西南能源 (SWN) 2017 Q4 法說會逐字稿

Greetings, and welcome to the Southwestern Energy Company Fourth Quarter 2017 Earnings Teleconference Call. (Operator Instructions) As a reminder, this conference is being recorded. It is now my pleasure to introduce Mr. Michael Hancock. Thank you. Mr. Hancock, you may now begin.

Thank you, Tim. Good morning, and welcome to Southwestern Energy's Fourth Quarter and Full Year 2017 Earnings Call. Joining me today to discuss our results are Bill Way, President and CEO; Jennifer Stewart, Interim CFO; Clay Carrell, COO, along with other members of our management team. Along with yesterday's press release we also issued our 10-K, which has been posted on our website.

Before we get started I'd like to point out that many of the comments during this teleconference 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, Michael. Good morning, everyone, thanks for joining us on our call today. Before we get started on 2017 results, I'd like to talk about the management changes we've had since our last call. Clay Carrell, our new COO; Julian Bott, our recently announced incoming CFO; and Paige Penchas, our new Vice President of Investor Relations are in the room with us today. And I want to tell you how excited we are about the extensive experience that each have gained throughout their careers in the energy industry and the diverse perspectives that they will bring to our leadership team.

I also want to take this opportunity to personally thank Jennifer Stewart and Michael Hancock for their outstanding work in serving in their respective roles for our company. I look forward to continuing to work with them and the rest of the leadership team at SWN on going forward. Jennifer and Michael will be working to transition Julian and Paige over the coming weeks.

Following my remarks this morning, Clay Carrell will give a detailed summary of the operating highlights, and Jennifer Stewart will provide a financial review.

2017 was a solid operational and financial year for Southwestern Energy. We met or exceeded every commitment we laid out in our 2017 guidance. The results of our rigorous financial discipline and returns-focused capital allocations are clear. We generated $1.1 billion in cash flow, grew production to 897 Bcf equivalent and reported record reserves of 14.8 trillion cubic feet equivalent.

Building on the strength, confidence and performance of our high-quality asset portfolio, last month, we announced the decision to reposition the company to compete and win. We are actively pursuing strategic alternatives for the Fayetteville Shale ENP and related Midstream gathering assets and identifying and implementing structural process and organizational changes to improve cost and margin leadership.

Our intention from these activities is to utilize the funds realized to reduce debt, supplement our highly economic Appalachia development capital, potentially return capital to shareholders and for other general corporate purposes. This next step in our strategy supports our drive to capture the highest value from our large-scale, high-quality Tier 1 assets, which we believe will deliver maximum long-term value for our shareholders.

We are successfully navigating through the continuing challenging commodity price environment, and we built strong momentum over the last 2 years by executing our multiphase strategy to improve the company's position in this sector. In 2017, we intensely focused on our assets and expanded margins to enable SWN to deliver growth within cash flow at realized natural gas prices well below $3. This second phase of our strategy is delivering real results and is ongoing.

Given the large scope and scale of our core assets, we are in the enviable position of being able to optimize and drive significant value from the existing portfolio we already own. It includes technical, operational and commercial excellence, as measured by our teams impressive results including improving cycle time, drilling longer laterals, material uplift of wells from significant improvement in frac design and implementation. It also includes renegotiation of transportation and gathering agreements across our assets and dramatic water handling cost savings, among others.

During 2017, we once again allocated capital to our highest return projects in Appalachia, which grew production 16% and increased reserves to over 11 Tcf in that area alone. To put this in perspective, 11.1 Tcf of Appalachia reserves at a $2.98 per MMBtu SEC price, compares to only 5.5 Tcf just 3 years ago, when natural gas prices were much higher at $4.35 per MMBtu. In other words, we have doubled the reserve base in the Appalachia Basin with $1.37 per MMBtu decrease in price further demonstrating the economic resiliency and ability to transform our portfolio to compete in a lower commodity price environment.

