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Southwestern Energy Company (NYSE:SWN)
Q2 2018 Earnings Conference Call
Aug. 3, 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's Second Quarter 2018 Earnings Call. (Operator Instructions) As a reminder, this conference is being recorded. I'll now turn the call over to Ms. Paige Penchas, Southwestern Energy's Vice President of Investor Relations, you may begin.

Paige Penchas -- Vice President-Investor Relations

Thank you, Chad. Good morning and welcome to Southwestern Energy's second 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, Head of Marketing and Transportation. Yesterday afternoon, Southwestern Energy released financial results for the quarter ended June 30, 2018. The release is available on the Investor Relations section of 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 in the coming days.

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 in 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. All comments today exclude any potential impact from strategic alternatives being pursued with respect to our Fayetteville Shale assets.

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.

Bill Way -- President & Chief Executive Officer

Thank you, Paige. Good morning everyone and welcome to our second quarter conference call. Today, I want to talk about the results delivered by our exceptional team of professionals from across the Company who continue to execute on our deliberate and determined strategy to reposition Southwestern Energy to compete and win in a low commodity price environment. Our return focused strategy targets five key areas to deliver improving returns and drive long-term value. We're capturing ever-increasing value from our concentrated portfolio of high-quality large-scale assets. We're driving value from our highest return Appalachia assets and growing our liquids production base in that area. Our leading transportation portfolio maximizes value in a volatile commodity market.

We are adamant about returns focused capital allocation and we invest in the highest value creating projects in our portfolio, all within cash flow. We are making continuous gains on increasing capital efficiency and expanding margin to deepen our inventory and we have a robust hedging philosophy for natural gas basis and a portion of our liquids focused on protecting our cash flows while retaining exposure to increases in commodity prices. And we are leveraging our leading technical and operating capabilities to maximize resource capture through strong operational efficiency and excellent execution.

As 2018 progresses, we continue to reshape the Company. In the second quarter, we improved margins and reported high cash flow, all above prior year levels driven by an increase in liquids production while benefiting from the impact of higher realized NGL and oil pricing. Our Appalachia assets continue to grow and alone generated over $489 million in EBITDA through the first six months of 2018. We took action during the quarter on our previously announced initiative to reduce costs even further with a savings benefit of over $50 million for the remainder of this year or $110 million in annualized savings, which includes interest cost and G&A savings.

We reported total production of 234 Bcfe including record total Appalachia production of 1.8 Bcfe per day and 44% liquids growth year-over-year. Our quarterly production, which is above the high-end of guidance reflects the strength of our high-quality Appalachia assets and as a result, we are raising full-year production guidance to 955 Bcfe to 970 Bcfe and 62,100 barrels per day of liquids with no increase in capital guidance. Important factors that underlie this guidance raise include improving operational execution and well performance. Clay will provide details on this shortly.

Our 2018 capital plan deliberately front loaded activity and we remain on track to invest within our original capital guidance. Further, we expect our assets to generate modest to excess cash flow above capital requirements in the current pricing environment, which clearly demonstrates our momentum and exercise of financial discipline. Our focus on liquids growth continues to improve our economics and we have ample current and forward planned NGL processing and fractionation capacity to deliver further results. We are working with multiple counterparties to strategically structure additional long-term takeaway capacity for propane plus liquids to maximize price, accommodate future growth, all while continuing flow assurance. To reiterate, we are raising production guidance and reaffirming capital guidance while investing within cash flow generated from our operations, consistent with our clear objective to maintain financial discipline.

And finally, before I turn the discussion over to Clay, our commentary around Fayetteville strategic process remains unchanged. As we've clearly and consistently communicated, we want to protect the integrity of this process. We believe it remains in the best interest of our shareholders not to discuss additional details or speculate on future outcomes. We will let you know when the process is completed. And now, let me turn it over to Clay for some operations highlights.

