Oct 24, 2014
Executives
Steve Mueller - Chairman and CEO Bill Way - Chief Operating Officer Craig Owen - Chief Financial Officer Jeff Sherrick - Executive VP, Exploration and Business Development Michael Hancock - Director, Investor Relations
Analysts
Doug Leggate - Bank of America Merrill Lynch Jeffrey Campbell - Tuohy Brothers Investment Michael Rowe - Tudor, Pickering Holt and Company Dave Kistler - Simmons & Company Gil Yang - DISCERN Investment Analytics Bob Brackett - Bernstein Research Charles Meade - Johnson Rice & Company Joe Allman - J.P. Morgan Dan McSpirit - BMO Capital Markets Brian Singer - Goldman Sachs Biju Perincheril - Susquehanna Financial Group David Heikkinen - Heikkinen Energy Advisors Scott Hanold - RBC Capital Markets
Operator
Greetings. Welcome to the Southwestern Energy Company’s Third Quarter 2014 Earnings Conference Call.
At this time, all the 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. Afterwards, you may feel free to re-queue for additional questions.
(Operator Instructions) As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Mr.
Steve Mueller, Chairman and Chief Executive Officer for Southwestern Energy Company. You maybe begin, Mr.
Mueller.
Steve Mueller
Thank you. Good morning.
Thanks all of you for joining us today. With me today are Bill Way, our Chief Operating Officer; Craig Owen, our Chief Financial Officer; Jeff Sherrick, Executive VP of Exploration and Business Development; and Michael Hancock, our Director of Investor Relations.
If you’ve not received a copy of yesterday’s press release regarding our [first] (ph) quarter results, you can find a copy of all of this on our website at swn.com. Also, I’d like to point out that many of the comments during this teleconference are forward-looking statements and involve risks and uncertainties affecting outcomes, many of which are beyond our control and are discussed in more detail in the Risk Factors in 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. Now let’s begin.
In one sense, the recent announcement of our potential new core area for our company has been very eventful. In the sense of third quarter results, it has been the consistent performance our shareholder expect from our staff and our high quality assets.
Production continue to increase, well economics improve as we learn how to best drill and then produced the very stratigraphic objectives and the well inventory increases as we apply what we learned other zones. Yes, gas price is down relative to earlier in the year and yes, it will be continue to be challenged next summer and fall, but we built that into the -- that volatility into our 2015 -- 2014 plan, we built it into the acquisition economics and we’ve built it in our 2015 plans.
Some interesting persistent counterpoints are beginning to change that gas price balance. This will be the first winter since 2008, with a total storage less than 3.75 Tcf and indications are that storage could be as much as 5% less or approximately 3.5 Tcf to 3.6 Tcf.
The ongoing worrying -- the ongoing worry is obviously the 12-month average production has grown just over 4.3%, but it’s often forgotten that the demand growth is also kept up or almost kept up at 3.9%. And new demand from known projects will increase that base over the next five years.
In addition, the current demand increase has occurred in a price environment, but for the most part as this group switching from utilities using coal to gas and its happened as net imports continue to decrease. In short, as a storage curves indicates, this is not 2012 from a gas price scenario and Southwestern Energy is stronger and better company poised to take advantage of the better outlook, but also able to deliver top tier results when prices are lower like this -- like we have this quarter.
Before I turn the call over to Craig, let me mention, that we have little new information regarding our announced acquisition. But I do want to address one impression.
I have heard and read that Southwestern Energy is making a coal and natural gas with this acquisition. While we believe gas fundamentals are improving, the acquisition is not call on gas, it is call on quality.
Quality wins in every price environment. As I will say about the acquisition from now.
But we have a much more to talk about regarding our quarterly performance. And I will now turn the teleconference over to Craig for an update on our third quarter financial results.
Craig Owen
Thank you, Steve, and good morning, everyone. As Steve mentioned, we had another excellent quarter, primarily driven by record production volumes.
Excluding the certain non-cash items, we reported net income of $178 million or $0.50 per diluted share for the third quarter, compared to $180 million or $0.51 per diluted share last year. Our cash flow from operations before changes in operating assets and liabilities in the third quarter was $504 million, compared to $528 million for the same period last year.
Operating income for our exploration production segment was $189 million, compared to $223 million we recorded in the third quarter of ‘13. This decrease was primarily due to lower realized natural gas prices and higher operating costs and expenses due to increased activity levels and partially offset by the revenue impact of increased production.
Including hedges, we realized an average gas price of $3.43 per Mcf during the third quarter, compared to $3.61 per Mcf last year. Excluding hedges, our average realized gas price increase to $3.21 per Mcf from $3.06 per Mcf last year.
Hedging added about $0.22 per Mcf to our realized gas prices in the third quarter, compared to adding about $0.55 per Mcf last year. Our realized average gas price in the Marcellus was $2.73 per Mcf for the quarter.
Our firm sales agreements along with our financial basis hedging activities protect 63% of our Marcellus production for the remainder of 2014 at NYMEX plus $0.12 per Mcf, excluding transportation charges. Currently, we also have about 34% of our 2015 Marcellus volumes protected with financial basis hedges and firm sales agreements at a price of NYMEX minus $0.13 per Mcf, excluding transportation charges.
We also have 117 Bcf or approximately 59% of our remaining 2014 projected natural gas production hedge to fixed price swaps at an average price of $4.35 per MMBtu. We also have 240 Bcf of natural gas swaps in 2015 at an average price of 4.40 per MMBtu.
On the cost side, our cost structure remains one of the lowest in our industry, with all in cash operating costs of approximately $1.29 per Mcfe in the third quarter of 2014. That includes our LOE, G&A, net expense and taxes.
