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Range Resources (NYSE:RRC)

Q1 2013 Earnings Call

April 26, 2013 9:00 am ET

Executives

Rodney L. Waller - Senior Vice President

Jeffrey L. Ventura - Chief Executive Officer, President and Director

Ray N. Walker - Chief Operating Officer and Senior Vice President

Roger S. Manny - Chief Financial Officer and Executive Vice President

Analysts

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

David W. Kistler - Simmons & Company International, Research Division

Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

Operator

Welcome to the Range Resources First Quarter 2013 Earnings Conference Call. This call is being recorded. [Operator Instructions] Statements contained in this conference call are not historical facts -- 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, Melissa. Good morning, and welcome. Range reported outstanding results for the first quarter of 2013, with record production and a continuing decrease in unit cost. Both earnings and cash flow per share results were greater than First Call consensus.

The order of 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. After the speakers, we will conduct a question-and-answer period.

Range did file our 10-Q with the SEC yesterday. It should be available on the home page 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 non-GAAP measures of cash flow, EBITDAX, cash margin and the reconciliation of our adjusted non-GAAP earnings to reported earnings that are discussed on the call today.

Now let me turn it over to Jeff for his opening remarks.

Jeffrey L. Ventura

Thank you, Rodney. We're off to a great start in 2013. We continued making progress with our plan of driving up production and reserves on a per-share basis while driving down cost. Production was up 34% versus the first quarter of last year. Total unit costs were down 10% versus the prior year, with LOE leading the way, down 23% from last year. DD&A dropped from $1.68 per Mcfe to $1.46 per Mcfe. Importantly, our operational successes are beginning to significantly flow through to our financial results. Despite prices being down 3%, our cash flow increased 34% year-over-year from $163 million to $219 million.

Looking further into 2013, growing production, coupled with improving well results, which Ray will discuss shortly, and lower per unit operating expenses for the entire year should result in substantial increases in Range's cash flow for the year. In addition to the operational success, we also had 2 other key accomplishments in the first quarter. We sold our New Mexico assets plus Powell Ranch for $275 million. We also issued $750 million of 5% senior subordinated 10-year notes. Both transactions allow us to continue to maintain a strong and flexible balance sheet.

As we previously announced, we're expecting production to grow at a rate of 20% to 25% for 2013. More importantly, we believe that we have line-of-sight growth of 20% to 25% for many years. All of this projected growth is on our existing plays. The reinvestment risk is low, and the projected rates of return are very good.

The growth is mostly driven by our approximate 1 million net acre land position in Pennsylvania, specifically by low-risk, high-return drilling in the Marcellus Shale. In addition to the Marcellus Shale, we're projecting impactful growth from the Horizontal Mississippian, Upper Devonian, Utica, Cline and Wolfberry plays. Given the high return of our plays, which is led by our liquids-rich and oil plays, our cash flow should grow at a faster rate each year than our production growth of 20% to 25% per year. With our projections, using current strip pricing, we expect to reduce our leverage with time, even with a slight outspend as we drive up production and cash flow.

Let me take a few minutes and reflect on U.S. E&P business in general today. With successful application of horizontal drilling, coupled with multiple-stage hydraulic fracturing, the industry has unlocked large-scale, repeatable oil and gas plays and shale formations across the country, such as the Marcellus, Eagle Ford and Bakken. In addition, this technology is being applied to old areas that have a rich hydrocarbon charge and a lot of hydrocarbon left to recover, like the Permian basin. The key to being a top-tier oil and gas company is to have a large position in the core area of one of the top quality plays. Range is clearly one of a handful of companies that meets this criteria. We are blessed by having approximately 1 million net acres in the state of Pennsylvania, which includes a very significant position in the liquids-rich portion of the play. Our position is further differentiated by the fact that in our area, we have not only the Marcellus, but we believe we have great stack pay potential in the Upper Devonian and Utica. Plus, where a play is located is also very important from a marketing point of view. Our discovery, the Marcellus, is well located in the northeast portion of the United States.

Gas from the Marcellus will not only supply the northeast United States, but gas from the Marcellus will move into the Midwest and Southeast markets. It's also strategically located relative to existing pipeline infrastructure, as well as the export facilities and harbor, in the Philadelphia area. It's this position that gives us the confidence to project 20% to 25% growth for many years.

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

Ray N. Walker

Thanks, Jeff. On the operations front, the synopsis is all about executing the plan with better efficiencies, lower operating cost and improving well performance in what we all now recognize as one of the highest-quality plays in North America. With continued strong execution in our approximately 1 million net acre position in Pennsylvania, combined with our stack pay potential in the Utica and Upper Devonian, our emerging plays in the Mississippian, the Cline and the Wolfberry, we believe we can drive increasing value for our stockholders for many years into the future.

Let me start with and spend most of my time this morning on the Marcellus. We continue to recognize substantial improvements in well performance that we believe will lead to real upside in our plan. These improvements are a result of longer laterals, RCS completions, better frac designs and the application of new targeting technology. To illustrate this, during the first quarter, we brought online a 6-well pad in the super-rich area at 14,040 boe per day that's 65% liquids. That's 2,340 boe per day average per well. Additionally, we're bringing online a brand-new 6-well pad as we speak with slightly shorter laterals in the same area that also looks very good at 1,860 boe per day per well with 64% liquids. Now in and of itself, these are impressive wells with great production rates and outstanding economics. The punchline is that these new wells are in an area that already had 8 offset producing wells with up to 5 years of production history, and the new wells are substantially better than the previous wells.

