Southwestern Energy Company (NYSE:SWN) Q1 2019 Earnings Conference Call April 26, 2019 10:30 AM ET
Paige Penchas – Vice President of Investor Relations
Bill Way – President and Chief Executive Officer
Clay Carrell – Chief Operating Officer
Julian Bott – Executive Vice President and Chief Financial Officer
Jason Kurtz – Vice President, Marketing and Transportation
Conference Call Participants
Charles Meade – Johnson Rice & Co.
Arun Jayaram – JPMorgan
Jeffrey Campbell – Tuohy Brothers Investment Research
Kashy Harrison – Simmons Energy
Rehan Rashid – B Riley FBR, Inc.
Marshall Carver – Heikkinen Energy Advisors
Noel Parks – Coker & Palmer Investment Securities, Inc.
Brian Singer – Goldman Sachs Group Inc
Sean Sneeden – Guggenheim Securities
John Abbott – BofA Merrill Lynch
Good morning, ladies and gentlemen, and thank you for standing by. Welcome to the Southwestern Energy First Quarter 2009 Earnings Conference Call. Management will open up the call for question-and-answer session following prepared remarks. In the interest of time, please limit yourself to two questions and re-queue for additional questions. Please note this event is being recorded.
I will now turn the call over to Paige Penchas, Southwestern Energy’s Vice President of Investor Relations. You may begin.
Thank you, Denise. Good morning and welcome to Southwestern Energy’s First 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-K, which is available in 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 statement section 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.
Thank you, Paige. Good morning, everybody. Thanks for joining us on our call today. We powered into 2019 refocused, reengineered and reenergized as a leading Appalachia in liquids and natural gas supplier, continuing to achieve the strategic commitments we made last year. Our people in alignment with our returns and value-driven strategy have delivered another strong quarter and successful quarter and a successful start to the year. We are well down our path of consistently delivering on every commitment and with repeatable results. These flow from an increasing capital efficiency and disciplined capital allocation.
Operational execution continues to be a core driver of our performance; from longer laterals to shorter cycle times, from higher production to lower costs, we have some impressive results to share with you today. In our first reported quarter post the Fayetteville monetization, our adjusted net income was $145 million or just $17 million below the first quarter of last year, which included Fayetteville. Production was above the midpoint of guidance with total Appalachia production up 14% over the first quarter of 2018.
We achieved another natural gas liquids production record underpinned by the dedication of our teams who with incredible focus and energy worked through winter weather conditions going to extraordinary lengths to deliver these results while operating safely, and I’m very, very proud of every one of them.
The entire company remains relentlessly focused on ways to operate even more efficiently, cut costs and further improve margin. Let me give you two proof points compared to the first quarter of 2018. Our margin of a $79 per Mcfe was up 14%. G&A and interest expenses were down 32%. Last quarter, we announced an ambitious plan to materially reduce well costs and we are well on track. With the benefits of our new water systems direct source sand and exceptional performance of our company owned and operated drilling rigs and track fleets average lateral links are projected to increase by 35% to over 10,000 feet in 2019 across our assets. I’ll share a couple of the many operational examples with you now.
In southwest Appalachia a 14,000 foot lateral was turned to sales in March at a cost of $804 per lateral foot. In Pennsylvania and West Virginia we drilled and cased wells with horizontal lateral lengths in excess of 18,000 feet. Both of these achievements further demonstrate our drive to reduce costs and improve the already strong returns of our Appalachian Basin well investments.
What has enabled this success? I think one key factor is the deliberate and ever-increasing pace of how we apply learnings at SWN. Our integrated drilling completions and subsurface teams test share and apply results across our 480,000 acre position in the Appalachia Basin in both liquids rich and dry gas assets. Rapid application of new knowledge is a key driver of the overall progress you’re seeing and you’ll continue to see going forward.
On the financial front, we ended the first quarter with the company’s best liquidity position in almost four years. Net debt to EBITDA was an impressive 1.7x down from 4.5x at year-end 2016, a testament to our rigorous focus on balance sheet improvement. We said we would do it and we did it. Our transition plan is producing results enabling the company to generate solid investment returns with less capital from lower costs and return to free cash flow by the year end 2020.
