西南能源 (SWN) 2018 Q1 法說會逐字稿

Good morning, ladies and gentlemen. Thank you for standing by. Welcome to the Southwestern Energy First Quarter 2018 Earnings Call. My name is Brenda, and I'll be your conference coordinator for today. (Operator Instructions) As a reminder, this conference is being recorded.

I'd like to turn the call over to the Ms. Paige Penchas, Southwestern Energy's Vice President of Investor Relations. You may begin.

Thank you, Brenda. Good morning, and welcome to Southwestern Energy's First Quarter 2018 Earnings Call. Joining me today are Bill Way, President and Chief Executive Officer; Clay Carrell, Chief Operating Officer; and Julian Bott, Chief Financial Officer, along with other members of our management team. Yesterday, Southwestern Energy released financial results for the quarter ended March 31, 2018. The release is available on the Investor Relations section of the company's website at 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 in the forward-looking statements 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.

Thanks, Paige. Good morning, everyone, and welcome to our first quarter 2018 earnings call and webcast. I'd like to lead off this discussion by sharing our first quarter results, where we once again delivered on our commitment to create value for shareholders, meeting or exceeding all of the commitments that we've made. During the quarter, we announced that we are repositioning the company to compete and win in a low commodity price environment. The strength and continued growth of our high-quality, high-margin Appalachia assets drives our forward momentum. We're confident that our strategy and the relentless delivery of technical, operational and commercial excellence across our assets will improve returns and increase value for our shareholders.

So today, I want to start off and share more detailed examples of our financial discipline and the work being done that is expanding corporate and asset level margins and driving returns. As you know, we are laser focused on continued cost-reduction opportunities throughout the company as we reshape and reposition Southwestern Energy for the future. Yesterday, we took deliberate steps to lower our interest expense and cost of capital, improve our liquidity and simplify our balance sheet. The company entered into a maximum $3.5 billion revolving credit facility, with a $2 billion initial commitment. And Julian will provide more details about this in just a few minutes.

We're accelerating value from our high-quality Appalachia business and adhering to a disciplined returns-based capital allocation strategy, while at the same time, investing within cash flow. In the first quarter, Appalachia assets generated a 36% increase in EBITDA to $294 million, representing approximately 75% of the company's first quarter consolidated EBITDA. Our teams continue to set new high watermarks for operational execution, growing Appalachia production 29% compared to the first quarter of 2017. And importantly, this production growth included a 37% increase in high-value liquids production. These liquids, which include condensate NGO volumes improved our overall weighted average realized natural gas price by $0.09 per Mcf in the first quarter. The uplift we received from this improved liquids pricing is a key contributor to our increasing capital efficiency.

In other words, we are generating greater value for each dollar invested. As an example and by way of demonstrating the resiliency and value of our Southwest Appalachia portfolio, we've got 400 Marcellus rich gas wells that include condensate and NGLs, which exceed our internal investment hurdle rate of return at $2 gas prices and current liquids pricing. Over the last past year, condensate prices have increased over $12 per barrel and NGL prices have increased over $2 a barrel. This increase in liquids pricing generates an incremental net present value of over $4 million per well, so as we have said before, we believe capital efficiency is about creating value for every dollar we invest, not just increasing production. We continue to leverage our highly competitive technical operating capabilities, resulting in an improvement in reservoir and well performance and project economics.

In a moment, Clay will share several examples delivered from our teams across the company. From a marketing perspective, we've taken steps to mitigate pricing pressure by hedging approximately 70% of our 2018 production at an average price of $2.97 while retaining price upside exposure on half of the hedged volumes. For 2019, we've hedged 279 billion cubic feet at an average price of $2.93. While forward NYMEX prices suggest a weaker market, it's important to note that the outlook for realized pricing at Appalachia has been improving. Due to the 3 billion cubic feet of pipeline capacity that came on in late 2017 and an additional 10 billion cubic feet per day of capacity additions now moving ahead, basis differentials have narrowed as the takeaway constraints have eased.

