Nov 5, 2013
Executives
Paul K. Heerwagen - Director of Investor Relations James D.
Palm - Chief Executive Officer and Director Michael G. Moore - President and Chief Financial Officer
Analysts
Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division Timothy Rezvan - Sterne Agee & Leach Inc., Research Division Joseph B. Stewart - Goldman Sachs Group Inc., Research Division Jason A.
Wangler - Wunderlich Securities Inc., Research Division Biju Z. Perincheril - Jefferies LLC, Research Division Will Green - Stephens Inc., Research Division Ronald E.
Mills - Johnson Rice & Company, L.L.C., Research Division Gordon Douthat - Wells Fargo Securities, LLC, Research Division Cameron Horwitz - U.S. Capital Advisors LLC, Research Division Brian T.
Velie - Capital One Securities, Inc., Research Division Ipsit Mohanty - Canaccord Genuity, Research Division Leo P. Mariani - RBC Capital Markets, LLC, Research Division Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division David E.
Beard - Iberia Capital Partners, Research Division
Operator
Good day, ladies and gentlemen, and welcome to the Gulfport Energy Corporation Q3 2013 Earnings Conference Call. [Operator Instructions] As a reminder, this conference call is being recorded.
I would now like to introduce your host for today's Mr. Paul Heerwagen.
Sir, you may begin the conference.
Paul K. Heerwagen
Thank you, Nova, and good afternoon. Welcome to Gulfport Energy Corporation's Third Quarter 2013 Earnings Conference Call.
I'm Paul Heerwagen, and with me today are Jim Palm, Chief Executive Officer; Michael Moore, Chief Financial Officer; Stuart Maier, Vice President of Geosciences; and Steve Baldwin, Vice President of Reservoir Engineering. During this conference call, participants may make certain forward-looking statements relating to the companies financial condition, results of operations, plans, objectives, future performance and business.
We caution you that 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 to our website.
An updated Gulfport presentation was posted this afternoon to our website in conjunction with this earnings announcement. Please review at leisure.
At this time, I'd like to turn the call over to Jim Palm.
James D. Palm
Thanks, Paul, and thank you, all, for joining us for our call. During the third quarter, Gulfport generated approximately $51.6 million of operating cash flow, $97.4 million of EBITDA and $11.1 million of adjusted net income on production totaling 1,193,808 barrels of oil equivalent.
In the year to date we continue to make outstanding wells. Let's take a moment to reflect in the past 10 months and the growth Gulfport has experienced since the beginning of 2013.
We entered 2013 with 2 rigs, developing our 106,000 net acres, and have since added 5 additional rigs. Today, drilling with 7 rigs and having increased our acreage to 147,350 net acres.
We exited 2012 with approximately 6,600 barrels of oil equivalent per day of production, and last month, Gulfport averaged approximately 15,500 barrels of oil equivalent per day, a 135% growth. In addition, we anticipate we will exit 2013 producing 27,000 to 32,000 barrels of oil equivalent per day, over a 300% increase from where we started in January.
As you can see, we are experiencing significant growth as a company and continue to add employees to our talented experienced team to support and lead the company in the development of this play. As we continue to bring more wells online and see sustained production, we are learning and developing an understanding of how to best complete and produce wells in each of the fluid phases.
Today, we brought online 7 wells in the wet gas phase of the play. As a can see from our presentation posted this afternoon, the wells continued to perform within the type curve.
We're pleased with performance of the wells to date, and it's obvious that wedge gas wells in the Utica generate some of the best economics of any onshore North American shale play at today's commodity prices. We've learned a lot about our wells in the condensate phase of the play as well, bringing 22 condensate wells online to date.
As you can see from the slide in the presentation, the actual production is trending in line with our type curves and performing to our expectations. We continue to analyze the production data and work towards optimizing our drilling and completion techniques.
We started in 2012 drilling one well on a pad, and using a hybrid frac, which incorporated linear and cross-link gels. We've altered our recipe, switching to primarily slick-water fracs.
The initial productions from the wells that have been brought online recently indicate that we are benefiting from eliminating the expensive cross-link gels and making better wells. In addition, we are seeing better results by serving our gas early with choke and pressure management.
By deferring some of the early higher rate oil production, we're seeing a flattening in our oil decline curves, which will allow us to realize most value from the well. We're in the early times of production from these wells, but we're pleased with their performance to date.
In the gas phase of the play, we are pleased to announce the Gulfport recently brought online, our Irons 1-4H well, which was drilled to a full vertical depth of 9,770 feet with the a 6,629-foot horizontal lateral. The Irons well is the furthest East well Gulfport has drilled to date, and we are impressed with the strength of this well.
The well produced, at an average, 24-hour sales rate of 30.3 million cubic feet of gas per day. I should note that the lateral on this well is shorter than many of the wells we have drilled in the play, and as you can see, this is a very strong well.
