Apr 22, 2016
Executives
Michael Hancock - IR Bill Way - CEO Craig Owen - CFO Randy Curry - SVP Midstream Paul Geiger - SVP Southwest Appalachia Division
Analysts
Michael Rowe - Tudor, Pickering, Holt Charles Meade - Johnson Rice Subash Chandra - Guggenheim Partners Brian Singer - Goldman Sachs John Abbott - Bank of America Merrill Lynch Bob Christensen - Drexel Hamilton Jeffrey Campbell - Tuohy Brothers James Spicer - Wells Fargo Marshall Carver - Heikkinen Energy Advisors
Operator
Greetings and welcome to the Southwestern Energy Company’s First Quarter 2016 Earnings Teleconference Call. At this time, all participants are in a listen-only mode.
A brief question-and-answer session will follow the formal presentation. In the interest of time, please limit yourself to two questions, and afterward you may feel free to re-queue for any additional questions.
[Operator Instruction] As a reminder, this conference is being recorded. It is now my pleasure to introduce, Michael Hancock, Director of Investor Relations for Southwestern Energy Company.
Michael Hancock
Thank you Rob. Good morning and thank all of you for joining us today.
With me today are Bill Way, our President and Chief Executive Officer, Craig Owen, our Chief Financial Officer; Randy Curry, Our Senior Vice President of Midstream and Paul Geiger, Our Senior Vice President of our Southwest Appalachia Division. If you've not received a copy of last night's press releases regarding our first quarter 2016 financial and operating results, you can find a copy on our website at swn.com.
Also I would like to point out that many of the comments during this teleconference are forward-looking statements that involve risks and uncertainties affecting outcomes, many of which are beyond our control and are discussed in more detail in the risk factors and the forward-looking statements section of our annual and quarterly filings with the Securities and Exchange Commission. Although we believe the expectations expressed are based on reasonable assumptions, they are not guarantees of future performance, and actual results or developments may differ materially.
I’ll now turn the call over to Bill Way to discuss our recent activity and results.
Bill Way
Good morning everyone. Before we get started, parts of the Greater Houston area, which is our home, here at Southwestern Energy have experienced some epic flooding and it continues to impact the city and I just ask you all to keep people of the Greater Houston area in your hearts and minds and ask you all on the call to support any kind of relief effort through your time or your treasure.
Lots of the energy companies in the United States are headquartered here and it's impacting a lot of folks. So please keep them, again in your mind and help out where you can.
When I look at to the company at the moment, on our last call I walked through our strategic initiatives for this year and discuss how we would proactively drive through the current price environment to strengthen and cross the bridge to the future. As you read in last night's press release, we are delivering on that plan that we laid out.
The first quarter demonstrated our focus and our resolve to deliver results as we exceed guidance on production volumes and delivered better margins than anticipated through production enhancements and cost savings initiatives. Our results are demonstrating a number of reasons to be confident about investing in Southwestern Energy.
I would like to take a few minutes and walk through few of those this morning with you. Much of the gas price, challenge being faced today is largely the result of the impact of one of the warmest winters on record.
There are number of sign post however indicating that the micro picture is changing and that a commodity price improvement may not be far away. With an over $45 billion reduction in the industry wide capital investments compared to 2015 a supply response and particularly -- potentially significant is underway in the industry.
In the Marcellus and Utica areas alone were some of the best dry gas rock is located. There were over 90 rigs running in the Northeast in 2015, while today there are fewer than 40.
This pattern has repeated itself across the country and in many cases even more extreme level then in the Northeast. The recent EIA data released shows production in January of 2016 has flattened remaining at levels back from in the summer of 2015.
Where these results being from very early 2016, the supply slowdown largely does not factor in the impacts of the 60% reduction in capital investment from last year. As we all know it takes time to this investment slowdown to demonstrate its impact on the supply and in our view this means the supply decline will likely even be greater as we move through the year.
Recent data is estimating that the current U.S. dry gas production is lower year-over-year by over 1 Bcf per day for the month of April so far.
The slowing supply is coming at a time when a strong demand story is no longer just a vision but is a visible reality. For years the industry has discussed the upcoming LNG facilities, coal plant retirements, petrochemical expansions and pipeline exports.
In 2016, were seeing these materialize and tangible increase U.S. demand.
With [indiscernible] LNG terminal now up and running incremental demand is online and forecasted to increase to over 1 Bcf per day by the end of 2016. Recent data also continues to show Mexico imports increasing, with these exports now totaling over 3.5 Bcf per day.
