Laith Sando - Range Resources Corp. Jeffrey L. Ventura - Range Resources Corp. Ray N. Walker - Range Resources Corp. Roger S. Manny - Range Resources Corp. Chad L. Stephens - Range Resources Corp..

Arun Jayaram - JPMorgan Securities LLC Pearce Hammond - Simmons Piper Jaffray Brian Singer - Goldman Sachs & Co. Ronald E. Mills - Johnson Rice & Co. LLC Robert S. Morris - Citigroup Global Markets, Inc. Neal D. Dingmann - SunTrust Robinson Humphrey, Inc. Marshall H. Carver - Heikkinen Energy Advisors LLC.

Welcome to the Range Resources fourth quarter and 2016 year-end earnings conference call. This call is being recorded. All lines have been placed on mute to prevent any background noise. Statements contained in this conference call that are not historical facts are forward-looking statements.

Such statements are subject to risks and uncertainties, which could cause actual results to differ materially from those in the forward-looking statements. After the speakers' remarks, there will be a question and answer period. At this time, I'd like to turn the call over to Mr. Laith Sando, Vice President, Investor Relations in Range Resources.

Please go ahead, sir..

Thank you, operator. Good morning, everyone, and thank you for joining Range's fourth 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.

Hope you've had a chance to review the press release and updated investor presentation that we've posted on our website. We'll be referencing some of the slides this morning. We also filed our 10-K 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 and to provide more details on both natural gas and NGL pricing. With that, let me turn the call over to Jeff..

natural gas, NGLs, and condensate. In addition, we're expecting continued improvement in our cash costs. The net effect is that our margins are projected to show a substantial increase versus 2016.

The significant improvement in margin, coupled with our very low development costs, results in one of the best recycle ratios in our business for either an oil company or a gas company. I'll take a minute to walk through the numbers. Beginning with netback pricing for natural gas.

We're projecting a 33% improvement in our natural gas differentials for 2017, to NYMEX less approximately $0.30. The reasons for the improvement are primarily twofold. The first reason is that we'll have a full year of marketing on the Gulf expansion project, which came online in October of 2016.

This project moves 150 million per day of our production from Pennsylvania to the Gulf Coast. The second reason is that we'll have a full year of our North Louisiana gas production, which receives near NYMEX pricing.

Our NGL pricing is also expected to improve to about 28% to 30% of WTI for 2017, which is significantly better than pricing in 2015 and 2016, while producing over 50,000 barrels per day of ethane and about 50,000 barrels per day of C3+. This is particularly exciting, considering WTI prices have also improved.

There are three primary drivers behind the NGL improvements. The first is that we'll have a full year of transportation on the Mariner East pipeline, providing us better netbacks to international markets with the optionality of domestic sales if it makes sense seasonally.

The second is that we'll have a full year of our North Louisiana NGLs, which are well located and receive Mont Belvieu pricing. The third reason is that overall NGL pricing has improved relative to WTI on improved supply-demand fundamentals.

Condensate pricing for 2017 is also expected to be significantly better as a result of having a full year of our new condensate agreement sales in Appalachia, plus a full year of our North Louisiana condensate production, which receives near NYMEX pricing. We're projecting a 40% improvement in our condensate differential to WTI minus $5 to $6.

Now looking at costs, we're expecting to see continuance of our low-cost structure in 2017. Combining improved netback pricing with lower cash costs results a projected margin of 40% for 2017, which is a great uplift over what we've seen the past couple of years.

Taking this one step further, our expected future development costs for PUD reserves is $0.42, which results in an unhedged recycle ratio of approximately 2.8 times. This is excellent and will be at or near the top of our peers when considering either oil or gas companies.

Shifting now to an asset base that underpins these financial improvements, I'd like to start in North Louisiana, as the team has made some very significant progress early on. In North Louisiana, our well costs were $8.7 million when we closed the acquisition in September. Today, we're drilling and completing wells for $7.7 million.

Ray will discuss this is more in detail, but this capital cost reduction obviously has a dramatic impact on the economics of a well, and we're very encouraged by the early improvements of the team.