We estimate approximately 44% of our acreage lies within this phase of the play. And our Irons well marks a critical data point in the development and derisking of the dry phase of the play.
Gulfport has been running an active leasing program focused on blocking up our acreage to best develop our position. With this in mind, we recently entered into a development agreement with Rice Energy, covering 4 townships in Belmont County, Washington, Wayne, Smith and Goshen.
This agreement is structured so that Gulfport acts the operator in the southern 2 townships and Rice is named the operator in the northern 2 townships. Combining Gulfport and Rice's position, we together own a vast majority of the acreage available on this area, allowing both parties to optimally drill and complete the wells.
We will have access to more resource as we are able to drill longer laterals and both operators will benefit from the ability to accelerate the development by joining forces. Rice's occupational and technical staff have a great reputation, and we look forward to benefiting from coordinated efforts and the shared learning in the development of our joint position.
We continue to work towards the determining the utmost spacing regime in the play. In the wet gas phase of the play, we are currently drilling on our Darla pad, which will test spacing between 300 and 1,200 feet.
The wells are scheduled to begin frac-ing by the end of this year, and begin the flowback process in early 2014. In the condensate window, at our Boy Scout pad, we continue to see strong results from the core producing wells, with no signs of interference during production, to date.
As a reminder, we drilled the 2 new wells 600 feet and 800 feet from the 2 original producers. We are not only benefiting from our own internal analysis but also learning from other operators.
Enterra recently had success on its Wayne pad, drilling 3 wells at 500-foot spacing. And in the dry gas phase of the play, we are participating with Rice in a downspacing pilot where they plan to test 500-foot spacing.
As we collect and analyze more data internally and as we learn of our peer's results, we continue to believe the utmost spacing regime in the play will be less than the current statutory 1,000-foot spacing. During the third quarter, we spud 14 gross wells on our acreage.
We currently have 7 rigs in the play, drilling ahead on the 39th through 45th wells of our 2013 program. Looking ahead towards our development plans in the Utica, during 2014, we plan to continue running a minimum of 7 rigs in the play.
At this time, we plan to concentrate 4 rigs in the wet gas phase of the play, 1 rig in the condensate phase of the play and 2 rigs in the dry gas space of the play. Assuming a 7-rig program in 2014, we budgeted to drill approximately 85 to 95 gross wells, which equates to 64 to 71 net wells in the play.
On the midstream and marketing front, Gulfport and MarkWest are working closely as we build out our drilling plans in 2014 and beyond. We believe Gulfport is vastly better positioned going into 2014, from an infrastructure standpoint, from where we sat a year ago.
Today, MarkWest wet gas system has the capability to process nearly 400 million cubic feet per day of gas, growing to 1 Bcf per day, processing by mid-2014. As we begin to focus more of our drilling on the dry gas side of the play, permits, right away and long lead items related to the construction of the dry gas system have already begun.
We are working with MarkWest to ensure that we have a coordinated approach to drilling activity and pipeline availability. Relating to marketing, Gulfport continues to take out firm transportation and secure the movement of our product out of the basin.
We recently executed a 10-year firm transportation agreement for up to 100,000 decatherms of residue gas, with an option to increase to just under 200,000 decatherms per day on the ANR pipeline, to secure access to premium Midwest markets in Wisconsin, Illinois, Indiana and Michigan. As our volumes grow in the play, we are focused on securing product takeaway while maintaining price diversity.
Between Texas Eastern, Rockies Express reversal various ANR projects and Dominion West, we estimate we'll be almost 1 Bcf of pipeline capacity to move gas west out of the Utica in 2014, growing to just over 2 Bcf in 2015. We are participating in various open seasons, and while we are experiencing substantial growth, Gulfport expects to have firm transportation agreements in place for 100% of our production volume.
Gulfport is partnering to cover approximately 70% of our anticipated long-term production with firm transport agreements, while executing short long-term sales agreements for the remaining volume. Gulfport's pleased to announce the execution of an ethane supply contract with Shell Chemical in connection with the proposed ethane crack in Western Pennsylvania that is currently under evaluation.
Although the terms and conditions of the agreement are confidential, we believe that the terms of our deal provide Gulfport with a high graded solution for ethane settlement. We are excited about continuing to support local projects that would add to the region's jobs development and would increase the infrastructure needed to support the industry as a whole.
Mike Moore will cover this in more detail, but Gulfport has also been active in securing the price realized for our product, locking in $4 fixed price swaps for approximately 50 million cubic feet of gas per day starting January 2014 through April 2016. And now let's move to our other asset areas, starting in Canada.
Grizzly has completed essentially all the construction required for start up and currently expects first steam this month and first production in the first quarter of 2014, and its first SAGD facility in Aligarh Lake. Grizzly remains on track to file an initial 12,000-barrel per day development application at May River by the end of 2014.
And now on to Southern Louisiana. At Hackberry, during the third quarter, we drilled a total of 3 wells, completing 1 well as productive, with one well waiting on completion and one well drilling at the end of the quarter.
