Jessica R. Wills - Associate Director-Investor Relations Michael G. Moore - President, Chief Executive Officer & Director Ty Peck - Managing Director, Midstream Operations Aaron M. Gaydosik - Chief Financial Officer.

Don P. Crist - Johnson Rice & Co. LLC Neal D. Dingmann - SunTrust Robinson Humphrey David A. Deckelbaum - KeyBanc Capital Markets, Inc. Jason A. Wangler - Wunderlich Securities, Inc. Leo Mariani - RBC Capital Markets LLC Michael Kelly - Global Hunter Securities Daniel D. Guffey - Stifel, Nicolaus & Co., Inc. Jeff S. Grampp - Northland Securities, Inc. David W.

Kistler - Simmons & Company International.

Good day, ladies and gentlemen, and welcome to the Gulfport Energy Corporation Q2 2015 Earnings Conference Call. As a reminder, this conference call is being recorded. I would now like to turn the conference over to Ms. Jessica Wills, Associate Director of Investor Relations. Ma'am, please go ahead..

Thank you, and good morning. Welcome to Gulfport Energy Corporation's second quarter 2015 earnings conference call. I am Jessica Wills, Associate Director of Investor Relations.

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 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. An updated Gulfport presentation was posted yesterday evening to our website in conjunction with yesterday's 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 $34.8 million of EBITDA, $74.6 million of operating cash flow and $31.3 million of net loss during the second quarter of 2015.

These results contain a non-cash unrealized hedge loss of $34.6 million. Comparable to analysts' estimates, adjusted net income for the second quarter, which excludes the previous mentioned items, was $250,000, or $0.00 per diluted share.

Operationally, Gulfport had an active second quarter, as we continued to see growth in sales, and produced approximately 474 million cubic feet of gas equivalent per day, ahead of our previously issued guidance of 445 million cubic feet to 455 million cubic feet equivalent per day.

This represents a 12% increase over the first quarter of 2015 and a 196% increase over the second quarter of 2014. Production during the quarter was comprised of 77% dry gas, 13% natural gas liquids and 10% oil. We continue to focus our efforts on the dry gas and lean wet gas windows of the play.

And today, reiterate our expectations to exit 2015 with total company production of 85-plus percent natural gas. Our impressive 2015 results have been a product of continued solid well performance, coupled with the exceptional results we are experiencing from the dry gas window of the play.

Gulfport implemented a managed pressure program during early 2014, which targeted to further enhance returns by improving EURs, predictability of production, operational runtime and overall capital efficiency.

As we moved east to the dry gas window, absolute productivity exceeded expectations and the production rates and pressures we are seeing from these wells are beyond our original assumptions.

Lastly our guidance for the year factored in a number of risk related potential delays and production downtimes associated with midstream and winter operations and as we have progressed throughout the year, we have been very pleased that our actual results have exceeded our risks expectations.

Strong results during the first half of 2015, coupled with our anticipated activity for the second half of the year have led the company to update our 2015 production guidance and we now expect to average approximately 517 million cubic feet to 541 million cubic feet equivalent per day during the year, equating to 115% to 125% growth over 2014.

In addition, we currently forecast third quarter production will average approximately 590 million cubic feet to 610 million cubic feet equivalent per day.

Driven by our firm transportation portfolio, we priced approximately 96% of our natural gas production at premium market points, relative to in-basin pricing and as expected, before the effect of hedges and including transportation costs, realized approximately $0.41 per Mcf or $0.59 per in MMbtu below the average NYMEX net gas price during the second quarter.

This compares to the company's previously announced full-year 2015 natural gas basis differential guidance of $0.52 to $0.58 off of NYMEX. We continue to utilize our firm portfolio to price our molecules at favorable indices and currently expect our full-year 2015 gas differential to be within this range.

However, through the remaining summer months, we anticipate to swing wide of this range and we expect a narrower differential throughout the winter months due to higher seasonal demand.

Before the effect of hedges, our second quarter oil price came in slightly higher than expected, driven by the completion and start up of MarkWest condensate stabilizer, allowing us more opportunities for better pricing for our Utica volumes. In addition, we continue to receive premium LLS pricing from our southern Louisiana assets.

Our realized NGL price came in lower than anticipated, largely driven by the continued deterioration in the Northeast NGL market.

Gulfport, as well as our peers, expect NGL weakness to continue near-term but believe overall prices could show some improvement during the fourth quarter due to higher seasonal demand and additional export capacity coming online.

We have updated our NGL realization guidance to reflect current expectations, which accounts for the decoupling between the price of NGLs and the price of oil and we now expect to realize approximately $0.32 to $0.37 per gallon during 2015.

Again, I'd like to reiterate that as we continue to focus on our high return dry gas opportunities in the Utica, liquids will become less and less of the total company production mix. On the hedging front, we realized a significant gain of $20.6 million in the second quarter.

