SM Energy Company (SM) Q2 2016 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to the SM Energy Second Quarter 2016 Conference Call. At this time, all participants are in a listen-only mode. Later we will conduct a question-and-answer session, and instructions will follow at that time. As a reminder, this call is being recorded. I would now like to introduce your host for today's conference, Mr. David Copeland, General Counsel. You may begin, sir. David W. Copeland - Secretary, Executive VP & General Counsel: Thank you, Ranya. Good morning to all joining us by telephone and online for SM Energy Company's second quarter 2016 earnings conference call and operations update. Before we start, I'd like to advise you that we will be making forward-looking statements during this call about our plans, expectations and assumptions regarding our future performance. These statements involve risks that may cause our actual results to differ materially from the results expressed or implied in our forward-looking statements. For a discussion of these risks, you should refer to the cautionary information about forward-looking statements in our press release from yesterday afternoon, the presentation posted to our website for this call, and the Risk Factors section of our Form 10-K that was filed earlier this year and our Form 10-Q filed earlier this morning. c We will also discuss certain non-GAAP financial measures that we believe are useful in evaluating our performance. Reconciliation of those measures to the most directly comparable GAAP measures and other information about these non-GAAP metrics are described in our earnings press release from yesterday. Other company officials on the call this morning are Jay Ottoson, President and Chief Executive Officer; Wade Pursell, Executive Vice President and Chief Financial Officer; Herb Vogel, Executive Vice President-Operations; and Jennifer Samuels, Senior Director-Investor Relations. I'll now turn the call over to Jay. Javan D. Ottoson - President, Chief Executive Officer & Director: Thank you, David. Well, good morning and thank you to everybody for joining us on this call this morning. I just want to start today by saying that I have never been more proud of our people here at SM than I am today. If you've had the chance to read our press release, I think you already know that we had a great quarter relative to expectations. Our objective as a company is to deliver differential value for our shareholders through debt-adjusted per share growth and cash flows and add high quality drilling inventory over the long term. I think our results this last quarter demonstrate that we today are a company that is executing with real excellence on projects with high returns even at low product prices. In our second quarter, we beat expectations on every major controllable operating item and made better wells at lower cost in each of our major plays. Our capital spending is trending below planned for the year while we are increasing production guidance. And that result, coupled with higher-than-expected proceeds from our divestiture program, will further strengthen our balance sheet, improve our liquidity position and provides us with more flexibility and optionality going forward. Wade is going to review the quarter and our revised guidance for you. Then Herb is going to provide you with some operational information that I think is just fascinating. Then I'll wrap things up, and we'll take your questions. Wade? A. Wade Pursell - Chief Financial Officer & Executive Vice President: Thank you, Jay. Good morning, everyone. I'm very pleased to reiterate that we witnessed outstanding execution this quarter and it directly flowed through to our financial statements. I'm on slide 4, if you want to follow along. Production exceeded plan by about 1 million barrels of oil equivalent driven by outperforming wells in both the Eagle Ford and the Permian, demonstrating very strong sequential production growth in both of those areas. Operating costs came in lower than plan in every line item. Drilling completion costs continued to decline during the quarter while we continued to see faster drilling times driving lower-than-expected capital expenditures for our activity to-date. Financial results, including adjusted EBITDAX, adjusted EPS and operating cash flow all exceeded consensus estimates by double-digit percentages. And as a result, we've raised production guidance, lowered capital guidance, and lowered guidance for all operating costs. In summary, better wells, lower cost. So let's drill down on a couple of these points. You might have slides 4 and 5 in front of you as I go through these. Production came in ahead of plan, following particularly strong initial rates from six wells located in a high-gas NGL