This is up over 1.5 Bcf per day from 2015 levels. Another key source of the growing demand is power generation, were coal plant retirements and increasing gas fired power demand are forecasted to increase demand by over 2 Bcf per day by the end of the year.
In addition to the improving macro positioned another reason to be confident about Southwestern Energy is that progress being made on a strategic initiatives we've previously discussed. That will set us up for differentiating value adding growth when commodity prices do recover.
Just a few months end of the year we are well on our way to delivering on that plan as we promised. And I appreciate you all have keen interest in the options being considered, whether that is in maintaining our already strong liquidity position, managing our balance sheet or our asset sales efforts.
Please allow us to continue to work on these. As I’ve commented to you before and have committed to you before at the appropriate time we will talk in details about the actions we have already taken to strengthen the balance sheet and be assured we've made good progress and our resolve to complete this work is clear.
As recently demonstrated by the tangible sets we took in the first quarter to maximize each of the available options to address strengthening the balance sheet and again we will discuss the pertinent options as we complete them throughout the year. Another key contributor to our confidence surrounded in company is associated with our ability to drive cost out of the system since we last spoke.
Consistent with our historical approach of driving down costs in less than two months since our call we have identified an additional $40 million of 2016 cost savings. This is in addition to the 200 million previously disclosed.
As we continue to look for ways to expand this number, Paul will discuss some of the main contributors to these savings to date in a few moments, but each area in the company has found ways to enhance their margins in the first quarter of 2016. Finally, I'm confident that with our vertical integration we stand ready to respond as commodity prices support additional investment activity.
Owning our own rig fleet and completion equipment and having terrific teams to manage them, will allow us the ability to bring wells to sales very quickly as market conditions warrant. Now let me turn over to Craig to discuss some of our financial highlights and he will be followed by Paul, who will discuss some of our operational highlights for the first quarter.
Craig Owen
Thanks Bill and good morning everyone. As Bill mentioned we had a strong exceeding the guidance we released in February and are making progress on each of the strategic initiatives we outlined at that time.
One of the key focus items was to strengthen our balance sheet. In the first quarter we maintained our emphasis on liquidity by adjusting our activity level with cash flow.
Our net cash flow was at 147 million, while our capital investments were 122 million in the quarter. This demonstrates our differentiating capital discipline.
We also enhanced our liquidity with a decision to pay our April preferred dividend in common shares, preserving 27 million in cash. We use our strong liquidity position to temporarily borrow 1.55 billion at the end of the quarter to maximize our secured and subsidiary debt capacity.
This entire amount was paid back in full on April 1st. We appreciate that there are many questions and heightened interest regarding our plans if any to utilize this secured and subsidiary debt capacity to address our debt maturities.
However and as Bill mentioned, we will not be addressing further details or specifics on what we are considering our full-turns [ph], status of discussions or anything else on the topic today. Another component of strengthening the balance sheet includes potential asset sales.
As the press release noted last night our asset sales process is continuing. As bids are received we will make a decision on which assets sales make the most sense to move forward with as an option to address our debt levels.
We will update you more on these decision as these decisions are finalized. In an effort to further protect the balance sheet in this challenging commodity price environment, we were also able to add commodity hedges in the first quarter.
We now have hedges for 107 Bcf or approximately 20% of our estimated 2016 remaining production, utilizing a combination of swaps inputs at an average price of $2.43. Approximately 100 Bcf for this amount covers April to October production when we see commodity prices remain challenged -- most challenged, as stores levels are worked back toward normal ranges.
We will continue to monitor market conditions and look for opportunities to add to our hedge portfolio. I’ll now turn over to Paul to discuss the few with the first quarter operating highlights.
Paul Geiger
Thanks Craig, and good morning everyone. I’ll briefly run through some of our first quarter activities for our E&P and Midstream businesses.
We completed 9 wells and brought 12 wells to sales, we expect to place an additional 11 wells to sales in the second quarter. As Bill mentioned earlier, one of our key focus areas during the first three months of 2016 has been an aggressive pursued of margin enhancements.
This emphasis has been placed on both the revenue side and cost side of margin. On the revenue side, we exceeded the top end of our production guidance by 2 Bcfe as a result of our production enhancement efforts in the first quarter.
This was the result of a number of initiatives including the increase production from compression and gathering system optimization projects. Also, across the company's strong well performance resulted in shallower decline of our base production than previously estimated.
