山脈資源 (RRC) 2017 Q1 法說會逐字稿

Welcome to the Range Resources First Quarter 2017 Earnings Conference Call. (Operator Instructions) Statements contained in this conference call that are not historical facts are forward-looking statements. Such statements are subject to risks and uncertainties, which could cause actual results to differ materially with you from those in the form to segments. At this time, I would like to turn the call over to Mr. Laith Sando, Vice President, Investor Relations at Range Resources. Please go ahead.

Thank you, operator. Good morning, everyone, and thank you for joining Range's first quarter earnings call. The speakers on today's call are Jeff Ventura, Chief Executive Officer; Ray Walker, Chief Operating Officer; and Roger Manny, Chief Financial Officer.

Hopefully, you've had a chance to review the press release and updated investor presentation that we posted on our website. We'll be referencing some of those slides this morning. We also filed our 10-Q with the SEC yesterday. It's available on our website under the Investors tab, or you can access it using the SEC's EDGAR system.

Before we begin, let me also point out that we'll be referencing certain non-GAAP measures on today's call. Our press release provides reconciliations of these to the most comparable GAAP figures.

In addition, we've posted supplemental tables on our website to assist in the calculation of these non-GAAP measures. The supplemental tables also provide calculated natural gas differentials for the upcoming quarter and detailed hedging information for all products.

With that, let me return the call over to Jeff.

Thank you, Laith. Improving price -- improving pricing differentials, driving expanding margins is the theme of the first quarter and what we believe will be a continuing theme for Range in 2017 and 2018. Coupling the enhanced margins with the lowest PUD development costs for any of our lower gas peers, we calculate our unhedged recycle ratio as approximately 3x. The story is ratified by independent work from well-respected firms and analysts with one such report included in our new presentation. It examines recycle ratios across the Delaware Basin, Midland Basin, the SCOOP STACK play, the Bakken, the Eagle Ford and the Marcellus. This work includes a number of very high-quality oil and gas companies.

Based on this analysis, Range has one of the top recycle ratios of any company whether oil or gas in an -- any basin. We believe this is a key indicator of long-term success, driving above-average profitability in a normalized price environment or strength and stability in a down cycle.

Moving back to margin expansion, improving price differentials for natural gas, NGLs and condensate are expected for 2017. A full year of transportation on our Gulf expansion Phase 1 pipeline project, and a full year of contribution from our near-to-market North Louisiana assets are resulting in our natural gas differential for this year improving to approximately NYMEX less $0.30.

Later this year, we're expecting Range leech express at their Southwest and Rover Phase 2 pipelines to commence operations. These transportation projects should result in further improvement in our 2018 differentials.

Per barrel NGL pricing for 2017 is projected to be 28% to 30% of WTI. A full year of Mariner East plus NGL sales from North Louisiana are the main contributors for the increase in realized price.

Looking forward to 2018, fundamentals suggest that higher demand for ethane and propane from the petrochemical sector and exports can improve our pricing differentials further next year.

Our condensate pricing differential per barrel for 2017 is projected to be WTI less about $5.50. This is driven by a full year of our new marketing agreement for Marcellus condensate and a full year of North Louisiana condensate sales. Importantly, this pricing differential will represent a 40% improvement over our 2016 condensate differential. This improvement in pricing across gas, NGLs and condensate, coupled with one of the lowest cost structures in the industry has resulted in the margin improvement we're seeing in the first quarter and are projecting for the full year.

Capital efficiency in 2017 will continue to improve as we're targeting over 9,000-foot laterals in Pennsylvania, and we're driving down the cost of drilling complete wells in North Louisiana. Ray will discuss our operational highlights next and provide more details on our plans.

With the first quarter in the books, 2017 is shaping up to be a good year for Range. Importantly, we expect our class-leading recycle ratio in 2017 to continue into 2018 and beyond as Range is one of the few companies in the industry with a decade plus of high-quality drilling locations. We have a resource potential of approximately 100 Tcfe as compared to our year-end proved reserves of 12.1 Tcfe. Our resource potential does not include the highly prospective Utica, which will drive our ratio of resource potential to proved reserves even higher.

As shown on Slides 23 and 24, in the Southwest portion of the Marcellus, Range has the highest estimated ultimate recovery per foot, lowest finding and development costs and lowest breakeven cost. We have a high-quality asset position in North Louisiana, and as shown on Slide 13, we've made significant progress adding value since the acquisition was announced last May.

Looking forward, Range remains well positioned to drive value for years to come.

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

Thanks, Jeff.

Production for the first quarter came in at 1.93 Bcf equivalent per day, and guidance for the second quarter is flat to the first quarter of '17 over 1.93 Bcf equivalent per day, and we remain on track for annual growth of 33% to 35% as the company's production growth is weighted towards the back half of the year.

Before walking through operations, I'd like to spend a few minutes on our production growth for the rest of 2017 and how this sets us up for 2018.

In Appalachia, we brought the sales in the first quarter less than 20% of our expected wells for the year, so growth in the back half of the year should look really good.

