Range Resources Corporation (RRC) Q3 2014 Earnings Report, Transcript and Summary

Welcome to the Range Resources' Third Quarter 2014 Earnings Conference Call. This call is being recorded. [Operator Instructions] Statements contained in this conference call 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 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 results for the third quarter with record production and a continuing decrease in unit costs over the prior year. The order of our speakers on the call today are Jeff Ventura, President and Chief Executive Officer; Ray Walker, Executive Vice President and Chief Operating Officer; Roger Manny, Executive Vice President and Chief Financial Officer; and Chad Stephens, Senior Vice President, Corporate Development. Range did file our 10-Q with the SEC yesterday. It should be available on our website under the Investor tab, or you can access it using the SEC's EDGAR system. In addition, we have 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 reconciliation of reported earnings to our adjusted non-GAAP earnings that are discussed on the call today. Now let me turn it over to Jeff.

Thank you, Rodney. The past several months have been a very challenging time for E&P stocks as Appalachian natural gas prices and now oil prices have been under pressure. We appreciate our shareholders' continued support as the commodity market sort themselves out as they always do. At Range, we remain focused on the things that will make Range and its shareholders successful in the long run, which is executing our plan for low-cost growth day in and day out. As one of the lowest-cost producers with the largest position in the core of the Marcellus, we are excited about what we have in store. Hopefully, in the next hour, you'll have a renewed or newfound appreciation for all the things that are going right at Range and how we've differentiated ourselves. This is the 10th year anniversary of the discovery well for the Marcellus, which was Range's rents #1 in October of 2004. This was the first commercial well in the Marcellus and the one that kicked off the play. It was a vertical well. Range followed with the first commercial horizontal well in August of 2007 and announced multiple successful horizontal offsets in December of 2007. Today, anchored by this discovery, we believe that Range has a simple story. One, Range has the largest acreage position in the core of the Marcellus, and being in the core makes a big difference in shale plays. Two, most of that acreage is in Southwest Pennsylvania area, where the Upper Devonian, Marcellus and Utica/Point Pleasant are all stacked on top of each other, which gives us built-in future capital efficiencies. Three, Range has identified the wells to be drilled that will take us to 3 Bcfe per day and beyond. Four, Range has the gathering, compression and processing plants already planned and under contract. Five, Range has the takeaway capacity arranged and under contract to support this growth. Six, Range has the liquidity and balance sheet to deliver on this plan. And seven, importantly, we have the team in place. The Marcellus discovery has brought to the region a tremendous supply of natural gas, creating a temporary oversupply in the region and the weakness in pricing that we've all seen. To support this supply growth, billions of dollars are being spent, both domestic and internationally, to utilize these resources for decades to come. With our cost structure and first mover advantages, Range is well suited for this short-term oversupply with outstanding growth plan for the coming years of growing U.S. natural gas demand. One of the advantages of being a first mover in a large play is the ability to secure low-cost transportation. We have disclosed our natural gas transportation agreements in the play through 2018. Under these agreements, our transportation grows from 1.1 Bcf per day at a cost of $0.28 this year to 1.75 Bcf per day in 2016 at the same cost for $0.28. In 2018, it grows to 2.4 Bcf per day at a cost of $0.39. It's not just about low transportation costs. It's equally important as to which markets you sell your products in. Our transportation agreements take us to solid demand markets at the endpoints, with the flexibility to sell to additional good markets along the way. By 2018, we plan to be selling into 22 different indices, which -- with gas headed to the Gulf Coast, Southeast, Midwest, Northeast Appalachia and Canada. By 2018, we expect about 1 Bcf per day of Range's production to be moving to the Gulf Coast or Southeast, up from 360 million cubic feet per day today. Every company's portfolio of transportation contracts and the destinations and markets that they go to is unique. Based on the data we have seen, Range, capturing the advantage of being the first mover in the play, has the lowest cost and most diversified portfolio to very good markets. Importantly, our transportation capacity follows our expected production growth. I also believe the same is true on the liquid side. Range is the largest liquids producer in the basin, and few companies have significant proven liquids-rich acreage. But even these companies that have liquids production, every company is different with unique transportation contracts and unique purchasers associated with them. Being the first mover in the play, coupled with a strong in-house marketing team, Range is in an advantage position here, too. The Mariner East propane project is projected to start up in early 2015. This will result in a significant cost savings of about $0.20 per gallon associated with transporting our propane to the Marcus Hook terminal. It will ultimately result in better propane pricing associated with faster loading in larger ships when exporting the propane. The ethane portion of Mariner East is projected to start up in mid-2015. Once this happens, combining Mariner East, Mariner West and ATEX, we project that we'll receive more than a 25% uplift to our ethane price versus selling the ethane as BTUs in the gas stream, and this is net of all transportation and processing costs. That combined increase of our ethane and propane arrangements when all of our contracts our operational equates to more than $100 million per year uplift to our net cash flow that all begins in 2015. No other company has that ability or the contracts in place for the next 15 years. Another advantage to being a first mover is our acreage position. We have the best potential for stacked pay versus any other operator in the basin. This is shown on Slide 10 of our investor presentation on our website. We put together an acreage position of approximately 1 million net acres in Pennsylvania. When considering all of the stacked pay potential, it's more like 1.9 million net acres, which is shown on Slide 11. We are on target for having our first Utica well in Washington County completed and tested in December this year. If successful, it will confirm the Utica/Point Pleasant potential in our Southwest Pennsylvania acreage. Being the first mover and capturing the best stacked pay potential, we've also captured the heart of liquids-rich and super-rich Marcellus. The same is true for the Upper Devonian. Range not only has the most net acreage with the best stacked pay potential, but we also have the best quality of rock in the southwest portion of the Marcellus. On Slide 19, when comparing our current completions on a recovery per stage or recovery per lateral foot, the Range wells are the tops in the southwest portion of the play. In addition to the positive attributes that I've just mentioned, the southwest portion of Pennsylvania also has the best infrastructure of any area of the play, which allows for expansion into new markets. Having size, scale, quality acreage in an area of good infrastructure and a great team, we have grown our gross Marcellus production in the third quarter to 1.2 Bcfe per day. We are the largest liquids producer in the basin. Our net production for the third quarter consisted of about 700 million cubic feet per day of gas, about 50,000 barrels per day of NGLs and approximately 8,500 barrels per day of condensate. As we've driven up production, our total unit costs have consistently declined. In some cases, we have even reduced our absolute costs as we've hydrated our portfolio and reduced our financing costs. Over time, as we grow net production 20% to 25% each year and drive down unit costs, even if prices remained steady, we expect our annual cash flow to grow by a rate in excess of 20% to 25% per year. As we move more gas to better markets, our gas prices should increase, along with liquids prices through the previously mentioned contracts. In addition, as the infrastructure in the basin builds out, our basis should improve with time, too. Importantly, our team has a track record of consistently meeting targets and doing what we say we'll do. Our reserve growth over the last decade has been impressive, and importantly, our performance reserve revisions have been positive for the last 6 years. Those are important aspects of our company. We're off to a great start after assuming 100% of operations in Nora, which is our Southern Appalachian division. Ray will discuss some recent technical breakthroughs, which have significantly enhanced that project. It has size, scale, repeatability, very good economics and one of the best gas prices in the United States. We have also made significant progress in the Mississippian Chat play, which will enable us to drill more there in 2015. Ray will talk about that, too. The third quarter for Range was a profitable one, in spite of a challenging pricing environment. Assuming stabilizing strip pricing and differentials, we still project that we can be cash flow positive in 2016, and then our planned growth beyond that can be within cash flow. Importantly, we project that we'll continue to grow 20% to 25% in 2016 and beyond, when gas demand is projected to grow significantly from LNG exports, petrochemical, power generation, manufacturing and transportation growth. With visible production growth for many years, price-advantaged end markets, balance sheet strength to exploit our deep inventory of low-cost assets and the capacity to increase our capital efficiency by leveraging our infrastructure as we continue to grow, we believe that we'll be well positioned as natural gas prices stabilize and strengthen over time. I will now turn the call over to Ray to discuss operations.