In Southwest Appalachia, we placed 7 wells to sales in 2015 with latterly length over 10,000 feet, the decline on these wells continue to outperform offset wells in the area and we are learning a lot from the performance of these wells, that will be applied in future growing to enhance value. Another example of outperformance is the Alice Edge pad, which was brought online in November of 2015.
This pad is currently producing 85 million cubic feet equivalent per day from 9 wells after almost five months of production. In addition to production improvements, we have realized over $15 million of operating expense savings in the first quarter through a review of operational practices, vendor usage and contract terms.
This savings is an addition to the more than 35 million in annual savings associated with the gathering contract changes that were finalized clearly in the first quarter. With this focus on cost reductions our E&P cash cost which include LOE, G&A and taxes other than income taxes decrease to $1.15 per Mcfe for the first quarter of '16 as compared to $1.28 per Mcfe in the first quarter of 2015.
In the first quarter we were able to reduce our water handling cost through reduced contractual rates with our vendors and by finding more efficient routes to move water. In Midstream, we are finding ways to further optimize our compressor fleet to align with production level changes.
In the first quarter we realize 4 million in savings primarily through equipment and maintenance optimization. As a result of these and other affords we have identified over $40 million in expected annual savings for 2016.
The company's differentiating firm transportation in sales portfolio once again provided tangible benefits. For the first quarter of 2016, our Appalachia firm transportation in sales portfolio added over $30 million in value compared to selling produced volumes into local production area indices.
In addition to the pricing benefit, we receive from our own natural gas, we were able to utilize some of the unused capacity within our firm transportation portfolio to generate additional margin. Our Appalachia transportation and sales portfolio will continue to be in assets that we have leverages as we move forward.
As a remainder, in the Northeast Appalachia, we have built an outstanding firm transportation portfolio that allows us to move our gas to multiple markets with volume and term flexibility. Another way, we are working to create value for us in today's environment is by focusing our increasing our learnings from historical drawing and completion techniques and results.
For example, our teams are redrilling wells on paper to identify improvement opportunities and find tune their geologic models to further increase the efficiencies of future drawing activities. With these learnings, the company expects to further optimize a well economics and to add shareholder value.
That concludes today's prepared comments. So we will now turn it back to the operator, who we explain the procedure for asking questions.
Operator
We will be now conducting a question-and-answer session. [Operator Instruction] Thank you.
Our first question comes from the line of Neil Davies [ph] with Suntrust. Please go ahead with your questions.
Unidentified Analyst
Nice quarter considered the environment out there, say Bill just a couple of questions. First on the 10,000 foot, it sounds like listening to you guys that the economics are really improving on those.
I'm looking at the slides that kind of breaks out the number of locations, how do you all think about, I guess two questions are on the 10,000 footers, I mean is that the direction you are heading to do much more of those and if so how should we think about locations if that's going to be sort of the protocol?
Bill Way
Yes, I think. Good morning, thanks for the question.
I think initially work we are looking at these 10,000 and we have some actually that are up to 12,000 foot in length. We want to -- we’ve successfully been able to drill and complete them, bring them online, we want to do some operating and flow testing and get some production history under our belts to make sure that from a stage contribution perspective as well as overall well perspective that our theory that it makes sense to do those longer laterals is in fact true.
Once we get a little production history behind us then we can know, we've done economics back in forth to make sure that we’re comparing apples-to-apples in wells. If we -- our models are all built on 7,500 foot lateral lengths and so there is an opportunity to improve efficiency and capital efficiency in that program should these actually be the line that we choose.
Unidentified Analyst
Got it, and then just one last one if I could obviously you've got a great locations status out there now after the acquisition and everything that you guys have. What's your thoughts looking at West Virginia thinking about drilling some Utica there, is it more just weighing on take away or I guess maybe a better way to say that is this your thoughts.
When you start to ramp up the drilling plan and again that's just a state of not or when, thoughts about getting after Marcellus versus Utica?
Bill Way
Yes, I'll let Paul to talk a little bit about it in a second, but fairly couple of factors are out on the table. One when we first went into the West Virginia, our initial plans were to drill Utica wells beginning in 2018 and begin to ramp that program at that time.
You will know that we drilled a Utica well and in portion of our acreage we have not completed it yet and as we ranked capital projects this year and prioritized them were keeping that one in mind on when we actually completed. We have some additional Utica wells planned for other portions of our acreage that are set in the queue and I think a lot of it really depends on where gas prices go, where liquids prices go and the balance between wet and dry Marcellus and Utica and then we operate as a portfolio so then you go up and look in the Northeast of Pennsylvania and the dry gas Marcellus area as well so it's too early to tell in specific drilling schedule but we had advanced the process from 2018 to sooner just on a general basis because we've already made that one well test.
