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Edited Transcript of SEA.AX earnings conference call or presentation 15-Aug-19 10:00pm GMT

Q2 2019 Sundance Energy Australia Ltd Earnings Call

DENVER Aug 23, 2019 (Thomson StreetEvents) -- Edited Transcript of Sundance Energy Australia Ltd earnings conference call or presentation Thursday, August 15, 2019 at 10:00:00pm GMT

TEXT version of Transcript

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Corporate Participants

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* Eric P. McCrady

Sundance Energy Australia Limited - MD, CEO & Director

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Conference Call Participants

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* Adrian Prendergast

Morgans Financial Limited, Research Division - Senior Analyst

* Bertrand William Donnes

SunTrust Robinson Humphrey, Inc., Research Division - Associate

* David Novac;Wealthwise Education;Co-Founder

* Derrick Lee Whitfield

Stifel, Nicolaus & Company, Incorporated, Research Division - MD of E&P and Senior Analyst

* Jiuying Ye

Imperial Capital, LLC, Research Division - Associate

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Presentation

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Operator [1]

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Good day, everyone, and welcome to the Sundance Energy quarterly earnings call and webcast. This call is being recorded.

At this time, for opening remarks, I would like to turn the call over to Eric McCrady, CEO and Managing Director.

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Eric P. McCrady, Sundance Energy Australia Limited - MD, CEO & Director [2]

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Thank you, Andrew, and thank you for everybody listening to the call.

Despite volatility in the economy and in oil prices, Sundance remains well positioned to deliver value for our shareholders. That really starts with our strong asset base, which is delivering good returns in the Eagle Ford, particularly in our Live Oak and Atascosa assets, where our development plan is focused. Those strong returns and strong assets underpin our ability to execute a financially disciplined strategy and generate free cash flow going forward.

Our wells, to give you an idea of the quality, produce about 90,000 barrels of oil for a typical lateral length well in the first 6 months and about 125,000 to 135,000 BOE in the first 6 months. That allows for a quick payback, strong returns and the ability to recycle cash flow into the next investment opportunity.

From a financial standpoint, in the second quarter, we reached what we believe to be our peak net debt level. We've reached that level with plenty of remaining liquidity, which we can use as a buffer going forward. Although we expect to generate free cash flow so don't anticipate needing that incremental liquidity.

During the quarter, that liquidity and the quality of our asset base was solidified or really confirmed by our bank group when they increased our borrowing base by 40% to $170 million. Additionally, in the third quarter, we anticipate closing the sale of our Dimmit assets, which was announced -- which was recently announced, and we're currently finalizing due diligence on.

In the second half of the year, we do expect to generate free cash flow. We also have about 8,000 barrels a day of hedging in place on our oil volumes. We remain more exposed to both natural gas liquid and natural gas pricing. However, the biggest chunk of our revenue base, the oil stream, is well hedged.

Lastly, the asset base and our strong financial position gives us the ability going forward to run a variety of different strategies to create value for our shareholders. Looking at goalposts, we have the ability long term to, within cash flow, generate roughly 15% compound annual growth for the foreseeable future without stretching the balance sheet. On the other side, we have the ability to maintain production and cash flow levels with roughly $100 million annual plan and generate free cash flow. I think those 2 really goal lines or sidelines for the company's position allow us quite a bit of flexibility in an uncertain economy and uncertain oil prices to create value for our shareholders going forward.

Moving forward into the second quarter, there are a couple of highlights. First, we ended the quarter near the high end of our guidance. We did see some increased gas production that was really driven by 3 things. First, the Esse pad that we brought on in Live Oak saw about 75% oil cuts, which is about 10 percentage points below, the next pad we brought on, the Georgia Buck pad, which came online in the third quarter. We don't really expect to see 25 -- or 75% oil cuts going forward in Live Oak. The total reserve base, we're comfortable, still remains about 63% oil. We don't believe this pad changes that. Secondly, our Dimmit assets, currently, the most recent wells we brought online are producing about a 25% oil cut, and while a small portion of our production base, that does reduce the total amount of oil that we're producing versus gas. And lastly, we have reduced our total flaring across the field through completion of the upgraded CGP-41 with our midstream partner, and so since we're capturing more gas and natural gas liquids, we have seen a little bit of an uptick in our overall gas sales. That's obviously a positive since we're capturing some economic value for gas and NGLs that we weren't previously capturing.