Clay Carrell -- Chief Operating Officer

Thank you, Bill and good morning to everyone on the call and webcast. Operationally we had a strong second quarter, building on the momentum we established in the first quarter. Total production was 234 Bcfe, which is above the high-end of guidance and included 61,370 barrels per day of liquids production. We continued to improve our operational efficiencies and well performance and it showed up in our results. Let me give you a couple of examples. We increased the number of completion stages pumped per day by 36% in Appalachia and reduced facility installation cycle times by 52% in Southwest Appalachia compared to 2017. These improvements coupled with our front-end loaded capital program allowed us to complete 13 more wells in the second quarter than our originally planned activity and bring nine more wells to sales.

I'll now provide a quick asset summary for the quarter and an activity update for the second half of the year. In Northeast Appalachia, we placed 17 wells to sales during the quarter, eight of them in the Tioga area. Late in the quarter, we began to realize the early cost reduction benefits from the previously announced water infrastructure project, which is on track to be completed in the third quarter, at which time we will see the full cost benefit of $400,000 per well. Additionally, we are seeing continued well performance improvements in Tioga. A recent two-well pad had the highest average initial production rate per well we have seen at 29 million cubic feet per day, a 35% increase compared to the initial development pad in the area. The performance increase is attributed to our continued effort to optimize completion designs and lateral placement. Total gross production in the Tioga area has grown from approximately 50 million cubic feet per day in June of 2017 to 210 million cubic feet per day at the end of the second quarter. We also enhanced our future operated drilling inventory in Tioga by executing a joint development agreement with a private firm at no incremental cost. The agreement adds 23 future drilling locations directly adjacent to our existing core position, which allows us to extend lateral lengths to approximately 11,000 feet, which results in improved well economics. Through the execution of this joint development agreement and strategic land leasing, we were able to core up and expand our total acreage in the Tioga area to approximately 37,500 net acres.

In Southwest Appalachia, we placed 26 wells to sales, all in the rich gas area. Our continued focus on liquids has led to NGL growth of 47% and condensate growth of 31%, both compared to a year ago. A two-well development pad was placed online early in the quarter and after 90 days of production, the two wells are producing 22.7 million cubic feet equivalent per day with 40% [ph] condensate and 70% [ph] total liquids including approximately 1,500 barrels of condensate per day, proving to be some of the highest condensate producers in the basin. We also added to the depth of our Southwest Appalachia drilling inventory during the quarter. We placed our first Upper Devonian well to sales less than a month ago and it is producing 15 million cubic feet equivalent per day with 43% liquids, which is in line with our liquids rich Marcellus wells. We are encouraged by the early production performance of the well and have further testing planned for later this year. Our approach to the Upper Point Pleasant has been to accelerate learnings via data trades and we completed additional trades in the quarter. This helps accelerate our operational and technical understanding while minimizing capital investment, so we can allocate capital to higher value liquids rich areas. Lastly, we continue to progress the Southwest Appalachia water project and expect it to be operational by the end of the year. The majority of the capital spend associated with this project will be in the second half of the year.

Fayetteville continues to deliver targeted production and cash flow to the Company. We placed two redevelopment wells online in mid-April. These two wells along with the initial well are showing a 25% to 50% increase in EUR compared to offset wells, which continues to validate the recovery improvements predicted by utilizing advanced completion designs and optimized landing zones. We ended the second quarter with four drilling rigs running and three frac crews. As we think about the second half of the year, we will reduce to two rigs and two frac crews in the fourth quarter. As Bill mentioned, this activity profile is consistent with our original plan, but as a result of the cycle time improvements, we expect to be toward the high-end of our completion count guidance for the year. So we are investing the same amount of capital and getting more done. I'll now turn it over to Julian to discuss the business performance in the quarter.

Julian Bott -- Chief Financial Officer

Thank you, Clay and good morning. We had a very good quarter and we expect that operational momentum contributing to this quarter's performance will continue the rest of the year. In the current pricing environment, we forecast operating cash flow from all our assets to exceed our capital investments. Any excess cash will be used to reduce borrowings under our bank facility.