The other thing that we are excited about is that we have for the area of where we would put down the next Utica well series when we get to that point we have a dry gas solution in hand and were -- which would enable us to have that optionality to go in any of the particular areas we want to drill.
Paul Geiger
This is Paul. I think that covers it.
When you look at our position the offset industry continues to improve that’s in an extremely viable position and some premium acreage within the Utica. As we go forward into prior investment opportunities from the drill and complete standpoint with the direction of living within cash flow certainly wet Marcellus and Utica in that area are both on the table and our premium within our portfolio and will let as we go through the pricing at the time and specifically NGL pricing as the time just make that determination or where our best returns can be had between the wet Marcellus drilling or the dry Marcellus or the dry Utica within that area.
Operator
Our next question is from the line of Michael Rowe with Tudor, Pickering, Holt. Please go ahead with your question.
Michael Rowe
Just a quick question on hedging you've taken some initial steps to lock in basis at various sales points for the rest of the 2016. I was wondering if you could just talk to their practicality of layering on additional basis hedges in Appalachia to potentially protect a significant amount of your production heading into 2017.
Just thinking about and protecting against implications of potential pipeline build out delays. Thanks.
Randy Curry
Yes, Michael. This is Randy Curry.
Thanks for the question and little color and context on the basis positions that we have put on, those have been as a result of some physical sales and physical basis positions. We do remain confident in our outlook over the improving basis position out there.
Particularly in ’16 you would look at some of the recent contraction in the M2 basis as little as November of last year that was the May contract was trading at about up $1.15 max and you look at it today and we are at about in the $0.60 to $0.70 back range so there is some opportunities that are presenting in the sales out paired that we think are significant improvements over the past and will continue to evaluate those.
Michael Rowe
Okay, thanks. And then just, for my final question, you all accrued $122 million of capital spending in the first quarter, but the cash spending from the cash flow statement was $196 million.
So I was just wondering as the year progresses, should we expect that gap between cash and accrual CapEx to shrink or should we be modeling that?
Craig Owen
Yes. Michael, this is Craig.
Thanks for question. I think in general, certainly we have timing impact of swings on, what it does of a GAAP cash flow statement.
But in general, you’ll see as add or underneath cash flow levels to the extent we’re thinking about strip right now, our planned we laid out in February, we’ll invest within cash flow and not add to the balance sheet. So all that is dictated on what price is and we will kind of continue evaluating that as we move forward throughout the rest of the year.
Operator
Our next question is coming from the line of Charles Meade with Johnson Rice. Please go ahead with your question.
Charles Meade
Yes. Good morning, Bill and good rest of your team there.
If I could go back to one of the earlier questions but maybe from slightly different angle. Can you -- we’re looking at the natural gas strip for the back half of ’16 I’m showing is 255 call it.
Can you give us an idea, which of your operating varies [ph] meets that 1.3 TBI hurdle at 255 and I know you look at the ‘17 strip as well, but could you give us an idea where you clear the hurdle and perhaps a ranking of what’s at the top right now?
Bill Way
Yes. I think, first of all it’s kind of multi-year view that you take our well economics.
So it is 255 today, that’s the data point. That same 255 today heads towards $3 in ’17 and ’18 or beyond and since wells are paid out over more than one year.
Based on what I just said, all of our areas with the exception of Fayetteville are economic and it gets back to a question of investing within cash flow and as we see that cash flow be assured than we can increase that investment. And I think we’ve talked about before, if you look at the highest capital efficient wells that we have and I’m using averages here.
So we’ve had some stellar wells in Fayetteville that have exceeded our expectations even this year. But on average, my highest capital efficient areas will be the Northeast and it will depend really on the fact that we have NGLs as a part of this.
And so as you look at NGL pricing and gas pricing. But basically West Virginia and Pennsylvania both would be in the top of that priority list.
The other thing that we would do is look at our dock inventory and we’ve got some were less than hundreds of those that, excuse me, just over hundreds of those that we would put in front of the line, because they bring cash flow back so quickly because they are already drilled. So as you are looking at prioritization.
Charles Meade
That makes sense. And then if we could drill down a bit on the, some of the compression or gathering authorization you have done that looks like a big win for you guys in the quarter and I’m curious, is that -- was that all from one specific area or can you tell us was that mostly Fayetteville, was that mostly Northwest or Northeast Appalachia, is there a breakdown there?
