山脈資源 (RRC) 2012 Q2 法說會逐字稿

Welcome to the Range Resources second-quarter 2012 conference call. This call is being recorded. All lines have been placed on mute to prevent any background noise. 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. 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. Rodney Waller, Senior Vice President of Range Resources. Please go ahead, sir.

Thank you, Operator. Good morning and welcome. Range reported outstanding results for the second quarter with a continued increase in production and a decrease in unit cost. Both earnings and cash flow per share results were greater than first-call consensus.

Our speakers on the call today are Jeff Ventura, President and Chief Executive Officer; Ray Walker, Senior Vice President and Chief Operating Officer; and Roger Manny, Executive Vice President and Chief Financial Officer. Also, Mr. Pinkerton, our Executive Chairman, is on the call today. Range did file our 10-Q with the SEC this morning. It's now available on the homepage of our website 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 our adjusted non-GAAP earnings to reported earnings that are discussed. We have also added tables which will guide you in modeling our future realized prices for natural gas, crude oil and natural gas liquids. Detailed information of our current hedge position by quarter is also available on the website.

Now let me turn the call over to Jeff.

Thank you, Rodney. I'll begin with an overview of the quarter. Ray will follow with an operations update and Roger will be next with a discussion of our financial position. Then we'll open it up for Q&A. Range is on track to achieve the targets that were set for 2012 for overall production growth and capital spending. Our capital expenditure budget for 2012 is on track and remains unchanged. Our production growth target of 30% to 35% now has moved to the high side of the range and is 35%. Our exit rate for the Marcellus should be 600 million cubic feet equivalent per day or greater. Our liquids production growth target was delayed due to permitting issues. However, we expect for the fourth quarter that liquids growth will be 40% versus the fourth quarter of 2011.

On the cost side, our teams are doing an excellent job and costs are coming in better than expectations. LOE per MCFE continues to decline dramatically from $0.60 per MCFE in 2011 to $0.48 in the first quarter of 2012, and $0.40 in the second quarter of 2012. Our total cash costs per MCFE is also following the same downward trend from $2.61 in 2011 to $2.50 in the first quarter of 2012, and finally to the $2.38 per MCFE in the second quarter of 2012. Our DD&A per MCFE has also been reduced from $1.80 per MCFE in 2011 to $1.67 in the first six months of 2012. These are both very impressive numbers and a very impressive trend.

Our teams are also making important progress on the marketing side of our business. We continued to negotiate on a third ethane solution and we believe we are close to finalizing the deal. In addition, we are well hedged for the remainder of 2012 and '13 for all three products -- gas, oil and natural gas liquids. The details of our hedge position are listed on our website. This includes how we've hedged both the light and heavy end of the NGL barrel. As we continue to focus on optimizing our portfolio, we have engaged RBC Richardson & and Barr to market our Ardmore Basin Woodford properties. We have about 9,300 net acres of liquids-rich Woodford properties that are currently producing about 12.3 million cubic feet equivalent per day, of which about 54% is liquids. Our Ardmore Basin Woodford properties are high-quality properties.

However, our current focus in the Mid-Continent is on our horizontal Mississippian play where we are achieving outstanding results. The position we have in the horizontal Mississippian consists of 152,000 net acres and therefore has much greater upside per share. In addition, although the rate of return in the Ardmore Woodford is very good, the rate of return in our horizontal Mississippian play is even better. The decision to market the Ardmore Woodford properties, assuming we find a buyer that recognizes the value in these properties, both increases our focus and fast-forwards the value we would have received from these properties.

The results we are achieving in the horizontal Mississippian play continue to improve and impress. The average result of our 2012 drilling program is significantly better than our first eight wells. You can view the 2012 curve as compared to the first eight wells on a slide included in our current IR presentation on our website. Also during the second quarter, we drilled our first horizontal Mississippian well in excess of 1,000 barrels of oil equivalent per day. Its peak 24-hour rate was 1,363 barrels of oil equivalent per day. The liquids portion of this rate was 1,122 barrels per day, comprised of 782 barrels of oil per day, and 340 barrels of natural gas liquids per day.

We're also making good progress in the super rich and wet areas in the southwest portion of the Marcellus, along with the dry gas portion of Northeast Pennsylvania. In particular, we just recently completed a new well in the super rich area that flowed at a rate of 5.7 million cubic feet of gas per day and 1,000 barrels of liquids per day, of which 55% is condensate. Ray will discuss these areas in more detail. And he'll also update you on our first two Upper Devonian wells in the super rich area in Southwest Pennsylvania. In addition, we are currently drilling our first Utica well in Northwest Pennsylvania and started drilling our next series of Cline Shale and Wolfberry wells in West Texas.

There is one other area that I especially want to mention. To date, we've given you production plots for the dry gas area in Northeast Pennsylvania, and the wet and super rich areas of Southwest Pennsylvania. In our IR presentation on our website, it states that we have 570,000 net acres in Southwest Pennsylvania. We believe approximately 335,000 net acres here are prospective for wet or super rich Marcellus. And 235,000 net acres are prospective for dry gas. We haven't talked much about the significant dry gas position, but recently we drilled and brought online two pads that are just on either side of the wet dry line, of 1,050 BTU gas. One is just on the dry side and has 1,040 BTU gas. This dry gas pad has five wells that averaged 14 million cubic feet per day per well, for an average initial 24-hour rate to sales. And it appears the reserves for these wells will average seven to eight BCF each.

The other pad is just over the wet/dry line and has a BTU content of 1,065. This 10-well pad has an average IP of 13.7 million per day, for its initial 24-hour rate to sales. And also appears to have average reserves of 7 to 8 BCF per well. These two pads are about 35 miles apart. My point is that we've tested over a dozen wells on the edge of the dry side of our acreage in Southwest Pennsylvania, and we believe the quality of these wells is excellent.

Our teams continue to deliver outstanding results in the field. Financially, Roger and his team are very disciplined and focused on maintaining our liquidity and strong financial position in order to run the business. Our hedges are a key component of our strong financial position, which allows us to execute our capital program as planned. Keeping Range financially strong while we grow reserves and production per share will always be a key principle of our business plan.