We continue to realize the benefits of our northeast transportation capacity in operating our business there. We secured low-cost transportation in Northeast Appalachia when we moved into the basin and the differentials have improved more than $0.30 per Mcf in this first quarter compared to last year due to increases in weather demand and more infrastructure being placed into service. Because I know many of you have on your minds the Fayetteville process, I wanted to give you an update on the strategic alternatives for Fayetteville that we announced in February. Since then, we've been working closely with JPMorgan to evaluate strategic alternatives and have commenced a process to maximize the value of the Fayetteville business. In the best interest of our shareholders and the integrity of the process, we'll not discuss additional details, nor speculate on the future outcomes of that process. We do, however, look forward to working and updating with you once the process is complete.

Let me turn it over to Clay.

Thank you, Bill, and good morning to everyone on the phone and on the webcast. I've been with the company now for about 5 months, and I'm very pleased with the technical innovation and operational capabilities of our asset and operating teams. In addition, we have a strong safety and environmental culture that goes hand in hand with the execution of our operational activities, and they were all on display in the first quarter.

The strong first quarter results were achieved while overcoming significant winter weather events in all our operating areas and some onetime compressor facility maintenance. Production was on track for the quarter at 226 Bcfe. We continue to grow our higher-margin liquids production to approximately 54,000 barrels per day, which now makes up 13% of the total equivalent production of the company. Our operating results included several records across the asset base that are driving further improvement in capital efficiency and returns from our portfolio of highly economic investment opportunities.

In Southwest Appalachia, we continue to extend lateral lengths by drilling our longest lateral to date, a 13,400-foot lateral, which we drilled in the plus or minus 15-foot target window, 100% of the time along the entire length of the lateral. That kind of drilling precision is typical of the performance of our integrated drilling organization, and is a key component of maximizing the benefit of the well completions. As part of our ongoing completions efficiency effort, we increased the number of stages pumped per day in Southwest Appalachia from approximately 4 to 6, a 55% increase that results in $400,000 per well cost savings. We accomplished this through the increased utilization of zipper fracs on the majority of our completions.

A key contributor to the greater utilization is our improved sand and water logistics that are required to allow for enough sand and water to be on location as we speed up the completion pace. In Northeast Appalachia, we also achieved record completion performance on a 2-well pad by averaging 6.5 stages per day, also utilizing zipper fracs. Along with our operations' execution focus and improved logistics, our company-owned and operated drilling and completion assets contribute to our improved results demonstrated by lower cost and increased productivity wells. This is accomplished through the use of premium equipment, providing greater flexibility and alignment of personnel to the shared objectives of the company.

We are currently running 6 drilling rigs, 4 in Southwest Appalachia and 2 in Northeast Appalachia. All of the rigs are owned by Southwestern Energy and operated by our own drilling crews. These rigs were custom made with the latest technology and again, are a key component of our drilling program success. In addition, we are utilizing a company-owned frac fleet in Southwest Appalachia, which has led the way in our completions efficiency improvements. Importantly, the use of our vertical integration assets also helps to keep our drilling and completion costs in check. Major spend categories, like drilling rigs and pumping services, are not subject to cost inflation because we own them, and we often unbundle or self-source services to secure the products ourselves at reduced costs. As a result, we expect low-to-single-digit service cost inflation this year, and expect to further benefit from operational efficiencies that will help to offset cost inflation.

In addition to the cost savings, we are also able to better control logistics and ensure timely deliverability of services. I will now walk through some specific highlights for each of our asset areas. The majority of our 2018 drilling activity in Southwest Appalachia will be done in the northern Panhandle area of West Virginia in the liquids-rich area, which includes both condensate and NGLs. Our liquids production in Southwest Appalachia increased 38% compared to the first quarter of 2017.

During the quarter, we placed 3 pads to sales with a total of 12 wells in the rich gas area that produced over 5,000 barrels of condensate per day, resulting in a 27% increase compared to the 2017 exit rate. In our Northeast Appalachia asset, we continued to improve the Tioga area economics by lowering completion costs through water infrastructure installation and increasing lateral lengths. We continued our early phase development in this area and expect to put 5 wells to sales in the second quarter. We recently commissioned a third-party water infrastructure project, which is expected to go into service in the third quarter and save approximately $400,000 per well. In addition, the latest 3-well pad in the area had an average lateral length of over 10,800 feet, which is a 45% improvement compared to historical wells drilled in the area.

