Jessica R. Wills - Associate Director-Investor Relations Michael G.

Moore - President, Chief Executive Officer & Director J. Ross Kirtley - Chief Operating Officer Ty Peck - Managing Director of Midstream Operations

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

Ronald E. Mills - Johnson Rice & Co.

LLC Jason A. Wangler - Wunderlich Securities, Inc.

Leo Mariani - RBC Capital Markets LLC David A. Deckelbaum - KeyBanc Capital Markets, Inc.

Jeoffrey Restituto Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc.

Jeffrey L. Campbell - Tuohy Brothers Investment Research, Inc.

Ipsit Mohanty - GMP Securities LLC Daniel D. Guffey - Stifel, Nicolaus & Co., Inc.

Thank you, Abigail, and good morning. Welcome to Gulfport Energy Corporation's first quarter 2015 earnings conference call.

I am Jessica Wills. And with me today are Mike Moore, Chief Executive Officer and President; Ross Kirtley, Chief Operating Officer; Aaron Gaydosik, Chief Financial Officer; Keri Crowell, Vice President and Controller; 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 vary 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 with the GAAP measures will be posted on our website. An updated Gulfport presentation was posted yesterday evening to the web site in conjunction with the earnings announcement.

Please review at your leisure. At this time I would like to turn the call over to Mike Moore.

Thank you, Jessica. Welcome everyone and thank you for listening in.

As announced in the press release yesterday evening Gulfport reported approximately $138.9 million of EBITDA. $88.2 million of operating cash flow and $25.5 million of net income during the first quarter of 2015.

These results contain a non-cash gain of $31.3 million, due to hedge ineffectiveness and a gain of certain equity method investments of $20 million. Comparable to analyst estimates adjusted net loss for the first quarter, which excludes the previous mentioned items, was $7.2 million or $0.08 per diluted share.

Production for the first quarter averaged approximately 424 million cubic feet of gas equivalent per day, ahead of our previously issued guidance of 378 MMcfe to 390 MMcfe per day. Solid well performance and exceptional operational run-time drove outperformance in the first quarter.

The Utica continues to prove itself an exceptional resource, and our first quarter production illustrates the strength of our P2P (2:44) reserve base into play. Furthermore it was another cold winter in the Northeast, and I am extremely proud of the winter operation initiatives that our team rolled out this year to minimize weather related downtime and ensure consistency in our production.

Overall, our first-quarter production demonstrates the high asset quality we have in the Utica and the experience of our team. Building upon our first quarter momentum we estimate April production averaged approximately 437 MMcfe per day.

Currently we forecast second quarter production to average 445 MMcfe to 455 MMcfe per day. We are off to a strong start to the year and seemingly on track to meet and potentially exceed our previously issued 2015 production guidance.

Gulfport experienced strong price realizations during the first quarter of 2015 with natural gas prices, before the effect of hedges and including transportation cost, settling at approximately $0.21 per Mcf, $0.44 per MMbtu, below the average NYMEX last day settlement price. This compares to the company's previously announced natural gas basis differential guidance of $0.52 to $0.58 off NYMEX.

Utilizing our firm portfolio, we were able to take advantage of the cold weather and price our molecules at premium market points relative to in-basin pricing. We are reiterating our full year natural gas basis differential guidance.

However as we enter the summer months we may swing a little wide of this range. Before the effect of hedges our first quarter oil price came in slightly higher than expected, driven by the premium LOF (4:33) pricing realized from our southern Louisiana assets.

For the balance of 2015 we reiterate our expectation to realize approximately $10 off of WTI for oil. Our realized NGL price came in slightly lower than anticipated.

Gulfport as well as our peers expect NGL weakness to continue throughout 2015 and have updated our NGL realization guidance to reflect our current expectations. Our updated guidance reflects continued weakness in the propane markets.

And our plans to recover a minimal amount of ethane through the remainder of 2015, which we believe will open up additional end market opportunities for our natural gas and enable us to optimize our marketing portfolio. We now expect to realize approximately 35% to 40% of WTI for natural gas liquids during 2015.

Meanwhile to keep all this in perspective, remember that NGLs will account for less and less of production as we approach year-end 2015, as we continue to focus on our high-return dry gas opportunities in the Utica. On the hedging front we realized a significant gain of $18.8 million in the first quarter.

As you can see from the press release and the updated slide in our investor presentation, we continue to opportunistically layer on additional hedges and basis swaps to provide certainly to our realization and cash flows. In addition as we enter development mode in the Utica and become more comfortable with the resource base, it has allowed us to take a longer-term view.