For the quarter, we generated cash flow of $280 million and adjusted EBITDA of $317 million, an increase of 12% and 13% above last year. These increases were primarily driven by higher liquids production and strong realized liquid prices. For the first six months, we generated cash flow of $638 million and adjusted EBITDA of $713 million. Appalachia contributed $489 million to adjusted EBITDA and Fayetteville E&P and Midstream contributed $191 million.

I'd like to talk briefly about margins. Our Southwest Appalachia division generated a margin of $1.60 per Mcfe during the quarter, an increase of 76% over the same period last year and $1.48 per Mcf for the first six months. The weighted average realized price of $3 for Southwest Appalachia reflects the pricing uplift from liquids on a per Mcfe basis. Our revised full-year guidance for average liquids production is approximately 62,100 barrels per day, which is 37% above 2017. Northeast Appalachia margins were $1.51 per Mcf for the first half of the year including a $0.26 per Mcf improvement in differentials. This was primarily a result of basis continuing to improve in the region as more pipelines go into service. In the second quarter, despite interruptions caused by planned maintenance on multiple northeast pipelines, our marketing team successfully navigated disruptions and our Northeast Appalachia production was 15% higher than the same quarter in 2017.

In the first six months, we invested $741 million in capital expenditures, consistent with our front-end loaded capital program. To reaffirm, we will invest within original capital guidance of $1.15 billion to $1.25 billion for the full-year, all of which will be within cash flow. As Clay mentioned, our activity will reduce in the second half, but actions already taken operationally have contributed to a more positive production outlook for the rest of the year. Our new production guidance range of 695 Bcfe to 707 Bcfe for Appalachia production. Looking at midpoint, this represents a 21% year-over-year growth and compares to original growth guidance of 18%. Our guidance for liquids coming from Southwest Appalachia is 5% higher and represents a 37% growth in liquids year-over-year to more than 68,200 barrels per day in the fourth quarter. Northeast Appalachia annual guidance is on average 15 Bcfe higher due to well outperformance, operational efficiencies and gathering system improvements. These improvements were achieved with no additional capital cost, which is consistent with our production guidance increase without a corresponding change in capital guidance. Lastly, our liquidity position remained strong with approximately $1.5 billion available under our revolving credit facility, net of borrowings and letters of credit. Our leverage ratio remained essentially flat quarter-over-quarter at 2.7 times debt-to-EBITDA compared to 3.1 times at the end of the second quarter last year. That concludes our comments and I'd like to turn it back to Chad to begin the Q&A session.

Questions and Answers:

Operator

Thank you. We will now be conducting our question-and-answer session. (Operator Instructions) The first question will come from Charles Meade with Johnson Rice, please go ahead.

Charles Meade -- Johnson Rice & Company -- Analyst

Good morning, Bill to you and your team there.

Bill Way -- President & Chief Executive Officer

Good morning, Charles.

Charles Meade -- Johnson Rice & Company -- Analyst

Bill, you guys already gave some detail on what the back half of 2018 activity level looks like and I appreciate that, but I wanted to explore it a little bit more and see if it holds any indications for 2019 that you'd be willing to share. So you guys are going down to two rigs and two frac crews, if I heard that right, in the back part of the year. Do you anticipate that being kind of a maintenance level where you stay and is that a level that would be kind of consistent with what you want to run in the case of Fayetteville sale sometime in the back half of this year?

Clay Carrell -- Chief Operating Officer

You're correct, this is Clay, on the two rigs and two frac crews at the latter part of the fourth quarter. We haven't completed our 2019 budget plans, but as we've talked about and is characteristic of us in the past years, is there's typically a ramp up as we move into the new budget year and I expect that to be heavily focused in Appalachia.

Charles Meade -- Johnson Rice & Company -- Analyst

Got it. That's helpful detail, Clay. And then Bill, I want to be respectful of your comments about not talking around the Fayetteville sale, but I wonder if you could help educate us and maybe the market a little bit, there was a recent sale by another firm of Fayetteville assets and can you talk a little bit about your -- the profile of your Fayetteville versus the profile of those assets that recently transacted and what maybe -- obviously they are in the same -- the assets in their same field, but what the important differences are between those two?

