Good day, ladies and gentlemen, and welcome to the Q3 2014 Whiting Petroleum Corp. Earnings Conference Call. My name is Sandra, and I'm your operator. [Operator Instructions] As a reminder, this call is being recorded for replay purposes. I'll now turn the call over to Eric Hagen, Vice President of Investor Relations. Please go ahead.

All right. Thank you very much, Sandra. Good morning, and welcome to Whiting Petroleum Corporation's Third Quarter 2014 Earnings Conference Call. On the call for Whiting this morning is the Whiting management team. During the call, we'll review our results for the third quarter and then discuss the outlook for the fourth quarter and full year 2014. This conference call is being recorded and will also be available on our website at www.whiting.com. And to access the call and the webcast, please click on the Kodiak Acquisition button on the homepage. Please note that our remarks and answers to questions include forward-looking statements and 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 #2 and in our earnings release. Reconciliations of non-GAAP measures we refer to and the 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 period ended September 30, 2014, is expected to be filed later this week. And with that, I'll turn the call over to Jim Volker.

Good morning, everyone, and thanks for joining us. As you can see, from Slide #3, we're pleased to again report that Whiting is a company on the move and a company with strong results at current oil prices. We're pleased to announce that we posted another quarter of record production and continue to lead the way in new completion designs that enhance capital productivity in the Williston Basin. In the Niobrara, we announced exciting discovery wells in the Niobrara C and the Codell/Fort Hays zones. We're well positioned for growth in view of the current oil prices. Our strategy for maintaining a strong balance sheet through disciplined spending and asset sales has worked and continues to benefit the company. We believe Whiting has a strong future at current oil prices, and we look forward to competing in this environment and continuing to create shareholder value. The Kodiak acquisition is on track to close in December. We continue to believe in the merits of the transaction, which will create the leading Williston Basin player. The combination of Whiting's technical acumen, strong balance sheet and efficient operations with Kodiak's high-quality asset base and talented people, makes even more sense at today's oil price environment and will drive meaningful production and operational synergies. As you know, it's impossible for us to give 2015 formal guidance until the Kodiak deal closes. We can, however, give you an idea of what we're planning. So assuming an $80 per barrel NYMEX oil price, we believe we can achieve high teens to 20% growth on a combined basis with a capital budget of approximately $3.8 billion, which is essentially equal to the combined budgets for WLL and KOG in 2014. This is a testament to the quality of both companies' assets and to Whiting's ability to increase…

On Slide #9, you can see our third quarter 2014 adjusted net income available to common shareholders was $148 million or $1.24 per diluted share. Our discretionary cash flow in the third quarter totaled $538 million. This total represented a 19% increase over the $450 million in the third quarter of 2013. Our guidance for the fourth quarter and full year 2014 is detailed on Slide #10. You'll note, we are guiding for a 20% production increase for 2014 over 2013. Also note that our LOE per BOE was down again in the third quarter and is expected to remain lower in the fourth quarter. Please note our 2014 guidance does not include the impact of the Kodiak Oil & Gas acquisition. On Slide #11, our third quarter EBITDA margin remained strong at 70% of our blended realized price per BOE. This continues to validate our long-standing strategy of focusing on oil. On Slide #12, you can see that we continue to maintain a strong balance sheet with only $100 million drawn under our bank credit facility. We have arranged $3.5 billion of bank commitments, effective upon the closing of the Kodiak acquisition. As a result, we are well positioned from a liquidity perspective to deal with lower oil prices. Slide #13 shows that our 2 senior notes and senior subordinated note continue to trade above par. It also shows that we are well within all the covenants in our credit agreement and our bond indentures. Slide #14 shows our crude oil hedge positions. At this point, we are 52% hedged for the remainder of 2014. On Slide #15, you'll see our fixed differential crude oil sales contracts that are locked in at an attractive differential of only $5 to $6 off of NYMEX. With that, I'll turn the call back over to Jim.

