Continental Resources, Inc.
Q3 2014 Earnings Call Transcript

Published: 6 Nov 2014

[Operator:]

Welcome to the Third Quarter 2014 Continental Resources, Inc. Earnings Conference Call. My name is Richard, and I'll be your operator for today's call. [Operator Instructions] Please note that this conference is being recorded. I'll now turn the call over to Mr. John Kilgallon, Vice President of Investor Relations. Mr. Kilgallon, you may begin.

[John J. Kilgallon:]

Thanks, Richard, and good morning, and welcome to the Continental Third Quarter 2014 Earnings Conference Call. Joining me on the call today with prepared remarks is the company's Founder, Chairman and Chief Executive Officer, Harold Hamm; Jack Stark, our President and Chief Operating Officer; and John Hart, our Senior Vice President and Chief Financial Officer. Also available during the Q&A session are various members of the senior management team, which include Jeff Hume; Vice Chairman of Strategic Initiatives; Gary Gould, Senior Vice President of Operations; Jose Bayardo, Senior Vice President of Business Development; Glen Brown, Senior Vice President of Exploration; Steve Owen, Senior Vice President of Land; and Warren Henry, Vice President of Research and Policy. Let me remind you that today's call may contain forward-looking statements that address projections, assumptions and guidance. Actual results may differ from those contained in our forward-looking statements. Please refer to the company's filings with the Securities and Exchange Commission for additional information concerning these risk -- statement and risk. Also in the call, we will refer to certain non-GAAP financial measures. For a reconciliation of these non-GAAP measures to the generally accepted accounting principles, please refer to our third quarter 2014 earnings press release issued yesterday. With that, I will turn it over to Harold.

[Harold G. Hamm:]

Thanks, John. Good morning, everyone. We appreciate you joining us on our earnings call. Continental has tremendous portfolio of high rate of return assets in both the Bakken and SCOOP plays. We have a clear line of sight and realize the value of these assets, and we are prioritizing our activity based on returns. We're extremely excited about our new oil discovery, the Springer oil play in Oklahoma. Our results continue to be exceptional, as evidenced by our October 23 press release, which highlighted 4 recent completions with various IPs of nearly 1,500 Boe per day with an average oil cut of approximately 79%. We delivered solid results in the third quarter, with production above 182,000 Boe per day. We grew production an impressive 9% over our second quarter 2014 and 29% over third quarter 2013. Increased production was driven by our continued success in the Bakken through continued optimization of enhanced completions and artificial lift and the additional Springer activity and SCOOP. Production remains robust. The October production rate averaged in an excess of 187,000 Boe per day. And as a result, we are on track to exit the year at 200,000 Boe per day. I would also like to highlight our recent strategic announcement, a joint venture with SK E&S in our Northwest Cana Woodford Shale. SK E&S is a subsidiary of SK Group, one of the largest conglomerates in South Korea. The transaction brought in approximately $90 million of cash upfront in addition to a $270 million drilling carry, which will be utilized over the next 5 years. The deal allows us to drill in the primary dry gas field at advantaged return and, further, HBP the asset. Lastly, let me give you some brief commentary on the current commodity price outlook and Continental's response. Our view ultimately comes back to global supply and demand which, in my opinion, has not fundamentally changed in the past 3 months. Certainly, not enough to justify a sell-off in Brent and WTI that has occurred. The forward discussion continues to be centered on international political wrangling and price changes, not demand destruction. In my opinion, it's great buying opportunity for equities and strong well-capitalized E&P producers. An adjustment in CapEx is called for, as we believe the recent pullback in oil prices will ultimately prove to be beneficial to Continental in many ways. First, a slower growth rate in our operating areas will allow us to further improve our operating efficiencies and lower well cost. Second, slower domestic oil production growth will allow global demand to keep pace at lower oil prices per demand growth and avoid an oversupply of crude oil long term in the future. Thirdly, we do expect crude oil prices to strengthen to the mid-80s or $90 range over the short term. Given our belief that the recent pullback in oil prices will be short-lived, we made changes to our existing hedge book by monetizing practically all of our oil contracts for the remainder of the year and for 2015 and 2016. Although we expect oil prices to recover, we felt it sensible to adjust our 2015 guidance until we realized higher prices. We do plan to maintain roughly 50 rigs for 2015 and have prioritized our areas by rate of return, balancing CapEx and production, which high-grade our 2015 drilling program. As a result, our revised capital budget for 2015 is $4.6 billion. We believe our adjustment allows us to prudently adapt to current prices while generating strong growth and preserving our ability to respond as prices recover. Let me remind you, this company has a very strong financial foundation and a drilling program with approximately 50 rigs, allowing us to maintain our momentum established in the second half of 2014 and to 2015. Now I'll turn the call over to Jack Stark.