portion of the Eagle Ford, as well as completion of eight net wells in the Permian, all of which were good performers. Oil production came in right at the midpoint of guidance despite delays in the Williston Basin that pushed completions until late in the quarter. As a result, we've raised production guidance for the full year by about 2 million barrels of oil equivalent at the midpoint. Third quarter production guidance comes down slightly from the second quarter just because third quarter completions are more heavily weighted to oil versus higher volume gas wells. This should result in our oil percentage increasing to about 31%. LOE per BOE benefited from higher production rates as well as continued operating efficiencies. We expect LOE to increase in the second half of 2016 where we have higher workover activity in the plan, as well as we expect a normalized ad valorem expense. It was a true-up in the second quarter that could potentially reverse in the third quarter. Full-year LOE guidance, which includes ad valorem, is reduced to $3.90 to $4.30 per BOE, down $0.20 at the midpoint. G&A continues to come down as we emphasize cost savings across departments and at all levels of the company, as well as continuing to hold on new hiring. G&A guidance for the full year is reduced by about $5 million at the midpoint. Regards to commodity price differentials, we saw improvement in liquids differentials from the first quarter, while second quarter natural gas differentials came in wider, a few points for forward modeling in those areas. The oil differential was narrowed mostly due to regional pricing in the Rockies. About 50% plus of oil production is from the Rockies where the impact of the Canadian wildfires supported higher Bakken prices. For the second half of 2016, we see the Rockies differential returning to the $7 range versus WTI. Eagle Ford oil differentials improved slightly from the first quarter. For modeling going forward, we use about $11 to $12 off of LLS. Conversely, company-wide natural gas realizations were dragged down by about $0.10 due to Rockies production, where too much regional supply and high-cost contracts are pushing realizations to sub-$1. You should know Rockies only accounts for about 7% of our gas production. On the NGLs, we continue to suggest that you model a realized price in the range of 80% of Mt. Belvieu. We continue to reject ethane, where allowed, as rising natural gas prices have kept the economics of ethane recovery in check. Also, we added some hedges during the quarter. You can see the summary on slide 6. These include 2017 oil collars, 2017/early 2018 natural gas swaps, and some 2017/2018 propane swaps. All the details are in the appendix of the slide deck. Capital expenditures of about $168 million came in significantly lower than planned. As a result, we reduced CapEx guidance for the year by about $35 million. Savings were realized due to faster drill and complete time and lower vendor costs than planned. Net-net, we're very pleased to report significant production growth for the quarter within cash flow. Year-to-date adjusted EBITDAX of $399.4 million exceeds capital expenditures of $373 million. For the second half of 2016, we've got about $300 million in planned capital activity, which depending upon quantity prices should be aligned with operating cash flow. This scenario positions us very well as we move into 2017. In addition, as announced Monday, our asset divestiture process is going very well. We have two asset packages under purchase and sale agreements for total expected proceeds of $172.5 million. Just to repeat some of the key data points on this, closing dates are at the end of the third quarter, total production from these assets based on second quarter production was 3,300 Boe per day, associated proved reserves as of year-end 2015 are 9.5 million Boe. One package was predominantly water flood assets in New Mexico and the second producing assets in North Dakota and Montana. The North Dakota piece does not include acreage in our Raven/Bear Den or Divide County assets. This package was actually divided up and the Powder River Basin portion is still in the sales process. Bottom-line on all of this, early alignment of capital expenditures and cash flow, combined with asset sales proceed well in excess of our PDP expectations set forth in February, sets us up very well. It might beg the question whether we will ramp activity. Our philosophy and strategy are unchanged from last quarter's discussion. Liquidity and coverage remain priorities. We expect – at this point, we expect to apply divestiture proceeds to reduce any balance on our credit facility. I'll now turn the call over to Herb Vogel, who will provide more operations detail behind our solid performance. Herb?