We are currently running 1 rig at Hackberry, drilling ahead on the 15th well of 2013. Looking ahead to 2014, we initially plan to drill 10 to 12 wells at-field.
Meanwhile, at West Cote Blanche Bay, during the third quarter, we drilled a total of 7 wells completing 5 as producers, with 2 waiting on completion at the end of the quarter. At present, the Barge rig is active at West Cote, drilling ahead on the 18th well of our 2013 program.
For 2014, we budgeted to drill 22 to 24 wells at West Cote. To wrap things up, we look forward to continued growth and increased activity in 2014.
From a gathering and processing perspective, infrastructure is largely in place, allowing us to have the flexibility to ramp up as we enter 2014. We've begun locking in firm transportation for our product and will continue to be active in the open seasons as we bring more production online.
Early on, we invested in services with the activity of surrounding operators heating up and the rig count in the Utica expected to increase dramatically in 2014, we believe securing quality services at fair market prices will pay significant dividends. We believe we have the infrastructure, services and skilled team to achieve our 2014 goals.
Thank you for your time and interest today, and now I'd like to turn the call over to Mike to cover our financial highlights.
Michael G. Moore
Thanks, Jim, and good afternoon to each of you. During the third quarter of 2013, Gulfport generated approximately $97.4 million of EBITDA, $51.6 million of operating cash flow and $40.5 million of net income.
Our third quarter net income also includes a loss from hedge ineffectiveness of $6.7 million and a gain of $52.9 million in connection with our equity interest in Diamondback Energy. Adjusted net comparable to analyst estimates, a non-GAAP measure, was $11.1 million or $0.14 per diluted share.
During the third quarter, production totaled 1,193,808 barrels of oil equivalent or 12,976 BOEs per day, which was up 45% on a unit basis, quarter-over-quarter, compared to the second quarter of 2013. Allocated by field, third quarter production breaks out to be 7,199 BOEs per day from Utica; 3,817 BOEs per day from West Cote; 1,821 BOEs per day from Hackberry; and 139 BOEs per day from Niobrara overrides and other miscellaneous areas.
Our production mix for the third quarter was 58% oil and natural gas liquids and 42% natural gas. Subsequent to the third quarter, October production averaged approximately 15,543 BOEs per day.
Moving along to the income statement, excluding the loss from hedge ineffectiveness, revenues for oil, natural gas and natural gas liquids in the third quarter totaled $75.5 million. Average realized prices for the quarter, excluding the loss from hedge ineffectiveness, were $108.88 per barrel of oil, $3.51 per MCF of natural gas and $1.14 per barrel of natural gas liquids.
Our Bennett price for the third quarter was $66.86 per barrel of oil equivalent. Lease operating expenses during the third quarter was $7.3 million or $6.11 per BOE, down 40% on a unit basis from the third quarter of 2012.
General and administrative expense for the third quarter was $5.3 million or 4.41 per BOE, down 7% on a unit basis from the third quarter of 2012. Depreciation, depletion and amortization expenses during the third quarter totaled $30.7 million or $25.71 per BOE, down 34% on a unit basis from the third quarter of 2012.
In terms of capital expenditure, during the third quarter, we spent a total of $117.6 million on 2013 activities, which excludes Gulfport's portion of Grizzly activity and Utica leases. Moving on to the balance sheet, in connection with our fall redetermination, our lead lender has proposed to increase our borrowing base from $50 million to $150 million, subject to the approval of the additional banks within the syndicate.
As of the end of third quarter, we had $95.5 million in cash and were undrawn on our revolving credit facility. At present, for the remainder of 2013, we have fixed price swaps in place for 5,000 barrels per day at well, at a weighted average price of $99.86 and 10 MCF of gas per day at a weighted average price of $4.
Gulfport has begun solidifying its hedging program for the coming years, locking in fixed price swaps for 2014, 2,500 barrels of oil per day and a weighted average price of $102.79. Additionally, Gulfport has fixed price swaps for 2014 through April 2016 on an average of 50,000 MCF of gas per day at a weighted average price of $4.09.
Historically Gulfport has been anywhere 40% to 70% hedged. In the wet gas, dry gas phases of Utica, Gulfport finds the returns very attractive in today's commodity price environment.
We are actively hedging gas at the $4 level and plan to continue to look for additional hedging opportunities to secure our fixed cap obligations in connection with our 2014 planned activities. Moving on to guidance, we anticipate fourth quarter production to be approximately 20,000 BOEs per day.
In addition, we currently estimate to exit 2013 producing in the range of 27,000 to 32,000 BOEs per day. Looking ahead to 2014, we estimate full year production to be in a range of 50,000 to 60,000 BOEs per day, and anticipate that to be approximately 30% to 50% liquids split evenly between oil and NGLs with the rest natural gas.