Including the cash settlement of our hedges and transportation cost, our blended realized price for the quarter totaled $3.41 per Mcfe. We continue to monitor the future curves (7:14) and plan to opportunistically layer on additional hedges based swaps to provide certainty to our realizations and cash flows as opportunities present themselves.

Accounting for the update in today's 2015 production guidance, Gulfport currently has 57% of our expected natural gas production hedged at $3.94.

As we look towards 2016, Gulfport is unique in that our absolute hedged volume increased year-over-year and we currently have 278 million cubic feet equivalent per day hedged at $3.65, locking in a significant amount of our anticipated cash flows next year.

While Gulfport, as well as our peers, would like to see an improvement in today's spot prices, we are well positioned through our strong hedge book and diversified (8:02) portfolio to generate very healthy economics, even in the current low commodity price environment.

On the cost front, as we bring on more gas weighted production, we continue to see per unit costs trend down. Second quarter lease operating expense totaled approximately $0.39 per Mcfe, which is down 12% over the first quarter of 2015. Second quarter G&A expense totaled approximately $0.22 per Mcfe, which is down 22% over the first quarter of 2015.

Second quarter midstream gathering and processing expense totaled approximately $0.76 per Mcfe, which as expected is up 15% over first quarter 2015 and in line with our full-year guidance.

Midstream costs increased quarter-over-quarter on a unit basis, reflecting the MarkWest condensate stabilizer coming online and a reduction in Southern Louisiana oil volumes from the first quarter. Cash interest expense, a metric not always highlighted that we believe differentiates us from our peers, totaled approximately $0.28 per Mcfe.

All in, our cash operating cost was approximately $1.73 per Mcfe the in the second quarter of 2015. We continue to focus on a low cost structure, which is essential in today's commodity backdrop and has further bolstered our returns in the Utica.

Gulfport's E&P capital expenditures and leasehold acquisitions for the second quarter of 2015 total approximately $203 million. During 2015, we have focused on high grading equipment and taking advantage of gaining access to superior services in this low service cost environment.

Specifically, we have high graded our rig fleet, which became particularly important as we moved into the dry gas window, where we are encountering higher pressures and have the need to carry higher mud weights.

We recently identified and contracted the high spec, built for purpose rig to begin development on the Belmont County, Paloma AEU acquired acreage upon closing and recently moved this rig into the play. To-date, Gulfport has four operated rigs running in the Utica shale.

On the acquisition front, as expected, Gulfport's continued execution and strong results both operationally and financially have led for opportunities to expand our position in the Utica.

Our strong liquidity position and improved management of the balance sheet over the past decade allowed us to transact the two separate transformational acquisitions that we are extremely excited about and view as very accretive for our shareholders and the Gulfport stream.

We recently entered into agreements to acquire an additional 59,325 net acres in the core of the dry gas window from Paloma Partners III and American Energy Utica LLC, which brings our total holdings in the play to approximately 243,000 net acres.

The acquired acreage represents a natural bolt-on to Gulfport's existing position in the dry gas window and makes Gulfport the largest holder of dry gas acreage in Ohio in the core of the play. As we provided a detailed overview of the Paloma acquisition in May, I would now like to provide a few highlights on the more recent AEU acquisition.

The AEU acquisition consists of approximately 35,325 net dry gas acres in Monroe, Belmont and Jefferson Counties, Ohio. The acreage in Monroe County is a large consolidated already positioned with high NRI leases and minimal HBP drilling requirements and the Belmont and Jefferson acreage serves to further block out the position acquired from Paloma.

In addition, we acquired 14.6 million cubic feet per day of production, 18 gross drilled uncompleted wells, a fully constructed four well pad, approximately 300 million cubic feet per day of firm transport and an 11-mile gas gathering system, a very valuable asset considering our near-term development plans in the area and the strategic opportunities it potentially opens up for the company.

The Paloma and AEU acquisitions are evidence of Gulfport's strategy to maintain a strong balance sheet and conservative leverage metrics so as to be able to quickly and opportunistically take advantage of highly accretive opportunities that emerge in this type of market.

Furthermore, the Paloma and AEU deals were significant in that they added a meaningful 335 net drillable dry gas locations to our portfolio, giving us the most exposure to this world-class dry gas resource and elevating our inventory to what we believe to be a critical mass given our forecasted development phase.

To firm these acquisitions and associated capital spending, Gulfport completed three capital market transactions consisting of both equity and debt. On the equity side, Gulfport successfully raised net proceeds of approximately $982 million to fund the acquisition cost of the non-producing leaseholds from both the Paloma and AEU.

Included in the total net proceeds is approximately $275 million, which is expected to pre-fund the near-term capital commitments related to developing the acreage. In addition, we completed a $350 million senior notes offering using the proceeds to fund our previously anticipated 2015 outspend and revolver balance outstanding at that time.

As of June 30, Gulfport had cash on hand totaling approximately $525 million and $482 million of availability under our revolving credit facility, which is currently undrawn.