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

Thanks, Jeff. Today I'm going to talk about production, efficiency improvements and give some additional highlights on our activity. Let me start with production. We exceeded our second-quarter production guidance coming in well above guidance on gas and oil, but lower than expected NGL production. The lower NGL growth was primarily due to permitting delays for pipelines and stream crossings in Pennsylvania. The good news is these permitting issues have been resolved by overcoming new residual impacts to the policies that were left over from the previous administration. We give a lot of credit to BEP leadership in Harrisburg for recognizing and then resolving these issues. We can now plan more effectively, and we do not anticipate these permitting delays in the future. As a result, we fully expect to see substantial growth going forward as those delay pads begin to come online.

By the end of this year, we expect to reach 40% liquids growth when comparing the fourth quarter of 2012 to the fourth quarter of 2011. Because of the delays, we will not hit our 40% full-year over full-year target, but we are back on track for impressive quarterly liquids growth. Guidance for the third quarter production will be 773 million to 778 million cubic feet equivalent per day. Comprised of NGLs at 18,300 to 18,600 barrels per day. Oil at 7,600 to 7,800 barrels per day. And gas at 618 million to 620 million cubic feet per day. In addition to our record production, another key story I want to tell is how we're significantly improving efficiencies in cost while delivering better well results all across the Company.

Let me give you just a few of the many examples that we're seeing. In the southern Marcellus, we've seen a 23% decrease in cost per foot drilled, while drilling 22% longer laterals in the second quarter as compared to the first quarter. Also, in the southern Marcellus, during the same timeframe, while pumping the same size jobs, we've seen the completions team perform 22% more frac stages. While at the same time introducing initiatives that we expect will reduce completion capital for the remainder of this year by over $4 million. In the northern Marcellus, drilling costs per foot has decreased by 21% from quarter one to quarter two. And we've seen a 25% decrease in completion costs per stage by optimizing our completion designs.

In our Mid-Continent division in the horizontal Mississippian we've seen a 25% decrease in drilling days, allowing us to effectively double the length of our laterals and increase the number of frac stages with a very modest cost increase. I'll give you more of those details in a few minutes. In our Permian division, we've drilled three Wolfberry wells and have already seen a 24% reduction in total well costs. In Virginia, from 2011 to 2012, we've seen an 11% improvement in total well costs while drilling and completing 13% longer laterals in 26% less drilling days.

We also continue to make great progress on our safety program. Our total recordable incident rate is 51% below our peer group. And our lost time incidents are 35% below the peer group average. While we continue to strive for zero incidents, we are really proud of our team and their focus on safety and environmental protection. That culture will play a paramount role in keeping us performing at a high level while remaining a low-cost and high rate of return producer.

Now, let me highlight some of the results that we are seeing across the Company. Please refer to our press release as we list the results of some really great wells. I'm not going to repeat those results in my remarks here, but they are certainly noteworthy and some great wells that we are really proud of. Also, please refer to the new presentation on the website as we have specific details in there for all of our projects.

In the super rich Marcellus, we had a really nice well recently tested at 5.7 million gas and 1,000 barrels of liquids excluding ethane. We have now brought online 11 wells in the wet and super rich area this year at over 500 barrels per day of liquids, not including ethane extraction. The super rich and wet Marcellus continues to deliver excellent results. Jeff highlighted some very impressive dry gas well results, which give us confirmation of the potential reserves for the 235,000 dry gas acres that we have in Southwest, PA. In the northern Marcellus we are continuing to see outstanding results with good economics, also confirming the significant resource in place there. The Marcellus has proven to be a great asset across our entire position, with class-leading rates of return and tremendous resource potential.

The horizontal Mississippian oil play, likewise, is progressing very well. Our team there is optimizing quickly. We are now drilling and completing approximately 4,000-foot laterals with more stages and making better wells. While seeing only a modest increase in total well costs to around $3.2 million, which is excluding the salt water disposal. And we fully expect that those costs will come down even more as we get more wells under our belt. As shown in our new corporate presentation, our 2012 wells are performing significantly better than our previous wells. And although early, we believe they could be as much as 600,000 BOE wells. That would mean a 25% improvement in well performance with a very modest 10% increase in costs. This is amazing progress and only six wells.

The team is continuing to optimize midstream and power infrastructure along with implementing improved salt water disposal, production designs and operations. We believe our team can continue to produce these wells at very low operating costs compared to the more traditional designs. And we are already recognizing significant benefits in costs and efficiencies.

In the first super rich Upper Devonian shale well, we confirmed a 300-foot section with a similar volume of hydrocarbons in place as compared to the super rich Marcellus. Given the thickness of this interval, which is three times thicker than the Marcellus, and understanding that the shale is in multiple layers, where to land the lateral in the section is complicated. The first well tested at a 24-hour rate of 1.9 million equivalent per day, which was composed of 1.3 million gas and 116 barrels of liquids from a 3,300-foot lateral with 16 stages. Now, let me put this in perspective. These results, although less than we hoped to see, are significantly better than the first four horizontal wells that we drilled back in the Marcellus in 2006 and 2007. We learned early on in the Marcellus that targeting was important. And it took more than a few wells to figure that out, and in fact, we're still optimizing our target in the Marcellus even today.

From an appraisal standpoint, we are pleased with the data we've gathered from the Upper Devonian in the super rich area. Mud log data indicates excellent gas shale, some of which are the best we've seen in the Upper Devonian section to date. Log data shows substantial porosity and permeability. Analysis of cord intervals has documented large pour development in each of the key shale members, therefore validating excellent porosity and permeability development. Using what we've learned from the first well and analyzing all the data and diagnostics from both wells, we believe we have a better target interval in the second well. We've also optimized our lateral length and adjusted our completion design based on what we learned. We are now completing that second well and hope to be ready to discuss those results at our next conference call.

Our first wet Utica well in Northwest PA is underway, and we still plan to spud a second test well in about October. We continue to monitor industry activity in the area and believe by the end of this year we'll know a lot more about the potential of the wet Utica and our 190,000 net acres. In our Conger Field properties, we've drilled one Wolfberry well, which is being completed as we speak. And we're drilling a third Cline Shale horizontal, as we speak. Please take a look at the updated Wolfberry economics in our presentation, as we've seen improved well performance as well as good cost reductions.