During 2014, we estimate $675 million to $725 million of capital expenditures associated with our drilling plan, with approximately 87% of that allocated to our Utica Shale activity. In addition, Gulfport has been running an active leasing program focused on blocking up the current position, and we plan to continue these efforts in 2014.
We have budgeted to spend $225 million to $275 million on leasehold acquisition in the Utica. For 2014, we estimate full year unit LOE to be in the range of $2 to $3 per BOE.
Full year unit, transportation processing and marketing to be in a range of $2.50 and $3.50 per BOE: full year production tax to be in the range of 4%, 6% of our expected revenues; and full year unit G&A to be in the range of $1 to $2 per BOE; and finally, we estimate our DD&A rate to be in the range of $21 to $24 per BOE. Thank you for your time and interest today, and we look forward to answering your questions.
Operator
[Operator Instructions] Our first question comes from the line of Neal Dingmann of SunTrust.
Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division
Say, Jim, I was wondering, what can you tell us -- maybe more color around the Irons, as far as how much you can say around like choke size or the pressure that is associated with it or such as the shut-in tubing pressure, those things that you could color around that well.
James D. Palm
Neal, It is really a strong well. We're are really pleased with it.
We started off with about 6,900 pounds shut-in pressure on it. The last 24 hours that we were looking at it, we were throwing well over -- we're over 30 million a day, we're going about 3,200-psi.
We probably will produce it long term, someplace from 15 million to 20 million a day. We think we'll be up in the 5,000 pound flowing pressure in that, and that's kind of the basics on it.
Looks really strong particularly considering that it's not that long a lateral.
Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division
Got it. And then just one, my one follow-up.
Just wondering on the type curves on this new slides that are out. Notice on there now, you've got a couple of -- just in detail, where you talked about sort of normalized trade, lateral length at 8,000.
I'm wondering, around that, Jim, is that kind of now what your typical lateral is and how does that impact how this would trend on the line a little bit?
James D. Palm
Well, that -- gosh, we've even got some laterals planned that are over 10,000 feet. But it depends on where you're drilling and how the leasehold comes together.
The point is that you've got to pick a length. We started out on the Wagner with an 8,000-foot lateral with Von Gonten, so we just decided to go ahead and use that.
You really do have to normalize them, we are seeing that there's a direct proportion between the length of the well and what it's going to produce, whether it's a gas well or whether it's a condensate well. So various people may pick other distances, that's what we chose.
Operator
Our next question comes from Tim Rezvan of Stern Agee.
Timothy Rezvan - Sterne Agee & Leach Inc., Research Division
A couple of questions on the dry gas window. Obviously, focus has turned there, with the strong dwell result, and I guess 2 rigs you're going to be running.
Are those rigs operating there now? And, I guess, my follow-up is on -- what gives you comfort that you're going to avoid the midstream delays that you had last year?
James D. Palm
Well, you just have to pick and choose early. Like this particular location we chose because we had a Dominion location -- or pipeline nearby.
So we're going to Dominion instead of MarkWest on this one. So we kind of followed the pipelines early on.
Also, as we start drilling further to the east, MarkWest starting out down South and down there, we've got Texas Eastern transmission and other pipelines. And so we're kind of starting on the South end and moving north.
That allows them to bring their infrastructure along with our drilling schedule for 2014. So you just have to work closely with what you got to work with.
But there are existing pipelines in place that helps us get started there.
Unknown Executive
And, Tim, just to add, we are working closely with MarkWest to ensure coordinated approach with our joint activities and pipeline availability and as Jim mentioned, we do overlap major pipelines, the Rockies Express and Texas Eastern. The permit right aways and long lead materials needed for the construction are already in place or in process.
So we feel like we're well ahead of the curve at this point.
Timothy Rezvan - Sterne Agee & Leach Inc., Research Division
Okay, thanks. And then a quick follow-up on 2014 guidance.
What kind of risking did you put in there? Do you think that gives you confidence that you can either meet or exceed those numbers?
Michael G. Moore
Yes, that's a good question. We certainly did risk it quite a bit as we are looking at it, Tim.
We've got people, infrastructure takeaway and services. So 2014 is certainly a different year than 2013.
We're further ahead on the learning curve. We're in a better position on infrastructure and continue to secure firm takeaway and work with MarkWest.
But we have put quite a bit of different risking factors into our model when we were looking at providing those estimates this year. So we hope and expect that we'll do a much better job this year of meeting those expectations.
James D. Palm
One thing that when you go into a new play, one of the big risk when you first get in there is, is it going to produce? And that's one of the things that's been really different about this play.
The first well we had, the Wagner, when we saw the sudden pressures up around 5,300 pounds on that, we had a 12.5- to 13-pound mud weight equivalent. Even over on the West side, we've got good pressures there.
We've got really nice pressures with 6,900 pounds at the surface. So that is one thing that's different about it.
I think we're finding that virtually all the parts of our acreage are good, and it's a question -- last year we had a lot of infrastructure questions, but those are getting resolved this year. So the infrastructure is much less of a risk than it was last year.
