Range Resources Management Discusses Q4 2012 Results - Earnings Call Transcript

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Range Resources (NYSE:RRC)

Q4 2012 Earnings Call

February 27, 2013 9:00 am ET


Rodney L. Waller - Senior Vice President and Assistant Secretary

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


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

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

Dan McSpirit - BMO Capital Markets U.S.

Pearce W. Hammond - Simmons & Company International, Research Division


Hello, and welcome to Range Resources' Fourth Quarter and Full Year 2012 Earnings Conference Call. This call is being recorded. [Operator Instructions] Statements contained in this conference call that are not historical facts are forward-looking statements. Such statements are subject to risks and uncertainties, which could cause actual results to differ materially from those in the forward-looking statements. [Operator Instructions]

At this time, I would like to turn the call over to Mr. Rodney Waller, Senior Vice President of Range Resources. Please go ahead, sir.

Rodney L. Waller

Thank you, operator. Good morning, and welcome. Range reported outstanding results for the fourth quarter, with record production and a continuing decrease in unit cost. Both earnings and cash flow per share results were greater than First Call consensus.

Know that 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. After the speakers, we will conduct a question-and-answer session.

Range did file our 10-K with the SEC and is available this morning. It should be available on the home page of our website, or you can access it using the SEC's EDGAR system. And additionally, 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. Detailed information of our current hedge position by quarter are also included on the website.

Now let me turn the call over to Jeff.

Jeffrey L. Ventura

Thank you, Rodney.

We accomplished a lot in 2012 that really helps to set up 2013 and beyond for Range. We continue making progress with our plan of driving up production and reserves on a per-share basis while driving down costs. This is beginning to significantly flow through to our bottom line and will do so in an even more impactful way in 2013.

Looking back at 2012, we sold $600 million of 5% senior subordinated 10-year notes. We also entered into an agreement with Sunoco and INEOS on Mariner East. To the best of my knowledge, Range will become the first company to export ethane from the U.S. by ship to international markets. This project also enabled us to export propane or to sell propane into the East Coast and North East U.S. markets. Importantly, Mariner East, along with our first 2 ethane projects, Mariner West and ATEX, enables Range to grow our Marcellus volumes in the wet portion of the play.

In 2012, we sold our Ardmore Basin assets and some other miscellaneous assets for approximately $170 million. Last evening, we announced that we entered into an agreement to sell our New Mexico assets, plus the Powell Ranch property for $275 million.

At year end 2012, our proved reserves increased 29% to 6.5 Tcfe. We replaced 773% of our production from drilling at an all-in cost of $0.86 per mcfe. Crude oil and NGL reserve volumes increased 64%, while natural gas reserves increased 20%.

Our percentage of proved undeveloped reserves at end 2012 was reduced to 47%. Our unrisked unproved resource potential increased to 48 Tcfe to 68 Tcfe. This is comprised of 35 Tcf to 46 Tcf of natural gas, and 2.3 billion to 3.5 billion barrels of NGLs in crude oil.

As a result of our development activity, we have moved 4.7 Tcf of unproved resource potential to proved reserves over the last 3 years. To put that in perspective, 4.7 Tcfe is more than our entire company's total reserves just 2 years ago. Because of this excellent performance, our total DD&A rate has declined from $2.32 per mcfe in 2009 to $1.62 in 2012, and the fourth quarter of 2012 was $1.46.

Looking at the same time period, our operating expenses per mcfe declined from $0.83 to $0.41 in the fourth quarter of 2012 with $0.38. We've also made significant progress with our other unit costs, which Roger will discuss.

Range turned in a very solid, profitable performance in 2012 marked by 36% production growth, a 32% reduction in unit lease operating cost and a 9% reduction in total unit cost. We increased reserves per share net adjusted by 22% over 2011 and increased production per share net adjusted by 29%. The bottom line is that Range is becoming much more capital efficient, and the results are beginning to flow through to net income.

Looking forward into 2013, we believe the bottom line results should be even better. The lower DD&A rate for the full year, along with a lower per-unit operating expense for the entire year, coupled with improving well results should result in a substantial increase in Range's cash flow and profitability for this year.

As we've 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 in our existing plays. The reinvestment risk is low, and the projected rates of return are very good.

The growth is mostly driven by our approximately 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 our approximately 160,000 net acre position in the Mississippian oil play in northern Oklahoma and Kansas. Given the high rate of 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 projected production growth of 20% to 25% per year. With our projections using current strip pricing, we reduce our leverage with time as we drive up production and cash flow.

In addition to the Marcellus and Mississippian plays, we believe that we have great prospectivity in the Upper Devonian, Utica, Cline Shale and Wolfberry. Ray will update you on the progress in all of these plays.

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

Ray N. Walker

Thanks, Jeff.

Our technical and operating teams have positioned us with large, high-quality acreage positions in the core sweet spots of some of the highest-quality plays with the best economics onshore U.S. We're continuing to see improvements in well performance, cost, LOEs and margins, resulting in increasing cash flow and higher returns. We're seeing significant growth in reserves in a time where reserve write-downs are common. We've made some highly innovative and strategic decisions in the midstream and downstream arenas that have opened up and solidified our logistics for marketing our oil, gas and NGLs with market-leading economics.

The result is a portfolio of opportunities represented by large-scale, low-risk, high-quality acreage positions that allow for long-term economies of scale. We believe these opportunities will yield consistent and significant growth for many years to come.

Let me start with a few comments on reserves. I think it's critical that we point out that even in light of greatly reduced natural gas prices, we had exceptional growth of reserves in 2012. We recognized a 29% gain in total reserves year-over-year while decreasing our PUD percentage by 10% and increasing liquids reserves by 64%.

We decreased the ratio of PUDs to proved developed in the Marcellus from 1.7 down to 1.2. We think all of this speaks volumes about our asset quality, especially when considering that we've moved 4.7 Tcf equivalent of potential to proved reserves over the past 3 years and yet we still increased our resource potential in 2012 by 12%. Again, it's a true reflection of our large de-risked and high-quality assets, as well as the exceptional performance of our teams.

Now let me point out a few things about the Marcellus. I'd like to make 4 points. Let me summarize first and then I'll go through in more detail.

