Talos Energy Inc. (TALO) Q2 2015 Earnings Report, Transcript and Summary

Good morning. My name is Shawn and I'll be your conference operator today. At this time, I'd like to welcome everyone to the Second Quarter 2015 Earnings Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session Thank you. Chairman, President and the CEO, Mr. David Welch, you may begin your conference. David H. Welch - Chairman, President & Chief Executive Officer: Okay. Thank you, Shawn, and welcome to our second quarter 2015 conference call. We're joined this morning by Ken Beer, our Executive Vice President and Chief Financial Officer. Ken will read the cautionary statement, review the financial performance for the quarter, he will then turn it back over to me to provide some additional color on our execution and an operational update in this low-priced environment. So, Ken, over to you.

All right. Thank you, Dave. In this conference call, we may make forward-looking statements within the meaning of the Securities Act of 1933 and Exchange Act of 1934. These forward-looking statements are subject to all the risks and uncertainties normally incident to the exploration, development, production, and sales of oil. We urge you to read our 2014 Annual Report on Form 10-K and the soon-to-be filed second quarter 10-Q for a discussion of the risks that could cause our actual results to differ materially from those that in any forward-looking statements, we may make today. And in addition, in this call, we may refer to financial measures that may be deemed non-GAAP financial measures as defined under the Exchange Act. Please refer to the press release we issued yesterday for a reconciliation of the differences between these measures, our financial measures and the most directly comparable GAAP financial measures. And with that, I will move on to our comments. We'll assume that everyone has seen the press release and the attached financials. Accordingly, I'll look to focus on some of the financial and operational highlights. Our second quarter results showed an adjusted $9 million loss or loss of about $0.17 per share before and after tax non-cash impairment charge of $144 million, which brought the reported loss to $153 million. Our discretionary cash flow for the quarter was about $85 million, or around $1.50 per share, which was above the First Call consensus of about $1.35 per share, driven primarily by greater-than-expected production and lower costs. As was also discussed in last quarter's conference call, the non-cash ceiling test impairment was primarily due to lower oil gas and NGL prices, which are calculated using a rolling 12-month trailing average. If prices continue to stay at the lower level compared to last year, we would be subject to another non-cash ceiling test impairment in the third quarter; again, no impact on cash flow, but a potential reported earnings impact. We also had about $45 million impairment to a potential resource play we tested in Canada over the past couple of years, which did not show enough positive results to continue the effort in Canada. We also recognized an upward working interest adjustment to a number of wells in our Mary field in Appalachia. A few potential partners did not elect to participate in several pads, which had been drilled and we had assumed their participation for accounting purposes. The largest adjustment was tied to leases that are having an ownership change late in 2014 and the new owner did not move forward with an election to participate alerting us in the second quarter. The volumes associated with the previous periods were approximately 18 million cubic feet equivalents per day. So production for the quarter, excluding the previous period adjustment, was about 46,000 barrel equivalents a day, or 274 million cubic feet equivalents per day, which is well above the upper-end of our second quarter guidance of 258 million cubic feet equivalents per day. Volumes for the Cardona #4 and #5 were above plan. The expected third party pipeline downtime affecting the Pompano volumes were minimized by the pipeline operator and our marketing group, shaving about 15 days off the expected downtime; and Appalachia was also above plan, flattish with the first quarter despite no well's been drilled. So a strong production in quarter from our base properties. Including the 18 million cubic feet equivalents in volumes up in Appalachia from the previous quarter's working interest adjustment reported quarterly production came in at 292 million cubic feet equivalents per day. (05:09) production from the oily Cardona wells liquids still totaled to about 53% of our second quarter volumes with gas at 47% despite much of the Appalachian adjustment volumes being gassy. On the Cardona, #4 and #5 wells have remained stable at a combined 10,000 barrels per day gross equivalents. And the Cardona #6 could add another roughly 5,000 gross barrel equivalents per day by the fourth quarter of this year. And then, Cardona #7 could add yet another 5,000 barrel a day of