Good morning. My name is Keith and I will be your conference facilitator today. Welcome everyone to the Whiting Petroleum Corporation Second Quarter 2019 Financial and Operating Results Conference Call. The call will be limited to 45 minutes, 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. [Operator Instructions] Please note, this event is being recorded. I will now like to turn the conference over to Eric Hagen, Whiting's Vice President of Corporate Affairs.

Thank you, Keith. Good morning and welcome to Whiting Petroleum Corporation's second quarter 2019 earnings conference call. On the call with me today is the Whiting management team. During this call, we'll review our results for the second quarter 2019. This conference call is being recorded and will also be available at our website at www.whiting.com under the Investor Relations section. We also posted an updated corporate presentation to our website earlier this morning. 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 2 of our corporate presentation and in our earnings release. With that, I'll turn the call over to our Chairman, President, and CEO, Brad Holly.

Thank you, Eric. As we continue to navigate the challenging industry landscape of volatile commodity prices, and a constrained gas infrastructure market in North Dakota. We are taking strong measures to improve our margins and deliver on our goal of generating free cash flow. This is consistent with our stated strategy to delivery a better cost structure and more consistent results. Now, I’ll briefly cover the quarter and then address the strategic initiatives we announced yesterday. I like to start off by referring you to Slide number 8 in our corporate presentation. The slide demonstrates that year-over-year our oil production rates have been consistent with our historical results. Our wells are performing as anticipated and a reduction of our oil guidance is a function of above ground constraints. We are getting strong well results, Foreman Butte as depicted on Slide 26 of our updated corporate presentation. We are delivering top tier results from acreage purchase for an attractive price. We believe this illustrates our team’s ability to understand the rock and apply the latest technology to further expand the Bakken core. Conservatively, the success adds over 100 net risk high-quality locations to Whiting’s inventory. Second quarter oil production was impacted by a very tight situation for gas processing across the basin. Industry gas capture in May delayed this month reported by North Dakota was 81% versus a regulatory mandate of 88%. Whiting is committed to remaining a responsible operator and continuing to meet this standard. To minimize flaring, we are producing some wells at constrained oil rates, while we focus on increasing gas capture through the installation of mobile combustion units, building out gathering systems, and completing our ray gas processing plant. Constraints also impacted the pace of planned operating activity. In summary, infrastructure constraints were more severe than anticipated…

Yes, certainly. [Operator Instructions] And today’s first question comes from Neal Dingmann with SunTrust.

Good morning Brad and all, and again welcome Correne. Brad my question is, you definitely said on the specific constraints that you referred to. You said now you put, you know, so should maybe a bigger buffer in there. Other items, you are doing things like will you lock in some contracts, will you try to build out your own pipes. Can you just maybe talk about anything else other than putting a bigger cushion how you sort of view the plan for the remainder of the year or are there in your opinion enough sort of infrastructure coming on latter part of the year where you don’t need to make these changes as well?

Yes, thanks for your question, Neal. I’ll take a stab and then maybe have Chip Rimer, our COO and even Kevin Kelly, our VP of Midstream Marketing help me out on this. That has been our big concern and our big constraint in North Dakota. Have you seen up there, with the industry increasing to 88% gas capture? We worked very hard to meet that and we are meeting that today. But that is putting significant pressure on us. When we came out with our budget this year, we had some key initiatives to try to help that. Looping lines in Sanish putting on our Ray Gas Plant and putting in these mobile combustion units is all helping us. But what we’ve seen is that with a startup of new equipment, the downtime is very significant, and so as third parties have started up new equipment, we’ve had significant downtime and Chip can walk you through. When those things go down, it’s not an instantaneous up back on the production side. So, they can go down for a day, and it takes us a little bit of time to get the wells back on at times, and get it aligned out again. And so, we’ve seen those bubbles and we are increasing our anticipated downtime to account for that moving forward as the infrastructure gets lined out. Chip?