Speaking on the midstream side, we have -- in the second quarter, we initiated the second project with our midstream provider to further expand capacity. We have a plan in place and have -- really starting the construction process on that today with some of the hazard planning meetings. All the design is done, and we believe we'll have that facility expanded to the capacity we need for the foreseeable future in the fourth quarter, and we don't anticipate there'll be any material impact on our production or financial performance surrounding the timing of bringing that facility up to the capacity we need. The capital associated with bringing that facility up to larger or higher capacity is 100% funded by our midstream partner under our agreement, and they're obligated to fund, cumulatively, $10 million of capital to expand and optimize that facility.

Secondly -- or thirdly in the quarter, we had a excellent focus in our operations team on cost reductions. I think there's 2 things that really stand out. First, our drilling days decreased materially year-over-year. We've shaved about 6 days off of our average drill time. We do -- I do think that the rates we're drilling wells at today should be sustainable depending on lateral lengths, and I think, again, our drilling team has done an excellent job of driving down the days we're on wells, and that's causing a reduction in drilling cost on the well side.

On the lease operating cost and G&A side, we've seen about a 16% quarter-over-quarter reduction in cost, and in the second quarter, we -- our total operating costs were approximately $15 a BOE, and we expect to be able to continue reducing those costs over time both through projects that we're implementing to increase efficiency and also through leveraging a fixed cost base off of a higher production level.

And that's -- you can really see the trajectory down in Slide 7 of the presentation that we put out earlier.

For Q3, in the second half, we have several key objectives. First, we have the objective of generating free cash flow in the second half of the year, which obviously means that we believe we're at our peak debt level and should be able to reduce that debt level on a net basis in the second half and going forward. That's obviously contingent on what happens with any unhedged portion of our commodity stream. In the second half, we expect to spend, give or take, $60 million in capital expenditures. We've provided second half guidance for CapEx as opposed to quarterly because in the first quarter, we noted that we've been drilling wells faster than expected, which brought some capital forward. Because of that, the 2-well Justin Tom's (sic) [Justin Tom] pad, which we're currently drilling, these are 2 12,500 foot lateral wells in Atascosa County, they're going to get -- we'll finish drilling those wells earlier than expected. And we may end up completing those wells late in the third quarter and so incurring the capital costs associated with those wells in the third quarter. And so there's some flex around the end of the quarter as to what capital will be. Those are the last 2 wells that we'll be fracking this year. Both completed -- upon completion of those wells, 22 total wells. Those 2 Justin Tom wells, we've extended the laterals on those versus our initial plan. So initially, we expected to bring 24 wells online, but we'll bring 22 online, including these 2 extended reach lateral wells.

In the end of the third quarter, we'll also have the rig likely in our Washburn Ranch wells in La Salle County. This will be the first 2 La Salle wells that we'll be testing out that acreage position. And once the rig is completed drilling those wells, we'll be done with our drilling program for the year. We expect that to happen sometime in -- likely in late October, potentially early November, and so we do anticipate that regardless of when we frac the Justin Tom wells, there will be a material drop in capital spending as we move into the -- at the end of the year, given that the majority of our program -- capital program will be completed.

In the third quarter, specifically, we're bringing 12 wells online. The first 8 of those wells have started flowing back. 4 of them are the Georgia Buck wells, which we've disclosed initial production rates on. The other 4 wells, the Chapman pad, we've modify our completion design a bit, and they've really just started flowing back. And so we expect to see them reaching peak oil production until later this month. And then we're currently fracking the 4-well Harlan Bethune pad, which we expect to have online in September, and those will be the last 4 wells we'll bring online this quarter. If we frac the Justin Tom wells late this quarter, they'll come online early in the fourth quarter.

Given that trajectory, from a development standpoint, we anticipate a material ramp in production during the quarter, so we're guiding for the quarter to 14,000 to 14,500 a day. But we anticipate exiting the quarter in September around 2,000 BOE a day higher than that, in the 16,000 to 17,000 BOE a day range, and that really sets up a strong production profile for the fourth quarter. We do still anticipate hitting our full year production guidance. The midpoint is 14,500 BOE a day from a sales volume standpoint.

Lastly, our team continues to be focused on controlling costs. We have not reflected a reduction in our cost guidance for the third quarter, but we do believe that we can continue to achieve the $15-a-BOE cost number that we had in the second quarter and potentially reduce that further going forward.

