西南能源 (SWN) 2014 Q2 法說會逐字稿

Greetings, and welcome to the Southwestern Energy Company second-quarter 2014 earnings teleconference.

(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.

Thank you. Good morning, and thank 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 Brad Sylvester, VP of Investor Relations. If you have not received a copy of yesterday's press release regarding our second quarter results, you can find a copy of all this on our website at swn.com.

Also, I'd like to point out that many of the comments during the teleconference are forward-looking statements that involve risks and uncertainties affecting outcomes, many of which are beyond our control and are discussed in more detail in the risk factors and forward-looking statements sections 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 guaranteed for the 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 continue 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, while invest $280 million in a new project in the Niobrara formation in the San Juan Basin 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 a 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 wanted to watch the storage fill through the summer before talking about or possibly changing our guidance or capital budget. As it stands today, the storage is filling at a pace to reach acceptable levels going into the winter.

Now that we can see -- or begin to see beyond the effects created by the cold winter of last year, we are more comfortable the fundamental NYMEX gas price going forward should be above $4.00. We still believe this will be the most difficult summer for pricing in the Marcellus Shale and SWN is building an amiable portfolio of firm capacity and hedging to allow us to thrive in both today's pricing environment as well as the potential volatility over the next few years.

Now in addition, since the first of the year, we have been approached by several entities regarding long-term contracts to fill the new 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 of SWN's major producing areas are in prime positions for taking advantage of this new demand. And third, Southwestern' s investment grade in 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.

Thank you, Steve, and good morning, everyone. As Steve mentioned, our results in the second quarter were outstanding, primarily driven by higher production 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 of 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 9% from the $253 million we recorded in the second quarter of 2013, primarily due to higher production volumes. and 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 Mcf during the second quarter, which was down from $3.87 per Mcf in the second quarter of 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 gas 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 volumes 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 hedged through 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. To-date, we have approximately 1 Bcf per day of firm sales contracts in place with LNG and other utility and industrial customers for our Fayetteville and 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 in 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 compared to $1.24 per Mcfe last year. That includes our LOE, G&A, net interest expense, and taxes. Lease 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 production volumes than in personnel costs. Taxes other than income taxes were flat at $0.11 per Mcfe, and the full cost pool amortization rate in our E&P segment was $1.09 per Mcfe compared to $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 and Marcellus Shale plays. Midstream 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 a 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 will now turn it over to Bill Way for an update on our operational results.

Thank you, Craig, and good morning, everyone. Our second quarter was outstanding.

We again set production records as our results in the Marcellus Shale continue 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 the 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 10 less wells than we originally planned and finish the year with two rigs running and with one frac 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 up side as the thickness in this area of the lower Marcellus is well over 100 feet and the pressure gradients are higher than we had originally thought. These latest results are very encouraging, and we will keep you posted on our progress in this area of the county. We are continuing to test our 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, in Sullivan County, to help delineate our acreage. We have begun testing the upper Marcellus formation and our first well, the Preston Perkins 7H, located in Bradford County, is drilled. Our next three upper Marcellus wells are planned to be drilled by the of the third quarter, and all four of these wells are planned to be completed in the fourth quarter.

In midstream, we are moving 744 million cubic feet of gas per day in the Marcellus Shale at June 30 and transporting the gas through our firm transportation capacity to market. We continue to work on adding to and improving our portfolio of firm 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 will 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 145 wells online at an average initial production rate of roughly 4.4 million cubic feet per day, a rate which is 20% -- 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 from 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 have drilled 15 upper Fayetteville wells through the first six months of this year. Several of these wells are still choked back and are continuing to clean up. However, six of these wells had an average initial production rate over 4 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 midstream, 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 was gathering and transporting approximately 2.3 billion cubic feet of natural gas per day at June 30. 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 gas demand from our Fayetteville asset.

Moving on to exploration, we began completion of our first vertical well in northwest 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 we will be reporting more about our plans for 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, and I look forward to sharing those results with you as the year progresses.

This concludes my comments. And I will turn the call back over to the operator who will explain the procedure for asking questions.

(Operator Instructions)

Our first question comes from the line of Doug Leggate with Bank of America Merrill Lynch. Please proceed with your question.