Our capital program is disciplined returns driven and fully funded. Capital is allocated to the highest return projects which are rigorously evaluated based on stripped pricing, and as commodity prices are volatile in our industry, I’d like to remind everyone that if commodity prices fall and cash flow funding investments drops below our budget, we will reduce capital investment by a like amount. We will not increase the use of Fayetteville proceeds in 2019 to supplement cash flow resulting from lower prices. This is a critical part of our capital discipline and is another way of saying, like last year, we will not invest more than our capital guidance this year.
As you’ve heard me say before operating in a safe and environmentally friendly manner is a core value at SWN. You have seen the press release yesterday announcing the company was named the number one publicly traded Energy Company in North America for water and chemical management practices. It’s gratifying to see that our hard work is being careful– of being a careful steward of the environment continues to be recognized. This is key to maintaining a sustainable business and license to operate.
So as you can see it’s a great time to invest in Southwestern Energy. We continue to demonstrate that we have delivered on every commitment we made on our plan as a repositioned company to capture greater value going forward for our shareholders, as a hallmark of how we operate this company. We’re driven by returns focused investment and defined by demonstrating rigorous financial discipline. Our efforts are led by operational and technical excellence in margin expansion through cost reductions and improved well productivity all the while drive — while driving differentiation through vertical integration, safety and environmental stewardship.
We’re always thinking about ideas and opportunities with a keen eye to assuring that there is real long-term value creation. We’ll evaluate those ideas with the clarity, rigor and discipline that you’ve come to know us for and we’ll implement those ideas with the confidence, assurance and underlying promise of delivering that long-term value when we commit that it will be delivered. Let me now turn the call over to Clay to talk about some operational highlights.
Thank you, Bill and thanks for joining us. We started the year with another strong quarter and continued our operational momentum. We achieved greater operational efficiencies and the resulting cost reductions as we began our planned progression to longer laterals in 2019. We continue to improve well performance on both new and existing wells. Total production for the quarter was a 182 Bcfe with liquids accounting for 21% of total production. Liquids production increased 33% to 71,740 barrels per day consisting of 62,260 barrels per day of NGLs and 9,490 barrels per day of condensate.
As planned, we invested $325 million in the first quarter; the shape of the capital spend will be similar to the 2018 and weighted to the front half of the year. In the current commodity price environment, we expect to average approximately six rigs and four frac crews in the second quarter. We set several new SWN records in the first quarter including completion stages, drilled footage and lateral links. We set a new pad record of 8.3 completion stages per day; we drilled a record 8,300 feet in a 24-hour period while drilling a 100% of the time in the target zone and we set new drilled lateral length records in both West Virginia and Pennsylvania.
As Bill mentioned, we are on track to deliver an average completed well cost of $875 per lateral foot for wells to sales, at 25% well cost reduction versus last year. Average well cost in the quarter were reduced by 10% to $1,022 per lateral foot on the 19 wells we turned to sales during the quarter with an average lateral length of just over 8,000 feet. As planned the Q1 wells to sales included some wells that were drilled in 2018 without the benefit of our 2019 cost improvements.
We have extended the average lateral length of wells drilled during the first quarter to almost a 11,000 feet and as they are brought to sales, will decrease our average cost per lateral foot even further. So costs are moving in the right direction and we have a clear path to our 875 goal. We drilled five ultra-long laterals this quarter, each in excess of over 15,000 feet applying learnings from our methodical approach to extending lateral links, improving the capabilities of our teams and our company owned super spec drilling rigs.
Well performance continues to improve in both our liquids, rich and dry gas acreage. In southwest Appalachia we brought nine wells to sales with a combined initial production rate of 99 million cubic feet equivalent per day including 67% liquids of which 4,800 barrels per day were oil. In Northeast Appalachia, we brought 10 wells online with a combined initial production rate of 199 million cubic feet per day including the Tioga County well that came online at an initial rate of 39 million cubic feet per day which was a new company record.
As part of our focus on converting resource to reserves, we continued to progress our evaluation of the Upper Devonian Utica and Upper Marcellus intervals. We drilled our fourth Upper Devonian well in the first quarter and plan to complete the well in the second quarter. We also continue to progress our operational and technical knowledge of the Utica through ongoing data trades. In Pennsylvania, we plan to drill three Upper Marcellus wells in the second quarter testing current generation drilling and completion designs.
And now I will turn the call over to Julian for the financial highlights.
