西南能源 (SWN) 2017 Q1 法說會逐字稿

Greetings, and welcome to the Southwestern Energy Company First Quarter 2017 Earnings Teleconference Call.

(Operator Instructions) As a reminder, this conference is being recorded.

It is now my pleasure to introduce Michael Hancock, Director of Investor Relations for Southwestern Energy Company.

Thank you, Doug. Good morning, and thank you for joining us today.

With me today are Bill Way, our President and Chief Executive Officer; Craig Owen, our Chief Financial Officer; Randy Curry, our Senior Vice President of Midstream; 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 first quarter 2017 financial and operating results, you can find a company 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 sections 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 this morning. It's great to be here today to discuss our first quarter activity and a number of exciting accomplishments that our highly talented team of people across the country have delivered across our business.

Building on the terrific momentum we achieved last year, we continued to combine rigorous capital discipline, innovation and operational excellence to deliver substantial value for our shareholders. As you saw in last night's press release, we have returned to value-adding production growth this quarter, including an impressive exit rate growth of 12% from December 16 from the Appalachia basin, where over 85% of our annual E&P capital will be invested this year. In fact, the first quarter delivered overall sequential production growth for the company from our large production base for the first time since late 2015. And we expect to continue to build momentum throughout the year, setting up the opportunity for solid growth trajectory into 2018. The improved commodity prices and our continued strong well performance have driven a near doubling of our proved reserves to over 10 Tcf equivalent during the first quarter of 2017, with the PV10 of reserves estimated to be approximately $3 billion.

About 2/3 of our proved reserves are associated with our Appalachia acreage. While this is a considerable increase from our year-end reserves, we believe we are early in our understanding of the full resource potential, especially in Southwest Appalachia where we estimate there is approximately 45 Tcf of net recoverable resource in our acreage. With the operational progress made to date since we took over the Southwest Appalachia asset, the resource potential could rise even more as we find additional efficiencies and the resulting productivity gains are realized. The last time we had over 10 Tcf of proved reserves was in 2014, when natural gas prices were $4.35 per Mcf and oil prices were $91.48 per barrel. This clearly demonstrates the resiliency and potential of our vast and upgraded portfolio.

As a reminder, our financial statements have reflected the declining value in reserves each quarter through drilling test impairments, as commodity prices had weakened. Due to the dramatic change in reserve quantities since our last call, we felt it was important information and provided this onetime off-cycle update to the investment community. We view reserve disclosure as an annual activity that we do at the end of the year, and we'll maintain that annual practice going forward.

In addition to the operational achievements being realized, the company is also seeing the benefits of strengthening macro environment. Despite another record warm winter, the storage season ended at just over 2 Tcf, approximately 427 Bcf below last year's levels. The primary drivers are new structural demand from increased exports of approximately 2.3 Bcf per day and lower year-on-year production of approximately 1.8 Bcf a day. And the effects of the strength in commodity price is being enhanced even further with progress being made on infrastructure projects in the Appalachia basin. Project -- progress being made on Rover and other projects in the region have driven significant improvements in the forward basis curve. For example, Dominion South basis for the May-to-October time frame has improved by approximately $0.70 since the end of last year. As a reminder, approximately 80% of our Northeast Appalachia volumes are priced off Dominion South and TETCO M3, which are both seeing tremendous benefits from the positive pricing environment. When the improvements are coupled with the improvements being realized in Southwest Appalachia, our first quarter discount to NYMEX, including transportation in the Appalachia basin, improved from the first quarter of 2016 by almost 40% to $0.43 per Mcf. These improved differentials are expected to continue throughout the year, and we are narrowing our discount to NYMEX guidance to $0.80 to $0.90 per Mcf. This lowers the top end of the differential guidance by $0.06 per Mcf, increasing expected cash flow for the year.

As you saw in our release, we had a numerous other operational achievements in the quarter, with some of the potential and excitement we have discussed in the last few calls now coming through in well results. Jack will discuss these in detail in a few moments, but I want to mention one other accomplishment that we are particularly proud of.

We recently became freshwater neutral in each of the 3 major areas we operate. This means that we now offset 100% of the volume of freshwater we use in our operations through a reduction in freshwater consumption, combined with conservation efforts, to replenish freshwater to the areas where we work and live. We were able to accomplish this while having these projects face the same rigorous 1.3 PVI hurdle that our drilling and completion activities do. As an industry leader in sustainability, we pride ourselves in efforts such as these and view them as an integral part of our ongoing operations. It's just who we are. Water is a precious commodity, and our actions prove that we are committed to being a contributor to the water cycle and not a disruptor.

So with the strong operational start we've had this year, combined with a strengthened balance sheet and improved commodity price environment, 2017 is shaping up to deliver exactly what we had in mind as we redesigned the company in 2016: sustainable, long-term differentiating value growth for our shareholders.

Let me turn over to Craig to discuss some of the financial highlights.

Thanks, Bill. And good morning, everyone.