As you can see on slide nine of our new investor deck, we feel very comfortable with our current available liquidity, which provides us with a tremendous amount of flexibility as we plan for the remainder of 2015 and look towards 2016 and beyond. We are well positioned to navigate this current commodity price environment.

And should we see a recovery in prices, we can be opportunistic and quickly increase activity. We remain committed to maintaining strong price realizations and alongside the acquisitions announced during the quarter, also continued to grow our firm portfolio.

With the announcement of the acquisitions, Gulfport strategically added an incremental 441,000 MMbtu per day of firm capacity to support our anticipated production growth from the acquired assets and provide access to more favorably priced markets, including Dawn, Midwest and Gulf Coast regions.

Looking forward, we continue to evaluate additional opportunities, both long-haul transportation and firm sales agreements to support our anticipated production growth profile.

To supplement the portfolio, our marketing group continues to be in discussions with industrial, LNG and utility end-users who are interested in reaching back to the Basin to secure shorter term firm sales arrangements.

In regards to long-term firm transportation, there are certainly a number of opportunities becoming available as operators continue to decrease their levels of activity in the basin. Gulfport has been and will continue to be an opportunistic buyer of these opportunities in the release market.

We strongly believe that the continued pullback of commodity prices will yield additional opportunities for well positioned companies such as Gulfport to very cost effectively step into the contracted space of our peers who find themselves long FT relative to their production growth outlook.

We are very confident in our knowledge of this market and our ability to transact quickly and at attractive prices and as the market adjusts to the reality of today's commodity price environment. Following today's guidance update, we reiterate our estimate that no less than 90% of our production will be priced at premium pricing points during 2015.

And as we look forward to 2016, we believe our portfolio will provide similar levels of exposure to premium price points. Yesterday evening, alongside earnings, we provided updated wet gas condensate type curves and released our much-anticipated dry gas type curve for the Utica Shale.

Our wet gas and condensate curves are now modeled in ethane rejection, which we believe provides the most accurate representation of how we currently produce the wells today. In addition, the type curves for all three phase windows assume the wells are produced under a managed pressure program.

As you can see from our second quarter results, we are encountering some very encouraging results in the dry gas window. Since bringing online our first dry gas pad during the fourth quarter of 2014, we have subsequently turned to sales an additional 19 gross dry gas wells.

This sample set of wells combined with data from a number of non-operated wells in and around our dry gas position represents an adequate amount of production history to provide our initial expectations for recoveries in the dry gas window of the play.

As you can see in slide 11 of our most recent presentation, we have separated the dry gas window into three sub-sections; Dry Gas West, Dry Gas Central and Dry Gas East.

Moving from northwest to southeast across our position, there's a meaningful increase in reservoir pressure and hydrocarbon deliverability that correlates directly with the depth of our target formation of Point Pleasant.

We expect that recoveries will follow this trend and currently estimate EURs in the Dry Gas West area of 2.2 Bcf of per 1,000-foot lateral, EURs in the Dry Gas Central area of 2.4 Bcf per 1,000-foot of lateral, and EURs in the Dry Gas East area at or in excess of 2.6 Bcf per 1,000-foot of lateral.

As you might imagine, these very prolific wells yield very attractive rates of return. Assuming a long-term strip price of $3.50 per Mcf, we believe each of these areas can generate in excess of 58% to 61% single well rate of returns.

In our most recent presentation uploaded yesterday evening, we provided additional details surrounding economic expectations for all windows of the play on slide 14. Having established the highly economic nature of our assets, let's now transition to inventory.

Since entering the play, we have made it a priority to determine the optimal lateral spacing across our position in an effort to yield the greatest net present value per acre owned. At the core of this work (18:48), efforts have been predominantly focused around our well-publicized Darla pad science work.

We have also executed or participated in a number of other spacing pilots to further validate and strengthen conclusions yielded from the Darla pad.

Added to our presentation and posted to the website yesterday evening are slides that in addition to describing the multiple technologies, third party consultants and methods of analysis used to derive our conclusions also includes a map depicting a number of spacing pilots that have been undertaking that we believe further validate our conclusions.

Our spacing work includes both technical and economic analysis yielded from microseismic, both down-hole and surface, fiber optic temperature and acoustic measurement during both completion and production, fluid chemical tracers, extensive log suites in both the pilot and lateral sections of the well and, finally, discrete fracture network modeling that is matched back to actual production history.

From this data, we have been able to surmise that our wells are yielding an average propped fracture half-lengths at approximately 330 feet.

Considering this, we currently believe that 750-foot inner lateral spacing in both the wet gas and dry gas windows and 600-foot spacing in the condensate window are necessary to optimize prop fracture links, with conductive fracture links being the concern.

While all technology used in this study proved to be valuable, the information yielded from the fiber optics provided significant insights by allowing us to validate models and simulations against real-time production data.

That's why I'm pleased to announce that under this optimized spatial regime, we now have 878 net undeveloped dry gas drilling locations, 168 net undeveloped wet gas drilling locations and 265 net undeveloped condensate locations in inventory in the Utica Shale, bringing us to over 1,312 net undeveloped locations in the play.