Thank you, Wade. Just to reiterate, outstanding execution grows bottom line results. Well performance drove production in the quarter, specifically from the Permian and the Eagle Ford, which I will talk about in a minute. And our efforts to realize efficiencies both on the capital side and operations side led to the lower second quarter costs and the ability at the lower guidance for both LOE and capital spend going forward. So on managing operating costs in F&D there are key goals and incentives for our employees in 2016. On the operating cost side, we have been successful through several initiatives. First, we are rebidding nearly all activity down the chain and across the portfolio very frequently. Second, we are fully utilizing costs and revenue data now accessible as the result of last year's new ERP system implementation. Through Big Data management, utilizing nearly real-time data available through this new system and modern digitalization program, we now have the ability to quickly identify cost drivers and can prioritize those areas where we can have the most impact. Specifically, nearly in real time we can now attribute costs and net back revenues from every barrel of oil and Mcf of gas to individual wells and assess the cash flow from individual wells. On a very frequent basis, we can now recognize any well that isn't profitable, understand why, quickly address the issue, and optimize our cash flows down to the well level. We have all hands on deck from the IT department through every part of the organization to get this system in place, and now we are seeing dividends that we hadn't originally anticipated. Third, we are looking at systemic improvements, and I'll just give a few examples. Managing our produced water, which is a key contributor to drive LOE more effectively, for example, in the Permian using produced water in our fracturing operations rather than paying for disposal; and optimizing our artificial lift to yield better runtimes and lower electric power generation costs, for example, in the Eagle Ford by changing from rod pumps to plunge and lift; and evaluating chemical treatments for effectiveness in optimizing the supplier and costs. All this and many more are delivering bottom line systemic and sustainable LOE reductions across the company. Switching gears now, given our increased production guidance and decreased CapEx guidance for the year, I'm going to spend some time elaborating on the drivers behind that production outperformance and lower CapEx year-to-date. That is why we are getting better wells at lower costs. Turning to slide 8, great reservoirs and great assets keep surprising the upside, and Sweetie Peck is no exception to that rule. Our new completion designs and landing zone optimization led to a 12% increase in our production expectations for the year from Sweetie Peck. The 12 new wells we completed so far this year are exceeding expectations and enabling further completion enhancements. And turning to slide 9, just briefly, you can see that others are starting to recognize that Sweetie Peck is truly a Tier 1 oily asset and that we are delivering wells that are some of the best in the Midland Basin. Turning to slide 10, new at Sweetie Peck since last quarter is further improvement in our operational performance. During the second quarter, we reduced the number of days from spud to total depth for 7,600-foot laterals from almost 19 days in the first quarter to under 14 days in the second quarter. And that's best-in-class in the basin. That's translated into lower CapEx per well, as shown in the figure on the right, down to $5 million to drill, complete, and equip for the last six we've – wells we completed during the second quarter. We continue to see opportunity to drive better well performance by looking at tests we started implementing over two years ago. As shown in slide 11, we began to see significant benefits after about a half-year of production from tightening stage spacing of fracture stimulation from 200 feet to 167 feet. In the tests shown, after almost two years, we saw that the tighter stage spacing improved our cumulative production by 17%. While the data we can show is limited to one test for now, we just implemented this improvement in three new Lower Spraberry wells and expect that the increased costs of the additional completion stages will result in stronger production from these wells and yield even higher returns. In terms of increasing our undrilled inventory at Sweetie Peck, we were very encouraged by the Middle Spraberry that we completed earlier this year. While this well had a manufacturing defect in the steel casing that restricted us to flowing back only 11 of the 26 stages stimulated, we stopped production per lateral foot that was very similar to our successful Lower Spraberry program average as shown on slide 12. While early after 60 days, the cumulative production for the Middle Spraberry well was within 5% of the Lower Spraberry average, despite the temporary impact of a frac hit from an offset completion during this period followed by some issues with the artificial lift employed on that well more recently. The fundamental properties of Middle Spraberry production at Sweetie Peck are also encouraging. The 38 degree API well versus the 39.5 degree API well in the Lower Spraberry well tells us their sufficient thermal maturity to support very productive wells even at the shallower depth. The gas-oil ratio is also sufficiently high to provide the reservoir energy to drive longer term performance. Each new interval we add at Sweetie Peck could add about 100 wells of 7,600-foot lateral lengths to our inventory, so this is significant. Obviously that number goes up if we drop 5,000-foot laterals and down if we go to 10,000-foot laterals. Summing up the Permian, at Sweetie Peck we have a Tier 1 oily asset where we continue to deliver better wells and lower costs that are best-in-basin. Our Permian Basin team has demonstrated the ability to deliver bottom line performance each quarter and to grow our inventory. So turning to slide 13 and the Bakken Three Forks now, during the second quarter we completed 17 new wells late in the quarter. Rain-related road closures in the Divide County area and installation of new steel assemblies in three of our new Raven/Bear Den completions delayed those completions until later in the quarter than we had planned. As a result, much of this new oily production will show up in the third quarter and beyond. Given early positive results on some tests of diverter technology and completions earlier this year, our standard completion design in the Divide County area now includes diverter technology. New wells CapEx in the Bakken continues to drop through efficiencies like pad drilling and market conditions. 