Yes, Brad. Thanks. This is Chip Rimer. Yes Neal, that’s correct. We’ve had times back, I think we had close to 14 downtimes in the second quarter, and when we have those downtimes, are we seeing up to 4,200 barrels available as we go down when we have those downtimes, and it takes a little while to get those wells brought back on, swapped, working on artificial lift to get them back on, so that’s been a big impact to us. Lot of that happens in the [indiscernible], which will be very prolific to us.

This is Kevin, Neal. As far as rest of the year, there are some big processing additions coming on about a BCF spread across several of the key processors, Oneok, Highland, [indiscernible]. We think that will help us by year-end, another key component be Oneok’s Elk Creek Pipeline. So, by year-end, going into 2020, we would feel much better about the infrastructure across the basin.

And maybe just for my follow-up, I just would stay with that, is the problems, I mean have you seen that sort of across the board, are there areas such in the Sanish on the East or different areas that you potentially couldn’t accelerate to, maybe have improvement even sooner than expected?

Hi Neal, it’s Eric Hagen. You are correct, so in general the constraints have been in the western side of the basin, central basin, McKenzie County, that’s where we have had a lot of activity in the first part of the year and the end of last year, places like the Flatland unit. And as we move to the East, it is less constrained. We actually have a right to put our gas into the large gas processing plant there, which does reduce the risk. So, that is one of the changes heading into the second half of the year that we think will improve our execution.

Very good. Thank you.

Thanks, Neal.

Thank you. And the next question comes from Leo Mariani with KeyBanc.

Hi guys. I just wanted to ask a little bit of question on sort of activity levels in the Bakken. I think you guys brought on about 50 wells in the second quarter, just trying to get a sense of where we see wells being tied in 3Q and 4Q. I’m just trying to get a sense of some of the impact that you kind of mentioned on the midstream and activity levels, is that really going to impact well tie-ins? I think you guys were previously planning on bringing a pretty large group of wells on in the third quarter?

Yes, thanks Leo. I appreciate the question and I think you described it pretty accurately. We had originally planned on bringing nine additional wells on in the second quarter and because of these constraints and operational ways we were not able to do that. But as Eric mentioned, we are moving the program to the east, we're moving more and more activity into the core of Sanish, where we feel like we have takeaway capacity, it's a lower working interest, hence that's going to help us meet our CapEx guidance. We're going to complete, about half of the net wells in the fourth quarter than we will in the third quarter. But the third quarter, we still have some stuff in the South that we're bringing on a little bit in the North. And the activity is moving to the east and to Sanish.

Okay, that's helpful. And I guess just also wanted to ask on the CapEx, I think you guys are kind of guiding third quarter CapEx roughly flattish with 2Q. You guys did drop a rig, I guess in the last couple of months. Can you just kind of help me out with what's, kind of, keeping the CapEx run rate still kind of high there in the third quarter?

Yes, Leo. This is Chip Rimer. Yes, we're taking from three frac crews going to two frac crews in this quarter towards the end of the quarter. 3Q as Brad said, we're moving a lot of our activity over into the Sanish area, which has a lower working interest. You can see those Slides on 17 through 21, you can see how prolific those wells are in that area. So, pretty excited about going over there. We're also going to be running upon some additional ducks that we're going to have a – which is above our normal inventory. So, overall, I think we're in line, but we will be moving the Sanish will be a reduction in a working …

Okay, so basically you expect that CapEx to fall pretty dramatically in the four quarter, just trying to kind of get a sense of how those numbers move around little bit here?

Yes, just to recap it. So, we went from – we recently dropped a rig, and then we're dropping a frac crew at the end of the quarter. We’re working into interest it has a little bit – into an area that's little bit lower working interest, and we're also accumulating some ducks. And if you look at our original plan, we released at the beginning of the year, really what we're going to do, second half of the year isn't all that different. It's just we're looking at the timing of POP's. But if you look at the activity was already forecast to dropped really significantly in the fourth quarter. So, we think all those things give us confidence that we will see a significant drop.

Okay, thank you very much.

Thanks, Leo.

Thank you. And the next question comes from Drew Venker with Morgan Stanley.

Good morning, everyone.

Good morning, Drew.

I'm just wondering, if you could just give us an update on what you think maintenance CapEx would look like for 2020? If you can give us on an exit-exit that would be great?

