Range Resources Corporation
Q4 2016 Earnings Call Transcript

Published: 23 Feb 2017

[Operator:]

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.

[Laith Sando:]

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.

[Jeffrey L. Ventura:]

Thanks, Laith. Before I discuss what we'll see for 2017, let me briefly review some accomplishments and results from the fourth quarter and 2016. The fourth quarter was our best quarter of the year, not only from a cash flow perspective but also because it was the first full quarter with our North Louisiana assets. The office integration has gone very well, and the team is making great operational strides, some of which we'll discuss this morning. Our unhedged margins for the quarter were the highest that we've seen since 2014, as operating expense and interest per Mcfe declined substantially, and pricing differentials improved by selling more of our products to better markets. Our reserve report for year-end 2016 also had a number of highlights that speak to the depth and quality of our inventory. Our F&D costs, however you like to slice them, were very competitive, with drill bit costs of only $0.34 per Mcfe. In addition, our resource potential now stands at over 100 Tcfe, with thousands of locations, providing us a tremendous runway for future investment. Looking towards 2017 and 2018, we're excited about what's happening at Range, as we have the ability to generate significant growth while spending at or near cash flow on the back of improved pricing differentials and margins. As it relates to pricing, we're projecting significantly better netback pricing for all three of our products

[Ray N. Walker:]

Thanks, Jeff. Production for the fourth quarter came in at 1.854 Bcf equivalent per day, and for the year we grew production 11% over 2015, with our exit rate 16% higher than it was in 2015. Guidance for 2017 is 33% to 35% growth, which will put us at approximately 2.07 Bcf equivalent per day net for the year. Guidance for the first quarter will be set at 1.92 Bcf equivalent per day, with 30% to 32% liquids. For 2017, our CapEx budget is approximately $1.15 billion, split about two-thirds in the Marcellus and one-third in North Louisiana. As you're aware, a portion of this year's budget will serve to reverse the significant ramp down in spending over the past three years. So while generating solid growth for 2017, this year's capital program really contributes to production growth in 2018 by getting us back on a normal trajectory. This encompasses spending on things like pad construction, roads, water infrastructure, production facilities, top holes, and things that we term, quote, "generating completable, lateral footage," close quotes, where the production from these expenditures really occurs in 2018. Incredibly, if you look at our D&C budget of $1.07 billion for 2017, we're actually spending less than we did in 2012, 2013, and 2014 prior to the downturn, but our 2017 program is still generating impressive growth and setting us up for 20% growth in 2018, despite having a production base that is triple the size that it was in 2012. This is possible because of the efficiency gains we've seen from hydrating our assets and now going into a full development mode in the Marcellus. Our 2017 capital plan has us running approximately five rigs and two to three frac crews in Southwest Pennsylvania this year, and four rigs with up to three frac crews at a time in North Louisiana. Starting with the Marcellus, we continue to make great strides in unit cost reductions, and our capital efficiency continues to improve. I'd like to take a few minutes here and talk about some impressive examples. Looking at water logistics and sourcing, because we don't own a separate water MLP, we're 100% focused on reducing costs associated with water handling, and our shareholders receive 100% of that benefit. This has been a big area of improvement, not only improving LOE by 39% over the prior year, but also reducing our capital expenditures for water by over $30 million in 2016. We've reduced the average completion costs per foot of lateral by 14% year over year, while pumping a record number of stages in 2016 with less frac crews than we had in the prior year. Our top three pads completed in 2016 averaged over eight and a half stages a day for a total of 432 stages. The best pad achieved a completion cost per foot almost 23% below the average, which again was already 14% lower than the previous year. We achieved a 17% reduction in CapEx for production facilities, resulting in over $6 million in savings as a result of design improvements, reductions in contract labor and materials, and redeployment of existing equipment. On the drilling side, we've realized a 40% increase in lateral feet drilled per day as compared to last year. This results in a 27% reduction in average drilling costs per lateral foot compared to the prior year and our top 10 best days for lateral feet drilled in a day were all accomplished during the fourth quarter. In fact, just a couple of weeks back, we set a company record of over 6,100 feet drilled in a single day. The drilling and G&G teams accomplished all of this with zero sidetracks from 2016, illustrating that we're still improving and expect to continue to improve going forward. In Southwest Pennsylvania, our current plans have us drilling about a third of our wells on existing pads in 2017, and that number could increase to as much as half of our wells in 2018. Our average drilled lateral length in 2017 is projected to be well over 8,000 feet, and our expectation is that the 2018 average will be longer. For example, we're currently drilling the third of three wells on a pad that will average over 15,100 feet per well. What's important is that we have the ability to drill longer laterals, drill on existing pads with permits in hand and infrastructure in place. Let me call your attention to our updated economics cost and type curves in the presentation on the website. Please take a look at slide 10, which summarizes the data from all the Marcellus areas with activity in 2017. Again, we believe our cost and performance are the best in the southwest portion of the basin. I also want to point out that these are expected averages for the year and are inclusive of all the costs, including facilities, and factor in all the midstream expenses using actual realized prices. Our well costs include all expected increases in services and supplies that we see in 2017. As we go throughout the year, I believe our technical and operational team will continue to optimize the plan and continue to beat these averages, as they have year after year. A good example of how this happens is a seven-well pad that we just approved a few weeks back that is projected to average 10,079-foot laterals with 50 stage completions per well for an average cost including all the facilities of $6.3 million per well. Thus, on a normalized per thousand foot basis, the cost is estimated to be $625,000, yielding a projected EUR of over 3.5 Bcf per 1,000 foot per well – clearly much better than the expected average case. I would also like to highlight a wet area pad in Southwest Pennsylvania that we brought online during the fourth quarter. It was a four-well pad averaging 9,265-foot laterals completed with an average of 46 stages per well. The average peak 24-hour production rate to sales under constrained conditions was 35.1 million cubic feet equivalent per day per well. The seven-day average to sales, again under constrained conditions, was 28.4 million cubic feet equivalent per day per well. Importantly, on a normalized basis, the 30-day cumulative production of these wells is 30% higher than the average offset, with the new wells flowing at significantly higher and constrained flowing pressures. I believe this pad represents some of the upside we expect to see as we go back into our underdeveloped core areas with longer laterals. We literally have thousands of these opportunities going forward. Again, please refer to our earnings release, where we provide the expected number of wells by area with all the average cost, recoveries, and economics that we have in our current plan for 2017. Our team continues to investigate creative new technologies. For example, in April of 2016, the team successfully executed a three-well pad in our wet area with a new pinpoint stimulation technology. The idea is to get more uniform and consistent proppant placement on a cluster-by-cluster basis along the wellbore. Production of the three-well pad at year-end was on average 22% higher than that of the closest offsets. The cost of this initial test on a standalone basis was about 20% higher. However, we expect the costs to come down significantly as we do more of these completions. We're currently planning additional applications for 2017. Another example