For the quarter, we expect to produce about 60% oil. We do believe there's a little bit of upside in that number, and we believe the fourth quarter should be higher than that. That's really just driven on timing of the development program and timing of the Dimmit divestiture. We'll start bringing on more oily wells through the quarter, which will increase our oil percentage. But in terms of the exact timing, we expect that to cross over sometime later in the quarter. And so we believe that this quarter, we'll likely continue to be a little bit gassier than we've had in the first quarter and really, the third and fourth quarters of last year. Again, that doesn't indicate a long-term change in the oil cuts in our assets. We still are comfortable that we'll be achieving just under 63% oil cuts in the asset base.

From a liquidity standpoint, as I mentioned, we've received a 40% increase in our borrowing base from our bank syndicate to $170 million. That leaves us today with about $50 million in short-term liquidity in addition to our cash flow and proceeds from the Dimmit sale that we expect in the third quarter. So all in, we anticipate generating free cash flows. We don't anticipate liquidity being an issue going forward, but we do have ample liquidity to provide a buffer for the company going forward, and really, it would allow us to react in the case of changing market conditions, even though our current plan is to focus on free cash flow generation.

From a debt structure standpoint, we have a -- 2 pieces of debt outstanding. We have a revolver, which is $170 million. Of that, only about -- well, about $100 million of that is drawn today. And we have a $250 million second-lien term loan. The RBL, the revolver matures in late 2022, and the term loan matures in mid-2023. So there's plenty of time remaining on the tenure of those 2 pieces of debt.

From a coverage standpoint, we have more than adequate 1P, PDP and EBITDA coverage of the debt and of the interest to service it. And we don't anticipate any issues going forward. Our credit profile, we expect to improve in the second half of this year and moving into next year or to continue to improve, and we anticipate reducing our debt over time.

In the last quarter, we had a brief discussion around evaluating, redomiciling the company to the U.S. There's nothing really new to update on that aside from leaving a slide in here that talks to some of the reasons why we think that may be beneficial to our shareholders. As I mentioned, there's really not anything to update -- on that at this time. From an inventory standpoint today, we have just over 400 remaining locations. In terms of location quality, we believe that we have somewhere around 200 locations that break even less than $50 oil. The highest-quality acreage we have on our inventory charts [is in] Live Oak, Atascosa and La Salle, and then we have remaining quality inventory in McMullen County. So we have a very lengthy runway to develop our assets and to begin creating and sustaining free cash flow for our shareholders.

Earlier this quarter, we announced the sale of the Dimmit County asset. It's producing, give or take, 700 or 800 BOE a day. Although in the third -- in the second quarter, it produced more than that with the IP of the 2 Red Ranch wells. All in, it's about 6,000 acres. The sales price was $29.5 million. There will be adjustments to that sales price at closing for cash flow generated from those assets and any other normal closing adjustments. And so we anticipate achieving a number that -- a cash proceed number that's similar to the number that's disclosed in our balance sheet.

In terms of development cadence, we've already talked through that. The bulk of our development this quarter is focused on Live Oak and Atascosa. Those 2 areas generate our best returns, and the 2-well Justin Tom pad that we're on right now will be the 2 longest laterals that we've drilled as a company at 12,500 feet. We're very excited for the economies of scale we generate by being able to access longer laterals on this lease block.

In the McMullen asset, we brought 2 wells online this year on the Bracken, which is the one on the map in our presentation on Slide 16. And we don't have any further development activity planned in McMullen County this year.

On Slide 17 and 18, we've put information out regarding the production profile of the various wells we've brought online in 2018 and 2019. These are relatively current numbers. I think what you'll see in the numbers is that the Live Oak, Atascosa wells continued to perform very strongly. They have good oil cuts. They cumed significant quantities of the hydrocarbons very quickly in their life, which supports strong economics and a quick payback on those wells, so we could recycle that capital into future investments. These are just raw production numbers, so they don't account for any periods of time where we've shut some of these wells in for offset fracs or for other reasons.

From a total production standpoint versus some other players in the basin, you can see on Slide 19 how our wells perform versus some of our peers. We are tweaking our completion design, as I mentioned. I say tweaking, it's actually a pretty material change that we believe can drive, over time, improved recoveries, although you see that our well results, particularly on the acquisition acreage in Live Oak and Atascosa, stack up very well in the basin. For every thousand feet of lateral we drill, we're cuming about 22,500 BOE in the first 6 months of production. And generally speaking, on the previous slide, you can see the oil cuts in Live Oak and Atascosa. So the majority of that is oil on that acquisition acreage.