[Jack H. Stark:]

Thanks, Harold, and good morning, everyone. Thanks for being with us today. As Harold mentioned, we put up solid numbers again this quarter and I am extremely proud of the team's effort. This is the second consecutive quarter where we grew production more than 14,000 barrels of oil equivalent per day, demonstrating the quality of our assets and the excellent execution by our teams. I'll start the operations update in the southern region and focus on the Springer oil play. I can say we are very pleased with the results. In fact, I can't recall a play that delivered such repeatability so early in its development. We feel this bodes well for the future of our Springer play. To date, Continental has announced 15 producing wells in the oil fairway of Springer with an average 24-hour initial rate of 1,230 barrels of oil equivalent per day at an average 30-day IP of 830 barrels of oil per day. All of these wells were drilled with approximately 4,500-foot laterals at an average cost of $9.7 million per well. Our reserve model for the play currently stands at 940,000 barrels of oil equivalent per well for a 4,500-foot lateral, which provides an 84% rate of return at $80 oil and $3.50 gas. To further improve these recoveries and economics of the play, we'll begin drilling our first 7,500-foot extended lateral in the Springer in a few weeks. We estimate a 7,500-foot lateral will recover 1.6 million barrels of oil equivalent at a cost of $12.1 million, which delivers over 100% rate of return at $80 oil and $3.50 gas. We currently have 10 rigs drilling in the Springer, and 6 of these are drilling our first 2 density pilots. We plan to keep an average of 8 rigs drilling in the Springer play throughout 2015. Turning to the Northern region. Our Bakken production grew an impressive 12% or 13,600 barrels of oil equivalent per day over the second quarter of 2014, reflecting the excellent job being done by our operations group. It also reflects the results of our enhanced completions and a growing concentration of drilling in high rate of return areas. Our enhanced completion program continues to deliver very encouraging results as well. Since Investor Day, we expanded our enhanced completion analysis to include industry-wide results as well as our own operated results. The study now includes over 300 wells, and approximately 1/3 of these wells have over 1 year of production. As expected, results show that slickwater and hybrid enhanced completions provide the best results and, on average, generate a significant uplift in early-time rates. Of even greater significance, our analysis shows that these high rates are being sustained, which translates to increase the EURs. Where we have the most complete data set, we have seen an average production uplift of approximately 45% in the first 90 days and an estimated 30% increase in EUR based on early-time projections. Looking forward, we expect to get similar results as these on at least 40% of our acreage based on the geology and data we have on hand. So what does this translate to in terms of EUR? The average projected EUR for our 2015 operated Bakken Three Forks drilling program is approximately 700,000 barrels of oil equivalent per well. This is a blended average from our budgeted development and step-out drilling activities and includes the uplift we expect to receive from 30-stage enhanced completions. Our average cost per well is $9.6 million, which delivers a 40% rate of return at $80 oil and $3.50 gas. Note that our average cost per well has decreased $400,000 from our previous guidance of $10 million per well. This reflects our decision to reduce the number of high-cost 40-stage completions scheduled for 2015. So these results demonstrate the quality of our Bakken assets and the upside potential that exists from continuing advancements in technology. The results also gives enough support to say that our net unrisked Bakken resource potential contains at least 8 years of drilling inventory averaging 775,000 barrels of oil equivalent per well, or 20 years of drilling inventory averaging 600,000 barrels of oil equivalent per well at our current run rate. To summarize, we have an exceptional inventory of high rate of return wells to drill over the next 2 decades. And as technology improves and efficiencies build, the value of this inventory will surely continue to grow. With that, I will turn it over to John.

[John D. Hart:]