[Roger S. Manny:]

Thank you, Ray. Continued financial progress was made in the fourth quarter to complement the operating progress Ray just mentioned. Financially, we turned the corner in the third quarter of this year, and the fourth quarter results show that we're gaining momentum as we further exit the down cycle. The fourth quarter results exhibit demonstrable improvement in top line revenue, cash flow, and cost control over earlier quarters in 2016 and over the fourth quarter of 2015. Revenues from natural gas, NGL, and oil sales, before hedging entries, was $459 million, 81% higher than the fourth quarter of last year. Cash flow at $254 million was 24% higher. EBITDAX at $299 million was also 24% higher than last year. Cash margin at $1.48 an Mcfe was 80% higher than the third quarter of this year. Fourth quarter earnings calculated using common analyst methodology, which excludes nonrecurring items, was $56 million, 33% higher than last year's fourth quarter. To help place the fourth quarter in perspective, cash flow in the fourth quarter was more than double the third quarter of this year and more than the first two quarters of this year combined. The last quarter where cash flow was higher than $254 million was two years ago, in the fourth quarter of 2014. These improvements from prior periods stem from continued margin gains from our new long-term takeaway capacity on Mariner East and the new Gulf Markets expansion project, combined with improvements in our cost structure, consistent organic growth, and completion of the Memorial transaction. Full-year 2016 cash flow was $569 million, and full-year EBITDAX was $723 million. These figures include only 15 weeks of results from North Louisiana. If one includes a full year of EBITDAX from the North Louisiana assets, as used when calculating a trailing four-quarter debt to EBITDAX leverage ratio, EBITDAX totals $1.033 billion. Fully diluted cash flow per share for the fourth quarter was $1.04 and for the full year was $2.99 per share. The DD&A rate is always reset during the fourth quarter of each year to reflect the results of our year-end reserve report. Our DD&A rate for the fourth quarter was $0.88 per Mcfe, down 9% from the fourth quarter of last year. Five years ago, in 2011, the DD&A rate was $1.80 per Mcfe. Reducing the DD&A rate by almost half over a relatively short period of time reflects the dramatic improvement in capital efficiency brought about from high-grading our asset base through the sale of non-core assets and further improving our processes as we develop our sizable position in the Marcellus. As for our cash operating expenses during the quarter, all items came in at or below fourth quarter guidance, except for G&A, coming in $0.02 high due to some nonrecurring land administration expenses. Another expense item impacted by nonrecurring activity was transportation, gathering, and compression expense, which at $0.96 was $0.08 below guidance. The major contributor to this cost improvement was a one-time cash payment associated with the extension of our MarkWest agreements. The extension provided an opportunity to settle the cumulative true-up items of both parties. To assist listeners with their financial projections, the fourth quarter earnings release contains detailed expense item guidance for the first quarter of 2017. Over on the balance sheet, things were quiet and stable following the closing of the Memorial transaction. Total debt was down slightly from end of the third quarter. And with cash flow building sequentially each quarter, we expect the leverage ratio has peaked and will begin to drift down as we move further into 2017 and 2018. Thanks to improving margins and our strongest-ever finding and development cost performance, our forward-looking recycle ratio, using either hedged or unhedged revenue, approaches 3 times, which demonstrates our ability to not only replace our production but also meaningfully grow within cash flow. The fourth quarter provided many opportunities to add to the Range 2017 and 2018 hedge positions. Significant volume increases were added to our hedge positions across all products. Currently, over 75% of our 2017 natural gas production is hedged, with an average floor price of $3.22 an MMbtu. Going forward, our hedging practices remain consistent