Least operating expenses for our E&P segment were $0.91 per Mcfe in the third quarter, compared to $0.87 per Mcfe in the third quarter of ’13. The increase is due to a combination of higher compression costs in the Fayetteville and the continued growth in Marcellus, which has higher gathering rates in the Fayetteville.
Our G&A expenses were $0.23 per Mcfe, down from $0.24 per Mcfe a year ago. Taxes other than income taxes were $0.10 per Mcfe, compared to $0.09 Mcfe last year and the full cost pool amortization rate in our E&P segment was $1.09 per Mcfe, compared to a $1.07 per Mcfe last year.
Operating income from our midstream services segment rose 30% to $97 million in the third quarter, compared to the same quarter in 2013, primarily due to increase in gas volumes gathering, which resulted from our increase in E&P production volumes. Mid-stream EBITDA was $111 million for the third quarter 2014, a company record, compared to $99 million in the third quarter of 2013.
At September 30, 2014, our debt-to-total book capitalization ratio was 30%, down from 35% at the end 2013. The debt balance includes $139 million borrowed on our revolving credit facility at September 30th and that is down from $171 million borrowed at June 30th and $283 million borrowed at December 31st.
I’m very proud of this strong results, we had this quarter and I’m very excited about what company has coming on the horizon. I’ll now turn it over to Bill Way for an update on our operational results.
Bill Way
Thank you, Craig, and good morning, everyone. As mentioned earlier, we have a great third quarter.
Our operating team impressed once again with strong performance allowing us to again set production records. In Marcellus Shale had an impressive 47% growth in production and we continue to improve our understanding and build additional confidence in our acreage position.
In the Fayetteville, where we're seeing the benefits from implementing the learning’s and efficiencies we have identified to-date, we translated into record production rates in increasing number of wells, with initial rates in excess of $5 million cubic feet of gas a day, an increasing numbers of future wells to drill, all of which exemplifies the curiosity and innovation that differentiates Southwestern Energy from the pack. An example of our curiosity and learning during the third quarter is our focus and testing of optimal landing zones, increased profit loading and frac spacing.
In both, Fayetteville and Marcellus, we are experimenting with these and other drilling and completion techniques, and early indications appear favorable. If we can confirm this with further testing analysis, it could result in decrease well costs.
On the exploration front, we have an exciting portfolio of opportunities in the pipeline and we are making good progress on testing of the projects that we’ve publicly announced. I’ll walk through the status of some of these projects in a few moments.
Each day I'm impressed with the dedication and focus that our employees bring with a common goal of working together to find new ways to add value. This team work has been instrumental to the strong results that the company is delivering in 2014.
To begin with the Marcellus Shale, our production in the third quarter grew to a record 66 Bcf, which as I said is an impressive 47% increase over our volumes produced in third quarter of 2013. We’ve seen continued improvement in our productivity index in the Marcellus, up 200% since we entered the play, through a combination of optimized lateral replacement stage spacing and profit loading.
In the quarter, we completed a well using as much as 835,000 pounds of sand per stage and we expect well results on this soon. We remain committed to growing our production to match our firm transportation capacity.
And we continue to look for economic opportunities to add additional capacity to our portfolio. Our strategy of finding the firm capacity and growing production to those levels has helped partially insulate the company from some of the depressed pricing in the region during the summer and shoulder months.
Additionally, our basis hedges provide a benefit over -- of over $9 million during the quarter. We were moving 840 million cubic feet of gas per day in the Marcellus Shale at September 30th and as I said, transporting the gas through our firm transportation capacity to market.
Let me pause here in this discussion of flowing to firm capacity and say, I know there have been some questions regarding the 30-day average rate of our wells in the Marcellus this quarter. While our well mix of 14 wells include some testing of new areas, we managed the overall Marcellus business on value and not just IP rate.
Our marketing and operations teams work very closely together to optimize the value of gas -- we received for our gas. And in the current pricing environment, we've increased production, pulling harder on wells during high demand days of the week and pulling back on wells on the weekends.
Again, the flexibility of our firm transport allows us to maximize the value of every Mcf we produced. By the end of the year, we currently have firm transportation out of Pennsylvania under contract, which totals more than a billion cubic feet of gas per day and increases to almost 1.2 billion cubic feet of gas per day in 2016.
Our current drilling budget allows us to ramp our production to match this increased firm transportation capacity. Additionally, on the midstream front, the range area in Northeast Susquehanna County now has 600 million cubic feet of gas per day of compression capacity and this will be significant -- a significant benefit to us as the productivity of the field continues to improve.
In the most Northern part of our Susquehanna County acreage block, that we call North Range, we’ve completed the acquisition of 3D seismic as we continue to derisk the area. The team is now interpreting the data and will be able utilize the results as we move forward in our development plan in North Range.
Initial well testing results from North Range area in Susquehanna County continue to be encouraging. We are well underway in extending our gathering system into North Range to gather production from this acreage as well.
In Wyoming County, we’ve now drilled our first horizontal well, the Dimmig 2H and we plan to test it in the fourth quarter. Additional locations are planned in both Sullivan and Wyoming counties as we progress our delineation efforts in that area.
Additionally, in the upper Marcellus, we drilled three wells during the quarter that are anticipated to be completed during the fourth quarter, a fourth well is also expected to be drilled by year end, with completion planned into early part of next year. In the Fayetteville Shale, we again had our best quarter in the company’s history for production volumes and had our 10th consecutive positive cash flow month.
We’ve placed a total of 106 wells online at an average initial production rate of roughly 4.3 million cubic feet of gas per day. Two of them are in the top 10 ever drill at over 10 million a day each.
We also had increasing average 60 day rates of 2.5 million cubic feet of gas per day, reflecting the better wells drilled in the past quarter. We are continuing to monitor well results from higher rate wells as we access whether these wells have higher EURs or if they are accelerating production, either way, the teams continuing to create value for the company.