Thanks, Jeff. For the third quarter, we beat our production guidance and either beat or met all of our operating cost metrics. And we continue to see exceptional well results, lower costs and improving capital efficiencies across all our divisions. Production for the third quarter came in at 1.21 Bcf equivalent per day, and we're currently right on track for our fourth quarter guidance of 1.35 Bcf equivalent per day with 30% liquids. This, of course, will put us at the high end of our year-over-year production growth guidance of 20% to 25%. For the third quarter, as compared to the same time frame last year, the company achieved 26% production growth. And our unit cost and cash flow improved, as Roger will discuss in his remarks. In the Southern Marcellus Shale division, our well results remain the best in the southwest portion of the Marcellus, and our finding costs are amongst the lowest in the entire play. Let me give you just a couple of examples illustrating recent well performance. In our wet and super-rich area, during the third quarter, 4 of the pads, which total 18 wells that we've brought online, had an average 24-hour IP of 16.1 million per day per each well. Again, it's important that I point out that these are actual 24-hour production rates to sales under production facility limited conditions. These 18 wells averaged 4,400-foot laterals and were completed with 25 stages. As I point out, one of those pads was a 5-well super-rich pad where 2 of the wells averaged over 1,000 barrels of condensate per day each, and 2 of the other wells on the pad averaged over 900 barrels of condensate per day each, all for a full 24 hours. In our Southwest PA dry area, we brought online a 3-well pad that had an average 24-hour IP to sales of 26.4 million a day. The 30-day average to sales for the 3 wells was 17.4 million a day per well, and they averaged 5364-foot laterals with 28 stages. These 2 examples illustrate both the quality of our core acreage in Southwest Pennsylvania, along with the technical and operational expertise of our team. On both an absolute and on a normalized basis, our results were consistently the best in the region. Operating efficiencies are also strong. For 2014, we will drill approximately 12% of our wells on existing pads. And just to remind you, all of our drilling has been pad drilling for many years, and as I've discussed on previous calls, this gives us the ability to go back and drill up to 20 more wells per pad in any horizon as capacity frees up in the gathering system, while at the same time, appreciating huge capital savings and improved well performance, as we've discussed before. This really allows us to optimize our investment in gathering and will provide us the lowest cost over time. As an apples-to-apples comparison to some recently reported metrics in the region, year-to-date, as compared to the same time frame last year in Southwest Pennsylvania, we've seen a 17% decrease in unit cost per Mcfe on a lateral foot basis, which is a clear indication of improving capital efficiency. And again, we believe the best in the basin, and we continue to execute more and more efficiently. Year-to-date, we've pumped 15% more frac jobs as compared to 2013, and we expect to pump approximately 42% more stages in 2014 as compared to '13. As you might suspect, this translates to a pretty good production and revenue increase as we bring wells on in a better pricing environment this winter. For 2014, our average lateral link for wells in Southwest PA, including super-rich wet and dry, is projected to be 5,402 feet. This is 55% longer than in '13. For 2015, we're estimating that our average lateral length in Southwest PA will be more than 6,200 feet, with 1/3 of the wells over 7,000 feet, and our longest lateral will be almost 12,000 feet. We expect longer laterals to continue to lead to higher EURs and even better returns. And on the volume side, our production from the Southern Marcellus Shale division for the third quarter is almost 36% higher this quarter as compared to last year. And we just set pipe on our Utica test in Washington County, PA, and are currently beginning our planned 32-stage completion. The logs and other diagnostic information from the well are consistent with our expectations. And the current schedule has us starting the completion this -- or as I just said, just now, followed by a flow test in December. Shifting to Northeast Pennsylvania. Production for the third quarter was 25% higher than last year, driven mostly by outstanding well results. We're still maintaining our activity level at 1 to 2 rigs, while the team is doing really well at lowering costs and developing bigger and bigger wells. At the last call, we announced the well in Lycoming County that flowed under constrained conditions at 25.1 million a day for 30 days, with a 6,550-foot lateral. The state data reports that well at 22.2 million a day for 53 days. To follow up, that well has now averaged 20.1 million a day for 90 days and is one of the top 10 wells in Pennsylvania, and I might add, the only well in the top 10 not operated by Cabot and not in Susquehanna County. We're planning in early 2015 to drill a full-well pad, offsetting this record well, with average lateral lengths of over 8,000 feet. For 2014, our lateral lengths in Northeast PA are 34% longer than last year, and the team is consistently bringing these wells in at less than $5 million. For 2015, we expect our lateral lengths will be approaching 6,000 feet, and we expect them to continue to get longer with larger EURs and improving economics. For the Midcontinent division, the team is making progress in refining the geologic model for the Chat play. Please refer to the earnings release for the details on recent wells. So far this year, our 2014 wells have shown a 33% improvement in their 30-day IPs over our 2013 wells. And with 37% of our wells, during the second and third quarters, having max 24-hour IPs greater than 1,000 Boe per day, we're confident that we've identified key reservoir areas to target going forward. For 2 quarters now, we've set records in well performance. And with continued success in the fourth quarter, we expect to be able to modestly increase the activity level in the Chat play next year. We're still finalizing those plans and will announce the planned well counts when we announce the 2015 budget. Moving to the Southern Appalachian division. We introduced our plans for the next 18 months at the last call, and I'm happy to report that operations are progressing with very encouraging results. Again, we have a lot of details in the earnings release. With Range now having a full quarter of operational control over the Nora assets in Virginia, the team has introduced new techniques and well designs, resulting in an improved performance and economics. In the short period of time, Range has already achieved some of the best CBM results in 15 years using a major well design change, incorporating higher-grade casing and higher-rate foam fracs. The additional costs are around $10,000 to $20,000 per well. With 6 CBM wells turned to sales using the new completion technique, average results are 100% better than the historical field average, with returns of 100% or better. On a particular note is a new CBM well that's produced at a 60-day average of 340 Mcf a day, which is 5x the average CBM rate. And we just turned in line a new completion that's at that same level. There's over 2,000 CBM locations identified at the current spacing with the potential of over 3,000 infill locations. Similar improvements have been achieved with the same well design and high-rate fracture technique on the vertical tight gas wells, with overall results more than 70% better than historical field average for approximately $10,000 to $15,000 in additional costs. With 7 tight gas wells turned to sales with these new designs, the 30-day production average of these wells is the highest in over 10 years. The estimated rate of return of these wells is over 74%, and there are over 1,500 locations that are de-risked for future tight gas development. The division is also drilling horizontal Huron Shale wells, and there are over 2,000 de-risked horizontal Huron Shale locations currently identified. And lastly, I want to remind you of the exploration potential beneath the 475,000 net acres that Range now controls in the Southern Appalachian basin. With only 4 penetrations below the Devonian Shale, we believe there's significant potential for exploration in the 6,000-plus feet of additional sediment between the Devonian Shale and the basement. Remember the old saying, the best place to look for oil and gas is in an oil and gas field. I want to reiterate a couple of important points about Southern Appalachian. Number one, we own the minerals, thereby, yielding better economics since we have 100% of the working interest and 100% of the net revenue interest for most of the property. And number two, like Jeff mentioned earlier, our Nora production sells into one of the best markets for natural gas on the East Coast. We expect the average NYMEX plus $0.20 year round, with some gas potentially achieving even better prices than the prime winter markets. The well-defined, large and de-risked inventory of projects, which totals over 5.2 TCF of de-risked resource potential in Virginia, coupled with the new well designs, improving well performance, large gathering system with capacity, expanding demand in the region and favorable pricing, gives us confidence that we have the potential to ramp up production in the coming years with economics that are very strong even relative to the Marcellus. In closing, we have an experienced and innovative team, a great portfolio of projects, a proven track record of execution, innovative marketing solutions with takeaway capacity, and all the infrastructure and financing security to achieve our growth projections for many years. There's really one clear message that I want to get across today. We have everything in place, soup to nuts, with the track record to support, to achieve our goals for growth in production and cash flow within a low-cost structure, building shareholder value for many years. Now over to Roger.

