Range Resources Corporation
Q1 2015 Earnings Call Transcript

Published: 29 Apr 2015

[Operator:]

Good morning, and welcome to the Range Resources First Quarter 2015 Earnings Conference Call. This call is being recorded. [Operator Instructions] Statements contained in this conference call 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. [Operator Instructions] At this time, I would like to turn the call over to Mr. Rodney Waller, Senior Vice President of Range Resources. Please go ahead, sir.

[Rodney L. Waller:]

Thank you, operator. Good morning and welcome. Range reported results for the first quarter 2015 with record production, a continuing decrease in unit cost and some outstanding well results. The order of our speakers on the call today are Jeff Ventura, Chairman, President and CEO; Roger Manny, Executive Vice President and Chief Financial Officer; and Ray Walker, Executive Vice President and Chief Operating Officer. Range did file our 10-Q with the SEC yesterday. It should be available on our website under the Investors tab, or you can access it using the SEC's EDGAR system. In addition, we posted on our website supplemental tables, which will guide you in the calculation of the non-GAAP measures of cash flow, EBITDAX, cash margins and the reconciliation of reported earnings to our adjusted non-GAAP earnings that are discussed on the call. Now let me turn the call over to Jeff.

[Jeffrey L. Ventura:]

Thank you, Rodney. I'm going to begin my remarks with some macro comments about our industry and then focus specifically on Range. Starting with the macro, as you all know, U.S. gas supply has increased ahead of demand causing low gas prices in most of the U.S. and negative basis differentials in the Appalachian basin. We believe that over the last year, the U.S. gas market typically has been oversupplied by about 2 Bcf to 4 Bcf per day. However, we see positive things that are happening on both the demand and supply sides of the equation. On the demand side, I believe that most people would agree that additional natural gas demand is coming and coming in a very meaningful way. In our presentation on our website on Page 19, we have a projection on natural gas demand with time. The good news is that gas demand is expected to increase about 2 Bcf per day this year. This projected 2015 increase in gas demand as driven by the conversion of coal-fired power generation to gas, increased industrial demand, plant exports of gas to Mexico and LNG exports from the Gulf Coast coming online. For 2016 through '20, natural gas demand is projected to increase by about 3 Bcf to 4 Bcf per day each and every year. It shows about 20 Bcf per day of incremental natural gas demand by 2020. There are multiple other reports that project natural gas demand with time in the report we reference as consistent with our internal work and within the range of other reports that I've seen. The other side of the equation is the supply side. The supply side can be broken into 2 pieces

[Roger S. Manny:]

Thank you, Jeff. Winter weather usually brings higher oil, natural gas and NGL prices paired with higher operating costs. Despite a colder than average winter, the first quarter of 2015 did not follow this pattern. Realized price for mcfe is 28% lower than last year's first quarter. However, 26% higher production and 15% lower unit cost combined to generate $423 million in first quarter revenue from natural gas, oil and NGL sales including cash-settled derivatives. This top line figure was only 10% below last year's first quarter, despite the headwind from 28% lower prices. The operating and administrative expense story for the first quarter is an exceptionally good one effectively bearing the brunt of much of the decline in prices. As I mentioned earlier, the winter weather of each year usually brings higher expenses as our field professionals cope with the challenges of an often brutally cold operating environment in Appalachia. This year was even colder than normal, but our operating teams really delivered. Not only did we beat all of our unit cost guidance figures, direct operating expense was lower than last year on an absolute basis as well. The same applies to G&A expense and interest expense during the first quarter, all below unit cost guidance and all below last year on an absolute dollar basis. Cash flow for the first quarter was $207 million and EBITDAX for the quarter came in at $244 million. Cash flow per fully diluted share was $1.24. These figures were 21%, 20% and 23%, respectively, lower than last year due to realized prices. First quarter book net income was $28 million, and earnings calculated using analyst methodology was $31 million, generating earnings of $0.19 per fully diluted share. The non-GAAP measures that I just mentioned, including EBITDAX and analyst earnings, are fully reconciled to the GAAP numbers in various supplemental tables, which may be found on the Range website under the Investors tab. Looking forward to the second quarter, please reference our first quarter 2015 earnings press release for detailed expense item guidance. Now turning to the balance sheet, our first quarter trailing 12-month debt-to-EBITDAX ratio was 2.9x, roughly equal to last year's figure of 2.8x and below the 3x figure from the year before. Despite lower realized prices, our first quarter leverage is essentially the same as prior years. Range added additional natural gas, oil and NGL hedges during the first quarter for the remainder of 2015 as well as additional hedge volumes for 2016 and 2017. Details of these additional hedges may be found in the earnings release, the 10-Q and the Investors tab on our website. The first quarter of 2015 reflects the impact of lower year-over-year prices for all of our products. However, the quarter also reflects an appropriate response to this environment by the company

