山脈資源 (RRC) 2018 Q1 法說會逐字稿

(Operator Instructions) Statements made during this conference call are not historical facts are -- that are not historical facts are forward-looking statements. Such statements are subject to risks and uncertainties, which could cause actual results to differ materially from those in the forward-looking statements. After the speakers' remarks, there will be a question-and-answer period.

At this time, I would like to turn the call over to Mr. Laith Sando, Vice President, Investor Relations at Range Resources. Please go ahead, sir.

Thank you, operator. Good morning, everyone, and thank you for joining Range's First Quarter Earnings Call. Speakers on today's call are Jeff Ventura, Chief Executive Officer; Dennis Degner, SVP of Operations; and Mark Scucchi, who will be named CFO at our Annual Meeting in 3 weeks.

Hopefully you've had a chance to review the press release and updated investor presentation that we posted on our website. We'll be referencing some of the slides this morning. We also filed our 10-Q with the SEC yesterday. It's available on our website under the Investors tab, or you can access it using the SEC's EDGAR system.

Before we begin, let me also point out that we'll be referencing certain non-GAAP measures on today's call. Our press release provides reconciliations of these to the most comparable GAAP figures. For additional information, we've posted supplemental tables on our website to assist in the calculation of EBITDAX, cash margins and other non-GAAP measures. The supplemental tables also include detailed information on realized pricing and transport expense for all products. To assist with the calculation of hedging gains and losses, you can also find summarized hedge information on the website under the Investors tab.

With that, let me turn the call over to Jeff.

Thanks, Laith. And thanks, everyone, for joining us on this morning's call. Range is off to a good start in 2018, executing on the operational and financial objectives that support our 5-year outlook. I'll provide a few comments on the progress we've made so far in 2018 and then turn it over to Dennis and Mark to elaborate on the details.

But before I do that, I'd like to say that I'm excited to have Dennis and Mark leading Operations and Finance here at Range. They bring new energy, ideas and skill sets to their positions, and the team we have in place is going to work tirelessly to translate our class-leading resource potential into shareholder value. I know I speak for Mark, Dennis and the entire Range team when I tell you that we believe we have an incredibly bright future ahead of us.

Before talking specifics on the quarter, I'd like to touch on the 5-year outlook we introduced a couple of months ago. We have received a lot of positive feedback regarding our firm commitment to capital discipline and delevering. However, I'd like to try and make it crystal clear what the 5-year outlook represents. It represents what our assets are capable of, under what we believe are conservative estimates for efficiency gains and underlying assumptions based on year-end '17 strip pricing. And it's driven by high-quality, de-risked Marcellus position.

The outlook shows the resulting path towards lower leverage without the benefit of asset sales. However, this is not our plan. Our plan is to continue the process of high-grading our portfolio and accelerate the deleveraging process by targeting non-core asset sales and the thoughtful monetization of underappreciated inventory in our portfolio. We currently have processes underway pursuing various transactions that would support our near-term goal of getting leverage below 3x, as we ultimately move towards an investment-grade leverage profile. And our near-term goal of sub-3x is reflected in the short-term management incentives laid out in the proxy we filed earlier this month.

We see, pretty clearly, a significant dislocation between the current equity value and the underlying value of our business, driven, we believe, in part by leverage exceeding investor thresholds and our own targets. For reference, Range's enterprise value is currently at a significant discount to the PV-10 of just our proved reserves. Obviously, our proved reserves, using the SEC definition, excludes several thousand top-tier Marcellus locations and significant upside in the Utica, Upper Devonian and Lower Cotton Valley. I believe this represents one of the largest disconnects in value in E&P today, and we believe that consistent execution on our plan and prudently addressing leverage should begin to square those valuations.

Reflecting on the quarter, we continue to see meaningful improvements in cash flow per share with production and cash margins both higher versus last year leading to record quarterly cash flow. Helping to drive this cash flow was a natural gas price differential of $0.13 better than NYMEX, as Range was able to take advantage of additional pipeline capacity and strong basis pricing in the Midwest and Northeast. The driver behind Range's improving differentials over the past 3 years and our strong first quarter price realizations is our diversified portfolio of both natural gas and NGL. Transportation, combined with an active marketing team, our thoughtful approach towards building out firm take-away capacity over the last many years, has set Range up for future success.