[Jeffrey L. Ventura:]

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

[Operator:]

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

[Arun Jayaram:]

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.

[Ray N. Walker:]

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.

[Jeffrey L. Ventura:]

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.

[Arun Jayaram:]

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.

[Chad L. Stephens:]

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.

[Arun Jayaram:]

Fair enough. Thank you, gentlemen.

[Jeffrey L. Ventura:]

Thank you.

[Operator:]

And the next question is from Pearce Hammond of Simmons.

[Pearce Hammond:]

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?

[Jeffrey L. Ventura:]

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.

[Pearce Hammond:]

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.?

[Chad L. Stephens:]

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.

[Pearce Hammond:]

Great.

[Ray N. Walker:]

Yeah, and I'll just tack onto that, Pearce. Chad said ME 2, but we're actually on ME 1, right?

[Chad L. Stephens:]

ME 1, yeah, sorry.

[Ray N. Walker:]

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.

[Pearce Hammond:]

Thanks, Ray.

[Operator:]

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

[Brian Singer:]

Thank you. Good morning.

[Jeffrey L. Ventura:]

Good morning.

[Brian Singer:]

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?

[Ray N. Walker:]

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.

[Brian Singer:]

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?

[Ray N. Walker:]

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.

[Brian Singer:]

Great. Thank you very much.

[Operator:]

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

[Ronald E. Mills:]

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?

[Jeffrey L. Ventura:]

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.

[Ronald E. Mills:]

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?

[Ray N. Walker:]

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.

[Jeffrey L. Ventura:]

Maybe flipped the other way, Ray.

[Ray N. Walker:]

Oh, did I say it wrong?

[Jeffrey L. Ventura:]

Yeah, you said it backwards.

[Ray N. Walker:]

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.

[Jeffrey L. Ventura:]

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

[Ray N. Walker:]

Right.

[Jeffrey L. Ventura:]

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.

[Ronald E. Mills:]

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

[Jeffrey L. Ventura:]

Thank you.

[Ray N. Walker:]

Thanks.

[Operator:]

And your next question is from Bob Morris of Citi.

[Robert S. Morris:]

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?

[Ray N. Walker:]

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.

[Robert S. Morris:]

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?

[Jeffrey L. Ventura:]

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

[Ray N. Walker:]

Yeah.

[Jeffrey L. Ventura:]

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

[Ray N. Walker:]

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

[Jeffrey L. Ventura:]

Yeah.

[Robert S. Morris:]

Okay. Great. Thank you.

[Operator:]

And the next question is from Neal Dingmann of SunTrust.

[Neal D. Dingmann:]

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?

[Ray N. Walker:]

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.

[Jeffrey L. Ventura:]

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.

[Neal D. Dingmann:]

Sure, sure. And then just lastly -

[Jeffrey L. Ventura:]

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

[Ray N. Walker:]

Yeah, we have 400,000 acres so -

[Jeffrey L. Ventura:]

Yeah, it's captured.

[Neal D. Dingmann:]

It's all HBP, Jeff?

[Jeffrey L. Ventura:]

Right.

[Ray N. Walker:]

Yes.

[Neal D. Dingmann:]

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?

[Laith Sando:]

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.

[Neal D. Dingmann:]

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

[Operator:]

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

[Marshall H. Carver:]

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?

[Jeffrey L. Ventura:]

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.

[Marshall H. Carver:]

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

[Ray N. Walker:]

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.

[Marshall H. Carver:]

All right. Sounds good. Thank you very much.

[Ray N. Walker:]

You bet.

[Jeffrey L. Ventura:]

Thank you.

[Operator:]

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.

[Jeffrey L. Ventura:]

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

[Operator:]

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