Additionally, we continued our strong performance in Susquehanna County, where we drilled an 11,200-foot lateral with an initial production rate of over 34 million cubic feet of gas per day. The area continues to benefit from our increased stage density design and improved flowback methods. In Fayetteville, we progressed our field-wide redevelopment program, where we are utilizing our latest technology drilling and completion methods to improve the production performance from both infill development wells and redrills. During the quarter, we drilled 2 wells, and they were both placed to sales in mid-April. The system is a normally spaced infill development well that was brought online, producing approximately 8 million cubic feet a day from an 8,642-foot lateral.

The Guinn James well is a redrill approximately 100 feet away from an earlier generation existing well, and was brought online producing approximately 6 million cubic feet a day from a 4,944-foot lateral. Both wells have improved early time production performance compared to offset wells, and are producing in line with the predicted performance from our Big Data analytics model. These 2 wells, along with the McNew well that we discussed in the fourth quarter call, are recent examples of the additional high-quality, low-risk economic investment opportunities that we are testing across the field. So overall, our continuously improving execution capabilities and high-quality assets are generating growing value for the shareholder, and we're not done yet.

I'll now turn it over to Julian to discuss some of the recent financial highlights.

Thank you, Clay. With this being my first call, I am truly delighted to be with you today, and I would like to thank my colleagues around this table and throughout the Southwestern Energy organization for extending me such a warm welcome. I will now talk in more detail about key performance drivers and financial results associated with our operations.

In the first quarter, we generated cash flow of $358 million, a 13% improvement versus cash flow of $318 million in the same quarter in 2017, driven by higher production and higher realized prices. Consistent with the company's discipline of investing within cash flow, capital expenditures were $338 million. The company's Fayetteville and Northeast Appalachia assets generated strong cash flow of approximately $200 million, much of which continues to be allocated to Southwest Appalachia as the asset grows and improves value through the capture of a greater liquids-rich volumes.

Northeast Appalachia generated a cash flow of approximately $225 million, and free cash flow of $115 million, almost double our prior year period due to higher production and basis improvement, driven by winter weather and new takeaway capacity. For the quarter, the company's gas revenue increased $540 million, up 7% year-over-year, primarily due to higher production. The company's natural gas production increased 8%, while realized gas prices, excluding hedges, were essentially flat at $2.72, which included a 52% improvement differentials offset by a 10% decline in NYMEX pricing. The company realized a $0.28 per Mcf discount in natural gas differentials in the first quarter compared to $0.59 per Mcf last year, while natural gas NYMEX pricing was $3 in the first quarter of 2018 versus $3.32 per Mcf in the first quarter of 2017.

We are beginning to see expected basis improvements as additional pipeline capacity is placed into service. With the strong start to the year and our view of the improving outlook for basis pricing, we are narrowing our full year differential guidance range or discount to NYMEX to a $0.70 to $0.80 range. Additionally, the improvement in liquids realizations increased natural gas liquids and oil revenue by 59% in the first quarter of 2018 compared to the same period last year. Natural gas liquids revenues increased by 63% in the first quarter due to a 41% increase in production and a 16% increase in price to $15.43 per barrel, including C3+ pricing of $36.01.

The company's oil revenues increased by 52% due to a 28% increase in realized oil price to $56 per barrel, and an 18% increase in condensate production. Now I'd like to address LOE, which was higher than usual this quarter, primarily resulting from weather-related maintenance and a onetime charge related to natural gas liquid processing fees. We expect LOE to return to historical levels going forward. Regarding the cost initiative we announced during the quarter, we have substantially completed our benchmarking analysis, and are progressing with corporate-wide initiatives aimed at reducing costs, while managing effectiveness and efficiency. Yesterday, we also took a significant step as we continue to simplify our capital structure, announcing a new revolving credit facility. It replaces prior bank facility, pays off the $1.2 billion term loan and reduces the negative carrying cost of holding more than $900 million in cash, which clearly is not efficient.

Interest expense is expected to reduce by $30 million per year as a result of the decreased debt level and lower borrowing costs. The new reserve base bank loan facility, or RBL, is a secured revolving credit facility, maturing in April 2023 and supported by a borrowing base. It was oversubscribed with commitments from 29 banks and replaces 3 bank credit facilities that included a revolver and term loans. Pledged assets support an initial borrowing base of $3.2 billion, but we elected a $2 billion initial commitment, which provides ample liquidity without incurring unnecessary commitment fees. We paid off the $1.2 billion term debt with the cash on hand and drawings under the new revolver. Financial covenants are usual and customary with an initial debt-to-EBITDAX maximum of 4.5x and a minimum current ratio of 1:1.