Bill Way -- President & Chief Executive Officer

Yes, Charles, I respect the question a lot. As I said, we're not going to comment on anything related to Fayetteville at this time. Process is ongoing and once we have concluded that, we'll let everybody know and so let me just leave it there.

Charles Meade -- Johnson Rice & Company -- Analyst

Okay. Thanks, Bill.

Operator

The next question will come from Rehan Rashid with B Riley FBR, please go ahead.

Rehan Rashid -- B Riley FBR, Inc. -- Analyst

Good morning. Just a couple of questions. The $110 million of savings beginning in 2019, I just want to confirm that all the benefits kind of will show up in '19, did we see anything this year? And then could you recap for us, if you could please, the breakdown of the sources of where we got these savings from?

Julian Bott -- Chief Financial Officer

Sure, this is Julian. So actually we will see benefit already because those steps have been taken. Of the $110 million, about $40 million is associated with financing costs, both from improving the capital efficiency when we did the revolver and also from the ratings upgrade that we got from the two ratings agencies, which gave us the ability to get rid of some of our letters of credit and credit assurance related costs. Those have happened, so that starts showing. Then as far as the remainder, the $70 million, those are ongoing steps, there was a reduction in force that we had at the very end of the second quarter. So you didn't see it in the second quarter numbers, but you start seeing those results or the effect of that coming as we move through the year.

Rehan Rashid -- B Riley FBR, Inc. -- Analyst

Okay, thank you. On the operational side in the Appalachias', the Northeast and the Southwest, as you think about '19, kind of -- as you think about kind of oil margins versus liquids margins versus gas margins, how much more practical room is there to shift capital whatever you spend in the Northeast as a proportion between Northeast and Southwest, meaning, can you shift more than what we have today or for '18 into the more liquids rich area for '19 and '20?

Bill Way -- President & Chief Executive Officer

Yes, this is Bill. We have the flexibility given the fact that we own our rigs, we own one of the frac fleets that's working and we set our contracts up to be basin -- our Appalachia area is broad enough, we can move back and forth and as we've done historically, our budget planning process will happen later in the year, we'll take a look at pricing and we can shift either as a budget or we can shift virtually on the fly as we conclude wells. So as we manage that area, we manage it as a portfolio and we'll continue to do so. So there's a lot of flexibility there.

Rehan Rashid -- B Riley FBR, Inc. -- Analyst

Perfect, thank you. Real quick for Clay. What would be your top two operational goals for second half of '18 and for '19? Thanks.

Clay Carrell -- Chief Operating Officer

Sure, clearly to continue to make operational efficiency improvements. We've made great strides, but I think there is room for us to continue that and then equally important is that we continue to advance the subsurface performance that we continue to improve how we are completing the wells and continue to get better production profiles out of them.

Rehan Rashid -- B Riley FBR, Inc. -- Analyst

Thank you.

Operator

Our next question will come from Marshall Carver with Heikkinen Energy Advisors, please go ahead.

Marshall Carver -- Heikkinen Energy Advisors -- Analyst

Yes, good morning. Just a question, after you have your water system in place, where do you expect well costs to be in Appalachia by liquids rich versus your more condensate area or dry areas?

Bill Way -- President & Chief Executive Officer

Sure, that all will vary depending upon lateral length, but when we get those -- both of those water systems fully up and running and we've talked about the $400,000 per well benefit in Northeast App and a $500,000 per well benefit in Southwest, we feel comfortable we'll get down in that $900 per foot type of range on the performance of those wells.

Marshall Carver -- Heikkinen Energy Advisors -- Analyst

Okay and that applies $900 a foot in both Northeast and Southwest?

Bill Way -- President & Chief Executive Officer

Yes.

