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Edited Transcript of WLL earnings conference call or presentation 27-Apr-17 3:00pm GMT

Thomson Reuters StreetEvents

Q1 2017 Whiting Petroleum Corp Earnings Call

Denver Apr 29, 2017 (Thomson StreetEvents) -- Edited Transcript of Whiting Petroleum Corp earnings conference call or presentation Thursday, April 27, 2017 at 3:00:00pm GMT

TEXT version of Transcript

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Corporate Participants

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* Eric K. Hagen

Whiting Petroleum Corporation - VP of IR

* James J. Volker

Whiting Petroleum Corporation - Chairman, CEO and President

* Mark R. Williams

Whiting Petroleum Corporation - SVP of Exploration and Development

* Michael J. Stevens

Whiting Petroleum Corporation - CFO and SVP

* Rick A. Ross

Whiting Petroleum Corporation - SVP of Operations

* Steven A. Kranker

Whiting Petroleum Corporation - VP of Acquisitions & Reservoir Engineering

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Conference Call Participants

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* Brian Michael Corales

Scotia Howard Weil, Research Division - Analyst

* David R. Tameron

Wells Fargo Securities, LLC, Research Division - MD and Senior Equity Research Analyst

* Gail Amanda Nicholson

KLR Group Holdings, LLC, Research Division - MD

* Graham Price

* Jeffrey Leon Campbell

Tuohy Brothers Investment Research, Inc. - Senior Analyst of Exploration and Production, and Oil Services

* Kashy Oladipo Harrison

Piper Jaffray Companies, Research Division - VP and Senior Research Analyst, Exploration and Production

* Michael Adam Glick

JP Morgan Chase & Co, Research Division - Senior Analyst

* Michael Anthony Hall

Heikkinen Energy Advisors, LLC - Partner and Senior Exploration and Production Research Analyst

* Neal David Dingmann

SunTrust Robinson Humphrey, Inc., Research Division - MD

* William Orin Green

Stephens Inc., Research Division - MD

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Presentation

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Operator [1]

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Good morning. My name is Keith, and I will be your conference facilitator today. Welcome, everyone, to the Whiting Petroleum Corporation First Quarter 2017 Financial and Operating Results Conference Call. This call will be limited to 1 hour, including Q&A. (Operator Instructions) Please note, this event is being recorded. I'd now like to turn the conference over to Eric Hagan, the company's Vice President of Investor Relations. Please go ahead, sir.

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Eric K. Hagen, Whiting Petroleum Corporation - VP of IR [2]

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Thank you, Keith. Good morning, and welcome to Whiting Petroleum Corporation's First Quarter 2017 Earnings Conference Call. During this call, we'll review our results for the first quarter, and then discuss the outlook for the second quarter and full year 2017. This conference call is being recorded, and will also be available on our website at www.whiting.com. And to access the presentation slides, please click on the Investor Relations box on the menu, and then click on the Presentations & Events link.

Please note that our remarks and answers to questions include forward-looking statements that are subject to risks that could cause actual results to differ materially from those in the forward-looking statements. Additional information concerning these risks is set forth on Slide #1 and in our earnings release. Reconciliations of non-GAAP measures we refer to and GAAP measures can be found in our earnings release and at the end of our webcast slides. Please take note that our Form 10-Q for the quarter ended March 31, 2017, is expected to be filed later today. And with that, I'll turn the call over to Jim Volker.

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James J. Volker, Whiting Petroleum Corporation - Chairman, CEO and President [3]

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Thank you for joining us, everyone. Let's begin on Slide 2. It was a great quarter for Whiting. Production came in at the high end of guidance, while costs came in below expectations. Earnings per share and cash flow per share exceeded consensus estimates. Capital expenditures of $186 million were below analyst estimates.