4 of the 11 Divide County wells we have completed year-to-date were drilled, completed, and equipped for less than $3.9 million each. Overall, we have an excellent, contiguous and largely HBP asset in North Dakota. It's a great operating environment up there with new infrastructure in place and an SM team that is successfully driving performance and improving the rates of return on our investment in new wells in the Bakken and Three Forks. Now turning to the Eagle Ford in slide 14, I think it's important to convey a few specifics on why we overachieved on production in 2Q and are increasingly confident that our operated Eagle Ford is a top-tier gas and NGL asset, whose close proximity to the key gas and NGL markets provide further benefits of bottom line via stronger relative product cycle. So through our substantial and successful testing work over the past two to three years, we have increased confidence in our well placement designs. Our most recent wells in the gas and NGL areas are now staggered in the Lower and Upper Eagle Ford. We have spaced them at 625 feet within each of the Upper and Lower Eagle Ford or 312 feet between wells if you look from above from a map view perspective. Given early planning and our large leasehold position, we have been able to drill laterals that average around 8,000 feet long in these areas and that has driven really excellent capital efficiency. And then we have coupled the longer laterals with our higher sand loading of 2,000 pounds per foot of lateral to drive near-wellbore fracture complexity with our simulations to deliver very strong wells. We often get questions comparing well performance with others in the area, so another important point I will make about our production performance here is that we choke manage our wells. You might ask ,what is choke management? This means that as we start flowing back wells, we open the choke valve on the production line to sale more slowly to control and initially limit the pressure drawdown on the reservoir. There are three major bottom line benefits and several lesser benefits of restricting reservoir pressure drawdown through choke management of our wells. First, this is very capital-efficient. If we were to pull these wells – new wells hard to report really high initial production rates like high IP30s, we'd need to use more CapEx to install larger and more expensive production equipment to achieve high initial rates that would be followed by steep declines. Second, we have found that choke management enables our wells to stay on a very shallow decline, effectively a plateau in production for several months, much longer than we originally anticipated and probably an additional benefit of our higher sand loading and completion and complex near-wellbore fracture system. In fact, on slide 15, you can see that in two of our recent tests of staggered Upper and Lower Eagle Ford wells, we have maintained rates of around 9 million to 10 million cubic feet per day per well, that is per well, for extended periods of time. In the lower right figure, you can see that we maintained rates at an average of over 9 million cubic feet a day per well for over six months. And in the upper figure, with our latest six-well staggered completions in this area, also including diverter technology, we produced these wells for over three months with very limited declines. And then third, our most recent finding is that after two years of choke management, our wells actually achieved higher cumulative production than if we had pulled them hard to report high IPs and decline them from there. Since the majority of the value attributed to a well originates from the first two years of production, it's a real positive to the rate of return on our investment and, we would expect, leads to higher ultimate recoveries, too. Given the findings I just talked about, we looked extensively at public data from other Eagle Ford operators and what they were seeing in their results. We found that several operators choke manage like we do, while a few others open their chokes early and report some very impressive initial rates. In slide 16, you can see a comparison of the top 10 operators across the entire Eagle Ford trend as measured by the total number of wells completed since 2014, each with over 100 completions since then. The red bars indicate the peak rate reported, the highest month's production reported per 1,000 feet of lateral length as indicated on the scale on the right. The grey bars indicate the ratio of the first 24 months of production to that initial rate. As you can see with company F in particular, the very high initial rate does not translate into continued performance at lat level through two years. In fact, they exhibit more rapid production decline rates. We then did an additional analysis of the result of companies operating near us in the Southwestern portion of the Eagle Ford trend and in the gas-to-NGL area. As you can see in slide 17, our gas and NGL-focused wells that are all choke managed achieved the highest two-year cumulative production relative to initial month's production of all the nearby operators. So you might ask what does this all mean? What I just talked about really addresses the underlying drivers for our outperformance during 2Q in terms of gas and NGL production. In addition, the stronger initial production rates from our new completion designs, our new wells in the gas and NGL areas remain on production plateau longer and decline much more slowly than we had forecast. This is the bottom line being delivered from the better wells and lower costs that we have talked about at a well level. The improvements that are achieved through our newer completion designs are giving us stronger wells, and you can see that in the results. Now turning to slide 18, from a marketing perspective, we wanted to point out that our Eagle Ford position benefits from its location relatively close to Mt. Belvieu. Transportation and fractionation costs to get our NGLs to market are lower than from any other basin in the U.S. This slide shows the frac spread of NGLs in dollars per million BTU by basin in a $30- and $60-oil price environment. This data is provided by En*Vantage. As NGLs' prices rebound from their lows of late last year and early this year, we are poised very competitively as the largest net NGL producer in the Eagle Ford. All this leads to the excellent bottom line returns that we can achieve with $3 per Mcf gas and recent NGL pricing in the gas and NGL portion of our operated Eagle Ford position, as shown in slide 19. Note that the return shown in that slide assume a 6,500-foot lateral. The wells I showed you earlier have 8,000-foot laterals so the returns are even higher. In addition, our ability to stagger our Upper and Lower Eagle Ford completions in this area doubled our inventory relative to expectations just a couple of years ago. So wrapping up, we are very pleased to be positioned with topnotch Tier 1 oily assets in the Permian Basin at Sweetie Peck and top tier gas and NGL assets with our operated Eagle Ford position. Our continuous and relentless focus on improvements in completion designs and capital costs, that is better wells and lower costs, is progressively delivering improved bottom line financial performance quarter-to-quarter. And you could see that in our 2Q operational flow. Now back to Jay. Jay? Javan D. Ottoson - President, Chief Executive Officer & Director: Well, thanks, Herb. And just some really interesting stuff there. I want to just say how much I appreciate you mentioning the implementation of our new accounting and land systems, something we don't talk near enough about. But a project over the last several years that was very well-executed, very important to our future growth as a company, and now really having significant impacts on our bottom line results. In closing, I'd just like to emphasize again the across the board nature of our outperformance this last quarter. In particular, the balance between our cash flows and capital spending was significantly better than we had projected earlier this year, and our well performance was just outstanding. We'll continue to drive towards higher margins and give priority to our liquidity and ultimately to our debt-adjusted growth. I'm comfortable saying that in the $50 oil and $3 gas world, we clearly anticipate in 2017 that we can grow, while aligning our cash flows with CapEx, at a capital spend similar to this year's spend. Our vision is to be a premier operating company with top-tier assets, delivering differential performance for our shareholders. I'm just very encouraged by our recent performance and very enthusiastic about the future of the company. With that, I'll open the call up for Q&A.

