山脈資源 (RRC) 2015 Q2 法說會逐字稿

Greetings. Welcome to the Range Resources second-quarter 2015 earnings conference call. This call is being recorded. (Operator Instructions). Statements contained in this conference call that are not historical fact are forward-looking statements. Such statements are subject to risks and uncertainties which could cause actual results to differ materially from those in the forward-looking statements.

After the speaker's 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 second-quarter 2015 with record production, a continuing decrease in unit cost, and some outstanding well results.

The order of our speakers on the call today are Jeff Ventura, Chairman, President, and CEO; Roger Manny, Executive Vice President and Chief Financial Officer; and Ray Walker, Executive Vice President, Chief Operating Officer.

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 posted to our website supplemental tables which will guide you in the calculation of the non-GAAP measures of cash flow, EBITDAX, cash margins, and the reconciliation of reported earnings to our adjusted non-GAAP earnings that are discussed on the call.

Now let me turn it over to Jeff.

Thank you, Rodney. The past several months have been a challenge. Appalachian natural gas differentials have widened as the basin awaits take-away expansions and a more balanced regional supply and demand picture. In addition, NGL netbacks have been weak in Appalachia, particularly propane, as regional supplies outstripped summer demand. In the face of these current pricing issues, we remain focused on things that will improve our netbacks in the near term, and things that will make Range successful in the long run. We are focused on executing our plan and driving down costs in the field and at the corporate level while operating safely.

The good news is that we put some arrangements in place years ago that will come to fruition later this year, which should make some of this pricing pain short-lived for Range.

For the second half of 2015, there are two projects that will benefit Range specifically. The first is Spectra's Uniontown to Gas City project. Range is an anchor shipper on this project and has approximately 200 million per day of capacity. The first leg of the project is anticipated to commence on August 1, and the second and final leg is projected to start up on September 1. This will move about 200 million per day gross or about 170 million per day net of our production from the local Appalachian M2 markets to premium Midwest markets.

Under current strip pricing, this should increase our realized price by approximately $1 on this production. For the next 12 months, we have locked in a significant portion of the price uplift by hedging the basis. The uplift from this project is expected to have a significant impact on our Southwest Marcellus realized pricing for future periods. The 170 million per day net capacity would equate to 28% of our average Southwest Marcellus gas production in the second quarter.

The second project, which we expect to be very impactful for us, is Mariner East I. Range has 40,000 barrels per day of capacity on Mariner East I, and is the anchor shipper on this project as well. The capacity is for 20,000 barrels of ethane and 20,000 barrels per day of propane. We will also have access to 80% of a 1 million barrel propane storage cavern at Marcus Hook. Sunoco is projecting Mariner East I to start up in late September, with commissioning completed a few weeks thereafter.

Mariner East I will lock in our Appalachian propane transport costs and result in significant transportation savings. It will also enable us to choose between Northeast markets and international markets, depending on demand and pricing. When Mariner East I is fully up and running, this project, in combination with Mariner West and ATEX, is anticipated to result in about a $90 million increase to our net cash flow on an annualized basis, without counting the potential propane price uplift opportunities.

The marketing team has not only put in place good projects for the second half of 2015; but also looking forward into 2016 and 2017, there are other projects that should benefit Range. Range is an anchor shipper and has 150 million per day gross of capacity on Spectra's Gulf markets expansion project. Startup is targeted for the fourth quarter of 2016, and this will move 128 million per day net of Range's gas to the Gulf Coast.

Rover phase 1 is also planned to start up in the fourth quarter of 2016.

In addition, at the end of 2017, Range has participated in several pipeline expansion projects that will allow Range to move an additional 900 million per day of Range's gas to the Gulf Coast, Midwest, and Canadian markets.

On a macro basis, good things are happening inside the Appalachian Basin. The overall rig count for the Marcellus is down 55% from its peak. Total Marcellus production has been flat to declining since the beginning of the year, based on pipeline flows.

The Utica rig count has dropped 66% from its peak. In addition to dropping rigs, the remaining rigs are moving out of the wet gas and liquids-rich portion of the Utica, which should help rebalance the oversupply of liquids in the Basin. Given the steep declines of most of these Utica liquids wells, the rebalance should happen sooner rather than later.

With the drop in the Utica rig count by two-thirds, coupled with the lack of hedges for 2016 and beyond by most companies, and with lower strip pricing for 2016, the Utica rig count will probably stay low for a while, which will help on the supply side.

Good things are also happening outside of the Appalachian Basin. Looking across the US, the oil rig count is down about 60%. There's a lot of associated natural gas with oil, and the associated gas now accounts for a significant portion of total US gas production. Per flow data, it appears that the gas from some of the key oil basins may have peaked in April. Since the associated gas is very rich, about 40% of all NGLs come from this source. Therefore, the NGLs from this source should follow the trend in associated gas.

On the demand side, LNG gas exports from the US are still on target to begin in the fourth quarter of this year, and ramp with time. Natural gas continues to take market share from coal. And I believe that this trend will continue, given that natural gas is a much friendlier fuel from an environmental perspective than coal. In addition, natural gas exports to Mexico, industrial demand for gas and natural gas for transportation, directly as CNG or indirectly as electricity, are projected to grow with time.

