山脈資源 (RRC) 2012 Q3 法說會逐字稿

Welcome to the Range Resources third-quarter 2012 earnings conference call. This call is being recorded. All lines have been placed on mute to prevent any background noise.

Statements contained in this conference call that are not historical facts are forward-looking statements. Such statements are subject to risks and uncertainties which could cause actual results to differ materially from those in the forward-looking statements. After the speakers' remarks there will be a question-and-answer period.

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

Thank you, operator. Good morning and welcome. Range reported outstanding results for the third quarter with record production and a continuing decrease in unit cost. Both earnings and cash flow per share results were greater than FirstCall 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. Also, Mr. Pinkerton, our Executive Chairman is on the call today.

Range did file our 10-Q with the SEC this morning. It's now available on the home page of our website. Or you are access it using the SEC's EDGAR system. In addition, we've 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 on the call today. We've also added tables which will guide you in the modeling of our future realized prices for natural gas, crude oil and natural gas liquids. Detailed information of our current hedge position by quarter is also included on the website.

Now let me turn the call over to Jeff.

Thank you, Rodney. The third quarter was another great quarter for Range. Production for the third quarter of 2012 was 790 million cubic feet equivalent per day. Which was 47% higher than the third quarter of 2011 and 10% higher than the second quarter of 2012. We're on track to achieve 35% year-over-year growth for 2012 versus 2011 within our capital budget of $1.6 billion.

On the cost side, absolute LOE dollars for the third quarter were below the prior year quarter, resulting in LOE per Mcfe dropping from $0.58 per Mcfe to $0.40 per Mcfe. This is directly related to the quality of the wells that we're drilling and the quality of the teams operating the properties. All-in unit costs continue to drop and are continuing the trend that we have for the first two quarters for 2012. Roger will discuss the cost management and results in more detail in a few minutes.

We also achieved an important marketing milestone in the third quarter. Range announced that we have become the anchor shipper on the Mariner East NGL pipelines project. As the anchor shipper, we have firm transportation to ship 40,000 barrels per day of processed liquids from MarkWest's Houston, Pennsylvania plant to Sunoco's market terminal facility near Philadelphia. The 40,000 barrels per day will consist of 20,000 barrels of ethane per day and 20,000 barrels of propane per day. Under the agreements, we also have access to a very significant portion of the 1 million barrels of propane storage at the facility. The propane can be delivered into the East Coast and Northeast US markets and/or exported internationally, which opens up significantly new markets for us.

In addition to this agreement, we also announced a 15-year ethane sales agreement with INEOS. INEOS is a global manufacturer of specialty chemical and oil products. And currently plans to utilize its own ship fleet to take delivery of our ethane at the Sunoco Marcus Hook dock facilities. Contracted volumes are planned to start in the first half of 2015 and increase over time to 20,000 barrels per day.

The Mariner East project is the third ethane project in which we have announced our participation. The first ethane project was Mariner West. Mariner West is expected to start in mid-year 2013 and ramp up to 15,000 barrels of ethane per day. The ethane will be purchased by NOVA Chemicals and transported to Sarnia, Canada. The second project that we announced was our participation in the ATEX project which will move ethane to the Gulf Coast petrochemical complex. This project is planned to start in 2014 and ramp up to 20,000 barrels per day. All three ethane projects originate at the Mark West Houston plant in Washington County, Pennsylvania. In essence, these three projects ensure that we'll be able to meet gas pipeline specifications in a timely manner, that give us operational flexibility. And they enable us to build and grow our wet Marcellus production volumes.

These three projects, assuming minimum ethane extraction, allow us to potentially to grow Marcellus volumes in the wet portion of the play up to 1.8 Bcf per day. In addition, these three projects will add about $0.40 per Mcf to our effective gas price.

On slide 10 of our current IR presentation on our website, it shows that we have about 335,000 net acres in the wet portion of the Marcellus, which is in the Southwest portion of the play. In addition, we have about 235,000 net acres of dry gas in the same area. Summing both areas, we have 570,000 net acres here. Since we discovered the play in October of 2004, approximately 1,500 wells have been drilled in this area. Based on those roughly 1,500 wells or so, our many long distance step out and delineation wells, and considering that our discovery well came online in 2005, and that we now have up to seven years of production history, we believe that all of this acreage is highly prospective for Marcellus shale.

Combined, between the wet and dry portions of the play, we believe that we can possibly grow the Marcellus production alone to 2 to 3 Bcfe per day. In addition, we believe a lot of this acreage is prospective for both the Upper Devonian and Utica shales and would allow us to leverage existing Marcellus infrastructure. With success in these other horizons, we have the possibility of growing beyond 3 Bcfe per day. It's important to note that it's not just growth, but growth in the gas field with the best large-scale repeatable economics in the US. Particularly given Range's dominant position in the wet portion of the play. The economics are very good, given the capital required to drill and complete the wells, versus the projected recoveries per well.

The other key is the effective uplift in price due to the liquids products. If natural gas is priced at roughly $3, given all the uplifts from the natural gas liquids and condensate, the effective price we receive on the wet gas portion of the Marcellus is about $6, or about double gas price alone. That assumes the ethane stays in the gas. Once we begin to recover ethane, and once all three ethane and propane agreements are in effect, based on current strip prices, it adds about $0.40 per Mcf to the $6 price, which further enhances our economics.

For 2012, we entered the year with a goal of growing between 30% to 35% with a $1.6 billion capital budget. I've stated on a couple of previous calls this year, that if we choose to live within projected cash flow for 2013, we could grow at 15% to 20%. This year we drilled in the dry gas portions of the Marcellus Shale in the Northeast, which for us centers in and around Lycoming County, Pennsylvania. We did this in order to drill to hold what we believe are some of the most prospective acreage in this region. We ran four, and at times up to five, rigs in this area. By January 2013, we plan to be down to one drilling rig here. The reason is, at this point we can run one rig and still hold the key acreage we want to keep in that area, given the continuous drilling clauses that we have. Coupled with the larger tracks in general in the Southwest part of the play. Therefore, given the relatively low price of dry gas as compared to wet gas and oil, for 2013 we're planning to focus on the wet and oil areas of our portfolio.

