西南能源 (SWN) 2017 Q2 法說會逐字稿

Greetings, and welcome to the Southwestern Energy Company Second Quarter 2017 Earnings Teleconference Call. (Operator Instructions) As a reminder, this conference is being recorded.

It's now my pleasure to introduce Michael Hancock, Vice President of Investor Relations for Southwestern Energy Company.

Thank you, Rob. Good morning, and thank you for joining us today. With me today are Bill Way, our President and Chief Executive Officer; Jennifer Stewart; our Chief Financial Officer, Jason Kurtz, our Vice President of Marketing and Transportation; Jack Bergeron, our Senior Vice President of Operations; and Paul Geiger, Senior Vice President of Corporate Development.

If you've not received a copy of last night's press release regarding our second quarter 2017 financial and operating results, you can find a copy on our website at swn.com.

Also, 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 and 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 to discuss our results and recent activity.

Thanks, Michael. Good morning, everyone, and thanks for joining us on our call today. We really are delighted to have you on the call to discuss the latest achievements here at Southwestern and some of the strong differentiating results that our very highly talented teams across the country have delivered throughout the portfolio.

As you saw last -- in last night's release, we once again delivered the solid results that we guided back in February. We did this as we promised while investing within cash flow and for our fully funded capital plan. We continue to monitor commodity prices and remain committed to adjusting our capital program to align with price changes as we move into the second half of 2017 and beyond.

As we continue to demonstrate, we believe that focusing on the highest return projects and investing within cash flow results in differentiating shareholder value. Production growth is an outcome of our plans, not a driver for them.

As we look forward, we believe that the increasing demand and the lower-than-anticipated supply response that we're currently seeing has been evidenced by the recent trend of strong weekly gas storage reports has yet to be reflected in the forward curve. The billions of dollars being invested in new gas-driven power plants and industrial facilities, coupled with continuing opportunities of increased exports both to Mexico and from LNG, are expected to increase demand by over 10 billion cubic feet per day over the next 4 years.

With the decline of many basins outside of Appalachia, additional drilling will need to be incentivized to meet this growing demand. One source of this needed supply is expected to be associated gas from the Permian. However, in this current oil price environment and with takeaway solutions from the region being required but not being fully subscribed, we think this supply will need to be supplemented by other regions of dry gas.

In addition to the encouraging outlook for natural gas prices, the basis differential outlook also continues to improve due to the momentum on pipeline infrastructure in the Northeast United States. As you know, we now have a quorum at the FERC, and this quorum should facilitate the approval of certificates to initiate construction on approximately 10 Bcf per day of new takeaway capacity in addition to the 5 Bcf per day of capacity that is currently under construction, increasing the total takeaway from the Northeast region by approximately 15 billion cubic feet per day between now and 2020.

Rover alone, which is getting a log of attention right now in the press due to its impending in-service date, will deliver capacity of over 3 billion cubic feet a day once it gets full. While there are many delays talked about in the press around Phase 1 of this project, we want to remind everyone that our 200 million a day of firm capacity is on Phase 2, which is still expected to be online near the end of 2017, as we have modeled.

We do not anticipate any impacts to our development schedule should there be a delay in Phase 2, as we proactively identified alternative operations for additional capacity on a short-term basis if we needed.

Focusing on our Northeast Appalachia asset for a moment. During this quarter, we added approximately 140 million cubic feet per day of new firm takeaway capacity at an average cost of only $0.10 per Mcf, substantially lower than our already impressive low-cost transportation portfolio out of the area. This new capacity, which facilitates further growth, with deliver volumes to be priced off of the Dominion Appalachia index, which is expected to improve even further from historic levels as additional Southwest Appalachia pipelines come online.

Let me switch now to the quality performance of our portfolio. The company had a total net production of 222 Bcf equivalent in the second quarter, a 9% increase compared to the first quarter of 2017 despite third-party gathering issues. The company's operations were impacted in the second quarter by a one-off delay in the installation of a small third-party field gathering line in Susquehanna County that was expected to come on in early 2017 and a third-party compressor station that unexpectedly went offline for repair in late June. We are leveraging our differentiating Midstream gathering expertise, our commercial optimization capabilities and our flexible gathering systems across the state and working closely with our third-party gatherer to diligently implement measures mitigating this operational downtime. As I said before, these are one-off events, are not structural changes and do not change our development plans.

Now let me turn over to Jennifer to discuss some of our financial highlights.

Thanks, Bill, and good morning, everyone. I'm excited to be here today. And for those of you that I haven't had the chance to meet, I look forward to meeting you on the road soon.