We and MarkWest have both learned a lot of things, and so things are coming together well. So we're looking forward to 2014.
Operator
Our next question comes from the line of Joseph Stewart of Goldman Sachs.
Joseph B. Stewart - Goldman Sachs Group Inc., Research Division
Looking at your 2014 guidance, I know that you expect to drill 64 to 71 net wells. But how many Utica wells are you assuming that you tie into sales on that forecast?
Michael G. Moore
Well, that's a good question. I would say, off the top of my head, that we're looking at probably 50, 55 wells.
James D. Palm
Yes, usually what happens, if you got 7 rigs running, and of course you're on pads or drilling maybe 3 at a time on the pad, more or less, it works out that whatever you drill in that last 3 months are probably not going to get on. That's about 21 wells.
So those last 21 of the year, on average, won't be on. That ties with what Mike had to say.
Michael G. Moore
It's going to depend, of course, where we would end up with the resting period ideas. So that will be a little bit influx this year.
But we're certainly getting closer to having those answers.
Joseph B. Stewart - Goldman Sachs Group Inc., Research Division
And Mike, what about the wells that were -- that are kind of waiting to be tied in from '13. I was expecting to be able to tie more of those in '14 as well.
Michael G. Moore
Right, if you're talking about the wells that will carry over from December 2013 into January 2014, it does appear we're on target for those wells. If that's your question.
Joseph B. Stewart - Goldman Sachs Group Inc., Research Division
Yes. So, I guess, like how many total net wells would you expect to tie in, that would impact '14 production?
Michael G. Moore
Now that's 10 gross wells and the net is maybe 75%.
Operator
Our next question comes from the line of Jason Wangler of Wunderlich Securities.
Jason A. Wangler - Wunderlich Securities Inc., Research Division
Just [indiscernible] it's kind of been pretty good on the Utica, so I think I'm pretty good there. Just curious with the oil sands, just the kind of continued kind of delays.
What you're seeing there, and then maybe if there's any other color about around the filing of the other application.
James D. Palm
Yes, I think I said '14. That's going to be filed in '13 at the end of this year, for the next application.
But with regard to the plant that's being built now, they actually have steam going into the ground by the end of this month. And sometime, 3 months or so later, we should start getting the first oil out.
So, as far as when we'll do something with it, with regard to the capital event and so forth, I think it's nice to have the production coming on. As we get more production, we're going to start derisking the play.
When we do something, depends on what the capital markets are doing and so forth, but we're optimistic about the way things are going up there. They pretty well got things behind them and moving to getting that steam going on the ground with first oil coming out.
Operator
Our next question comes from line of Biju Perincheril of Jefferies.
Biju Z. Perincheril - Jefferies LLC, Research Division
So looking at your CapEx for next year, looks like there is some cost savings that's factored in. Can you talk a little bit about where costs are currently?
I think you talked about $9.5 million. And what are some of the drivers, maybe, to bring that down?
James D. Palm
Sure, Biju. Some of the things -- we've discovered that there is a large part of our acreage where we can leave out the intermediate string of 9 7/8 that we were setting about 7,000-plus feet deep.
When we can leave that out, we can set that 9 5/8 string back at about 2,000 feet. So that saves a lot of drilling time.
That saves us $1 million per well. So that's a big driver.
The other thing is that we've found that we make better wells without the cross-linked polymers in there. Von Gonten has seen evidence of the same things.
So, by leaving that out, we were going from what might be a $125,000 cost to own a frac stage to $100,000. And we're sometimes drilling well over -- or having well over 30 stages of fracs.
So you're starting multiplying 30 stages times $25,000 a stage, and it makes a big difference. So we're seeing some of those kind of things come along too.
Also, with pad drilling, of course, as you drill more wells off the pad, you get to spread that location cost around. And, Mike, anything you want to add to that?
Michael G. Moore
Yes. We are, Biju, getting more efficient at drilling.
So I think the important thing is that, as we move forward, we keep cutting down the number of days it takes us to drill a frac complete well. So obviously, that's going to help us save money.
We're assuming, for modeling purposes, $9 million to $9.5 million well cost next year. And keep in mind that we're talking about, generally, an average of a 75% working interest next year as we look to put together acreage with other operators and drill the longest laterals we possibly can.
Biju Z. Perincheril - Jefferies LLC, Research Division
And then my follow-up is -- I don't know if you mentioned the 2014 exit rate.
Michael G. Moore
Yes, I don't think we're going to start talking about that yet, Biju, so I did not mention that.
Operator
Our next question comes from the line of Will Green of Stephen's.
Will Green - Stephens Inc., Research Division
I wonder if you guys could break down the 64 to 71 wells? Can you guys talk about how that looks per phase?
Or is there an easy way to do that?
Michael G. Moore
Yes, I think there is. I mean, I think we've talked about where our rigs are going to be allocated.
