山脈資源 (RRC) 2014 Q3 法說會逐字稿

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 [but] 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 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 EDGAR system. In addition, we posted on our website supplemental tables which will guide you in the calculation of the non-GAAP measures of cash flow, EBITDAX, cash margin, 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 of 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 markets 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 will have a renewed or newfound appreciation for all the things that are going right at Range and how we have differentiated ourselves.

This the 10th year anniversary of the discovery well for the Marcellus, which was Range's rents number one in October 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 BCF 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 amount of natural gas, creating a temporary oversupply in the region and the weakness in pricing that we have 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 the short-term oversupply with outstanding growth plan for the coming years of growing US 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 of $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 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 transportation contracts in 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 liquids 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 advantaged 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 and 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 are operational equates to more than $100 million per year uplift to our net cash flow that all begins to 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 have also captured the heart of the liquids-rich in 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 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 have driven up production, our total unit costs has consistently declined. In some cases, we have even reduced absolute costs as we've high graded 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 remain 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 the liquids, prices through the previously-mentioned contracts. In addition, as the infrastructure in the Basin builds out, are 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 six 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 Appalachia 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 Mississippi and 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, in 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 costs 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 cost 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 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 we'll point out, one of those pads was a five well super-rich pad, where two of the wells averaged over 1,000 barrels of condensate per day each. And two 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 a line of three well pads that had an average 24-hour IP to sales of 26.4 million a day. The 30-day average to sales for the three wells was 17.4 million a day per well, and they averaged 5,364 foot laterals with 28 stages. These two 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 are 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 in improved well performance, as we have 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 have 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 2013. As you might suspect, this translates to a pretty good production and revenue increase as we bring wells on in the better processing environment this winter. For 2014, our average lateral length for wells in Southwest PA, including super-rich wet and dry, is projected to be 5,402 feet. This is 55% longer than in 2013.

For 2015, we're estimating that our average lateral length in Southwest PA will be more than 6,200 feet, with one-third 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, as I've just said just now, followed by 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 one to two rigs, while the team is doing really well at lowering costs and developing bigger and bigger wells.

At the last call, we announced a 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 ten wells in Pennsylvania. And I might add, the only well in the top ten 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 IP greater than 1,000 BOE per day, we're confident that we have identified key reservoir areas to target going forward.

For two quarters now, we have set records in well performance. And with continued success in the fourth quarter, we expect to be able to modestly increase the activity levels in the Chat play next year. We're still finalizing those plans, and we'll announce the planned well counts when we announce the 2015 budget.

Moving to the Southern Appalachia 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 improved performance in economics.

In this 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 six 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.

Of particular note is a new CBM well that's produced at a 60-day average of 340 MCF a day, which is five times the average CBM rate. And we just turned in line a new completion that's at that same level. There are over 2,000 CBM locations identified at the current spacing with a potential of over 3,000 infill locations.

Similar improvements have been achieved with the same well design and high rate fracturing 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 cost. With seven 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 derisked for future tight gas development. The division is also drilling horizontal Huron shale wells, and there are over 2,000 derisked 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 four penetrations below the Devonian shale, we believe there's significant potential for exploration in the 6,000 plus feet of additional settlement 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 Appalachia. 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 properties. 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 to average NYMEX Plus $0.20 year-round, with some gas potentially achieving even better prices in the prime winter markets.

The well-defined large and derisked inventory of projects, which totals over 5.2 TCF of derisked 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 secured 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 a track record to support, to achieve our goals for growth and 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 in 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 plus; and Moody has moved 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 price markets. Not just in the US, but all over the world.

Following the ratings upgrade, even though Range has continued to add significant long-term 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 a hidden cost of transportation and reduces available liquidity.

Credit quality matters now, and we believe it will matter even more later. Complementing our new credit ratings, Range restructured and renewed for another five 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 one-quarter percent below the old facility. And the new credit contains a fall-away, a 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 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 the 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 a $1.54 per share. Given that the third-quarter 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 8 times 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 excludes asset sales, mark-to-market hedging entries, and various nonrecurring items, was $62 million, 8% higher than last year at $0.37 per fully diluted share.