Our Cline Shale EUR average of the two producing wells is 340,000 BOE. And we've also updated those economics in our presentation. Plans are to drill four more Wolfberry Wells and maybe one more Cline Shale well this year. We also see lots of offset activity in this area and are monitoring that activity, as well.

As you can tell, I'm really proud of our operating and technical teams. They continue to execute, innovate and improve efficiencies. Cost and well performance are steadily improving while working safely and protecting the environment. We are able to do more with less while getting better at what we do. And we have some great rate of return projects. All of that combined should enable us to meet our production goals and grow at very attractive returns for many years to come.

Now over to Roger.

Thanks, Ray. Like last quarter, there are significant positive developments to discuss on both the income statement and balance sheet. The big income statement story is our continued progress at reducing operating and overhead costs without sacrificing per share growth in production and reserves. This was a great quarter, where most of the recurring cost items all came in at or below guidance. And in some cases, significantly below guidance.

Leading off with direct operating costs. The operating teams exceeded all expectations. With direct operating costs including workovers coming in at $0.40 per MCFE. That's $0.25 per MCFE below last year due to reduced water handling, equipment rental and well service expense. To help put this in perspective, on an absolute dollar basis, we spent $3.7 million last on direct operating expense during the second quarter this year compared to last year, on 42% higher production volumes. We are now seeing the benefits of focused growth from a continually high-graded asset base by employee shareholders who understand what is required of them in a low price environment. As we add additional oil and liquids rich production the rest of the year, absolute operating costs are expected to increase slightly with production. And unit costs will likely also increase slightly. Next quarter, we believe we will see operating expense in the range from $0.42 to $0.44 an MCFE.

Third-party transportation, gathering and compression expense for the second quarter was $0.68 per MCFE, the same as the first quarter of this year. And $0.02 higher than the second quarter of last year. We anticipate this expense to decline slightly on higher volume next quarter, to between $0.63 and $0.65. Second-quarter DD&A rate was $1.66 per MCFE, slightly below guidance and $0.03 lower than the second quarter last year due to changes in production mix and the Barnett assets held as discontinued operations in the second quarter of 2011. The steadily declining DD&A rate is further evidence of improving capital efficiency. We project DD&A next quarter to hover in the $1.66 to $1.68 range, again depending on production mix.

Listeners may recall that the way we're handling the new Pennsylvania impact fee guidance is to provide a specific absolute dollar quarterly estimate for the impact fee. Plus a quarterly production tax estimate for non-Pennsylvania production on a unit cost basis spread across total Company production. The second-quarter Pennsylvania impact fee was $7 million and production taxes on the non-Pennsylvania production, reflecting lower oil and gas prices, totaled $0.07 per MCFE. For the third quarter, we expect the impact fee to be $6 million plus $0.10 per MCFE on total Company production as we bring on more production and higher tax rate areas.

Second-quarter G&A expense, adjusted for noncash stock comp and other nonrecurring items, was $0.47, $0.12 below last year and $0.03 below the first quarter this year. The decrease in year-over-year unit cost G&A expense is due to lower legal fees and lower unit cost salary and benefits expense. Third-quarter G&A expense per MCFE is projected to be $0.46 to $0.47. Interest expense for the second quarter was $0.66 per MCFE, $0.10 below last year's second-quarter figure/ With higher borrowing levels at slightly lower rates, spread across higher production volumes.

Exploration expense, excluding noncash comp in the second quarter, was $15 million, $4 million higher than the second quarter of last year due to higher seismic expenditures. We have additional seismic expense coming through in the last half of this year, making our best estimate for third-quarter exploration expense approximately $20 million. The second quarter impairment on unproved properties was $44 million. Of this amount, $21 million was ordinary calculated quarterly impairment expense. And $23 million was a special provision attributed to an acreage high grading transaction. In this transaction, we exchanged our drilling rights and obligations on some non-strategic Marcellus acreage for Marcellus acreage in a high-quality de-risk area where we are actively drilling. The net result was, in our view, a smaller number of higher-quality acres. Next quarter, we expect unproved property impairment to be back in the Range of $20 million to $22 million.

Cash flow for the second quarter was $156 million. That's $12 million below the second quarter of last year. On a fully diluted share basis, cash flow was $0.97, $0.02 above analyst consensus estimates. EBITDAX for the second quarter was $196 million. $5 million lower than the second quarter of last year. Cash margin for the quarter was $2.34 per MCFE. And earnings calculated using analysts methodology were $18 million or $0.11 a share. That's $0.06 above the analyst consensus estimate, thanks to lower costs. As Rodney mentioned our website contains a full reconciliation to these non-GAAP figures to GAAP. In addition to updated hedging schedules and other useful investor information.

Turning briefly to the balance sheet. We began to draw upon our $1.75 billion credit facility in the second quarter, to help fund the front-loaded 2012 capital program. At the end of the second quarter, we have 141 operating wells awaiting pipeline connection or completion. The capital spent on these wells approximates one-third of our total annual capital budget. Spending one-third of the front-loaded 2012 budget with no contribution to year-to-date production of cash flow, when combined with lower realized prices has taken our debt to EBITDAX ratio to 3 times a bit earlier in the year than you might have expected. And we remain comfortable with our leverage hovering around the 3 times EBITDAX level, thanks to our high-return plays, low cost structure, long reserve life, operating control of our growth assets, and our favorable hedge position. However, as has been our practice, when our leverage exceeds the 3 times level, as it did before the Barnett sale in 2011, we will advise you as to how we intend to manage the leverage going forward. And as Jeff mentioned, we have commenced the marketing process for our Ardmore Basin Woodford Shale properties when, which when completed, as we expect, will help manage our leverage. While at the same time fast-forward net present value.

EBITDAX should grow as completed, already paid for wells are turned to sales. And the combination of asset sales and higher EBITDAX should help bring the leverage ratio down towards the end of the year. Looking at our hedges for a moment, Range has continued to build upon its hedge position during the quarter by adding new hedges in 2012, 2013 and 2014. For the remainder of this year we have more than 80% of our projected gas production hedged at a floor price of $4.18 an MMBTU. Approximately 60% of our NGLs hedged at above market prices. And approximately 80% of our projected oil production hedged at a floor price of $91.19 a barrel. Please reference the hedging schedules on the Range website for the new and existing hedge volumes and prices.

