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Southwestern Energy Co (SWN 0.79%)
Q3Â 2018 Earnings Conference Call
Oct. 26, 2018, 10:00 a.m. ET
Contents:
- Prepared Remarks
- Questions and Answers
- Call Participants
Prepared Remarks:
Operator
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 yourselves to two questions. Afterward, you may feel free to requeue 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.
Paige Penchas -- Vice President of Investor Relations
Thank you, Brandon. Good morning, and welcome to Southwestern Energy's third quarter 2018 earnings call. Joining me today is Bill Way, President and Chief Executive Officer; Clay Carrell, Chief Operating Officer; Julian Bott, Chief Financial Officer; and Jason Kurtz, Vice President, Marketing and Transportation.
Yesterday afternoon, Southwestern Energy released financial results for the quarter ended September 30, 2018. The release is available on our website at www.swn.com. Our 10-Q for this quarter has been posted on our website. 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 vary -- 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 website.
I'll now turn the call over to Bill Way.
William Way -- President, Chief Executive Officer, Director
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 toward our goal of sustainable 2 times leverage. Our strengthened 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 a 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 5,000-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 year-end 2017, one-third of which is comprised of liquids. As I indicated previously, we agreed to sell Fayetteville for $1.865 billion, subject to customary adjustments and are delivering on our promise of debt reduction, and return of capital to shareholders in the form of a share repurchase program.
Bondholders accepted our tender offer and, as such, we will reduce SWN's bond debt by $900 million, effective with the closing of the transaction in early December. Additionally, we began our $200 million share repurchase program in September and have repurchased $25 million of stock to-date. We are on a mission to achieve both the sustainable 2 times leverage ratio and free cash neutrality by the end of 2020.
Our Northeast Appalachia assets are already cash flow positive, and over the next two years, we plan to replace the Fayetteville cash flow of approximately $300 million per year, which was -- with funding as part of Southwest Appalachia's development by utilizing a portion of the sales proceeds to responsibly invest in high return liquids projects in the basin. We expect these steps will enable us to achieve both of our goals.
I continue to be impressed with the operational and technical capabilities of our team. When you couple their excellent skill sets with the high quality purpose-built drilling rigs and frac fleets that we own, we are uniquely positioned to consistently drive outperformance in our assets. Our rigorous returns focused capital allocation provides laser focus on cost efficiencies, well performance and innovation for continuous improvement.
As evidenced by our quarterly results, we continue to make meaningful improvements and remain focused on delivering high-end operational and financial results in a safe and efficient manner. Going forward, with our team's leading execution capabilities combined with greater liquids exposure, basis improvements and a fully funded '19 and '20 capital program, SWN is well positioned for solid return-focused value creation.
Now, we all know how volatile commodity prices are. As we have clearly demonstrated, we will adjust our capital program with changes in the commodity price and only drill when our portfolio of projects yields the required returns for generating real value for our shareholders. Production growth continues to be an outcome of our strategy and results-driven investment practices and not a goal in itself.
We remain committed to our clearly demonstrated returns-focused capital allocation, improving operating efficiency and risk management through hedging to protect cash flows, while capturing further opportunities throughout our highly economic asset base. At all times, we remain flexible and I speak from experience when I reinforce the point, we will not drill if we cannot generate meaningful returns.
In summary, Southwestern Energy has had another outstanding quarter both financially and operationally. Year-to-date, we have reduced costs, outperformed in our operations and raised production guidance without increasing capital guidance. And let me be clear here, our capital investment is right in line with our original plan and will not exceed guidance. Our team is really delivering this year, setting the stage for continued success in the coming years with a firm strategy in place that guides everything we do.
And finally before I turn it over to Clay, this is the last quarter that we will own our Fayetteville assets. And I want to say to all of the Fayetteville employees, extraordinary work, extraordinary results, you are truly a remarkable team. Thank you for what you've done to make Southwestern Energy what it is today, one of this nation's leading shale producers. You're an inspiration to all of us at SWN and we are grateful for your dedication and commitment. Please note that this asset and its people have changed the gas business forever and the legacy you leave will be part of our company well into the future.
Now, let me turn the call over to Clay, our COO to discuss operating highlights.