As you saw in last night's release, in addition to the strong operational start we had for the year, we also had a very strong first quarter financially. Our returned (sic) [returns] activity in the second half of 2016 focused on corporate-level returns, combined with improving margins, is becoming visible in our financial results. We returned to generating GAAP net income and reported adjusted net income of $0.18 per diluted share. We also generated $318 million of net cash flow in the quarter compared to capital investments of $290 million.

The first quarter of 2017 saw margin expansion across the portfolio. Costs continued to be optimized, as LOE once again came in below our guidance, while G&A expense came in near the bottom of our guidance range. On the revenue side, improvement was seen in natural gas, with realized prices improving 74% to $2.57 per Mcf, including the impacts of hedging. And significant improvement was also seen in NGL pricing. Our realized C3+ NGL prices were $30.91 per barrel for the quarter, up 130% from $13.43 per barrel in the first quarter of 2016. Our total NGL barrel realization after transportation charges was $13.28 per barrel, up 167% compared to $4.98 per barrel in the first quarter of 2016. Our focus on the wet gas window in Southwest Appalachia continues to extract incremental value from liquids, helping drive strong and improving margins and returns. And as a reminder, each $2.50 per barrel increase in realized NGL prices reduces the break-even gas price by $0.50 and generates incremental cash flow of approximately $35 million per year.

Yesterday, we announced we are calling our outstanding 2018 bonds, which further strengthens our liquidity and credit profile. All that remains due between now and 2020 is $40 million in bonds due in the fourth quarter of this year, which we plan to retire at maturity. The combination of these 2017 retirements will decrease debt by about $315 million in total, lowering our total debt to approximately $4.3 billion. We ended the quarter with $3.2 billion in net debt. And we'll continue to look to opportunistically delever as we move forward -- or excuse me, move toward our longer-term goal of net debt-to-EBITDA of less than 2x.

As of March 31, we had a cash balance of $1.4 billion; and revolving credit facility capacity of $800 million, of which $327 million was utilized for outstanding letters of credit.

As we have mentioned previously, our hedging strategy is a key component of ensuring that we achieve targeted returns for our investors while also protecting the balance sheet. We continue to make progress on our hedging positions, adding additional protection to 2018 and 2019 since our last call. In addition to the 429 Bcf of remaining 2017 gas production hedged, we also have 336 Bcf and 99 Bcf of our 2018 and '19 gas production hedged, respectively. Our 2018 and '19 positions are predominantly callers at this time in order to retain upside exposure to potential improvements in commodity prices.

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

Thanks, Craig. And good morning, everyone.

In the first quarter, we invested approximately $283 million in our E&P business and returned to value-adding growth, with total net production of 204 Bcf equivalent. Production from within our Appalachian basin totaled 123 Bcf equivalent. In Northeast Appalachia, we continue to see strong results from the completion and optimized flowback changes being implemented. To date, we have placed 39 wells to sales, with cumulative production outperforming offsets by approximately 130% in the first 150 days. While obviously there is value being created in accelerating production, we also now believe there is an uplift in our EUR on these wells. On average, based on the early data observed in these wells, we believe these changes are improving the average EUR by more than 25% compared to historical well results in Susquehanna County. An example of this is in our core area that previously had an EUR of 11 to 12 Bcf per well, now looks more like a 15 Bcf per well with our new completions. And we're not done yet, as we are continuing to test additional ways to improve our well performance.

Our successes in Northeast Appalachia acreage have continued, with more positive delineation results. In the first quarter, we placed 7 delineation wells to sales in Tioga, Wyoming and Susquehanna County, all exhibiting productivity that delivers returns greater than our 1.3 PVI hurdle. In Tioga, we placed 2 wells to sales with an average lateral length of approximately 6,700 feet and an average 30-day rate of 13 million cubic feet per day per well. These wells are expected to improve as compression is added later in the year. Also, in Susquehanna County, we placed 2 wells to sales in the acreage that we previously acquired in early 2015. These wells are outperforming the offsets by over 100% and had an average 30-day rate of 15 million cubic feet per day per well. Due to the successful results in each of these areas, we have derisked approximately 40,000 net acres and plan to continue delineation efforts throughout this year.

Moving to Southwest Appalachia. We are continuing the -- our early testing that was accelerated from 2018 on our first Utica well, the O.E. Burge. This well is currently flowing at a flat rate of 17 million cubic feet per day, with over 8,500 psi of pressure. Based on our current assumptions, early results indicate this well as a top-quartile well in the region with an average EUR of 2.5 to 3 Bcf per 1,000 feet of lateral. This type of productivity shows the potential of the enormous resource this play in our estimated 1,400 locations. Also, we've recently placed 5 wells online that tested tighter stage spacing and increased proppant loading. 4 of these wells were completed utilizing 140-foot stage spacing and 3,500 pounds of proppant per foot, while 1 additional well was completed utilizing as much as 5,000 pounds per foot of proppant. Early indication shows that all 5 of these wells are performing better than their closest offsets. And to date, these 5 test wells have performed similarly, and we will continue to monitor these wells to determine their long-term performance enhancements.