In North Louisiana, we expect to bring to sales 29 additional wells in the second half of 2017, also providing solid growth in the second half of the year. We delivered on our expected production for the first quarter of '17 in both Appalachia and North Louisiana. And in Terryville, we expect wells going forward will generate better growth than the group of wells turn to sales in the first quarter.

To illustrate, let's compare and contrast our first quarter activity with our expectations going forward. As discussed on the last couple earnings calls, 18 of the Terryville wells brought to sales in the first quarter were drilled prior to the acquisition, many of them over a year ago.

As a result of completing such a large swath of wells at one time, which was 27 during the first quarter and because of the location of many of these wells, approximately 40 million cubic feet equivalent per day of offset production was shut in to minimize the frac hit. The shut-in production does not come back all at once, but will come back throughout the year via flatter declines.

Moving forward, we're planning a more balanced approach, both in terms of activity and planning the well locations to help minimize the impacts on offset production.

As discussed before, we've implemented a completely different flowback in early production protocol. The wells will now be opened up under designed, constrained conditions, allowing the use of more cost-effective facilities and a minimization of expensive flowback rental equipment. We believe this will improve the overall project returns. What it means is that we won't see the initial 30-day rates that you would've seen in the past, and we've changed production operations in the field.

In addition to the different approach to flowbacks, we're also implementing Range's safety facility and production protocols. One example is eliminating production of the annulus. This practice well common in some areas is not the preferred practice with the equipment that is currently in place. These design and operational changes resulted in cutting back production by approximately 30 million cubic feet equivalent per day for the year. Of course, this simply curtails production and we expect to get that production back via a flatter decline.

In the first quarter, we also tested some meaningful step outs in Terryville that will help to further delineate and de-risk our well inventory. Some of these wells were in areas perceived as the edges of the field, due to poor historical results. While the results from the new wells are early, they're very encouraging and are in part the result of improved targeting. With lower drilling and completion cost, the encouraging early well results and the ability in the future to incorporate better mapping and seismic, we believe these areas hold significant potential.

As part of that same process of better understanding the field's ultimate potential, the first quarter included wells that had been drilled preacquisition in some of the pink horizons. Completing these wells will provide us a better understanding of the resource potential over the coming years. Going forward, we'll continue to be focused on the Upper and Lower Red, while occasionally drilling other horizons and extension wells to optimize our full development plans. This is similar to our approach in Appalachia, that is focusing on the Marcellus while unlocking the Utica and Upper Devonian opportunities over time.

So while the first quarter was a great quarter operationally and financially, we're really looking forward to the second half of this year as we continue to build on our operational successes in both North Louisiana and Appalachia.

Hitting on some of the operational highlights for the quarter, we'll start with Appalachia, where we're directing approximately 2/3 of our capital spend. We continue to make great strides in unit cost reductions, improving well performance and capital efficiency.

I'd like to take a few minutes now, walk through some updates on the drilling side in Appalachia. Our team has now drilled the longest Marcellus lateral in Pennsylvania, and 3 of the top 4 longest laterals in the entire basin. In the first quarter, we drilled 3 laterals over 15,000 feet, and 7 laterals over 10,000 feet. We're achieving a 67% increase in daily lateral footage drilled versus a year ago. Combining our drilling performance and planning efforts, our average lateral length drilled this year will be approximately 9,000 feet. These improvements can be attributed to 4 things. We've upgraded our rig fleet through higher horsepower and higher pressure-rated equipment, we've adopted and greatly improved the efficiency of our rotary steerable tools, the team has redesigned our current mud systems, and a real focus on key performance indicators that trigger real and measurable success. And two final things on the drilling side, we've accomplished all of this while narrowing our lateral target to a 10-foot window, at the same time drilling faster while lowering costs from last year on a per foot basis by over 30%. And it's been almost 2 years since the team has had to side-track a wellbore. Needless to say, we're really proud of their accomplishments.

On the completions, facilities, water and production front, we're continuing to innovate and improve efficiencies and costs. We're fine-tuning frac designs and zipper frac operations, and I expect we'll continue to do so for years ahead. Even with some forecasted pressure on service costs, our cost per stage and our cost per foot of completed laterals should continue to improve throughout 2017.

Facility costs should continue to improve, and LOE continues to trend in the right direction. Anyway, you look at the data, Range has the lowest well cost including facilities of any operator in the Southwest portion of the basin, and we expect those costs will continue to improve. One significant and unique advantage that we have is the extensive network of existing infrastructure in pads. We're planning for approximately 1/3 of our 2017 wells on existing pads with as much as half of our wells in 2018. This will drive down our costs significantly by as much as $200,000 to $500,000 per well.

On the well performance side, we continue to improve completion designs and see impressive results. As an example, I want to highlight a couple of liquids-rich pads that we bought online during the first quarter.

In the wet area, we brought online a 3 well pad with average lateral length of 7,186 feet completed with 37 stages per well that produced net to sales under designed, constrained conditions at a max 24-hour rate of 35.3 million cubic feet equivalent per day per well. In the super-rich area, we have a 4 well pad with average lateral lengths of 10,772 feet completed with 54 stages per well that have only been able to put 2 of the wells to sales so far. The reason why is that they're some of the best liquids-rich wells in the basin. Those 2 wells have averaged over 31.4 million cubic feet equivalent per day each well or over 62.8 million cubic feet equivalent per day combined with 69% liquids, again, under designed constrained conditions net to sales for a max 24-hour rate.