Importantly, these lower well costs also expand the inventory of wells to drill, including generating attractive returns in the Lower Red and potentially in the Pink horizons. In addition to driving the cost to drill and complete down, our team has done so while keeping the wells entirely within zone.

This should improve the wells' performance versus any well that was out of zone for a portion of the lateral. In addition, we're now targeting a much tighter landing zone, and we're keeping the wells within the tighter target. This technique significantly improved the performance of our Marcellus wells and has done so in other plays as well.

As we complete wells with this tighter targeting over the coming months and have some production history, we'll see if the technique works here as well. The bottom line is that the team has completed the trifecta. They're drilling the wells at a significantly lower cost while keeping them totally within zone and also within a tighter target window.

In regard to the North Louisiana extension areas, we've drilled three wells and have disclosed the results of those wells in our earlier press release. Based on the encouraging initial results of the wells east and west of Vernon field, we're also planning additional tests this year.

As we mentioned before, the Upper Red thickens in these wells and consists of three zones versus one in Terryville. Likewise, the Lower Red thickens in these wells and becomes three zones versus one in Terryville.

Bottom line, there's about two and a half times the net pay and about two and a half times the gas in place in these two areas versus Terryville. The extension area activity in 2017 will be focused on how to best drill, target, and complete and produce the wells in this area to recover as much of the resource as possible.

As for the majority of our 2017 North Louisiana activity, we will stay focused on driving up production in Terryville and driving down cost, which is consistent with how we originally evaluated the assets.

We'll gather additional data and be very scientific and thoughtful as we continue to evaluate the extension areas, which is the way we do business at Range. Moving to the Marcellus, we're seeing improvements in normalized well costs and therefore rates of return.

These improvements are driven mostly by lateral lengths increasing from about 6,400 feet in 2016 to over 8,000 feet in 2017, which is reflected in our updated economics for the dry, wet, and super-rich areas. Given the recent improvements in NGL pricing, coupled with longer laterals, the wet gas economics are significantly improved versus 2016.

Consequently, we'll focus much of our activity there in 2017. We've also made tremendous operational strides in reducing our days to drill and lowering costs through innovation and a focus on costs, which Ray will discuss in more depth.

Lastly, our capital efficiency is expected to improve not only from longer laterals and operational improvements, but also from going back onto existing pads and drilling within our built-out gathering system. So 2017 is shaping up to be a good year for Range.

Importantly, the improvements we see in 2017 should continue into 2018 and beyond, resulting in better margins and a class-leading recycle ratio. Range is one of the few in the industry with a decade plus of high-quality drilling locations. We have a deep bench of stacked pays in both Pennsylvania and North Louisiana.

Plus, we have the optionality of drilling dry or wet, which is important considering the recovery of NGL pricing. Hitting on the natural gas macro, first looking at the near term, 2017 is shaping up to be a better year than 2016, or much better than 2016. Last year was the first year since 2005 that natural gas production in the U.S.

declined on a year-over-year basis, setting up a more balanced market that we believe the current activity levels are not sufficient to supply the increased demand that we see coming in 2018 and beyond. Looking at NGLs, propane pricing relative to WTI have improved to levels that we've not seen in years.

And the rest of the NGL barrel has also improved. This is meaningful to Range, as we're going to be producing approximately 100,000 barrels per day of natural gas liquids in 2017. Looking beyond this year, there's significant demand for natural gas coming from LNG exports, Mexican exports, power generation, and industrial use.

In total by 2020, about 14 Bcf per day of additional natural gas demand is projected to occur. In addition to the roughly 14 Bcf of additional demand, it takes more than 6 Bcf per year to offset the base decline in the U.S.

In aggregate, that's 14 Bcf of demand, plus about 24 Bcf per day of base decline, which is a total of about 38 Bcf per day of new gas that's required by the end of 2020. Looking forward, Range remains well-positioned in the two best gas and gas liquids plays in North America. I'll now turn the call over to Ray to discuss our operations..

The team rolled out initiatives to exploit Big Data technology using machine learning or artificial intelligence. These groundbreaking tools have significantly reduced the time required to update well forecasts and assess the economic performance of different development scenarios in almost real time.

