Range Resources Corporation (NYSE:RRC)
May 21, 2013 9:05 am ET
William A. Featherston - UBS Investment Bank, Research Division
William A. Featherston - UBS Investment Bank, Research Division
Okay. I think we're going to get started this morning. I'd like to welcome everyone to our UBS Global Oil & Gas Conference. I think this is the ninth year we've done it in Austin, but the first year at the Four Seasons, so we're very excited about the new venue. And I think we have a very exciting lineup for you over the next 3 days. And we're pleased to kick it off with Range Resources with a very large and dominant position in the Marcellus Shale. Here to tell us about it is Mike Middlebrooke who runs Northern Marcellus Shale division, and we also have Laith Sando from the IR division. So with that, I'll hand it up to Mike.
Thank you, Bill. As Bill said, I'm Mike Middlebrooke. Most of you probably don't know me. This is one of my first conferences to speak at. So I just wanted to give -- for a second, talk about how long I've been at Range.
I started with Range in 1997. So I've been there about 16 years. When I came in, I came in as an operations engineer in our Conger Field, which is our legacy acreage right now for the Cline shale, you can see that there in West Texas. We were -- at that time, we were completing Canyon and Cisco sands in the Pennsylvania formation. So I've been around a while. A matter of fact, when I started, my hair was brown, so that tells you a little bit about how long I've been here. I used to look like Laith here.
So anyway, the reason I want to let you know how long I've been here is because Range has a simple strategy and it's been the strategy since I was here at day 1, and that is focus per share growth on production and reserves at top quartile or better cost structure and then when necessary, high-grade inventory. In addition to that, we've maintained a simple, strong financial position. Roger Manny is, for the last 10 years, made sure that was the case. He often speaks at these conferences. And then lastly, but not least important, is we operate safely and are good steward in the environment.
What you see here is our resource potential. Primarily, what we're going to talk about today is the Marcellus Shale and the Midcontinent, Mississippian Lime. And you can see that makes up the lion's share of the resource potential, which today, stands at 20 -- or 68 Tcfe. With that resource potential, we've got 20% to 25% line of sight growth for many years. And that's with our current asset base, according to our long-range plans in place at this time. So incredible growth for many years in the future. On top of that, we've got cash flow growth that's expected to outpace the production growth, primarily due to the liquids production that we're focusing on in developing this resource potential at this time.
We're focused on high rate of return, high-growth, large-scale assets. We've sold about $2.3 billion worth of acreage over the last 10 years, including the Barnett Shale and most recently, our assets out in Mexico, and that's done in an effort to focus on what our high-growth areas are and bring as much capital that we can to those areas. And in this case, it's going to be primarily the Marcellus shale and hopefully, in the future, Mississippian Lime.
As I mentioned earlier, we focus on low-cost structure. This is really what's made Range, especially in these tough times with commodity prices where they're at. Our resource potential at 68 Tcfe is about 10x our premium reserves, and that's large part due to our technical teams and the work that they do.
So let me talk just a second about our financial position. As I mentioned, Roger Manny makes sure we have a strong simple balance sheet, a consistent bank debt, subordinated notes and common stock. We have a well-structured bank credit facility. We have 28 banks holding not more than 9% each, so we've minimized the risk there. Roger like to say that he's got 28 additional engineers looking at our books as well. So we have a solid hedge disposition. We've hedged religiously over the last 10 years, maybe 15 years. Just to protect our cash flow, we're continuing to do so. And in 2013, we have over 70% of our production hedged; in 2014, approximately 50%.
This just shows a little bit of the results of the low-cost growth. The metrics you see here starting on the right on the slide, these are excellent against our peer -- excellent asset coverage compared to the peers, and there's 16 peers in this case.
And then debt to EBITDAX, you can see, we try to keep that under 3x. When that does drift upward, we like to let the public know what our plan is to get that changed. And this year, in 2012, at the end of 2012, we sold that asset in the Mexico and West Texas to get that back down below 3x.