I want to stress that these 24-hour production rates from each of these 12 wells are actual rates to sales, but yet they're all constrained by limitations of the facilities and gathering system. In spite of being choked back, which is by design, by several metrics, these new wells are simply better than those nearby older wells. In our view, the improvements are because the new wells were targeted better, had 30% longer laterals and had optimized RCS frac designs when compared to the older wells. For the new wells, the gas rate per frac stage is 28% higher for the first 20 days, and the gas rate per equivalent lateral length is 125% higher. Importantly, production per dollar spent is 140% higher than the older wells for those first 20 days. This is really important, so I'm going to repeat it again. The new wells' gas rate per frac stage is 28% higher, and per equivalent lateral length is 125% higher. And the production per dollar spent is 140% higher than the older wells for those first 20 days.

Clearly, this illustrates the potential upside that we could see going forward as we go back into previously drilled areas. These 12 wells also support our belief that we have not yet drilled our best well in the wet and super-rich Marcellus. As we apply these new designs and technologies along with longer laterals, we expect that our well results will continue to improve. And as was the case in this example, and I'm repeating myself again, we can expect substantial upside going forward, even in areas where we've previously drilled.

On the last call, we discussed 5 new wells in the super-rich area that also had impressive production rates. As follow-up on those 5 wells, the 3-well pad, after 30 days of production, was producing 1,085 boe per day per well, still at 65% liquids. And the 2-well pad was producing 1,257 boe per day per well, still at 58% liquids. I think the results of these 17 super-rich wells demonstrate the impact of improving well performance and economics as a result of our team continuing to unlock and apply new technologies. In fact, 11 of those 17 wells now have more than 30 days production and, for the first 30 days, are 45% to 50% above the super-rich type curve in our presentation. The key is it's still early, but we are really excited about the long-term potential that, that shows. Our technical team is really taking advantage of our improved reservoir modeling, which can only come with time and more data.

What we're excited about is the potential upside that we see all across the Marcellus, including in the dry areas. We've been talking about these techniques for quite some time but now are seeing tangible and impressive results and again, recognizing real upside in well performance as we go back into previously drilled areas. Today, we have over 430 horizontal Marcellus wells in Southwest PA on our 540,000 net acre position, which are producing approximately 500 million cubic feet equivalent per day net. If we were to develop the entire position on 80 acres, that's 6,750 wells. Best to-date, we've only drilled about 6% of our wells on 80-acre spacing. If you could drill all 6,750 wells today, when you do the math, we have the potential to grow our Southwest Pennsylvania production to almost 8 bcf equivalent per day. Of course, this is assuming we drill all our acreage on 80s and all the wells are equal and, at the same time, and so on.

Obviously, I'm not saying we will grow at 8 bcf equivalent per day, but it does give us confidence that we have a very large and high-quality asset that we can grow significantly for many years. Remember, there are over 1,650 producing Marcellus wells, which significantly de-risk our acreage. And again, this estimate does not include the Upper Devonian or the Utica or 40-acre spacing, all of which, we believe, are highly prospective across our Southwest PA acreage.

If you factor in all the things we're seeing, improving well performance, increasing capital efficiencies and lower operating cost, and you add to that 40-acre development in portions of the reservoir and additionally, you tack on the stack pay potential of the Utica and Upper Devonian and the potential of our other plays across the company, I think you can see for yourself why we have confidence in our ability to grow production at 20% to 25% for many years, essentially doubling our production every 3 years or so, which, in about 6 years, takes us up to 3 bcf equivalent per day as a company. And we believe it continues to grow significantly from there.

Shifting to Northeast Pennsylvania, while continuing to hold acreage with 1 to 2 rigs running, our technical team is focusing on delivering great wells, reducing cost and increasing efficiency. Two significant wells were brought online in Lycoming County and are described in the press release, and our plan for the remainder of the year is to continue with the 1-to-2-rig program in that area.

Now I'll bring you up-to-date on our emerging plays and start with our Mississippian play in Northern Oklahoma. We ran 5 rigs during the first quarter. Efficiencies are improving quickly. For example, we've seen our spud-to-rig-release days decrease from 37 days down to approximately 20 days in a short span of just 9 months. We've had some good news on a couple of other fronts. We've gotten a better result from pooling than we predicted, and we're ending up with almost 100% working interest in our wells rather than the prediction of 80% or so. Also, the team is making much better use of our saltwater disposal infrastructure, therefore, not needing to drill as many disposal wells this year. As a result of the rigs getting faster, higher working interest and less saltwater disposal wells needed, the good news is we're going to be able to utilize fewer rigs this year for about the same number of net producing wells. We're still working out the numbers, but we should be able to finish the year with fewer rigs as we do plan to stick to our CapEx budget.

The team did have some noteworthy wells and updates on previous wells that are detailed in the press release. In this play, it's all about location in a core sweet spot area, execution, controlling cost and steadily and thoughtfully building out infrastructure. And I'm happy to report that the Midcontinent team is doing a great job on all fronts.

In the wet Utica, Northwest PA and the Cline in West Texas, we're continuing to closely monitor offset activity, along with trading data and results as wells in both areas are completed and brought online by our peers. Again, we have large acreage positions in both areas that are largely HBP, and our plan continues to be to watch, trade and learn before we make any further development plans. Later this year, we expect that there'll be significant information that we can talk about in both plays.

For the first quarter, we exceeded our production guidance primarily due to some better-than-expected timing of pads coming online, combined with some really good well performance, both of which happened in the Marcellus. Like I was talking about earlier, some of these multi-well pads coming online are really impressive, and just a few days ahead or behind schedule can really impact our production in any given quarter. While we're likely to see quarter-to-quarter variability, we still expect to come right in at 20% to 25% growth for the year. Although we lost approximately 18 million cubic feet equivalent per day from the New Mexico sale that was effective April 1, guidance for the second quarter is set between 880 million and 890 million cubic feet equivalent per day with 20% liquids.