Thanks. Good morning, Steve. 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 -- there is obviously been a very significant step up, you said in the release seven of the best wells in the Company's history. 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.

When you think about what we're doing in the Fayetteville, we are just looking at more and more detail in smaller and smaller areas. And so there's three major things that are going on and they're -- some overlap, some don't overlap. First one is we are just debottlenecking the very things at the surface. And that's allowed us to get higher rates in part of the field where you had little bit higher pressures.

Second thing we are doing is what we call extended shut in. Again, some of the field has more water than other parts of the field. The extended shut in has decreased that water. Then the third thing is just we're finding some areas that's got some good geology that either we hadn't tested before or we hadn't tested correctly before with the procedure we were doing.

The end result of that is that the three areas don't quite overlap. There is some that do overlap. But if you had to guess over 600,000 acres that we're drilling on, somewhere between 80,000 and 120,000 to 150,000 acres has the potential for one or all of those things to happen.

That's really helpful, Steve. I guess my follow-up to this, 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, LNG ex-[thought] 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 it's just too early to even think about it at this point. I'll leave it there. Thank you.

When you think about long-term contracts last couple of years, we have been asked very regularly what's going on, and there is a lot of talk and not many contracts. That seems here recently starting to get more different kinds of groups wanting contracts, as I said, for fairly short term as they start building out and trying to figure out what they are going to do in the near future.

We do have a contract with an LNG provider. They are out there and they are starting to make those contracts. I would say most of what we're doing right now is on the power side with some industrials along with the LNG.

I don't suppose you'd care to elaborate on details, Steve?

That's about all the details we are going to go into.

Thanks very much, guys. I appreciate it.

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

Good morning.

Good morning.

So I guess you just mentioned on the first question kind of some of the things you're trying in the Fayetteville to really increase the IP rates there in the initial production. I was just wondering, too, if there is anything you're doing on the completion side that could enhance the economics there?

You have had a lot of success in the Marcellus by increasing the amount of sand from 350,000 pounds to 500,000 pounds per se. So I was just curious kind of where you sit in the Fayetteville today and if you have any changes to -- any plans to change that.

We continue to learn in the Fayetteville and we -- whatever learnings we have in the Fayetteville, we apply back to Marcellus, and vice versa. Marcellus sand is up from what it was in the past. Probably not up in the same percentage that the Marcellus is. And when I say that, I say it in just very general terms.

As we think about the Fayetteville on top of all these plays, there is a lot of differences across the plays. So whether it's well spacing, amount of sand, exactly where you land it, how far your frac is going out, that varies across all of these plays. And I think what we're doing, whether it's Marcellus or -- which is a little bit behind, at least in the learning than the several years we've been in the Fayetteville, we're fine tuning that in the various areas, is really what's happening.

As we fine tune that, we are getting better wells along the way. So there is no magic formula. In general, we are putting more sand in the ground but that's not either across Marcellus or across Fayetteville, just a standard. It's just certain areas that more sand seems to work. Other areas you don't necessarily need it.

Okay. That's helpful. And then just switching gears real quick to the Marcellus. You all mentioned you were kind of -- you are going to hit 1.1 Bcf per day of firm transport in 2015 and then 1.2 in 2016. I was just thinking about this year.

You are spending $60 million less capital to kind of hit the same production in 2014. So I was 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.

You don't need many wells to keep the production flat. There's not a lot of capital and I don't know if we thought about that in the Marcellus, frankly. As you think going forward, as Bill said, we're still trying to add some more capacity. We'll talk about 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 the Marcellus at a very quick pace. I don't know, maybe it's 20 wells or 30 wells. It's a small number and keep it flat.

Okay. Thanks a lot.

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

Thank you. Good morning.

Morning.

I wanted to follow up on Doug Leggate's Fayetteville discussion. You highlighted 7 of the best 10 wells you've drilled were done during the quarter, but then there were 140 other wells during the quarter and it seemed like the well performance was not that dissimilar on 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 IPs relative to cost going forward throughout the program, or is this more an offset to maturity elsewhere?

