Q3 2019 Earnings Call
Good morning, ladies and gentlemen, thank you for standing by welcome to the southwestern Energys third quarter 2019 earnings call.
Management will open up the call for question and answer session following prepared remarks.
The interest of time, please limit yourself to two questions and every Q for additional question.
This call is being recorded I would now like to turn the call over to page purchase southwestern Energys Vice President Investor Relations you may begin your.
Thank you Anita good morning, welcome to southwestern Energys third quarter 2019 earnings call. Joining me today, our Bellway, President and Chief Executive Officer, quite Carroll, Chief Operating Officer, Julian Bott, Chief Financial Officer injuries occurred head of marketing and transportation along with yesterday's press release, we also entered <unk>.
In Q, which are available in the Investor Relations section of our website at Www Dot Dot com.
We get started I want to point out that many of the comments. During this call are forward looking statements involve risks and uncertainties affecting.
Many of these are beyond our control and or discuss in more detail in the risk factors and afford looking statements section of our quarterly filings with the Securities Exchange Commission, although we believe the execution to expressed or based on reasonable assumptions are not guarantees of future performance and actual results or development may differ materially when they also referred as a non-GAAP .
Got you measure, which helped facilitate comparisons across periods with peers pretty 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 film slate.
Thank you page good morning, everybody.
I appreciate all he joined US today to state the obvious today's commodity price environments today.
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've already taken a clear actions designed to assure that we are.
Challenge the industry faces today play to our strengths and further differentiate swim.
So let me share with you what resilience looks like first it's when has one of the strongest balance sheets and a leading debt maturity profile with nothing material due in the next five years, that's no looming high cost refinancing risk or liquidity challenge.
We have says substantial liquidity with a 2 billion dollar credit facility and after Moody's announcement yesterday, both rating agencies have now completed reviews of the company and our ratings have remained site.
Second we have a clear record up demonstrated operational and financial efficiency improvement and outperformance, we dramatically lower cost a record drilling and completions execution.
Further efficiency gains or insight and being added continuously.
These achievements are happening today, not forecast to happen sometime in the future.
Third our basin, 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 on 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 15000 barrels per day.
For the company has an inventory of rich Super Rich in high volume dry gas wells totaling approximately 900 core Marcellus locations 500 of which meet our required economic threshold at current strip.
Yep, our robust rolling through your hedging program is designed to protect cash flow and the rolling nature of our program means we continue to look at a head to protect future years cash flow, while retaining the opportunity to capture upside that the market fundamentals suggest.
As a proof point, we realise $112 million in cash from settled hedges in the first nine months 88 million of which was 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.
Oh this is made possible every day.
Expert execution, both strategic and details of our highly talented innovator 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 two year transition plan to reinvest a portion of the monetize cash flow and our tier one Appalachian 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 our sustainable as we plan for 2020.
Well, it's still too early to be definitive on specific 2020 targets. Let me give you. Some brief color on how we're 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 other remaining monetized they they'll cash flow.
Sure It 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 frontloaded program in 2020 as well.
Once we have sat 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.
The forward curve, where to increase temporarily we would not expect to increase capital investment beyond the plan. Instead, we would evaluate options for the use of that excess cash flow, including debt reduction purchases 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.
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 when I mentioned, a couple of important S.G. 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 or freshwater we use our operations. We returned at least that amount of freshwater back to the environment, where we work and live your conservation projects that restore streams and aquatic habitats.
I'm delighted to share with you that Weve reached an important milestone returning in excess of 10 billion gallons, a fresh water to the environment over that time over this time.
In addition, the continued implementation of the company's piped water strategy, which targets delivery of water for all well completions through our extensive freshwater Pike network. We have removed 1.3 million truckloads of water off the road ways in Pennsylvania, and West, Virginia, all while improving the economics of our wells here.
For the environment as core value of swim and it's the right thing to do.
I'll now turn the call over to client who will discuss operational.
Highlights in more detail.
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 costs and improve efficiencies.
The performance bar keeps going up quarter over quarter, then our organization has embraced that approach.
What a production for the quarter was 202 bcf fee, including 22% liquids.
The production growth was driven by both improvements in our capital program performance and continued based production optimization.
Our primary focus of our capital activity has been in our Super Rich area of southwest Appalachian where condensate yield is the highest as a result, our condensate production increased 42% compared to the prior year quarter to 15400 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 80000 barrels a day similar to Q, 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 three drilling rigs and two frac fleets as we delivered on our planned activity reduction.