[Ray N. Walker:]

Thanks, Roger. At Range, we believe there are 3 key facts that differentiate us from our peers

[Jeffrey L. Ventura:]

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

[Operator:]

[Operator Instructions] Our first question is from Doug Leggate of Bank of America Merrill Lynch.

[Douglas George Blyth Leggate:]

Jeff, clearly, I'm going to take Ray at his word. I'm not going to ask about the EUR and Utica. However, as clearly, the results are pretty stunning obviously. So I guess I'm trying to understand is, things are pretty well set up. It looks like they really move very quickly on this program. What gives that basically makes space for -- in other words, how would you prioritize what you're seeing in the Utica versus, for example, equivalent opportunities in the Marcellus? And I've got a couple of follow-ups, please.

[Jeffrey L. Ventura:]

Okay. Yes, what our plan is to -- we've got the first well online, 12 weeks, you're right. So far we're very encouraged. Permanent facilities for that first well will be there about middle of the summer. We've spud our second well. And our plans are to put both wells online in the permanent facilities at summer, and then we'll spud a third well after that. Obviously, we're doing a lot of preplanning for a success case. How would we move the gas and also -- the key then will be as we get to the end of the year, and we have 3 wells, and we have longer production history, what do the economics and returns look like versus the Marcellus? You're correct, it could be a change in capital efficiency or another way for us to grow with better returns or better capital efficiency. To the extent it looks like that in the end of the year and it could be, then you'll see us work the Utica into our 2016, '17 programs and beyond.

[Douglas George Blyth Leggate:]

I appreciate that. I guess it's kind of a related question then. So you've obviously now got a very large opportunity literally under your feet. So lack of any mention in this quarter of the Mississippian, and I guess it really raises the question of what do you consider a core or rather what do you consider non-core now? And I would ask specifically about Nora and the Mississippian in terms of -- whether they're going to be able to compete for capital. And I've got one final one, if I may?

[Jeffrey L. Ventura:]

Yes, I mean it's a good point. I'll answer it in this way. If you look at Range historically since 2004 when we sold roughly $3 billion worth of assets, that's done several things for us. It's allowed us to continue to focus our capital into our highest return, best projects that keeps us focused. It's driven down our cost structure. It's driven up our returns. It's been a source of funds. So clearly, when we see that other people value those assets higher than we value them, we'll do the right -- what we think is the right thing for the shareholders. In the Mid-Continent area, we have roughly -- I don't remember exactly. I'm going to say 75 million per day and about 360,000 net acres. So we have a big footprint, lot of production, and we'll do what we think is the right thing there ultimately for shareholders. And then we have $170 million per day and 460,000 net acres, basically in the Southern Appalachian Division, basically in Virginia. So yes, we always look at those things, and we look at how -- what competes for capital and what's the best way to manage those assets going forward.

[Douglas George Blyth Leggate:]

Is it an active process underway at this point, Jeff?

[Jeffrey L. Ventura:]

We're always active. I mean we're always looking at the opportunities and considering how to best to maximize the value of the assets for the company.

[Douglas George Blyth Leggate:]

Okay. My final one hopefully is quick, so OpEx and CapEx cuts, the prospect of our gas price recovery. If you're growing at 20%, having already cut your capital $700 million, what do you do with incremental cash flow, whether it comes from CapEx adoptions or better gas prices? And I'll leave it there.

[Jeffrey L. Ventura:]

Yes, I think in the short term, if you're looking into 2015 to the extent we get service cost reductions or other things happen, I don't think -- we're not going to change our guidance for 2015. It's 20%, CapEx will be the same. To the extent we're more efficient, it might help us better set up 2016. Plus I think the other thing to remember that maybe helps to distinguish Range from its peers, we're one of, I think, several things, is our production profile is back-end loaded. And it's been that way every year for the last 5 years. So we see relatively little bit of growth in the second quarter, but the big growth in the third and fourth quarter. What that does and it's really helped set up 2016. And then with the portfolio we have, looking at 2016 and beyond, then it's a matter of -- we're in a fortunate position that we're in the core of the Marcellus, Upper Devonian and Utica. We have 900,000 acres of dry and 700,000 acres of wet. We can drill up and down that section and back and forth, so we'll be able -- we'll maximize returns as best we can going forward from there.