Marshall Carver -- Heikkinen Energy Advisors -- Analyst

All right. Thank you.

Operator

The next question will come from Michael McAllister with MUFG Securities.

Michael McAllister -- MUFG Securities -- Analyst

Good morning, guys. Thank you for taking my question. There's a comment in the press release about using the cash flows or the free cash flows to address the credit facility, is that about $350 million?

Julian Bott -- Chief Financial Officer

Yes, that's right. In the 10-Q, it was $360 million.

Michael McAllister -- MUFG Securities -- Analyst

$360 million, sorry. Is that kind of like the North Star for you of where Q1 -- is there a level that you feel comfortable working with and does that kind of dictate how you approach 2019?

Julian Bott -- Chief Financial Officer

I mean, look, it's a $2 billion facility. Clearly, we have ample room under it. We're living within cash flow. So we don't expect to ever push upper limits of that. I mean the $360 million is a comfortable level. I think the comment about the cash is just that that's efficient rather than carrying it on the balance sheet when you're living within cash flow, just reduce the debt.

Bill Way -- President & Chief Executive Officer

And let me add to that, so as we put our budget together later in the year and into the first part of next year, part of the timing of that is to get a little bit clear picture on what the forward curve looks like for that year, we then lock that number and then we adjust the capital investments on a dynamic basis depending on what projection to cash flow looks like. So investing within cash flow is how we run and that will be the level we report.

Michael McAllister -- MUFG Securities -- Analyst

Okay, fair enough. I think that the comment about it's better to -- the idea of cash and on your balance sheet, that kind of answered my question of kind of like the barometer of what you guys feel comfortable with around [ph] financial and so thank you for that. Can I have another question and dealing with just basically the DUC inventory guidance that you gave earlier in the year for the regions and has that changed any with these decisions that you've made today?

Clay Carrell -- Chief Operating Officer

We're still on track with our full-year guidance range of 35 to 45.

Michael McAllister -- MUFG Securities -- Analyst

All right, great. Fantastic, thank you.

Operator

The next question will be from Noel Parks with Coker Palmer Institutional, please go ahead.

Bill Way -- President & Chief Executive Officer

Noel?

Noel Parks -- Coker and Palmer Institutional -- Analyst

Oh yes, can you hear me?

Bill Way -- President & Chief Executive Officer

Yes, go ahead.

Noel Parks -- Coker and Palmer Institutional -- Analyst

Oh great. I just was curious about the redevelopment results you had in the Fayetteville and just wondering if you had any sense of what the returns are on projects like that? And I was also wondering with the legacy development pattern, are sort of all vintages of wells in the play equally good candidates for redevelopment or does it sort of depend on when they were drilled, how they were completed?

Clay Carrell -- Chief Operating Officer

Yes, I'll take that, this is Clay. There is a lot of them that are -- all benefit from the latest completion and latest landing zone technology. If you remember, there is a mix of wells that are DUCs on our books that we're drilling now with the current technology and then there are wells that are offsetting existing producers and the one that maybe has a little more variability that we look at is, when -- how they were completed, what vintage of well they were, how long the lateral was, how much of it stayed in the zone, but using the data analytics that we have for that area, we're able to high grade those opportunities. As we said in the previous call and we've got a little more production history on the three wells, they're tracking consistent with our expectations and from a PVI standpoint, they're in that 1.3, little over 1.3 range , which is attractive, it just doesn't compete with our Appalachia asset economics.

Noel Parks -- Coker and Palmer Institutional -- Analyst

Got you, OK and are there any implications for density you can achieve either as you redevelop I mean compared with previous assumptions?

Clay Carrell -- Chief Operating Officer

When we're putting in the new full wells that are part of the normal spacing pattern, we're comfortable with that spacing pattern. Where it's getting tighter is where we do the redevelopment well offsetting an existing producer, but we are doing things and how we frac those wells to limit and we haven't seen the communication over to the offset legacy well that has produced in the past. So you're almost twinning that well, you're drilling a new one, getting next door to it and contracting rock in a better way than we did in the first go round.