Yes. Hi, Drew, we're just not going to comment on 2020 now because with the situation, so constrained in the basin, it's really hard to predict downtime and capital efficiency. So, we prefer to wait until the third quarter, see how some of these gas processing plants, that Kevin mentioned to come on, that I think we'll have a better basis to forecast that.

Okay. And remind us the timing of when the rate plan is expected to be complete?

The rate plan actually was just – was completed, so…

Okay. So, you see the benefits of that coming in the next couple of quarters?

We should see the benefits of that.

Okay, thanks.

Thank you.

Thank you. And the next question comes from David Deckelbaum with Cowen.

Hi, David.

Mr. Deckelbaum, is your phone on mute?

Sorry about that guys. Thanks for taking my questions guys.

Hi, David.

Good morning. Just wanted to ask on just – you talked about the downtime situation before. So, we should think about the forward guidance now risking for unplanned downtime, but also a constrained environment where you're turning in wells into what tighter system. So, is it sort of like a 50-50 contribution there?

Yes, if you look at the 3,000 barrels a day that we pointed out in the call, it was about 2,000 of that was from delays and POPs and that's when you're waiting on gathering lines will be put in place or compression to be installed in the system, so you can flow the wells, and about a third of it was constrained rates and I think Chip gave a good example of that in an area like the Flatland area where you have a large number of wells, a large pad if you get constrained, you can lose 3,000, 4,000 barrels a day for a period until they debottleneck that. And going forward, the plan is risk that it – similar to that in terms of the risk volumes.

Okay. Has this caused you at all, I know that you, kind of, like restructuring the reporting lines? I guess, how do we think about planning now going forward. Is the – I know you're moving East into Sanish and then plans were to, kind of, ramp up in Cassandra with the Ray coming online. How much are geographically plan is changing right now versus what you had set out in the beginning of the year?

They're not changing very much maybe when it's all said and done. We're very close to our original plan.

Yes, when we think our original plan was a solid plan in terms of trying to move away from constrained areas. It's just that it wasn't risked enough and it led to some downtime that we hadn't predicted frankly.

Our original plan was to move into Sanish area after these.

And just lastly for me, I think we had thought about Midstream spends next year sort of declining, particularly after I guess, Ray was included this year. Has this situation made you look at all on sort of required spend around, field infrastructure and should we expect any changes there?

David, this is Brad, I just don't see a whole lot, I think we're still that message is still good, we don't see a whole lot of spending in 2020, we had some short-term stuff like line looping and getting Ray up and running, but as Kevin mentioned earlier on the call, there's a lot of infrastructure coming to bear at the end of this year, both gas and NGLs, and we think that's going to help us quite a bit, but so we don't see anticipated increased spend on our side.

Thanks guys.

Thank you. And the next question comes from Joe Allman with Baird.

Thank you. Good morning, everybody.

Good morning, Joe.

So, just trying to get a more full understanding of the infrastructure constraints. So, is it overwhelmingly processing or is it actually a combination of kind of processing, but also maybe some gathering in some larger pipe?

Yes, this is Kevin, Joe. So, it's the processing is part of it and the NGL takeaway. So, in the first part of the year, especially in the Tarpon area, we’re waiting on big compression to come online that will help us flow there. It came online a little bit at late, and then it had a bunch up and downs. And as we work through this year waiting on new processing that become sort of the second-tier bottleneck in the second half. But as we see line of sight with Oneok’s reiteration yesterday in its own plan of bringing Demicks online fourth quarter of this year, as well as the NGL line fourth quarter of this year, will become more positive getting into the end of the year.

Got it. And do you see any – do you see like pretty much full resolution, kind of, late this year, early next year or do you think there is visibility on some further constraints over the next couple of years as well?

Well, I think with the additions and what we look at for the basin for the next couple of years. The basin, looks like it has good room of growth for the wet gas.

Okay, alright, that's helpful. And then just in terms of locations, is it overwhelmingly the West, but also some issues in the East, or could you just kind of describe kind of location-wise the constraints?

It was still predominantly for us in the core of the system in this – our South area, McKenzie County and in particular the Tarpon area.