Also, come January 2013, the two areas that we plan to focus on drilling to convert acreage to held by production are the wet portion of the Marcellus and the horizontal Mississippian oil play in Northern Oklahoma and Southern Kansas, which has a large liquid and oil component. The good news is that out two most economic plays happen to be where we need and want to drill to hold acreage. Given that we can reduce drilling in the Northeast portion of the Marcellus from four to five rigs to one in 2013, we will most likely be reducing capital spending in 2013. I want to stress that we don't set our budget until our December Board meeting. Our budget is subject to Board approval. In past years, after Board approval, we typically announce our 2013 capital program at the end of January, or early February.

Given those caveats, and realizing that it's still early, looking at strip pricing today, preliminarily it looks like, even with the reduction to a single rig in the Northeast dry Marcellus, we can still grow volumes for 2013 at a rate of 20% to 25% over 2012, focusing on the liquids-rich and oil areas. To do so, we currently estimate that we would overspend cash flow by approximately $250 million, plus or minus, assuming current strip pricing. Over the next month and-a-half, we'll prepare a recommended 2013 budget for our Board and present it at our December Board meeting.

Looking at 2014 and beyond, we control and operate almost all of our assets expect for Nora Field in Virginia. If strip prices hold for 2014 and beyond, we will look at ramping our growth back up. In essence, we'll move the growth lever up with higher prices, while being mindful of holding key Marcellus and Mississippian acreage. And fulfilling our longer-term ethane and propane commitments.

In the Mississippian play, given continued drilling success in our 150,000 net acre position, we're planning on ramping up drilling. If we begin 2013 with five drilling rigs and move to 10 rigs in 2014, and 15 rigs in 2015, we believe we can hold all of our acreage within the primary term. And significantly grow our oil, NGL and gas volumes in the play. As most of you probably recall, in the time frame from 2004 to 2011, we sold about 1.8 billion of properties. These asset sales did several important things for us. They allowed us to keep focusing on growing our most economic projects which had the highest growth rates with the lowest cost, while divesting of our low-growth, high-cost projects. This focused not only our capital on our best projects, but it also enabled us to focus our technical talent on our best projects.

In our release this week, we announced another $170 million of sales, most of which consist of our Ardmore Basin assets and some scattered Marcellus acreage. Completing this transaction, as we expect, will bring us a total of about $190 million in sales this year. We'll continue to identify assets that we think make sense to divest. In summary, we believe that we have the ability to create substantial shareholder value in the current commodity price environment. And have the quality of assets and flexibility to do so for many years to come.

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

Thanks, Jeff. We exceeded our production guidance, coming in higher on gas and NGLs, and right in the strike zone on oil. In fact, 47% organic production growth, when comparing to the prior year quarter, is the highest production growth in the Company's history. Again, this is a great testament to our operating and technical teams. They've reached record production levels, while at the same time substantially reducing expenses and improving efficiencies.

To illustrate that point let's talk about operating cost. In addition to our record production, we continue to see an impressive decrease in field level expenses. As I've pointed out in the past, we've seen really great improvements in efficiencies all across the board. And we still see those happening. And we believe that they will continue to happen as we go forward. But when you combine the increased efficiencies with what our operating teams have achieved in lowering the finding and operating cost, it's truly impressive.

For example, when comparing the third quarter of this year with the same quarter last year, we've seen a 47% increase in production, with a 31% decrease in LOE per Mcfe. In fact, our absolute field level expenses have decreased year-to-date this year as compared to the same time frame last year by 12%. Accomplishments like this really help us to achieve great economics long term in what we believe to be some of the best and largest repeatable plays out there. Not only are we seeing great growth at low cost, we are also seeing improving well results.

Now let me highlight some of those results that we're seeing across the Company. Please refer to our press release for specific well results. I'm not going to repeat all of those results in my remarks here, but they are certainly noteworthy and we can discuss them during the Q&A. However, I do want to call your attention to the table in the Southern Marcellus section of the press release. It shows 64 wells coming online during the third quarter in the super-rich and wet Marcellus areas. If you compare those rates to the type curves in our current IR presentation, you'll notice that the average IPs of those 64 wells is above the type curves. And in particular liquids rates are well above the type curves.

In the super-rich area, we had a significant step-out well that tested at 1,044 barrels of liquids per day and 10.3 million gas, excluding ethane. If you figure in ethane, the well was 2,053 barrels of liquids per day with 8.7 million gas. The lateral length is approximately 3,800 feet, and it was completed using a 20-stage RCS completion. As you can imagine, the economics on a well like this would be phenomenal. What I want to stress here is that this well is one more example of how our wet and super-rich acreage is not only being derisked as we step out across the acreage, but it also illustrates the exceptional resource base that we put together over the last several years. As we're working on designs and stepping out across this position, we're continuing to see improving results as this position is derisked. We expect that our 335,000 net acres in the wet and super-rich Marcellus will provide for a highly profitable drilling program for many years to come.

In addition, in our Northern Marcellus division we continue to see outstanding results with good economics. But as Jeff said, we'll be ramping down our activity to enter 2013 with one rig. As we continuing to focus the majority of our capital towards liquids-rich and oil projects. Next year we expect to be able to meet our lease commitments on our key acreage in Northeast PA with generally one rig, as now most of that acreage is HBPed or in a continuous drilling mode.

Also of importance, I want to give a quick update on the Upper Devonian Shale. Our second super-rich Upper Devonian well continued to clean up following our early August announcement. It ultimately had a peak 24-hour rate of 552 barrels of liquids per day, of which 31% was condensate and 4.7 million a day of gas. With ethane extraction, the well would be 998 barrels of liquids per day and 4 million gas. We don't plan any further Upper Devonian tests this year and we're currently developing our plans for 2013.