Strengthening the balance sheet remains a key focus for the company. And to that end, in the second quarter of 2017, we retired our remaining 2018 senior notes and will retire the $40 million in 2017 senior notes upon their maturity in the fourth quarter. While we have no other near-term maturities, we will continue to look for ways to opportunistically delever or extend our maturities in order to further strengthen our liquidity and credit profiles.

As Bill mentioned, financial discipline drives our decision-making process. And our robust hedging program provides protection of cash flows and ensures targeted returns. We made additional progress on building our hedge book during the second quarter, as we now have over 400 Bcf of 2018 production hedged at an average swap of purchase put strike price of approximately $3 per Mcf, with upside exposure on approximately 72% of those protected volumes up to $3.39 per Mcf. The company also has over 100 Bcf hedged for 2019 at an average purchase put strike price of $2.95, with upside exposure up to $3.32 per Mcf. Our 2018 and 2019 positions continue to be predominantly callers in order to retain upside exposure to expected improvements in commodity prices.

We continue to see the benefits of an improving commodity price environment this quarter. Compared to the second quarter of 2016, realized natural gas prices, excluding hedges, increased 94% to $2.35 per Mcf. Improvement also continues to be seen with NGL pricing. Our realized C3+ NGL prices were $21.62 per barrel, including transportation cost, up 46% from $14.78 per barrel in the second quarter of 2016. Our total NGL barrel realization, inclusive of transportation charges, was $11.25 per barrel, up 76% compared to $6.41 per barrel in the second quarter of 2016.

I will now turn it over to Jack for an operational update.

Thanks, Jennifer, and good morning, everyone. In the second quarter, we invested approximately $318 million in our E&P business and had total net production of 222 billion cubic feet, an increase of approximately 9% compared to the first quarter of the year. This includes an increase in our Appalachian basin of 140 Bcf or 14%.

We're continuing to progress our technical learnings and apply these learnings across our portfolio. We have been achieving our leading operating capability related to extended laterals, lateral placement, completion intensity and optimized flow techniques. These achievements represent a step change in how the company is approaching well design to maximize value, and again, confirms Southwestern as a leader in U.S. shale gas development.

For example, in Northeast Appalachia, the company has increased the average lateral length of its wells by over 10% since 2015 while staying in the targeted interval over 90% of the time, a substantial improvement from the approximately 75% precision back in 2015. 2 of these wells were recently completed with average lateral lengths of over 11,000 feet. The most recent example of this is the Seymour 1H, which is demonstrating productivity among the top 10% of the company's wells ever drilled in Bradford County on a C-Lat-adjusted basis. This well, with a lateral length of over 12,000 feet, delivered an initial production rate of 37.7 million cubic feet of gas per day. The company is also seeing continued success with its increased completion intensity testing across its acreage.

In Southwest Appalachia, the Ritchie pad in Wetzel County continues to outperform its offsets by approximately 25% after the first 160 days of production. 2 of the wells on this pad were completed with 3,500 pounds of proppant per foot with 140-foot stage spacing.

Additionally, in Marshall County, we've placed the Michael Dunn pad online in the second quarter of 2017. After over 3 months of production, this 4-well pad is at a flat pad rate of 38 million cubic feet a day, 44% of which is liquids, at an average flowing casing pressure of 2,400 psi. Early indications suggest the new completion designs are outperforming the old standard completion design by 25%.

Continuous improvements made in our core acreage positions are also delivering benefits in our delineation testing throughout our portfolio that could unlock additional value.

In Southwest Appalachia, our first company-drilled Utica well continues to perform as a top quartile well with cumulative production of over 2 Bcf in its first 6 flowing months. The well is currently flowing at a flat rate of 15 million cubic feet of gas per day with a casing pressure of approximately 6,000 psi. And based on our extensive analysis, it's projected to remain flowing at this rate until sometime in 2018. We have recently finished drilling and completing our second Utica well in Washington County and our progress -- and are in the process of completing the final steps of bringing this well online and expect to have results later this year.

In the Fayetteville, we progressed our learnings of the Moorefield where we brought 2 additional wells online this quarter, 1 of which encountered a fault, which has resulted in increased water production and limited early-stage productivity. The second well confirmed our geologic understanding, and it was brought online with a 5 million cubic feet per day, 30th day rate and an initial EUR of over 5 Bcf. We expect to bring additional delineation wells online throughout the remainder of 2017.

This concludes our prepared remarks. We'll turn it back to Rob who will explain the procedure for asking questions.

(Operator Instructions) Our first question comes from the line of Scott Hanold with RBC.

Bill, you talked a little bit about, and you wrote on it in your release, some of the actions you took to mitigate some of the downtime in the Northeast. Could you give a little bit more color on exactly what you're doing? And as we think of that, is this something that you have available -- you feel comfortable that's going to be available to you going forward? And what's the cost of these options?

