Southwestern Energy's (SWN) CEO Steve Mueller on Q2 2014 Results - Earnings Call Transcript

Aug. 1.14 | About: Southwestern Energy (SWN)

Southwestern Energy (NYSE:SWN)

Q2 2014 Earnings Conference Call

August 1, 2014 10:00 a.m. ET

Executives

Steve Mueller – Chief Executive Officer

Bill Way – Chief Operating Officer

Craig Owen – Chief Financial Officer

Analysts

Douglas Leggate – Bank of America Merrill Lynch

Michael Rowe – Tudor, Pickering, Holt

Brian Singer – Goldman Sachs

Joe Allman – JPMorgan

Charles Meade – Johnson Rice

Bob Brackett – Sanford Bernstein

Dan McSpirit – BMO Capital Markets

Rehan Rashid – FBR Capital Markets

Gil Yang – DISCERN

David Heikkinen – Heikkinen Energy Advisors

Drew Venker – Morgan Stanley

Operator

Greetings. Welcome to the Southwestern Energy Company Second Quarter 2014 Earnings Teleconference. At this time all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation. (Operator Instructions). As a reminder, this conference is being recorded.

It is now my pleasure to introduce your host Steve Mueller, Chief Executive Officer for Southwestern Energy Company. Please go ahead, sir.

Steve Mueller

Thank you and good morning. Thank you for all of you joining us today. With me today is Bill Way, our Chief Operating Officer; Craig Owen, our Chief Financial Officer; Jeff Sherrick, Executive VP of Exploration and Business Development; and Brad Sylvester, our VP of Investor Relations.

If you’ve not received a copy of yesterday’s press release regarding our second 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.

We had a top tier second quarter led by solid performance from our core Marcellus and Fayetteville shale assets which continued to deliver more production with less capital. Because of this ongoing efficiency we have raised our production guidance for the second half of the year. We will invest approximately $280 million in a new project in the Niobrara formation in the Sand Wash basin, and have increased the total capital by only $75 million. Craig and Bill will give more details about these areas in a few minutes. I want to spend little time talking about our thoughts on gas price.

Remember – you may remember that we based our 2014 capital plan on $3.75 NYMEX gas price and last quarter we stated that we want to watch the storage fill through the summer before talking about or possibly changing our guidance for capital budgets.

As it stands today, the storage is filling at a pace to reach acceptable levels going into the winter and now that now that we can see or begin to see beyond the effects created by the cold winter of last year, we are comfortable the fundamental NYMEX gas price going forward should be above $4. We still believe this will be the most difficult summer for pricing in Marcellus shale and SWN is building a viable portfolio of firm capacity and hedging to allow us to thrive in both today’s pricing environment as well as a potential volatility over the next few years.

In addition since first of the year we’ve been approached by several entities regarding long term contracts to fill the growing demand. Craig will talk a little about this but I want to mention three aspects for your consideration. First, long term contracts to end user deals -- and end user deals are being done for demand as early as 2015.

Second, both the SWN’s major producing areas are prime positions for taking advantage of this new demand. And third, Southwestern’s investment grade and our concentrated assets allow us to be one of the preferred providers for many of these major projects.

With that, I will now turn the teleconference over to Craig for an update on second quarter results.

Craig Owen

Thanks, Steve and good morning everyone. As Steve mentioned, our results in the second quarter were outstanding, primarily driven by higher product volumes. Excluding certain non-cash items, we reported record net income of $207 million or $0.59 per diluted share for the second quarter compared to $190 million or $0.54 per diluted share for the second quarter 2013.

Our cash flow from operations before changes in operating assets and liabilities was $579 million, up 18% compared to this time last year. Operating income for our exploration and production segment was $275 million, up % from the $253 million we reported in the second quarter of 2013, primarily due to higher production volumes offset slightly by lower realized gas prices, and an increase in operating costs and expenses due to increased activity levels.

Including hedges, we realized an average gas price of 3.77 per Mcfe during the second quarter, which was down from 3.87 per Mcf in the second quarter 2013. Excluding hedges, we realized an average gas price of 3.58 per Mcf in the Marcellus and 4.11 per Mcf in the Fayetteville. When considering the impact of settlements from our financial basis hedge program, our realized average price in the Marcellus was 3.66 per Mcf for the quarter.

Our gas marketing team has had good success in securing additional firm sales agreements which along with our financial basis hedging activities protects 58% of our Marcellus production for the remainder of 2014 at NYMEX minus $0.12 per Mcf, excluding transportation charges.

Currently we also have about 30% of our 2015 Marcellus margins protected with financial basis hedges and firm sales agreements at a price of NYMEX minus $0.14 per Mcf, also excluding transportation charges. We currently have 233 Bcf or approximately 60% of our remaining 2014 projected natural gas production hedge to fixed price loss 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.

