Greetings and welcome to the Fourth Quarter Gulfport Energy Corporation Earnings Conference Call. At this time, all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation. As a reminder, this conference is being recorded. I would now like to turn the conference over to your host, Jessica Wills. Thank you. You may begin.

Thank you, and good morning. Welcome to Gulfport Energy Corporation's year end 2015 earnings conference call. I am Jessica Wills, Manager of Investor Relations and Research. With me today are Mike Moore, Chief Executive Officer and President; Ross Kirtley, Chief Operating Officer; Aaron Gaydosik, Chief Financial Officer; Keri Crowell, Chief Accounting Officer; Paul Heerwagen, Vice President of Corporate Development; and Ty Peck, Managing Director of Midstream Operations. I would like to remind everybody that during this conference call, the participants may make certain forward-looking statements relating to the company's financial conditions, results of operations, plans, objectives, future performance and business. We caution you that the actual results could differ materially from those that are indicated in these forward-looking statements due to a variety of factors. Information concerning these factors can be found in the company's filings with the SEC. In addition, we may make reference to other non-GAAP measures. If this occurs, the appropriate reconciliations to the GAAP measures will be posted on our website. Yesterday afternoon, Gulfport reported a full year 2015 net loss of $1.2 billion or $12.27 per diluted share. These results contained several non-cash items, including an aggregate non-cash unrealized hedge gain of $83.7 million, a loss of $1.4 billion due to an impairment of oil and gas properties, a gain of $10 million attributable to net insurance proceeds in connection with a 2014 legacy environmental litigation settlement, a loss of $101.6 million associated with the impairment of our Canadian Oil Sands assets, a loss of $4.5 million in connection with Gulfport's interest in certain equity investments, and an adjustable tax benefit of $11.8 million. Comparable to analysts' estimates, our adjusted net loss for the full year of 2015, which excludes all the previous mentioned non-cash items, was $16.2 million or $0.16 per diluted share. Gulfport's…

Thank you. We will now be conducting a question-and-answer session. Our first question comes from Neal Dingmann with SunTrust. Please proceed.

Good morning, guys. Mike, I wanted to drill down on just two slides, if I could. First, on slide 14, could you talk a little bit about – I know you mentioned, I think, the 2.5 rig plan, I assume most or all of that will be in the dry gas east. Is that correct? And if so, could you just discuss that slide 14 that talks about the single well economics? Does that have all-in costs? I know versus some others that back out some things, if you could address sort of where you're going to drill and then the economics behind these wells. Michael G. Moore - President, Chief Executive Officer & Director: Okay. Sure, Neal. First of all, the activities that we have scheduled for this year, you're right, will be at least partially in the east window of the dry gas area, but we'll also have some activities in the central dry gas area as well. And then as far as the returns there, those are all-in costs, includes everything less G&A. So it obviously continues to show that we have – we're able to deliver good returns. We talked about in the scripted comments our operating costs of $1.20, and our F&D costs are about $0.65, so break even around $1.83. So we're able to deliver some good returns even at today's commodity price environment. We feel pretty good about that.

Okay. And then just lastly, around slide 18. I like that slide where you show your basic exposure in the realized pricing. You mentioned, and I think it was on that February 2 release, obviously now you have that JV, that commencement with Rice going on, and I think it commenced on February 1. Is that playing into this? I noticed on that slide 18 that obviously the basis impact continues to lessen into 2017 and onto 2018. Is that based on kind of what you said, Mike, on your scripted comments about now having more choices on the end market? Or if you could just talk a little bit about the basis impact and the FT variable cost on that slide and maybe is that a result of that latest Rice or what all is that driven by?

Yeah, Neal. This is Ty. So what that is on 18 is our firm portfolio. We feel very confident that the firm portfolio we put together, we need to show the value of that. And so what we did was, we took 18, the slide 18, and broke that down a little bit so you can see basis impact and then our firm cost both in demand and variable. As far as our JV with Rice, it's more about reaching this firm portfolio and making sure that all the areas that we have new exposure to, new acreage on, we can reach these firm outlets. And so, yes, it does help us get to that – but it's – to reach this firm portfolio, but that's how that's related.

Got it. Got it. Great optionality. Thanks, guys.

Thank you.