Number one, we have a large, high-quality position that we control; number two, our position is largely de-risked; number three, well performance and economics continue to improve; and number four, our marketing team has us well positioned for future growth.

So now let me expand on those points.

Number one. Not only do we have approximately 1 million net acres in Pennsylvania, of which a large portion is prospective for the Marcellus, we believe our acreage encompasses very high-quality reservoir rock in both the dry and liquids-rich areas. We've been working for years now to consolidate and high grade our acreage positions and, in essence, we believe not only have quantity, we have exceptional quality in core areas.

Number two. Our position is largely de-risked in Southwest and Northeast Pennsylvania. To illustrate, in 2006, on my very first trip to Pennsylvania, I was up there to work on the very first horizontal well, which was the fifth well ever spud in the Marcellus. Today, there are approximately 7,000 Marcellus wells that are either drilling, completing or producing. Marcellus is producing close to 9 Bcf equivalent per day and is now the largest-producing gas field in the U.S. and still growing. For the last couple of years, Marcellus operators have begun exchanging data, analyses and results on a regular basis, resulting in everyone going up the learning curve a whole lot faster.

If you look at Slide 12 and also at Slide 30 in our presentation on the website, you can see why we say that our acreage is largely de-risked by thousands of wells with now up to 7 years of production history. This is a large part of why we believe we have line-of-sight growth and can consistently grow at 20% to 25% corporately in the future.

Number three, we are continuing to see improving well performance, better efficiencies and are implementing well designs that continue to improve our returns all across the Marcellus. In our investor presentation, we've updated our economics for the wet and super-rich areas, reflective of our 2012 performance. The wet area wells went up to 8.7 Bcf equivalent, which is made up of 712,000 barrels of liquids and 4.4 Bcf of gas, which calculates 49% liquids. And for the super-rich area, our EUR is now 1.44 million Boe, which is 824,000 barrels of liquids and 3.7 Bcf of gas, which is 57% liquids. Importantly, in the super-rich area, the condensate is 109,000 barrels as compared to 27,000 barrels in the wet area. Also, the new economics for the wet and super-rich areas now reflect full ethane extraction as we will commence extracting and selling ethane this year.

Of note, let me point out a 3-well pad in the super-rich area that came online since our last call at a combined rate of over 6,100 barrels of oil equivalent per day. That's an average of over 2,000 Boe per day each. The wells on that pad had an average lateral length of 3,358 feet in 18 stages, and the combined production was 1,200 barrels of condensate, almost 3,000 barrels of NGLs and 11.7 million gas, which means the production is over 68% liquids, of which 29% of the liquids is condensate.

Just last month, we brought online another super-rich area pad with just 2 wells that averaged 3,356 foot laterals, with 17- and 18-stage completions that produced a combined total of 6,866 Boe per day, which is 793 barrels of condensate, 3,200 barrels of NGLs and 16.9 million of gas, which is 59% liquids, of which 20% of that was condensate. I think these 5 wells clearly illustrate the exciting potential of the super-rich area. We're continuing to see improving well performance and EURs as we implement better landing targets, RCS completions, longer laterals and more efficient frac designs. Our teams are continually introducing innovative technologies and strategic analysis techniques, and we still believe we'll see significant additional improvements in the future.

And number four, we have midstream infrastructure, transportation arrangements, sales contracts and marketing deals in place to handle our production well into the future. Our team has literally been working for years on highly strategic and innovative solutions for all of our products. The recent ethane arrangements are excellent examples of these types of innovative solutions, which opened up entirely new markets like the international markets via Mariner East. These solutions position us with industry-leading returns and some of the lowest fee arrangements, connecting us to some of the best markets, including the premium-priced international markets.

So in the Marcellus, number one, we have a large, high-quality position that we control; number two, it's largely de-risked by thousands of wells and actual production; number three, well performance and economics continue to improve; and number four, our marketing team has us positioned strategically to move our products with industry-leading terms for years to come.

In summary, we believe we're positioned for line-of-sight growth with great economics for many years.

In the Mississippian play, we have approximately 160,000 net acres located along the Nemaha Ridge. Like the Marcellus, we believe it's really important where your acreage is located, and we believe our position on the ridge is highly prospective. Please refer to the press release for the details of the wells brought online in the fourth quarter.

I'd like to point out that we're still seeing great results, and we recently brought online a well at over 810 Boe per day. Also, we're announcing the 30-day rates of the 2 fourth quarter wells, and those wells are averaging over 800 and 600 Boe per day for the 30 days. We have 5 rigs running, and the current plan is to bring online 51 wells and 17 salt water disposal wells this year.

We will deploy the majority of our capital and resources in 2013 in the wet and super-rich Marcellus and the Mississippian oil play, with the split being approximately 80% to the Marcellus and 15% to the Mississippian.

I'd like to now move on and bring you up to speed on the other projects in our portfolio, namely the Wolfberry, the Cline and the wet Utica in Northwest Pennsylvania. Our position in all 3 of these plays is predominantly HBP. And therefore, we fully control the timing of development.

While we had to bear essentially all the cost of the learning curve in the Marcellus and, to some extent, in the Mississippian, we can enjoy a less risky approach in these 3 areas. Because we are largely HBP, we can allow industry to move up the learning curve and bear those costs while we focus our capital and our resources in our lower-risk, lower-costs and higher-rate-of-return projects like the wet and super-rich Marcellus. This is a great position to be in.

So in West Texas, the Wolfberry and Cline continue to see significant activity offsetting our Conger Field. In the Wolfberry, we drilled and completed 5 wells in 2012. We saw the cost of the Wolfberry wells decrease by over 30% in just those few wells in 2012. Our plan in 2013 is to drill 5 additional Wolfberry wells and do a few recompletions while we monitor the considerable offset activity throughout the year.

Our third Cline well had a max 24-hour rate of 620 Boe per day, and it was a 4,000-foot lateral with 16 stages. Industry is drilling quite a few wells in the area with much longer laterals and more stages. In fact, if you look at Slide 53 in our presentation, you can see there's a lot of activity directly offsetting our position. In the Cline, we believe there will be close to 50 wells drilled all around our Conger Field this year by Devon, Oxy, Apache, Laredo, FireWheel and others. Our team is actively working with the offset operators to exchange data and better understand the play. Importantly, there are now significant tests near our position with impressive production rates, indicating that the play could have significant upside.