Moving on to Fayetteville with -- which has direct access to the premium Gulf Coast markets. We brought on a 7-well Moorefield pad to sales in March with an average lateral length of 6,442 feet and average initial production rate of 6.8 million cubic feet of gas per day and an estimated -- have an estimated EUR of 6.5 Bcf per well, exceeding our expectations. These results confirm the productivity of the targeted zone we have in the Moorefield and demonstrate this zone's potential to compete for capital within our portfolio. We plan to place an additional 8 Moorefield wells to sales throughout 2017 to further delineate that play, and this will further understanding -- enhance our understanding in -- of the areal extent of this reservoir.

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

(Operator Instructions) Our first question comes from the line of Subash Chandra from Guggenheim.

Bill, 2 questions for me. The first is, when I look at the -- some of the initial successes, deep Utica, Moorefield delineation, could you characterize sort of what innings you are in that process? So how influential it might be to 2017 development versus in the outer-years? And then the second question is, with some of these highlights on the drilling front but then with a goal towards delevering, how you might view acceleration versus debt reduction over the next several years ahead of your 2020 maturities.

Okay, great. And thanks for your questions. When you take a look at the Moorefield, and we've talked about this before, we have derisked for this current program 15,000, 20,000 acres out of what could have an areal extent as much as 100,000 or more acres. And so our focus going forward from here, as Jack said, is to put -- invest in another 8 wells across the remainder of that acreage to test the same concepts that we have done so far but in a broader areal extent to try to derisk that. When you take a look at the economics of those wells, and again this is the first test -- series of tests into that, I expect that they compete quite well in the portfolio. And our objective would be to further improve them, use some of the techniques that we've used in some of the other areas of the company as we derisk to improve them further. So I think it's early days, but we're -- relative to Utica, we're a little bit further along because we have a pad running and there's 8 wells running and we have a -- we got a bit of production history. In the Utica area, that covers a good portion of our acreage in the West Virginia area and in Southwest Pennsylvania area as the first focus of Utica, we've got our first well flowing. And we're very, very excited about it. And we're excited enough about it to put a second one in the drilling program, which is well underway. I mean the drilling has progressed, and Jack can comment on where we are on that. But we'll get that well done, drilled and then completed as we move through the year, get it flowing and analyze it in the exact same way that we've done this first one, which is take our time, make sure we understand what's really going on, substantive analysis around potential and then go from there. We have a couple of other wells that are in the sort of near-term program around Utica, but we've got 2 things to do: one, get a second one going, get an understanding of it, look at -- and see where we want to test next; and two, always have a mindful eye on the well costs and what we want to do and when we want to do it in terms of taking some of the cost out. You'll recall, with our first well in the Utica or even a second or a third, we're going to put quite a bit of science investment into these so that -- I mean pilot holes and lots of other testing that goes on, to get the maximum amount of data. But we're already looking at what is it taking, how do we -- to shift from there. The Utica, we're fortunate that we have a lot of data points all around us as well. So it gives us even more confidence, but I would say Utica is even a bit of earlier inning because we have basically one well that is flowing. But we are marching forward in a methodical risk-managed way to address that, so stay tuned. Our actions will speak fairly loudly as we work and add well after well into the program.

And Subash, on your question, on acceleration. Certainly, we look to delever over time both absolute and through the metric. We announced, again, yesterday that we'll delever some absolute with our 2018 -- or call it, 2018 bonds, but we'll kind of manage that over time. We have plenty of opportunity. Obviously, be return focused in that every decision made on the incremental cash flow, whether it's through acceleration or whatnot, is -- goes through the filter of what return does it provide within a risk profile. So we'll continue to be opportunistic on delevering and kind of look for opportunities but, again, focused on returns, returns at an acceptable risk profile and again improving on a ramp. Our debt-to-EBITDA, we talked about our long-term goal of being less than 2x on that over time. So creating value and returns focused on any incremental decision on investing with excess cash flow or otherwise.

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

Well, just I was wondering if we could dig or actually try to dig a little bit more into the Moorefield Shale result, which looks pretty encouraging. I was almost thinking about making a joke that perhaps the most important rate is the one you didn't give us, which is the water rate with those wells, because as I understood it, that was really the key technical hurdle. So could you give a little color on that and whether you feel like you've solved that issue and whether it -- you're -- how close you are to moving ahead with large-scale development?

Let me hand that one to Jack. Go ahead, Jack.

Charles, the results of these wells have been very positive on a water basis. We are actually slightly less than 50% of the water what the previous wells were, and that is through 30 days. So we're very encouraged. We're not stopping there. We're continuing to look at different ways of technology on our additional wells; and improve landing, which that's what the main part here was, to actually lower that even more and improve the economics. And that's a big part. We talked, like you said, about the encouraging EURs but that the water is very integral to our economics. So yes, we're very encouraged there as well.

If you -- in its simplest form, if you know there's water and you stay away from it and don't hit it, you're likely to get less back. And that's effectively what we've done.