We believe these supply- and demand-side forces are working together to rebalance the market sooner than it was currently priced into the strip. Consequently, we believe that as supply and demand equalize that natural gas will move up. Equally important, as the infrastructure within the Appalachian Basin builds out, the basis should narrow with time. In combination, this should result in better netbacks for Range. In a commodity business, it's important to be low-cost and have scale.

On slide 4 of our IR presentation, we have included a new slide from Wood Mackenzie. According to their work on the Marcellus, Range not only has the largest resource base, we have the lowest breakeven cost. In addition, we have the upside of potentially 400,000 net acres of dry Utica gas beneath our Marcellus acreage. Coupling this resource base with our capital discipline and diversified portfolio of marketing arrangements which gives us multiple options that our competitors do not have, Range is positioned to create value as we move forward into an expected better market that balances supply, demand, and infrastructure.

I will now turn the call over to Roger.

Thank you, Jeff. The second quarter traditionally brings the mildest weather of the year, which tends to amplify the pricing impact of a supply surplus. This year's mild second quarter occurred against the unusual backdrop of seasonal market surpluses from all of our energy commodities: oil, natural gas, and NGLs. Fortunately, as Jeff discussed, better days are ahead. And in the meantime, our results are supported by significant cost reductions and a strong hedge position.

Quarterly financial performance since 2008 has been a tug-of-war between low-cost production growth and realized price. With the help of consistent and significant unit cost reductions during this time frame, more often than not at Range, growth at low cost has won the contest. Production growth of 24% and 11% lower unit cost in the second quarter, however, were no match for a 38% year-over-year reduction in realized price.

Despite significantly higher production, revenue from natural gas, oil and NGL sales, including cash-settled derivatives, was $383 million, 15% below last year. Second-quarter cash flow was $161 million, and EBITDAX for the quarter came in at $203 million. Cash flow per fully diluted share was $0.97. Year-to-date second-quarter cash flow totaled $367 million, while year-to-date EBITDAX was $446 million.

GAAP net income for the second quarter was a loss of $119 million. Non-GAAP earnings, calculated using popular analyst methodology, was $2.3 million, or $0.01 per fully diluted share.

The second quarter was another good one on the expense reduction side, with direct operating, production, taxes, exploration, G&A, and interest expense totals all coming in below last year on both a unit cost basis and absolute dollar basis.

The only expense item to slightly exceed quarterly guidance was interest expense, as the second quarter included one month of negative interest carry from our issuance of $750 million in 4 7/8% 10-year senior notes. We issued these notes in favorable market conditions several months ago, well before next month's redemption of our callable 6.75% notes.

Second-quarter cash unit costs were reduced by $0.25 per Mcfe, and total unit costs were reduced by $0.36 per Mcfe from last year. At current realized prices, these are very meaningful reductions. We believe additional unit cost reductions are possible as we become even more efficient with both our operating and capital expenditures. Third-quarter specific line item expense guidance may be found in our second-quarter earnings press release.

The big news over on the balance sheet was the $750 million issuance of 10-year senior notes. At May issuance, the 4 7/8% notes represented the lowest yield of any non-investment-grade energy and power sector issuer of any maturity in 2015. Many thanks to the institutions on this call who helped make this possible, as the transaction demonstrates the creditworthiness of our Company and the quality of our long-lived, low-cost, high-return assets.

Lower prices and the front-end-loaded nature of our capital budget in 2015 pushed our leverage a bit higher in the second quarter, with second-quarter trailing 12-month debt to EBITDAX ratio coming in at 3.3 times. I should mention that this leverage ratio is charted territory for Range, as we have been over 3 times on several occasions over the years. Even though we no longer have a debt to EBITDAX loan covenant, and our next annual borrowing base determination isn't until May of next year, our stance on leverage has not changed. When leverage exceeds 3 times, we will begin working on ways to bring it down.

It would be premature to discuss the specific things we are working on right now, but as Range has sold over $3 billion in assets over the past 10 years, this is the first option we consider to reduce leverage.

Range added new hedges for 2015 and 2016 across all commodities during the second quarter, the details of which may be found in the earnings press release and the Range website.

As Jeff mentioned, the second quarter was a challenging one. However, Range is structured operationally and financially to handle this kind of adversity. Our low-cost structure, high-return projects, long-life assets, strong balance sheet, plentiful liquidity, and consistent performance history provide welcome stability and the means to navigate through these tough times. Until times are better, we will continue to drive down costs, high-grade our portfolio, and prudently allocate capital.

Ray, over to you.

Thanks, Roger. During times like these, it's critical to have a great team, quality assets, size and scale, a strong balance sheet, and a low cost structure. Range has all of that, but we also have the unique ability to drill in high quality, core areas of dry, wet, or super-rich, with the operational flexibility to reallocate capital when needed, and maintain capital discipline.

During the first half of this year, we've clearly exercised those abilities and changed the lay of the land, and I will walk you through some of those changes now.

Of course, the first step happened at the beginning of the year, when we adjusted our 2015 plan by cutting CapEx by 45% or $700 million less as compared to last year, while still delivering 20% production growth. And we're still on track to execute that plan.