We're currently utilizing one drilling rig and two frac fleets.
We invested $240 million in the quarter and the fourth quarter activity will be managed such that total capital will not exceed the 1.15 billion dollar annual capital guidance.
We continue to reduce average well cost in the quarter on wells to sales.
With the majority of our wells to sales for the year already online or 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 10466 feet.
Both the average cost per foot and the average lateral length or the best we've had this year and they represent a continuation of a cost benefits. We are realizing from longer laterals piped water direct source sand and operational execution improvements.
The operational improvements are driven by our teams 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 four well pad.
This efficiency improvement reduced well cost on these four wells by $575000 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 sales sooner or 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 Ela, we was 94 cents nmcf <unk> as anticipated given our well mix and completion timing.
We expect to be within our revised lower guidance range of 90 cents to 94 cents per mcf fee for the year.
In southwest Appalachia, We brought 21 wells online 16, located in the company's Super Rich acreage for located in the rich acreage and one upper Devonian delineation well.
Up to Super Rich Wells mine 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 2018, driven by improved well performance and longer laterals.
In the rich area of the four well pad had a combined peak rate of 141 billion 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 three upper Marcellus delineation wells that I mentioned that our previous quarter call.
Nine of the 13 wells were online for at least 30 days, consisting of six lower Marcellus wells and three upper Marcellus wells.
The six lower Marcellus Wells had an average 30 day rate of 15 million cubic feet per day, which represents a 14% increase from a year ago quarter.
The three upper Marcellus Wells had an average 30 day rate of 10 million cubic feet per day, which is inline with our estimates and consistent with offset tests.
In addition, the north and 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 continue 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 Super Rich acreage.
Standalone initial well performance was in line with offset Super Rich Marcellus wells in the area pilot test included two lower Marcellus Wells that were subsequently brought online and we're continuing to evaluate the combined production performance.
Also as I mentioned earlier in northeast Appalachia, we continue to evaluate the three upper Marcellus wells that came online early in the third quarter.
Well performance is consistent with our forecasts and we expect to continue the 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.
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 eight cents per share compared to $40 million last year last quarter.
Adjusted EBITDA was 202 million, which is 8% higher and for Q2 22019.
Our weighted average realized price, including derivatives and transportation costs was 2016 cents per mcf fee essentially flat second quarter.
Our increased liquids production and 88 million in hedge settlements almost entirely offset the impact of decreased commodity prices.
I would natural gas differentials for the quarter was 78 cents compared to 84 cents in the second quarter as we were able to proactively benefit from optimizing on low cost transportation portfolio.
During the quarter there was several pipeline outages that affected Appalachian 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 utilize a three hedging programs 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 hedging 2020 , roughly 60% hedged by callers limiting our downside risk, while allowing the upside and roughly 40% of fixed price swaps with an average strike price slightly below $2.60.
On the cost side, our third quarter DNA expenses was 15 cents per Mcf fee, which includes the impact of decreased mark to market stock based compensation expense.
Excluding a small one time charge related to the headquarters transaction that I discussed last quarter DNA was down 15 million compared to the third quarter last year.
The strength of our balance sheet remains a priority and a key differentiator for this quarter, we reported net debt to EBITDA of 2.2 times excluding Fayetteville.
As previously announced during the quarter. We further this strength by Opportunistically repurchased 50 million of our senior notes at an average 13% discount funded principally by non core non producing 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 all banks completed that semiannual redetermination with no change to our borrowing base and extended the maturity of the credit facility by one 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 to continue to drive to a return to free cash flow neutrality by the end of 2020 , even that recent strip prices.
By focusing on what we can control.
Managing costs downwards.
Following our hedging strategy broadly changing the teams while identifying further operational improvements and to continue we'll capture of capital efficiencies, we remain confident in delivering off plans.
That concludes our prepared remarks, so Anita you could perhaps open the lines for questions.
Thank you we will now begin the question and answer session to ask a question a press Star then one on your touch downtown if you're using a speakerphone. Please pick up your handset before pressing the keys to withdraw your question. Please press Star then tail. Please limit yourself to two questions here for any additional questions.
The first question Jay comes from Charles Meade with Johnson Rice. Please go ahead.