As those 2 wells decline, we'll be adding the other 2 wells to sales as capacity frees up in the system. It's important to point out that what -- that this pad is near the planned Harmon Creek processing plant and a lightly drilled super-rich area, and we have plans to develop additional wells and pads in this area going forward.

Clearly, these 2 pads illustrate the quality of our low-risk, long lateral inventory in Appalachia in the dry, wet and super-rich areas. These types of results when combined with going back onto existing pads with existing gathering and compression infrastructure generate liquids-rich drilling economics that are among the best in the business.

Like I said in the past, we literally have thousands of these types of opportunities, and I still don't believe we've drilled our best well yet.

As a quick update on the Utica, I believe it's worth pointing out the updated map in our presentation on Page 44. A particular note, we've highlighted the recent activity, including some direct offsets to our acreage currently being drilled that will clearly enhance our 400,000 net acre positioned further. We'll continue to monitor those wells and other Utica activity in Pennsylvania as we go forward. Our best well remains as one of the top 4 Utica wells in the play. We believe that will hold flat for close to 400 days, and the EUR looks to be around 3 in a quarter Bcf per thousand foot. Again, essentially, all of our acreage is HBP-ed, and we believe the Utica play will play a complementary and important role in the future.

Shifting to North Louisiana, we're excited about the progress we've achieved in just a little over 6 months, and believe we're on track to exceed our original acquisition expectations. We're in line with forecasted production and cash cost, and we're expecting solid growth in the second half of the year, while drilling and completion costs have improved further and faster than we expected. We've reduced our average all-in well cost for a 7,500-foot lateral by another $300,000 to $7.4 million, while reducing drilling time, refining the target window and staying 100% in zone. This is now $1.3 million or 15% below the $8.7 million cost last September, which obviously has a major impact on the economics.

Like we've discussed, this lower cost will open up additional inventory from various horizons across our acreage position.

Our capital plan and the $7.4 million well cost in North Louisiana has baked in our forecast for service pricing increases for the year. For some services, those increases could range from 5% to 25%. However, as evidenced by our well cost, we fully expect that improvements in our operations and designs will more than offset the service price increases.

As mentioned earlier, our 2017 North Louisiana program includes drilling, delineate and de-risking our well inventory in Terryville. This plan consist of wells in the various Lower Cotton Valley intervals that will lead to an improved understanding and mapping of the reservoirs, alongside the acquisition of additional science work directed at determining optimum targeting and completion design. We're acquiring additional seismic along the southwestern and southeastern portions of the field to help calibrate the reservoir mapping and well results.

During the quarter, we completed 27 wells made up of 19 Upper Reds, 5 Lower Reds and 3 Pinks, and we're producing these wells much differently than the historical practice mainly under designed facility constraints resulting in lower costs and flatter decline. We believe that this new approach of adopting more cost-effective facilities combined with better targeting and completions will drive the next step in development for the Terryville field.

To put some context around 2017 well activity, there are really 3 groups of wells. The first group is the well that we simply call the pre-range wells. In essence, we may have taken over operations in 1 phase or another, but essentially, they were planned and designed using historical practices. This was 21 of the 27 wells in the first quarter, and 18 of them were drilled almost a year ago.

The second group of wells, which 6 of the 27 fall under this group, is those wells where Range may not have been able to pick the location or the formation, but we did have some influence in the targeting and drilling of the well. And then the last group are the Range wells, where we picked the location, formation, target and designed them from start to finish. The majority of the remaining 29 wells for the year, again, which are weighted to the last half of the year fall into this group, and we've only recently begun completing the first of these wells.

We're excited about what we see so far, and I look forward to updating those results throughout the year as we gather that performance data and build our reservoir models and development plans for the future.

As an update on the extension area activity, results continued to be encouraging from the 2 of the wells that we announced last quarter. Each of the 2 wells, each located in separate Terryville sized default blocks, one to the east and one to the west of the Vernon Field, has cumulative production to date of approximately 1 Bcf each. As a result, plans are underway to offset each well with another horizontal well.

Additionally, in the extension area, we have 2 pilot holes, 1 partially completed lateral that we're currently testing, and we'll be starting a couple of new vertical wells designed to test multiple targets on an individual basis. This allows us to determine reservoir and rock properties, while performing specific diagnostics to identify the best lateral targets. With over 400 Bcf per square mile and up to 6 target intervals, the potential is large. Again, we remain focused on Terryville, while methodically testing and delineating the extension areas over time.

In the Marcellus, we're continuing to improve returns through lower costs and improved well performance, and we continue to develop our extensive inventory of core locations with longer laterals.

In North Louisiana, we're ahead of our acquisition case, and believe we'll continue to make progress going forward. We're on track for our production growth guidance for 2017, and 2018 is shaping up very well.

Now I'd like to turn the call over to Roger to discuss the financials.

Thank you, Ray.

The first quarter of 2017 builds upon the excellent fourth quarter of 2016 with further improvements in top line growth, cost control, margins and bottom line net income and cash flow.