equivalents by mid-2016. Stone has a 65% working interest in these Cardona wells. We also expect to have volumes from Amethyst coming online in the first quarter of 2016 and then production from the Pompano rig program adding volumes throughout next year. So we would expect deepwater Gulf of Mexico to continue to show high-margin production growth in 2016. It's important to highlight that the incremental production projected from Cardona #6, Amethyst, Cardona #7, and the Pompano rig program should come on at virtually 100% cash margin as there is minimal incremental LOE costs to the Pompano rig, or negative LOE when receiving a platform handling fee from our partner. We have focused on these development projects because they generate immediate positive free cash flow. In the second quarter, we averaged around 144 million equivalent per day in Appalachia, excluding the previous period adjustment, which was over our plan as we had minimal downtime and a full quarter of volumes from a pad that was brought online during the first quarter. And then, we had another 9 million or 10 million per day boost from the added working interest adjustment for the second quarter itself. We expect that Appalachian volumes to decline in the second half of the year as we don't expect to have any new wells drilled and completed in 2015. We do have 25 wells on three different pads, where we've drilled, but not completed the well, just waiting for improved margins and pricing. Overall, given the strong performance to-date from our deepwater Gulf of Mexico properties, our Appalachian volumes and the added working interest in Appalachia, we are increasing our 2015 production guidance from the previous 39,000 barrel equivalents per day to 43,000 barrel equivalents per day up to 42,000 barrel equivalents per day to 44,000 barrel equivalents per day. This is about a 15% increase over 2014 when you pro forma for the non-core shelf property sales of last year. We also provided guidance for the third quarter 2015 at about 39,000 Boe per day to 41,000 Boe per day, which carries some projected weather downtime and operational downtime in the quarter itself. Regarding pricing, our quarterly oil price realization before hedging was around $55 per barrel, which is down from the $100 per barrel from a year ago. Our oil hedges at around $92 pulled up our second quarter realized prices to just over $72 per barrel, but the oil price drop was obviously a significant hit to our revenue for the quarter. Our gas price realization, even after hedging, dipped to $2.14 per Mcf for the second quarter, with both weak Henry Hub benchmark pricing and a very negative Appalachian differential of over $1.25 per MMBtu for the quarter. We're hopeful that the expansion programs from the midstream and the pipeline companies in the Appalachian area will increase the access out of the basin over the next 12 months or 18 months; although, the current environment remains poor. We've secured sales arrangements through this year, which provides us with a market for our gas, but we're still subject to the pricing at the M2 Index. In the second quarter, our realized NGL prices dropped to under $14 per barrel, as Appalachian NGL pricing continues to experience a severe discount to an already-low product pricing environment. So the production side of the equation has been positive, while the pricing side has been very painful. On the cost side, we continue to show declining LOE per Boe, dropping to about $6 dollars per Boe for the second quarter, a 50% decline versus our per unit cost in the second quarter of 2014. The combination of operational leverage at Pompano, cost savings and higher volumes up in Appalachian has allowed for this impressive cost reduction. On the transportation, processing and gathering, expense is up slightly versus the first quarter, but the increase is primarily due to the added $2 million in catch-up costs related to the added working interest adjustment in Appalachia. Our DD&A rate for the quarter was under $3 per Mcfe, and we'd expect the DD&A rate to remain at around that level for 2015, although any future potential ceiling test impairment may impact this figure. Our base G&A before incentive comp came in at around $16 million for the quarter, down slightly from the first quarter. Reported interest for the quarter was, again, just over $10 million, flat versus the first quarter. As I've mentioned before, about $4 million of this reported interest expense per quarter is non-cash interest tied to the convertible notes accretion. Our total cash interest, which includes capitalized interest, is still running at around $16 million a quarter. Regarding taxes, our reported income taxes were negative due to the net loss for the quarter and we do not expect to pay any cash taxes for 2015. Our CapEx for the second quarter was approximately $91 million after about $114 million in the first quarter. The third quarter CapEx is expected to rise and will include a majority of the facilities costs for Amethyst tie-in project. We