Let me start with this -- the slope pipeline jumper that we talked about. If you imagine going out into the extents of the gathering systems and looking at hydraulic opportunities for new -- for linking them together. So we're not anywhere near our major trunk line. These are out in the gathering system. There was a delay in getting a permit. So the pipeline will get put on -- it's only a mile long or 2 miles long. So it's not even a major trunk line. That will get sorted to be done. Our gathering system has a number of tie-in points, if you look at that one alone. But if you look at our company, we've got gathering systems and capabilities all over the state. So you can -- we can optimize and move things around. So that one-off gathering issue is there. And being finished. There's not anything holding that up. The compressor station issue had to do with some vibration issues. The station has been nearly completely rebuilt. They are working on the final pieces of equipment that have to do with pulsation and dampening. They'll get that done. And the machines are set, roofs being put on. I mean, it's getting done. So we also have flexible delivery from our network of marketing opportunities and firm transportation that enables us to move volume around, which enables us to, again, mitigate any issues with -- from the gathering side going to that compressor station. So again, a one-off issue, unfortunate for the company, the compressor company but we've moved it around. The cost to mitigate all of this is really not a cost to mitigate. It's shifting deliveries from one pipeline network to another to deal with the compressor issue and moving around and seeing what further optimization we can have on our gathering system. I think -- and the gathering system, it's kind of actually a sort of wake-up to you that says, hey, are there further ways we can optimize this gathering system and optimize gas flows for the future as we get past all this. So as I said, not structural, not -- it doesn't change our development plan. And the cost to us, we've not put any cost into it actually, except manpower time from our marketing team, kind of field folks. Having said that, we have a great deal of marketing expertise, I mean, gathering expertise. And we have that from the Fayetteville and from our Northeast presence. And we have joined together with our gathering company, the third-party gathering company, and are supporting the efforts to get this done. And part of that is helping accelerate schedules, et cetera. We look at these as cooperative efforts with all of our third-party suppliers.

Okay, appreciate that color. And then my follow-up question is on the Moorefield, the well that's encountered the fault. As you did the postmortem on that, is there any indication that you all had that -- that could be a risk? Or did you learn anything that can be -- when you look at that 150,000-acre bubble, how much of that do you think could be impacted by that?

Yes, I don't think we actually know. There's 2 kind of things. One, there's the fault we encountered 2, it's how close you get to it as you're drilling. So you'll recall back in the early days when we were trying to figure out how to do Moorefield, one of the big question marks was how to -- where's the landing zone and how far do you stay away from that so that you don't encounter the water. And when we encountered this fault, there was a bit more water. We think we got a bit too close. So we'll just go back and validate the model and continue forward. We haven't changed our view on the expanse of this, nor have we proved it all up. That's part of the delineation programs. So I want to give you a balanced answer. We'll keep moving forward. The other well was fine and was positioned appropriately away from any kind of water source. And so there's not a major shift here. We've got several more wells to add to the -- or to finish up before we can declare that. But our intention and or plan is still to move forward. And as you would know, so that I complete the circle, we've put all of this kind of capital investment in the big prioritization bucket, look at how it's prioritized, timing, et cetera, and go forward. So it's just part of our normal ongoing way we work.

And could you remind me the Fayetteville geology, is that pretty subtle? Or do you encounter much fault in the Fayetteville formation?

Scott, this is Jack. We have 3D across the whole Fayetteville. Some faults are smaller than seismic would show up. And the geology, it's -- the faults are easily seen. It's really how close you could get to them. And this time, we got too close to a deep-seated fault.

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

I'd like to start with kind of a big picture question on your strategy. And it goes -- maybe a good place to start is in your prepared comments. And excuse me if I'm paraphrasing a bit here. But you said that growth is an outcome of your -- is an outcome for you, not a goal. Could you talk about what actually the goals or the drivers of your behavior are? And perhaps comment on whether you see them still fitting with the macro outlook that we're living in and if there's been any shifts or adjustments on your part?