The strong depth and breadth in our application portfolio backed up with clear metrics and our significant growth in the Appalachia area has positioned the company to take the next step forward. The time is right to seek strategic alternatives for the Fayetteville asset and focus on additional growth, cash flow and the higher returns generated from the growing contribution natural gas liquids are contributing to our results to further strengthen our investment returns at even lower gas prices.

While Fayetteville has numerous additional economic development opportunities, the high bar set by our Appalachia assets and our rigorous capital allocation discipline of investing in the highest return projects, make it challenging for Fayetteville to compete for capital in our portfolio.

I will note here that the Fayetteville process and our further work on cost reductions are moving forward. We have announced these 2 strategic actions early to provide additional context to our strong 2017 results and our 2018 objectives. However, we are very early in the process, and we will engage in further discussion on these 2 actions at the right time and once we have completed our work.

While these repositioning actions progress, we are laser-focused on creating value from all 3 of our large-scale, high-quality assets and are well on our way to delivering the exciting plans we have for 2018 with the same vigor you've come to expect from Southwestern Energy.

Our 2018 guidance demonstrates the benefits of our margin expansion mandate and the impact of our growing liquids portfolio. Liquid production is expected to grow approximately 30% compared to 2017, assuming the midpoint of guidance, helping deliver an over 5% increase in cash flow, despite a $0.25 per Mcf decrease in the forecasted NYMEX gas prices.

Consistent with our rigorous and demonstrated capital discipline, our capital investment program of $1.2 billion will be fully funded from cash flow. Our Appalachia assets in Pennsylvania and West Virginia are expected to generate almost $850 million in EBITDA for 2018, setting them up nicely to self fund future growth within cash flow.

In 2018, these assets are delivering more with less, and are expected to generate almost 20% production growth from just $770 million of drilling and completion capital. This includes approximately 30% production growth in Southwest Appalachia alone.

Looking forward to the company's Southwest Appalachia assets, providing growth -- growing natural gas liquids-rich production and are capable of doubling production over the next 4 years, with only $500 million per year of capital investment, excluding capitalized interest and expenses. While pipeline infrastructure continues to expand in Appalachia, SWN is well positioned to capture the resulting basis improvements today and well into the future.

As a reminder, Southwestern has drilled in the Marcellus for more than 8 years, and was an early participant in the pipeline expansion in the area, locking in low-cost firm transportation with ample capacity to grow our business and access multiple high-value markets. Our Northeast Appalachia business is solidly positioned to capture materially improving basis differentials, with transportation costs essentially flat throughout the development.

In 2018, we expect to realize a $0.25 per Mcf improvement in Northeast Appalachia differentials and an over $0.10 per Mcf improvement in company-wide differentials. In Southwest Appalachia, we have sufficient outlets to market our growing gas production even if pipeline projects are delayed. We continue to monitor additional pipeline capacity opportunities to access the growing Gulf Coast demand going forward.

As the impressive portfolio of natural gas pipelines are built and expanded, we believe the availability and cost of future capacity will further improve over time and fully support future development. We are confident about the solid foundation we have in place and are excited about the momentum we have built.

I'd like to now turn over to Clay to provide some further specifics on the exciting road ahead for this company.

Thank you, Bill, and good morning, everyone. To begin with, I'm excited to be a part of a company that has a long-standing culture of operational excellence. A core tenet of my operating philosophy throughout my career has been a continuous improvement focus on operational and technical excellence, and that's one of the key things that attracted me to Southwestern. I'm even more impressed now that I've had the chance to see the team in action firsthand and get a deeper understanding of our asset base.

As Bill mentioned, total production was 897 Bcfe in 2017. Production from Appalachia accounted for 65% of our total production or 578 Bcfe, an increase of 16% compared to 2016. Further, our 2017 gross operated exit rate was 2.35 Bcfe per day in Appalachia, a 40% increase compared to December 2016. Appalachia assets generated over $500 million in EBITDA in 2017. Underlying this cash flow growth is a higher natural gas liquids component and an intense focus on applying technology and improving well efficiency; so doing more with less and doing it better.