Well, I think the improved performance that we are 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 are not tubing up the whole well. We rest all of our wells as a matter of practice now so and there is not a cost to doing that. The major difference will be lateral length but that would be across the entire field and it flexes up and flexes down depending on the unit size.

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. In 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 costs down. And when you combine that with our new rigs and the fact that they are more efficient than our older rigs, just as the new generation, we actually see opportunities to improve margin further both on the cost side and on the well performance side.

And I think part of your question was that you're not seeing the whole group of 30 and 60 day rates higher. These wells have only been on for a short period of time and it is -- it's about 15% of total wells are drilled in say the last six months or in that we are doing all these things to them. We're assuming right now internally that it's all acceleration except for where we've talked about the better geology. But that's not bad.

Going back to your cost part of it, we think on a PV-10, basis we are adding a little over 10% of PV-10 by accelerating and going forward. Internally, we are saying it's all acceleration. We will be able to tell you probably in about six months whether there is any actual incremental reserves that go with that.

Great. Thank you. And then shifting to the Marcellus, is there any update you can give with regards to drilling in the north -- the northeast portion of your Susquehanna County acreage?

Yes. We basically went back and reentered the pilot hole recently. We've drilled a 4981-foot lateral and put 14 frac stages on it. We're using our sort of higher level sand content, which is 500,000/530,000 pounds of profit per stage. Right now, we're just in flow back operations. But what we see is -- what we've seen we're encouraged by.

So we're going to complete a 3D study of that area as well. Probably about a 100 -- a little over 100 square miles and then we'll 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.

Great. Thank you.

Thank you. Our next question comes from the line of Joe Allman with JPMorgan. Please proceed with your question.

Thank you. Good morning, everybody.

Hi, Joe.

Good morning.

So you've beat the high end of production guidance five quarters in a row. And is the main driver a flatter Marcellus production curve?

I don't know. It's probably the main, yes. The Fayetteville, certainly if you look there, we've added almost every quarter a little bit of Bcf to our guidance. Certainly, Marcellus has held up better than we thought and was a better performer.

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 are planning this year and the timing, I know it may change based on the results, but in your mind right now, what's the timing of a go or no go decision for this play?

And then also could you talk about any surface issues? I think where you are operating may be in or around some sage-grouse nesting areas. If you talk about permitting and any other insights you have on this play?

I'll let Jeff Sherrick talk about that. He's in charge of that project. Go ahead, Jeff.

We're really -- the first acreage tranche that we picked up was in May of this year and we're actively out there now. We do have a drilling rig on location. We've drilled one well. We'll continue to drill through a planned program of at least four verticals was we go through the end of 2014.

Our goals are about the end of the year is to drill a horizontal well and at that point in time, get a flow test to see how the overall program looks. So I would say, if we're looking for 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 issues, and in particular the sage-grouse question that you brought up, there is no question that this is an area that you have to work and plan and get ahead. We have been able to do it that just in the first three months.

We don't think that there are going to be any surface restrictions on slowing down our current planned program that we have for the rest of this year and the early part of 2015. We'll continue to work on that real hard and we think that we can have a very active program out here provided that we see the results that we are expecting.

Yes. As far as the sage-grouse go, they are there in the area. The whole area is not conducive to sage-grouse, but certainly part of it is. And we're working with the industry, just like everyone is across various states 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's something that we just have to keep working on.

Very helpful. Thank you.

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

Good morning, everyone. I'd like to ask a question, drill a bit down bit more on the upper Fayetteville tests. You guys have mentioned six of these wells are on at a rate over 4 million a day. If you look back in how that compares to -- against your historical table, that would be -- that's only exceeded by your last four quarters for the play.

And so I'm wondering, I guess those really look like positive well results. I am wondering if you could break down how much of that is lateral length or completion design and how much of that is or would perhaps be you're resting or the remainder might be or the other explanation might be that the quality of the formation?

One of our chief objectives in drilling these upper Fayetteville tests, and we have been working on this for some time, was the ability to stay in zone in the more brittle zone of this particular part of the formation. And we've spent a lot of time and a lot of evaluation and a lot of testing trying to make that happen. And with technology as it's advanced and our monitoring of these wells as they are being drilled continuously, we have been able to achieve that.