Looking forward, Energy Transfer's Rover project is expected to be in service sometime in the second quarter. Rover represents the last firm transportation commitment that Range has made for natural gas, and we expect to fill this capacity by the fourth quarter of this year. To frame that for you, Range is currently selling approximately 1.4 Bcf per day of natural gas in the southwest part of the Marcellus on a gross basis. This compares to our current firm capacity of just under 1.3 Bcf per day. So we're currently selling the difference, or approximately 130 million per day, in the local Appalachian markets. When our Rover capacity starts, those local volumes will simply move from the [Dominion] M2 market to the Gulf Coast and Midwest, and our plan is to fill the remainder of the Rover capacity as we grow throughout 2018. This puts Range in great shape heading into 2019 and to what we expect will be much better differentials in Southwest PA, and provides Range a great deal of flexibility in where we set spending as we'll have filled our firm natural gas commitments.

In addition to our natural gas production, in the first quarter, we produced 103,000 barrels of NGLs per day and about 12,000 barrels per day of condensate and oil. So in addition to being one of the top 10 natural gas producers in the country, we're one of the top 3 NGL producers amongst E&P companies, which provides significant leverage to improving NGL and oil pricing fundamentals. Importantly, our basis for natural gas, NGLs and condensate are all improving or stable.

Looking at operations for the quarter, I think there are several things worth noting, and Dennis can touch on them in more detail. First, as most of you know, the Mariner East I pipeline shutdown created challenges for us operationally, but collaborative efforts between our marketing, planning and operation teams working together with our midstream and processing partners allowed us to maintain production from the field.

Second, the team continues to become more capital-efficient. Like we've been talking about for some time, the team is going to be drilling up to half of this year's activity on existing pads. This not only reduces well costs, but it also improves our go-forward costs on gathering, as we're using existing infrastructure to produce these wells. Improvements on our gathering, processing and transportation cost in the second half of '18 and going forward should result in better margin in what you'd expect to see in this phase of development in the Marcellus. Another benefit to our more mature development is land position allows for longer laterals. We've recently drilled our 2 longest Marcellus laterals at around 18,000 feet each. We'll see what the results are from these wells later this year, but if these wells produce EURs that are in line with our type curve, the extended laterals would improve our normalized well cost and returns by approximately 17%, so meaningful potential. Pushing average lateral lengths beyond 10,000 feet is consistent with our plans and expectations, but it's worth noting that this efficiency wasn't assumed in our 5-year outlook.

Before turning the call over to Dennis and then Mark, I'd like to reiterate that we see great things happening as 2018 gets underway and we begin a new chapter at Range. We have an energized team working hard every day to translate our high-quality inventory into shareholder value. I truly believe that we'll see Range valued as a top-tier E&P company again, and we're all going to work diligently to make that reality -- a reality for our shareholders.

I'll now turn the call over to Dennis to discuss operations.

Thanks, Jeff. Before I begin first quarter highlights, I'd like to say this is a really exciting time to be leading operations here at Range. We've got a de-risked, world-class asset in the Marcellus, and we have a great team in Appalachia with a long track record of delivering results. We are focused every day on continuing to build upon that history as the Marcellus drives the company forward. In North Louisiana, we also have high expectations that the new team will build on the improvements seen in late 2017 through enhanced completion design and renewed technical approach.

Looking at the quarter, production came in at 2.188 Bcf equivalent per day, exceeding our guidance of 2.18 Bcf equivalent per day. We turned to sales a total of 13 wells in Q1. And as we look ahead, the combined activity for both divisions in the second quarter will result in first sales on approximately 40 wells. Operations are in full swing on these wells, with the majority of them scheduled to be turned in line during the last month of Q2. With this in mind, we are setting second quarter guidance at 2.19 Bcf equivalent per day, which is in full alignment with our 2018 production plans to deliver 11% year-over-year growth. Our capital budget for the year remains at $941 million with 85% being directed towards the Marcellus as discussed on the last call.

Looking at our operational highlights for the quarter, we'll start with the Appalachia division. As Jeff mentioned, our Southwest PA drilling team continues to build upon their success by drilling the company's 2 longest Marcellus laterals in Q1, with the longest well at just over 18,100 feet. We expect these wells to turn to sales in the third quarter and look forward to sharing the results on a future call. Overall, the team has drilled 5% longer laterals at a pace 12% faster per day in Q1 versus the average in 2017. With these efficiency gains, the team has been able to offset small service cost increases and ensure well costs remain in line with the guidance we provided on the last call in February. We couldn't be prouder of the team and the service partners that are producing our longest, quickest and most efficient wells. While we had winter conditions to contend with this year, the completion team was still able to successfully complete 1,003 frac stages, or 19% more than Q1 in 2017. This translates into an 11% increase in wells completed compared to the same time a year ago and sets us up really well for 2018.

