Good morning, gentlemen, welcome to the Murphy Oil Corporation second quarter 2018 earnings call and webcast conference call. If at any time during the call you require immediate assistance, please press star zero for the operator. I would now like to turn the conference over to Kelly Whitley, Vice President, Investor Relations and Communications. Please go ahead.
Thanks, Pamela. Good morning, everyone, thank you for joining us on our call today. With me are Roger Jenkins, President and Chief Executive Officer, and David Looney, Executive Vice President and Chief Financial Officer. Please refer to the informational slides we have placed on the investor relations section of our website as you follow along with our webcast today. Please keep in mind that some of the comments made during this call will be considered forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995. As such, no assurances can be given that these events will occur or that the projections will be attained. A variety of factors exist that may cause actual results to differ. For further discussion of risk factors, see Murphy's 2017 annual report on Form 10-K on file with the SEC.
Murphy takes no duty to publicly update or revise any forward-looking statements. I will now turn the call over to Roger Jenkins.
Good morning, Kelly. Good morning, everyone, thank you for listening to our call today. Our second quarter results clearly validate the strength of our diversified portfolio as robust production from our oil-weighted onshore and offshore plays continue to drive high margin realizations. This enables us to return 13% of operating cash flow to our shareholders through our long-standing dividend policy. We also have achieved an annualized EBITDA for capital employed of 20%. Our adjusted net income was $63 million, and we maintained our balance sheet strength. Production for the second quarter averaged 171,000 barrels equivalent per day at 59% liquids. Production exceeded the high end of guidance by 2,000 barrels of oil equivalent per day. This beat was driven by outperformance in our onshore Canada and Gulf of Mexico assets, with liquids production accounting for 50% of this beat.
As we look to the strengthening of our portfolio, we achieved exploration success at our Samurai-2 well in the Gulf of Mexico. In our onshore business, we're able to show continuous improvements in cost reductions by achieving our drilling and completion cost goals in the Kaybob Duvernay of $6.5 million per well, which is well ahead of our target date. In the second quarter, on slide four, we continued to successfully execute our focus strategy. We've returned to offshore exploration with successful Samurai-2 well just mentioned. In Vietnam, we've worked with our partner to assume operatorship of the 15-105 block, which shows existing LDV discovery and will increase our working interest there to 40%. Our teams delivered excellent operational performance in the second quarter, and the Gulf of Mexico production exceeded guidance by some 1,700 barrels equivalent per day, driven by better performance and uptime.
The Kaybob Duvernay continues to exceed our expectations, with production increases by more than 100% year-over-year, while simultaneously achieving record low drilling and completion costs. During the second quarter, we benefited from the strength of our diversified portfolio, achieving high margin realizations with a weighted average of $68 per barrel of oil sold. Slide five. Over the first half of the year, we delivered strong EBITDA for BOE from three core areas. These areas receive premium pricing, which is the key of our high margin generation and account for 70% of our production and 70% of our capital. First, in Malaysia, achieved an EBITDA of over $36 per BOE. Second, North America offshore, EBITDA of $39 per BOE. Thirdly, Eagle Ford Shale achieved an EBITDA of $38 per BOE. These assets have a four-year CAGR of 7% production growth as per disclosed long-range production plan.
On slide six now. We're increasing our full year CapEx guidance by $65 million to $1.18 billion. We're allocating $55 million to onshore Canada, primarily in Kaybob Duvernay, for additional wells and required infrastructure. We plan to bring the additional wells online later this year. The remaining $10 million for the deepening and successful logging program of our Samurai-2 well in the Gulf of Mexico. Production for the third quarter is expected to be in the range of 165.5 thousand-168.5 thousand barrels equivalent per day. Third quarter production is lower than second quarter due to the annual turnaround of our non-operated offshore Canada fields and to executing operated capital projects in Malaysia, accounting for some 7,400 barrels equivalent per day. The decrease will be partially offset by onshore production growth in the Eagle Ford Shale and Kaybob of 3,900 barrels equivalent per day.
Because of our strong production first half of 2018, we're also increasing the midpoint of our full year guidance by 1,000 barrels equivalent per day to a range of 168.5 thousand-170.5 thousand barrels equivalent per day. I'll now turn the call over to our CFO, David Looney, who will give a financial update for us this morning.
