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Edited Transcript of SWN earnings conference call or presentation 25-Oct-19 2:30pm GMT

Q3 2019 Southwestern Energy Co Earnings Call

HOUSTON Oct 28, 2019 (Thomson StreetEvents) -- Edited Transcript of Southwestern Energy Co earnings conference call or presentation Friday, October 25, 2019 at 2:30:00pm GMT

TEXT version of Transcript

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Corporate Participants

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* C. Paige Penchas

Southwestern Energy Company - VP of IR

* Clayton A. Carrell

Southwestern Energy Company - Executive VP & COO

* Julian Mark Bott

Southwestern Energy Company - Executive VP & CFO

* William J. Way

Southwestern Energy Company - President, CEO & Director

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Conference Call Participants

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* Andrew Elliot Venker

Morgan Stanley, Research Division - VP and Lead Analyst for the Mid-Cap Oil & Gas Exploration & Production

* Arun Jayaram

JP Morgan Chase & Co, Research Division - Senior Equity Research Analyst

* Biju Z. Perincheril

Susquehanna Financial Group, LLLP, Research Division - Analyst

* Charles Arthur Meade

Johnson Rice & Company, L.L.C., Research Division - Analyst

* Holly Meredith Barrett Stewart

Scotia Howard Weil, Research Division - Analyst

* Jeffrey Leon Campbell

Tuohy Brothers Investment Research, Inc. - Senior Analyst of Exploration & Production and Oil Services

* Kashy Oladipo Harrison

Simmons & Company International, Research Division - VP and Senior Research Analyst of E&P

* Noel Augustus Parks

Coker & Palmer Investment Securities, Inc., Research Division - Senior Analyst Exploration, Production and MLP’s

* Scott Michael Hanold

RBC Capital Markets, LLC, Research Division - MD of Energy Research & Analyst

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Presentation

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Operator [1]

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Good morning, ladies and gentlemen, and thank you for standing by. Welcome to the Southwestern Energy's Third Quarter 2019 Earnings Call. Management will open up the call for a question-and-answer session following prepared remarks. (Operator Instructions). This call is being recorded. I would now like to turn the call over to Paige Penchas, Southwestern Energy's Vice President of Investor Relations. You may begin your call.

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C. Paige Penchas, Southwestern Energy Company - VP of IR [2]

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Thank you, Anita. Good morning, and welcome to Southwestern Energy's Third Quarter 2019 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.

Along with yesterday's press release, we also issued our 10-Q, which is available on the Investor Relations section of our website at www.swn.com.

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 website. I'll now turn the call over to Bill Way.

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William J. Way, Southwestern Energy Company - President, CEO & Director [3]

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Thank you, Paige. Good morning, everybody. We appreciate all of you joining us today. To state the obvious, today's commodity price environment is tough. Consistent with our previous conversations, one of the core objectives of the company is to be rigorous and disciplined in our approach to value creation.

We have led the discussions regarding the importance of remaining resilient in any commodity price environment, and we have already taken clear actions designed to assure that we are. The challenge the industry faces today play to our strengths and further differentiates SWN. So let me share with you what resilience looks like.

First, SWN has one of the strongest balance sheets and a leading debt maturity profile with nothing material due in the next 5 years, thus no looming high-cost refinancing risk or liquidity challenge.

We have substantial liquidity with a $2 billion credit facility and after Moody's announcement yesterday, both rating agencies have now completed reviews of the company and our ratings have remained the same.

Second, we have a clear record of demonstrated, operational and financial efficiency improvements and outperformance, with dramatically lower cost from record drilling and completions execution.

Further efficiency gains are in sight and being added continuously. These achievements are happening today, not forecast to happen sometime in the future.

Third, our base in leading condensate acreage in West Virginia provides commodity diversification and captures the highest margins and highest returns at current pricing. It's not enough to just own great acreage in this area, we are using our strategic reservoir management and operations capabilities to maximize the condensate yield.

We've increased our condensate production by 50% in the last quarter alone to 15,000 barrels per day.

Fourth, the company has an inventory of rich, superrich and high-volume dry gas wells, totaling approximately 900 core Marcellus locations, 500 of which meet our required economic threshold at current strip. Fifth, our robust rolling 3-year hedging program is designed to protect cash flow and the rolling nature of our program means we continue to look at -- ahead to protect future year's cash flow while retaining the opportunity to capture upside that the market fundamentals suggest.

As a proof point, we realized $112 million in cash from settled hedges in the first 9 months, $88 million of which was realized in the quarter. We're controlling what we can and mitigating many of the things we can't.

When you combine all of these critical criteria with our ongoing operational outperformance, the facts are quite compelling. All of this is made possible every day by the expert execution both strategic and detailed of our highly talented, innovative and committed team, and I'm quite proud of everyone's efforts on that team.

Before I talk about 2020, I want to give you some context.

In 2018, we generated free cash flow in excess of $100 million. When we repositioned the asset portfolio by successfully monetizing Fayetteville, we committed to a 2-year transition plan to reinvest a portion of the monetized cash flow in our Tier 1 Appalachia assets in order to return to cash flow neutrality by the end of 2020, while maintaining our balance sheet strength. This plan remains on track despite the subsequent decline in commodity prices.

In the first year of the plan, we have dramatically improved operational efficiency with better-than-expected performance, and we will continue to unlock incremental value.

In other words, the improvements we continue to make are sustainable as we plan for 2020.

While it's still too early to be definitive on specific 2020 targets, let me give you some brief color on how we are thinking about capital allocation. For this second year of our transition plan, capital investment will be limited to cash flow based on strip pricing at the time we set our plans, plus up to $300 million of the remaining monetized Fayetteville cash flow.

Should the strip at the time we set our budget in 2020 be lower than when we set the '19 plan, I would expect a reduced capital program. Consistent with prior years, we expect to have a front-loaded program in 2020 as well. Once we have set and begin to implement our activity plan, if prices dictate a change, we will adjust accordingly, just like we've done over the last several years.