Lastly, with regard to our 2016 capital outlook and production growth, which I know is on everyone's mind today, we have run a wide range of scenarios at today's commodity price to share with you and outlined the options the company has with the current commodity price backdrop for 2016, although no conclusion is being made today.

On one end, we can run a five-rig program and grow around 50% year-over-year, while spending $625 million to $675 million on D&C CapEx, which we expect to fund entirely from operating cash flow and our current sources of liquidity, while not decreasing our leverage metrics.

On the other end of the spectrum, in maintenance capital mode, we believe we can hold production flat December 2015 to December 2016 and grow 2016 average volumes around 25% year-over-year, while only spending approximately $300 million and generating free cash flow at current strip pricing.

As we contemplate levels of activity for 2016, we will act thoughtfully and responsibly. Our corporate philosophy of funding E&P expenditures through operational cash flow and available sources of liquidity, while maintaining our leverage at or below 2.5 times remains unchanged.

As a reminder, we currently have approximately $275 million of available cap that was raised alongside the acquisition offerings to prefund the anticipated near-term activities on both the Paloma and AEU acreage.

The implicit growth rate of approximately 25% under the maintenance capital scenario truly highlights the asset quality we have here in the Utica. High quality assets maxed out by a strong liquidity position allow Gulfport a high degree of flexibility compared to the majority of our peers.

As we plan for 2016, it is a very delicate balance between protecting the balance sheet and managing the capital outspend within forces of liquidity while also generated strong returns for shareholders.

We feel that we are well-positioned with low development cost, a strong hedge position, financial flexibility and diverse takeaway optionality, all of which play an integral factor into our industry-leading returns. In closing, we believe Utica has proved itself to be the lowest cost gas basin in North America.

While we will not dispute regions of the Marcellus produce very large wells, the Utica has also had some very outstanding results and the marketing and transportation advantages available as you move west provide Utica producers with access to premium markets, resulting in overall higher returns.

Gulfport now has over 243,000 acres under lease in the core of the Utica, with 64% residing within the prolific dry gas window. On an absolute basis, we have more exposure to the dry gas window than any other operator in Ohio.

And on a per share basis, Gulfport has the highest exposure by a wide margin for this world-class resource than anyone else in the southern portion of the play.

Today, we were excited to be able to deliver two critical pieces of information, our dry gas type curve and initial thoughts around down spacing, both of which create a step change in valuation for the company.

It is unfortunate to have such good news in a bad play (24:33), but we feel like the information we provided today is important for the long-term value perspective. And in the near term, we are well-positioned to do what we need to do to navigate in the current commodity price environment. This concludes our prepared remarks.

Thanks again for joining us for our call today, and we look forward to answering your questions..

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

Thank you. And our first question comes from the line of Don Crist from Johnson Rice. Your line is open..

Good morning, Mike.

How are you this morning?.

Hi, Don.

How are you?.

I'm good.

Can I start with the production guidance? I know the production that you added from the AEU transaction factors into it, but can you talk about the main drivers that were behind the significant guide up in production guidance? I mean was it more related to just risking or is the rock better or was there infrastructure things that you were worried about that came online faster than you thought? Can you just expand on that?.

Well, thanks, Don. First of all, let me say that really the production we got from the AEU acquisition had very little impact in the second quarter to our overall production. But really I think, Don, it speaks to our rock quality here in Utica shale in the southern part of the play.

These dry gas wells we brought on are pretty phenomenal wells, quite frankly, and they've exceeded our expectations. So really nothing's changed from a timing schedule aspect. We pretty much brought on what we thought we would for the second quarter.

We're not slowing completions, we're not accelerating completions; it really is completely related to the quality of the assets that we have here..

Okay. And just looking at your overall inventory count, how you calculated versus your total acreage position. It looks like it's pretty conservative.

Can you talk about some of the drivers behind that?.

In our new location count slide?.

Yeah..

Okay. So, certainly we factored in the effects of down spacing to 750 foot in the wet gas and dry gas window and 600 feet in the condensate window, and so we used that as the base for our calculation.

Of course, we got lots of extra locations from the AEU acquisition and the Paloma acquisition but then we also applied a risking factor of 20% and I will tell you, that is an estimate and we continue to work on trades, swaps and we would expect to be able to create additional locations.

But we thought it was appropriate to at least apply some risking factor to the number of locations we have available to develop..

Okay. And if I could sneak in one more here, the 17 Bcf to 20 Bcf that you talk about in dry gas is obviously without ethane, any ethane contribution.

Can you talk about other operators in the area that are talking about a 20 Bcf and kind of put that on apples-to-apples? Are they counting ethane in their EURs as well?.

No. The operators that I can think of in the area also do not count ethane in their EURs as well..

Okay. I'll jump back in queue. Thanks for the -.

Thanks..

Thank you. Our next question comes from Neal Dingmann from SunTrust. Your line is open..