On the operating side, we continued to achieve cost savings, with the first quarter LOE, G&A, and interest expense per BOE at the low end of guidance. As detailed in our press release, Whiting's operations team made excellent progress during the downturn on items that drive LOE. They reduced well downtime by 22%, and saltwater disposal cost by 10%. DD&A per BOE benefited from the improvement in capital efficiency related to enhanced completions, as well as the sale of our North Dakota midstream assets, and came in below the low end of guidance. First quarter oil differentials were well below the low end of guidance, benefiting from the addition of new pipeline infrastructure in the Williston Basin.

Our enhanced completions continue to exceed expectations. The Loomer pad is tracking a 1.5 million-barrel of oil equivalent type curve after 50 days of production. We've also raised our 2017 production forecast, and lowered per-BOE cost guidance for LOE, G&A, interest expense, DD&A, and oil and gas differentials. Therefore, as you can see, the improvements we've made in costs and well productivity allow us to operate effectively and efficiently in the $40 to $50 oil price environment. As you can see on Slide #3, with a focus on the Bakken and the Niobrara, our total net production averaged 117,360 BOE per day in the first quarter. At 109,125 BOEs per day, the Bakken/Three Forks represented 93% of our total production.

On Slide #4, we provide an overview of the Williston Basin, where we control approximately 0.5 million net acres, of which 99% is held by production. It also shows the location of our Loomer pad. On Slide #5, you can see that our Loomer pad is tracking a 1.5 million BOE type curve. The pad was completed significantly west of our prior reported enhanced completions in McKenzie County.

Slide #6 depicts our Redtail field in Colorado, where we plan to complete 105 DUCs in 2017. Earlier this week, we added a second frac crew at Redtail. We are testing enhanced completions on our first 2 pads that will incorporate up to 50 stages, and up to 8 million pounds of sand per well. Mike Stevens, our CFO, will now discuss our financial results in the first quarter of 2017.

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Michael J. Stevens, Whiting Petroleum Corporation - CFO and SVP [4]

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On Slide #7, we show our first quarter 2017 financial results. Our discretionary cash flow was $183 million, which was in line with our CapEx of $186 million. On Slide #8, you can see our liquidity and debt covenants. Our $2.5 billion borrowing base was reaffirmed this month, with 100% approval from the 24 banks in the syndicate. We had $450 million drawn at quarter-end, and have no debt maturities until 2019. We remain well within all of our covenants, and are strongly positioned from the liquidity and debt maturity perspective. Our guidance for the second quarter and full year 2017 is detailed on Slide #9. We are increasing our full year production guidance and lowering our cost per BOE guidance across the board. The improvements we have made in our cost structure and well productivity, along with our hedge positions, will allow us to operate effectively and efficiently in a $40 to $50 oil price environment. Our full year CapEx budget remains unchanged at $1.1 billion.

Slide #10 shows our crude oil hedge positions as of March 31, 2017. We are 53% hedged at attractive prices for the remainder of this year. With that, I'll turn the call back over to Jim.

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James J. Volker, Whiting Petroleum Corporation - Chairman, CEO and President [5]

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Whiting has delivered 3 straight quarters of production at the high end of guidance, with CapEx in line or below expectations. We've also consistently improved our cost structure and delivered major productivity increases in the Bakken. This is a testament to the quality of our assets and the strength of our team. Keith, please open up the conference call for questions.

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Questions and Answers

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Operator [1]

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(Operator Instructions) And this morning's first question comes from Graham Price with Raymond James.

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Graham Price, [2]

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So with regard to the 2 Redtail pads that you'll bring online in May, was just wondering if any of those wells are going to be drilled with the longer 10,000-foot laterals? And then kind of how we should expect those longer laterals to come online through the rest of the year.

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Rick A. Ross, Whiting Petroleum Corporation - SVP of Operations [3]

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This is Rick Ross. The 2 pads that we mentioned with the enhanced completions are all 960-acre spacing units. We do have 34 1280 wells that we'll be completing later in the year.

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Graham Price, [4]

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Okay, perfect. And then real quick for my follow-up. I guess with the resumption of strong production growth expected for the back half of the year, I was wondering how you see kind of the overall base decline rate trending throughout the year.

