Thank you, and good morning. Welcome to Gulfport Energy Corporation's Fourth Quarter and Full Year of 2018 Earnings Conference Call.

I'm Jessica Wills, Director of Investor Relations. Speakers on today's call include David Wood, Chief Executive Officer and President; and Keri Crowell, Chief Financial Officer.

In addition, with me today available for the question-and-answer portion of the call are Donnie Moore, Chief Operating Officer; and Paul Heerwagen, Senior Vice President of Corporate Development and Strategy. 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 condition, 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 full year 2018 net income of $430.6 million or $2.45 per diluted share. These results contain several noncash items, including an aggregate noncash derivative loss of $65.1 million, an expense of $1.1 million in connection with the litigation settlement, a gain of $231,000 attributable to net insurance proceeds in connection with the legacy environmental litigation settlement, a gain of $124.8 million in connection with the sale of Gulfport's 25% interest in Strike Force Midstream and the sale of common stock held in Mammoth Energy Services, and a gain of $49.9 million in connection with Gulfport's interest in certain other equity investments.

Comparable to analyst estimates, our adjusted net income for the full year of 2018, which excludes all of the previous mentioned items, was $321.7 million or $1.83 per diluted share. An updated Gulfport presentation was posted yesterday evening to our website in conjunction with the earnings announcement.

Please review at your leisure. At this time, I would like to turn the call over to David Wood, CEO of Gulfport Energy.

Thank you, Jessica. Welcome, everyone, and thank you all for joining this morning.

2018 marked the start towards a focus on capital discipline and it is heightened now by the 2019 plan, underscored by putting returns first. I applaud the team on remaining committed to the full year 2018 capital budget, ending the year in line with our public guidance and investing approximately $815 million across the portfolio.

Our asset base drove meaningful cash flow generation in 2018 with full year production averaging 1.36 Bcf of gas equivalent per day, an increase of 25% over 2017 and operational cash flow totaling $829.3 million during 2018, increasing 31% over the preceding year. We are focused on optimizing the cost structure and our per unit operating expense, which includes LOE, production tax, midstream gathering and processing and G&A, decreased 7% over 2017.

Furthermore, when the expense reductions are coupled with the strong realized pricing received across all our products, we expanded our EBITDA margin by approximately 4%, increasing overall corporate returns for the year. During 2018, the process of simplifying the portfolio began and we competed two noncore asset sales, monetizing our 25% equity interest in Strike Force Midstream and completed our first offering of common stock held by Mammoth Energy Services.

These transactions as well as cash flow generation during the fourth quarter, allowed Gulfport to return a significant amount of capital to shareholders. And in December of 2018, we completed the previously announced and expanded $200 million share repurchase program, repurchasing 20.7 million shares and reducing shares outstanding by over 10% during 2018.

I am pleased to see the progress in noncore asset sales to date. And as we noted in our budget release in January, we plan to meaningfully expand upon this during 2019 and 2020.

The anticipated monetization of certain noncore assets held in the portfolio today will allow us to return a significant amount of capital to our shareholders through our recently announced $400 million share repurchase program, which I will touch more on shortly. Turning to reserves.

Gulfport's year-end 2018 proved reserves totaled approximately 4.7 Tcfe and was comprised of 88% natural gas and 12% natural gas liquids and oil. Our commitment to capital discipline and the shift to funding our future activities within cash flow led to knock-on changes in our long-term development plan.

And as expected, resulted in a decrease in our booked proved undeveloped reserves at year-end 2018 and contributed to lower year-end 2018 reserves when compared to year-end 2017. The changes in our proved undeveloped reserves resulted in more weighting of the overall reserve base to the proved developed category, and bringing us more in line with where our peer group sits today.

Touching on proved developed producing reserves, we saw meaningful growth totaling 2.1 Tcfe at year-end 2018, up 18% over the prior year and converting approximately 17% of year-end 2017 undeveloped reserves into the proved developed category. Proved developed reserve additions, positive performance revisions and the improvement in commodity prices led to an increase in our PV-10 value, up 18% year-over-year and totaling $3.4 billion at year-end 2018, a compelling value proposition when compared to where the market is valuing Gulfport today.

In summary, Gulfport's 2018 activities established a foundational start for the business. The volatility in the commodity markets last year as well as the industry's response underscores our repositioning for this year and beyond.