Thanks, Ray. The third quarter brought steady improvement in our cost structure and balance sheet, with continued year-over-year growth and cash flow despite lower realized prices. Starting with the balance sheet this time. Since our last quarterly call, Range has received an upgrade from S&P to BB+ and Moody's with our Ba1 credit outlook from neutral to positive. These upward moves by both rating agencies ratify our continued progress, both operationally and financially. As natural gas and natural gas liquids continue to become true global commodities in the years ahead, our improved credit standing and favorable export contracts will help us continue to compete for long-term customers and new and better priced markets, not just in the U.S. but all over the world. Following the ratings upgrade. Even though Range has continued to add significant, long-term, firm transportation commitments and now has sufficient contracted capacity to see us through many years of double-digit production growth, the amount of standby letter of credit collateral posted behind these commitments has declined by 21% from its peak earlier this year. Posting collateral behind pipeline contracts or taking an equity interest in a pipeline to avoid posting collateral adds the hidden cost of transportation and reduces available liquidity. Credit quality matters now, and we believe it'll matter even more later. Complementing our new credit ratings, Range restructured and renewed for another 5 years our bank credit facility. The facility size was increased to $4 billion. The borrowing base was increased to $3 billion, and we chose an additional commitment of $2 billion. Importantly, borrowings under the new credit facility are priced 1.25% below the old facility, and the new credit contains a fallaway collateral feature that will enhance our future transition to investment grade. Like the old credit facility, the new facility is comprised of a leading energy industry's savvy group of diversified domestic and international financial institutions, with no one bank holding more than 6% of the commitment. I wish to thank each of these 29 institutions for their continued support of Range, equipping us with a state-of-the-market credit facility. Now moving to the income statement. Cash flow for the third quarter was $257 million, 5% higher than last year's third quarter. EBITDAX for the third quarter was $294 million, 2% higher than last year. Cash flow per fully diluted share was also higher than last year at $1.54 per share. Given that the third quarter of net realized Mcfe prices were down 17% from last year's third quarter, these year-over-year increases in cash flow and cash flow per share were the hard-fought result of disciplined growth at low cost. Reported net income for the third quarter of $146 million was almost 8x higher than last year due to a pretax $125 million mark-to-market derivative gain, as our hedges became more valuable with declining prices. Third quarter earnings, calculated using the methodology used by most analysts, which exclude asset sales, mark-to-market hedging entries and various nonrecurring items, was $62 million, 8% higher than last year at $0.37 fully diluted share. As Rodney mentioned earlier, please reference the various reconciliation tables found on the Range website and earnings release for full reconciliations of these non-GAAP measures to GAAP. Looking at our cost performance in the third quarter. Total unit costs were down by $0.36. In the case of interest expense, on an Mcfe basis, this expense was not only down year-over-year by 30% or $0.15 per Mcfe, it was also down by approximately $5 million on an absolute basis as well. Another noteworthy third quarter unit cost expense decline was in our DD&A rate, coming in at $1.28 an Mcfe, down 14% from $1.48 figure for Mcfe last year. The decline in DD&A rate continues to signal improved capital efficiency, which helps our cash flow grow faster with less capital. Please reference the third quarter earnings release for additional detailed expense item guidance for the fourth quarter. The earnings release also contains summary details of our hedge positions on both commodities and basis in 2014, 2015 and 2016. Additionally, detailed hedge volume and price information may be found on our website. In summary, the third quarter was a solid quarter, with the benefits of low-cost growth outweighing the negatives of significantly lower realized NGL gas and oil prices. Building off of the balance sheet improvements and restructured credit facility, based on current strip prices, we are positioned to finish strong in 2014, with a return to double-digit, quarterly, year-over-year cash flow growth to a company of double-digit production growth. Chad, over to you.