In the Upper Fayetteville formation, the company has placed 15 Upper Fayetteville wells online through the first nine months of 2014, with an average production rate of 3.4 million cubic feet a day. Three of these wells had an average initial production rate of over 5 million cubic feet of gas per day, with the highest IP rate being 6.6 cubic feet of -- million cubic feet of gas per day.
We plan to drill five additional Upper Fayetteville wells in the fourth quarter and complete them in early 2015. While it’s early, we estimate that the Upper Fayetteville may expand over 130,000 acres or 1000 well locations for future development opportunities.
Regarding a vertical integration, we are nearing completion of the upgrading of our drilling rig fleet where we took possession of our fifth rig -- seven rigs during the quarter. The capability of these new rigs continues to impress as the technological improvements are helping obtain even more efficiencies in the process.
We fully expect through this drilling days of Fayetteville wells by one day allowing us to drill more wells with fewer rigs. Our gas gathering business was gathering and transporting approximately 2.3 billion cubic feet of natural gas per day on September 30th.
We have additional firm transportation capacity to deliver any growth from our acreage in the play and we are positioned very well to supply future long-term demand for our Fayetteville asset. Moving to exploration, we now have drilled three vertical wells in northwest Colorado targeting the Niagara formation and our drilling our first horizontal well.
An additional vertical well is planned for the fourth quarter. As we mentioned before, we anticipated it will take us 8 to 10 wells before being able to determine the long-term commerciality of this play.
As we continue to get more data and make progress in our testing, we’ll talk more about well results and what we are finding but we are encouraged so far. In closing we’ve had a great third quarter and first nine months of 2014 and we are looking forward to finishing the year even stronger.
The amazing team of people that I have the privilege to work with everyday continues to innovate and find ways to improve performance and capability which gives me great confidence in our road forward. This is an exciting time for Southwestern Energy and we look forward to sharing even more terrific results on our next call.
This concludes my comments. So we will now turn the call back over to the operator who will explain the procedures for asking questions.
Operator
Thank you. (Operator Instructions) Our first question today comes from the line of Jeffrey Campbell with Tuohy Brothers Investment.
Go ahead with your question please. I’m sorry.
The first question today comes from the line of Doug Leggate from Bank of America Merrill Lynch. Thank you, Doug.
Go ahead.
Doug Leggate - Bank of America Merrill Lynch
Thank you. Good morning Steve.
Good morning everybody. I keep getting amused by the different translations.
Anyhow, I think this is me. Two quick ones if I may.
Steve, I'm afraid I missed the call last week. I was traveling, unfortunately, when your call was on.
But so I wonder if I could just risk a question on the acquisition and then one on the quarter, if I may. On the acquisition you did make clear that your investment grade credit rating is very important to you.
So I don't want to get into specifics, obviously, but I'm just curious if you could frame for us what that means for you in terms of metrics. I think you did say the midstream was not high up on the list.
But just for completeness, if you could give us a tax basis there and just any color around what you think retaining an investment grade credit rating would mean in terms of potential financing structure. And then I'll get a follow-up on the quarter, please?
Steve Mueller
Okay. I mentioned kind of what it means and each group that’s out there has different criteria they look at.
We on a very simplistic basis and Craig talked about it, we look at that debt ratio and talk about 30%. Historically, we like to be in the low-to-mid 30s.
This acquisition will bring us up to something higher than that. And when we talk more about it, we’ll get that -- we’ll show you how we’re going to get that debt ratio down, what it will be and how we get it down.
And that’s to be discussed later day. As far as tax basis on midstream, I’ll let Craig answer that.
Craig Owen
Yeah, midstream in general is fairly mature. Most of that investment has occurred over the past 10 years certainly but really in the last seven.
So the tax basis is not significant. We’ll say exactly what it is but it’s -- we enjoy the benefit of that tax depreciation over the past couple of years.
Doug Leggate - Bank of America Merrill Lynch
Okay. Thank you.
Steve Mueller
It’s basically the capital we’re producing right now.
Doug Leggate - Bank of America Merrill Lynch
Right. So in the event of any monetization than there will be a fairly hefty tax impact?
Is that a good way of thinking about it?
Steve Mueller
It depends on how you monetize but that is correct.
Doug Leggate - Bank of America Merrill Lynch
Okay. My follow-up in the quarter is really more, Steve, you've obviously continue to have substantial success in the upper Fayetteville.
So routinely you've given us an idea what the economic backlog looks like at range of oil prices. Just wondering if you could give us an update as to how the upper Fayetteville is changing things in terms of what you see as economic.
Let's assume a stressed gas price, call it $3.50 in perpetuity. I don’t know what sensitivity you hear is but any color as to how you see that backlog in the comment of R&D.
That would be great. Thanks.
Steve Mueller
And I’ll just put upper Fayetteville in perspective with the lower Fayetteville. They are separated at most by 100 feet.
It’s relatively small interval separation. So cost, lateral length, all those things are almost identical between the two zones.
The upper Fayetteville is a little bit thinner than the lower Fayetteville. So with the lower Fayetteville, we’re drawing on 60-acre spacing, the upper will be more, just over 100-acre spacing.
That’s why Bill made comments about 130,000 acres, 1000 wells because it will be a wider spacing. With that wider spacing, EURs IPs will be very, very similar to the lower Fayetteville.
So that same distribution I talked about in the past were at $3.50 we had something 2400 or so wells to drill going forward. You can add probably about 250 or 300 oils offer into that category.
And when we had $4 flat forever, that’s the 1000 wells that Bill is talking about.
Doug Leggate - Bank of America Merrill Lynch
That’s great. Thanks a lot.