Morning, guys. Trying to think of a question after all those. My first, just Mike, can you talk a little bit on cost structure a little bit? How you see it, or I guess you know what I'm getting after. It seems like in your guidance you've got cost structures I think, or well costs estimated to be about the same.

How do you think about either the breakeven gas price or sort of, what – if you could talk about maybe what returns you're seeing today, just in broad terms for either one of those?.

Well, first of all, from a return perspective and, of course, we provided a lot of the new information this morning or last night in our slide deck, but single well economic returns, the dry gas window or at today's prices are somewhere in the 56% to 61% range of IRRs, so very good returns.

From a cost structure, you know we increased the costs in the dry gas window, just slightly to account for the higher mud weights that we have to deal with here but generally, we're able to drill these wells that are really efficient, a really efficient pace and at a very good price.

From a breakeven aspect, Neal, I'd say somewhere around $2 is probably a breakeven price that you should think about..

Got it. And then just secondly, just moving over to takeaway in differentials. I noticed you had a slide, and you've had this before though, just talking about LNG exports. When you all look at it, and I know Ty is always looking at takeaway well into the future.

Do you take into consideration potential for LNG exports? Is there anything that you're signing up there? Maybe if you could just address your takeaway differentials going forward..

Neal, this is Ty. We do look at the end users and what capacity they might have taken out. And I think they're all wanting access to Utica supply, which works well for us. So we've been doing that.

We actually have been talking to the LNG markets and have done some deals there and continue to do some deals there, as well as all the growth in the Gulf Coast that's coming on..

Makes sense. Thank you, all..

Thank you..

Our next question comes from the line of David Deckelbaum from KeyBanc. Your line is open..

Morning, Michael. Thanks for all those details. Just wanted to ask a question on the rig activity and where you see the rigs progressing through the end of the year.

And for the conceptual guidance that you were talking about for 2016, does that envision that all of your rigs would be active in the dry gas window?.

That's a good question. So right now we have four rigs running, two actually in wet gas right now and two in dry gas. As you recall, when we made the Paloma and AEU acquisitions, we pre-funded almost $300 million to bring in our fourth and fifth rig. The anticipation was that the fourth rig would come in late third quarter, early fourth quarter.

We actually had had our eye on a big rig and it became available a little early, so we brought it in 30 days to 45 days earlier. The reason we have two rigs right now in wet gas window is because we've got some pad development going on, side-by-side pad development. As you know, that's the way we develop the units out there for efficiency's sake.

But as soon as that fourth rig finishes up, it will move over within the next 30 days back to dry gas window. So the short answer is, what we would expect the rest of the year probably is three rigs in the dry gas window and one in the wet gas window. As we look to 2016, clearly the majority of our activity is going to be in the dry gas window.

We have 900 locations to drill over there and only 168 locations left in the wet gas window. So we'll be heavily concentrated next year in the dry gas window..

All right. That's helpful.

And could you just remind me where you are on the HBP schedule in the wet gas window? Are there any like significant commitments over the next couple years?.

I'm sorry, you broke up there. I couldn't hear your question..

Sorry. I was asking if there are any significant HBP commitments over the next couple years outside of the dry gas window..

No, no. We have a minor drilling commitment on some of the new acreage that we acquired. It's 10 wells a year, but, no, we don't really have any issues there..

Okay. And I guess.....

You've got to remember that we're largely drilled up, so most of it's held..

Okay. And just a last one for me, just trying to get inside your head a little bit. You talked about this conceptual 50% growth of $600 million or so of spend running five rigs and then you know doing more maintenance, another $300 million, generating free cash, 25% growth. And both of these scenarios are talking about strip pricing.

So if we're in the same environment, what motivates you one way or the other? Because clearly you're growing fairly robustly in both scenarios. And you look at like the firm commitments that are coming online, it doesn't necessarily seem like there's a reason to necessarily go faster.

So how do we think about you guys reaching your decision points on that, philosophically?.

That's a good question. And I know 2016 is certainly on everyone's mind. And Aaron may want to jump in here, too, as well. When we're looking at level of activities that we think are appropriate, obviously we have to think about commodity prices, returns, liquidity, our hedge book, firm transportation.

But I think, what's interesting and I think unique for Gulfport, David, is that we pre-funded $300 million. So we really pre-fund the 2016 activity for our fourth and fifth rigs out there. So we're going to be very thoughtful and think about our balance sheet, making sure our balance sheet is in good shape.

We will not exceed our leverage ratio of 2.5 times. That's just something that we feel very strongly about. So we certainly, as we look at our activities, will consider that. If we do have an outspend, we want to make sure we can fund it with the money that we've already pre-funded.

But as we look towards 2016, obviously we have to think about what is – the reason we are going to delay giving you a final conclusion obviously is because we want to see some visibility of commodity prices. But I will tell you, David, that we only gave you the maintenance scenario just to tell you the strength of these assets out here of this rock.