In summary, the second quarter demonstrates the commitment of all Range employee shareholders to meet the challenge of lower product prices by reducing an already low cost structure. While still producing double-digit per share growth in reserves and production.

Jeff, I'll turn it back to you.

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

(Operator Instructions) Dave Kistler, Simmons & Company.

Real quickly on the comments about leverage that Roger made, as you start to look towards '13, in the past you've highlighted you can live within cash flow and deliver maybe 15% to 20% production growth. However, it seems like there is a willingness to go outside of cash flow. Should we be looking at that leverage metric to determine how far you guys would go outside in ' 13? Or could there be a decision to start living within cash flow by '13? Any color you could give us there would be great.

This is Jeff. Let me start and then Roger will add his comments on at the end. Let me put it in context. Back to this year, we're taking it to a really high level. Our strategy is to stay focused on growing reserves and production per share within some of the highest rate of return and lowest cost plays out there. This year, we are looking at 35% growth, outspending cash flow in what most people would recognize are two of the best plays, if not the best plays, in the industry. The Marcellus, particularly the wet part, and the horizontal Mississippian oil play.

Next year -- and we won't set our budgets until later this year, but we're obviously working ahead and we're planning ahead. And we said it earlier this year. We have the opportunity, if we choose to do so, to live within cash flow and still grow 15% to 20%. And we believe we can still do that. So it brackets off a couple of different spots. here's where we are this year, if we choose to do that next year, we have that ability.

But let me put that in context and I want to talk about it in a number of ways. One, another advantage of Range is we control or operate every area we have with the single exception, really, of Nora. So outside of Nora, we operate typically with a high working interest or 100%. So we really have the ability, even if we choose to live within cash flow next year, or something close to cash flow, to really shape our growth to what prices ultimately do in order to capture NAV. We have the ability and we have great operating teams led by Ray that can ramp up quickly, if we choose to do so, and capture NAV. If we keep spending down for a year, a year or two or a year, we have the ability to ramp up significantly. And you can see this year what the quality of the portfolio can do.

I think another key thing to really look at, too, if you go up to the 100,000-foot level and you look at the various plays that are out there, if we were strictly focused on maximizing growth in all these plays, the highest growth areas are the dry gas parts versus the liquids-rich parts. And they're typically the thickest, gasiest, highest pressure parts, whether its the Barnett Shale, the Marcellus or Haynesville, or you pick it. So that's where you get the best growth. And what's really impressive is if you look at the quality of some of our gas properties that we've talked about, literally if we were only focused on growth -- and we aren't, we are focused on rate of return and we are focused on a lot of other things -- but if we only focused on growth, what we would do is direct 100% of our drilling into the dry gas areas. And rather than growing within cash flow at 15% to 20%, theoretically, you could probably double that. Probably be 30% to 40% or where we are today.

But importantly, what Range is, is we're really focused on maximizing rate of return. And given today, that oil prices are high and gas prices are low, in order to maximize rate of return, what we're doing is focusing on liquids. In fact, you can see us, we're dropping rigs in the dry gas areas and focusing predominantly in the wet or super rich parts of the Marcellus or horizontal Mississippian play.

But I think a really key part -- again bringing it back to Range -- is Range is in a great position. We have great potential in both oil and gas. Just in the Marcellus alone, we talked about what we have in the wet and super rich part. But if you look at the dry gas part in the Southwest, there's 235,000 acres plus another 180,000 in the Northeast. So we have 415,000 acres of dry potential in the Marcellus alone. And then if you look at the super rich and wet combined just in the Marcellus, that's 335,000 acres. We've got tremendous running room with really strong rates of return both ways. With the ability and flexibility to direct our capital off into the future, including the rate of production growth. Plus we have 152,000 net acres in the horizontal Mississippian.

So I'm reaffirming that we have the ability to do that if we choose to do so. We'll continue to work it through the end of the year. We'll look at the results of our projects. We'll put together a plan that we think optimizes value for our shareholders based on our core values of growth and reserves per share, production per share, both at adjusted rate of return, holding acreage, all those considerations. And we'll present that to our board in December. And typically we've come out with our 2013 plans early, be early in 2013. Whether we accelerate that a little bit and do it right at the end of this year or early next year, like in previous years, we'll decide later this year. But Range is in great shape. We've got high rate of return projects in multiple areas. And what we're trying to do is just bracket off a little bit of some of the flexibility that we have. Let me turn it over to Roger to discuss further.

Yes, Dave, just a comment on the leverage. Clearly the leverage in 2013 is going to be a function of where we set the drilling throttle and where oil and gas and liquids prices are going into next year. And since we haven't set the drilling throttle yet and we don't know where prices are going to be, it's a little hard to predict where the leverage is going to be. But we have committed to keep the balance sheet strong and that's what we're going to do.

And as I mentioned, when the leverage gets in that 3 times range, while we are fully comfortable in that range because of all the factors that I mentioned earlier in my remarks, we are going to tell you what we intend to do to manage it going forward. And in this case, that asset sale is a big part of that. So we'll see how the asset sale goes later this year. And then we'll see where the drilling throttle needs to be set. And then leverage will be somewhat of a byproduct of that. But when you look at the EBITDAX build that results from bringing these wells that aren't on production yet on production, that EBITDAX build will help to bring leverage down, as well. Along with the asset sales. So we're very comfortable with leverage where it is presently.

Great. I appreciate that color. And then maybe just one follow-on. The Mississippi results that you outlined, both in your release and then in the presentation, on the longer laterals generating over 100% rates of return at the current strip, it would seem to me it would make sense to be redirecting activities there, than many of the other plays just from a rates of return comment that you guys both made. Can you talk a little bit about your thoughts on that? Does that encourage you to buy more acreage? You added another 7,000 acres but should we look at this as becoming a much bigger part of the portfolio on a longer-term basis?

This is Jeff. Let me start again and then Ray will probably add a little more color. Yes, I think the key thing is to look at the position we've built. And you can go through some simple back-of-the-envelope math that I've done with several of you at conferences. And that could be 1 billion to 2 billion barrels type of resource potential on upside. It's huge, particularly for a company our size. Coming with rates of return that you mentioned. So what you're seeing is we'll be at increasing activity there.