Thank you, Clay and good morning everyone. The company generated $319 million of adjusted EBITDA. Our net cash flow was $309 million, which was 20% higher than the first quarter of 2018 excluding Fayetteville contributions driven primarily by greater production and benefiting from higher realized gas prices offset slightly by lower NGL prices. The cost saving initiatives we implemented last year is now being fully realized with $46 million in G&A and interest savings this quarter. $22 million of that was associated with the G&A and the remaining $24 million is the interest expense savings as a result of our strategic actions that reduce debt by over $2 billion last year.
Our weighted average realized price which is reported for all commodities on a per Mcfe basis was $2.98 per Mcfe, $0.17 higher than the $2.81 per Mcfe last year.
For natural gas, we benefited from overall base differential improvement, realizing a $0.20 discount to NYMEX, $0.08 better than last year before the impact of derivatives. Our realized NGL prices were $1.00 per barrel lower than a year ago as we receive 26% of WTI this year compared to $0.25 last year. Ethane prices moved lower during the second quarter –second half of the quarter primarily due to delays in new cracker startups.
We believe ethane pricing at Mont Belvieu should improve in the second half of as demand in the Gulf Coast grows from the new cracker capacity coming online. Additionally, propane prices were pressured by isolated export shipping constraints. However, we have seen recent improvement now that they have been resolved. Our balance sheet remains straightforward and strong. Earlier this month, our Bank Group reaffirmed our borrowing base and we are maintaining our bank facility at the $2 billion level with no borrowings outstanding today.
We have no significant debt maturities before 2025 and our leverage ratio is currently at 1.7x. I’d now like talk about hedging. We continue a dynamic commodity and basis hedging program utilizing swaps and collars. For 2019, we are approximately 70% hedged on gas and over the next two quarters approximately 80% is hedged at a floor price of $2.85 meaningfully above the current strip. Of this, 40% is Collard to capture price upside up to $3.10 .
That concludes our prepared remarks. So, Gary, could you please open it up for the questions.
Our first question comes from Charles Meade with Johnson Q – A J Rice. Please go ahead.
Good morning, Bill, Clay and the whole team there. I wanted to first ask about your outlook for pricing. I know it seems to be a bit of theme for a lot of Marcellus players, Marcellus producers right now that differentials are tightening or have tightened in 1Q but they’re looking a little more wide in the shareholder season. So can you talk about what you see as the drivers for your differentials going forward?
So, Charles. This is Jason. So our view on basis has been for several years that wants the new take away from the northeast was placed in service that we would see dominion tighten as take away exceeded production and with over six Bcf a day of capacity placed in service in the northeast in 2018 and early 2019, while production has remained relatively flat. We’ve seen dominion tighten to somewhere around NYMEX minus 45 to 50 which is a level that we haven’t experienced in several years.
And we were well positioned and our transportation portfolio was positioned have benefit from the tightening and the basis differentials in that area. And I would also say going forward; we’ve been actively adding financial and physical basis protection for the balance of 2019 and summer of 2020 for locking these levels to be able to secure cash flow. So we’ll continue to monitor the remaining takeaway projects that are under construction in the supply and demand balance in that area and add basis protection accordingly.
Got it, Jason. But to the — so what you’re expecting in say 2Q, 3Q, 4Q versus what you experienced in 1Q, any directionality, you can offer?
So, yes, 2Q and 3Q the dominion will be wider than what it was in 1Q. I think in 1Q it was somewhere around NYMEX minus 30 and 2Q and 3Q somewhere around NYMEX minus 50. So there’s about $0.20 differentials between those quarters.
Got it. That was I was after. And then Clay, you’ve mentioned that Tioga well in your prepared comments and you got mention in your press release as well, I was wondering if you could add a little bit on or what you could add on where you landed that well, if there was anything different about it and how it compared with your previous expectations?
Sure. We landed it for Marcellus normal landing zone some of the big differences on this well are we were able to drill a longer lateral there, it’s over 11,000 feet versus what some of the offsets have been. This area benefited from that joint venture we talked about last year, where we were able to bring some acreage together and get the longer laterals. Secondly, we continue to be optimizing our completion designs and we feel like in that area we adjusted some ideas there and it resulted in even better well performance, so that the combination of longer laterals and the ongoing completion design improvement is resulting in better performance.
The next question comes from Arun Jayaram with JPMorgan. Please go ahead.
Yes, good morning. Bill I was wondering how your thought process is about in southwest PA? Obviously you guys have been focused on the wet gas part of your acreage. Given the softness and liquids pricing how are you thinking about the relative attractiveness of dry gas versus your wet gas acreage?