Our year-end 2017 proved reserves of 14.8 Tcfe reflect our meaningful improvements to economics across our portfolio. We were able to enhance the economics through innovative breakthroughs and drilling and completion techniques, along with renegotiated pipeline gathering and processing agreements. Proved reserves were comprised of 75% natural gas and 25% liquids compared to 93% natural gas and 7% liquids in 2016, driven by a significant increase in liquids-rich Southwest Appalachia proved reserves.

Operationally, throughout 2017, we utilized latest generation technology that tested tighter stage and cluster spacing, increased sand loading, longer lateral lengths and optimized flow techniques across the portfolio. These improvements resulted in increased type curves and improved economics in both of our Appalachia assets.

As an example, in Southwest Appalachia, we increased the stage density and sand loading by 20% and 14%, respectively, in 2017 and increased the average horizontal lateral length by over 2,000 feet, or 41%, compared to 2016. The results from these wells are outperforming historical offsets by approximately 30% on a per lateral foot basis, and you can see the uplift in the type curves shown in last night's press release.

Additionally in Northeast Appalachia, increased drilling precision in the optimal landing zones and enhanced completion designs are yielding higher well productivity and higher well returns, as evidenced by an approximately 75% increase in first year cumulative production and approximately 25% increase in EUR over the life of the well. As mentioned in the past, we have tested new designs in multiple counties in our Northeast Appalachia acreage and are seeing the uplift across our position. We expect to capture this enhanced value on all of our future Northeast Appalachia development.

Our well productivity is translating into improving capital efficiency, demonstrated by the continued improvement in proved developed F&D. In 2017, total company proved developed F&D costs were $0.72 per Mcfe, 4% better than 2016. Capital efficiency is expected to further improve in 2018, as we take the learnings to the next level of application and look for even more ways to capture additional value.

Beyond our technical and operating capability, we are delivering additional value through the Southwest Appalachia water project, which is expected to save approximately $500,000 per well beginning in late 2018.

In 2017, we also expanded our testing of prospective acreage in each asset. In Southwest Appalachia, we expanded the rich gas footprint of our acreage, placing our northernmost pad [to sales] in Brooke County, West Virginia. This 4-well pad has produced approximately 8 Bcfe of cumulative production, comprised of 68% liquids, and has an average F&D cost of approximately $0.50 in Mcfe, with a gas breakeven price of less than $1 based on current oil prices.

Based on these results, we have added an additional 6,000 acres in Brooke County and plan to focus our 2018 activities in the rich gas window of the play, further enhancing our economics.

In Northeast Appalachia, the company commenced development of its acreage in Tioga County, with gross production increasing to 73 million cubic feet per day at year-end 2017. Southwestern holds approximately 28,000 acres in the Tioga area and has commissioned the installation of the first phase of a gas gathering and water distribution system throughout this acreage.

In 2017, we placed 8 wells to sales in this area and had an additional 11 wells in progress. The first portion of development in Tioga has shown encouraging results and Tioga activity is planned to increase as part of the 2018 Northeast Appalachia program as we continue to develop more pads, further delineate the reservoir and continue to capture acreage.

In Fayetteville, we tested 2 concepts in 2017, which included further delineation in the Moorefield and redevelopment opportunities in the Fayetteville Shale. The results of our Moorefield test have derisked approximately 36,000 productive net acres out of the prospective 100,000 acres in the play. Additionally, we identified a significant opportunity for additional future value through the redevelopment of the Fayetteville Shale, utilizing the latest generation drilling and completion techniques, supported by our internal big data analytics.

The redevelopment opportunities include both redrilling infill wells in older, lower-performing areas of the field and drilling normally spaced proved undeveloped locations, again using the latest drilling and completion's technology, and in some cases extending lateral lengths.

The company drilled its first redevelopment well, a redrill of an older vintage well in the second half of 2017, which resulted in a 40% improvement in initial production rates over offset well averages, which validated the results generated by the data analytics model.

Based on this result, the company is currently drilling additional redevelopment opportunities to further validate the improved performance predicted by the data analytics model across the field.