Shifting to the Utica. Our first wet Utica well in Northwest PA was drilling and completed successfully. The log data and core data that we collected, along with the pressure testing we performed, show us to be right in the strike zone for liquids-rich production. The well is currently shut in for a 60- to 90-day period post-frac and we'll be keeping any results proprietary for a while longer. With the date we've gathered, we now believe the Utica in this area could potentially benefit from the so-called aging or seasoning process that you may have heard others talk about. And that's why we have the well shut in. Of course, we'll have our own conclusions as to the technical and economic viability of this technique after we finish some of this testing. We are encouraged by what we see and we still plan to spud the second wet Utica horizontal well late in the quarter. As it's still real early in this play, we expect to know a lot more about the potential of the wet Utica on our 190,000 net acres in northwest PA by our next conference call.

Now let me shift to Oklahoma. The horizontal Mississippian oil play is progressing well. We're up to 156,000 net acres and now have our second well that exceeded 1,000 BOE per day. It had a peak 24-hour rate of 1,227 BOE per day. The lateral length is approximately 4,000 feet, and it was completed with a 20-stage frac. We own a 74.9% working interest in that well. I think it's also important to point out that our first 1,000-plus BOE per day well that we previously announced was turned to sales in the second quarter and has held up very well. The well has now achieved a 90-day average of 1,049 BOE per day.

Let me also point out that when you look at the IPs of the wells turned on in the last two quarters, the average IP is 552 BOE per day, which is well above our 600 MBOE type curve. The team is continuing to optimize mid-stream and power infrastructure, and is steadily improving our completion designs. While it's early in the play, we believe our team can continue to produce these wells at very attractive operating costs that will continue to enhance our economics.

In West Texas, at our Conger Field properties, we've drilled our third Wolfberry vertical well. That well had an initial 24-hour production rate of 505 BOE per day. This is substantially better than our first two Wolfberry wells. Those first two wells were projected to recover 216 MBOE each, and we expect this well will do better. It's also significant to point out that it was completed at 11% lower cost than the first two wells. And when you combine that with the better expected recovery, the economics will improve substantially. Plans are to drill and complete three additional vertical Wolfberry wells at Conger in the fourth quarter.

Shifting to the horizontal Cline oil play, there's still a lot of offset activity in the area and we are monitoring that closely. We successfully drilled and completed our third horizontal Cline oil well and it's currently being tested. It's still early in the cleanup process and we expect to have test results to discuss at our next conference call.

I also wanted to give a big atta boy to our marketing department. As the Marcellus and the Utica have growth, our team has taken many important and strategic steps in the Northeast markets. These steps ensure that our production flows steadily on a year-round basis for many years to come. Certainly the ethane and propane deals are great examples of just a few of those strategic moves. Our team is always evaluating future opportunities, and is consistently adjusting our portfolio, working with both pipelines and customers. Again, our marketing folks have done a great job staying way out in front of the ever-evolving Northeast markets.

Our already-strong safety record continues to improve as we remain well below our peer group averages. Our incident rate is 53% below our peer group's rate and 39% below our own incident rate in 2011. And our lost time rate is 54% below our peer group's rate and 64% below our 2011 rate. Safety and environmental protections remain a core value at Range. And from the bottom up our operating teams believe it, live it and own it.

As for guidance, like Jeff said, while our drilling and completion activity level will slow down a bit during the fourth quarter, which is primarily in Northeast PA and in spite of the Ardmore Woodford sale, we still expect to come in right at a 35% year-over-year production growth target. With our fourth quarter liquids growth in the range of 33% to 36%, as compared to the fourth quarter of 2011.

As you can tell, we are really proud of our operating and technical teams. They make it really easy to talk about our results each quarter. In summary, cost and well performance are steadily improving, while working safely and protecting the environment. And we have some great rate of return projects that are continuing to get better and better.

Now over to Roger.

Thanks, Ray. The third quarter extended our favorable growth and cost trends evident in the first two quarters of 2012. Fueled by strong production growth at low cost, cash flow and EBITDAX both registered quarter-to-quarter increases. Turning first to the income statement, third-quarter cash direct operating costs, including workovers, was $0.40 per Mcfe. $0.18 below last year, and equal to the second quarter. Year-to-date cash direct operating expense on an absolute dollar basis was $11.4 million lower than last year on 36% higher production volume. It would be impossible to forever increase production while at the same time reducing cost. So we expect cash direct operating unit cost to be in the $0.43 to $0.45 range in the fourth quarter, as we further increase our oil and liquids-rich production which carry higher margins but also higher unit operating cost.

Cash G&A expense for the third quarter was $0.46 per Mcfe, $0.07 below the third quarter last year, and $0.01 lower than the second quarter of this year. Salaries and benefits make up the largest component of our G&A expense. And we've seen these costs decline on a unit cost basis for the past six consecutive quarters. This is a key indicator of the quality and maturation of our play expansions as we are now increasing production consistently faster than our overhead. Fourth quarter G&A unit cost is expected to be $0.44 to $0.46 per Mcfe.

Third-party transportation, gathering and compression expense in the third quarter came in at $0.71 per Mcfe, $0.03 higher than last year. The timing of additional firm transportation capacity and the capital spent to hook up incremental production do not always coincide with the timing of production commencement, which makes this expense somewhat variable. We anticipate this expense to be $0.75 to $0.79 per Mcfe in the fourth quarter. The third-quarter DD&A rate was $1.69 per Mcfe, $0.20 per Mcfe lower than last year. Fourth-quarter DD&A rate should be in the $1.65 to $1.68 per Mcfe range. And we believe that the DD&A rate will continue to decline as our capital efficiency further improves. The fourth quarter DD&A rate should reflect this, as it will incorporate our year-end reserve report results.