And we currently have hedges in place through December 2018. Including the cash settlement our hedges and transportation costs, our blended realized price for the quarter totaled $3.79 per Mcfe.

On the cost front we continue to focus on operating efficiencies and continue to make strides in driving down unit cost, and today reiterate our full-year 2015 operating cost guidance. First quarterly lease operating expense totaled approximately $0.44 per Mcfe, down 2% (6:41) over fourth quarter 2014.

First quarter Midstream processing and marketing expense totaled approximately $0.66 per Mcfe, down 14% from our fourth quarter 2014. First quarter G&A expense totaled approximately $0.28 per Mcfe, down 5% over the fourth quarter of 2014.

First quarter unit costs were largely in line with our expectation. And as we mentioned on our fourth quarter call we believe costs will continue to trend lower throughout the year, as our volume growth outpaces our fixed expenses, allowing us to realize economies of scale and lower per unit cost.

Our continuous focus on cost discipline throughout the entire organization has enabled us to mitigate the effects of a lower commodity pricing environment and protect our margins. Gulfport's E&P capital expenditures and leasehold acquisitions for the first quarter 2015 totaled approximately $246 million.

As expected, capital expenditures were heavily weighted to the first quarter of the year, as this figure reflects carryover costs associated with our 2014 program and our transition from six to three operated rigs in the Utica. In addition, as we announced in February, our 2015 capital budget begins to incorporate a service cost savings of 10% beginning in the second quarter.

And we estimate the balance of our E&P CapEx will be spent ratably per quarter over the remainder of 2015. This is in line with our previously announced 2015 capital budget of approximately $646 million to $706 million, which we are reaffirming today.

As hoped, continued execution and the strong results both operationally and financially have led to opportunities to expand our position. And we are excited about our recently announced Utica acquisition.

A few weeks ago we announced our acquisition of Paloma Partners III for approximately $300 million. Paloma holds roughly 24,000 net acres in the core of the dry gas window in Belmont and Jefferson Counties, Ohio.

This acquisition allows Gulfport to increase our scale in the core of the dry gas window and brings our total acreage holdings in the play to approximately 208,000 net acres. Moreover, the addition of this premier acreage fits hand in glove with our ongoing development activities in the dry gas window and makes Gulfport the largest holder of dry gas acreage in Ohio in the core of the play.

We believe this acquisition is highly accretive to our shareholders, as it is one of the most consolidated and blocked-up acreage positions we have seen of this size in the Appalachia. The acreage is drill ready.

And we have already identified over 150 additional drilling locations at 160-acre spacing that will further enhance our exposure to this world-class resource. Once we close the acquisition in the third quarter we plan to add a rig and begin development of this acreage during the fourth quarter of 2015.

This increased activity is reflected in our current 2015 capital budget, which we updated in conjunction with the announcement of the acquisition. Equally as important as sourcing and executing on the acquisition of Paloma was funding it in a manner that is accretive to our shareholders and maintains our strong financial position.

In conjunction with this acquisition we recently completed two capital markets transactions consisting of both equity and debt. On the equity side Gulfport successfully raised net proceeds of approximately $502 million of capital to fund the $300 million acquisition cost of Paloma and the anticipated near-term capital commitments related to the development of this acreage.

In addition we completed a $350 million senior notes offering using the proceeds to term out our borrowings outstanding under our revolving credit facility and pre-fund our expected outspend for the balance of 2015. The industry has certainly had an active start to the year in the capital markets, and we believe our deals were unique in that they were the first to be accompanied with an accretive acquisition for shareholders.

In addition during the first quarter we completed our spring bank redetermination, which increased our borrowing base from $450 million to $575 million. Gulfport is pleased to announce that BBVA Compass, BNP Paribas, PNC Capital and U.S.

Bancorp have joined our bank group. Following the senior notes offering the lenders elected to maintain the borrowing base at $575 million.

I think this speaks to the quality and low risk nature of our asset base, as we were able to increase the commitments from our lenders with no reduction to our borrowing base following a high yield transaction, despite a decline in commodity prices. Pro forma for these recent capital market transactions, Gulfport's revolving credit facility is undrawn with approximately $70.5 million in letters of credit issued, leaving approximately $504.5 million of availability under the facility.

In addition pro forma for the payment of the transaction cash on hand totaled $359 million. Our dedication to capital discipline and balance sheet preservation have resulted in a strong liquidity position today.