If the forward curve were to increase temporarily, we would not expect to increase capital investment beyond the plan. Instead, we would evaluate options for the use of excess cash flow, including debt reduction, purchase of shares or for other corporate purposes.

But to repeat, if the forward curve goes down from where we set the budget, I would expect that the capital program will be lower for 2020. And to be clear, the discipline around this capital allocation that you've come to know over the last several years remains unchanged.

Before I hand it over to Clay, I want to mention a couple of important ESG water-related achievements for the company. Southwestern Energy continues its commitment to the environment by being freshwater-neutral. In fact, we've been freshwater-neutral since 2016. For each gallon of freshwater we use in our operations, we return at least that amount of freshwater back to the environment where we work and live through conservation projects that restore streams and aquatic habitats.

I'm delighted to share with you that we have reached an important milestone of returning in excess of 10 billion gallons of freshwater to the environment over that -- over this time. In addition, through the continued implementation of the company's piped water strategy, which targets delivery of water for all well completions through our extensive freshwater pipe network, we have removed 1.3 million truckloads of water off the roadways in Pennsylvania and West Virginia, all while improving the economics of our wells. Therefore, the environment is a core value of SWN, and it's the right thing to do.

I'll now turn the call over to Clay who will discuss operational highlights in more detail.

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Clayton A. Carrell, Southwestern Energy Company - Executive VP & COO [4]

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Thanks, Bill, and good morning, everyone. We had another quarter of outperformance by delivering production at the high end of guidance and continuing to reduce well costs. Our teams keep expanding our continuous improvement culture as they keep finding ways to enhance well performance, lower cost and improve efficiencies. The performance bar keeps going up quarter-over-quarter, and our organization has embraced that approach.

Total production for the quarter was 202 Bcfe, including 22% liquids. The production growth was driven by both improvements in our capital program performance and continued base production optimization. A primary focus of our capital activity has been in our superrich area of Southwest Appalachia where condensate yield is the highest. As a result, our condensate production increased 42% compared to the prior year quarter to 15,400 barrels per day, which was above the high end of our quarterly guidance.

Driven by the increased condensate production, total liquids production increased 19% compared to the third quarter last year to approximately 80,000 barrels a day. Similar to 2Q, we maximized value by rejecting ethane at certain periods during the quarter, resulting in slightly lower NGL volumes.

In the third quarter, we averaged approximately 3 drilling rigs and 2 frac fleets as we delivered on our planned activity reduction. We are currently utilizing 1 drilling rig and 2 frac fleets. We invested $240 million in the quarter and the fourth quarter activity will be managed such that total capital would not exceed the $1.15 billion annual capital guidance.

We continued to reduce average well costs in the quarter on wells to sales.

With the majority of our wells to sales for the year already online or are in the late stages of completion, we will beat our annual target of $875 per lateral foot, which represented a 25% cost reduction from 2018.

In the third quarter, we averaged $784 per lateral foot with an average lateral length of 10,466 feet.

Both the average cost per foot and the average lateral length are the best we have had this year, and they represent a continuation of the cost benefits we are realizing from longer laterals, piped water, direct source sand and operational execution improvements. The operational improvements are driven by our team's ongoing success in reducing cycle times on drilling completions and facility installations. For example, in the quarter, we set a new company completions record averaging 12 stages per day on a 4-well pad. This efficiency improvement reduced well cost on these 4 wells by $575,000 each and reduced the total time to complete the wells by 16 days.

Year-to-date, we are averaging 7.8 completion stages per day, which is an efficiency improvement of greater than 45% versus last year. The cost and efficiency improvements coupled with bringing wells to sale sooner are improving overall economics, and we now estimate we will be at the high end of our full year wells-to-sales guidance without increasing capital.

Third quarter LOE was $0.94 an Mcfe, as anticipated, given our well mix and completion timing. We expect to be within our revised lower guidance range of $0.90 to $0.94 per Mcfe for the year.

In Southwest Appalachia, we brought 21 wells online, 16 located in the company's superrich acreage, 4 located in the rich acreage and 1 upper Devonian delineation well. Of the superrich wells, 9 were online for at least 30 days or more and had an average 30-day rate of 13 million cubic feet equivalent per day with an average of 570 barrels per day of condensate production.

The 30-day equivalent rate represents a 60% increase compared to third quarter of 2018, driven by improved well performance and longer laterals.

In the rich area, the 4-well pad had a combined peak rate of 141 million cubic feet equivalent per day and an average 30-day rate of 27 million cubic feet equivalent per day per well, representing 100% increase over the prior year quarter, also driven by well performance and longer laterals.

In Northeast Appalachia, we brought 13 dry gas wells online, 10 lower Marcellus wells and 3 Upper Marcellus delineation wells that I mentioned in our previous quarter call.

9 of the 13 wells were online for at least 30 days, consisting of 6 Lower Marcellus wells and 3 Upper Marcellus wells. The 6 Lower Marcellus wells had an average 30-day rate of 15 million cubic feet per day, which represents a 14% increase from the year ago quarter.

The 3 Upper Marcellus wells had an average 30-day rate of 10 million cubic feet per day, which is in line with our estimates and consistent with offset tests.

In addition, the -- in Northeast Appalachia, we began to see the production benefit from our pad compression installations. We experienced an initial gross production uplift of 55 million cubic feet per day from 10 installations. We expect to continue this program across more of the asset, and we'll see a shallowing of the base decline as a result.

We continued to progress our resource to reserves effort in Southwest Appalachia. As mentioned earlier, we brought our fourth upper Devonian well online, which was our first test in the superrich acreage. The stand-alone initial well performance was in line with offset superrich Marcellus wells in the area. The pilot test included 2 Lower Marcellus wells that were subsequently brought online, and we are continuing to evaluate the combined production performance.

