西南能源 (SWN) 2015 Q1 法說會逐字稿

our >> Operator Greetings and welcome to the Southwestern Energy Company first-quarter 2015 earnings teleconference call.

(Operator Instructions)

As a reminder, this conference is being recorded. It's now my pleasure to introduce your host, Steve Mueller, Chairman and Chief Executive Officer for Southwestern Energy Company. Thank you, sir, you may begin.

Thank you, operator. Good morning and thank all of you for joining us today. With me today are Bill Way, our President and Chief Operating Officer; Craig Owen, our Chief Financial Officer; and Michael Hancock, our Director of Investor Relations. If you've not received a copy of this morning's press release regarding first-quarter 2015 financial and operating results, you can find a copy 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 the Forward-Looking Statements sections of our annual and quarterly filings with the Security 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. The first quarter was one of high activity for us and one of delivering on promises. We promised to announce asset sales of between $600 million and $800 million and we've already closed one disposition of approximately $500 million and we'll close another totaling $218 million later in the second quarter. Operations and integration of our new acquisition are ahead of schedule and the Company set new production records that were above our first-quarter guidance.

I'd like to briefly talk about that production and what we are thinking regarding guidance. Approximately 3.6 Bcf of the production in the first quarter was from the E&P assets we were selling. We did not guide for production, revenues, or cash flow from the identified disposition candidates, but even accounting for the production from the asset sales, the actual production was slightly above the high end of our quarterly guidance.

Typically, you'd expect us to guide production higher, and if I'm pushed today, I would say we expect to be at or slightly above the upper guidance of 955 Bcfe in 2015. We are not changing the production guidance yet because other key items are also in flux. We certainly want to see more of the second quarter before taking a better guess whether to revise our guidance on basis differentials, and in addition, we've identified approximately $120 million of capital reductions that do not affect production.

These include the way we fracture stimulate, 2015 cost savings, and just plain fine-tuning of the budget. Even larger savings may be recognized with a little bit more knowledge. So for now, we'll not give any detailed guidance changes, just assume better production with lower capital and no detrimental effects to 2016 or beyond. We'll update you later as we know better. Let me now turn the call over to Craig Owen so he can discuss our financial results.

Thank you, Steve, and good morning, everyone. We're off to a strong start in 2015, as our expanding portfolio continues to exhibit its strength. We achieved record production for the quarter and saw our realized gas prices benefit from our firm transportation portfolio.

Excluding certain non-cash items, we reported net income attributable to common stock of $84 million, or $0.22 per diluted share, for the first quarter, compared to $231 million or $0.66 per diluted share, for the first quarter of 2014. The mandatory convertible shares that we issued in January had the impact of reducing our current quarter earnings by $0.07 per share due to the dividend, and $0.03 per share due to a required theoretical allocation of undistributed earnings to the convertible shares.

Our cash flow from operations before changes in operating assets and liabilities in the first quarter was $493 million compared to $617 million for the same period last year. This cash flow funded 95% of our capital investments in the quarter when excluding acquisitions.

We realized an average gas price of $2.99 per Mcf during the first quarter, including hedges, and $2.63 per Mcf excluding hedges. Our combined realized average gas price excluding hedges in our Appalachia divisions was $2.86 per Mcf for the quarter. As a reminder, all of our realized prices include the impact of transportation costs.

Our continued focus on our cost structure remains a differentiator for Southwestern, with all-in cash operating costs of approximately $1.28 per Mcfe in the first quarter of 2015, excluding certain transaction costs from the Chesapeake transit acquisition. At March 31, 2015, our debt-to-total book capitalization ratio was 42%, down from 60% at the end of 2014. When adjusted for the northeast Pennsylvania gathering divestiture, which closed this month, and the pending closing of the transaction to divest our conventional E&P assets, our pro-forma debt at March 31, 2015, is $4.5 billion, with a debt-to-total book capitalization ratio of 39%.

We expect to end 2015 with a debt-to-EBITDA of about 3 times at current prices, trending lower in the next few years, keeping us on track for hitting our goals. I am proud of these results we delivered this quarter and am excited for what we have planned for the rest of 2015. I'll now turn it over to Bill Way for an update of our operational results.

