast of the United States, overcoming those transportation bottlenecks in the Bakken and at Cushing and securing premium prices for a consistent high-quality sweet Bakken oil production. Without question, the past 12 months was third of that in the establishment of multiple new refinery markets on the coast for Bakken oil.

This significantly impacted 2012 realized prices and earnings, and we expect it to continue helping us improve earnings growth in 2013 and beyond.

Number four, we've continued to expand our strategic acreage position in our 2 leading plays, increasing the 1.1 million net acreage in the Bakken and 218,000 in SCOOP at year end. We've built an exceptionally valuable inventory of drilling opportunities for future years. We refocused our efforts in operations by selling mature, non-core properties and increasing our Bakken and SCOOP footprints which provide faster growth for Continental.

Number five, we significantly de-risked the Bakken play both geographically as we explored new areas west of the Nesson Anticline and vertically as we established productivity in the second and third benches of the Three Forks formation.

Number six, we increased proved reserves to 785 million barrels of oil equivalent and a year-over-year gain of 54%. With 2012 gain, we've grown proved reserves at a compounded annual growth rate of 45% since year end 2009. We expect another very strong year of proved reserves growth in the Bakken and SCOOP play of Oklahoma.

Number seven, we supported our industry-leading growth and higher rate return projects with 2 record-setting bond capital raises totaling $2 billion, with record low rates of 5% and 4.625%.

And finally, number eight, we achieved all these impressive accomplishments in 2012 while completing the move of our headquarters down Oklahoma City. We resettled 100 employees and their families into new homes, new schools and our new headquarters building downtown. The move has dramatically increased our ability to attract seasoned oil and gas professionals with the skill sets that could help us move in the next level of performance.

We've added strength at all levels of professional disciplines and management.

2012 was truly a transformational year for Continental. But now, what about our opportunities in 2013? First, the Bakken. We once again focused more than 2/3 of our CapEx on development and exploratory drilling in the Bakken. Our priorities for the new year are, we plan to extend the viability of lower Three Forks benches through accelerated productivity testing, interference testing and pilot density projects, you should expect a steady stream of news on these exploratory programs quarterly throughout 2013 to 2014. And we plan to keep driving down well cost with the end of year target of $8.2 million per well average for all wells in the Bakken. We will continue transitioning our drilling program to efficient ECO-Pad as part of the manufacturing process we've begun. We are focused on capturing maximum value from our Bakken barrels as we market our oil through the most efficient combination of pipe and rail to premium markets, wherever that may be.

The other key catalyst is, of course, SCOOP. We plan to expand our current 6-rig fleet to 12 by year end, developing and extending the play and turning acreage into oil and gas production. We expect to see continued strong production growth with our emphasis on crude oil and natural gas liquids as we develop in this historic oil province of Oklahoma. The priority around which all these pad lists [ph] evolve, of course, is shareholder value. We've been later in creating shareholder value since our 2007 IPO and we expect 2013 to be another stellar year as Continental's exploration team remains very active in its quest to find large fields for the company's interest.

Now I'll turn the call over to Rick Bott.

Winston Frederick Bott

Thank you, Harold. This morning, I'd like to examine in little greater detail some of Continental's fourth quarter operating achievements, specially as they indicate positive trends we are carrying in 2013 as you mentioned.

We achieved record production of 107,000 barrels of oil equivalent per day in the quarter, comprised of 70% crude oil. We estimate liquids, if you count liquids as a percentage of total production, would be more than 80% if our NGLs reported in our natural gas stream were reported separately. This strong production growth continues into this year, and we are on track in 2013 to deliver 120,000 barrels oil equivalent per day and for February.

We kept you abreast of our efforts in controlling cost throughout 2012. This disciplined approach allowed us to maintain our CapEx budget for the year and remain a margin leader in our key plays. In addition to execution, our commitment to operational excellence and safety remains the top priority at Continental. And we outlined for you at last year's Investor Day the efforts we are making to build our organization for the future. We have an extraordinary opportunity set ahead of us, and we plan to deploy capital in a highly efficient manner as John will give you more detail on later.

Speaking of capital, our work -- well cost in the Bakken continue to be among the lowest in the basin. However, we still have a goal to drive them lower. As Harold mentioned, our goal is to drive down average well cost by $1 million to $8.2 million by year end 2012 and we are already well on our way. To do this, we will focus on improvements in drilling cycle times, increased transitions to pad drilling and further optimization of completion design.

Our oil price realization are continuing to improve as well. Looking back on 2012, with a volatile year for crude oil realization across the country, including the Bakken, where dedicated pipeline capacity was constrained, thanks to the leadership provided by Continental and others, a fundamental change occurred in the basin with the emergence of multiple true real markets, new loading facilities across the play and the proliferation of offloading facilities at end-user refineries on all 3 coasts. Logistical bottlenecks created market opportunities, allowing rail capacity to grow and become the primary mode of shipment out of the Bakken. Continental was the first mover in getting Bakken crude in many of these markets, which helped drive 2012 realizations from above $12 per barrel in the first quarter to $3.25 or just under in the fourth quarter.

Now the capacity exceeds production and competitive markets are enabled, Continental has increased rail utilization and has access to refineries and markets throughout the U.S. These refineries prefer the highly consistent and premium crude quality of the low- to mid-40 APIs and extremely low sulfur and bottom content of the Bakken crude barrel.

During the year, we grew rail shipments to 72% of our Bakken oil in December from a starting point of 46% in January. As an industry, we are displacing high priced foreign crude on all 3 coast. And by switching to low sulfur Bakken crude, refineries can potentially help meet stricter, clean air standards.

We believe in time as the true growth potential of the Bakken is recognized, Bakken crude will become a North American and global suite benchmark.

Continental is one of the few operators, given our scope, growth and flexibility in the play, that can fully capitalize on this trend and deliver a reliable, growing supply to even the largest refiners on the coast.

The other key piece in the transportation puzzle last year, which gets a lot fewer headlines, involve the ongoing emergence of what we call the first mile gathering system at the wellhead. We focused a great deal of effort the past 2 years on first mile hookups to ship oil and gas directly from the wellhead to pipe and rail loading facilities in the Bakken. This effort has allowed us to again set the pace for industry in reducing flaring in the Bakken to approximately 10% or less of Continental's operated leases. With the expected reduced volatility and now improved visibility and access to pipe, rail and personnel infrastructure, we are narrowing and lowering on 2013 guidance range for differentials to $5 to $7 off with WTI. This represents a 37% improvement on our previous estimates.

Now let's shift to exploration development activity in the Bakken and SCOOP plays and the key catalysts for the year. 2012 was a tremendous year for us in the Bakken. Average daily net production grew 64% from fourth quarter '11 to fourth quarter '12, to 67,500 barrels of oil equivalent per day. And we essentially doubled proved reserves year-over-year to 564 million barrels of oil equivalent for the Bakken.