Thank you, Jack. And good morning to everyone. We are pleased to announce another strong quarter. Third quarter EBITDAX totaled $948 million, an increase of $80 million or 9% over the 2014 second quarter. Our cash margins of $51.26 per barrel or 74% continue to be impressive. We ended the quarter with $152 million in cash, and we are currently undrawn on our credit facility. We are in a very strong financial position with ample liquidity and remain committed to maintaining our strong credit metrics and investment-grade classification. As I mentioned on the last call, the higher oil differentials did continue into the third quarter and oil net realization was outside our annual guidance forecast. We finished the quarter with a $11.77 differential for oil and a positive $1.04 differential for natural gas. On a year-to-date basis, we are still within the guidance range for both oil at $10.60 and natural gas at a positive $1.28, and we expect to remain so for the year as a whole. For the third quarter, our operating costs were in line with guidance or better, with lease operating expense at $5.80, DD&A at $21.65 and cash G&A at $1.82 per Boe, reflecting our focus on cost. On June 3, we announced that we were going to redeem all of our outstanding 8 1/4% senior notes due October 1 of 2019. The redemption date occurred on July 11 and resulted in a pretax loss of $24 million. The call of these 8 1/4% notes was financed by proceeds from our 3.8% offering in May and effectively lowers our ongoing financing cost. This nonrecurring charge was excluded from the adjusted EPS calculation. As Harold mentioned, we have lifted substantially all of our oil hedges for the remainder of the year, 2015 and for 2016. In doing so, Continental realized approximately $433 million of proceeds in the fourth quarter. We expect oil prices to rise and elected to lock in gains and pull the cash forward. At the same time, we have an adaptable capital program. We have adjusted our 2015 capital program to reflect current prices yet remain positioned to adapt with higher prices. We now expect production to grow 23% to 29% in 2015. Compared to our original plan, we are reducing capital by $600 million or 12%. And at the same time, we brought in nearly $520 million in proceeds from hedge monetizations and the Northwest Cana JV. This amounts to a $1.1 billion overall improvement in liquidity versus prior plans and is a prime example of our ability to be adaptive, the flexibility of our asset base and our disciplined financial approach. For the fourth quarter, we are almost entirely hedged for natural gas at an average price of $4.20. For 2015, we are hedged approximately 1/3 for natural gas at an average price of $4.34. We will continuously monitor market conditions and may choose to increase hedge positions at opportune times. We are very excited about our joint venture with SK in our Northwest Cana assets. This transaction is the first time the company has entered into a business relationship with a foreign company to codevelop an area. Our Northwest Cana dry gas assets have previously not garnered capital when compared to the Bakken and SCOOP, given recent commodity prices. These assets still have enormous potential for future cash flow generation. Bringing in SK with its long-term investment horizon allows us to jointly develop this asset at a steady and consistent pace. This JV brings together 2 high-quality companies that are very well aligned from a strategic standpoint. We have committed to keeping 4 rigs in this area, which will provide 15 to 20 gross wells per year over the course of the next 5 years. We estimate that specific to our Northwest Cana assets, we will remain cash flow positive from now through the entire 5-year drilling commitment based on current natural gas prices. The Northwest Cana carry will reduce our CapEx from what it would otherwise be required to develop these assets. Now we'll be glad to take any questions that you may have. With that, I'll turn it back over to the operator.

[Operator:]

[Operator Instructions] Our first question online comes from Mr. Doug Leggate from Bank of America Merrill Lynch.

[Douglas George Blyth Leggate:]

I wonder if I could take my full quota of 2, please. I guess someone has to ask this, Harold, your decision to liquidate the hedges. I'm just curious if you can give us a little bit more color as to how the board had the confidence to authorize that and whether or not you had any consultation with the credit agencies in making that decision. And perhaps, just a little bit of color as to -- it's quite a bold call, obviously. And I have a follow-up, please.

[Harold G. Hamm:]

Well, good question. Well, first of all, we didn't have any contact with credit agencies. This -- we've got a great board here at Continental. And we took this to the board and made a determination to go ahead and liquidate at those prices. Feel like that's the bottom. And certainly, going forward, understanding what our competition is and the prices they need to receive in international periods, particularly with OPEC members, we feel like we're at the bottom rung here on prices, and we'll see them recover pretty drastically, pretty quick. So getting by the OPEC November 27 meeting, I think that's going to be a revelation in itself. But we feel good about what we've done with prices.

[Douglas George Blyth Leggate:]

Obviously, we have no idea what the outcome of the OPEC meeting is going to be. So I'm -- what do you see as a catalyst to put a floor under the price, obviously, given you've taken this move?

[Harold G. Hamm:]

No doubt they -- I mean, what we're dealing with here is a renaissance that's going to be very long-lasting here in the U.S. And we see OPEC worried about that and want to slow down what we're doing over here. So that's really the backdrop we have. And so my thought is if they slow it down a little bit, it's probably going to be good for everybody and let world -- global demand pick up over the next couple of years to match the growth that we have here in the U.S. and will have for many years going forward. So probably, overall, that may be very well -- may very well -- we may all be well served by what's happening, even though we're not looking, probably at it that way right now. But to -- I see price improving, I see price improving to $85, $90 range, just like I've been saying all along.

[Douglas George Blyth Leggate:]

And my follow-up is more -- I guess more on the assets. Maybe this one is for Jack. But as far as the SCOOP/Springer, Jack, it looks like we see a little bit more of a gassy mix coming out of the SCOOP earlier this year with higher rates. It seems to be slowed down a little bit, but it seems to be a little more oily. So I'm wondering if you could help us with how the development plan is shifting in the SCOOP. And then maybe as part of the same answer, I guess the Springer is in the same area. Is there any update you can give us on the inventory? Just 10 rigs on a full year inventory seems a little aggressive. So -- and I'll leave it there, please.