And we think it's a great play. We've got a great team up in Oklahoma City that manages it. We've been in that area since 2004, so we've got infrastructure, office, good local knowledge. But I think what you'll see, as we continue to drill, and assuming continued success, which I believe we'll have, you'll see us ramp up activity throughout this year. Again, we haven't set our budgets for next year. And we'll continue to look at that and present to the board late this year. But it wouldn't be unreasonable to think that we could run something in the order of 5 rigs next year and maybe the following year, 2014, maybe going to 10 and the following year to 15. If we follow a schedule like that, that allows us the opportunity to not only hold that acreage but really significantly ramp up our oil production NGLs. And you get great rich gas with that. So Ray, you might talk a little bit about things we have in place and things we're doing to start leading us down that path.

Yes, David, this is Ray. I think the results that we've seen so far this year are really impressive. Our guys have done a great job thinking through the future. We did a really good job, we were really disciplined in the way we put those leases together up there. We stayed very disciplined in making sure they were consolidated. Because we knew handling salt water and all those things was going to play a big role in the economics of the play. So it's taken some time to really put a lot of those corridors together, to put a lot of those plans in place, to get the midstream infrastructure and power infrastructure and all of those things in place.

One of the things that we don't want to be guilty of is just going fast for the sake of going fast. We're trying to take a very disciplined approach and ramp up as it makes sense to ramp up. In other words, we don't want to bring rigs in, complete wells and then not be able to flow them. So that play is really dictated a lot by handling a lot of fluid at really cheap prices to get that oil production. And so I think the guys have got an excellent plan. I'm really confident in what they're doing. And like Jeff said, I think we do have some pretty aggressive plans in the future to ramp that play up. And I think you'll start hearing and seeing that as we get into the early part of next year. You'll start seeing that really happen pretty quickly.

The other thing, if you look at on our website, Ray talked about a very efficient plan that we have. There is a diagram in there that shows that. And the other thing, when we finally release our specific detailed land maps, like we have in the Marcellus, I think you'll be impressed with the big blocky dominant position we have. And obviously the early drilling looks great.

Great. I really appreciate the color. One just last one. On the Miss line, how do you guys think about the NGLs and how you're going to manage that in that area of the country? I know you've been very focused on it up in the Marcellus, but any color you can give us with respect to NGLs, pricing outlook, around the Miss would be helpful.

One, I'd say again, we have a high liquids component and a big piece of that is oil. We have two facilities in place able to handle and process liquids and NGLs. And with a third one that will be up by the end of the year. So we have good diversity, we have a strong marketing team. And I think really we'll be in good shape there.

Great. I appreciate the color, guys. Thank you so much.

Brian Lively, Tudor Pickering Holt.

Just a follow-up on the 3 times debt to EBITDAX commentary. Just wondering if that's your covenant levels or is that just the internal comfort from the management team?

Yes, Brian. This is Roger. Our covenant is 4.25 times. So it's clearly a management comfort level. We talked with rating agencies. Everybody's comfortable with us being here in the low 3s. Using that financial flexibility. That, quite frankly, financial flexibility to us is a lot more than just having a $1.75 billion committed credit facility under a $2 billion borrowing base. It's the cost structure, it's the hedging, it's the operating control. As I say, being able to set the drilling throttle where it needs to be. All those factors together make us very comfortable being in that low 3 range. But we're not going to come anywhere near the covenant limits. That's just not the way we do things.

Right. So if we're thinking about 2013, and I know it's a function of commodity prices, but do you guys expect to use the 3 times debt to EBITDA as the throttle, such that we would either have to look at slowing activity or doing more asset sales in terms of keeping the leverage below that ratio?

I think at this point it's a wait-and-see game. We'll see how the asset sale goes. And we'll just play it accordingly. One of the big factors that's different about Range is when you look at our reserve to production ratio, whether on a total approved reserve basis or just approved developed basis, our ratio is about double the other shale players. And that's really indicative of the quality of our plays. And also the diversity of the plays. We have a lot of assets contributing a lot of value to the Company. We've sold $1.8 billion in assets in the last 10 years. And we are not in love with our assets. So if it comes down to making some of those hard decisions, we'll make them just like we always have.

Yes. I think another key point, too, is our strategy has been growth at low cost on a per-share basis, debt adjusted. And really the other part we say periodically, build and high-grade the inventory. Like Roger said, over the years, we've added in, not only sold $1.8 billion worth of properties, we added in things like the Marcellus. We added in things like the horizontal Mississippian. I think in the future, the St. Louis looks pretty exciting. We're looking at the Cline, Utica, the Upper Devonian. So it's that constant process of building shareholder value by adding in higher quality plays and periodically divesting of things that either no longer are competitive in our portfolio or that we're not going to fund anymore. Even if they're quality properties. Like the Ardmore Woodford, great properties, just small position for us and it's going to be worth more to somebody else than us.

And are there any properties right now that you guys are thinking, given the high grading that's happened? Are there any other properties that you could think of that are moving more to non-foreign to be monetized?

Sure. We always look at our portfolio. We always fore-shrank it. We look at the upside. We look at the other potential. And we make that decision. I'm not on the call today going to talk about what that is. But, yes, we absolutely. Chad Stephens and his team are on top of that.

And just final question and I'll hop off. But if you were to keep CapEx flat in 2013 versus 2012, do you have a sense of what growth would look like?

One, we haven't made all those iterations. Like I said, a lot if it ends up on where you end up focusing. If we focus in the liquids-rich portion, and we stay within cash flow, we would grow on the order of 15% to 20%. If gas prices moved up substantially, and we added in a bigger component of that, you can see this year for that amount, we are growing at 35%. Like I said, if you just focused 100% on dry gas, literally you could theoretically probably double the numbers we have. But it's early.

Right now, I think we're doing exactly the right thing. We're staying disciplined. Oil prices are still high. Gas prices are relatively low. Moving into our liquids-rich areas in Southwest Pennsylvania and focusing on the high rates of return there, as well as great rates of return, like Dave Kistler mentioned earlier, in the horizontal Mississippian, I think is the right thing to do.