In summary we had an outstanding quarter operationally, achieving record production, which has put us on a trajectory to meet and possibly exceed our 2015 production guidance. Our robust hedge book and superior firm transportation portfolio positioned us to achieve strong realizations during the quarter, and I believe remain well-positioned to continue this for the remainder of the year.

As expected continued execution of our plan led us to an accretive opportunity to expand our portfolio. And the Paloma acquisition adds to our top tier position in the Utica Shale.

In addition the deal provides us further exposure to what we believe to be one of the lowest cost and highest margin gas basins in North America. Lastly, following our recent capital markets transactions we are well-capitalized with over $860 million of liquidity today.

This strong liquidity position when coupled with our proven ability to execute, preserves the option to ramp activity when appropriate should commodity prices rebound, as well as remain poised to be opportunistic in the acquisition market. This concludes our prepared remarks.

Thank you again for joining us for the call today. And we look forward to answering your questions.

Abigail, please open up the phone lines for questions from the participants.

Hey morning, Mike. So, Mike, was looking at the slide, the new deck that you have out.

Could you maybe talk a little bit on slide 14, the wet gas wells. I guess what I'm particularly looking at your thoughts or Mark (14:08) and the other guys' thoughts as far as now that you're hitting that intersection or inflection point, anything new on how you think kind of your perception on how these wells are holding up?

Your perception on where do you think these wells – what's going to happen once they particularly – once they possibly hit the natural line pressure? Just I guess any details you could add around that.

Okay. Thanks, Neal.

Yeah sure. First of all let me remind you that we put both the condensate type curve and the wet gas type curve together when we only had one well producing in each window of the play.

So I think it's pretty remarkable that the wells have tracked as well as they have against those original type curves. And you know what we have done historically.

We've been very transparent by plotting the production of the wells onto the curve, so you guys see everything that we see. I think the fact that – well first of all let me back up.

The condensate wells were put on managed pressure program earlier than the wells in the wet gas window. So when you look at the dataset for the wet gas window, you've got about 45 wells under the optimized program.

But quite frankly 31 of those wells didn't come on until post July 1 of last year. So we haven't even had 12 months' production yet.

And really the majority of the 31 wells didn't come on until after September 1. So we have a pretty small period of production on the largest part of the dataset for the wet gas window.

I think the fact that we've already reached the inflection point is encouraging. What happens next, we'll just have to wait and see.

We'll continue to plot the production onto the curve. What we're doing on this is really not seen in the first 12 months of production.

So we're encouraged by what we see with the curve. And we'll continue to plot the production and track it along the curve.

If at some point we see that we need to tweak the curve we will. But quite frankly even the low end of the curve, at 18.2 Bs [Bcfe] of EURs [estimated ultimate recoveries], that's a pretty remarkable well.

So nothing that we see is discouraging to us at this point, and we'll continue to monitor it as we have more time and more history.

No, that makes sense. And maybe just two others.

Just could you talk a little bit – I think you said going from six to three rigs. Talk about for the remainder of the year.

I think you had mentioned mostly dry gas wells coming up. What region will most of those be in?

Or how will you – where are you targeting I guess for the remainder of the year and the beginning of the next year? Which areas?

Well I think the way you should think about the wells that we bring on for the rest of the year quite frankly, Neal, is dry gas. Even the wet gas wells that we'll be bringing on in the fourth quarter, I think we have a couple pads, are very lean.

They're on the east side of the wet gas window. So they're more dry gas in nature.

Really from a window perspective array, commodity perspective, you need to think about dry gas for us for the rest of the year. The Paloma activity that will start in the fourth quarter of course won't come on until sometime next year.

Okay. And then just lastly, Mike, on the M&A.

Any other larger packages like Paloma out there? Anything that you guys think are interesting that's out there?

Oh there's always parts of acreage that we like. And certainly we're aware who has acreage in the core, acreage that we think geologically makes sense.

I hate to speculate on those opportunities. We're really putting our heads down and focusing on our development of our Utica acreage.

But we always have a goal in mind of creating value for our shareholders, so if there's an opportunity that presents itself, we'll certainly take a look at it.

Perfect. Thanks for the details, Mike.

Thank you.

Good morning, Mike. Couple questions.

One on you brought your first dry gas well or a good dry gas pad on in the fourth quarter. I know typically you like to have six plus months of data.