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James J. Volker, Whiting Petroleum Corporation - Chairman, CEO and President [5]

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It's going to stay fairly stable. It may increase. I think Steve ran some numbers that shows it may increase 2% or 3% by year-end.

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Steven A. Kranker, Whiting Petroleum Corporation - VP of Acquisitions & Reservoir Engineering [6]

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That's a result of bringing on new production. That's all.

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Operator [7]

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And the next question comes from Michael Glick with JPMorgan.

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Michael Adam Glick, JP Morgan Chase & Co, Research Division - Senior Analyst [8]

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Just in the Williston, we did some mapping and measuring last night. And the area where you all are posting 1.5 million barrel type wells has grown and is quite large geographically in terms of square miles. In that context, how should we think about the distribution of your rigs across your acreage as we move through the year? Just if I look at your rig distribution right now, looks like you've got 1 down in Stark, 2 kind of along the river, and 2 in Central Williams.

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Mark R. Williams, Whiting Petroleum Corporation - SVP of Exploration and Development [9]

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Right. Mark Williams here. We have, and continue to have rigs across the basin in all 7 of our geo plays, so going forward, in addition to the areas that you've mentioned, we'll be doing more drilling in Dunn County, as well as McKenzie County. We've got a little bit more drilling to do down in Stark, but we'll be winding that up here sometime around the end of the second quarter, and then we'll continue to drill there along the river, both in Williams and McKenzie County on both sides of the river there.

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James J. Volker, Whiting Petroleum Corporation - Chairman, CEO and President [10]

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Yes, so to follow on Mark's answer. So we view all of our acreage, each one of our 7 plays, as capable of getting to 1.5 million BOEs per well. That's why our rigs are scattered in all 7 plays.

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Michael Adam Glick, JP Morgan Chase & Co, Research Division - Senior Analyst [11]

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Got you. And then just how should your working interest in the basin trend during the year as the JVs roll off?

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James J. Volker, Whiting Petroleum Corporation - Chairman, CEO and President [12]

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It'll be typically between 60% at a low and 90% at a high, working interest.

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Operator [13]

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And the next question comes from Neal Dingmann with SunTrust.

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Neal David Dingmann, SunTrust Robinson Humphrey, Inc., Research Division - MD [14]

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Jim, it seems that, speaking with some investors, they believe that much of your, I would say, 2017 plan success relies on the $55 or higher oil. Could you address what you believe, how the plan would fare in sort of a $45 to $55 range. I mean, by my judge, it looks like the economics are still quite good and the activity should be good. But I just like to hear your color on it.

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James J. Volker, Whiting Petroleum Corporation - Chairman, CEO and President [15]

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Right. No, our activity is designed to take us forward even at -- even at a $40 oil price environment. So I would say, we certainly wouldn't consider cutting back until the trend got below $45. And I see everything that we're doing in 2017, and for that matter, what we planned in 2018, already as being very economic even at $40 or $45 oil, so.

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Neal David Dingmann, SunTrust Robinson Humphrey, Inc., Research Division - MD [16]

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So you'd go forward, tackling the DUCs and everything, Jim, you would go forward with that?

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James J. Volker, Whiting Petroleum Corporation - Chairman, CEO and President [17]

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Absolutely, yes, yes. We have flexibility should something untoward happen. Should oil prices, I'm going to say, stay consistently below $45, and maybe even get below $40, something like that. We have plenty of flexibility to do that. We're running, I'll say, only 6 rigs, 5 in the Bakken, 1 at Redtail. We recently renewed 3 rigs at day rates that are almost $10,000 a day lower than the prior rates. And we were able to do that with extensions of the rig contracts of only 6 to 12 months. So we could drop all of those rigs for nominal fees. And in addition, we have 2 of our rigs that expire later this year in November. So, and we have 4 completion crews running, and we could drop all of them on a month's notice. So I would say we're in a great flexible position, and I would say the kind and quality of wells that we're completing make good sense even in the mid-40s.