We’re fortunate to have both super rich and rich liquid fill gas in West Virginia and dry gas in West Virginia and Pennsylvania. And so as we allocate capital we look at and the super rich has condensate with it as well but as we allocate capital, we run returns on every project that’s in the queue and we force rank them against each other and strip pricing. And so where we see a shift to higher gas pricing or higher liquid pricing or the for the reverse of that we can adjust and schedule accordingly because we drill our own rigs and we complete at least partially with our own frac leads.
And so it gives us a lot of flexibility to go back and forth at the current time, as we look at the core period which is the period where we get returns investing if we’re –if we remove — using six rigs today having around four of them in the super-rich area that includes condensate and having two of them in these high volume and high rate wells in Pennsylvania is where we sit. And we think that that will continue through the year.
Yes, got you, and just given the softness we’ve seen just in pricing at one point, Bill, will you consider if any adjusting the capital program to reflect what’s been a little bit of a softer start to the year in terms of pricing?
Right. So what we do is we keep a running total of the cash flow projections and the impact of cash flow from commodity price changes. And if we have our cash flow go down then we will adjust our capital back and so what we do we’ve got –we need more than one months view but let me just give you a direct example. We’ve got this list of wells, we’ve got them prioritized, If you see a reduction in cash flow because of prices will go in and sort of red circle the back end of that drilling schedule where we need to adjust down, and then as we move through the year if that sustains itself we’ll pull back. But our commitment is to drill or invest within guidance or lower if capital price or gas prices and liquid prices should shift down and impact that capital.
The next question comes from Jeffrey Campbell with Tuohy Brothers. Please go ahead.
Good morning. Congratulations on the quarter. I want to go back to that tie over well again real quick and just ask will the result, I mean it’s such a strong result is that going to attract increased future capital as a result of the success? And I’m also just wondering how the JV would limit you or help you if you wanted to put some more money into that area?
Yes. The JV doesn’t limit us at all in terms of the acreage that was included there; it benefits us with longer laterals. We’ve been fairly consistent in the last two years with our Tioga development and we have a nice program plan here in 2019 and we’ll continue on that path. So we’re pleased with it. We’ve got some quality inventory there and I would expect similar development as we go forward.
And as we — to add a little bit to that as we flow this well and learn more about it in terms of how ultimate UR and flow characteristics that comes into that equation of fracking and stacking well projects to determine where we go.
Okay, great, thank you. And I just noticed that it sounded like that the liquids content of the super rich wells in the first quarter was a little bit above tight curve. I was just wondering if this was a statistical result or is there anything you’re doing and completions down there that’s capturing a little bit more liquids.
I would say it’s tied to just the general mix of wells that we’re bringing on. It was a little bit higher. We certainly want to maximize the liquids contribution from those wells in the way that we flow them back early in their life. So kind of in the range of the expectations we had on the liquids performance.
Our operating teams are testing dynamically. So we’re altering our characteristics of how we flow back, how we design completions and so as we learn more about that we’ll make adjustments.
The next question comes from Kashy Harrison with Simmons Energy. Please go ahead.
Good morning, everyone, and thank you for taking my questions. So, Bill you’ve been very clear on your ultimate strategy of returning to our organic cash flow neutrality and you’ve been committed a capital discipline for many years now. I was just wondering if you could share some color on just how you think about just the state of your current portfolio and how you think about Southwestern’s role in M&A or either as a buyer seller just to the extent that you can share your general strategy on that side of the equation.
Sure. We’re very confident in the portfolio that we have, and we especially like the diverse nature of it, whether it’s super rich condensate laden wells in West Virginia or high flow rate volume gas wells in Pennsylvania, and a variety of emerging intervals whether it’s upper Devonian or Utica as we continue to solve that. So a lot of confidence, a lot of a real drive to figure out organically what we’ve got in that case. As we look forward, you kind of look at this in two parts.
We’ve got 50 trillion cubic feet of resource across our acreage and just about 12 trillion cubic feet equivalent of reserves. So a big focus of ours is what the shareholder already owns, we want to make the best of it. So organically grow that, organically figure it out, testing research, we have a science budget and very methodically work through and bring more reserves to bear in that large resource base. Any opportunity beyond that whether it is that organic growth I mentioned or something that comes our way, you will have our commitment to rigorously analyze that and make sure that it drives long-term returns and long-term shareholder value.