Good morning builds your whole team there.
I appreciate you in your prepared comments you 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've heard is that that you said you're going to look at your cash flow at the time looking to 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 in and what I'm curious about is if let's say you set your you set your budget in February when the strip is the tax if the strip goes down in let's say in.
In June of 20 to something less than next are you also then going to decrement the capital budget to it. So you can stay within 300 million cash flow.
Yes. Thank 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 at that 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.
The sale proceeds our cash flow from that.
Yep, two parts pretty important as we rock through past approval time and get to your month June or any other month and the risk Committee, which meets every week sees the trend of that.
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 cat.
Funded.
Cash flow plus up to 300 million from whatever strip there is and that's a practice that we had been doing for several years.
If if you have done a subsequent period of time in the in the in the year where prices jumped back up.
And again, the economics of the projects remain robust than we will.
Unread start all those projects and add them back to the list, but not go over that that budget that we set.
If.
And that's most important when you get these surges of pricing and set winter month or something.
One month or one week or one even one quarter does it 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 its adjusted.
That is helpful clarity the thank you Bill and.
There's a lot of questions I could ask but but just for my follow up I wonder if I could drill down a little bit more into the beat and condensate volumes on the quarter and maybe this is for clay because I think you addressed some of it I can I can match at least three things and there's probably more that that could be driving one could be timing of wells that you get.
You guys are getting two wells on earlier and you're going to be near that.
You know near the high end of your guidance that would be too is just the number of wells.
You, maybe there's a mix shift, but then there is a third which has made the most interesting which is that the actual productivity of your of your wells is higher in terms of the condensate yield.
Then you were planning so could you could you give us a sense of how that beat on condensate what the drivers bonded, Oregon and if there are temporary or something that we should be looking for.
Looking forward to continue going into 20.
Let me I'll make a couple of comments and handed to clay first of all our acreage.
Has a condensate component to the gas that is is leading in the basin.
And so if you look across our Super rich area.
Our Super Rich area contains more condensate than any other acreage is out there number one number two.
We do a lot of yield management. So it's it's all about economics, and so we managed 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 the condensate yield.
That's what's generating additional value for that for the company and clay has some further details to talk about it as Bill mentioned, we have it in the IR materials in our broken, Ohio County, where we had the highest condensate yields a 100 plus barrel per million in some areas and.
And as you all know from the previous calls we've been focusing the majority of our wells in that area and our plan timing had the largest number of our wells come into sales into Q in Threeq, you and we're continuing to see the benefit of those wells coming online in Threeq you.
And the 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 sub surface knowledge.
Maximize on how we're completing the wells and where we're landing 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.
Thanks for the color.
Thank you.
The next question comes from June vendor with Morgan Stanley . Please go ahead.
Hi, everyone.
Is it really great results 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.
Well you didn't much different in the upper Devonian well relative to the offsets never has its different reservoirs.
And then the upper Marcellus Similarly, if.
Theres things, you're doing different on that test as well.
Certainly this clay we.
This is our first test of the upper Devonian in the Super Rich and as you know in our previous testing during the year.
We took what we learned from that the testing in the rich area and adjusted our completion designs in order to maximize the economic benefit of.
The combined production of both the upper Devonian and the Marcellus.
So we ended up with a reduced completion design, which help the economics and we're seeing similar performance. So we think we're continuing to make progress.
On.
Elevating the combined development, but it's still early and we have some ways to go to keep pushing that in the current commodity price environment and any reduction of completion designs or any reduction of cost.
Always looks at the value creation.
That that is involved in that so we don't they'll reduce.
Costs to reduce cost and impair value in and it's a great example, and in how they manage these wells.
To highlight that back.
And then on the upper Marcellus.
We we like some other operators have been testing the upper Marcellus sell us 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 inline with what we thought that upgraded performance would be and so our plans are to continue testing that as we move into 2020.
Thanks for that Kelly, So just a follow up on the the upper Devonian.
In the past a lot of operators had seen reduce performance relative to the Marcellus I think in part because it was lower pressure.
Do you think it partly maybe because prior operatives and then drilling upper Devonian subsequent to drilling upper I'm, sorry, the drilling Marcellus and less pressure drawdown may be reduced the productivity of the reservoir as it or maybe it's just the upper Devonian.
Higher pressure in more productive on your acreage.
Yes, we're we're aware of the kind of the past.