Clayton Carrell -- Chief Operating Officer, Executive Vice President
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 $1 million barrels.
Appalachia production of a 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 continued 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 1,100 to 1,400 btu gas and represent initial condensate yields in the 150 barrel to 200 barrel per million range. As a result of a 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 links over time and then incorporated the learnings into the next lateral length extension.
We have progressed from 10,000 feet to 13,000 feet, and now 16,000 feet over a two-year period without any significant cost overruns or deviations to the original drilling plans. These successes result from the company's leading technical and operational execution capabilities, our drilling and completion teams and our ability to assemble contiguous acreage positions. In the third quarter, we averaged 4 rigs and 3 frac crews, and in the fourth quarter, we expect to average 3 drilling rigs and 2 frac crews consistent with our original activity and investment plans for the year.
In Northeast Appalachia, we posted record net production of 1.3 Bcf per day. In addition to the new wells we brought online in the quarter, compression was added to maximize throughput. We continue to optimize production without adding significant cost. Our Tioga water project was operational in the quarter and all future wells in that area will benefit from the expected cost savings of $400,000 per well.
In Southwest Appalachia, we had total production of 66 Bcfe, 52% of which was liquids. NGL and oil production averaged 56,300 barrels per day and 10,800 barrels per day, totaling 67,100 barrels per day of liquids. 14 of the 16 wells turned to sales during the quarter, were in the super rich area and had a product mix of 43% NGLs, 23% oil and 34% gas. Our Southwest Appalachia water project is already generating benefits, as our first pad was completed utilizing the new water system this quarter. We are on schedule to deliver piped water to all wells beginning in 2019, with an estimated $500,000 per well savings. Further, we expect this will result in taking approximately a 140,000 truckloads of water off the roads next year.
Our initial Upper Devonian well continues to perform in line with our rich Marcellus wells, contributing greater than 40% liquids. Further testing is ongoing and planned in 2019 to add to our liquids-rich inventory. We are encouraged about the Upper Devonian opportunity, it's liquids-rich, it has a similar development cost to the Marcellus and it can utilize the existing Marcellus processing and gathering infrastructure. For the Utica or Upper Point Pleasant, we continue to advance our drilling completion and subsurface knowledge through our ongoing data trades and technical evaluation. We are planning a 3D seismic program in 2019 to further advance our assessment of the play.
In summary, we are on track to deliver at or above on all our operational guidance metrics, while keeping costs and expenses within the original guidance. During the year, we have seen low single-digit service cost inflation and we've been able to offset that with operational efficiencies.
Now, I will turn the call over to Julian for the financial highlights.
Julian Bott -- Chief Financial Officer
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, liquids 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. Basis 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 on it 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 ATEX pipeline.
Condensate realizations of $61.20 per barrel reflect a 12% discount to NYMEX pricing and include transportation. We continue to successfully manage takeaway capacity for our condensate, despite tight trucking capacity in the area. Year-to-date, we have invested just over $1 billion in capital and we remain committed to keeping within our total capital investment guidance of $1.25 billion for the year. We initiated the previously announced share repurchase program during the quarter, buying 4.8 million shares for $25 million or an average cost of $5.18 per share.
Bill mentioned cost savings initiatives and I want to give a bit more detail of what we've done this year, as well as address incremental opportunities. Total cost reductions will be approximately a 100 million -- $180 million per year, starting in 2019. This includes approximately $80 million in interest expense and financing cost savings with the remainder in organizational cost reductions. On the second quarter call, we described G&A initiatives that will save $70 million per year. The remainder of the reductions are associated with Fayetteville and will start to be realized once the transaction closes.
Having announced the Fayetteville sale in September and with the transaction progressing to close in December, I'd like to briefly address its impact on our financial statements, the pro forma debt and liquidity and considerations as we look to the fourth quarter's results. In the third quarter, we reported a non-cash impairment of a $161 million related to the Fayetteville assets, primarily midstream, which were reclassified as held for sale as we allocated sales proceeds and marked them to fair market value.