It's pretty amazing that you can spend $300 million and you can actually grow your average production year-over-year. So we weren't necessarily trying to indicate that was the lower bookend of what we're thinking about, we were just giving you that to help you understand the strength of these assets..

Understood. Thanks for all the color. That's it for me..

This is Ty. I would add as well that we have strong, you've seen our core portfolio of the firm, I think we have good diversity there as well as strong connectivity. And so as we get into this market where we have projects coming on, those projects were committed to under a root assumption that was higher than we're seeing today.

So that's where we have additional growth. We'll be very active in that release market and make a home for that extra gas..

Thanks, Ty..

Your next question comes from the line of Jason Wangler from Wunderlich. Your line is open..

Hey, good morning, everyone. You made some comments about the AEU acquisition. I was just curious with the 18 gross, 11 net wells, just what the plans are with timing there. And just maybe if you have any comment on the type of wells that they drilled, are they similar to yours, different, just what you're seeing there..

Beginning of the year probably is when we'll start activity out there and you're talking about the uncompleted wells? Is that...?.

Yes, sorry..

Yeah, certainly they had a different process on their activities out there, but it's a relatively small number of wells. So we'll get those wells hooked up and see what they do..

Okay, great. I'll turn it back. Thank you..

Our next question comes from Leo Mariani from RBC Capital. Your line is open..

Hey guys, I was just hoping to get a little bit more color on your sort of your theoretical thoughts on 2016. If I heard you right, you guys were saying that you could run five rigs next year for $625 million to $675 million in capital.

Now looking at the 2015 program, I guess you guys are – $630 million to $690 million in capital for maybe three and half rigs. So I was just trying to kind of reconcile those numbers there; any help you have on that..

Well, certainly we're going to – go ahead, Aaron..

Yeah. Hey, Leo. I think what I'd say is, keep in mind we did start the year with the six rigs running in 2015. And we also had service cost improvements and efficiencies that we did not build into that CapEx number for Q1.

And so in Q2 we started to get the benefit of those efforts that Ross's team is working on and also just bringing the rig count down to three, so not quite apples to apples, year-over-year because of that. These are preliminary numbers and we'll follow up later this year with more fulsome thoughts on 2016. We're just pacing the numbers we run.

We feel like these are pretty good numbers that we gave you in Mike's prepared remarks..

And I think you have to remember, Leo, that we had an eight rig program running in 2014. So we had quite a few of those costs spill over into the first and even a little bit into the second quarter of 2015.

So it's a completely different capital structure for our 2015 activities and that's why you're going to see some apples and oranges CapEx comparisons..

Okay. Now that makes sense for sure. And I guess, so you guys are also saying that the $625 million to $675 million next year, well I know it's not set in stone.

That's more of just D&C and that's just operated, it wouldn't include any non-op that you may have had in the past through leasehold costs or anything like that?.

It is all D&C and obviously we can't – what happens on the non-op side is TBD but that's kind of based on current line of sight, we think that's a good number. But it is kind of an estimate of both operated and non-operated activities..

Okay. And I guess with respect to well costs, you guys have got I think different costs quoted in the different windows. You're showing your type curve assumptions $9.2 million, condensate $9.9 million, wet gas $10.2 million to $10.7 million.

Just trying to get a sense on those costs, are those kind of what's budgeted for 2015? Are those current well costs and just trying to get a sense of what current well costs are and if you guys think that you can continue to move those lower?.

That's a good question, Leo. I'm glad you asked. Those are current well costs, so that is what we anticipate right now for 2015. And really the only change that we made is we increased the cost of the dry gas window by about $35 a foot, so not as large an increase.

But we do have to deal with higher mud weights out there and higher pressures, so a little bit of extra cost and then also we have to set intermediate stream more consistently out there.

But I will tell you that we've not factored in, and Ross can comment on this as well, but we've not factored in any additional service cost reductions that we think we might be able to achieve and quite honestly, we are working on those right now. The vendors do seem to be receptive to that.

And then secondly, we are not factoring in any additional efficiency gains that we think we might be able to achieve, which as I think you recall, we were bringing them some bigger equipment to deal with the pressures that we have over here at the dry gas window and we think we can achieve additional efficiency there, but we haven't built anything in.

So hopefully we can maybe get those costs down a little bit but we'll just have to wait and see..

Again, that's helpful. And it sounds like you guys definitely want to continue to make acquisitions.

Are you still seeing stuff available out there to pick up in the Utica?.

Well, I would say right now we're very focused on the development of the acreage that we have. We have a large critical mass. We've given you the number of locations, which gives us a very nice inventory. It's in the core of the play. So we're not currently looking at any acquisitions. We're heads down working on development, putting units together.

Are there opportunities out there? Leasing on the ground is fairly nonexistent at this point. Most of those leases are gone. So you know what's left out there, you know the guys who own the acreage, so we're not necessarily aware of anything, but we're also not really looking. We are focused on our development plan..

Okay. Thanks, guys..

