Good morning, ladies and gentlemen, and thank you for standing by. Welcome to the Southwestern Energy Third Quarter 2018 Earnings Call. In the interest of time, please limit yourself to two questions. Afterward, you may feel free to re-queue for additional questions. Please note this event is being recorded. I would now like to turn the call over to Ms. Paige Penchas, Southwestern Energy's Vice President of Investor Relations. You may begin.

Thank you, Brandon. Good morning and welcome to Southwestern Energy's third quarter 2018 earnings call. Joining me today are Bill Way, President and Chief Executive Officer; Clay Carrell, Chief Operating Officer; Julian Bott, Chief Financial Officer, and Jason Kurtz, Vice President of Marketing and Transportation. Yesterday afternoon, Southwestern Energy released financial results for the quarter-ended September 30, 2018. The release is available on our Web site at www.swn.com. Our 10-Q for this quarter has been posted on our Web site. We will post an updated investor presentation next week. Before we get started, I'd like to point out that many of the comments during this call are forward-looking statements that involve risks and uncertainties affecting outcomes. Many of these 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 Securities and Exchange Commission. Although we believe the expectations expressed are based on reasonable assumptions, they are not guarantees of future performance, and actual results or developments may differ materially. We may also refer to some non-GAAP financial measures which help facilitate comparisons across periods and with peers. For any non-GAAP measures we use a reconciliation to the nearest corresponding GAAP measure can be found in our earnings release available on our Web site. I'll now turn the call over to Bill Way.

Thank you, Paige, and thanks to everyone for joining us this morning. The third quarter is best defined by our continued strong outperformance on each of our operating and financial commitments and taking the next step forward in our strategy. This quarter we signed an agreement to sell the Fayetteville Shale assets. We initiated the return of capital to shareholders, and are completing the necessary steps to permanently reduce debt towards our goal of a sustainable two-times leverage. Our strength in balance sheet and improving investment returns from our Appalachia Basin Development program provide clear evidence that our strategy is working, and delivering greater value to our shareholders. Let me speak a bit about the quarter. Cash flow was more than 40% higher than the same period a year-ago. Results benefited from our liquids volume growth as prices improved, and the company recorded its highest liquids revenue and liquids production quarter in its history. Thanks to the strong performance of our Appalachia assets. Additionally, we benefited from our leading low-cost gas transportation portfolio as regional basins tightened. The company generated record Appalachia production as we continue to accelerate the value of our liquids assets. EBITDA of $276 million for Appalachia alone was 134% higher than last year. I know many of you historically think of SWN as purely a natural gas producer. As we move forward, liquids are representing a significant and growing percentage of our revenues. We expect liquids to approach one third of our total Appalachia revenue for the year. We are now one of the largest NGL producers in the Appalachia basin. Our vast 500,000 acre core position in Appalachia is an area we know well. Our acreage holds 40 Tcf of potential resource from several intervals and 11.1 Tcf of proven reserves at the yearend 2017.…

Thank you, Bill, and good morning to everyone on the call and webcast. Operationally, our team had another strong quarter. As you know, we recently raised full-year production guidance for gas, oil, and NGLs while affirming we would remain within our original capital spending guidance. Total company production was $252 Bcfe which is at the midpoint of the revised guidance and included a record 67,100 barrels per day of total liquids production. Gas production was at the midpoint at 215 Bcf. NGLs were above guidance at approximately 5.2 million barrels and condensate and oil were near the top end at approximately a million barrels. Appalachia production of 187 Bcfe included 20% liquids by volume and 35% by revenue. This production has grown 22% year-over-year while liquids production has grown 39%. The combination of improved operational efficiencies and well performance continue to produce results that exceed expectations while we also deliver on our commitment to invest within our original capital guidance. We are developing some of the highest quality liquids rich acreage in Appalachia. Our rich and super rich areas produce 1100 to 1400 Btu gas and where present initial condensate yields in the 150 to 200 barrel per million range. As a result of the high quality liquids rich acreage and current prices, we have focused approximately 60% of our drilling and completion activity in this area for 2018. During the quarter, we drilled the two longest laterals in company history using SWN operated drilling rigs and crews. One in Pennsylvania was 16,272 feet. The other was in West Virginia and set a new state record of 15,559 feet. Both of these wells were on time and on budget which is a credit to our continuous improvement approach where we have gradually extended our lateral lengths over time and then…