Thanks, Roger. First, I'd like to provide a little macro perspective on Appalachian natural gas. Northeast natural gas supply has grown to a current rate of roughly 60.5 Bcf per day. Half of that coming from Southwest Pennsylvania, Ohio and West Virginia, and the other half from Northeast Pennsylvania. Most of the recent volume growth has come from the Southwest Pennsylvania region, with Northeast PA supply flattening due to pipeline constraints in that area. Base demand in the overall northeast is approximately 12 to 13 Bcf per day, including summer injection. This seasonal oversupply has had a negative impact on regional Appalachian index prices during the current shoulder period. Index prices in other parts of the country have remained relatively stable. As the current shoulder period ends and winter season demand picks up, northeast regional index prices are expected to improve. The good news is the Midstream industry is bringing relief to the oversupplied Appalachian region. Beginning in mid-2015 through 2018, new announced pipeline takeaway capacity from Appalachia totaling an estimated 31 -- excuse me, 34 Bcf per day and representing over $35 billion of capital investment will provide improved supply/demand equilibrium, strengthening Appalachian basis differentials and improving net realized prices. Also, beginning in 2015 and growing through 2020, increasing demand, totaling an estimated 15 to 20 Bcf per day, is expected to come from DOE FERC-approved LNG exports, the majority of which is on the Gulf Coast, increasing exports to Mexico, power generation, especially in the Southeast and pet chem industry growth. As we have emphasized in our third quarter earnings release and in our IR presentations, Range's early entry into the Marcellus has allowed us to secure relatively low-cost, firm transportation, the in-service date of which follow our projected annual production growth of 20% to 25%. We want to assure we are not paying for capacity we won't be using. These firm transportation arrangements move our natural gas and natural gas liquids to markets, with strong year-round demand and stable index prices. As mentioned earlier, we're sending our gas to the Midwest, Gulf Coast and Southeast. We believe that there are certain locations on the East Coast as well that have strong demand throughout the year, including the summer, and provide attractive index prices. We will continue to pursue those markets as well. I will direct you to our earnings release, which provides detail on our corporate gas price basis differential to NYMEX for the third quarter of minus $0.49, which is an improvement over the second quarter. As you know, Range extracts ethane from our wet gas at the MarkWest processing plants. We do this because our ethane sales contracts generate more cash flow for Range then leaving the ethane in the gas stream. For Range, we prefer to optimize cash flow rather than a higher gas price and NGL price per unit. Alternatively, some of our peers leave their ethane in the gas stream, creating richer gas, and reflect the impact of a richer gas as BTU uplift in their gas price realizations. Again, Range maximizes our cash flow by extracting the ethane from the gas and selling it separately into, by mid-2015, 3 different sales agreements. If you took our current ethane sales proceeds and added it to our total corporate gas production revenue, it would increase our corporate gas price realization by $0.32 for the third quarter. As a result of this, the third quarter corporate differential would be minus $0.17 rather than the minus $0.49 figure reported. We believe this to be the most accurate comparison of peer group gas price realizations. While in the near term, the Northeast regional oversupply subsides as Midstream industry builds out their announced expansion projects, Range will continue to direct our efforts toward finding the strongest, most stable areas of domestic natural gas demand. We also are expanding our NGL sales efforts to a broader, more global scope, seeking any available arbitrage in international markets. Back to you.

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

[Operator Instructions] Our first question comes from Brian Singer with Goldman Sachs.

You've talked about the increase in your takeaway contracts in detail in your slides over the past couple of months in 2016 versus 2014, but can you talk a bit about 2015 and how those contracts look if we would take away the benefit of Mariner East out of the equation and assume no changes to recent pricing? What you see as the benefits to your margins from the contracts that would be coming on in the next year?

Yes, Brian, this is Chad. As we've alluded to in the notes, there are other areas of the country where the indexes have remained relatively stable. One of those is in the Midwest. We do have, in 2015, some significant volume coming on to take gas through the Chicago, Michcon area, which is -- that's really the main amount that's coming on in 2015. Again, 2016, we have quite a bit coming on that's going to the Gulf Coast. It's really competitive, and we do have some other deals we're working on with NiSource and TETCO that we really don't want to get into specifically. So I can just say that, that level [ph] in lateral Michcon, Chicago volume that's coming on in 2015 is what we want to talk about.