Also, as I mentioned earlier, in Northeast Appalachia, we continued to evaluate the 3 Upper Marcellus wells that came online early in the third quarter. The well performance is consistent with our forecast, and we expect to continue to test this interval across a larger portion of our acreage in Bradford and Susquehanna Counties.

Now I will turn the call over to Julian for the financial highlights. Julian?

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Julian Mark Bott, Southwestern Energy Company - Executive VP & CFO [5]

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Thank you, Clay, and good morning, everyone. As reported last night, we once again met or exceeded each of our financial and operational targets this quarter despite headwinds from the challenging price environment.

Adjusted net income for the quarter was $44 million or $0.08 per share compared to $40 million last year -- last quarter. Adjusted EBITDA was $202 million, which is 8% higher than for Q2 2019.

Our weighted average realized price including derivatives and transportation costs was $2.16 per Mcfe, essentially flat second quarter. Our increased liquids production and $88 million in hedge settlements almost entirely offset the impact of decreased commodity prices.

Our natural gas differential for the quarter was $0.78 compared to $0.84 in the second quarter, as we were able to proactively benefit from optimizing our low-cost transportation portfolio. During the quarter, there were several pipeline outages that affected Appalachia basis, but thanks to the diverse nature of our transportation portfolio, we were able to assure continual flow of our production to our key markets.

As Bill said, we utilized a 3-year hedging program to mitigate price risk and protect cash flow.

During the quarter, we continued to layer on additional hedges for future periods, as detailed in the 10-Q. Of the total 360 Bcf of natural gas hedged in 2020, roughly 60% are hedged by collars, limiting our downside risk while allowing for upside, and roughly 40% of fixed price swaps with an average strike price slightly below $2.60.

On the cost side, our third quarter G&A expenses were $0.15 per Mcfe, which includes the impact of decreased mark-to-market stock-based compensation expense. Excluding a small onetime charge related to the headquarter's transaction that I discussed last quarter, G&A was down $15 million compared to the third quarter last year.

Strength of our balance sheet remains a priority and a key differentiator. For this quarter, we reported net debt-to-EBITDA of 2.2x, excluding Fayetteville. As previously announced, during the quarter, we furthered this strength by opportunistically repurchasing $50 million of our senior notes at an average 13% discount funded principally by noncore nonproducing asset sales. The repurchase notes had a weighted average interest rate of 6.72%, and the buyback results in $21 million of interest savings on senior notes over the remaining time to maturity.

Our year-to-date interest expense is down $54 million compared to last year.

We also announced that our banks completed their semi-annual redetermination with a no change to our borrowing days and extended the maturity of the credit facility by 1 year to April 2024.

We are in an enviable position with our debt maturity profile, with only $265 million of bond maturities until 2025.

We remain focused on the macro environment and continued to drive to a return to free cash flow neutrality by the end of 2020 even at recent strip prices.

By focusing on what we can control, managing cost downwards, following our hedging strategy, broadly challenging the team to identify further operational improvements and the continual capture of capital efficiencies, we remain confident in delivering our plans.

That concludes our prepared remarks so Anita, you could perhaps open the line for questions.

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Questions and Answers

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Operator [1]

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(Operator Instructions) The first question today comes from Charles Meade with Johnson Rice.

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Charles Arthur Meade, Johnson Rice & Company, L.L.C., Research Division - Analyst [2]

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I appreciate in your prepared comments, you're going through the -- through your approach to the '20 CapEx, but I wonder if I could just make sure I got it right. So I think what I heard is that you said you're going to look at your cash flow at the time -- look at the strip at the time when you set the budget and you're going to do cash flow plus $300 million. I guess what -- is that right? And what I'm curious about is if, let's say, you set your budget in February at when the strip is at x, if the strip goes down, let's say, in June of '20 to something less than x, are you also then going to decrement the capital budget just so you can stay within $300 million of cash flow?

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William J. Way, Southwestern Energy Company - President, CEO & Director [3]

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Thank you for your question. Yes, the first part of what you said is accurate. At the time we set our budget, we look at the forward curve for multiple years because we want to make sure that economics are intact for projects as well. But we set the budget off of that curve. Cash flow plus up to $300 million of the favorable proceeds, cash flow from that. And the up to part is pretty important.

As we rock through past the approval time and we get to your month June or any other month and the risk committee, which meets every week, sees the trend of strips dropping, then we will look at the -- what that looks like in terms of cash flow generation through our economic model and then we will go back to the capital stack and we'll begin peeling off projects so that we do not exceed the funded cash flow plus up to $300 million from whatever strip there is, and that's a practice that we have been doing for several years. If you have then a subsequent period of time in the year where prices jump back up and again, the economics of the projects remain robust, then we will un-red circle those projects and add them back to the list but not go over the budget that we set. If -- and that's most important when you get these surges of pricing in, say, winter month or something. One month or 1 week or 1 -- even 1 quarter doesn't make a drilling program decision. It is a bit longer term but it always matches and goes by what we're seeing on the strip, and it's adjusted.

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Charles Arthur Meade, Johnson Rice & Company, L.L.C., Research Division - Analyst [4]

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That is helpful clarity, Bill. And there is a lot of questions I could ask but just for my follow-up, I wonder if I could drill down a little bit more into the beat in condensate volumes on the quarter. And maybe this is for Clay because I think he addressed some of it. I can imagine at least 3 things and there's probably more that could be driving it, one could be timing of wells that you guys are getting your wells on earlier and you're going to be near the high end of your guide and that would be two, it's just the number of wells and maybe there is a mix shift. But then there is a third, which is maybe the most interesting, which is that the actual productivity of your wells is higher in terms of the condensate yield than you were planning. So could you give us a sense of how that beat on condensate, what the drivers behind it are? And if they're temporary or something that we should be looking for to continue going into '20?