In summary, we're excited about the potential, and it appears we'll learn a lot more about this play throughout the year.

Let me now update you on the first test well of the wet Utica in Northwest Pennsylvania. It had 285 feet of thickness, it's got all the right liquids-rich characteristics, good reservoir pressure, and the initial test rate was 1.4 million cubic feet equivalent per day. Along with the cores and logs, we did perform a significant amount of diagnostics during the completion. Those diagnostics determined that our completion was not optimal as it frac-ed mostly out of zone. However, there is good direction as to how we optimize the next step in order to achieve a better completion by moving the target and changing our frac designs. We have seen this in other areas like the Marcellus, and it certainly indicates a really good way going forward. We're working closely with our partner, Cabot, and offset operators to exchange data and results.

If you look at Slide 46 on our presentation, you can identify this well and our 181,000 net acre position, along with significant offset activity by operators like Halcón, Hilcorp, Seneca, Shell and Chevron. We believe there will be approximately a dozen wells drilled, offsetting our position this year, and we'll, of course, be monitoring closely as we work on the timing of the next test. Being this is a new area, we have a lot to learn, and the good news is we like what we see. The area has all the right ingredients, the right TOC, the right liquids characteristics, the right pressures, and we have a lot of science indicating what the next step should be.

I continue to be very proud of our efforts in safety, environmental protections, community stewardship and communications. On the safety front, for example, our OSHA incident rate for 2012 was 19% better than the peer group, and our lost time rate was 21% better than the peer group. Although the only acceptable rate is 0, we are seeing steady and measurable improvement. It's a core value here at Range, and we definitely see it translate to the bottom line.

Like Jeff said, 2012 was an important year and it sets the stage well for a terrific 2013. We believe that with our assets and our great team, we can grow significantly and consistently for many years to come.

Now over to Roger.

Roger S. Manny

Thanks, Ray.

Any way you look at it, the fourth quarter was a great one, both operationally and financially. Strong production growth, improved capital efficiency, lower unit costs and better realized prices led to significant top line and bottom line growth.

The fourth quarter of 2012 saw a notable improvement in cash margins and cash flow from the prior quarter. Cash margin was $3.12 in mcfe, up 22% from the third quarter, and cash flow was $248 million, up 31% from the third quarter figure.

Cash flow per fully diluted share in the fourth quarter was $1.54, $0.18 above analyst consensus estimate and 14% above the fourth quarter of last year. EBITDAX for the fourth quarter was $287 million.

For the entire year, cash flow totaled $756 million, 2% higher than the 2011 figure, and EBITDAX for all of 2012 was $910 million. GAAP net income for the fourth quarter and full year 2012 was $53 million and $13 million, respectively.

Fourth quarter earnings, calculated using analyst methodology, were $73 million, or $0.46 per fully diluted share, that's $0.17 above the analysts' consensus estimate. As Rodney mentioned, the Range corporate website contains detailed non-GAAP to GAAP reconciliations of these non-GAAP figures that I just referenced.

Looking closely at the income statement, there was a line item reclassification this quarter. As our Appalachian production volume has grown, we have engaged in limited third-party gas purchases and resales solely to accommodate seasonal swings in regional supply and demand. To better reflect this activity, we have reclassified the associated revenue and expense under the income statement caption Brokered Natural Gas and Marketing. This activity previously netted into other revenue and it's conducted to support our marketing effort, and it's not intended to operate as a separate profit center. We expect this activity on its own will at best be breakeven and seasonal.

Moving to the cost structure performance in the fourth quarter, cash direct operating costs, including workovers, came in at $0.38 per mcfe. That's $0.02 below last quarter and $0.07 below the fourth quarter of last year. One of the truths in the E&P business is that it costs more to operate an oil or gas -- wet gas well than it does a flowing dry gas well. So with our liquids production rising, sooner or later, our unit operating costs are going to flatten and possibly begin to increase slightly. Fortunately, quarter-after-quarter, our production teams have done such a terrific job reducing operating cost. We have thus far enjoyed the higher profit margins that come with liquids without the higher unit costs associated with greater liquids production. And if we're able to continue this trend, the first quarter 2013 cash direct operating cost, including workovers, should be relatively flat at $0.38 to $0.40 in mcfe.

Third party gathering, transportation and compression expense was $0.71 in mcfe. That's the same as last quarter, and $0.11 higher than last year, reflecting the continued build out of our gathering lines and related systems. This expense is anticipated to be up slightly in the first quarter to between $0.75 and $0.77 in mcfe.

Production in ad valorem taxes for the fourth quarter totaled $0.12 per mcfe, $0.02 higher than last year due to higher Pennsylvania impact fees. The Pennsylvania impact fee amounted to $6.5 million during the fourth quarter, or $0.09 per mcfe based on total company production.

Now first quarter 2013 production taxes, including a $6.2 million impact fee estimate, should be in the $0.14 to $0.15 per mcfe range, reflecting both higher prices and first quarter Pennsylvania drilling activity.

Exploration expense in the fourth quarter, excluding non-cash comp, was $17 million, or $7 million below last year, mostly due to lower seismic expenditures. Now based on our 2013 seismic budget, first quarter 2013 exploration expense should be in the $18 million to $20 million range.

Abandonment and impairment of unproved property during the fourth quarter was $21 million, and we anticipate this quarterly expense to decline in 2013, with a first quarter estimate of $15 million to $17 million.

Cash G&A expense was $0.40 in mcfe in the fourth quarter, $0.06 lower than last quarter and $0.17 lower than last year's fourth quarter.

We continue to see improvement in unit cost G&A as we gain economies of scale in our high-growth, large-scale plays. We expect first quarter cash G&A to be around $0.40 to $0.42 in mcfe.

As last year's Range capital program was heavily front-end loaded, our fourth quarter production increased much faster than our debt, which effectively reduced our interest expense per mcfe in the fourth quarter down to $0.58 in mcfe. First quarter 2013 should see this figure decline further to approximately $0.55 to $0.57.