The other thing is if you look at our company our size, we are a [90-10 billion dollar] company depending on the stock price in the day. We've got such a huge position that is predominantly de-risked. And again, you can look on our IR presentations, but we've literally got the opportunity to grow tenfold from where we are today. We're only a 5 PCF company. And not counting ethane or those things we've got the opportunity, or resource potential, to grow 44 to 60 Ts. And again, some of the highest rate of return plays out there.

If you focus in just on the Marcellus Shale, we've got the opportunity -- and we're only a 5 PCF company -- our net resource potential in the Marcellus is 24 to 32 TCF. That's massive and it's largely de-risked. This is a play now that is basically the largest gas field in the United States, and recognized by most as the highest-quality, too So we've got a great portfolio. We will continue to work it as we go throughout the year. We'll work it internally with the divisions on what we think maximizes shareholder value, present it to our board and then let you guys know. But we are in great shape.

As always, thanks for the comments.

David Tameron, Wells Fargo.

Can you guys just talk about your drilling plans in the Cline? It looks like you shift a little bit from Sterling over to Glasscock. Can you just talk about the reasoning behind that, if I have that correct?

Let me start out again and Ray may want to pile on. And I probably shouldn't start every time, so I've got to let Ray and Roger start some. I get excited, you can probably tell. If you look at our legacy -- really what you're describing is predominently our legacy position in Conger Field. Conger Field straddles the Sterling/Glasscock line. So we've got a big position. About 90% of it's held by production. And so far, we're excited by our first two wells. The other neat thing, if you look at that, is there's a lot of drilling off on the western side of us. And Devon has got a 500,000-acre position just east of us basically. So we're surrounded by -- and there's a slide on the website that Ray and Roger are looking at right now that shows our activity relative to Laredo and Concho and Devon and others that are out there.

So what we've done literally is just scattering a few wells across our acreage, because the interval itself is relatively consistent. It's 270 to 330 feet thick across the entire 100,000 acres. And we believe it's got a lot of hydrocarbon in place. So what we're doing is just trying to look across a large area from our wells, and we're going to factor in what our competitors are, and partners. And hopefully we'll share some data with them. It's got great upside, great potential, but the good part there, it's all HBP. So we have no rush.

The other thing I'd like to say, going to a higher level, it fits the Range model. We like to get in areas that have stacked pays, a lot of hydrocarbon in place. And getting really high-quality technical teams that just continually work on how to extract more and more of it out of the ground. That's the same model in Appalachia, same in Mid-Continent, same in West Texas for us.

Okay. It looked like earlier you planned on drilling some Sterling wells and all your wells have moved further west. Is that an indictment of Sterling or is it just more of a --?

I think maybe we're mixing wells. If you look on our presentation, on the slide, originally we had three wells planned in Sterling County. Those were Cline Shale wells. The wells on the western edge are Wolfberry vertical wells. And if you look at that slide, we got a little dashed line circling where the potential is for that Wolfberry. In our last conference call we talked a lot about that, how the Wolfberry vertical is really only potential over on the Glasscock County side.

So what you've seen is, with all of the offset activity, like Jeff was referring to, we basically are learning a lot from what's happening all around us. We've got tons of logs and scientific data all across this field, so we've logged the Cline Shale many times. And so really we're in a validation mode. It's HBP. We don't have to be in a hurry. The Wolfberry wells are looking really good. And we can stamp those out quickly. Make a good, decent rate of return. It's oil production. And so all of those reasons, what you saw us do was shift a couple of those horizontal Cline tests over and into basically drilling Wolfberry wells while we had that rig out there. So if you're looking at permitting activity that's probably what you're seeing.

And just to reiterate what Ray said, the entire 100,000 acres is prospective for Cline. The Wolfberry is just prospective on the western side. Still could be 100, 150 maybe 200 wells. But it's predominantly, the Wolfberry is just prospective on the side. Maybe that's what you were thinking.

Okay, yes. My bad. I think I misread that chart. One more question. Can you just talk about Lycoming. You originally talked, if you go back six months, you talked about allocating a big chunk of CapEx next year to that county. Now it sounds like you're reducing the rig count because of some of the issues you mentioned. But can you just talk about some of the challenges up there and why lay down a rig up in Lycoming?

This is Jeff. I'll start. I'm looking at Ray. He's laughing at me for jumping in. There's several considerations. The wells up there are great. The team has done a great job of ramping up reduction. They're phenomenal. We've got wells that average 10 million a day, big reserves. Some that are over 20 million a day. So we've got a great position up there.

But there's really two issues. One issue is, as good as the wells are, given where natural gas prices are versus liquids, if you look at on our website, you can look at the rates of return in the wet Marcellus in the Southwest in the super rich. And compare it to the Northeast. Even though the Northeast is good, because there's a lot of liquids that come with the wells, including condensate and NGLs in the Southwest, the rate of return's higher. Then you've got one other consideration too. Is you got the drilling for holding acreage. The two areas -- the only two areas, really in the entire Company -- we have to really drill a lot to hold acreage is in Southwest Pennsylvania, and in the horizontal Mississippian play. It so happens those are our two highest rate of return projects, so we'd be directing anyway.

The leases up in the Northeast tend to be a lot bigger. We are at a point where, at the end of the year, really, just by running one rig next year, there's continual drilling clauses because the leases are bigger. And some of the leases are as big as 20,000 acres. So literally one well per year will hold that in perpetuity. So there's no pressure to drill up there from holding the acreage that we want to hold, point of view. Coupled with just where oil and gas prices are now.

The good news is we got a great team. You got good economics up there. I believe gas prices, some of the analysts on the call are calling for $4 gas next year or maybe $4.50 the year beyond. So we've really got the ability to ramp that also. Like I said earlier, we've got high-quality gas assets, we've got high-quality oil assets, and within gas we've got high-quality wet gas and high-quality dry gas.

Okay. That's helpful. Thanks for the color.

Brian Singer, Goldman Sachs.

Looking at the NGL production trajectory here, the production's been relatively flat the last couple of quarters. And I just wondered, as we look ahead to the next few, particularly in the fourth quarter where you expect more and more meaningful ramp-up, could you quantify the amount of NGLs, non-ethane, that are currently behind pipe or from wells that have already been drilled? I.E., can you just talk to wells that may have already been drilled but from a propane and other NGLs perspective just aren't online today?