[Operator:]

The next question is from Bob Brackett of Bernstein.

[Bob Brackett:]

You all replaced your debt-to-EBITDAX covenant with an EBITDAX to interest expense covenant. Can you talk about how easy or hard that discussion conversation was? And what the new covenant lets you do?

[Roger S. Manny:]

Sure, Bob, it's Roger. It's a good question. It was actually a pretty easy conversation. As evident by the fact that all 29 banks unanimously approved the change. And on our part, a 51% vote, no bank chose to be carried. They all stepped up, doing the right thing. And we're very pleased and proud of them for doing that. So the reason is that the covenant really no longer fits. We redid our bank facility in the fourth quarter of last year. And in that process, we went to an annual Borrowing Base determination. A lot of folks really didn't pick up on that. But it was pretty big changes, saved us a lot of money. It helps us manage our affairs better over the long term. But when the banks do the Borrowing Base determination, they basically take all your cash flow until your next review date and toss it out. So in our case, when you went to a full 1 year redetermination, they took essentially over a year of our cash flow out through April of the next year, which encompasses a lot of our hedges and everything. So you can see, with the $3 billion-plus Borrowing Base that they approved, we're real pleased that, that ratified our liquidity and our position. The Borrowing Base is -- because that's their primary tool to manage leverage. And the reason is pretty simple, it's a forward-looking test. It's basically a PV-9 coverage test. So the best way to work your growth is to be looking out the windshield and working the brake and throttle accordingly. And that's why the banks rely on that test first and foremost. The debt-to-EBITDAX covenant, that's a rearview mirror test. So it's really not as applicable to managing leverage over time. So in our case, the covenant was kind of a no-harm-no-foul covenant. We're never anywhere close to that ratio, never intended to be anywhere close to that ratio. But looking at it after getting through the restructuring process, we just decided that an interest coverage test was more appropriate. We rely on the annual Borrowing Base determination to work with our banks to keep leverage where it needs to be. And that rearview mirror test just didn't make sense for us anymore. And the banks agreed with us, and we made the swap. And it just removes a source of potential concern from investors that may not have an in-depth knowledge of the process.

[Bob Brackett:]

That's great color. Quick follow-up, you talked about your rig contract roll-off in the strategy there. Can you talk about your completions contract and the strategy for keeping them busy? Do those contracts roll? Or are they longer term?

[Ray N. Walker:]

Yes, Bob, this is Ray. We really don't have any long-term frac contracts. We have what we more commonly refer to inside the company as relationships. We've had, for instance, frac-ed the majority of our completion work in Southwest PA, really for almost -- since 2007. So that long-term relationship allows us to work with them on key performance indicators that help us work more efficiently, and then we're able to arrive at pricing, kind of based on the market and utilization that allows us to do things that a lot of our competitors can't do. And that consistent strategy over the years has allowed us to innovate with a lot of things like new manifolds that our teams designed and new liner systems to protect the pads. And all those sort of things that have allowed us to go forward. So we don't really technically have any long-term frac contracts. And that was one of the things that allowed us, like on the drilling rig side, to take advantage of what we were seeing happening back in December and January, work with our supply-side vendors and suppliers to create prices where they could still work and we could still continue on with some pretty significant savings. And I think that was way in advance of what a lot of our competitors were able to do.

[Operator:]

The next question is from Brian Singer of Goldman Sachs.

[Brian Singer:]

Your lateral length in the 2 Southwest Pennsylvania, Marcellus that you highlighted today was in the 8,000 to 9,000-foot range, which is well above your average. Could you just update us on how significant your ability to drill wells of this lateral length in your southwest dry and wet gas acreage is from a contiguous perspective? Whether you see these type of results as repeatable? And maybe I'll ask an EUR question on this, what the impact on EUR and well cost per thousand feet of lateral is versus your base case Slide 17 assumptions?