Net income on a GAAP basis for the first quarter was $170 million, while earnings using common analyst methodology, which excludes noncash derivative mark-to-market entries and nonrecurring items was $61 million. Cash flow for the first quarter was $258 million, 2.5x the first quarter of last year's $99 million figure. Cash flow per fully diluted share was $1.05, 78% higher than last year's per share figure of $0.59.

EBITDAX for the first quarter of 2017 was $303 million compared to the last year's $135 million amount.

First quarter 2017 cash margin at $1.47 per Mcfe was almost double that of last year's cash margin at $0.77.

One notable achievement in the first quarter of 2017 was that for the first time since 2014, Range was solidly profitable without any contribution from our hedge book. With our unhedged recycle ratio approaching 3x and continued margin and capital efficiency improvements projected, future quarters should be much more like the past 2 quarters than the other preceding 7.

Moving to the expense performance for the first quarter, all of our expense results came in at/or below guidance. The detailed expense guidance for the second quarter of this year may be found in the earnings release.

Turning to the balance sheet. Like last year, we ended the first quarter with less debt than we entered, as our spending outflows were less than our cash inflows. Our debt-to-EBITDAX leverage ratio calculated using a first quarter annualized EBITDAX was 3.1x, and our book debt-to-capitalization ratio is 40%.

Additional hedges were selectively added during the first quarter to the already well established 2017 and 2018 hedge positions, and we initiated our first hedge on 2019 production. Presently, over 75% of our 2017 natural gas production is hedged with an average floor price of $3.22 an MMBtu. Additional hedges were added to our oil and NGL book during the first quarter as well.

While disclosure of our hedge price and volume positions may be found in the 10-Q earnings release and Range website.

The first quarter of each year has historically been a strong one financially. The reason for this first quarter strength is usually the peak of winter weather and the resulting strong demand and higher prices for our products. In 2017, the story is very different. This winter, we experienced the second warmest first quarter in 30 years based on gas-weighted heating degree days, and the second warmest first quarter in 123 years based on average temperature. However, our first quarter cash flow of $258 million was roughly the same as our cash flow for the first quarter of 2014, a year when we had the coldest first quarter in 30 years. The reason that our first quarter financial performance and the second warmest winter in 30 years is on par with the coldest winter in 30 years is a result of capital-efficient growth and the improved transportation marketing and cost control measures Range has been working on for the past 10 years. The margin improvements we're seeing from our relentless cost control, the capital efficiencies from technology and the quality of our rock combined with the marketing network from our unique natural gas and NGL marketing projects, have made Range's financial performance much more durable regardless of the weather.

Now Jeff, back to you.

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

(Operator Instructions) Your first question comes from the line of Dan McSpirit with BMO Capital Markets.

Touching on different here, a big scene no doubt. I may be picking up where Roger left off in his prepared remarks. How much of the improvement in differentials in your mind is unique to the company based on moves made in pricing molecules outside the Appalachian Basin? Say, versus how much is based on developments general to the industry, asking here in an effort to get a better sense of really what's sustainable?

Yes, Dan. This is Laith. I think it really gets back to the approach that we've taken with marketing to move our molecules and have the flexibility of having production in basin as well as moving gas to the Gulf Coast, the Midwest and the Southeast. So in the first quarter, you'll notice that we came out with a positive $0.01 differential. So despite having the warmest winter in the last 130 years, like Roger mentioned, we still have some capacity that gets us to premium markets despite having no winter. And as you -- as we move towards the end of '17 with some of the transport that we've coming online, we'll have 90% of our gas being sold to markets better than what we're typically seeing in Appalachia.

Okay, great. And just as a follow-up to that, just addressing the Terryville cost reduction. What's behind the cost reductions to date? And what drives that the reductions going forward here? I'm just trying to get a sense of how much the company scale explains the improved capital efficiency in the field versus simply cutting fat that was in the prior operators system, if you will?

Yes, Dan. This is Ray. That's a great question. In last quarter, we went through a whole litany of examples where they had increased drilling time, employed new downhole mud motors, more aggressive bit designs, and essentially changed out the drilling team, we brought in a gentleman that -- Scott (inaudible) that's extremely talented, and knows as much about high-pressure, high-temperature drilling, as anybody around. And so he's really reshaped our whole program there. We recently, for example, drilled a curve in one of these wells in 24 hours. And the average last year was 86 hours. So it's just a continual litany of things like that, that we've been able to do. We went from, in the series of wells that we fracked in the first quarter we had planned, because in the past they had averaged about 8 stages a day or a little bit less, and so we planned to for about 8, and ended up averaging 12 to 15 stages a day. So I think it's been a lot of that. It's been a lot of using Range's purchasing power just simply because of the size and scale that we bring to the table. And now I think as we go forward with a more balanced approach, and we kind of smooth out the activity levels, and we plan where the wells are a little bit better, as we go forward, we won't go through this -- these very variable up-and-down cycles of activity levels going forward. And I think that will help improve costs as we go forward.

Your next question comes from the line of Holly Stewart with Scotia Howard Weil.