Yes, and I would just add to it. What Chad had mentioned earlier, we're going to get into winter pricing, assuming we have any kind of normal winter, which some of the weather forecasters are saying we will. So we'll get into winter pricing, which is good in Appalachia and with our contracts. And we get into Mariner East propane in the first quarter of next year of 2015. We get into Mariner East ethane at the middle of the year, and all these things are uplifts. And now we get into the better gas price contracts that Chad mentioned, coupled with just the increased demand with the LNG exports, Cheniere starting up, hopefully, and projected to be on time about this time next year. Plus some of the increased Mexican exports and also -- we think that Range is uniquely positioned with ethane contracts and propane contracts and some things that some of our competitors don't have that will give us an uplift in a stable price environment or steady price environment. But we have some incremental contracts and things coming on as well.

And as a follow-up, switching to the Utica. Your Utica heat map [ph] now focuses more heavily on Southwest PA. If your thesis is correct, how would that change how you think about your capital priorities between Utica -- between drilling the Utica versus the Marcellus within Southwest PA? And how strategic would that change, how strategic your Northeast PA position as to the company?

Yes, let me talk a little bit about -- one of the things we do that you just mentioned is our map before for gas in place or hydrocarbon in place was for Utica/Point Pleasant. So we stripped it out and showed just the Point Pleasant since that's the real reservoir target, and that's where the more prolific wells are. And we think it's not just about gas in place, but we think there's other things that factor into it. Another key factor other than gas in place is we think the areas of the highest pore pressure and highest geo pressure really relate to where the high-quality gas wells are. And we've outlined that in green on Slide 14. So when you look at where those 2 things coincide, we have a really dominant position in there, of course, where -- there's old Trenton-Black River wells that gives us the ability to map that, and then we've just drilled, and pet logged, and cased our first well, and we're in the process of completing it. Importantly, when you look at our hydrocarbon in place numbers, there's no potential in there right now for Utica/Point Pleasant. When you look at the acreage map back on Slide 11, in that Southwest -- we have south -- 537,000 acres in Southwest PA on Slide 11. 400,000 of those acres are prospective for Utica/Point Pleasant. So you can kind of do the math yourself, take the gas in place numbers, times that, and come up with what the resource potential could be. Specifically getting into your question, our strategy is to have that well completed, tested, and if all goes well, announced towards the end of December. We'll put that well online and test it, and we have the capacity and ability to do that. And then we'll offset that well a couple of times with the wells spudding somewhere in the spring of next year, and we'll drill a couple of more wells. And then we'll watch their performance. Then the key is, really, the performance of those wells. Again, strategically, when you go into 2016, even with where prices are, where the strip is today, we still think that we'll be cash flow neutral to a little bit positive in '16, but we think in 2017, '18 and beyond, we throw off a lot of cash. So the Utica gives us optionality. One of the options with increased cash flow is to reinvest in the high rate of return projects and pull some of that value forward and potentially ramp growth in those years. Still living within cash flow but getting higher growth because of the incremental cash flow that we'll have. Another option that it gives us is to the extent the returns are strong, we can start rolling in Utica wells and get even more efficient capital growth. We think there's a lot of efficiencies coming. Another important part, I think, to our acreage position, stepping back away from your question a little bit, is the fact that we own all horizons. So we drill -- as we're drilling the Marcellus and driving up production and driving up cash flow, we're holding everything above and below. So there's no pressure on us to drill. It's a great option that I think will create a lot of value on our stock. Kind of a long-winded answer, but I wanted to -- hopefully, I answered your question and added a little bit to it.

Our next question comes from Doug Leggate with Bank of America.

Doug, are you on? You may be muted, we can't hear you. Operator, we're not hearing anything on our end from Doug.

Okay, I'll go on to the next -- next question comes from Neal Dingmann with SunTrust.

Say, Jeff, for you or Ray, the first question is, obviously, just -- I was looking at, I guess, the expected wells that come online in the fourth quarter. Certainly, a large number of the wet area in the Marcellus and then, obviously, in the Nora. So I guess, as you look out into 2015, is this an indication of getting kind of the -- indication of, I guess, the direction you're going to go there? Or how do we think about 2015 CapEx directionally?

Let me talk at a high level, and then, Ray, you may want to add to it. What we typically do every year is we -- of course, we have a long-range plan. We've revised that periodically. We present it to our board in December. Upon board approval -- and typically, what we've done is announce it towards the end of January. So our capital budget is not set yet. That being said, I think what you'll see -- and we've talked about it a lot through a number of things like longer laterals and more stages and better targeting and LOE coming down and unit costs coming down, ultimately, land costs coming down, you're going to see the capital efficiency roll through. Roger mentioned, we're already seeing it in the DD&A coming down strongly over time. So we haven't set that yet. Clearly, our budget next year will continue. The value driver will be the Marcellus. And -- but you may see a little bit of incremental capital go towards Nora and/or a little bit in the Midcontinent. But you're still going to see 90-plus strong percentage of our capital being directed towards the Marcellus with the longer lateral wells. Ray, do you want to comment about some of the wells lateral lines in the fourth quarter and a little bit maybe what you're thinking about for the '15?

Yes, sure. Neal, what -- I think we're -- there is no question, we're striving to drill longer and longer laterals. We see that as really improving our capital efficiency. Our team is learning a lot of technical things about targeting and RCF completions and frac designs. We're making a lot of really great progress from what we think is already a leading position as far as well performance because we do have that core area. I think another thing to point out is the mix of wells, I think, will change from time to time just simply because we have -- remember, we have 1 million net acres. We're developing over 500,000 of that in Southwest PA. We have dry, we have wet, and we have super-rich. When you look at our presentation that the economics of those 3 different areas, you'll see they're all relatively close, something over 100% even at today's -- all of today's prices, today's EBITDAX, transportation costs, everything rolled in as it is. They're all very competitive. So HBP is not really an issue anymore. We've got that taken care of. And what we see going forward is just really a focus on driving up our capital efficiency even to higher levels than we are today. And I think you'll just see that kind of ebb and flow between super-rich, wet and dry as we go and as we build out infrastructure and make all that happen.

Ray, just a follow-up to that. How do the -- sort of the near term differentials play into your thoughts about what to drill? I mean, I was just looking, obviously, where your guidance -- we certainly know that just in the near term, the Northeast PA has a little bit wider differentials until some of your FT and other things come online. How do the differentials sort of play into this in the near term until some of the FT and other arrangements come online?