During 2019, we are shifting to building an organization that is focused on capital discipline, cash flow generation and a commitment to executing a thoughtful, clearly communicated business plan that enhances value for all of our shareholders. The 2019 capital program and operational plan, as previously announced, prioritizes margin maximization over production growth and generates free cash flow, while adhering to strict capital discipline.

During 2019, we currently forecast a maintenance capital spend that will hold our fourth quarter of 2018 production relatively constant for the year and assuming today's strip pricing and our current hedge position generating excess of $100 million in free cash flow. As we plan for 2019, it is important to note our commitment to capital discipline and focus on shareholder returns goes beyond this calendar year, and the 2019 total capital spend establishes a sustainable maintenance level program.

Our focus on delivering more with every dollar invested by maximized lateral lengths in both core asset areas allows us to deliver more with less going forward. Our drilled lateral lengths continue to go up, increasing lateral length expectations for anticipated time lines and providing increased resource exposure per well over time.

Furthermore, as the company's asset base continues to develop, we forecast that our base level corporate decline shallows and assuming a maintenance capital scenario in 2020 similar to this year, we would expect our land spend to be minimized allowing even more capital to be invested in revenue-generating efforts. To summarize, while we have not published out-of-year guidance, as we look into 2020 and beyond, we forecast a similar capital spend to the 2019 program to hold total production relatively constant, highlighting the quality of our assets by delivering sustainable production with low maintenance requirements.

In addition to our planned operational activity for 2019, alongside our budget release in January, we also announced a new $400 million stock repurchase program and noted our plans to exclude this program within the next 24 months from the time of announcement. The authorization follows close behind the completion of the 2018 previously announced and expanded program, further demonstrating our commitment to enhancing value and returning capital to our shareholders.

The new program will be funded through organically-generated free cash flow and the anticipated monetizations of certain noncore assets held in the portfolio today. We have identified several noncore potential divestiture candidates and are actively pursuing options for each of those today.

In addition, bear in mind, we also hold a 22% interest in Mammoth Energy Services totaling 9.8 million shares valued in the public markets today. So with this in mind, I'll quickly provide a summary of our 2019 plans.

During 2019, we forecast our total capital spend will be in the range of $565 million to $600 million, funded entirely within cash flow and to provide free cash flow generation in excess of $100 million. We are fully hedged to support our 2019 program, and our strong hedge position provides clear line of sight into our anticipated results.

As we heighten our focus on returns in 2019, we look to allocate capital to the highest return prospects within the portfolio. In 2018, the budget was allocated roughly 70-30 to the Utica and SCOOP, respectively.

In 2019, we have increased weighting to the SCOOP, and absent the completion of the DUCs in the Utica, this year's budget is expected to be roughly 50-50. As we look toward next year and assuming commodity prices stay similar, we would expect this allocation to continue to weight heavier to the SCOOP over time.

Turning to our specific core areas in the Utica. Our 2019 program will be centered around the dry cast window of the play, with a focus of maximizing lateral lengths and realizing economies of scale with our per foot metrics.

In our Oklahoma core asset area, the 2019 SCOOP program is largely focused on the liquids-rich wet gas area of the play, where we continue to see strong well results and efficiency gains. When normalized to a 7,500-foot lateral, our fourth quarter of 2018 average spud-to-rig release was 51.1 days, an improvement of nearly 30% from the 2017 program average and we are continuing that momentum going into 2019.

All in all, our 2019 program is moving the company in a positive direction. We are focused on controlling what is within our control and maximizing results with the core assets we have in the portfolio of today.

We are committed to disciplined capital allocation and focused on returns that will allow us to operate within our own cash flow, shifting the target from top line production growth to leading bottom line debt-adjusted per share growth rates. With that, I will turn the call over to Keri for her comments.

Thank you, Dave, and good morning all. As announced in our budget release, for 2019, Gulfport's Board of Directors has approved a capital budget of $565 to $600 million, which as Dave mentioned, we forecast will be funded within cash flow and generate free cash flow in excess of $100 million.