The highly favorable 2012 drilling results reported in our January 30 reserves release have already begun flowing through the income statement. Reflecting continued improvement in our capital efficiency, our fourth quarter DD&A rate declined to $1.46 per mcfe. This rate is $0.23 lower than last year and places Range among the very best of our peer group that employ the Successful Efforts Accounting method. The DD&A rate will vary slightly from quarter-to-quarter based on production mix. And we expect the DD&A rate in the first quarter to be between $1.46 and $1.48 in mcfe.

Now turning over to the balance sheet for a moment. There are 2 items to highlight. First, in late December, we used $259 million of our revolving bank credit facility to fully redeem, including expenses, our $250 million of callable 7 1/2% senior sub-notes that were scheduled to mature in 2017. The early redemption will reduce interest expense. And with over $1 billion in available borrowing capacity remaining under the bank borrowing base, the redemption does not materially affect our liquidity.

Second, during the fourth quarter, we closed on our Ardmore Woodford asset sale. And as Jeff mentioned, most recently, we entered into a definitive agreement to sell a portion of our Permian Basin assets for approximately $275 million, subject to usual closing adjustments.

Now adjusting our year end 2012 debt balance for the completed and expected asset sale proceeds reduces our debt to trailing 4-quarter EBITDAX ratio to a pro forma figure of 2.9x. As we have said before, while we are comfortable with our leverage in the low 3x range, bringing the ratio back below 3x in 2013 has been one of our objectives. And when the Permian asset sale closes, we should be back below the 3x level.

Now for many years, Range has relied upon a disciplined hedging program to provide certainty of cash flow so that we may more effectively plan and execute our capital program. And from 2009 through 2012, our hedging program has provided just over $900 million in revenue to help fund our projects. During the fourth quarter of 2012 and year-to-date 2013, we have continued to add to our hedge position with approximately 70% of our 2013 natural gas hedged at a floor price of $4.18 in Mmbtu, and over 80% of our 2013 oil production hedged at a floor price of $94.65 a barrel.

Please reference our press release and website for detailed hedge volumes and prices for 2013 through 2015.

In summary, thanks to the hard work of our employees, the fourth quarter was -- of 2012 was an outstanding quarter by all measures, significant increases in production at lower unit cost, driving improved cash flow and earnings. With one asset sale closed last quarter and another under contract, leverage has declined from its third quarter 2012 peak. Going forward, continued capital discipline, cost control and production growth should lead to another year of success.

Jeff, back to you.

Jeffrey L. Ventura

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

Question-and-Answer Session


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

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

Just on the Mississippian. You've talked about your portion of the play, and the results in your portion of the play along the Nemaha Ridge have been different and a little bit better than to the western part in terms of EURs and potential spacing. When you look at your Mississippian and the 80-acre spacing and the longer laterals, can you talk about some of the variability? And how much of that is driven by the chat and how the presence of that chat in -- if that creates variability, how you work through that?

Ray N. Walker

Yes. Sure, Ron. This is Ray. It's a good question. The Nemaha Ridge -- well, let me back up and kind of step out broader. The Mississippian, and Jeff said it before, and I think most of us agree, is a huge stratigraphic play and it's going to have structural enhancements. And we believe one of those structural enhancements is the Nemaha Uplift. And one of the enhancements on the Uplift is the fact that there is more chat present in general, and the chat has a lot higher porosity, better perms. So i.e., more storage capacity for hydrocarbons there. It is a very diverse and unconventional type structure, so we are still really, really early. When you look at the amount of acreage that we have in our 160,000-acre position there, just a few wells literally that we've drilled to date. So what we've done is very similar to what we did in the Marcellus, and we're going to show you what the wells are doing, good, bad and ugly as time goes on. So what you see in our presentation is what the wells look like that we did, the early vintage, 2009 to '11, which were primarily shorter laterals, and came in at around, I think, 485 Mboe-type wells. And then the 2012 wells, which look like they're on -- around a 600 Mboe-type curve, and all of that is in our presentation, so what we'll continue to do is set that out there. But literally, we don't have enough wells yet to understand or be able to predict what the whole thing will do. So we're going to take again an approach we did very much like the Marcellus and just tell you what the data looks like as time goes on. So quarter-by-quarter, we'll continue to update those curves, and we'll just put that data out there. And you'll know what we know going forward.

Jeffrey L. Ventura

Yes. Let me tack onto that a little bit. I think -- if you look on Slide 48, it's on our website, and what it shows is the historical cumulative oil production per well from the Mississippian. This is looking at all the historical vertical wells, and there's a lot of them. And by far and away, the best vertical wells in the play are on the northern part of the Nemaha Uplift in Kay County, Cowley and Sumner up into Kansas, right through that little area. The vertical wells in Kay County are the highest. They're at 85,000 barrels per well. If you think about a horizontal well, really, it's a multiplier of a vertical. So a horizontal could be, in any play, really 3x a vertical, 4x, 5x, 6x or whatever. So one good indication of where the best horizontal wells are going to be is look where the best vertical wells are. So -- and to compare that, if you go way off to the western side of that map, or that stratigraphic trap shown in green, as Ray mentioned, the vertical wells, say, in Woods, Barber, Comanche counties are 13,000 barrels, 22,000 versus 85,000. So they're significantly different. And then there's a slide right next to it, on 49, that shows -- as you go far west, the other thing that happens is the play gets gassier. So we are, there's better vertical wells, higher oil cuts. Then the question is why, and it's back to those things that Ray said. We think when you're up on the Uplift, or the things you mentioned, Rod, early on, when you're on the Uplift, you're -- one, you're higher structurally, which we think is a positive; two, you have a chat component that when you're on the uplift that you have, but when you're off it, you tend to lose. In fact, it's not just being on the uplift, you've got to be on the northern part of the uplift to have that chat component, plus, you have a higher degree of fracturing up on the uplift which enhances permeability. So we think that's what supports better vertical wells, so far, or better horizontal wells. And then like Ray said, we'll just update you with time as they are just like we did in the Marcellus.

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

And is that also driving a little bit tighter spacing on your portion or what's driving the potential for tighter spacing versus...