Our acreage position grew 24% year-over-year to approximately 1.1 million net acres. We established production in the second and third benches of the Three Forks, and our program to further delineate and de-risk these lower Three Forks benches is accelerating rapidly in 2013.

We are also continuing to transition our drilling program to a more efficient pad drilling. We currently have 21 rigs drilled in the field, 14 of these are on pad, driving down cost. The remainder of our fleet is focused on exploration and step-out drilling to expand the productive extents of the field vertically and geographically as Harold mentioned.

During the quarter, we completed 132 gross (50 net) operated and non-operated wells in the Bakken. We are making excellent progress in several fronts and particularly on the key catalysts we expect to have significant impact on the field and Continental's results in 2013. These catalysts include that lower Three Forks exploration, 4 density pilot appraisal programs to test 320- and 160-acre full development concepts and cost reductions due to drilling and completions efficiencies and increased use of pads.

Let's start with the lower Three Forks exploration program, which is currently well underway. As a reminder, this exploration program is designed to delineate the productive extent of the lower Three Forks reservoirs by drilling a series of wells strategically placed throughout our acreage. We initially planned to drill 14 gross wells in the 2013 program. However, we have now increased this to 20 gross wells (15 net) to further define the commercial productivity of the lower Three Forks and help to assess the incremental reserves in these lower benches. These 6 additional wells are not incremental to CapEx budget, but are just a reallocation of CapEx. We expect to have all wells drilled and completed by year end.

We reported in our release yesterday results of the first 2013 completions from the lower Three Forks program. The Angus 2-9H-2 with 85% working interest flowed 1,556 barrel of oil equivalent per day at 3,200 psi during its first 24-hour test period from the second bench. We are very pleased with early performance of the Angus, and we want to point out that extends the known producing extent of the second bench of the Three Forks 27 miles northeast of the Charlotte 2-22H well, a significant step-out.

We currently have 8 additional lower Three Forks exploration wells being drilled and completed and plan to provide quarterly updates on the results. Although we would be pleased if they all turned out like the Angus, this is an exploration program we expect to see some variation in results as we test the extents and deliverability of these reservoirs over a very wide geographic area.

Before moving on, I like to provide an update of the Charlotte 2-22H and the Charlotte 3-22H wells, which were the pioneering second and third bench producers in the field. The Charlotte 2-22H has produced 108,000 barrels of oil equivalent from the second bench in approximately 14 months, and the Charlotte 3-22H has produced 35,000 barrels of oil per day from the third bench in approximately 3 months. We estimate reserves for these wells are very much in line with a typical first bench producer.

Continental continues to be the leader in the development of Three Forks with this 2013 lower Three Forks exploration effort. With continued success, this program could materially increase the value of our position in the play.

Now let's move on to our pilot appraisal projects. We have 5 wells in operations at the Hawkinson location, which is the first of our 4 independent pilot density projects to test the full-scale development potential of the Middle Bakken and the Three Forks on 320-acre and 160-acre spacing. The pilots again are distributed across a wide geographic footprint within our acreage, ranging from 30 to 80 miles apart. These are aggressive pilot projects. We plan to spend the next 18 months drilling and completing a total of 47 wells. Production from these wells will start coming online in December 2013, and we expect to have all wells by producing by the end of the first quarter 2014.

We are applying an integrated, technological approach in these programs, which includes 3D seismic, microseismic imaging, coring and advanced petrophysical characterization. This approach will help us further elevate the reservoir and optimize our completion designs to increase recoveries, improve efficiencies and drive down costs.

Our downspacing program is very important to the ultimate development plan for the basin. Again, taking the industry in pioneer position, Continental is looking to leverage its premium acreage position to extract the maximum value possible.

So now let me move now to our SCOOP activity.

We continue to be very pleased with the results we're getting from our new SCOOP project in Oklahoma. In particular, both the oil and condensate fairways are delivering repeatable results within those fairways, in line with the October expectations. To date, we have completed 62 gross (33 net) horizontal Woodford wells in the SCOOP area. We completed 17 gross (10 net) wells in SCOOP during the fourth quarter, including 12 wells in the condensate window and 5 wells in the oil fairway.

Recent highlights include the Cosby 1-13H well, which IP-ed at 1,761 barrels of oil equivalent a day and still climbing. And the Lowrance 1-10H, initially flowing at 1,580 barrels of oil equivalent per day. These recent completions support our economic model of 1.2 million barrels of oil recoverable reserves for the condensate fairway and 626,000 barrels of oil equivalent per wells in the oil fairway. At $90 oil and $350 gas, the condensate fairway wells have an average 50% to 60% rate of return, and the oil fairway wells have an average 40% to 50% rate of return.

As Harold mentioned, we have 6 rigs running and plan to reach 12 by year end and invest $450 million to drill 90 gross wells (41 net) wells within the play. Our 24-month goal in SCOOP -- our 24-month goals in SCOOP are to de-risk and HBP our acreage. Based on our repeatable results, we have greater confidence in this resource discovery and the production in reserve that will follow.

So in summary, we have a clear vision to include shareholder value in the next year as a good start on our 5-year plan. We plan to de-risk and expand our 2 core plays by developing these premier oil basins. We're off to a great start, with production expected to exceed 120,000 barrels of oil equivalent per day this month. We are focused on operational excellence, safety and continued efficiency. We have a defined path to assure our transportation infrastructure gets built as we grow. We have implemented an oil marketing strategy to reach premier markets, and we plan to maintain a strong balance sheet and financial flexibility.

Echoing Harold's comments, with such a record-setting year, I have left only 2 things: First to thank our employees for their hard work and dedication. And to turn it over to John to give us some context on our financial results. John?

John D. Hart

Thanks, Rick. Yesterday afternoon, we announced the excellent results for 2012 as a whole and for the fourth quarter, exceptional production, earnings per share and cash flow. For the year, we generated net income of $739 million or $4.07 per diluted share. And for the fourth quarter, our net income was $221 million or $1.19 per diluted share. Clean earnings for Q4 after adjusting for nonrecurring items was $1.04, well in excess of Street consensus.

We also reported record EBITDAX of $2 billion for 2012. Annual EBITDAX was a 51% increase when compared with $1.3 billion for 2011.

We accelerated cash flow growth in the last 3 months of 2012, ending the year reporting almost $600 million in EBITDAX for the final quarter, which was 44% higher than Q4 of 2011. Our 2012 earnings were driven by record production of 36 million barrels of oil equivalent, a 58% increase over 2011. We replaced our production by 6.5x with new proved reserves through the drill bit and an average F&D cost of $12 per barrel, reflecting our team's success in efficiently developing high-quality, oil-focused reserves. Beyond the drill bit, our production operations continued to generate exceptional cash margins due to our continual focus on safe and efficient operations in high-margin assets.