As Rodney mentioned earlier, please reference the various reconciliation tables found on the Range website and earnings release for a 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 in MCFE, down 14% from the $1.48 figure per MCFE last year. The declining 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 finished strong in 2014, with a return to double-digit quarterly year-over-year cash flow growth to accompany our double-digit production growth.

Chad, over to you.

Thanks, Roger.

First I'd like to provide a little macro perspective on Appalachia natural gas. Northeast natural gas supply has grown to a current rate of roughly 16.5 BCF per day. Half 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 gas 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, the 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 take away capacity from Appalachia, totaling an estimated 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 demands 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 dates of which follow our projected annual production growth, up 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 economics 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 plant. We do this because our ethane sales contracts generate more cash flow for Range than 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 the 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, three 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.

Thank you Mr. Ventura.

(Operator instructions)

Brian Singer, Goldman Sachs.

Thank you, good morning.

Good morning Brian.

You've talked about the increase in your takeaway contracts in detail in your slides of the past couple of months in 2016 versus 2014. But can you talk a bit about 2015 and how those contracts look? And if we were to 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 have 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 to the Chicago, MichCon area, which is -- that's really the main amounts 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 Techco that we really don't want to get into specifically., So I can just say that, that lateral MichCon Chicago volume that's coming on in 2015 is what we want to talk about.

I would just add to it, like Chad had mentioned earlier, we're going to get into winter pricing assuming we have any sort 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 then we get into Mariner East propane in the first quarter of next year 2015, we get into Mariner East ethane at the middle of the year and all these things are uplifts.

Then we get into the better gas price contracts, that Chad mentioned, coupled with the increased demand with the LNG exports in here, starting up hopefully, and projected to be on time about this time next year. Plus, some of the increased Mexican exports and all so, 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.

Thanks. And as a follow-up, switching to the Utica, your Utica heat map 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, or would that change how strategic your Northeast PA position is to the company?

Let me talk a little bit about -- it's one of the things that we did that you mentioned is our map before for gas in place or hydrocarbon in place, was for Utica Point Pleasant. So we stripped it out and show 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 that there's other things that factor into it. Another key factor other than gas in place, is we think the areas of the highest core 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 two things coincide, we have a really dominant position in there, of course there's old Trenton-Black river wells that give us the ability to map that, and then we've just drilled and cataloged 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 is no potential in there right now for Utica Point Pleasant. When you look at the acreage map back on slide 11, in that Southwest Penn, we south of 530,000 acres in Southwest PA on slide 11, 400,000 of those acres are perspective 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 to 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.

Then we'll watch the performance. And then the key is really the performance of those wells. Again, strategically when you going to 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 2016, but we think that in 2017 and 2018 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 the 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 is our acreage position, stepping back away from your question a little bit, is the fact that we own all horizons. So if 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 in our stock. Kind of a long-winded answer but hopefully I answered your question and add a little bit to it.

Thank you.

Doug Leggate, Bank of America. Neal Dingmann, SunTrust.

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

Let me talk a high level and then Ray, you may want to add to it. What we typically do every year is, of course we have a long-range plan, we revise that periodically, we present it to our Board in December, upon Board approval, and typically what we've done is announced 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 lateral's 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. But you may see a little bit of incremental capital go towards Nora or little bit in the mid-continent, but you're still going to see 90 plus or a strong percent of our capital being directed towards the Marcellus with those longer lateral wells. Ray, you want to comment about some of the wells lateral lengths in the fourth quarter, and a little bit maybe what you're thinking about for 2015?

Sure. I think there's no question that we are striving to do longer and longer lateral's. 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, and 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 the 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, remember we have a 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, and you look in our presentation at the economics of those three different areas, you'll see there all relatively close to something over 100% even at today's, all of today's prices, today's deducts, 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 focusing on driving up our capital efficiency, even to higher levels than we are today, and I think that 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.

Hey Ray, just a follow-up to that. How do sort of the near-term differentials play into your thoughts about what to drill? I was just looking at 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 on line. How did the differentials play into this in the near-term until some of the FT and other arrangements come on line?

Well, we look at everything on a real-time basis. So we make real-time capital allocation throughout the year. And when you look at the economics of Northeast PA today, again with all the basis differentials, with all of 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 have 90 day production of over 20 million a day.