We are big believers in making data-driven decisions that are based on, and tailored to, our large inventory of core area assets. And the team's innovation and resulting successes speak to that. So shifting to North Louisiana. We're incredibly excited about what John and the team there are doing.

But, first, let me take a step back to where we were in mid-September. Our expectations for the acquisition were initially grouped into three categories. First, we believed strongly we could lower well cost, improve operations, lower unit cost, and improve targeting in Terryville. This is where our focus is and will remain so throughout this year.

We've made great strides and exceeded a lot of those expectations already. Secondly, we believed our cost and targeting focus could increase our potential drilling inventory in other horizons in Terryville, namely the Lower Red and the Pink intervals. Additionally, we believed there were marketing synergies and advantages. Both of these look promising.

Thirdly and longer term, we also believed there was significant upside in the extension area, potentially developing more Terryville-like fields with expanded stacked pay opportunities that also exhibited significant overpressure and higher gas in place.

As you know, we recently released the early data from our first three tests, which verified that that potential is real. So we'll be working very methodically and strategically to delineate that potential as we go forward. But again, as you would expect, our primary focus will continue to be on Terryville.

So let me cover some of the successes and highlights from our activity at Terryville. We've reduced our average all-in well cost for a 7,500-foot lateral by another almost 12% to $7.7 million while reducing drilling time, refining the target window, and staying 100% in zone.

This is over $1 million less than we reported just last quarter, which obviously has a major impact on the economics. It not only improves the economics on an Upper Red well, but also opens up some of the Lower Red and Pink potential in Terryville.

So how did we get there? On the drilling side, Scott and his team have made great strides, setting all sorts of company and field records resulting in lower cost.

Since taking over, they've drilled the fastest two wells, spud to rig release, the most daily footage drilled, the fastest curve, and the longest drill-out under intermediate casing with a single bit.

They've reduced drilling time by 11%, lowering costs by over $300,000 per well by increasing mud motor and MWD reliability using more aggressive motors and bits, and responsive and real-time decision-making.

New drilling rig contracts with reduced day rates, along with ancillary contract negotiations, have lowered overall spread cost, dealing an additional $125,000 per well cost savings. Casing costs have also been reduced by over $50,000 per well by utilizing the Range supply chain management team. We reduced our mobilization time significantly.

We've brought in different vendors and a lot of new technology. And this was all done while routinely staying 100% in the new refined target window, which is now around 30 feet versus 90 to 100 feet before. On the completions front, Jeremy and the completions team have refined our completion designs, resulting in less impacts on offset production.

We're routinely pumping almost twice as many stages per day as in the past, greatly reducing costs and cycle times. We've reduced the flowback equipment and coiled tubing costs by over $300,000 per well by utilizing more efficient designs and operations. And our design changes have helped us reduce our fracturing costs by over $200,000 per well.

We started the year with a plan of completing eight stages per day, and I'm happy to report that we're routinely pumping 12 to 15 stages per day. And one crew achieved a high of 17 stages per day on a three-well pad while pumping between 330,000 and 350,000 pounds of proppant per stage. All of this accelerates our return of capital.

And on the G&G side, Kyle and his team are approaching near full 3-D seismic coverage across the Terryville area and the expansion areas, as well as acquiring significant new core and reservoir characterization data that will help direct our development going forward.

All of this helps to open up a large inventory of future locations on our Terryville acreage. Please see these economics presented on page 11 in our updated presentation. Again, these economics and our capital plan in North Louisiana have baked in our service pricing for the year.

We fully expect that improvements in our operations and designs will more than offset any modest service price increase that we have baked into our 2017 plan. By the end of March, we'll have completed 26 wells so far this year, utilizing up to three frac crews since the start of the year.

These include 19 completions in the Upper Red, five in the Lower Red interval, and two in the Pink intervals. Of these wells, 18 were drilled by the Memorial team prior to Range and have waited an average of 10 months to be completed.

Eight of the wells were drilled by the Range team with improved targeting and will average just three months waiting on completion.