During the first quarter, the division turned to sales 9 wells from 3 pad sites covering our super-rich and wet Marcellus acreage. In the super-rich area, we initiated production on 2 wells from a 5-well pad with an average IP of 33.7 million cubic feet equivalent per day, which was comprised of over 60% liquids. The average lateral length on these 2 wells is 13,600 feet and is a great example of the type of lateral lengths and well performance in our 2018 plan. The 3 remaining wells on this pad will be turned to sales during the second quarter. The other 2 pads turned to sales in the quarter were in the wet area. These wells are cleaning up nicely and are producing in line with the normalized type curve. Similar to prior results reported, all 9 wells are flowing under facility-constrained conditions.

Before we leave Appalachia operations, I wanted to look back on some of the continued performance of wells drilled in late 2017. As a reminder, we had 5 pads in 2017 that produced at or above 100 million cubic feet equivalent per day each. These wells continue to be strong performers with an average production in line with our type curves. One of these pads in the dry area contains our first wells drilled to 15,000 feet. And today, they're producing 19% above the type curve, further supporting long lateral development. Also 4 of the 5 pads that produced over 100 million a day were drilled from pads with existing production. Going back to existing pads has become a normal course of business for our operations team. And in 2018, we plan to repeat this model where drilling from existing pads could represent as much as 50% of our program.

Like Jeff mentioned, this not only saves upfront capital costs for roads, pads and facilities, it also saves on go-forward gathering costs as we more efficiently use our existing systems.

Commissioning of the MarkWest Houston 1A processing plant was completed in the first quarter. It is in full operation today. This additional processing capacity, along with the Harmon Creek plant, which is scheduled to be in service later this year in Northern Washington County, will support our development plans for the years ahead.

Now to North Louisiana. Consistent with the plan discussed on our prior call, we started the year with 4 active rigs and are now running 1 rig. The plan will be to stay active with this rig for the remainder of the year with the frac crew active as needed. The division completed and turned in line 4 wells in the first quarter, with 7 more wells scheduled to turn in line this year. Our first quarter Terryville well results are early, but as we look at the normalized type curves, the new wells are producing at or above their forecast due to well placement and improved completion design. As we look at both historical and recent well results, fluid intensity is proving to be a key driver in our Lower Cotton Valley well performance. The technical work by our North Louisiana team is ongoing, but the effort is translating into an improved completion design for the 2018 plan.

Last item on the operations front is around Range's company-wide tubular goods. Over the past several months, discussions have surfaced around increasing transportation cost and tariff change impacts to oilfield tubular goods. To get ahead of this impact, our supply chain and operations teams moved quickly in late 2017 to secure a large percentage of our 2018 tubular needs at a cost below current spot market. Planning efforts such as this, coupled with the operational efficiencies mentioned earlier, are helping to ensure we continue to advance the ball as a low-cost operator.

In summary, we're off to a great start in 2018, drilling record laterals in an attempt to improve returns and hitting production and cash flow targets despite temporary setbacks.

Mark, over to you.

Thank you, Dennis. As we evaluate Range's first quarter performance, we're keenly focused on project level returns and translating those into tangible corporate level returns. Jeff and Dennis highlighted operational successes, which are underpinned by our rigorous capital allocation process, directing dollars to wells with highly competitive rates of return. Efficient operations and diligent efforts in marketing production resulted in cash flow of $323 million for the first quarter, an increase of 25% over first quarter of 2017. The increase in absolute cash flow translated to an equivalent 25% increase in cash flow per fully diluted share. EBITDAX was $374 million, an increase of approximately $70 million over first quarter 2017. Increased cash flow and profitability was driven in part by higher realized commodity prices, despite NYMEX natural gas prices having declined 9% for the first quarter compared to the same quarter prior year. Average realized price per Mcfe, including the effects of hedges and transportation costs, increased 8% compared to the same quarter prior year.

Something that stands out to me in the first quarter is Range's brokered gas book, which saw the benefit of some winter volatility. By optimizing our sizable transportation portfolio and using brokered supply, we were able to take advantage of some temporary market opportunities. This is episodic and would be difficult to replicate, since winter volatility created the opportunity. But it was the driver behind our $4 million net gain in the brokered book for the first quarter of 2018 and shows the benefit of having an in-house team dedicated to marketing.

Looking at unit costs for the quarter. Total unit costs were up about 2% excluding the impact of changes in accounting treatment of certain processing contracts, which I'll touch on more in a moment. LOE increased by $0.03 due to water hauling, equipment leasing and work [overages]. These are transitory and timing-related costs, largely a function of the significant number of wells completed and brought online during the fourth quarter of 2017.

General and administrative expenses increased by $0.02 also due to nonrecurring items. The presentation of gathering, processing and transportation expense is changed beginning with the first quarter of 2018 due to the implementation of new accounting standards and applying the new standards to certain of our existing processing agreements. The associated costs are now shown in gathering, processing and transportation expense line item, whereas historically these costs were reductions to revenue. The end result is an equal increase in revenue and expense with no impact on margins or cash flow. Comparisons of financial results to prior periods will require adjustment for this change in accounting to ensure line items are compared on an apples-to-apples basis, which we have done in our 10-Q and press release.