just released the ENSCO 8503 rig after completing our Cardona #6 well in July, so it can go back to the shipyard during the months of August and September for its required certification and to modify the rig for mooring capabilities. This drilling break will lessen our CapEx draw in the third quarter before we ramp up in the fourth quarter with the Amethyst completion, using the ENSCO rig and are preparing for mobilizing the Pompano platform rig program in the fourth quarter. As previously disclosed, our board has authorized our 2015 capital budget at $450 million. This figure does assume a sell-down of some minority working interest in certain targeted areas. And this is an exercise we continue to work on. Although, it is premature to announce our 2016 capital budget, we would certainly expect it to be lower than our 2015 budget and are working to present a budget to our board in the fourth quarter. At 6/30/2015, we had just over $140 million in cash and our $500 million borrowing base remains undrawn, except for $19 million in LCs. So we have – certainly have near-term liquidity and that we're fully compliant with all of our financial covenants under our credit facility. Again, our two key bank covenants are at debt-to-EBITDA ratio of 3.75 times, whereas at quarter end, we were under 2.8 times, and then in the EBITDA-to-interest coverage of greater than 2.5 times, while at quarter-end we were over 9 times. So covenants were well in compliance with our covenants. Our next borrowing base we determine is due by November. And although oil prices remain weak, we expect to have our proved producing volumes from Cardona #6 to be included in the fall calculation. Our convertible notes do not mature until March of 2017. That's convertible notes coupon of 1.75% is obviously very attractive, particularly in this environment. We're focused on enhancing our options for addressing the coverts prior to maturity, which is over a year-and-a-half away, including reducing expense in CapEx, selling some non-core assets, selling minority working interest in our core assets, evaluating joint venture arrangements in Appalachian and/or the deepwater, monitoring external financing options and certainly maintaining availability on our credit facility. And with nothing currently drawn on our $500 million bank loan, we can certainly be deliberate in our next step regarding the convertible notes. I believe that wraps up the financial overview. And with that, I'll turn it back over to you, Dave. David H. Welch - Chairman, President & Chief Executive Officer: Okay. Thank you, Ken. We're now preparing for the lower-for-longer scenario, while still believing in the longer-term viability of the exploration and production business. This year, we've cut our capital spend and our lease operating expense each by almost half; we reduced our G&A expenses as well. If the lower-for-longer scenario persists, we'll likely do even more in all categories again next year. The equity issuance in May of last year and sale of our non-core shelf assets last July improved our liquidity such we remain in a relatively good position, ending the quarter with about $142 million of cash on the balance sheet and an undrawn $0.5 billion revolver. Our objective over the short and intermediate term is to conserve cash and position ourselves to maintain liquidity and protect the balance sheet. We've also used this period of low prices to focus our organization almost exclusively on two of the lowest cost non-OPEC oil and gas supply basins. These two areas are oil in the deepwater Gulf of Mexico and gas in the Marcellus and Utica and Appalachia. Strategically, we've recently highly curtailed all current business development activities, including a potential resource play in Canada and have dramatically de-emphasized the deep gas and conventional shelf businesses. We've also temporarily delayed our investment in Appalachia waiting reduced differentials and better transportation terms before returning to development spending there. We do see both of these events on the horizon and are well-positioned in some of the best acreage in Appalachia, where we own stacked Marcellus and Utica rights that have much infrastructure in place. The important discovery we made in the Utica and Appalachia at the end of 2014 should position us for over a decade of low-risk development, investment and growth once the infrastructure catches up and differentials and transportation costs begin to improve. So in the intermediate term, we do expect to get back to work in Appalachia, but we'll hold off until margins improve. Meanwhile we continue to take steps to preserve our acreage with the minimum amount of spending. Most of our reduced capital budget of $450 million is allocated to the deepwater Gulf, where we're focused primarily on development drilling projects that create high returns and positive three-year cash flow. Added to these development projects are a few deepwater exploration wells that we expect will provide us with the next round