By doing that, the area where we initiate fracs 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 track this on every well. Certainly we rest them.

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 we're doing in all the others. They don't vary materially. But it's more about staying in zone and in a particular part of the zone that we're in. We're trying to really optimize within a fairly narrow window and we have been able to achieve that.

(multiple speakers) Let me add to that that if you ask us a year and a half ago, two years ago, stay in zone, plus or minus 25 or 30 feet with staying in zone, today when he said stay in zone, it's less than 10-foot. And in some cases we are trying to stay 5-foot. And we are doing it very successfully in both Fayetteville Shale and Marcellus on 80% of the 5,000 foot lateral. So we have learned a lot and because of that a lot of different things get better as you go to this well.

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

it doesn't have to be quite as tight in the upper, but we're doing it in the lower. We're doing it in the Marcellus. And we'll talk about more -- there is some other zones we are testing in both the Marcellus and the Fayetteville. We'll talk more about in the future that we're doing it in.

Got it.

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

Right. Right. And if I could just sneak one more in.

Can you -- with these good results you're having now in the Fayetteville in the basis issues, temporary though they may be up in the Marcellus, can you compare what your PVI looks like for some of these -- your recent vintage Fayetteville wells versus the Marcellus at this point?

Well, I will just make a general comment. The very best Fayetteville wells certainly match with the better Marcellus, but on average with the prices we see today and with the prices we see going forward, Marcellus is still a little bit better economics.

Thank you, Steve.

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

I had a 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 are you changing -- or are you actually following the old traditional decline curve? And then a follow up.

We have some examples where -- and again we don't have long periods of time. But some of the longer wells we have examples where it looks like there is some incremental EUR that you're going to get in addition to just getting the higher rate to begin with. But we don't have enough information to say that's really going to be the answer. Some wells certainly look like you are getting some more EUR out of it.

On a margin basis, we continue to get the benefits on a cost -- on the cost side for the water not being needed to be handled, which is approaching $100,000 a well.

And then a quick follow-up. You talked about sort of advances in directional drilling. Can you talk about sort of what state-of-the-art 3D seismic for these shale plays for you all?

You know, I don't know that we have an answer on state-of-the-art 3D seismic. I can tell you that we are -- have shot and are going to shoot some more three-component surveys and we have done some work with shear strength and we are doing some with shear as well.

But I think we're like everyone. The costs are going down. You are putting geo-phones on the ground. You are getting more information and we're doing that just like everyone else is in the 3D.

Okay. Thanks.

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

Thank you, folks. Good morning. Could you comment on the cost of firm transportation in the Appalachian Basin today, and what's expected over the balance of this year? And at what price does it not make economic sense for this -- for Southwestern to secure additional firm transportation?

Well, our long-term average transportation is about $0.37. And so that's the range that we've had for the Appalachians. As we look into the future, some of the new projects out there have a fairly high cost and you have seen some I think over $1. 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 is going to go right by the Fayetteville and we will just sell Fayetteville 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 some of the big demand is coming up in the next four or five years. We can get there much cheaper than that. Today I'd say most of what we're looking at is between $0.40 and maybe as high as $0.65 looking at going forward.

Okay. Great. And as a follow-up to that, just on the subject of long-term contracts, maybe with an LNG provider as you state, what does that tell us about your view on the price of natural gas longer term if the Company is willing to sell gas under these longer-term contracts?

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

Very good. Thank you.

Thank you. Our next question comes from the line of Gil Yang with DISCERN Investment. Please proceed with your question.

Good morning. So it's a little hard to tell, but it looks like the working interest net 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 -- am I reading the numbers a little bit wrong?

Yes, it did come up just a little bit. And it depends on the mix of wells and where we happen to be producing at the time. Certainly and by way of example, you can look at the acreage we bought from Chesapeake. Some of that is on wells that -- on acres that we already owned. So by its very nature, it will raise it.

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

Well, we always try to get as much in a drilling unit as we can. So we're always working at that. And whether it's the Marcellus or Fayetteville Shale, we have an 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 essentially side to the firm or anything other than that. We're going to operate it. We'd like to have as much as we can.