Remember in the last call, during Q&A, I kept referring to and restating, "Did I tell you about those 5 super-rich Marcellus wells?" We had a lot of fun with that, obviously. But there were a few folks on the call that caught the real meaning. It really is the Marcellus and our large acreage position in Pennsylvania that will drive our share price for many years. You could sum it up into 7 key points: number one, the sheer size of our acreage position in Pennsylvania at approximately 1 million net acres; number two, the largely de-risked nature of our Marcellus potential, largely in Southwest and Northeast PA; number three, the stack pay potential of the Utica and the Upper Devonian and the potential of the wet Utica and Northwest PA; number four, the tremendous economic impact of the liquids in our wet and super-rich area in both the Marcellus and the Upper Devonian and the developing markets for those products; number five, the high-quality dry gas assets both in Northeast and Southwest Pennsylvania; number six, capital efficiency improvements as we go back into areas where infrastructure is already in place, combined with the lower unit cost; and number seven, substantial improvements in well performance as we incorporate better RCS designs, better targeting and longer laterals.

As we begin to appreciate all these things going forward, it really is all about what those 17 super-rich wells illustrate. We've only just begun to get a glimpse of the upside as our technical team continues to accelerate its understanding of the reservoir and delivers results. What it means is as we work our plan for 20% to 25% production growth year-over-year for many years going forward, we have great confidence in our team and our assets. In short, we are confident in our plan to deliver substantial shareholder value for many years to come.

Now over to Roger.

Roger S. Manny

Thank you, Ray. The first quarter of 2013 produced continued improvement from last year in most all financial measures, on both the income statement and balance sheet, higher revenue, higher cash flow, with lower unit cost and declining leverage.

Reflecting first on the balance sheet improvements this quarter, we requested and received unanimous ratification of our existing $2 billion bank credit facility borrowing base and $1.75 billion binding commitment. At quarter end, approximately $1.6 billion of the committed credit facility was unused. Shortly after filing our annual 10-K in February, we issued $750 million in new 10-year, no-call 5 senior subordinated notes at 5% fixed interest. The combination of the new 5% notes, the December 2012 call of our 7.5% notes and pending call of our 7.25% notes reduces the weighted average interest rate on our long-term, fixed-rate debt by 58 basis points. This balance sheet improvement further reduces our interest rate volatility while extending our first bond maturity to 2019, 6 years out.

On April 1, we closed the sale of our New Mexico assets for approximately $275 million. The sale will produce about $84 million pretax gain in the second quarter, and proceeds from the sale were used to repay debt. Adjusting the first quarter debt to trailing 4 quarter EBITDAX ratio for the asset sale reduces our leverage ratio from 3.2x at year end to 2.8x.

Moving to the income statement, cash flow for the first quarter was $219 million, 34% higher than the first quarter of last year. Cash flow per fully diluted share for the quarter was $1.36, $0.03 above analyst consensus estimate of $1.33. EBITDAX for the quarter was $259 million, 31% higher than last year. Cash margin was $2.75 an Mcfe for the first quarter. That's 2% higher than last year, even though realized prices were down.

Earnings calculated using analyst methodology, which were adjusted for certain noncash and nonrecurring items, was $53 million for the first quarter of 2013, more than twice last year's figure of $24 million. On a per-share basis, analyst -- earnings were $0.33 per fully diluted share. That's $0.04 higher than analyst consensus.

Natural gas futures prices increased between the end of the year and the end of the first quarter. And while this is good news, the gas price increase made our hedges less valuable at the end of this reporting period compared to the end of the last reporting period. And this explains the $97 million noncash mark-to-market loss on our hedges, which was primarily responsible for our GAAP net loss. GAAP net income was further reduced by $42 million in noncash deferred compensation expense. That's due to the fact that our stock price increased from $62.83 per share at year end to $81.04 per share at the end of the first quarter. So even though the shares required to fund the deferred comp obligation have already been issued and placed in the plan, because the shares are held in the Rabbi Trust, GAAP requires that we expense the amount of the value increase.

Lastly, as discussed in the 10-Q, we recorded a legal contingency of $35 million, which is included in the G&A expense line. The bottom line impact of these items was a GAAP net loss for the quarter of $76 million compared to a loss of $42 million last year. Please remember, as Rodney mentioned, that all non-GAAP numbers I just mentioned are reconciled to GAAP in the IR tables posted to our website and in the press release.

Running down the first quarter cost performance and guidance figures, cash direct operating expense, including workovers, was $0.37 an Mcfe, $0.11 or 23% below last year's first quarter. Second quarter is expected to be in the $0.38 to $0.40 per Mcfe range. Third-party gathering, compression and transportation expense came in at $0.79 per Mcfe for the quarter, $0.11 higher than last year, due to continued system expansion and a greater percentage of our production coming from those expansion areas. Second quarter expense for this item is expected to run $0.82 to $0.84 an Mcfe.

Production and ad valorem taxes for the first quarter were $0.14 an Mcfe, and that includes Pennsylvania impact fees of $0.09 per Mcfe based on total company production. In absolute dollar terms, total production taxes for the quarter were $11.4 million, of which the Pennsylvania impact fee was $7.1 million, and non-Pennsylvania production taxes were $4.3 million. Production taxes in the first quarter of last year were significantly higher as last year's first quarter marked the initial implementation of the Pennsylvania impact fee, and that included the $24 million retroactive payment. Second quarter Pennsylvania impact fees are expected to approximate $7 million, and total production taxes per Mcfe should be between $0.15 and $0.16.