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William J. Way, Southwestern Energy Company - President, CEO & Director [5]

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Let me-- I'll make a couple of comments and hand it to Clay. First of all, our acreage has a condensate component to the gas that is leading in the basin and so if you look across our superrich area, our superrich area contains more condensate than any other acreages out there. Number one. Number two, we do a lot of yield management. So it's all about economics, and so we manage flow those wells to create the greatest yield of the most valuable product, which happens to be condensate. And so as we throttle those back on the gas side to increase the condensate yield, that's what's generating additional value for the company. And Clay has some further details to talk about on that.

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Clayton A. Carrell, Southwestern Energy Company - Executive VP & COO [6]

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Yes, as Bill mentioned, we have it in the IR materials in our Brooke and Ohio County where we have the highest condensate yields, 100-plus barrel per million in some areas, and as you all know from the previous calls, we've been focusing the majority of our wells in that area, and our planned timing had the largest number of our wells coming to sales in 2Q and 3Q, and we're continuing to see the benefit of those wells coming online in 3Q and the optimization of the production performance through what Bill talked about, facility design so that we can benefit from the max condensate production and with our subsurface knowledge maximizing how we're completing the wells and where we're landing the wells. So we're really pleased with the growth in the condensate, and we have a healthy set of remaining drilling inventory in that area where we can continue to focus there.

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Operator [7]

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The next question comes from Drew Venker with Morgan Stanley.

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Andrew Elliot Venker, Morgan Stanley, Research Division - VP and Lead Analyst for the Mid-Cap Oil & Gas Exploration & Production [8]

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I wanted to just dig in a little bit more on the upper Devonian and the Upper Marcellus results, and if you could give us some color on whether you did much different in the upper Devonian well relative to the offsets. And I realize it's different reservoirs. And the Upper Marcellus, similarly, if there's things you're doing different on that test as well?

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Clayton A. Carrell, Southwestern Energy Company - Executive VP & COO [9]

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Certainly, this is Clay. We -- this is our first test of the upper Devonian in the superrich and as you know, in our previous testing during the year, we took what we learned from the testing in the rich area and adjusted our completion designs in order to maximize the economic benefit of a combined production of both the upper Devonian and the Marcellus. So we ended up with a reduced completion design, which helped the economics, and we're seeing similar performance. So we think we're continuing to make progress on elevating the combined development up but it's still early, and we have some ways to go to keep pushing that in the current commodity price environment.

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William J. Way, Southwestern Energy Company - President, CEO & Director [10]

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And any reduction of completion designs or any reduction of cost always looks at the value creation that is involved in that. And so we don't reduce costs to reduce cost and impair value and it's a great example in how they've managed these wells to highlight that fact.

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Clayton A. Carrell, Southwestern Energy Company - Executive VP & COO [11]

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And then on the Upper Marcellus, we, like some other operators, have been testing the Upper Marcellus this year with latest generation completion designs, landing zones, and we're really pleased that we've seen the improved production performance by those latest designs, and the results of the wells have been in line with what we thought that upgraded performance would be. And so our plans are to continue testing that as we move into 2020.

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Andrew Elliot Venker, Morgan Stanley, Research Division - VP and Lead Analyst for the Mid-Cap Oil & Gas Exploration & Production [12]

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So just to follow up on the upper Devonian. In the past, a lot of operators had seen reduced performance relative to the Marcellus, I think, in part because it was lower pressure. Do you think it's partly maybe because prior operators had been drilling upper Devonian subsequent to drilling upper -- I'm sorry, drilling Marcellus and thus, pressure drawn on may be reduced the productivity of the reservoir? Is it -- or maybe it's just the upper Devonian higher pressure and more productive on your acreage?

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Clayton A. Carrell, Southwestern Energy Company - Executive VP & COO [13]

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Yes. We're aware of the kind of the past discussions around the codevelopment of the upper development -- upper Devonian with the Lower Marcellus. In our minds, it's -- how do you optimize the completions to limit the well interaction between the 2 zones and maximize the economics from codevelopment there. And so that's the progression that we are on. Like Bill mentioned, because of the interference that can exist there, when we back off the completions, we're working on limiting that interference but yet still getting the same or better production results, which would enhance the economics.

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Andrew Elliot Venker, Morgan Stanley, Research Division - VP and Lead Analyst for the Mid-Cap Oil & Gas Exploration & Production [14]

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Just one last follow-up on this point. Do you have any locations identified in your -- identified drilling inventory for either of these zones, Upper Marcellus and upper Devonian?

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Clayton A. Carrell, Southwestern Energy Company - Executive VP & COO [15]

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We definitely in our full playground of inventory of future drilling locations have drilling locations in both of those 2 areas. We have not finalized 2020 plans and so we'll factor that into the go-forward but as I mentioned earlier, I would expect for sure that the Upper Marcellus will be in the 2020 plans.

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Operator [16]

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The next question comes from Holly Stewart with Scotia Howard Weil.

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Holly Meredith Barrett Stewart, Scotia Howard Weil, Research Division - Analyst [17]

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Just maybe Bill, starting off with kind of a high-level question, in your prepared comments, you talk about being in a position to take advantage of financial, operational and strategic opportunities given your maturity profile. I was wondering if you could provide some further insights here and then maybe also given what we've seen in other basins with mergers [who have] equals, do you think this might makes sense in the Appalachian basin?

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William J. Way, Southwestern Energy Company - President, CEO & Director [18]

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We look constantly at creating value with our assets and beyond our assets for the shareholders, and we look at growth or expansion along the lines that you're talking about in 2 ways, organic and inorganic. As we've kind of mentioned a little bit, we've got 53 TCF of resource across the Appalachian basin in multiple benches.