Well some of the top ten wells in 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'd up there, we can maintain that area with the one to two rig program. But that 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 take away projects, the increased demand, you know, there's billions of dollars being spent on, we believe all of this is going to allow us the great option to be 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 2015 or 2016 of some sort of monetization around this? Like one of your peers has done at the Perm or have you all given any thought to that?

Yes, this is Roger, I'll take a swing at that one. When you look back 8 years range it sold or exchanged over $3 billion worth of assets, so I think we have a pretty clear history of when we have an asset that we feel is worth more to a different set of shareholders than ours, that we will part with that asset. And we don't view this as any differently. I think though, in the case of the Nora royalty, when you look at the low decline underlying that field, this is an enormously high quality royalty interest.

I think even as property evaluations might look out there today, I think it's better than most of what is out there. But looking back at our history, we are 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 [frothy] evaluations that might be out there today, but as Ray was mentioning, the extraordinary improvements that we're seeing in recovery and production out there, what is that asset going to be worth a year or two out?

We want to get our arms around that before we make those kinds of decisions. I think that is very characteristic of how we have done things in the past and what you'll see us do going forward.

Great thank you all.

Thank you.

Doug Leggate, Bank of America.

Hello. 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 to turn to the deeper opportunity in the Nora.

Is this a dry gas play in that deeper down-to-basement that you talked about? Or is there a liquids opportunity? And I'm just thinking more about the premium gas market, how does this impact your capital allocation decisions particularly as it relates to Northern Marcellus? And I have a follow-up please.

I'll 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 the value of the pipe gas hands and CBMs and having great success right out-of-the-box, I think we're ten for ten or twelve for twelve. But it's interesting, there's potential -- deeper potential and some of that deeper potential is in the Devonian section literally and by deep we're talking 5,500 feet but there are other horizons as you go below that.

According to our exploration and we'll see with time, some of the upside or optionality is, is even though the southern part of the Appalachian Basin is sub-normally pressured, our explorationists think, as you drill deeper and remember deep here 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 has ever drilled that deep. Most of the wells stop at 4,000 and some to 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 3-D sides making just a couple of 2-D lines. Our explorationists feel as you go deeper you actually break back into 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 and again deep being below 5,500 feet. Which isn't really that deep in most parts of the US. So we have that potential. We own the 475,000 acres, 100% working interest and most of it 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. From there it's fairly inexpensive and we're seeing an average almost double the rates for an incremental cost of, call it $15,000. So, long-winded answer again, but I think that there is the potential for higher pressure as we go deeper and there is the potential for liquids.

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

Yes and we have in the book and there are 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 under various gas prices in the Southwest part of the Marcellus, depending on the price you use and where you are, anywhere between about 90% to 120% rate of return.

We have strong returns in the Northern Marcellus, they're really in that same range, and then when you flip to the Appalachian slides that we have in there, on slides 30 and 31. We're seeing 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 focused 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 of 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 of the stack pay potential and information that we gather as we drill those wells. But in time, I think there's great upside in Nora. When you look at that area, we're making roughly 100 million per day.

I think with what we have 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 could become 700. You throw a little bit upside in and I think there's great potential if we have some expiration success and stuff down in that part of the basin. And it's near an area where you have good gas markets.

I don't want to belabor the point but could you put a timeline on that, because that's really what I'm trying to get at, how quickly do you think--?

Yes. We haven't -- 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 there and most areas you do have a JOA, we couldn't spend capital so really capital allocation in Nora has been close to zero and 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 timeframe.

As we do that, we'll unlock what we believe is great value 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 up too much time here, but I have a very quick follow-up if I may. Just real quick, you've been very good about optimizing capital.

When I look at the stack that you mentioned there. I just kind of wonder when you start talking about Utica [devoting] Marcellus all in the same kind of area, what can you do to redress your surface strip? I'm thinking about -- is it a multi-stack lateral opportunity somewhere down the line? Or is it still too early to think about that?

I think one advantage that Ray pointed out is we can put a lot of wells on those pads. In excess of twenty wells on the pads into whatever horizon we want. So then you get the ability utilizing the same pads and roads and a lot of the other infrastructure.