Lastly, a brief update on hedging. Southwestern Energy maintains a dynamic hedging program to protect cash flow and the ability to fund planned capital investments. Recent hedging activity reflected in the hedging schedule in the press release indicates that additional hedges have been added for 2019 and 2020, primarily using 3-way collars. For 2018, approximately 70% of the forecast production is hedged, at an average floor price of $2.97, while retaining price upside exposure on half of the hedge volumes. That concludes my comments.

And I'll turn it back to Brenda to begin the Q&A session.

(Operator Instructions) Our first question comes from the line of Dan McSpirit with BMO Capital.

Behind capital efficiency that you rightly emphasize are cycle times, the offset date highlighted increases in stages pumped per day, you spoke about it in your prepared remarks as you did improve facilities installation times. What more can be done on this front? Or is the company nearing the physical limit, if you will, on these efficiency gains?

This is Clay. I don't believe we're anywhere near being done on this. The logistics are improving dramatically around sand and water in our Appalachian business and then that gives us the opportunity to move more into the completions utilized in the zipper fracs, which allows us to be much more efficient in the completion side of the business. We're continuing to focus on efficiencies around our cycle times in both the facilities and the drilling side of our business. So the opportunity is there for us to continue to expand on some of the results we talked about in the call.

And as a follow up to that. At the time of the announcement on repositioning the portfolio, it was expressed that one of the use of proceeds was to "potentially return capital to shareholders." Has that option been further refined or maybe defined? And where do you see it ranking today, appreciating debt reduction likely ranks highest? I ask that question in the context of share buybacks being all the rage these days.

Yes. We're well aware of that trend. And I think you're right, we have said that our first focus is to reduce debt on our balance sheet. And we've targeted 2x. The new facility that we've just put in place does remove some of the obstacles to continuing to address our capital structure, and certainly would give us some flexibility around share buybacks. That said, today, I think there's a limited amount that we could do, and I think it would probably be imprudent to do anything until we have greater clarity on the strategic initiative.

But to further that, as a public company, we understand the obligation to consider really all of the strategic options, those you talk about and the ones we've talked about to enhance value. And at this point, all those are on the table and we'll continue to work that as we progress the work on Fayetteville.

Our next question comes from the line of Arun Jayaram with JPMorgan.

Bill, I was wondering if you could maybe elaborate on the company's kind of transportation strategy on a go-forward basis. You do have some options when I look at your northeast kind of portfolio. But how do you think you're going to manage that portfolio on a go-forward basis?

Well, I'll start with Northeast Appalachia and go to Southwest. And Jason, you chime in here as appropriate. Our strategy into Pennsylvania when we first moved in there was to lock up firm transportation for our future development in the area. We entered at a time when transportation costs were low and the ability to lock those up, including a significant amount of flexibility in those commitments, was present and we took advantage of it. Today, we have almost 1.4 billion to 1.5 billion a day of firm transportation to multiple different markets, including, as you saw in our first quarter announcements, access to the high-value winter markets in the region. We continue to retain that flexibility to either shift volumes around or, if we don't -- if we're not quite full yet, we actually even go and acquire volume and put it through our transport again given its cost. We have continued to look for additional capacity. You'll note that in an era when there really kind of wasn't any, our marketing folks found a couple of quarters ago, another 140 million a day of capacity. We added that to our portfolio. So our strategy is continue to manage that very low-cost, high-access transportation portfolio and continue to develop and invest in there, in line with our capital allocation strategy of highest economics. In Southwest Appalachia, as you're seeing in the news reports and seeing in -- actually out on the ground, there's as much as 13 to 15 or so billion a day of pipeline capacity that is being brought into that region. Certainly, our focus originally the strategy was to get pipeline capacity from a couple of different pipelines to get our production to the Gulf Coast eventually, and commit to the level that we needed to make sure the pipes got built near where we were going to begin development in the high-value liquids-rich area and add to the portfolio that we had when we acquired the asset. And so it was a more measured approach. It's a much more liquid market. There are a lot more options, including demand side, transportation. So our strategy has been to get in, have a total of about 800 million a day of residue side or dry gas transport. Remember, our wells are very liquid-rich. And that would be our initial movement. As we look at our long-range development plan, we grow nicely into that and then we'll opportunistically add additional capacity as it becomes available. And our view is that as this pipe gets built and then additional expansion capacity gets built, there's going to be opportunities to leg into additional transport and likely at a lower cost than some of these newbuild charges that you hear about out and take the gas to the market we want to take it to, which is -- our preference is the Gulf Coast at this point.