[Ray N. Walker:]

Yes, Brian, good questions. We have only -- like Jeff said in his opening remarks, we've only touched a small, small number of the total potential locations that we've got left to drill. We don't have -- while we do have a lot of units formed, we don't really have a lot of limits on the lateral length that we can do going forward. So we do expect to continue to significantly increase lateral lengths by year going forward. And I think eventually, you'll see our average up there in the 8,000 to 9,000-foot range. And of course, every area will have a different optimal at-lateral length depending on liquids and as [ph] well pressures and all the different things. Because remember, we have a huge position there in Southwest Pennsylvania. So the Marcellus is not the Marcellus -- it's not the same all across that property. We have super rich, wet, dry. We have thicker areas, higher-pressure areas, a little bit deeper areas. So all of those wells will be designed differently. But we do expect to get significantly longer each year. Those wells, longer wells that we talked about in the remarks today, they were in the plan. That's part of what makes our average go longer this year. And our team is continually able to push those wells out. We have, in fact, to drill the wells that are much longer than those. So technically, mechanically, from a land standpoint, there's really no limits to what we can do. What I would like to point out is, look at some of those wells, for instance, in that 8,000 to 9000-foot range and compare them to some of the offsets in the plank areas that aren't as good a rock. And I think you'll start to see what we get excited about talking about the longer laterals and how much more capital efficiency the well improvements we're going to see going forward. From your standpoint of...

[Jeffrey L. Ventura:]

And totally to clarify that, I know what Ray means. When he's saying plank areas, he's saying our acreage is core. You can look at other operators who have drilled outside of what we feel are core areas who have already drilled longer laterals like that and then compare them on a rate basis or EUR per thousand foot or per stage. But sorry to interrupt, Ray. For listeners, I want to make sure that was crystal clear.

[Ray N. Walker:]

Yes, good to point out. And then your point on cost -- well cost. I mean, again those were also forecasted into our model and our plan this year. But if you'll look on Page 8 in our presentation for 2015 in Southwest PA, we give you a cost per foot for those wells. That's for the average well that will turn to sales this year. And if you were to think about it from a standpoint, longer is certainly better because economies of scale kick in and so forth, so longer laterals do get cheaper on a per foot basis. And we have seen well performance hold rock steady. And in fact, I think these 2 wells will probably end up having some of the highest performance on a per thousand foot basis of any of the wells in the area. So we do see good improvements going forward. And the third point I want to make is we really did forecast -- our team is getting really good at understanding this rock. And I think our track record supports that. But they were forecasting rates pretty close to these in our model. So that's part of what was a significant point in allowing us to reach 20% growth this year to $700 million less capital. That's what we've been saying for many years is our capital efficiency is going to flow through as we drill longer laterals, and our team gets better at getting more out of the rock. And like I've said, you probably get sick of me saying it, but I'm going to keep saying it, the rock rules. And we think we've got a core position where all of this is possible. And we're in the very early innings of the ballgame, because we've got thousands and thousands of more of these wells that we can do as we get better and better.

[Jeffrey L. Ventura:]

And I'd just add again a little bit to what Ray said. I totally agree with what he's saying, the rock rules. But you want to have the high-quality rock in the core in an area of good infrastructure with favorable takeaway and contracts to external markets. And I'm sure Chad, at some point, will hit on some of those.

[Brian Singer:]

That's helpful. My follow-up is that you highlighted in your opening comments the unique attractiveness of your NGL's contracts. Beyond the startup of ethane exports later this year, can you talk to what you see as differentiating your ethane and propane FX versus others? And whether you see a situation in the market whether to maintain pipeline stacked portions of your ethane, or propane production would at least temporarily be a drag to cash flow?

[Jeffrey L. Ventura:]

Let me -- I'd like Chad to answer that question. But, Chad, if you would, could you also talk about some of the gas contracts for second half of the year? Because it's all, really all 3 products, natural gas and NGLs and condensate.