Discussions around the co development of the upper development Upper Devonian with the lower Marcellus.
In our minds, it's how do you optimize the completions to to limit the well interaction between the two zones and.
Maximize the the economics from co development, 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 bad interference, but yet still getting the same or better production results, which would enhance the economics.
Okay. That's really quickly just just one last follow up on this point.
Do you have any of any locations identified in there.
Identified drilling inventory in for either of these zones upper Marcellus and upper Devonian.
We definitely in our full playground of inventory of future drilling locations have drilling locations in both of those two 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.
Yeah, Thanks for like I guess.
The next question comes from Holly Stewart with Scotia, Howard Weil. Please go ahead.
Good morning, gentlemen page.
Just maybe bill starting off with it kind of a high level question in your prepared comments you talk about being in a position to take advantage of financial.
Regional and strategic opportunities given your maturity profile was wondering if you could provide.
Further insight here and then maybe also given what we've seen another basins with merger of equals do you think this might make sense in the Appalachian basin.
Well, thank you all and good morning to you.
We look constantly at creating value.
With our assets and beyond our assets for the shareholders and we look at at growth or expansion that along the lines that you're talking about it in two 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 reserves into two 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 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 both bolt on opportunities for adjacent acreage, where we can expand the efficiency of drilling longer laterals are just expanding the footprint as long as its accretive.
But also look at add to significant.
Additions, including combinations, including mergers.
We study those opportunities all of the time and 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 play room in that space than we believe that that we ought to focus on and 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 an accretive inventory to us generate real economics on a full cycle basis.
Once sheets 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 than the opportunity may make sense and will and we'll continue to explore it.
In that in a DNA.
Margin based commodity based business industry scale.
Materiality resiliency in all forms of.
Of our pricing environments or regulatory environments, and a number of things you think about it makes sense to explore those opportunities and we do.
As I said upfront, we continue to evaluate that we'd prefer not to comment on the details. It's just how we will work when we sell 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 two ourselves for now.
Understood good color.
And then maybe just one for Julien on the on the debt repurchases in the quarter.
Good how do we we think about this yeah as we kind of pre feed into the fourth quarter and then head end you Tony Tony on further get retail.
Yes, I mean, Holly we obviously always focused on 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 too.
Tend to make some repurchases we've made some noncore asset sales and so.
It seems like an appropriate steps and consistent with our goals, we're always evaluating all opportunity evaluating opportunities.
And and consider debt repurchases along with any of the other investments that might make so I can't give you clear color as to what we would do you know at any given time, but.
Again, I think you know what our principles, which is maintaining the balance sheet and addressing the business.
Great. Thanks, guys.
Thank you.
The next question comes from Aaron Jan with JP Morgan. Please go ahead.
Good morning, I wanted to first started off on the on the well costs 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 the thoughts on service costs I know you are being 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 you're if these well costs.
Come in at this seveneighty or lower number for next year.
Alright, and I'll start on the on the cost reduction discussion.
As you've seen from the results. Our teams are 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 the us taken over.
Self sourcing of sand as an example, where we dramatically benefited the cost and on the water system and then of course to the longer laterals. So all of that is continuing and then when when you look at the numbers were 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 to under their cost structure of 2018 and look only at wells spud in 19 and that are coming online to sales in 19 that numbers down close to.
$790 per lateral foot. So directionally, we're going to budget for 2020 factoring in all the efficiency gains that we've already realized and then raising the bar to go find more.
Got you clay, maybe just some thoughts on your sustaining capex requirements. If if you.
If you theoretically went too.
You know what capex required to keep 19 production flat.
Yes. This bill again, a a maintenance capex as as we call it is $600 million to $650 million.
When I look at how reinforce some declines that it's not only the drilling cost is 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 years.
Programs why that wed in any kind of form of cost and the 606 50 is exclusive any.
Right. So that's the D. and see that component that's right.
Okay.
My follow up I was wondering if you could shed some more light on the compression.
Work that you've done it sounded like that help boost production by 55 million today 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.
Yes so.
There is an initial flush benefit, but we have the full benefit modeled as we look at the how the production.
Shallows that decline because you are lower and the.
Line pressures at those pads when we look at the base decline were already able to see the trends and that it's going to help us improve our base decline to a mid twentys around a 25% number down from the upper Twentys, where we've been Matt.