[Jack H. Stark:]

Well, the -- the oil gas mix in the SCOOP area is going to vary depending on where we place rigs. You're exactly right. In the Woodford, you've got the transition play going from oil to gas, and we're focusing in the oil and gas condensate window there. And so we have -- and then in the Springer, the area we're focusing on is really just the oil window at this point. We're not pushing out too far to the West yet looking at the gas or the condensate and, say, a gas window there. And so I think that Springer play right now, you can expect for 2015, it's going to be an oil play. And the Woodford play itself, you can expect that we're going to have a good mix. Right now, we have the density pilots going on in both the gas, the condensate and the oil window, and we're attacking both the oil and the condensate window together.

[Douglas George Blyth Leggate:]

But Jack, is there any color you can add on the scale of the inventory in the Springer, I guess, is what I was getting at? Because 10 rigs, from what you told us, I think it puts you on a full-year drawing backlog.

[Jack H. Stark:]

So sure. I understand that. Really, Doug, we're just in the very beginning on the Springer here. The inventory that we put out there is based on like 46,000 net acres, and we've got another 72,000 net acres we're exploring into. So that was an area that we consider to be derisked. And we're expanding out into that and that's just in the oil window. We've got 200,000 acres total. And so the -- you could see that oil window inventory double easily in my mind. And we're doing a density test right now, 2 of them actually, to get a good handle on what density we can drill. So that inventory that you're looking at is a snapshot of what we really -- we're going to have in the future. This play is -- the play is for real, it's already showing great repeatability, as I said. And the beauty of this is, too, is what -- I don't think a lot of people realize that all of the Woodford wells that have been drilled actually have cut through the Woodford. So this thing is not -- is much -- it is probably the least speculative play I've had the opportunity to drill in, because we already have a well about every mile out here and so -- because the Springer is above the Woodford. And so as you drill to the Woodford, you're always getting a free look at it basically. And so we know where it's at. We can map it out. And so I think you can continue to expect good things coming out of the Springer.

[Operator:]

Our next question online comes from Drew Venker from Morgan Stanley.

[Andrew Venker:]

I was hoping you could provide a little bit more color on the Bakken inventory figure that you mentioned on spacing and productive zones and anything else you might think is pertinent.

[Jack H. Stark:]

Sure. I'm glad you asked that. Because just I think probably just -- get this, the inventory out there, and kind of discuss this again, we're really been showing our resource potential in the inventory. What we're trying to do is we're really trying to do 2 things. First is we're trying to show the resource potential across all of our acreage from the core out to the fringe, okay? And that's the one thing. And then, two, we're trying to show you, give you -- show you the quality of that inventory in a short-term and kind of a long-term perspective. And so the short-term perspective is, is if we were to drill nothing but our core areas, you'd be looking at 8 years at 775 MBoe average. But on a longer term, which is more representative of the type of blend that we would drill, we've got a 20-year inventory of 600 MBoe average per well. And so what are we going to drill? And if you're looking at your models and looking short term, what do you put in? I think our 700 MBoe program that we're talking about this year for 2015 is a really good representation of what we can expect to drill going forward here for the next, I don't know, 10 years. So that's really -- we're trying to provide color and some clarity on our inventory, and we're -- and I expect we're going to continue to see increases in EURs out here as technology advances. And so right now, this is a snapshot of what we know. And we would've shared this at the Investor Day, but we just didn't have enough information. Our teams, when I said that our teams had worked very hard to incorporate all industry activity as well as our own. I mean, they have done that. And they've got another 1.5 months of production plus they incorporated well over 300 wells in this study. And so to me, the -- at Investor Day, we just wanted a place when we said there was 8 years of over 600 MBoe average. We just couldn't put that 775 MBoe out there because we just didn't have enough evidence and confidence. But we have substantially increased our database, and so that's why we're able to come out with it at this time.

[Andrew Venker:]

That's helpful, Jack. On the way you're planning to add -- allocate capital, you said on a return to basis, the conventional wisdom would tell you, all else being equal, higher EURs translates to higher returns. Can you help us, as you think about the core, you said 775 MBoe on average versus the 700 MBoe you expect for your 2015 program, is there some other dynamics that maybe changes the return profile versus the EURs?