Thank you, Craig, and good morning, everyone. As mentioned earlier, we are off to a very strong start for the year. While the industry faces the challenge of lower prices compared to this time last year, our portfolio and our people once again exhibited their strengths and showed the benefits of combining exceptional assets with our trademark focus on low cost structure and strong performance improvement, while delivering another quarter of record production.

I'll briefly run through some of the latest activities in each of the divisions. In Northeast Appalachia, the team continues to impress and build on its momentum from 2014. During the quarter, we had production of 83 billion cubic feet of gas, which is 43% higher than the 53 billion cubic feet of gas from the first quarter of 2014.

We were able to achieve this production growth through continued well performance improvements and by fully executing on our very successful gas transportation strategy, by taking advantage of our strong firm transportation portfolio to move our gas to premium markets. We were moving approximately 1.15 billion cubic feet of gas per day in Northeast Appalachia at March 31, and realized a natural gas price of $2.92 for the quarter. This represents a benefit of $150 million, or $1.61 per MMBtu, versus selling natural gas without the benefit of the SWN firm capacity.

The transaction that closed in January with WPX puts us in an even better position with our firm transportation portfolio, ensuring we will be able to continue our impressive growth in this asset and get our production to market with competitive pricing. In addition to the pricing benefits we received from our own natural gas for the quarter, we were able to utilize some of the unused capacity from our firm transportation portfolio to generate additional margin on third-party gas where we created $2.5 million in additional margin.

While delivering our solid first-quarter results, we also moved forward with our delineation program on our northeast Pennsylvania acreage. We placed our fourth upper Marcellus well, the Marcucci Jones 7H online in the first quarter, and this Bradford County well is another indication the upper Marcellus contains promising potential and will add to the portfolio of economic drilling locations. This latest well was producing 5.2 million cubic feet per day on March 31 after being online about 45 days.

We have a total of four additional upper Marcellus wells planned this year in Susquehanna County. We've begun drilling on two of these wells and will complete them over the next two quarters. Further delineation activities will progress throughout 2015, as we continue to prove up our acreage in the area.

We also continue to make progress on our frac optimization learnings, where we are now consistently placing our laterals in the portion of the reservoir where the best rock properties occur, and we are placing more sand per foot of lateral while controlling costs by varying the stage phasing of the completions.

Moving on to southwest Appalachia, we accomplished a great deal in the first quarter of owning this asset. The team did a very detailed review and identified the key items that needed to be handled as part of the transition, and have diligently worked throughout that list and knocked off many of those already.

Stepping back from the specific progress made, while the transition of any asset this size has its challenges, the first four months could not have gone much smoother. It's a testament to the focus and attention to detail that the team has each and every day that this transition has gone so seamlessly. In the first quarter, southwest Appalachia had net production of 30 billion cubic feet of gas equivalent, with approximately 55% of this volume being dry gas.

Thanks to the decisive action by the West Virginia legislature and governor, we were able to transfer permits from the previous owners early in the year, allowing the SWN team to do a great job of implementing a plan to bring wells online and begin our investment program. The net exit rate for southwest Appalachia was 333 million cubic feet of gas equivalent per day and we anticipate a steady ramp from this number now that the transition is complete.

On the marketing front, we've heard some feedback from some analysts that there's some concern over whether we'll be able to get our production to market as we develop these assets. Well, after only four months of operating these assets, I can say that we are well on our way to implementing the plan that we identified during the acquisition evaluation and we hope to be able to give you details on some of this in the very near future.

We are in active discussions with a number of parties and are very confident that our ability to acquire sufficient capacity out of the region. Without going into details, I can summarize by saying we feel even more comfortable about the state of the available infrastructure than we did in our original assessment, and we believe that potential pipeline capacity challenges can be mitigated, just as we did in northeast Pennsylvania and Fayetteville before that.

Looking at NGLs, our price realizations for the quarter were $10.35 per barrel, consistent with our guidance for the 1.7 million barrels of NGLs we produced. We feel confident with our firm sales and our capacity levels for our development plan through late 2018 and early 2019 and in the interim, we'll continue to optimize our liquid strategy for the longer term.