Got it. That's helpful color, particularly the -- that it's less than 50% of what you're seeing previously. And then if I could ask another question, on your Southwest Appalachia completions and that you haven't seen any difference between the 100- and the 140-foot stage basin. Have you -- it was not clear. Have you seen any difference between the 3,500 and the 5,000 pound per sand loading? And I recognize that there's not a -- not going to be a bright line over which you cross and you can say, well, there is difference and there's not, but what kind of time line should we be thinking about for a verdict from you guys on whether the incremental cost of the 5,000 pounds of sand per foot is worthwhile?

Well, at this point, they are performing very similarly. And that's why we take a wait-and-see approach. In the long term, we may see incremental value out of the 5,000. The other thing is the economics of it. We're taking a look at that, but we're early in the -- usually, after 6 months, we'll have a very good call on whether there is incremental to the 5,000. The 3,500 do look better than the 2,000. So our goal was to actually break the model. We don't know that we have, but we're continuing to monitor it.

We purposely planned this to ramp up technically and get the sand placed as the prime driver, get the results on a few wells and then optimize economically around that. And so it's a good data point. The majority of the next series of wells will be probably in the 3,500-pound range because we know that one's got a good -- a great data point while we wait for some additional data on this one. But we are able to get to 5,000. We haven't declared it a limit yet economically, just need a little more time.

And the -- furthermore, on all these wells in Southwest Appalachia we tend to -- because of the liquids-rich environment, we tend to control their production rate and their drawdown. So that's why it takes a little bit longer to find out if 5,000 is differential from 3,500.

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

Bill, signs of some really interesting kind of well productivity gains kind of throughout the portfolio. I was wondering if you can maybe give us a sense of how much of these well productivity improvements had you factored into your 2017 guide of around 900 Bcfe at the midpoint. And what are some potential upside risks as we think about 2017?

Yes, I think that we have put a lot of these into our program because we've been working on them now for the better part of this year -- or this year and a bunch of last year. And so a lot of that's included in there. I think well mix, well opportunities to -- that we have as a result of the flexibility of our program are continuously analyzed. And where we see opportunities to improve on the plan, were able to shift fairly quickly. And the reason for that is -- of course, you know that we've got our vertical integration capabilities. That puts us kind of in charge of the order in which we do things. So stay tuned. And as we work through more and more of these, we're getting some rather incredible results even surpassing some of our P 10 expectations. And so -- but most of it, we've put in the plan.

My second question is as you think about 2018. You guys have been drawing down on some DUCs just -- during 2016, just in a period when you aren't drilling as much as you are today. How does that -- as we think about 2017, going into 2018, is 2017 a year where you have to maybe build up some DUCs in order to get the operating momentum to think -- as we think about next year?

Yes, our operating momentum is probably not as -- we manage DUC inventory for efficiency, say. That's the prime driver. We don't stack them up at the end of the year so we can get a running start of the next year. We've got a continuous 24-hour business that's segmented into quarters and years, so that -- those have data points attached to them, but we will -- our guidance around 55 to 65 DUCs by the end of the year is we're still good with that. I think the thing that we did this year was trim down on the Fayetteville DUCs because we weren't going to have as much activity because we're focused on the Moorefield. And we -- and so you don't need them for efficiency's sake. So I think that our plans are solid at these numbers. DUCs will fluctuate and probably in the plus or minus 10 or 20, at the most; fluctuate by location, depending on where the activity is. So it's just how we stay efficient. So when you're running your own rigs and your own frac fleets and all that, you want efficient.

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

If we could revisit the balance sheet question that was previously asked at the top of the call. What does an improvement in capital efficiency mean for the cash flow outspend on your model? That is, do you see the company needing to pull less cash off the balance sheet to fill the gap than previously anticipated? And what are your current thoughts on where leverage will sit at year-ends 2017 and 2018, assuming strip pricing?

Dan, I'll start on that. As we guided beginning of the year, we had $200 million in cash coming into the year leftover from our equity raise. So capital efficiency, we continue to work through that. And we've talked about it quite a bit, but we also spoke at year-end about increased service costs; increasing well costs in our plan roughly 5% to 10% "back end of the year" weighted. So it wasn't a significant driver, but it was -- some inflation was part and parcel with our plan. Now kind of what our leverage would look like at the end of this year, from an absolute perspective, I think, with the announcements we made last night, I think you can probably get there with absolute debt levels coming down with the call of these 2018 bonds and retirement of '17. From a metric perspective, just assuming strip prices for the rest of the year today, certainly we'd be in the -- well into the 2s on the leverage ratio, so not quite, probably 2.5 but somewhere in the -- between 2.5 and 3, just kind of depending on what your model looks like. So we'll continue to look for opportunities there. And as we continue to obviously grow throughout the year, that gets better on a trailing 12 months basis.

Got it, appreciate it. And then as a follow-up to that, if I could: Based on the Moorefield successes of that achieving -- yourselves were in the program with enhanced completions and the like. How do you now rank the individual assets by field-level return or breakeven price?