I think that you're right. With time, having stack pay like that, there is kind of a free option of technology in the future of stack lateral's. And clearly you can drill stack lateral's right now, and then I'm sure with time, ultimately we may be able to drill stock lateral's and effectively stimulate them. So there's enough nice upside to what technology can bring, and there's a big advantage to having all of those horizons on top of one another, let alone scattered out across different parts of the country.

I will leave it there. Thank you very much.

Thank you.

Joe Allman, JPMorgan.

Thank you operator and good morning everybody.

Good morning.

Hello. Regarding the completion techniques and completion design, I heard what you said on Nora. I also heard what you said on longer lateral's 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 are trying? Could you talk about the differentiation by area?

Ray, do want to take that one?

Sure. I will start with Nora. 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 tried 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 holes so to speak. You create more near wellbore complexity and factors which therefore gives us more production and that's been highly successful at this point.

Again, we're early, but like Jeff said, I think we're ten for ten or twelve for twelve and some of the best results we have 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 and 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 haven't 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. The results on a normalized per foot of lateral basis have been very consistent, and we think that 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 the 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.

You've seen us just continue to get better and better results and I'm really proud of our technical team there, and my hat's off to them continually because they just continue to make better and better wells. I mean, like some of the wells I talked about in my remarks, when you've got four out of five wells making close to a 1,000 barrels of condensate per day, that's a tremendous fractured connectivity downhole.

So 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. 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 like we've 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 have a 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, you're going to continue to see our capital efficiency get better and better.

Thanks. The only thing I would 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.

And Ray, do think we are in the third or fourth inning in terms of the technological leaps? Or, do you think we are in the third of fourth inning in terms of application across your acreage?

I think it's mostly both is the way I would characterize it. I think there are some technological breakthroughs that are being looked at in a lot of different areas. Whether it is 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 lateral's or even opposing lateral's out a single vertical wellbore. I think there's some major technological breakthroughs that will happen in the next, I can't say they're 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 will be a major step change and none of that is built into our long-range plan and I think that those kinds of things are just going to be more upside for us going forward.

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 the 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 it's higher-quality rock versus some of the other plays and 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 faster, and I think that we are in a position.

That's very helpful. Are you convinced that you're getting increased EURs versus just bring production forward?

Yes.

Yes.

Yes.

And the third yes was Alan Farquharson our senior reservoir engineer, if you heard three yes' on the call.

Yes, I got the confirmation thank you. And then just quickly, in your Northeast PA, could you just remind us of your take away situation there? And is that also, are you in good shape there keeping up with production growth?

Also, talk about any assets you have for sale right now or in the near future.

Let me just say it at a high level and then I think we'll probably take one more question here. We're already running over little bit, I don't want to run over too long.

The marketing team has done a really good job, we have a long-range plan which is an important part. We have a really well integrated team, everybody from all the engineering, geology, marketing, finance, midstream, all the different pieces.

So the plans that we have and long-range that acreage, the marketing team has done a good job of mirroring 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.

And then I think we have one more question? Operator?

Dan McSpirit, BMO Capital Markets.

Thank you and good morning folks.

Hello Dan.

I have several questions but will limit 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 a high level and then turn it over to Chad and 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 at the 25 BCF of incremental demand and it comes from a number of things.

I think on the LNG side, again Shaner the first project, everything that I hear is on time. In the second and third trains that start in 2016, all of that's on time and it should happen. So I think the LNG stuff in the US 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 will 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 will 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% 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 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 as feedstock for petrochemical, displacing a little bit of oil as a 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 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?

Yes this is 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've 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, PowerGen 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 at least raining and cold. So from our perspective that'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 rain. We have that firm transportation and supply to bridge us through those harder periods Dan, that you mentioned.

And 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 2015. Not that far out plus the weather, if we get any normal winter at all, is not that far out and then again, it is an advantage for us.

I appreciate it.

Thank you Dan.

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

Okay, I will conclude on the same theme as I discussed in my opening comments. Fundamentally, we believe that Range is a simple story. Range has the largest acreage position in the core of the play, largely in the stack 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 multi-year growth. 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 and if you have additional questions, please follow-up with our IR team.

Thank you for your participation in today's conference.