Thank you. Our next question comes from Ron Mills with Johnson Rice. Please proceed. Ronald E. Mills - Johnson Rice & Co. LLC: Good morning, Mike. Michael G. Moore - President, Chief Executive Officer & Director: Hi, Ron. Ronald E. Mills - Johnson Rice & Co. LLC: Just to drill down a little bit more on the tighter – I mean, on the wider spacing, the 1,000 feet versus the 750 feet, from an acreage standpoint or maybe a capital extension standpoint, any way you can provide some color on how much that improves from a capital spending standpoint versus acreage maintenance – and you noted that years 21 to 26 don't mean much to NAV, but that move to 1,000-foot spacing, and what would drive you back towards that 750-foot? Michael G. Moore - President, Chief Executive Officer & Director: Okay. It's a good question, Ron. So really what we're doing here is trying to navigate as efficiently as we can through the capital constrained market. It obviously has nothing to do with well performance or type curves. And remember, all the scientific data that we had when we moved to 750-foot spacing indicated that the propped half-lengths were 330-foot, and that certainly seems to be evident in everything that we're seeing. But what we're trying to do, with this plan, is hold as much acreage as we can with the levels of activity that we have scheduled for 2016. It's certainly not intended to be a permanent change to 1,000-foot spacing, but a temporary change in response to the commodity price environment that we're living in today. So we're trying to be as efficient as we can. We did do an extensive NPV model and find that it's NPV-neutral to us. But I guess to put it, to quantify it a little bit for you, in terms of 2016, it's going to save us about, probably $30 million, if that helps. Ronald E. Mills - Johnson Rice & Co. LLC: Okay, great. And then from a just activity standpoint, or on the leasing standpoint, how was your activity driven? Do you have particular areas whether it's Paloma or AEP or maybe some legacy Gulfport acreage with maintenance issues, or what drove the move to 2.5 rigs? Michael G. Moore - President, Chief Executive Officer & Director: Well, Aaron, I think, can take that one for us.

Yeah. So, Ron, really as we thought about the budget for 2016, the first benefit we had was that we had a pretty strong hedge portfolio in place, so having 480 million a day, almost 80% of our natural gas production hedged at $3.29 per M was a key factor. But really the driving factor after that was to make sure that we were working within our balance sheet, and the key focus there was making sure that our leverage metric was staying within that two times to three times guidepost range that we target. And that's what kind of results in the budget that we were looking at and really that's how we got to the 2.5 average rigs running for the year on the operated side. Ronald E. Mills - Johnson Rice & Co. LLC: Great, thanks, and congrats on the hedging all the way through 2018 that you guided.

Ron.

Thank you. And our next question comes from Jason Wangler with Wunderlich. Please proceed.

Hey, good morning. Maybe to dovetail on Ron's there on the hedge side and having them so far out is, is there a certain metric we should look at as what you're trying to do? I mean, 80% this year is obviously a pretty good number. I think you're maybe pretty full here, barring a huge move in prices. But just as we look at the rolling book, is there targets that you guys look at? Michael G. Moore - President, Chief Executive Officer & Director: Well, I think – and Aaron can jump in here too as well. And you know us – you know us for a long time, Jason. So you know that historically we typically are in the 50% to 70% range. And the variance inside of that range always have to do with our macro view on the commodity for the upcoming years. And so where we're concerned, we'll hedge more aggressively, where we're less concerned, we'll hedge less aggressively. So you try to find that balance. You do have to have a macro view. Certainly, for 2016, I think we all agree that it will be a challenging year, and it's important to have a really, really good strong hedge book to mitigate the current strip prices. For 2017, I think we've got a really good start on a base level of hedges. I'd love to be able to tell you what percentage of our production for 2017 that that represents, but obviously I can't do that yet. But just know that we're very focused on 2017. We hope that there might be some recovery in 2017, so we have to decide obviously internally if we want to add additional layers of hedges and at what point we do that. So it all depends on our macro view of the commodity.

Sure. Okay. And then just on the leasing side, is that going to be focused really around just getting the book that you already have, just kept it in place? I assume that it's just maintenance leases picking them back up versus going out and making new leases. I think there's probably not much left out there, but just wanted a comment on that. Michael G. Moore - President, Chief Executive Officer & Director: Yeah. We call that leasing activity. But really, Jason, honestly, it's mostly almost all renewals. There is just not – there's not much left. There will be a little bit to build out units of new leasing but not much. We continue to be very active on the trade front with other operators as well trying to be efficient with the acreage that we have that we may not get to right away. So all operators, including Gulfport, certainly are continuing to trade acreage back and forth. But you can think about that number really, Jason, as a renewal extension number and not a leasing number.