First quarter exploration expense, excluding noncash comp, was $16 million, down 24% from last year's first quarter, with the timing of seismic expenses prompting the reduction. Our seismic budget for 2013 is only slightly below that of 2012, so we anticipate second quarter exploration expense to come in between $18 million and $20 million. As expected, abandonment and impairment of unproved property during the first quarter was $15 million. That's significantly less than last year's figure of $20 million. The second quarter will likely continue to see this expense fall, down in the $15 million to $17 million range.

Cash G&A expense for the first quarter was down $0.05 below last year at $0.45 an Mcfe. We came in a tick over guidance on this expense due to some nonrecurring expenses associated with the deployment of several hundred new field vehicles, approximately 150 of which, we are proud to say, are fueled by natural gas. The second quarter should see cash G&A expense back down in the $0.40 to $0.42 range.

First quarter interest expense is $0.54 an Mcfe, which was $0.08 below last year. And while we expect unit interest expense to resume its downward trend later this year, second quarter interest expense is estimated to be in the $0.58 to $0.59 range due to the timing of the new note issuance versus the old note redemption, the asset sale closing and the fact that we replaced some lower-cost, floating-rate bank debt with that higher-cost, fixed-rate debt.

Our first quarter DD&A rate per Mcfe was $1.46, $0.22 less than the first quarter of last year. As the E&P business is highly capital-intensive, our depreciation, depletion and amortization expense figure is, by far, the largest absolute dollar expense item on the income statement. The significance of a $0.22 reduction on this unit cost in just 1 year provides clear evidence of the improving capital efficiency that both Jeff and Ray mentioned. The DD&A rate per Mcfe is estimated to be in that $1.46 to $1.48 range next quarter.

Range has continued to add new natural gas and NGL hedges for the next 3 years as we seek to generate greater predictability of cash flow to underpin our capital program. And please refer to our press release and website for the details on our current hedge position.

In summary, the balance sheet saw a significant improvement in the first quarter, with lower leverage, higher liquidity, lower long-term financing cost and reduced exposure to interest rate and refinancing risk. On the income statement, looking through the mark-to-market accounting losses caused by higher prices for natural gas and higher Range stock price, one can see another solid quarter of production growth and cost control, driving significant double-digit cash flow growth over last year.

Jeff, back to you.

Jeffrey L. Ventura

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

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from the line of Ron Mills with Johnson Rice.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Ray, a couple questions. You talked a lot about the new, I guess, 12 wells or 14 wells in the super-rich area and how they were better than other -- your older wells in the area. A couple questions. You have a little bit longer laterals, maybe some more frac stages, but what were some of the primary drivers behind that performance? And even though you had a little bit longer laterals, you're still in the mid-3,000 range. Is there the opportunity or likelihood that you would continue to expand that lateral link into the 4,000, 4,500-foot level? And if so, what would your expectations be?

Ray N. Walker

Yes, Ron, great question. I think the drivers of that improved performance are really all of those things combined. Better targeting has certainly been significant, and that involves some of the new focused ion beam scanning electron microscope, pictures where they take -- they model some of this rock at the molecular level almost. And what we've seen is being able to use some of these new technologies and really how the technical teams figured out how to apply those, and where we actually placed that lateral in the rock has made significant changes. And these wells, in the 2- and 6-well pads that I've talked about in the super-rich area nearby the 8 previous wells that were -- some of them are up to 5 years old, the difference there is, on average, they're about 30% longer laterals. And when you combine that with the RCS, that's almost twice as many frac stages in the -- basically, on a per-lateral kind of comparison. So really comparing all those or combining all those things together is really what makes that difference. And I like to talk about the fact that this is really a good indication of, I think, what we're seeing going forward and the application of all the technology. And we've gone back, and of course, we're really excited about all this, and we keep going back and looking at these and how they're comparing to our overall averages and our type curves. And like I said, it's really early. But I think it's really key to point out that these wells, on average, are posted between 45% and 50% above the type curve that we've got in our PowerPoint. So that's pretty exciting. It's still early. It's only 30 or 40 days on some of these wells, but we think that that's going to be really key. As far as longer laterals, yes. I mean, I think over time, you're going to see us migrate to that. In these cases, you're somewhat limited because you were going back into units, in some cases, that had already been formed around it on all sides, so you're sort of limited in some of those cases. But remember, these economics are really, really good at the lengths that we're at today. And they're good in the PowerPoint, so you got a, say A plus B equals C, and they're going to be a lot better overall. So we're pretty excited about it. But to answer your question, yes, we are going to be going longer over the next several years, and we are going to continue to refine some of these technologies. We've got some other ideas. The technical team is just doing a wonderful job up in Pittsburgh, so we're really excited about what they're seeing.

Jeffrey L. Ventura

And Ray, you might mention, when you go back into some of those units and drill some of the efficiencies, you think we might see going...

Ray N. Walker

Yes. Yes, and that's another good add that we're seeing, too. When you go back into these areas, these new -- whether it's a new pad in that area, it won't have to pay as much money for water impoundments, for instance, because it will use an impoundment that's already there. If we're going back and adding a well on a pad that already exists and say we want to drill a couple of more wells there to go kind of backfill the infrastructure, in a lot of cases, they don't have to pay a lot of money for new infrastructure. They don't have to pay for new pad construction or new roads and that sort of thing. So we could see several hundred thousand dollars less on the upfront cost, which is also really significant going forward. And I think all of those things just continue to enhance our story and what really translates down to shareholder value going forward.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Okay. And then, I guess, a corollary to that, and then I'll let someone else jump on. Is there anything special about this particular area where you drilled these wells within the footprint of older wells, or would you expect similar-type results as you enter other older areas? And then you mentioned, I don't know if it was you or Jeff, in passing, a little bit the 80-acre spacing, but you mentioned the potential for 40-acre spacing. Do you think that's going to be prevalent across most of your acreage in Southwest and Northeast PA?