Okay. So it's just standard operating procedure.

Exactly.

Okay. Second question I have is there does seem to be very wide swing in the quality of wells that you are drilling in the Fayetteville, much stronger sort of in the maybe the second half of the quarter versus the first half, it looks like. You 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 saw early this year, or more like what we saw end of last year?

That's dynamic and we certainly have a schedule actually that goes out until the middle of next year. But rigs are working across the field. I'll just remind everyone. Shallow, north side of the field is significantly different production profile than deep southern side of the field. When you get several of these high-rate wells together, you will overload your midstream system.

So you have to move a rig out, move it to a different area. That may be a medium, may be a little bit less production swinging back in. So the goal is to produce as much gas as we can. Keep the midstream system balanced and not have to put a bunch of money in just moving compressions around, chasing wells that go through. We'll continue to move that.

Certain quarters may have a little bit less IP because, as you know, a little bit fewer wells. Other quarters may have a little bit higher IP. But I think the kinds of numbers you've seen in the last couple of quarters will go forward for the next three to four quarters probably at least.

All right. Great. Thank you.

Thank you.

(Operator Instructions)

Our next question comes from the line of Rehan Rashid with FBR Capital Markets. Please proceed with your question.

Good morning, guys. On Fayetteville, actually, a couple of assets Marcellus and Haynesville. There has been some talk about re-fracs. Any thoughts on the applicability of it for Fayetteville? And then I've got one more question.

Yes. We're trying to evaluate that right now and the field is ten years old this year. We've certainly improved our performance over time and learned quite a bit.

And so we've got a few candidates that we're evaluating along with a number of other sort of technical improvements, learnings that we've learned from industry or from Marcellus that we'll apply there, and we'll let you know how those go once we get some results.

As a number, how many well bores, call if from a year, year and a half ago, at the end of 2012, which might not have benefited from all the advancements in completions in RCS and what not?

I don't know if we've got an answer to that one. You know, usually you think about re-frac as your wells get to some kind of marginal rate.

Right.

And we just haven't had many wells get to a marginal rate yet. And then it won't be -- things like the unbottlenecking at surface or the extended shut in, it doesn't factor in those wells any more. And it's just a matter of can you do something different with the frac.

Or the other thing to look at, going back to our comment about were you are in zone or not in zone, we are going back to look at all the wells and making sure they were in the right spot of the zone and how we have to that as well. But really, the reason you haven't heard us talk much about it is just we haven't had that many wells that are marginal enough to talk about re-frac. So that's kind of where we're at on that one.

But the mechanical possibility is there, right?

Yes.

Okay.

And I don't know if you remember a few years ago, I think we do four or five. And they were wells that were very early on. They were wells that were fracked with a gel. They weren't even slickwater fracs. And in that case, we did see about a 20% new reserves when we did the re-fracs.

But again, those were very, very early wells in the field and didn't produce that much to begin with. So we don't have a good base there to say it's going to be good or bad. Physically, you can do it.

Got it. And then switching gears to Marcellus, and I should know the answer to this but I apologize. So the Constitution gives you access to new then markets only or can we tie it into something else that goes to Canada and kind of is that the Constitution still on time, anything to watch out for there?

The Constitution is designed mainly for the New England markets. You could send some gas to Canada, but I think the better price is New England markets. That's what it's designed for.

Timing wise, that goes back to Bill's comment about being at 1.2 Bcf per day in 2016. We are assuming Constitution is a 2016 event, not late 2015. Actually, another thing we've shown is second half of 2016.

We don't have any information that says that's right or wrong. That's just what we built our plan on. So really need to talk to Williams and Cabot, the guys who own the line, to figure out if it's on schedule or not on schedule.

But second half of 2016. Okay.

That's what we put in our budgets and our plans.

Okay. Thank you.

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

Good morning. Just one little bit of simple math to be very clear here. Your Fayetteville best 12s were late in the quarter, and so you should have a continued carry through into the third quarter was my expectation. Steve, you made a comment that sometimes you overwhelm systems and you have to shift rigs. Did any of that rig shifting have to happen given the -- looks like the June wells were the best wells.

Yes.

Okay.