I appreciate it.
Operator
Our next question now comes from the line of Jeffrey Campbell with Tuohy Brothers Investment. Go ahead with your question, please.
Jeffrey Campbell - Tuohy Brothers Investment
Good morning. When you put out the press announcement on West Virginia acreage acquisition, you also stated that Southwestern was considering dispositions of certain non-strategic assets.
Just wondering if you could provide some color on what acreage might be behind this statement?
Steve Mueller
I don’t know that we’re going to make much comments about that now. Stay tuned and in about three weeks, we’ll go in a lot of details on that.
Jeffrey Campbell - Tuohy Brothers Investment
Okay. And the other question I want to ask was going back to investment grade, but maybe a little bit different way.
You did say you didn’t want to threaten your investment grade and you didn’t want spending to get uncoupled from cash flow. I was just wondering how will this develop -- affect your development plan for the Colorado Sand Wash if the West Virginia acquisition actually comes through?
Steve Mueller
It's all about economics and it's all about quality. So any exploration project, not just what we do in the Sand Wash Basin, if we have a discovery, it will be what we do with it and how fast we grow will depend on the quality of that discovery.
If it's the best economics we have in the company, a bunch of money is moving in that direction and something else isn’t getting drilled. And if it's in the middle of the pack and it has less to it and if it's on the lower side, maybe we don't keep it.
So it really just the economics and as Bill said, economics on that won't be known. At least on Sand Wash won't be known until probably this time next year.
Jeffrey Campbell - Tuohy Brothers Investment
Okay. Thanks, Steve.
That was very helpful.
Steve Mueller
Thank you.
Operator
Our next question comes from the line of Michael Rowe with Tudor, Pickering Holt and Company. Go ahead with your question, please.
Michael Rowe - Tudor, Pickering Holt and Company
Hi, good morning.
Steve Mueller
Good morning.
Michael Rowe - Tudor, Pickering Holt and Company
I was wondering could you provide just a little bit more detail around just the moving pieces that caused the IP30 day rates out of the Marcellus to look a little bit lower? I think it’d be lowest kind of since the third quarter of 2013.
So just wondered if you could go through that in a little bit more color, please?
Steve Mueller
Bill's kind of addressed it a little bit in his comments. I'd say kind of did a political dance around on that.
But basically, what we've been doing and we've talked about this in the past, if we could buy gas someplace else and make more money than producing our gas, we would shut wells in. And specifically to his comments, weekends are low demand time.
The weeks are high demand time. And so what we've been doing is we're not shutting all of our gas in.
We back down on the gas on the weekends when we don't think there's demand. We get more gas that kicks up during the week.
And on those 14 wells, there were three or four of those, if it is a 30-day rate hit on weekends. So it's just simply that.
Michael Rowe - Tudor, Pickering Holt and Company
Okay. That's helpful.
And then I guess you made a comment that in both Fayetteville and Marcellus, you're sort of testing optimal landing zones, increased proppant loading and tighter frac spacing. And you also mentioned you expect potentially some reductions in well costs.
So could you talk about I guess one of the key drivers of reducing well costs there, just given the fact that you potentially are doing a more enhanced completion than you had previously?
Bill Way
Yeah. It's really about how much sand per foot we can get into the ground and optimizing that amount of sand.
And so if you take a look at the Marcellus wells, for example, where we are. Our objective is to test and increase the sand loading on these wells.
If I can get 800,000 pounds of sand into the ground in 17 stages or I can get 800 pounds or 1000 pounds of sand into the ground with fewer stages than that by increasing concentration. It affects the cost of completion.
We'll test it to make sure that it doesn't impact the overall recovery, but you're trading parts. Either -- I can either have 18 stages or I can have fewer.
In the Fayetteville, it's the same way. We pay to pump based off stage count and the more sand we can pump into each stage improves the quality of the frac and lowers the cost overall of the well.
We're doing some other things on well cost as we've talked before. We rest every well in the Fayetteville that we have after we drill it and complete it.
The result of that is that there's less flow back water to no flow back water that comes back. That really impacts us to the tune of about $100,000 a well because we're not moving water around from place to place.
If we can -- where we can drill longer laterals as units allow or we combine units together to do cross-unit wells, we're at the well site one time drilling a longer lateral and enabling us to optimize cost there as well. On pad drilling, when we go to a pad, we drill out the initial acreage capture well.
But then when we come back to a pad, we work very hard to try to only go back one time and drill all the remaining wells rather than making multiple trips. Our new rigs certainly are able to drill faster.
They're also able to move faster. They're more agile, both on the road and on the pad site.
If we can crack the code of single trip drilling, you have additional cost opportunities that come in both areas. And we're working on that as we speak.
Steve Mueller
As you can see, we've got a lot of different things that we're doing. Let me just make two kind of general comments.
I know the industry has gone to tighter spacing and you even said in your question tighter spacing. We have certainly tried and are continuing to try some very, very close spacing, 80, 90 type frac intervals in some of our wells.
But what we're seeing, if we can put a lot of sand away we actually do less fracs, less stages. So that's part of that savings.
And then the other thing, and it should be obvious from Bill's comment, we're trying just a lot of things and continue to try a lot of things. As we do those, some cost more, some cost less, but we think the end result is less cost.
Michael Rowe - Tudor, Pickering Holt and Company
Okay. Thanks very much.
Operator
Our next question comes from the line of Dave Kistler with Simmons & Company. Go ahead with your question, please.
Dave Kistler - Simmons & Company
Good morning, guys.
Steve Mueller
Good morning.
Dave Kistler - Simmons & Company
One thing in the Fayetteville, as you guys hit these higher IP rates, can you talk a little bit about how you're optimizing surface infrastructure for those kinds of changes? I would guess you had a standard well design and is that starting to fluctuate a little bit to allow for greater IPs out of the gates and is that changing any of the capital burden?