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Neal David Dingmann, SunTrust Robinson Humphrey, Inc., Research Division - MD [18]

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Great, Jim. And then lastly, Jim, for you or one of the other guys. Just on differentials, obviously, with DAPL and other things coming on, seems that for you and others in the basin, differentials really continue to improve. Can you talk about how you foresee those remainder of the year and into '18?

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James J. Volker, Whiting Petroleum Corporation - Chairman, CEO and President [19]

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Yes, it's been a nice change, for sure, coming down least a couple bucks already. Some of our areas in the Bakken now are in the low 5s, and the outlook is actually for that to even improve a little bit more. We haven't put that in our guidance yet. But I would say that the outlook is for continuing shrinking differentials in the Bakken.

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Operator [20]

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And the next question comes from Brian Corales with Howard Weil.

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Brian Michael Corales, Scotia Howard Weil, Research Division - Analyst [21]

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With some of the Bakken results that we've seen with these really big wells like the Loomer wells, what -- I'm assuming that's well above what you all planned, I guess, for guidance for 2017. Can you maybe talk about what the well performance is, what you're currently seeing versus what you planned for the year?

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Eric K. Hagen, Whiting Petroleum Corporation - VP of IR [22]

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Brian, it's Eric. I think it's kind of evident in the fact that we keep on either coming in or exceeding the high end of guidance. So really that's really the best numerical estimate we can give you, so.

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Brian Michael Corales, Scotia Howard Weil, Research Division - Analyst [23]

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And can you maybe quantify how many well completions, say, first half or second half in the Bakken?

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James J. Volker, Whiting Petroleum Corporation - Chairman, CEO and President [24]

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Well, in our last call, we said there were 70 wells in the first half, of which 55 were in the Bakken and 15 at Redtail. And then in the second half of the year, 163 wells in total, of which 68 are in the Bakken and 95 at Redtail. No change. Still in that range.

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Brian Michael Corales, Scotia Howard Weil, Research Division - Analyst [25]

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Okay. And one final one. At Redtail, with all the DUCs, are all those on the southern acreage of Redtail, the DUCs you'll be completing?

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Mark R. Williams, Whiting Petroleum Corporation - SVP of Exploration and Development [26]

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The DUCs that we're completing are all on the east side of Razor and west side of Horsetail. So that's all in the very best part of the field.

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James J. Volker, Whiting Petroleum Corporation - Chairman, CEO and President [27]

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Just where the completion rigs are right now. It's where the completion rigs and frac crews are in our development for the entire area. And Mark's correct. It's a very good part of the field. But frankly, based upon all the results we've seen, we actually believe that a large portion of our acreage as we continue to expand concentrically from where we have been growing will look just as good as what we've drilled to-date. And we're pretty excited as we move to the west in terms of how the Codell is thickening up out there.

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Operator [28]

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And the next question comes from David Tameron with Wells Fargo Securities.

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David R. Tameron, Wells Fargo Securities, LLC, Research Division - MD and Senior Equity Research Analyst [29]

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The Niobrara JV that was potentially discussed. If I remember right, you kind of said $50 was the -- was kind of the magic number, you'd look at that as far as $50 crude. Where does that stand and what's your thoughts on that?

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James J. Volker, Whiting Petroleum Corporation - Chairman, CEO and President [30]

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Well, the first 44-well joint venture is largely complete, with 4 wells remaining to be completed in May. And the second 30-well joint venture at Pronghorn has 20 wells remaining. And they'll be completed between May and January of '18. And in terms of answering the second part of your question, we don't have any plans for further JVs in the Williston Basin. As for the Niobrara, there are several parties who have contacted us and are interested in doing drilling out there because they realize we've got 5,000 drilling locations. So we are talking to some of them, and they -- as I think we've just tried to convey here, they like the economics even with oil in the $40 to $50 range.