The 2019 budget includes $525 million to $550 million of capital expenditures related to drilling and completion activities and approximately $40 million to $50 million of capital expenditures associated with lease-hold activities during 2019. At this level of capital spend, we forecast our 2019 full year average daily production to be 1.36 billion to 1.4 billion cubic feet per day, consistent with our fourth quarter of 2018 average production.

With regard to realization, before the effect of hedges and including transportation expense, the company expects basis differentials to range from $0.49 to $0.66 per Mcf of NYMEX monthly settled price for natural gas. This differential is derived based upon our current firm portfolio, including both Utica and SCOOP, and forecasted 2019 production at current strip prices and current basis marks.

Driven by the seasonality of natural gas and the markets we reach, we believe our differential will average at the narrow end during the first and fourth quarter of 2019 and wider end of the range during the second and third quarter. In addition, we expect to realize 45% to 50% of WTI for natural gas liquids and $3 to $3.50 of WTI for oil.

Additionally, our realized prices continue to be supported by our hedge position, and we have fully hedged our expected 2019 natural gas production at $2.83 per MMBtu, providing a high degree of certainty surrounding the cash flow profile for the 2019 program. Maintaining a strong strategic hedging program is an important element to supporting the long-term development of our assets, and we will opportunistically layer on additional hedges and basis swaps to provide line of sight to our realizations and cash flows.

In terms of cash expenses, we continue to manage our per unit cash operating expense and forecast per unit cash cost will decrease by approximately 7% over full year 2018. For 2019, we expect -- we estimate LOE to be in the range of $0.15 to $0.17 per Mcfe, production tax to be in the range of $0.06 to $0.07 per Mcfe, midstream gathering and processing to be in the range of $0.53 to $0.58 per Mcfe and G&A to be in the range of $0.09 to $0.11 per Mcfe.

Moving on to the balance sheet. We remain committed to maintaining conservative leverage metrics.

And as of December 31, 2018, Gulfport's net debt-to-EBITDA ratio equated to 2.15x. I will now turn the call back over to Dave for closing remarks.

Thank you, Keri. In closing, with the near-term outlook for North American natural gas facing challenges and the market increasingly focused on shareholder returns and free cash flow generation, we feel that prudent capital spending and disciplined capital allocation are distinguishing features in our business.

More importantly, as I mentioned earlier in my remarks, our focus on capital discipline and cash flow generation goes beyond this calendar year and we are committed to running this business with a focus on enhancing shareholder returns going forward. Should commodity prices improve late this year or in 2020, we foresee this as temporary and would remain disciplined to our program.

This concludes our prepared remarks. Thank you, again, for joining us for our call today.

And we look forward to answering your questions. Operator, please open up the phone lines for questions from the participants.

Could you give me -- my first question is just on the sensitivity of the plan. Dave, I'm just wondering is there a -- when you look at sort of what's going on with oil and gas pricing, is it much the way you're looking at it given your capital plan these days that could change the impact of SCOOP activity?

Or I guess, for that matter, just overall activity based on maybe what pricing would do for the next quarter or 2 or 3?

Yes. Neal, one of the benefits we have, I think, is a well -- what I call fully hedged position.

And so we clearly do that to protect what I see as the downside. And so for 2019, I think we're in good shape.

2020 is something that we'll have to run a little bit further on this year, probably past the midpoint of the year to get a sense of what it looks like. But the plan in 2020 is to do the same thing to be fully hedged and to protect that program given the volatility in the markets.

Great. And then just one follow-up.

Just on SCOOP economics, maybe for Donnie. I'm just wondering, are you continuing to see notable improvement either in the SCOOP well cost or the results?

It seems like you've done a number of changes and continue to do a number of changes. So just any color you could shed on either the cost or just even the results side, Donnie.

Absolutely, Neal. Yes, I mean, I think we've all continued to be very pleased with the performance of our wells.

As you noted in the release, the continued improvement in our drilling efficiencies, reducing those cycle times and that's what we'll continue to work on this year. So very excited about the economics in the SCOOP.

Those liquids play a big key for us and are very strong.

I'd just add to that, that if you looked at our capital spend last year, it was weighted towards Ohio. With the DUCs that we're bringing on, it's closer to 50-50.

But if I look at 2020, I see more capital going towards that SCOOP play. We're excited about what we see there and the types of returns we get given the current price outlook.