Well, we look at everything on a real-time basis. So we make real-time capital allocations throughout the year. And when you look at the economics in Northeast PA today, again, with all the basis differentials, with all -- everything that the Northeast PA market is challenged with right now, because our team is doing so well with those wells, our well costs are down below $5 million, and we're making wells that are -- have 90-day production of over 20 million a day. Well, some of the top 10 wells in the Northeast PA, those wells still, on a rate of return basis, compete very favorably, even with the wells in Southwest PA. And of course, in Northeast PA, we have -- everything is HBP-ed up there. We can maintain that area with the 1- to 2-rig program, but that's, again, like Jeff was talking about earlier, as we move into the out years, past 2016, when we go cash flow neutral or slightly positive, we're going to start throwing off lots of cash in the outer years. We see Northeast PA as another area that we can ramp up because we do believe, as Chad was speaking about earlier, the increased takeaway projects, the increased demand, that's -- there's billions of dollars being spent on, we believe all of this is going to allow us a great option to able to accelerate areas going forward. And one of those areas could potentially be Northeast PA.

Got it. And Jeff, one last one, if I could. You all mentioned just a large amount of mineral ownership that you all have. Would you think down the line, either '15 or '16, of some sort of monetization around this like one of your peers has done at Perm or? Have you all got any thought to that?

Yes. Neal, this is Roger. I'll take a swing at that one. When you look back 8 years, Range has sold or exchanged over $3 billion worth of assets. So I think we've got a pretty clear history of when we have an asset that we feel is worth more to a different set of shareholders than ours, than we will part with that asset. And I don't -- we don't view this any different view. I think, though, in the case of the Nora royalty, when you look at the low decline underlying that field, I mean, this is an enormously high-quality royalty interest. And I think even as faulty is the valuation might look out there today, I think it's better than most of what's out there. So -- but looking back at our history, we're very reluctant to part with an asset until we know with a high degree of certainty what it's really worth. So for us, the issue isn't so much the front [ph] evaluations that might be out there today. But as Ray was mentioning, the extraordinary improvements that we're seeing in recovery, in production out there, what does that asset going to be worth a year or 2 out. We want to get our arms around that before we make those kind of decisions. I think that's very characteristic of how we've done things in the past and what you'll see us do going forward.

Our next question comes from Doug Leggate with Bank of America.

Two quick questions, if I may. First of all, on the Nora. I don't know if you touched on -- or at least not to the extent that we wanted to on the deeper opportunity in the Nora. Is this a dry gas play in the deeper -- down the basement that you talked about? Or is there a liquids opportunity? I'm just -- and I'm thinking really more about the premium gas market. How does this impact your capital allocation decisions, particularly as it relates to Northern Marcellus? And I've got a follow-up, please.

Yes, let me take that one. Yes, Nora is really interesting, and Ray mentioned we're doing some fairly low-tech things that are really inexpensive to enhance value of the tight gas sands in CBMs and having great success right out of the box. I think we're 10 for 10 or 12 for 12. But it's interesting, there's potential, deeper potential. Some of that deeper potential is in the Devonian section, literally. I mean, by deep, I mean, we're talking 5,500 feet. But there are other horizons as you go below that. According to our exploration, and we'll see over time, some of the upside or optionality is, even though the southern part of the Appalachian basin is subnormally pressured, our explorationists think as you drill deeper, and remember, deeper may be, ultimately, basement. We're not sure where basement is, which is really exciting. It may be 11,000 12,000, 13,000 feet because nobody's ever drilled that deep. There's only -- the deepest -- most of the well stop at 4,000. Some at the 5,500. There's a couple of wells, one goes to 7,000 and one goes to 7,500. But they're old wells, old technology. No 3D seismic and just a couple of old 2D [ph] lines. Our explorationists feel as you go deeper, you actually break back in to normal pressure, and then potentially, geopressure, which is exciting. And they also think some of those horizons, as you go deeper, may contain liquids or wet gas. Well, we'll see with time. The nice part about it is we have 475,000 acres that are basically unexplored deep. Again, deep, being below 5,500 feet, which isn't really that deep in most parts of the U.S. So we have that potential. We own 475,000 acres, 100% working interest and most of 100% net revenue interest. And we totally control the timing. So what you'll see us do in the short run is experiment with some of these completion techniques, which really is just running a higher strength pipe so we can pump at a higher pressure, pump at higher rates, pump bigger fracs and better stimulate the wells. And there, it's fairly inexpensive, and we're seeing, on average, almost double the rates for an incremental cost of, call it, $15,000. So long-winded answer again, but I think there is the potential for higher pressure as we go deeper and there is the potential for liquids.

So Jeff, just -- again, this is obviously arguably a better gas market than your Northern Marcellus. So I guess you're just running minimum activity there any way to hold acreage. But how does it stack up in terms of the overall portfolio, as almost like a diversification play if you like, now that you own the whole thing?

Yes, and we have in the book and there's some slides in there, and Ray talked about it last time. We're just flipping through the slides. On Slide 19, you can see the returns in the -- under various gas prices in the southwest part of the Marcellus, depending on price you use and where you are. Anywhere between about 90% to 120% rate of return. You've got strong returns in the Northern Marcellus there in that -- really in that same range. And then when you flip to the Appalachian slides that we have in there, on Slides, really, 31 -- Slides 30 and 31, we're saying the returns of some of those projects are also up to 100%. So they're all strong returns. The one area that you'll see us focus on drilling again in the short run is the Southwest Marcellus in that that's the only area where, ultimately, we need to drill to hold all the production. To make it really clear, with the leases we have and the drilling plans we have, we'll hold all that acreage within the existing lease terms that we have. So there's no concern over losing it. But we need to drill it to hold it. So you'll see us focus our activity down there. It also happens to be where we have some of the highest returns, and it also happens to be where we have the flexibility of wet, dry and super-rich, plus we have all the stacked pay potential and information that we gather as we drill those wells. But in time, I think there's a great upside in the Nora. When you look at that area, we're making roughly 100 million per day. I think with what we've identified, I think we have the potential to drive it to greater than 500 million per day, with stuff that's already on the books, 500 million could become 700 million. You throw a little bit upside in, and I think there's great potential if we have some exploration success and stuff down in that part of the basin. And it's near good gas markets.