Recalling that most state production taxes are assessed on wellhead prices rather than effective prices after hedging, third-quarter production taxes were $0.05 per Mcfe. Plus the Pennsylvania impact fee of $5.4 million. That brings the total production tax burden for the quarter to $0.12 per Mcfe. Prices have improved a bit recently, making our best estimate for fourth-quarter production taxes $0.08 per Mcfe on total Company production. Plus $5 million for the Pennsylvania impact fee. Making the total $0.15 per Mcfe.

Interest expense for the third quarter was $0.61 per Mcfe, $0.08 below last year's figure. Higher production volume and incremental debt funded under the lower floating rate bank revolver is what helped bring the unit interest cost down. The fourth quarter should see this trend continue with interest expense of $0.59 to $0.60 per Mcfe. Exploration expense in the third quarter, excluding non-cash compensation, was $14 million. That's $3 million below last year, due to lower dry hole and lower seismic expenditures. Seismic expenditures in the third quarter were only one-third of the budgeted amount due to project timing. So we expect to catch up the fourth quarter with total exploration expense of approximately $19 million.

Our ordinary unproved property impairment for the third quarter was $20 million. We also recognized an unusual impairment on an unproved property of $20 million. Bringing the total unproved property impairment for the quarter to $40 million. The unusual item consisted of our last undeveloped Barnett Shale lease which was held out of the 2011 sale. The fourth quarter estimate for unproved impairments is $19 million to $21 million.

Third-quarter cash flow was $189 million, essentially the same as the third quarter of last year. While EBITDAX for the quarter was $230 million, 4% higher than the third quarter of last year. On a per fully diluted share basis, cash flow was $1.18 per share, $0.03 above analyst consensus estimates. Cash margin for the third quarter was $2.56 per Mcfe. And earnings, calculated using analyst methodology, were $32 million or $0.20 per share, also $0.03 above analyst consensus estimate. As Rodney mentioned, please see our website for detailed reconciliations of these non-GAAP figures to GAAP. Along with hedging schedules and other helpful information for investors.

Over on the balance sheet, things are pretty much business as usual in the third quarter. We funded our capital program with cash flow and draws under our 1.75% bank credit facility. The bank credit facility has a $2 billion borrowing base, which was unanimously reaffirmed by the 28 member Range bank group earlier this month. And it's currently approximately 25% drawn. Though our rate of spending slowed considerably in the third quarter this year compared to the second quarter, our leverage, as measured by current total debt to trailing four quarter EBITDAX, increased slightly to 3.3 times. We remain comfortable with our leverage around the 3 times EBITDAX level thanks to our high rate of return plays, low cost structure, long reserve life, operating control of our growth assets, substantial liquidity, and our hedge position.

EBITDAX is beginning to grow again thanks to higher production and slightly higher prices, which should give us a bit of a tailwind on the leverage ratio going forward into 2013. Our increasing EBITDAX in 2013 will enable us to outspend cash flow by approximately $250 million, while also reducing the leverage ratio to below 3 times. As has been our practice, as Jeff mentioned, we continually evaluate our assets for potential sale. And will likely entertain additional sales periodically to sharpen our operating focus, which will also help keep leverage in check. As Jeff also mentioned, we have signed a purchase and sale agreement to sell our Ardmore Basin Woodford Shale properties at a gain. Which, when closed, along with several small miscellaneous assets, will garner approximately $170 million in proceeds to shave the peak off of our leverage and help keep leverage from going any higher in the fourth quarter.

We're pleased to have increased our hedge position during the third quarter. We added new hedges in 2012, 2013, and 2014. For the fourth quarter this year, we've got approximately 85% of our projected gas production hedged at a floor price of $4.17 an MMMBtu. We've got approximately 60% of our NGLs hedged at above market prices. And approximately 80% of our projected oil production hedged at $90.82 a barrel. Our 2013 and 2014 natural gas and liquids hedge positions were increased during the third quarter. Such that we will again be entering the new year with approximately 75% of our 2013 production hedge, and over 50% of our 2014 production hedged. Please reference the updated hedging schedules on the Range website for these new and existing hedge volumes and prices.

To summarize, the third quarter showed continued cost reductions. Which, when combined with record increases in production volume, increased our quarterly earnings and cash flow, positioning us very well for the fourth quarter. Jeff, back to you.

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

(Operator Instructions)

Dave Kistler with Simmons & Company.

Real quickly, with your comments about outspending for next year, and tying that to discretionary cash flow, obviously that discretionary cash flow is going to move with commodity prices but you must have some sort of range in mind currently. Any chance you could share that with us?

Let me start and then I'm sure Roger can pile on. But what we're talking about for next year, and it's preliminary and subject to Board approval, but what it looks like right now is we would get year-over-year growth of 20% to 25% outspending cash flow, looking at current strip prices, by approximately $250 million, plus or minus. And then the other important part is looking at the strip in 2014 and beyond, in essence we would look at ramping growth back up.

Let me talk about it philosophically before I turn it over to Roger. Our strategy, and we've talked about it before, is, on the low end, within cash flow, we can grow at 15% to 20%. Of course, on the high end it depends where you focus, whether you're focusing oil, liquids-rich or gas. But this year obviously we're growing it 35%. And then we have a huge inventory and a lot of flexibility, both in oil, wet and dry. And then we operate and control almost all of it. So as prices move up, or as the strip looks better, we'll look at ramping up. And as prices are worse, the growth rate will be a little lower.

And there's several key things in there. When we look at growth, for instance, for 2013, we're not focused on absolute growth. We're focused on best economics and best returns. So our drilling, therefore, next year, like I said, is we're going to cut down in the dry gas areas in Northeast Pennsylvania and focus our drilling on the liquids-rich and oil areas. Liquids-rich down in the Southwest part of the Marcellus and oil in the horizontal Mississippian. So we're looking at cash flow per share, rate of return, that type of stuff. If we were looking at just best absolute growth, obviously what we'd do is drill 100% dry gas. And for $250 million over cash flow, we'd probably grow it 35% to 40% or more.