And as we evaluate those that discipline and focus and really mirroring the efforts that we’ve done so far, if we’re ready to commit to benefits from another kind of an opportunity and we’ll figure out when those benefits are to be seen by the shareholder we’ll make commitments to end, we will deliver on those. And if we’re unable to do that then it’s not a deal that makes sense to us.
And just as a follow-up to that question any thoughts on outside of just think about it from perhaps a value or NAV perspective but any thoughts on what it would have to be a accretive on whether it’s free cash flow per share or EBITDA or just anything you can share with that regard.
Yes. I mean you look at all the metrics that a responsible publicly traded company would address and those are those or some our leverage ratios are health of our balance sheet all of the different pieces and the true full cycle returns that that are required, and I emphasize full cycle returns that are required to make such a thing, such an idea viable. We look at all that and if it doesn’t meet those criteria then you’ve got to ask yourself while you’re doing it.
We are agnostic to commodities where we can deliver value from commodity we go and look there, thrust into West Virginia and our belief in NGL but as the leader of a public traded company looking at all options in all places and then prioritizing and making a move when we know we can deliver the result and protecting that by such things as our hedging policy and other practices that we have, we can move forward.
Make sense, thanks for the great colors there. And then Julian, you talked a little bit about NGLs, I was just wondering if you could help us think through the shape of NGL realizations relative to TI in the coming quarters. Should we think about Q2 maybe roughly similar to Q1 and then maybe second half towards the higher end of guidance? Is that how we should think about the shape?
So this is Jason. I’ll take that. I’ll take that question. Yes, I think you’re right based on what we’re seeing in the market – the market place right now. NGLs were a little weaker, they didn’t follow the movement up in crude for several reasons so you know in Q2 and Q3 ill probably be at the lower end and then on up towards the middle to the higher end in Q4.
Make sense. Thanks and congratulations on the solid quarter in the ESG award.
The next question comes from Rehan Rashid with B Riley FBR. Please go ahead.
Good morning. Couple of quick questions. The 15,000 foot lateral can we kind of get some color on what portion of your acreage would lend itself to this kind of lateral length and kind of how much incremental data do you need to help us think through how broadly you will apply this in the out-years? And then I’ve got one more question.
Okay. Our acreage with the work of our teams over the last few years has positioned us for progressing the lateral links significantly like we did this year, and then when we look a little further out, we think we’ll be able to maintain those lateral links. Of the five that we’re talking about four of them were in West Virginia. We saw a nice 20% reduction in the cost per lateral feet that were partly contributed to the longer laterals that were seeing in West Virginia. And then the fifth one was in Pennsylvania, so both parts of our portfolio have the ability for us to extend these laterals and that’s what we will be doing throughout the year.
And I would add real briefly before your second part of your question is, our commercial group is constantly looking at opportunities and the proof point was the JV we did in Pennsylvania, where commercially we were able to come together and trade acreage or do JV as we did. That creates an increased opportunity to drill longer laterals even in a more developed area. So I think there’s a sign across all of our acreage to do that.
Okay, good, thanks. And, Bill, again great amount of success and congrats you guys on restructuring the firm the last 24 months from this point forward. Mr. COO and CFO go to their own corners and kind of deliver on the incrementals here. The question for you is kind of this tie back to the earlier questions about M&A, but what do you kind of spend most of your time on thinking about the next one, two, three years. Where are the levers? What– how do you create value beyond kind of M&A discussion that we have and to move that kind of ball forward. Thank you.
And I think I covered a little bit of that I mean for me looking at the at a high level the impact that we can have on growing returns across this portfolio, earmarking a portion of our capital budget to science and technology advancements that move the resource base closer to reserves. Looking out at the landscape of acreage and options, we’re very proud and very confident with the acreage that we have. There’s opportunities to expand to always extract further value whether it’s learning from others, whether that’s looking at additional intervals in the acreage that we have or looking at opportunities outside of our acreage footprint, but again evaluating those on their merits to return.
Stepping up and looking at how we capture and analyze data, how we look commercially at opportunities above our existing assets to expand their footprint to make an even bigger impact is always important looking above the day-to-day and drives efficiency that today we can’t see. You look just few years ago, I think the industry had aspirations to get to 2018 and 20,000 foot wells, but those were largely not done and it’s with that advancement in leveraging that advancement technology and some incredible people, we’ve been able to methodically get there.