Ray N. Walker

Yes. If you go to Slide 47, and what drives that, because you have that chat component, you have higher porosity, you have better storage and you have a higher oil cut, you have more hydrocarbon in place. On Slide 47, when you look at where we are, the EUR under those various types of completions, even if you use 600,000 boes per well, we're only recovering 6% to 11% of the oil in place, so a very reasonable recovery with that kind of well, so that's what drives the tighter spacing is really 2 things, it's higher hydrocarbon in place, and then just simplistically, we have a higher oil cut. Again, going back to where we are on Slide 49, in Kay County and Cowley County, Kansas, those 2 areas, 92%, 95% of the wells are oil wells. So if you go up to the west side of the map, somewhere between 38% and 47% of the wells are oil wells. So it's a lot gassier. And generally speaking, the gassier you are, the wider the spacing. The oilier you are, the tighter the spacing. The more hydrocarbon in place, the tighter the spacing, the less, the wider the spacing. So that's why we think what we think and it's supported by the wells we've drilled so far and we'll just keep updating you.

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

And then just to clarify on the Utica, it sounds like technically, it has all the characteristics you want. Is it just a matter of finding where within the 285-foot of pay is the optimal place to land the lateral to allow you to effectively stimulate the Utica/Point Pleasant? And is there something, if I look at your map, it looks like a lot of industry activity to this point is really focused on the central to southern part of your acreage through Crawford, Venango, and Mercer County. Is that just because we have more core data from vertical wells in that area or is there something that you think changes as you move North and East into Warren County?

Ray N. Walker

Well, let me start with the first question. I mean we are very encouraged by what we see. It's the first well in a pretty big area. And when you combine what we learned on this well with what we're -- the little bit of data we have so far from working with the offset operators, it's a very encouraging area. I mean, we saw TOCs by volume in the 10% range. We got a good pressure. We got 63 gravity condensate. Everything is lining up exactly like it should. But when you drill a first well like that, we went up the learning curve and we spent a lot of money in the Marcellus trying to figure out the ultimate best landing target. And here we are, several years later, we're still optimizing that and making big improvements. And a lot of these recent well improvements that we see in the super-rich and wet areas is very much that, it's landing the target in the right place and pumping the right-sized frac job so that you optimally stimulate what you're trying to go after and not stimulate a bunch of other rock and connect up a bunch of rock that does you no good. What we saw in the Utica was we simply put the target in what we thought was the best spot at that point with the data that we have. But clearly, when it frac-ed, we now know that the frac did not go where we wanted it to. So that means we take that data, we have a lot of right mechanics data, full core data, all that stuff that tells us we need to put our target in a different spot in the next test. So our plan, again, is to HBP so we can kind of sit back and we can kind of control our own destiny, and we've talked with our partner, they're very much on board with this. They also are very encouraged by it. And so we're going to sit back and trade information with some offset operators, see what some of their experiences are, and then we'll kind of figure out what the timing of our next test should be. But the good news is, I can't say it strong enough, I mean we're really encouraged that we think we know exactly what to do next time. And 1.4 million cubic feet a day equivalent test, while disappointing, is not a bad test. I mean it did make 1.5 million a day, so it's a pretty decent well. So we're pretty encouraged by the area. But again, it's HBP, we can sit back. We don't have really hardly any capital allocated to it this year. This year, we're really focusing on the super-rich and wet Marcellus, that's where 80% of our liquids are going. And our 80% of our capital and resources are going. And I always want to direct you back to -- did I tell you about those 5 wells that we just brought online? And then if you're looking in the super-rich area, in 2012, we've brought online 51 wells there and we're saying the average is 1.44 million boe per well. I mean that's phenomenal stuff and that's where we're focusing our time and resources and science this year in that area, because it's really phenomenal and with these recent wells, we're getting real excited about what we've got there.

Jeffrey L. Ventura

Let me, again, add on a little bit to what Ray is saying. To look at that first Utica test, 285 feet of pay, and we got 1.4 million, 63 gravity condensate, good pressure, all that kind of stuff. Go back and look at the initial Marcellus wells. To put it in context, the Marcellus in Washington County is about a 80 to 100 feet thick, 110 feet thick where a lot of the stuff we're drilling. Here, it's 3x thicker. Going back to the first 3 Marcellus, and I've told the story several times and it's sort of fun telling. The first 3 wells, if you just look within that 100 feet, one of those wells was landed at the bottom, it made 20 Mcf a day, the one in the middle made about 200, the one at the top made about 700. And that was our first 3 Marcellus tries. We ended up just moving the fourth well. Actually Bill Zagorski, the -- now considered the father of the Marcellus, drew a little 3-point correlation, and said, "Hey, move it up a little bit, change where you landed it within that 100 foot interval, just move it up at the top a little more," and the fourth well was 3.4 million a day. And then now when we're drilling and completing with what we learned right in that same area, the wells are 10 million a day plus a lot of liquids, I'm going on an equivalent basis. So you think about here, now you've got instead of a 100-foot to play with like in the Marcellus, you got 285 feet. So the fact that we've got 1.4 million a day from something that's really ineffectively stimulated if we land it properly and stimulate it effectively, what could the well be? Clearly, in the Marcellus, we cracked the code, and now it's the largest producing gas field in the country, that we have a million net acres in the state, a lot of which is prospected for. So we're excited about the position, 190,000 net acres, it has all the right ingredients. And it's part of our dream factor. Now, we're part of the upside. Like Ray said, we're going to be driven by that 1 million acre position that's going to give us the 20% to 25% line-of-sight growth for many years. I'm going to be delevering with time, even with the little bit of outspend, it puts us in a great position. And we've got great upside in all those in the Utica, coupled with all the things that Ray said earlier. We're still excited about the Cline, the Wolfberry, the Upper Devonian, looks very, very encouraging, and in the Mississippian as well.


Our next question comes from Doug Leggate of Bank of America Merrill Lynch.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

I've got a couple. If I could go back to the Mississippian real quick, when you think about capital allocation, you guys have talked about moving up to 10 rigs and maybe 15 rigs over the next couple of years, hold acreage, how should we think about how you're allocating capital in terms of -- does that take money away from something else in terms of activity levels? And this is as a follow-on to Ron's question, can you just confirm that you are using geoscience down at the Mississippi at this point?

Jeffrey L. Ventura

What was the last sentence? We heard you up to the last sentence.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

Are you guys -- there's been a lot of debate over the effectiveness of using geoscience in the Mississippi. I just wanted to check where you guys are in that side of the debate.