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

Thank you, Clay, and good morning, everyone. One of our key 2017 initiatives was to improve financial strength in order to increase our resilience and flexibility in a volatile commodity price environment. We delivered on that initiative.

In 2017, we took several steps to further strengthen the balance sheet by investing within net cash flow, which was supplemented by the remaining $200 million from our 2016 equity offering. We reduced gross debt by $262 million and extended our debt maturity schedule resulting in no significant bond maturities prior to 2022.

Further, improvements in pricing and operational enhancements combined with our liability management actions implemented over the last 2 years, improved our net debt-to-EBITDA ratio 38% from 4.5x at the end of 2016 to 2.8x at the end of 2017. We remain committed to continuing improvement of our debt metrics with our announced strategic alternatives, where we stated our intention to accelerate the path to below 2x.

Additionally, in the fourth quarter, we received consent from the majority of our 2022 and 2025 bondholders to align the covenants of those bonds with our 2020, 2026 and 2027 bonds as well as to amend certain covenants that created additional financial flexibility.

In the fourth quarter of 2017, we generated approximately $322 million in net cash flow, a 53% improvement compared to the fourth quarter of 2016, due primarily to higher liquids pricing, which more than offset lower NYMEX natural gas prices.

Our focus on NGL-rich gas development resulted in a 44% increase in liquids production, capturing the benefits of improved liquids pricing. In Southwest Appalachia, this resulted in an over 80% increase in margins compared to a year ago. For the total company, liquids revenues provided a $0.19 per Mcfe price uplift, compared to a $0.06 per Mcfe price uplift in 2016.

As part of our commitment to ensure cash flow and economic returns on our capital investments, we continued to add to our hedge portfolio. As of February 27, we had approximately 70% of our 2018 production hedged at an average swap or purchase put strike price of approximately $2.97, with upside exposure up to $3.39 per Mcf on approximately 53% of those protected volumes.

The company also had approximately 215 Bcf of 29 production hedged at an average swap or purchase put strike price of approximately $2.96, with upside exposure up to $3.31 on approximately 57% of those protected volumes. Our 2018 and 2019 positions continue to be predominantly costless collars in order to retain upside exposure to expected improvements in commodity prices.

That concludes our prepared remarks. Operator, we'd now like to open up the call for questions.

(Operator Instructions) Our first question comes from the line of Charles Meade of Johnson Rice.

Bill, I wanted to ask about the Fayetteville sale and the expectations that you'd like to communicate for it. Can you talk about what time line we should be thinking about? And also, could you maybe add some thoughts on what sort of buyer would be -- you're going to be targeting for this?

Let me put in the room for all the callers a comment around this entire process and ask you to bear with us. We are early in this process. We announced the process in order to bring context to our 2017 and 2018 performance. We've spoken about the fact that a major driver for this is repositioning the company to capture liquids in the Northeast and that the funds from any kind of monetization of that asset would go, in the first instance, to pay down debt and then the other things that I mentioned on the call. It's critical for you to understand, and I'll ask for your indulgence, that timing and details and success cases and non-success cases and floor pricing and any other things that may come at an angle on this question, we're just not ready to talk about them. This is -- we've got a process to get underway, which we have started, but I'll ask you to be patient with us; and as we work through and achieve milestones, we'll be more than happy to communicate those. But for right now, I'm going to put that -- ask you to just be patient with us.

Certainly. Understood, Bill. I just wanted to see what more you'd be interested in sharing. And then, if I could actually ask a follow-up question on Fayetteville also. Clay, I was really -- it was interesting to hear a lot of what you guys are doing with that asset, even though you're going to be parting ways with it. And -- well, particularly, you talked about redrilling a previous well, and I wonder if you could elaborate a little bit more on that. Was this -- were you twining an old well that had a bad frac or maybe you had screen outs on several stages? What was the bigger setup for why you'd redrilled an old well?