Okay, that's great. Okay, that's all very helpful, thank you very much.

Thank you, Joe.

Thank you. And the next question comes from Paul Grigel of Macquarie Capital.

Hi, good morning. I was wondering, if you guys think about the fourth quarter slowdown in the cadence into 2020 really is not formal 2020 guidance. Should we be thinking that there is a resumption back to kind of normalized level of activities at this point in time. And then, is there any thoughts on potential increased seasonality with winter costs being higher versus the summer and loading into 2Q to 3Q, more so?

Well, there's always, it's Eric, Paul. There's always going to be seasonality in the Bakken and as Chip mentioned, we are building some additional ducks and we'll – we also have sort of extended our POP schedule a little bit. So, we'll be popping a fewer more wells later in the quarters, and that hopefully will give us some momentum into that seasonality.

Okay, that's helpful. And then I guess maybe you guys could talk about the current plans on either converts or the 2021, and just where you kind of stand today on your thoughts on addressing those maturities as we start the events closer towards them?

Yes, sure, Paul. Thanks for that question. We feel like we have multiple options on our upcoming debt maturities. Our first one is to try to pay down debt with free cash flow, we're trying to build the organization to be able to do that. The second, we continue to sell the non-core assets as you've seen us do a couple of transactions this quarter that helps us and that's what those are designed to go for. The third thing we have the $1.75 billion revolver with only $40 million drawn at the quarter end, so that's an option. And finally, we could refinance that, but we are looking to pay it down. We want to get a lower net debt-to-EBITDAX, as well as reduce our absolute debt.

Alright. Thank you.

Thank you. And the next question comes from Jeoffrey Lambujon with Tudor, Pickering & Holt.

Good morning, thanks for taking my questions. First one is just on the non-op, as you think about the opportunity set there. Can you just give us some guidelines on how you think about budgeting for that part of the business? Just trying to get a sense out of forecast that going forward?

Okay. Yes, sure. Jeoffrey, this is Tim Sulser. We've had obviously an uptick in non-op activity and we're very pleased with the well results. That said, we did have an opportunity to monetize some of those assets this quarter, we did that in two separate transactions both were to the operator of those properties. And so, we were really excited about the well performance, the [AP capital] came in a little higher than we expected. So, we were pleased to transact where we did. And we'll continue to, kind of, look at those opportunities as we go forward, but again our non-operated assets are – in amongst our operated assets and we see really good results and manage that accordingly.

I appreciate that. And then just following up on the midstream side in terms of the expected relief. What's baked in now for you all in terms of the timing there? I know you mentioned a couple of projects coming online in Q4, is that what's kind of assumed to provide relief going into next year, or are there any solutions, you kind of point to in early 2020 as well?

So, this is Kevin. Yes, we're being conservative. We know what the schedule is people bringing on things in the fourth quarter, but really, we're looking at those as a year-end. We want to be optimistic that also realistic given some of the downtime constraints, as we saw things get brought up earlier in the year. So, really by its year-end, is what we're looking at.

Anything in the early 2020 timeframe to watch for us, as well as the year-end, kind of, Q4 timing the bulk of it?

Year-end is the bulk of it, and another plant will be the Demicks II plant, which is Q1.

Thank you very much.

Thank you. And the next question comes from Asit Sen with Bank of America.

Thanks, good morning. Hi, Brad. Can you talk a little bit about the departure from the original plan of operating three asset teams, and in the context of the announced restructuring, you talked about evolving industry landscape, but the infrastructure constrained could be fairly transitory, so just wondering if you could talk a little bit about your thought process in such a big restructuring?