Another step we took was to allocate more of our capital to dry gas drilling in Southwest PA, due to the challenges we saw coming in the NGL market. The dry gas economics were substantially better.

In Southwest PA, our normal year-end inventory of wells ready for completion would normally be in the range of 20 to 30 wells. Our current forecast is that we should have between 50 and 60 wells in inventory, and about half of those wells are expected to be in the dry gas area. Of course, it's very preliminary, and those numbers will likely change. But those wells can be brought online in 2016 with less capital, since we're only looking at the completion cost rather than the total well cost.

In addition, we've increased the number of wells being turned to sales in 2015, as we now expect an additional 16 Marcellus wells to be turned in line at the very end of 2015 rather than early next year, all of this allowing us to start 2016 with good momentum into the historically better winter pricing environment.

With our new contracts in low-cost transportation, we will be positioned well to start off next year while maintaining good capital discipline.

Our capital spending was front-end-loaded this year, with the spending approximately two-thirds of our capital budget during the first two quarters. In January, we had 15 rigs running. Currently we have 10 rigs running, and we expect to average seven rigs in the third quarter, going down to six in the fourth quarter. We will also be tapering off frac crews in the second half of this year.

So as you can see, our CapEx spend will be substantially less during the second half of the year, and I want to reiterate that we remain committed to meet our planned $870 million budget.

We beat production guidance for the second quarter and came in at 1.373 Bcf equivalent per day, largely driven by better-than-expected performance in the dry gas area of Southwest Pennsylvania. For the third quarter, we are setting guidance at 1.39 to 1.4 Bcf equivalent per day, with approximately 28% liquids, and are still on track to deliver 20% production growth for the year.

The Mariner East I project has been delayed from the original expectation of a July startup, and we forecasted the project coming online late in the quarter, with full operations during the fourth quarter.

Like Roger pointed out in his remarks, our costs are consistently improving on both an absolute and unit basis. Corporate LOE per Mcfe is down 20% for the quarter as compared to last year, and G&A per Mcfe is down 21%. We've demonstrated discipline and a continued focus on cost.

Reacting to the current environment, we had to make some tough decisions in closing our Oklahoma City division office and making substantial personnel cuts in our legacy fields in Pennsylvania. Those decisions resulted in layoffs of approximately 11% of our workforce. Those decisions were not made lightly; but in this environment, tough decisions like these become necessary.

We have updated our Marcellus economics on page 16 in our presentation to reflect the current pricing in differentials. We left the well cost and tight curves unchanged in order to get an apples-to-apples comparison. As you can see, our economics are still good in all cases, but the dry area economics have improved, supporting our decision to direct more of our capital towards dry gas in Southwest PA. The improved economics in the dry area are driven primarily by the improvement in basis differentials coupled with our transportation contracts going forward.

In the Marcellus, we've continued to upgrade our completion designs by optimizing profit loading, sizes, and concentrations, along with reduced stage spacing across our very large and diverse acreage position in Southwest PA.

For example, stage sizes today range from 200,000 pounds of proppant per stage up to 500,000 pounds per stage, depending on the area and the particular reservoir characteristics in that area.

Well performance this year is on target, and I'll point out a couple of examples of recent performance.

In the wet area, we brought online a five well pad, averaging 28.2 million cubic feet equivalent per day, per well, initial rate to sales, with an seven-day average rate to sales of 20.8 million a day, per well, under constrained conditions. Those wells averaged 5,204 foot laterals with 27 stages per well.

In the dry area of Southwest Pennsylvania, we had a two-well pad come online with an average initial rate to sales of 34.2 million a day, per well, under constrained conditions. The average 90-day rate is 20 million a day per well. Those wells average 9,074 foot laterals with 45 stages, and have cumed over 1.8 Bcf each well in 90 days.

Expanding on that area where these two wells are located, we have a total of six offset wells with up to a year of production history. The average cume production at 90 days to sales under facility and gathering system constraints was 1.5 Bcf per each well. These were shorter laterals, averaging 5,064 feet with 26 stages.

Our EUR in this area is currently 3 Bcf per 1,000 foot, with some of the older wells over 3.2 Bcf per 1,000 foot, putting this area on par with some of the best production in the basin. We believe our dry gas area in Southwest PA will be very prolific, and is clearly exceeding our expectations thus far this year.

In Southwest Pennsylvania, we completed 52% more stages in the first half of this year as compared to last year. Our stage count per day improved by 20% for the first quarter and by 30% for the first half of the year.

Highlighting the second quarter, we averaged 6.3 stages a day per frac crew, which we believe is the best in the basin. As we front-end loaded a lot of the activity this year, our total stages and stage counts per day are expected to be less during the last half of this year.

On the drilling side, during the second quarter, we saw a 13% decrease in days while drilling 21% longer laterals as compared to last year. To put that in perspective, based on recent data, we would estimate drilling an 8,500 foot lateral well in less than 18 days. These efficiencies have been critical in helping us deliver 20% growth this year with 45% less capital. And we're far from done, as these improvements will keep on coming.