Bill, where do you see kind of transport cost today on some of that new capacity? Any color on that?

This is Jason. So what we're seeing in the market right now when we look at the new transport and what you can buy release capacity for, it's probably somewhere in that $0.20 to $0.40 range coming out of Southwest Appalachia, given the spread between the Gulf Coast and Dominion indexes right now.

Great. And my follow up, Clay, I was wondering if you could elaborate on the redrills and the optimized completions in the Fayetteville? What are the PVIs looking like on some of those projects? And is this changing the way you're thinking about how the Fayetteville could compete in the lower price environment?

Sure, Arun. We're really encouraged with the early performance of these wells. We're doing tighter distance between our perf clusters and a smaller stage spacing in the current generation completion designs that we're using. And we think that, that is definitely having a benefit on the performance. And then the precision of staying in the lateral landing zone throughout the lateral with our current drill wells versus the earlier generation wells in the Fayetteville, we think is also improving the performance of those wells. When I think about the PVIs, when we incorporate the benefit of our vertical integration assets, we're right at the 1.3 and in some cases, a little higher than that, PVIs. And we're going to keep watching the early performance. We're really encouraged. Our PVIs in Appalachia are better than that, which has been our conversation that we really like returns in the Fayetteville, but they don't compete as favorably with our Appalachia assets. So it's early, we're going to keep watching the performance. We're going to keep working on subsurface enhancements and things that we could do differently that could keep improving those, so we're kind of in a watch-and-see mode right now.

And I would say, we're in the early stages of that, but looking at the asset more holistically what I do -- even the commercial work we did last year, as long as we have every asset we have, we're going to continue to optimize it, whether it's through a drill bit, through changes in the way we operate or in terms of even transportation commercial arrangements. And then as we move further into the future, wherever that value can be best realized, we'll do that.

Our next question comes from the line of Bob Morris with Citi.

I know you touched on the concept of return of capital to shareholders. But with -- it looks like better efficiency on the Southwest Marcellus wells and some outperformance versus your type curves, a little bit better cash flow in the quarter, you've always stated that you would spend within cash flow. So apart from thinking about proceeds from the sale of the Fayetteville, as you go forward here and now with the restriction on share repurchases lifted under the new credit facility, with that incremental cash flow that you might realize here from all those factors, how do you think about spending more or drilling a little bit more on that front versus buying back stock? And again, apart from the Fayetteville sale from this point.

Well, I think that -- we again, we run models on investment, on debt reduction, on share buybacks, all of those options. We will invest within cash flow and investment, whether that's invest in paying down debt, whether that's investment in buying back shares. We do have the restrictions moved on -- once we got the RBL, but there's limited availability and limited ability to do that and Julian can speak more into it. I think the real focus is to move with prudency through the Fayetteville process, take a debt reduction, which is the prime objective, and then look at the material options that are presented in front of us at that point in time and make those decisions.

Yes. I mean, look, when we entered into this, and you'll see it because the credit agreement will be filed. So we have normal restricted payment limitations under the agreement as it is effective today. So you've got your 2.75x, which gives us not a lot of room today to do something like a stock buyback. Now you will see that we've built in some additional flexibility, such that if there is a consummation of the Fayetteville shale process, that will then trigger an ability to have greater flexibility. So I think that's the right time to address appropriate uses of capital. We'll know how much we have and we'll know what's right to do with it.

And our next question comes from the line of Charles Meade with Johnson Rice.

I wanted to actually go back, if we could, to that Sisson well in the Fayetteville to make sure I understood. That wasn't 1 of these wells like the McNew where you went back in and twinned de novo. This was kind of a brand new kind of de novo location but with a new completion design, is that right?

That is correct. Our redevelopment includes both applying the new drilling and completion designs to the remaining normally spaced infill locations that we have across the acreage and in different parts of the field, redrilling next to earlier generation wells. This Sisson is a normally spaced infill well. We drilled an 8,000-foot lateral and we thought it would have improved performance, and it has.