So, 4 rigs will be in the wet gas window, 2 rigs over in the dry gas window, with 1 rig in the condensate window. So that makes it easy for you to do the math.
Will Green - Stephens Inc., Research Division
Got you. And then the $250 million in leasehold expense for next year.
I'm not sure if I heard what you guys were planning there, but is that just grassroots kind of leasing efforts in the Utica? Is that what that's budgeted for?
James D. Palm
Yes, there's a lot as we bring our units together. But on the last 2 quarters, we have been averaging about 10,000 acres per quarter.
And so if you take that for the full year and start putting the type of prices we're seeing today, that pretty well gets you to the number we're talking about.
Michael G. Moore
So, generally, we're talking about filling acreage, Will, but for competitive reasons, we can't be more specific than that at this time.
Operator
Our next question comes from the line of Ron Mills of Johnson Rice.
Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division
You guys mentioned the production mix. Mike, in your guidance, in terms of -- it sounds like 50% to 70% gas with the remainder being split evenly between the condensate and the NGLs.
As you look through the full year and kind of the production build that goes through, is it something that continues to get more gassy as we look through the year or how should we think about the production mix transitioning through the years as you grow those production volumes?
Michael G. Moore
Yes, Ron, I think that's exactly how you should probably look at it. You will see a continued, I think, build during the year, as to get to a more gassy nature at the end of the year.
James D. Palm
Wells are really strong on the East side, it looks like.
Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division
For sure. And then you mentioned the hedges that you've put in place on the gas side, the $4.
Presumably, this is all to handle the Utica gas. Is this $4, is a Henry Hub, is it local index price?
If it's Henry Hub, is there any way to protect bases or how do you think about it from a marketing of the gas standpoint? I understand the $4 price point, but how will that potentially translate into pricing given what we've seen recently in differentials widening in parts of the country?
Michael G. Moore
Yes, it's certainly Henry Hub. We do have the option to lock in our bases as well.
But it's as firm as taken. As we take firm, we will hedge bases.
So you've seen us already begin to take some firm out. You'll see us begin to layer in bases as we go through the year.
Operator
Our next question comes from the line of Gordon Douthat of Wells Fargo.
Gordon Douthat - Wells Fargo Securities, LLC, Research Division
A question on the joint operating agreement with Rice Energy. Just curious how this came to be and was wondering if any acreage or financial consideration change hands in this transaction.
James D. Palm
No, not really. They had more acreage on the North half, we have more acreage on the South half.
We could all go out there and work separately, but it's more efficient to get together and just -- we concentrate our efforts south, they do it North. So it just works out just fine like that.
We have some other things that we're not talking about now, some other projects we've got. We're going to make it more efficient for us to frac our wells and so forth.
And so there's a lot that we're doing out there. But this makes both companies more efficient when we got the development agreement going.
Michael G. Moore
And keep in mind, while this is a formal agreement, we do have CAs with virtually every operator in the Utica. And so we are working with our peers to put together blocks of acreage, as I mentioned earlier, so that we can drill longer laterals.
So, effectively, we're doing this with other operators. And you probably have heard other operator talk in the last couple of days about these same scenarios.
So this is something you'll probably see more and more of out there.
Gordon Douthat - Wells Fargo Securities, LLC, Research Division
Okay, makes sense. And last question, on ethane rejection.
How do you view that in 2014 and do you foresee a point where you'll have to process some just to meet pipeline specs? What's your outlook there?
Michael G. Moore
Well, ethane's certainly going to continue to be rejected in 2014, and there probably will be a point where you have to do some minimum ethane recovery.
Operator
Our next question comes from the line of Cameron Horwitz of U.S. Capital Advisors.
Cameron Horwitz - U.S. Capital Advisors LLC, Research Division
I was hoping you could update us on the Wagner well, just given it's your longest producing well in the play and just hoping you could tell us kind of where current production is on that well.
James D. Palm
Right now, we've got it shut-in, what we've been producing some of the wells around. They've been frac-ing some of the wells around it and we're also going to be drilling a Wagner 4 well nearby.
So we haven't got anything real new for you on that one.
Cameron Horwitz - U.S. Capital Advisors LLC, Research Division
Okay, and can you address just current realizations you all are seeing there? And I guess also maybe talk about the NGL side as well, the step-down quarter-over-quarter in realizations.
I guess, that being a function of more of the cuts you're seeing out of the plant and softening in demand. Or how are you viewing that?
Michael G. Moore
Yes, condensate basically is currently WTI less 10. And then NGLs for this quarter, we saw them at 45% of WTI.
Operator
Our next question comes from the line of Brian Velie of Capital One Securities.
Brian T. Velie - Capital One Securities, Inc., Research Division
A couple of quick questions. The Irons well, can you comment as to how much of that well costs and your expectations for prices there on the dry gas window side?