First, maybe, Ray, you gave a lot of detail on Terryville, and the well results during the quarter and -- which I think explains the production that we saw in 1Q, but given these dynamics and the fact that you got 29 more wells, which are all Range designs, can you maybe help us think through the volume for Terryville for the rest of the year, and maybe how that sequential, I guess, progression goes throughout the quarters?

Sure, Holly, and basically, the high-level answer is the next 29 wells are going to be a lot better than the first 27. And of course, to understand that, you have to compare and contrast a lot of that. And I went through in my remarks and talked about how 21 of the 27 wells were actually wells that were pre-Range, 18 of those were actually more than a year old. So in a lot of ways, we had very little influence on how those wells were picked, where they were -- what they were targeted in and so forth. And then 6 of the remaining wells, which was the full group of 27, were wells that we took over in 1 place or another. We didn't get to pick where they were, but we may have been able to refine the target or different phases -- took over in different phases of operations. And some of those wells, show -- we're testing other horizons and different things like that. So we're learning a lot. We've changed a lot of production facilities, we've changed a lot of the early flowback procedures. We're really focused on project returns instead of just 30-day IPs. I don't think the previous operator did anything wrong. I think it was just different. And I think that's -- we've got a much different approach. And as we implement that approach, I think what we've done in these first 6 or 7 months that we've had in under our belt, which, again, is not very long. But we've -- I think I'm real proud of what the teams accomplished. And I think you'll begin to see the results of that going forward. We've shot a lot of 3D seismic, we've done a lot more mapping, we're starting to build reservoir models, and we'll be able to place a lot of wells in some of the areas where we're seeing really good results. And I think bottom line, the next group of wells will be a lot better. And that's part of how we get there for the production growth for the year.

Okay. Well, perfect. But any attempt to sort of breakdown Terryville versus Appalachia in that growth number?

Appalachia is -- we only had about 20% of the wells to come online, this year. I think, I would attribute some of the changes in Appalachia to -- a lot of it is timing, and a lot of it is the team is making really great progress in drilling longer laterals. And we're going to -- you're going to start seeing some of the wells that we talked about being on existing pads start to domino in the last half of the year. And as we've ramped up activity with the new budget and everything that started in January, a lot of that activity starts domino-ing 6 to 9 to 12 months later depending on if it's an existing pad or whatnot. So essentially, we're getting really solid growth from both areas. In Appalachia there is a lot of -- it's just a lot of timing that's going to come forward in the second half of the year. I'm really, really excited about some of the recent stuff we've done because since we've now HBP-ed our acreage, one of the things that teams really focused on in some of the very, very best areas, and the 2 examples I gave in my prepared remarks are certainly extremely impressive. I mean, those are some of the best economics out there, dry, wet or super-rich. But there were 3 more pads that I could've talked about, that were 25, 26, 16 million a day equivalent type constrained rate conditions again, which I think as you see us do more of that, focusing great areas, long laterals, existing pads. We're going to see really strong growth in the second half of the year out of Appalachia, just like we're going to see, I think, stronger growth out of North Louisiana. And we're really still solid on our production annual growth targets.

Well, maybe switching gears to Appalachian for the follow-up. You mentioned a lot of infrastructure constraints adding the Harmon Creek plant, the downtime in Houston, and then the new gathering systems. Can you just maybe talk about the timing of these things, and how it sort of impacts in your term volume?

The MarkWest plant, it's something that -- what they're doing there is the original cryogenic plant was about 30 million a day plant, and they're basically is going to use that spot and put a new generation 200 million a day plant. So again, it's building a lot of infrastructure for our growth in the coming years. In order to do that, they have to take the whole plant down for a day or 2, reroute a bunch of power and do different things there. I won't get in too many details, also part of that, the de-ethanizer will be down for about a week. And so while that won't impact our second quarter sum, it won't even be a blip in MarkWest infrastructure. I mean, they've gotten so huge now. So it's something we knew about, we forecasted, it's been built into our annual growth plans for some time. So we're pretty pleased with that. The new wells up around the Harmon Creek, the future site for the Harmon Creek processing facility, we need to get up there and start drilling wells. In preparation for that, we have some basic backbone of the infrastructure up there. But just like our position in Southwest Pennsylvania is really, really large, we're far from having all the infrastructure built out. And so as we move to the north and so forth, you're going to see us add more and more of that infrastructure and compressor stations, the processing plants and so forth. And I think the exciting thing is, is that could be potentially some of the best rock in the whole core up there. So we're pretty excited about that.

Your next question comes from the line of Neal Dingmann with SunTrust.

Gentlemen, say, a question first just on guidance. I looked, noticed about the -- just more about sort of allocation of activity, and northern that -- noticed that northern Marcellus, kind of the drop we've seen year-over-year and sequentially. Could you just talk about the kind of rig allocation or activity allocation? Should we expect kind of similar, I know now you kind of blend in the whole Appalachia together. But as we looked, particularly at the northern Marcellus, how should we think about that for the next remainder of the year?