This is -- this shows what our main focus is, production per share, debt-adjusted basis. This is what our management team gets paid on. And you can see the phenomenal growth year-over-year that we've had in the last 5 years. 2012 alone, 29% production per share growth and 22% reserves per share.
This just shows the value that we've added over the last 10 years. And this is despite the fact that we've divested $2.3 billion worth of properties over these 10 years. You can see 20% to 25% growth projected with 19% compounded growth historically. This is something we're real proud of at Range. We work diligently on the operating teams, as well as in the G&A folks and whatnot. You can see, over the last 4 or 5 years, we -- unit costs have declined over 30%, and that's phenomenal and that's very necessary in today's environment. You can see reserve replacement, the top 2 items, reserve replacement and LOE, are the biggest contributors. LOE is cut more than in half and reserve replacement is down by $1.
That leaves us with $3 per Mcfe, which, as you can see, plotted on this particular study that this is something we show at every conference, just to kind of remind folks of where we line up in the cost area. And as you can see here, in 2012, in this particular study, we were #1, and that's at $3 per Mcfe. We're proud of the fact that over the last 9 years in this study, we've been either first, second or third.
Our reserve base and upside are continually growing. You can see here, this is just showing you the 68 Tcfe versus and the 6.5 Tcfe of proved reserves growing with time, and what's not in this in these particular reserves, if you notice, the Utica, and any downspacing other than 80 acres at this point in time, so no significant downspacings, including this. And the key metric here is -- we've moved 4.7 Tcf from potential to proveds over the last 3 years.
Let's talk about the asset base. Of course, where we're going to start is in the 1 million net acres perspective for the Marcellus and Pennsylvania. As you can see, it lies in 3 primary areas. Starting with the Northwest area, 315,000 acres, which is primarily held by production in the shallower formations. There were perspective for Marcellus and wet Utica. In Northeast, which the division that I'm currently over, we have 145,000 net acres, they're a perspective for the Marcellus, as well as the Upper Devonian, and at this time, we're only developing the Marcellus.
And then in the Southwest, which is where we'll focus the rest of the time in talking about the Marcellus today, 540,000 acres net, approximately 50% held by production. This is where activity level is the big bulk of the capitals being spent in the wet area and the super-rich area. And here, we're perspective for Marcellus, as well as Upper Devonian, we'll talk a little bit about that, and then the dry Utica as well. So multiple stack plays, a lot going on in this area.
Folks shown in that area, the 540,000 acres to date. There's been 1,650 wells drilled by us and others in the area, so that's highly delineated, highly derisked at this point in time. And this has been -- these wells have been drilled since 2004, when Range discovered the Marcellus with the Range #1 well.
Just to give you a little perspective on what we've done so far and what our potential is. With 540,000 acres and 80-acre spacing, there's approximately 6,750 locations. To date, we've got a little more than 430 producing wells. That's about 6% of the wells' potential locations of 80 acres at our own production. We're currently at about 500 million a day in this area. So if you do the numbers, that works out. If everything drilled out as planned, just in the Marcellus, we're talking about 8 Bcf per day. Not saying we're going to get there, but that's the potential, so that's what we're looking at.
Splitting the Southwest Marcellus into 3 regions, we'll look at the super-rich, where we have 110,000 acres and that's 1,350 Btu or higher. And then in the wet gas window, 220,000 acres, that's 1,050 Btu to 1,350 Btu. And then in the dry gas, when the -- which is less than 1,050 Btu. So far, we've drilled 200 wells or -- plus or minus in the wet gas area. On average, 3,200 feet, 13 frac stage -- 3,200-foot laterals, 13 frac stages, EUR is in the range of 8.7 Bcfe. In 2013, we're going to -- assuming we're going to look at some economics here, and the economics will assume the same 13 frac stages, 3,200-foot lateral. With that set up, 3,200-foot, 13 stages, strip price, 8.7 Bcfe with 85% rate of return, and then $5 gas, it will be over 100% rate of return. That's why we're focusing on this area.