We've got a science budget that helps test those, all with the intent of converting resource into reserves and reserves into economic drilling opportunities to expand the base, the shareholder already owns that, and so there is a focus on making sure that we're getting all of that value. At the same time, looking for opportunities beyond that to further expand the company's ability to create greater levels of value, we look at bolt-on opportunities for adjacent acreage where we can expand the efficiency of drilling through longer laterals or just expand the footprint as long as it's accretive. But also look at significant additions, including combinations, including mergers. We study those opportunities all the time and where we can find the ability to create real accretive value that can't be added through commercial negotiations -- and there's a lot of playroom in that space -- then we believe that we ought to focus on and advance our thinking around those with a couple of clear screening methodology in line.

First of all, real returns on capital, accretive financial and balance sheet metrics and then the opportunities have to have accretive inventory to us, generate real economics on a full-cycle basis, balance sheet has got to remain strong, synergy capture is critical and we must assure ourselves that when we make commitments about -- around synergies, those synergies can and will be delivered. And then if those things are in line, then the opportunity may make sense and we'll continue to explore it.

In a margin-based, commodity-based industry, scale, materiality, resiliency in all forms of pricing environments or regulatory environments and a number of things you think about, it makes sense to explore those opportunities, and we do. And as upfront we continue to evaluate that, we prefer not to comment on the details, it's just how we work. When we sold Fayetteville, we told the world; as you look through opportunities to expand the scope and scale of the company and its economic generation capability, we'll keep those to ourselves for now.

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Holly Meredith Barrett Stewart, Scotia Howard Weil, Research Division - Analyst [19]

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Understood. Good color. And then maybe just one for Julian on the debt repurchases in the quarter. Julian, how do we think about this as we kind of proceed into the fourth quarter and then head into 2020 on further debt repo?

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Julian Mark Bott, Southwestern Energy Company - Executive VP & CFO [20]

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Yes, I mean, Holly, we obviously always focused on the balance sheet. We've done a lot to get it to where it is and we look to continually find ways to improve it. There was an opportunity based on where the market was trading to make some repurchases. We've made some noncore asset sales. And so it seems like an appropriate step and consistent with our goals. We're always valuing -- evaluating opportunities and consider debt repurchases along with any of the other investments that we might make. So I can't give you clear color as to what we would do at any given time but, again, I think you know what our principals are, which is maintaining the balance sheet and progressing the business.

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Operator [21]

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The next question comes from Arun Jayaram with JP Morgan.

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Arun Jayaram, JP Morgan Chase & Co, Research Division - Senior Equity Research Analyst [22]

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I wanted to first start off on the well cost reductions that you've been able to generate. I think you were at $784 per lateral foot in the quarter. I was wondering if you could maybe provide some commentary on how much more do you think we can go here Bill, particularly, with thoughts on service cost. I know you are partially vertically integrated but just some thoughts on how more do you think we could push on the well cost front? And any thoughts on sustaining CapEx requirements for 2020 if we are -- if these well costs come in at this $780 or lower number for next year.

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Clayton A. Carrell, Southwestern Energy Company - Executive VP & COO [23]

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Arun, I'll start on the cost reduction discussion. As you've seen from the results, our teams are all over figuring out how we can keep being more efficient, and we continue to find those efficiency gains coupled with cost improvements in the environment right now. Us taking over self-sourcing of sand is an example where we dramatically benefited the cost and on the water system and then of course, the longer lateral. So all of that is continuing and then when you look at the numbers we're reporting what will be the full year numbers where we're saying we'll beat the $875, when you pull out the wells that were spud under the cost structure of 2018 and look only at wells spud in '19 and that are coming online [to] sales in '19, that number is down close to $790 per lateral foot.

So directionally, we're going to budget for 2020, factoring in all of the efficiency gains that we've already realized and then raising the bar to go find more.

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Arun Jayaram, JP Morgan Chase & Co, Research Division - Senior Equity Research Analyst [24]

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Got you, Clay. And maybe just some thoughts on your sustaining CapEx requirements if you theoretically went to -- what CapEx required to keep '19 production flat?

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William J. Way, Southwestern Energy Company - President, CEO & Director [25]

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Yes, this is Bill again. Maintenance CapEx, as we call, is $600 million to $650 million. When I look at -- I'll reinforce something that Clay said, it's not only the drilling cost, it's every part of every piece of this company where we can make improvements. One-off improvements are great, sustainable improvements are even more exciting and all of that is built into the next year's programs why -- with -- in any kind of form of cost and the $600 million to $650 million is -- exclude CI&E.

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Arun Jayaram, JP Morgan Chase & Co, Research Division - Senior Equity Research Analyst [26]

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Right. So that's the D&C component?

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William J. Way, Southwestern Energy Company - President, CEO & Director [27]

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That's right.

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Arun Jayaram, JP Morgan Chase & Co, Research Division - Senior Equity Research Analyst [28]

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Okay. My follow-up, I was wondering if you could shed some more light on the compression work that you've done. It sounds like that helped boost production by 55 million a day. Just talk about -- I mean, do you get a sugar high from this compression or is this sustainable? And thoughts on what this could mean on a go-forward basis?

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Clayton A. Carrell, Southwestern Energy Company - Executive VP & COO [29]

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Yes. So there is an initial flush benefit but we have the full benefit modeled as we look at how the production shallows that decline because you're lowering the line pressures at those pads. When we look at base decline, we're already able to see the trends and that it's going to help us improve our base decline to a mid-20s, around a 25% number, down from the upper 20s, where we've been at.

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William J. Way, Southwestern Energy Company - President, CEO & Director [30]

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Yes. And let me put a topside on this. One of the things we're trying to do is get out of the way of the reservoir. We have a choice of either doing this at a pad location or doing it across the entire gathering system. Well, we have got a lot of robust areas of -- and wells and pads in different acreage that continues to perform quite well at higher transmission level pressures. And so we target pads in individual areas where we can draw down the pressures on the well but maintain the more efficient and higher residue pressure into the gathering system. It's a practice that we started back in Fayetteville, very successful. You have sustained performance from it.