To date we have approximately 1 Bcf for day affirmed sales contracts in place with LNG and other utility and industrial customers for Fayetteville Marcellus Gas that have an average price of NYMEX minus $0.06. These contracts include significant multi-year contracts. One that begins later this year at 100 million cubic feet of gas per day and one that begins on 2015 also at 100 million cubic feet of gas per day. Approximately 88% of the volumes associated with these sales contracts are sourced from the Fayetteville.

On the cost side, our cost structure continues to be one of the lowest in our industry with all in cash operating costs of approximately $1.29 per Mcfe in the second quarter of 2014 compare to a $1.24 for Mcfe last year. That includes our LOE, G&A, net expense and taxes.

Least operating expenses for our E&P segment were $0.90 per Mcfe in the second quarter, up from $0.85 per Mcfe last year, primarily due to higher gathering costs associated with our growth in the Marcellus Shale and an increase in compression costs. Our G&A expenses were $0.23 per Mcfe, down from $0.24 per Mcfe a year ago and were lower due to a larger increase in productions volumes than in personnel costs. Taxes other than income taxes were flat of $011 per Mcfe, and the full cost pool amortization rate in our E&P segment was $1.09 per Mcfe compared to a $1.05 last year.

Operating income from our midstream services segment rose 27% to $93 million in the second quarter, compared to the same quarter in 2013, primarily due to increase in gathering revenues from our Fayetteville Marcellus Shale place. Mid-stream EBITDA also surpassed $100 million, a company record and rose 26% to $107 million in the second quarter compared to the same period in 2013.

At June 30, 2014, our debt to total book capitalization ratio was 31%, down from 35% at the end of 2013 and our liquidity continues to be in great shape with only $172 million borrowed on our revolving credit facility at June 30. We currently expect our debt-to-total book capitalization ratio at the end of 2014 to be approximately 28% to 30% at current share prices.

I am proud of our second quarter results and excited about the future. 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. Our second quarter was outstanding. We again set production records as our results in the Marcellus Shale continued to deliver exceptional growth. We also had one of our best quarters ever in the Fayetteville as we were able to place on production, several recent new wells with impressive initial rates including a record well at over 14 million cubic feet of gas per day.

We remain really encouraged about opportunities that lie ahead of us in our exploration projects which I’ll cover in a few moments. I’m extremely proud of all the hard work and relentless commitment to adding value that all of our employee teams have across the company to continue to work together and deliver these results.

To begin with the Marcellus Shale, our production of 61 Bcf in the second quarter grew by 80% over our volumes produced in the second quarter of 2013. We now expect to beat our original production forecast from this area, while at the same time drilling about ten less wells than we originally planned and finish the year with two rigs running with one flat crew. As a result our Marcellus business will require approximately $60 million less capital than originally forecast to deliver this improved volume performance.

We are continuing to have encouraging results as we move north and east in our range area in Susquehanna County and during the quarter we drilled two northern most wells in the county to-date which reached the farthest northern boundary of our acreage at the New York State border. Formation thickness and pressures have surprised us to the upside as the thickness of this area of the lower Marcellus is well over 100 feet, and the pressure gradients are higher than we originally thought. These latest results are very encouraging and we will keep you posted on our progress in this area of the county.

We’re continuing to test acreage in Wyoming and Sullivan Counties and are currently drilling our first horizontal well in Wyoming County, the Dimmig 2H which is planned to be tested in the fourth quarter. Three vertical wells have also been drilled in Wyoming and Sullivan County to help delineate our acreage.

We’ve begun testing the upper Marcellus formation and our first well, the Pristine Perkin 7H located in Bradford County is drilled. Our next three upper Marcellus wells are planned to be drilled by the end of the third quarter and all four of these wells are planned to be completed in the fourth quarter.

In mid-stream we are moving 744 million cubic feet of gas per day in the Marcellus Shale at June 30th, and transporting the gas through our firm transportation capacity to market. We continue to work on adding to and improving our portfolio from a transportation capacity out of Pennsylvania, which totals under contract to more than 1 billion cubic feet of gas per day by year end and increases to almost 1.2 billion cubic feet per day in 2016. We’ll update you on our progress as the year continues.

Moving on to the Fayetteville Shale, we had one of our best quarters in the company’s history related to well performance and initial production rates and placed a total of a 145 wells online at an average initial production rate of roughly 4.4 million cubic feet per day, a rate which over 20% higher than a year-ago levels.

Our second quarter results include 7 out of the top 10 highest IP rate wells and included four wells which had peak rates in June ranging to 13 million to 14.1 million cubic feet per day of gas. You may recall that at this time last year the highest rate well in the Fayetteville was recorded at 8.7 million cubic feet of gas per day.

We also continue to test the upper Fayetteville formation and to date we have drilled a total of 45 wells. We drilled 15 Upper Fayetteville wells to the first six months of this year. Several of these wells are still choked and are continued to clean up, however six of these wells had an average initial production rate over 4 point million cubic feet of gas per day, with the highest initial production rate being 6.3 million cubic feet of gas per day.