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Operator [31]

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And the next question comes from Will Green with Stephens.

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William Orin Green, Stephens Inc., Research Division - MD [32]

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Very impressive work on the Loomer pad. It looks like to me that 2 of the 3 of those are Three Forks. First of all, is that right? And then secondly, of all these recent completions, because I know you guys have a bunch of them now that are tracking over 1 million, what's kind of a general split on how many of those have been in the Bakken or Three Forks? If you just help us understand if this is a phenomenon that's extending to the Three Forks as well.

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Mark R. Williams, Whiting Petroleum Corporation - SVP of Exploration and Development [33]

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So our typical wine rack involves staggered Bakken/Three Forks development programs. So we're drilling roughly the same number of Three Forks wells as we are in the Bakken, plus or minus a few in different areas. In this case, it was 2 Three Forks wells and 1 Bakken well. So we have had good luck in our geo-steering efforts in the Three Forks as we targeted the best part of the Three Forks. That's had an impact. And the larger completions that you mentioned, especially on the Loomer pad, 8 million and above, have been very effective on Three Forks, as they have in the Bakken as well.

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James J. Volker, Whiting Petroleum Corporation - Chairman, CEO and President [34]

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And I'd like to point out, too, Will, that some of the prior completions we've reported, the 1.5 million barrel wells in the McKenzie County, the majority of those wells were actually Three Forks.

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William Orin Green, Stephens Inc., Research Division - MD [35]

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Yes. That's great to hear. I mean, I ask because I think that there's kind of a common thought that Three Forks -- I think there's a common thought that maybe the Three Forks can't be as productive as the Bakken, and it's great to hear that you guys are seeing the same type of luck in the Three Forks. The second thing I wanted to hit on is, I know you guys are revamping kind of the completion style in Redtail this year. I also have noticed -- and granted, you guys aren't going to raise type curves there until you actually see it. But you guys are still targeting 465 and 655 on the 960s and 1280s down there. It's fair to assume that that's what you guys, or something similar is what's running through your guidance for this year. And if you saw any kind of benefit from enhanced completions this year, that would kind of be icing on the cake. Is that fair to assume?

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James J. Volker, Whiting Petroleum Corporation - Chairman, CEO and President [36]

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Yes.

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Operator [37]

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And the next question comes from Jeffrey Campbell with Tuohy Brothers.

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Jeffrey Leon Campbell, Tuohy Brothers Investment Research, Inc. - Senior Analyst of Exploration and Production, and Oil Services [38]

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I'd like limit my 2 questions to Redtail. The press release said that both of the tests have around 50 stages, but varying amounts of sand. I think 5 million and 8 million were quoted. I'm just wondering what was the thinking behind the variance in the sand loadings.

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Rick A. Ross, Whiting Petroleum Corporation - SVP of Operations [39]

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This is Rick Ross. The idea was just, number one, to test the impact of additional stages holding proppant concentration steady on 1 pad. So we went from 30 to 50 stages. And then the second was to test what would the impact be of larger proppant loading. So in that one, we held the 50 stages constant and ramped up to 8 million pounds. So we wanted to test both concepts. More entry points, better distribution, as well as increased proppant loading and maybe more complexity.

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James J. Volker, Whiting Petroleum Corporation - Chairman, CEO and President [40]

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And interestingly, Jeffrey, we see the well cost only going up around $300,000 as we move from 30 stages with 4.5 million pounds to 50 stages with 5 million pounds. And then only about $0.5 million increase as we go and hold the stages constant at 50 and move the sand up to 8 million pounds.

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Jeffrey Leon Campbell, Tuohy Brothers Investment Research, Inc. - Senior Analyst of Exploration and Production, and Oil Services [41]

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That's interesting. That was a really helpful answer because it's obvious that you're -- it will isolate the 2 variables. One -- get it to 1 variable in each well. I just want to ask one last follow-up on that. Are you testing all of the zones in these -- the 3 Niobraras and the Codell in these NS completions?