We do the same thing with looking and optimizing any kind of Midstream, whether it's pipe restrictions or anything else, all at the same time. The goal is get out of the way of the reservoir and allow that reservoir to continue to perform. And base production improvements are great economic projects. And you talk about our capital allocation, these come up to the top of the list because of the return they generate and it stems decline.

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Arun Jayaram, JP Morgan Chase & Co, Research Division - Senior Equity Research Analyst [31]

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Yes, just maybe one housekeeping question. Bill, you did beat consensus production estimates for the quarter, yet you kept the full year the same. Any thoughts on that, just some conservatism? Or did it just reflect some [tills] moving into the third quarter?

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Clayton A. Carrell, Southwestern Energy Company - Executive VP & COO [32]

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Yes, Arun, we're going to continue to focus on the value added aspect of our production. As we move forward, there is the possibility of some ethane rejection that could occur. As we move through the fourth quarter like we've done at certain periods in 2Q and 3Q, which has an effect on the overall equivalent volumes. So day to day, we're going to keep looking to maximize the value from the production but there's some variables that could swing it a little bit.

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Operator [33]

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Your next question comes from Kashy Harrison with Simmons Energy.

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Kashy Oladipo Harrison, Simmons & Company International, Research Division - VP and Senior Research Analyst of E&P [34]

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So I guess my first question surrounds the capital efficiency improvements that we were just discussing and that you've seen in Q3. This might be a question for Clay or Julian, and I know it's not an easy one to answer. But if we took the 2019 pace of activity so the number of wells drilled, completed [turns] to sales, et cetera, and just marked it for the leading edge current cost experienced in Q3, what would -- and the guesstimates are fine -- what would the adjusted CapEx budget be for 2019? Like would it be 10% lower? Just any rough guess on how that would change, would be great.

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Clayton A. Carrell, Southwestern Energy Company - Executive VP & COO [35]

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I guess from a starting point if I take into account the -- at least a 5% may be adjustment when you think about the -- solely the impact of wells that have come online in '19 compared to the higher cost structure that came in, in '18.

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Kashy Oladipo Harrison, Simmons & Company International, Research Division - VP and Senior Research Analyst of E&P [36]

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Right. And then -- that's helpful. And then as you look to further reduce costs, do you think there might be a potential benefit to monetizing the oilfield services segment and just taking advantage of really low service pricing across the entire industry. We've seen a larger operator in the Permian due to this here more recently and it sounds like it's generating positive capital efficiency rate of change for them. So I was just wondering if perhaps there is a thought process on monetizing the service business?

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William J. Way, Southwestern Energy Company - President, CEO & Director [37]

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Yes. I think what you have got to look at it is across any part of our business, whether it's the services side, whether it's our water infrastructure, any of those kind of things, you've really got to take a look at the value they create for the company, and we do this all the time. Rigorous analysis of the value we create by doing it ourselves versus what we could do on the outside.

We take the flexibility that these businesses provide in moving capital around. If you take multiples that you might want to get on any of these will come with drilling commitments and other -- or other project commitments. That's what drives these things to be so valuable. And you've got to balance all of that on the back of economics, and if it makes sense to do it one way that's how we do it, if it make sense to do it another way, we have to look at that. And that's how we -- if you look at a lot of the questions that we get asked, they all have an economic root. And that economic root is at strip pricing, that economic root is making sure that from an objective point of view, whatever we're doing is delivering the value that it's supposed to and if it does not then we have to look at the alternative to that.

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Kashy Oladipo Harrison, Simmons & Company International, Research Division - VP and Senior Research Analyst of E&P [38]

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Got you. If I could sneak one more in. And your last comment was a great segue to the question, but I was just curious, if we look at the forward strip for natural gas, we look at the implied NGL prices, they're pretty bad. And I was just wondering, using your preferred metric of returns, are these projects generating sufficient returns to take care of corporate expenses? Or is the thought process with using $300 million from the Fayetteville proceeds just countercyclical investing with the belief that eventually the price will correct itself and will land closer to the 285 price that you included in the initial 2019 budget?

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William J. Way, Southwestern Energy Company - President, CEO & Director [39]

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When we take a look at whatever we're going to invest in, whether it's operating expenses, capital, whatever -- and in the case of capital which was your question, we take each and every individual project that we plan to put on the table, supported by the fact there's cash flow to invest it and the proceeds as we've already talked about. We force rank those projects against economics and so we know the order with which they might be done in, then we add them all up and load them up with all the costs that you speak about and if they don't generate the required return then that package doesn't work and we go back and relook at it, we carve off projects and it's prudent in the economic return, fully burdened. And at current strip with current differentials, projected through a 3-year period, so if you're going to drill a well, you kind of want to look at the forward curve for 3 years, so that's where the bulk of the return comes from in that 1 to 3 year period.

And we run that over and over. And then as we said earlier, if those economics change because there is a lower commodity price or higher basis in any of the areas where we work, we adjust that and then we peel off the bottom end of that stack, if you will, because they're prioritized and that's what you -- that's how we invest. And so to be crystal clear, whether it's vertical integration, drilling wells, any kind of investment we make, it's got to earn its way to creating value and generating returns on that investment for the shareholder. That's how we run the company.

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Operator [40]

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The next question comes from Noel Parks with Coker & Palmer.

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Noel Augustus Parks, Coker & Palmer Investment Securities, Inc., Research Division - Senior Analyst Exploration, Production and MLP’s [41]

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Just a couple of things, I was wondering, at this point because your release does -- always give us an update on average lateral length, where is your longest lateral length sort of by region now. How long -- how far ahead have you drilled?

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Clayton A. Carrell, Southwestern Energy Company - Executive VP & COO [42]

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We've got a 18,600 foot successfully completed lateral in West Virginia and an 18,000-foot in Pennsylvania.