So investing time thinking about what’s the next chapter efficiency whether it’s cost, whether it’s how we allocate capital, how we use the strength of our balance sheet, to build even further confidence with our shareholders and then look at opportunities across the piece on. So as we generate growing cash flow, what are the uses of those of — that cash flow and thinking about how we allocate that as a publicly traded company to the various stakeholders? Whether its shareholders, returning money to shareholders, whether it’s further debt reduction or investments in high value capital projects.
Okay, thank you. I apologize, one more question. On the Northeast, can you give us some color on what kind of CapEx what kind of well count is needed to keep production flat at these levels and kind of what’s the depth of your inventory in the Northeast? Thank you.
Inventory solid. We’ve got many years of inventory there. And we continue to improve on the performance of those wells. We’ve mentioned before the maintenance CapEx for Northeast Appalachia is —
About [253,00] is what we’re doing this year.
Right. So kind of on track in line with this year.
And let me kind of add a little bit to this inventory conversation. Clay mentioned in his remarks and we’ve talked a bit about the fact that we’re going to do some additional upper Marcellus testing. And what’s really exciting about this is we’re going into places where we’ve been before. And what I’m going to tell you about we’ve done before in other parts of our business, but taking today’s technology and capability of our teams these ultra long laterals and all the technical and operating capability that we have and going in back in there and looking and drilling some additional tests wells, opens opportunities for further inventory growth and further focus into there.
In Pennsylvania, we also have Utica, we’ve not done any drilling in that space just yet but if people around us are and so as we study and learn and prioritize that kind of development. And again it’s into this resource to reserve project we’ve got drillable inventory for some time to come. But it’s opportunities like that data utilization to drive just further growth organically.
The next question comes from Marshall Carver with Heikkinen Energy Advisors. Please go ahead.
Hey, Marshall, just before you start can I just clarify. I said 250 to 300, I meant 300 to 350. I apologize.
All right. Thank you. Just one quick question, you gave the plan recount and crew count for 2Q with your current CapEx guidance. What’s the plan? What would you expect for a recount and crew count in 3Q and 4Q?
Yes. I mean let me just shape it. We put out in our guidance that we front-end loaded and that’s what we do. You’ll see this in the second quarter you’ll see the kind of activity level that we’re doing today, and then as you go into the third and fourth we manage that back again to invest within the guidance that we issue. Same as we did last year, philosophically the same as we did last year the numbers might be slightly different but principle is the same.
So what would that imply in terms of recount for 3Q and 4Q?
We are ever improving on our efficiencies, so it would be reduced from where it is. I’ll give you that color as we move forward in time.
The next question comes from Noel Parks with Coker & Palmer. Please go ahead.
Good morning. So one thing you mentioned as far as the records and first you’d had in the corner was one of the long laterals being able to stay a 100% in zone while drilling it. I was curious for the other targets the Devonian and Upper Marcellus and so forth. Is that — are they pretty uniform in terms of your ability to predict I guess the ease at which you stay in zone or do they present any other challenges just from their geology.
Let me answer the first part. And then Clay can talk about some of the challenges. One of the things that’s important and it’s benefited us and you’ll see it in our results prior today and in the future is we have seven of the very best high spec rigs that are out there in this Basin, with some incredible employee teams that are running them. And they were purpose-built to drive quality and speed of drilling and both of those are important, which is all about landing zone, all about optimizing that, but they have the equipment, manpower, electronics et cetera to consistently be able to deliver performance.
Whether it’s the speed of drilling and we’ve got some very strong results in that area. They going out 15,000 or 18,000 feet 100% of the time and a 15-foot window, they’re capable of doing that and the integrated teams make that happened because the engineers and geologists and the drillers and everybody are all watching that at the same time. In terms of where we go from here, Clay?
Yes. I’ll just add to Bill’s comments, we get similar percentages in all the intervals. We’ve got a 24 hour engineering and geologic support on all our drilling activities which are partly to make sure that we are staying on top of keeping the well exactly where we want it to be to maximize the effectiveness of the completion that we’re going to then go up put on the well. So I’m glad it looks easy or it feels easy, but our teams take a lot of pride in making sure that’s what we’re doing.
Great and the other question I had been about commodity. The commodity price outlook and you mentioned being pretty product agnostic and I’m just thinking of you look ahead and planning the out-years just your thoughts on what you say for liquidity in the futures markets. I guess seems like mostly dry gas going forward. It’s been a while since we’ve had sort of the longer dated futures really even crossover over three bucks. So just wondered if you had me any concerns about the liquidity and just on top of that I was just wondering if you foresee volatility in the commodity or do you assume it gets lower going forward just as transportation becomes better worked out or do you sort of see as some of these global demand factors like LNG and so forth have a bigger impact, if the volatility picks up? So thanks.