I guess, I wanted to follow up a little bit on Neal's first question. Obviously, company has been almost fully hedged in 2018 and looking to 2019, but not a lot of hedges in place right now looking to 2020.

So how do you think about hedging the portfolio here? And is there a thought that -- I know you've talked about discipline that maybe keeping a little lower hedge level might give you some kind of strategic optionality if something changes, given your kind of conservative view on gas prices today.

Yes, Tim, thanks. I wish I had a better crystal ball on pricing of oil and gas and -- but I'm afraid I don't.

I think that looking to 2020 is really for us going to start in earnest kind of past midyear. I really want us to deliver on the type of plan this year and going on beyond that.

And so I see us being fully hedged in 2020. The real question is at what point we do that.

I have a little bit of a more optimistic view, but I haven't seen it in the market yet. I think the discipline that's being shown, I talked about, and amongst our peers I think is good.

If that actually materializes, then I think we could see some meaningful price improvement next year, but I think we have to go a little way further to see that. I am midterm quite optimistic about gas prices, witness some of the talk around new LNG export facilities moving forward.

And so it's really this near-term window that I have the most concern about. And we'll maintain our pretty conservative position to be fully hedged as we move our program forward.

Okay. Okay.

And then, I guess, the SCOOP obviously is becoming a -- getting a larger portion of your capital. Other than cycle times, can you talk about kind of what initiatives you're focused on for 2019, and specifically, do you plan to sort of continue delineation of other zones besides the Woodford?

Yes. So Tim, I'm a old sub-surface guy by background, and so plays like this that are relatively early in their maturity cycle, I'm very interested in.

And I think the Woodford and the Sycamore, both have quite a bit of running room in our footprint. The Sycamore is quite a bit more immature for us.

I think we're only going to do one well this year and some nonop penetrations. We're still learning about that, but I'm encouraged by what we see.

This year we're really focused on the Woodford. We're moving around some of the completion techniques.

And so I'm encouraged by what I see. But in everything you kind of need a little bit of time to see how that manifests itself.

But overall, as a sub-surface guy, I kind of like what I see, and I like the things that we're trying to get more out of those wells. So overall, very encouraged.

Not to just belabour the hedge thing, but just looking at the quarterly breakdown of them, looks like it kind of jumps up in the back half of '19. And at least my expectation, please correct me if I'm wrong, is kind of production should be relatively uniform throughout the year.

Just how should we think about that position? And then like you said as you layer on 2020, how do we think about that?

Jason, this is Paul. Generally speaking, we try to shadow that hedge position alongside of our production profile.

While we've guided to production being generally relatively flat through the year, slightly up, but not everything is perfectly flat quarter-to-quarter, month-to-month. So we've tried to shadow that alongside some of our production profile for the year.

Okay. And that's, I guess, my question, Paul.

Should I kind of think about that similar to what you guys did years ago, I guess, what's the kind of the firm takeaway, just kind of think about the hedge book is kind of trying to shadow it in some form or fashion then?

Exactly, Jason. You hit the nail on the head there.

I was hoping to get a little bit of clarity around a few of your comments here. I guess, when I look into 2020, you guys kind of made the comment that capital will remain flat.

And if gas market improved, you still wouldn't kind of spend money. At the same time, I guess, you guys talked about being more optimistic on 2020 gas prices.

Just kind of help me with the philosophy there. I guess, is it more just a commitment to free cash flow in 2020, so if things are better, you guys want to continue to kind of maintain base production and just return more to shareholders.

What's the thinking there if prices do move up?

Yes, Leo. Yes, we like to stay disciplined to this plan, so free cash flow generation, returning to our shareholders is kind of #1 for us.

I would like to think that 2020 it'll be better gas prices, but it's not showing itself that way. The curve is still in backwardation and so we have to kind of manage that.

I think 2020 will look very similar to 2019. The wells that we drill going forward are longer laterals versus, for instance, the DUCs that we're bringing on.

So that's more capital efficiency there. So we need less capital for that.

We do have the advantage of last year, we spent $110 million-or-so in land. By 2020, that will be a what I call a de minimis number, few tens of millions of dollars that's all.

And so that capital is available to redirect into drilling. So I feel good about this year.