[John D. Hart:]

Yes, there are a number of factors that we looked at. We certainly looked at our positions into various areas. We looked at the wells that we were drilling and the EURs. But then beyond that, we have to look at infrastructure, how many rigs we can have in a particular area, takeaway capacity, the service, various other services are set up and established. So we went in with a view towards balancing all of those while factoring in the level of spend to reduce that but also maintaining a high production rate. So what you get for backing off as much capital as we did, we still have a very attractive growth rate for next year. That's a good indication to Jack's earlier point about the quality of our assets and how well we can grow. We've got a lot of scalability in this program, we continue to have that. And for -- $2 billion is a good maintenance capital number to have year-over-year flat levels of production. So there's a lot of scalability between those numbers and we try to balance all of that.

[Operator:]

Our next question online comes from Pearce Hammond from Simmons & Company.

[Pearce W. Hammond:]

Thanks for the color on the EURs, the update here. Just following up on that, would the 8 years of 775,000 Boe EURs, I'm assuming enhanced completions, is it fair to use that $9.6 million well cost number? Or do you think we should use something a little bit lower?

[John D. Hart:]

Yes, that $9.6 million is appropriate for that particular EUR. The $9.6 million that we're using are based on static costs that we've seen right now. And so, as you know, we've just started these completion tests between our own engineers and our field folks and our contractors. And over time, as we continue to work on these more standard completions that we're narrowing down to in the hybrids and the slickwaters, I expect there can be more cost reductions as we execute more efficiently.

[Pearce W. Hammond:]

Great. And then my follow-up, if oil prices were to weaken further, what level of HBP drilling requirements do you have that could influence the minimum amount of rigs that you need to run in the Bakken and the SCOOP?

[John D. Hart:]

The Bakken is largely HBP-ed within the accounted delineated area that we've shown on the map. It's in slides. It's in the 90%, 95% range. Some of that fringe acreage is pretty closer to 70%. So we're in a pretty good -- really good position in the Bakken. And in the SCOOP play, we can walk through that in the term and HBP that over the next 2 or 3 years at a substantially lower rig rate than we're at today. So I think we see both of those with our -- in our vision and don't have a near-term pressure. Certainly in 2015, we don't have a lot of pressure.

[Jack H. Stark:]

In addition to that in the SCOOP, majority of our leases provide for automatic extensions at extremely reasonable prices. So if we get in a bind we can always rely on that. In addition, we have top lease protection language. We're really covered with our leasehold in SCOOP and the Bakken.

[Operator:]

Our next question online comes from Brian Corales from Howard Weil.

[Brian M. Corales:]

Just maybe kind of to follow on the cost side in the Bakken, you're already down to $9.6 million. Can you talk about what that savings is? And then you always have these internal goals of declining that even further. Can you maybe talk about things that you're looking to do that could improve the cost even further?

[Jack H. Stark:]

Sure. That reduction from what was talked about earlier in Investor Day of $10 million, we were testing 40-stage jobs within that $10 million cost estimates as well as the 30-stage jobs. And so far this year, we've got over 50 tests that we're headed toward with 40 stages. And so we're planning to evaluate those, see how those perform. And if those provide incremental economics, we'll make decisions based on those. But going forward, what we're looking at is 30-stage jobs already proven with this incremental production as described earlier.

[Brian M. Corales:]

Okay. And maybe one follow-up. The Ears Back program, I mean, you kind of blow in and go in. Is there another area that is close to that sort of development in the Bakken?

[Jack H. Stark:]

We have an area called our Williston area. It's very highly productive, and we're concentrating a lot of rigs there also.

[Brian M. Corales:]

And where is that located?

[Harold G. Hamm:]

It's just on the West side of the anticline.

[John D. Hart:]

Yes. In Williams McKenzie County.

[Operator:]

Our next question online comes from Mr. Brian Singer from Goldman Sachs.

[Brian Singer:]

What oil price for 2015 have you configured your revised budget for? You mentioned you expect WTI can go to the mid-80s to $90 a barrel. If and when that happens, do you revert to your prior budget? Or if oil prices fall from here, given that you're now less hedged, would a further change be warranted?

[John D. Hart:]

We've modeled in current prices. So we're at an $80 WTI is in the current $4.6 billion model. We have a very expansive inventory. We certainly have that opportunity to expand, but I wouldn't expect us to change near term. We want to see the recovery, and we want to capture those benefits that Harold laid out in his script, focus on efficiency and cost in our area. And we're growing at a rather attractive growth rate with the current budget. So if we see a good recovery in 6 to 9 months. We'll look at it. But for the near term, the $4.6 billion we'd laid out is where we're going to stay.

[Brian Singer:]

Great. And as a follow-up, I wanted to pick up on some of the EUR commentary, as a bit of a follow-up to Pearce Hammond's earlier question, when you talk about having 20 years of 600,000 Boe EURs in the Bakken, does that contemplate enhanced completions across the portfolio? Or is it a blend of EURs without enhanced completions and with enhanced completions? And can you talk about that split, if so?