On the operations side of our new asset, as I mentioned earlier, we've started off with some very encouraging signs on the cost front. We drilled our first five wells during the quarter and were able to drill the wells quicker than we anticipated. These five wells had an average drill time to total depth of 19 days, well below the original assumption of 26 days.

While we're still early, these are very encouraging data points and we fully expect that we will continuously drive drilling days down, just as we've done in Fayetteville and in northeast Appalachia. As we promised, we announced the acquisition. We also continue to do what we do best, identify efficiency enhancement opportunities that will drive out cost in future wells.

As an example of this is water handling, where we are currently trucking every water movement. Once we get the watering handling infrastructure in place, we expect to recognize material cost savings, likely in the $1 million per well range. Consistent with our water goals and practices in other divisions, we've begun reusing produced water, saving over $6 a barrel versus disposing of the water. These are just two examples and we continue to look at additional opportunities as we get more familiar with the asset.

Any time there's a large acquisition such as we did in southwest Appalachia, it's easy for the market to put all the focus on that new asset. Our Fayetteville team sure has not done that. We continue to operate one of the best natural gas plays in the country with the Fayetteville shale, and it continues to perform very well.

This asset continues to be a core piece of our portfolio as its location near the growing demand, low-cost structure, stable basis differentials and our vertical integration combine to create significant value for our shareholders. It also provides the extra benefit of flexibility, which can be a key differentiator in times like these.

Due to our HBP position and our vertical integration, we have the ability to slow down or ramp up much quicker than others in the industry. This will continue to be the case, as we watch to see what gas prices do over the next few months. We remain ready to act should prices change in either direction, and the Fayetteville will be a large component of that plan.

In the first quarter, our net production from Fayetteville shale was 115 billion cubic feet of gas. The team did an incredible job of delivering these results despite what turned out to be a pretty rough winter in Arkansas. There are a couple week back in February where icy conditions created challenges to rig moves, well maintenance, and completion operations, but with the extra effort from a lot of team members, we were able to hit our targets and beyond without jeopardizing safety, which will always be a core value for this Company.

In closing, as I said earlier, we've had a strong start to 2015 and we are looking forward to delivering even more value for our shareholders as we go through the year. The SWN team prides itself on focusing on long-term shareholder value and this year will be no different.

This is an exciting time for Southwestern Energy, as we continue the integration of our new assets into the already strong portfolio of legacy assets. We look forward to sharing more good news with you on our next call. This concludes my comments, so I'll turn it back over to the operator who will explain the procedure for asking questions.

(Operator Instructions)

Our first question today is coming from Doug Leggate from Bank of America Merrill Lynch. Please proceed with your question.

Thanks. Good morning, everyone. Good morning, Steve.

Good morning.

Steve, since the last earnings call, the pace of rig activity in the US in the lower 48 has obviously accelerated lower on the oil side. I'm just curious as to if you could update us on your macro view because obviously you've taken a longer-term, very positive outlook. How are you seeing specifically the impact on things like associated gas and your broader macro outlook as we go through the next 12 months? And I have got a more operational follow-up?

And I'll just be general with these comments and we can talk specifically, if someone wants to talk specifically. Our macro view really hasn't changed much. There isn't that much difference today in the supply/demand balance, and certainly we had a much warmer December than you normally have, and weather swings it back and forth.

But we've been saying for the last three or four years, basically starting in 2014 and going through 2018, demand continues to increase at a significant clip and production has to increase. It doesn't have to increase necessarily as fast as it did the last half of last year, but we see some things that are slowing down there.

So from a macro picture, irrespective of the associated gas part of it, we were heading towards a balance. When you add the associated gas back into it, that means the balance pulls up a little bit earlier in the process, so I expect over the next 12 months that we're heading towards the $4 mark, not staying less than $3 mark.

My related follow-up is, in the event then that we see a recovery, given you've now obviously got this very significant asset in the portfolio, how do you prioritize it incremental capital allocation as across the three core areas? And if I may just add on to that, if you could include your commentary around emerging opportunities, as well, in terms of how much capital you allocate to exploration?