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Noel Augustus Parks, Coker & Palmer Investment Securities, Inc., Research Division - Senior Analyst Exploration, Production and MLP’s [43]

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Okay. Great. And I know the data for wells that size is still in the process of accumulating it. Any signs that you're nearing diminishing returns for going out with that length?

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Clayton A. Carrell, Southwestern Energy Company - Executive VP & COO [44]

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From a mechanical standpoint, nearing is probably relative, that's pretty far out there but there's probably a little more room to go with current technology. And then from a well performance, we're continuing to get the one-for-one benefit on the longer laterals, there is not as big data set of those, so we continue to watch those but everything is looking good so far. I gave you those longest laterals flip flopped, Southwest Appalachia is 18,000, Pennsylvania is 18,600.

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Noel Augustus Parks, Coker & Palmer Investment Securities, Inc., Research Division - Senior Analyst Exploration, Production and MLP’s [45]

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Okay. Great. And then I was just thinking about infrastructure in general or maybe more thinking about transportation agreement. At this point, what is sort of the oldest vintage agreements you have in place at this point? And is there anything on the way to rolling off, where you might have opportunities to renegotiate terms in this environment?

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William J. Way, Southwestern Energy Company - President, CEO & Director [46]

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I'll take part of this and Jason can add some color if necessary. I would say that our oldest contracts are in Pennsylvania where we have built a very flexible long-term portfolio of capacity that is well below the market for anything that's being built or operating today anywhere else. And it's really an asset to the company. It's highly flexible and gives us a lot of flexibility of the pace of investing, et cetera all the way to the newest transportation portfolio that we have in West Virginia that is priced appropriately for the market in the times that it was built. It is right sized for our company so that as we move through time at a -- even a moderate development program, you have a rolling into that. And a proof point around that is we're able to add transportation at a discount in the future that enables that flexibility to continue and we haven't had to overcommit and purchase a lot of transportation that we don't need and the strategy for how we managed this is playing out.

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Operator [47]

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The next question comes from Biju Perincheril with Susquehanna.

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Biju Z. Perincheril, Susquehanna Financial Group, LLLP, Research Division - Analyst [48]

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Bill, it sounds like your well mix will be shifting more towards the superrich area and I'm wondering if that's going to put some upward pressure on your lease operating expense or do you have projects in the works, gathering systems or something else, that's going to offset that?

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William J. Way, Southwestern Energy Company - President, CEO & Director [49]

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Yes, let me just check one comment in the front of it. For the last couple of years, we've been running majority of the activity in the superrich liquids-rich area whatever you want to call it in West Virginia, 2/3, 1/3-ish of the activities in the superrich area and smaller portions in Pennsylvania. Commodity prices drive that. So if you have 5 rigs and you put 3 of them in 1 place and 2 of them in another or 3 in 1 -- 4 in 1, it bounces a little bit back and forth. But right now, even in the forward curves as we look, because of the condensate and all the liquid value that we get from that, you'll be biased towards that investment. So we constantly look at ways to renegotiate agreements where we can or expand the pies so that we can get better rates and we'll keep doing that -- ally its impact on LOE. But it may have a higher LOE, but a great part of that is it has higher revenues, which means the margins are greater. And so we're happy to take those.

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Biju Z. Perincheril, Susquehanna Financial Group, LLLP, Research Division - Analyst [50]

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Yes. Definitely. And my follow-up was actually going back to the upper Devonian test. It sounded like the previous test in the rich window, perhaps you saw some interactions between the upper Devonian and the Marcellus. And when you move over to the superrich area, either anything changing on with respect to geology that makes the 2 zones being independent, or is it simply how you're completing sort of minimizing the intensity of the completions.

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Clayton A. Carrell, Southwestern Energy Company - Executive VP & COO [51]

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So the 2 intervals are 150- to 200-foot apart, a little further apart in the superrich area. But we're seeing communication. It's a matter of maximizing the overall completion design to elevate the economics of a dual completion coal production project so that it adds value economically. Little bit thicker in superrich than in the rich, but we're dealing with a 150 to 200 foot between the 2 intervals.

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Biju Z. Perincheril, Susquehanna Financial Group, LLLP, Research Division - Analyst [52]

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Got it. So you're not ruling out in the rich area that you could still have the upper Devonian as a viable zone?

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Clayton A. Carrell, Southwestern Energy Company - Executive VP & COO [53]

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Yes. I'm not ruling it out anywhere. It's really early in the discussion and continuing to adjust the completion designs like the progress we made from rich to super rich, I think is going to continue to be an opportunity for us.

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Operator [54]

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The next question comes from Jeffrey Campbell with Tuohy Brothers.

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Jeffrey Leon Campbell, Tuohy Brothers Investment Research, Inc. - Senior Analyst of Exploration & Production and Oil Services [55]

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Congratulations on the quarter. Going back to the superrich upper Devonian test, was that test done -- or let's put it this way, were the Marcellus offsets to that well in the high condensate region of the superrich and if so, did the higher cut show up in the initial upper Devonian results?

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Clayton A. Carrell, Southwestern Energy Company - Executive VP & COO [56]

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Yes, most definitely, which is how we plan the test. We -- there's 2 Lower Marcellus wells right below this upper Devonian well, all in the superrich acreage. We brought on the upper Devonian well first, and it had all the exact same liquids and condensate-rich characteristics of our Lower Marcellus superrich wells, and that's part of the testing that we're doing.

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Jeffrey Leon Campbell, Tuohy Brothers Investment Research, Inc. - Senior Analyst of Exploration & Production and Oil Services [57]

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Okay. Great. That's good color. And Bill, I don't want to ask a downer question but I mean it's -- I think it's worth asking that is, is there a scenario where the 2020, I guess, strip could be low enough that achieving the year-end 2020 cash flow neutrality might have to leak into 2021?

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Julian Mark Bott, Southwestern Energy Company - Executive VP & CFO [58]

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Yes. I mean, Jeff, Julian here. Indeed, I mean obviously, it's all dependent upon what we get to invest from the cash flow. I mean there's a plan and it works in this environment but there is clearly cases where you just -- you would not be able to accomplish that goal.