Noel Parks -- Coker and Palmer Institutional -- Analyst

Great, thanks a lot.

Operator

The next question will come from Jamaal Dardar with Tudor, Pickering, Holt & Company, please go ahead.

Jamaal Dardar -- Tudor, Pickering, Holt & Company -- Analyst

Good morning everyone, thanks for taking my call. Just wanted to dive into Tioga County a bit more here. This region has seen rapid improvements over the last several quarters. Just kind of want to get a sense on what percentage of the acreage you would say is derisked out of that disclosed 37,500 acre count and does this include most of Lycoming County as well or is that also a potential leg of upside in the future?

Clay Carrell -- Chief Operating Officer

Sure, I'll touch on that. It includes most of the Lycoming County. We generally call that whole area, our Tioga area, but it's a combination of those two counties. We're well on our way to fully proven all of that up, I would say the majority of that 37,500 we feel really good about. There are some of the northern reaches of it that maybe are not as advanced, but overall, the majority of it is going in the right direction and we're seeing better performance with each new pad that we bring on.

Jamaal Dardar -- Tudor, Pickering, Holt & Company -- Analyst

All right, that sounds good and the Upper Devonian comments, that seemed new and pretty promising as well. Just kind of want to get a sense and granted it is early, but just want to get a sense of the size of the prize there for additional liquids rich locations within that horizon and also if co-development may be needed with the Marcellus?

Clay Carrell -- Chief Operating Officer

Yes. So, I agree with your comment, it is early. We're intrigued and excited about what we're seeing right now and part of that has to do with the liquids rich nature of it. That's compelling in this commodity price environment. We've talked about before the kind of the 3P potential around the Upper Devonian is in the 7 to 9 Ts range. It is early days there and as you mentioned, co-development is a possibility and so we're scratching the surface right now, but we've had continued focus on the continued progression of our inventory and we like what we're seeing so far.

Jamaal Dardar -- Tudor, Pickering, Holt & Company -- Analyst

All right, thanks a lot everybody.

Operator

The next question comes from Jeffrey Campbell with Tuohy Brothers, please go ahead.

Jeffrey Campbell -- Tuohy Brothers -- Analyst

Good morning. I wanted to go back to the question about the Fayetteville recompletions again and just to ask you two things. One, as you continue to manage the decline in the Fayetteville until you've reached the end of your process, are you mainly doing recompletions to optimize the decline rate or are you still doing some active drilling in the Fayetteville?

Bill Way -- President & Chief Executive Officer

Yes, the wells that Clay talks about in redevelopment are all part of the test program while we own assets or anything, we're constantly working on them to improve them, but the capital program for SWN [ph] under our capital allocation model of highest PVI and economic returns focuses the vast majority of our capital to our Appalachia basin area and that's where our focus is, but really the -- any changes in decline rates or activity around gas in the Fayetteville is because of the work the teams are doing to continuously operate and improve that asset on an ongoing basis.

Jeffrey Campbell -- Tuohy Brothers -- Analyst

And a follow-up to that is just some of these things that you're learning in that program in the Fayetteville, would they be eventually applicable to Appalachia legacy portions -- whenever it's appropriate to take a look at that.

Bill Way -- President & Chief Executive Officer

Absolutely and we have -- one of the great things we're doing is we've really accelerated the learning cycle . So as we try an opportunity in one part of our Company and we apply it in the rest. So we're already in the planning stages around doing some of that and we'll bring that information out shortly, but both parts of the Appalachia division have opportunities there.

Jeffrey Campbell -- Tuohy Brothers -- Analyst

Right, and if I could just ask a quick question about the JV. I mean, typically JV means 50:50, I'm imagining you are carrying some acreage with your partners, so you guys can drill those 11,000 foot laterals you talked about. Does it end up really being a 50:50 split after you put everything together?

Bill Way -- President & Chief Executive Officer

No, it doesn't, I mean we're obviously we're operating this and we'll be maximizing the value out of it for both ventures as we go forward. So we didn't disclose any more details on that under the agreements that we have.