Yes, it's a good question, Neal. We did combine all the operations in Pennsylvania into our Southern Marcellus division or what was previously called that, and it's now we just referred to it as Appalachia. We -- you're right in that we have over the last several years put less and less capital up there as the differentials have been really tough. It's good rock, it's just hard to sell the gas, when you've got those kind of discounts in place up there. So we have put it all under one team. It'll be much easier to allocate capital. With that team up there, they'll put it in their whole mix of assets that they've got across Pennsylvania. I think that they're likely to find some new things, anytime to get a fresh set of eyes looking at a project, they're likely to come up with new ideas, and they'll put their grassroots plan together going forward. And if it competes economically with the projects in Southwest PA, then we'll fund it going forward. But at this point, they literally just took it over in the last month. So I think it'll be some time before we see anything happen up there. The good news is it's HBP-ed. So we're not in any rush to do anything.

Great flexibility there. And then, Ray, just one follow-up. As far as looking at how well all that changed, it seems like you're encouraged, I should say about the changes in Terryville, when you look at kind of your new pressure management, how should we think about, you did mention, which is not a surprise that the IPs might be a little bit lower, but how should we think about sort of that cumulative production of over, I don't know, either the first 6, 9 or 12 months as you've sort of dial that in versus what the previous team had?

Well, I think what we have -- this is Alan, Neal. I think what we have in the appendix portion of the book, we have some type curves associated for both the Upper Red and Lower Red. And I think what you see in those forecast is a lower initial rate coming through. And so we would expect to probably with the wells -- with the 29 wells going forward, that Ray talked about, that we've had our design and everything in there. We would expect those well performs to kind of look somewhat similar to that. I don't have the exact page. I think if you look at 47 -- Page 47 in the book kind of gives you an idea of what it would look like. Probably, what we would see you should probably won't be starting that peak rate, you'd probably have to Slide that out about 15 days or some for wells to kind of -- for -- as a come on becoming increased productivity for a little bit. So I would expect it's going to look something similar to that, so a little bit lower rate overall. Similar for the Lower Red that's also in the book as well.

But overall, Alan, your returns, I guess, the way you now are positioned at. It's certainly appears to me like on an EUR return basis, they're a bit better despite that initial little bit lower rate, correct?

Yes. I think that's fair to say.

With the lower well costs.

With the lower well costs.

Your next question comes from the line of Ron Mills with Johnson Rice.

Just one quick follow-up on Neal's question. Ray, I think part -- is it safe to assume that part of the same or better economics despite the lower production rates is associated with the upfront cost? I think you mentioned facilities, gathering flowback equipment, how much is the cost savings associated with that flowback to offset the lower initial production?

It's a good question, Ron. We could get back to you with more exact numbers. But off the top of my head, when you're running that expensive flowback equipment for 30 to 60 days, it's several hundred thousand dollars, probably half a million tops, somewhere in that range. So you're saving a lot of money off the top, upfront. Also like -- much like we've learned and done in the Marcellus over the years, you learn to optimally size your production equipment and make it more generic in nature so you can kind of stack it, move it around, reallocate it to new wells, pull it off well that have fallen below that, and so forth. So it allows us a lot of overall project flexibly going forward. The team is doing a lot of things on LOE side. They're doing a lot of things on the saltwater disposal side. Again, we've only had it 6 or 7 months, and gone through significant organizational changes. The -- I think the teamwork is really coming to fruition, and you're already seeing -- we've already lowered costs faster and further than we thought we would in our early expectations. So we're pretty excited what about -- what we see. But again, those well costs, we've made a -- we've caught a lot of the low-hanging fruit, but I still think there's a lot of fine-tuning that were going to do going forward over the next year. And again, we'll see, I think, begin to see a lot of that performance and economics really happen in the second half of this year.

Okay, great. And the moving to my question, the super-rich pad that you brought on, you've talked about that being in more likely drilled portion of Washington County. Why was that area more lightly drilled? Does that de-risk for in years in industry mines, that portion of that acreage, and how does that flow-through to kind of your -- the resource potential what you thought that area may have?

Yes. Well, again, we have a really large position in Southwest Pennsylvania, and we sort of started in the wet area around the Houston plant, and you've sort of seen our development expand from that area over the years. We drilled years ago several wells up into the northwest portions of the field and got some early indications. We have full seismic coverage, we've got a lot of information on the fields. These recent wells, we've gone up there, they're 10,000-foot plus laterals. They're completed with 54 stages, using all the latest technology, and we've made wells that are essentially 5,200 barrels of oil equivalent per day. The wells, we're making over 1,000 barrels a day of condensate a piece each well. So, I mean, the bottom line is, yes, all wet area is completely de-risked. And I think now we're beginning to become more excited about drilling a whole bunch more 10,000, 15,000-foot laterals up there as we go forward, and it gives us a whole lot of confidence it helps us in sizing, the infrastructure and things that are going to be developing over the years ahead. This is something that's been in our plan for many, many years going forward. It's just now a really exciting to see it come to fruition and how good those extra long laterals are going to be up there.

Your next question comes from the line of Subash Chandra with Guggenheim.

I wanted to ask about your frac protect plan in Terryville. Do you expect these offset wells to return to their pre-rates, to their prior rates? And could you give us a sense of, was it a mile radius or so that you saw the frac interference, and how many wells might have been impacted?