As you think to dry gas type curves, is the timing still kind of late summer? And any update in terms of how those wells have performed?

Maybe if we were even looking at competitor type curves?

What I can say is we still expect to bring out a dry gas type curve late summer, early fall. So our thoughts have not really changed there.

We want a bigger dataset, multiple pad, dry gas pads. But I can tell you the Perkins pad is that first pad that we got on in the fourth quarter of last year.

And we are currently flowing the Perkins well at 2,000 Mcf per day per thousand feet. And that is in line with our peers.

So we're very pleased with what we see at this point on our first dry gas pad.

Okay. And then I know we've talked about this for quite some time, but where are we on the Darla pad evaluation and design to test not only spacing but also different types of completion designs and everything?

Are we – are you getting closer to having some resolution on Darla?

Well, closer. Again I hate to keep saying this, but there's just so much data that's come out of that science experiment.

We are continuing to work through the data. We are continuing to put it into models that we have.

And the current expectation is that we hope to be able to provide an update by midyear. So I think maybe a little sooner than we had indicated previously.

But we're working through it as fast as we can and trying to draw our conclusions. But keep in mind we've done some other things aside from the Darla pad on down spacing.

And quite frankly we have some pads that are performing very, very well at 750-foot spacing. We have some other pads that we've done 500-foot spacing.

Our peers are also obviously doing some testing. So hopefully the industry will come to some conclusions this year about the same time.

And then as it relates to service costs, I know the Marcellus/Utica hasn't seen as dramatic of a response. Can you give a comment on service cost environment?

And also what you're doing to high-grade vendors in this kind of environment?

Hey, Ron. This is Ross Kirtley.

As you know earlier this year we put out some of the lowest targeted well costs in the Utica. And we continue to work with all of our vendors to drive those costs down as low as we can.

We have recently just signed a contract to upgrade one of our drilling rigs. So we're pretty excited about that opportunity.

And we continue to work with all of our vendors to gain efficiencies throughout all of our operations.

And I might add, Ron, to your high-grade comment. It has certainly given both us and vendors an opportunity to high-grade relationships.

And so what you do is you migrate to the vendors that have done a good job for you, that have good crews and good equipment. And so in a sense you have high-graded and more efficient operations out there.

All right. I'll jump back in queue.

Thanks, guys.

Hey. Good morning.

You gave a lot of color on the Paloma acquisition. And could you just talk about a takeaway from that area?

Is there much Midstream so far in that area? And then maybe even who you're using?

Or do you have any contracts yet or that you can utilize that you already have signed for that area?

Yeah. This is Ty.

As far as a takeaway from that Paloma area, there was a lot of the development already started. And so there's some advantages that we have there.

We are working right now to firm up those deals. And at this time I can't tell you specific names.

But we do feel comfortable with position that we have with the timing that we're putting the rig in that we will be – have adequate takeaway, both on the gathering and the firm transport.

So, Jason, we have options; we have several different options. And if you think about the timing available to us, we don't close until September.

So we won't have a rig out there drilling until probably October. By the time we get that pad on we're talking about probably April.

So we've got plenty of time to decide what makes the most sense for us.

No, that's really helpful. I appreciate it.

And then just on the first-quarter numbers, the Midstream transport costs were down quite a bit. Maybe even lower than the guidance.

Just curious if there was something you saw there? And just your thoughts as we go throughout the year, how those should trend?

This is Ty again. They're going to trend in line with our expectations that we've put out first quarter.

The first quarter – the lower first quarter was largely driven by the performance of the condensate wells that we brought online as well as our Southern Louisiana assets.

Great. I'll turn it back.

Thank you.

Jason.

Hey guys. Mike, you made a comment that you guys are on track to meet or exceed production guidance here in 2015.

Can you maybe give us a little bit more color in terms of what it would take for you guys to exceed? Is this just more strictly a function of seeing wells drilled and tied in on time?

How are we thinking about it?

Well, Leo, that's a good question. And quite frankly we have a great deal of visibility right now with our first-quarter production and with the second quarter expectation that we gave out, the estimates that we gave out.

So certainly feels like we're tracking along the high end of the guidance expectation. And could possibly have a beat there.

But I think right now we're pretty sensitive to meeting our guidance and are a little bit on the conservative side. Our wells continue to perform well.

And we're consistently seeing a period of prolonged flat production versus our forecast. The only reason we didn't change guidance expectations right now is because we felt like it was a little early after just one quarter.

Just of course tie-in schedules affect that some. But we have a great deal of visibility for that schedule.