We plan to drill and complete five additional upper Fayetteville wells later in the year. Our vertical integration in the Fayetteville continues to be a key value adding component of our strategy going forward and a significant benefit to us resulting in an average savings of approximately $437,000 per well or 15% of the total well cost of every well in the second quarter. Additionally our third of seven new drilling rigs began drilling this month and results from these first three rigs to-date are exceeding our expectations.

In Mid Stream, as Craig mentioned our large position in Fayetteville is gaining considerable attention from current and future long term sales customers and we continue to work on adding to our long term sales portfolio. Our gas gathering business is gathering and transporting approximately 2.3 billion cubic feet of natural gas per day at June 30th. We have additional transportation capacity to deliver any growth from our acreage in the play and we are positioned well, very well to supply future long term gas demand from our Fayetteville asset.

Moving on to exploration, we began completion of our first vertical well in North West Colorado, targeting the Niobrara formation. The Welker well earlier this week and are currently drilling our second of four vertical wells planned for the year. Our first horizontal well in the area is planned to be on production by year end. We look forward to what we have to learn in this new exploration play and will be reporting more of our plans going forward here in December.

In our Denver-Julesburg Basin oil play in Eastern Colorado we are completing our third well targeting the Marmaton and Atoka sections and will have results from this well in the fourth quarter.

In closing we have had extraordinary results to-date from an extraordinary team of people. There is more to come in 2014. I look forward to sharing those with you as the year progresses. This concludes my comments and I will turn the call back over to the operator who’ll explain the procedure for asking questions.

Question-and-Answer Session

Operator

Thank you, we’ll now be conducting a question-and-answer session. (Operator instructions). Our first question comes from the line of Doug Leggate with Bank of America Merrill Lynch. Please proceed with your question.

Douglas Leggate – Bank of America Merrill Lynch

Thanks, good morning Steve and good morning everybody. Steve, the very strong results in the Fayetteville, as I understand it, are in an area that I guess had previously not been quite as prospective as the broader position you have in the play. I am just wondering what exactly has changed there in terms of -- I mean, there has obviously been a very significant step up, I guess you said in the release seven of the best wells in the company's history. So I'm just curious as to how much running room over your portfolio backlog do you think you have that could be repeatable to that extent or if these are somewhat isolated? And then I have a quick follow-up, please.

Steve Mueller

When you think about what we’re doing on Fayetteville we are just looking in more detail in smaller and smaller areas and so there’s three major things that are going on and they’re , some overlap and some don’t overlap. First one is, we’re just the bottlenecking the very things at the surface and that’s allowed us to see higher rates and part of the field where you had little bit higher pressures. Second thing we’re doing is what we call extended shut in. Again some of the field has more water than other parts of the field. Extended shut in has decreased that water and then the third thing is just we’re finding some areas that has got some good geology that either we hadn’t tested before or we hadn’t tested correctly before as well with procedure doing. The end result to that is the three areas don’t quite overlap. There are some that do overlap. But if you had to guess over 600,000 acres that we’re drilling on, somewhere between 80 and 120, 150,000 has a potential for one or all of those things to happen.

Douglas Leggate- Bank of America Merrill Lynch

That’s really helpful, Steve, an unrelated question, you mentioned the long-term contracts. I'm just curious, given the position you have, we hear a lot of chatter that the level of interest for long-term -- forgive me for this one, LNGX contracts, it seems to be gathering a little bit of momentum. I am just curious as to whether you have seen any of that, whether you would be prepared to participate and whether you would think about it at this point.

Steve Mueller

When you think long term contracts last couple of years we’ve been asked very regularly what’s going on and there’s a lot of talk and not many contracts and it seems here recently you start to get more different types of groups wanting contracts and they set for fairly short term. They start building out and trying to figure out what they’re going to do in the near future. The one, we do have a contract with an L&G provider. So they are out there and they’re starting to make those contracts and I think most what we’re doing right now is on the power side with some industrials along with the L&G.

Douglas Leggate- Bank of America Merrill Lynch

Care to give in detail Steve?

Steve Mueller

That’s about all the details we’re going to go into.

Douglas Leggate- Bank of America Merrill Lynch

Thanks very much. I appreciate it.

Operator

Thank you. Our next question comes from the line of Michael Rowe with Tudor, Pickering, Holt & Co. Please proceed with your question.

Michael Rowe – Tudor, Pickering, Holt

Hi, good morning. I guess you just mentioned on the first question kind of some of the things you’re trying Fayetteville to really increase the IP rates there in the initial production. Was just wondering do you think that you’re doing on the completion side that could enhance the economics there. You’ve had a lot of success in the Marcellus by increasing the amount of sand from 350,000 pounds to 500,000 pounds per stage. So just curious kind of where you sit in Fayetteville today and do you have any changes to, any plans to change that?