Let me start by taking part of the paraphrasing, and bringing back the fact. I said production growth. Drilling -- if you get into a place where you're exceeding cash flow or you get into a place -- and we're not there now, but if you get into place like back in early 2016 where there is no -- there aren't economics to support drilling and completing wells, gases, $1.70, then you don't drill just so that you can realize production growth. We're all about -- our strategy is all about value growth from economic projects, through rigorous financial discipline, stringent capital allocation against economics, unhedged, in priority order, premier asset optionality. We've talked a bit about that this morning, being able to leverage our marketing asset and our gathering assets to try to mitigate unanticipated third-party things. And then always being on an increasing capital efficiency and margin drive. So our objective and our strategy is economic value growth. It's not changed at all. I think the -- you'll see us, as we move through this quarter we're reporting on and the quarters going forward, it's all about investing within that cash flow, having that cash flow be measured against strip and having a proper hedge program using tools that mitigate the downside and tools that allow for upside as gas moves around for a variety of reasons. And that is what we're all about, been about, and that's what we're doing. And leveraging the technical capability of our organization in an integrated way to unlock additional potential out of these large-scale assets. Our strategy is focused on large-scale assets. As we go forward in time, you'll see us continue to focus on those. And as we look for future opportunities in how we might take the current asset portfolio forward, we'll work those and get that out there. But my point mainly to drive is production growth, whether that's liquids or gas or anything, is not a main driver, because you've got to put economics in there. This is about value generation.

Bill, it's good to hear that again from you guys. And then if I could ask a asset-level question, again, back on the Moorefield. Could you give us a recap or maybe a summary of how you're viewing that zone at this point? Where it is perhaps in the relative maturity or where is it on the S-curve of your learning about it? And can you give a -- I know you mentioned you're going to have more activity there in the back half of '17. Can you give us some idea of how many more well results you're going to share and perhaps how it fits into that -- into your view of the zone?

Sure, let me start with the greater Fayetteville complex, so I'm talking about Fayetteville in its broadest sense. Our objective in Fayetteville is to work from a commercial technical, operational perspective to bring Fayetteville's breakeven cost, bring Fayetteville's economic value drivers higher and higher and higher, expand the opportunities for that resource phase. We went through and looked and found the Moorefield under the Fayetteville. There's other benches under the Fayetteville that we looked at. And we came -- the team studied, looked at the optimal geology, optimal reservoir characteristics. And we went on a test program and figured out that on a projected basis, we probably had 115,000 acres of the kind of first tier, looking acreage that we wanted to go test. So we set out on a delineation program. These wells are a bit deeper. They're a bit higher pressure. But what happens with that, assuming you can stay away from the water, is the wells have higher EURs and only slightly higher cost relative to the higher EURs, and position them in the portfolio quite favorably. And so we began with a single pad test that proved up only a small amount of acreage, but it proved the reservoir model. And then we have gone to spreading out across the remaining 100,000 acres that we hadn't tested yet and put a campaign together. We got about 4 wells in the test program for the remainder of the year. As you would expect me to say, those 4 wells, while we want the data and we want to understand what it is, as we continue to adjust our cash flow and monitor what's going on, we will -- whether that's 4 or 3 or 2 or 5, it's going to just be on a cycle like that. We're optimistic that we understand the model because of the track record we've had so far, but we'll see where we go from there. We've built -- we have all of the gathering network, all of the -- everything that you need, because these are in the same field being drilled under deeper in the horizon. So being able to go out, capture them, add additional gathering revenue to the gathering company, add additional inventory to the company, that potential is there and that's what we're trying to prove out.

Our next question comes from the line of Dan McSpirit with BMO Capital Markets.

Bill, the announcement to hire an experienced individual to head up corporate development before maybe announcing the same with respect to the open CFO position may carry some weight unless, of course, Ms. Stewart permanently fills that role. If you could, please discuss the decision to hire Mr. Cecil, what he will be charged with accomplishing and how it ultimately translates into value creation for shareholders?

Sure. Let me start -- back up a bit from Mr. Cecil and just tell you that in our company, across the employee base, across the country, in a number of years, we've got a lot of different technical operating groups or technical groups that are driving a lot of the changes and the things that you hear about. We have emerging technology groups, big data groups. We've got our link to reserves, a number of those technical roles. We took the decision to bring all of that together. If you have a strategy that says, leverage large scale, and you have all these different groups everywhere, well bring them all together and leverage them as a unit. In doing that, we took one of our existing officers, Paul, who's in the room with us today, who has deep technical and operating capability and expertise to run that business, which resulted in a need for a new head of corporate development. Corporate development looks after our strategy, looks after our planning -- strategic planning efforts, our commercial development, our business development, all of those. We have known David for some time. David worked with me, alongside with myself and the board and our CFO, in crafting and working through all of our 2016 early days work to strengthen the balance sheet, the rigorous capital management, all of the development of that. And he's worked alongside us for some time, so we know him well. We know his strategic capabilities, his corporate finance capabilities. And when you combine those and his expertise in this business with a CFO, a COO and the rest of the leadership team, the core purpose of bringing David on was to strengthen the capability and capacity of our expertise in these areas and to deliver step change in shareholder value as we look at our strategy going forward, think about options that we may have to -- with our overall portfolio and work to develop and strengthen the business development, commercial development and portfolio optimization efforts that we have. So we're very excited to have him. There's not some kind of a signal that is equivalent to him showing up, other than we are very excited that we bring yet additional capacity, additional capability to this technical effort that we're working and bring the additional capacity to the executive leadership team, who he's charged with driving forward and continuously improving our strategy.