Steve Mueller
We've modified facilities into two areas, primarily. First being how we run chasing in the design of that tubing in the well.
At these higher rates, taking tubing down below all the safety equipment and stopping there allows the well to have less restriction to flow to the surface. One of the things that happens in any kind of very highly efficient business is you tend to go down a path where everything looks the same.
You are buying multiples of the same kind of meter run and separator and all that. What we figured out is that in some of the areas, we really do have a need for some larger equipment.
So where a two inch meter run might have been standard, now a three or four inch meter run might be there. So we're optimizing all of the midstream gathering facility standard equipment.
In addition, then we look at optimizing flow lines into the main gathering system. And what we're talking about here is well connection flow lines.
The main trunk lines of the field are already invested and so we look at the economics on an integrated basis to determine sort of the optimal pipeline sizes and others facilities. So, it's kind of through the -- from the well below all the way through to the compression point.
We also are working on some new processes or work plans around getting wells back on line sooner which brings in some well side compression, gets those wells unloaded and on line faster. So it's kind of an overall logistics and optimization effort and it has a number of components.
Dave Kistler - Simmons & Company
I appreciate that. Maybe switching over to the new ventures just for a second.
You in the past had mentioned doing a vertical test in the DJ Basin that was going to be pretty impactful on a go or no-go decision for developing that asset going forward. I didn't see any comment in the release on that this time.
Any color you guys can provide us on that?
Steve Mueller
Let me just say that we drilled that well in the second quarter. We have fracked or tested what we call the Atoka interval and we're getting ready to test the Marmaton which is shallower intervals.
And when we get that all tested, we will talk about it. But just haven't got all our testing done yet.
Dave Kistler - Simmons & Company
Okay. I appreciate that.
Any early indications that's helpful or still we just don't know until we get all final detail?
Steve Mueller
Atoka is a fairly tight zone, and it's a fairly thick zone. We tested a couple of intervals in it and it performed like we thought it was going to perform.
That's pretty low perm. And then the Marmaton is completely different kind of interval.
It is higher cost and higher permeability. It's not conventional but it’s more conventional than it is unconventional and certainly it’s characteristics.
So, Atoka tested like we thought it was going to test. Marmaton's we're about to test and they're completely different.
You can't add or subtract anything. You just have to test them and then come to a conclusion.
Dave Kistler - Simmons & Company
Great. I appreciate the color guys.
Thank you so much.
Operator
Our next question comes from the line of Gil Yang with DISCERN Investment Analytics. Go ahead with your question, please.
Gil Yang - DISCERN Investment Analytics
Thank you. Good morning everyone.
You had really tremendous success in a number of wells in the Fayetteville, scattered over a pretty broad part of the play. Can you talk about how predictable those really strong wells are or are they a little bit unpredictable in terms of when -- obviously you tweak a lot of things, but can you predict when those tweaks are going to generate those really good wells?
And then in that context, what proportion of your inventory do you think has the opportunity to be able to get that really strong result category?
Steve Mueller
In the Fayetteville Shale, it really is a coming of that most unconventionals. You can get a sense of what's going to happen, but trying to predict whether it's 10 million a day well, 12 million a day well or an 8 million a day well is difficult but you can tell it should be in that range.
And so there is some variability but you can certainly start figuring out the size and your real question was how many of those do we have. As we said, each area is little bit different and we are trying different things and so shallow, it’s not quite the same as it is in the deeper part of it.
But we think about 20% of our 600,000 acres has a potential for some kind of enhancement. And when I say some kind of enhancement, some of that might be reserved but certainly all of it will have some kind of acceleration component to it, to the economics.
Gil Yang - DISCERN Investment Analytics
And then 20% of the acreage would be -- would that be 20% of the remaining locations or a greater percentage or smaller?
Steve Mueller
We probably won’t add any locations if that’s what you are asking or add very few locations. The locations we have now are better.
Gil Yang - DISCERN Investment Analytics
Okay. Okay.
So, 20% of the remaining locations could be of that extra strong category.
Steve Mueller
Should have something -- some kind of enhancement to it.
Gil Yang - DISCERN Investment Analytics
Great. Okay.
And then my sort of the third question is the exit rate of the Fayetteville seemed to be down in the quarter. Was there any commentary around that?
Is that significant at all or is it just sort of the day-to-day variability?
Steve Mueller
I think that was just the way it bounces around.
Bill Way
Yeah. It’s just really well mix and timing of completing fracs.
There is nothing there.
Steve Mueller
If you work on there and you can almost tell when we put a big pad on and not put a big pad on, our production curve bounces up little bit and it goes down literally. We see bounce back up here.
Gil Yang - DISCERN Investment Analytics
Thank you very much.
Operator
Our next question comes from the line of Bob Brackett with Bernstein Research. Go ahead with your question, please.
Bob Brackett - Bernstein Research
Good morning. Quick question on the final EIS for Constitution pipeline.
Any thoughts on that and what you think the next milestones for getting that truly constructed are?
Steve Mueller
I don’t know that we have any thoughts on that too much. We follow just like everyone else does.
The big thing that will happen after we get some approvals here, supposed to be happening right now, is get approvals from New York State. I want to get approvals from the New York state.
Unless there is some kind of misestimate on water crossing or road crossings, it’s a relatively short process. We know that process is, nine month type build.
But just making sure you get all the permits and predicting when and how you are going to get all those permits is an issue.
Bob Brackett - Bernstein Research
And a quick follow-up, what's your interest in joint ventures in general? It looks like you could potentially be having a partner in this new acquisition in West Virginia.