Thanks, Mike. Ladies and gentlemen, I'd like to now talk about our agreement to acquire Kodiak Oil & Gas. The definitive proxy was recently filed with the SEC, and we have set a special shareholder meeting for December 3, 2014, to vote on the approval of the transaction. After the approval of the Canadian court, we expect to close the transaction before year end. We also successfully completed consent solicitations of all 3 Kodiak bond issues. This will result in certain of their covenants being amended upon completion of the Kodiak acquisition to make them more consistent with Whiting bonds. On Slide 17. I'd like to note the compelling strategic benefits we see in this transaction. First and foremost, this transaction creates a leading player in the Williston Basin. The combined company will be the largest Bakken/Three Forks operator by production and will have a combined acreage position of 855,000 net acres in the play. The combined company will have more than 3,460 net drilling locations in the play. We believe the transaction will drive significantly higher production and cash flow growth for the combined company. We plan to substantially accelerate the Kodiak drilling program by increasing the rig fleet from 7 rigs to 12 rigs by the fourth quarter of 2015. This acceleration will be supported by the combined company's greater access to lower cost capital, allowing us to substantially enhance the net asset value per share of the combined company. The transaction also underscores Whiting's position as a leading U.S. oil-weighted growth company as we expect our growth profile and strong EBITDAX margins to be driven by our oil focus. Most importantly, this transaction positions the combined company to realize meaningful operational synergies and value creation opportunities relative to what could be achieved by either company on its…

[Operator Instructions] Your first question comes from John Freeman from Raymond Job (sic) [Raymond James]. John Freeman - Raymond James & Associates, Inc., Research Division: The first question I had, you all raised your EURs at mid-year based on what you had. Big improvements you all had on the cemented liner plug-and-perf completions. And I'm just curious, kind of based on what you all have seen on the improvements in the slickwater. If an update of your EUR guidance is something that we should think about for like a fourth quarter release? Or is that something that's a more mid-year again next year?

John, this is Jim, and then I'll turn it over to Steve Kranker here, VP of Reservoir Engineering as well as Acquisitions, for further amplification. But I would say this to you, I think at year end, you'll see the benefit of exactly what you've asked about there. That is improved recoveries and greater EURs. Steve, you want to take it away?

Yes. We're monitoring our slickwater fracs. There are several that are up 60-plus percent on initial rates the first month or 2 production. A little early to tell what it'll translate into in the EUR, but we're hopeful it'll be the similar uplift that we saw on the cemented liner, plug-and-perfs as well. And as Jim says, we'll see more of that in the year-end reserve report. John Freeman - Raymond James & Associates, Inc., Research Division: Okay. And then my last question, you all obviously had a good bit of facilities-related CapEx during the third quarter, namely on the Robinson plant in the fourth quarter. Is there any additional kind of meaningful facilities-related CapEx that we should expect?

Not that significant, John.

We have another question for you, and this one is from Will Green from Stephens.

I wanted to start on Redtail. To this point, most of the development programs have been focused around the A and the B. Given that you guys are going to be running 5 to 6 rigs going forward, how does the -- how did the new results in the C and Codell kind of change that? When did those zones get factored into the pad development you guys are going to be doing there next year?

Sure. Will, it's Mark Williams. The C and the D are both pleasant surprises, especially the D. We knew the C was going to work from a couple of wells that have been drilled previously. So what we're doing to plan for that going forward, we have a number of wells, 6 wells, that we call ITW wells or initial test wells that define the expanded area in our acreage position. And we're drilling those to ensure that we have a full understanding of where each of those zones is fully developed. We have, we think, approximately 50% of our acreage position being perspective for those 2 zones. But as [indiscernible].

Sandra, this is Eric Hagen. If you can hear us, can you maybe just type over to us? [Technical Difficulty]

Maybe you can just repeat what you said, Jim, just to -- I don't know if that -- maybe you got that or not about the -- our neighbors to the south.

Right. Just in case you didn't catch that or the line went dead while I was speaking, we feel very good about the C zones, especially in the southern tier of our acreage, as it abuts our neighbors to the south where in case it sort of slipped through. On their reporting, they have completed 5 very good C wells down there. So we're very confident in the derisking that we've done and the derisking of the Cs that's been done by our neighbors to the south.

Great. I appreciate that. And then I also wanted to touch on the coiled tubing fracs up in the Williston. Given all the additional stages, what's the incremental cost you guys are seeing on those wells? Or is it such that you're saving so much on time or better targeting at the pumping and same usage that there isn't much cost associated? Can you just talk through the differences there in a typical noncoiled tubing frac?