Other than having a great operating team, a critical factor in achieving these operational and well performance gains is being in the core of the play. As I've often said, the rock rules. We list the normalized EUR and cost results of our Marcellus areas in a table in our earnings release. Achieving results comparable to these are very difficult when you are not in the core. When you combine these results with our lower transportation costs, and all the great work our team has done at securing better markets, it drives what we believe to be one of the best capital efficiencies in the industry.

Operational gains, coupled with further service cost reductions, have helped reduce our overall well costs significantly. When comparing the first half of 2015 with the second half of 2014, we are seeing total well cost reductions on an apples-to-apples basis of up to 25% or more. And we're continuing to see costs come down on things like steel, along with other goods and prices -- services.

Like I said on the last call, Range did not have any long-term drilling or service contracts; and, therefore, our operating teams had, and still have, a tremendous competitive advantage in optimizing our service provider relationships.

Coupled with our operating practices, we can achieve attractive pricing while our service providers maintain high utilization rates and reasonable margins. Over the long-term, we expect that this will differentiate Range versus our peers, as we believe our well-planned, disciplined, and growing operations have allowed us to attract some of the most favorable service pricing in the basin.

Our Washington County, PA, Utica well is still producing into our wet system on an interruptible and constrained basis, and it's still too early to make any reasonable estimates of ultimate performance. We're finishing up the completion on our second well, and expect that both wells will be online in the permanent new dry gas infrastructure over the next couple of months. You can see some of the details on that second well in our earnings release.

I expect that we'll be able to give more information on well performance after both wells have been online consistently for a few months. And we still expect to spud our third well before year end, and it will be completed in 2016.

Our Fort Worth operations team, which now also runs our Mid-Continent division in addition to our Northern Marcellus division, is doing a great job focusing on cost while delivering great well results.

In Northeast PA, we just drilled and set pipe on a well for $284 per lateral foot, as compared to $394 per foot estimated for 2015. That's a 28% reduction in cost from what we originally planned. Since that team has taken over the Mid-Continent assets, in a very short time and with just a few wells under their belt, they have reduced the total completed well cost in the Nemaha Chat Play by over 31% to approximately $2.2 million per well with the last few wells. Any initial production from those wells is consistent with our expectations.

Our Southern Appalachian Nora team is also doing great, and while they have a very limited capital budget this year, they are continuing to bring online some of the best coalbed methane wells we've seen in 25 years. Utilizing the new high rate frac technique, the recent CBM wells are 60% better than their average offsets with significantly better economics.

Although Range's operational tempo has been high, employee safety remains a top priority. Employee and management commitment to safety has resulted in Range having no OSHA recordable injuries thus far in 2015, and zero hours of lost time in the last 18 months. We are really proud of all of our operating teams for working safely and being good stewards in the communities where we live and work. Like I said in the beginning, times are indeed tough, and every penny really counts.

Maintaining capital discipline and a low cost structure are extremely important. I'm proud to say that we believe we have a deeper, more diverse, and better inventory than anyone in the basin, with minimal type curve risk at one of the lowest cost structures, with one of the best capital efficiencies, great capital discipline, and one of the best teams in the industry.

Now back to Jeff.

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

(Operator Instructions). Ron Mills, Johnson Rice.

I know it's still early, but do you have any preliminary thoughts on 2016? In particular, in light of your 3 times leverage ratio, how CapEx versus growth can look at either varying levels of CapEx, depending on how the cash flows look like they'll settle out?

Yes, let me -- that's a great question, and I'll start by saying it is early. Typically we work that really hard, present it to our Board in December; and then, after their approval, announce it in January.

But let me give you a lot of thoughts around it that hopefully will put some sideboards around it and give you a lot of color. I'd like to start by talking about this year, 2015. In this year we're getting 20% growth with $870 million of CapEx, and we feel good about those numbers, and that's where we'll end up.

And if you look at that, I think versus any of our peers, I think we're at the head of the class. Our dollars go further than almost any operator. We're, I believe, one of the most, if not the most, capital efficient company out there. So we'll start with 2015.

If you look into 2016, I think our pricing gets better. The netbacks will get better. One, we'll have a full year of Mariner East in 2016, and we're -- again, we have the lion's share of Mariner East. We're the only producer that has capacity on it. We have 40,000 barrels per day on it. So our netback pricing for our NGLs should get significantly better for ethane, for propane, et cetera.

Also we'll have a full year of Uniontown to Gas City, which is a big uplift on a really significant portion of our production in the Southwest. It's initially a $1 uplift, in that $0.75 to $1 range, and we've hedged and locked a lot of that in. So our netbacks should get significantly better in 2016. And, as I mentioned on my call notes, there's other projects that come on in 2016, like Spectra's Gulf markets expansion and Rover phase 1. And as each of those projects occurs, and the supply and demand inside the Basin equal out a little bit, basis should contract.

So I think we are one of the most capital efficient companies in terms of growth, plus we are -- given our unique portfolio of marketing contracts, I think our netbacks improve next year.

But I think a really important slide that I'd like to refer everyone to is slide 8 on our website. And it's a slide that shows what our production growth has been with time, plotted against the dollars of capital per incremental Mcfe of production. And if you look at that, you can see consistently, really for the last five years, our capital efficiency has gotten better.