Thanks, Clay, and good morning to everyone. As you saw in our press release, we reported very strong third quarter financial performance driven by higher gas, liquid, and condensate production, higher realized prices, our leading operational execution, and the benefit of our cost savings initiatives. We generated cash flow of $355 million, 43% higher, and adjusted EBITDA of $377 million, 39% higher than the third quarter last year. For the nine-month period, adjusted EBITDA was just under $1.1 billion, and is almost $200 million, or 21%, higher than the first nine months of 2017. Based on our current prices, we expect cash flow for the year to be above guidance even after excluding Fayetteville revenues, assuming the sale closes in December. As Bill mentioned earlier, we saw higher realized gas, liquids, and oil pricing driving incremental value from our all-time highest production levels throughout Appalachia. Bases tightened as Appalachia pipeline infrastructure additions commenced service, and we expect to continue to directly benefit from the improvements this year. While our gas differentials guidance includes Fayetteville, this improvement in Appalachia basis could drive total company gas differentials below the guidance range issued earlier this year. Compared to last year, gas differentials in Appalachia improved over 40%, and averaged $0.77 during the quarter. NGL realized pricing, including hedges, was particularly strong this quarter, and 29% above realized pricing versus the second quarter. Both ethane and propane pricing has improved, and the forward curve for full-year '19 indicates pricing in the mid $0.30 range per gallon for ethane. We do hedge ethane and propane barrels consistent with our hedging strategy, and our reported NGL realizations included a $2.17 per barrel hedging impact. We continue to recover all our ethane, and have direct access to the Gulf Coast via firm transport on the pipeline. Condensate…

Thank you. We will now being the question-and-answer session. [Operator Instructions] Our first question comes from Holly Stewart with Scotia Howard Weil. Please go ahead.

Good morning, gentlemen, Paige.

Good morning.

Maybe first, you've done a lot of talk about NGLs, and pricing, and your production uptick, et cetera. Could you just strategically maybe walk through your fractionation capacity processing takeaway, just kind of how that looks for maybe 2019 and beyond, and just where you sit from an infrastructure standpoint on NGLs?

Holly, this is Jason. Let me see if I can put a couple of data points together there for you. So when we think about our liquids growth we're highly focused all around the value of that. And then we've been prepared, and we have gathering, processing, frac infrastructure and capacity that we've secured that's under construction right now to be able to accommodate this growth through 2019. And that growth will be based on the value that we can get out of those liquids. Additionally, we do have ethane capacity that we mentioned that achieves Gulf Coast pricing. And the team does an excellent job of maximizing the value that we receive through rejection recovery economics on our [8x] [ph] capacity.

And so I'll add to that. We contract well ahead so that we have no gathering, processing, transportation or fractionation constraints into 2019.

Okay, that's great. And just a follow-on to that, maybe Jason, on the processing side, are all those fee-based contracts or is there some POP in there?

They are all fee-based.

Okay. And then maybe just as a follow-up, Julian, you mentioned on the guidance, you sit pretty well as we look at the fourth quarter. It looks like on basis guidance, specifically your midpoint right now I think is about $0.75, if you look at the year-to-date you've probably averaged $0.61. I'm assuming that uptick for the fourth quarter is just the capacity that you've got on a couple of these projects that are factored in. But you sit in a pretty good situation, so just kind of curious how you all are thinking about sort of fourth quarter and beyond for that natural gas basis.

Sure, Holly, as I was suggesting, I think if things continue as we see in forecasts, we expect that we will be probably below our guidance. And at this point, probably in the mid $0.60 to $0.70 range on the basis.

Yes, that's great. Thanks, guys.

Our next question comes from Arun Jayaram with JPMorgan. Please go ahead.

Yes. Good morning. Bill, I was wondering if you could walk though kind of the benefits of shifting towards the longer laterals. You talked about drilling 15,000-foot and a 16,000-foot lateral. Are you seeing any optimal lateral lengths which are optimizing returns? And maybe you could maybe discuss what types of returns uplift do you see from going, call it, from 10,000 feet to 15,000?