Yes. This is Jason I’ll take that question. So really on a longer term basis there’s really big primary driver and demand as LNG exports, Mexico exports and power generation. And global demand continues, government mandated policies call for bigger percentage of overall energy consumption mix. And the US has really supply is –it’s in a good position on the global supply curve. I mean there’s 10 Bcf a day of operating and under-construction LNG export capacity right now, plus multiple second round LNG export facilities in different stages of FID or FERC approval out to curve.
So there’s a big demand coming from the LNG side. At the same time you have demand coming from exports to Mexico for industrial, electric and electrical generation and as the pipelines get built out in Mexico that will continue to grow as well. And so year-over-year you have stronger demand out in 2020 and 2021, but the question around volatility. When we saw it in November and December, volatility is all going to be driven around deliverability out of storage.
And one thing that’s not happening right now in the market is we’re not building any new storage. So our view is that as you increase demand and you increase supply, but you don’t increase storage which is all based around deliverability. Could be in the winter or it could be in the shoulder season from an injection standpoint. We’re going to see growing volatility in an NYMEX market moving forward.
The next question comes from Brian Singer with Goldman Sachs. Please go ahead.
Thank you, good morning. You highlighted the sharp improvement in cost particularly on the SG&A side, and I wanted to see if you could comment on the trajectory going forward. It would seem that the first quarter SG&A on a per unit basis was well below the annual guidance. And wondered if there are one-off there if this could lead to lower SG&A cost on an annual basis.
Brian, we continue to work it. I do think that in the first quarter some of the costs are sort of lumpy. So when you look at subscriptions, when you look at things on the IT side, those tend to come in lumps and there weren’t any lumps in the first quarter. So I think you will see some of those come in latter part of the year as planned in our budget. But we’re still very comfortable with the guidance levels we’ve given.
And as things are dynamic, and just I’ll add to that. I’ll step away from it any one category of cost. We are driven on a total cost basis everywhere in the company to look for opportunities to become more efficient, look for opportunities to drive out unnecessary cost. And we’ve taking action to do that and it’s showing up in well cost, it shows up in transportation costs. It shows up in a number of areas across the company. Our commercial teams, our teams everywhere actually are again looking for ways to get to do more with less and that’s a hallmark of our culture.
And you’ll see that continue both here and throughout the other components of cost that we record and disclose.
Great, thank you. And then my follow-up is with regards to the Upper Marcellus drilling. You highlighted a couple of times the bringing new technology or bringing technology that hasn’t been applied to the Upper Marcellus into that zone. Can you talk for what is your hypothesis or what are your base expectations? Do you see more of the technology coming add coming in terms of cost reductions versus what had been done previously or would it be well productivity and what would make a good result in your mind on those two metrics?
Yes. Brian. I’d say it’s both. We’re definitely focused on both. We were showing evidence of the lowering of the cost through the initiatives that we’ve already talked about. And then secondarily, the improvements in landing zone, improvements in the completion designs. We think have the opportunity to elevate the economics in the Upper Marcellus versus previous year’s Upper Marcellus performance. And there are some other offset operators that I think are commenting similarly about that.
What would you need to see for that upper for Marcellus to become to take a greater weighting in your mix in the next couple of years?
I think that like Bill has talked about, it’s a rack and stack deal and based on our forecasts, I think that it will play a component but it will continue to gauge it based on the well performance that we see, but it’s not going to take a significant Herculean type of jump on either cost or performance to get it to be in the mix.
The next question comes from Sean Sneeden with Guggenheim Securities. Please go ahead.
Hi, good morning and thank you for taking the question. Maybe first for, Jason, you talked about NGL realizations there and there are some one-off factors you guys highlight around ship channel, but I was just kind of curious have any of those developments changed or thinking about your old NGO marketing strategy or is that still generally remain on track?
I would say our general marking strategy remains on track. We’re like –we’ve talked about we’ve hired a team or staffed up and what we’re trying to do is build so much optionality and flexibility into our NGL liquids portfolio as possible.
And so let me put a little color on that for you. If we have an issue where we can’t– where there’s a threat to a pipeline capacity or there’s a threat to a fogged up ship channel or whatever. We’ve got alternatives and we –the team does a great job of proactively accessing those alternatives. We’ve got great relationships with our gas processors who in turn predict, fractionate and in some cases market our liquids for us and in some cases turn them over to us to market. We’ve got a strategy where flow assurance is critical.