And then if I could go back to the Tioga County results. Can you give us -- I think you already talked about how the Fayetteville, those results are good, but they don't compete with the remainder of your Appalachian portfolio. How does the Tioga asset and those recent results, how does that place the Tioga position with respect to the rest of your Appalachian portfolio?

Yes. Just in Tioga, we're really encouraged there. We're in the early phase of development and we brought some wells on in the first quarter. And that performance has been above our hurdle rates. And then we're currently flowing back some brand new wells that are continuing that upward performance trend. And we're incorporating all the same learnings sharing from Southwest Appalachia to Northeast. And we're seeing the benefits of that. And then in addition, as we mentioned, we're putting the -- working with a third-party to get the water infrastructure in place that also is going to enhance the returns in that area with the savings that comes from that.

Which is about $400,000 a well.

Right. Right. So I get the message it's getting better but is there anything that you can offer on where it fits versus your more, I guess, mature Southeast -- or Southwest Marcellus or Susquehanna County?

It is above the 1.3 PVI that I mentioned, it's not as good as the condensate and NGL-rich areas as Southwest Appalachia, but again, it's early days, and the performance continues to improve.

Our next question comes from the line of Holly Stewart with Scotia Howard Weil.

Just maybe starting off 2. And I think you highlighted the free cash flow generation in Northeast PA in your remarks. There is guidance, I believe, at the beginning of the year that calls for $150 million recognizing that it's a nice benefit during the first quarter from the pricing volatility we saw. Can you just maybe update us on your thoughts for the free cash flow in the Northeast area?

We're not changing guidance at this point. But I think you're right, we did have a really strong performance with those base differentials in the first quarter. At this point, Holly, we're not changing guidance.

Okay. Maybe just moving on to the Fayetteville. You talked about a lot about of redevelopment. So can you give us just the updated cost outlook on the first, maybe, the AFEs for the first 2 wells?

Yes. Again, we're not in full development mode yet. And so we would expect to continue to see efficiencies and benefits. But utilizing the benefit of our vertical integration assets, the Sisson is a longer lateral, it's going to be in the $4.5 million range. And then the Guinn is a 5,000-foot lateral, and it's in the $3 million range.

Our next question comes from the line of Brian Singer with Goldman Sachs.

I wanted to start on lateral length. I wanted to see if you could refresh us on your thoughts of where average lateral lengths could go over the next couple of years in Northeast and Southwest Appalachia. You've highlighted some decent lateral -- a significant lateral, long lateral wells in your press release. The averages, I think, are kind of between 6,800 and 7,400. So perhaps you could address what acreage and technical limitations are? And what opportunities or interest you may have for acreage swaps or acquisitions?

Sure. We're definitely making progress on extending the laterals. You mentioned acreage swaps, that's where we can get a benefit and bring acreage up against some hedges of our acreage and that allows us to drill longer laterals. Another development that was beneficial for us is the approval of the cotenancy bill in West Virginia. That also is going to allow us to drill some longer laterals. And as we incorporate it into our forecast, we have an estimate in Southwest Appalachia to be north of 9,000-foot average lateral length in 2019.

And then my follow up is, I think you mentioned earlier, and correct me if this is not right, that you see some opportunities to move gas to the Gulf Coast for about $0.20 to $0.40 per Mcf. Is that what you're seeing now or your expectations over time? And given that this would seem enticing to almost any company, how significant do you see the volume contribution being of those type of opportunities?

Brian, this is Jason. That's a great question. Really, what we're seeing is the spread between Dominion and the Gulf Coast. When you look at the differential between the 2, that's kind of the value of that transportation that's out there. And that's kind of summer '18 on into 2019 as the rest of this massive wave of buildout of capacity goes in service. That'll be just extra capacity that's on the market that producers or market full customers have available to sell into.

Okay. So this would essentially be kind of more short-term spot opportunities during this period to pick up small quantities?

Yes. Probably 12 to 24 months.

And our next question comes from the line of Scott Hanold with RBC.

There's a lot of conversation earlier on vertical integration. It seems like it's almost become a core part of what you guys are looking to do. Could you talk about how many frac crews that you own? And are you evaluating, further enhancing some of your integration efforts? Is this sort of like the long-term direction you'd like to see Southwestern Go?