Well, in general, our Northeast Appalachia assets, we have some core and we have some areas we delineated. Our goal has been to prove up additional core, and we think we have. And so they tend to, at current prices and costs, be the highest returns. Southwest Appalachia is right behind them. Fayetteville has been lagging, but the Moorefield has brought these things back up to where we have an inventory there now, that does compete in our portfolio. it -- a lot of it has to do with liquids prices. Southwest Appalachia is going to be -- as liquids prices continue to improve, continue to improve the returns there.

We set out to reinvent ourselves from a $4 gas company to a $2.75 to $3 gas company. We have locations in all 3 areas that work in that range, well in that range. And in fact, we have more opportunities than we have current cash flow capital, and therefore they'll continue to kind of compete with each other for that. That's not a bad thing because then the margin improvements that go along in the business by division, cross-collaboration from the divisions are yielding even greater and greater returns. So we'll keep investing in that way.

Our next question comes from the line of Tim Rezvan from Mizuho.

I wanted to follow up a little bit on what Dan was talking about just to clarify. With the leverage outlook looking a little bit better, I guess, is it safe to say that, your prior EBITDA guidance of around $1.2 billion, you feel pretty comfortable about kind of being at or above the midpoint there?

Tim, I think that was based on -- when we came out in February, that was based on a $3.25 total year NYMEX average. Certainly, NYMEX is currently looking north of that, but we don't know yet, obviously, and get more and more comfort with that as we move throughout the year and months settle. But as NYMEX is above $3.25, yes, I think you can expect cash flow to follow it.

Okay. The operations questions I had were addressed, but on the differential side, very strong start to the year. You did update full year guidance, but it was a -- I guess, not surprisingly conservative amendment given where we are in the year, but can you reconcile the 1Q differentials versus the modest change to the full year outlook?

Yes, Tim. This is Randy. The full year outlook still has a component of timing built into it on the new export capacity that's coming online. So the lower end of that range would indicate some midyear timing on the first phase of Rover. And if that slips, then there could be some impacts there or some delayed impacts, just further improvement in basis. That would be the way I would try to characterize that for you.

Our next question comes from the line of Scott Hanold from RBC.

You all had a lot of well catalysts this quarter, and there's a lot going on and, frankly, a lot of success. In big picture, could you give us a sense then when you step back and look at your goal of having an inventory, obviously, that's very economic between $2.75, $3.25? You also made a statement you have obviously more projects than capital. What is the grand plan of like testing things like a Moorefield and Utica? At the end of the day, how are you going to prioritize your opportunities? And what are you going to do with the assets that may not be able to compete or going to be part of that over the next several years?

Yes, this is Bill. Our focus is clearly on returns as we do capital allocation, as we do projects within a division that are not capital oriented or cost oriented, same kind of thing. It's all prioritized on returns. There is a balance between testing new and emerging concepts with development drilling and completions and all of the marketing activity that goes with that to generate cash flow. And that balance is done on a risk-adjusted basis where we take a look at where we are in the pace of learning. So if you're drilling your first well, you're going to get that going and completed and start on the second one and get that going and completed before you dive off into a rapid development. In the areas where you prove-up some acreage and you get some confidence in there, you make it a little bit faster so that you can prove it up. So the balance of the year, in Moorefield, to get 100,000 acres proved up, 7 more wells at that well cost. That's got to be part of the plan or that we're looking at. Utica, first well; early results; really, really good; second well drilling; much more expensive wells in an earlier development area. And we'll go a little bit slower but we'll go methodically through there. The second thing that we try to do is pull value forward either by leveraging these learnings and spreading them across the company, whether they're operational or technical advances; and doing that as rapidly and prudently as we can. And we manage them as -- the business as a portfolio. So that is happening, and it -- the pace of that is happening faster. On the commercial development side, looking at options around how do we optimize the cost structure. So we've done renegotiations of contracts. We've done raising -- making the pie bigger between us and somebody we have a contract with so that we both can win but we end up with a lower cost out of it or longer term or both. The opportunity to bring value forward with partners or with -- in helping us derisk a play that we might be in or not. Looking for opportunities on an incremental basis to upgrade our portfolio either through optimization of the inventory and optimization of the order of projecting -- or attacking that inventory; or through some kind of commercial means that, again, somebody can bring to the table, that can help derisk a well or a testing program or a portion of acreage is always part of that answer.

Okay...

Go ahead.

So to add a little bit to that. The things we did in our Susquehanna acreage, we've taken inventory that previously wasn't competitive and through our completion improvements have made it competitive. And that's the other thing. We're trying to do everything that I won't -- the inventory that you would say would be lagging, we're working on how we can make the wells better and improve the value we're generating there.