Thank you, Roger, and good morning. We're now on slide seven. Consolidated results in the second quarter of 2018 included net income of $46 million, or $0.26 per diluted share, compared to a loss of $17 million, or $0.10 per diluted share in the same quarter one year ago. Our adjusted net income was a profit of $63 million, or $0.36 per diluted share in the second quarter 2018 versus a loss of $19 million in the comparable quarter last year. The adjusted income varies from our net income, primarily due to a $10 million after-tax mark-to-market loss on open crude oil hedge contracts and foreign exchange losses of $7 million after tax. At June 30th, 2018, Murphy's total debt amounted to $2.8 billion, excluding capital leases, or 38% of total capital, while net debt amounted to slightly less than 30% of capital at $1.9 billion.
As of June 30th, we had no outstanding borrowings under our $1.1 billion revolving credit facility. Worldwide cash and invested cash balances totaled $900 million at quarter end. In keeping with our stated goal of living within cash flow, slide eight is a snapshot of our six-month cash flow statement presented on a GAAP basis and displays how certain one-off items negatively impacted us during this period. Primarily two things. Number one, the $35 million withholding tax on funds repatriated from Canada earlier this year. Number two, an inordinate amount of 2017 CapEx being paid in 2018 led to a greater than expected reduction in our cash balances at June 30th.
As we begin the second half of the year with $900 million in cash on our balance sheet, we expect that we will rebuild a good portion of this first half deficit over the remainder of the year, given current pricing, production, and CapEx mechanics. With that, I'll turn it over to Roger to review the company's operations.
Let's move to slide 10. During the quarter, we brought 26 wells online in the Eagle Ford Shale, 10 in Karnes, 10 in Catarina, and six in the Tilden area. In the second half of 2018, we plan to bring an additional 13 operated wells, all in Catarina, for a total of 45 operated wells online this year. 10-well pad in Karnes at an average IP 30 of 1,750 barrel oil equivalent per day. Seven of these wells produced at the highest peak rates that Murphy's ever achieved in the Karnes to date. The 24-hour peak rate for the Lower Eagle Ford Shale was some 2,300 barrels of oil per day, not BOE. While the average 24-hour peak rate for the Upper Eagle Ford Shale was some 1,800 barrels of oil per day, again, not BOE.
We have over 240 remaining locations in the Karnes area, including the Upper and Lower Eagle Ford Shale, plus our very successful Austin Chalk formation. We're also pleased with the encouraged results from staggered lateral tests in Catarina, as well as recent IP 30 improvements in the Tilden area. Our team also continues to lower drilling and completion costs, as well as operating expenses in this play. On slide 11. In the Tupper-Montney, we brought a five-well pad online during the quarter. We continue to be impressed with the outstanding well performance in the play, with these wells producing in line of our 18 Bcf type curve. In the second quarter, our realizations in Tupper-Montney were CAD 1.84 per Mcf, compared to an average AECO price of CAD 1.19 per Mcf.
During the second quarter, we approved the Tupper expansion project, a long-term project at 200 million cubic feet per day of production, beginning in late 2020. The project is expected to increase reserves by more than 400 Bcf. The expansion has strong economics, with full-cycle break-even prices of CAD 1.75 AECO per Mcf. Our assumptions are based on a very conservative AECO price of CAD 2 in 2020, with modest price increases to slightly above CAD 3 in 2030. Together, if these assumptions, our new tariff, and outstanding execution are able to deliver an income-producing long-term project expected to generate approximately $125 million of free cash flow per year every year going forward. This project, under this set of assumptions, has an NPV10 of over $600 million with an IRR of over 25%.
In our Kaybob area on slide 12, we brought a four-well pad on at the 03-33 online at Kaybob West late in the second quarter. The wells are currently producing with initial rate approaching 800 barrels equivalent per day at 80% liquids. We're allocating $50 million of additional capital to the Kaybob due to outstanding execution and production results and achieving lower end drilling completion costs well ahead of schedule. We now plan to drill and complete 25 wells and bring a total of 27 wells online during the year. With this plan, we're on track to deliver a fourth-quarter exit rate of more than 11,000 barrels equivalent per day. We continue to reduce the remaining drilling carry, which will be completed by the end of next year. Slide 13.