If you look at the press release, I think it lists the number of wells that we've got in Southwest PA. And I think there's something like 56 wells waiting on completion. And maybe something like 50 wells that are waiting on a pipeline hook up. And like I said in my prepared remarks, primarily the delay in bringing those pads online has been pipeline infrastructure. And that pipeline infrastructure has been delayed because of some permitting issues for the actual pipeline construction phase and the stream crossing part of that.

The good news is we've resolved those issues. To just come absolutely clean, we underestimated the impact of those, both us and MarkWest earlier this year. We just didn't allow enough time to get far enough ahead of those. So good news is we've worked with the EP leadership. They have resolved those issues. Now we have a predictable permitting process in place. We know how long it's taking. And moving forward, we don't expect to see that. I think another part of the good news -- and you'll see a significant ramp-up in NGLs in the third quarter and the fourth quarter -- is, as we bring these pads online that were delayed, they're literally sitting there just waiting for a pipeline to get there. And that part of it is really kicking into gear over the next quarter. Fourth quarter, I predict, will be much bigger than the third quarter just because it's going to take a couple of months for this stuff to start Domino-ing as we go forward.

But we should have a great fourth quarter.

Yes. Fourth quarter, just like what I said, we believe we'll see, when you compare fourth quarter of this year to fourth quarter of last year, we will see 40% liquids growth.

And that's all, incremental to get there, is all from basically wells that have already been drilled and it's just an easing of the midstream bottlenecks? Or is some additional drilling or some wells where you're not sure on what the NGL component is still required?

We are still drilling wells and so you've still got new wells coming into the mix as we go. But, yes, there is a big backlog of wells in the wet and super rich area where we were really trying to ramp a lot of this infrastructure up in the last 6 months to 12 months or so.

Great. Thanks. And then lastly going back to, I think it was David's question, just before, just to finish up on Cline versus Wolfberry. Is your decision to move, to shift a little bit more towards vertical Wolfberry from horizontal Cline because of a negative relative view on the Cline? Or is it because you just think you're going to get the information that you would have otherwise been drilling that well from others, other operators that are drilling around you?

I would classify it as two things. One is, we are seeing a lot of offset activity, more than we previously saw earlier in the year. And we do expect to learn some from that. And then I think the second reason is the Wolfberry wells are looking pretty good. And the team is doing a great job, costs are coming down. Just in three wells I think we saw -- I forget the exact number -- 24% cost reduction. And we believe that they're going to see significant cost reductions even in the next few wells. They've got some new ideas in drilling and completions. And so we really believe that the Wolfberry wells have looked so good. And since it's HBP acreage, and we know a lot about all of that already in the Cline, it just made a lot of sense to redirect some of that capital to get some of these Wolfberry wells drilled up front. And then just take your time with the Cline, learn from offset activities at the end of this year. We can look at it. And we still have the potential to drill another Cline well before the year is out. Right now we've just got that on the drawing board.

I agree 100% with what Ray said. Another point to add to that is, when you look at shale plays, the Wolfberry is just commingling a bunch of traditional horizons together in a vertical well. The Cline Shale is really a shale. So back to shale plays, and you got this interval that's plus or minus 300 feet thick. Typically what happens in successful shale plays, and not all shale plays work, but in the ones that do work, and you can see it in all of them, in Marcellus, Barnett, you pick it, as you continue to drill and learn, the results tend to get better. You learn, where do you optimal land it vertically in the Section, what's the length of the lateral, number of stages. And typically, as you're learning how to drive up production per well, and over a number of wells, typically, then you get economies of scale and you drive down costs.

For us it's a held by production position that we are excited about. In fact, we're really excited about it that the first two wells, rather than, for example, go back to the Marcellus, the first few wells there were awful. Our first couple wells here actually were pretty good and were economic even off of our first couple of tries. If you project forward, if you drill that 100,000 acres on 100-acre spacing, it could be 1,000 wells, could be 2,000 wells. So there's a lot of running room. It's a very exciting play and early on it looks like we've got a big saturated hydrocarbon Section, that the first couple of wells are good. But we don't have to carry 100% of the R&D, like we did in the early years in the Marcellus. We'll drill some wells but we'll also learn from our partners in the industry out there, or other companies in the industry.

That's great. And the strong vertical rates that you're seeing, is that a function of the multiple zones? Or are there other specific zones like the Wolfcamp where you think down the road it may make sense to drill horizontally?

It's a combination of all of them. It's just like any completion like that. Different areas show different results. But it's really a combination of all of it.

Not to say that down the road that you won't zero in on a horizon and try some horizontal wells. I think that potential is, too.

Absolutely.

Thank you.

Ann Cameron, BNP Paribas.

Just a question about the Mississippian. You released your IPs of your first two wells, and it looks like it was a breakout of about 60% crude. Yet your EUR is 25% crude. So I'm just wondering if you can comment on how fast the crude drops out of the production stream.

Let me start. Actually, we'll ask Alan Farquharson, who's the Head of Engineering. (laughter) But when you look at it on a high level, actually I think we talked about four wells. And it was the combined rates for four wells and then we zeroed in, obviously, on the one that was well over 1,000 barrels per day. And it had a very high oil rate in there. Again, the neat part is, very early on into the play, we had great results from 2,000-foot laterals. Now we've gone to, at least that one, close to 4,000-foot with more stages. And didn't cost a whole lot more. It's a Packers-plus type completions. So adding the stages and drilling the laterals isn't that expensive. But we got significantly better results. Shifting the curve up. It could be from 400,000 to 500,000 to 600,000 barrels. And therefore you can look out on line and the rates of return are much higher, like David Kistler, I believe, mentioned earlier. But, Alan, do you want to zero in on those projections?