Is that something you look forward to, is that something you prefer not to do, would you consider it for other assets?
Steve Mueller
Yeah. As long as they are quality partners and certainly in West Virginia that partner brings a lot to the table, both technically and financially as all the quality partners.
We don’t have any partners at all. And especially on the exploration side, as we’ve said in the past that in New Brunswick that we probably will get a partner at some point of time because it’s too big of a project for us.
So if partners are just another one of those things you use and work with you on there and as long as you make sure you’ve got high quality, no problems at all.
Bob Brackett - Bernstein Research
Okay. And if that partner in West Virginia offer their interest in that acreage, would you be tempted?
Steve Mueller
I don’t want to address that right now. We’ll just have to wait and see if we would be tempted or not if that ever happens.
Bob Brackett - Bernstein Research
Okay. Thanks Steve.
Operator
Your next question comes from the line of Charles Meade with Johnson Rice & Company. Go ahead with your question, please.
Charles Meade - Johnson Rice & Company
Good morning, Steve and to the rest of your team as well. Picking up on that point of Bob’s, I think I recognized the good reason you have to be reticent about the acreage.
But given that you’ve analyze this last week talking about that Wetzel County, Utica well coming on line and you presumably your working interest partner is looking at the same what proportions you are. I’m wondering if there is anything you feel you could bank on that?
Steve Mueller
There is activity going on in drilling and completion and all kinds of wall activity going on that acreage right now. We don’t own the acreage, so we can’t talk about it frankly.
It’s just one of those things. Once we go further down the road, we actually own it, we’d be happy to talk about a lot of things on that acreage.
Charles Meade - Johnson Rice & Company
That makes sense, Steve. I just thought I will probably give a shot.
Could we go back up to the -- if we can go back up to the Northeast Marcellus, the two things I’d like to ask about, that Wyoming well and what you are seeing on that north range acreage first. On the Wyoming well, I know you are still testing but can you talk about maybe what you’ve seen as far as the pressures you’ve encountered and the drawdown if you perceive that far on your testing and how that is fitting versus your expectations?
Steve Mueller
I can’t address both of them at the same time. Right now, we don’t want to talk about it and whether it’s farther north range and in the case of far north range, we are just in the early stages of getting production back soon and there is nothing to talk about.
In the case of Wyoming County, there is obviously a lot of other competitors around us and there is some advantages to keep all information quiet well.
Charles Meade - Johnson Rice & Company
We will see. I guess that makes me owe for two, so I call maybe good questions but good questions but bad timing maybe.
Steve Mueller
Ask in a few months and I will answer them all.
Charles Meade - Johnson Rice & Company
All right. Thanks a lot.
Operator
Our next question comes from the line of Joe Allman with J.P. Morgan.
Go ahead with your question, please.
Joe Allman - J.P. Morgan
Thank you. Hi everybody.
Steve Mueller
Hey, Joe.
Craig Owen
Good morning, Joe.
Joe Allman - J.P. Morgan
Hey, Bill, could you -- I know you covered this in some of your answers but could you go to both the Fayetteville and the Marcellus and talk about the standard completion designs you are using now and then what have you changed that you are seeing encouragement on early on? And also could you address these changes you are making -- how do you think they compare in an oil reservoir versus the gas reservoir?
Bill Way
In both areas what we are focused on are kind of three things. One, optimizing where we are landing in interval and right now in both areas, we think we’ve found a place in the particular interval where you get the best fracture initiation to begin that frac.
The second thing we are looking at is spending a lot of time on this profit volume. And so in Marcellus for example, we’ve gone in the past, probably 18 months or so from 250,000 to 300,000 pounds of sand per stage up to, as I said before, we are testing as high as 800,000 pounds of sands per stage and trying to determine.
We believe that the more sand we can get per stage into -- around the well bore, the better quality for that we get. We are trying to find really the end numbers on that, so that we can optimize it.
And then looking as we said before about, into the drill stage spacing and so that range so far has grown as I said early on, it was 250. I think this year, we sort of standardized around 350 to 500 and now we are going from 700 on up to 850.
In the Fayetteville, we are trying to do the same thing except the numbers are a bit different obviously. We were at about 65,000 pounds a stage before and we are going up to about 100,000 pounds.
We’ve got three tests going on in that right now. We don’t have any specific early results yet that where we want to land.
As I also mentioned, as part of this whole completion, there is flowback. And in both areas we rest these wells to try to keep the water in the ground.
In some parts of the Fayetteville, especially the deeper areas, we do get a bit more gas back then in -- otherwise the rest of the acreage is pretty much -- in the shallower areas, it’s pretty much, just the water doesn’t come back, so we save on operating cost. We will continue to share that knowledge back and forth between the assets and try to use this what is now 4,500 or 4,300 well database to the instruct us as well and to just see exactly where that goes.
Obviously, we have no real production in the oil side, but I know from our understanding of the industry, higher sand loading in some of the oil reservoirs are including well reserves in that space as well.
Steve Mueller
And well Bill was talking, we quickly looked up -- couple of us quickly looked up what the averages for this year. For the third quarter in the Fayetteville per well and again our stages haven’t changed much over the last couple of years, think about 115,000 barrels of water, about 4.2 million pounds of sand.
When you compare that to the Marcellus, it’s a 150,000 barrels so not much difference on a barrel side, but about 8.5 million pound of sand. So we are putting significantly more sand in the Marcellus.
So that -- and that just goes back to Bill’s comments, whether it’s the liquid in there or the rock itself, you have to design the fracs for that rock.
Joe Allman - J.P. Morgan
Okay. That’s right.
Helpful. And then as a follow-up, just moving to the Marcellus and production in FT, I am just curious what can you do to increase production beyond FT besides making a big acquisition in different area.