Our banks have completed our full borrowing base redetermination that excludes the Fayetteville assets and our RBL commitment is confirmed at the same $2 billion level, following the close of the sale. We also successfully completed a $900 million debt tender contingent on closing, which further strengthens our balance sheet and alleviates any material near-term bond maturities. Looking ahead, we remind you that we will continue to report cash flow and production from the Fayetteville assets as part of our operations until the transaction closes, which we expect to occur in early December.
Finally, I'd like to address hedging. During the quarter and in the subsequent period, we have continued our proactive risk management strategy by adding to our hedge position to capture the recent price increases we have seen in the NGL markets. Our hedging philosophy remains unchanged and at current gas pricing levels, we continue to utilize collars where possible to protect our cash flow, while retaining upside exposure.
That concludes our comments, and I'd like to turn it over to Brandon to begin the Q&A session.
Questions and Answers:
Operator
Thank you. We will now begin the question-and-answer session. (Operator Instructions) Our first question comes from Holly Stewart with Scotia Howard Weil. Please go ahead.
Holly Stewart -- Scotia Howard Weil -- Analyst
Good morning, gentlemen, Paige.
Paige Penchas -- Vice President of Investor Relations
Good morning.
Holly Stewart -- Scotia Howard Weil -- Analyst
Maybe first, you've done a lot of talk about NGLs and pricing and your production uptake 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?
Jason Kurtz -- Vice President-Marketing, Transportation
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 would 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 ATEX capacity.
William Way -- President, Chief Executive Officer, Director
And so I'll add to that. We contract well ahead, so that we have no gathering, processing, transportation or fractionation constraints into 2019.
Holly Stewart -- Scotia Howard Weil -- Analyst
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?
Jason Kurtz -- Vice President-Marketing, Transportation
They are all fee-based.
Holly Stewart -- Scotia Howard Weil -- Analyst
Okay. And then maybe just as a follow-up. Julian, you mentioned on the guidance, you said 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 shifts the capacity that you've got on a couple of these projects that are factored in, but is it 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?
Julian Bott -- Chief Financial Officer
Sure. Holly, as I was suggesting, I think if things continue as we see in forecast, we expect that we will be probably below our guidance. And at this point, probably in the mid $0.60 to $0.70 range.
William Way -- President, Chief Executive Officer, Director
For basis.
Julian Bott -- Chief Financial Officer
On the basis.
Holly Stewart -- Scotia Howard Weil -- Analyst
Yeah. That's great. Thanks guys.
Operator
Our next question comes from Arun Jayaram with JPMorgan. Please go ahead. Arun, your line is now live.
Arun Jayaram -- JPMorgan -- Analyst
Yeah. Good morning. Bill, I was wondering, if you could walk through kind of the benefits of shifting toward the longer laterals? You talked about drilling a 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 feet?
Clayton Carrell -- Chief Operating Officer, Executive Vice President
Right. 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.
William Way -- President, Chief Executive Officer, Director
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 feet. This 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 were right on target in terms of their costs. 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 optimize around economics.
Arun Jayaram -- JPMorgan -- Analyst
Yeah. Bill, just to follow-up is, 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?
Clayton Carrell -- Chief Operating Officer, Executive Vice President
Yeah. Arun, again, Clay. The -- 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 you know, there is 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.
William Way -- President, Chief Executive Officer, Director
I think the secret of 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 are applying learnings that we have, whether the 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.
Arun Jayaram -- JPMorgan -- Analyst
Okay. Just one more quick question. You guys have talked about running up to 6 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?
William Way -- President, Chief Executive Officer, Director
Yeah. We haven't -- we're right now assembling our budget and we typically approve our budget in the first quarter. We are 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 -- 6 rigs is an estimate based on a forward curve of natural gas and the other commodities. We put it through our model to generate cash flow and we are replacing the Fayetteville cash flow with 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 is the only 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 on that, but that work is under way.
Arun Jayaram -- JPMorgan -- Analyst
Okay, Thanks a lot.
Operator
Our next question comes from Charles Meade with Johnson Rice. Please go ahead.
Charles Meade -- Johnson Rice -- Analyst
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, you're running 3 rigs and 2 completion crews here and you're going to be on kind of -- your '18 guidance implies about $200 million in 4Q. That would be hard to ramp up to 6 rigs just overnight in the beginning of '19, am I right? Or is that -- should we think about '19 starting off the way that '18 is ending?