Jeffrey L. Ventura

Define what is geoscience -- using geoscience?

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

Seismic to avoid faulting basically.

Jeffrey L. Ventura

Yes. Let me start with capital allocation. We've always been driven by the same strategy. And our strategy is we want to consistently grow production and reserves per share on a debt-adjusted basis, with one of the best cost structures out there, build and high-grade the inventory. We direct our -- simplistically, we direct our capital into our highest rate of return, best economic projects that we have that are large-scale and repeatable. Clearly, that's right now the Marcellus. And no matter what happens, it's almost hard to think that it would be anything other than the Marcellus because we have a million net acres in the state of Pennsylvania, all of which is not only highly prospective for the Marcellus but it's highly prospective, a lot of it, for the Upper Devonian and the Utica. So really, because it's a little bit stacked pays in areas we're in, you can argue that instead of having a million net acres, we have 3 million net acres or 2.5 million net acres or something like that. And again, I mean, the Marcellus has up to 7 years' worth of history. And like Ray said, 7,000 wells now that define when we drill in there, we have great upside and great prospectivity. And just to drive home the point, when you look at Slide -- and I'm flipping through the package, when you look at just the south -- or when you look at Slide 13, and this just considers the southwest portion of our position. It ignores -- just looking at 540,000 net acres, using 80-acre spacing, which I think is extremely conservative, I would argue and we have pilots we haven't talked about, you can down space that and we've got good evidence, we just haven't put it out yet. And some of those down space pilots are 2 years old. But ignoring that, we still have 6,750 wells to drill. So if you look at what we've drilled so far, we've only drilled 6% of our acreage. So as of roughly year end, on a net basis, we have 470 million per day coming from 6% of our acreage. If you do the simplistic math and assumed it was all the same and you can argue, there's enough data down there to tell you there's going to be high-quality wells all through there, and you divide 470 million by 0.06, that's 7.8 boes per day. I've said many, many times, I think our Marcellus position is, again, just looking at a part of it, without down spacing, has the potential to get us to 2 to 3 boes per day. And we said corporately, we're going to grow line of sight 20% to 25% for many years, which gets you to that rate in relatively short order when you're growing at that kind of compounded rate. So our capital is going to be driven -- our capital allocation is driven by high rate of return, large-scale repeatable projects. That's why 80% roughly of our capital is going to go into the play, and then a high percentage of our capital will continue to go in there. That being said, if you look at the Mississippian, what we said, we have 160,000 net acres, we think is very well positioned up on the Nemaha Ridge for all those reasons we just said, that I won't repeat, when Ron asked. So we think all that acreage is highly prospective. The difference is the Marcellus has 7 years' worth of history with brand new horizontal wells and high quality data and there's 7,000 new wells that define it. In the Mississippian, we're just starting. We started there in 2004, but we started in the Tonkawa and then we started with our vertical program. We drilled a number of good vertical wells. Then we converted in 2009 to '11 and drilled a handful of good horizontal wells. And we reported those, over 485,000 boe. They're still hanging in there, they look good. Last year, we drilled a handful of wells, more horizontal, but it's still a handful of wells. And those wells were 600,000. And we'll update you with time. But when you look at -- so it's new drilling and it's really just across the southern part of our play, almost spans the width of the ridge, but it's not 7 years' worth of history and 7,000 wells, it's a couple years' worth of history and 20 or 30 wells. So as with time, if the Mississippi continues to drill out, and it may or may not as we go north. Hopefully, it's just like the Marcellus and it does, and if it does, then we'll continue to ramp up our drilling, 5 to 10 to 15 rigs, and we'll do that. But again, the big driver, the big gorilla is the Marcellus. It's the largest producing gas field in the country. We've got the dominant position in it. And we've got line-of-sight growth to grow for many years. And these other plays were all enhancements to that. If the Cline drills out or the Wolfberry, you'll see us allocate a little capital, and the capital allocation is really driven by rate of return, by economics, large-scale and repeatability.

Ray N. Walker

That was a long-winded answer but it was a great question, and that's how we think about it.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

I guess my follow-up, hopefully, is a little quicker.

Jeffrey L. Ventura

Alan Farquharson just reminded me, I want to answer one of your questions. It was -- you brought up the geoscience or seismic. So still want to answer the question. We do use seismic in a lot of the areas we drill and we use them for different reasons. So early on, and it goes back to the history of Tonkawa field, we got in Tonkawa, which is the big part of our Mississippian position. It's that group of wells on the southern end. And when you look at that position on the southern end, it was the largest light oil field back in the 1917, 1920, in that era. And what we did is start reactivating it by drilling Tonkawa wells. After successfully doing that, a couple of years later, we shot a 3D over it, which, at the time, amazed me as Chief Operating Officer, and those guys, after a great sales pitch, said, "Hey, we wanted to 3D it." I said, "How in the world could you have missed anything?" There's a gazillion wells out there and being an engineer, I'm thinking that -- and but sure enough, when you look, it has that same characteristic like a lot of our plays. It's stacked pay. It's not just the Tonkawa, it was the Mississippian below. And remember the Tonkawa was at 2,700 feet, the Mississippian is at 4,000, then they had some neat stuff in the Red Fork, and then the Wilcox. And then the Woodford. And so even though basement's relatively high and it's -- you're looking at that interval from 2,700 feet to 5,000 or 5,500 feet, there's 20-some stacked pays in there that are all oil charge. So we started drilling deeper and the seismic was actually useful to help identify all those different upsides and targets. Again, on a broader basis, if you look at the other areas we're in like Pennsylvania, great stack pay potential, and we talk a lot about the Upper Devonian, we talk about the Marcellus and we talk about the Utica, but I guarantee you, there's tons of conventional pays that are stacked in there. So seismic helps us identify, look at those other targets, it helps us target wells. So it's useful as a tool. It's not critical. It wasn't -- I won't say it's critical in the Marcellus or it's critical in the Mississippian, but clearly, it adds value not only in those horizons but helping us understand the full section in the hydrocarbon charge and what we have.


Our next question comes from Dan McSpirit of BMO Capital Markets.

Dan McSpirit - BMO Capital Markets U.S.

The question is often asked of producers, when will operations turn cash flow neutral or cash flow positive? Is that in itself a goal of Range Resources or important to the company? And if it is, how do you balance that with accelerating the resource capture and bringing the value forward?