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Rick A. Ross, Whiting Petroleum Corporation - SVP of Operations [42]

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We are.

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James J. Volker, Whiting Petroleum Corporation - Chairman, CEO and President [43]

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Yes.

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Operator [44]

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And the next question comes from Kashy Harrison with Simmons Piper Jaffray.

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Kashy Oladipo Harrison, Piper Jaffray Companies, Research Division - VP and Senior Research Analyst, Exploration and Production [45]

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So can you walk us through how many wells you would need to turn sales with these new enhanced completions before you would feel comfortable enough to run the entire program on those completions?

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James J. Volker, Whiting Petroleum Corporation - Chairman, CEO and President [46]

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You mean the Niobrara or the Williston?

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Kashy Oladipo Harrison, Piper Jaffray Companies, Research Division - VP and Senior Research Analyst, Exploration and Production [47]

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In the Williston.

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James J. Volker, Whiting Petroleum Corporation - Chairman, CEO and President [48]

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In the Williston, we're already doing 100% advanced completions, which Rick can give you more detail on.

Yes. Basically, we're already at 9 million pounds, 9 million to 10 million pounds, and how many stages, Rick, 50?

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Rick A. Ross, Whiting Petroleum Corporation - SVP of Operations [49]

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Generally, about 40 stages in the Bakken is what we we're completing with. And as we mentioned, we will be trying some higher proppant loading. About 16% of our completion program in 2017 will be at higher proppant loading, 10 million plus, 10 million to 15 million pounds. I guess to answer your question, we've switched to all enhanced completions in our program. And we're just testing the upper limits right now in 2017.

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James J. Volker, Whiting Petroleum Corporation - Chairman, CEO and President [50]

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We'd also say that because of our core lab, we believe that we have some good insights. And therefore, all of our frac jobs are customized for the particular reservoir rock conditions at each location.

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Kashy Oladipo Harrison, Piper Jaffray Companies, Research Division - VP and Senior Research Analyst, Exploration and Production [51]

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Got it. And last quarter, you provided the maintenance CapEx estimate of $900 million to hold full Q '17 production flat into '18. So was that predicated on the 1.5 million barrel wells in the Williston? Or was that predicated on 900,000 barrel wells in the Williston?

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James J. Volker, Whiting Petroleum Corporation - Chairman, CEO and President [52]

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The 900 million (sic) [900,000] is an estimate. It wasn't predicated on any of these bigger completions. We actually think that, that number is probably coming down a little bit now. But we just got to wait and see how the program goes this year and it will be easier to estimate it when we get later into the year.

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Kashy Oladipo Harrison, Piper Jaffray Companies, Research Division - VP and Senior Research Analyst, Exploration and Production [53]

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Got it. And then just switching gears to service cost. How has inflation come in year-to-date relative to your expectations? And what are your expectations over the course of the rest of the year?

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Rick A. Ross, Whiting Petroleum Corporation - SVP of Operations [54]

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I think pretty much in line with our expectations. We -- our service company costs have increased, and that's reflected in our guidance. For a Bakken well, we've seen an increase of about $200,000 on the total well cost, which translates to 2.8% on a total well. But we have been able to offset about $180,000 of that through improved efficiencies in our completion process. And as Jim mentioned earlier, some of the revised drilling contract rates. So we've been able to offset a fair amount of it. And I think just to keep things in perspective, the actual sand or proppant cost reflects only about 4% of the total well cost. So it's fairly small.

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Operator [55]

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And the next question comes from Michael Hall of Heikkinen Energy Advisors.

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Michael Anthony Hall, Heikkinen Energy Advisors, LLC - Partner and Senior Exploration and Production Research Analyst [56]

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I guess couple questions. One, just on the -- going back on the enhanced completions on the Williston. As you guys continue to get more and more data and new results throughout your position, are you seeing any variability as it relates to how well the various parts of your acreage position are taking to these enhanced completions? Has it been pretty consistent across the board?