Hey, Arun, this is Clay. We definitely see the benefit of the longer laterals. It's more efficient on a cost per foot standpoint. When you look at the two long laterals that we mentioned in the press release, we're going to be in the low 900s to the mid 800s on a dollar per foot standpoint on those wells. And we definitely see an uplift in our economic metric, it probably generates somewhere between a 25% and a 30% increase by drilling one long well as opposed to two shorter wells.

So our objective here is value creation. We're on a very deliberate path. We went past 10,000, went past 12,000, went past 14,000 feet, we've done 16,000. It isn't about the length of the lateral, it really is about, on a risk-adjusted basis, what value can we create. And we've done a great job the team has in learning along the way. And as we reported, these latest two record-length wells benefited from those learnings and we're right on target in terms of their cost. And as we produce these wells and then move forward we will continue to see what that looks like in terms of lengths, but always optimized around economics.

Yes, Bill, just to follow-up. One of your peers talked about having some operating challenges as you move beyond 14,000 feet. What are some of those operating challenges, and how have you been able to manage against that?

It's, Arun, again Clay. I think the longer you get out there you have torque and drag issues; you have issues around getting your casing all the way to bottom. The rig that you start with, the longer your lateral lengths get out there is critical to position you to be able to successfully get those wells drilled, the TD and casing to bottom. And there's a lot of pre-modeling that's occurring with all the data you already have around the torque and drag that you've seen as you're drilling these extra-long laterals. And so there's a lot of science that goes into it. You got to have the right equipment, but we think as you keep taking these measured steps you can stay on top of that and deliver on your planned wells.

I think the secret to our team is we've got a team of people that work for the company, our drilling rigs are owned by the company, and we're applying learnings that we have, whether they’re learnings from us or someone else, and avoiding those mishaps or slowdowns that we see in others. So we're very, very encouraged by this.

Okay. And just one more quick question, you guys have talked about running up to six rigs in 2019 with an 8% to 12% kind of growth rate. Can you maybe give us a sense of where you think capital could shake out for next year and '20, Bill?

Yes, we're right now assembling our budget. And we typically approve our budget in the first quarter. We're working to get some guidance out a bit earlier, probably right after the Fayetteville closes because just the company's reset. But if you want to take a look at capital and where it's sourced from, it's sourced from cash flow. And so we take a -- six rigs is an estimate based off of a forward curve of natural gas and the other commodities. We put it through our model, generate cash flow. And we are replacing the Fayetteville cash flow with the proceeds, as I said earlier. And that sets the upper limit of our capital program. And so between now and December or now and winter, we'll lock in on a forward curve, still a tradable forecast you can have, appropriately hedge it, and then set that cash flow and then that capital budget. So, as we move through the year we'll put more detail out on that, but that work is underway.

Okay, thanks a lot.

Our next question comes from Charles Meade with Johnson Rice. Please go ahead.

Good morning, Bill, to you and your team there. I apologize for pushing on this a little bit more, but I want to pick up where Arun just left off. As I look at your, and I know you're not in a position to give guidance on 2019 here, but maybe we can talk about what your operational pace looks like in Q4 as a starting point to go into Q1 '19. As I look at it, if you're running three rigs and two completion crews here and you're going to be on a kind of -- your '18 guidance implies about $200 million in 4Q. That would be hard to ramp up to six rigs just overnight in the beginning of '19, and am I right or is that a -- should we think about '19 starting off the way that '18 is ending?

Do recall, and we believe this to be an advantage for us, we own and operate our own rigs. Those are our employees that we're talking about. And so our ability to position our rigs, ramp down to invest within cash flow, and then bring those rigs right back up and run at the number of wells that we say we're going to do in rigs in the first quarter and beyond is something we've been doing for some time. So we're actually quite good at it. And this year will be no different. We will phase down in the fourth quarter, as we've already disclosed. But the teams have got clear plans on how to get right back to it.

Okay, that's a helpful distinction to highlight again, Bill. And then if I could ask a question perhaps, of Clay, on the Upper Devonian, I know this is something that you've talked about before. Could you characterize for us kind of where in the maturation or where in your scope of understanding or your development you understand that zone, where it is right now? And if you're in a position to talk about what location count perhaps would be?