I feel good about where we're going in 2020, and we'll stay that program. The comments around where gas prices are going if they go up, absent discipline by the industry and if people start to chase price from, say, this $2.60 soft bottom to something like $3, my personal view is I think it'll just come right back down.

So I don't know why I would go chasing something that would cause our strategy to change. So it's really that kind of macro response that we're working with.

And so we'll stick to our guns here and enjoy the extra free cash flow next year if it happens, and then we'll be looking to redeploy that appropriately.

All right. That's good color.

And I guess, just with respect to the DUCs, obviously, you guys are blowing down some of that inventory in 2019. I guess, as you look into 2020, would there be a plan to sort of drill more wells in '20 to kind of rebuild all of that in DUC inventory or we still have DUCs to kind of work down in 2020 as well?

Leo, I'm not a great believer in DUCs. I haven't quite worked out why I would want to drill a well and not get it on production to get some return.

So I have to tell you, I'm not the greatest fan of DUCs. But having said that, a normal carry rate for us is about 20 wells.

So the way I look at this year, next year is we're going to basically use up about 40 DUCs in our inventory and get those wells producing here. Most of that spend is going to be in the first part of the year.

As I look to next year, the wells that we're going to drill are going to be over 11,000-foot laterals. The DUCs are about 9,000 feet, so we're going to be able to penetrate more rock with less wells.

And so I think that's the important point for me. And so with the saving in land that I mentioned, I think next year we'll be able to do the same with less capital and less wells.

Okay. That's good color.

I guess, just lastly on the Springer side, you mentioned sticking to the Woodford this year. I guess, it sounds like you want to go with the reservoir where you have the most confidence, but just curious as to whether or not there could be some Springer oil drilling this year or next, just given the fact that oil prices are maybe behaving a little better than gas here?

Yes. So one of the advantages of moving capital into the SCOOP is the higher liquids component there.

The Springer, as I look at it, is an attractive opportunity, but I wouldn't displace the Woodford or the Sycamore for that. But it is a nice add to our portfolio, and as we kind of roll along, we'll take a pretty strong look at that.

As I said to one of the earlier calls, I'm really a sub-surface guy, so stuff like that is of high interest to me and see what we can do.

And David, congrats on your appointment.

Thanks, John. I appreciate that.

Just curious on what your thoughts are for both public and private company consolidation within Appalachia? And what role, if any, do you see Gulfport playing?

Yes, I think we're reset ourselves on our program for what's going to happen in 2019, and then to continue that in 2020. So we're not looking to be part of the game.

I will say the game looks to be very interesting. We see a number of companies that are in a position that's a lot less favorable than the position we're in.

And I do think on a capital efficiency basis, both basins that we have a core position in could do a whole lot better if there was some consolidation. So it's something we're aware of, it's something we watch.

But our 2019 plan is pretty well set. And 2020, once we get a handle on gas prices, I think we'll have a pretty good set there.

So nice thing to watch for us, but I don't have any specific plans.

Okay. And then as we think about the capital mix this year being 50-50 SCOOP, Appalachia and rising the SCOOP over time.

Can you just speak to, one, how high that SCOOP mix should ultimately go? And is Appalachia really just kind of a free cash flow engine in your mind at the current time?

Yes. I think that gets to the heart of what I think is good about having at least 2 legs to a stool, is it allows us to move capital backwards and forwards.

And here we're making a concerted effort to move capital at this price stack from Ohio to emphasize more in the SCOOP. I'm not to say it's always going to be that way, but I think moving in, in that direction makes sense.

I think Donnie and his operational folks are doing a great job in drilling wells better, faster, cheaper. And so that's very encouraging.

The liquids component of the wells that we're bringing on clearly has a economic advantage, and so we want to take advantage of that opportunity. So I would say, yes, generally over time, 50-50 is DUC weighted.

I would expect that it will be more than 50 in the SCOOP in 2020. If we get a handle on where gas prices are, et cetera, then that may change a little bit.

But the contrast between the 2, if you think about it, the SCOOP wells are more expensive and take longer. And then they have slightly better returns than the Utica does.

But we can have very attractive wells still and have a great inventory in the Utica. So it's certainly something that I would not dismiss at all.

We regard it as a very valuable and core asset to us. So it just happens to be in this time frame, we're just moving capital one way.

That's very helpful. If I could sneak one more in.