For the first quarter 2018, GP&T expense was in line with guidance before the accounting change. Please refer to the Slide 17 in our company presentation for a reconciliation of revenue and GP&T expense under prior and current accounting standards.

Looking ahead, I'll direct you to the guidance provided in our press release on expected trends in unit costs. We expect to continue driving better unit costs with transitory impacts behind us and changes in GP&T unit costs influenced by the timing of our final contracted firm transportation capacity coming online.

Turning to the balance sheet. While we still have work to do, the first quarter was productive from a capital structure perspective. During the quarter, our scheduled barring-base redetermination associated with our revolving credit agreement went well with our existing group of lenders. We also used this opportunity to renew the credit facility and extend its maturity date to April of 2023. Due to the quality and scale of Range's asset base, lenders extended the maturity of the credit facility on terms and with borrowing costs essentially equivalent to our previous agreement. As a result of this renewal, we have maintained and extended our ample liquidity and Range's debt maturity profile is well structured with the first maturity not until 2021.

Leverage, as measured by debt-to-EBITDAX, was 3.5x at the end of the quarter, a slight improvement from 3.7x at year-end. As I mentioned before, we still have some work to do and are actively pursuing multiple initiatives to monetize certain assets and use those proceeds to reduce debt. We're working diligently to negotiate these asset sales, and we expect these efforts to yield meaningful progress toward achieving our leverage targets. Our near-term objective is to have leverage below 3x. And our longer-term objective is to maintain leverage closer to 2x.

In summary, our focus is on converting consistent drilling success into tangible shareholder returns. From a financial point of view, a cost-effective, resilient capital structure is the foundation to those efforts. Drilling success achieved with Range's existing inventory when coupled with safe, efficient operations and rigorous capital management, we believe, will yield predictable and growing cash flow. Range's deployment of future cash flow, whether into drilling, debt repayment or returning cash to shareholders, will vary over time, but it will be underpinned by a disciplined, thoughtful allocation process.

Jeff, back to you.

Operator, let's open it up for Q&A.

(Operator Instructions) And the first question comes from Bob Morris with Citi.

My first question is for Dennis. You mentioned that the higher unit operating cost is partly timing related on the water hauling side. But where are you seeing some cost pressures? Because you mentioned equipment leasing also being higher in the quarter. So what is -- for Range, where are you seeing some cost pressures or tightness in the system?

Yes. Great question, Bob. What we're really seeing in some regards is really working off some of the water hauling from really the fourth quarter wells that we turned in line that really were part of our success story toward the end of the year and that production is now carried into the first quarter. But we really haven't seen a lot of cost pressures; it's really more just service-related versus unit cost.

Okay. And then my second question is for Jeff, and Jeff, I know this year you're going to be focused on filling your firm transportation capacity or have your final pipeline project online. You talked before about the 5-year plan at the end, if you wanted to be able to hold production flat than 3.5 Bcf per day. But beyond this year after filling your capacity, as you look at look at where oil prices are and the ramp and associated production in places like the Permian basin, what would it take or at what point might you consider holding production flat sooner? Or if you were to choose to do so beyond this year, given your valuation, just look into somehow return capital to shareholders rather than continuing to grow? Does that ever come into the thought process or is something you would contemplate?

Yes. I think we'll constantly look at what's the optimum way for Range to operate and do the best job we can for our shareholders over that 5-year period. And we'll look at all the different sensitivities and things that are out there, what happens to gas prices, oil prices and NGL prices. And go back to some of our commitments are -- to spend within cash flow, we'll have a lot more flexibility post '19 when we fulfill those commitments. So we'll look at all those things. The good news is we have high-quality assets and we have the ability and flexibility to do multiple things. So we'll be looking at all those different sensitivities.

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

Can you give a bit more color on the asset sale process? And how you weigh the need to delever versus [de-free] cash flow given up from assets being sold? Or are there -- is there a middle ground of delevering the assets that don't actually generate much free cash flow?

Brian, this is Mark. I'll start off and then Jeff and others will chime in. So to your point, the sale price is, of course, a consideration as we look at monetizing assets and what the resulting impact on leverage would be. The good news is that Range has a deep inventory of projects and we have multiple asset sales initiatives underway. Some have significant future potential, some are further out the drilling schedule. So there is no current impact on cash flow. Some have modest impacts to cash flow because, looking backwards, they might have had wider basis differentials and not have contributed significantly, or in any material respect, to our corporate cash flows. So that is, kind of, a valuation question specific to each asset. But the punchline, I think, that we're trying to convey is we have multiple asset sales underway. Interested parties and dialogues going on, on multiple fronts and monetizing those assets. In some respects, you're pulling inventory that may be much further out our drilling schedule, may not be currently reflected in our stock price, in our opinion, and on an NPV basis, it may be so far out the drilling schedule that we have the opportunity, potentially, pull that forward by monetizing it today to reduce debt and still maintain many, many years of the high-quality inventory and all without harming or altering the trajectory of the company laid out in the 5-year outlook.