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Rick A. Ross, Whiting Petroleum Corporation - SVP of Operations [57]

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Yes. We have seen positive consistent results across all of our acreages. We were discussing before, we're drilling 7 different areas on all corners of the basin, essentially. And so our enhanced completions have been successful in all of those up to about 9 million pounds. And we're testing above that we -- which we mentioned.

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Michael Anthony Hall, Heikkinen Energy Advisors, LLC - Partner and Senior Exploration and Production Research Analyst [58]

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Okay. So the kind of uplift relative to, I guess, kind of parent well or offset well has been pretty consistent throughout the acreage footprint?

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James J. Volker, Whiting Petroleum Corporation - Chairman, CEO and President [59]

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Yes.

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Michael Anthony Hall, Heikkinen Energy Advisors, LLC - Partner and Senior Exploration and Production Research Analyst [60]

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Great. And then I guess just to circle back on the prior question, just to confirm I heard it right. As it relates to DAPL and how that's being factored into the new guide. I guess, how much of the improvement that you've seen thus far is factored into the rest of the differential guide? Is that all factored in, or is it...

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James J. Volker, Whiting Petroleum Corporation - Chairman, CEO and President [61]

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We've only factored in what we've seen so far. The thought is that the differentials, the best insight we have with all of our marketing individuals, is that it's probably going to tighten up a little more as we go through the year and DAPL actually starts flowing. We start putting barrels on it June 1 ourselves.

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Michael Anthony Hall, Heikkinen Energy Advisors, LLC - Partner and Senior Exploration and Production Research Analyst [62]

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Okay. And so I guess what would you say is like a realtime differential, as you see it?

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James J. Volker, Whiting Petroleum Corporation - Chairman, CEO and President [63]

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Michael, we said at the last questions, Eric, we -- Mike Stevens said in some of our fields we're seeing as low as $5, with a potential to go lower. So we kind of already answered that one.

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Operator [64]

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And the next question we're going to take is from (inaudible) with Morgan Stanley.

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Unidentified Analyst, [65]

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You mentioned that you saw some service cost inflation. So I'm just curious where that's been focused in terms of the value chain and how you see that trending over time? And really, ultimately, where you see your fully burdened, unlevered breakevens in the Williston and Niobrara, taking those expectations into account.

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Rick A. Ross, Whiting Petroleum Corporation - SVP of Operations [66]

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I would say as far as where we've seen the cost increase, it's been primarily on the pressure pumping services at this point. Some minor increases in some of the ancillary or support parts of completions. But as I mentioned, we have been able to offset a number of those -- or most of those costs through increased efficiencies, better drilling rig contracts. And also on the water supply side, we've been able to offset most of that.

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Unidentified Analyst, [67]

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And just -- sorry, also just how you see that affecting your fully burdened, unlevered breakevens taking sort of your forward expectations of inflation into account?

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James J. Volker, Whiting Petroleum Corporation - Chairman, CEO and President [68]

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Well, as Rick said, we've offset the increase in the inflation, so it doesn't affect our breakevens. There's no -- really no change. We've offset at all 3 efficiencies.

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Unidentified Analyst, [69]

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Okay. Sorry. Go ahead.

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James J. Volker, Whiting Petroleum Corporation - Chairman, CEO and President [70]

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No. I was just going to say, does that answer your question? Or is that clear?

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Unidentified Analyst, [71]

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Yes. I guess I was more just thinking in terms of expectations of inflation going forward, and how that would affect it. But I think that's clear. The other question was just a follow-up on, you mentioned some potential discussions of JVs in the Niobrara. Don't know if you had a sense, I know it's probably still early in the conversations, but a sense for size for those potential JVs?

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James J. Volker, Whiting Petroleum Corporation - Chairman, CEO and President [72]

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Really don't want to disclose that since that's -- would differ depending upon the partner. And sort of really, if you will, not one potential partner's business as to what we might be doing with another in terms of size. So, but they're all significant and would add significant volume out there and continue to help us drive down cost.