William Way -- President, Chief Executive Officer, Director
I 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 just 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 are 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 we've -- the teams have got clear plans on how to get right back to it.
Charles Meade -- Johnson Rice -- Analyst
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 the -- your scope of understanding your development, you understand that zone, where it is right now? And if you're in a position to talk about what a location count perhaps would be?
Clayton Carrell -- Chief Operating Officer, Executive Vice President
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 rich -- 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 sub-surface work in 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 type and the development of an underlying Marcellus interval with a 150, 200 foot above that Upper Devonian development. And where there are both virgin rock and where we've had some production in the Marcellus below it and then we're going to do in 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 is 7 to 9 Ts of resource, that's including then the resource number that we have on our existing acreage, and the fact that it's liquids-rich with the current commodity prices, we think really gives an advantage.
Charles Meade -- Johnson Rice -- Analyst
Thanks for the color, Clay.
Operator
Our next question comes from Jeffrey Campbell with Tuohy Brothers. Please go ahead.
Jeffrey Campbell -- Tuohy Brothers -- Analyst
Good morning and congratulations on another solid quarter.
William Way -- President, Chief Executive Officer, Director
Thank you. Good morning.
Jeffrey Campbell -- Tuohy Brothers -- Analyst
Just real quick Upper Devonian question because I think you've mentioned the rich Marcellus several times. Are there any super-rich Upper Devonian analogs? And if so, will they be tested in upcoming wells or is it really the inventory all rich gas analog?
William Way -- President, Chief Executive Officer, Director
We think there's an opportunity for condensate to be present, we're not sure at what levels yet. And -- so we are -- we have -- we think there's upside there as we further delineate that we may start getting some of that super-rich contribution.
Jeffrey Campbell -- Tuohy Brothers -- Analyst
Okay, great. Thank you. And Bill, I want to kind of ask a little bit higher level question because I just don't think we've heard much out of a lead Appalachian operators on it. A couple of weeks ago, Schlumberger raised some eyebrows when they started saying that they thought that future US oil production growth might be overestimated due to significantly lower performance of offsite 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 particularly in reference to your wet gas regions.
William Way -- President, Chief Executive Officer, Director
Yeah. Let me take a shot at it and I'll get Clay to add to it. I think that the possibility exists and there's facts that back that up in the Permian and other areas, where you have issues in parent-child relationships. What we've seen in the Appalachia Basin, both in dry and wet, part of this is a timing issue. As you go and develop pads and lock up acreage and move about proving up your large footprint, going in and drilling wells to lock up an area and then not coming back to them for quite some time does have a risk that you create, I should think, and then that can impact that. I think our planning -- our development plans and our planning really tries to assure that that doesn't happen to us. And we have not seen where we've been very deliberate about moving to our acreage, securing that acreage and then being very efficient about how we develop that we've not had that type of degradation in any material way.
Clayton Carrell -- Chief Operating Officer, Executive Vice President
Yeah. I'll comment a little further. I'm familiar with the presentation. I think it is a potentially more significant issue when you're in basins with 5 inches and 6 inches 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 proppant loadings and that we're starting to figure out the optimal or more optimal proppant loading and what's come in with that is maybe not as much sand usage, which is then creating some cost benefits as we go forward.
Jeffrey Campbell -- Tuohy Brothers -- Analyst
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 to not want to overcapitalize a well just to -- in the name of a marginal increase in production. I mean, is that fair?
William Way -- President, Chief Executive Officer, Director
Exactly. And the evidence that would back that up very clearly is our sand loading. We've got out our way up in front in terms of increasing sand loading from one to as much as 5,000 pounds a foot and we did that technically and then very quickly worked back off on that because it was more about returns than about 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 and that's an example of just doing that.
Jeffrey Campbell -- Tuohy Brothers -- Analyst
Okay, great. I really appreciate the color and we look forward to seeing you next month.
William Way -- President, Chief Executive Officer, Director
Look forward to seeing you as well.
Jeffrey Campbell -- Tuohy Brothers -- Analyst
Thank you.