Yes, it's a great question. We're still learning exactly how far these wells will impact, offset wells. But generally speaking, today, I think the thoughts are around 4,000 to 5,000-foot, so about a mile. I think that to answer first part of your question, yes, that production -- those wells will eventually come back some faster than others. And so that's what I meant in my prepared remarks, while we shut in 40 million a day, while we had all that frac activity going on, some wells come on sooner than others and some come back to where the were sooner than others. There's just a huge variation in that. So I think as we go forward when you take a much more balanced approach in the second half of the year, you'll see wells where we planned that out better to try to mitigate and minimize the amount of impacts. So we don't have to shut in as much production and a lot of those things going forward.

Could you comment on how many wells were shut in?

I don't know off the top of my head. I guess it's something we could -- you could follow-up with Laith and the guys, and we could can get an answer. But I don't -- I just don't know that answer.

Sure. My follow-up is, the Terryville well cost reductions. What was in the CapEx guide? Are you -- it sounds like you're overachieving the CapEx guide for the year.

Yes, I think we were probably a little higher than where we were today. Again, we achieved it faster and further than we thought. We're going to do what we always do. We're not going to change our stripes, were going to use that capital to optimize the plan. There's still a lot of things we want to test. We won't -- a lot of the southern edges of the field we want to test, a lot -- the extension areas, we've got -- it's going to allowed us to do more science and diagnostics in that area, help us move that plan forward faster. So I think that's a good thing in the long run for us.

Your next question comes from the line of Bob Morris with Citi.

Jeff, on the -- in your slide presentation, you highlight the 3 pipeline projects that are coming on in the second half of the year. Do you expect to -- apart from an initial ramp-up period, fuel your firm transportation capacity on those lines? And if so, is some of that moving gas from other existing lines to be more economic on these new lines? It still leaves you with some excess capacity in the system that you could fill if you continue to see better-than-expected well results? And separately from that, for the industry, we're not at the 100 rigs you've always talked about that the industry needs to fill the pipe capacity, but as we get to year end, do you see all this pipe -- apart from what you're going to do, being fueled by the industry?

Yes, let me kind of work backwards through that. In order to fill all that capacity, our current rig count in Appalachia is somewhere around 64 plus or minus. I will quote one of our competitors Rice said, they believe, I think it's a 125 rigs, they're needed now in order to have all that filled. We've actually done our own internal work. And our number is right around their number. So we think the basin basically needs to almost double the rig count in order to fill the pipes. And that needs to happen almost immediately because some of those pipes are going to come on by the end of the year. So we actually believe the pipes all won't fill, and they'll be excess capacity in the southwest part of the play. Of course, up in the far northeast part of the play, there's really no new pipe coming on this year, and probably, at the earliest, it's middle of '18 or something for Atlantic Sunrise to come on up there. So one advantage of where we are in the Southwest part of the play is better infrastructure, better take away. And it's a really important point. It will -- as those pipes come on, it will allow us to re -- to get to the first part of your question, to redirect some of our gas to better markets, which should result in continuing to improve margins. Big part of the story this year, but I think we'll extend it to next year is margin improvement which translates into better cash flow, better cash flow per share and coupled with that second half ramp really helps us set up '18. So I think when you look at the infrastructure, the other thing, and then if you looked really forward, the team's done a good job of setting up a diverse portfolio of transportation. We've got a huge position, where we continue to grow volumes, and as we grow volumes, then we'll have optionality whether to move some of that gas out of basin to sell some in basin, which will ultimately really drive down, if you look forward, our transportation cost.

So I guess there -- I guess as part of my question, the corollary is that, is your guidance -- your guidance really isn't dictated by the available pipe capacity that it could move up, given that there could be excess capacity from where your diverting gas have existing lines?

There'll be that optionality. A big part of that will be cash flow. Our spending for next year will be a function of cash flow or -- at/or near cash flow. So it depends on where you think gas prices are next year. But clearly, we have the inventory and ability to grow and move gas. But we'll be somewhat -- will be disciplined in order to be at/or near cash flow.

Okay. And then my follow-up for Ray, real quick is that, Ray, you mentioned in the press release you're drilling it to further extension wells to offset the 2 Terryville wells to the East and West of diverting field, and your press release shows a 3rd extension well. Is that going to be targeting the area to the north before you have the Lower Red well that came on at about 5 million a day, which was less than the other 2? But is there activity to the north in the -- north of the Vernon Field, part of the plan this year also to go back to that area and see if you can get some better results up there?

We don't have anything going on right now to the north side of the Vernon Field. That third well is in a different fault block than the first 3 that we've talked about. The East and the West ones are pretty encouraging. They both [keened] about a Bcf each. And so we're going to offset those 2 wells to the East and West. The north one, we haven't done a whole lot with. And there's another fault block where that third well is. And we're right now doing a lot of testing on it. So it's more turned into more a science well than anything at this point. And so we kind of got that activity going, and then we've got another area where we're going to put a couple of vertical wells in and do some real serious coring and long analysis, and microseismic imaging and a lot of different things in that area to try to optimize our reservoir models, and figure out what the very best target is. I mean the good news in several of those different fault blocks in all of those fault blocks are Terryville size and larger. So the potential is really huge. But again, we're going to take our time methodically and strategically and test each one of those as we go forward. But all those fault blocks are different and they all have tons of gas in place. So that's the exciting part of it. We just want to make sure we've got really solid plans going forward.