Steve Mueller

We continue to learn in the Fayetteville, and early learnins we had in Fayetteville we apply back to Marcellus and vice versa. Marcellus sand is up and that it wasn’t fast – by not up in the same percentage of Marcellus shale and when I say that I say it in very general terms. As we think about the Fayetteville and talk all these plays, there is lot of differences across the play. So it’s well spacing, amount of sand, exactly where you land it, how far your fracs going out. That varies across all these plays. I think what we’re doing for Marcellus or which is a little bit behind at least learning some years we have been in Fayetteville we’re fine tuning them in various areas is really what’s happening. As we fine tune that we’re getting better wells along the way. So it was, there’s no magic formula. In general we’re putting more sand in the ground, but that’s not either across Marcellus or across Fayetteville, just a standard. There are certain areas of more single work, others don’t necessarily need it.

Michael Rowe – Tudor, Pickering, Holt

Okay, that’s helpful. And then just switching gears real quick to the Marcellus. You all mentioned you going to hit 1.1 Bcf per day for some transport in 2015 and 1.2 in 2016. So just thinking kind of about this year you’re spending about $60 million less capital to kind of hit the same production in 2014. So just wondering on a go forward basis what amount of capital do you all think you need to spend to kind of keep production flat or maybe modestly increase it in line with your firm transportation capacity?

Steve Mueller

You don’t need many wells to keep production flat, so it’s not a lot of capital and I don’t know if we’ve even thought about that on Marcellus frankly. As you think going forward, as Bill said we’re still trying to add more capacity and we’ll talk about that 2015 and how fast we go and how fast, we go in 2016 as we get close to those. But just think about it, you’re only drilling 60-70 wells this year and you’re growing Marcellus at a very quick pace. So I don’t know how many its 20 wells or 30 wells total. It’s a small number and we keep it flat.

Michael Rowe – Tudor, Pickering, Holt

Okay, thanks a lot.

Operator

Thank you. Our next question comes from the line of Brian Singer with Goldman Sachs. Please proceed with your question.

Brian Singer – Goldman Sachs

Thank you, good morning. I wanted to follow-up on Doug Leggate’s Fayetteville discussion. If you highlighted seven of the ten best wells you’ve drilled, we’re done there in a quarter, but there are 140 other wells during the quarter. It seemed like the well performance was not that dissimilar on an average to some of the other quarters we’ve seen. When you think about the new procedures and the application to new acreage that you highlighted, do you see that as driving improving IP relative to cost going forward throughout the program or is this more an offset to maturity offer?

Bill Way

Well I think the improved performance we’re getting out of these wells is – the cost to do that is very limited. I mean we’re actually putting in shorter tubing lengths which cost less obviously because we’re not tubing up the whole well. We rest all of our wells as a matter of frac just now. So there’s not a cost to doing that. And so I think the major difference will be lateral length, that that will be across the entire field and it flexes up and flexes down depending on the unit size. So in terms of capital efficiency, the more of these higher rate wells and as the averages move up, our well costs are not moving up materially, except as you adjust them for again lateral length and some of the less tested areas we have the opportunity to drill longer laterals. That’s a much more efficient way to work. So you actually have the opportunity to bring some additional cost down and when you combine that with our new rigs and the fact that they’re more efficient then our older rigs, just as the new generation. We actually see opportunities to improve margin curve both in the cost side and on the new well performance side.

Steve Mueller

And I think part of your question was you’re not seeing the whole group of, already fixed they’re rates higher. These wells have only been on for a short period of time and its about 15% of total wells we drilled in the last six months or in that where we’re doing all these things to them. We’re assuming right now internally that it’s all acceleration except for where we talk about the geology. But that’s not bad. You’re going back to your cost part of it. We think on PV 10 basis we’re adding a little over 10% PV10 by accelerating growth forward. So internally we’re seeing full acceleration. We’ll be able to you probably in six months whether it’s in the actual incremental reserve to do with it.

Brian Singer – Goldman Sachs

Great, thank you and then shifting to the Marcellus, is there any update you can give with regards to drilling in the north, north-east portion of your Susquehanna County?

Bill Way

Yeah, we basically went back and re-entered the pilot hole recently. We drilled a 4981 foot lateral and put 14 frac stages on it. We’re using our higher level sand content which is 500,000-530,000 pounds of [indiscernible] per stage. Right now we’re just in flow-back operations, but what we see is – what we’ve seen we’re encouraged , so we are going to complete the 3D study of that area as well, probably 100, little bit over 100 square miles, and then we will retest this well in a few weeks after it has been able to rest and then we are looking for some additional wells to drill in that area and we’ve got a few of them planned.

Operator

Our next question comes from the lien of Joe Allman with JPMorgan.

Joe Allman – JPMorgan

So Steve you beat the high end of production guidance five quarters in a row and is a main driver of flatter Marcellus production curve.

Steve Mueller

I don’t mind. It’s probably the minus [ph]. The Fayetteville, certainly if we look there, we’ve added almost every quarter a little bit of BCFs to our guidance that certainly Marcellus is a shale better than we thought and the wells are better performing.