Yes. Really, on average across our acreage position, there isn't going to be a change in our drilling and completion cost. We'll still be in that $8 million to $8.5 million range kind of depending upon where we are, whether we're using coiled tubing or any of the other completion techniques. I think early on, some of the slickwater jobs will cost a little bit more. But as we move forward and basically, I'm going to say, get everything that we need lined up there, we typically have great, let's say, relationships and coordination with all of the pumping service companies that we use out there. I'm sure you're aware they're under pressure, not only from us but from others, since they -- we're able to see some price increase as well. Oil and gas prices were rising and to quote the CEO of Oxy, we hope they'll be as flexible on the way down.

Your next question comes from David Tameron from Wells Fargo.

A couple of questions on slickwater that you just alluded to. If -- I know it varies across the basin, but can you talk a little about cost and just additional cost? Like in Sanish, for instance, what's the additional cost there versus what you have been doing? Let me start with that.

This is Rick Ross, and I can respond to that. I think, as Jim said, our cost on slickwater jobs will vary from flat to maybe as much as 12% incremental, depending on job sizes that we pump and logistics in the area.

I mean, is that -- so I can't characterize it by Sanish does this other basin, this other subset does this? You can't really characterize it...

Probably the 2 areas that are close to flat pricing are like Sanish and Missouri Breaks, just because we have lower water handling cost there. And in some areas, where we don't have as -- and that's what Jim was referring to. As we build out our water handling networks and things like that, we can reduce that incremental cost. So...

And to be honest, I'm trying to imply that, really, over the next 6 months, I would expect to see some flexibility on the part of truly what we consider to be our partners in the development of these areas, and that is the pumping services companies. And as you know -- well, we take great pride in our relationships with these folks. Not only do they help us with respect to the design and some new equipment ideas that we have and have had and have implemented through them, and they're very talented machinists, but they've also been what, I would say, is reflective. They've had good sound thinking, I think, on pricing towards us. And with our improved size in the Bakken/Three Forks area, we're expecting to see some reasonable flexibility there on their part. So I'm trying to get across the idea here that we still think we can drill these things for about $8.5 million -- drilling complete for about $8.5 million, including the slickwater job, as we line things out into 2015.

Okay, that's helpful. And just one...

Thank you, Dave.

Okay. Can I ask one follow-up?

Sure.

Just in the Niobrara C. Just the way, and I may be talking semantics, but the way the press release is worded, it said recent 10-day rates have average x. Are these wells that are showing similar profile and that they take a while to clean up? Or can you just talk about how those come on line in -- is that 10-day rate -- go ahead.

They're the same. It's Eric. It's -- Dave, they're about the same as the A and the B. It could take 15, sometimes even 30 days, to clean up and then they hit kind of a stabilized rate. And that's what we're referring to in the press release. That's the most recent stabilized rate we've got. The wells are holding in there around those rates, so we think they're similar to maybe even better productivity. If you noticed, they're drilled on 9 -- 640-acre spacing versus our typical wells on 960. So...

Okay. But I lay that curve -- if I lay -- if I look at the A and B curve, that's a similar profile, is what you're saying?

Yes, sir. Yes, sir. And the important point is there that, I think, Eric was pinging away at, is that, that was a 640 and, of course, not a 960. So we're hoping for some uplift when we start drilling longer laterals into that zone.

And we have another question for you. This one is from Joe Allman from JPMorgan. Joseph D. Allman - JP Morgan Chase & Co, Research Division: So as Whiting pushes completion technology forward, have you drawn conclusion about what techniques work best and where? I mean, for example, when I look at the coiled tubing wells that you disclose in the press release, I mean, some of those wells are just huge. And so I'm assuming that, that doesn't necessarily work as well in every field. So you could you just describe that?

And I guess, responding first to your comment about the coiled tubing wells that we reported in the Tarpon field, I think the coiled tubing completion compares pretty well there to our state-of-the-art cemented liner plug-and-perf. They're just huge wells in Tarpon with both of those completions. Regarding coiled tubing completions, probably the area that's going to work the best is, I would say, probably Eastern Sanish drilling, eliminating the drill-out of the plugs. So I think we'll see limited use of the coiled tubing completions, but it is a good tool.