Yeah, and I put a top side on this.
One other things we're trying to just get all the way the reservoir, we have a choice of either during this at a pad location or doing it across the entire gathering system, but we have got a lot of robust areas and wells and pads in different acreage that continues to perform quite well at higher transmission level pressures and so we target.
Ads in individual areas, where we can drawdown the the pressures on the well 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 you have sustained performance from it we do the same thing with with.
Looking at optimizing any kind of midstream.
Whether its pipe restrictions or anything else all at the same time the goal is.
His get all the way of the reservoir.
And allow that reservoir to continue to perform and base production improvements are are great economic projects you talk about our capital allocation. These come up to the top last because of the return that generate.
Added it stems decline.
Yeah, just would maybe one housekeeping question Bill you did in a beat consensus production.
Estimates for the quarter, yet you kept the full year.
The same at any thoughts on that just conservatism or did it just reflect some tils moving into the third quarter.
Yes, a room, where we're going to continue to focus on the value added aspect of our production.
As we move forward there 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 Twoq and Threeq, you Wouldnt, which has an effect on the overall equivalent volumes. So.
Day today, we're going to keep looking to maximize the value from the production, but theres some variables that could swing it a little bit.
Fair enough. Thanks, a lot like.
The next question comes from Kashy Harrison with Simmons Energy. Please go ahead.
Hi, Good morning, everyone and thank you for taking my questions thing.
So I guess my first question surrounds the the capital efficiency improvements that we were just discussing and that you've seen.
In Q3.
And this might be a question for Claire Julien and I know, it's not an easy one answer but if we took the 29 team pace of activity.
So the numbers wells drilled completed turned to sales et cetera, and just mark did for the leading edge current costs experienced in Q3, what would you know into guesstimates or find what would that be adjusted Capex budget be for 29 team.
So would it be 10% lower just just any rough guess on how that would change would be great.
I guess from a starting point if I if I take into account the the at least a 5% maybe adjustment when when you think about the.
The solely the impact of wells that have come online in 19 in 19 compared to the higher cost structure that came in in 18.
Okay and then that's helpful. And then if you look to.
Further reduce costs.
Do you think there might be a potential benefit to monetizing the oilfield services segment.
Taking advantage of really low service pricing across the entire.
Industry.
We've seen a larger operated in the Permian due this year more recently and it sounds like it's generating.
Positive capital efficiency rate of change forms I was just wondering if perhaps there's a there's and thought process on monetizing the service business.
Yes, I think I think what you've got to look at is.
Across any part of our of our business, whether it's the services side, whether it's our water infrastructure or any of those kinds 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.
The value we create by doing it ourselves versus what we could do on the outside we take the the.
Flexibility that that these businesses provide.
And moving capital around you take multiples that you might want to get on on any of these will come with drilling commitments and other at or other project commitments. That's what drives these things to be so valuable.
And you've got a balance all that on on the back of economics, and if it makes sense to do it one way that's how we do it makes sense there another way we look at that.
And Thats, how we if you look at all out other questions that that we get asked.
They all have an economic rate.
And that economic rate is at strip pricing that economic route is making sure that permanent objective point of view whatever we're doing is delivering the value that that is supposed to and if it does not that we have to look at the alternative to that.
Gotcha, if I, 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 for natural gas, we look at the implied NGL prices.
They are pretty bad.
And I was just wondering using your preferred metric of returns.
Are these projects generating sufficient returns to take your corporate expenses or is that thought process with using $300 million from from the favorable proceeds just.
Counter cyclical 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.
We take a look at whatever we're guiding to invest and whether its operating expenses capital whatever 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 factors cash flow to invest in it in the proceeds as we've already talked about.
Force rank those projects against economics, and so we know the order, which way they might be down in than we add them all up and load them up with all the costs that yours that you speak about and if they don't generate.
Acquired return that that package doesn't work and we go back and re look at it we carve off what projects again, it's it's created in the economic return.
Fully burden.
And.
At current strip with current differentials projected through a three year period, so you're going to all the while you're kind of want to look at the forward curve for three years. So that's where the bulk of the return comes from in that one to three year period.
And we run that we run that over and over and then as we said earlier, if those economics change because there is a lower.
Commodity or price our of higher basis.
And the areas, where we where we work, we adjust that and and that Weve and then we peel off the bottom end of that stack if you will.