I appreciate the full response there. And then just as a follow-up to that, just turning to the Fayetteville. The $425 million in free cash flow is expected to be generated by both the E&P and gathering operations this year. What's the breakdown of that, appreciating, of course, that there's some dependence between the 2? And then just a quick follow-up to that, what's the basic decline rate today on that asset?

Michael will jump on this for us.

Dan, it's Michael. The guidance for Midstream this year was $210 million to $225 million. And there's a little piece of marketing in there, but that's primarily the Fayetteville gathering system. So that kind of gives you some color on what to expect from the gathering side. And what was the second part?

And the second part was the decline rate on that asset today, the Fayetteville.

It's probably -- exit-to-exit, you're looking at probably like a high teens, 17% type number.

Our next question is from the line of Karl Chalabala with Stifel.

A question for you guys on the Marcellus FT pickup. That looks to be the standard tariff in the Dominion. So would assume that the firm transport is of view on near-term growth constraints outside of FT capacity before Sunrise comes online rather than price driven. What should we be reading into the need for this versus simple spot sales into the firm sales market without FT cost? And then could you also place it in context with the substantial Marcellus productivity uplift you guys have been seeing in the last few quarters?

Yes. I think if -- Jason, we'll give you some of the detail here in a second. But our objective, and it has been a very solid and very beneficial strategy, is to assure flow out of that region, given all of the challenges of all of these pipelines that need to come on, et cetera, to have firm capacity and at $0.10, it's a great price, into the Dominion market and be able to assure movement of our gas in just about any circumstance. And so as you look at our portfolio and you look at the timing of different projects in that portfolio, just like we've done in Southwestern Appalachia around Rover, no signal to the -- our friends of Rover, we just like to proactively manage any risk that might be out there. And so we took this opportunity to grab this capacity. And it does 2 things. It risk assures and get us locked in, number one. And number two, it allows for further expansion of our business as you see these dramatic improvements in the E&P side feeding our markets. And Jason may have some additional color on that.

You did a really good job, Bill. What I would say is that, that capacity is on Tennessee and Millennium, and it really gives us the ability to make sure that we can move all of our production and grow prior to Atlantic Sunrise coming in, so we can make sure that we don't get constrained in those areas.

Got you. And then a lease geometry question. The 12,000 foot lateral you guys put out there, what kind of -- in terms of looking at Marcellus position, what -- how does that sort of fit into the program? How many of those locations might you possibly have?

Well, this is Jack. From the standpoint of how many 12,000-foot locations we have, again, depending on the unit geometry, we're drilling more and more of those, because the economics are better on longer lateral. Where it's really a function -- our average lateral length, 7,500 foot, we try and extend it where we can and do that. In that area, we have more locations -- a few more locations in the area of that 37 million-a-day well that we're pushing forward at this point in time.

I think to kind of supplement that, here's the dynamic answer here, because as we can go and block up land and add to lateral lengths, because they are economic to do so, we do that, and we do it all over the portfolio. And so you'll see these longer laterals show up in different places. And it's a continuous process of blocking, trading, buying, selling at the unit level to maximize the -- those lateral lengths. And we test these long laterals and like we do most things, we want to test and assure. So we'll test and pilot some of these, make sure that they actually are contributing through the entire lateral, continue to build our expertise in these areas and even go further as units would allow out much further than 1,200 in the future.

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

Continuing on the topic of pricing in Appalachia and capital allocation. In an optimal scenario where your pipeline takeaway solutions come on and local gas prices improve, how aggressively would you be in ramping up volumes, both to fully fill the new pipe and to grow volumes that you're selling in the local market? What combination of local and Henry Hub prices as you run through your capital allocation would you think you'd need to see where we should expect essentially net growth?

Well, I think, obviously, this is all driven by economics from the individual wells and by cash flow in the portfolio. And we did comparative -- we don't allocate capital by division to bulk. We allocate capital by project, and it depends on where it is as we build that mix out. So as we can see, economics in this 10 seconds, the Northeast assets that we have draw the highest amount of capital, because there's the highest effective capital. As we talk about often that the NGL price impacts the allocation between Southwest and Northeast Appalachian areas. And so because we have we have our own rigs and all of that piece of the story, we can flex back and forth. We will move forward and continue with a lot of the optimization efforts, some of which we don't even need to drill to get as we debottleneck or work on different things. But we'll continue to fill that. You can put a timestamp on it and get us a change in liquid prices, and then it moves that back and forth. So we look at it kind of as an overall portfolio versus how fast do I go here, because the answer changes. The answer changes from out [year] your pricing as well. These are 3-year economic kind of things. And so you've got to take a look at and have a view on both the gas prices and liquids and the differentials.