Capital allocation is fairly simple, as long as you don't have constraints, and you're always going to put the capital where the best economics are at, but you have constraints. So we've debottlenecked, basically, the northeast, and as we get more capital -- and when I say northeast, northeast Pennsylvania -- as we get more capital available and as we get pricing that's a little bit stronger, expect us to go faster there as we grow into that capacity use that we recently purchased the term capacity.

In our new acquisition, it's got comparable type economics, but going back to the comments about the takeaway, we need to get a little bit of that more firmed in place. That will happen over the next couple quarters, but once that happens, then you could start going faster there. But right now today, if it happened, it would be number two on the list.

And then as Bill said, Fayetteville shale is swing for us. It's got good economics, but it's a little bit less than those other two areas and so that's where you are going to make your swing. If what I just said about the pricing doesn't even come close and we're in the $2 world eight months or nine months from now, the first place you're going to start backing down is in the Fayetteville shale.

When you start thinking about new ventures or exploration, we're always going to do some of that. The whole concept there is we're looking for something that's even better economics than whatever we have, and I don't care if it's an acquisition or the exploration component, that, we believe, should be the major reason that you do it, and we're always going to put a little bit of capital to that direction.

Historically, we've put about 10% of our capital that way. Next couple of years, as we're working on the debt that Craig talked about, we may be doing a little less than 10%, but we'll always put something to the exploration side, looking for that next better economics where we can more efficiently put capital to work.

Right. Appreciate the answer, Steve, thank you.

Thank you. Our next question today is coming from Neal Dingmann from SunTrust. Please proceed with your question.

Morning, gentlemen. I'm looking at your slide that shows that -- some of that attractive acreage you have in the, what I call, that West Virginia panhandle area. Really two questions around that area and just the more southern West Virginia. When you tackle that, I noticed on the Melvin well that you had in the Marcellus, and then as well as the Hubbard, it looked like the lateral length was a little bit shorter than some others in the area.

My first question is just around that. Does that continue to be the plan, or was that more because of lease lines, or maybe, Bill, for you, just your thoughts around lateral lengths as it pertains to both Marcellus and Utica wells in that area?

Yes, the lateral lengths for West Virginia in the current state of where we are with permitting, and certainly in northeast Pennsylvania, are largely controlled by unit size. So you'll see those, depending on where we are drilling, moving around. We are in the process of permitting and preparing for some much longer lateral lengths.

In West Virginia, our average was 7,500. We've got 10,000- and 11,000- and 12,000-foot wells planned where we have longer units and we have just got to get through the permits and get those done. Same in northeast Pennsylvania. We've got a couple of very long laterals that are in front of us to drill and complete, again, because the unit sizes were set up to enable us to do that.

Let me jump in there. We have drilled -- or we haven't drilled -- there's over 200 wells drilled in that West Virginia panhandle area, and so when you go back on those units, it's basically the size of that unit, and so in that case, they're probably in the 5,000 foot or less. As we put the new units together, they are greater than 7,000 feet, and that goes back to Bill's comment about we think, going forward, the average is around 7,500-foot, but it will swing from 5,000 all the way up to 10,000 feet.

Wow, okay. Good to hear. Then just one follow-up. You mentioned that huge savings you'll likely see on the water going forward. Your thoughts, as you drill some of this in West Virginia, you certainly have -- more than just West Virginia, but just using that -- you certainly have prospectivity for both Utica, Marcellus, maybe in some upper Devonian.

As you all tackle this, will you do -- on some of these pads -- go after some of these multi-stacked and tackle it that way? So my question is, one, how will you -- when you complete some of these pads, will you do it on some of these multi-formations? And two, besides the water, is there other things like that, that you see some material cost savings going forward?

Well, the way we've planned the development, we're targeting it upfront, the Marcellus, for the next couple of years. And what we've disclosed when we put the acquisition together, we would both study and get learnings from the industry on the Utica and so the timing of the Utica was pushed out a few years, just so that we could get a handle on that. But our development plan includes pads that are sufficient to handle both the Marcellus development and the Utica development in the same pad or in the same area.