Jeffrey L. Ventura

That's a great question. And I think if you look at our plan and what we're saying today and I think what we're saying consistently is, we believe we have 20% to 25% line-of-sight production growth for many years, and it's all that stuff and part of the answer to the previous question. And based on our modeling and based on current strip pricing and with all the assumptions that go with it, but a very bottom's up driven plan based on thousands of wells and all the guys in the divisions and led by Ray and Alan and others. When you look at that plan, we can outspend cash flow by $250 million to $350 million per year, still grow at 20% to 25%, but importantly, we're delevering with time, and I'm going to talk a little bit about it, then turn it over to Roger. So when you look at like debt to EBITDAX, our debt to EBITDAX, even with that outspend, continues to drift down with time. If you think about NAV and pulling the value forward, okay, I'm just simplistically, again, if we're growing at 20% to 25% on a compounded basis, roughly, every 3 years, we'll double. So we would double in 3 years and double again. So if you take our fourth quarter volumes at -- roughly, I'm rounding down to 800 million or 0.8 boes per day net, in 3 years, you're looking at roughly 1.6 growing at that compounded rate, if we can successfully do that and we've got the database and all those wells to say we believe we can, led by our million-acre position in Pennsylvania, then we're doubling from 0.8 to 1.6 in roughly 3 years. And then in roughly another 3 years, we'll be at roughly 3 boes per day, which is a number that I talked about earlier. To me, that's pulling forward a heck of a lot of value. And then what's great about that, it's in largely low risk plays with strong economics and strong returns and a very low cost structure. When we talk about our resource potential being enormous and we put a number out there, but it's based on a ton of data and a ton of support in the best play -- best gas play, clearly, out there, I would argue one of the best plays overall. So we think we're pulling forward a lot of NAV. We think we're aggressively driving up production with time and delevering by outspending by $250 million to $350 million per year. Roger, do you want to tack on with that?

Roger S. Manny

Yes. Yes, I will. Thanks, Jeff. Yes, Dan, I think becoming cash flow positive or cash flow neutral in and of itself is not real high on our priority list. We're much more concerned about bringing the NAV forward, drilling up our high return projects. I mean, there's a lot of companies out there that are cash flow positive because they don't have anything economic to drill right now. We're not that company. So deciding where we set the drilling throttle, where we allocate capital. As you probably know, having followed the company, every AFE over $200,000, is signed off on by Alan, Jeff, me, Ray, all individually. So we're very granular and very thorough in our capital allocation decisions. So at this point in our growth cycle, I think just as Jeff described, you're going to see us keep the drilling throttle at we consider an optimal setting, where we're probably still slightly overspending but still delevering and keeping leverage in check.

Dan McSpirit - BMO Capital Markets U.S.

Got it. I appreciate that answer. I look at cash flow neutral state more of a result than a goal myself, so in agreement there. Another subject often discussed is the difference between returns at the field level, and of course, those at the corporate level, there being a disconnect between the 2. Where do you see returns at the corporate level maybe measured by return on capital employed trending over the next several years?

Roger S. Manny

Yes. That's a good question, Dan. I mean return on capital employed is a tough one, because you can reduce your capital spending and you look like a rock star and you're not really bringing NAV forward and painting the value that you could, it's a suboptimal way to develop your resource base. So I think it's a troublesome measure in and of itself. I think in my case, it's a little like NAV. You want to adjust the inputs and see what happens to the outputs, it's the relative measure that counts. And when you look at the relative measures at Range, the DD&A rate falling, I think is a really key and underappreciated metric. When you look out there over the last year, there -- it used to be the DD&A rates of the E&P sector moved somewhat in tandem, albeit, differences between the full costers [ph] and the successful efforts guys. But lately, what we've seen is companies with big feelings it has to write down. So its DD&A rate actually went -- goes up, which is very odd. And Range is one of the few that has consistently seen our DD&A rate go down, and that's clearly an indication of our improved capital efficiency and lower cost structure, which, to your point, will flow to the bottom line. It's why we just had our second year of consecutive profitability on a net income basis despite really low, low prices the last 2 years.

Jeffrey L. Ventura

I think as we continue to build volumes in high-quality plays like the Marcellus, more and more of that's going to flow through to the bottom line or the net income. You're seeing it now, you're going to see it a lot more this year and off in to the future.

Dan McSpirit - BMO Capital Markets U.S.

Understood. And one last one for me, if I may. Do you have the itch to sell more Permian Basin properties based on the attractive price received in the recent deal here? I ask simply in the context of present value. Why not monetize the asset today and recycle the cash, the capital into higher return drilling opportunities found, say, in the wet gas Marcellus or the Mississippian?