And that third fault block that you can test that's east, west, or where is that?

I do know that we've disclosed that yet, but I'm sure we'll be talking a lot more about it in the next call.

Your next question comes from the line of Brian Singer with Goldman Sachs.

Just following up with regards to the extension wells in Northern Louisiana. You've gotten to 1 Bcfe per well over, I think it's about a 160 days. Can you just add some more color there, and parse it with your type curve? What you think that suggests so far regarding economics and opportunity? Obviously, we've -- if you've talked to your next up there?

Yes, Brian. This is Alan. We continue to pot those wells up against both our Upper and Lower Red, and they are producing kind on in line with what -- both those curves that are out there. It's kind of consistent with what we've said on the last call when we disclosed the well results at that point in time. So wells continue to produce similarly with what those type curves are. We're continuing to help understand where we are within the section, continue to gather a lot of data. And I think we're encouraged where we are to date to feel about going heading offset in both those wells. We still like the fact that there's a tremendous amount of gas in place. There's multiple horizons out there. And of course, there's a lot of information we are continuing to glean from the production data as well as offset well performance from both vertical wells as well.

Great. And then shifting to Appalachia, Range was historically very early in signing low-cost takeaway contracts to get that out of the region, and recognizing that the wave of new pipelines are coming on now from what you're contracted a couple of years ago. Wanted to get your view on the strategy for growth in the next decade, and why do you think it makes economic sense to be thinking about contracting now or whether you're flexibility to shift capital geographically, means Range down the road will depend more on local market prices and apple -- than Louisiana prices?

Brian, let me start and others can chime in. I think one thing, if you look at the next decade out, something that's I think not real well understood, actually was part of internal work we've done and I've heard other people talk about a little bit, but not much is that the -- that comment or concept of sweet spot exhaustion. I think if you really looked at core areas in Appalachia, but I think it's true in the Permian, the only 2 plays, I think, with more than a decade worth of true sweet spot drilling is probably Permian and Appalachia, but when you look at Appalachia, there's only a couple of companies that have more than a decade worth of really high-quality wells, not that a lot of people won't claim that. But when you look at the data and you look at the EURs per thousand and cost per thousand. So I think -- again, I think there's only 2 plays that have more than a decade worth of true sweet spot drilling, a lot of the other plays will be exhausted quicker than that. So if you look at Appalachia, even early on, our thoughts where, when we look at all these plays infrastructure tends to get overbuilt with time. I mean, that's true historically, we assumed that we would get what we thought was rightsize transportation early on to allow us that flexibility to grow. So I think given the position we're in, we're in great shape as we look forward, again, we don't think the pipes fill early on. But particularly, if you look out over the next decade, there'll be -- that optionality probably to sell gas in-basin or we'll have the ability to probably move it out,whatever is more optimum. And with that, I think that will continue to drive down unit cost with time, again, the advantage we have is just a huge inventory of high-quality prospects, plus we have now the optionality of drilling in Northern Louisiana or in Appalachia. So I think we're well positioned for the future.

We're nearing the end of today's conference. We will go to Blaise Angelico with Iberia for our final question.

Apologies, if I missed this early on, but just, I was wondering if you could talk about what specifically you're going to be changing on the completion design, on those Range controlled wells in North Louisiana versus what the prior operator was doing? And then in terms of that well that is completing, is that a second quarter, third quarter call, type of event, where you release production rates?

Yes, this is Ray. As far as completion designs, I don't want to get into too many details, but we're looking at stage facing, the perforation cluster designs. As you can imagine, this is the sandstone. It's not a shale. There's a lot of differences involved here. We're still trying to optimize the targeting, and figure out what makes sense to be, we understand that being that in the zone for 100% of the wells is certainly appears to be making a good difference so far, and we've got some good examples of that. So I think that we're doing well on that. It's going to be looking at different fluids, different proppant mixes, different perforation designs. And we're far from understanding what we believe the optimum is going to be going forward. We're still working on that issue in the Marcellus. So I think we'll have a lot of that going forward. And then the last part of your question, I've already drawn a blank on.

I was just in terms of that, that Range controlled well which Range was just completing, just the timing on the production rates on that?

We only just started completing it, literally a week or 2 ago. There's going to be a little bit of a lull of time period until the next group of wells, we start completing. So assuming it comes online in the next month, then we would probably want to see, I'm looking at Alan here, but probably 3 months plus of production history because, again, we've got to completely different flowback protocol and early production protocol. And so the well we know is going to be constrained a lot longer. So I would think it's going to be at least probably the call after next before we'll have a lot -- anything that we can talk about definitively as far as an EUR per thousand feet or anything like that. I think we'll continue to improve costs, but I think it's just going to take us some time before we can tell you much about that.

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

Thanks to everyone, for participating on the call. If you have additional questions, please follow up with the IR team.

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