If you hone in just on 2015 versus 2014, and you look at the blue line on the graph, we're getting 20% growth. But the blue line, our capital -- our costs are down literally 50%. Dollars per incremental capital were 50% less in 2015 than they were in 2014, through a combination of better completion, better targeting, lower service costs. And I really applaud Ray and the entire operations team. If you had asked me at any point in time, this time last year, where would we have been? I wouldn't have predicted we would have been able to reduce that by 50%, but it speaks to the quality of the team and the rock and our position.

So, when you -- 20% growth in 2015 for $870 million CapEx is, I think, outstanding. Next year we get better pricing, but I don't think our efficiencies go to zero in 2016. I think -- I'm not saying we're going to knock 50% off; but I think that you'll see significant improvement in capital efficiency when you look at 2016 versus 2015, if we're sitting here at this time next year.

So I think that's really important. And that efficiency will come from, again, our laterals issue average about 6,000 feet with X stages; it's in our work. You'll see us, I think, continue to migrate towards longer laterals with more stages and all those types of things. Plus we'll have a full year's worth of service contract benefits that we didn't have this year. So I think all that speaks to better performance in 2016 than in 2015.

I think there's a couple of other ways to look at it, as well. Ray mentioned we're going to be carrying in almost double the number of wells into 2016 that we normally would in a typical year. It's almost 50 to 60 wells, instead of 20 to 30. So, the drilling costs are in this year. Just the completion costs are in next year, so it's going to be really capital-efficient growth with that.

And I think if you look at us versus our competitors, if you look at our fourth-quarter 2015 exit rate versus fourth-quarter 2014, we should be growing roughly 15% fourth-quarter 2015 over 2014. So we've had that continual ramp up in growth, so we're going to be entering 2016 with good growth versus a lot of our peers who will be flat over that same time frame. And, in fact, some of them will be down.

So, I think all those things are important; and, again, hopefully give you some things to think about in terms of how you might model 2016. We don't want to be premature. Again, would I have predicted we would have knocked 50% off of our capital efficiency, and grown 20% for $870 million? I wouldn't have. But I predict Ray and the team will step up again, big time, for 2016 and you'll see good improvement in those numbers.

But I can also tell you we'll look hard as we go throughout the year at what oil and gas prices are in 2016. We will look very hard at the returns. We just recently updated the economics and returns of all of our areas where we're spending money in the book, and we'll continue to do that.

We will be very prudent with our balance sheet, and we will be sensitive to that. And given that, I think we're in good shape for 2016. Kind of a long answer, but an important question.

I guess a follow-on to that, maybe if you don't want to give more clarity, that's great. But the second half capital run rate of a little bit under $300 million, if you were running on that run rate, can you still -- with those completion backlog, can you still stay on track and hit that 20% or 15% to 20% type growth? I'm trying to get a sense of growth versus CapEx dollars to be able to compare with cash flow/liquidity.

Yes, let me try it at a high level, and maybe Roger or Ray will chime in. You're right. We're not going to come out with specific numbers at this point in time. Again, if we would have done that last year -- I've been with the Company now 12 or 13 years -- I would have missed every year. Our team has outperformed my expectations, year after year. Plus we don't want to get ahead of our Board. We want to run it by them. And we want to look at prices as we get closer to the year.

That being said, I think you'll see significant improvements, just like on page 8; you've seen year after year after year with better contracts, better netbacks. So, carrying a big inventory in, exiting the year high, with improved capital efficiencies.

I think, again, if in terms of growth for the dollars spent, if we aren't the head of the class I think we'll be near the head of the class, with some of the best contracts there.

And actually on page 8, our IR team has looked at all of our competitors and looked at every single company in the basin, and out -- peers out of the basin -- and based on our work, I think we're -- if we aren't one, we're two. But I think we're actually one.

Ray or Roger, do you want to add to that, or no?

Well, I think talking about the run rate in the second half of this year, we're still absolutely committed, again, to the $870 million CapEx budget that we had set. And we're still on target to deliver 20% growth for the year. So all of that has been part of our model going forward.

Typically, capital budgets are always a little bit front-end loaded. But just taking that run rate and running straight through 2016, I don't think is a good way to look at it. Because we'll probably ramp activity up a little bit in the first half of next -- or first quarter for sure, into that better pricing environment and so forth, as we always try to do.

So I think the shape of our growth profile will be about the same as it's been most years.

But I think we're in good shape. We're going -- 2015 should be a good year. Particularly, we should end strong with two new contracts kicking in: Spectra and the Mariner East. And with carrying the wells in, exiting high, and with the continued improved efficiencies, we'll be sensitive to the balance sheet and to the economics, but I think we're in good shape.

All right. Let me get back in queue. Thank you, guys.

Doug Leggate, Bank of America Merrill Lynch.

Jeff, I apologize for the laboring the last question. Maybe I'm going to ask it slightly differently, or a different take on it. What would it take, in your view, to hold 2016 production flat? I know that's probably -- with Range, that's probably of bit of an unrealistic scenario. But from a CapEx point of view, do you have a kind of ballpark, what do you think it would take to just hold the production flat from here? And I've got a follow-up, please.