Yes, Asit. Appreciate the question in the philosophical ramifications there. We broke out in the three asset teams really to get micro-focused in our individual asset areas, and really understand our business on a very isolated area with good leadership. It allowed us develop leadership capabilities internal, it allowed us to try some different things. And as we look going forward, it really, the competitive landscape and trying to cut cost out of the system, I would say we reorganized from a corporate model to an asset-based model. And now everyone in the company as super-focused on really four things; we're looking to be safe and we've got to be safe every day; we're looking to be focused on production; focused on capital efficiency and then cost leadership. So, everybody is about creating value now and we really feel like that the – bringing everybody together under one major asset team is going to allow us to transfer technology across the organization, it's going to allow us to maximize our opportunities and make sure that our highest and best opportunities you're coming for first. We've had some improvements on both innovation and technology that we're using and we have provided more technology into the field. We can see our business better and we haven't really had any significant headcount reductions in our D&C areas. Our drilling and completion areas, and so we think that same amount of focus will be generated there, but everyone is really rallying around kind of those four pillars that we're using to try to drive value.

Okay, thanks, Brad. Appreciate the color. And then a nice non-operated divestiture. Just wondering, if you have more to go, is there a target that you can elaborate?

Yes. So, this is Tim Sulser. And as I had mentioned earlier, we are absolutely pleased with those two transactions that we did and we will continue to look at divesting those in favor of being able to then further focus our capital and attention on our operated assets.

Yes, and Asit Sen, just chip in there, it's Eric Hagen. We sold about 700 barrels a day; we've got about 10,000 barrels a day. So, we have a very solid non-op position in it. It has lot of potential value.

Thank you, guys.

Thank you.

Thank you. And the next question comes from Marshall Carver with Heikkinen Energy Advisors.

Yes, on the personnel cost savings, the 33% headcount reduction. When does that fully kick-in, and how much of that will be hitting the G&A line items versus other line items like, you know, LOE or something like that?

Yes, thanks, Marshall. I appreciate the question. That was actually executed on yesterday and so immediately August 1, we are at our new size. We estimate about $15 million of cost savings this year, that's kind of net of the one-time severance payment of that $15 million, I would think about half of it goes to G&A and about half of it LOE of an exploration for the back half of this year. On an annualized basis of the [$15 million], feel like about 75% of that is going to be G&A and 25% of that is going to roll through LOE and exploration moving forward.

Okay, thank you. And then a follow-up, we typically think of the Bakken is being flattish in the first half of the year, and then de-growth in the back half of the year. Knowing you don't want to give a lot of color on 2020 yet, but with all this infrastructure coming on at the end of this year. And beginning of next year, is it safe to say that you're going to have a lot of growth in the first part of next year. So, that waiting for growth for the back half of the year will be different in 2020?

Marshall, it's Eric Hagen again. Just to reiterate – we're just not going to give 2020 commentary until we have line of sight that, you know, at year-end all the processing is in place. We'll look at, you know, how our POP schedule develops into the third and fourth quarter, and our momentum coming out of the year. In addition to how we want to deploy our ducks. But yes, I mean, I do agree with you, overall kind of logically that, that we're setting up for the prior question, we're setting up for maybe a more – having more momentum heading into the tough season than we usually do.

Thank you.

Thank you. And the next question comes from Victor Prado with Credit Suisse.

Sorry. This is Betty Jiang from Credit Suisse. So, Mr. Eric following up on the POP cadence to ask about that again on the power plan is 146 turning lines in 2019, of which 60 completed in the first half. So, I just wanted to clarify is the POP count generally staying largely the same, but more back-end weighted or is the second half POP count coming down much lower than the prior program?

Yes, it's going to stay the same, Betty. We're just – this is Chip Rimer, we're going to back half weighted on the POP count going forward.

Got it. And then, Brad that you mentioned in the start of the call that you won a more stable production and consistent program going forward. So, as we – I know you're not commenting on 2020, but as we think about the baseline activity is the second half 2019 level in terms of rig count and crew come as a good baseline going forward?

Yes, Betty appreciate the question. I think you're accurate there as you've seen in the last few quarters, we struggled to make oil production and that has been forecasting that these wells, we know the potential on the wells are there, the wells are performing well. And we're taking those wells and the type curves and we're adding that to our program and we've seen that hasn't been that easy to do with the infrastructure, and so, we've just backed-off of that and added more downtime of that. And we're obviously working internally on our own facilities and constraints to make sure we can move that, we're also working actively with our third-party gathering companies, as well as the processors to try to line all that equipment out. And then we can open up our wells and flow-through that with more stability going forward. So, that's why we've come out with the new guidance moving forward. It's something that in the environment that we're currently operating in, we think that, that's achievable and we can do that, and we'll be looking to improve upon that moving forward.