Our cash margin percentage for 2012 was 73%. We believe these results are indicative of the strength of our teams and the quality of our assets yielding -- leading corporate performance relative to the industry. We also note that our margins are reflective of a multiyear history of strong, stable cash margins. And in fact, they're indicative of our expectations for 2013.

Supporting our cash margins and capital plans, we continue to strategically utilize commodity hedges for cash flow stabilization. We currently have in excess of 3/4 of our expected 2013 oil production hedged. 62% of our production is hedged against the WTI average of $93, and 15% of our production is hedged against a Brent average of $109.

As our marketing has shifted to coastal markets, a process of more reflective of Brent, we began increasing our percentage of Brent-dominated hedges during 2012. The summary of our hedge portfolio, including 2014 and '15 positions is contained in our Form 10-K, which we filed last night.

Our production target for 2013 is 35% to 40% production growth as compared with 2012. So we are kicking off our 5-year growth plan with exceptionally strong momentum. A summary of our full 2013 guidance, inclusive of positive revisions in oil differentials and our effective tax rate are included in our earnings release. The change in the effective tax rate noted in the guidance is attributable to changes in our blended state rates.

E&P capital expenditures were approximately $3 billion, in line with our budget, which included $2.2 billion directed towards the Bakken. The company also spent an additional $1.3 billion acquiring producing and nonproducing properties, mainly in the Bakken, our Samson acquisition, which was completed and announced in the fourth quarter being the largest of those.

We ended 2012 with $3.5 billion in total debt, inclusive of the revolver, which calculates to a year-end net debt to EBITDAX of 1.78x, among the best in the industry. Obviously, this ratio is significantly lower annualized in Q4 EBITDAX.

In closing, our financial position remains exceptionally strong with plenty of liquidity. Our expanding operating cash flow, combined with significant optionality and flexibility, enables us to fund our portfolio of low growth opportunities for multiple years.

I will now turn the call back over to Harold for a few closing remarks and a final overview before Q&A. Harold?

Harold G. Hamm

Thank you, John. I hope you're prepared for an exceptional year in 2013. At Continental, we will continue to expand, de-risk and realize exceptional value of our strategic oily assets. We will continue to drive cost efficiency through operational excellence while always seeking to improve our excellent record in safety and environmental compliance. We'll continue to capitalize on the opportunity to maximize the value of our consistent, high-quality sweet Bakken oil by accessing premier markets on the coast. And we will seek to bring value forward by accelerating growth, managing margins and mitigating business risk. As always, we'll be disciplined in maintaining a strong balance sheet and our financial flexibility.

With that, I'd like to turn the call back over to our operator, and we'll be glad to take any questions you might have on this. Thank you.

Question-and-Answer Session

Operator

[Operator Instructions] Your first question comes from the line of Ryan Todd from Deutsche Bank.

Ryan Todd - Deutsche Bank AG, Research Division

If I can start with a question on costs. You mentioned an impressive well pad is under $8 million a well. Can you remind us what your implied cost was on a blended basis in your 2013 guidance? What you're seeing right now across the portfolio in the Bakken in blended well costs? And if you're ahead of schedule, and you get that lower versus the implied 2013 guidance, will you try to keep the same budget and drill additional wells or how should we think about that wedge of capital?

Winston Frederick Bott

Let me take a stab at that and then I'll get Rick to add some color. So we went out and forecast that for our budget, the average well cost, and remember Continental drills north to south and east to west across the entire basin, so our footprint is quite large. Our goal, currently we budgeted $9.2 million for the average well cost in 2013. However, we said we had a goal, as Harold mentioned, to knock $1 million off of that and reach $8.2 million for the average well cost, blended average well cost across the basin. We're seeing good progress already. Are we ahead schedule? I think it's probably a little too early to say that, although we're seeing good positive results, and we put that ECO-Pad results in the press release specifically to emphasize that we are seeing progress and that ECO-Pad drilling concept continues to find multiple opportunities for us to leverage our efficiencies and drive down costs. And so we're excited about that. We're going to move much more towards ECO-Pad drilling this year, and we think that we're on track to deliver that year-end target. Rick, would you like to add anything?

Richard E. Muncrief

I think the Florida ECO-Pad, the 6-well pad that we announced were just a hair under $8 million. I think that gives you a little insight of maybe longer term where the company is headed. You probably have heard we have already started on our first 14-well pad, and we're really, really pleased with what we're seeing thus far, and we feel fairly confident that we will achieve that goal that we laid out that Rick just referred to. And I think we're well on our way.

Ryan Todd - Deutsche Bank AG, Research Division

That's great. And if you do come in below that targeted budget, I mean, do you think would we expect to see you drill incremental wells for the same CapEx over the year or just come out with a lower CapEx budget?

Winston Frederick Bott

Yes, I think I've you note, we told you in our Analyst Day, we sort of said out there, our goal is to accelerate value. We have a deep ,multi-decade inventory, and we want to bring as much of that value forward. So our plan would be to leverage those efficiencies and be able to drill additional wells and achieve that production targets. So we invited you to measure us in terms of reserves and production over a 5-year period to triple both of those, as well as being a low-cost leader. So that's our goal and so I'd say our bias would be towards continuing to use those rigs as efficiently as possible and get additional value.

Ryan Todd - Deutsche Bank AG, Research Division

That's great. It's very helpful. If I can ask one quick follow-up on realizations. You were at 70% crude on rail in the quarter. Can you give us an idea of how much -- what the split was in terms of how much is going to which coast? And how much more upside is at that number? Are you starting to reach the limits of what you think you can move on rail?

Winston Frederick Bott

Well, the markets are fairly balanced in terms of where we're going. And actually, those are changing weekly. So if I gave you a number, it would be wrong as soon as you printed it. So the focus is that we are maximizing to get to premium market space on the price that's available at that time. Is there more upside to that? There probably certainly is. But we're probably at the point where it's harder and harder to get there. But yes, we're certainly continuing to make sure that we put all the crude to the highest price market that we have in any given week, which benefits our royalty owners and our shareholders.

Operator

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

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

I too would like to stick with the macro, and I do have a question given your marketing expertise and the breadth of customers your reach. There has been some discussion of condensate prices weakening versus oil prices. Have you seen that? And do you have any color that you could share about potential ways to combat any weakness the industry might see there?

Jeffery B. Hume

Ryan, right now -- this is Jeff. Right now we're not seeing in any of our markets the condensate weakening, but we anticipate that, that will occur as we see more and more of the Eagle Ford production hit the coast. And so we're going to have to be finding those markets with what little condensate that we have. The majority of our oil is light sweet crude oil and not the condensate, though.