I mean you’ll make the product if you can’t move it so our 8X capacities been terrific and evacuating ethane out of our West Virginia Basin to the Gulf Coast where we can get Gulf Coast pricing. So whether it’s commercial or whether it’s — always trying to be in front of the gatherers, the processors or the fractionators and being sure that not only today from an isolated event, but two -three years down the road, our infrastructure is in place. Our capacities in place and we can move our products to market.
Got it, that’s helpful. And Julian, working cap was a bit of a source of cash in the quarter, was that all just Fayetteville related or how should we be thinking about that as we go throughout the balance of the year. Is that expectation that it normalizes kind of Q2 and beyond.
Yes. That’s actually not so much Fayetteville but rather just timing, just timing of the activities.
Got it and then I guess just lastly when you kind of think about, you kind of mention economics and thinking about projects in terms of the current strip. When you look at start– you are start making your 2020 plans do you feel that kind of the current cadence that you have this year is something that you or you’re going to be thinking about for next year or if you think about kind of spending within cash flow? Do you need kind of have a — in that sense.
Well, obviously, it will depend upon on commodity prices. We haven’t yet but we can continue to work but we have not in any way indicated what next year will look like. That said we have indicated a path to free cash flow and that does have a spending cash flow plus some allocation of the proceeds from Fayetteville and we signal that but that was over two years and we are in the first year of that.
Great. I appreciate the color there guys.
On the flip side of that argument is as prices, if prices were to surprise to the upside, but you pull back on the amount of those proceeds that you need to invest, and that provides opportunity for other uses of funds. We’re not in this to drive some kind of a production growth. We’re in this to deliver a free cash flow by the end of 2020 or earlier opportunity driven entirely by returns and economics at prices we can assure we can deliver those economics. Go ahead, I’m sorry —
The next question comes from John Abbott with Bank of America. Please go ahead.
Hey, good morning, guys. Good quarter. Getting towards the end of the hour here just one quick question so for 2020 you have a goal of getting to free cash flow by the end of the year. And to get to a 2x net debt to EBITDA target. Now I know you haven’t given really specific guidance in 2020 but if commodity prices did not, we’re not agreeable and leverage was by chance higher by the end of the year, is there a certain –how should we think about a certain level of growth that you guys would want to maintain maybe in 2020 to continue to drive down leverage.
Is there –in other words do you need to outspend cash flow or do you still would try to aim within cash flow?
Yes. I mean you are endlessly pulling levers and sometimes free cash flow versus leverage against one another. And so again as you look at price environments, if we have unfavorable pricing you can still potentially achieve free cash flow, but your leverage will suffer because you’re putting –you you’re putting less to grow that EBITDA. I think we look at all the levers, we work through them and we’ll continue to do so.
That’s great. And then finally my follow up question you gave your inventory for the year and as your last press presentation. What is your current liquids inventory look like average lateral length? And what is the approximate split between the rich and the super rich windows?
Yes. We extended laterals when we update our inventory at the start of the year. So when we had been talking about 800 rich and super rich locations at the start of the previous year. Now that number is around 600. It’s roughly 50/50 but between the two areas and the lateral length now is about 9,000 feet in the inventory versus 7,500 on the previous. So there’s a small amount of consumption, but then the rest of that reduction is just tied to higher return, more economic locations that are longer now.
End of Q&A
This concludes our question-and-answer session. I would like to turn the conference back over to Bill Way for any closing remarks.
Well, thank you Gary and thank everybody up front for being here today. As we step back and look at quarter after quarter after quarter of results and built on that we’re very confident about forging ahead on our determined path that we’ve laid out to create growing value for our shareholders, and continue to deliver on every commitments that we make. We are firm believers in the power of our portfolio and especially the capabilities of our people to deliver that quarter after quarter performance.
And we will continue to execute in the same relentless focused way, always looking at returns as the core driver in everything we do against the strip price in whatever price environment that we’re in. Today, Southwestern Energy is moving from strength to strength, earning the confidence of all of our stakeholders and we look forward to sharing some more exciting results with you guys, you all in the coming months.
So thank you very much for joining our call, and your interest in our company. And we hope you have a great weekend.
This concludes the Southwestern Energy’s first quarter 2019 earnings call. You may now disconnect your lines.