I'll add to that. That, really, what we try to do, our acreage position is we have several of the sweet spots at the basin that we're trying to develop. But the geology varies subtly from one area to other areas. And so for example, on our slickwater fracs, we've gotten excellent results in 3 areas, as we mentioned earlier in the call, both Sanish, Missouri Breaks and it shows up on Page 7. But we also got a very good slickwater test down in Pronghorn. So certain areas that respond to different completion techniques differently than other areas. So really, what we've been trying to do here over the last couple of years is fine-tune our completions to the geology in each of those different areas. So I think that's the important take away here. It's just going to be subtly different from one area to the other.

And we design our [indiscernible] [Technical Difficulty]

Do I have you on? Joseph D. Allman - JP Morgan Chase & Co, Research Division: Joe Allman's here.

Okay, Joe. Just... Joseph D. Allman - JP Morgan Chase & Co, Research Division: Yes. So -- no, so I think we had the same crackly problem. So Jim, when you just started discussing, I heard the first 3 words, but I didn't hear the remainder.

Well, thank you, Joe. What I was mentioning is that we have specialist teams in each one of our project areas. These are cross-disciplinarian, including our geoscientists, our completion engineers, our drilling engineers as well as our operating people. And so to try to relate how I think about that is in each one of our areas, I feel like rather than "going to" a GP on this, we're going to a specialist to design the frac in that area. Joseph D. Allman - JP Morgan Chase & Co, Research Division: Okay, that's very helpful. And then a follow-up. Jim, you talked about plans for 2015. So in an $80 WTI environment, do you think activity changes much from the current level? And what would happen if WTI sat at $70 for a while? And whatever you did, like, what would be the impact on production growth?

Thank you, Joe. Well, I think what we're really saying to you here is, look, as a combined entity, I think we're going to push the bigger ball up the hill just as fast as Whiting did in 2014. So basically, spending no more money than the combined entities did in 2014 and 2015. We're going to take that combined entity and grow it at least as fast as Whiting grew alone in 2014. So we're doing that by being effective and efficient by using these completion techniques by -- I'm sure you're well aware we're -- we view our acreage. Everything that we own in one way or another is being in a good area. And then within each area, obviously, there are, as Mark referred to, some subtle differences, and we're trying to concentrate our rigs in the areas that are giving us the biggest bang for the buck. To go on and answer -- I hope that part of it is helpful to you, so that you can see that we're working on our efficiency, and that's reflected in my comments about approximately 20% year-over-year growth as being a target for us in 2015. In terms of whether or not there would be much of a change if oil prices fell to, say, $75 or so, no, I don't think so. I really don't. I think the activity would be about the same. The rates of return, the IRRs and other things, times to payout really don't change very much. I might say even all the way down to $70. Obviously, there's some, and we'd have a little bit more. We obviously have a little bit more outspend, but not significant than as we've tried to show you here. We think even at today's oil prices are, our capital availability will be over $4 billion.

We have another question for you. This one's from Brian Corales, and he's from Howard Weil.

You all continue to test all these enhanced completions in the coiled tubing. It doesn't seem to be common place from anybody else. Is that something as we more field-wide -- testing field-wide in the Bakken and potentially even to the Niobrara? And what are the cost differences there? And what is the main benefit, I guess, outside of these big wells that you all are getting?

Brian, it's Eric. And we already answered that question. And...

It may have been when I got knocked off, I'm sorry.

Yes, it's all right. So yes, we already answered it. So give another one?

Yes. And can you tell about what those declines look like? Are they -- are those better? Or I mean, is it holding up just like a typical well in the Bakken?

I think the coiled tubing has similar declines. Is that the case, Rick?

Yes...

I don't know if there's any appreciable difference. I mean, we think maybe the slickwaters might have lower declines in certain areas, but the coiled tubing is pretty similar to our state-of-the-art cemented liner.

Okay. And can I just do one follow-up, if you don't mind? The...

Sure, Brian.

In the Niobrara, I know you're kind of going on pad drilling and it gets lumpy. Are we going to start seeing kind of a smoothing effect as we get into 2015? Or is it going to continue to be relatively lumpy?