Great, thanks for that. And then just one quick follow-up. Is there – can we get an update on the year-end backlog on the – in terms of absolute numbers. I guess what's the number of actual working ducks that can be drawn down at year-end?

Yes, Betty it will be closer to 50 at the end of the year. This is Chip Rimer.

Okay. Great, thank you.

So, we've carried a normal like 40 probably working inventory of 40 ducks and or just – it's a few more ducks at the end of the year. So, probably go out with 10 more than what we normally have.

Great, thanks.

Thank you. And the next question comes from Mike Scialla with Stifel.

Good morning, everybody. Brad appreciate the comments you made on the strategic changes that you put in place. Just wondering, a part of the prior plan was to do acquisitions and maybe convert some non-core areas [into core] looks like you did with the Foreman Butte acquisition. Just wondering, are you still in position to do that now or have you changed your plans there long-term?

Yes, Mike, I appreciate the comment. We think that Foreman Butte thing was a great, better work, we saw that opportunity there and really felt like that we could improve upon it. And 117% improvement on the prior wells is important. At this commodity price, we certainly are focused on paying down debt. And that is what we are working on, we're building a value-based organization that can generate significant free cash flow and we want to reduce our absolute debt at this time. And so that is our primary focus at this point. We'll continue to learn about the rock, we'll learn about the basin, and we think we understand it pretty well today, but we'll continue to try to drive value on our own acreage. We've got, as you know, we've continued to have some Tier 2 acreage of our own that we think we can turn in Tier 1. So, we're working on our existing yellow acreage right now. And, but we will always have our eyes open, but our priority clearly right now is to pay down debt.

Okay, and you mentioned in your prepared remarks you added at least 100 locations with your new completion design, were those all in Foreman Butte or can you give any more detail on what contributed to that increase in that inventory?

Yes, Mike, that was just a Foreman Butte comment. So, that's just based on the 55,000 acreage that we purchased last year, we see those 100 net locations on that acreage.

Again, if you run the math on that, Mike you'll see those are net and there are – it's also a risk on a very reasonable spacing assumption.

Great. Thank you.

Thanks, Mike.

Thank you. And the next question is a follow-up from Joe Allman with Baird.

Great, thanks again. Just on operating costs. So, operating cost rose in the second quarter versus the first quarter, was that overwhelmingly or exclusively the infrastructure constraints or was there something else in there?

Yes, Joe. This is Chip Rimer. Yes, we had some flooding impacts that occurred to us over in the North County, Yellowstone flooded. And so that impacted the numerous wells over there are workover costs rose in the first part, I would thank our operations folks they jumped on that and addressed that challenge and got knocked out, but a lot of that was driven by workover activity and the other thing was our mobile combustion units for gas capture drove that.

Okay, that's helpful. And then back to the convert question, the converts are due in April next year. So, now they are current, is the plan to really knock those out this year, or might you actually get into next year do knock those out?

Yes, Joe. This is Brad again. We are working. We are focused on that right now. We are working on that. Again, we sold two non-core assets this quarter, and with the design of using that moving forward to help pay down that debt. We can do some more of that in the back half of the year, as well as continue to try to generate free cash flow going forward, so we'll generate free cash flow to pay that down, we'll sell non-core assets to pay that down, and then we have the $1.75 billion revolver that's undrawn to use to help that as well.

Got it. Okay, very helpful. Thanks again.

Thank you. And as there are no more questions, I would like to return the floor to Eric Hagen for any closing comments?

Alright, thank you very much Keith. Whiting will be presenting at the Barclays Conference, on September 4, in New York City. I will now turn the call over to Brad Holly for closing remarks.

Thank you, Eric. We remain dedicated to our strategy of focusing on margins, full cycle returns and generating free cash flow. As a management team, we remain disciplined in our investment decisions and focused on further strengthening our balance sheet. Our commitment to delivering shareholder value is evident in the tough decisions we recently made to improve our cost structure and maximize capital productivity.

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