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

Right. Okay. That's helpful. And then I also wanted to dig into your view on the lower Three Forks benches following these first 3 tests. How do these wells compare to others drilled nearby? And how do you think about lower Three Forks prospectivity across the play to the extent that you can extrapolate from these only 3 wells?

Jack H. Stark

This is Jack. We are [indiscernible] obviously with the result the Angus well and it is representative of the type of wells in that area. And now if I maybe step back on just the lower Three Forks program as a whole and talk about before we actually kicked this off, everybody was targeting the Middle Bakken and the first bench of the three forks and now we did our core program and demonstrated that there was oil saturation all the way to the lower benches, the fourth bench in the Three Forks. So essentially redefine the Bakken petroleum system. And so, in this, clearly we see more oil in plays. In fact, we bumped it up to about 900 billion barrels of oil in plays, about a 57% increase in reserves there. And so, this whole process and the reason I'm going here is I just want to make sure everybody recognizes that this is an exploration program and it has breadth of about 60 miles wide and about 75 miles north to south, and we've got 5 different areas where we're actually drilling wells in the various benches. So we expect to see some variability in outcomes across the play, but we expect them to be representative of the areas that they are drilled in. And so, we're well on our way with 7 wells that are actually in the stage of completion right now out of our 20 wells we plan for the year. And so, and then getting back specifically to what you're talking about here is, how do we feel about the repeatability in these zones. Well, I think as I've said before, the first bench obviously is widespread across the basin. The second bench is about as equally widespread across the basin. And the third tends to be a bit thicker and have a few more shale breaks though in it, but it extends almost as far as the second bench. The work we're doing here shows it has a pretty good extent here, and then the fourth obviously, as we've always said, it's going to be a bit more spotty, and where it's developed more -- more well developed on the west side than on the east side. So all this said is that we're just -- we're excited about the program as we're going ahead here, we're really looking forward to getting the results. And this is really an aggressive and accelerated approach at evaluating this given a large footprint of wells that we're drilling out here. But ultimately, I think what you should expect to see is the wells will perform in line with those that are around them.

Operator

And your next question comes from the line of Abhishek Sinha from Bank of America.

Abhishek Sinha - BofA Merrill Lynch, Research Division

I'm just filling in for Doug Leggate. So basically, the first question is, I just want to get an idea of like what's the timeline to move to 100% pad drilling? And while you guys transition to pad drilling, do you expect like you're flat spot in the Bakken production?

Winston Frederick Bott

Our pad drilling, as Rick mentioned earlier, we have approximately 70% of our active rigs are pad capable. If you look at 2011, 31% of our total wells were on pads. We're estimating that 2013, that number is going to climb up to about just over 60%. And so, I think that over the next 2 years, we'll see a trend continuing to climb. We still have some acreage to HBP, and we also got an exploration program that Jack is just talking about. So those are of our 2 driving priorities, if you will.

Abhishek Sinha - BofA Merrill Lynch, Research Division

So do you expect the production to be like spotty, is it going to be a flat Bakken production at some point?

Winston Frederick Bott

I think you're just going to continue to see some growth from time to time. Anytime you see a 14-well pad, you may see just a little bit of a bump. But remember, we've got a lot of activity, we're bringing all of the cycle times, we're bringing on a lot of production all the time. And so, our goal is to make that as smooth as possible and also to accelerate as much as possible.

Abhishek Sinha - BofA Merrill Lynch, Research Division

Okay. And if you can provide any color as to what you're hearing on regarding to potential restrictions on gas flaring in North Dakota, and how does that affect your production in any ways?

Winston Frederick Bott

Well, gas flaring is an interesting topic. I mean clearly, gas is a valuable and marketable commodity. There are number of issues there, particularly the fact that the Williston Basin in this area is quite remote, and so there is not the infrastructure there to handle the rapid growth in the field. However, we and other operators have continued to address this issue and continue to work hard, as we talked about in our description there of what we call the first mile hookup that's these gathering systems with our midstream partners to make sure that we can gather that gas as quickly and efficiently as possible. And to further the point Rick Muncrief was making there, as we go to these larger and larger pads and areas, we can plan that better, we can make sure that we have the infrastructure, the gas gathering systems hooked up earlier. In fact, we hook them up every time we can before we start drilling. And that continues to provide a lot of value for our shareholders. And so that's essentially our goal is to do those as quickly as possible. Right now, we kind of led the industry, we're less than 10% flaring, and we anticipate continuing to lead industry through this pad technology. The driving forces are there really is make sure that we have supportive regulatory framework and that landowners also agree that this is valuable enough and the access is granted to make sure the infrastructure can be hooked up. But we're very pleased with the result so far, and we're well ahead of our goal as I said below 10% flaring in the Bakken.

Operator

And your next question comes from the line of Gil Yang from Discern.

Gilbert K. Yang - DISCERN Investment Analytics, Inc

Can you talk about the -- 2 related questions, can you talk about the relative spacing of the Charlotte -- the 2 Charlotte wells, the 2-22H and the 3-22H? Were they right on top of each other, and how far apart were they effectively?

Jack H. Stark

Gil, this is Jack. I believe the Charlotte 2 is obviously they're stacked, they're about 50 feet apart vertically, the Three Forks 1, 2 and 3 in the vertical sense and then in the lateral sense the Three Forks 2 well is 660 offset from the Three Forks 1 well. And the Three Forks 3 was actually, I'm going to say, it's about a half mile to the East of our Three Forks 2 well. So we did that Three Forks 3 test out there further away. We didn't do it as a 660 offset because we wanted to be sure we had a very clean completion there, that we didn't have any confusion with any of the other wells around there, we wanted to make sure we've got an isolated test there. And we drilled our Three Forks 2 well, and that's about 1 year ago, and we just recently drilled the Three Forks 1 well there, 660 offset to potentially start our interference testing. One of the things here is that our first effort here is obviously with this aggressive exploration program we've got here, it's an attempt to prove the productive footprint very quickly for the -- these lower benches, and then the next step is to demonstrate clearly that we have incremental reserves coming from each of these layers. And so, this interference, this Three Forks 1 well we just drilled will be used to start monitoring what if any communication exists between these various benches. So that is part of our whole process here. Step one is prove the productive footprint. Number two, test the incremental reserves. And we believe, based on our history, we expect there's clearly incremental reserves to be had here. Everyone's going to have the question in their minds until we can prove -- it's going to take some time to get the production from these wells to assess that, but we clearly know from just what we've seen, like as I said before, in the core, there is substantially more reserves in the ground than we had previously considered given the oil saturation going from it being present in the second, third and fourth benches.

Gilbert K. Yang - DISCERN Investment Analytics, Inc

Right. Thanks, Jack. A sort of follow-up to that is, if you look at your 603 Boe, Mboe type curve, how much interference is acceptable? Or in other words, I guess, how small a type curve would make those other benches or the downspacing, rather, effective?