Yes. The idea was around -- we've been developing, producing that field for many, many years and the quality of drilling and completion techniques has continued to improve across all these shale plays. And so our team continued to look for ways to add value in that asset and identified, through the help of this data analytics model, where we put all 44,000 wells into the model, and looked for the different areas that had the best performance. We identified those that were the older generation fracs that had not performed up to the averages of some of the more recent wells around them. And that helped us identify the candidate to do, as you said, essentially go redrill 100 foot away from an existing well that didn't perform like we now think we can get out of the field based on our analytics model. And it played out right in line with that analytics model, so we were really pleased with that result.

And Charles, to follow up with that a bit. You'll note in our results, the strategy behind all the work that's going on in Fayetteville right now is for the company to capture all of the value and upside that is present in that world-class asset and position it to get maximum value out -- going forward. And so transportation renegotiations, the incredible work the teams are doing around Moorefield and the work -- the very strong and encouraging work that they're doing around redevelopment and opportunities, is all part of the drive to maximize the value of that asset and -- in this entire process.

That's helpful, Bill. So if I understand the comments, this was going to be -- you pick one of your more productive areas of the field and then find the -- maybe the lowest performing well in that productive area, and that's how you sorted the opportunity?

That's how we sorted the first one. We have some additional wells that have been approved. And those will be testing spacing, testing a number of other dimension. The real nugget here is applying the latest technology that we've proven that delivers increased value that we brought from the Appalachia Basin back to the Fayetteville and drive additional results. And the uplift on this first well was very strongly encouraging.

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

My only question regarding the Fayetteville, I'm just wondering if you could help us with kind of the year-end PV10 value and maybe just the split -- I think it was at $2.98 gas, but the split between PDPs and maybe undrilled inventory at that time?

You're talking from a PV10 value, Arun?

Yes. And I don't know if you have that at the strip, but just...

Yes. Most of that is going to be the PDP and we don't have to break it out at today's strip, but its -- it hasn't changed to a great deal since you've run the SEC price. So -- but most of that value is PDP because those are out later in the development cycle, so the discounting get you...

Yes. The PDP component of the Fayetteville is a little over $2 billion.

Great. Okay. And just my follow-up. Bill, you talked about potentially looking at ways to kind of renegotiate some of the transportation agreements where you're successful in the Fayetteville. Could you just give us a little bit more color around that?

Sure. We previously announced -- a couple of quarters ago, the Fayetteville has 2 major transportation routes out for Southwestern. And those agreements, there's 2 parts to it. One, we don't use all that transportation in our operations today; and two, they expire in '19 and '20, I believe. And so what the team did is take a look like they've done across the company at what options do we have, how do we get out from under some of the excesses that we have and how do we extend and lock in a pathway to the growing Gulf Coast market. And so, basically, they did that. They went to the parties -- one of them, in particular, wanted to engage us, so we engaged them. And basically, renegotiated, amended and extended the agreement, allowing for some near-term value, about $70 million, to come back to us and then a long-term transportation rate for 10 years to the Gulf Coast, which can be renewed and extended at a very, very favorable transportation rate.

And is there opportunity to do something similar in Appalachia?

In Northeast Appalachia, we've already got industry-leading portfolio of very low-cost transport. And so we've done some work in our history around this, and it's paid -- has paid us well. In the Southwest Appalachian Basin, we've been -- our strategy has been very clear about committing to as much transportation as we needed to, to get the pipes built where we wanted them built and then begin to grow into those with a very clear expectation that as all of these pipelines come on and all of the transport comes into play, that the opportunity for capacity to add on to our portfolio, at a lower cost, is certainly present. And we will phase that in as we develop our asset, but we believe that there's more than enough capacity to allow us to grow very significantly in that basin. And we are not under a large amount of long term very, very high-cost transport that needs to be renegotiated. We took a different tact, and we think it's going to pay off for us.

Our next question comes from the line of Michael McAllister of MUFG Securities.

My question is on the Fayetteville and the redevelopment program. Can you go into what you're doing in 2018? And is it being done with the budget of $25 million or $15 million or the midpoint?