Yes. And that's great. And it looks like a lot of these initiatives are working. And I guess my big picture question is, by the end of '17, early '18, it seems like we're going to have a pretty good understanding of the progress and where a lot of these things stack up and in those things that may not stack up. And it seems like the Fayetteville has always been the poster child of something that's served at the bottom of the rung in terms of what can compete on new drills. What do you do with that inventory? Are you happy just saving it for the next day and looking at further improving it over time? Or could there be a round of, "All right, what doesn't make sense? Should we start selling off the assets to accelerate the value of what we really think is most important?"

Yes. And as I said earlier, I think our approach to that at this point and going forward is, under the umbrella of commercial development, how do we extract more value out of that acreage, whether that is through a -- some kind of a partnering or commercial arrangement; whether that's through some kind of restructuring of agreements with our providers, such as our downstream gathering, our long-haul transporting of those. To drive that value up, we want to do that. We have a number of benches we're testing in the Fayetteville, whether it's Moorefield or some of the other layers of Fayetteville, and a lot of acreage to look at. And so I would caution 1 year -- or one view that in today's world, with liquids being where they are, that suddenly 900,000 acres of a massive play should be tossed out. We don't believe that. We think that -- nor do we believe that you just let it sit idly by. And there is a lot of people that are doing a heck of a lot of things, including the Moorefield and some of the other things we've talked about, to drive improvement in that business. And we're seeing signs that that's happening and so that's encouraging to us. And 6.5 million a day wells with the cost structure that we have there are pretty solid wells, and that excites us. So are there commercial opportunities that allow us to continue to enjoy the cash flow and the strategic nature of that asset and bring competitive activity to it at the same time? We believe so, and that we're working on this. And we'll bring them to you when we get them. And it's important to -- that we do that, and as we work through that, we'll lay them out.

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

Can you talk to the cost inflation outlook that you're seeing here and how the trajectory of your CapEx looks through the year relative to first quarter levels?

Yes. When we look at cost increases that we have built into this year, we're somewhere between 7 and 8 in Northeast assets and a little bit lower than that in the Fayetteville. We are mitigated, we have a bit of a mitigation against the double-digit numbers because of our vertical integration. We drill all our own wells. We are restarting our frac fleet equipment because there's cost pressures on that side. We will always have third-party suppliers with us. We really enjoy the arrangements that we have with our -- and service we get provided by those, but we are relentlessly looking at how to drive that down. And we have our own sand plant in the Fayetteville. The Moorefield wells are all being supplied with sand. So I think that there's benefit to that. So we're a bit mitigated. Capital, relatively smooth second quarter to fourth quarter from here. So we've built-in those numbers high single digits into our system. We have some legacy contracts that are -- they will roll off eventually but continue to help that bit as well. Longer term, I think the commodity price and activity levels and all of that will come to play. And we will relentlessly go after trying to figure out how we mitigate that but have the services that make sense and that get the quality of work that we need done to deliver these results.

And then the $340 million from the first quarter, that would look like you're kind of ahead of the pace for $1.225 billion. Could you just comment on the rest of the -- how the rest of the year looks?

Yes, Brian. This is Michael. The $340 million is really cash flow, right? $290 million was really the capital incurred for the first quarter. Some of that's just timing of invoices that come over from fourth quarter. So the number, the guidance number, is really just a CapEx number. The $290 million will be the equivalent.

And we will be within our cash flow, plus the $200 million that we've -- from the equity raise last year. That will happen.

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

I want to just dig in on the delineation drilling you did in Northeast PA. I think a few of those areas were places where you were less optimistic in the past, from results. And these look good. So I'm partly just curious how much inventory you have in your identified county you've published, from Western Susquehanna and Tioga and Wyoming counties.

Well, so now Tioga, that was first sales. That's the first wells that we'd ever brought to sales in Tioga. And we drilled 1 a few years ago, but we actually established sales, putting in the infrastructure. Total inventory there would be somewhere between 60 and 80 wells currently that we could do. In Susquehanna it's -- and again, that's total inventory that could happen in Tioga. In Susquehanna, their acreage there, we have only drilled 2. We're going to delineate with several more, but there are 30 to 40 wells that could be drilled there pretty easily. We also announced our Wyoming County, which we have a smaller acreage but very good results there, and are continuing to develop that.

And would all those be incremental to what the inventory counts you've laid out before?

No. A lot of those are included in there. What you're really doing, this focus with the results you're seeing; you're seeing things kind of move down the price bucket. You might have had one in one bucket that, as you prove up, derisk this. It probably moves down a bit into a lower price bucket.

Yes. In Tioga County, for example, part of it was uncertainty because we hadn't tested it. So it's not -- when early test results are bad, it's because we hadn't tested it. So now we have. The other drive for Tioga County was we didn't have a gathering arrangement. We got one last year. Then we had to wait. We did a lot of pre investment for timing. Well, now that gathering arrangement is closer to -- or is now a reality. So the time from when you finish a well to getting it online and actually earning your return is an important piece of that efficiency in margin. So as we get those systems online and going, you can even move a bit faster. And then we'll continue to test these, and where we can add further inventory that competes -- or that meets the criteria we needed to meet, we'll do that. And again, early into Wyoming; Sullivan, early; and to -- relatively even into Tioga. And so we've identified some, but well, we're going to keep going. And then you look at the benches that are in there, and none of that bench activity has been done. Therefore, it's not in the inventory, and so there's a potential upside to that in all 3 of our areas.