Jeffery B. Hume

I think that's an excellent question. One is going to actually surface over time when you start to get more data in. And I think your question is how much is truly -- are you talking acceleration, unique reserve, all of the typical questions that come up with increased density type projects, and I think that'll come out over time. But obviously, there are 603 model that we have currently, you could come off that a fair amount and still have very economic reserves.

Gilbert K. Yang - DISCERN Investment Analytics, Inc

Are you willing to say you could come off like 20% or can maybe even more?

Jeffery B. Hume

Probably so. I think we just need to -- we have all types of sensitivities and once again, the bigger commodity is oil price assumptions and things like that to come into your economics.

Winston Frederick Bott

Yes. If I could just supplement there, just a point there if you don't mind. It really comes down to a balance between economics and recovery factor. So we know just to set the larger context based on the numbers that our team has done in the large extensive coins [ph] program plus all the vertical wells in the basin, that if you use a 3.5% recovery factor, that's roughly 24 billion barrels of oil in the field recoverable. Now if you can up that to 5% recovery, then you're talking about 45 billion barrels of oil ultimately recoverable from the field. So you can see that this -- you're talking about very small amounts of improvement and recovery factor, and that comes down to how economically can you get the oil out. It's not necessarily a question of whether or not there's interference. And so it's kind of a balance between the density to well spacing and the cost of the well. So as we continue to drive down well cost, that curve will shift lower in terms of what will be ultimately economical. But we very much feel that we're on the right track. We feel this is an integrated fully high-pressured petroleum system, top to bottom, versus the old theory that the deeper Three Forks were sort of just a halo of the oil pushed down into that interval based on the pressure in the middle Bakken. We now feel it's all one cell and it's all very, very similar pressure. And therefore, the recovery factors are going to be much more an important factor for us to determine. And we set out these programs to de-risk and determine what the ultimate recovery can be and the ultimate development methodologies.

Operator

And your next question comes from the line of Brian Corales from Howard Weil.

Brian M. Corales - Howard Weil Incorporated, Research Division

A couple -- another question on the lower Three Forks. By the end of this year, how much of your acreage or how much of the acreage is going to be tested? Or would you feel comfortable to say whether it works or doesn't work?

Jack H. Stark

This is Jack. What I mentioned there is we've got a footprint that's 75 miles north-south and 60 miles east-west from the way these -- our exploratory project area is spread out. And actually, these are areas where we had taken cores. So there really, when you look at this strategic placement of this, we're testing all the way to the north end of our acreage down to almost the southern edge and definitely to the eastern edge of our acreage and almost to the western edge as far as we got one well, it's right on the Montana/North Dakota border. So very large footprint. Step-out program here. And all these are relative to the Charlotte well. If you look at it, you're probably 50 miles north of the Charlotte, 35 miles west of the Charlotte and 36 miles south of the Charlotte. So we've kind of done this and it's kind of like a spoke on a wheel where we stepped out in all directions to really just define the productive footprint. So once we're done with the well control that we have, subsurface existing oil control, and the cores, we should have by year end a fairly good opinion about the viability of or the produceability of these zones across much of the basin.

Brian M. Corales - Howard Weil Incorporated, Research Division

That's helpful. And then realizations have been strong. Looking at what you reported today for the fourth quarter, what have they looked like thus far in terms of your net backs on the realization side for 2013? Has it been better than the fourth quarter?

Winston Frederick Bott

Let's just say we're off to a good start.

Operator

And your next question comes from the line of Noel Parks from Ladenburg Thalman.

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

Just a couple of things. I wanted to ask about the SCOOP. As you do more drilling out there, I know it's still early, have you sort of identified a core, if you will, of the player of your acreage? I wondered is that determined just by where you have that unusually thick section of the Woodford?

Harold G. Hamm

Right now, Noel, it's still very widespread, covered a broad area. We have identified what we call our oil window and condensate window down there. But it's a very broad play at this point and quite extensive.

Winston Frederick Bott

And really, Noel, it's more a part about how we developed the acreage as our ideas developed. So really, our concentration is then in drilling areas that we need to hold acreage, and that will probably be the case for a while. And so we continue to expand our ideas and we continue to expand acreage. And so we're kind of following that acreage schedule, if you will, really, but essentially as we talked about, we probably got more than a 600-square-mile de-risked area. I wouldn't say it's really a core there, but it's really a question of where we have the data and where we have confidence that we are getting great repeatable results.

Jack H. Stark

Noel, this is Jack. I don't think when you say core, I think that as Harold said, this is a broad area. And quite frankly, we see a very -- we've defined what's now maybe a 15- to 20-mile wide condensate oil fairway in here. And our position, we have a lot of what I would consider core areas all through our position, all through this whole fairway down here in SCOOP. And so, we're looking at a long, very long end [ph] of oil and condensate fairway here that there's, we expect to find great production all the way along it.

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

Great. And I want to turn for a moment over to the Bakken. Something that I hadn't actually noticed at the Analyst Day, but I think it was on your map back then. In your most recent acquisition in the Bakken, I believe you got some Divide County acreage. I noticed from the last presentation that it looks like there actually is drilling activity that crosses that Brockton-Froid Fault Zone. And I was just curious, I thought that, that was pretty much considered to be a sort of a drop-dead barrier for productivity?

Jack H. Stark

Noel, we put our Brockton-Froid Fault Zone on there as, say, a linear line. But in fact, it's quite a, it's a fault system going through there. And the question is, is it the Northwest limiter to the play, or is it something that came in after the fact? There's arguments both ways, but bottom line is, we're seeing production that would extend across just a single line that we would put it there on our map as a trace.

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

And that Divine County area, is that essentially considered prospective like much of sort of the Northern part of the play? Is that something that'll be put in particular emphasis then or is it just kind of ranked in line with everything else you have to drill?

Harold G. Hamm

Noel, we're seeing production, a good production on the side of Brockton-Froid. And it's -- we don't know how extensive it's going to be, but so far it's -- definitely we're pursuing it, and other companies are pursuing it as well. So it's -- we, we leased acreage up there early on and certainly a lot of acreage that we've acquired recently is in that area. So we've got a very strong position there.

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

Does it exceed the footprint that you use for your estimates of oil in place in the basin?

Harold G. Hamm

In my opinion, it's about the same, along the same lines as is there originally.

Operator

And your next question comes from the line of Hsulin Peng from Robert Baird.

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

Most of my questions have been asked, but I just have one quick follow-up in the SCOOP play. I was just wondering if you can give us an update on the gathering and processing infrastructure in the play currently? And who are your partners there? And are you currently rejecting ethane there?