of development opportunities as well as help to satisfy our rig commitment. We have a two-year contract for the ENSCO 8503 deepwater drilling rig. And one of our top projects over this time period is to manage the rig expenditures to be consistent with the viable capital program. There are three levers at our disposal to do this. The first and best lever to manage capital and retain potential to create value is to find partners with the prospects that are coming up over the next couple of years. We believe we have quality prospects and are optimistic that we'll find partners to get our working interest down to the desired level and we're active in this effort right now. The second lever is to farm out the rig to another operator, decreasing our contractually obligated spending under the two-year commitment. We're actively in the market now, discussing possibilities with other operators. The rig is performing well and we believe this will facilitate our being able to execute this option. The third level is to suspend operations at our convenience for an extended period of time, pay a reduced day rate and also eliminate substantially all of the support spread rate, which is greater than the rig cost itself. The current rig day rate is $341,000 per day. If we decide to suspend operations, we can reduce our overall spread costs by 70%. Obviously, the last lever is not as desirable as either of the first two, but we will do what we have to do to protect our liquidity in the balance sheet. With the ENSCO 8503, we just recently finished its first development well, the Cardona #6, successfully and efficiently. The rig is presently off our payroll, in the shipyard for its five-year inspection and the addition of a mooring system to enable it to work in essentially all deepwater depths. We expect to get the rig back in October. The other two already producing wells – Cardona wells, the #4 and #5, have been holding up very well. They're still currently producing approximately 10,000 barrels of oil equivalent per day. We've already produced about 2 million barrels from these two wells and believe that the ultimate estimated recovery for the whole Cardona development could be closer to 20 million net barrels compared to our proved reserves, which are under 10 million barrel equivalents. So I'm happy to report that the Cardona #6 well was drilled and completed for just over $80 million, which is about $30 million under the AFE cost, making it one of the most efficient wells drilled in the area. There's several reasons for this performance. First, extensive preplanning, including execution of the Drill Well on Paper process, Complete Well on Paper process, and a formal management of change process, which makes sure that everyone knows exactly what they need to do. Secondly, we've conducted extensive recruiting and training to get the best people we can on the rig, supervising and conducting actual day-to-day operations. Thirdly, and very importantly, the contract between Stone and ENSCO provides provisions that incentivize ENSCO's operational efficiency in a way that both enhances safety and reduces Stone's overall cost. ENSCO can earn performance bonuses based upon efficiency and safety, which is good for them and good for us as well. The better the rig performs the fewer days it takes for us to drill and complete our wells. Fewer days means savings for us, not just in rig cost, but also in the ancillary support services, which are often more – even more costly than the rig itself. So the rig and the contract performed just as planned on the Cardona #6, and helped to achieve these savings. So at this point, we're quite happy with the rig performance. If we can maintain this level, it could mean our gaining the equivalent of an additional free deepwater well over the two-year term of the contract. Turning to the next steps for the rig, after leaving the shipyard, we plan to complete the Amethyst well, which is another subsea tie back to Pompano. Once the well is completed, we expect to install the subsea flow-line and umbilical and connect to the Pompano platform to commence production in the first quarter of 2016. Project is proceeding on schedule and on budget at this time. Platform modifications to receive the well for production are essentially complete. What remains is the well completion, the flow-line and umbilical installation and hook-up. This development is an efficient, hopefully, sub-two-year cycle time from the date of discovery project, and the initial production rate from Amethyst well is expected to be in the 20 million to 80 million cubic feet of gas equivalent per day, including 30 barrels of condensate and 50 barrels of NGLs per million cubic feet of gas. We currently own a 100% working interest in Amethyst. Once Amethyst is completed, we'll most likely move over to the Cardona #7 development well to drill, complete and (22:10) into the Cardona subsea loop that we completed last year. We're expecting another 4,000 barrel per day or 5,000 barrel per day well