So we'll adjust it when we get just a little more actual visibility.

All right. I guess speaking of tie-in schedules, just trying to get a sense of how many wells you guys plan to tie-in the second quarter?

And I think you guys got just over seven in the first quarter. And I guess I just wanted to clarify so the tie-ins in the first quarter that you guys reported, 7.2 net [wells], I guess that's a – is that strictly an operating number or does that include non-ops as well?

Operated. It's just operated, Leo.

And as far as the rest of the year is concerned, Leo, I would say it's really hard to talk in terms of number of wells per quarter, because then we have to tell you whether it comes on the first day of the quarter or the last day of the quarter. So I think a better way to think about it is a very linear production ramp for the last three quarters of the year.

I think if you work your model that way it makes it a little easier. So it'll be a very linear ramp for the rest of the year.

We'll bring on probably on a net basis more than we brought on in the first quarter. For the last three quarters, the first quarter just timing was such that we just brought on those 7.2 condensate wells.

Okay. That's helpful.

And I guess obviously a lot of talk about cost reductions. Could you just update us in terms of what your latest costs are for your dry gas wells there that you're drilling in the Utica?

Well as we said on our fourth quarter call our expectation is $9.5 million well cost in the wet gas and the dry gas window beginning April 1. And at this point we're still sticking to that.

And that's for an 8,000-foot lateral keep in mind, because that does make a difference.

Okay. Thanks guys.

Thank you.

Morning guys. Thanks for taking my questions.

Just on the dry gas side as you get into the rest of the year, a lot of the activity goes towards there. On the completion side is the recipe going to be fairly uniform?

Are you going to be testing some of the increased sand loading that we've seen from some of the peer operators in the area?

Hey, David. This is Ross.

We're pretty comfortable with our recipe right now. Of course we are always testing and working with our peers in trying to do a few different things, different tweaks.

But we're pretty happy with what we're doing right now, 180-foot spacing, 1,500 pounds to 1,800 pounds per linear foot. So obviously we see what our peers are doing.

And we try to take those things into consideration as well.

Okay. And in terms of the dry gas system down there on the Midstream side, it looked like MarkWest had built out that system for you.

Is everything in place like relative to your guidance or allowing for the tie-ins that you have for the rest of the year?

Yeah. This is Ty.

Yeah. MarkWest has done a good job of getting the necessary timeline and construction timeline in place.

And so as we look into the year I think we feel very comfortable that turn-in lines will meet expectations.

Hey, David. One comment back on your well design.

Obviously as Ross said we've basically got a recipe. But we're certainly open to other thoughts and ideas.

And one of the benefits of having the non-operated activity is we don't have to do the science ourselves. We can look to see what our peers do.

And we have access to that information. And so it gives us a bigger dataset to learn off of.

Fair enough. And then just on the four rigs, once you get going on Paloma with the fourth rig in 4Q.

Will you have any rigs that would be on anything but a well-to-well contract?

No, no, we wouldn't.

Okay. And then just a last one from me.

Is there any color you can give on just the – what's going on with Grizzly right now? If we should think about that, it obviously seems to be like a price-driven decision.

But what sort of activity levels are going on there right now? And how do you guys think about – with your partner up there is managing that asset through this down cycle.

And is there – should we think of a price point at which activity starts back up there again?

I can't tell you specifically what that price point is today. The activity right there right now going on is just shutting down the plant.

And that is purely a commodity price driven decision. We'll restart it when commodity prices reach a level that we think are appropriate.

Okay. That's all for me.

Thanks guys.

Good.

Morning. Just regarding your commentary around your industry's thoughts on NGL weakness throughout 2015, can you talk more about where you currently see NGLs trading in the Northeast in terms of pricing?

This is Ty. When we look at pricing I think that you're going to see a weakness in propane, just because the weather and then the fact that we just have – you can't reject propane.

So you're going to get to a point where you're just bringing on that liquid. And while we're – the thing that we're doing right now is through MarkWest, marking our barrels.

We're sending as much as we can to the regional base of the Northeast region here, which is a premium market. But then we're now have to export a percent of our barrel as well as go to regions such as the Gulf Coast, the Canadian market as well, and the Mid-Atlantic.

So we have a diversified approach to kind of weather that downturn and have adjusted our realizations for the remainder of the year to reflect that.

And again, the good news is for Gulfport, as we move through the year we're bringing on dry gas wells. So our liquids mix becomes less and less part of our value.