[Chad L. Stephens:]

Yes, this is Chad, Brian. As Jeff mentioned in his notes earlier in the call, 80% of our ethane is tied to either oil or gas index. So that's already reflected in the prices we show in our financials. Once Mariner East starts up, 20,000 additional barrels of ethane will be going to market, so it can go into international markets priced at a common Naphtha Brent crude sliding scale formula, which will again improve our cash flow. We focus more on improving our cash flow than we do our per unit metrics. So that's an important point we try to make in our slides on 37, 38 and 39 in our slide deck. Once Mariner East is in service and flowing in later this year, we, going forward, our LRP forecast, we don't need any more ethane projects to meet spec. We can grow our production under the LRP up to as much as 3 Bcf a day. So we don't need any more projects. Mariner East will also help in propane service because we can float 20,000 barrels a day and load ships at a very high rate once that's in service. Jeff referenced our gas contracts. As reflected in our slide deck, we show what our firm transport capacity projects are. And later this year, we have our specter Uniontown to Gas City project coming online, which takes 200,000 a day of firm capacity over to the Midwest, where we get much better pricing. It's -- the indexes over there are very stable. And then later in 2016 and 2017, we have other firm transport capacity projects coming online, which again will take our gas away from the Appalachian basin to more stable of indexes and help improve our cash flow.

[Operator:]

The next question is from Dave Kistler of Simmons & Company.

[David William Kistler:]

Real quickly, looking at the CapEx this quarter, it's down 45% quarter-over-quarter and keeping your full year CapEx guidance, which would imply that it continues to step down similar to kind of what you outlined with rigs falling off contract, et cetera. Can you break down for us how that CapEx declined both this quarter and going forward? It's split between lower activity, lower service cost and better efficiency gain.

[Roger S. Manny:]

Dave, this is Roger. Let me answer the first half of your question. I'll switch it over to Ray to talk more about where the capital is going later in the year. Just one thing I wanted to highlight, there was a big working capital swing in the first quarter. So over $100 million of the incremental debt and spending was due to working capital. So there's a delta between the cost and current schedule and the cash flow. So please go through the queue or give our guys a call. They can walk you through that. So the CapEx increase, depending on how you measure it, is not as large as it first may appear, but I'll let Ray tell you where -- exactly where the money is going.

[Ray N. Walker:]

Yes, we -- Dave, when we put together the CapEx plan for '15, we did plan in there some service cost reductions. And I talked a lot about that on the first call that if you looked at a well in Southwest Pennsylvania, the lion's share of our CapEx is gone. And if you looked at a well in February compared to December, on apples-to-apples basis, we're seeing 23% to 25% less total well cost as a result of service cost reductions. Those numbers were built into our plan this year, but it's also important to realize that all those savings didn't kick in on January 1. They really kick in towards the end of the first quarter, and then they start flowing through the rest of the year. So I think you'll see the CapEx will come down quarter-over-quarter because we tend to -- we have more rigs running at the first part of the year than we will at the last part of the year. And that's pretty, pretty much the same that it's been every year. So I don't see that as a whole lot different, but hopefully, that's a little more color on how that comes together.

[Jeffrey L. Ventura:]

And then to just reemphasize, we still feel comfortable and are confident with the 20% growth at $870 million.

[David William Kistler:]

Great, I appreciate that clarification. And then maybe switching a little bit to some of your slides where I know you put some of this out last quarter as well, but you highlighted the benefit of the optimized completions and the down-spacing in the Marcellus and then in the optimized completions in the Nora area. And obviously, nice step uplift in production associated with those. Does that maybe argue for going back to existing wells and doing optimized completions or refrac on those existing wells, just given that they'd be even lower cost and probably generate with 50% uplift of production versus what you've done before, maybe even a better rate of return than drilling original wells?

[Ray N. Walker:]

Yes, Dave, I mean we did talk about that example that we put in there last conference call on Page 36. And that was an exact case that you just described where we went into a well, a pad that had 5 wells on it that were 2 years old, had been online for 2 years and we put 2 new wells sort of in between the laterals. And there were really 3 things we wanted to test. We wanted to test how much less would the wells cost, drilling them on since all the existing infrastructure roads, pads, water, gathering system and all that sort of thing was already there. Number two, did the new wells interfere with the older wells? And then number three, how much better would the new wells be with the new completion -- newer completion technology. And number one, the wells were $850,000 a piece cheaper. And we think that number could even be higher as we begin to do more of this as we go forward. Number two, there was no impact to the older wells, which I think is very significant. And I think you've read a lot about our competitors that are in noncore areas. They have not been able to do that, where they've seen big hits on their offsetting wells. And then third thing, the wells produced 53% more production than the first year as compared to the older wells that had -- I think early on, the eyepiece were 4x higher. So clearly, we see that as unbelievable upside going forward, because we clearly have a lot of those pads already out there, some of them as much as 8 or 9, 10 years old on those. So I think that going forward, you're going to see us probably in about 2017, '18 as we get into our further plans down the road where a bigger and bigger percentage of our wells each year will be going back on to those existing pads. We see that as a huge step change in both well cost, efficiencies and well performance and then in -- also in gathering system cost. Because your gathering system's already there, already been mostly paid for. So essentially, those wells will produce at a much lower gathering fee. So we see that as big potential going forward. There's not really any of those wells planned at this year as we're still trying to really optimize our program to try to get the wells, the final HBP work done that we need to get done, the infrastructure buildouts that we're still doing over this year and next year. And I think that, that is big potential that we see going forward.