Great. And then my follow-up is with regards to the NGLs and the marketing arrangements and agreements that you have. Obviously, there was a very slight impact from the Mariner I delays. Beyond that, do you still see upside relative to others from the NGL and marketing agreements and the exports of ethane and propane? Is there further relative upside that we should expect? Or through -- has most of that already been achieved?

I think there's further upside to that. I think we're -- if you go back on how we're set up, we have different outlets, Mariner West, Mariner East and good exposure to the international markets with our ability to export on -- from that. Internationally, we see -- we believe it will be robust demand for propane, ethane and some of the NGLs, driven a lot by China, some by -- in Europe. And then even here in the U.S., we had good weather this winter, which helped. We have new demand from all the ethane crackers that are coming on and, of course, I think exports are a big part of it, and we're able to benefit. If you look at propane prices, even though as a percent of WTI they're down some, on an absolute basis on a -- propane currently is about $0.80 a gallon. This time last year it was $0.73 a gallon. So I think it's important when you look at Range on the NGL side, we're expecting on our NGL and WTI and even if you go to natural gas, our net back pricing to improve or be stable from where we are today, which I think puts us in a good position relative to other companies and perhaps even relative to other basins.

And your next question comes from the line of Arun Jayaram.

I was wondering if you could maybe elaborate a little bit more of what you're seeing in the [A&D] market. Jeff, you guys have talked about having your Northeast Appalachia assets on the block, so obviously some assets in the mid-continent. And today you guys articulated maybe perhaps some opportunities to even look at selling some of your core inventory that perhaps has not looked to be developed over the next 15 years or so. But I was wondering if you could just comment on the A&D market for natural gas-focused assets?

Yes. I think the good news, as you just pointed out, we have multiple levers we can pull. And of course, we'll consider all of our assets and whatever makes the most sense. We'll pursue all of those. So I think the good news is we have a huge inventory. We have high-quality assets. Like Mark said, some of those are, because of the size and scale and quality, maybe out there in the future, to the extent we can pull them forward. So I think it's -- you have to have high-quality assets that will interest people. And I think you have to be somewhat disciplined in order to find the right buyer. That being said, we're really focused on -- and we believe we can accomplish significant asset sale by the end of this year. And we -- like Mark said earlier, we have multiple processes underway.

Fair enough. Dennis, as you take over and are now leading the operating group as a whole, I was wondering if you could comment on your leadership style and any new ideas that you think that you can bring to the table.

Yes. I'm happy to answer that. Over the past now almost 8 years with Range, one of the things with my time in Appalachia and now moving to this new role is I'm kind of an incrementer at heart. And I really enjoy the ability for us to take what we have as repeatable and successful and continue to build upon that year-after-year and month-after-month and watching the teams be successful. I think that's coming out in notes like today when we talk about our long lateral lengths or efficiencies that we capture on a completion side or LOE levels that we've been able to achieve over the last few years. As we look at the 5-year outlook, I think the next chapter is now how do we look at what our next phase of efficiencies and really being capital-efficient looks like in line with that 5-year outlook. So from a leadership perspective, I'm really looking forward to working with the team to try and capitalize on that.

And your next question comes from the line of David Deckelbaum with KeyBanc Capital Markets.

I know there's a lot of interest in some of the M&A opportunities you guys have discussed. And I wanted to ask like 2 questions basically around that. One, within the 5-year plan now, Jeff, in your prepared comments you talked about Range having the largest valuation disconnect in the market right now. One, I guess, how do you see -- what do you think is the most pertinent thing for Range to take care of in order to bridge that gap? Or is that -- do you have an intention of pursuing things like share buyback plans before potentially deleveraging to kind of address some of that near-term? Or is it squarely focused on using potential proceeds to delever? And then I just have a quick follow-up.

Let me start with the answer and then I'm going to flip it back to Mark as new CFO. And you heard a little bit about Dennis and some of his thoughts. I'd like for everyone to hear a little bit more from Mark and what he's thinking in that regard. But yes, I think when you look at the disconnect, I think when you look at Range versus our peers, I think we have excellent quality assets up in the Marcellus, long lead time that's driven it. I think when you look at our EURs per thousand, costs per thousand, they're at the head of the class, recycle ratio. What's different, and I think what helps or what's driven some of that disconnect, is our leverage relative to peers is high. It's come down a little bit, but at 3.5x, it's still high. So in the short run and in the short run being our goals, and you can see it even in our management short-term compensation that we have a leverage target in there. To hit where we need to be for this year, we need to get it below 3x. So we're intently focused on that. We have different processes underway. Once we get below 3x, then I think it opens up different options and flexibility. Let me turn the call over to Mark for that.