The super-rich, to show the difference and the economics between the 2 areas. We had approximately 51 wells in 2012. We're looking at 1.3 million barrels EUR. In 2013, we're looking to increase the number of stages, lateral lengths and the number of stages a little bit. And estimated EUR is going to be in the 1.4 million barrel range. Looking at the economics there, you can see, with 3,800-foot lateral links, 18 stages at the strip, we're at 97% rate of return and $5 -- 105% rate of return.
Just a quick note to show the impact of the wet gas and the liquids. This is based on $4 gas, 1,040 Btu, be $4.16 up to $7.54 with just the wet gas, and that's without ethane rejection -- or with ethane rejection, and then a slight bump, with ethane extraction. Of course, all of those reserves and that great price are only good if you can loop [ph] the gas. I think Range has been a leader in recognizing this.
As many as 5 years ago, we began planning for what we needed to do to get ethane out of the region. We've got a three-pronged approach. As you can see here, the red line is our Mariner West, and it is going to Sarnia in Canada. This is Sunoco gathering the gas. We're expecting that in the second half of '13. We're expecting to move up to 5,000 barrels of ethane to Sarnia at the second half of this year.
The next project that's going to hit the line will be the ATEX, which is from the same area, Houston plant down to Mont Belvieu, we're expecting that in 2014. There, we should be able to move 20,000 barrels of ethane a day eventually. And then finally, the third project is what we called Mariner East, that goes to Philadelphia. There, you can either go to international markets, you can ship, or to the local markets. We are currently moving propane there through truck and rail. We're loading the propane on ships and taking it to South America. And at this point in time, we've got -- we're working on markets for the ethane in the future internationally, as well as propane. And just with our existing agreements in place, with minimal methane extraction, we expect to be able to move in the wet Marcellus up to 1.8 Bcf a day at this point in time.
That's what a ship looks like that carries ethane. Got a lot of word slides, thought I might throw a picture in here. This is -- Evergas does ship ethane for any hubs that's one of our clients.
Skipping to the dry gas area in Southwest PA. This is often we've neglected to talk about because we've been so focused on the rich area. But it's a key to talk about because it's so big. What you're looking at here is our acreage in yellow and then you see the red dots that are 10-plus Bcf a day wells or Bcf EUR wells, and then the purple dots are 5 to 10 Bcf wells. So in this area, at these depths, that's economic today. Look a little bit at the economics here in a second. We've got 210,000 acres.
Let's take a look at that economics here. So far, we've drilled 16 wells or, on this presentation, 16 wells averaging 2,900-foot lateral links with 10 stages. We do expect in future drilling to try to link in those laterals and add more stages as well. But even with that, we're looking at 7.5 Bcf EURs and the current strip, 57% rate of return with 88% at $5.
Visual upside. On the left side of the screen there is that Utica, the Utica and the Cline. Both of those areas we have tested, done some test that are encouraging, at least very encouraging in the Cline shale. We do have the ability here with acreage being held by production to take a step back and let some of our competitors that are working around us, ensuring they're with [ph] us, go through some of the hard knocks. So that's kind of where we're at with those 2 plays at this point in time. The Upper Devonian, we've done for tests there and very encouraged with it. We're not actively drilling the Upper Devonian because we're holding the Upper Devonian with every Marcellus Shale while we drill. So it's not critical at this point in time with the capital that we have that we deployed it to the Devonian. But we know we have it. We can always come back to it. the infrastructure is going to be in place. The cost structure will be even better by that time.
And then skipping down to the Wolfberry, here, this is our vertical stack pay in the Conger Field that I mentioned at the beginning of the presentation. Here, we are active with the drilling rig. We just planned 5 wells this year. We're seeing initial rates averaging 500 barrels a day, boe a day. It's encouraging. The economics look good there as well.
So let's move on to the Horizontal Mississippian, which is another big resource potential for Range. Here, we have 160,000 net acres based on -- and based on vertical well control. Here, compared to the Marcellus, which we've had 1,650 wells, there's 4,500 vertical wells in this area, and that's what you see there in light blue.