Yes, Doug. This is Roger. Let me take a swing at it. I'll answer it similar to how we've answered this question before. When you take our anticipated 2015 production times our F&D costs -- and you can pick any F&D cost; it's in the appendix of the book on any of our key plays -- you end up with a maintenance capital to replace our reserves of around $200 million to $220 million. So I think that's one bookend for you -- for folks to think about.

The other bookend, of course, is what Jeff just mentioned, that in 2015 we've gotten 20% growth at $870 million, with anticipated additional efficiencies going into 2016, for a lot of the reasons that were just mentioned. So I think you can look at those as two bookends.

Another thing I would add is just that something a lot of folks forget about his we really have, if not the highest RP ratios, one of the highest RP ratios out there, particularly of a shale producer. And especially if you look at just the proved developed producing reserves and that ratio.

So we have a much shallower decline, which means it's a lot easier to replace production. So, I know I'm not getting to the exact number. But like Jeff said, we don't have a micrometer for 2016 right now. But I think hopefully that will help you with bookending the answer.

It does, Roger, but it kind of begs another question, which is I suppose an issue facing all you guys right now, is that if your assets are that good, which they clearly are, and with the Utica they're probably -- the portfolio shift is probably going to see an even better aggregate for the whole high grade portfolio, if you like.

Why accelerate or push the growth in this environment when historically your shares have been, given the equal recognition for debt adjusted growth -- in other words, the shoring of the balance sheet, the strength of the balance sheet, and so on, as opposed to growing the top line.

From a strategic point of view, how are you guys reconciling that? Why not wait a year and then push the growth, once things sort themselves out from a commodity standpoint?

Well, again Doug, it's not like we have a growth number and we're just not telling you. We just don't have the facts to make that decision yet. So, in answer to your question, we have never been about growth for growth's sake, and we're not going to start now. We're going to be mindful of the forward curve. We're going to be mindful of the supply and demand balance; our optionality to drill where the best opportunities are; and the balance sheet. So we're going to triangulate on all of those variables to come up with the right growth percentage. But at this point, it is just too early to predict on what that might be.

Yes, and I would add in a little bit. Historically, if you go back historically over the last several years, we've talked about growing 20% to 25%. And I have always -- and I'm sure you've heard it in all the people in 101s -- and to draw home the point, I take silly examples. If gas is $0.05, we're not going to grow at 20%. Or if gas is going to be $10 flat, we'll grow higher than 25%. But that's been kind of reasonable target.

It's interesting over that time frame, for the most part prior to the last year, people have challenged us: why didn't we grow faster? And we always stuck to our guns of what we thought was a reasonable and prudent plan.

If you look at this year, it's very interesting. Again, we wanted to be reasonable and prudent where prices were. We cut $700 million out, and at that point we weren't even targeting growth. We were just saying how capital efficient could we be. The 20% fell out of that, and it happened to be kind of in line with 20% to 25%, but there was really nothing magical. That's just the quality of the team and the rock.

And again, if you would have asked me, could Ray and the team, on page 8, knock 50% off of our capital efficiency from 2015 versus 2014, I wouldn't have said that last year. They did -- went above and beyond, which, again, speaks to the quality of the rock and the team.

We'll approach 2016 and 2017 and beyond in that same fashion.

I appreciate the full answer, fellows. My follow-up is hopefully a little quicker, because we're only talking about six rigs at the end of the year. Given you're still testing the Utica side of your portfolio mix, how should we think about allocation of those rigs as we roll into the end of the year? I'll leave it at that. Thank you.

Well the Utica, like I said earlier, I think we'll have both of the first two wells online here in the next month or so, into the new infrastructure, and we'll be able to produce them consistently at that point. And we're going to need to watch them for a couple of three months or so to get an idea what those wells are going to look like on an ultimate performance standpoint. The third well will get completed sometime early in 2016, so we'll have three wells.

And one of the things I'll point out: when you couple that with some of the recent wells that have been announced around us, it really proves up our maps that we've had in the book for over a year now. And I think it really helps delineate our 400,000-acre position, which is the biggest position out there. And it's going to give us a big, big lever going forward for some really capital-efficient growth when the time is right.

But like Jeff and Roger have pointed out really well, I think, at this point, it's just too early to know how we're going to allocate those rigs to potential Utica wells in 2016 or not. I think we'll look at the economics; we'll look at the cost, look at the markets and our new transportation deals, and customers that are coming online. We'll have to look at all of those things to see how that rolls out when we present our budget to the Board in December.

And then like we've done every year, we will continue to manage that budget as we go throughout the year, and reallocate capital to the best returns. That's what we've always done, and that's part of what's been able to drive our capital efficiency.

And I would just point out, it's nice that the Utica is stacked with the Marcellus and with the Upper Devonian. Really, the Marcellus that we're drilling will hold all that acreage. So, in essence, it's kind of a free option on what may be the biggest and potentially the best Utica position out there, which could drive capital efficiencies in 2016 and beyond, and continue to make us more capital efficient.

Appreciate the answer, guys. Thank you.

Jon Wolff, Jefferies.