Sure. So Jeff's kind of touched on the gating item, which at present is leverage. We think that can have a material impact in valuation as we look forward into really integrating our operating strategy and financial strategy and directing the company in this kind of next phase of development. I mean, we're a decade into developing the Marcellus at this point. So the, in effect, commissioning phase is done. And we're at the point where we're optimizing infrastructure, optimizing sales and customer relationships. We continue to optimize operations and drilling new wells more efficiently. So as we bring together a financial strategy and an operating strategy and think about these targets that we've laid out of immediately, as quickly and prudently as possible, getting leverage below 3x, what are some of the options on the table? As you pointed out, maybe returning cash to shareholders in some form or fashion becomes a much more active dialogue. To get below 3x, those are the discussions that we, management and the board, have to have and decide what a prudent time is once you have a durable, sustainable leverage in your target range. Does that mean a change in the dividend? Does that mean share buybacks? The 5-year outlook laid out the possibilities of what the assets can generate, in terms of deleveraging and the profile and timing of that. But as we said numerous times so far, the asset sales are intended to accelerate that. So in other words, as we accelerate that deleveraging effort, that should also accelerate our ability to give serious consideration on how and when and in what format to return capital to shareholders. So all of those things are under consideration. It's a function of timing, durability, sustainability and making prudent decisions around those things.

I guess, following up on that, the conversation around potentially monetizing some underappreciated inventory that could potentially be within the core. I know that you guys have talked about other zones outside of the Marcellus before. One, I guess, are you considering in the areas where you would actually enter agreements for Marcellus development with somebody else's capital? Or -- and two, should I presume that the deals that you would be considering would have large cash components or cash components upfront and not necessarily just be some sort of accelerated JV program?

Well, the most effective form of deleveraging and intention there would be, obviously, to bring in some proceeds upfront and reduce debt in the absolute as well as a leverage, measured debt-to-EBITDAX in this case. To your point though, Southwest PA is what you're touching on, the core of our acreage position. It's a stacked pay opportunity with 0.5 million acres. So it's a tremendous opportunity set with a very long-dated drilling inventory. So there's the ability to bring forward some of that, and there's any number of ways of monetizing that, either through outright acreage sales, to your point, joint ventures, using somebody else's capital. So what I would say, in general terms, is that we are open to considering a number of different structures. The key principle is to not do anything that complicates our core asset and what is the heart of the company.

And your next question comes from the line of Ron Mills with Johnson Rice.

Thanks for all the comments on the asset sales, but shifting to Dennis for a minute. You talked about some of the improvements of -- in productivity of some of the longer laterals. I see even your overall lateral length this year is plus or minus 10,000. What are some of the gating items moving to potentially longer development? Is it more production history? Is it area dependent? I'm asking because your -- the continuous position you have sets up well for as long of laterals as you want to drill.

Yes. Thanks for the question, Ron. I think at this point, we're fairly confident that we can continue to advance the ball with long lateral development and continue to see those numbers increase over the course of time. What we also know is that one of the fundamental principles for us to be successful is to be repeatable. So having a good methodical approach to advancing those lateral lengths year-over-year will be key versus trying to leap to the record numbers. From a production standpoint, we see -- our performance at this point has been really close and in line with our type curves and projections. So we continue to have confidence that, as we drill longer, our well performance is going to align with what our projections are. From a completion standpoint, same thing, we haven't seen any challenges from an execution standpoint, and when you look at, as you pointed out, the contiguous acreage position that we have, it really sets us up well as we drill both in the heart of the field and also move to the outer areas and continue to advance our development, we see the lateral lengths really not being impeded.

Okay, great. And in terms of productivity, are you talking about productivity per 1,000 lateral feet? And is there any goal post you can provide in terms of what that's doing on a cost per lateral foot as you have presented in the past?

So I'll start with the first part. Yes, we do see that the well productivity on a normalized basis is in line with shorter lengths and also our projections and forecasts. So we've got a high degree of confidence there. What was the other question? I apologize.

The other question was just as you drill the longer laterals with the same productivity per lateral foot, I would assume one of the bigger efficiencies is on the well cost side. What's the -- what kind of efficiencies or improvements are you seeing on a well cost per 1,000 foot of lateral?