Jeffrey Campbell -- Tuohy Brothers -- Analyst

That's helpful, I appreciate it. Thank you.

Operator

Our next question comes from Kashy Harrison with Piper Jaffray, please go ahead.

Kashy Harrison -- Piper Jaffray -- Analyst

Good morning everyone and thanks for taking my questions. So there's a lot of good work happening operationally and I mean it's certainly coming across on the financials, just given your ability to deliver higher production despite the same amount of capital invested and once this water infrastructure project comes online, it looks like capital efficiency is going to get even better next year. So I was just wondering when you put everything together, all the efficiencies, all the improvements, everything you're seeing in your portfolio, is the quantity of economic inventory expanding in a sub-$3 gas environment and if so, can you give us a rough sense of what that rate of change in inventory could look like as we get closer to the year-end reserve season?

Clay Carrell -- Chief Operating Officer

Yes, so, what I would say is that we're improving the economics and improving the progression of our inventory by all these operational efficiencies and focusing on higher production rates and EURs. As it relates to progressing the inventory, our rich and lean inventory in Southwest Appalachia is clearly already in our inventory, already highly economic and we're working on ways to make it better. As it relates to Upper Devonian and UPP, those are where there is more opportunities to keep progressing the understanding and move those into the sub-$3 inventory mark and we're focused on that. In Northeast App, similar type of activities, the Tioga example that we've shared today is where we are bringing both new drilling locations into the portfolio and making them longer which is improving economics, which is lowering the breakeven and helping them below $3 and the teams are actively continuing to work on that.

Bill Way -- President & Chief Executive Officer

And a couple of comments of color to add to that. First one would be, one of the terrific things for Southwestern that is happening in this current environment is while gas prices are down, our differentials are improved and so our realized prices are able to come up when NYMEX prices are going down and our transportation portfolio and the access to the markets we have enable that to happen, that'd be one. Number two, as you look at, if you do this on a breakeven basis, we're trying to expand the breadth, so you have ventures like, we talked about in Northeast PA adding to inventory and we talked about the depth and in the rich area in Southwest Appalachia, we're less than $2.50 depending on liquids prices and so we have the opportunity to capture quite a bit of that and as all of these changes happen in terms of improvements, we just drive that down further. In Northeast PA, we're right around $2.50 breakeven for the area and some even better than that and so our repositioning drives everything we do to top quartile and to be sub-$3. In the sub-$3 environment, we can continue to deliver some fine results.

Kashy Harrison -- Piper Jaffray -- Analyst

Thanks. That's excellent color there. And then maybe a separate sort of question more strategic in nature. Bill, for several years now, you have more or less invested largely within cash flows. You're one of the earlier companies to do so and I was just wondering, what are your thoughts on potentially breaking glass in 2019 or 2020 and transitioning to just keeping production flat year-on-year, but just producing a significant amount of free cash flow that could be used either to apply it to the balance sheet or to pay some sort of variable dividend. Just trying to get your thoughts on a potential shift in the strategy longer term?

Bill Way -- President & Chief Executive Officer

Yes and I think when we look at the 2019 plan, the context around it always needs to be; first, invest within cash flow and then look to optimize value, not investing outside of cash flow, but at what rate do we invest, do we -- what the commodity prices look like and as a public company, you've got to look at options like that, do we continue to drill at the pace we are, do we slow back down, do we put cash to pay further down our debt. So I think your question has more than just those three options to it and we'll look at all of them too as we put the plan together.

Kashy Harrison -- Piper Jaffray -- Analyst

All right. Thank you. That's it from me.

Operator

The next question comes from Doug Leggate with Bank of America Merrill Lynch, please go ahead.