[Jack H. Stark:]

It includes enhanced completions.

[Brian Singer:]

Got it. So the other way to look...

[Jack H. Stark:]

I think that includes the 25% uplift.

[Brian Singer:]

Across the entire portfolio, i.e., you would only be using enhanced completions with the higher cost in that 20-year inventory?

[Jack H. Stark:]

That is correct. And 95% of what we're doing next year includes enhanced completions. That's where we're seeing the biggest bang for our buck.

[John D. Hart:]

It also factors in that we've got enough there, inventory in the areas where we've seen the uplift benefit. So we've got plenty of running room there for that 20-year period.

[Operator:]

Our next question online comes from Leo Mariani from RBC.

[Leo P. Mariani:]

Guys, could you speak to your SCOOP production levels in the third quarter? It looks like your growth there kind of slowed down despite the fact that you had a lot of wells. I guess roughly 20 net wells, it looks like, were completed. Is there anything going on there in terms of infrastructure limitations or potentially delays in well completions that caused your growth to slow there in 3Q?

[Jack H. Stark:]

Yes. Leo, that kind of stands out, but that's really just a timing issue. And right now, what this month between...

[John D. Hart:]

40,000.

[Jack H. Stark:]

What was it the month of October, we averaged 40,000.

[John D. Hart:]

Exactly.

[Jack H. Stark:]

So you can see it's jumped up about 4,000 barrels a day. So it's coming on. It's just that there's -- some of these oil wells come on a little bit lower rate initially and they clean up. And then with pads and timing, that's what's really affecting it.

[Leo P. Mariani:]

Okay, that's helpful for sure. I guess just in terms of oil diffs, you guys talked about seeing a little bit wider diff here in the third quarter. Can you give us an update on what you've been seeing recently on your oil diffs there in the Bakken and kind of what your expectations are heading into 2015?

[John D. Hart:]

That's a great question, Leo. What we're going to see is the diffs pushing back down and we're getting more pipe access out of the Bakken that's going to improve that. We're going to have better connection on the SCOOP barrels into Cushing. We found very good market. The Springer oil has really lit up the market in the Mid-Continent for that oil. They love that oil, and so we're getting good competition for that oil. The pipelines that's delivering oil into the Cushing market, you're getting a pure Bakken barrel into that market and it's going to be pulling a very good price. It's got strong demand. It's much better quality than a blended WTI equivalent. So we should see the number we saw in the third quarter start improving immediately and get very -- much better, get back into our lower part of our range, hopefully, by middle of next year.

[Operator:]

Our next question online comes from Phillips Johnston from Capital One.

[Phillips Johnston:]

I just wanted to ask you about your growth profile throughout next year. If we look at 2014, you've had very strong sequential growth in every quarter of the year, so it sort of sets up a pretty easy comp for the '15 average versus the '14 average to where you -- even if you kept volumes flat throughout the year at the 200,000 exit rate, you'd probably still post around 15% growth. So given that and also just the fact that the cut to CapEx is likely probably going to have more of an impact on production in the second half of '15 rather than the first half, my question is can you give us a sense for where you expect your '15 exit rate will be versus the 200,000 exit rate for this year?

[John D. Hart:]

We haven't guided to the exit rate for '15, but let me give you a little color there. I agree holding flat at 200,000 would give you about a 15% growth next year. To give you a little color on that, that'd be a CapEx somewhere in the $2.7 billion range across the company. That's another way we look at maintenance capital. Earlier, I gave you holding 0% growth year-over-year is around $2 billion, but holding at that exit would be in that genre. What we see next year, as currently modeled, we're seeing fairly consistent growth next year throughout the year. Obviously, the shifting of pads or timing, if we had any shifting of those that could impact that. Pads, do have an impact on that production. But we currently see pretty consistent growth throughout the year, so you're exiting at an exit rate that's substantially higher, say, 40,000 a day higher than where we are today. I'm not giving that as guidance, because we do shift around, but your modeling is going to indicate somewhere in those ranges.

[Phillips Johnston:]

Okay, great. And just to follow up on the hedges. If we assume oil prices do recover from here, at what price would you consider re-hedging some of your production for '15 and maybe hedge some of your '16 volumes as well?

[Harold G. Hamm:]

Well, we -- obviously, a lot of talk back out there for eventual hedging opportunities in the $100 barrel range again. And certainly, we would hope to see that, that we could reset those. And that would be nice in the next few years.