Sure, I'll comment on that. So, the one test that we have and the way that it is performing is right in line with our Marcellus lean inventory, which we have a long history with. And so that is the Marcellus -- sorry, the Marcellus rich area of our acreage, and we have a long history there. And the well is tracking nicely there. And that's what our subsurface work and our geology was indicating that that would be the type of performance. So we're really pleased with that. What we're now working on is making sure that we understand the interaction with frac height and the development of an underlying Marcellus interval with a 150-200 foot above that Upper Devonian development. And where they're both virgin rock and where we've had some production in the Marcellus below it, and then we're going to do an Upper Devonian. So, we're steadily progressing our science there. We're going to spend more dollars in '19 to adjust that or to understand that better. And the prize for us a seven to nine Ts of resource, that's including in the resource number that we have on our existing acreage, and the fact that it's liquid rich with the current commodity prices, we think, really gives it an advantage.

Thanks for that added color, Clay.

Our next question comes from Jeffrey Campbell with Tuohy Brothers. Please go ahead.

Good morning and congratulations on another solid quarter.

Thank you. Good morning.

Just a real quick Upper Devonian question because I think you'd mentioned the rich Marcellus several times. Are there any superrich Upper Devonian analogues, and if so will they be tested in upcoming wells or is really the inventory all rich gassed analogue?

We think there's an opportunity for condensate to be present. We're not sure at what levels yet. And so we think there's upside there as we further delineate that we may start getting some of that superrich contribution.

Okay, great. Thank you. And, Bill, I want to kind of as a little bit higher level question, because I just don't think we've heard much of lead Appalachian operators on it. A couple of weeks ago Schlumberger raised some eyebrows when they started saying that they thought that future is all production growth and might be overestimated due to significantly lower performance of offset wells and parent child discussion usually concentrates on the Permian but Schlumberger made it clear that they saw this as an issue throughout North American unconventional resource. So I'm interested in your view and in particular in reference to your white gas regions.

Yes, let me take a shot now and get Clay to add to it. I think that the possibility exists and there're facts that backed that up in the Permian and other areas where you have issues with parent child relationships. What we've seen in the Appalachian base in both and dry and wet part of this is a timing issue as you go and develop pads and a flock of acreage and move about proving up your large footprint going in and drilling wells to lockup an area and then not coming back to them for quite some time does have a risk that you create I should say and then that can impact that I think our planning, our development plans and our planning really try to assure that, that doesn't happen to us. And we have not seen where we've been very deliberate about moving through our acreage, securing that acreage and then being very efficient about how we develop that we've not have that type of degradation in an immaterial way.

Now, I'll come in a little further, I'm familiar with the presentation. I think it is a potentially more significant issue when you're in basins with five and six benches and you have much tighter development spacing than what we are operating on. And so, I think it is an issue, it's -- I think a whole lot of it is about your subsurface understanding and that you develop the asset on the right spacing from the get go and then you have less of this parent child situation, some of the other part of that paper was about wells are not continuing to just benefit from greater and greater and greater profit loadings and that we are starting to figure out the optimal or more optimal profit loading and what's coming with that is maybe not as much sand usage, which is then creating some cost benefit as we go forward.

Okay. And I would think based on the last thing that you said. I mean, knowing that Southwestern is so focused on returns I mean, you I think you guys would be very sensitive that I want to over capitalize a well, just to in the name of marginal increase production, is that fair?

Exactly, and the evidence that would back that very clearly is our Sand loading, we've got out way up in front in terms of increasing san loading from one to as much as 5000 pounds per foot and we did that technically and then very quickly work to back off on that because it was more about returns than about that little tiny bit of production because it wasn't -- it didn't pay to do that. And so, economics drove that and that's how we work at and that's an example of just doing that.

Okay, great. I really appreciate the color and we look forward to seeing you next month.

We look forward to seeing you as well.

Thank you.

Our next question comes from Marshall Carver with Heikkinen Energy Advisors. Please go ahead.

Yes, you gave some commentary on depth pricing for 4Q assuming the triples, what sort of NGL pricing would you expect and less worthy here.

This is Jason, Marshall. Yes, I think based on what we are seeing right now, we would expect the NGL pricing to be in line with what we've got into for the year, we saw pricing move up in the September early October and it's then probably got over down a little bit, prices have come back, have come back off, so I think it will be in line with what we got into.