Well, we see significant improvement. But what we also are seeing is that once you're starting to get beyond somewhere in the neighborhood of 10,000 feet in reference to our 18,000-foot lateral, you're seeing that rate of change slow down, and it makes a whole lot of sense. But we're continuing to see it improve as we drill longer and longer. What's the upper limit going to look like? I don't think anyone knows at this point, because ultimately here's what's driving some of this. A, we're drilling some of, as I mentioned earlier, our fastest wells, and we're also seeing the team repeat now 4,000 and 5,000 foot days on a regular basis, not just again on a record basis. So as we look at how fast we're drilling the wells, that all plays into it also from a total cost standpoint. So I don't think we've seen the lower end yet, and we're close on where we think the dollars per foot could look like.

But Ron, I'd go back to my introductory comments. We talked about we've got a couple of wells now, we've drilled 18,000 feet, one of them was a little more than that. We haven't completed them yet. But if they produce EURs that are in line with the type curve, the extended laterals both -- long laterals would improve our normalized well cost and returns by about 17%, so it's meaningful.

Great, thanks for the repeat there. And then my follow-up is just in terms of completions, Dennis, you mentioned 40-plus completions in the second quarter, up from, I guess, 13 including Louisiana in the first quarter, most of which come on in June. Are those fairly evenly spread across your 3 windows in the Appalachian basin? And then as we look to the second half of the year, does the completion base, in terms of wells being turned in line, become, I guess, more linear?

Yes, as we look over the balance of the year, I'll start there. We have about 43% -- 40% to 43% of our activity will basically be focused on the dry area. So you can almost say it's a 60-40 split when you look at Appalachia. Over the balance of the second quarter, we're going to see a very similar well mix, but some of the stronger wells that we'll be bringing on toward the end of the quarter will be focused in the dry area for this particular next reporting segment.

And your next question comes from the line of Paul Grigel with Macquarie.

Could you guys provide some more color on the [S-tip] proxy focusing on leverage? And then as a follow-up to that one, the fact that the top threshold is focused at 2.9x. Should we be viewing that as really the goal is 3x and you're comfortable below that? Or should there be further debt reduction beyond that?

So to your point, the leverage levels have been set in new incentive -- management incentive measures. That's all been disclosed in the proxy, along with a number of other changes that have been made to try to enhance the linkage between the company's goals, objectives, incentives for management team as well as shareholder interest. To your point, the 1-year target at the [excellent] level is 2.9x. Those are measures set with a desired level of hitting over the coming year, but I think I'd go back to our high-level comments of a near-term objective of being below 3x and a longer-term objective of being at 2x. So those are fundamental objectives and targets in order to achieve in the near term as well as hit and sustain over the longer haul.

And just on the color on that. Is that -- was that push from shareholders? Was it from the board? Obviously, a pretty sizable change, just trying to understand where it manifested from.

I'd say -- I'll start and then kick it back to Jeff. It comes from all of the above. It is looking at the company and what a sustainable leverage level is that preserves a strong balance sheet to support the operating profile and the ability to harvest the value that's in our inventory. It is what leverage levels appear to impact your trading multiples on the equity side. We hear that loud and clear from shareholders and what their views are. We internally have our views, as does the board. So it's a dialogue amongst all of those topics.

Yes, I'd just add in, I agree 100% with what Mark said. But there -- we made a big effort this year of shareholder outreach. So clearly there was a big effort to communicate with as many shareholders as possible, and we talked to a number of them.

Okay, great. And then changing tones just a little bit. You guys talked about getting the decline rate down to below 20% in 2019. Could you indicate where it's at now? And then could you also walk us through, kind of, where the trajectory goes throughout the 5-year plan, but also what the main driver is of the reduction between '18 and '19 in the corporate decline rate?

This is Alan Farquharson. Let me kind of address the issue. I think we mentioned on the year-end call that our corporate decline rate for 2018 was approximately 23% and then moved to 18% thereafter. I think it's really just the impact. And then what we had said previously in previous years is that within 5 years or so, we're going to get down to low double digits. So I think that kind of plays in well to what the overall production forecast is and that's what's going to drive the overall low maintenance CapEx. What's driving that is probably a combination of things. Number one, obviously the Marcellus has -- our decline rate in the Marcellus has historically been lower than probably most of the other peers. I think it's really a function of quality of reservoir, well performance, obviously with over 10 years of production history, we kind of understand what the declines of those wells are going to look like. Then, of course, as you get longer and longer laterals added into the mix, it's going to flat and decline as well. Obviously, it's going to continue to feed in. So decline rate at the Marcellus is what's going to drive overall decline rate, and we would expect to see it continue to decline from, I believe, 23% to 18% next year. And then continue to decline out. That's corporate. So Marcellus is obviously less than what that is at this point of time.