The water infrastructure, along with gas infrastructure, they've got two different flavors. One, with the water infrastructure, we will bring water to the pad as we're laying gathering lines to those pads and be able to use that water for both Utica, for Marcellus. As we develop through time, to your other part of your question, can we go after multiple intervals with the same well, that's to be played out and that's obviously upside.

But remember, we've got wet gas in the Marcellus in a large portion of acreage and dry Utica gas, so we won't co-mingle those, just simply because of the fact that you end up paying processing on dry gas, which you get no value for. So we've got a lot of efficiencies that we're working through. We may even -- we've been studying the acreage and studying the unit sizes and making sure that we can best utilize the pads for all of these particular intervals, size them accordingly, and look how we manage those well slots going forward, so that we are not adding to the investment in the future.

That makes sense. Great details. Thank you.

Thank you. Our next question today is coming from Charles Meade from Johnson Rice. Please proceed with your question.

Yes. Good morning, everyone. I was wondering if you could offer a bit more detail on the 13 wells in southwest Appalachia that you brought on in the quarter. I know these weren't wells that you drilled, but could you talk about whether they had a Southwest completion on them, and where they were geographically, and also if there were any surprises in there?

We are primarily focused in the north part of our Marcellus acreage. We have a combination of wells that were waiting on pipeline and being able to bring those on so they were previously completed, and just waiting to be brought online. If you look at Marcellus and over the -- an average of these wells, 30 day IPs for the SWN wells range anywhere from 5 million up to as high as 14 million and what we are doing right now is looking at managing and optimizing flowback to generate the highest liquids yield on these that we can, so we're in a bit of study in that place.

There's several other wells that came on adjacent to us from Noble and a number of other operators that are in that same 10 million to almost 20 million a day rang, again, liquid content varying, lateral length varying. The wells we brought on are really more 5,000- to 6,000-foot laterals, again, in this area where the units are already established. Then the wells we've got planned going forward are more in the 10,000-foot to 12,000-foot length.

Got it. That's helpful detail, Bill. But any surprises, either positive or negative, in there? Or was it all just pretty much within the bounds of what you expected?

No real new surprises. The ability to get in there and get to work, the ability to maneuver through. We've got some additional work to do on permitting. It is not a constraint but it's more really understanding the rules of the game and the time it takes, that sort of thing, but we've got quite an effort to building an inventory of those, but other than that, we're encouraged.

One of the things that has happened, and I mentioned it in my comments, is our ability to drill wells, the time it takes to do that, we're seeing quite a bit more success in driving down that days to drill faster than we anticipated. We brought our new flagship rigs to the region to be drilling, and they're perfectly suited for drilling in this particular rock and in this particular area, and given how we put together the movement or the packaging of the rigs, we're able to move them a lot faster than competitor rigs in the area and that's been able to help us, as well.

And let me add two things to that. One, I want to emphasize what Bill said about the production. We are, as it stands today, we believe that we need to manage that production rate to get the maximum liquids, so you're not going to see really high rates out of the wells. So for us even to determine if it's a good well, bad well, it's a several month process because we're managing that rate and so we don't see anything today, but part of that has to do with the way we completed the wells.

The other thing, as you said, those wells were all drilled by the other company, and from where you land the well, and how much you stay in zone, there are going to be some differences in what we do going forward. We can talk more about it in later quarters for some of the wells we recently drilled and we'll figure out if we're doing better or worse at that point in time, and that's part of it, so this is way early stages and we're happy with what we're seeing, but there's still a long way to go even on these wells.

Got it and if I could just sneak in one more. In Northeast PA, at least relative to Q4, your average lateral was shorter, but your production rate was up, or your 30-day rate was up. Again, Bill, is that just a function of that geographic mix and you're more in the good areas or is there any more story that you'd elaborate on there?

Again, the lateral lengths are driven by unit size, so they will bounce around as we go. We've made a significant effort to really tighten up the landing zone for these wells in Appalachia, and we're sharing this across the whole Company, of course, but really tighten up the landing zone, where initiation of the fractures is best suited, where the rock characteristics are best suited to get the best well.

On average, we're increasing our sand loading on wells, and on average, we are staying in zone much, much better, and the result of that is these improved wells. What you'll see as we go through time, and some of this can be location driven, but the majority of it is just the quality of our wells are improving so much with all of the learnings that we're doing and that is impacting both IP rates and the 30-day rates.