I think it's going to continue to be lumpy. We're going to be drilling on 8-well pads. So when we bring on an 8-well pad, we're going to see a good sized jump in production. I think as we get up to a 6-rig program, that may smoothen out a little bit, but I think the nature will be the same.

This one is from Michael Hall, and he's from Heikkinen Energy Advisors.

I just wanted to kind of take the flip side on Joe's question and thinking about the 2015 kind of soft plan that you have. So if oil prices, let's say, do recover, would that scale up with oil prices? Or is that level probably something we should anchor out the full year expectation?

I think, naturally, if oil prices recover and we have more cash flow, we can scale up our plan and grow faster. But the point we're trying to emphasize is that at current oil prices, we can achieve something similar to this year's growth rate, we think, around 20%. And on a flat capital budget of $3.8 billion, we think that most of the Street is somewhere between $4.1 billion, some guys have $4.5 billion. So we just want to kind of narrow into your expectations as to how we can compete in the current oil price environment.

Okay, it make sense. Kind of seems like adding production has a similar spend rate and relative to expectations, so good capital efficiency. I guess as a follow-up, as you think about the funding of next year, I know you got ample liquidity, but you do have some nonproducing assets on the gas processing side and some kind of noncore assets as well. Any commentary around potential to monetize assets in 2015? And if so, what sort of total sums we might be thinking about?

I really don't want to speculate on that, because I'd like to sort of announce those if and when they occur. I will confirm that we do have a lot of interest in our gas plant assets and realize that we spent some money on them here during the third quarter. But I'd like to just sort of underline what you, I think, are observing, which is that these assets, after we installed them and developed them, are typically worth a big multiple of what we spent to develop them. And so -- and we have what I consider to be people who would like to be and I think will be great partners for us, not only perhaps in buying some of those assets perhaps, but also in going forward and partnering up as we develop even more of those assets in the future. So I'm very optimistic about our capability to do that. I do think it's a big number if we ever wanted to monetize them all. We have a lot of chances, I guess, let's say, to dance on our dance card. And we're evaluating the, I'll call it, the intensity of the interest on all of those folks who have been kind enough and smart enough to give us a call.

This one's from Jason Wangler, and he's from Wunderlich Securities.

Just curious kind of as we look into '15, and I appreciate the commentary there, just the cash flow, it looks like they're going to be pretty solid. And Jim, you mentioned that, obviously, that will fluctuate with oil prices. But what are your plans as far as the hedges? I know that you guys don't have too much going into next year. Is there anything that you can comment on as far as that going forward?

Well, I will say that I really don't think that we, to date, have lost all that much in terms of if we've been greater hedged, say, to 50% or so for 2015 already. I certainly will admit that I wish we were hedged more. But to be honest, I, for one, didn't know what the Saudi's were going to do. It -- well, that particular downturn that we're existing in here, I might say that yours truly has lived through 6 of these in my 40-year career. And I can tell you that they all provide opportunities, as well as pain. And I think over the years, Whiting has been adept at finding those opportunities and doing that because we have a strong balance sheet, not necessarily because we were well hedged. So I bring that up only to mention that over that 40-year period, and 30 of them here at Whiting, I really look forward, if you can imagine that. I look forward to these periods that give us these opportunities. And frankly, it's good to be able to show the quality of our inventory to be able to compete. It doesn't scare us here at Whiting to compete at the current oil prices or even a little lower. I think it shows the quality of our inventory, our ability to grow and still add net asset value per share. And I might say, I appreciate the long-term shareholders that we have that stick with us through these periods of time. And I hope that's kind of beneficial for you in thinking about it. We really didn't see what I thought was a great pricing out there due to the [Technical Difficulty]

Jim, can you still hear me? [Technical Difficulty]

Well, let's ask Jason how much of my answer he heard.

I appreciate it, Jim. I mean, I got the most of it. You kind of said you didn't get great pricing or you weren't seeing great pricing, I guess, maybe before the downturn. And that's kind of where we lost you and that's kind of all I have.

Right. Did you hear Mike's answer?

I did not. I'm sorry.

Okay. So go ahead, Mike.

What I was saying is that Whiting generally protects about an $85 floor on the hedges. So with the strip at $80, if we were to be 50% hedged for '15, at least for the first half of '15, that costs us about $45 million. And while that's not insignificant, it would not change our capital budgeting around $3.8 billion. We wouldn't change that because of that $45 million.