Perfect. I appreciate it. Thanks. Michael G. Moore - President, Chief Executive Officer & Director: Thanks, Jason.

Thank you. Our next question comes from Dave Kistler with Simmons & Company. Please proceed. David William Kistler - Simmons & Company International: Good morning, guys, and congrats on another strong operating quarter. Michael G. Moore - President, Chief Executive Officer & Director: Thanks, Dave. David William Kistler - Simmons & Company International: A quick question kind of going back to the decision to move to 1,000-foot spacing and reduction in locations. You highlight that that could be temporary in nature. What would you need to see on a pricing front to move back to 700-foot spacing? Michael G. Moore - President, Chief Executive Officer & Director: I think, I don't know if I can give you an exact price, Dave, that makes us consider going back. Obviously we'll continue to evaluate that as we move through the year and then as we look forward into 2017. I think we'd want to see some sustained improvement in pricing. I think we'd want to be able to make sure that we have the appropriate hedge book in place to take advantage of that. And so if we saw things improving and they appear to be improving on a longer-term basis, certainly we're going to go back to that as quickly as we can.

And Dave, it's Aaron. Let me follow-up on that. Price is part of it, but also just the development pace that we have, and thinking about leasehold budgets, et cetera. That's also driving our decision of what the right time will be to think about whether or not it makes sense to go back to that 750. David William Kistler - Simmons & Company International: Absolutely. And just kind of thinking about that, at 1,000-foot and what you'll do this year, ultimately maybe that impairs going back to a certain section on 700-foot spacing. Can you talk about the progression of how much of that inventory it might remove permanently? And maybe an offsetting question to that would be, at 1,000-foot spacing, could you look at enhancing your frac design and maybe increasing the recoveries of those wells on a 1,000-foot spacing? Michael G. Moore - President, Chief Executive Officer & Director: Yeah. It's a good question, Dave. And so when you think about a year's worth of activity, the number of gross wells that we're drilling, and I think your implication is you can't go back in between and put another well, so how many locations are you losing? I don't know. Maybe five to 10 this year, Dave. So it's pretty de minimis in the big scheme of things when you consider that when we had 750-foot spacing, we had 1,300 locations. So really not material in the big scheme of things, and again, we hope that this is relatively temporary in nature. So we wouldn't be thinking about this on a permanent basis. David William Kistler - Simmons & Company International: Okay. I appreciate that. Second part of that question though was, do you think you could enhance your frac designs and maybe at 1,000-foot increase the…

Thank you. Our next question comes from Drew Venker with Morgan Stanley. Please proceed. Drew E. Venker - Morgan Stanley & Co. LLC: Good morning, everyone. Michael G. Moore - President, Chief Executive Officer & Director: Good morning. Drew E. Venker - Morgan Stanley & Co. LLC: I was hoping you could just give some more detail on what the requirements are to hold leases. It sounds like it's not the conventional single well per section to hold a lease. Michael G. Moore - President, Chief Executive Officer & Director: Well, I'm not sure of your question exactly. I'm sorry. Say that again. Drew E. Venker - Morgan Stanley & Co. LLC: I'm just curious as to how much drilling you need on a given lease to hold the acreage. You alluded to spacing the wells wider to preserve capital, but hold more acreage. Michael G. Moore - President, Chief Executive Officer & Director: Yeah, but we're kind of talking here about full field development versus a one-well pad design. So it's really hard to think about it that way because you have these multiple well pads, and because of that, you don't hold quite as much acreage. So I'm not sure it's quite that easy. Drew E. Venker - Morgan Stanley & Co. LLC: Okay. All right. Thank you. Michael G. Moore - President, Chief Executive Officer & Director: Thank you.

Thank you. Our next question comes from Ipsit Mohanty with GMP Securities. Please proceed.

Yeah. Hey, good morning, guys. Michael G. Moore - President, Chief Executive Officer & Director: Good morning.

It seems to me that with the activity focused around the dry gas, the dry gas east window around your newly acquired acreages, the working interest is lower than prior. When we think about going forward in 2017, what is the working interest? Does it improve beyond what you have right now or does it going to stay focused in that region of 65%, 70%?