Operator
Our next question comes from Marshall Carver with Heikkinen Energy Advisors. Please go ahead.
Marshall Carver -- Heikkinen Energy Advisors -- Analyst
Yes. You gave some commentary on debt pricing for 4Q. Assuming the strip holds, what sort of NGL pricing would you expect in the last quarter of the year?
Jason Kurtz -- Vice President-Marketing, Transportation
Yeah, this is, Jason, Marshall. Yeah. I think based on what we're seeing right now, we would expect the NGL pricing to be in line with what we've guided to for the year. We saw pricing move up in September, early October and then it's been probably got overdone a little bit and prices have come back off. So I think it will be in line with what we've guided to.
Marshall Carver -- Heikkinen Energy Advisors -- Analyst
Okay, thank you. And one follow-up. You've given liquids growth commentary into 2019. You're drilling wells with a really high oil cut. Do you have any color on the oil versus NGL split into next year?
Jason Kurtz -- Vice President-Marketing, Transportation
Yeah. So I don't have definitive percentages there. I think with the math of our current split, I think we're somewhere around 5%, it is coming from condensate and the rest is coming from NGLs. I think it's 3% to 5% of our 20% right now.
William Way -- President, Chief Executive Officer, Director
And well, as we've tightened up the budget and then tightened up the schedules, we will get that information out at the time.
Marshall Carver -- Heikkinen Energy Advisors -- Analyst
Okay, thank you.
Operator
Our next question is from Dan McSpirit with BMO Capital. Please go ahead.
Dan McSpirit -- BMO Capital Markets -- Analyst
Thank you. Folks, good morning. What's the tolerance to outspend cash flow over the next two years at 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?
Julian Bott -- Chief Financial Officer
The governor on growth for us when you take the $300 million of cash flow replacement that Appalachia has 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 million supplement are -- is the cap on capital investment. We are -- we have a fully funded budget and we won't go past that. We won't add to debt just to drill wells.
Dan McSpirit -- BMO Capital Markets -- Analyst
Okay. Very good. And as a follow-up to that, how do the fully burdened breakeven prices across your Appalachia Basin asset base compare? And how are they expected to change on further efficiency and effectiveness gains? And really asking in effort to get a better handle on the marginal cost of supply and how it competes with the cost of associated gas.
Julian Bott -- Chief Financial Officer
Yeah. So our breakevens in Northeast App were around a 250 gas price breakeven. And then when you look at our rich and super-rich areas, if you assume a $60 oil price and an $18 per barrel NGL price, our 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.
Dan McSpirit -- BMO Capital Markets -- Analyst
Very helpful, thank you. Have a great day.
Julian Bott -- Chief Financial Officer
You too. Thanks.
Operator
Our next question comes from Jane Trotsenko with Stifel. Please go ahead.
Jane Trotsenko -- Stifel -- Analyst
Good morning. My first question is about the Northeast Appalachia. Could you please comment on how in-basin dynamics have changed in Northeast Pennsylvania with the coming on line 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?
Jason Kurtz -- Vice President-Marketing, Transportation
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 winning service in the entire Northeast Appalachia Basin, specifically Atlantic Sunrise was about 1.7 Bs a day out of Northeast PA. And what we've initially seen is that we've created 1.7 Bs a day of capacity with this pipe going in service and we've probably seen about a 1 Bcf a day of gas coming off of existing pipes going into Atlantic Sunrise and new production somewhere around 0.5 Bcf a day going into 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 differential standpoint, we're probably seeing higher cash prices and local prices (inaudible) and what we've seen in five years up in that area. So there's definitely some opportunities to create margin in that area going into the local indices.
Jane Trotsenko -- Stifel -- Analyst
I see and -- go ahead. Yeah.
William Way -- President, Chief Executive Officer, Director
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 rank them and then feed them into the capital program against cash flow. So as we refine those numbers, we will put out details around each individual asset. But we have transportation capacity that we already own and we can move all the gas that we need to move to the markets that we choose to go to.
Jane Trotsenko -- Stifel -- Analyst
Okay, got it. Maybe related question. I'm just curious, given this improvement in in-basin pricing in Northeast Pennsylvania, the asset should compete quite well with Southwest Appalachia, even though Southwest Appalachia has this NGL component. I'm just curious, how this has changed the way you look at your assets?