Range's acreage is on the Nemaha Ridge primarily. That's in yellow. This build was developed by Range in 2004 with vertical wells, so we've been here quite a while. It's kind of analogous to what we did in Conger where we drilled -- drilling completed wells in the 90s and the sands, the shallower sands, and are now our development stack pace.
So at 80-acre spacing, there's 2,000 potential locations here. And you can see, 85,000 in Kay County. These are EURs for the vertical loans on average in the Kay County, which is in the heart of our acreage and Southern and Kay is where all the development is going on at this point in time. That is one of the highest areas for EUR. So just based on the vertical well productivity, we expect initial results are very encouraging, what we're seeing there.
We've had kind of had to 2 timeframes of drilling, one with the original 2009 to 2011. In that timeframe, we were using a little bit shorter laterals and fewer stages. We've sensed in 2012 increased lateral link number stages. You can see, we've gone from 485,000 average to 600,000 Mboe average. And the economics here: At strip, with 485 as 91%; 133% at 600. So you see the difference that 100,000 barrels makes and then, obviously, a lot better than the $100 barrel.
Just to touch on just for a brief moment on markets. I mean, what are we going to do with all those gases in the industry? A lot of coal-to-gas switching going on in the power sector. Of course, that can go the other way if the gas prices go screaming up eventually. So that is going on. We are seeing Bcfs a day added to the demand based on that.
Petrochemical plants, we're seeing the cost advantage of natural gas, ethane versus naptha. They're having to run their models and figure out what they're going to do going forward. So there is big potential there.
Exports, from our information, there's 27 Bcf a day of projects for natural gas exports that are being worked on at this time. And then in the transportation sector, it's important to note that Range, as well as a lot of other companies are seeing the benefits of switching over to CNG. We've done that in 2012. We've converted our fleet of 150 vehicles to CNG and a number of other operators, as well as bigger and different companies are doing the same as you see on the slide.
Coming back to environmental health and safety, which we always seem to put last, but it's actually the most important thing that we talk about. We kind of want talk to -- about the numbers, do the numbers folks first. But this is very important to Range. We feel that we're a leader in this area. Specifically, in Pennsylvania, with the work Ray Walker and that group has done and getting that play going. There were a lot of things that needed to be done to make sure that we could sustain and keep it moving in that area. I think we've made huge strides.
One of the things we started early on and know late was recognize that the casing and cementing standards were poor and needed to be improved to protect the environment. And we took a large role and seen that, that got done. We soon figured out we need to recycle water and figured out how to do that, and do that now 100%. Combined, in Pennsylvania, we recycle 100% of our water. And a lot of companies are doing the same at this time.
And then in 2010, we were the first company to disclose the hydraulic fracturing chemicals and are continuing to do that as well. And then 0 vapor protocol and emission reduction is something we got really serious in, in 2011, and are continuing. So it's very important to Range and the sustainability.
So to sum it up, these are the key takeaways: 20% to 25% line of sight production growth; cash flow should outpace production growth; we're working on high rate of return projects, that's why you see us focusing on the Marcellus; and hopefully, we'll be focusing seriously on the Mississippian Lime as well. And then looking for the high rates of return and get -- in developing that resource potential.
So thank you for your time. I'll be happy to take questions that we're doing, so...
William A. Featherston - UBS Investment Bank, Research Division
Yes, we have time for questions.
I think it's, right now, it's trying to stay within the reasonable distance of cash flow. So I didn't talk a lot about it, but we are outspending cash flow by, on the average, $250 million to $350 million. We expect to be able to do that and still delever over time with the growth potential that we have. So that's kind of where we're at right now with the cash flow plus. But from other hindrances to production, we're addressing those on a daily basis. And obviously, they include take away, environmental issues, regulations, but we've got a fairly good handle on that. We're not going to spike the football, but those are the things that we can deal with and then we have to live within what prices we're dealing with.
[indiscernible] when you look at the type curves of all of these shale plays, you've got rapid initial production, which declines very quickly. So if you stopped drilling everything right now, the production would just fall off a cliff quite quickly. So I suppose, if -- what we assume about your growth is that you have to steadily carry on with new wells and new acreage but then you -- where do you get to the point where acreage growth is being outpaced by production decline? I'm not quite -- I want to get a feel for how confident we should be about production steadily increasing, because we know that if acreage stops, production stops fairly shortly afterwards. And is there any fine [ph] amount of land [ph] where I see?