And your next question comes from the line of Mike Kelly with Seaport Global.

Sorry to give you a kind of boring modeling question here, but I'd love a little bit more color on your go-forward gathering and transportation unit costs. I think on Slide 25, you give $1.35 to $1.40 per Mcf, kind of peak rate, and then it's supposed to come down from there. Can you just talk about that trajectory and maybe what it should look like as we move maybe through 2019?

Sure. So the guidance we've provided there, first of all, incorporates the impact of the new accounting guidance, so the increase over prior numbers. Remember that's just a gross up increase in revenue and an increase in the expense. But we've also talked about for the last of our contracted firm transportation capacity is expected to come online in the form of Rover in Q2. So we talked about our gathering and transport expense peaking in the early period as that comes online. And then over time as we're able to continue filling all of our gathering and long-haul transport, you're able to optimize that expense. So by the end of the year, we expect to have long-haul transport filled with our production. That's a benefit. And then going forward, we see the benefit of ourselves as well as other producers shifting their current in-basin sales into this new capacity coming out of Southwest Pennsylvania. What that does is it frees up sales capacity, your demand, in-basin. So we're not obligated to take on any further long-haul transport. We have the options of sitting back and looking at what the best netbacks are. Whether improvement in local basis differentials benefit us just locally, or do we use some of the expected unused capacity to move gas out of basin. So what that does is it allows us to continue fully utilizing the existing gathering and transportation inventory and portfolio we've put together, continue growing our production and what that's expected to do over the 5-year outlook, we laid out a $0.25 improvement per Mcfe, and that's the trajectory.

And your next question comes from the line of Bob Brackett of Bernstein.

I'm intrigued by the 18,000 foot laterals. Can you talk about what the constraints are as you go beyond that in terms of completion technology or even, sort of, production physics?

Yes, I think at this point, what I would focus on is, is really -- it's going to be the gathering and processing side of the equation. I think we're still looking for what the technical limits are going to be from the drilling and completion side, and again we're walking our way down the pathway of longer laterals and really haven't seen where that limit is just as yet. And clearly there are other examples in other basins where folks have drilled 20,000 foot laterals. So we feel confident that there's still running room for us to continue to push lateral lengths longer. But the other piece of this is how do you optimize facility design and your ability to compress, gather and process what comes off of a given well side, vapors management, all the other facilities, components that have to be considered. So with all that in mind, we can certainly upsize facilities and have done in a lot of cases, but we're really not seeing, at this point, where the end of the runway is for the end of this lateral length development.

But you're able to complete as many stages as you want out to that length and you like the spacing of the stages and you don't worry about staying in zone and you don't worry toe up, toe down, all that stuff's handleable?

We have a very dedicated and talented team that monitors our geosteering efforts 24/7. So our -- if anything, I would tell you we're drilling our fastest wells, but we're also drilling it within our tightest targets that we've had in the history of the program in Appalachia. So we feel really good about our ability to land these wells, keep them within the desired target and drill them in excess of 3 miles long.

Bob, that's a great question. I've challenged our team and asked Dennis that question. So at the end of that 18,000 foot lateral, that target line is plus or minus 10 feet and they're able to do that.

Okay. And we are nearing the end of today's conference. We will go to Marshall Carver with Heikkinen Energy Advisors for our final question.

I know your 5-year plan cooks in 10,000 foot laterals and you do have a very [blocky] acreage position. Have you been able to figure out what -- if the longer is better and you wanted to go a lot longer than 10,000 feet, which you theoretically could do over the next few years, I mean, is it 15,000 feet, is it 13,000 feet, is it 18,000 feet, based on what's already been drilled and [lease] configurations and things like that?

Yes, Marshall, it's Jeff. That's one of the things we tried to do when we laid out our 5-year outlook was to lay out something very reasonable. Even though you've seen us each year continue to expand lateral length and we totally have the expectations that we'll do that with time, we wanted to put out something reasonable to conservative. So even though we totally believe we'll do that, we didn't bake that into our plan. So that's an upside to our plan. Same with some other efficiencies. We didn't put a lot of efficiencies in there. We only put things that are kind of in hand. And so there's good upside to our plan, as Dennis mentioned, that I mentioned, with this year we're drilling some wells that are as long as 18,000 foot. Dennis talked about earlier some wells that were 15,000 foot performing above type curve from some of the wells we talked about last year, so that's a good upside to our plan.

Thank you. This concludes today's Q&A -- excuse me, question-and-answer session. I'd like to turn the call over to Mr. Ventura for his closing remarks.

Thanks, everybody, for participating on the call. And feel free to follow up with Laith and the team with any additional questions that you have. Thank you.

And thank you. Thank you for your participation in today's conference. You may disconnect at this time.