And the other thing I think is important, we think in the dry gas area, just looking out we ran some economics earlier this summer. If we delay drilling in, say, Lycoming County for a year or two, in essence it doubles the rates of return on a per well basis, if you move the capital out to the point in time when the strip's better.

For 2014 and beyond, again, I want to just give you a little context before Roger comments more on the financial part. But in the Mississippian, we talked about ramping beginning of this year 5 rigs. And then with success to 10 and 15. So it gives you a feel for the shape of the curve there in the growth in the Mississippian. In the wet Marcellus, you can look at those ethane agreements as a proxy for what our gas rate's going to be in the wet areas. When you add the three together, we've committed to 55,000 barrels of ethane per day. Currently we're at zero selling ethane. By mid to late 2016 we need to be at 55,000 barrels of ethane per day to fulfill those agreements. Under minimum extraction, that's 1.8 Bcf per day. Under most likely extraction it's 800 million.

To put that in context, currently in the wet area we're about 370 million per day. So on the minimum, on the low end, we're going to more that double production in the wet Marcellus to fill those agreements by mid to late 2016. So I wanted to put it all in context. I think probably the most important thing to do that is, with our portfolio, and we talk about 44 to 60 Tcf. But I want to stress, a lot of that's in the Marcellus and down in the Southwest, highly derisked because there's 1,500 wells. And there's not just 1,500 wells. But when you go in our IR presentation, you can look at the quality of the wells. In the wet, the super-rich and in the dry. There's a big data set with up to seven years worth of history. And that's where our acreage is. So not only can we grow at 20% to 25%, and then ramp up in subsequent years to potentially something higher, we can do that for many years to come, for probably a decade or more to come.

I'm not saying we're unique. But because we discovered and have a big position in what we think is one of the best, the largest gas field now in the US, particularly in the wet area, where the best economics are, we're really well-positioned to do that for a long time to come. Let me flip it back to Roger to talk more about the funding and the leverage.

Just coming on the overspend, Dave. We're obviously in a capital-intensive, highly cyclical business. And we mind our balance sheet very closely. Our balance sheet's in great shape. We want to keep it that way. We've got a lot of financial flexibility and liquidity built into the balance sheet. So the question is, how comfortable are we leaning on the debt throttle in times like 2012 and times like 2013. And the reason we're comfortable at this point talking about overspending cash flow $250 million plus or minus, as Jeff says, is that with a current debt to trailing four-quarter EBITDAX measure, which we feel is the best measure of leverage, getting the tailwind from higher EBITDAX from higher prices and higher production lets us go into 2013 to where you can overspend cash flow by about $250 million and still actually drive that leverage ratio down a few ticks. That's really the plan behind that. We have, as I mentioned, plenty of liquidity. The question is how we use that liquidity. We intend to be very prudent about how we go about doing that.

I appreciate that. And then maybe just to clarify a little bit. You must have a range around that discretionary cash flow. And I'm imagining that that's organic discretionary cash flow, not necessarily cash inflows -- IE, asset sales. Just roughly looking at our model, that would put you in a range of maybe, call it, $850 million to $950 million for next year. Am I way off the mark? I'm trying to triangulate to what that aggregate CapEx number would be.

We've never given cash flow guidance and I certainly don't want to start now. What I can comment -- and I'm also not going to second guess the Board on the CapEx budget for next year. So I really can't comment on your range. But I can assure you that we've run the numbers and we feel confident in the 20%, 25% range and the $250 million approximate overspend.

(Operator Instructions)

Marshall Carver with Capital One Southcoast.

On the 2013 growth, thanks for the color there. With the emphasis on liquids in both the Mississippian and Southwest PA, is it safe to assume that the liquids growth would probably be a little bit higher than 20% to 25% and the gas growth would be lower?

We're not going to come out with the specifics again until we present to the Board and get it approved. But generally speaking, yes, the liquids growth disproportionately to the gas and to the overall. But we'll come out with all those specific numbers once we get formal approval from our Board December. Typically we get approval roughly around the first week of December. It's been end of January and early February when we do it. Maybe we'll accelerate that. We can bat that around. Maybe we do it in mid-December or something, or January. But the overall answer to your question is yes, they will grow disproportionately.

And the follow-on to that, then I'll hop out of queue. Are there any bottlenecks on the liquids end next year? Or how should we think about that?

I think what we're seeing in the fourth quarter is, due to some of the timing issues that we talked about a couple of quarters back, a lot of these wells are getting compressed into the third and fourth quarter. So you're seeing a lot of wells come online. And that's just exaggerating the bottlenecks that are there. And I think that we're seeing that unwind and we really expect that to unwind even further into 2013. We turned on 84 wells in the third quarter, which is a bunch of wells. And as we see that backlog unwind, which we're beginning to see the effects of that, I really believe in 2013 most of that will have worked its way out. Especially as we get into the second quarter or so of next year.

Okay. Thank you very much.

Brian Lively with Tudor, Pickering Holt.

Just a follow-up on the 2013 preliminary numbers. Specifically on the outspend. It sounds like you guys are comfortable with just using the leverage to grow. Are you guys going to plan to plug that $250 million gap via additional asset sales? And if so, what's next up on the list in terms of what you would consider selling?

Let me talk about it in general terms. If you look at the period from 2004 through 2011, we sold $1.8 billion worth of properties. Through that time we significantly drove up production and drove up our share price. This year so far, because we sold a little bit in the beginning of the year, to date we've sold $190 million worth of properties. So Roger and his team, working together with the Board, will come up with a way we can optimally finance that as we look forward. Clearly we have the ability, if we choose to do so, to carve off a little more assets, like we have historically. But Roger will be making that recommendation as we go forward.