Thank you, gentlemen. This is all great detail.

Thank you. Our next question today is coming from Michael Rowe from Tudor, Pickering, Holt & Company. Please proceed with your question.

Good morning. I just had a quick question on the Fayetteville to start out. Seeing that daily volumes declined sequentially by about 6%, and you spent about 40% or so of your budget CapEx for the full year in the first quarter. So was weather a driving factor at all in the decline quarter-over-quarter or how should we think about the production sequentially from Q4 relative to the capital spend?

Well the first key point is we beat guidance in that asset and all the other assets that we have, in spite of the weather conditions that we have, but I did mention weather. We did have a couple of weeks worth of ice in Fayetteville, which impacts both the ability to get out and service wells and produce, and the timing of when we get wells completed.

So the quarter was back-end loaded more than normal, given the weather, which, yes, we got the investment done but the wells were delayed coming on and that impacted what was there. If you look at February and into March, that's when the majority of the wells were put online versus ratably, but that will catch up with itself and certainly take us forward for the year.

Okay, that's helpful. Then you mentioned it was a 330 million a day exit rate for southwest Appalachia. Is that an equivalence number and is that net or gross?

It's a net number, and it's equivalent, Mcf equivalent.

Okay, perfect. Then maybe just one last question to squeeze in would be just can you remind us, on the capital allocation within southwest Appalachia this year, you all have 50 to 55 gross wells planned. Can you just remind us what the mix is between Marcellus wet gas and dry gas and how much flexibility you have around that mix?

Yes, right now, the target area for us is Marcellus wet gas. We may do some testing and/or some acreage holding with a bit of that investment, but the majority of it is focused on Marcellus wet gas at this point.

And let me just jump in and say that one of the reasons that it's the Marcellus wet gas is that's where your gathering systems are at. Part of the dry gas area, we have some gathering, but we don't have all that we need so that's really later this year into next year to accelerate the dry gas part.

Okay, thanks very much.

Thank you. Our next question today is coming from Jeffrey Campbell from Tuohy Investment Research. Please proceed with your question.

Good morning. First thing I wanted to ask was just a follow-up on what you've been discussing here today and that's the discussion of managing southwest Appalachia liquids production by optimizing the production rate. Is this to avoid condensation issues or is there something else involved?

Just in general, we don't think we have retrograde condensate or any of those kind of things. In general, what we want to do is maximize that down hole energy you have to get as much liquids as you can to the surface. Part of that has to do with what we call jewelry, but part of it has to do with the configuration of the well bore, and the tubing of the surface equipment, and then part of it has to do with the draw-down pressure you have at the perforations where you're in a reservoir.

We've seen some data that seems to indicate that, that's very important to manage that, to keep that liquids from just dropping out in the well bore and then have a hard time getting it out. I know some other operators are seeing a little bit different things, but today, at least, we're going to manage that direction.

Okay, great. Thank you. My other question is in the press release, I didn't see any discussion of upper Fayetteville or any kind of stacked well tests. Are these efforts still ongoing or are they slowing on budget restraint and concentration on the new acquisitions?

No, not for Fayetteville. We've got 12 wells that we plan to drill and complete this year. We've got 45 to date. We've got three wells online in the quarter at 4.5 million cubic feet per day average, with about a 3 Bcf EUR, 3.1 Bcf EUR. We'll continue those tests as we has planned to further understand that opportunity and add those wells to our economic inventory.

Okay, great. Thank you for that color.

And they [compete]--

Congratulations on the quarter.

Thank you.

Our next question today is coming from Subash Chandra from Guggenheim. Please proceed with your question.

Yes, on the issue of frac optimization and lateral targeting, and you mentioned that it's quite early days in West Virginia in that regard, but some initial commentary maybe on how many potential targets you might see and how tight a target you're staying in the areas and not just in here, but Fayetteville and northeast Appalachia, and specifically if you think rotary steerables will be required or are being used currently?