While the first quarter was dominated by all of the completion activity, we do expect to smooth the frac schedule out over the year to get to a steadier pace of one to two frac crews working consistently as we go into 2018.

So switching to marketing for a few minutes, as Jeff mentioned earlier, our netbacks continued to improve in the fourth quarter, with a full quarter of North Louisiana production and with the addition of Spectra's Gulf Markets project going in service in early October.

Additionally, we've received favorable news regarding other takeaway projects where Range is a long-term capacity holder. Spectra's Adair Southwest Project and TransCanada's Leach and Rayne XPress projects have now received final FERC certificates with projected in-service dates in late 2017.

The combined capacity from these projects for Range is 400,000 dekatherms per day out of the Appalachian Basin to the Gulf Coast, further improving our expected pricing. In addition, Energy Transfer's Rover project was approved earlier this month.

Touching on North Louisiana quickly, there is an incredible amount of existing downstream infrastructure in the area to markets and liquidity at near NYMEX pricing. This does not require any significant contract capacity commitments, as there are several large trunklines around our acreage.

You almost couldn't place a field in a better area for accessing demand in the Gulf and the Southeast. Combining our existing base of transport capacity, our Louisiana production, and the 400,000 dekatherms per day from Adair Southwest and Leach/Rayne, approximately 85% of our gas will move to better markets by year-end 2017.

As Jeff mentioned, this solid base of natural gas sales gives us confidence that we will improve our corporate differential dramatically to approximately minus $0.30 for 2017. This is nearly a $0.20 improvement over what we've realized for the past couple of years and significantly improves our margins.

In summary, our Marcellus team is continuing to improve returns through lower cost and improved well performance as we continue to develop our extensive inventory of core locations with longer laterals. In North Louisiana, we've achieved outstanding results in a short amount of time and expect more of the same going forward.

And our marketing philosophy that we've followed for many years now is paying off by improving our margins and setting us up well for many years of profitable growth. Now I'd like to turn the call over to Roger to discuss the financials..

to opportunistically hedge a significant portion of our expected production in order to have a more predictable cash flow which supports efficient operations and our ongoing capital program. Please reference the just-filed 10-K and Range website for specific hedge volume and price information.

As good as the fourth quarter of 2016 was from a financial perspective, we look forward to even more improvements in margins and cash flow going further into 2017, as the out-of-basin capacity on Rayne and Leach XPress becomes operational, production increases from both of our core areas, and we experience a full year of higher prices and better margins from our diverse portfolio of marketing contracts.

Jeff, I'll turn it back over to you..

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

Thank you, Mr. Ventura. The question and answer session will now begin. And the first question is from Arun Jayaram of JPMorgan..

Arun Jayaram at JPM. My first question just regards the 80% planned allocation to liquids or the wet area and super rich in the Marcellus. Why was that the right number? And I'm thinking about just the returns that you guys cite in your deck versus the Southwest PA dry gas area..

Yeah, Arun, this is Ray. I think the answer's got two parts. I think, one, we see a greatly improving market for liquids over the next several years, and with the great contracts we have, and when you fold in the large core inventories of liquids-rich locations that we have, we think this is going to create a ton of value going forward.

And you've really seen improvements in liquids showing up, of course, in the fourth quarter numbers as a result of some of our great contracts, but we've also seen substantial improvements in ethane and propane and so forth since the first of the year.

And then, secondly, we've got a huge inventory of existing pads and infrastructure and really a core liquids-rich area that's underdeveloped at this point. And I think as you see us moving into a true development mode, we're taking advantage of that.

And I think that's an advantage that's really unique to the Range story, and you're going to see improving well performance, improving capital efficiencies. At least a third of our wells are going to be on existing pads this year.

And I don't know if you heard in my remarks about that four-well pad we just did that's 9,300-foot laterals and has already cumed in 30 days 30% more than the offsets, and we're talking substantial improvements in Bcf per thousand foot over what we've seen in the past.

And literally, we have – I said it before – we have thousands of those opportunities going forward, and I think I can say with confidence that the team is going to far exceed those average numbers that you see in the press release, and clearly those economics are going to be outstanding going forward.