William Way -- President, Chief Executive Officer, Director
Yeah. It -- you are exactly right there, we have some highly competitive projects in both areas. So our focus in Appalachia is to look at the portfolio of projects from each one and hand-pick the best of the best and put them in our drilling schedule. So -- 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 are doing so within our funding mechanism of cash flow.
Jane Trotsenko -- Stifel -- Analyst
Okay, got it. And my final question is about well costs. Do you think you will see well cost inflation in 2019 or would it be like relatively flat?
William Way -- President, Chief Executive Officer, Director
We actually kind of look at a little bit different. First of all, we own all of our rigs and two of our frac fleets. So we mitigate increases in cost quite well. We're actually seeing a deflationary effect on the balance of items that we use. We're able to self source sand, we are 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 costs overall.
Jane Trotsenko -- Stifel -- Analyst
That's perfect. Thank you so much.
Operator
Our next question comes from Sean Sneeden with Guggenheim. Please go ahead.
Sean Sneeden -- Guggenheim -- Analyst
Hi, good morning and thanks for taking the questions. Bill, maybe for you, can you talk a little bit about how you're thinking about the long-term NGL strategy? And 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?
William Way -- President, Chief Executive Officer, Director
Yeah. It's a great question. How we approach any of these efforts in the company, whether it'd 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, through fractionation, 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. I said before, we are ahead of trend on securing, gathering, processing fractionation pipeline in any exit route. And then we manage our growth in that particular area accordingly. If -- 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 purity ethane, our capacity to the Gulf Coast, (inaudible) project coming online and projects that are -- that come behind that, we will compete effectively to get access to those. We're positioned in the some of the best rock in the basin. So the economics are quite strong and we 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 just -- the capacities are available, they will get produced, the demand is strong and we'll look into that and that's really how we approach everything we do.
Sean Sneeden -- Guggenheim -- Analyst
Great. No, that's helpful. And I appreciate the commentary around lateral length earlier, but I know -- 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 16,000 footers?
William Way -- President, Chief Executive Officer, Director
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 and especially in the Tioga area, which is our latest development in Northeast and in our -- across our Southwest Appalachia acreages that were early enough in the cycle, early enough in -- with our land teams to set up the conditions to develop -- to be able to extend laterals on longer units. And then with the work that Clay and his team are doing around, again heading from 10,000 to 12,000 to 14,000 to 16,00 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.
Jason Kurtz -- Vice President-Marketing, Transportation
Yeah. One thing I would add is that the lateral lengths that we report quarterly tie to the wells turn to sales. So there's a little bit of a lag there because those wells may have been drilled in 4Q, 1Q, 2Q and then our current drill wells have longer average laterals than that and then they'll show up when those wells get turned to sales.
Sean Sneeden -- Guggenheim -- Analyst
Perfect. That's a helpful clarification. Thanks guys.
William Way -- President, Chief Executive Officer, Director
Thank you.
Operator
This concludes our question-and-answer session. I would like to turn the conference back over to Bill Way for any closing remarks.
William Way -- President, Chief Executive Officer, Director
Yeah. Thank you all for joining us today. When I step back and 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 will 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.
Operator
This concludes the Southwestern Energy third quarter earnings call. You may now disconnect.
Duration: 50 minutes
Call participants:
Paige Penchas -- Vice President of Investor Relations
William Way -- President, Chief Executive Officer, Director
Clayton Carrell -- Chief Operating Officer, Executive Vice President
Julian Bott -- Chief Financial Officer
Holly Stewart -- Scotia Howard Weil -- Analyst
Jason Kurtz -- Vice President-Marketing, Transportation
Arun Jayaram -- JPMorgan -- Analyst
Charles Meade -- Johnson Rice -- Analyst
Jeffrey Campbell -- Tuohy Brothers -- Analyst
Marshall Carver -- Heikkinen Energy Advisors -- Analyst
Dan McSpirit -- BMO Capital Markets -- Analyst
Jane Trotsenko -- Stifel -- Analyst
Sean Sneeden -- Guggenheim -- Analyst
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