Next question comes from Mike Kelly from Global Hunter.

Jim, at Redtail, the gross location count continues to climb higher here just about every quarter. I was hoping you could give us a sense of really how much? And what type of delineation work is still up to be done here in your eyes before you could more kind of definitively state that the 5,000 potential locations is really exactly what we should expect to get?

Well, Mark Williams has been waiting for somebody to ask that question and jumping up a bit. I will interject beforehand that, just a reminder here, kind of remember that this area out here was really the playground of the old oil and gas operators here in the DJ Basin going all the way back to the '40s and '50s. And so we had the benefit when we came out here of looking at the logs from those wells that went down to the D and the J sands. We have a pretty good idea across our entire acreage position of the thickness of, if you will, the A through the D, essentially calling the Codell/Fort Hays the D. So we have a pretty good idea that virtually all of our acreage would be productive in typically 2 or more of those 4 zones. Now what we're doing with -- really, our initial test well drilling out here, what we call ITW, is not really what I would say exploration drilling or expansion drilling. It's just filling in some knowledge areas that because there are subtle differences out there between old wells that were drilled and whose logs we have. So at this point, I really don't think that you need to think too much further about true derisking. I think we know that the majority of our acreage position, the vast majority of our acreage position is going to be productive in at least 2, and in some cases 3, and in some cases 4 of those zones. So what we're really doing with that IT -- with the what we call ITW drilling, is really just gathering further information to better plan the development of the area rather than necessarily derisking it any further. That's how we feel about it. And we do gather, what I would call, a deeper knowledge in the sense that while we're out there, we can use more modern techniques than just the old logs that we had when we began to evaluate the area.

And just to add to that. These ITW wells, of which we've now drilled 6, are really designed to give us a more granular feel for the amount of oil in place. As Jim mentioned, the logs tell us. We use those logs to a great deal to help us map out each of those zones, all 4 of them across our acreage. Still, we've got a pretty good idea there. What we're doing with the ITW wells is we're taking core to the combined interval, the A, B, C and then the Codell/Fort Hays, which we call the D here. And what that really does is allow us to give a true volumetric metric to each one of those different zones and help us to fine-tune how we setup our development pattern in each of the areas around those ITW wells. So we do that in advance of our fleet of development rigs before they get there to help us really fine-tune exactly what we're going after, exactly what part of each of those zones we're drilling in. So in terms of where they -- where each of those zones are developed, we've got a pretty good handle on that already just from the mapping those ITW wells, really just allowing us to quantify and put actual values of oil in place on each of those different zones. So as we've said here earlier in the script, we think that the C and the D are each going to be present and developable through about half of our acreage position. We don't know exactly what that number is right now, but that's what we're estimating from all the mapping that we've done. And this ITW program will allow us to stay ahead of the development rigs to determine with several months to a year before the development rigs if they're exactly how we're going to fine-tune our development program, which of the 3 or 4 zones that we're going to go after.

Great, good color. Second one for me. And I don't know if Paul hit on this with his monetization question. But if you look at Slide 5 here, Jim, that kind of shows that Whiting's a much more focused company than what it's been in the past. And you highlighted you've done over $1 billion of asset sales in the last 15 months. North Ward Estes just kind of sticks out as maybe the asset here that doesn't fit with Redtail and Williston. And I think you guys have been pretty candid in the past sort of the right price and at the right time, you might look to monetize this. But just curious here, with the drop in oil prices if you would -- how that changes you're thinking on this asset, potentially if you'd want to wait out for a potential oil price to get a higher price? Or just how you think about that asset in the whole context of the portfolio right now?