And we just really see a great market looking into the future over the next couple of years with all the ethane and propane improvements that we see there..

And I'd just tack on what Ray said. When you look at the economics in the book, as we have every year, that's just strip pricing as of December 31. If you look at where we are today, gas is lower, liquids are probably better in the NGLs.

So in addition what Ray said above, when you take that into account today, that gap is narrower, and really that's saying the strip is very volatile over a short period of time. If you look at what we're trying to do, we're managing through the cycles. We're looking forward a year, two, five, and 10 years.

Ultimately, we're going to drill all those locations..

Fair enough. Thanks for that. And my follow-up, just wanted to get your perspective. There's been some talk from the buy side regarding potential gas-on-gas competition if the TRP Mainline kind of goes through with their rate reduction.

I know you guys have some volumes committed on Rover, so I wondered if you could, from a marketing perspective, talk about the potential impact to netbacks to Dawn from a Range perspective if that project goes through..

Yeah, hi. This is Chad Stephens. I run our marketing team. So on Rover, half of our volume goes to MichCon Citygate and Dawn, and half goes to the Gulf Coast.

We think that the TransCanada offering that they just had an open season on is going to be difficult to feel because the arb or spread between the prices they're getting in the Western Sedimentary Basin and Dawn and the cost to get the gas there, it's going to be difficult.

But whether it gets done or not, we feel like with our volumes going – about half going to MichCon and half going to the Gulf Coast, it doesn't put us in a difficult situation..

Fair enough. Thank you, gentlemen..

Thank you..

And the next question is from Pearce Hammond of Simmons..

Thanks for taking my questions. Jeff, obviously the winter has been very warm, and gas storage estimates here for April 1 have been ballooning upwards. And then the price of gas has settled lower.

Is there a gas price that you would say, hey, we're going to dial things back a little bit? Or do you feel like with all the hedging that you have in place, that right now you're pretty comfortable with your plan and you're just going to move forward with that?.

Yeah, I think if you look at where we are for 2017, we're well-hedged, we're comfortable with our plan, and we'll move forward. And then I think if you look into 2018, there are several thoughts there. One is there's multiple ways to win, even if gas is a little lower and closer to strip.

We see differentials that could even improve, beyond what we have in there. NGL pricing and netbacks could be better. Cost structure inefficiencies I think will get better. So I think you look across 2017-2018, we're in good shape.

And then I still think if you look out far enough and you take into account incremental gas demand's coming and account for base decline that has to be overcome, there's a story brewing for gas.

And, last but not least, I'd add in with gas prices where they are for people that aren't hedged, or even with some people saying oil prices may fall back in the second half of the year, actually lower prices in 2017 might help 2018, even though the strip doesn't reflect that right now..

Great. Thanks, Jeff. And then my follow-up – I appreciate the prepared remarks on the improvements in the NGL market.

I'd love to get a little more color on what you guys see as far as the opportunity set for Range over the next few years with the ethane market and how you see ethane's supply-demand over the next few years in the U.S.?.

Yeah, this is Chad Stephens. I'll take that. We think that the ethane markets, both domestically and globally, are improving. There's several crackers coming online in the Gulf Coast in mid to late 2018 and coming into 2019. Those stocks are high right now.

We feel like they'd be – several hundred thousand barrels a day demand that's represented in those crackers that's coming online will more than offset the supply that's available there.

Also, propane with the ME 2 (sic) [ME 1] project that we're involved in and the propane that we're flowing through and putting on boats to the global markets is really flowing through currently into the improved NGL prices you see. And we see global propane demand increasing, PDH plants in China, the energy use for propane in Japan.

So we see over the next several years propane demand increasing as well..

Great..

Yeah, and I'll just tack onto that, Pearce.

Chad said ME 2, but we're actually on ME 1, right?.

ME 1, yeah, sorry..

Didn't want to confuse anybody there. But with the great contracts we have on Mariner East 1, on Mariner West and ATEX and the improving markets that Chad was just referring to, we're pretty well set up. Our goal all along for years has been to have a diverse set of outlets and a diverse set of pricing scenarios.