Because they are prioritized and that switching that's that's how we invest.
And so.
To be to be crystal clear, whether its vertical integration drilling wells any kind of investment we make.
It's got to our it's it's way too creating value and generating returns on that and its investment.
For the shareholder it's how we run the company.
Got you. Thank you for taking my questions.
Thank you.
The next question comes from Noel Parks lets Coker and Palmer. Please go ahead.
Good morning.
Morning.
Oh.
Just a couple of them as I was wondering at this point 'cause your release does those always give us an update on average lateral length.
What are your longest lateral length sort of by by region now how long how how far out have you.
Have you drill.
Now we've got a eighteensix 18600 foot successfully completed lateral in west, Virginia, and an 18000 foot in Pennsylvania.
Okay.
Great and.
I know the data for love that that sizes. So on the process of accumulating it.
Any any signs that the your your nearing diminishing returns for for going out so with that length.
From a mechanical standpoint are nearing is probably relative thats 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 to get the one for one benefit on the longer laterals, there's not as big a data set of those so we continue to watch those but but everything is looking good so far I gave you those.
Longest laterals flip flopped southwest Appalachia is 18000.
And so but Pennsylvania is 18 six.
Okay great.
And.
Just thinking about infrastructure in general or maybe more thinking about transportation agreements at this point, what's sort of the.
Oldest vintage.
Agreements you have excuse me you have in place at this point.
Is there anything on.
The way to rolling off are you you might have opportunities to.
Renegotiate terms in this environment.
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 dealt or operating today anywhere else.
And it's and it's really an asset to the company it's highly flexible.
And gives us a lot of flexibility of the pace of.
Testing et cetera.
All the way to the newest.
Transportation.
Portfolio that we have in west Virginia that is.
Priced appropriately for that for the market in the times that 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.
Rolling into that.
And a a proof point around that is four wheel, we're able to add.
Transportation at a discount in the future.
That enables that flexibility to continue and we havent had to overcome it.
And purchase a lot of transportation that we don't need.
And this strategy for how we manage this is playing out.
Great. Thanks, a lot.
Next question comes and Bgs paraphernalia Susquehanna. Please go ahead.
Hi, good morning, Thanks for taking my question.
Well it sounds like you are well make won't be shifting more towards via the Super Rich area and wondering if that's going to some upward pressure on your.
Operating.
Lands or do you have projects in the works gathering systems or something else, that's going to offset that.
Yes, I think let me just check one one comment in the front of it you know for the last couple of years, we've been running majority of the activity in the Super Rich liquids rich area wherever you want to call. It in West Virginia, two thirds, one third ish.
Of the of activities in the Super Rich area and as a smaller portions in Pennsylvania.
Commodity prices drive that so if you have.
It out five rigs and you put three of them in one place into than the other three and what are far and one it bounces a little bit back and forth, but 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 towards that investment so.
We constantly look at ways to renegotiate agreements, where we can or or expand the pie. So that we get better rates and we'll keep doing that.
Our lives impact on on Valerie.
Got it may have higher allele, but it.
Great part of that as it has higher revenues, which means that margins greater and so we're happy to take us.
Yes definitely.
Well it was actually.
Going back to the upper Devonian test.
It sounded like the previous test in the.
The rich.
Window.
Perhaps you saw some interaction between dupper.
Good morning, and the Marcellus and when you move over to the Super Rich area.
Is there anything changing on.
With respect to geology that made.
Indeed.
The two zones being independent.
Or is it simply.
How do you have computing.
So minimizing the intensity of the completions.
So the two intervals are 150 to 200 foot apart.
A little further apart in the Super Rich area.
But we're seeing communication, it's a matter of.
Maximizing the overall.
Completion design to elevate the economics of a dual.
Completion.
Co production projects, so that it adds value economically a little bit bickering Superrich then in the rich, but we're dealing with a 150 to 200 foot.
Between the two intervals.
Got you would not ruling out in the rich area that you.
You could still have.
Upper Devonian.
As a viable.
Zone.
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.
We have thank you that's helpful.
The next question comes from Jeffrey Campbell with Tuohy Brothers. Please go ahead.
Good morning, and congratulations on a quarter.
Going back to the.
The Super Rich Upper Devonian test.
Was that test done at Laura let's put it this way where the Marcellus offsets to that well in the high condensate region of the Super Rich and if so did the higher cut show up and initial upper Devonian results.