Joe Allman – JPMorgan

Got you, okay. And then a second question on the Sand Wash. Could you talk about just the timing of the results of the five wells you’re planning this year and the timing I never mentioned. It’s based on the results. But in your mind right now, what’s the timing of a go or not go decision for this play? And then also could you talk about any surface issue? I think we’re operating maybe in or around some Sage-Grouse nesting areas and if you talk about permitting and any other insights you have on this play?

Steve Mueller

I’ll let Jeff share a talk about that. He is in charge of project. Go ahead, Jeff.

Unidentified Participant

Yeah. Really, the first acreage trans that we picked up was in May of this year and we’re actively out there now. We had [ph] drilling [ph] location. We drilled one well. We continue to drill through a pre-planned program at least for Verticals as we go through the end of 2014. Our goals are about the end of the year there are just two drill wells, horizontal well and at that point in time get a flow test to see how the overall program looks. So I would say for looking to our early results we would be reporting on this in the early part of 2015 with information that we could be more definitive about. With respect to surface issue in particular the Sage-Grouse question which you brought up, there is no question and this is an area that you have to work and get the plan and get ahead. We’ve been able to do that just in the first three months. We don’t think that there’s going to be a surface restriction on slowing down our current plan, program that we have progressed this year in early part of 2015. I will continue to work on that real hard and we think we can have a very active program up here provided that we see the results of our team.

Steve Mueller

Yeah, as far as the Sage-Grouse go, they are there in the area that always is not conducive to Sage-Grouse but certainly part of it and we’re working with the industry just like everyone is sticks on Sage-Grouse to figure out how to mitigate or somehow allow us to drill and still keep Sage-Grouse in good shape. So that sum has just [ph] from.

Operator

Thank you. Our next question comes from the line of Charles Meade with Johnson Rice. Please proceed with your question.

Charles Meade – Johnson Rice

Yes, good morning everyone. I’d like to ask a question dealing bit on them. One is the upper Fayetteville test. You guys have mentioned 60 wells or on at a rate of 4 million a day. If you look back in how they compare to against your historical table, that’s only exceeded by your last four quarters for the play. And so I guess does it really look like positive well results? And why don’t if you could break down, how much if that is lateral link there or completion design and how much of that is perhaps be your resting [ph] or the remainder might be or the other explanation might be that the quality of the formation?

Steve Mueller

One of our chief objectives in drilling this upper Fayetteville test and we’ve been working on this for some time was the ability to stay in zone in a more brittle zone of this particular part of the formation and we spent a lot of time and a lot of evaluation and lot of testing trying to make that happen and with technology as its advance and our monitoring of these wells as are being drilled continuously, we’ve been able to achieve that. And by doing that, the area where we initiate tracks is a bit more brittle. The ability to have that kind of a higher quality frac throughout the entire interval has produced the kind of results we’re seeing and we tracked this on every well. Certainly, we rest and certainly we are using the completions that we believe are fit for this particular type of rock in this particular type of area just like for doing along the others. They don’t vary materially, but it’s more about staying in zone in a particular part of the zone that we are in. We’re trying to really optimise within a fairly narrow window and we’ve been able to achieve that.

Bill Way

Let me add to that. If you ask us year and half ago, two years ago staying in zone plus or minus 25-30 feet was staying in zone. Today, when we said stay in zone, it’s less than 10 foot and in some case we’re trying to stay 5 foot and we’re doing it very successfully to both Fayetteville and Marcellus on 80% of 5000 for lateral. So we’ve done the lot and because of that lot of different things get better as you go to as well.

Charles Meade – Johnson Rice

That makes sense. I guess the natural follow-up of that would be.. Is there similar opportunity to target up 5 or 10 window, in the lower Fayetteville? Is there just something that there is a particularly attractive really thin member in the upper Fayetteville that you look after that?

Steve Mueller

It doesn’t have to be. It quite is tight in the upper, but we’re doing it in the lower, we’re doing it in the Marcellus and we’ll talk about it more. There are some other zones. We’re testing it both for Marcellus and Fayetteville. We’ll talk more about it in the future that we’re doing it.

Charles Meade – Johnson Rice

I got it.

Unidentified Speaker

With two large core assets that we have, we’re able to transfer knowledge and learn even faster and then transfer those learnings back and forth between the divisions and please see the results that come from.

Charles Meade – Johnson Rice

Right. And if I could just speak one more, can you -- but these good results you’re having now in the Fayetteville in the basis issues temporary, though they maybe up in the Marcellus. Can you compare what your PBI [ph] looks like for some of the recent village, Fayetteville wells versus the Marcellus at this point?

Steve Mueller

I just made general comment. The very best Fayetteville wells certainly match with the better Marcellus, but on average with the fracs we see today and not to surprise we see going forward Marcellus has a still little bit better economics.

Operator

Thank you. Our next question comes from the line of Bob Brackett with Sanford Bernstein. Please proceed with your question.