[David William Kistler:]

Okay, appreciate that. But maybe one just clarification. Other than drilling in kind of a tighter spacing, would you look at going back to an existing well and refrac-ing it. We're hearing about recompletions from other folks that are seeing that as a positive, and obviously, from some of the service companies commenting on that. How do you guys think about that in your inventory? Or is it really, hey, we're going to finish HBP and then we'll consider those things?

[Ray N. Walker:]

Well, our teams, I think it's probably technically one of the most gifted teams in the industry. And they are continually coming up with innovations and new ideas and concepts and sort of things. We have studied and talked about refracs for some time. I personally have a lot of experience with refracs, most of which was not that good. So we don't really see refracs as big potential going forward. It's certainly not anything we're counting on. But we will clearly study it as we go forward. And my overall statement for refracs, if you really mess something up the first time, then there's potential that you could do something if you went back in there. But we don't see that as big potential and it's not certainly -- not anything that we're counting on going forward.

[Operator:]

The next question is from Neal Dingmann of SunTrust.

[Neal Dingmann:]

Just a kind of follow-up on the Slide 36, that somebody was asking about the down-spacing, guys. Just a question now, is -- have you kind of looked at that as far as in the entire Southern Marcellus and the Northern Marcellus area? And are you confident now that, that's working -- going to work in most of the area? Or is that still isolated to kind of core areas of each of those respective regions?

[Alan W. Farquharson:]

Neal, this is Alan Farquharson. I think that what we've seen so far is we've done a fair amount in -- we've done a fair amount of activity in the wet and super rich area. Our plans are to do some -- a little more testing in the dry. We're also looking at what some of our competitors have done as well. Obviously, we don't have to spend all the R&D work, but we believe fairly comfortable that you'll be seeing a significantly tighter spacing in the wet and super rich. We also believe, but we don't have yet the data to kind of really feel comfortable yet that we'll probably see some of that happen in the dry areas as well. And we think some of it has to do with just the quality of the rock that we have at the end of the day compared to what our other competitors have.

[Neal Dingmann:]

Yes, got it. And then obviously you've had 2 monster wells within the Southern Marcellus between this recent Washington County well, the 43.4 million a day test rate, and then obviously, on the heels of this one in December. I guess a couple of questions around that. First, on that, I noticed I think both -- or you mentioned I think in here that your Utica's flowing around 20 million a day. Could you just talk about how you see -- I mean given these monster test rates that you have, how you guys sort of think about the sales or the choke program that you have that once you see these huge test rates?

[Ray N. Walker:]

Well, that's a good question Neal. And one thing I want to correct you on, those aren't just monster wells, they're monster pads. Because they both are multi-well pads, and we just simply hadn't been able to turn the other wells on yet. But we expect actually pretty similar results from other wells on the pad. Part of our long-term goal that the team works on, sometimes 3, 5 and 7 years in advance, is looking at the gathering system. And we have very intricate models of the gathering system. We're working with MarkWest on deliverability at any given point, compressor stations, upgrades, process and plant and so forth. So all of this has been built into that plan. And we don't have a choke management program as a gimmick or a fad or anything like that to manage the wells. We're simply trying to produce those wells of what we believe is the optimum performance that will generate the best economics for the project at the end of the day. It's a long-term look that we take at it. Initial production rates are great. They're fun to talk about. It's kind of a yardstick to compare wells. And these -- in a case like these 2 monster pads, you had a lot of facilities there for maybe 3 wells or 5 wells, depending on how many wells were on each pad. And what you end up doing is bring one well on and just let it produce through the facilities that all 5 wells might use to see what it's capable of. In actuality, we'll probably choke that well back and then start opening up the other wells and try to get them online. They'll all be produced or constrained conditions for quite a while in that case. But that's the way we designed it going forward. And we think that keeps our cost structure down. It's better planning with MarkWest, which allows them to keep their cost structure down, which in turn gets us lower gathering fees. And again, we're really focused on the years ahead and watching that gathering fee fall off as we go back in and fill in on these areas. We think that's the most efficient way to develop this project long term. Because again, we've only touched a very small portion of the total number of locations that we can drill going forward just in the Marcellus. On the Utica and places like that, the other stack-pay potential, we've got a long ways to go on that also. As for as the Utica well, when we get the permanent facilities online in the middle of the summer, those wells will be put online, and they will be uninterruptible. In other words, we'll be able to hold them at a constant rate. And these production facilities are designed to limit those wells at 20 million a day. And again, that's not necessarily for any sort of choke management or anything that we're worried about on that end of it as much as it is trying to optimize the cost for those facilities in that gathering system that we're putting in play.