A few things, since I'm getting a tremendous amount of questions; maybe we can just clear up. So number one on -- a little bit of confusion out there on Marcellus versus Utica. My response has been that there's quite a long inventory -- a very differentiated inventory in the Marcellus that is highly capital productive. And people are thinking, well, why does Range need the Utica right now? I completely understand why you want to test the potential.

So just thinking about that, and the high rates of the wells and the added midstream infrastructure or the takeaway from the pads, how does that color your view? I assume it's a low capital item that may kick in over time.

And related to that, CONSOL reported a very strong well test in Westmoreland, which is kind of in and around your acreage. Any reactions to that?

But the bigger one is just the capital productivity returns at this point, given your just huge Marcellus inventory, how do the two compete and how do you think about that?

Well, let me start, and Ray or Roger might chime in. We agree. The low-risk, high quality, strong return is the Marcellus. That's where we're focused, and that's where 95% of our capital is going into that. It's important, we think, to drill a few wells. And we picked three to give us a feel for what the Utica could be. Plus, like Ray said, it's encouraging with the well in Westmoreland County and the EQT well.

Actually, you can see it on our website. I think they are still up there. Bill Zagorski did a presentation with SunTrust that's much more detailed in terms of the Utica. And you can see where those wells are and how they delineate our acreage and help de-risk our acreage.

And again, it's -- being stacked pay is important. We're getting some phenomenal -- right now, some of the strongest returns we have are in the dry Marcellus, but that take-away for the dry Marcellus could be used at some point for dry Utica.

So all that stuff kind of stacks together. The wells we're drilling are off of existing Marcellus pads and with Marcellus roads. It's the same team. We've already paid for the acreage. It is already held by the Marcellus. So it's kind of an option.

We'll stay focused on the Marcellus. But to the extent we learn more about the Utica, and to the extent the Utica economics ultimately compete with the Marcellus, then you may see us allocate some capital there in a very disciplined way in order to maximize our returns and to -- as we go forward.

Yes Jon, one of the things that we're considering is the Utica, we're three wells into this -- or 2 1/2 wells into it, if you want to say it that way, right now. And a couple things we need to understand is the production characteristics of the well and what we believe the cost can get down to. And, so far, everything is meeting our expectations, if not exceeding our expectations. We still believe we can get the cost down. And we still believe the wells are going to perform. And clearly with the Westmoreland County well from CNX and the EQT well, which I'll be the first to congratulate both of them, those are monster wells.

But we really believe that just helps prove up what we've been saying for a year or so now, that this is going to be a great big -- great lever for Range to push going forward. And when you start thinking about the gas markets three, four, five years out, that's where we really see the Utica being highly potential for us.

Like Jeff said, we're holding all the acreage with the Marcellus wells. That's where our best returns are. Some of those Marcellus wells, there's probably nothing in the world that's going to compete with them. They're just that good.

But if the Utica ever does, or even in the shorter term, we'll just allocate a little bit of the capital there.

You'll see us work it in (multiple speakers).

Yes, from a land perspective, any one well (technical difficulty) one horizon, holds all of it.

Right, right. I'm just -- I just wanted to make sure (multiple speakers). Yes.

Okay.

Is the messaging really that -- is this going to be potentially a 10% capital item next year? I would assume less than that.

It's too early to say. I know we're driving you guys crazy a little bit. We think about those things hard. But we actually try to factor in the most recent data as we go into the year, and most prudently allocated capital to where it's best for the Company.

Okay, that's fair. And on the Westmoreland results, just on a [close-ology] basis, or however you want to think about it -- what does that tell you about some of your more Eastern acreage?

Well, see, like Jeff said, if you look at on our website, there's a presentation that Bill Zagorski made at a SunTrust conference. And on page 5, there's a great map. It has that well and the recent EQT well highlighted.

And if you look at the map, it fits right in with what we've said all along. And if you see the outlines on the map, you'll see we've got a considerable amount of acreage offsetting both those wells. So, again, it helps just prove up what we've been saying for some amount of time. We've got 400,000 acres that we think is highly prospective. And as time has gone forward, it's just getting better and better.

We probably have the largest position. And the good news is it's stacked right underneath our high-quality Marcellus. And there's still good Upper Devonian on top of it. Yes, it all helps.

Two more quick ones on -- I think I get the concept around the weak NGL realization. It feels like you had to deal with other ways to evacuate, like rail, which we're hearing $0.25 to $0.30 cost. Obviously it's transitory for Range. But is that a -- I know you've got some tails into Marcus Hook, but I imagine it was a small number. As Mariner East gets commissioned, my guess is that that $0.25 falls to something less than $0.10. Is that fair?

Well, I'd answer it this way: again, we're the only producer that has a position on Mariner East I. And we have 40,000 barrels per day: 20,000 of propane, 20,000 of ethane. The 20,000 of propane covers basically all of our propane production. And we've said, and we still believe when you consider take Mariner East, Mariner West, and our whole portfolio, once that's up and running -- and Sunoco is still saying, end of the third quarter, a little commissioning, so call it early fourth quarter -- on an annualized basis it's about a $90 million uplift for us, net of transportation. About half of that is savings on the transportation side on propane. So hopefully that's enough clarity into what that looks like.

Last one on the (multiple speakers). Yes, okay.