Bob Brackett – Sanford Bernstein

I have question on the extended shut-in, which I think I have asked variations of before. As you see these wells flow longer, how do you think about that ratio of IP to EUR? Do you get a sense that you’re getting the volumes faster so it’s more economic or you actually following the old tradition of decline curve and then a follow-up.

Steve Mueller

We have some examples where.. And again we don’t have a long period of time with some longer wells. We have examples of what it looks like. There are some incremental EUR that you’re going to get in addition to just getting the higher rates to begin with, but we don’t have enough information to say that that’s really going to be the answer. Some wells certainly look like getting some more EUR.

Bill Way

And then on a margin basis, we continue to get the benefits on the cost side for the water [ph] not being need in the handle, which is costing [ph] $100,000 a well.

Bob Brackett – Sanford Bernstein

Yeah. And then a quick follow-up. You talked about sort of advances in direction of drilling. Can you talk about sort of what state-of-the-art 3D seismic for this Shale placed for you all?

Steve Mueller

I don’t know that we have an answer on state-of-the-art 3D seismic. I can tell you that we are headshot and are going to show some more three components, surveys and we have done some more per shares, We have done some of shares well but.. I think we’re like here everyone. The costs are going down, you’re putting more geophones on the ground, you’re hearing more information and were doing there just like everyone has in the 3D.

Bob Brackett – Sanford Bernstein

Okay.

Steve Mueller

Thanks.

Operator

Thank you. Our next question comes from the line of Dan McSpirit with BMO Capital Markets. Please proceed with your question.

Dan McSpirit – BMO Capital Markets

Thank you, folks. Good morning. Could you comment on the cost of firm transportation in the Appalachian Basin today and what’s expected to do with the balance of this year? And it worked thrice as it didn’t make economic sense for Southwestern to secure additional firm transportation.

Steve Mueller

Well. Our long-term average transportation is about $0.37 and so that’s the range that we’ve had for the Appalachian Basin. As we look in the future, some of the new projects out there have a fairly high cost and you have seen some as high over a dollar. Those go all the way back to the Gulf Coast. You probably won't see us participating in a lot of that because that gas will go right by the Fayetteville and we will just sell gas if we want to do that. So our cost in general, we think going back in the Mid-Atlantic there is some room for some more demand. That's where the big demand is coming up the next four or five years. We can get there much cheaper than that. Today I would say most of what we're looking at is between 40 and maybe as high as $0.65 we are looking at going forward.

Dan McSpirit – BMO Capital Markets

As a follow up to that, just on the subject of long term contracts within LNG provider as you state, what does that tells about your view on the price of natural gas longer term if the company is willing to sell gas under these longer term contracts.

Steve Mueller

Well, I won’t go into the terms of the contract but I can assure you that we haven’t fixed it.

Operator

Our next question comes from the line of Gil Yang with DISCERN.

Gil Yang – DISCERN

So it’s a little hard to tell but it looks like the working interest for your gas in the Marcellus sort of jumped up a little bit for the gross gas in the quarter, is that fair to say or is that – may I reading the numbers little bit wrong?

Craig Owen

Yeah it did, it did come up just a little bit and it just depends on the mix of wells and where we happen to be producing at the same, certainly – by way of example you can look at our acreage evolved Chesapeake and some of that is on wells that are on acreage that we already own and so it’s by nature a raise it.

Gil Yang – DISCERN

Is there a sort of tactical effort to.. Given your firm transportation commitments, is there tactical effort to increase the working interest so you can actually get more net gas or that not really a consideration?

Steve Mueller

Well. We always try to give much of going news [ph] as we can. So we’re always working at that and we -- Marcellus and Fayetteville shale we have ongoing land capital budget every year that we do that with. So we’re always trying to get our net up. I don’t know that it’s necessarily side to firm anything other than that, we’re going to operate it we like as much as we can.

Gil Yang – DISCERN

Okay, so it’s just standard operating procedure?

Steve Mueller

Exactly.

Gil Yang – DISCERN

Okay. Second question I have is that there does seem to be very wide swing in the quality of wells you’re drilling in the Fayetteville, much stronger sort of mid to the second half of the quarter versus the first half, it looks like. If you look at your drilling portfolio for the rest of the year, how would you evaluate that in terms of the quality of the completions? Are they going to be more like what we thought early this year or more like what we saw end of last year?

Steve Mueller

That’s dynamic, yeah, and we certainly have a schedule actually goes until middle of next year, but rigs are brought across the field and as a reminder everyone shallow north side of the fields is significantly different production profile than deep southern side of the field. When you get several of these high rig wells together, you will overload the Midstream system and so you have to move a rig out and move to different area and that maybe a medium, maybe a little bit less production and swing back in. So the goal is to produce much gas we can to keep to the Midstream system balance and now I have to put a bunch of money and just moving compressions around chasing wells and go so and so. We’ll continue to move that certain quarters. We may have a little bit less IP because it will appear well, though the quarter may have a little higher IP, but I think the kinds of number you’d seen in the last couple of quarters will go forward for the next three to four quarters I faced.