Well, I think like everything that we do is measured against strict economics and returns, and then prioritized against other opportunities we have to invest. And all of that being done within cash flow. So today, we believe that the success of our vertical integration is embodied in the fact that we only do it for ourselves, so it's not a business that works for others and loses track of the real core purpose here. So it works for us. It must compete with competitors around us. So our drilling teams and integrated in-house teams know that the performance of our rigs and the performance of that is predicated on delivering better performance. And to date, since we've been in this business, that has been the case. We -- high utilization is important, and today, we have 6 of our 7 latest generation drilling rigs working and are mindful that we have to include the economics of the seventh one in those decisions. And so I think that for now, we think that we're right-sized for that business. We can show returns in that business, and it serves us well. In the Fayetteville, for example, not only do we have rigs, we have a frac fleet and we have a sand plant. And in the days of development drilling in Fayetteville, you had a significant margin improvement because of the sand plant alone, and so we think that's an asset to that business. Where you can self-source sand or any of those kind of high-margin components, you've got to take a look at it. But again, with utilization rate cost and economics in mind. So I think that nothing is ever permanent. And so you evaluate it regularly and we do. But for right now and for our core period plan, this vertical integration and all of its parts are highly economic for us. They allow us to be highly flexible and be able to shift from liquids-rich gas to dry gas as market conditions change or any other prioritization of our capital and it's working well for us.

And could you remind me, how many frac fleets are you running right now? And how many of those you own?

We own 2, we are running 1 of ours. The other 1 is in Arkansas. And then we are running 5 frac fleets across the company at this time.

Okay, understood. And could you discuss a little about the Utica and where that ranks on priorities to do some further, I guess, work to see the potential there? Or is that something that could be a monetization effort at some point in time as well?

Yes. This is Clay. We're actively continuing our subsurface and our execution knowledge around the Utica. We've done numerous data trades as part of our plan this year, spending some capital to make sure that we're understanding the subsurface opportunity in the Utica, and then working through the ways to most efficiently drill the wells. We participated in some wells going forward in the year, so it is an active part of our ongoing inventory delineation in our Southwest Appalachia asset. And then there's also Upper Devonian in that asset, and we're doing the same thing around progressing our subsurface knowledge.

Our next question comes from the line of Subash Chandra with Guggenheim.

You'd mentioned earlier, start the call off something about 400, I think, wet gas locations in Southwest PA. And I was curious overall how you feel about inventory in the Southern Marcellus? And if we should look at the 400 in context of the '18 guide for somewhere between 60 and 70 completions in Southern Marcellus?

Definitely, that's where we're focusing. And we should be at or above that guide in 2018. We have 400, like we mentioned in the prepared comments, that are in both the NGL and condensate-rich area. We have another 400 in that area that have a high NGL content.

I was going to ask, so we should think about -- so what is the cut-off? I think you gave us sort of economic cut-off of the initial 400. What about the other 400 in just the NGL window?

Yes. It's going to vary with what the NGL prices are doing. But somewhere around $2.40 to $2.50 gas prices is probably the good number for that.

Northeast PA, so one of your peers is testing that market, it seems to be coming out of a thaw and forward prices are looking better, capacity, et cetera. Can you just review again how it fits in your portfolio? And why it fits as a core asset?

Northeast Pennsylvania for us is a very large high-economic, high-quality asset that has direct access today with no additional cost being needed. Direct access today to multiple markets. Its performance on a well basis and the wells that we're drilling are among the highest economic return wells we have. And we have a portfolio of those wells, plus the work in Tioga and some of the other areas using the latest technologies that we have to continue to generate very strong returns. And as liquids goes back and forth between 1 higher or lower, they trade places, we can shift pretty much on the fly between Southwest Appalachia and Northeast Pennsylvania to -- for our investment. It's a cash-flow-positive asset for us, $115 million this year, for example. And as we've repositioned the company going forward and put a bit of additional drilling in Southwest Appalachia, our objective is to get the entire region to at least be breakeven, if not cash flow positive in the nearer term. So we are -- it's a core asset valuable cash generation, very high economics already in place, don't have to wait, access to transportation and an inventory of wells. On this call, we've talked about redevelopment in Fayetteville. We're looking and actually executing wells in different benches in the Marcellus, in Northeast Pennsylvania, looking for the same opportunity. And so there's quite a bit more to do. We are ever improving the returns that we're getting, and it's a cash flow generator that's strategic to our company.

I would add, Bill, that upper Marcellus opportunity that we're continuing to further vet also.

And our next question comes from the line of Michael McAllister with MUFG.