I realize it's not hard and fast for a lot of the reasons you mentioned. But is there some minimum threshold, assuming you have cash flow capability for the company where you could say, hey, it's local, you're not Dominion South or local or Leidy prices are $2, $2.50 or kind of pick a number, you would be wanting to allocate more capital there?

At a given gas price on a sustained basis, it will tell you what direction to go in terms of capital allocation. We don't have any limit, except for our desire to invest within cash flow. But there's not constraints that won't allow us to go faster here or slower there. It's again, a portfolio mix of projects. And the gathering capacities, the differentials, the well economics themselves, all are part of a matrix that we work through, and we work through that fairly continuously.

And then my follow-up is on the Fayetteville. The Fayetteville has been in decline for a number of quarters. And this quarter was flat. I want to see if there was something to that, if you feel like there's reasons for a stability or what the -- at current capital allocation and activity, what you would expect the trajectory to look like?

Brian, it's Michael. No, that's really -- the biggest driver there is a function of timing. You put a lot of wells on at the end of the first quarter, which impacted second quarter. So there's probably a roughly 3-rig program to hold that flat. So you could assume they're still a decline in the back half of the year with the one rig we're running.

And those decline rates moderate over time, just as you enter the flatter part of the curve. So we track that. But we're not sitting still there. We've got a full team that is focused of how do we drive economic value, margin expansion and all of the economic metrics that we need to get the Fayetteville asset to compete with other investment opportunities we have. And there's a relentless pursuit on that, so that will change too as we go forward.

Our next question is from the line of Doug Leggate with Bank of America.

Bill, I wonder if you could speak to the -- what the underlying outlook is for the Fayetteville at this point. Tremendous free cash flow still. But can you talk to what are your objectives for that part of your business for the time being? Are you trying to hold it flat? Are you trying to manage a minimum decline rate? Give us some idea as to how you're thinking about maintaining that piece of the business while you evaluate the Moorefield?

Yes, what we do overall in the corporation is allocate capital projects based on economics. And we do that across the piece. For Fayetteville, we have the objective to unlock additional value, whether it be Moorefield, whether it be improvement in competition drilling techniques and flow-back techniques, water handling, all of that, to raise the bar in LOE cost and op cost, whether it's renegotiation of transport agreements that enable us to extend our agreements in the future and lower near-term numbers. All of those things are designed to drive economic value for Fayetteville up and continue to try to work to position it to attract investment from our investing within cash flow mandate. And so there's a number of technical, commercial, operational objectives that we're chasing. And the team is incentivized to do that, and that's how we measure their performance. And so the Fayetteville is an incredible source of cash flow that drives our business going forward in the Northeast and in testing opportunities like the Moorefield and other benches that are present there. And so it has a significant value to us in terms of driving our agenda going forward of the economic value growth.

So what do you think the underlying decline rate looks like currently?

Yes, this is Michael. It's probably that 17% we talked about for the first year, and it obviously shallows over the next few years, it gets down to the high single digits.

My follow-up, Bill, if I may, is obviously continuous strong performance out of that first Utica well. Can you just speak to the longer-term game plan there? What are the current constraints? And assuming those get resolved, how would you see relative capital allocation across the Northeast part of the business? And I'll leave it there.