I'll use the Barnett Shale as an example because that's an area where drilling rigs are really slowed down. They haven't slowed down as much in the Marcellus, there's still quite a bit of drilling going on. But in general, what you saw, and this is the difference between unconventional plays and more conventional, high-perm, offshore-type plays, where, when you shut the rig down, everything drops like a rock. And in old established production, low-pressure mountain West Texas. But you saw in the Barnett when that happened, we dropped the rigs from 200 down to 50 and production continue to increase, partly because of all the wells that hadn't been completed yet. But also because the decline rates aren't as steep, they're steep early on, but that's over with fairly quickly. Once you -- once the well starts to level out, then the decline is very stable, not steep at all actually. And so that's the reason why we can build so fast, it's because we're not actually using that many drilling rigs and drilling that many wells. We get people asking us why don't we drill more, more and more, well, we're increasing production significantly with the wells we're drilling. And so, we really don't see that huge decline rate. We see initial -- the initial decline, well, it levels out quickly.
Mike, can you help us get a feel for where you are in terms of maximizing efficiencies? So you talked about 3,200-foot laterals in the wet window, and I think 3,800 in the super-rich. Have you determined that's the ideal lateral length, the number of frac stages? And then also, what percentage of your wells are drilled off of pads, and when do you expect to be fully on the pad development?
We don't have it fully figured out. I don't know if anybody here ever gets there. We're continually reiterating, trying to do better. And then you move to a different area and the rock's a little different and things change, and so -- and then you make a change there as well. So I'm not going to save 3,200 feet and 18 stages is awful [ph] by any means. What we do know is that for a rate of return perspective, it's fantastic. We can work off of that. A lot of times, we have issues. Even though we've got a ton of acreage, there are issues with how it's located, how things are situated, we may be somewhat limited on lateral link. So what we've seen primarily, especially in the dry area, is pretty much 1:1 relationship of more lateral, more stages, higher and higher EURs, maybe 2 Bcf per 1,000 feet or something along those lines. Once you get out to 5,000-plus feet, then you may start seeing that 2,000 Bcf -- or 2,000 -- or 2 Bcf per 1,000 feet start to drop. Once you see that, then you kind of realize you're hitting the maximum because you're not getting the feed in from the total lateral and those sort of things. So we have -- in our dry areas, we are planning to drill longer and longer and longer. In our wet and super-rich areas, we're really kind of focusing the stages down, doing more and more stages, reduce cluster spacing. The other part of your question?
What percentage of the wells are drilled off the pad? And when do you expect to be at full pad development?
I would say by the time we're coming back and doing the Upper Devonian, we're going to be at full pad development. We're, right now, we are in the holding acreage mode. So we're probably drilling, on average, about 1/2 of the wells we're going to drill on the pad. So once we've completed holding acreage and -- we combined that with production. There are certain times where we may drill 8 wells on the pad, in an area where we've got pipeline ready to go and we've got capacity and we know we can get the production to sales. So we do have to play that game and try to optimize where we drill the laterals. But as I think you're alluding to possibly, things will get significantly more economical once we're coming back to these pads and they'll have to rebuild them.
[indiscernible] improving? I know you have NGLs broken out, but I'm just curious as to -- is that a component of leaving some ethane in the stream and getting paid on the gas price for it? Or is there something structural going on with your gas price realization?
Do you want to handle that, Laith?
Yes. Some of that is just seasonality. What you're seeing in -- up in the Northeast is you get seasonally higher prices. And as the Marcellus becomes more and more of your production, you're just seeing that. Really, in the fourth quarter, first quarter is where you saw our realizations kind of add a premium to the hub. Some of it is that you're leaving the ethane in the gas, but it's also, there's just some seasonality to it.
William A. Featherston - UBS Investment Bank, Research Division
Are there any more questions for Mike? All right. Thank you very much.
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