I am specifically asking about the Northeast. What can you do to kind of enable Southwestern to increase production even more than the 1.2 Bcf per day of FT you got lined up?
Steve Mueller
I think the answer at least for the last couple of years is you want to stay within your FT. And so we said several times between now and the end of the year, you will see and hear us commit to some other FT, that’s out there.
And as we do that, you will see how that ramps up and whether it’s this year, next year or beyond and how that works in the overall picture. But it’s really getting more FT up there at least for the next two years.
I think by time you get to 2017, certainly by 2018 that becomes a less of an issue. So other than that from our perspective anyway we are just going to follow FT.
Joe Allman - J.P. Morgan
Great. Thank you very much.
Operator
Our next question comes from the line of Dan McSpirit with BMO Capital Markets. Go ahead with your question please.
Dan McSpirit - BMO Capital Markets
Thank you. And good morning, folks.
Regarding the 1000 Upper Fayetteville Shale locations, how many of these locations meet the company’s economic hurdle at say sub $4 gas, maybe $3.50 NYMEX.
Bill Way
Yes. Those are same before.
It’s probably in the 250 to 300 range, maybe a little bit more than, that’s range. And then at $4 flat, that’s all 10,000 wells.
That’s what we usually talk about.
Dan McSpirit - BMO Capital Markets
Got it. And as follow-up, regarding the recent acquisition and your review of the assets and operations, can you sketch for us where maybe efficiency or effectiveness gains can quickly be achieved.
Maybe put differently, what are the easy levers to pull to drive better returns at the field level than what maybe the prior operator achieved?
Steve Mueller
We certainly have some ideas, but until we get out there and actually get on the ground, they are just ideas. I think the key is, we are not going to start out of the box fast and that’s why we talked about the fact we start ramping up the five rigs and then work it up to 11 rigs over 2.5, 3 year period of time.
We don’t know exactly what we can do. As I said, we have the ideas, but what we are concentrating on today is doing all the due diligence towards closing and getting answers from the partner on pref right.
So that’s a question probably to ask towards the end of the first quarter.
Dan McSpirit - BMO Capital Markets
Good. Thank you.
Operator
Our next question comes from the line of Brian Singer with Goldman Sachs. Go ahead with your question please.
Brian Singer - Goldman Sachs
Thank you. Good morning.
Steve Mueller
Good morning.
Brian Singer - Goldman Sachs
This may have been asked earlier. Apologies.
But can you just talk about how you’re thinking about capital commitments to exploration, A? And then, B, when you think about non-core opportunities, is there value in any of the historically exploratory areas or are you kind of waiting to create value there?
Bill Way
Yes. Start with exploration in general, we think that’s important to do and we will today and continue in the future doing explorations.
Now certainly with the acquisition, we may slow down a little it from the pace we’ve been in the last year or two years and invest little bit less in 2015 and ’16, maybe ’17, but we will do exploration. Then the question of how that fits in and what you do with the explorations has to do with the risk on the exploration project early on and then what you find later on.
And if it’s high risk with significant upfront capital commitments, going back to earlier discussion, we may bring partners in. If we have a discovery and that discovery -- depending on the economies of discovery, we will slot it in as we need to slot it in.
And in some cases that may mean bringing a partner and to help us on that part too. So it’s going to depend on the project, the kind of projects we have and whatever we discover, but we will continue to do exploration.
Brian Singer - Goldman Sachs
Great, thanks. And then as a follow-up, have you had or engaged any of the potential LNG consumers regarding their interest, either in upstream positions in areas like the Fayetteville or the Marcellus?
Steve Mueller
We have talked to a lot of different groups. Some of them here have or want to have LNG positions, others are our utilities and others are end-users and still others are some kind of industrial.
And there is all kinds of different wants and demands and timings on those things, but we have taught to them we know generally what the market is. I don’t know if there is something else to your question.
Brian Singer - Goldman Sachs
More in the context of opportunities beyond funding for the acquisition with just debt and equity, really trying to identify what the asset sale potential and whether that’s an avenue for you?
Steve Mueller
We will talk more of that in the future, but certainly anything that we have if we can get the right value for it, we are going back to the partner questions or anything else. We are willing to look at it and talk about it with whoever is out there.
It’s just -- that’s something to catch or capture as it comes out.
Brian Singer - Goldman Sachs
Thank you.
Operator
Our next question comes from the line of Biju Perincheril with Susquehanna Financial Group. Go ahead with your question please.
Biju Perincheril - Susquehanna Financial Group
Thank you. Good morning.
Steve, some question on your Fayetteville firm transports, can you give us some idea of the sales contracts you have associated with those firm transports? What the duration of those contracts are?
Steve Mueller
Kind of put in general perspective, Fayetteville Shale has been producing, this is the 10th year anniversary on it. So we have a couple different agreements for transportation, one with the Kinder Morgan and one with Boardwalk.
They start expiring in probably 3.5, 4 years and the first one would be Boardwalk, these are 10 year terms and the next the Kinder Morgan would be another 1 year, 1.5 year past that. Actual commitment is just over 2 Bcf a day, it’s about where we’re at right now.
And it’s I think $0.26 or $0.27 is what the transportation fee is average.
Biju Perincheril - Susquehanna Financial Group
Perfect, great. When you said 3.5…
Steve Mueller
Those two pipelines together add up to over 4 Bcf of total takeaway and that was going back to the comments earlier that we had plenty takeaway. The industry has taken just a small percentage of that and so there is plenty to takeaway if we want to go fast and save them.
Biju Perincheril - Susquehanna Financial Group
Got it. And then the 3.5 to 4 years, that’s the FT itself or is that sales contracts under those FTs?
Steve Mueller
We’re at the FT.