[Neal Dingmann:]

Ray, if I can have just one last one. Just again, I know it's not just Washington County, obviously, that's where these huge pads where for this Marcellus and Utica, but kind of in this surrounding area. Near term, do you have -- I guess when you have the takeaway for each of the -- all this Utica production on top of the existing Marcellus production you have there, what do you have sort of near term, I guess? I mean could you flow it, I guess, in the same line? I guess you could, but you really don't want to, maybe you can just, maybe talk about takeaway if you would start with kind of Washington County, that generally, given these huge pads, takeaway for both the Utica, Marcellus in this specific area?

[Ray N. Walker:]

Well, I'll start and let Chad jump in. But again, like Jeff brought up earlier, there's really 3 keys to a big successful play like this. One is, you got to have the rock, and we've clearly done that. Number two, you've got to have the infrastructure. And we request that 75 years plus of infrastructure was built right through this area. And we were able to tap into all of that. We were first movers in the play. And working with MarkWest, we've been able to put a huge system of interleaks and placed there for the wet gas. I think what a lot of people forget is there's clearly also a lot of dry gas lines in that system as there's a lot of residue gas that comes off the plant, a lot of meter taps into the different pipelines, Tennessee and Columbia and Line N [ph] and so forth. So we have all of that together growing over time. And then the third piece, the third cornerstone of it is the market and having actual customers on the other end to use the product. And that's also been a core philosophy of ours for years is to cultivate, not only the firm transportation and the actual infrastructure to get there, but also the consumers on the other end to use that. So in part of our plan that the team is currently working on today, to put an effective Utica development program together, which could begin as early as next year depending on market conditions. All 3 of those pieces have to be in place, and I'll let Chad refer to how we might expand going forward.

[Chad L. Stephens:]

Yes, so to expand on that a little bit, because of all the existing infrastructure, we are currently working on a short-term solution to be in service, be it the late 2016 for what we're calling a header system, which is some pipe that would run through this particular area of Utica development to get the gas to our existing capacity that we have to take it to market. And then long term, that header system, we're going to be able to expand it to whatever direction the Utica and dry gas development takes us. So having the existing infrastructure allows the optionality to be able to quickly as we -- as the drilling teams come up with these new monster pads as you described them, we have the opportunity to build out the infrastructure, and we'll do so. So we have short-term projects that we're working on for mid 2016 and much bigger projects beyond that in later years to help get the gas out of there -- at good economics, at good prices.

[Operator:]

Ladies and gentlemen, that is all the time we have for questions. I would like to turn the call back over to Mr. Ventura for his concluding remarks.

[Jeffrey L. Ventura:]

2015 is a challenging year for our industry. With our current plan to spend approximately $700 million less in 2015 and 2014 and still target 20% growth, we believe that we'll be one of the most capital-efficient companies in our industry. These capital efficiencies coupled with our large footprint in the core of the Marcellus, Utica and Upper Devonian and the optionality of being able to drill dry, wet and super-rich acreage, as well as the shape of our 20% growth profile for 2015, which is back-end loaded, have us well-positioned for 2015, '16 and beyond. Thanks for participating on the call. If you have additional questions, please follow-up with our IR team.

[Operator:]

Thank you. Ladies and gentlemen, thanks for participation in today's conference. You may disconnect your lines at this time. And have a wonderful day.