Okay. And just wanted to follow up on that, on -- just on the improved well performance you've seen really across the whole portfolio. And you guys showed some great sensitivities for drilling inventory at different prices. And I don't think they've been updated that recently, so I'm just curious if they reflect -- it's -- and particularly like a $3 gas price, reflect the recent improvement in well performance in Northeast PA and Southwest PA?

Yes, we updated those in the last deck that came out. And we kind of update those annually. And that one -- the ones in our first quarter was updated.

Yes. And Drew, I think what you'll see and [Mike] referred to this earlier, the challenge is what we're really trying to do is push our inventory lower on the breakeven of the cost curve. And that's kind of what you're seeing. So over time, I'd expect to continue to see that migration, with continued results like we're seeing this quarter.

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

Most of my questions have been asked and answered but maybe just, Bill, on the Fayetteville. I know you've talked about before kind of needing a multiple-rig program in order to sustain or grow production in the Fayetteville. And realizing it's very early days in the Moorefield, but I guess, in these terms, how do you think about kind of overall Fayetteville production there? Could we stem the decline with a 1-rig program potentially?

No. I think probably it's close to -- where it sits today on the decline curve, it's probably closer to 3 rig to keep it flat. And so when you take that concept and you're thinking about so from a commercial development perspective and structuring some of the costs, looking at how to reduce it, those kinds of things, we try to -- you'd put that in your head as a beginning benchmark. Anything beyond that, I think, you end up getting in that "capital competition for returns" bucket. So I think that might be a little further away, but I think -- we think it's about 3.

Okay, okay. And then maybe just on the guidance. I mean a very good start to the year. And I know it's early days, but any thought in kind of the guidance? From an EBITDA perspective, it looks like consensus is above the guidance range. Is it just too early to tweak that?

Yes, Holly, what we try to do at year-end is provide guidance that's kind of been -- strip price and provide sensitivities off of that. So I just kind of refer everyone to kind of that sensitivity and all that. And as we mentioned earlier, obviously a big hedge position, roughly 70% or so hedged on the gas production side. Somewhat mitigated to movement in prices, but they still obviously do move quite a bit with the improved back end of the year. So more to come on that.

Our next question comes from the line of Kashy Harrison with Simmons & Company.

Jack, could you help us quantify the level of outperformance on these Southwest PA wells employing 3,500 pounds per foot of proppant compared to their 2,000 per foot offsets?

Well, at this point, what we're -- the productivity is slightly higher, but the pressures -- the drawdown is less on them at this point in time that -- from what we've got.

Our next question comes from the line of Marshall Carver from Heikkinen Energy Advisors.

Yes, just one question on the Moorefield. You -- it looks like most of those wells were off of one pad. Do you have any feel for spacing in the play? And you talk about 20,000 acres being perspective -- or being derisked out of the 100,000 that are perspective, how many locations would you say are derisked?

We've derisked about 15,000 or so acres out of the 100,000 acres. We did all of that on a single -- or virtually a single pad, trying to get some efficiencies and in the space. I think we've got 1,000 foot spacing on the Moorefield right now. And I think we'll continue to kind of look at that as kind of the test case as we go out and do these next 7 or 8 wells across the full acreage, just try to prove up the remainder. I mean that's our strategic objective, is trying to do that. You could go as low as 600 foot -- feet, but we'll optimize as we prove-up the acreage. I think the focus right now is to prove-up the acreage and then optimize later based on a set of assumptions. So well placement would be important for spacing on a pad, but optimization will come as we get more confidence. The completion techniques that we have in -- that we're testing, doing them in consistent geologies so that you're not changing too many variables at once, which is a kind of a typical challenge. There is rationale for doing a single pad to focus on that. It is an optimization exercise. And you have different choices as -- when you do that, but since we have all these learnings, it makes sense to do that. But stay tuned on that. We'll spread out across the acreage from here.

That's helpful. And with the sort of first wells that have -- I imagine those were in a particularly prospective area. Or do you feel like the future wells are also in an area that geologically looks about as good as this first area?

Well, geologically, they all look prospective. This is an area that was actually close to where -- we weren't trying to -- we were trying to test our completion techniques that Bill just mentioned, with a consistent geology, in a more known area. It was closer to where we have other -- Moorefield. And we're also testing landing and trying to avoid the water that has been a problem on some of the wells. And we think we've successfully done that to the point we're very encouraged at this point.

Our next question comes from the line of Biju Perincheril from Susquehanna.

Most have been asked, but a couple of quick questions, though. Bill, in the area that you have delineated or derisked in the Moorefield, what are the next steps before you can move into development there? Do you need additional infrastructure for water handling or anything like that?