Jeffery B. Hume

Okay. On buildout, first question on the buildout, our midstream gathering company has spent tremendous amount of money and effort this year to build us out. We currently have 0 wells waiting on completion for that infrastructure. So they have caught up with our drilling and staying ahead of us. So I think we'll be in a position as we drill wells through 2013 to be able to complete them and get all those molecules down the line. On ethane rejection, we are currently not rejecting any ethane in our Oklahoma properties. All that's being processed. But as you know, ethane is receiving approximately the same value on a BTU basis as the methane. So residual, so it's kind of a moot point whether it's rejected or not, but to answer your question, it is not being rejected at this time.

Operator

And your next question comes from the line of Amir Arif from Stifel.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

Just a couple of quick questions. First on just the quality of the crude of the Bakken, ignoring transportation cost bottlenecks, can you just tell us what the quality differential should be relative to a Brent barrel and a WTI barrel?

Winston Frederick Bott

Great question. You couldn't go out and look on our Investor Day presentation, and we've got a graph in there that shows the typical refinery splits. And the percentage of each of those splits on a number of barrels, LLS, WTI, Brent and Kwaiba [ph] Light. And if you look across those and the 40s blend, so if you look across those, the Bakken crude is actually one of the higher quality crudes. It's got the lowest sulfur content of any crude benchmark in the world. In fact, it's probably of the term of ultralow sulfur crude. So that's a very, very good point. The other point is that in terms of the Bakken, the Williston Basin, the depth of burial and the maturity of the source rock is such -- within such a range that all the way across that very, very large basin, 15,000 square miles, you have near identical consistency, perhaps more than you expect in many, many basins, identical consistency in terms of API gravity and quality. So it's extremely consistent barrel. So all of that huge range of ultimately recoverable is all of the same quality. And the final point in terms of our refinery yields, you get very high refinery yields because of the high content of gasoline and distillates like jet fuel and diesel. So it's very high content -- very low content of the very light in volatiles and very low content of the heavy residual bottom of the barrel. So it's a very, very good quality. In terms of price, as we've talked about before, we think if you fast-forward to sort of bottleneck unconstrained that we think -- within our 5-year plan, that the Bakken crude will be traded at a premium to Brent minus the transportation cost to get it there.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

Okay. And I mean, just given the consistency of the Bakken crudes and everything else you mentioned and the volume of Bakken now, have you guys tried to do what the Canadians are doing in terms of the Western Canada select, just trying to get a better benchmark and better marketing of the crude rather than just one-off transactions with each refinery?

Winston Frederick Bott

What a great question. Yes we are putting a lot of effort and trying to make sure that the end user, that we have relationships with the end user, that they understand the fundamental quality differences and they're professionals and experts in their fields. So they understand that. And then looking at based on the consistent quality, ease of distribution now to the entire country, if you will, and the long-term largest supply, we think, in the country that ultimately as we said in our note that it could become a national benchmarker of global light sweet crude benchmark because of the great quality of the Bakken crude.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

Okay. And then in terms of the rail cost, can you share even just a rough idea of what the rail costs are to the east coast as well as to the west coast? Are you willing to...

Winston Frederick Bott

We haven't really gone out and spent and talked specifically about the transport cost. I think a number of other players have and they put that out on their website and it's sort of like what is the advertised cost. It's quite a competitive and commercial piece of informations and it's changing quite quickly. And so, we prefer not to talk about that for commercial reasons.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

Okay. And then just switching over to the deeper Three Forks bench test. If you already had an existing Bakken well in terms of the road, the pad, the infrastructure sort of buildout on the gathering, what is the incremental cost from an existing pad to drill one of these deeper bench wells?

Winston Frederick Bott

Oh, not much. They're, as Jack said, 50 feet apart, so it's really just a change in our angle at which we kick off on the horizontal. Rick, you want to add anything to that?

Richard E. Muncrief

Yes, that's right.

Winston Frederick Bott

We basically will lump all those wells within our goal of reducing knocking $1 million off. So we will include the deeper benches of the Three Forks in that as we set that corporate goal for our team.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

But if your average well cost on a new pad or new well was 8.5 or 9, would this -- I mean because if you've got the gathering in the road and the pad built, is this cost more 7.5, 6.5?

John D. Hart

No. You wouldn't see a 6.5 range. You can certainly see potentially $300,000 to $400,000 knocked off those costs. You can come back in and do, say, a new generation of lower bench wells.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

Okay. And then just a final question. Based on your knowledge to date, are you thinking of these deeper benches as a way to sort of extend the life once the primary zones are produced? Or would this sort of be targets for initial developments as well right up front? Or I guess it depends on the economics...

John D. Hart

What you bring up is an excellent question and we're going to, in the next 24 months, we're going to have a lot of things revealed to us. And included in that is secondary recovery of potential. And if so, which zones, what caps patterns, things like that. So we're just really excited about what we're going to find in the next 24 months with these infield programs.

Winston Frederick Bott

If I could add to that. We think it will become part of the primary development. We would look at the best areas and how we optimize and maximize value and we will -- it doesn't matter what interval we'll be in. Once we have de-risked these and understand where the sweet spots are, the deliverability and operational efficiencies that we can gain from these large programs, once we understand that, then we will modify and roll into full field development. But you could be drilling at Three Forks third bench just as soon as you drill a first bench on the same pad, just to looking at what is the optimal way to reduce costs and increase efficiencies.

Operator

And your next question comes from the line of Rudy Hokanson from Barrington Research.

Rudolf A. Hokanson - Barrington Research Associates, Inc., Research Division

This is a macro question. And it has to do with the attractiveness of the Bakken crude and the end markets, and that is, is the refinery system that you're shipping to in the lower 48, what is it appetite for this crude when you look at the way that the refineries have been built over the last 15 years and the changes they had to make before there was the Bakken crude and the blends that they were looking for? How much crude can the refinery system take given the expected growth of production right now and maybe what they're telling you? I know that it's a great crude, et cetera, but the way that they've been constructed and the capital investment they've made for the different types of crude may say that there's eventually a limit to how much they can take. What have you seen or heard? And what are your studies telling you?

Harold G. Hamm

Luckily, Rudy, this play started coming on before everybody went to coproducing and spent all the big bucks to transform those refineries. We see the market as quite extensive yet, due to all the Afghan oils and Middle East oils are still coming through our coast. So obviously, backing that crude out and getting all of the East Coast markets is very important. So as this field came on, luckily, it was in time to say that a lot of people, a lot of investments. So the rail system has certainly become transformative in the delivery, speed of delivery, efficiency of delivery, everybody is realizing that this is totally transformative. So we feel like it's a large market out there.