Hey, Ipsit, it's Aaron. One thing to keep in mind is that the stuff that we are drilling today, there is a lot of focus on the dry gas east, a lot of the stuff coming online is stuff that we drilled prior, and so just kind of understand that balance as we think about the difference in the working interest. So a lot of stuff coming online is within that Rice AMI, and so those just have, as we've talked about in the past, a lower working interest than stuff that we may have picked up as part of that Paloma acquisition last summer.

Okay. And then it could be a little far stretch right now to talk about the other windows, but just specifically on the wet gas window, which still a year back looked very good on the rate of return basis, what's the outlook in moving any activity towards that side? Michael G. Moore - President, Chief Executive Officer & Director: I'm not sure exactly what it's going to take for us to go back to the wet gas window. The returns that we're seeing over the dry gas window, the number of locations that we have, give us a lot of running room over there. So certainly some improvement in liquids prices condensate will help us think about that. But this – we've got to be – in this capital constrained environment, we've got to be return driven, and we have the luxury of having this multi-phase window opportunity set out here in the Utica, which I think is pretty unique among our peers. So we can adjust our activities depending on where the best returns are, and that's what we're going to have to do until commodity prices improve.

Yeah. Ipsit, it's Aaron. We will have a few completions in the wet gas side later this year, but that's just a function of DUCs that we had in inventory as we exited 2015. But from a pure spud point of view, as Mike mentioned, it's all about relative return, and right now the best relative return is in the pure dry gas area.

All right. Thank you.

Thank you. Our next question comes from Kyle Rhodes with RBC. Please proceed.

Hey, guys. Good morning. Just curious if you've had an estimate on the percentage of your acreage HBP to year-end 2016 assuming your base plan, and maybe if you had that by window? Michael G. Moore - President, Chief Executive Officer & Director: Well, I don't know if I have it by window. I think at year-end, I think we have about a third held, Kyle. We probably – until we did the Paloma and AEU acquisitions this year, that number would have been higher. But obviously, we've now got more that we have to take care of, but probably about a third.

That's at year-end 2015 or year-end 2016? Michael G. Moore - President, Chief Executive Officer & Director: Year-end 2015, and I don't have an estimate for year-end 2016, in case you're going to ask that.

Okay. Got that. And then, I guess, I think you may have addressed this in the prepared comments, but just wanted to make sure I had this right; as you guys shift more activity over to the dry gas area exclusively, is there anything we should be aware of in terms of minimum commitment (41:01) volumes in your wet gas or condensate areas? Or is that not an issue for you guys?

This is Ty. I think the thing to highlight there is that in the deals that we've done, we've been able to obtain anchor status, which affords us the most competitive rates out there in the area in the basin, as well as a structure that we prefer, which is the acreage dedication, which allows us to drive decisions based on economics and have that flexibility around that as opposed to trying to fulfill or catch up to a minimum volume or take-or-pay type arrangement. Michael G. Moore - President, Chief Executive Officer & Director: Yeah. And Kyle, just to reiterate, from the very beginning, we were extremely focused as a corporate strategy/philosophy that we not burden the company with minimum volume commitments, so that we can do what's best for the shareholders in regards to our joint activities so we are not committed to filling commitments with uneconomic volumes. So we feel very, very good about our ability, our good fortune and strategy of avoiding those minimum volume commitments.

Great. Appreciate it, guys. Thanks. Michael G. Moore - President, Chief Executive Officer & Director: Thank you.

Thank you. Our next question comes from Jeoffrey Lambujon with Tudor, Pickering, Holt & Company. Please proceed. Jeoffrey Restituto Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc.: Good morning. Thanks for taking my questions. Just a few follow-ups on the spacing. Can you talk about how you arrived at the 1,000-foot number instead of something wider that may have potentially allowed you to go back in infill? I know it's temporary in nature, but just wondering if that carried any weighting in terms of the decision to go to 1,000 as opposed to something wider? Michael G. Moore - President, Chief Executive Officer & Director: No, it really didn't. We were given up so few locations with the 1,000-foot spacing. It just didn't feel like wider – wider spacing that we could eventually go back to was really that material. So we did not consider going to wider spacing. Jeoffrey Restituto Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc.: Okay, thanks. And then, you mentioned development pace also driving the spacing decision. Just thinking about the CapEx range, should we think about that as purely driven by only timing? Or is it more like the pace and the timing are driven by commodity prices? So if prices are kind of towards the high end of whatever bands you may use in setting your budget, would you spend towards that high end? Or is that the range for the overall CapEx number pretty agnostic to commodity price at this point?