Our strategy has been we think periodically selling things makes a lot of sense for a number of reasons. One, it really keeps us focused operationally. It keeps us directing our capital into our highest return, best growth, large-scale repeatable projects. And, by the same time, selling them, it prevents us from investing. Like when we had the offshore, I guarantee you, whenever you're in an area, you get AFEed by a partner, you have to react to something, the only way that you get out of spending money in areas you prefer not to spend them a lot of times is just to sell it. Plus, it enables you to redirect your people. I think we have a very focused Company. We've shown the ability this year, even with the sales that we have we're still hitting our growth targets. Even when we sold the Barnett, literally selling 120 million a day, within six months we had such robust large-scale probabilities now we more than made it up within a short period of time, with much higher rates of return. So that's what we've done historically. As we finalize our budget and look into next year we'll come out with what that plan is.

Okay. And in that vein, for the Permian, how much more do you guys need to see from a delineation standpoint to bucket that area in terms of being one of those core assets versus being something that you would consider monetizing?

I think the key part with the Permian, it's like our Utica play, as well. All of that Permian acreage is held by production, which really gives you great flexibility. It gives us time to watch wells, to watch our competitors' well. Same with Utica. There we have another 190,000 net acres that's all held by production. And, again, going back to a higher level theme of Range, we like to get into areas that are high quality, large scale, repeatable, stack pays, rich hydrocarbon charge. And then put a really strong technical team on there. And continuing to work and work and work, and coming up with those new opportunities. And that's really paid a lot of dividends for the Company.

So we don't have a time frame per se, but we continually look at the results of our wells and others. And then we'll determine what's optimum for the Company. Like I said, as evidence, we're aligned with the shareholders. It's all about share price, performance, growing production per share, reserves per share, debt adjusted. So whatever makes the most sense to do, we'll do. We sold $1.8 billion worth of property. If that's the right thing to do, we'll do it. We're really focused on the best returns and best opportunities as we go forward. And as we learn more about those areas, then they either go higher into the list or lower based on performance.

Thank you.

David Tameron with Wells Fargo.

I'm not sure who alluded to this, but can you just talk about all the infrastructure coming online in the Marcellus? And how much more capacity that frees up for you. And just think about the time frame over the next few quarters as that comes on, when do you anticipate most of that additional infrastructure to be in place? And what does the time frame look like for the next couple quarters?

Yes, David. This is Ray. The infrastructure bottlenecks per se that we experienced this year were really midstream. Had to do with low pressure gathering and compression and so forth. And like we've said earlier, Mark West has done a yeoman's job of catching up and actually getting ahead of us now. And now we're beginning to get those wells put online. And so, as far as the infrastructure needs going into 2013, the amount of pipe, for instance, that they have to put in place in 2013 is a whole lot less than it was this year. So, for lack of being cheesy about it, we have reached an inflection point in the infrastructure in the fact that the biggest part of it's been built. And basically now we're just tying in wells to already major infrastructure that's there.

In Southwest PA, we really don't see any big issues. Of course, we're still going to be ordering plants going into the future and different things like that. But that's all way out in front of where we're at. And we feel really good about that. Like Jeff talked about in his remarks, we've got a definite plan to be getting to the point where we can deliver on all these commitments that we've got. And do it in an economic and reasonable manner to get there. So we feel pretty good about infrastructure going forward. And we don't foresee any huge bottlenecks, especially in Southwest PA, or really in the Northeast PA where PVR just put phase three online up there. We're in really good shape for the next couple of years on infrastructure.

I'd just add, back to the ethane agreements, and as we continue to ramp up in ethane, in essence we're taking the ethane out of the gas and selling it as liquids. Which frees up about 100 million a day from the gas pipelines. So there's another benefit that comes out of those projects.

Let me ask an unrelated follow-up. If you talk about selling assets in Huron, presumably on the potential board for being sold, would you guys sell that jointly with Equitable? How would that process work?

You'd have to ask Equitable what they're doing, which I'm sure you've done. But EQT, to make it modern day. We're partners with them. They have the Huron in Kentucky. And then on the virginia side, we're partners with them in Nora. And then, separately, we have other assets. For instance, we own [Heysa] 100% and Big Rock, 100%, and that type of thing. [Wyden] 100%.

We like those assets in Virginia. We always want to do whatever the right thing is for the shareholders but we really like the assets we have in Virginia. It has that same characteristic that we like to see at Range. They're stack pays, everything, literally from about 1,000 feet down, you have the CBM, then you have the traditional zones in Berea and Big Lime. Then you have the Huron shale. All of it is either held by production or we own the minerals. Actually, our economics are superior to what EQT has because we own the royalty and we actually get paid the royalty on those pieces. Our team, even though we've cut the capital way back there because we can, and we have that in idle, they're stilling growing production this year. Even with a $30 million budget which is just a minor fraction. So we have a really high-quality asset with a high-quality team.

But we do have other scattered assets throughout the Company, if we wanted to sell things, that we control and we operate. And like I said, as evidenced by the past seven, eight years now, periodically we're always looking at it. And we rank those assets out and there's things that fall to the bottom and we would consider selling those if it's the right time and the right price and the right area. Don't get lost a little bit in our flip book. If you look at the IR presentation. We're focusing on the things we're spending money on. But we have a lot of production in other areas, we just don't list it all. For those of you who have been with us for a while, we used to have the pyramid that Rodney loved. The pyramid are all those other things that would be possible considerations for asset sales.

All right. That's actually helpful. Thank you.

Neal Dingmann with SunTrust.

Great color so far. Just two questions here. First, on that great result you had on that step-out on that super-rich area, was wondering, are you planning to drill a number around that? Is that why the delay to bring that online? And by the result you're seeing there, have you already essentially delineated and connected the dots in that area, if you know where I'm going with that?

It was a significant step-out. By definition, we didn't have infrastructure out there where that well is. So it's going to be a while before it comes online. And to answer your question, yes. Now that we have derisked that step-out area, we'll begin marching towards it with infrastructure and with wells as we go forward. That way you know there's a great target out there. And, again, that's been real surprising to me especially since I was there essentially from the beginning, that, as we've stepped out and continued to step out, we're just seeing better and better and better results. So the size and scale of this play is really, truly amazing. It just keeps getting better.