I think we're finally beginning to see how that's serving us really, really well. And what's important – it's going to offer us a ton of optionality going forward. So we can sit back and wait and see what Mariner East phase 2 is going to look like, or Mariner East 2X and the Shell cracker and all these other things.

We've got lots of opportunities going forward, and I think that that's going to be a unique story for us as since we were so early on in these other projects..

Thanks, Ray..

And the next question is from Brian Singer of Goldman Sachs..

Thank you. Good morning..

Good morning..

The ability to increase lateral length relative to the contiguousness of your acreage has long been a question, and it's certainly notable, you're at Range is substantially increasing lateral lengths in the 2017 program.

Can you talk about whether the 2017 program is representative of the lateral lengths through the rest of the southwest Marcellus portfolio? And can you give us a sense of where you expect the lateral lengths to trend in future years?.

Yeah, Brian. It's a great question, and I think something that's not well-understood. But we literally have thousands of opportunities when you think about the hundred and some odd existing pads that we have that were all set up for anywhere from 15 to 20 different well locations, and most of them are five or six wells or less per pad.

So it sets us up really well, and you've seen consistently, I think last year our average lateral length was around 6,400 or 6,500, something in that range. This year I think I can say with confidence it's going to be well over 8,000 feet.

I think with the same amount of confidence, even more so, I think I still see those numbers going up significantly in 2018 and 2019. I think eventually, if you look at it on a whole, I think the optimal lateral length that we see in the dry gas areas is probably over 10,000 feet.

And I think in the liquids-rich areas I think we see some – the optimal average is probably going to be a little less than 10,000 feet.

But, again, we've got more and more examples every day coming up like the one I talked about in my prepared remarks, that we're currently on a pad where we're drilling the third of three wells that's going to be over 15,000 feet. I think the average for that pad's going to be 15,100. And we've got several more of those pads coming up.

So the fact that we've got this large core inventory of existing pads, we have a lot of flexibility in how those units are formed and reformed, and the ability to do that is really going to set us up for some big capital efficiency improvements going forward..

Great, thanks. And then shifting to Louisiana. You mentioned before that post the extension wells that you drilled that you see a gas in place that's pretty significant and expectations for EURs to be in line with what you're seeing in Terryville.

What is the specific plan activity-wise in the extension area in 2017? And what are your expectations for what the wells you're drilling this year are going to deliver and tell you?.

Well, like I said, in our last press release, we put out the early results on the first three wells, and those three wells are – two of the three wells, the ones east and west, are still performing right in line with what we had talked about previously, right in between the Lower Red and the Upper Red type curves, so we're real pleased of those.

Those are first up at bats. We've got a lot of work to do in reservoir characterization and modeling and a ton of science we need to do. We've permitted three more wells. We're in various stages of drilling pilot holes and taking cores, and I think we got one lateral waiting on a completion. I'm not sure what the timing's going to be on that.

All of that stuff we're developing very methodical, strategic plans that are going to be very data based, and they're going to be pretty slow going through this year. So I think the results, as we get more meaningful results that we have a lot of confidence in, we'll be able to talk about those, but I think those are going to be later this year.

And our focus is still going to stay at Terryville, because that's clearly where we're seeing all the big wins. Lowering the cost by $1 million just in the last quarter is phenomenal, and I can say with great confidence it's going to go a lot lower. So I think that we're going to see some big, big things out of Terryville going forward.

It's pretty exciting..

Great. Thank you very much..

And your next question is from Ron Mills of Johnson Rice..

Good morning, guys. A question just on capital allocation, this year's two-thirds Marcellus and one-third North Louisiana.

As you get more wells drilled in Louisiana and given the relative return profiles, do you foresee a situation where in 2018 or 2019 or beyond that the spending could be more equal between those areas?.

Yeah, I think well, the good news is we have optionality there as you look forward. So there's good things happening in Louisiana, and of course with the pricing, that's a big advantage and all that, but there's good things happening up in the Marcellus, too.

You're seeing a lot of improvements, longer laterals, better netbacks, new transportation agreements kicking in. So we'll continue to look at that as we go forward and turn that knob to where we think is optimum for any one particular year or time..

Okay.