Ray N. Walker

Well, we've got at least a couple. I think there may be 3 40-acre pilots that are out there, and some of them have well over 2 years of production now. We have not released any data and don't really plan to anytime real soon. But I'll tell you they're all encouraging at this point. And just from a pure standpoint of doing this kind of thing for a whole lot of years, a lot of us would tell you that there's no doubt as you're in these liquids-rich areas that you're probably going to go to denser spacing over time. So I think that's -- the answer is technically yes. I think a good portion of the wet and super-rich area will probably develop on 40s eventually. But we see that much further down the road. We've still got a lot of room to go back in and infill the rest of the 80s, 60s, whatever combination of lateral lengths and distance between laterals that we come up with over time. So to answer your question, yes, we will be down-spacing significantly going forward.

Jeffrey L. Ventura

I think another key thing to say there, too, is on -- if you look at our website and we go through it on our pitch book, what Ray referred to earlier, we got 1 million net acres in the state of Pennsylvania, highly prospective for multiple horizons. And you just zoom in on the 540,000 acres in the Southwest, which Ray did in his example. There's 1,650 wells there, up to 7 years' worth of history on our discovery well, which kicked the whole play off. And we go through in detail on our website, starting on Page 12, 13 and so on, and we break out all the dry, the wet and the super-rich. And really, there's over 1,650 wells that have delineated it, and that acreage is really all high-quality. So we think it's all very prospective, very low-risk, a lot of -- it's a big data set. It's not 7-day rates or 30 or 60. It's up to 7 years' worth of history on over 1,650 wells. So on 80-acre spacing, since we think it's all prospective, potentially 6,750 wells, and like Ray said, we've drilled only about 6% of that on 80s. But it's all highly de-risked with high returns. So we've got a lot of drilling. And the good news, there's data all over the place out there. So we think those techniques that Ray described will be very applicable, really, across that acreage.

Ray N. Walker

Yes. And just another final word, just so Jeff doesn't get the final word, if you look at the 20 super-rich wells that we turned on in the first quarter, those wells averaged about 65% liquids and the IP on those and boe per day is not a lot different than these wells I've been pointing out here. So I think the hints are, yes, we do expect to see those kind of results. We're pretty excited about this. This is a big deal.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

And Ray, was there any difference about this particular area of going in amongst the older wells or…

Ray N. Walker

No. Not appreciably, no.

Operator

Our next question comes from the line of Dave Kistler with Simmons & Company.

David W. Kistler - Simmons & Company International, Research Division

Real quickly, when you think about the placement of those laterals in the Southwest Marcellus, is that something that you can apply that same technology across your portfolio? And should we be looking to you guys doing that across all the Marcellus and maybe even testing some of that down in the Miss Lime and potentially seeing an uptick from EURs across the board?

Ray N. Walker

Well, the answer is yes. I mean, we are looking at this everywhere we're working, in the Cline. We're looking at applications in every single play. I think what we tried so far, we've seen varying levels of improvements. And I think it's going to vary a lot based on reservoir rock conditions. And I think the jury is still out because we've only really been applying this last part of last year and early this year, and so it's going to take some time. But I think all our experts would tell you yes, we do expect to see some improvements. But at the same time, we're going to also be doing longer laterals in general everywhere, and we're also doing the RCS-type completions in a lot of cases, too. So it's really going to be a combination of all those things, not just the targeting by itself. But I do expect that we'll try all of those things in pretty much every play.

David W. Kistler - Simmons & Company International, Research Division

Okay, appreciate that. And then looking at the Miss Lime just for a second, you put up a couple wells that were very, very strong in your release. EURs look good, but the EURs would generally based off those IPs that you shared with us on the new wells, showed that there's some decent variability between the wells. Maybe I'm misinterpreting that, but looking in other parts of the Miss, different geographies, that's certainly the case. What are you doing to kind of think through or try to avoid having that sort of statistical aberration between all the wells?

Ray N. Walker

Well, the chat, which is really what we're playing on the Nemaha Ridge, is very variable. It's probably not good grammar. But it varies in thickness, and it varies in the fact that it's -- it's not everywhere. It's very prevalent. It's much more prevalent on the uplift than it is other places. But what we're trying to do with more and more time is trying to determine where that is. We're using our 3D. We've got 4,500 historical wells in that area. And one of the original ideas in putting that lease position together was to really stay close to the historical oil production and try to be around the better historical vertical production because your horizontal results are always going to be a multiple of your vertical. So the best place to look is where the best wells were. So we've got a lot of well log history and different things. And the chat play is really a conventional-type play, for lack of a better description, which is sort of unconventional in today's world. But it has high porosity. It has high permeability, there's lots of fractures. And it's going to be -- I think the standard deviation of results is going to be larger in a play like that. It has to be. So the key is determining why the good wells are good and trying to find more of those as we go, and that's going only going to come with time. Just like we've seen in the Marcellus, with more time, more data and more modeling and more understanding of all of these different rock properties, that's the same thing that we're going to go through in the Mississippi. And we're really early. We'll continue to update the type curves as we get more production at wells throughout the year. But so far, we're really excited with what we see, and it's holding on. And it's going to be a good emerging play, we think. But again, it's still early.