Thank you. And our first question comes from the line of Kyle Rhodes from RBC Capital Markets. Your line is now open.

Hey, morning, guys. David W. Copeland - Secretary, Executive VP & General Counsel: Good morning.

Permian obviously delivered a great quarter here. I was hoping you could update us on expected completion counts there for 3Q and 4Q 2016 and how you see that production growth trajectory continuing for the back half of the year?

Okay. We're just sticking straight to plan. This is Herb. So there's really no change from what we've talked about for the year, around 40-some completions in the Eagle Ford, just over 50 in the Bakken, and about 20 to 24 in the Permian by the end of the year. So there's really no change in our plan. We're just plowing along on that.

Okay. Got it. And then maybe just touch on any downspacing pilots or delineation work in the Wolfcamp A or D that's maybe on the docket before year-end 2016 here?

So we've got – we're basically sticking to the program. We haven't made any changes. So in some cases we've tightened up the spacing, and as we get results from those wells we'll be sharing them. We don't have any new results to report on Wolfcamp A or any others, other than the individual wells we've talked about previously.

Got it. Is there – are there any plans for the back half of the year maybe, I guess I was trying to get at?

Yes. So we're basically just straight on the program where we plan to drill wells. We're really not making any change there.

Got it. Okay. I guess maybe just touching on service costs real quick, I know in some of the service earnings calls, we've heard some of the bigger providers saying pricing discounts are coming to an end here in short order. Just it sounds like you guys certainly didn't see that in 2Q. Just curious what you're seeing out there on a leading edge basis? And I'll leave it there. Thanks.

Okay. Yeah. I would say as we rebid activity and it's a little bit base end dependent, so in some areas we're still seeing, as we rebid work, that they're coming down. And in other areas, we see they're flat and not really changing much. And then there are some specific items where we see slight increases on some tangibles but they're relatively minor. It was really overall down for 2Q, and we've locked in stuff for 3Q. So we don't really see a change there. I hope that gives the color you're looking for.

Thanks, guys.

And our next question comes from the line of Kevin Smith from Raymond James. Your line is now open. Kevin C. Smith - Raymond James & Associates, Inc.: Hi. Good morning and congrats on a great quarter. Appreciate all the color on the Eagle Ford production. Clearly, the Galvan Ranch well results were very strong, but I'm just trying to make certain I understand. Was the production beat solely due to higher IP rates, or was there some combination of better IP rates, lower base decline, or possibly changing kind of your choke plans?

Okay. I think I'm following your question. So when we forecast production for a year, we have certain declines baked in. And as we're enhancing our completions, we don't have a real good ability to say exactly how well we will do. So we'll decline the wells away. Then when they come on really strong and they come on, we can see it with really high pressures, and then as we start producing those pressures decline less rapidly than they would have previously. And so we're able to open up the choke and the rate is maintained. And we found that we're getting five, six months type of plateau levels on our wells. So when we got into 2Q, we had those wells and those figures. Five of them started last year and then six of them started during the quarter. That's really where the overachievement came from. So it's not so much the base declines on the other wells, but it's not getting on decline as fast on wells that came on last year and the new ones this year. Kevin C. Smith - Raymond James & Associates, Inc.: Okay.