I don't want to labor the point, but can you put a time line on that? Because, actually, what I'm trying to get at is how quickly do you think you...

Yes. I think, what I mean, -- we have it again. We'll present our budget to the board in December because of the fact that we didn't have a JOA with EQT down under. And most areas, you do have a JOA. We couldn't spend capital. So really, capital allocation in Nora has been close to 0. And with last year, I think we had allocated -- or this year $20 million roughly. So we haven't set our budget yet. I think for next year, $20 million may become $50 million, something like that, $40 million, $50 million, $60 million. We haven't set it yet. The year after that, it may become something like $100 million, again, all subject to board approval. And then $100 million may become $200 million. And you'll see that ramp kind of in that time frame. And as we do that, we'll unlock what we believe is great value or out-of-the-box, I think, we're off to a strong start in enhancing the value. And then we can decide that ultimate ramp and how to ultimately maximize the value even from a financial perspective.

Okay. Jeff, I don't want to take out too much time here, but I've got a very quick follow-up, if I may. Just real quick. You've been very good about optimizing capital. When I look at the stock that you mentioned there, I just kind of wonder, when you start talking about Utica, Devonian and Marcellus, all in the same kind of area, what can you do to reduce your surface footprint? I'm thinking about is there a multi-stock gradual opportunity somewhere down the line? Or is it still too early to think about that?

Well, I think one advantage, as Ray pointed out, is we can put a lot of wells on those pads in excess of 20 wells on the pad and to whatever horizon we want. So then you get the ability utilizing the same pads and roads and a lot of the other infrastructure. So there -- but I think you're right with time, having stacked pay like that, there's kind of a free auction of technology in the future of stacked laterals. And clearly, you can drill stacked laterals right now. And then, I'm sure, with time, ultimately, we may be able to drill stacked laterals and effectively stimulate them. So there's a nice upside to what technology can bring. And there's a big advantage to having all those horizons on top of one another, let alone scattered out across different parts of the country.

Our next question comes from Joe Allman with JPMorgan. Joseph D. Allman - JP Morgan Chase & Co, Research Division: Regarding the new completion techniques and the completion designs, I heard what you said on Nora. I also heard what you said on longer laterals and better targeting. But what design changes do you think are having the most impact? And what are some of the new techniques that you're trying? And can you talk about the differentiation by area?

Ray, do you want to take that one?

Sure. I'll start with Nora. And like Jeff alluded to, really, what it amounted to there is, in the past, a lot of those wells were -- completed limited entry where you put a limited amount of perforations in a lot of different layers and try to accomplish the stimulation with one frac job. Essentially, what we're doing today, by running, investing a little more money in constructing the well with higher strength casing, we can pump at higher rates and higher pressures and allow us to pump more fluid at higher fracture pressures down hole, so to speak. You create more near wellbore complexity and fractures, which, therefore, yields more production. And that's been highly successful at this point. Again, we're early, but like Jeff said, I think we're 10 for 10 or 12 for 12. And some of the best results we've seen in 10 or 15 years, both in the tight gas vertical and the CBM. I think there's a huge potential for us to study and model that further and look at different types of frac designs, different volumes and a lot of things there. Like Jeff said for a number of years, we've not really spent much money there, and we just have really done a lot other than just maintenance type work. So we're pretty excited about that. Shifting to the Marcellus, we're doing a lot of the things. We're just continuing to refine and do a lot of the things that we've been doing all along. And you've seen us, year after year, continue to update our EURs. Our type curves continue to look better. Our results on a normalized per foot of lateral basis have been very consistent. And we think there's still a lot of work to do as we continue to refine our targeting techniques, we continue to define the spacing between our RCS completions and perforation clusters and different types of profit designs or some of things that we're working on, the profit loading, liquid loading that we're pumping into these wells. So a lot of that stuff is continuing on with what we've been doing in the past, and you've seen us just continue to get better and better results. I'm really proud of our technical team there, and my hats off to them continually because they just continue to make better and better wells, I mean, some of the wells I've talked about in my remarks. When you've got 4 out of 5 wells making close to 1,000 barrels of condensate per day, I mean, that's a tremendous fracture conductivity down hole. And we're really excited about what that means going forward. And we've seen just in the last couple of quarters some of the best wells we've ever done. And we're pretty excited about that and how we use that information going forward. So again, we're just continuing to capture that data, model it, understand it and continue to refine that going forward. And I think we -- like we talked about a lot of times in the past, I still think we're in the third or maybe fourth inning of the baseball game. We've got large core area there with a lot of diversity being super-rich, wet and dry. And I think there's no one pat answer for any one specific area. And I think as our team has learned to identify those things, which makes the best wells, I think we're just going to -- you're going to continue to see our capital efficiency get better and better.

The only thing I'd add to what Ray said is we're in that maybe third inning of the Marcellus or so. And the Point Pleasant in Washington County, we have first batter up. So we're excited about the first batter. Joseph D. Allman - JP Morgan Chase & Co, Research Division: And Ray, do you think we're in the third or fourth inning in terms of the technological leaps? Or do you think we're in the third or fourth inning in terms of the application across your acreage?

I think it's -- mostly both is the way I would characterize it. I think there's some technological breakthroughs that are being looked at in a lot of different areas, whether it's modeling, whether it's frac design or just pure operations. Even in the well construction side of things, like Jeff referred to, being able to drill stacked laterals or even opposing laterals out of a single vertical wellbore, I think there's some major technological breakthroughs that will happen in the next, I think 3 years or 7 years out, but some of it exists and some of it is just not commercially applicable in our situation yet. But I think those things will happen. And when they do, it'll be a major step change. And none of that is built into our long-range plan, and I think that those kind of things are just going to be more upside for us going forward.