Unidentified Analyst

Great, thank you.

Operator

(Operator Instructions). Our next question comes from the line of Rehan Rashid with FBR Capital Markets. Please proceed with our question.

Rehan Rashid – FBR Capital Markets

Good morning guys. On Fayetteville, actually couple of assets Marcellus and Haynesville, there have been some talk about re-fracs. Any thoughts on the packability of a [ph] and then I have got one more question.

Steve Mueller

Yes. We’re trying to evaluate that right now in the fields 10 years old. With this year, we’ve certainly improved our performance over time and learned quite a bit and so we’ve got few candidates that were evaluating along with a number of other sort of technical improvements learnings that we’ve learned from industry or from Marcellus that will apply there and we’ll let you know how those go once we get some results.

Rehan Rashid – FBR Capital Markets

As a number, how many well bores, call it maybe from a year or year and half ago again of 12, which might have benefited as much as all the advancements and completions in RCS and Whit-Mart?

Steve Mueller

I don’t know if we got an answer to that one. Usually, I think our re-frac is your wells get to some kind of marginals. Right?

Rehan Rashid – FBR Capital Markets

Right.

Steve Mueller

And we just have not made wells get to marginal rate yet and then it won’t be things like the [ph] at surface or doesn’t attract on those wells anymore and it’s just a matter, can you do something different with the frac or the other thing to look at going back to our comment about whether end zone or not end zone, we’re going back in all the wells making sure that they were in the right spot of the zone and how we have to do that as well. But they really have not heard and talked much about it. So we just have made them many wells. There are marginal not to talk about re-frac. So that’s kind of we’re right on that one.

Rehan Rashid – FBR Capital Markets

Got it, but the mechanical possibility. Is that right?

Steve Mueller

Yes. I don’t know if you remember. Few years ago, I think we did four or five and there were wells that were very early on. There were well that were frac with the gel [ph] fracs and in that case we did see about 20% due reserves when we did the re-fracs, but again those were very, very early wells in the field and didn’t pretty so much. So we don’t have a good base there, say it’s going to be good or bad, physically you can do it.

Rehan Rashid – FBR Capital Markets

Got it. And switching yours to Marcellus, I should know the answer to this, but I apologize. So the constitution gives the access to new Indian markets only and can be tight into something [ph] goes, takes it to Canada and coming to this constitution still on time anything to watch for there?

Steve Mueller

Constitution is designed mainly for New England markets. You could sense some gas in Canada, but I think the better price is New England market. So that was designed for. Timing-wise, it goes back to build comment about being a 1.2 a day in 2016. We’re assuming constitutions of 2016 event not like 2015 and actually on our time we’ve shown anyone it’s second half of 2016. We don’t have any information that says that’s right or wrong and so we build our plan on. So really this talk of Williams and Kevin [ph] on the line to figure out if the time is on schedule or not on schedule.

Rehan Rashid – FBR Capital Markets

But second half of ’16. Okay.

Steve Mueller

That’s how we put in our budgets in our plans.

Rehan Rashid – FBR Capital Markets

Okay, thank you.

Operator

Our next question comes from the line of David Heikkinen with Heikkinen Energy Advisors. Please proceed with your question.

David Heikkinen – Heikkinen Energy Advisors

Good morning. Just one little bit of simple math that be very clear. Your Fayetteville best 12s were [ph] and so you should have a kind of continued carry-through into the third quarter. It was my expectation, but Steve made a comment that sometimes you have overwhelmed systems and you have to shift rigs. Does any of that rig shifting have to happen given the.. it looks like the June wells or the best wells?

Steve Mueller

Yes.

David Heikkinen – Heikkinen Energy Advisors

Okay.

Steve Mueller

We are [ph] and had four of those good wells on it. So yes we did have.

David Heikkinen – Heikkinen Energy Advisors

Okay. Alright. So I think that load leveling [ph] is a good way to think about it, not some bigger performance that was perfect. And then onto the Niobrara Vertical program objectives as you think about the four wells, can you talk about how you’re drilling them? You’ve described the intervals going from dead [ph] oil from where Shell was, the dry gas where private operator was. What’s the zone kind of.. are you drilling across depths to go from white [ph] gas to oil or what would your objectives be for the vertical program before you drill your first [ph] on the well?

Steve Mueller

We’re doing three major things. We’re trying to learn as much as we can about the rocks. So we do a bunch of coring, testing the core, logging, etc. So just flat learning. At the other time, we are doing as well. We will be targeting the middle bench as the main objective is best we can tell the day. There are some other benches in there. So we will be testing in various wells different benches. And then the third thing, going back to your window kind of analogy there, we do need to figure out what will be the best producing window towards those various benches absolutely. Part of this is just drawing the cross-section and understanding the gas ratio and the liquids ratio on the quality of the liquids and trying to figure out where the better spots would be. So all of that will have [ph] four wells and some wells next year. Yeah, we haven’t thought about next year yet, Jeff said that we know full in the year if things were going to work, but as we learned how to expect with drill over the next year some more verticals and then starting to do more heavy horizontal part of it as well as it goes and we think ultimately it’s going to take some more close to 10 wells to really get to find we’re really understand enough to say go or no go.