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Unidentified Analyst, [73]

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That totally makes sense. The last sort of non-op related question is just on those '19 notes. Are you sort of thinking about - to refi them or draw the revolver or pay down with cash, assuming there is cash available when you decide to address them? I'm just trying to -- just curious how you're thinking about them.

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James J. Volker, Whiting Petroleum Corporation - Chairman, CEO and President [74]

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It's just too early to really discuss how we're going to refinance the 2019 notes. We have multiple options, and really it's just too early to really address that now. But we appreciate the question.

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Operator [75]

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And the next question comes from Gail Nicholson with KLR Group.

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Gail Amanda Nicholson, KLR Group Holdings, LLC, Research Division - MD [76]

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You guys did a phenomenal job at reducing the water handling and reducing the LOE. When you look kind of at the water handling aspect, is there more room to make further improvements there? Or do you think you've achieved the low-hanging fruit?

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Rick A. Ross, Whiting Petroleum Corporation - SVP of Operations [77]

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I'll say that we have made good progress on it. And really, the way we've done that is putting more of our water -- produced water on pipe, which is the least expensive way to move it. We've also renegotiated a number of our producing wells -- our water disposal contracts. And then we also benefited from some agreements that we had negotiated with cost reductions at a certain trigger point that have triggered over the last quarter. So that's really what we've done. Our opportunity is to continue to renegotiate some additional ones. I would say that there's probably still some room out there to advance that.

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Gail Amanda Nicholson, KLR Group Holdings, LLC, Research Division - MD [78]

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Great. And then just looking at the enhanced completions. Has what you've been seeing with the results of the enhanced completions changed any of your thoughts about the lower Three Forks benches and other areas that you currently don't have location credit for?

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James J. Volker, Whiting Petroleum Corporation - Chairman, CEO and President [79]

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Well, as we discussed already, the Three Forks that we've been drilling which, through most of the basin is the upper bench, has responded very well to enhanced completions. We have great opportunity for second bench Three Forks in the core of the basin. So in what we call our Tarpon area, the area around the river west of the Nesson, has very good saturations in the second batch, that we've been developing that and getting good results there as well. So as far as enhanced completions go, I think it's a good generalized statement to say that as long as you're doing it correctly, and by that, I mean accompanying the larger sand volumes with more effective entry points, that that's going to apply just about everywhere. We've seen that. We've seen a broad overall uplift in virtually everything that we're doing in the Bakken with these larger completions because we're taking the time to really test it and do it right with accompanying with more entry points. We think we're going to see the same thing in Redtail. We just had a little bit of a hiatus in completions late last year. But we're going -- as Rick's already talked about, we're going to be testing that -- or we are testing it right now, so we'll see the results of that here late this spring, early summer.

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Operator [80]

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There are no further questions. So I would now like to turn the call back over to Jim Volker for any closing remarks.

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James J. Volker, Whiting Petroleum Corporation - Chairman, CEO and President [81]

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Thanks very much, Keith. I'd like to thank our directors, and especially all of our Whiting employees who, as you can see, are responsible for the improvements that we've made in costs and well productivity that allow us to operate effectively and efficiently in a $40 to $50 oil price environment. Thanks to everyone for their great contributions and for a solid first quarter. Eric?

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Eric K. Hagen, Whiting Petroleum Corporation - VP of IR [82]

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Pete Hagist will be presenting at the Citi Global Energy and Utility Conference, Wednesday, May 10, 9:30 a.m. Eastern time. And then Mike Stevens will be presenting at the Bank of America Energy Credit Conference in New York the week of June 5. Thank you.

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James J. Volker, Whiting Petroleum Corporation - Chairman, CEO and President [83]

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In closing, we thank all of you for your interest in Whiting Petroleum Corporation, and we look forward to meeting with you soon.

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Operator [84]

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Thank you. The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.