Jeffrey L. Ventura

Well, that's a great question. We look at that stuff all the time and we constantly look at what we think adds the most value for the company. Well, I think we're in a great shape, again 20% to 25% line-of-sight growth. We got great balance sheet, Roger does a fantastic job monitoring that. And periodically, I mean, look back, we've sold $2.3 billion worth of property so we're not in love with our assets. We're trying to be one of the best performing companies out there, not just growth for growth's sake, but it's better is better, not necessarily bigger is better. But when you look -- so we have great opportunity. And where we're positioned now, we have the ability with that small outspend to continue to grow significantly with time. That being said, we've cleaned up, and clearly, New Mexico for us was only 7,000 net acres. It was a relatively small position. We got a great price for it. We didn't see a lot of upside. It wasn't going to move the needle for us. The Ardmore Basin sale was the same thing, I think it was 14,000 net acres. What we really we have left in the Permian is Conger. Conger is different, I think, and it's something to look at, and we need to understand a little bit better. Conger -- our Conger -- basically 100,000 net acres, but in essence, it's almost all of which is held by production. Goes back, it has those same characteristics. We own all depth rights, it's stacked pay, rich hydrocarbon charge. It worked well for us in the Canyon. And if you -- for the people that have been with us for a while, it works well. In the Cisco, it's worked in the Wolfcamp, it's worked in the Leonard. We've drilled some great, strong wells. Now, we're looking at a couple of other horizons or techniques. One is the Cline. The Cline has roughly 300-foot of net thickness across the entire 100,000 net acres. And like Ray said, it's really important. There's going to be a lot of data points coming out this year. We have really high quality operators surrounding us who are going to drill roughly 50 wells that are going to impact our position. The results of their wells will be very meaningful for what we have on our property. Like Ray said, we carried 100% of the R&D in the Marcellus. We don't have to do it out in Conger. But to the extent that works in the Cline, we got 100,000 net acres and you could drill oil wells, could you drill oil wells on 80-acre spacing? I think, clearly, and you could argue, maybe it ought to be tighter, 40 or something. If you used 80-acre spacing, that's over 1,000 wells. If you use 40, it's over 2000 wells. And you can pick numbers. What if the Cline works and the Cline -- the wells stabilize at 50 barrels a day a year out or something, even on the low end, that's over 60,000 barrels net and it's predominantly oil. On the high end, it could be double that. The Wolfberry, stacked payer out there, we're doing a lot of interesting things in the Wolfberry. Our Wolfberry wells are better than competitors so far, again, it's HBP, we're learning a little bit, but that could become a very repeatable play and really even expand beyond what we've talked about publicly so far. So it has a lot of upside. And we want to understand what that is before we decide what to do. I can tell you as a shareholder in the bulk of my net worth, I'm rooting that it works, that's another great opportunity for us. Because going back to that simple strategy of growing production and reserves on a per share basis, net adjusted, and building and high-grading the inventory, who knows, it may be a high-grade. The Marcellus for us, back in 2004 and '05 and '06, was a huge high-grade than what we were doing and really helped to drive results. I think Conger has the ability to be a significant high-grade and it's clearly oil, which could be beneficial.


Our next question comes from Pearce Hammond of Simmons & Company.

Pearce W. Hammond - Simmons & Company International, Research Division

How should we think about lateral length in the Marcellus and the balance that Range has to strike between holding acreage and maximizing well economics? Essentially, do you think your laterals in the Marcellus will increase further over time or lateral length kind of remain unchanged but frac spacing will narrow?

Ray N. Walker

We have definitely seen horizontal lateral lengths increase over time. And I think it has to do with a lot of different factors in southwest Pennsylvania namely. In northeast Pennsylvania, I think it's a little easier to drill longer laterals. You have much bigger tracts of land and it's easier to put those together. It's dry gas. But in the wet and super-rich area, I don't know, did I tell you guys about the 5 wells that we just brought online? They're pretty darn good for 3,300 feet or so. And this year, I think our target -- we put in there, in the economics, our -- what we expect our average laterals to be this year and going into next year. Right now, we rather than look at, like I've said in previous calls and so forth, rather than look at well-by-well economics, and IPs and such, we're much more interested in the total project and how that -- how we ramp that up with the infrastructure so we keep our transportation costs down and our compression cost down, and we fill up the plant at the right level at the right timing, and we HBP acreage all at the same time. Our teams are getting really good at drilling multiple pads from a single surface -- or multiple units from a single-surface pad and different things like that. So we're getting more and more efficient every quarter, every year that goes by in HBP and acreage, and we're beginning to see that focus more to a development mode-type well. I mean we're still a ways away from that. We still have a lot of infrastructure to build. We still have a lot of that kind of thing to happen. But we -- I would forecast that our lateral lengths probably continue to get a little longer over time. I don't see them getting a lot longer anytime soon. But we -- I mean we have drilled a lot longer laterals and we will drill some and in special cases whether it's a land situation or it's just a science test or the reservoir characteristics are a little bit different, where we think we need to drill longer. But right now, we're pretty happy. I think what we're seeing in the super-rich area, we're just knocking it out of the park there. I'm just overly excited about that. And I'll probably tell you about those 5 wells again before the meeting is over.

Pearce W. Hammond - Simmons & Company International, Research Division

And then my follow-up is just staying in the Marcellus, on how tight a spacing are you drilling in the Marcellus right now and how tight do you think it can go?

Ray N. Walker

We, on average, I think in Southwest PA, us and most of the offset operators in that area are pretty much anywhere between 1,500 feet to down to 700 feet between laterals. We typically, when we drill multiple laterals today on a pad, will not generally get closer than 1,000 feet. Now like Jeff said earlier, we have some pilots out there that are 500-foot spacing, which would basically be a 40-acre-type pilot. And those have a couple of years. We haven't released the data on that yet. But I think, today, we're more interested in trying to HBP acreage, while at the same time, building production as efficiently as we can. And like those 5 wells, I told you I'd say that again, those 5 wells, that was 3 wells that's holding a 6 40, and then the other one is 2 wells holding a 6 40. So they're clearly more than 1,000 feet apart. But in general, if we're drilling multi-well situations on a pad, there will be about 1,000 foot today. And I do think that there is significant potential at least in some areas that it's going to go denser than that. And I know EQT and CNX, from time to time, have talked about that also. And so I think there's clearly no question we'll be there. When you look at the Barnett, the granddaddy of all of them, where it all started, I mean there's literally some areas where they're 125 feet apart and they still think there's more gas in play. So who knows where it will eventually go. But the one thing I can say is it they won't be the same everywhere. We sometimes get caught in a trap of thinking the Marcellus is the Marcellus everywhere, and it's considerably different. When you just look at the map of our acres position in the dry and the wet and the super-rich, they're significantly different between those 3 regimes, and even from one edge of one area to the other edge, you see a lot of difference. So I think they'll get longer, but again, we're pretty happy with what we're doing today. So it's pretty exciting.

Jeffrey L. Ventura

Yes. And like Ray said, I mean I think, clearly, we're in a core area. There's other core areas. And then at the end of the day, whether you can infill, just comes down to what's the hydrocarbon you're getting out of the wellbore versus hydrocarbon in place. And there are some areas based on that ratio that will support 40 acres. I won't get into all the details. If you want, call us later, and we'll talk about it.

Let's go to the next question and I believe final question. That was it? Okay. I apologize. I see a lot of other people teed up. So let me say then for all the people that didn't get to ask questions, that we want to make sure we talk to you, make sure to call the IR guys. Our team will be on call. We want to make sure we get to all the people who didn't get a chance to ask questions. And I'll just go with my closing comments then, which is a lot of what I've been saying, is 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. 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. 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. Thank you for participating on the call.


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

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