Bill Way
Yes. The highest impact area or benefit area would have come from Northeast Pennsylvania and Susquehanna and Bradford counties and its part of our ongoing agreement with our gathers to, as we move through time to get that work completed.
So yes, it was a big win for us absolutely the other opportunity was in Southwest Appalachia with Williams. And then we are continuously looking in the Fayetteville at optimizing our compression fleet we have quite a bit of compression in Fayetteville across, a very large gathering system.
But optimizing that and looking at any kind of constraints. But your specific question around where the biggest benefit was came from our Northeast operations which is around compression would be up there.
In addition, I will just point out, we talked about this before our renegotiations, with Williams and our bright new deal we have with them contribute, so that as well.
Charles Meade
Thanks for that detail Bill.
Bill Way
Sure.
Operator
The next question is coming from the line of Subash Chandra with Guggenheim Partners. Please go ahead with your question.
Subash Chandra
Yes, good morning. Is it fair to say that you have to deal with 18 maturities in any, or gas price environment is a, there is a view towards more drilling?
Bill Way
Well let me, I think how I would characterize this and again I am not going to go into a lot of detail, on the details of what we are doing. But one of the things that I believe strongly in is you cultivate options to manage your business and manage through any kind of -- if you’re connected to commodity price environment, you manage through that.
And cultivating those options, when you look at, when do you need to do things? I have 2018 maturities and from a calendar year perspective it's two year away.
From a priority perspective of managing and being proactive around it, I want to work on that, and it's a priority of ours to do that. So as -- the more proactive you can be, the more options you get to retain and the more you get to use.
So that’s really the underlying strategy of it. We are not in a place where we have to do one thing or another and that’s why we are continuing to work a portfolio of options, but have come out very clearly that it's a priority where we are focused on and we’re going to manage that.
Subash Chandra
And my second question is I think you implied that you were benefiting from capacity released market, any sort of sense on what sort of pricing there is, any sort of generalities up there, which you can stand firm for?
Randy Curry
This is Randy again. Without getting to a lot of specifics, our Northeast portfolio is all alluded to earlier, it’s made up of a multiple transportation agreements to fairly multiple markets down to the gulf to the Northeast, across to the mid-west, with varying transport rates and commitments.
And in the first quarter we did release about 80,000 a day that allowed us to generate some significant value over and above the inherent demand charges of. So we could talk some more specifics, but generally speaking about 89,000 a day is what we put together as a package in multiple agreements out of the area.
Bill Way
Just a couple of comments around it, there is a lot of challenges out there in the capacity world and some people have more than it, some people have less than even. Our Northeast Appalachia take away is a great example where our portfolio of transport is really an asset to us, not even -- I wouldn’t even call it a liability and what do I mean by that, you’ve seen our investor pack, we have got -- and we actually lay out the reservation charges and the rates that we pay, we have the volumes, under 1.3 billion a day of firm of capacity out of there, and as you move through a very short period of time we have the opportunity even today to release some of this, we have the opportunity to -- it's made up of so many tranches of capacity that we can release if we want to, we can hold on it if we want to, we can move gas through it if we want to.
It's great optionality and it doesn’t hold us hostage or handcuffed to having to drill wells and do things that are economic when you have so much flexibility around this. So we are pretty excited about the strategy that we have a building firm.
This particular firm is at $0.32, $0.33 which is well, well into any kind of market conditions, so we do view this as a strategic strength for us.
Subash Chandra
Okay thank you.
Operator
Our next question is coming from the line of Brian Singer with Goldman Sachs. Please go ahead with your question.
Brian Singer
First question is on production, with the production surprising a bit to the upside versus your guidance and really ahead of really starting to see the impact of zero rigs, has your view of your natural decline rate changed particular on the sales deal [ph] or you just beat more over timing or initial low productivity?
Bill Way
I think there is a couple of things that play here and more really into the year. The teams did such a terrific job last year of pricing wells, drilling wells, we have such significant advancements in our understanding of how to place them, sand loading all of things we’ve always talked about.
So it set us up well here, and then in addition to that our guys have been working tirelessly, debottlenecking, looking at we’re flowing them, the initiative number of aspects that Paul already talked about. So we are optimistic in what we’re saying and it backs ups some of the statements that we made or factored that our wells are actually, at least from a performance standpoint when we bring them online doing much better.
And that’s -- it’s not manipulating the flow, it's just how they flow and how we optimize that flow. I think it's probably early to tell whether we have got the number pegged exactly right on percentages and we are going to continue to watch that and I’ll be very transparent with you when we get a deal for that.
