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 one hour, including Q&A. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer period. Please limit your questions to one question and one follow up. Please note this event is being recorded. I'd now like to turn the conference over to Eric Hagen, the company's Vice President of Investor Relations. Please go ahead, sir.

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 number 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.

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 an 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 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 cost and well productivity allow us to operate effectively and efficiently in a $40 to $50 oil price environment. As you can see on slide number 3, with the 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 number 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 number 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 number 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're testing enhanced completions on our first two 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.

On slide number 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 number 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 a liquidity and debt maturity perspective. Our guidance for the second quarter and full year 2017 is detailed on slide number 9. We're 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 number 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.

Whiting has delivered three 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.

Yes. Thank you. And this morning's first question comes from Graham Price with Raymond James.

Good morning, Graham.

Hey. Good morning, guys, and thanks for taking my question. So, with regard to the two Redtail pads that you'll bring online in May, I 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.

This is Rick Ross. The two pads that we mentioned with the enhanced completions are all 960-acre spacing units. We do have 34 1,280 wells that we'll be completing later in the year.

Okay. Perfect. Thank you. 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 the overall base decline rate trending throughout the year.

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

Okay.

Just the result of bringing on new production. That's all.

Got you. Perfect. Thank you. That's it for me.

Thank you. And the next question comes from Michael Glick with JPMorgan.

Good morning.

Good morning.

Just in the Williston, we did some mapping and measuring last night. In the area where you are all posting 1.5-million-barrel-type wells has grown and it's quite large geographically in terms of the 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 one down in Stark, two kind of along the river and two in Central Williams.

Right. Mark Williams here. We have and continue to have rigs across the basin in all seven of our geo plays going forward. And in addition of the areas that you 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. We'll be winding that up here sometime around the end of the second quarter and then continue to drill there along the river both in Williams and McKenzie County on both sides of the river there.

Yeah. So, to follow up on Mark's answer, so we view all of our acreage, each one of our seven plays, as capable of getting through a million and a half BOEs per well. That's why our rigs are scattered in all seven plays.

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

It will be typically between 60% at a low and 90% at a high working interest.

Okay. Perfect. Thanks very much, guys.

You're welcome.

Thank you. And the next question comes from Neal Dingmann with SunTrust.

Hi, Neal.

Hi, Jim. Jim, it seems that just speaking to some investors, they believe that much of your, I would say, 2017 plans 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'd just like to hear your color on it.

Right. No, our activity is designed to take us forward 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.

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

Absolutely. Yeah. We have flexibility should something untoward happen, should oil prices, I'm going to say consistently below $45 and maybe it can get below $40, something like that. We have plenty of flexibility to do that. We're running, I'll say, only six rigs, five in the Bakken, one at Redtail. We recently renewed three 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 six months to 12 months. So, we could drop all of those rigs for nominal fees. And in addition, we have two of our rigs that expire later this year, in November. And we have four 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.

Would agree, 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. Could you talk about how you foresee those remainder of the year and in 2018?

Yeah, It's been a nice change for sure, coming down at 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 into our guidance yet. But I would say that the outlook is for continuing shrinking differentials in the Bakken.

Very good. Thank you, all.

Thank you.

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

Good morning, guys. With some of the Bakken results that we've seen with these really big wells like the Loomer wells, 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 kind of what you planned for the year?

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.

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

Well, on 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.

Okay.

Still in that range.

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?

The DUCs we're completing are all on the east side of Razor and west side of Horsetail. So, that's on the three best parts.

It's just where the completion rigs are right now. It's where the completion rigs and the frac crews are in our development for the entire area. And Mark is correct. It is 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 drilling, 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.

Thanks, guys.

You bet.

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

Good morning, Jim.

Hi, Dave.

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

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 2018. 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 to the Niobrara, there are several parties who've 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 just tried to convey here, they like the economics, even with oil in the $40 to $50 range.

Okay. That's all I got. Thanks.

Thanks, Dave.

Thank you. And the next question comes from Will Green with Stephens.

Good morning, everyone.

Hi, Will.

Very impressive work on the Loomer pad. It looks like to me that two of the three 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 could just help us understand if this is a phenomenon that's extending to the Three Forks as well.

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 two Three Forks wells and one 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.