And then, Ray, can you go over again in terms of lateral lengths on the dry gas versus the liquids-rich areas up in the Marcellus in terms of where you think they can go? And does that have any impact on potential well spacing?.

Sure. I think what I've been saying for some time now is we believe, from looking at what the optimum spacing and lateral length and all that is, I would say today that we're thinking in the dry areas of Southwest PA, you're looking at probably in excess of 10,000 feet.

I don't know if I'd say 11,000 or 12,000, but somewhere between 10,000 and 12,000 foot, we feel like will probably be the optimal lateral length from an economics and return standpoint. I think as far as well spacing, we're probably looking at between 750 and 1,000 foot in general.

I think as you go more and more liquids, that spacing could get a little bit closer, and we still have in our presentation some of the extended tests, 500-foot spacing, and some of that stuff that looks really, really good.

And then also the infill wells that we put on some of the existing pads, we've continued to update those examples in the PowerPoint also. So I'd encourage you to look at that, and the results are still very impressive.

So I think to sum it up, dry areas are longer; liquids-rich areas are probably a little bit shorter just simply because of the physics of the issue..

Maybe flipped the other way, Ray..

Oh, did I say it wrong?.

Yeah, you said it backwards..

I'm sorry. Well, I'm talking about lateral lengths. The lateral lengths will be longer in dry and probably a little bit shorter – probably a little less than 10,000 foot in liquids. Spacing would be closer in liquids and a little bit further apart in dry. I think that says it clearer..

Yeah. Yeah. The other thing I'd say is we have a really big acreage position..

Right..

And we have the ability, back to Brian's question, it's really a big blocky position. If somebody says otherwise, that's fake news, to use that term. So we have the ability to drill long. And what you're seeing us do, again, is we try to be very thoughtful and methodical, scientific, data-driven, so we're drilling some 15,000-foot wells as we speak.

We have some 10,000-foot wet wells, like Ray said, that are phenomenal. So we'll look at where that optimum is. It's probably a little early to say where it is.

It's longer than we are, so we'll continue to march out, but we'll step out like we are with 15,000-foot wells, so we can see what that data looks like, and then again, dial it to where we think is optimum as we move forward with time. But that'll drive increasing efficiencies..

Great. I appreciate it. The rest have been answered. Thanks..

Thank you..

Thanks..

And your next question is from Bob Morris of Citi..

Thanks. Ray, just following up on the lateral lengths in Southwest PA. The average lateral length you said is going to be just over 8,000 foot this year, but you talked about a lot of 10,000 and even 15,000-foot laterals with very good results.

So 30-year wells are being driven on pads; that implies that there are going to be a good number of wells drilled at 5,000 or 6,000-foot laterals.

Are those shorter laterals strictly on continuing to hold acreage? Or why would you drill shorter laterals anywhere in your program?.

Well again, like referring back to Jeff's comments, we have a huge position out there, and there are some areas where you physically can't go more than 5,000 or 6,000 feet, just because it may be somebody else's lease or just a lot of different reasons when you look at that large of an area.

So in general, the team is always pushing to drill longer and longer laterals. And again, what we put in the earnings release showing you the plans, that's the plans as of we see them today.

And the one thing I can tell you is we're going to change, and just like we have pretty much every year, those lateral lengths will all go longer, and the performance will be better and the costs would be lower. I mean, we've seen that year after year with what the teams have been able to do up there. So again, I mean you're exactly right.

What we're quoting is averages. So there will be some that are, like I talked about, that seven-well pad we just approved that's over 10,000 foot average. There's a three-well pad that the three 15,000-foot wells, actually on that same pad there's a 5,000-foot lateral. So you average all that up, but in general, we're going to be going a lot longer.

And we see that continual improvement in capital efficiency over the next several years for sure..

So the shorter laterals are just due to physical limitations? Just where you don't have acreage blocked out to drill the longer laterals right now?.

Or you could have an old well out there that's butting up against that lease, so there's some of that in there..

Yeah..

But we have a lot of wells that we can drill longer laterals on..

Yeah. Like I said, our focus is going to be always going longer..

Yeah..