Just on the 2009 budget, could you just let us know if there was any oilfield service price deflation base cased in the budget? And to follow-up on Neal's question earlier, within the SCOOP, obviously the rig counts come off, so any kind of leading-edge commentary on price -- service price weakness that you're maybe seeing or not seeing in the SCOOP?

Yes. So on the general comment about price weakness, I think we're going to see some price advantage dribble into our areas here.

As far as budgeting goes, we just stay the same as 2018. So we didn't bake in to our numbers any sort of anticipated advantage.

So I would say that.

For my first one, I wanted to follow-up on some of the drivers around improving capital efficiency in 2020. Specifically, to what extent will lateral lengths increase next year?

I think in some of the comments, it sounds like Utica is going from 11,000 to 9,000, but wondering if they're increasing in the SCOOP as well? And then also to what extent would your land expense decrease year-over-year from '19 to '20?

And then what will your base decline look like next year versus this year?

John, thanks. Yes, so we're going from the DUC average of 9,000 to new wells being 11,000.

So that's kind of directionally where we're going. As we continue to drill in the SCOOP, those lateral lengths and a lot of it is a complex geology, but we would see the 9,000-foot level there, and hopefully, being able to make some progress on that.

So that's kind of the lateral length part. And then Paul, do you want to answer -- you had a question about the base decline.

Was that right, John, did I miss that?

That's correct. And also the land expense decrease year-over-year.

Yes.

Yes. So on the land side of things, you've seen that come down approximately by 2/3 from 2018 actuals to what we're guiding to here in 2019.

We would expect to see a similar type kind of percentage decrease year-over-year again as we look towards 2020 there. So that's a nonrevenue-generating dollar turning into a revenue-generating dollar within the budget as we had forward.

And then secondarily on that base decline side of things, heavy on the activity, and a historical year, particularly in 2007. As those wells are kind of exiting their initial year one, year two decline phase and turning the corner into their terminal declines, you will see that PDP base shallow out over time, making the treadmill less steep for the company on a go-forward basis.

Okay, got it. Paul, I'm not sure if you have it handy or not, but any way to qualify the decline?

I could follow-up off-line if you don't have it, but just curious.

John, this is Donnie. Yes, if you look at Utica, our base decline now, like Paul said, is continuing to shallow out.

We're in those low to -- low 40s right now for Utica. For SCOOP, probably in the mid- to upper-30s right now on those.

As you know, those two assess the wells perform very differently. SCOOP initially is a much lower decline so -- and newer wells, so they're continuing to flatten out as well.

Okay, great. I appreciate that.

Then one more if I could sneak it in. Just on noncore assets sales.

I know you, of course, have the ownership of Mammoth here, but I imagine you also have some other assets you're looking to part ways with. I was hoping you can expand on what some of those other noncore assets could be?

Or maybe to approach the question a little differently, what do you currently view as core?

Yes. John, I think that's the right way that I look at it is everything that's not Ohio and Oklahoma is noncore and is on the table for us to monetize and use those proceeds to come back and help with our share buyback.

So that's the way I'd look at it. Clearly, the share ownership that we have in Mammoth is a large part of that.

And it's a good company and we've been happy to have that investment, but it's noncore to us. And so at the appropriate time, we would be an exiter of that position.

So that's where we stand today.

David you highlighted your focus on debt-adjusted per share growth, which I think is commendable, particularly in that it seems you're focused on returns over growth instead of splitting the baby, so to speak. I was hoping you could give us a sense of your corporate breakeven and really thinking for 2020 and beyond, given that you're essentially 100% hedged for 2019.

Yes. So Drew, it's Paul.

As we think about corporate breakevens, we could comfortably tell you that when we bake in sort of cost of capital onto the equation, we're well into the low $2 NIM zip code on a corporate portfolio basis. And certainly as the capital allocation weights more towards the SCOOP over time, our corporate level breakeven will continue to push further down as that liquids component comes into the portfolio.

Okay. And yes, with strip pricing, what kind of free cash flow do you anticipate in 2020?

Yes, we would expect it to be -- well, you got to make a simplifying assumption, we know what gas prices are going to do and we don't. But like I said, we'd be kind of similar in '20 to '19 is the way I would look, a way I would hope anyway.

Then it's the same extra price?