Yes, I think I wouldn't put a constraint on our Utica testing, because everything that we need to do is something that we need to do. There's no -- not a problem area. We've drilled one, completed one, drilling and completing one and have been flowing it. The performance of that well has been exceptional. And we expect that that it'll run the way it is for sometime as we've continued to test it. The learning -- the second well, same thing, drilled it, complete it, going to test it and run it and see where we are. The learning around us has been terrific, because there's been a lot of activity. We get to see different pieces of information wells. That learning -- that activity has slowed a bit. And so the learning capability to learn by other wells and others has slowed. So we'll continue to study and analyze this. Today, our ability to drill, complete, place proppant, flow back a well, get it to be a top tier well is terrific. The well costs, at this point in the cycle, are higher, because you load it down with all kinds of technical tools. And -- I mean, if you think about it. This is just past the exploration phase into the delineation phase. So the fact is you've got to put a lot of extra cost in. We need to get our well cost down to $12 million to $14 million. We have in our models a pathway to get there. Neither of these wells were set up to be development wells, so again, the extra cost of ceramic proppant or downhole tools or extensive testing, pilot holes, all that sits with these. So I guess, the next step for us is to learn enough about what we have across the field where we have it. We've got significant resource that we believe is present across significant acreage that we believe is present. And then begin to move into, when we get enough of a understanding of the model, some additional 3D, then begin to think about, okay, what's the cycle look like for timing to begin drilling development well. So there's the risk profile from Utica. There's the learning. There's all that. And then you go and these -- they get to play the same strategic rigorous capital allocation process that everybody -- all the Marcellus wells do. You put them in the matrix and you see, based on gas prices, based off of differentials, based off of volumes and capital costs, et cetera, where do they stack up in the portfolio. Certainly, the first well looks incredibly encouraging. We have a second, and there are some additional wells through -- going forward. But these wells today are $20 million wells in the test phase. And so the we want to use a measured approach, along with capitalizing on the terrific acreage we have all around in the liquid side and the gas side. We have a gathering solution for a portion of our acreage, which we're excited about. We've had it for some time -- so that has to kind of get built. And then you figure out where along the system do you need to put additional gathering and what's the timing of that. And those commitments get made when you get more confident around the development.

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

Maybe just following up quickly on Doug's question with the Utica. Just the maybe thought process around testing Washington County and then how many acres do you have there?

In terms of why we tested Washington County?

Yes.

I think you're going to find that we're going to test across different places in the portfolio. Washington County, there's a gathering line near where that well was drilled, which enables us to do more than a flow test to actually bring it online and are able to do that. So watch us look around as we do the areal extents of our acreage, try to figure out the different subsurface characteristics or different gathering availability, that kind of thing, that drives some of those decisions. And so you don't want to put them all in one place. And that, if you do, then you end up proving up or delineating a smaller footprint. So you'll see us spread out. Then we'll leverage the data that we have surrounding us as well. So there's a bit of an impact on that in that decision maker.

Okay. And then maybe just one final one on the transportation. You've got a big ramp expected in the Northeast in -- or in Appalachia in the second half the year. Just trying to balance out how to think about how your transportation cost will look as these projects kind of get turned into service?

Yes, this is Michael. On the Northeast side, obviously, the stuff we added will bring down the cost a little bit. So you're still in that $0.30 plus or minus range, so still very attractive there. And in Southwest Appalachia, it does increase on the cost side, but it's probably a $0.10 type number today going to about $0.50 longer term. But -- and that's offset by the much improved realizations down at the Gulf Coast since you are getting it down there. So net-net, a good story.

And just to kind of supplement that a little bit from sort a of strategic level. You will notice, obviously, that our -- we discussed it a little earlier on the call, our implementation of our strategy to lock up the full volume growth of potential firm in Northeast is different than what we're doing in Southwest Appalachia. First of all, there's a lot more pipeline capacity that will be built in Southwest. And the area and the market, locally and what -- where these pipelines go -- serviced is much more liquid. The cost of these pipeline projects are dramatically higher than -- and with much longer terms than we had and have historically seen in our asset. So we put in -- we committed to about 800 million a day of firm capacity in a number of projects out of Southwest Appalachia, knowing that we would need much more, but also knowing and believing the sort of industry belief that as we move through time, those costs to transport those differentials, the cost of expansion capacity, all of that brings those costs down. And we'll leg into it again, as we need it, going forward for the long term.

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

Just one quick follow-up question on the Moorefield. The average cost of the 2 wells in the quarter was $4.3 million, above the $3.8 million average for the 7 wells in the first quarter. In Q2, was that average skewed up by the one well that encountered the fault? And then secondarily, how much experimentation or science are you doing here such that once -- and if you do go into development mode, what should we think about the development mode well cost being as things play out here in the Moorefield?

Okay. This is Jack. On these 2 wells, both of them, but the 1 -- specifically the 1 we quoted the cost on, we did a lot more logging on, science. And we did -- we tried some completion intensity that drove the cost up. Realistically, it's probably somewhere between the 2, but skewed more towards the development cost. So $3.8 million was a little development pad. And so that's a lot more indicative of what development cost would be instead of a one-off well with the full mode.

Okay, great. I mean, if you're $3.8 million with 5 to 6, 7 Bcf, those are pretty good economics, so hopefully that continues to play out.

Our next question comes from the line of Jason Gilbert with Goldman Sachs.

Jennifer, in your prepared remarks, you mentioned the company continues to look at ways to opportunistically delever, I think, were the words you used. I was wondering if you could maybe elaborate on that a little bit?