Okay. Great. Thank you..

And the next question is from Neal Dingmann of SunTrust..

Morning, guys. A question on that slide 38, where you just talked a little bit on the Utica/Point Pleasant. Totally understand your box where you talk about the low-risk, high-return in the Marcellus and North Louisiana, kind of with the focus there.

Is there a few more well – I guess, what would you be waiting to see in order to accelerate the program there, would be my, I guess, larger question?.

Yeah, it's a good question. And our well – I mean, the good news is we've drilled I guess three wells in the Utica, and our third well is clearly one of the top four in the play. And so when looking at going forward, we're still basically in a wait-and-see mode, Neal.

The issue is, as much as we've improved cost and understanding and everything else, you're still looking at something that cost 2.5 times more than a Marcellus well. And I quoted one in my remarks, a four-well pad that averaged over 9,200 feet for around $6.3 million per well that's making 30% more. It's going to be way above a 20 Bcf well.

And so we just don't see it – it's going to be a compatible play or comparable play, something that at some point it's going to make sense to pull the trigger on.

But in this current market and given the fact that we have literally thousands of these kind of locations that we're talking about to do going forward, I just don't see it competing with the Marcellus in our case anytime soon..

Yeah, and it's back to, that play's in an earlier state, so you'd be spending a lot of R&D dollars to try to unlock it when, like Ray said, we've got a lot of much higher probability, stronger economic wells to drill instead. But at some point, there'll be a lot of value to it..

Sure, sure. And then just lastly -.

We hold all those deep rights, by the way, so we -.

Yeah, we have 400,000 acres so -.

Yeah, it's captured..

It's all HBP, Jeff?.

Right..

Yes..

Okay.

And then just lastly on the hedging, how active I guess, or how liquid is the NGL market if you're able to try to not do a dirty hedge but try to hedge each of the components right now out a year or two or three?.

Yeah, this is Laith. There's really no problem hedging out a couple years. Liquidity gets a little more challenged if you get out beyond a couple years, but we're also on the physical side able to hedge some of that. If you're looking at propane and some of the sales out of Mariner East you're able to do that through some physical sales as well..

Yeah, I've seen that. Okay. Great. Thanks, Laith..

We are nearing the end of today's conference. We will go to Marshall Carver of Heikkinen Energy for our final question..

Yes. Thank you. Most my questions were answered, but I do have one left. You had very good results in two of the initial extension wells in North Louisiana.

With the higher net pay in the extension areas in multiple zones, do you think those first couple wells targeted the best possible zone? Or do you see any room for improvement there in terms of targeting now that you've been looking at it a little bit longer?.

That's a great question, Marshall, and back to – what we said is those wells, really they're east and west of Vernon. They're more like Vernon, so you've got instead of just Terryville, you've got one Upper Red; down there you've got three Upper Reds. In Terryville you've got one Lower Red; there you've got three Lower Reds.

And all these laterals are just in one of the six zones. Did we pick the optimum zone? Did we optimally drill and complete it? And actually – I mean, you can go on and on. That's why there's tremendous upside. We're excited about the 400 Bcf per section, the high pressure, the thicker interval.

And which of those six laterals is best ultimately that we developed – who knows? Four of six or five of six or two of six? So there's a lot of upside and a lot of potential there, so it gives us optionality. We just want to be very thoughtful how to go forward.

Like Ray said – he talked about all the types of data we're gathering to help understand that..

All right.

And the next wells will be likely the second half of this year?.

Yeah, I think before we can talk about any results that are meaningful, I think, yeah, we're looking later this year.

Like I said, we're in various stages of drilling pilot holes and thinking – I think we've got one lateral that's ready to be completed, but we're waiting on a lot of the rock data and the stuff back from the cores and valuations of all the logs that we've run to figure out and design those ultimate completions and figure out the best fluids for it and that sort of thing.

Like Jeff said, there's just a ton of work to do, and with all the great success and our focus on Terryville, we're able to basically take our time and make some real data-driven decisions going into this extension area..

All right. Sounds good. Thank you very much..

You bet..

Thank you..

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

Thanks, 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 now disconnect at this time..