Slides 20, 21 and 22 really just look through continued well performance versus type curve on a normalized basis. We -- I think I've shown these every quarter, and they demonstrate that our wells continue to outperform our third-party type curves, which obviously means we're getting better economics than what we expected from that Ryder Scott report. However, we do believe that these results, they're in line with or even slightly ahead of what our internal expectations were, which were a bit higher than Ryder Scott's numbers. From a hedging standpoint, we continue to execute the same hedging strategy we have previously. When we commit capital to a well, we put hedging in place to protect payout of it. We have about 8,000 barrels a day hedged for the remainder of this year and just under 6,000 barrels a day hedged for 2020. As we begin committing capital for 2020, if we have economic -- or based on the economic wells that we're going to drill, we'll put hedging in place to protect those economics. But our development plan will be based upon the current strip pricing at the time we make those capital commitments, not based on the hedging that we have outstanding. We think this gives us a sufficient protection for the invested capital to not only recoup our money but also generate a commercial return on the capital that we're investing in these wells.

So to wrap up, Sundance today, small position to withstand and create value in a turbulent market. We have a high-quality asset base that's generating good returns. We're going to begin generating free cash flow in the second half of the year and have reached our peak debt level. The Eagle Ford has advantaged pricing, we're still receiving in the third quarter, and in the fourth quarter, we expect to receive anywhere between a $3 and a $4 premium to WTI by being located on the Gulf Coast. And we have a strong balance sheet with ample liquidity as a buffer while we're continuing to execute our plan to generate free cash flow and grow the business within cash flow.

So with that, happy to open up -- open it up for questions.

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Questions and Answers

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Operator [1]

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(Operator Instructions) And our first question comes from the line of Bertrand Donnes with SunTrust.

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Bertrand William Donnes, SunTrust Robinson Humphrey, Inc., Research Division - Associate [2]

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Can you talk about the impact that a U.S. listing could have on the possibility of acquisitions and divestitures and maybe describe the mindset of how you evaluate packages that you'd consider buying?

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Eric P. McCrady, Sundance Energy Australia Limited - MD, CEO & Director [3]

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Sure. I think a U.S. listing allows us to have a U.S. currency or accept a U.S. currency for either an acquisition or in the case of selling the company, it makes it a lot easier to have 2 U.S.-domiciled companies transacting in scrip or stock-based deals versus having a U.S. and an Australian-based company doing that. There's different regulations in each jurisdiction, and I think having the company located in the jurisdiction where we will likely be transacting may or could potentially be beneficial in that situation. Certainly, if there's an opportunity to increase scale by issuing our stock, if we could find an accretive transaction, which I think, today, is probably challenging, but if we could find an accretive transaction, I think potential sellers will be much more likely to be interested in U.S. stock, at least from feedback we've gotten. And so I think those are, I think, the key benefits associated with it. Really, it's regulatory, which kind of feeds into legal fees both ourselves and any -- a buyer of us or a seller to us would also have to engage an Australian counsel and get familiar with Australian regulation and then the ability to issue stock to somebody if it made sense in an acquisition.

In terms of how we evaluate acquisitions, to be honest right now, we're not really looking at much. I think there's a disconnect in the market today between public market cash flow multiples and net asset values of assets. Because of that disconnect, I think it's very hard to transact. In terms of how we would look at acquisitions normally, we typically start out with a net asset value, really, a bottoms-up NAV evaluation, and then we come up with what we think the value of an asset is. We compare that back to our cost of capital to see if it's accretive. And if we can do a deal accretively, then typically, it's something that we're interested in if we think it's good for our shareholders and have access to capital. If we can't do it accretively or if we don't think there's a strategic fit to the assets, then generally, we would pass on that asset. As I started off, we don't believe, today, that we can participate, really, in acquisitions because our cost of capital's too high, and there's too big of a disconnect between cash flow multiples and NAV multiples.

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Bertrand William Donnes, SunTrust Robinson Humphrey, Inc., Research Division - Associate [4]

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That's perfect. And then really just one last one. It looks like the acreage count on the first few pages went down about 1,300 net acres. Is that just normal expirations? Or maybe you could highlight where that was.

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Eric P. McCrady, Sundance Energy Australia Limited - MD, CEO & Director [5]

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Yes. It's in Dimmit. One of the leases we [had did not] HBP, and so there were some minor expirations in Dimmit. And that's already -- the acreage expired was not included obviously in the sale to the buyers. There's no risk to the purchase price from that acreage.

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Operator [6]

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And our next question comes from the line of Derrick Whitfield with Stifel.