Yes. I'm assuming that gas prices aren't going to go too far down from where we are today.

Okay. So like a 2019 strip, roll toward 2020?

Yes.

I have a question on land CapEx. And I'm aware that it was already asked, but I would like to understand the reason why it's expected to be lower in the next few years?

Is it like because of lower production growth or is it like a conscious decision to spend less on land?

Yes, Jane, that's a good question. Generally land expenditures are lumpy because land terms usually lock them up and then you don't have to spend any money on renewals for a while.

So that's one of the main drivers. The other one is, we took a real hard look at what our program in the out years looks like.

And there was some land that was not stuff that we were going to get to. And so the question for us was why are we spending money there.

So really it was just making sure we had the land that we needed for our long-term program and the periodic need to renew leases. So that was the reason why it was a heavier spend last year, it's a lighter spend this year, and it's what I call a minimal spend in 2020.

Okay, got it. This is very helpful.

The second question, I would like to understand why lease operating expenses should be lower year-over-year. You mentioned 7%.

You're not thinking about production being largely flat, what would be driving lower lease operating expenses?

Jane, this is Donnie. Yes.

And if you think back on fourth quarter, I know we had a little higher in the fourth quarter, more seasonal impact there as we enter winter, a lot of winter prep going on. But if you look at that underling OpEx, which I'm able to do and the things that teams have their line of sight on today, the opportunities there, we continue to drive those efficiencies in our operations and see those costs continue to come down.

So very encouraged with what we've seen and where we're going.

So we should expect this trend to continue, let's say, in 2020-plus as well? Is it something -- or should we kind of think about more like flat lease operating expenses afterwards, after 2019?

I think in '19, we're guiding roughly $0.16-ish or so, $0.16, $0.17 in LOE, which is pretty -- I think pretty flat going forward.

Okay, that's perfect. And may I ask the last question.

I understand that you're kind of targeting maintenance mode and prefer to generate free cash flow. Still I'm just curious like what Henry Hub threshold price would you need to think about maybe accelerating production a little bit?

And a similar question on SCOOP. Is there like a certain WTI or NGL Henry Hub price that you would consider helping to accelerate the development program there as well?

Yes, Jane, I think those are very good questions. I'm not so sure that I feel comfortable as to where gas prices and oil prices are going.

And so a small move in gas prices, say, up to $3, I think we're still in a oversupply situation as an industry. And so absent broader discipline in the industry, I think we'll just come straight back down to this $2.60 soft bottom that we have.

So I don't see any value in changing our strategy here to go chasing price that's on a temporary basis. So that's the reason why we're sticking to the game plan here for '19, I expect that -- exactly the same game plan in 2020.

Oil prices moving and associated gas influence, I think will be an overhang on us. As I mentioned to one of the earlier questions, I see LNG by the 2025 window and beyond as being a nice potential mop to increase gas prices.

So I have an eye on that. But anything in the short term, I wouldn't chase, and we're not going to change our strategy to do that.

Two quick wins. One, stock buyback.

Is that event dependent or you're going to generate free cash flows and you will buy back somewhat systematically? So that's kind of question #1.

Question 2 is on the PUD revision, was that -- where was it? Was it more Utica, I presume?

And then how much was it for the 5-year window versus anything economic related?

Yes. Rehan, thank you.

So on the buyback, we're going to use free cash flow and money from noncore asset sales. If I look at the distribution of free cash flow this year, it's kind of second half weighted because we're spending a bulk of our capital in the first half because we have this DUC inventory I really want to get on production.

But we are pulling the reins on all of our noncore asset sales. Those are all being worked now.

And so as you can appreciate some of the timing is not fully in our control. But certainly, they will be trigger points for us to use those proceeds to go back and do that.

So that's kind of how the timing will work. And then on the PUD, Keri will answer that question.

Sure. So on PUD revision, with the shift in the capital development plan, it was purely a function of those PUDs moving out of the 5-year SEC rules.

It was not at all performance related. We actually had positive performance revisions.

And those -- the 5-year rule mainly came into play for the Utica wells.

Thank you, Operator. We appreciate everyone dialing in today.

And should there be any further questions, please don't hesitate to reach out to our Investor Relations team. Thanks, everyone.

I hope you have a good day, rest of the day. Thank you.