Yes, obviously it depends on where we're drilling or where we're completing and the rock quality, but suffice it to say that what the teams are trying to do, first -- I'll use northeast Appalachia as an example -- we look at the full interval of, say, the lower Marcellus. Over time and through experimenting and through other studies, we've been able to determine where in that column of rock is best to land the well. Then what we do to enhance that is they subdivide that and you can narrow that down to an interval as narrow as 20 feet.

So the Marcellus rock thickness hasn't changed. It's just exactly where we landed them. They are just trying to get tighter and tighter with that. So on a 5,500-foot lateral, the team may have an objective of trying to get within a 20-foot interval in there to land the well. Then through enhanced sand loading and some other techniques, we are improving the frac quality of these wells and that's what's driving some of the performance.

Our new rigs have quite strong capability. We've got an operation support center with geologists and engineers that are studying and are monitoring these live and helping steer the well. We're steering up with a lot more precision, just as technology, and then this operation support center continues to kick up and go, and the results we're able to significantly improve the accuracy of what we're trying to achieve. These intervals are self -- again, the rock quality and the rock thickness hasn't changed -- these are self-imposed intervals to try to reach the optimum landing point.

As far as rotary steerables, we do at times use rotary steerable, but usually it's not necessarily to land in the zones because we have other geologic issue out there. So we don't normally need to do rotary steerables, and I will mention, at least the wells we drilled to date in West Virginia, the Marcellus drills faster in West Virginia than it does in the northeast corner, so part of that five days difference we talked about was the horizontal just going a little bit faster than we thought it was going to.

Okay, yes, and that is as my follow-up, as you get a better understanding of the mechanics in the southwest Marcellus, would you sacrifice at some point in time rate of penetration, stay in zone, tighter targeting? Do you think that it's worthwhile to do that versus really targeting days to drill?

Do you think it would make a meaningful difference? And I ask, because I think -- and this is more in the Utica, perhaps -- but there are operators out there spending quite a bit more to stay within 8 feet and others targeting 40 feet, believing that it doesn't really compensate for the cost, and was curious what your initial thoughts there are?

We're very comfortable that, going back to Bill's 20-foot or 10-foot or whatever we target, you need to stay in zone or it is -- we'll sacrifice speed for staying in zone every time in every one of our areas.

Okay, thank you.

Thank you. Our next question today is coming from Brian Singer from Goldman Sachs. Please proceed with your question.

Thank you. Good morning.

Good morning.

You talked about the $120 million, at least for the moment, of cost savings and that's in both the bucket of just general 2015 savings and then some of frac efficiency gains that we've talked about already on the call. I wondered if you could provide any further break down of what you think of the $120 million would represent more cyclical service cost-related items versus the secular benefits from the integration or the fracking completion efficiency?

Yes, I can give you general numbers. About $75 million really has to do with fracking efficiencies, and so that is ongoing and will continue no matter what. There's about $33 million that is cost savings. Both of those have the potential to go up a little bit, as we learn a little bit more, but certainly that cost savings one is the one that we have more uncertainty about today.

Then there's about $12 million that is just tweaking the budget, where we took a little bit out of midstream and we got to fine-tune some numbers in some other places. Most of that is in a deferral category that is somewhere down the road, you would invest that capital anyway. So of the $120 million, about $75 million is ongoing everyday savings.

Got it, and that's the Corporate-wide number that would include anything going in the Fayetteville, as well, is that correct?

That is correct.

Okay, great. And then in your comments, as well, you mentioned optimism about getting adequate takeaway solutions for to source your growth coming out of southwest Pennsylvania and I wondered if you could comment as to whether your midstream subsidiaries and midstream operations play a strategic role in boosting that confidence and where that stands in terms of the importance to the Company?

Your question is would want to invest in the midstream or is the midstream going to do part of this thing. Let me start with saying that midstream is always strategic and important to what we're doing and they are working every day on the pricings that's out there. One of the reasons we have confidence, at least short-term, that we can get firm and get it out to the right points, is that working through our midstream and working with other companies, we know there's some capacity out there that we can get to.