In our Kaybob Duvernay asset, we increased production by 35% from last quarter and more than 100% from second quarter of 2017. Since assuming operatorship of this asset two years ago, we've increased production by approximately 500%. At the same time we've been growing production, we've been significantly reducing drilling and completion costs. Early in the year, we laid out an aggressive well cost target to reach $6.5 million development costs by end of year 2019. I'm pleased to say that we met that target in the second quarter this year, which is more than one year ahead of plan. We also drilled an industry-leading pace setter well and completed for only $5.9 million. We expect costs to continue decreasing as we move the asset further into development mode. Slide 14. In the Gulf of Mexico, we finished a recompletion of a Juliet-5 well during the quarter.
The recompletion improved the producibility of a new zone in that field. In Malaysia, assets continue to be a reliable, free cash flow generating business. Our [inaudible] Gas project is now approximately 95% complete, and we expect to bring it online in the third quarter. At South Acis Field, we've mobilized a jackup rig for some in-field drilling campaign, and our Block H Rotan floating LNG project remains on track with first production in 2020. In Vietnam, it's expected we receive full approval to assume operatorship and increase our working interest to 40% in the Block 15-105 well. Our development team continues to progress the field development plan for the LDV field, and we expect to declare commerciality by year-end. Slide 15. Returning to successful exploration. As we previously discussed, Murphy implemented a new focused exploration strategy.
I'm very pleased that the first well drilled on this new strategy, the Samurai-2 appraisal well, is a success. As expected, we encountered thicker and better quality sand in the well than the original Samurai-1 well. So far, we've encountered more than 150 feet of pay, which is primarily from two zones and have sampled high-quality oil from each. We've also encountered additional pay zones that were not present in Samurai-1 well. As a result, we extended the planned total depth of the well to over 32,000 feet and are currently logging deeper interval. Along with our partner, we are currently evaluating options to drill a sidetrack into the adjacent block to the south to further appraise this discovery. We have exceeded our pre-drill resource estimates of 75 million barrel equivalent. However, we could see upside if the planned sidetrack, as well as current evaluation, proves successful. Slide 16.
For the remainder of 2018, we have an exciting exploration program with three exploration wells. We expect to spud the Gulf of Mexico King Cake well late in the third quarter and the Vietnam LDT and Mexico Block K wells in the fourth quarter. Success at one of these wells will be very meaningful to our company. Slide 17. Finally, I would like to leave you with a few points this morning. Our second quarter results demonstrate the advantage and strength of our diversified portfolio, allowing us to increase our full year production guidance for second consecutive year. Quarter, I'd rather say. In our offshore business, we successfully returned to exploration with the Samurai-2 well. While in our onshore business, we achieved record low drilling and completion costs in the Eagle Ford Shale and Kaybob Duvernay.
In keeping with our long-standing focus on shareholder returns, we once again paid a competitive dividend to our shareholders while achieving our goals on cash returns over invested capital. Looking ahead to our long-term plan, our production remains on track to deliver 10%-15% CAGR over the next four years while spending within cash flow. Lastly, I'd like to thank our people who successfully execute our strategy every day for us here at Murphy Oil. That's all my comments today, and we'd like to now take your questions at this time. Thank you.
Thank you. Ladies and gentlemen, we will now begin the question and answer session. Should you have a question, please press the star followed by one on your touch tone phone. You will hear a three-tone prompt acknowledging your request, and your question will be pulled in the order they are received. Should you wish to decline from the pulling process, please press star followed by two. If you're using a speakerphone, please lift the handset before pressing any key. One moment for your first question.
Hello? Roger, is that you?
I'm sorry, I didn't hear anything. Yeah, Roger here. Good morning. Strange price action off the quarter, but I thought your results were good, and the guidance was certainly favorable. Can you walk us through?
Yeah, Roger. You're exactly right.
Can you walk us through how you're looking at the Gulf of Mexico exploration? I'm just curious, the Kosmos transaction announced earlier this week, did you look at it, or is that the type of thing you might be interested in? Maybe a quick compare and contrast to doing a transaction like that versus the farm-in s that appear so far have been pretty favorable.
We really don't discuss ins and outs of business development too much, you can safely say that any significant cash flow accretive, very good EBITDA multiple asset in the Gulf of Mexico that Murphy's involved in looking at those as best we can because we feel that's the best way for us going forward with all the value we can add with our operating ability and our long-term history working in the Gulf of Mexico. In general, the Gulf of Mexico for us is really building up nicely. We're working with a new group of an exploration shop to deliver prospects to us, which we're drilling next to King Cake. We had this asset for a very long time, Samurai. We had to refigure all of our partners.