Thank you..

Our next question comes from Mike Kelly from Global Hunter Securities. Your line is open..

Hey, guys. Good morning..

Good morning..

I appreciate the bookends on 2016's growth and I was hoping Ty could do a similar exercise on gas differentials in 2016. You guys have guided to $0.52 and $0.58 off NYMEX for 2015. What could that potentially look like in 2016? Thanks..

Thanks. Mike. It's Ty. So I'd say that first of all the – we are not giving guidance right now for the differential for 2016 until we figure out a little bit more as to what we're going to weigh in those bookends. At the high end, I think we see 85% of that being sold through a premium price through the basin.

And then I think beyond that, we have opportunities like I talked about earlier to be active in the release market as well as the connectivity to the different new pipelines, and we'll be the first to be able to jump on and get deals done..

Okay.

Is there anything that stands out that's different in 2016 versus 2015?.

Let me – Yes, I was going to say, the other thing I'd say is, to give a little bit more color is to go to the slide deck to see if where our portfolio changes from 2015 to 2016. It ticks up a couple cents in 2016 and then it has a little bit more Gulf exposure in 2016 beyond.

So just because of the nature of that, I think gives you a flavor for what those differentials might look like and then like I said, the percentage in basin versus out will kind of give you a bookend..

The beauty – Mike, the beauty of our portfolio is our optionality. So as different pricing point change, we certainly have the option of moving our molecules around and that's a very big strategic advantage in our opinion to our firm transportation portfolio and makes us very unique.

For instance, as the Gulf Coast market demand continues to improve, we'll be able to move a lot of molecules down there. So we've got a lot of options and that's why it's difficult at this point to tell you specifically what the differentials are going to be. We're going to have to wait and evaluate what the best options for us are..

Understood, thanks. And just a quick one. What's the right number of days to model for you guys in terms of cycle times to spud to TD in the dry gas? Thanks..

24, 25 days is probably the right way to think about it here in the dry gas window..

All right. Appreciate it. Thank you..

Thanks, Mike..

Our next question comes from Dan Guffey from Stifel. Your line is open..

Hi guys. Thanks for the comprehensive update this morning. You contracted for FT [firm transportation] into early 2018.

I guess, how do you think about adding additional volumes in the out years and how do you mold that FT as you move forward?.

Hi. This is Ty again.

You know, as far as, I think I understand your question being, or are you meaning additional FT projects we've subscribed to?.

Correct, yeah adding additional commitments..

I think we continue to look at those, to look at where the demand is coming from, where the upside is. I think we're all looking at Mexico, we're all looking at LNG. We are all looking at the conversion from coal to gas. So when we look at those type scenarios and see where those – that demand is, we are looking at the FT that supports it.

And currently we've got to look at both ends. We've got to look at what producers have already subscribed to as well as what's in market to subscribe to, and make sure that's being fully taken advantage of before we go and try to subscribe or subscribe to another project, if that is the bottleneck is already happening.

And so we're constantly monitoring that with the results that we see, our peers are seeing as well as what the demand growth is having as well. So both ends become pretty critical to make sure that balance is happening and we are definitely, if that pans out, and we see the need, we will do additional FT..

It's an interesting market right now dynamic, because of course you have a lot of rigs that came down and you have producers who took out a lot of FT early on assuming they were going to have a certain level of activity and certain volume of production as a result of that activity.

Now, with folks cutting back on capital budgets and probably another swath here going forward, there's lots of FT available in the release market. And we are certainly well positioned to take advantage of that. Ty is looking at that.

But we want to make sure what we find is additive to our portfolio and gets us to the right places and gives us the right options. These are twenty-year financial commitments. So we've got a great FT portfolio that allows us to grow next year with 90% of our product being sold in premium pricing points.

And as we move forward, we'll continue to layer on the incremental projects that are additive to us..

Okay. Thanks. And then switching gears, looking at completion styles, they still vary widely in the dry window between different operators.

I guess can you discuss your current standard design in terms of stage spacing, sand, liquid volumes, et cetera? And then anything you guys are currently testing to improve recoveries?.

Well, it's interesting. You're right. There still is quite a variance among producers out here. We continue to like the recipe that we have. We're still generally at 180-foot stage spacing and we generally still pump 1,500 pounds to 1,800 pounds per 1,000 lateral foot of proppant. And we think stage spacing is maybe more important even than sand.

So while our completion folks continue to test different ideas, generally, we really like the recipe we have, we like the results that we've had. And, right now, we're not really making any wholesale changes. Certainly there's a big bang for our buck here when you're considering cost EURs and stage spacing. And so it's a cost-benefit analysis.

So we'll have to see. But, generally, again, lateral spacing is important and we're excited about the opportunity to move these wells closer together. We do know that longer laterals are very important to results. So we'll continue to try to drill the longest laterals possible. But I'm giving you a long-winded answer.

The short answer is we like the recipe that we have, and we're not making any wholesale global changes at this point..