James D. Palm
Well, we haven't got all our costs in on it yet, but those wells -- I think you probably saw some internal numbers of $10.5 billion for wells over on the East side. I think that this one is a little deeper than that, it's going to be more expensive.
But it's too early to tell exactly what they're going to be. We had some other things.
When you get over East like that and you got you're new well, you're doing pilot holes and coming back up and drilling your laterals. And so I think it's going to be on the high-side, obviously, the average for next year.
But very economic with the kind of rates that we're getting out of them.
Brian T. Velie - Capital One Securities, Inc., Research Division
Sure, and then just one follow-up there on -- as we kind of model out the dry gas play, obviously, it's super early to be making too many assumptions, but for kind of a placeholder, would you use maybe what we have in the wet gas window for an EUR expectation? Something in that range?
James D. Palm
Well it's really too early to tell about the East side. We're going to have to get some history before we know for sure, but we sure like the way it started off.
But you just got to have some history before you can start talking to EURs.
Operator
Our next question comes from the line of Ipsit Mohanty of Canaccord.
Ipsit Mohanty - Canaccord Genuity, Research Division
Real quickly just see the production taxes kind of trending down and going forward in '14. Is that more of Utica?
Is that more of Ohio state contribution or anything like that?
Michael G. Moore
Yes, it's absolutely directly related to the increase in the Utica production in our volumes.
Ipsit Mohanty - Canaccord Genuity, Research Division
And my second question is just on leasing, but not exactly. I know you're differing from that.
But with the joint development efforts, is it fair to say that you're probably going to quote up more of the dry gas window?
Michael G. Moore
Well, it's certainly fair to say that we have an appetite for the dry gas window. The Irons well is a phenomenal well.
And so we're really excited about the dry gas window. We think it's going to have really good returns.
We have thought that for some time now. The Irons well is confirming that for us.
So certainly we have a large appetite for...
James D. Palm
Hell, that's why we put 2 rigs over there, next year, and of course depending on results, we'll see what happens. But we like what we see.
Operator
Our next question comes from the line of Leo Mariani from RBC.
Leo P. Mariani - RBC Capital Markets, LLC, Research Division
Just wanted to follow up on a previous question regarding NGL pricing here. Mike, talked about 45% of WTI this quarter.
I guess that price has sort of been degrading on you guys for several quarters here. Any insight into kind of why that's been dropping relative to WTI, is it all kind of local market conditions in the summer?
And where do this expect that, going forward, as we head into 2014?
Michael G. Moore
Yes, that's exactly right, Leo. It's seasonal, and as you know, for the first 2 quarters, we actually saw 55% to 60% of WTI for our pricing.
So there is some seasonality. But we are getting a full cryo [ph] recovery, which allows us to get an deeper cut of the NGLs.
And we do have a heavier NGL mix with the Marcellus. So I think you're going to see us continue to get good pricing.
I think we saw some seasonality this quarter.
Leo P. Mariani - RBC Capital Markets, LLC, Research Division
Okay, thanks. And I think in terms of the Irons well can you guys give us what the choke size was on the 30 million a day initial production rate?
And it sounds like you're choking it back and talking about pretty significant, 15 to 20? Can you give us the choke size to get to the 15 and 20?
James D. Palm
Leo, choke size -- I mean it's kind of immaterial in some ways. We really kind of look at the pressures more than we look at the choke size, but we thought that 3,200 pounds of that kind of rate was pretty darn strong pressure.
But we'll choke it back to that 5,000 plus kind of range and manage the pressure out there. And based on what we saw as we put the well on and bring it down to the sales line.
It looks like we should to 15 million to 20 million a day at those kind of pressures. The reason I don't really get too concentrated on choke size is because you're bringing back little sand that eats up the chokes.
So really pressures is what we look for and the rates that go with the pressures.
Michael G. Moore
And we were looking at 5,000-psi. So that's really what's relevant.
Operator
Next question comes from the line of Amir Arif of Stifel.
Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division
Just a question on the gas weighting of 50% to 70% for next year. Is that simply a function of the higher IP gas wells coming in or are you seeing changes in your GUR for some of your wet gas and condensate wells?
James D. Palm
No, really, the GURs that we're seeing, or the NGL recovery that goes with the million cubic feet of gas, those numbers are staying pretty constant. Of course, when you start off on a new well, you're going to have a lot more condensate coming with it.
And that will, over time, drop off. But the main thing is that we're just moving over into the dryer gases.
And so we're getting more MCFs coming in there. And some of the far ones like the Irons well won't really have any NGLs or condensate with them.
BTU is up around 1,070 or so, but it's not going to make those. So it's going to lower your percentages.
Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division
Okay, and just for the follow-up question. On your gas rigs, can you just [indiscernible] more on the Belmont County or are you going to be moving further south into Monroe County?
James D. Palm
No, we've got acreage down in Monroe County and even some south of that. But we like where we are.
We've been real pleased to see the kind of wells that we've made -- and any place we go that we plan on drilling well we have expectations that it's going to be a good well. We're not worried about drilling 4 wells.