We'll be – we should be 85% dry gas by the end of the year. So it becomes a much less of a value implication for us.

Thank you.

Good morning.

Morning.

Mike, you're guiding 49 to 55 net wells online in 2015. And bearing in mind that you maintain a well inventory to enhance completions efficiency, can you just add some color on what underlies the variance?

The – I'm sorry; the what?

Well, the spread. What are the things that make the difference between getting 49 or 55 net wells on?

Because...

It's just timing. It's just timing of bringing them on.

Sometimes you have a little movement in the field, hooking wells up. And so that's the only variance there.

We're not – we did slow completions a little bit this year to line it up with our drilling activity. So we are not – we're certainly not using completions to manage production.

We don't – we're not in a position that we need to do that. So it's really more well timing.

Okay. And only other question I wanted to ask was I noticed that in Louisiana it didn't look like you drilled any wells in the quarter, but you maintained – you hit your guidance on production with recompletions.

And I was just wondering if that's the plan for the rest of the year, to basically just do recompletes and avoid drilling.

Yeah. It is the plan.

That's – we've done it before. We did it back in 2008, 2009.

And so we plan to not have any rigs drilling for the rest of the year.

Okay. Great.

Thanks.

Thank you.

Thank you. Good morning, Mike and team.

Just a quick question on the Paloma acreage. If you can give us some broad color on the sort of the well control there and your confidence to replicate what you have going on for you in your current dry gas into Paloma when you start activity in 4Q?

Listen, there's a lot of well control out there. This is Belmont County.

And this rock has already been delineated across the play. It's very homogenous.

In fact our geophysicists think it's the most homogenous rock they've ever seen. So from a delineation perspective this acreage has been delineated.

Okay. And then as I look at your wet gas and condensate slides, you're hitting -- on your wet gas wells, you're hitting about 2,000 pressure – 2,000 psi, call it, after probably six months of production.

Where is the line pressure here at?

We are going right now into a higher pressure system and going to expect that for some time as these wells continue to perform like they do. On the...

In other words – yeah.

On the condensate side we are under 150 pounds and will remain there throughout the year.

Okay. In other words I mean where I'm going is how long before you see this pressure – you see the underlying pressure hit line pressure.

How long can you otherwise maintain choke and keep it at a flat rate?

On our first dry gas pad?

Yes.

We don't know yet. We haven't had enough time.

So we just need more time to see when it hits line pressure.

All right. Thank you.

Thank you.

Just real quick. This is Ty.

With regard to the pressure of the systems, we do have kind of a – different phases of our system that allow us to – the condensate is going into a lower pressure than the other wells that are going into a higher pressure. So that's – it's most efficient that way when we operate the system.

Okay. Thank you.

Okay.

Hi guys. You guys have a robust firm transportation portfolio as you guys show on slide 17.

I'm just curious, kind of a bigger picture question of how you're looking at basin prices over the long term? I'm curious at one point if at all will you add FT in the out years?

2018, backend of 2018, and beyond, looks like you guys are covered before that. But just curious kind of your thoughts on potentially adding?

And where the price to add would be in today's market?

Yeah, this is Ty. When we look at the projects out there today, most of them are now starting in that 2018/2019 period.

And if you look at the forward marks right now, it looks like post 2017. There is quite a bit of new capacity coming online, which we show in the mix of our slide deck.

And so with that we do think there is a recovery. To what level or to what extent, we're still trying to work through that ourselves.

And when it makes sense – we view this transportation as kind of our insurance policy. And when it make sense we will pick it up.

But I'd say right now we're just currently evaluating. The nice thing is with our portfolio that we have today through 2018, we do have the luxury of being the prediscriminate party on which projects we want to support and which ones we don't.

Okay. Great.

Appreciate the color. And then just one last quick one from me.

Southern Louisiana, you talked about in the past potentially spinning that off. I'm curious if you've had discussions?

Or if you were just planning on keeping that in-house until you see higher oil prices?

Well certainly we've been pretty open about potentially monetizing that asset at some point in time. In this commodity price environment I don't think it makes sense to pursue any of those opportunities.

There are always buyers out there for any asset that you have, but I think it's unlikely it would be something that we would look at this year.

Okay. Appreciate the color guys.

Thank you.

Thank you, Abigail. We appreciate your time and interest today, as we know this is a busy time for many of you on the call.

Should you have any questions please do not hesitate to reach out to our Investor Relations team. This concludes our call.