[John D. Hart:]

And recognize we look at Brent and WTI on our hedging just because of we're selling production, so we would look at both of those and you can have some variability. You've seen the average prices that we were hedged at before, and as you start to move into those areas, it becomes more attractive. We're looking for areas that we think are indicative of the pricing environment going forward.

[Operator:]

Our next question comes from Noel Parks from Ladenburg Thalmann.

[Noel A. Parks:]

A couple of things. With the change to the production guidance for next year, can we still consider the 5-year target of tripling production reserves? Can we still consider that intact? And I think at the Analyst Day, the thinking was that you might get there with production by the end of '16.

[John D. Hart:]

Yes, we remodeled that. We've looked at it. Really doesn't have a material impact on our 5-year plans as in terms of achieving that goal. We think we're still on track. What we've indicated at Investor Day is we saw that pulling forward a year into late 2016. Our current model still shows us on track. I would maybe say we were in the -- we expect to achieve that triple in late '16, early '17. But again, just to clarify, right now, we still see us on track for late '16.

[Noel A. Parks:]

Great. And with the production growth that we saw for third quarter, I noticed that Montana actually had a pretty hefty sequential increase. I think it was about 15% increase in volumes over second quarter. Was just that related to pad drilling you had going on there and a lot of stuff coming on all at once? Or is there another factor in there?

[Jack H. Stark:]

It's just natural fluctuation of how we allocate rigs out there. We're doing various tests -- have done various tests in North Dakota and Montana. Going forward, we're going to have probably a lot more focus in North Dakota in the coming year.

[Operator:]

Our next question online comes from Joe Allman from JPMorgan.

[Joseph D. Allman:]

Just a question on the EUR uplift. So I think your 775,000 Boe EUR assumes a 25% uplift from the completion modifications. Does that assume that the kind of early production is a higher uplift versus the baseline? Because typically, we see the EUR uplift lower than the early production uplift.

[Jack H. Stark:]

Right. That assumes just a shift up in the type curve. And so you've heard the numbers we've seen so far as far as having a larger 25%, 30% uplift, we've seen a 45% uplift with our test. And so we think there's some additional upside there.

[Noel A. Parks:]

Okay. So just to clarify. So do you think that the early production uplift would match the overall EUR uplift? So in other words, just on a blended basis, the early production 30-, 60-, 90-day plus early production uplift will be roughly 25% and therefore, the EUR will be 25%. Or do you think overall...

[Unknown Executive:]

Overall, we think the production uplift in the early days will be more than later. And that's for 2 reasons. One is the data that we've already shown and reflected earlier in Jack's comments, where we've seen 45% production uplift along with a 30% EUR increase. And then the second part would be part of what we're doing is not only the completion uplift, but we're also working with higher volume artificial lift. And so when we do that, that accelerates part of it forward. So that's an additional benefit to us.

[Joseph D. Allman:]

Okay, that's helpful. And then on your change in the CapEx budget, the table at the end of the press release is very helpful, the change from the prior budget and where the changes are. But how about from the current level of activity, could you just describe for us what's going to happen in terms of rig count in various areas between now and 2015?

[John D. Hart:]

Okay. We've -- what we're doing in the '15 CapEx budget is we're going to hold rigs fairly constant with where we're at today. So in the SCOOP area for next year, we're going to average 26 rigs. We're right at 26, 27 today. We had more than that a few weeks ago, but we're starting to shift rigs into Northwest Cana with the JV. So we expect to have 4 rigs in there. In the Bakken, we're shifting some rigs out of Montana. And then we're shifting some rigs out of the -- out of the broader extents of the play and coming in -- back into some of the areas we're talking about. The Bakken, we expect to go from 22 rigs average in the original budget down to 19. And that's kind of the general working range that we've been in the Bakken.

[Joseph D. Allman:]

So John, give me that again. So where are you now in the Bakken and where you're going to be in 2015?

[Unknown Executive:]

Right now, we're at about 22 rigs in the Bakken. We're going to be at 19 next year.

[Operator:]

Our next question online comes from Eric Otto from CLSA Americas. Our next question comes from Dan Guffey from Stifel.

[Daniel D. Guffey:]

Guys, you did a really good job at your Analyst Day kind of walking through the Bakken petroleum system and laying out 4 different zones throughout the basin. With dropping 3 rigs, you're moving to 19 into next year. It looks like 3 have been dropped from kind of fringier areas. So all 19 are going to be running kind of in the Tier 1 and Tier 2 acreage. I guess what drives your decision to allocate capital to that Tier 1? Why not focus entirely on the core where you think you have maximum overpressure and also structure?

[Harold G. Hamm:]

Well, we continue to prioritize our drilling schedule according to rate of return. And so that's what drives it.