When you are not adding a ton of wells in a year, it's a different flow dynamic. And so as we watch this and if we need to change it we’ll tell you.
But -- and I just say I just need a little more time to look at it.
Brian Singer
Okay got you thanks. And then my second question is with regards to the leveraging affords, I know you don’t want to be too specific on some of the individual items you are pursuing but I guess how should we think about where you want to get your net debt-to-EBITDA as assuming if we’re going to assume $3 gas, with what you may already have, you don’t want to be specific on, can you kind of talk to where you think that leverage would be, if that all were to close and then where equity issuance stands in the need to achieve your objective.
Craig Owen
Hey, Brain this is Craig. I think we've got just the whole industry were not immune to and we've got such a long way to go to get to certain debt to EBITDA leverage target from leverage ratio or anything else as we indicated in February were going to continue to work on the 18 maturities maintaining liquidity and deleveraging certainly in a $3 world or whatever the strip gives us, we look to improve that significantly from where we are, but I don’t think we’re ready to kind of state a specific target that we’re driving towards in any time frame.
Bill Way
And my view on equity, I'm a publicly trading company. So all options and I've talked a little bit about this before and even down the road we've got cultivate all options in that and obviously we've talk about that asset sales and all this sort of things, but equity is an option, it is an option for any publicly traded company and so we analyze it in the same way we analyze the other items that we are working on and as we work through and I believe that as we move through this whole process and again we are very deliberate and focused on doing it, it's made up of a number of pieces and so as we pull it together we will talk about it.
But your specific question, is it on the table, it sure is because I’m publicly traded company.
Brian Singer
Great, thank you for the color.
Operator
Our next question is coming from the line of Polly Stuart with Scotia [Indiscernible]. Please go ahead with your question.
Unidentified Analyst
Two quick ones just first one the April election of the preferred shares how should we think about that cash maybe cash preservation I guess going forward?
Craig Owen
This is Craig. Talking about future elections on those dividends.
Unidentified Analyst
Yes exactly.
Craig Owen
Our Board -- will and management team will make recommendations at the Board every quarter throughout. So we just have to watch for those each quarter, but certainly why we did April just to preserve cash in the world we’re in, that was more critical and more important to us at that time.
Bill Way
And it was built into the agreement -- the plan when we started, so it was somewhat that we always looked at.
Unidentified Analyst
Okay so in the agreement you can't continue to do that?
Craig Owen
Right that's correct.
Unidentified Analyst
Okay, great. And then with respect to the ongoing asset sales process is there any update on the JV opportunities with the exploratory projects you could give us?
Bill Way
I'll say that, as we've worked through that we've had some interest in the couple of areas. We don’t have a specific offer on the table at the moment, but there continues to be some interest in a couple of different places and I'll let that process play out.
We've actually looked even in -- on pieces of this whether we want to move it into the an asset disposition mode because when you talk with these different people as kind of said well, I might JV with you but I’d rather buy it. And so we’ll watch that as over the next little while.
Operator
The next question is from the line of Doug Leggate with Bank of America Merrill Lynch. Please go ahead with your question.
John Abbott
Good morning. This is John Abbott here calling in behalf of Doug Leggate.
Just wanted to go back because I have two question on your drilling locations slide of your presentation. Just wanted to go back to that.
Firstly your locations at $3 entry hub. Could you provide an update as far as returns for the Fayetteville Northeast Appalachia and the Southwest Appalachia?
And then second could you provide a little bit more color on the breakout of locations with the Southeast Appalachia between rich gas and more lean gas opportunities? Thank you.
Craig Owen
John this is Craig. I'll just kind of briefly on the locations and returns, certainly and we looked at that and as we think about economic locations, as our total rate is in terms of PVI so 1.3 PVI to minimum at $3 and that's where it will translate in those location levels.
So obviously as we move up that PVI increases, generally 1.3 shale well is in the high teens on a return perspective so we haven’t broken out further on higher prices and what those PVIs turning into or returns rather.
John Abbott
And then could you provide a little color in terms of the break out and locations for Southwest Appalachia between more rich gas and dry gas opportunities?
Craig Owen
In the sort of Marcellus probably half of those are wet Marcellus, half of those are dry Marcellus and then if I look at the balance between wet or between Marcellus and Utica, about half the locations are Utica and half of the locations are Marcellus. I guess backing up the map a little if you look at the total half of our Utica quarter of them are wet and quarter of them are dry, Marcellus.