I guess just a quick follow up, if I could. You mentioned the longest laterals possible, you'll drill your type curves at 8,000 feet.

I guess what is your capacity to go longer? On what percentage of your acreage are you able to drill those longer laterals?.

That's a good question. I don't know that off the top of my head. They're still working on putting units together. On some of our acreage, they don't have all of those forms yet.

From a technical limits perspective, I think we view when you get into 10,000-foot to 12,000-foot range, you begin to have challenges from a coil tubing perspective, from just getting your frac put away that far. So you can get up to there pretty efficiently and anything below there is fairly easy and we're very efficient at it.

We've done some very long laterals, but I don't have the longest laterals that we have available to us right now in front of me..

Great. Thanks for all the details and congrats on a good quarter..

Thank you..

Thank you. Our next question comes from the line of Jeff Grampp from Northland Capital. Your line is open..

Morning, guys..

Jeff..

And great job on all the additional color on the slide deck and 2016 and everything. I guess one of the things that I was interested in my getting some more color on as we look across your different dry gas areas on a rate of return basis, it looks like the east area's the strongest. But not a lot of planned activity there in 2015.

So just wondering, is that infrastructure related, is that because you guys just want to methodically move out there? Or just curious on how the eastern area gets integrated into development over the next couple years..

That's acreage that we just picked up. And those acquisitions we haven't even closed on the stuff that's the furthest east, the Paloma acreage. So we'll start working on that. It's going to be a while. Ty's working on the infrastructure piece out there, as we mentioned I think on our last call, related to Paloma.

So we're certainly moving full-steam ahead on getting everything that we need in place to get that developed. Midstream, that I mentioned that Ty's working on, is in the LOI phase right now. So we're right on schedule with the infrastructure piece of that project.

And as we mentioned, we're tentatively bringing in – we brought the fourth rig in, started drilling on some of that acreage. And then we had previously announced we'd be bringing a fifth rig in also to help us with that.

And of course we'll wait and see what we decide to do for 2016, but we're certainly incorporating that acreage in as quickly as possible into our development plans, but it takes a while to get those units put together and start that development. But we're on track..

Okay. That's helpful. And then just looking at the updated condensate type curves. And given the returns that you guys can get in the wet gas and dry gas areas, just wondering how that fits into the story longer term. It looks like it may be struggling to compete for capital with your other areas.

And obviously you don't need the extra liquidity like you guys laid out with your position now.

But does that become a divestiture candidate if there's some interesting acquisition opportunities elsewhere, or how do you see that area fitting into the story?.

Look, under today's commodities prices, certainly the returns in the condensate window aren't really there for us. We've been pretty open about that. We view it more as optionality. It's not a great deal of locations. If you look on that slide, it's about 260 locations out of our total. We'll have to wait and see.

I can't say today what exactly what we're going to do with it. We did like the condensate window, but we certainly need a better commodity price for it to make sense for us. So, we'll have to wait and see. We've got some time on those leases. They're not expiring right away, so we'll wait and see what the options might be for us..

Okay. Great color and great results, guys..

Thank you..

Thank you. Due to time, our last question will be from Dave Kistler from Simmons & Company. Your line is open..

Good morning, guys..

Hey, Dave..

One just last question respective to the midstream and processing agreements that you established early on that I believe cover the development in the wet gas and the condensate windows.

Can you talk a little bit about utilization there? Is there any overhang of costs? Are there any kind of commitments you need to deliver on? And this kind of comes part and parcel with a more focused activity in the dry gas window..

This is Ty, because we're an early on anchor, we don't have overhang commitments. We do have a set up to make sure that we're getting the best value for the product that's coming out. So but, no, we have flexibility as we go forward across those phase windows..

And then one thing I might add just to remind everyone, we were an early mover in this play and we were the original partner for MarkWest in their build out of the Utica. So we were an anchor tenant, we got anchor tenant status, which gives us a different kind of relationship with MarkWest than some other folks have.

So, we have an acreage dedication and we don't have a volume commitment. So, again, from a cost perspective, we're strategically advantaged..

That's great news.

And then to the extent that you do have an acreage dedication there, is that something you could remarket in a different time for people who don't have the luxury of being in the dry gas window?.

No, that's not. I would say that's – I don't want to get into details of how that would all work, but as far as someone else coming through there and the – it would be available to someone else, I guess. Trying to understand your question..

Well, I was more thinking about it in terms of the flexibility it provides. It's great news that there's no overhang there. But I was just curious if there could be upside optionality or benefit from that over a longer term basis..

Yeah, no, I wouldn't say – there's, no..

Okay. Really appreciate it. A great work on the quarter guys and fantastic results on the dry gas window..

Thanks, Dave..

Ladies and gentlemen, we have unfortunately run of time today. At this time, I would like to turn the call back over to Mr. Mike Moore for any closing remarks..

Thank you, Amanda. We appreciate your time and interest today, as we know this is a very 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..

Ladies and gentlemen, thank you for participating in today's conference..