When we talk about our exploration strategy, it's changed so much and so different now that we just get people to recognize that. For example, we changed out all the partners in Samurai and brought in the new experience holder in the area that has great success and great acreage position in the area. That's what we call working with better partners. Our next well at King Cake has involved a successful exploration shop that has over 78% success. Through that, they're looking at the southwestern part of the Gulf, and our teams are looking at the northeastern parts of the Gulf. Building a nice portfolio to drill two or three wells there every year. They range in size from tieback on everything to tieback plus facilities if they're larger.
They're building a very nice position and tying that in and managing that with the same team in Houston and our Mexico Block 5, one of the most prolific blocks, probably some of the nicest prospects I've seen in my career. We have the Brazil upside in that same hemisphere. A lot of positivity, positive action in the Gulf for us and momentum building in the Gulf, and we're very pleased with our Gulf of Mexico business.
Appreciate that. Maybe just taking a quick look at the Eagle Ford Shale. You mentioned, if I wrote the number down correctly, 248 well locations. I'm not sure if I got that right as we go through everything pretty quickly. Can you give us an idea Sorry?
That's just Karnes, Roger. I think it's 240.
Okay. Sorry about that. 240 in Karnes. You mentioned also the Austin Chalk. Can you give us an idea of maybe how that's evolved over the last several, at least quarters, if not years? Maybe an idea of, we hear from a number of the companies, the core keeps expanding, how your core in Karnes County and some of the other parts has maybe expanded as you've delivered obviously record wells this quarter and continue to prosecute on that.
We're doing very well. I think all of our acreage is prolific there. Our best well ever is an Austin Chalk well there, and we have some 50 something locations remaining, which we're very happy about. It's just a matter of getting to them and staggered completions with that, with the Upper Eagle Ford and Lower Eagle Ford, and how best to minimize offset frack impacts, how best to drill a wine rack type design, which we're all over right now. All of our pads today are, even in Catarina and Karnes, are both drilling lower and Upper Eagle Ford Shale with great success and just right to the curves that we have. I don't know about the core expanding. We think of all our acreage as core, and I think it's pretty clear where our acreage is located, it's core.
It's also a real misnomer that I have about two locations left there, which I think some people believe. I have hundreds left, and it's getting better all the time, down spacing all the time, and it's a great part for us to work in there. Other areas are working, too. Our Catarina and the oil-weighted area is very successful. Our Kaybob Duvernay area is really coming on with lots of issues around staying in zone better, designing wells better, drilling longer laterals, more completion, and positive moves there. All in all, it's a very good business and going to continue to be one for us for a long time.
All right. Thank you.
Thank you.
Your next question comes from Paul Cheng with Barclays. Please go ahead.
Hey, guys.
Good morning, Paul. How you doing?
Doing very good. Hey, Roger, when you talk about the 240 in claims, if I'm looking at your presentation on page 29, it seems like it's 325. Is that just the difference between the gross well and the net well for the working interest?
I would say so, Paul. Yes.
All right. That, you haven't talked anything about the Permian wells that you drilled early in the year. Are those wells that being tied in, or that you are still doing what that means? Is there any update that you can give us?
Paul, we drilled 2 wells there that worked out to our expectation there, and we have been really hard. With capital allocation like it is, we had some capital there, but with a $20 advantage price over Permian to Eagle Ford, we felt like that, through earlier part of the year, we moved some money down there, and it's involved in the capital that we have today. Today in the press, you might have seen that one of the companies, FANG, has purchased acreage there, which touches our acreage that we purchased and lease sale there as 2 years ago. Now we have to reevaluate that, and they paid a lot of money for that acreage right next to where we work.
This year, we were focusing our capital on Eagle Ford due to the incredible price advantages that we have there over the Permian. That's the situation. I find it incredible that we ask a question about 2 wells in Permian when we have a significant discovery in the Gulf of Mexico, Paul, but that's your question.
Yeah.
That's your deal.
We still want to get an update on Mexico. You're going to drill one well in the fourth quarter, and for the next year, in total, how many well you're going to drill in Mexico, or that is the only well?