Under the current budget, the decline rate for Fayetteville for 2018 remains around 17%?

About 15%.

15% to 17%? Okay. Because it seemed a little higher in 1Q on the decline rate basis year-over-year. And then I know you've mentioned that you weren't going to change guidance and it seems like that's fine. But with the NGL production from 1Q, is it fair to lean to the higher end of guidance for the year?

I don't think we guide to guidance. I think we've got a range out there, and I think it's best we stick to it.

And the next question comes from the line of James Spicer with Wells Fargo.

I wondered if you can provide any more detail on the terms of the new credit facility. You talked about a 2.75x ratio. I wasn't quite sure what that was. And then also, what cash -- the cash revolver balances look like post this refinancing? And then finally, what the Fayetteville means in terms of contribution to the borrowing base.

Yes. So a couple of questions there. So 2.75x, I was just referring to the sort of customary restricted payments basket test. So that's a debt-to-EBITDA test, and you have to be meeting that. You also have to have limited amount of outstandings under the revolver in order to be able to make restricted payment. Okay. Another question you had, I think, was on the Fayetteville. Again, we have -- what I will say, we have worked with the banks and we've looked at if we were to extract all of the Fayetteville properties out from the borrowing base, we believe that we would still be able to support this type of a commitment that we took to $2 billion, in this price environment and so forth. There was one other question. I'm sorry, what was the other question?

Yes. I was just wondering, post the refinancing, if you still had any material cash balance and anything drawn under the revolver?

Yes, we do have drawings under the revolver. We had ended the quarter at $950 million of cash, and obviously, with working capital, some of that has been spent. As I said, we took out about $1.2 billion of term debt. So the delta between our cash balance and that payment was made with the revolver. On a go-forward basis, I expect to run cash balances that are fairly small because this is a revolver. So obviously, there's no benefit to sitting with cash on the balance sheet and paying for it.

And our next question comes from the line of Sean Sneeden with Guggenheim.

Of the call it 70 wells or so that you're planning to bring on this year in Southwest Appalachia, can you give us a breakout of what the rich gas versus lean gas window looks like?

I guess it's about 3/4 rich gas window, roughly.

Okay. 75%. Okay. And then I guess just on the return of capital concepts, I just want to clarify. Is the order of priority -- if I understand you correctly, is getting leverage at or below that 2x target that you're talking about? And then you think about share buybacks and what have you? Or how are you guys kind of thinking about it?

Yes. I mean, we have stated that we want to continue to delever the balance sheet. So that is #1 priority. And then I think as Bill had said earlier, all other options are looked at and buybacks is one of those. We will look at all viable options to add value.

Okay, got it. And then just one clarification on the borrowing base. Is it the -- what's the actual component of Fayetteville, the kind of $3.2 billion borrowing base today? Can you give us a sense of what that looks like?

I don't actually have it because the banks don't share with us the exact calculation that goes into the borrowing base. But I think you can see what the PV10 of our proved reserves are and banks typically have a 65% advance rate against that.

And then again, once we move forward and finish Fayetteville, Eric, if you just exclude Fayetteville from the whole equation, we're still roughly expecting that to be at the $2 billion.

Correct. That's right.

And I assume this is the case, but it doesn't include the Midstream component, just the value of the upstream, right?

The borrowing base is calculated off the E&P reserves.

This concludes our question-and-answer session. I'd like to turn the floor back to management for closing comments.

Well, thank you all for being here and for all the questions and dialogue we had today. We appreciate it. I think you can see that our teams continue to deliver impressive results into 2018, and we've got a lot of exciting things going on at our company. The strength of our technical, commercial and operating capabilities are demonstrated again this quarter, with the achievements we've made and included a number of company records as well. We also have delivered on what we said we would do, targeting a simplified capital structure, resulting in our new credit facility. The steps we took help us prepare for the future, whether high or low commodity prices come our way or we're exposed to those. We're very proud of what we're doing here at Southwestern Energy as we capitalize on the growing momentum we've built over the last few years to support our relentless drive to create sustainable value in this commodity price environment, and we look forward to joining with you again in a quarter to discuss more about what we're doing, the highlights and the additional ways we're creating value. So thanks for joining us, again. Have a great weekend, and take care.

Thank you. This concludes today's conference. You may disconnect your lines at this time, and thank you for your participation.