Jeffrey L. Ventura

Yes. I think the other thing, there's variability, but I think at the end of the day, the key is what's the average of the program. So if you look at the average of our -- on Slide 26 on our website, if you look at the average of our 2009 to 2011 horizontal wells, they're 485,000 boes type curves or the 0 time plots here in the back. With the costs where we think we are or where we're close to, those generated, strip pricing, 91% rate of return. So really, the average is the key. Granted there's variability, really, in all plays, if you look at the average of the 2012 program at 600,000 boes, and it's over 100% rate of return. But we're learning. Just like we did in the Marcellus, we got progressively better with time. We learn with time. We'll see as we drill forward here how it eventually drills out. And you don't know until you drill it and you get long-term history. But looking at the old historical wells and looking at the 3D and the data that we have, personally, I don't think we've drilled our best areas yet even. We've started around where we started our development in Tonkawa field, and we just expanded around that. Again, I'm very happy with the 2009 through '11 program and 2012, and we'll see what it looks like going forward. But there's -- we still think it's a very attractive play. Nothing -- because we have 1 million net acres in Pennsylvania and you got stack pay potential, that's what's going to drive the 20% to 25% line-of-sight growth for many years. Again, and there's -- if you look at the whole Marcellus play, there's over 7,000 wells and up to 7 years history that have de-risked it, so that's the driver. But the Mississippian is exciting. Our potential in the Upper Devonian, the Utica, the Cline, and those other -- Wolfberry, all those other plays have value, too.

David W. Kistler - Simmons & Company International, Research Division

Great, I appreciate that. One last question just in the Miss. When you talk about your time to drill those specific wells and we look at kind of the initial plan to ramp to 7 rigs, then 10, then 15, it would seem like also, with the increased working interest in wells, you really don't need to ramp rigs even materially over the next 2 years to be able to drill your objective of wells. Is that a fair way to think about that? Am I overstepping in terms of -- you're throwing out 20 days to drill a well and trying to work through that math, or how should we think about that as we model stuff out?

Ray N. Walker

No, Dave, I think you've nailed it. I mean, we just need to quit talking about rig counts because the drillers are just getting too good too fast. And just like we saw in the Marcellus, we had to quit talking about rig count, and it's really the number of net wells we're going to put online each year. And our plan is still to ramp up activity, but you may not see it near as much in rig counts going forward as we thought earlier on because just in 9 months, they went from almost in half. And we've seen wells 16 days or less, and I predict they'll be a lot less than that a few months from now. So you're exactly right. I think rig count is going to be really difficult to model. We can't even do it internally any more. It's just too – they're changing too fast.

Operator

Our next question comes from the line of Mike Scialla with Stifel.

Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division

I got on your call late. I seem to be challenged by understanding time zones, so I apologize if you addressed any of these in your prepared remarks, but I missed them. Some people are worried about future condensate prices in certain parts of the country, and it looks like your Marcellus condensate prices, at least as a percentage of WTI, have increased each of the last 3 years. Just wanted to see if you could talk about how you see the market dynamics of the condensate market going forward in your areas?

Rodney L. Waller

Well, this is Rodney. And one of the things that we're blessed about is being where we are in the Appalachian area, you're in a very high-demand area, from White Plains down to Baltimore. Canada has brought a lot of imports of C5s and condensates as part of the development there. What you've seen on the slide that we have in the presentation...

Jeffrey L. Ventura

Slide 36. It's out there if you're looking.

Rodney L. Waller

Yes, Slide 36. Is that as we get to larger and larger volumes and we have the economies of scale, it allows us to go to different markets than what we are otherwise able to go to. And usually, those are premium markets. So we think there's still upside in the condensate market in Appalachia. There's always the ability to stabilize condensates and have them to qualify for export if that is required. So we think gasoline blending is another potential use that we haven't tapped into yet. So we think there's still growing and expanding markets. And the blessing that we have here is any demand that you have in Appalachia, if it has to be sourced, would have to be sourced from the Gulf of Mexico, which is going to add a huge amount of transportation cost. So we have some built-in margins in every one of our products, whether it's NGLs, condensates, propanes, we have this built-in differential because the only other way to get it is to buy it from Mont Belvieu, which is going to cost you money. And so we're just basically totally disconnected from the Gulf and the challenges that are going on there with all the NGL markets and the condensate market.

Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division

So condensate prices could weaken in the Gulf and you wouldn't be impacted by that?

Rodney L. Waller

We can't set the index, but we can have alternative export and other alternatives that could stabilize prices much better than any wells in the United States.

Jeffrey L. Ventura

And that's why going back again to that Slide 36 or whatever, our prices have just been climbing with time. And we're in a great position not only for condensate but to move gas. And that position, particularly in the Southwest, is right on top of a lot of historic infrastructure that we're able to move gas in a number of directions. We're close, again, to the harbors in the Philadelphia -- harbor in the Philadelphia area to be able to -- and we got our ethane export agreement in place. We're currently exporting propane. So it's not only finding a large field and then having a million-acre footprint in the state and then being in some of the core areas, but also, all the advantage of having that infrastructure there is really critical, coupled with the team.

Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division

Okay, great. And then on your NGL price, I guess 37% of WTI for the first quarter, would you expect that to come down some in the second half once Mariner West goes into service?

Roger S. Manny

For NGL -- yes, when you put the ethane into the NGL, that will come down because what you're adding to the NGL barrel is the lowest dollar value of the total barrel, but production will go up. And so yes, that will happen over time. So be able to do that will help develop for you by next quarter how those fit into it. But with 5,000 barrels, you're not moving it that dramatic this second half of 2013. In 2014 and '15, obviously, there will be big changes in those because you would have much greater values. But also remember, the ethane that we're going to be selling in the second half of 2013 is going to be at a higher price than probably anybody else in the United States. Again, Appalachia's totally differentiating itself as to what we're trying to do with multiple markets that we can serve.

Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division

So maybe some modest percentage decline in that percent of WTI but nothing material for second half of '13.

Rodney L. Waller

Yes, we can help you model that, Mike.