Well, if you think about 2016, maybe it just depends on your time horizon, and it's Aaron talking. For 2016, things are pretty set. We like our hedge book. We like where we are, but we've thought a lot about the plans and so that we feel pretty good about that. Thinking for 2017 and beyond, as Mike mentioned earlier, part of it is commodity prices, but part of it is also just a function of what level of rate activity makes sense to stick within our leverage goal posts. So that's kind of what's driving our decisions over the longer term. Michael G. Moore - President, Chief Executive Officer & Director: Hey, Jeoffrey. Just one comment I want to add to make sure that I clarify, because it is an important comment. Remember, we have found historically that it doesn't work to go back to an existing producing pad. So from a spacing perspective, it doesn't really matter if it's a 1,000-foot or 1,400-foot, it's really inefficient to go back. There's too much risk. And so it's good operationally, it's not good for the reservoir, and so there's a lot of reasons we'd not go back. As you recall, early on in the play, we were going back to the pad and drilling additional offset wells, and it just doesn't work very well. So that really wasn't a consideration. Jeoffrey Restituto Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc.: Okay. Thanks a lot for the detail. Michael G. Moore - President, Chief Executive Officer & Director: Thank you.

Thank you. Our next question comes from Biju Perincheril with Susquehanna Financial Group. Thank you.

Hi, good morning. Thanks for taking my questions. Mike, I was trying to understand is the lease renewal needs, is that tied to infrastructure buildout as well? I'm trying to understand, if you're able to add a rig or two, how should we think about the lease renewals dollars going lower? Michael G. Moore - President, Chief Executive Officer & Director: Yeah, I'll talk a bit. And then I'll have Ty jump in here as well, but the answer is no. It's not tied to infrastructure. Ty's done a good job of making sure that we stay ahead of that. And so we've never been in a position where we can't develop acreage or we can't turn on our wells into sales lines when we're ready to do that. And that's just by a lot of strategic planning and foresight, but I'll let Ty comment here as well.

Yeah, this is Ty. I'd just add to that that we work when we go out and look for these partners that we're going to develop on the Midstream site, one of those prerequisites is that we can work to make sure that we are efficiently getting tied to the areas that we need to get tied to. And we're working on, if not a weekly basis, it's almost even a daily basis to make sure again that there are no wells waiting on pipe. So it's a big focus for us on the Midstream side. Michael G. Moore - President, Chief Executive Officer & Director: Yeah. What you don't see or know is, there are long lead times in activity plans that we have so that we can work with our midstream groups and make sure that they understand where our planned activities are going to be and give them plenty of time to build out everything. So we are having conversations, for instance, about 2017 already. So those are some of the things that go on behind the scenes that you guys don't always see.

Got it. So I'm sure you guys have looked at – when looking at your HBP needs, drilling single wells per section versus these multi-well pads, and is the reason not to drill the single well pads because of what you just talked about I think in the previous question about going back and drilling offset wells? Michael G. Moore - President, Chief Executive Officer & Director: Yeah. Again, it's the same answer. It just doesn't work. We don't think it works to go back and infill. It's not good operationally. It's not good from a reservoir perspective. We found out, Biju, as you remember early the hard way that it's just a very, very efficient way to do it. So while it sounds good in theory to try to hold acreage that way, from an operational standpoint, from a reservoir standpoint, it just doesn't work.

Okay, great. Thank you. Michael G. Moore - President, Chief Executive Officer & Director: Thank you.

Thank you. Our next question comes from Subash Chandra with Guggenheim. Please proceed.

Yeah. On the density question, I guess my understanding was that you want to optimize that day one, just because it's so difficult to come back and do the proper density or infill density because of communication between wells. Is that a risk that's overblown in this case? So if geologically you can do even denser than 750, that would be very difficult to achieve once they're drilled on 1,000? Michael G. Moore - President, Chief Executive Officer & Director: I think if you look at some of our early wells, you'll see that it's not overblown. It's a real operational risk. And so we've drilled enough wells that we know it just does not work, from a reservoir perspective, from a communication perspective operationally, and so it may seem illogical to you, but because of this particular rock communication system, it just doesn't work.