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Derrick Lee Whitfield, Stifel, Nicolaus & Company, Incorporated, Research Division - MD of E&P and Senior Analyst [7]

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If you were to project out your current operational and capital efficiencies into 2020, where do you see your breakeven prices to hold production flat?

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Eric P. McCrady, Sundance Energy Australia Limited - MD, CEO & Director [8]

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I think next year, we likely need to drill somewhere around 16 wells. I say that -- I should give you a disclaimer. We haven't obviously run a formal budget through the Board, and so we haven't finalized all the analysis around this specifically for next year. So there's going to be some contingencies on timing when wells come online. But I think next year, it will hold flat. We need about 16 wells. For 16 wells, that's going to be somewhere between $90 million and maybe $100 million or $105 million in capital. And I think that holds us at -- holds us flat from a production standpoint. And so I think we'd have to see a pretty, I think, material drop in pricing to impact EBITDA enough for us not to be able to hold production flat. We haven't run the specific breakeven price in that context, but I suspect that it would be below $40 a barrel.

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Derrick Lee Whitfield, Stifel, Nicolaus & Company, Incorporated, Research Division - MD of E&P and Senior Analyst [9]

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Perfect. And then referencing Slide 7, could you speak to some of the specific initiatives in place to drive lower cash costs?

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Eric P. McCrady, Sundance Energy Australia Limited - MD, CEO & Director [10]

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Sure. We've been converting -- I think, first, we've been converting wells from rod pump to gas lift, which is more efficient and requires less workovers. I think that's probably the single biggest thing. Second, we've been able to convert a handful of equipment rentals to purchases with very quick paybacks, like kind of 3 by 6-month paybacks. Our field management has finished rolling out SCADA, which allows us to monitor wells real-time and remotely, and that's helped improve the efficiency of our workforce down in Texas. And so we've been able to reduce our overhead.

We've changed some of our chemical programs, and so we've been able to reduce the chemical costs associated with creating some of our wells. We've done that gradually to make sure that there weren't any adverse consequences. It's been something that our engineer in Texas has been -- I think he started on 9 months ago, and [is] very gradually been rolling that out. And so it's really been, I think, a variety of different things that we've been focused on. The -- I think one of the big things that we have left is water disposal. I think water disposal is the single largest cost that we have that we -- while we can manage it and negotiate it, given our acreage is a little bit spread out, it's been hard to find a single-source solution to materially drive that down. I think we do have something in the works, which can help continue pushing costs down. But that's likely a third or more likely a fourth quarter benefit.

And I think lastly -- last year, we anticipated higher LOE after closing the Pioneer acquisition because we had -- we knew we had more workovers to bring some of those old wells back online. And so as we brought those back online and put gas lift in, we just -- they -- we haven't had to continue operating the same workover cadence. And so we've seen that number in our overall LOE come down, and we expect that to continue.

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Derrick Lee Whitfield, Stifel, Nicolaus & Company, Incorporated, Research Division - MD of E&P and Senior Analyst [11]

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And if I could just perhaps sneak one additional question, just to follow up with that, could you potentially exit the year with sub-13 cash cost?

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Eric P. McCrady, Sundance Energy Australia Limited - MD, CEO & Director [12]

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I think sub-13's probably going to be challenging for this year. However, longer term, I think that's certainly something that's feasible.

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Operator [13]

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And our next question comes from the line of Irene Haas with Imperial Capital.

Our next question comes from the line of Adrian Prendergast with Morgans Financial.

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Adrian Prendergast, Morgans Financial Limited, Research Division - Senior Analyst [14]

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Just a quick question, just on the 2 longer Justin Tom wells. Just wondering, operationally, what the strategy would be if they're successful? Or how much of your acreage you would look to perhaps roll that out across?

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Eric P. McCrady, Sundance Energy Australia Limited - MD, CEO & Director [15]

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We have a relatively limited amount of acreage that we can drill longer laterals on. We currently drill wells as long as we can within lease boundaries, to the extent possible, we've been negotiating agreements with offset operators to extend laterals and share wellbores. So I'm not particularly concerned about the operational performance of those wells. It's more contingent on really just the acreage footprint. We do have blocks of acreage where we can continue drilling longer laterals. The one big area where -- depending on really final geologic assessment where we can drill -- one of the wells would be La Salle, there is some faulting through there that could make that more complicated. But we will be -- we try to drill the longest laterals we can to optimize those efficiencies.

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Adrian Prendergast, Morgans Financial Limited, Research Division - Senior Analyst [16]

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Fantastic. And just on the La Salle, would that look to be -- you're drilling your first wells there in this -- from the new acreage. If successful or near curve, would you look to roll some more in? Or is it sort of success-based? Or is this just part of just normal hold by production drilling?