Jeffrey L. Ventura

Yes, and to think about it in aggregate, when you look at that contract with Mariner West, it's at a gas index, so we're actually kept whole as a company plus a little bit with the efficiencies that come. So it's an economic uplift for us in general when you consider everything, as is Mariner East as well.

Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division

Yes. And then you mentioned that you're watching offset operators in some of your emerging areas like the Cline, the Utica and Upper Devonian. I don't know if you mentioned this in your prepared remarks, but anything new there that has made you more or less encouraged by any of those plays?

Ray N. Walker

This is Ray, Mike. In the Cline, we're continuing to see a bunch of activity. We still think there's going to be about 50 wells completed and put online in that area this year. We are seeing some good wells pop up here and there, close to 1,000 barrel a day IP type things, on both sides of this, east and west. So we're really almost a donut hole in the activity there. We got a people all around us, north, south, east and west, and so we're really watching that closely. And then in the Northwest Utica, certainly, there's a lot of guys that are really active up there, Halcon, Seneca, Shell, quite a few, Hilcorp. I mean, there's some -- there's going to be -- we still think about a dozen wells up there that year, and actually, Halcon at IPAA last week or so was talking about a couple wells that they're beginning to start flowbacks on. So I think we'll have quite a bit of data over the next couple of quarters that we can start talking about.

Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division

Okay, great. If you are more encouraged by any of that data, any chance you'd allocate some capital toward those plays this year, or is it more likely a 2014 event?

Ray N. Walker

I think it's more than likely a 2014 event. We'll need to see some of the stuff, some production history, and it'll take a while to digest that. And then it'll go into the mix when we put together the budget for '14. And I suspect that's the earliest it would happen.

Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division

Okay. And then just one last one for me. You had mentioned that you've had some 40-acre space pilots in the Marcellus on for a couple years. Any reason for holding back the data there? Is it competitive reasons, or is there some unitization issues or something that would impact how you would go about saving the acreage?

Ray N. Walker

No, there's no particular reason for holding it back other than -- I think the best way to describe it, and hopefully, nobody shoots me for saying this, is we just don't want -- we don't want to think about it too much yet because we think -- going back into drilling, actually, drilling on 40 acres is down the road somewhere. And I think we've got a lot of going back into areas to finish up the 80s, and we've got a lot of that kind of work to do before we get to that point. So I think you're just not going to see any for a while, but it is encouraging data. And I think we will come out at some point.

Jeffrey L. Ventura

Yes. Let me talk about that a little bit because I think it's a key point. Like Ray said, again, going back to 14 on our slide deck, just in the Southwest, we've drilled about 6% of our wells. So we've got a lot of drilling to do on 80s because we think that whole area is prospective, and of course, on 40s. And we think a lot of it is prospective for 40s. I think there's a couple of key thoughts that come out of that. One, again, that's what gives us confidence to say we think we can drill at 20% to 25% for many years. So again, if we can -- and if you're growing at that rate on a compounded basis, roughly, every 3 years, you're doubling. So take, and I always roll back to around year end, around 0.8 Bs net, round it down, 3 years out, around 1.6 Bs net and going to around 3 Bs per day net, which would be phenomenal. That's why we think we can do that. I think the other key thing to think about with the down-spacing is, when you look at all the numbers we have for resource potential in aggregate for the Marcellus, is the recovery factors in that 30%, low 30% of gas in place or hydrocarbon in place, liquids in place. Through a combination of what Ray discussed, which is better quality wells going forward, through a combination of RCS, better landing, a little longer laterals, a few more stages, we can really drive up recoveries from our wells. The other way we can drive it up is through drilling the wells closer together, instead of 1,000-foot apart like we're drilling now 500 feet apart, which some other operators are already doing. So when you look at those 2 things combined, do we think we have the potential to take our recovery factor in the better areas from 30% roughly to maybe 50%, 55%, maybe even double it on the high side? That potential exists. So if you take some from 30% to 50% but you got the giant acreage positions we have, that's a lot of value. That's a lot of NAV. That's a lot of stuff that gives us confidence that we can grow consistently at 20% to 25% per year. That, to me, is the real significance of it. And it's not just growth, but it's higher-quality growth for all the reasons that Ray said earlier, those first wells again, or back in earlier this year, performing. And it's early, and it's just a handful of wells, but they're 45% over our type curve for the super-rich area. That's really impactful in terms of modeling and NAV and value creation.

Operator

[Operator Instructions] Our next question comes from the line of Doug Leggate with Bank of America Merrill Lynch.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

I wanted to go back to the commentary in the release about the extent of which continuing to hold acreage by production is limiting your ability to really go after some of these wells. So I'm just wondering if you can give us an update as to where are we in that process and at what point would you feel comfortable revising higher because it looks like we're heading out where the type curves on some of the super-rich results you've announced last night.