[Daniel D. Guffey:]

Okay. And on the 40-stage completions that you've tested, over 50, should we have a decision do you think by next quarter? Or will you need to see longer-term production data before you decide to maybe return to that 40-stage completion design?

[Jack H. Stark:]

I think that we'll give a lot these in the Q, where we can monitoring production in the first quarter, late first quarter, probably next year in the second quarter. So maybe mid-year next year, we'll start having a good enough perspective. I mean, you know what we've done on the 30 stages. We were patient and wanted to make sure we've got some information before we did any adjustments to our EURs. And so we're going to do the same there. So I don't see us really being confident enough to say much until probably mid-year next year about the 40s.

[Operator:]

Our next question online comes from Paul Grigel from Macquarie.

[Paul Grigel:]

Just in regards to service pricing outlook. Obviously, given the pullback, have you guys had any discussions or have there been any ongoing in terms of renegotiating service pricing going forward?

[John D. Hart:]

Yes. We have begun those discussions. And certainly, with the pricing changes that we've had, besides seeing cost reduction in the future from some better execution from ourselves and our operations, we expect to see some cost reductions also from our contractors. As it goes right now, there's still a lot of demand out there as some of the rig activity and completion actively hasn't changed much. But we have begun those discussions with our vendors.

[Paul Grigel:]

And then just another strategic kind of follow-up here. In terms of acquisitions, more specifically to acreage, be it either in the SCOOP or up in the Williston Basin in a, let's say, a downtrodden price environment moving forward, what's the appetite for potentially adding acreage?

[Harold G. Hamm:]

Well, we've had a good appetite for acquiring acreage. I think it's too soon for any meaningful changes happening out there in the industry. We've not seen fire sales yet, so we'll just have to see how that plays out. We do control a lot of our destiny here in SCOOP and same way in the Bakken. So there's going to be opportunities and we'll monitor those.

[Operator:]

Our next question online comes from Marshall Carver from Heikkinen Energy.

[Marshall H. Carver:]

Yes. So my first question is, is the addition of rigs in the gassier Northwest Cana change your expectation to oil gas mix in '15? Or is it still likely 69% to 70% oil?

[John D. Hart:]

Still in the same range. It doesn't change it. We've factored it in when we were looking at it previously and giving some viewpoints on that.

[Marshall H. Carver:]

Okay. And then second question...

[John D. Hart:]

Additionally we had some existing production with that, where we sold -- obviously, they acquired a 50% interest in what we had. So we actually sold some of our gas production, and the drilling will just build back a portion of that.

[Marshall H. Carver:]

Okay. And second question, we've heard that the Springer is difficult to drill. Would you say that's a fair characterization? And can you compare and contrast the drilling days for the Springer versus the Woodford?

[Harold G. Hamm:]

We've heard that from some other operators. We've not had much difficulty ourselves with Springer. It was maybe 1 or 2 instances, but our people getting the job done. We're very proud of the operation we have out there.

[Marshall H. Carver:]

Okay. What were the -- are there any specifics you could share with the 1 or 2 instances?

[Harold G. Hamm:]

Well, it's a -- you know a lot of things can bite you here, we're operating at some pretty good depths. This is big boy drilling, as we call it. And so normally, the staff, that wouldn't be a problem at 12,000 plus could be. But our guys are up to it and we have good people, we've got the best equipment. So I think our folks are getting it down and making a lot of good progress in this area. So just we don't have any one thing that's caused us a lot of issues.

[Operator:]

Our last question comes from Pearce Hammond from Simmons & Company.

[Pearce W. Hammond:]

My follow-up is with John Hart. John, you were going through some capital numbers that would either keep production flat or grow production. And just to clarify, so you said $2.7 billion in capital would give you 15% year-over-year growth, so that would be '15 over '14?

[John D. Hart:]

Let me give you those numbers again just to make sure we're clear. There are different ways to look at maintenance capital. One is you're looking at just year-over-year total production. With our growth rate quarter-upon-quarter sequentially and with the steepness of that curve, you get a different answer looking at year-over-year production versus your exit rate. So year-over-year, to hold total production flat somewhere in the $2 billion range. If you look to what we are -- our exit rate for the year, which we've indicated we expect to be 200,000 a day. Holding that 200,000 flat would be about $2.7 billion of capital that, that would require. The difference between that exit rate in that annual production, those 2 numbers, that's about a 15% growth rate.

[Operator:]

And John, there are no more questions in the queue.

[John J. Kilgallon:]

Well, thank you, everyone for joining our call today. If you have further follow-up, please let myself or Warren Henry know. That concludes our call.

[Operator:]

Thank you, ladies and gentlemen. This concludes today's conference. Thank you for participating. You may now disconnect.