We had a pad come on that had four of those good wells on it. Yes, it did happen.

Okay. All right. So you think that load leveling is a good way to think about it, not some big out performance there. That was perfect.

And on to the Niobrara vertical program objectives. As you think about the four well, can you talk about how you are drilling them? You described the interval as going from dead oil from where shale was to dry gas where a private operator was. Like what's the zone and kind of are you drilling across depths to go from wet gas to oil? Or what would your objectives be for the vertical program before you drill your first horizontal well?

We're doing three major things. We're trying to learn as much as we can about the rocks. So we will be doing a bunch of coring, testing of the core, logging, et cetera. So just flat learning. The other thing we're doing as well, we'll be targeting the middle benches. The main objective as best we can tell today.

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 looks -- what will be the best producing window for those various benches.

Part of it is drilling across a section and understanding the gas ratio and the liquids ratio and the quality of the liquids and trying to figure out where the better spots would be. All that will happen in those four wells and some wells next year. We haven't talked about next year yet. Jeff said it. We'd know early in the year if things were going to work.

But as we learn how to expect what to drill early next year some more verticals and then starting the more heavy horizontal part of it as well as it goes. We think ultimately it's going to take somewhere close to 10 wells to really get to a point of where we understand enough to say go or no go.

So effectively you will have at least 10 wells next year one way or the other?

Five this year and then whatever else we need to drill next year.

All right. Thanks, Steve.

Thank you. Our next question comes from the line of Drew Venker with Morgan Stanley. Please proceed with your question.

Good morning, everyone. I was hoping you could provide a little bit more color on the Brown Dense. 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?

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 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, tie 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.

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

I think that's the thing about the whole exploration strategy. It's really not an oil strategy per se. I tell everyone all the time we are just looking for good projects. Some of that exploration acreage we have is on gas plays.

It just happens that we are working on some oil ones right now. Whether it's Sand Wash, eastern Colorado, which we're testing right now, shooting in 3D in Brown Dense and then some other acreage we haven't talked about, it's just part of our ongoing program where in any given year, we'll be testing two to four ideas and try to get 10 ideas tested over a five-year period of time.

So in the case of the Brown Dense, we are a little bit confused. So we stepped back. We got some theories that we think was 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 just drilled a well and it's probably make or break on that well and we are completing that one right now, and then of course Sand Wash is early in the process. So just each one is a different step and different phase in their exploration and efforts.

Thanks for the color. Steve.

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.

Thank you. You know, sometimes the investment community talks about catalysts and they talk about near-term catalysts and they talk about long-term catalysts. After they talk about catalysts, then they make some kind of comment about how you should invest based on this catalyst. You know, we don't talk that way internally here.

What we talk about is performance, number one. Make sure we hit your numbers. And number two, what's the future look like and what's the upside we can bring as we go through? If you think about this quarter, Southwestern has definitely performed and we have performed better and our capital efficiencies continue to increase.

The Marcellus has shown upside in well performance. It's shown upsides we drilled to the north, towards the New York border. It's showing upside in the upper Marcellus that we're testing. So we're seeing upside there along with the performance.

In the Fayetteville Shale, we continue to set new records in the individual wells as we talked about. As we learn operationally and geologically the nuances across the entire large acreage position. As Bill talked about, we're adding new rigs, upgrading equipment in our rig fleet, and that's driving costs down and making wells drill faster.

One of the things he didn't mention was we drilled our first well less than five days with that first rig that we've done and what was amazing about that, that was in the deep part of the field where the best we've ever done before was something about six and a half days.

And then there is the new projects we just finished talking about. You've got the Niobrara, you've got eastern Colorado, Brown Dense, and all that extra exploration acreage out there that provides upside for us also. And then finally, when we look at our Company, we've really built ourselves to thrive in a low gas price environment.

The same environment that allows industrial users, power generators, and each of our households to also thrive, and we are starting to see the beginning of those -- of benefits from our great assets in feeding that upside of that new demand. Hopefully, get the point that we're 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's happened in the second quarter to dampen that at all. I am as excited as I was before. With that, I thank you for listening today. I hope you have a great weekend, and that concludes our conference call.

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.