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

Yeah. That's great to hear. I mean, I asked 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 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 MBOE and 655 MBOE on the 960s and 1280s down there. It's fair to assume that that's what you guys are – 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 be icing on the cake. Is that fair to assume?

Yes.

Great. Well, thank you, guys. That's all I had.

All the best. Thanks for your questions.

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

Good morning and congratulations on the strong quarter.

Thanks, Jeffrey.

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

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

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.

That's interesting. That was a really helpful answer because it's obvious that you're able to isolate the two variables.

Thank you.

To get to one variable in each well. I just want to ask one last follow up on that. Are you testing all of the zones in the three Niobraras and the Codell in these enhanced completions?

We are.

Yes.

Okay. Great. Thank you.

You're welcome.

Thanks, Jeff.

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

Good morning and thanks for taking my question.

You're welcome.

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

Do you mean in Niobrara or the Williston?

In the Williston.

In the Williston, we're already doing 100% advanced completions which Rick can give you more detail on. I mean, yeah basically, we're already at 9 million pounds to 10 million pounds and – on these stages, Rick, 50?

Generally about 40 stages in the Bakken is what 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, 15 million pounds. I guess to answer your question we switched to all-enhanced completions in our program and we're just testing the upper limits right now in 2017.

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.

Got it. And last quarter you provided a maintenance CapEx estimate of $900 million to hold 4Q 2017 production flat into 2018. So, was that predicated on the 1.5 million barrel wells in the Williston or is that predicated on 900,000 barrel wells in the Williston?

The $900 million is an estimate and 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 I'm just going to wait and see how the program goes this year and it'll be easier to estimate it when we get later into the year.

Got it. And then just switching gears to service cost. How is the inflation coming year-to-date relatively to your expectations? And what are your expectations over the course of the rest of the year?

I think pretty much in line with our expectations. 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.

Got it. That's very helpful. Thanks for the time and have a good rest of the day.

Thank you.

Thanks.

Thank you. And the next question comes from Michael Hall with Heikkinen Energy Advisors.

Hi, Michael.

Thanks. Good morning. Hey. I guess a couple questions. One, just going back on the enhanced completions in 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, because they've been pretty consistent across the board?

Yes. We have seen positive consistent results across all of our acreages. We were discussing before, we're drilling seven 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, as we mentioned.

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

Yes.

Great. And then, I guess just to circle back on a 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...

We've only factored in what we've seen so far.

Okay.

The thought is that the differentials – 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.

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

Michael, we said it last question – this is Eric – Mike Stevens said in some of our fields we're seeing as low as $5 with the potential to go lower. So, we kind of already answered that one.

Yeah. That didn't sound like that was for the entire stream. I was just trying to think about the blended average, but I can follow up later. Thanks.

Yeah. You can follow up later. Thanks.

Thank you. And the next question comes from Jacob Gomolinski-Ekel with Morgan Stanley.

Morning.

Morning, Jacob.

You mentioned that you saw some service cost inflation. So 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, Niobrara, taking those expectations into account?

I would say as far as where we've seen the cost increase that 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.

Thanks. Also just how you see that affecting your fully burdened unlevered breakevens taking sort of your forward expectations of inflation into account?

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

Okay. And – sorry. Go ahead.

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

Yeah. 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 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.

Really don't want to disclose that since that would differ depending upon the partner. And so to really, if you will, not one potential partner's business as to what we might be doing with another.

Right.

In terms of size. But they're all significant and would add significant volume out there and continue to help us drive down cost.

That totally makes sense. The last sort of non-op related question is just on those 2019 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? Just trying to – just curious how you're thinking about them.

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.

No problem. Thank you very much. Thank you.

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

Good morning. You guys did a phenomenal job reducing the water handling, 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?

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 well or 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 there's probably still some room out there to advance that.

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

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 in what we call our Tarpon area. The area around the river west of the Nesson has very good saturations in the second bench. 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 larger sand volumes with more effective entry points, that that's going to flag 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 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 to – as Rick's already talked about, we're going to be testing that or we are testing it right now. So we'll see results of that late this spring, early summer.

Okay. Great. Thank you.

Thank you. There are no further questions. And so, I would now like to turn the call back over to Jim Volker for any closing remarks.

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?

Pete Hagist will be presenting at the Citi Global Energy & Utilities Conference Wednesday, May 10, 9:30 AM 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.

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

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