Yes. So we've got a drilling rig running right now. And like Bill mentioned, we're further testing the different concepts that are part of this redevelopment opportunity in line with the model that we're using, and those dollars are all included in the 2018 budget capital.

So it's as high as $25 million and that's what they're working with in the Fayetteville?

That's total capital. There are some other capital that's non-drilling and completion related in that total number, but that's the total pool of money that we're currently working on.

And as you should think about this at the -- kind of in the broader sense, our capital allocation principles and practices to invest in the highest PVI projects remains. The majority of our capital is allocated to the Northeast. But the terrific potential that we think could be unlocked if these tests actually come through is a game -- could be a game-changer for just the whole view on Fayetteville from a -- the breadth of the 900,000 acres we have. And so it's very early days. We're doing this one test at a time, being very structured about it and very disciplined about it, all the while honoring our capital allocation practices of targeting high value in these investments.

I guess, I'm trying to get to the balance of that because if it's -- if the goal is to find a strategic alternative for Fayetteville, I would almost put a little bit more capital and try to -- as you're trying to sell this in some form, and you could gain more upside by putting more capital there; might not be more PV10 for you because you have higher rates in other areas, but if you can create it, why wouldn't you put a little bit more capital into it and kind of accelerate that to show the wares of this field?

Yes. And we certainly discuss, quite at length, your point. And so just be -- stay tuned, is what I'll tell you. We are working this at pace. We've got the greater value of the enterprise, certainly in front of us and in mind. So just stay tuned. We will update you more as we go forward.

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

I wanted to start and hopefully this call will qualify as a okay Fayetteville-ish type question. Can you just talk a little bit about the framework for how you would use the cash coming in? You talked some in your opening comments, but wonder as you think about debt paydown and balance sheet, if there's specific leverage objectives and then as you think about potentially accelerating to add -- or to accelerate exposure to Southwest PA liquids, if acreage acquisitions would play into that?

This is Jennifer. And yes, we did -- we think -- in our 8-K that we announced the strategic alternatives for the sale of Fayetteville Shale, and in my prepared remarks, we said we're targeting a debt-to-EBITDA of about 2x -- or lower actually than 2x. But really, the decision on what debt we're going to address with any potential sales proceeds, and that includes the decision of bank versus bond debt, near or longer-dated maturities, is really going to be based on the amount of proceeds that we receive and the market conditions at the time we get the proceeds. So as of right now, it's just, again, as Bill said, stay tuned on that.

And in terms of broader uses, we mentioned potential return to shareholders. Today, we're prohibited under our agreements to do that. So we've labeled this a debt reduction priority first. If we're going to go and be able to use funds for return of -- to shareholders, we have to get approval. We'd be in -- we're in a better spot if we get some debt off first, so we'll do that. Certainly, this -- by doing this, it provides us with much greater flexibility, stronger balance sheet and the numbers that Jennifer talked about and the options that are available to us to look at it are certainly there. We fund a certain portion of acreage in and around our assets, the acreage that Clay talked about in Brooke County. We have a land budget within our overall capital budget to deal with things like that, and we'll continue to pursue that. But as we get the uses of funds or the sources of funds identified by a successful implementation of this plan, it will, as Jennifer said, bring more clarity to where exactly that will go.

Great. And then my follow-up is with regard to Southwest Appalachia. You raised your type curves and talked about further improvements in productivity and efficiency. Can you just talk about recovery rates? Are the increases in EURs reflective of greater cumulative recovery? Is it offset by fewer locations? And where are those recovery rates now?

Yes. It's definitely improving recoveries because we are getting greater frac intensity in each of our stages. And so we believe we're improving the recoveries and then that's translating to the greater EURs, and it's part of the ongoing continuous improvement around the drilling and the completion designs.

Can you talk to where recovery rates are?

Yes. I think, right now, some of this work is early. And so what we try and do is get a flow history long enough to be able to both determine EURs and determine recoveries, but it's all pointing in the right direction.

Our next question comes from the line of Drew Venker of Morgan Stanley.