Yes, it's really exciting. Like Ray said, in that area, as we stepped out in the super-rich, we have 125,000 acres out there. Really big blocky position. So it's a great opportunity. And even though we've been drilling out there for years now, I would argue, Bill Zagorski, our geologist, has said we probably haven't drilled our best wells yet. So the future's really bright.

And there's significantly higher rate of returns. If you look at our updated PowerPoint slides on the website, you can see in that area just because prices have come up a little lately, and we're making better wells, too. But those wells are over 90% rate of return now.

That's very noticeable. Great point, guys. Then just a follow-up. On the Utica, I noticed having that first one shut in, then talking about drilling a second here in the fourth quarter. Again, I know you haven't said too much yet on that, Jeff -- either for you or for Ray. I just wanted expectations, liquids expectations. And then thoughts on, once you'll see these two, will this dictate -- I know you talked about your budget next year. Depending on how good or how liquid these wells are, could this dictate some of your spending next year in that area?

I'll start. I'm sure Jeff will jump in afterwards. The Utica well, being a first well for us, we did not have to bear a lot of the cost of the learning curve that we did in the Marcellus. So we set back on purpose. It was an HBP position. It's been there for years. So we tried to learn from everybody else. But we began gathering data. And then on this well what we've done is the actual data from this well -- and I mean logs, cores, pressure data, everything that we've done to date -- puts us right on strike with some of the good stuff that's happening down in Carroll and Harrison County that we're reading about. And we've been working a lot with offset operators and talking about that and exchanging data. So we've learned a whole lot.

Everything we've seen to date we're very encouraged with. So currently we got the well shut in, doing the aging or seasoning or shake and bake, or whatever you want to call it. And we do believe that there's some technical reasons that that could help the well and could work on it. So we're just trying to gather all this information, get our test results. Everything we see tells us we still should go ahead and drill the second well. As far as next year, it's way too early to tell. I'm going to make the case, until we get the results from these first two wells and some of the offset activity, we problem won't plan anything. Again, it's an HBP position so we don't have to do anything next year. And I'd rather put our money in some known projects down in the super-rich, for instance, and make 100% rate of return wells, if I can do that.

Ray, Are you targeting the Utica or the Point Pleasant?

It's the Point Pleasant. In most cases it's the Point Pleasant that's what's producing. It's not really the Utica, although we all call it that.

Very good. Thanks for the color, guys. Great job.

Thank you. I'd just add a little bit. Like Ray said, we're confident that we're in the liquids part of it. Got all the right ingredients. We'll see when we test it. And Ray's point is really a key one. It's all held by production. Just like all that stuff out in the Permian where we're testing different things, too. In the Marcellus, when we started, since it was a Range idea and we were the first Company out there, we had to carry 100% cost of the R&D. We don't have to do that for the Utica or for the Cline or for some of these other plays because they're HBP positions. I've noticed recently Floyd Wilson's company, Halcon, spotted a lot of wells just in and around us up there. They have a big position. Jeff Hildebrand's company has that. And others. But we're right on strike with the good stuff. And a lot of other people, you're going to start to see a lot of wells popping up in and around us. We'll carry some of the R&D and let others carry some of that, as well.

That's a great follow-on. Thanks, Jeff.

Leo Mariani with RBC Capital Markets.

Just a follow-up on 2013. You talked about ramping down the pure gas activity in Northeast Pennsylvania Marcellus and ramping up Mississippian by a fair bit. You said you were going to start the year with 5 rigs and then go to 10 in '14. Would you expect to ramp up the rig count in '13 in the Mississippian linearly over the next couple of years to get to 10 in '14? And then to 15 in 2015? And would you also expect any potential reductions in the wet Marcellus in 2013 as part of your plan to lower CapEx?

We'll reverse it. I'll start this time and then Ray can go add on. When you look at the Mississippian, what we're thinking about right now it's a little more stair step. We'll probably have 5 rigs starting the year, probably in January of '13, going to 10 rigs in January of '14, and 15 in the following year. And then obviously as we learn and become more efficient, we'll tweak it and all that but that's the trajectory we're on. We really significantly drive up oil volumes, liquids volumes and gas volumes up there by doing that. And hold all the acreage within the primary term. We've got a really strong team up there, a really good plan.

In the wet and super-rich part of the Marcellus, as I said, we're looking at an easy way to think about it. And we'll give more clarity with time. But if you just look at the three ethane deals we committed to, we have to be by 55,000 barrels per day by mid to late 2016. Which dictates if you back calculate it the other way under most likely ethane extraction it's 800 million a day. Under minimum it's 1.8 Bcf per day. We're currently at 370 million. It gives you a feel high and low what the trajectory is just in the wet and super-rich part. Obviously Ray, working with the teams there, and the guys that we have on the ground, they're going to do that as efficiently as they can with the fewest number of rigs and least capital to get the highest returns. I'm tossing the baton back to Ray.

Thanks, Jeff. It's really --

Don't feel any pressure, by the way.

Yes, exactly. It's really hard to think about slowing down in the Southern Marcellus because we're really not slowing down in 2013. We're really continuing to grow pretty substantially.

We're slowing down the dry part in the Northeast and we're keeping the Southern Appalachia down in Nora idled. But I think, as gas prices pick up, those areas will kick in and really super charge the growth. And at that time we'll have better returns. Sorry for the interruption. I haven't done that before.

And the drilling rigs, again, this is one of my pet peeves. It's hard to think about rig count anymore as describing activity because these rigs are getting so fast and so efficient that we're literally doing twice the work with a drilling rig today that we did a year ago. It's really more about, in these kind of plays, it's what all of the industry is learning, it's more about infrastructure and pads and timing of bringing those pads online and all that sort of thing. So what we're seeing next year is longer laterals, more frac stages, we're getting better and more efficient designs. We're having to build less infrastructure. So we really are, activity level-wise, probably still growing. We may be growing slower than we were but we are still growing next year. We're not slowing down by any means.