Winston Frederick Bott

And, Rudy, if I could supplement a point to Harold's comments there. It depends on the timeframe you're looking. But I think as the North American refinery segment and the upstream segment sort of come together in terms of the estimates of the ultimate recoverable from North American and from these plays that are being uncovered. Certainly the Bakken, the Eagle Ford, the Permian, some of these other liquids-rich plays, that at the end of the day, they will look at what the economics are in terms of additional investments and additional expansion and what can be done with that. And so long term, we think that you'll see the opportunity for buildout for additional investment and even saw it last year with the refinery there in Philadelphia that was going to be mothballed, had private equity come in and invest in it and essentially because they run a light sweet crude. And so that refinery stayed on the market and otherwise it would've been closed if it weren't for the Bakken crude.

Operator

And your next question comes from the line of Jason Wangler from Wunderlich Securities.

Unknown Analyst

This is actually Mo dialing in for Jason. Just a couple of questions, if you can tell us what the NGL mix in those wells that you drilled in the condensate fairway, the 3 wells that you've drilled in the fourth quarter? And if you can talk a little bit about the pricing of those NGLs?

Winston Frederick Bott

One second, we're just making sure we've got that. Jeff's got it here.

Jeffery B. Hume

Well, what we're seeing in the condensate fairway, we're seeing about 37% NGL mix in those areas. So you're seeing a very, very good price in there. We had a crisis in December in that area of around realized prices around $5.60 at the wellhead. So with the NGL content that high -- of your total mix, your total stream is about 37% NGL, about 24% oil and 39% gas. So it's very, very rich.

Operator

And your next question comes from the line of Sven del Pozzo from IHS.

Sven Del Pozzo - IHS Herold, Inc.

Just briefly. Looking at your wells, looking where the best wells are, would you -- could you generalize at this point and say that the lower Three Forks benches were the better areas? Or lower Three Forks benches would also be in the better areas where you've had -- of your Middle Bakken and the shallowest Three Forks member?

Jack H. Stark

At this point, that's a fair generalization to make right now. Obviously, we've got a lot of drilling to do to figure all this out. But right now, I think it's fair.

Sven Del Pozzo - IHS Herold, Inc.

Okay. Is there -- I mean, is it just the typical things that would make rocks better that would also make these deeper Three Forks benches better in terms of rock characteristics?

Jack H. Stark

We see -- the best correlation we see is just with the percent dolomite development in each of these benches. And so in the first and second benches, we're really just dealing with pretty much just dolomite up there, and better with some of the shales. If you get down in the third bench, as you get out to the flanks of the basin, you start seeing some evidence of anhydrite showing up. And even in some areas more central. But then in the fourth bench, you see a higher percentage of anhydrite showing up, which anhydrite is something that just -- it includes porosity a little bit, which could reduce permeability. So as far as the quality is concerned, I mean the dolomites themselves, I mean you definitely see that as this basin was evolving, that there are common environments in which the dolomites being positive [ph] and repeatedly through time. That's why we have these various benches.

Sven Del Pozzo - IHS Herold, Inc.

Okay. And then lastly, in Montana, looks like almost 30% of your net well count in the fourth quarter was in Montana. I'm wondering, is that higher than in the past? And if so, just brief description of your most recent developments in Montana and if there is a ramp up and why?

Jack H. Stark

It's pretty consistent where we've been I think over the last 6, 8 months, I'd say. And we've got 5 rigs running out there and say 2/3 of those are outside of the confines of the field, so that's 3 of them are outside of it and then 2 are drilling some infill locations. And the results we're seeing continue to meet our expectations up there of our 430 model, pretty much across the board up there. And we're drilling from the east side of our undeveloped acreage block up, northbound curling to the west side right now. And we've, on average, extended the field out about 7 miles, some places even upwards of 10 miles. So we're continuing to plug away there and continuing to expand the footprint of the field.

Operator

And your next question comes from the line of Eli Kantor from Iberia Capital Partners.

Eli J. Kantor - Iberia Capital Partners, Research Division

I wanted to touch on the downspacing conversation that was discussed earlier with regard to 24-hour IPs that you come out with density results from the 320- and 160-acre spacing pilots. There's been talk about an EUR degradation of roughly 30%. I'm just wondering if that's a good benchmark to use for 24-hour IP expectations when you announce results at the end of this year or beginning in 2014?

Jeffery B. Hume

We don't know where the 30% comes from. So it's really hard for us to even address that, Eli, to be honest with you.

Jack H. Stark

Yes, I'd say, Eli, right now, I would say that we aren't seeing any reduction in IPs from wells drilled in these lower benches yet. We need to obviously a larger database and as far as the density is concerned, obviously, we've got a lot of wells. We've got numerous wells that have been drilled on in pairs of wells that are 660 offset, Middle Bakken and the first bench well and their 660 offsets. And we're not seeing any influence on IPs or even EUR. So I mean, there's just a constant building of data set out here that's saying that pattern is not causing any kind of degradation in at least initial rates.

J. Warren Henry

Eli, this is Warren. Are you referring to the Ryder Scott study that we discussed at the Investors Day?

Eli J. Kantor - Iberia Capital Partners, Research Division

Yes, that's correct.

J. Warren Henry

That was a projected EUR.

Winston Frederick Bott

On the [indiscernible] that was down to 160 that was projected EUR possible on the seventh and eighth well, in a 160 spacing in Middle Bakken.

Eli J. Kantor - Iberia Capital Partners, Research Division

That's a reasonable assumption, but we have to see it.

Harold G. Hamm

As we said earlier in the next 12 or 24 months, we're going to get a lot of data. So neither we can support that or dispute that assumption at where it's at.

Winston Frederick Bott

Again, it goes back to the economics of each individual well and the balance between driving down costs and the density spacing that you'll ultimately choose. And we've -- the internal models that we run particularly in a lot of areas don't show much degradation at all. And so, I think it really is going to be about the quality of the rock in a given area and how it performs with the stimulation technologies that we're currently applying, leaving room, of course, for additional optimization, additional stimulation techniques that we might use in the future.

Eli J. Kantor - Iberia Capital Partners, Research Division

Okay. That's helpful. Question on timing on the fourth -- your first test into the fourth PFS bench. When should we hear results on that?

Jeffery B. Hume

I think we should see something on that within 30 days. And with the wells down, and we're going to have the several wells here coming up in the next 30 to 40 days, and we'll probably -- what we're planning on doing is going ahead doing a quarterly update. as I said, this is a program and we're probably not going to be just feeding well by well as we go along here. I think what we'll do is each quarter just put a summary together of how the program is progressing here. We came out with our Angus well because this is our first test out here and I'm sure people wanted to hear some results and it is good to hear some of these results because it's just this whole lower bench play is evolving. But that's kind of how we plan on doing a reporting base going forward.

Eli J. Kantor - Iberia Capital Partners, Research Division

Okay. And then moving on to the SCOOP. For the 12 wells that were completed in the condensate window and the 5 in the oil window, you have an average IP for each group -- each of those different groups?