Bill, I was hoping you could talk about pro forma of the Fayetteville sale, what kind of growth you think you could deliver, probably, I guess, thinking beyond 2018? Because the metrics you talked about for this year, you're still going to be in the process, I think, of the sale and then potentially debt paydown. And you're also thinking about an Appalachia growth rate that's, I think, really pretty high. But if you're spending to cash flow in 2019 and beyond, have you run through what those numbers might look like?

Yes. We -- I mean, we model, obviously. We're going to continue to invest within cash flow. That's the objective. And so with pricing and the volatility of that and the -- yet to be determined total amount, we would get for our Fayetteville is kind of premature. The numbers that I said in my opening comments around the ability to grow at these cash flow numbers, that the Appalachian Basin alone generates, will be double-digit and robust.

And that -- Bill, you meant for that number beyond 2018?

Right.

Okay. And is there any significant amount of Midstream EBITDA that would be left after you sold the Fayetteville gathering?

It's about $25 million is probably a good placeholder from like marketing activities and things like that, that's captured in that guidance we put out.

Okay. And have you provided any updated drilling inventory for Appalachia? And I'm sorry if I missed that.

We -- I think that is going to be in the release or the presentation deck that will come out after this call. But we've got future inventory in Southwest Appalachia around 3,700 future drilling locations in total, and then in Northeast Appalachia, it's over 400.

Okay. And Clay, how much of that in Southwest Appalachia is attributable to Marcellus? Or is that all Marcellus?

No, it's not all Marcellus. About -- a little over 2,000 of that is Marcellus.

Okay. It's still quite a big number. Okay. And then just on the corporate costs, you guys have talked about doing a pretty high level and detailed review of the cost structure and any opportunities there. Do you anticipate that G&A could be materially reduced, whether or not you sold the Fayetteville? Or are there other costs that you guys are targeting?

Yes, we're looking at all costs in the company. And whether that's G&A, LOE, any other kind of costs along with all the fees and transportation and everything. So everything is on the table to evaluate. Our stated objective is to be top quartile in this and every other part of our business. And so as we dig into and evaluate all of the dynamics -- or the dimensions of that project, we'll bring those cost savings to the table. We're not -- we have haven't put any kind of number or range, even in our own head, so that we don't limit what we're looking at. We want to do a very rigorously benchmarked analysis, which is well underway, against our peer group and our stated objective is to be in that top quartile.

Our next question comes from the line of Jeffrey Campbell of Tuohy Brothers.

I thought the increased type curve in Susquehanna based on the enhanced completions is really quite noteworthy. I just wanted to ask first, is the ceiling on improved well performance starting to come into view? After all, 75% improvement is a lot. Second, do you expect to see similar percentage uplift in well performance on a percentage basis in other [NEAP] counties? Or is this uplift fairly unique to Susquehanna?

We believe the improved completion technology is going to lead to similar improvements in performance across the acreage position. There's varying (inaudible) areas across our position, but we think we'll be able to generate similar increases. And I think the continued learning around the best way to frac these shale wells is going to continue to grow, and we're going to continue to see increases.

I've been here for 6 years and we have had this question asked of us on -- we have a track record of getting into an area and applying learning -- the capturing of learning and applying it is what really matters. And I've been asked if we're at the ceiling, and we continue to say no and we continue to demonstrate no. So the use of the data analytics models that we have, we've got some of the largest inventories of wells of anyone, and leveraging that and then reconfirming our engineers and scientists and operations folks continue to drive innovation. And I -- it's a really a delightful thing the watch.

I appreciate that color. And let me just ask as a follow-up, apart from the enhanced completions themselves, do you still have upside with regard to longer laterals in the Northeast? Or are you pretty much tapping a limit there?

Yes, we do. It's obviously, connected to the unit size are the ability to renegotiate, to extend units. And so we have opportunities in all of the assets, even in some of the areas in Fayetteville to extend lateral length. And we've set some bigger objectives to do that and put a group of people out from our commercial side of the company to -- and land to help facilitate that, where it might not be obvious in front of you, by renegotiating the land side of that deal.