Biju Perincheril - Susquehanna Financial Group
Okay. Got it.
And then another question was on the midstream. If you work to monetize it hypothetically speaking of course, did you do already breakdown -- give a segment breakdown in your reporting?
So would there be any impact to the reported cost structure for the upstream business?
Steve Mueller
We in our upstream side of that, we count the gathering fee and our LOE. So when you look at our $0.91 LOE, there is roughly $0.60 of that that’s gathering.
Biju Perincheril - Susquehanna Financial Group
All right. That is being paid to I would imagine in the Fayetteville, Southwestern midstream.
Steve Mueller
Whoever is gathering the gas for us is going to pay that way, yes.
Biju Perincheril - Susquehanna Financial Group
Right. So if you were to separate the midstream business, there would not be an impact on the upstream cost structure as it is reported today.
Is that correct?
Steve Mueller
On the pure upstream cost structure, no. On the actual reserve life, yes.
Biju Perincheril - Susquehanna Financial Group
Can you give us a little more why on the actual reserve life?
Steve Mueller
Well, when you are on the -- for instance, I want to run, whether I keep the well producing or not, as long as within my company, I’m going to back out that gathering fee when they do that calculation. If it’s not my company, then it’s actually going the money out the door and the reserve life gets cut off earlier.
So yes, we accounted for it, but on any well it’s marginal, you don’t -- you’re going to have to back that back out again.
Biju Perincheril - Susquehanna Financial Group
Okay. Anyway to quantify what that would be to if you were to look at your (indiscernible)?
Steve Mueller
Why are these questions, when and if do some of the midstream? In a few weeks we’ll tell you what we’re going to do financing wise.
And if midstream is part of that, you can ask all the questions you want.
Biju Perincheril - Susquehanna Financial Group
That’s fair. Thank you.
Operator
Our next question comes from the line of David Heikkinen with Heikkinen Energy Advisors. Go ahead with your question please.
David Heikkinen - Heikkinen Energy Advisors
Good morning, Steve. And just about an hour or so.
One quick question on fourth quarter guidance, do you have any updates or thoughts on volumes for the quarter?
Steve Mueller
No. We didn’t bother to change that any of the -- as Bill said, we’ve got the new capacity coming on in the Marcellus, so that production will continue to go up and Fayetteville's performing well.
So if I had to guess, we’re on the high side of that number, but for the couple of months, we just didn’t bother with it.
David Heikkinen - Heikkinen Energy Advisors
And then just couple units that here realized price in the Fayetteville and I think you said that you’re expecting the cut a day from your drilling days in the Fayetteville. You’ve been 6.8 year-to-date.
So you would be about 5.8 for next year. Is that only on the new rigs?
Steve Mueller
That’s really on the new rigs, but it will have a five on it probably.
David Heikkinen - Heikkinen Energy Advisors
Okay. Cool.
And then realized price just in the quarter for Fayetteville. You said the Marcellus was 273, I believe.
Steve Mueller
Right. The Fayetteville is 351.
David Heikkinen - Heikkinen Energy Advisors
351. Okay.
Thanks.
Operator
Our next question comes from the line of Scott Hanold with RBC Capital Markets. Go ahead with your question please.
Scott Hanold - RBC Capital Markets
Yeah. Thanks.
Good morning. Really, quickly, remind me, are you guys still running eight rigs in the horizontal rigs in the Fayetteville?
And if you did get you well drill time down or your rig did down by one? Is the plan still to operate within cash flows that’s reducing the number of rigs in that area?
Steve Mueller
We are still running eight and the rest of the questions come 2015 budget and we’ll talk about that in couple of months. I hate to say this all the time, but unfortunately, this quarter is at the wrong time and needs to be about three or four weeks from now.
Scott Hanold - RBC Capital Markets
Fair enough, guys. I’ll leave it at that.
Thanks.
Operator
Thank you. Ladies and gentlemen, we have reached the end of our allotted time for questions.
I would like to turn the floor back over to Mr. Mueller for closing comments.
Steve Mueller
Thank you. I ended up my comment earlier about talking, about not being a call on gas, but being a call on quality.
Certainly, this quarter again shows the quality of our assets and what we’re going to able to do with those assets. And it’s not about the growth.
It’s not about size. But it’s about understanding and hopefully -- and I know a lot of the questions were about understanding, understanding what we’re doing differently and we’re learning and what we want to see differently.
That brings me, kind of to, who we are and what we do. We have three main strategies.
The first one is, develop our current assets better than anyone else can. The second one is learn quickly and then apply that learning rapidly.
So we don’t just create learning at a linear pace but we create at an exponential pace. And then the third one is to remain positive and how we do our work and how we engage the communities and that has do if we remain positive and what we do as lot of (indiscernible) emissions.
And then certainly, how we work with regulators and the various communities we are working. When you think about that, each one of those strategies has something that goes up and beyond.
And we call that value plus and that’s what we try to deliver. And whether it’s a new acquisition or it is exploration or it’s our whole core assets that have all that strength that has in the pad that’s what we’ll do.
As I’ve said many ways in the past, our success is not based on growth rates, it’s not size. But it’s that curiosity that leads to innovation and coupled with the disciplined approach to delivering above average economics.
The outcome and I want to emphasize that the outcome of doing that everyday is the improvement, the quality, the growth and the other things that go with it and you’ve seen that what we’ve done this quarter. Our pledge to you is that we’ll continue to learn.
We’ll continue to be curious and we’ll continue to be disciplined. And if we do that, we’ll have many more quarters just like today.
Thank you for listening today. Have a great weekend and that concludes our teleconference.
Operator
Thank you, Mr. Mueller.
Yes, this does conclude our teleconference. You may disconnect your lines at this time.
Thank you for your participation. Have a great day.