Does that makes sense? Kevin C. Smith - Raymond James & Associates, Inc.: Sorry. Go ahead.

Does that makes sense? Kevin C. Smith - Raymond James & Associates, Inc.: Yeah. So basically, if I'm correct or just to kind of restate what you said, it's just production hasn't declined from wells that you've put on over the last six months.

Yeah. Kevin C. Smith - Raymond James & Associates, Inc.: and less.

Through choke management. Right. Javan D. Ottoson - President, Chief Executive Officer & Director: And I'll just chime in there, too. I think it's important that as you look at the press release, we did experience some delays in the Bakken on the number of our completions which hurt us on our oil rate, but we offset that – basically got right back to our target, numbers on oil because our Permian wells have been outperforming so much, again, relative to our expectations. Kevin C. Smith - Raymond James & Associates, Inc.: Understood. And then lastly and I'll jump back in the queue, as you think about your second half drilling plans at Sweetie Peck, is there any plans to drill any more Middle Spraberry or is everything going to be focused on Lower Spraberry?

No. There's no more plans to drill the Middle Spraberry. We locked in our program which is really Wolfcamp B and Lower Spraberry-focused because we knew what those – what the expectations were for those and we – basically we're really working to optimize our programs. And that's why we're getting the cost reductions we're seeing, the capital reductions we're seeing. So no, we're not... Kevin C. Smith - Raymond James & Associates, Inc.: Okay.

... going to drill another middle Spraberry well this year. Kevin C. Smith - Raymond James & Associates, Inc.: Okay. Thank you. And once, again, great quarter. Javan D. Ottoson - President, Chief Executive Officer & Director: Thank you.

Thanks.

And our next question comes from the line of Chris Stevens from KeyBanc. Your line is now open.

Hey, good morning, guys. Great quarter. I just wanted to touch on M&A a little bit. What's the appetite at this point to go out there and maybe make an acquisition, and any thoughts on sort of size of what you'd be interested in looking at? And then if you could possibly comment on what your thoughts are on the valuation that we've seen, maybe out in the Permian, whether it's Delaware or Midland? Javan D. Ottoson - President, Chief Executive Officer & Director: Okay. That's a pretty broad question. This is Javan. In general, we're obviously very interested in continuing to improve the quality of our assets. The types of acquisitions we look at and are interested in are ones which will perform as well as or better than our best assets. And we look at every deal that comes up in our core areas. Certainly the Permian Basin is an area of great interest to us, and we look at everything that's come up. I appreciate the fact that when you look at the headline numbers on Permian deals they seem expensive, but I think a lot of the reason for that is that people are simply proving up more and more intervals there. If you actually look at it on a per-interval basis, I still think the numbers are not unreasonable. And we're continuing to look at those and I wouldn't be surprised at all. Certainly, we're going to focus on that. I don't know that there's a size limit that we necessarily look at there. There's a lot of creative ways to do these deals, and I think you have to keep your mind open a little bit to that as we move forward.

Okay. Understood. And I guess maybe if I could just kind of touch a little bit on the outlook here as we head into next year? Any sort of initial indication of what the rig count might look like between your core assets, and is there the potential for a third rig in the Permian at some point? Javan D. Ottoson - President, Chief Executive Officer & Director: We don't have a defined plan yet. As I said, I think at capital levels similar to this year, we believe that in a $50 and $3 world we can grow within our cash flows next year. We have several different scenarios we've looked at between the Eagle Ford and the Permian, moving rigs around that can get us to that. I don't have exact rig counts to give you yet.

Okay. Thanks a lot. Great quarter. Javan D. Ottoson - President, Chief Executive Officer & Director: Thank you.

And I'm not showing any further questions. I would now like to turn the call back to Mr. Jay Ottoson, President and CEO, for any further remarks. Javan D. Ottoson - President, Chief Executive Officer & Director: Well, I think it's clear everybody's out looking at inventory numbers right now, and I haven't seen them yet. I'll look forward to that. But thank you so much today for your questions and for your interest in our company, and we look forward to talking with you again next quarter. Thanks.

Ladies and gentlemen, thank you for participating in today's conference. This concludes today's program. You may all disconnect. Everyone have a wonderful day.