Jeffrey L. Ventura

Well, I think if you flip to Slide 12 on our website or in our pitch book, it shows where our approximately 1 million net acres are, and then for each one of those areas, it shows a percent HBP. So the main area, we have the HBP is in the Southwest. And which predominantly, a lot of the dry stuff, most of it, a lot of it, is HBP. So it's predominantly in the wet and super-rich. So for the well designs we have been drilling, and again, you can look at them, like Ray mentioned earlier, they're really high returns, whether you look at rate of return, return on investment, PVI or whatever you want to look at. So we got really high returns doing what we're doing. The exciting part, though, is they can get better. So what we've done is sort of artificially constrained ourself over the last few years because we're in a different position than really I think when you look at it on a net acreage basis in Pennsylvania, I think Range probably is number one . So we have the largest position in the highest-quality, largest gas field out there, plus we have a position in the wet part of it, as well as really high-quality dry acreage. So we're trying to hold acreage, as well as drive up production per share, reserves per share and cash flow per share. Having done that, we constrained our wells to things that are probably less than optimum, still generating really high rate of returns. So going forward, as we hold more and more acreage, what you've seen every single year, back from when we first started releasing the 0 time plots, is every single year, as we have migrated towards all those more optimum completion techniques, our reserves per well have gone up, including -- if you go back even a year ago, we were at 5.9 Bs in the wet. So in the Southwest this year, we're at 8.7. Of course, there's a giant liquids component to that. So they're going up every year. Will I expect that they'll stop going forward? No. I would expect that they'll get better as they go forward as we continue to do all those things. We've done it every year in the past, and we're continuing to do things that we know will work based on what we've done and based on what others are doing. So it's balancing and trying to capture that opportunity. Again, going back to Page 14, we've drilled on 80-acre spacing, 6% of our wells. If you use 40, it's 3%. Did we optimize the first 3% to 6% of our wells? No. But we've generated, I think, some really good returns and really good performance. And for the remaining 90-plus percent, I think they're going to get better and better.

Ray N. Walker

Yes. Another thing, I'll just tag on a little tidbit, one of the measures that we often look at is recovery per 1,000-foot of lateral. And a few years ago, we were in that 2 bcf per 1,000 foot of lateral in kind of in the wet area per se. Last -- in these type curves we've got today, we're in that 2.7 range, in that same area, so that's a really large percentage increase in the recoveries per 1,000 foot of lateral length. And so just as important as increasing the lateral length is the more you get per 1,000 foot of lateral. And clearly, these new wells that we were talking about earlier in my remarks, the 2 new 6-well pads plus the 5 wells from the previous call, look like they could be 45% to 50%. I mean, they are for the first 30 days, 45% to 50% above the type curve that we have in the book. So we're seeing major improvements in recoveries per 1,000 foot of lateral and at the same time, going longer laterals. So we all totally agree that these wells are going to get better as we go and our ability to drain the rock is going to get a lot better as we go.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

All right, guys. Maybe just sort of a clarification. Jeff, when did you expect to be done with the bulk of the HBP process on the current line?

Jeffrey L. Ventura

Well, okay, let's flip back. When you go to the Northeast, there, we have on Slide 12, 145,000 net acres, 69% HBP. The key thing is at this point in time, although we're not in HBP mode there, we're in a continuous drilling mode. So we just need to run 1 to 2 rigs per year, and we'll hold all the acreage that we want to hold there, the high-quality acreage. If you go to Southwest, that 51% probably goes up roughly 10% to 15% per year.

Operator

[Operator Instructions] We will go to Marshall Carver [ph] of Heikkinen Energy Advisors for our final question.

Unknown Analyst

In terms of the 20% to 25% growth per year over the next few years, does that cook in any of this improved well performance that you're seeing, or is that based on the current well performance or even the well performance that you were seeing in late 2012? Could you give me some clarity around that 20% to 25% growth?

Ray N. Walker

Yes. Well, first, I want to correct. It's not for just a few years we're going to grow 20% to 25%. It's many years. But yes, some of that is built in there in the type curves that we updated first part of this year. So yes, there is some of that. But clearly, what we're seeing in some of these recent wells is, like I've been saying, 45%, 50% above that already. Now it's still early, and it's hard to put an EUR on the well with only 30 days of production. And they're somewhat choked back and constrained by design and...

Jeffrey L. Ventura

None of that's baked into it.

Ray N. Walker

Yes, none of that's baked into it at all, and certainly, none of it's baked into it in the dry areas and the other plays, which we -- that's just one more thing that gives us confidence in the ability to grow it at 20% to 25% for so many years going out there. It's just a really high-quality portfolio of assets.

Jeffrey L. Ventura

If you're modeling it going forward, we're comfortable with the 20% to 25%. That's why we've been saying it consistently. If you're going to model that because our wells have improved every single year since we've been in the play, I wouldn't model it flat going forward. I think the proper way to model it would be to build some of that in there. In fact, I've built a lot of it in there.

Ray N. Walker

Bigger and [indiscernible].

Jeffrey L. Ventura

Yes, and what I'm saying is we'll grow at 20% to 25%. But the quality of the wells and the returns on the investment will get better with time as you build that in there.

Ray N. Walker

Yes, absolutely.

Operator

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

Jeffrey L. Ventura

In closing, I'd like to make 3 points. One, given Range's large, high-quality, low-risk acreage position and drilling inventory, we believe that in addition to growing production 20% to 25% this year, we have 20% to 25% line-of-sight growth for many years. Secondly, given the high returns in our liquids-rich and oil plays and assuming current strip pricing, our cash flow is expected to outpace our production growth. We're also projecting that with current strip pricing, we'll be reducing the leverage of our company with time as we drive up production and cash flow. The third point is that we expect our well results to continue to get better with time as we have demonstrated over the past years.

Having drilled only a small fraction of the wells that we ultimately expect to drill in the Marcellus, as we refine our targeting of our laterals, drill longer laterals and optimize our completions with RCS and additional stages, we're convinced that we have not drilled our best wells yet. Led by our approximately 1 million net acre position in Pennsylvania, we project that we'll consistently drive up both production and reserves on a per-share basis, debt-adjusted, for years to come. Plus we continue to be one of the lowest-cost producers in our peer group and are still improving. We believe that this plan will translate into substantial shareholder value in the months and years ahead.

I know that there's several other people that were queued up for Q&A. Please give our IR team a call, and we'll try to handle all those questions as fast and as best as we can. And thanks to everyone for participating on the call.

Operator

Thank you. This concludes today's teleconference. Thank you for your participation. You may disconnect at this time.

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