And again, don't forget Spectra. That's August 1 of this year, so that's like next week, the 200 million a day. That takes a huge portion of our production out of M2 and into a better market. And we've hedged that uplift, which is -- it will be a nice uplift for us. And again, we're an anchor shipper. We have a huge part of the volume on that project -- 200 million per day.

Right. Last one. When I saw you last time, you talked about there being at least a small arb between Mont Belvieu to Europe or other versus -- Mont Belvieu to Europe versus Marcus Hook to Europe. You feel good about being able to at least market those propane barrels overseas? Just in terms of liquidity?

This is Chad Stephens. Yes, one of the things that we're excited about is the ability to take advantage of any available arbs. To date, we have been selling the propane on what they call Handy ships. Very inefficient loading, less barrels; you've got to use more ships. Transportation costs are higher.

Once Mariner East is in service, we'll be loading VLGC ships, about 500,000 barrels per ship, and we'll be taking advantage of the arb between Rotterdam, the ARA -- Rotterdam Index, South America, Mont Belvieu, and the FEI Index in Asia. And that's both -- you can take advantage of either lower transportation costs and/or better index prices as you play those arbs around the world. And so we're real excited about the ability to do that.

And we think we'll get better pricing. The $90 million does not include any uplift on pricing. That's just counting the transportation savings and the other contracts. So it could be better than that, and we expect that it will be better than that.

Got it. I had one more but I forgot it. So I'll -- that was long enough. Thank you so much for the color.

Blaise Angelico, IBERIA.

Just one quick thing: can you talk about well costs, and where service prices are trending? Do you see any additional relief coming over the balance of the year?

And then, second, I know you don't have long-term service contracts in place; can you maybe step in now and lock in that lower service cost with long-term contracts? Just kind of curious as to how you guys are thinking about all of this, given the macro environment.

Well, great question, Blaise. The service costs have clearly come down a lot this year. And like I said in my prepared remarks at the beginning of the call, on an apples-to-apples basis, when you look at what we've seen in the first half of this year compared to the second half of last year, and you just pick Southwest PA for instance. Some areas are more; some are less. But just pick Southwest PA -- we are 25% or more, less total well cost. And that's a range of all sorts of things: less cost for the drilling rigs, frac costs coming down, directional drillers, all that sort of thing.

And we are still seeing some of those prices come down because, like Jeff said in his remarks at the beginning, the rig counts are down in the Utica by 66%. They're down in the Marcellus by over 50%, I think close to 55% now.

The other basins are seeing the same kind of things. So there's a lot of competition out there. The service providers are having to really pick the people they want to work for, and really having to hammer down on their suppliers. So you are seeing this continual bump down of lower costs, going all the way down into things like steel and proppants and guar gum for friction reducing -- all those sort of chemicals and everything else are getting cheaper.

So, I think it would be pretty aggressive, probably too aggressive, to think that we're going to see as much of a decrease as we've seen so far. But I do think we'll see more as all of this tries to settle out at some level of constant activity.

I think because of our well-planned and disciplined approach, and the way we try to really focus on utilization of the frac crews and so forth, that gives us a leg up. And the fact that we didn't have any long-term contracts was a big advantage to the team. I think it's still a big advantage to the team.

We are much more a believer, philosophically, in long-term relationships rather than long-term contracts, because we really try to make it a win-win relationship with our service providers.

And when you -- I think we're living proof of the fact that that's allowed us as a company to attract some of the best pricing and some of the lowest well cost. And all that translates into the best capital efficiency I think in the basin. So that's our philosophy going forward.

I think the other thing you'll see going into 2016 is we'll have a full year of these price reductions, which will really help our capital efficiency. So I don't know that -- we'll probably still see some decreases here and there. But the fact that we'll be able to apply what we've seen thus far to a full year is really what's going to help us next year. Plus the fact that we have a bigger inventory; we got better contracts. We got Mariner East up and running. We got Spectra's Uniontown to Gas City. We got Rover, and the Gulf expansion coming on late next year.

All those things that we've been talking about on the call are really going to help set 2016 up very, very well.

Appreciate the color, guys.

Thank you. This concludes question-and-answer session.

I'd like to turn the call back over to Mr. Ventura for his closing remarks.

The first half of 2015 has been challenging for Range and our industry. The good news for Range is that we have two significant marketing events that are projected to commence in the second half of the year, which are Spectra's Uniontown to Gas City project and Mariner East I. Combined, they should result in a significant increase in our netback price we receive for our gas, ethane, and propane.

We're on track to spend approximately $700 million less in 2015 than 2014, and grow our production volumes 20%. We believe that we'll have the most capital efficient growth versus any of our Appalachian peers on a corporate basis.

Importantly, with our 1.6 million acre of stacked pay potential in the Marcellus, Utica, and Upper Devonian, we have the option to drill dry, wet gas, or super-rich acreage, since about 900,000 net acres are dry and the rest is split between wet and super-rich.

In essence, this gives us a portfolio within our portfolio. Coupling this resource base with our capital discipline and diversified portfolio of marketing arrangements, which gives us multiple options that our competitors do not have, Range is positioned to create value as we move forward into an expected better market that balances supply, demand, and infrastructure.

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 at this time.