And, I don't have the exact decline rate of the oil. But I think what you see is historically in a lot of these reservoirs, since it's a relatively completion drive reservoir, you're going to look at oil declining and your gas/oil ratio goes up over time. So over the long haul, over the life of the well, if you go look, as we looked at a lot of the vertical wells, you see the gas rate stay relatively stable but the overall gas/oil ratio is increasing. I'd have to go back and look and get a little bit more color on exactly what the decline rate is. But I can tell you this. It's not falling out of the bottom very quickly. So it is declining, is what you would normally expect it to do. And remember, since you look at that time zero graph, a lot of the production early on is going to be oil. So that gives you a fairly representative decline rate of what the oil's going to be. You're not going to see a significant change in gas/oil ratio that early over the first year. So if you honor the data that's in there, and use what the IP is, that gives you a relative sense of what it would look like.

And a couple of other comments. Obviously the economics that we have on our website include all of that. And have factored all of that in there. Plus, again, we're showing the zero time plots for all the wells that we've had so far. And what that historic data looks like.

Okay. Got it. And similar question, different play. The 33 wells that you brought on in Southwest PA look like they are 14% condensate. Which is a good bunch oilier than both your wet and your super rich curve. So, especially because I included five dry wells, and because the NGL cut is lower, could we see a change in composition for both of those type curves?

I'd say one thing what you're seeing is we are shifting where we are drilling the wells. So as we continue to move -- and there's a map in there again on the website that shows different BTU lines. And I think we denote 1,050, 1,350. But there's a gradation as you go across there. And as oil prices are high and condensate prices are high and gas is low, we've shifted a lot more of our drilling into the wetter areas. So yes, therefore, that could happen with time and we'll keep you updated on what those results are.

Okay. Thanks, guys.

Mike Scialla, Stifel Nicolaus.

I wanted to ask you a few things about your NGLs. You said you were close to an agreement on a third outlet for ethane. Can you elaborate on that at all?

Obviously we can't. (laughter). As soon as we can, Mike, we will put that out. Wish we could say more, but we can't.

Understand. It sounds like Enterprise is considering changing that Atex line from ethane only to Y-grade. Would that cause you to change your plans if that were to happen?

We've been focused on multiple outlets and multiple contracts. And, again, we've got a great team up there, led by Chad Stephens, who's here in the room with us, and his team. The guys that work for him do just a great job. Greg Davis, Curt Tipton and company. We continually look at those things. I think the good news is there's more and more options are developing in the basin. It's turning into, like I said, the largest gas field in the country. And ultimately, when you consider the other horizons, has the potential to be the largest gas field in the world. We've got a great position. More and more of those options are developing, all of which I think ultimately enhance the value of our properties.

Okay. Fair enough. Let me switch over to the Utica. You were quiet about your Northwest Pennsylvania acreage for a while. Can you talk about maybe why that was? And why now that you're confident that you are in the wet gas part of the play out there?

That's a legacy asset that we've had for a long time, 25-plus years. I think over 300,000 acres in the shallow rights. We've had different teams, different divisions within the Company look at it over time. And essentially, through a group of events, more or less, when we sold the Barnett, we took some of those really highly gifted technical folks that were working on the Barnett and we said, why don't you go look at the Utica up here underneath the Northwest PA? We're bound to have some lease rights there. And lo and behold, they looked at it, saw good potential. It was about the time the stuff in Ohio was looking pretty good. And we have 190,000 net acres.

And so they've done a tremendous amount of really good technical work, putting together lots of information. Some of that's in the presentation where we've shown type blogs and we've shown that it's on strike, it's about the right depth. It's got a lot of the same characteristics as some of the successful wells over in the wet Utica and Ohio. So we think it's got a lot of potential. There's a lot of smart people that are in and around our position up there, leasing or drilling or testing some wells and doing some different things. And so we're at the point now where we believe it's got great potential. It could be phenomenal. We are essentially at the point where we really just got to get some horizontal wells drilled and tested and see what we would have there.

The well that we are currently drilling right now, we are doing a lot of diagnostics on it. And we'll be completing that well here in a month or so, once we get all that data in and look at it. And hopefully by the next conference call, we'll be able to talk about that and have some really great results. Assuming what we learn there, and everything we learn over the next couple of months, we've got another well tee'd up to drill in October. So I think when we get to the end of the year, like I said in my remarks, we'll know a whole lot more about that play and what the potential is going forward. And we can put into the portfolio. We don't have any of that in any of our resource potential right now. So we're really excited about the upside potential that we see there.

Okay, great. In the last call you talked a lot about your RCS completion technique. The improvement you were seeing there in recoveries. Is that something that you are continuing to implement? Is it becoming the predominant completion technique in the Marcellus? And also, have you tried it outside the Marcellus?

We have tried it to a limited extent outside the Marcellus. We're looking at more stages along the lateral in literally all these plays that we're looking at. While we have done it a lot, I wouldn't quite classify it as the predominant completion method yet, at least in our Marcellus. We've certainly done more of them. We're certainly intrigued by the results. They're all looking really well. Unfortunately, we had a delay that we talked about earlier in some of these wells coming online. And so I think over the next quarter, two quarters, we'll really get to see a lot of those wells come online, that we've tried some of the RCS in some of the super rich and the really wet part of the Marcellus acreage. And once those wells come online and we get a few months under our belt on production, then I think we'll be better equipped to answer that question. But right now we are encouraged very well by it. And if it works like it has shown us in the early wells, it's going to really improve our economics.

Okay. Great. Thank you.

Thank you. This concludes today's question-and-answer session. I'd like to turn the call back over to Mr. Ventura for his concluding remarks.

Range is on target to meet our production goals within our capital budget. We're driving down our unit costs in the process. Because we have very large acreage positions in some of the best ways in the country, we should be able to achieve double-digit growth in production and reserves on a per-share basis, debt adjusted, for many years. Plus we continue to be one of the lowest-cost producers in our peer group, and are getting better. In addition, the five enhancements to our portfolio -- the super rich Marcellus, the super rich Upper Devonian, the wet Utica, the horizontal Mississippian play and the Cline oil shale play -- all offer significant upside to Range. Additional news on all these plays will be coming on our third and fourth quarter calls.

I'd like to point out that we still have 10 callers in the queue. And we are not able to take questions in order to honor the time of the call. But I'd really encourage you to give us a call so that we can follow-up on all those questions. And thanks to everybody for participating on the call.

Thank you for your participation in today's conference. You may disconnect at this time and have a wonderful day.