John Abbott
I appreciate the color. Thank you.
Operator
Our next question is from the line of Bob Christensen with Drexel Hamilton. Please proceed with your question.
Bob Christensen
Can you talk a little bit more about the ability of Fayetteville gas to move to Gulf Coast Markets? Historically, this is largely moved to the north as I understand it, the opportunities would seem to be pretty robust over the next 24 months to petrochemical plants and LNG facilities?
Bill Way
I’ll let Randy talk to you about it and maybe put a little color on this, but Fayetteville gas has largely moved to the Gulf Coast and Southeast all over its time and we’ve got significant capacity that’s available to us and it’s actually well positioned. So I will let Randy talk a little bit about it.
Randy Curry
Yes, Bob. I would just add that, Bill commented on some of the optimism, we’ve got in the signpost that you’re looking at some increasing demand and a lot of that demand is manifesting itself in the Gulf Coast.
And as Bill stated our Fayetteville transport portfolio is largely oriented to the Gulf and where most of our disposition has always and we’ve expected it to be in the future as well.
Bob Brackett
Very good. Thank you.
Operator
Our next question comes from the line of Jeffrey Campbell of Tuohy Brothers. Please go ahead with your question.
Jeffrey Campbell
Good morning and congratulations on the quarter. My first question was Slide 13 mentions company-owned assets can ramp up quickly as prices recover, Slide 18 shows 235 and that gas is the 2016 guidance benchmark.
And today you suggested some optimism from future prices. My questions are what price range for what duration is likely required for an increase in investment.
And once the investment decisions has been made how quickly can a productive effect become evident?
Bill Way
Yes. For every $0.25 in gas price movement, there is a $185 million of cash flow that that generates.
When I look at drilling and completing and obviously some ducts [ph] before you do some of the other things. You have got a rig in West Virginia is about $100 million, a rig in Northeast Pennsylvania is probably $180 million.
And so for every $0.25 you can begin putting, if we chose to do that put rig one to two rigs on and if you look at strip going in, let’s say we based our budget of 2.35 and you got $0.50 improvement. You could put two or three rigs back to work if that’s what we chose to do and be within cash flow certainly again doing ducts first and that will have an impact on decline rates in the year and going forward.
Jeffrey Campbell
Okay. Thank you, that’s helpful.
Referring to the longer lateral commentary this morning. I just want to make sure I understood this, do the longer lateral’s promise to provide or potentially promise to provide flatter initial declines than the type curves that you provide in the appendix of the current company presentation?
Paul Geiger
Jeffrey this is Paul Geiger. We believe it has to do some of the conservative, conservatism you’ve seen in the production in the rest of that.
As we certainly the most economic thing to do on paper from a fixed and variable cost and benefit standpoint is to push those laterals out as long as you think you can incremental economic returns, so that is on paper. And so what we have demonstrated a few of those operationally and been able to get out and not only drilled but complete those and drill those out bring them onto production.
And so we’re watching those from a decline standpoint, there was some industry concern about, are you able to effectively produce the tail end of that lateral. We believe we are through various combination of things including dissolvable plugs, blow through plugs, things like that.
We think we’re getting good contribution there. But as you recall from our earlier comments regarding overall productive strategy, the ability to have tight landing zone control, the ability to have increased sand on completions and the ability to have managed drawdown were big factors we believe to outperformance from a well’s standpoint.
So as a longer laterals, we believe we’re able to produce those at a managed rate and get improved EURs, but then also in our liquids rich Marsalis areas also increased liquids recovery versus offset shorter laterals or wells are higher drawdown. And so as we do see those continue to outperformed curve.
So that potentially has an impact on our forward projections for those wells, type curves.
Jeffrey Campbell
Okay. Thanks very much for the answer.
Operator
Thank you. Our next question is from the line of James Spicer with Wells Fargo.
Please go ahead with your question.
James Spicer
Looks like you spent about 60 million in discretionary capital during the quarter, which I think is tracking a little high relative to your discretionary full year budget of 100 to 125. How should we think about the pace of capital spending during the remaining quarters of the year?
Craig Owen
You should think about this way. That capital is front end loaded and that makes the most sense from a number of perspectives both in terms of ramping down and then also getting the full benefit of the cash flow that’s generated from it as quickly as you can.
And you will see that taper off and the real answer is, we will not be adding to any kind of cash flow deficit by investing so you watch cash flow and you watch capital.
James Spicer
Okay, great. And then just along the same line there -- at least relative to EBITDA minus CapEx, you were free cash flow positive during the quarter, what's your cash flow outlook for the remainder of the year at strip prices?