And so we think we're pretty well derisked our acreage, and we like what we got.
Operator
Our next question comes from the line of Marshall Carver [ph] of Hiking Energy [ph].
Unknown Analyst
I had a question on the number of net wells to go online this year. I wanted to make sure the -- so that's 50 to 55 total net wells should go to sales next year, including the wells being drilled next year and the wells from this year, that could put online next year.
So 50 to 55 net wells for the year.
Michael G. Moore
Yes, I don't want to get into a specific discussion. We can certainly take this off-line after the call, and we can have a specific discussion about net versus gross.
Operator
Our next question comes from the line of David Beard of Iberia.
David E. Beard - Iberia Capital Partners, Research Division
Two questions. First, just given your increase in CapEx, could you prioritize how you would look to close the gap between internally generated cash flow and CapEx?
Michael G. Moore
Sure, we have cash on hand, obviously. We will have proceeds from the sale of the Diamondback Energy stock we announced today.
And then we have borrowings under our revolving credit facility available to us about $150 million. And certainly, we always have the option of debt and equity securities as well.
David E. Beard - Iberia Capital Partners, Research Division
Okay, and then the follow-up just to shift to your 2 type curves. The type curves have been tried tracking the lower end of your band.
Can we really read or should we read anything into where they're tracking this early on in the type curve development?
James D. Palm
Well it is real early and it's not many wells out there. But I think if you look back at the previous type curves, you'll see their tracking up even higher on the bands.
And so it seems like we're getting more history and the type curves strengthening all the time. The actual wells as compared to the type curves.
Operator
We have a follow-up question from the line of Biju Perincheril of Jefferies.
Biju Z. Perincheril - Jefferies LLC, Research Division
Yes, I know you mentioned, on the Wagner well, that's currently shut-in, but can you comment on where it was producing? Is it still around 10 million a day that the type curve would suggest?
James D. Palm
Biju, we've kind of moved on to not going over the individual wells. It's a good well.
It's doing fine, but probably gave more information than we should have on it because we kind of moved into [indiscernible] individual wells, we'd hardly get called on. so we kind of moved on to not discussing the individual wells.
Mike?
Michael G. Moore
No, I think that's right. The what that we have production from wells in the type curve we think the more relevant data point is a composite average of the wells that we have producing under scenario.
So we think that's meaningful at this point, and we think we have enough wells now producing that we are trying to move away from talking about individual specific wells.
Biju Z. Perincheril - Jefferies LLC, Research Division
Okay, that's fair. So the fact that the type curves still showing about 18 months or so flat production, and that was based on, I think -- it was worse [indiscernible].
I guess, you have you're gaining confidence in that number was history, is that a fair statement?
James D. Palm
That's right, and like we say, if you look at the wells as compared to type curve for the last time we put it out. We're stronger all the time with production.
So we like what we're seeing.
Biju Z. Perincheril - Jefferies LLC, Research Division
Okay, and just to confirm, the production guidance and the mix that you gave for '14, does that include any ethane or is that assuming...
Michael G. Moore
No, that assumes ethane rejection.
Operator
And our final question is a follow-up question from the line of Tim Rezvan of Sterne Agee.
Timothy Rezvan - Sterne Agee & Leach Inc., Research Division
Just wanted to, I guess, for those things out, what's your latest spot on resting wells, especially as you kind of look towards the Eastern part of the play?
James D. Palm
That's a good question. We're still trying to figure it out.
We have seen with slick water fracs, we can bring them back right away, and we can make a good well with minimal resting. However, you make more water then and bring back more sand.
So we're still divided within our company. We still go back and forth as to whether or not we need it.
But certainly, I would say it's certainly not the 2 months that we thought when we started maybe. Maybe it's no rest at all, that's why we're doing the Darlot.
We're doing the science there and we're going to have parts of those wells that are 300 feet apart and we're going to look for communication between them, and we're going to do the microseismic and there's so many things that go into it. But we have done a lot of science.
And we've made some remarkable wells today. But I think just tell you Tim, we still don't have all the answers.
I wish I had a final answer for you, but I can tell you that I think Mike, you built 30 days into your model, the conservatism end of that?
Michael G. Moore
When we finish tracking a well, it takes us approximately 30 days to drop plugs and get everything plumbed up and turn production on. So effectively, wells are being rested 30 days, yes.
Operator
And we currently have no further questions in the queue. I would like to turn the program back to management for closing remarks.
Paul K. Heerwagen
Thank you, Nova. I believe this concludes this afternoon's call.
A replay of the call will be available for temporarily through the company's website. It can be accessed at GulfportEnergy.com.
Thank you for your time and interest in Gulfport Energy this afternoon. This concludes our call.
Operator
Ladies and gentlemen, thank you for participating in today's conference. This does conclude the program ,and you may all disconnect.
Everyone have a great day.