That is the only well planned at present. We have many prospects there. We have many amplitude-aided prospects with direct hydrocarbon indicators around our first well, and we have some very nice subsalt prospects there as well. We'll be drilling additional wells there in the future, but we need to get our first well in and to get that executed. I'm sure we'll base on that success. We're hoping for that success, and I believe it will be successful. We'll be looking at other wells to drill there.
How about you in Brazil? Any current plan has been formulated?
We are taking seismic there with our partner group. I think we're over 65% with the seismic across all the blocks and a very large seismic acquisition. My big partner there doesn't like me to talk about it. We're very proud of it. It's a great position for us, and we'll be disclosing those plans at a later time.
We assume that any drilling is probably 2020 or 2021, given that you guys-
That's a safe assumption on that, Paul.
Okay. A final one, I know it's early on. 2019 CapEx versus 2018, should we assume to be up somewhat or a lot more or flat? Any kind of direction that you can give?
What was the question about 2019, Paul? What was your-
2019 CapEx outlook versus 2018. Is it going by last year?
You know, Paul, your conference hasn't even come yet. We haven't even got football season going, real football. It's going to be in the one, two range probably, Paul, I don't know. We're standing by our long-range plan, which is about that number. I don't see it to be significantly different from that. We'll be disclosing that in January.
There's nothing in our long-range plan that I don't see that won't be the same or positive at this time.
All right. Thank you.
Your next question comes from Arun Jayaram, J.P. Morgan. Please go ahead.
Arun, how are you doing this morning?
I'm doing well, sir. Roger, I'm wondering if you could spend a little bit more time on Samurai, on page 15 of the slide deck. It looks like the areal extent could extend into block 476. I was just wondering if you could give us your thinking about the sidetrack and down the road potential development options for the discovery.
Well, thank you for asking. No one's asked about it yet. We appreciate at least someone focusing on it, Arun. Yes, you can see all the green dots, and it's quite clear there could be a very large structure here. We're very happy with the results we have. We have a commercial discovery today with what we found, and have many flowback options. We are contemplating and planning a sidetrack with our partner. It's a matter of the displacement. We're actually involved with some logging now that could pick what's the best depth and azimuth to drill that. It's highly likely that the sands do thicken in the 476 block that we feel good about, so do our partner. I would be surprised if we didn't do a sidetrack here. There is a possibility of larger accumulations.
We laid out originally a 75 million barrel mean with an upside to 200. 200 is quite a big number, it's not out of the question with what we have. We're very pleased with 75 million barrels. I can tell you that your NAV estimate in your report for that on a per share basis is probably about what we lost today. Yes, you're spot on with that share price improvement. It's a nice discovery, super economic discovery, great full-cycle returns, and low F&D costs with just what we have today. We're very excited about it.
Yeah. Roger, I don't know if you could just walk us through what are potential development options. I know a Front Runner is somewhat in the area. Talk us through, what could, in timing, and what you're thinking about for development options here.
Well, what we're seeing, we're highly likely to have to drill another appraisal well because we've been successful, and a lot of these small tiebacks are just drill one zone and bring them back. Probably have to drill a well, finishing a year from now. Of course, we'll have to work with our partners on all that. Then if we sanction at that time, we could have an early production two-well system flowing in 2021, mid to third quarter 2021, something to that effect. The Christmas trees for something like this takes 18 months. If we're able to have continued success and want to buy some long lead items early, we could move that forward a bit, I suppose. Again, we have to work with our partners on that. We would probably be going back to There are three different host facilities.
We have one of our own. Our partner has one, of course, and some nearby. A new facility being built by some other folks, there'll be a lot of options for tiebacks. It would be that type, and it could turn into a facility here, until we get a lot more information and get ahead of this mean number where we are, we're just talking tieback game here. All these are very creative and very income providing and great F&D metrics for our company.
Great. Roger, you did increase your capital allocation, I think, to Kaybob. What's your current thinking about that play, and thoughts on how active you could be here in 2019?
Well, I was told when I was a young man, if you're getting paid, to keep drilling. That's what we do at Samurai, and that's what we do there. It's going very well. This is part of a long-term business that we bought there. We bought this at the total collapse in February of 2016. At that time, this involved a very low amount of money, and you have to go back up to what the goal was. The goal was there was to replace the production from Syncrude at lower operating expenses as an operator and lower total cost between DD&A plus OpEx. At the end of the year, we will have done that with the Placid asset plus us. We accomplished all of our goals, hitting all of our targets.