Do you expect to continue to be for free cash positive? And if so, what does that mean in terms of organic deleveraging versus some of the kind of more proactive alternatives you’re evaluating?
Craig Owen
Yes, I mean we are going to watch that obviously. If we can put money to back to work and we agree with that something that we need to do and we talk to with our Board of Management and that’s an option for sure.
But I want to take a look at where gas prices go, the important piece of it is whatever decision we make with that, we are ready to implement it. One of the benefits we are having the vertical integration we have, we’ve kind of talked a little about that before.
And retaining the DNA for both our drawing company and our completion company inside the business, we can get back to work very quickly.
Operator
Thank you. And our next question comes from the line of David Heikkinen, Heikkinen Energy Advisors.
Please go with your question.
Marshall Carver
Yes thank you, this is actually Marshall Carver with Heikkinen Energy Advisors. Regarding the comment on the longer laterals and improve type curves, are those officially outperforming the type curves on a per laterals foot basis, or is it more just that their longer laterals -- and so naturally they are better than 75 foot 100 foot lateral?
Bill Way
Paul will talk a little detail about this, but let me just tell you that we’re going to look at it on a per lateral foot basis, we are going to make sure that the decision to drill a long lateral versus two shorts is a straight up economic comparison and that economics is EUR, flow rates of that and investments in so, Yes, we analyze that very, very specifically. We actually have some benchmarks internally that we use to say that a 12,000 foot lateral has to perform at this level greater than two sixes four to make sense, that’s the analysis we are doing.
But again we don’t -- making up on length is not something we will do.
Paul Geiger
This is Paul. Regarding those longer laterals, we have got a few of those so we’re early in the testing stage, but to your questions specifically, yes on a per foot basis at this point we have got 10% to 25% improvement versus offset and so we are very encouraged about that.
Marshall Carver
How are the cost trending for the lateral foot?
Paul Geiger
This is interesting question, this is Paul again. We are zero right now.
[Multiple speaker]
Bill Way
We find that we had going for us when we have rigs and pay was we went from -- early entry into West Virginia and kindly to trying find a way to pay setter and what I mean by that is best in class or at the top of the class, performance on a cost per lateral foot. And we did that with some extraordinary drilling performance out of our company own drilling teams and our rigs placing these laterals 100% or nearly 100% in zone, which helped boost the performance and so it's driven cost down comfortable.
Paul Geiger
This is Paul. Where we left off in the drilling program like Bill mentioned, we expect it to in the early time of West Virginia acquisition a year ago to move ourselves to top quartile drilling complete performance on $1 per foot basis over a couple of years, we did that by mid-year last year.
And as we left off at the end of the ’15 programs were driving those below a $1,000 foot. And so that we consider to be very fast competitive in the Marcellus.
We don’t have enough data points to give hard numbers in the Utica, you can see some of those in our expectations and they are consistent with what the industry calls a development cost of the Utica well.
Marshall Carver
All right, thank you for that commentary. Thank you.
Operator
Thank you. Ladies and gentlemen we have reached to end of our allotted time for questions.
I would like to turn the floor back over to Mr. Way for closing comments.
Bill Way
Thank you very much. And thanks for all the questions and the dialogue and we look forward to answering any that didn't get answered when we see you in person.
As you heard we are driving forward on the plans we shared with you early in the year and we’ve delivered strong results in a short period of time. And I think the lastly for the yesterday [indiscernible] that out.
And as I said previously, I really believe that creditability comes from consistent delevering on the commitments that we have made and I can tell you that we have got a firm result to build on a creditability and lay out plans, execute them, share those results with you and be as transparent as we can about that. We have no doubt that this strategic initiatives that we are pursuing this year and going forward to setting us up to generate significant value for our shareholders going forward and whether it's the quality of the assets, the steps we are taking to strengthen of balance sheet, to improving micro indicators, the reasons to be excited about Southwestern Energy is an investment, I think are strong and very apparent and getting even stronger as we move forward through 2016.
So we are not hunkered down we are powering and driving through these commodity price environments and the result show it when every member of our team is out trying to drive margin improvements and are very focused on getting more out of the assets that we have and we are excited about the future that we have in front of us and I’m looking forward to talking with you again about these accomplishments as we continue to generate them and until them we want to thank you for being here with us today and hope you have a great weekend. So thanks a lot.
Operator
Thank you. This concludes your teleconference.
You may disconnect your lines at this time. And we thank you for your participation.