And growing at a significant level.

Yes, very significant.

Okay. That's helpful there on the clarity. Question on the cost side. I've just been noticing that your transport cost has been going up on a dollar per Mcfe basis, really ever since you guys established that metric. I think it was in the fourth quarter of '11. You guys are expecting to go up again this quarter. Do you have any longer term color on when that may start to flatten out? Should we see that flat in '13 at $0.75 to $0.79 per Mcf? Is that going to keep climbing? Just any thoughts you have around that would be helpful.

Yes, Leo, this is Roger. As I mentioned in the notes, it's truly a variable cost. There's a lot going on under the hood with that metric. You've got money being spent. You're got production volumes varying in different areas of the country. So you've got a lot of moving parts that come up with that. The uptick in fourth quarter, we've got some capacity on the team project that's coming on in fourth quarter. So the bills are going to start coming in for that capacity, so it creates a little lump there. Then the production will start to catch up and then maybe you're putting on a plant somewhere. So it's just a constant tug of war between volume and capital spend. So we'll continue to try to guide you guys as best we can. But as I mentioned in the notes, the timing doesn't always work out the way your spreadsheet says it's going to. But you'll probably see that continue to trend upwards for a piece and then eventually the volume will build and it will trend back down.

Especially on the gathering side, Leo. On your transportation side, as we can transport this gas to newer markets that have a higher positive basis in market to sell the gas at, that sales price is going to go up in gas sales. It's not going to come reducing your transportation costs. You're going to have to be cognizant of the expansion of the market and our margin versus just the absolute cost. So there will be different arrangements that come that direction. But Roger is exactly right. The gathering charges, you've got to build it before you put the gas in it. They're going to start charging for you as soon as that comes on. Then as the volumes come on, it's going to ramp that per Mcfe down on the gathering. And we've discussed internally as to whether or not we actually break that line out into two components when it gets to some significant size. So as you can see, the gathering ebbing and flowing as you turn on things, and then your transportation charge basically will translate back to your commitments footnote as to what you've got for firm take-away capacity to be able to always deliver your gas to the markets and keep the gas to flow.

All right, thanks. That was helpful.

Joe Magner of the Macquarie Group.

Just curious where the Permian fits into your plans for 2013. It looks like they're having good success down there. I know a lot of it's HBP. But just curious how you're thinking about that.

Right now we're not what I would call super active out there. It's a big HBP position. We're drilling a few Wolfberry vertical wells. Those are, as I talked about earlier, they're improving dramatically just in the first three wells. And so we've got three more wells we'll do this quarter. We're still putting plans together to see what we do next year. Again, the important thing about that position is it's HBP. We don't have to do anything next year. I'm guessing at this point that we'll have some minimal amount of activity there next year to help prove up some things or more or less confirm some things that we learned from activity in the area. But no real big plans at all at this point.

Okay. And then you touched on it a little bit here a second ago, just on improving rig efficiencies. Is there a way to quantify or perhaps provide us with an update on how many wells you think you can drill per rig, per year, in both the Southwest Marcellus, as well as the horizontal Miss?

That's a great question, Joe. And unfortunately there's not a real good black-and-white answer to it because we're still finalizing plans on lateral length and completion styles and number of wells per pad, and all of those different things. We're also looking at some better designed rigs, as we've gotten smarter and gotten more wells under our belt. And different things that we're considering. So it's hard to give you an answer. But you can go back and look -- I think it was in the last quarter where I spent a lot of time talking about the efficiencies that we saw year-over-year and quarter-over-quarter. And we're still seeing those kind of results. I can't quote you numbers today but I'm sure we could get the IR guys to follow up with you on some numbers. But it's too early to talk about 2013 or '14 because we're still putting those plans together and finalizing, tweaking what the actual numbers will be.

Still need to present it to the Board. Still need to get approval, all those kind of things.

Okay, thanks for that. One last one. Jeff, you touched on gas prices, as gas prices tick up perhaps ramping up some activity. What price level would you need to see on a sustainable basis for you to start thinking about dry gas activity again?

I think what's really key is if you look on our website for the dry gas areas we have economics out there. And you can see them for both Southwest PA and the Northeast. I'll see if I can flip to it. I'll make my point, make sure I get it off the right numbers. For instance, if you look at slide 18, PA, slide 18, and you look at pricing, $3 flat gas, it's a 21% rate of return. At a $4 flat price, it's 56%. At $5, it's over 100%. So it's really price sensitive and really steep. And the same thing is true in the Northeast without going through it. If you look at the strip out in 2014 and beyond, you're starting to see prices where you start to generate some really attractive returns in the dry areas. The good news is, again, we've got a really big bucket of dry gas opportunities, wet and super-rich opportunities and oil opportunities. And we have the operational flexibility to throttle back and forth between those various buckets. And we're looking at maximizing the returns for the dollars we spent, most efficiently driving up cash flow per share, production per share, reserves per share.

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

Okay. Thanks to our hard-working teams in each division, Range is on target to meet our 2012 production goals within our capital budget. We're driving down our unit costs in the process. Because we have very large acreage positions in some of the best plays in the country, we should be able to achieve double-digit growth in production and reserves on per share basis, debt adjusted for many years. Plus we continue to be one of the lowest cost producers in our peer group and are still improving. Therefore we believe that this will translate into significant shareholder value in months and years ahead.

I want to say, before I thank everybody for participating on the call, let me just add to that, we're out of time. In fact, we've overrun time by 5 or 10 minutes. And there's still some people queued up in Q&A. Please feel free, sorry we didn't get to everybody, but follow up with Rodney and the IR team. And we'll make sure we do our best to answer all your questions. Thanks for participating on the call.

Thank you for your participation in today's conference. You may now disconnect your lines.