Well, what we would look to, our first priority would be to address our $327 million unsecured term loan as we run into excess cash flow or we come into some sources that we can pay that down. We may also look to address the 2020 notes if we can have an opportunity to rise to look -- to take to address both those, we're going to consider it. But our credit agreement looks to that $327 million unsecured term loan first to pay that down. And then we look to address the 2020 to try to push that maturity stack out.

And as part of our overall way we run our business is we look at these sort of longer dated -- 2020 is several years away, but in banking terms, it's very short. So we do this and every other one of these efforts to improve our position by looking out far enough and proactively managing it. So we retain all the options we can and then execute on it and let you know when we're done.

And maybe -- or noncore asset sales, may be part of the plan here?

Well, we've got -- we hold off in the past on some acreage that was very long dated. We have our 3 large-scale assets. We have very little sort of noncore assets. Most of them are in the exploration zone. Those we continue to look at. But to date, we haven't moved on -- had any movement on those.

Okay. And then one more follow-up, and I don't know if it's a totally fair question. But let's fast forward a year from now, you're all going on with your various assets, you've got debottlenecking occurring in Northeast Appalachia, you've got the new Utica wells, you're working hard to improve the economics in the Fayetteville, you've got the Moorefield. A year from now -- I mean, you just said, I think, that the Northeast Appalachia was at the top rung of the ladder currently. But how would you -- if everything goes as planned, how do you think the economics rank between the various areas on the 2Q '18 call?

Well, I like -- if everything goes exactly like you plan, then all 3 of them are highly economic and they compete at a much higher level. What I will tell you is that where we sit today, with the opportunities and things that we've captured, our 2 Northeast assets, large-scale as they are, compete back and forth. And the liquid side of that business, the realizations from NGLs, which is such a substantial portion of the very rich gas we have in West Virginia, is really the lever that moves that decision back and forth. We've become so efficient that we can capture both opportunities for both areas with 5 rigs or less. I mean, it's a very -- the capital efficiency is so high. So -- because we own them, of course, we can just move them from place to place, and we do that kind of on a flexibility basis. So if you want to kind of look at that in bulk, our Northeast assets today have the highest in a year from now. I'm not going to predict all the great things or outcomes that our Fayetteville team will do, because they will always impress. And so there's all the opportunity for them to jump in there. But as we look right now, with what we know right now, that's where the priority is or the majority of the development type capital, we have.

Our next question is from the line of Sean Sneeden with Guggenheim.

Maybe just to follow up on Jason's question there. But Jennifer, when you think about the capital structure, do you envision a scenario where you're able to extend the term loan and actually return to more of an unsecured capital structure or fully unsecured capital structure? Or is the intent to kind of keep the current complex relatively similar and just extend the maturities?

Our objective is to simplify our capital structure. Given that we're currently -- with all the rating agencies we're in the high-yield world, we certainly would like to get back to investment-grade and have the unsecured capital structure. That's certainly our long-term objective. As of right now, we're looking to simplify the current capital structure, make it a little more easier to -- for you all to understand and for everyone to understand. And we're opportunistically looking to do that as we get a tailwind in the credit capital markets.

Okay, that's helpful. And then just one housekeeping question. But when we think about -- as you guys exit this year, how should we think about overall kind of maintenance capital to kind of keep you flat at that the run rate?

We're estimating about $900 million.

I'm sorry, $900 million?

We're estimating about $900 million to hold flat exit-to-exit in 2018.

Our next question comes from the line of Daniel Norman with Wells Fargo.

It's Dave Tameron from Wells. And actually, to be honest, everything's been answered. So I'd just say welcome to Jennifer and David Cecil on the new hires. So that's all I got.

At this time, I'll turn the floor back to Bill Way for closing remarks.

Well, I hope you've heard kind of in our discussion here, we're very proud of the continuing accomplishments of our teams across the company and how the company is positioned to capture the full potential of our large-scale assets. We've accomplished a great deal in a short amount of time, and we are driving forward for the innovation and focus to extract even more value from these assets.

With our differentiating technical, operating capabilities to improve well productivity and our relentless focus, as I hope you've heard, on improving capital efficiency, driving margin expansion, the existing inventory is building quite a bit of potential. And our delineation efforts and our impressive marketing transportation capabilities are all underpinned by our rigorous financial discipline and stringent capital allocation practices. We think there are multiple exciting catalysts on the horizon, and we're ready to ignite those further.

We look forward to joining with you guys next quarter and talk a bit more about all the achievements that we have. And we want to thank you for joining us today and wish you a good weekend.

Thank you. Ladies and gentlemen, this concludes today's teleconference. Thank you for your participation, and you may now disconnect your lines at this time.