Yes, most definitely which is how we plan to test we there's too.
Lower Marcellus wells right below this upper Devonian well all in the Super Rich 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.
Okay, Great Thats, good color and.
Bill I don't want to ask a downer question, but I mean, it's I think it's worth asking and that is is there a scenario where the too.
Thousand 20, Nat gas strip could be low enough that achieving the year end 2020 cash flow neutrality might have to leak into 2021.
Yes, yes, I mean, I mean jet fuel enhance indeed, I mean, obviously, it's all dependent upon what we get to invest and from the cash flow I mean, that's that's a plan and it works in this environment, but thats clearly cases, where you just.
You would not be able to accomplish that goal and the and the follow on question that I think you may be asking me is is there a price where you'll stop drilling and the answer to that cut that question is what 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.
So we will reduce our stop activity.
We did it and twice pain and look for the same reason and we'll do it again, it's not our preference.
Thats the duty, we have to create and protect value for the shareholder and it's not about activity or our production growth. It's about real value creation, we're fortunate to be in some of the richest.
Condensate late and acreage in West, Virginia, and have some terrific acreage with that has high.
Correct the in production flow in Pennsylvania.
And a combination in the middle between the two and and so our economic stay robust, but but yes.
That question.
Right well now that that's really helpful. So I made the point is as 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.
Fundamental.
Okay, great. Thank you appreciate it.
The next question comes from Scott Harold with RBC. Please go ahead.
Yes, Thanks, and I apologize if I'm going to re ask your question I've been dropped off line a a few times here. So I didn't get the year. The full a full set of questions here, but first a follow on on the pre prior question is what is the level of.
Production or what do you need it to achieve that free cash flow sustainable free cash flow neutrality by year end 20 is today is it a capital.
Since the with your well cost is the certain size or the production base you need to hit but what is sort of that level, we should be looking at.
Yes, 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.
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 all contributing to that and that's that's what's driving it.
Okay. So so if I can ask it more more directly like what is what is sort of the base production level that you feel as sort of that free cash flow like breakeven level.
Where is that.
There's it's got this not there's not really a production level I mean, it's going to depend on commodity prices write them into commodity prices I guess, but up different EBITDA different cash flow I mean at different levels. So it theres not a production number we're chasing to deliver that it's all.
Okay.
Combined together with the cost structure and everything else so.
Okay, Okay, and then and then what.
What impact could do it could have those improvements on compression that you all been talking about have you know on on on reaching that I mean like how much how big is that as you kind of rolled that out to another well pads and reducing your maintenance capex.
Yes, I mean.
The impact that that had is it just helps further the resilience and handle that.
The base declines and so forth.
As far as rolling it out I mean clay.
Yes. So so we're we're doing the majority of our work in 2019 is in our dreams wig area in Pennsylvania in Bradford County.
And then we have plans that were finalizing for the continuation of it going into 2020.
Okay, and what did that have an impact than a maintenance cap does it like reduced by like 5% or 10% like how big could that be.
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 balancing all those things were in that 600 million dollar type of number.
Yes, I think there to cap. This question off just like in your model you've got multiple levers that you can you can tweak and you'll get a different answer.
That's how we run a company we look at all of those variables.
You have lower commodity prices and basis can be awesome. It can even negate the lower commodity price you just got to look at every one of them feed them into the model.
That produces a glide path for investment for.
Revenue for costs and and then we go from there and so we're we're seen and very clear.
We can be free cash flow neutral today, if you just stop.
But thats not the right thing to do and we have a model for that so we really look at it added holistically.
Okay understood. Thanks.
Due to time constraints. This concludes our question and answer session I would now like to turn the conference back over to delay for any closing remarks.
You know this year's plan out fundamentally with the way, we position the company and ready to 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're running the business to ensure that we've got it in a compelling investment thesis today and in this environment as well as over the long term.
I think we've 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 Appalachian for example, and reshape the portfolio.
Whether it's through divestitures, whether it's the diversification of the liquids.
To make southwestern energy strong resilient organization with a lot of talented people who share the outperformance mindset that we hope we've gotten across from me today.
Teams continue to innovate they continue to execute quarter after quarter. So we thank you for your interest. Thank you for your questions and you will have a great weekend.
This concludes the southwestern Energys third quarter 2019 earnings call you may now disconnect.