And some of that, with partnering, would offset operators.

Yes. Yes.

Our next question comes from the line of Sean Sneeden of Guggenheim Securities.

I guess, just number one is on the term, loan. Jennifer, given the 2020 maturity, how are you guys thinking about that? Do you need to wait for, I guess, the Fayetteville sale to take place? Or do you think there's more of a -- you're kind of near term refinancing event in that sense?

As of right now, we don't have anything -- there's no concrete plans. We're waiting to see what -- how the Fayetteville sale progresses and what the proceeds are. And then, like I said for the previous caller, we have a lot of decisions to make on bank versus bond debt; and with respect to bond date, the nearer- or longer-dated maturities. And then we also -- as part of the scripted remarks, we built in a lot of flexibility up to now. And we really want to take advantage of that flexibility and then evaluate what options we have to make our capital structure more efficient. So we're going to put that on pause for a little bit and make our decisions at the right time based on market conditions and also the outlook from our (inaudible) agency.

Okay. I think that makes sense. And so, really, we should be thinking about more of a holistic review of the cap structure whenever you have a Fayetteville sale in hand. Is that really kind of fair in that sense?

That's right. Yes. I think -- yes.

Okay. And then, Bill, I think in your prepared remarks, you mentioned the ability of the Appalachia assets to generate decent amount of cash as you scale up. And just longer term, and I think you talked a little bit about this on some of the previous questions, but just -- is the thought process there to use the free cash flow and return it to shareholders through dividends or share buybacks? And I guess, if so, is that -- where do you think the balance sheet needs to be and where does leverage need to be in order to do that?

Well, again, we're targeting debt-to-EBITDA of less than 2 or at 2. We are able to, as we move forward in time, once the transaction would occur, to be able to fund from cash flow from those assets as they continue to improve and grow in scale. And then the third and probably large point that Jennifer mentioned is, if we -- to be able to be free to return capital to shareholders, we've got covenants that we need to change. And we think the best time to think about changing those is after we've taken some of the risks and some of the debt of, and then go through and get those cleared to give us that optionality.

Okay. I think that makes sense. And then, just one last one, if you don't mind. You guys highlighted the nice performance and uplift in the Appalachian-type curve. I just want to make sure the guidance you guys have out there, is that incorporating that current performance? Or are you guys using more of P60 outcome?

It includes the performance we put out. Once we can validate a performance, similar to what we put out on these curves, we move our objective to that performance.

Our next question comes from the line of Gregg Brody of Bank of America Merrill Lynch.

Just one follow-up on the debt side. You mentioned the covenant restrictions that would prevent you from buying back equity. Is that at the -- what securities are those at? Is that the term loan or is that the bond as well?

Yes. The term loan, currently -- the way we renegotiated our current bank facility prevents us from issuing dividends or buying back shares. We would anticipate that when we -- as I mentioned before, when we're looking to streamline our capital structure and become more efficient with the capital structure, that we would look to renegotiate with our consortium of banks to have some type of outlet depending on certain credit metrics and utilization of whatever facility we use to be able to do a certain amount of dividends or buybacks. But as of right now, our current credit facility prevents that.

And can you just remind me how many banks are in your term loans?

Approximately 24.

Ladies and gentlemen, we have reached the end of our allotted time for questions. I would now like to turn the floor back over to Mr. Way for closing comments.

I just want to thank everyone for being on the call today. We've got a great team, and I think you've seen results that continue to deliver on the commitments to drive long-term value for our shareholders and our company. We've got more to do as we reposition the company to be top quartile performer in the U.S. shale business. We're focused on our high-value liquid-rich investment opportunities within our existing position in the Appalachia Basin. And we look forward to joining you again in the next call to discuss progress being made on the repositioning of our company and all of the exciting things to come around our existing assets.

So thanks for being on the call. Hope you have a great weekend. Take care. Bye.

This concludes today's conference. Thank you for your participation. You may disconnect your lines at this time, and have a wonderful rest of your day.