John Abbott -- Bank of America Merrill Lynch -- Analyst

Good morning, this is John Abbott on for Doug Leggate. It looks like he just hopped on to another call. Our first question relates to your Southwest Appalachia drilling inventory at 275. You have about 875 locations, you've said in the wet and lean gas window. You've so far provided us with guidance for 2019 that lateral lengths could be 9,000 feet. When you think about those 875 locations in Southwest Appalachia, assuming your current run rate, how many years do you think that you can maintain that post 2019?

Clay Carrell -- Chief Operating Officer

Yes, I think it's going be -- we've been to drilling about completing wells for the full year Southwest App in '18, is somewhere around 70 wells, something like that. So 875, if you go to 100 wells a year, I mean that's seven, eight years --

Bill Way -- President & Chief Executive Officer

-- of just that inventory and then you have obviously the other two benches, which we're exploring and optimizing for testing and so you pounce balance that opportunity as well.

John Abbott -- Bank of America Merrill Lynch -- Analyst

So that's seven to eight years of 9,000 foot laterals in Southwest Appalachia or is that 7,500 feet?

Clay Carrell -- Chief Operating Officer

Well, that's why I put a range on it. I mean, if we're going to the longer laterals, it's probably on the lower end of that and that will be our objective is to figure out ways to make them longer.

John Abbott -- Bank of America Merrill Lynch -- Analyst

That's very helpful. And then also related to Southwest Appalachia, I mean a lot of that inventory is still related to the deep Utica at 275. I mean, you must have some sort of confidence around that inventory. When do you think you might be able to provide the street with a type curve?

Bill Way -- President & Chief Executive Officer

Right now in the Utica, we are capturing knowledge by data trades and studying information that we've been able to get to build a drilling program, our opportunity for a drilling program next year and once we kind of land on what we know, what we need to find out, then we'll put those wells in a well plan and once they're drilled, we'll get them done. And we haven't done the well plan for next year yet and we're digesting a significant amount of data that we've traded for to be able to further answer that question, but we're pretty positive about what we're seeing. We can see a pathway. We have to reduce well cost as well and we're doing some seismic work. So we need to do -- to complete the seismic work and so it's a very methodical approach. The abundance of our inventory in the liquid-rich areas of West Virginia provide great benefit to us while we study and learn this and the Upper Devonian as well.

John Abbott -- Bank of America Merrill Lynch -- Analyst

Thank you very much guys on a good quarter.

Bill Way -- President & Chief Executive Officer

Thank you.

Operator

Thank you. Ladies and gentlemen, we have reached the end of our allotted time for questions. So I'd like to turn the conference back over to Bill Way for any closing remarks.

Bill Way -- President & Chief Executive Officer

Well, thanks everybody for joining our call today. As you can see from the results in all of the releases we've had, our highly talented teams continue to deliver impressive results supporting our commitment to drive long-term shareholder value. We continue to unlock value from every part of this Company and as we reposition the Company to deliver top quartile performance in the US shale business, we are focused on our liquid-rich investment opportunities going forward. We look forward to joining you on the call again next time as we talk more about the many pieces of our Company that we're driving forward to deliver even greater results. So thanks for joining the call today. Have a great weekend.

Operator

And thank you, sir. The conference is now concluded. Thank you for attending today's presentation. You may now disconnect.

Duration: 44 minutes

Call participants:

Paige Penchas -- Vice President-Investor Relations

Bill Way -- President & Chief Executive Officer

Clay Carrell -- Chief Operating Officer

Julian Bott -- Chief Financial Officer

Charles Meade -- Johnson Rice & Company -- Analyst

Rehan Rashid -- B Riley FBR, Inc. -- Analyst

Marshall Carver -- Heikkinen Energy Advisors -- Analyst

Michael McAllister -- MUFG Securities -- Analyst

Noel Parks -- Coker and Palmer Institutional -- Analyst

Jamaal Dardar -- Tudor, Pickering, Holt & Company -- Analyst

Jeffrey Campbell -- Tuohy Brothers -- Analyst

Kashy Harrison -- Piper Jaffray -- Analyst

John Abbott -- Bank of America Merrill Lynch -- Analyst

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