there, which should contribute positive cash flow over the ensuing two or three years. While we are doing this work, we'll also be participating in the Vernaccia prospect, which is operated by Eni. This is an exploration well, which, if successful, at the P50, or P-mean reserve level could be another tieback to Pompano. This is a four-way geologic structural closure, which historically have had the highest probabilities of success in Mississippi Canyon. Up until recently, we held a 32% working interest in Vernaccia, but in light of spending most of our capital on development and conserving cash, we've reduced our interest to 22%. The good news from our commercial transactions on Vernaccia is that we will have only a 4% cost interest in the exploration well as we've sold down our interest at an attractive promote. The results of Vernaccia should be known around the year-end. When the ENSCO rig finishes with the Cardona #7 drilling well – drilling and completion, we expect to mobilize it to the Western Gulf to drill our Lamprey prospect. We believe Lamprey to be a large high-quality prospect, which is located just South of the Perdido Hub in Alaminos Canyon. There is a possibility that Lamprey is the Southern extension of the Great White field. If so, Lamprey could be a significant field and has the potential to add great value to our company. Our internal estimates are that Lamprey has a P90-to-P10 reserve range of 100 million barrels to over 500 million barrels of potential with a P-mean number that is over 200 million barrels of primary recovery. It could also be a prime candidate for water flood, which would increase these numbers significantly. We presently own 100% working interest in Lamprey. And this is a relatively inexpensive deepwater well. The dry-hole cost is in the $60 million to $75 million range depending upon how deep we decide to drill the initial well. We will likely want to take a partner for this project that are presently in marketing a minority interest in the exploration wells. Depending upon the terms the market is willing to offer, we'll decide how much working interest should be retained for the exploration test. We're also already in action to determine the optimal development and financing plans, should we succeed. If Lamprey is a significant discovery, we expect to almost immediately drill an appraisal well with the purpose to get a development to sanction and first production as inexpensively and as soon as practical. Following the Lamprey well or wells, we expect to move the rig back over to Mississippi Canyon to drill the Derbio prospect. By this time, we should have had enough production history from Amethyst to feel comfortable that Derbio has been substantially de-risked. Derbio is another amplitude-supported trap that is a sister prospect to our Amethyst discovery. We own Derbio at a 100% working interest then it has a reserves distribution of 16 million barrels of equivalent to 94 million barrels of equivalent, whereas Amethyst is mostly gas, Derbio is shallower and cooler, therefore, it's more likely to contain oil or higher liquids content gas. If successful, this would be yet another short tieback to their (25:37) platform. To conserve cash, we'll also likely try to get a partner for Derbio. So that's a look at our capital activity for the next year, focused almost entirely in the deepwater. We feel it's an attractive lineup of projects that work even in a lower-for-longer price scenario. Sometime next year, we might also get back to doing some development work in Appalachia, depending upon pricing and market efficiency. On the expense side, as you'll recall, we divested essentially all of our non-core properties by the summer of 2014. And this, along with expanding our low-cost production in deepwater, in Appalachia, plus our cost-cutting initiatives, have helped us restructure our company into a much lower-cost operation. We've been able to reduce our LOE from over $12 a barrel equivalent in the second quarter 2014 to just over $6 this quarter. So we saw a total LOE in the quarter decline from about $50 million last year to $27 million this year. We expect to see this trend continue a bit further as we bring on the low-cost Cardona #6 and Cardona #7 in the next several months and continue to examine carefully all of our expenditures. Speaking to volumes, net production, excluding the positive prior-period adjustments in Appalachia, was approximately 46,000 barrels of oil equivalent per day this quarter compared to 44,000 barrels of oil equivalent per day in the same quarter last year, which is about a 4% increase over last year's quarter. So our projects are working and execution has been good. Looking forward, we anticipate a temporary decline in production from Appalachia as we stop drilling there, which is offset by an increase of Gulf of Mexico production, as Amethyst, Cardona #6 and #7 and the Pompano platform drilling program all deliver new production over the next year. With this, we'll now be happy to take your questions.