Sure. So first of all, let's just comment about North Ward Estes and how we think about it. Yes, I have responded that really is, with any of our assets, everything is always available for review and to receive offers on. I'd like to kind of comment about what I call the advantages as well as the challenges of having an enhanced oil recovery project. So one of the challenges are, I'll deal with that right away, that if you're expanding it and building it out, it has capital requirements basically for drilling the patterns that we used to water and CO2 flood the property. On the other hand, one of the great benefits of having an enhanced oil recovery project is that, especially, I would say, during times when oil prices might fall, you have the benefit here of basically slowing down a bit on the capital. You have the benefit of wetting up the WAG, the water, gas injection cycle, and have put in more water, which is cheaper than buying CO2. So one of the great things about North Ward Estes and, to be honest, why it's a great asset is that #1, you replace the Mother Nature. So you're in charge of the decline curve. You can hold that asset, that production out there, which is about 10,000 BOEs a day, to us net, flat, because you are Mother Nature. You decide the pressure. And you can make that, what I call, expansion pressure to go into new areas by using more CO2, or you can keep the pressure up and basically the production up in your existing areas simply by wetting up your WAG. So I would say this about North Ward Estes, it provides us a great flexibility in times of fluctuating oil prices.…

We have another question for you. This one is from Jason Smith from Bank of America Merrill Lynch.

Jim, just to stick on the potential monetization track, you guys have, in the past, provided some color around Robinson Lake, in particular, in terms of the EBITDA or cash flow with that asset. Following the work you guys have done there, could you maybe provide some more color in terms of what that asset is generating today?

Well, there really isn't any update. I think we show in the range of around $40 million of cash flow per year. And Mike, go ahead.

$40 million to $50 million.

That's going to be in that -- Mike just said $40 million to $50 million. And that's especially the case here, is we are ramping up the capability there from basically 100 million to about 130 million cubic feet of gas a day. And we should have that expansion done by the middle of next year. So I think you could probably give it about a 30% uptick during that period of time.

And are there any other significant projects that you guys are thinking about at this point on the midstream side?

Well, so I think you're probably well aware in those slides we've had out in the past. We also talked about the assets that we have in the area of Pronghorn. We call that Belfield, and that's a great plant for us as well. And that it's in the range of around 20 million cubic feet of gas a day. And so it has similar economics just sort of pro rata with the volumes there. It's an excellent plant. Both of these plants have very high operating times. We pride ourselves essentially in making sure that these plants have the capability to get all of the gas that we and the others in the area are developing. And we try to be proactive being early into the game at capturing our gas here. And as you know, that really worked well to our advantage in terms of our relationships with the state, the regulators, both federal and state, and as well as capturing gas that other operators were developing. So we continue to expand the Robinson Lake. We have further plans that would permit us to expand Belfield. I think you're well aware that we've already build a plant, but it is on its way. It's currently at about 20 million a day but -- capacity, but Redtail is planned to go to 140 million cubic feet of gas a day inlet. And I'll let Rick mention about one other small one, the bay plant that we're putting in.

So we're currently building up a plant up in our Cassandra development area that will come online in probably January of this year that will process 15 to 20 million cubic feet a day.

Great. So these plants have -- and I'm going to say the capture prices being paid by people who would want to be a partner, whether be a financial partner or, what I would call, a joint operating partner there with us have been pretty enticing. And as I said earlier in the call, we're just going to kind of fill up our dance card and see maybe who wants to be our partner for a longer period of time.

That's really good color. A quick follow-up for me. Just in Redtail, you guys talked in the past about testing the northern part of the acreage. Just any update there.

Well, as we were talking, we've got this ITW program, and that is designed to test all our acreage position. And we're just wrapping up now a 6-well ITW program. I think we'll have results on those wells, probably sometime during the first quarter, and we'll release them at that time. But we continue to do that to keep in front of the development rigs.

Thank you. I'll now hand back to Jim Volker for closing remarks.

[Technical Difficulty]

Why don't we just have Jim Volker give his last remarks then we can close it up. Thanks, Sandra.

Sorry, everyone, for the blinking line. And I think you heard -- I hope you heard Eric say that Pete Hagist will be presenting at the Bank of America Merrill Lynch Conference at 10:30 a.m. on Thursday, November 13. And then in closing, I just want to thank all of you on this call. We noticed some new callers here, thank you for your new interest in Whiting; and for many of you, your continuing interest in Whiting; and to all of you, thank you for your great questions which, we hope, allowed us to be expansive and very clear in our answers. Thanks again, and we look forward to meeting with you soon.

Thank you. Ladies and gentlemen, that concludes your conference call for today. You may now disconnect. Thank you for joining, and enjoy the rest of your day.