The next step will be to delineate the rest of the acreage, and we're focused on that. The infrastructure we need both from the gathering side and the long-haul transportation side is not an issue. It's -- these are -- it's an area that -- of where we operate. And so we're really just trying to, if you think about strategic execution, go out and figure out how much of the areal extent this is and then go back and try to figure out is there any other optimization that we need to do and then go into development drilling. The costs, well costs, we're drilling them ourselves, completing them ourselves, so we're pretty good at that. The water handling issue, we're accomplishing by staying away from the water. And we've got some optimized -- optimization going on in the Fayetteville, even around water handling, and trying to reduce truck traffic and optimize the distribution with that. So I think that's where we are.

Okay. And then in the Fayetteville I think you were also testing some higher-intensity completions with shorter stage lengths. And any update from that program?

We have -- this is Jack. We have seen incremental results there not as quite as substantial as we have in the Northeast, but yes, we are still seeing an improvement there. And there we have our own sand mines, so sand is relatively inexpensive. We are going to continue to do that, but it hasn't been a substantial -- it has been good in the Moorefield. So those are the things we are going to continue to experiment with.

Our next question comes from the line of David Tameron with Wells Fargo.

If I -- just Equitable or one of your competitors -- well, say, Equitable mentioned on their conference call that they're hearing tightness in rig -- in frac crews out in the basin. Can you guys talk about what you're seeing, if anything, and just how the frac situation is looking right now?

So I think, obviously with the increased activity in oil in certain parts of the country, along with how distressed the group -- the activity got, there is tightness in there. We have mitigated that to a degree with our own frac fleets being restarted. We've mitigated that to a degree with how we contract and our willingness to contract at a long -- for a longer period of time because of the confidence we have in our plan and the confidence we have in our acreage. And I think having a number of folks do that for us is also helpful. We've seen frac fleet supposed to be here on a certain day and it gets tardy because it's somewhere else, but we just plan and manage around that. So there is cost pressure. Everybody knows that. Our cost pressure exists as well. And we just -- we believe that working together with these frac suppliers, having that strategic relationship and looking at how we commercially negotiate deals with them and how we work for the longer term is paying off for us.

And right. And then one final one, just kind of random. A couple of years ago, if I remember right, you guys were maybe looking over testing some Rogerville -- Rogersville shale. One, is that accurate? Two, what ever happened with that? Is that acreage still in your books? Or anything you can say along those lines?

Yes, what I'd say on -- and there's a number of different plays we have about where we over the last few years may have tested in here or tested in there. I've 2 points on that. In our focus on returns and returns now and building long-term shareholder value, we are -- they would not be prioritized in the core capital program, at least right now. I think there is -- certainly, as we build momentum in -- from last year into this year and next, opportunities for those come to pass. And then the second piece of it, which is probably more important here, is that as we go and look at any acreage we have and drill less -- drill a well, just trying to see what we can do in tests, we're -- we won't bring those to the table and talk about them until we get a program that we understand works. We've got 3.5 million acres of exploration plays scattered all over the place, some of which we can touch, some of which we really can't. And so as we kind of work through that and work around our own assets, I mean you look at our sort of focus with a lot of our exploration staff: Get in and really open up our thinking in -- around our assets, other benches, other concepts of how we produce. And as we get -- work through those, we'll bring those to the table because -- but what I don't want to do is we get a one-off well here or one-off well there and begin to sort of watch single wells. The story for this company is much grander and we look at it like that. So it's all about upgrading the returns and making the portfolio as resilient as it can be to different commodity prices.

Thank you. Ladies and gentlemen, we have reached the end of our allotted time for questions. I'd like to turn the call, the floor back over to Mr. Way for closing comments.

Well, I want to thank everybody right off the bat, and I'll do it again later, for being here.

As you've heard today in this call, we've boldly moved ahead building on the momentum that we created last year. And we work every day to demonstrate our commitment to delivering the full potential of our premier assets as we grow shareholder value in the company. The early results on Southwest Appalachia, enhanced completions, looking good to improve margins; promising results on our first Utica well, getting us excited about the vast resource there; the Northeast Appalachian delineation and testing activities that have gone on that are yielding incredible results and strong learnings, which as a learning organization we're passing around as rapidly as we can, to be applied across the company; on early results on Moorefield, potentially adding inventory to the company; and our capital allocation flexibility and our ability to continue to work down our debt, along with other exciting news: We're confident about the progress we're making now and going forward. We've rebuilt the company to excel in a prolonged lower commodity price environment, and this was demonstrated with our strong first quarter operational results. And we expect to make additional strides to create even more value moving forward.

Combining our operational excellence, capital discipline with strengthening macro picture, we're positioned for very exciting times ahead. And I want to thank the staff. I want to thank you all for taking interest in our company but really thank the staff across the country for the efforts that they've put in and the results that they have generated.

And with that, we'll sign off. I hope you all have a great weekend. Talk soon.

Ladies and gentlemen, this does conclude today's teleconference. Thank you for your participation. You may disconnect your lines at this time, and have a wonderful day.