Your first question comes from the line of Jon Evans from JWEST. Your line is open.

Can you just talk a little bit about your initial thoughts for CapEx spend next year? And then also, as you go into the redetermination, do you think any indication, does the $500 million stay pretty constant, or can you give us any insights?

Yeah, Jon. This is Ken. Let me take the second question first. So on the redetermination, very difficult to tell. I think even the banks are in limbo as to exactly what their price deck is. Clearly, back in the spring, they had a low-price deck. So we're not sure what that will look like. As I mentioned in my comments, you might have lower prices. But one of the positives for us will be, we'll have a Cardona #6 online and we expect to have that online. And as you may be aware, from a bank standpoint, as they go through their borrowing base calculation, by far, the most important factor in their determination is who producing. And in this case, having the Cardona #6 on and having the #4 and #5 performing so well certainly will help us, but very difficult for us to estimate what that new number will be, whether it stays at $500 million or not. Shifting to CapEx, as I mentioned in the comment, again, premature to come up with a number. Certainly, directionally, it will be down from the $450 million that we have for this year. But exactly where that number unfolds, we're working through that now. And we'll certainly have a figure for our board to ultimately sign off. Probably, they will see that sometime in the October board meeting.

Okay. And just one more follow-up to that. Is it fair to say that you hope by this time next year that you have the convert taking care of, et cetera, and extent to that maturity, it seems like that's been an overhang on the company and the stock? So I'm just curious. David H. Welch - Chairman, President & Chief Executive Officer: Yes. So I think that's fair to say that a year from today, we would hope to have a lot more clarity on exactly what steps we'll take, whether that is with using internal funds, using our credit facility, using a restructuring with the current holders, coming in with a totally new external financing approach, those are all options that are out there. I think it is important that we don't have to make those decisions – that decision right this moment in what clearly is a very difficult environment. But certainly that is one of the key issues that we'll be addressing certainly as we go into 2016.

Great. Thank you for your time. David H. Welch - Chairman, President & Chief Executive Officer: Great. Thank you, Jon.

Your next question comes from the line of Blaise Angelico from IBERIA Capital. Your line is open.

Hey, good morning, gentlemen. David H. Welch - Chairman, President & Chief Executive Officer: Hi.

Just looking at possible ways to fund additional CapEx over the coming years, what are your thoughts about potentially selling in its entirety or selling down an interest in Pompano and Amberjack? Those are assets that probably don't receive an appropriate valuation from an NAV perspective. Just curious as to how you're thinking about this as an option to realize value, but also bring cash in the door to fund future CapEx? David H. Welch - Chairman, President & Chief Executive Officer: I'll ask Ken to give you his thoughts, but basically everything is on the table right now and we're considering any option that might improve the state of the company. So I'm not really keen to go do something right now, but it's not a bad idea to think about it. Ken?

Yeah, and, Blaise, I think what you're alluding to is just that the platforms themselves, which certainly, at least in our minds, have some true value that could be separately financed. Certainly, any step we take in that regard might have some impact on whether it's the borrowing base or other issues. But, as Dave pointed out, these are all capital – or financing options that we're going to take a hard – that we have and will continue to take a hard look at.

Got you. Thanks. And just one quick follow-up on the onshore. Say, prices are steady-state, differentials remain where they are, and you all don't reinvigorate the drilling program, what would the cost to terminate that rig contract be? David H. Welch - Chairman, President & Chief Executive Officer: It's in the $18 million range.

Yeah, that's over $6 million a year. So for 2016, you're looking at about $6 million.

Perfect. Got you. Thank you, guys. Appreciate the color.

Your next question comes from the line of Patrick Rigamer from Seaport Global Securities. Your line is open.

Hi. Good morning, guys. David H. Welch - Chairman, President & Chief Executive Officer: Hi, Patrick.