But I would -- I agree with Ray, but what I would add, though is, again, what's really important is to be in the core part of the play, whether it's in Marcellus or any play. So you want to be in the core and about -- on average, about 10% of the acreage is core. And then it's important when you compare cores of the various plays. And the advantage that the Marcellus had is its higher-quality rock versus some of the other plays in other parts of the country. The big technology increases will really impact people in those areas. What you want to have is acreage in the core with high-quality rock, a lot of hydrocarbon in place. And then using high-quality teams, tighter spacing, new technology and better completion and drilling techniques to just keep driving up recovery factors. And I think we're in that position. Joseph D. Allman - JP Morgan Chase & Co, Research Division: That's very helpful. And then are you convinced that you're getting increased EURs versus just bringing production forward?

Yes.

Yes.

Yes.

And the third yes was Alan Farquharson, our Senior Reservoir Engineer. If you heard 3 yeses on the call, so... Joseph D. Allman - JP Morgan Chase & Co, Research Division: I did. And I could say I got that confirmation. And then just quickly, in your Northeast PA, could you just remind us of your takeaway situation there? And is that also -- are you in good shape there, keeping up with production growth? And also talk about any asset, the after-sale right now or in the near future.

Yes, let me just say it at a high level, and then I think we'll probably take one more question. And then we're already running over a little bit. I don't want to run over it too long. The marketing team's done a really good job. We have a long-range plan, which is important part. We have really well-integrated team, everybody from all the engineering, geology, marketing, finance, midstream, all the different pieces. So the plans that we have, long range for that acreage, the marketing team's done a good job of varying the takeaway to good markets for that team as well. So I think in terms of takeaway out of there, I think we're in pretty good shape.

Nearing the end of today's conference, we will go to Dan McSpirit of BMO Capital Markets.

I have several questions, but will limit it to one and one that's maybe more philosophic. If you speak to an improving supply/demand balance in today's press release or yesterday's press release, what are the chief risks to that outlook, whether on the supply or demand side of the equation? I asked to not only get your view of the world but determine whether producers in the basin that are less well positioned have really felt maximum pain?

Well, let me start at the high level and then turn it over to Chad, and then there may be others on our team that want to talk about it. But I think the good news when you look on the demand side is -- there's a number of analysts out there, and I won't quote them, but there's a lot of people that show incremental gas demand, plus or minus 20 Bcf per day. Some people are saying 2018, 2019, 2020. I think on the high side, the University of Texas had 25 Bcf of incremental demand. And it comes from a number of things. So I think on the LNG side, again, Cheniere, the first project, everything that I hear is on time. And the second and third trains, they'll start in '16. All of that is on time, and it should happen. So I think the LNG stuff in the U.S. is important. I think gas is a superior fuel to coal. So in terms of -- gas has been displacing coal from power generation with time. I think that'll continue as well. Billions are being spent on the petrochemical side to convert the feedstock from an oil-based feedstock to a gas-based feedstock. So I think that'll happen. And slowly but surely, you're seeing transportation occur. So I think the demand is coming, the demand is coming timely, plus there's exports to Mexico. So I think those things will happen. On the supply side, again, I think most of the plays -- the core parts of the plays are about 10%. Our teams have looked at all the plays around the country. They range from a low of 6% being core to a high of 17%, according to our team, with an average of 10%, which means 90% is non-core. If you look at a lot of the non-core stuff, it's not going to get drilled in the next 20 years or 30 years. I don't think. I think it's way out there. So I think, ultimately, as that shakes out, there's help there. And then the other piece is the infrastructure build-out, and we have a slide in there in our presentation that addresses infrastructure build-out, and it's on Slide 22. And we think, in the Appalachian Basin, that occurs at about 2016. So I think all that stuff works out. And once it does work out, then it's where's the low-cost gas. The other thing that low-cost gas has done, it's not only going to be exported, but it's displacing coal for power generation. It's displacing oil, the feedstock for petrochemical. Displacing a little bit of oil to feedstock for transportation. The other thing low-cost Marcellus gas is doing is displacing high-cost gas in plays like the Haynesville and Barnett and Woodford and other areas where you've seen the rig counts come down and the production from those fields come off significantly. So I think all of those things are happening. Back to your question about maximum pain, I think, again, our team has done a good job, the marketing team working with the operations team to make sure that we can move our gas between now and then. I think companies that haven't done that maybe haven't felt maximum pain. But I think it's another competitive advantage and another differentiation for Range. So anybody else on our team want to add to what I said? Or did I...

It's Chad. I couldn't have answered any better, but I will say that where commodity prices are right now, we know the demand is coming. It's just a matter of when will it come and at what levels. So with that being said, you got to look at the curve and see at what price are you able to drill and deliver the supply to meet that demand. So you'll see the curve play out as that demand -- as the market starts seeing that demand take traction between the LNG exports, power gen in the Southeast, Mexican exports, we're displacing gas from Canada. It's happening. It's just a matter of exactly when the markets will see it coming, at what price to be able to supply that demand.

Yes. And again, I think it's not that far out there, weather clearly plays an issue. I read something from AccuWeather that, hopefully, it's snowing in parts of the country on Halloween or at least raining and cold. So that's -- from our perspective, it's a good thing. I feel bad for some of the kids trick-or-treating, but that's helpful in the short run. And then it's back to differentiation for Range. We have that firm transportation and supply to bridge us through those harder periods, Dan, that you mentioned. And then in addition, we have contracts that none of our competitors have in terms of some of the liquids, which give us an uplift starting in the first quarter of '15, not that far out. Plus the weather, if we get any normal winter, though. It's not that far out. And then, again, it's an advantage for us so...

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

Okay. I'll conclude on the same themes I discussed in my opening comments. Fundamentally, we believe that Range is a simple story. Range has the largest acreage position in the core to play, largely in the stacked pay area in Southwest Pennsylvania. We have the wells identified, the field infrastructure being built and the necessary takeaway capacity contracted to grow 20% to 25% each year to triple our current production to 3 Bcfe per day and beyond. The acreage position largely covers the most perspective liquids resources in the basin, with necessary transport and export facilities being built to handle our multiyear growth. We want to thank our shareholders for their support. We believe that Range will be a leader in building shareholder value. Thanks for participating on the call. If you have additional questions, please follow up with our IR team.

Thank you for your participation in today's conference. You may disconnect your lines at this time.