David Heikkinen – Heikkinen Energy Advisors

So effectively you’ll have at least 10 wells next year one way or the other.

Steve Mueller

They will have five this year and then whatever else we need to [ph]

David Heikkinen – Heikkinen Energy Advisors

Alright. Thanks Steve.

Operator

Thank you. Our next question comes from the Drew Venker with Morgan Stanley.

Drew Venker – Morgan Stanley

Good morning, everyone. I was hoping you could provide more color on the brown dents. It looks like you have lowered capital for the play in 2014. Can you just discuss what drove your decision to lower the capital spend?

Craig Owen

As we put out in the early part of the year we decided we would adjust the pace of the capital depending on what we were learning. We've had some well results really mixed well results early part of the year. We've just completed a well in -- just recently that produced 600 barrels a day unstimulated. The name of the well is called the Benson well. Its peak production was of 660 barrels of oil and 2 million cubic feet of rich gas. That well we just finished in the quarter and then our plan was to back up and redirect the efforts of the team to our 3D seismic project that would enable us over a 75 square mile area right around where we've been drilling to get a better picture of what we've got tied our wells both successful and unsuccessful to the rock and then proceed later on with further testing. It made a lot of sense to, based on the theories that we are chasing on how to land and where to land these vertical wells to focus on that. So it's not a real change of plan. We've just reallocated the capitol back to the company while we do the 3D. But we're very encouraged by this latest well.

Drew Venker – Morgan Stanley

I guess that’s part of the thinking of stepping back and figuring out what you have exactly on the level, as it fits it within your emerging oil program is this going to be slower pace, and then you focus on Sand Wash basin and can you discuss your strategy there.

Steve Mueller

I think you have to think about the whole exploration strategy and it’s really not an oil strategy per se, so some of that exploration acreage we have is on gas plays, just happen to working on some wells right now, whether it’s Sand Wash, Eastern Colorado which we are testing right now tuning 3D and ground down, and then some acreages we haven’t talked about it’s just part of our ongoing program, where in any given year we test 3, 4 ideas and try to get 10 ideas tested over a five year period of time, so in the case of the brown ins, we are little bit confused, we step back, we got back some theories, we think with some 3D, might help get rid of some of that confusion, and so that’s what’s going on there, in the case of the Eastern Colorado, we drilled a well and that’s probably make or break on that well, and we are completing that one right now and then of course Sand Wash is really in the process, so it’s just each one is a different step and different play and their exploration and efforts.

Operator

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. Sometimes the investment community talks about catalyst and they have talked about near term catalysts and talk about long term catalysts and as they talk about catalysts and they make some kind of comment about how you should invest based on those catalysts. We don’t talk to that way internally here, what we talk about is performance, number one, to make sure you hit your numbers. And number two, what’s the future look like and what’s the upside that we can bring as you go through. As you think about this quarter Southwestern has definitely performed and we performed better and our capital efficiency continues to increase.

The Marcellus is showing upside and well performance, as we drill to the north, towards the New York border, it’s showing upside in the upper Marcellus that we are testing, and so we are seeing upside there along with the performance, in the Fayetteville shale, we continue to set new records in individual wells as we talked about, as we learn operationally and geologically and nuances across the entire disposition, and then as Bill talked about we are adding new rigs, upgrading equipment of rig fleet and that’s driving cost down, and making wells drill faster and one thing you didn’t mention was we drilled our first well less in five years, it was the first rig that was done and that wasn’t deep part of the field, was the best we’ve ever done before, something about six and half days. There is a new projects, we just finished, we got the Niobarra, you got Eastern Colorado, and all other exploration acreages out there that provide upside for us also.

And then finally when we look at our company we really drilled ourselves to thrive on low gas environment, the same environment that allows industrial users, power generators and each of our households also thrive and we are starting to see the beginning of those benefits from our great assets exceeding that upside of that new demand. Hopefully you get the point that we are hitting our numbers and we got a lot of upside, as I mentioned towards the end of the first quarter conference call, I was really looking forward and excited about 2014, nothing has happen in the second quarter to dampen that at all, and as excited as I was before, so with that, thank you for listening today, I hope you have a great weekends and that concludes our conference call.

Operator

Thank you. This concludes today’s conference call. You may disconnect your lines at this time. Thank you for your participation and have a wonderful day.

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Southwestern Energy (NYSE:SWN): Q2 EPS of $0.59 beats by $0.01. Revenue of $1.03B (+19.5% Y/Y) beats by $51.31M.