Okay. This answer might be obvious, but are there any sort of ways to optimize value in this environment from Grizzly or Mammoth or South Louisiana? Michael G. Moore - President, Chief Executive Officer & Director: I think, you're right. The answer's probably obvious. Listen, we'd love to be able to monetize those assets. I don't think this is the environment to do that. We are having some discussions and thoughts on what to do with Grizzly. Certainly there's some value there. We just need to figure out how to extract it and at what commodity price we can extract it. But Southern Louisiana is a little different because it does generate its own cash flow for its own activities. So it's not a physical or financial distraction to Utica. And as long as we can do that, as long as we can have a maintenance CapEx program in Southern Louisiana and they're using their own money for their activities, we're okay with that. And we can hold production, we hope, mostly flat in doing that. And I think the answer is, the short answer is, we're going to have to wait for some commodity price improvement before we're able to think about monetizing either one of those.

Okay. And final one for me. Can you remind me what the offset rules are in Ohio? Is it 500 feet off the lease line? Michael G. Moore - President, Chief Executive Officer & Director: That's right, 500 feet off the lease line. Correct.

Great. Okay. Thank you. Michael G. Moore - President, Chief Executive Officer & Director: Thank you.

Thank you. Our next question comes from Jeff Grampp with Northland Capital Markets. Please proceed.

Good morning, guys. Michael G. Moore - President, Chief Executive Officer & Director: Hi, Jeff.

More of a, I guess, housekeeping one on the 23 to 29 gross DUCs you guys expect to have at the end of 2016. Do you have a net on that or maybe spill it between operated versus non-operated? Michael G. Moore - President, Chief Executive Officer & Director: Yeah, we have. I don't think we have a net. We have the gross. I'm sorry, Jeff. Gross is all I have with me today. I don't have net.

Okay. That's fine. And then, more on the... Michael G. Moore - President, Chief Executive Officer & Director: You can follow up offline if you want.

Sure, will do. And then, on the – I noticed the Utica net acreage was down maybe about 10,000 or so from your last update. So I guess, kind of two-parter. One, just kind of wondering, should we expect some future kind of leakage as you guys maybe let some condensate or kind of non-core stuff expire? And then, on the CapEx side and leasehold dollars, should we expect there – that to be a fairly recurring expenditure for the next couple of years as you guys maybe extend or renew some things that you want to retain? Michael G. Moore - President, Chief Executive Officer & Director: Yeah. I think that's a good – I'm kinda back in to your question – that's a good number, I think, to use for the next few years, Jeff, as you think about our renewals and extensions. The 10,000 less acres are oil and condensate expirations quite frankly that we decided not to renew. And then there's a little bit of trading activity where we're maximizing our acreage positions by trading acres back and forth, and there may be cases net-net where you lose a little to gain better acreage. So it's a combination of the two.

Okay, perfect. And then just last one for me on M&A. I don't think it's been hit on too much here. Is it fair to say that given what you guys are doing in terms of the wider well spacing and allocating some dollars to renew and extend that – the bar is probably pretty high for you guys for deals that make sense. Just given that it seems like you guys would probably be unwilling in this market to take on any acreage with any meaningful drilling commitment. Is that kind of a fair statement or accurate of how you guys are looking at things? Michael G. Moore - President, Chief Executive Officer & Director: Well, I'd say, drilling commitments are – I guess, I don't mind taking on drilling commitments as long as they're minimal. And when we got the AEU acreage, obviously we had a 10-well drilling commitment with that per year, which is easy to do. Drilling commitment is something certainly that you have to pay attention to on M&A opportunities. But there's a lot of things you have to look at as well. Is the acreage core? What's the renewal term? I think if we took on acreage that has drilling commitments, it would have to have meaningful reserves and production which would encourage us to have higher activity levels.

All right. Great. Thanks for the color. Michael G. Moore - President, Chief Executive Officer & Director: Thanks, Jeff.

We've run out of time. I'd like to turn the call back over to Michael Moore for closing comments. Michael G. Moore - President, Chief Executive Officer & Director: Thank you. Should you have any questions, please do not hesitate to reach out to our Investor Relations team. This concludes our call.

This concludes today's teleconference. You may disconnect your lines at this time, and thank you for your participation.