Jack H. Stark

You know what, I think we just don't have that handy, Eli.

Jeffery B. Hume

We can sure get it to you. I don't have that. You have anything, Rick?

Richard E. Muncrief

Give me a minute, I'll circle back on it.

Eli J. Kantor - Iberia Capital Partners, Research Division

While you're digging it up, last question is on testing dual reservoir prospectivity within the SCOOP. At the Analyst Day, you had mentioned potentially drilling an upper and a lower SCOOP well to effectively drain the 400 feet of [indiscernible] you have there, just looking for an update on that potential pilot well -- pilot program?

Jack H. Stark

We have several wells, I guess, that I can say that have been drilled in the upper and the lower halves of the Woodford here. And we're also participating in an outside-operated project that has got -- I think it's 3 wells in the lower and 2 or 3 in the upper. And so, initial results are showing the wells started out at a very similar IPs, and so we're pleased with the results right now. It looks good.

Richard E. Muncrief

Yes, Eli, what we're showing on the condensate is about an 830 average 8 Boe per day and oil 440 Boe per day.

Jeffery B. Hume

Is that -- no. What that is right there, I think what you've got, Rick, is there's an average -- at this point, we've got 52 wells in this that we have production greater than 30 days. And so what we're dealing with there is a 30-day average. And so, out of those 52 wells, 33 have an average first 30-day IP or a 30-day average rate, it's right at about 835-odd barrels equivalent a day and that's in the condensate window. In the oil window, we're seeing an average of about 400 to 450, all right? So those are the first 30-day averages. And so, anyways, that's -- I was trying to think, that you were asking for the...

Winston Frederick Bott

That's what we have today, that's what we can get to you.

Harold G. Hamm

And Eli, what I really should add there is what we're really impressed here and that's a point I really wanted to get across here in the discussion is that you compare the wells, IPs and the performance wells within the condensate window and those within the oil window, and what we're really pleased is that we're really seeing consistency in outcome in there. That's what I'm really pleased with. And our average model is of EUR is 1.2 and actually in the condensate window, and actually our average from the outcomes is even higher than that. But we're sticking with our original model right now because we have a small population. But in our oil window, we're also hitting right on our model as well. So the outcomes that we're seeing, this is across the middle of our 40 miles -- extends 40 miles northwest-southeast, and it's about 15-, 20-mile wide area. So it's a big area, big footprint, and we're seeing very consistent results within the oil window when you compare oil window wells with oil window wells and then condensate wells to condensate wells. So when we talk about consistency of results, you got to consider it with -- keep in mind where they are located within the oil and condensate fairways. But again, the consistency and the performance of these wells is very encouraging.

Operator

And your next question comes from the line of Gail Nicholson from KLR Group.

Gail A. Nicholson - KLR Group Holdings, LLC, Research Division

Just 2 quick questions. I was wondering what is the average lateral length in the SCOOP that you're currently drilling?

Jack H. Stark

We're averaging about 4,200 feet on average.

Gail A. Nicholson - KLR Group Holdings, LLC, Research Division

And do you guys have any plans to test a longer lateral or is it right now you're just currently kind of trying to drill the whole acreage?

Jeffery B. Hume

Where we are, we have our first long lateral down SCOOP underway currently.

Gail A. Nicholson - KLR Group Holdings, LLC, Research Division

Okay. And then are we looking at about a $9 million well cost for that 4,200 lateral right now?

Jeffery B. Hume

Yes. I think we had in our budget was $9.5 million. I'll expand a little bit. The first lateral, longer lateral was a 7,500-foot lateral, and that is due to some faulting in our -- the second section, if you will.

Operator

And your next question comes from the line of Dick Kindig from Keeley Asset Management.

William Richards Kindig - Keeley Asset Management Corp.

There's an old saying in the industry, the good fields just keep getting better, and of course this is just an incredible resource. Harold, I'm curious, you talked about 3.5% to 5% recoverability. If you go out 10 or 20 years, what would you guess the recoverability would be? Of course I realize it depends on oil prices, in that regard, and so what would be the hurdle price where further development halts in that play?

Harold G. Hamm

There's 2 or 3, of course. One of the biggest ones is density of drilling. The other one is whether EUR will work and what form of EUR works. We think in this tight rock that it will. We've seen it work in other tight rock areas. So it just remains to be proven yet. That's one thing. But obviously, the initial recoveries are always low in these large fields. Historically, that's been the case. And as you go on and technology advances along with development, that number always tend to increase. So 5%, you're looking at 45 billion barrels. So is that within reason, I think it is.

William Richards Kindig - Keeley Asset Management Corp.

One other question. Have you looked into using the top full rigs, lesser expensive rigs to drill the vertical part of the well before you go horizontal with a more sophisticated rig?

Jeffery B. Hume

Well, what we're doing in the Bakken is we do have a smaller rig that goes out and presets our surface casing, which is typically at about 2,000 feet. Here in the SCOOP area, we'll need to get our rig count up really to get that justified. But once you have your initial surface casing set, the 1,500 horsepower rigs we use that here in SCOOP, they're fine.

William Richards Kindig - Keeley Asset Management Corp.

How much of a savings can you get out of using a less expensive rig to drill the top part?

Jeffery B. Hume

Well on the top part, on the surface hole, we're saving about $200,000, $250,000 on each one of our Bakken wells by doing that.

Operator

[Operator Instructions] And your next question comes from the line of Brad Hafren [ph] from RBC Capital Markets.

Unknown Analyst

I just had one quick question for you on the SCOOP. Basically, how quickly you guys are going to be ramping up with the rigs there? You were at 6 as of the Analyst Day, I think you're still at 6 now. Was that just sort of letting the infrastructure catch up and how do we expect to see a change during the year?

Jeffery B. Hume

It is. We're budgeting currently to go from 6 in the Woodford to 12 in the exiting the year in the Wood. Those are all operated rigs. We also got obviously non-operated. But the operated side, we're currently [indiscernible] at 6 wells.

Unknown Analyst

Right. Is that 6 expected to sort of stay the same here in the near term or are we expecting a ramp-up?

Jeffery B. Hume

Actually, our seventh rig is going to be starting to move out in the next week. And it will just slowly ramp up throughout the first half of the year.

Operator

And I will now turn the call over to Mr. Hamm for closing remarks.

Harold G. Hamm

Thank you. I appreciate everybody joining us on the call this morning. And try to remember the 45-year history continental has been first and foremost exploration company, leading the industry and planning and developing world-class unconventional oil plays. And we intend to continue to be the industry leader in E&P development. The future of Continental's shareholders is very bright indeed, we believe. With that, I'd like to thank everybody for joining us this morning. Thank you.

Operator

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

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