In that deal, with the low amount of money paid up front, was a carry that we needed to drill wells in certain locations over a certain period of time. It had a cost, a price, oil price index associated with that allowed that carry to be spent all the way to 2020. Oil prices are great higher, requiring the capital carry to be spent between now and the end of 2019. We're just executing that original purchase We held the money out of CapEx until the team showed further ability to execute. The team executed all the way through. We have this carry, we're very successful, we put capital in to get this carry behind us, and then put us in a situation of perfect capital allocation, if you will, between the Eagle Ford and that asset, and that's what we're working on.
That's why the capital is allocated to that.
Hi, Roger. My final question is kind of a housekeeping question. I was looking at your guidance for three Q. The pricing in Malaysia is a little bit light of our model, just given how it's tied to Brent, particularly at Sarawak. Could you just give us some color around that?
That all involves capital spending, timing, and liftings and loadings as per the capital for the quarter. We base this usually on these assets in Malaysia, usually about 375 to 425 positive over Brent. We work through the PSC. I still would say, even after all PSC effects, we're probably ahead of WTI. Kelly's giving me the number now. On a realized price basis, that as a quarter has to do with timing of capital spend projects and production that we're doing, and these things move around. I still think these realized prices are pretty good compared to a big hunk of the United States.
All right. Fair enough. Thanks, Roger.
Okay, thank you.
Ladies and gentlemen, as a reminder, should you have a question, please press star followed by one. Your next question comes from Mohammed Ghulam, Raymond James. Please go ahead.
Thanks for taking the question. Obrador won the election in Mexico recently, and before the election, he'd made several comments about his opposition to the country's energy reform. Since his victory, have you guys heard anything new from the government?
Well, we did receive an approval that we highlighted in our highlights today, and we continue to progress that along. I think in recent statements by this leader, he's now pulling back a lot of that rhetoric and saying he's positive about these energies. There's some 50-plus wells to be drilled there with enormous amount of capital to be spent in the country and personnel to be hired in various support of these vessels. It's our view that his latest statements have been recanting a lot of that and back supporting the leases that we have today. I'm not sure about where the future leases will be, but we have ours. We feel good about it.
We feel good about what we're hearing, and we're progressing through an approval process to drill, and we're moving full on with that and do not see anything in that election prevent that at this time.
In other words, you guys don't think his victory is really going to change your plans anyway, and you're pretty confident that the new government is going to respect the permit?
Yes, we are.
Okay. That's all for me. Thank you.
Okay. Thank you.
Your next question comes from David Meats, Morningstar. Please go ahead.
Hey, good morning. In response to an earlier question, you guys talked about low F&D costs for the potential development of Samurai, I was just wondering if you can put a range on what you consider low for F&D at this point.
Well, we placed in our original program of all of our exploration wells as a targeted F&D of $15. Even on an example of this, if the field is only $50, the F&D would be not even $15 a barrel. There's no outcomes here greater than $12 at this time. We feel that a bigger development would be around $1 billion growth, we feel that a smaller development would be around $500 million. The $15 F&D, which is outstanding, which means that the ultimate DD&A of the project would be $15, is good and industry-leading and as good as anything there is onshore, I can tell you. That's where we are. I'd say this would be in the $10-$15, with $15 at the ultimate top. That's industry-leading too.
Okay. That's super helpful color. In the, I guess, the exploration upside case where you have the development of Samurai or other discoveries like Samurai, is there any kind of scenario where that exploration success and the resulting development justifies going away from living within cash flows for a short period while you ramp up on the development?
I suppose that could happen. We have lots of capital allocation options and the different ways to execute these projects, where we may not own a facility if a facility is built and things of that nature. When things happen and things get sanctioned, you make decisions on capital allocation. We surely can afford it, that would just have to be with the timing at that particular time and how our other assets are performing. We're not going to hold this back if it's a very successful project that we believe we have at this time.
Okay. That's super helpful. Thanks a lot.
Thank you.
There are no further questions from our phone lines. I would now like to turn the call back over to Roger Jenkins for any closing remarks.
That's all we have today. Had a good quarter. Real happy with it. We'll be right back here next time, I think on Halloween day. Lowering costs, raising EBITDA, drilling successful wells, and hitting all our targets again. We appreciate people calling in today, and see you next time. Thank you.
Ladies and gentlemen, this concludes your conference call for today. We thank you for participating and ask that you please disconnect your lines.