We're comfortable about 2015, soon to be comfortable about 2016, and really, the things that Bill talked about are 2017 and 2018, as we add some bigger pipe in there, and we'll announce more about that later, but we are really comfortable in 2015 and 2016. Our midstream may very well be part of the capital that's invested and it could happen in a couple different ways and we just have to look at it. Again, it's a financial decision and strategic decision and sometimes the financials overpower the strategy and sometimes the strategy overpowers the financials, but we will certainly look at and you may see us invest more in the midstream than in any of our assets that are out there.

Great, thank you.

Thank you. Our next question today is coming from Arun Jayaram from Credit Suisse. Please proceed with your question.

Good morning, gentlemen. My first question really regards what you're seeing on the cost deflation front. I know you are pretty vertically integrated, but I was wondering if you could just comment on what oil service cost deflation is doing to perhaps the breakeven cost of your gas in the Northeast?

From a just a general response, it doesn't do much to the breakeven cost. It may move it $0.10 or $0.15. It's not moving to the $0.25 to $0.50 type numbers. I'll let Bill talk a little bit more about the details and where we are seeing the cost breakdown, but I'll just make a general statement. The normal cost that you think about, the drilling, the fracking, the tubular kind of costs, that's only about 50% of the well, and when people start talking about these numbers, that's usually what they talk about.

That other 50% of the well is mainly labor and you're not seeing 30% to 40% decreases in labor. You're seeing companies go out of business because they can't take 30% to 40% decreases in those costs. So the end result of that, even with big numbers on the other ones, the ultimate effect of breakeven is not as much as you might think, but Bill can talk about the various details.

What we're seeing in cost reductions so far, and we're out actually in the market working on a number of these at the moment, so I can share more later, but somewhere between 10% and 20% reductions really across-the-board in terms of fracking, in terms of drilling, in terms of tubulars, that we're seeing. We are actually looking at bringing our own equipment into some of these areas where they tend to be a bit more sticky.

So we're moving some of our rigs to the northeast to replace rigs that are under contract, for example, in northeast Appalachia, and those will begin drilling with our own rigs. So you have a combination of our lower cost relative to outside parties and rigs that are specifically designed to really excel, both in terms of speed, movement, and the ability to reach these long 10,000- and 12,000-foot laterals that we're at.

In our vertical integration areas, like in Fayetteville, for example, where we've taken out cost as third parties have left, our businesses are utilized 100%. But you'll see that we are already at those lower costs with our own performance so the savings have been built in over time.

I will comment on one thing around that breakeven concept that you're talking about. If we are able to take this new piloted frac design and implementation, higher sand loading, et cetera, and the well performance comes up as much as it is happening to us, and the stage spacing is optimized, that is a significant benefit to those wells and moves them quite down the cost curve.

Cost curves, okay.

(Multiple speakers) big advantage.

Thank you for that. The second question or final question is just regarding the Fayetteville. What do you estimate, at today's service cost, would be the maintenance CapEx to keep that asset flat? And secondly, what is the gas price you estimate where you generate free cash flow or that point of generating free cash flow for the Fayetteville?

Keeping production flat is a little more capital than we're investing right now because we've got a little bit of decline built into this year in the Fayetteville numbers. And this year, we're roughly $550 million to $560 million, so somewhere around $600 million in that range, $600 million to $625 million keeps it flat. I forgot the other part of your question.

Just the gas price, where it starts to generate free cash flow on a NYMEX basis?

Again, depends. I assume you're saying if production was flat?

Right.

Okay, you need a mid to high $3. I want to say mid to high -- $3.60 to $3.70, somewhere in that range.

Okay. Thank you very much.

Thank you. Ladies and gentlemen, we have reached the end of our allotted time for questions. I'd like to turn the floor back over to Mr. Mueller for closing comments.

Thank you and I won't say a lot here. The quarter was strong production results, good basis differentials, nearly balanced capital with its cash flow, and performing in both our promises and our operations certainly should give everyone a good indication of what the future looks like for us as we go down the road.

As I stated earlier, expect from us to have better production with lower capital in 2015, and that's always good, and it's always good for Southwestern Energy. So with that, I wish you a great weekend, and we'll call it the end of this call. Thank you.

Thank you. That does conclude today's teleconference. You may disconnect your lines at this time and have a wonderful day. We thank you for your participation today.