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William J. Way, Southwestern Energy Company - President, CEO & Director [59]

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And the follow-on question that I think you might be asking me is, is there a price where you'll stop drilling? And the answer to that question is, which will affect this answer, and the answer is very clear. When the price of the commodities reaches a point where we cannot meet the company's rigorous economic threshold, we will reduce or stop activity. We did it in [2016] and -- for the same reason and we'll do it again. It's not our preference but that's the duty we have to create and protect value for the shareholder and it's not about activity or production growth, it's about real value creation. We're fortunate to be in some of the richest condensate latent acreage in West Virginia and have some terrific acreage that has high productivity and production flow in Pennsylvania and a combination in the middle between the 2, and so our economics stay robust but yes, to that question.

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Jeffrey Leon Campbell, Tuohy Brothers Investment Research, Inc. - Senior Analyst of Exploration & Production and Oil Services [60]

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Right. That's really helpful. So I mean the point is, is you do have a goal but it's not a rigid goal. You're going to respond to conditions and always with an eye on being able to make returns.

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William J. Way, Southwestern Energy Company - President, CEO & Director [61]

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It's fundamental.

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Operator [62]

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The next question comes from Scott Hanold with RBC.

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Scott Michael Hanold, RBC Capital Markets, LLC, Research Division - MD of Energy Research & Analyst [63]

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Apologies, if I'm going to reask a question, I've been dropped off the line a few times here so I didn't get to hear the full set of questions here. But first, a follow-on on the prior question is, what is the level of production? Or what do you need to hit to achieve that free cash flow, sustainable free cash flow neutrality by year-end '20? Is it a capital efficiency with your well cost? Is it a certain size of the production base that you need to hit? What is sort of that level we should be looking at?

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Julian Mark Bott, Southwestern Energy Company - Executive VP & CFO [64]

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Yes. I mean Scott, it's really a combination of all these things, which is why we've been able to continue to say we can hit the goal despite the fact that the industry conditions have certainly changed. And I mean a lot of the things we've talked about on this call, the operational efficiency gains, the lowering of our capital cost structure and frankly, the productivity gains that we've had are all contributing to that. And that's what's driving it.

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Scott Michael Hanold, RBC Capital Markets, LLC, Research Division - MD of Energy Research & Analyst [65]

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Okay. And so if I can ask you more directly, like, what is sort of that base production level that you feel is sort of that free cash flow like break-even level? Where is that?

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William J. Way, Southwestern Energy Company - President, CEO & Director [66]

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Scott, there is not really a production level. I mean it's going to depend on commodity prices, right? I mean commodity prices are going to spit out different EBITDA, different cash flow, I mean, at different levels. So it's -- there's not a production number we're chasing to deliver that. It's all combined together with the cost structure and everything else. So.

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Scott Michael Hanold, RBC Capital Markets, LLC, Research Division - MD of Energy Research & Analyst [67]

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Okay. Okay. And then what impact could have those improvements on compression that you all have been talking about have on reaching that, I mean, like, how much -- how big is that as you kind of roll that out to -- in other well pads and reducing your maintenance CapEx?

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Julian Mark Bott, Southwestern Energy Company - Executive VP & CFO [68]

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Yes. I mean the impact that had is it just helps further the resilience and handle the base declines and so forth. As far as rolling it out, I mean, Clay?

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Clayton A. Carrell, Southwestern Energy Company - Executive VP & COO [69]

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Yes. So we're doing the majority of our work in 2019 is in our Greenzweig area in Pennsylvania, in Bradford County. And then we have plans that we're finalizing for the continuation of it going into 2020.

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Scott Michael Hanold, RBC Capital Markets, LLC, Research Division - MD of Energy Research & Analyst [70]

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Okay. And what is that having an impact on maintenance CapEx, does it like reduce it by like 5% or 10%? Like how big can that be?

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Clayton A. Carrell, Southwestern Energy Company - Executive VP & COO [71]

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Yes. I think, again, it's this combination of things. We have a little bit higher exit rate as we come to the end of the year. Right now, we have a view of improved or shallowing base decline. So kind of with balancing all those things, we're in that $600 million type of number.

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William J. Way, Southwestern Energy Company - President, CEO & Director [72]

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Yes. I think to cap this question off, just like in your model, you've got multiple levers that you can tweak and you'll get a different answer. That's how we run the company. We look at all of those variables. You can have lower commodity prices and basis can be awesome. It can even negate the lower commodity price. You've just got to look at every one of them and feed them into the model that produces a glide path for investment, for revenue, for cost and then we go from there. And so we're keen and very clear. We can be free cash flow-neutral today if you just stop but that's not the right thing to do and we have a model for that. So we really look at it holistically.

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Operator [73]

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Due to time constraints, this concludes our question-and-answer session. I would now like to turn the conference back over to Bill Way for any closing remarks.

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William J. Way, Southwestern Energy Company - President, CEO & Director [74]

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This year is playing out fundamentally with what -- the way we positioned the company and readied it over the last several years to face this kind of a volatile commodity environment or any other kind of impact that the industry might get. We are running the business to ensure that we've got a compelling investment thesis today and in this environment as well as over the long-term. I think we've proven and continue to prove that we've taken intentional and very strategic actions over time to improve the quality of the earnings, advance our quality condensate acreage in Appalachia, for example, and reshape the portfolio whether it's through divestitures, whether it's diversification of the liquids to make Southwestern Energy a strong resilient organization with a lot of talented people who share the outperformance mindset that we hope gotten across [from] you today. The teams continues to innovate. They continue to execute quarter after quarter. So we thank you for your interest. Thank you for your questions and you all have a great weekend.

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Operator [75]

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This concludes the Southwestern Energy's Third Quarter 2019 Earnings Call. You may now disconnect.