Okay. Thank you and one follow-up. You've given liquids growth commentary into 2019, you are drilling wells with a really high oil cut. Do you have any color on the oil versus NGL split into next year?

Yes, So I don't have definitive percentages there. I think with the math of our current split? I think we are somewhere around 5% is coming from condensate and the rest is coming from NGLs. I think it's 3% to 5% of our 20% right now and we'll as we tighten up the budget and then tighten up with schedules, we will get that information out of it at the time.

Okay, thank you.

Our next question is from Dan McSpirit with BMO Capital. Please go ahead.

Thank you, folks. Good morning. What's the tolerance doubt spend cash flow over the next two years that's strip pricing. That is, should we look at the $600 million that's allocated to supplement cash flow over the next two years as the governor on growth?

The governor on growth for us, when you take the $300 million of cash flow replacement that Appalachians been consuming from Fayetteville and you take forward curve pricing and you put it all together, that's -- the cash flow that's generated and this 300 supplement are is the cap on capital investment. We are, we have a fully funded budget and we won't go past that we will add to that just to drill wells.

Very good and as a follow-up to that, how do the fully burden breakeven prices across your Appalachian base and asset base compare and how are they expected to change on further efficiency and effectiveness gains and really asking an effort to get a better handle on the marginal cost of supply and how it needs with the cost of associated gas?

Yes, so our break evens in northeast staff. We're around a 250-gas price breakeven and then when you -- when you look at our rich and super rich areas, if you assume a $60 oil price and an $18/barrel NGL price are super rich pushes down around below a $1 gas price because of the benefit of the condensate and the NGLs and then our rich area is down around a $2 gas price breakeven.

Very helpful. Thank you. Have a great day.

Sure. Thanks.

Our next question comes from Jane Trotsenko with Stiefel. Please go ahead.

Good morning. My first question is about the Northeast Appalachia, could you please comment on how in based and dynamics have changed in Northeast Pennsylvania with the coming online of Atlantic sunrise especially I'm interested to hear if more space became available on local pipelines, so that you could possibly get much better pricing right now and do you -- how do you think about production growth in Northeast Pennsylvania for the next year?

This is Jason. I'll -- that's a good question. Let me see if I can put some color around Northeast Pennsylvania, so recently Rover, Atlantic Sunrise and Nexus they -- about 4 Bcf a day in total of capacity when in service in the entire northeast Appalachian basin specifically Atlantic, Atlantic Sunrise was about 1.7 Bcf a day, out of Northeast PA and what we initially seen is that we've created 1.7 Bcf a day of capacity with this pipe going in service and we've probably seen about a Bcf a day of gas coming off of existing pipes going into Atlantic Sunrise and new production somewhere around half of Bcf a day going in the service, so the in service of Atlantic Sunrise is definitely going to create some opportunities to sell into local indices up there and from a from a differential standpoint we are probably seeing higher cash prizes and local prices [indiscernible] than what we've seen in five years up in that area. So there's definitely some opportunities to create margin in that in that area going into the local industries.

I see and that. Go ahead. Yes.

And as far as production growth that was again, part of our budget, we look at the portfolio of assets that we have in Appalachia as a combined unit and we run rig lines and well models, we figure out economics on each project. We force to rank them and then feed them into the capital program against cash flow. So as we've thought refine those numbers, we will put out details around each individual asset, but we have transportation capacity that, that we already own and we can move all the gas that we that we need to move to the markets that we that we choose to go to.

Okay, got it and maybe a related question. I'm just curious given this improvement in basin in pricing in Northeast Pennsylvania, the asset should compete quite well with Southwest Appalachia, you know, even though, Southwest Appalachia has NGL component. I mean, I'm just curious how this has changed the way you look at your assets.

Yes, you're exactly right. We have some highly competitive projects in both areas. So our focus in Appalachia is to look at the portfolio projects from each one and handpick the best of the best and put them in our drilling schedule. And as prices move around if liquids come up or go down or gas goes up or go down, we make adjustments to those so that again we have highest margin projects being completed and we're doing so within our funding mechanism of cash flow.

Okay. Got it. And my final question is about low cost, do you think you'll see low cost inflation in 2019 or would it be like relatively flat?