The press release mentioned that you sold a deepwater block. And I was just curious, any more color on that? And are there more opportunities to do that or – just kind of what was going on there? David H. Welch - Chairman, President & Chief Executive Officer: Yeah. This was a lease that a different operator had a discovery right next to that lease. We didn't have plans to move forward. They did want to move forward. So we were able to just monetize the lease at roughly $10 million. So certainly, those are the kinds of hidden assets that we hope to be able to continue to monetize as the opportunity presents itself.

Okay. And then, I guess, moving onshore, the Utica well that you drilled was drilled in a different price environment on the service side. I mean, I realize that there's not a lot of activity up there now, but do you have a sense of where development cost, well cost might be today? And is there a certain well cost that would, kind of, make you reconsider the development program up there? David H. Welch - Chairman, President & Chief Executive Officer: Let me tackle the latter part of it, and Ken can weigh in on the actual well cost. But we really feel like we need some sort of a structural change there before we would want to get back to drilling. The structural change is really in the price and in the transportation environment. As you know, there's a big differential between Henry Hub and Appalachia right now. There are a lot of pipelines that are being built out of Appalachia that over the next couple of years that differential should be cut in half or even improve better. So that's one factor that we're looking for. The closer we get to 2017, the better – the more pipes are being built, so the lower that differential is likely to be. So that's one thing. The other thing is just that we are starting to now see some of these export LNG things start to add a little demand. And over a cumulative period of time, the demand growth may help lift Henry Hub a little bit as well. So we just feel like it's a good time to take a little bit of a time out. Obviously, with prices coming down across the board for rigs and services, I think we expect that we could drill wells cheaper. But I don't know exactly if we have a current outlook on what a well would be to drill today. Ken, do you know that?

No, that's fair. I mean, certainly, those numbers have come down, but, as Dave highlighted, it's really the price – the gas price side that's the bigger driver. And not wanting to add to the oversupply situation in the next three, six, nine months, our thought was, let's go ahead and step back and use this time to prepare for the Utica development program, but not initiate it in the face of, as was highlighted, very unattractive differentials that we do expect to get better. So no reason to rush now, when in 12 months or 18 months we feel like we could see, at least, in our minds, a material change on the differential side. David H. Welch - Chairman, President & Chief Executive Officer: And just tactically, we've chosen to put our capital into projects that throw off as much cash as possible over the shortest period of time. And so that's another reason that we've really tilted everything to the deepwater right now. We do have developments to do. And these developments are low-risk. They provide a high return and they also provide immediate cash.

Yeah, and really to that point, Patrick, as Dave pointed out, the Gulf of Mexico production is very high-margin, whereas right now the Appalachian production, they've done a very good job of keeping production pretty flat with no extra wells. But the margin there, because of the differential and because particularly in the Marcellus, the low prices that you're experiencing out of the liquids side, it just seems like push capital to where we're getting a high-margin on our production, just makes a lot more sense. And so that's why we've just diverted capital to those projects.

Okay. Appreciate the color. And then just quickly on the model, gas and NGL, as a percent of total production, were up a little bit this quarter. I'm assuming that's just because of the prior-period true-up; and going forward, kind of, return to what it was like over the prior quarters? David H. Welch - Chairman, President & Chief Executive Officer: Yeah. That's a fair observation. And, in fact, as you get into the fourth quarter with Cardona #6 coming on, that – I think you'll see even more of a waiting towards oil. So not only do you have, kind of, the catch-up behind you in the second quarter, but by the fourth quarter, I expect that number to be up higher.

Okay. Great. Thanks. David H. Welch - Chairman, President & Chief Executive Officer: Thanks, Patrick.

There are no further questions at this this time. Mr. Welch, I turn the call back to you. David H. Welch - Chairman, President & Chief Executive Officer: Okay. Thanks, everyone, for joining the call. And we appreciate you being here, so long.

Thank you.

This concludes today's conference call. You may now disconnect.