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Eric P. McCrady, Sundance Energy Australia Limited - MD, CEO & Director [17]

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We'll bring those wells on early next year. I think all things equal, we'd like to drill some additional wells down there if the economics stack up with Live Oak and Atascosa. We expect that they'll stack up at least with Atascosa. Although I think it's not as oily in La Salle as it is, so that may disadvantage it in the current gas and NGL market over here in the states. But we would like to increase the development at La Salle a bit. We own and operate the central gathering facility there. So we have a fixed cost base that if it's economic, additional wells will help dilute that fixed cost base, which helps obviously reduce our unit lease operating cost to improve our EBITDA margins. And so we'd like to allocate more capital there, but it's going to be contingent on the returns there versus the returns we're seeing elsewhere and then how additional development would impact our ability to generate free cash flow next year.

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Operator [18]

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And our next question comes from the line of Claire Ye with Imperial Capital.

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Jiuying Ye, Imperial Capital, LLC, Research Division - Associate [19]

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This is Claire for Irene. I wanted to ask about when you have transitioned your listing to the U.S., what kind of G&A savings do you expect by avoiding to sort of work in both countries?

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Eric P. McCrady, Sundance Energy Australia Limited - MD, CEO & Director [20]

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I don't think there's a huge G&A impact to being listed the way we are today. There may be some savings around the edges, but we don't really anticipate any material difference. Our staff today does both the GAAP and the -- the SEC and the IFRS stuff in Australia that we need to, and we really just be shifting staff from Australian compliance to U.S. compliance. So if we do make that shift, we don't anticipate any major G&A savings, although there may be some around the edges and it may free up -- or could free up some time from some of those people if we did that.

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Operator [21]

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(Operator Instructions) And our next question comes from the line of David Novac with Wealthwise Education.

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David Novac;Wealthwise Education;Co-Founder, [22]

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Just wanted to find out, like we're talking about the -- by the end of the second half, being cash flow positive. I just want to see what projections you have about that. Because obviously, there's been a drag on the share price over many years with the company spending -- investing so much capital in development and production. So I just want to get a -- is there any kind of idea about going forward, what do you expect to end the year in terms of turning this -- obviously the cash flow situation around?

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Eric P. McCrady, Sundance Energy Australia Limited - MD, CEO & Director [23]

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We previously issued full year EBITDA guidance. We have not included EBITDA guidance in this deck. I think as we've looked at our peer companies, we don't see a lot of people guiding to EBITDA. And that's the -- the primary driver, I think, is people tend to run their own oil, gas and NGL price decks instead of us running it. We've provided all the information for people to make that calculation for the third quarter. We haven't revised our full year guidance. But given volatility in gas and NGL pricing, we haven't refreshed that guidance either. Going forward, one of the analysts earlier asked, in 2020, what our maintenance capital plan looks like. And we believe that, subject again to full analysis, that for running a $90 million or $100 million capital budget, we should be able to generate somewhere around $40 million a year in free cash flow at $55 oil, $2.50 gas and $18-a-barrel NGL prices. Some of the current prices are a little bit below that today, but that's roughly what we think holding flat does with the current capital structure.

If we accelerate development in the future, then we can obviously increase that free cash flow generation. But that's what a hold flat case looks like, we believe, next year. Again, that's not formal budget or guidance, but I think that's what the asset should be able to do.

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David Novac;Wealthwise Education;Co-Founder, [24]

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And are you satisfied with your current hedging policy going forward as well with -- to alleviate any price shocks in the oil market?

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Eric P. McCrady, Sundance Energy Australia Limited - MD, CEO & Director [25]

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Yes, I think we're happy with the strategy that we have in place. We'd love to have more capital available to invest and be able to hedge more into the future. So for example, we would love to know exactly what prices are next year so we could formulate our capital plan and commit to it and have hedged it out when oil prices were higher. But we're a small company, so we're very happy with the way the hedging program is performing. It provides us significant buffer if prices drop to protect capital invested. And it's functioning the way we think that it should or the way we've designed it to function. We do always tweak that program around the edges and monitor it to make sure it's still achieving those objectives. But right now, we're very happy with how it's performing.

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Operator [26]

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And ladies and gentlemen, I am showing no further questions. So with that said, we'd like to thank you for participating in today's conference. This does conclude the program, and you may all disconnect. Everyone, have a wonderful day.