We actually kind of look at it a little bit different. First of all, we own all of our rigs and two of our rigs and two of our fracs, so we mitigate increases in cost quite well. We are actually seeing a deflationary effect on the balance of items that we use -- we're able to self source sand, we're able to do a lot with our terrific strategic sourcing group and they from contracting mechanisms to just really anticipating the market, we're not expecting a increase in cost overall.

That's terrific, thank you so much.

Our next question comes from Sean Sneeden with Guggenheim. Please, go ahead.

Hi, good morning and thanks for taking the questions.

Sure.

Bill, maybe for you, can you talk a little bit about how you're thinking about the long-term NGL strategy and you know, I guess, how do you guys see that playing out as more and more of your peers are prioritizing NGL production growth and to kind of put that in context with pretty limited or no new export capacity?

Yes, it's a great question. How we approach any of these efforts in the company whether it be an NGL pathway or a gas pathway is we take a very integrated view, we look at both the -- from the rock through how we access the rock, through the infrastructure, through the facilities to process for re-fractionation and export routes all the way through the value chain and we work to optimize each piece of it and that helps us understand how to get ahead of trends -- as I said before, we're ahead of trend on securing, gathering and processing fractionation pipeline in any exit route. And then we manage our growth in that particular area accordingly. You know, a liquid rich well isn't advantaged unless you can get to market. So as we look at that, we manage with that infrastructure and stay ahead. Our view with the in basin projects that are under development for ethane the opening up of additional export routes, the ability to export it, purity ethane our capacity to the Gulf Coast, marries two project coming online and projects that are -- that come behind that. We will compete effectively to get access to those. We're positioned in some of the best rock in the basin so the economics are quite strong and we're very confident that we can -- we'll get through that. We don't have near-term constraints on any part of this business at the moment and I think that's a testament to our folks and we will operate out in front securing capacity that we need. But our view and the view of advisors that we work on is that the capacities are available, they'll get produced, they'll get -- the demand is strong and we'll work into that and it's -- that's really how we approach everything we do.

Great. Now that's helpful And I appreciate the commentary around lateral length earlier, but I think the average for Q3 was roughly 7,000 feet. How should we think about that progressing in 2019 as we kind of go along here and especially with some of the recent success on the 15,000 footers?

So our average -- and averages can be interesting. But our average for -- in next year should approach 9,000 feet. And lateral length has got a lot of dimensions to it. One of them is have you secured the land to be able to do those long laterals, are you in a mature area where units are already set, is there any negotiating that can extend them? We're in a great position in -- especially, in the Tioga area, which is our latest development in northeast and in our -- across our southwest Appalachia acreages that we're early enough in the cycle, early enough in -- with our land teams to set up the conditions to be able to extend laterals on longer units and then with the work that Clay and his team are doing around you know, again heading from 10 to 12 to 14 to 16 and so on, we can capitalize on all that great set of work. And so our trend is longer. We set a number as I said about 9,000. Emphasis point here if economics and risk tell us don't go further, we won't go further. This isn't a game for us who has the longest lateral and they don't work. That's not our -- that's not how we do it.

Yes, one thing I would add is that the lateral links that we report quarterly tie to the wells turned to sales. So there's a little bit of a lag there because those wells may've been drilled in 4Q, 1Q, 2Q and then our current drilled wells have longer, average laterals than that and then they'll show up when those wells get turned to sales.

Perfect. That's a helpful clarification. Thanks guys.

Thank you.

This concludes our question-and-answer session. I would like to turn the conference back over to Bill Way for any closing remarks.

Yes, thank you all for joining us today. When I step back and I look at all this, our highly talented teams continue to deliver impressive results and that was shown in this quarter and it supports our commitment to drive long-term shareholder value. We continue to unlock value in every part of our company and everybody understands that's the mission. And as we reposition the company to deliver top quartile performance, focusing on high value liquids rich investment opportunities in our assets. And I'll tell you we're quite enthusiastic about our future and look forward to joining you again on the next call to discuss even more progress being made to capture growing value in our assets and for our shareholders. So I want to thank you all for joining us. Thank you for the questions and hope you all have a great weekend. Take care.

This concludes Southwestern Energy third quarter earnings call. You may now disconnect.