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Edited Transcript of SEA.AX earnings conference call or presentation 27-Mar-19 9:00pm GMT

Q4 2018 Sundance Energy Australia Ltd Earnings Call

DENVER Jul 9, 2019 (Thomson StreetEvents) -- Edited Transcript of Sundance Energy Australia Ltd earnings conference call or presentation Wednesday, March 27, 2019 at 9:00:00pm 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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* Derrick Lee Whitfield

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

* James Eginton

Tribeca Investment Partners Pty Ltd. - Investment Analyst

* John W. Aschenbeck

Seaport Global Securities LLC, Research Division - Former MD & Senior Analyst

* Leonard Joseph Raymond

Johnson Rice & Company, L.L.C., Research Division - Research Analyst

* Welles Westfeldt Fitzpatrick

SunTrust Robinson Humphrey, Inc., Research Division - Analyst

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Presentation

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Operator [1]

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Good afternoon, everyone, and welcome to the Sundance Energy's Fourth Quarter Earnings Results Conference Call. This call is being recorded.

At this time, for opening remarks, I would like to turn the call over to Mr. 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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Thanks, Catherine, and thanks, everybody, for joining the call today. Obviously, market conditions late last year, particularly in December, were very unstable. And while they firmed up a bit, there does still seem to be some economic uncertainty worldwide that could potentially impact oil demand. Despite that uncertainty, and while there's risk that may materialize, to date we really haven't seen a significant impact to oil demand and are still seeing continued demand growth. And I think that sets up for a constructive year for U.S. E&P companies in the United States and for Sundance.

But OPEC and Russia today have been so far sticking to the supply cuts that they've agreed to, which is supporting price. And we've obviously seen some Iranian barrels start to come off the market. And it does look like there's some cracks showing from U.S. supplies in the shale plays. We are still seeing, I think, strong growth in the U.S., but I think what we are starting to see are some of the unintended consequences of the shale boom that have started to hit some of the suppliers.

Some of those things are investor appetites in the United States shifting from a growth-at-all-cost philosophy to pushing companies to return -- to return-based growth and growing within cash flow. Now we're seeing political challenges in certain areas, particularly in Colorado, where we're headquartered but fortunately don't have any assets, where development activity is being threatened by regulators and the government.

And we're starting to see some parent-child well relationships that have caused some issues that are developing in some of the newer shale plays. These are things that we've seen over the past 7 or 8 years in the various resource plays that we've been involved in.

And, fortunately, in the Eagle Ford, where we operate, or 100% of our assets are located, we have the ability to -- a pretty good understanding of all these issues. We don't have significant political challenges. We have a good understanding of the reservoir, a good understanding of our asset base and understand what parent-child relationships look like and can appropriately account for those when we're running economics on our wells.

And that means that Sundance today is very well positioned to take advantage of market conditions in what seems to be setting up to be a pretty favorable 2019. We did, in late 2018, cut our development plan in 2019 as oil prices dropped. We have significant hedging in place, but at the same time, our philosophy is to run economics for wells at strip, to run our cash flow forecast at strip. And we feel it's a priority for us to manage the cash flow to grow the business. And we generate -- I think we'll generate pretty significant year-over-year growth.

But I think with oil prices having dropped in December, we did slow down the pace, particularly in Q1. And we've slowed down the pace for, really, the entire year of 2018. And we don't really anticipate materially flexing that at this point. Our main focus is executing the program that we put out a couple of weeks ago from a guidance standpoint, executing that well, beating the guidance, generating free cash flow in the second half of 2018 and delivering -- sorry, 2019 and delivering organic growth within that cash flow base for the company.

There's a couple of, I think, benefits -- or a few benefits I think that our shareholders should realize this year from the strategy. First, it preserves our balance sheet strength and liquidity. At the end of the year, we had about $50 million in liquidity remaining that we're not spending this year. We will use some debt in the first quarter. We'll draw some debt to pay for development activity for Q4. So we will see our debt balance increase in Q1. And then throughout the remainder of the year, we'll be operating within cash flow. And we should be able to retire or repay a portion of that debt, thus, preserving the liquidity as the company grows throughout this year.

Secondly, by slowing down our pace of development, and for this year, we've cut our development program from about 35 to 40 wells to about 23 to 25 wells. It extends the inventory life, the high quality inventory that we have in the Eagle Ford. And we really have seen some, I think, fantastic results out of the acreage that demonstrates the strong economics of the core inventory that we control in the Eagle Ford. I mean by cutting pace today, we have visibility to 17 years of future development, which gives us a good visibility to grow the business in a prudent, sustainable way to create shareholder value over the whole long term.

And then third, the third kind of key benefit to slowing pace a little bit this year is it reduces our decline profile moving into 2020, which reduces our 2020 maintenance capital requirements and should allow us to continue generating growth, production EBITDA and net asset value growth at higher rates than some of our peers or competitors. And we think that, that really sets the company up to create strong shareholder value over time.

Our focus is to generate growth in per share value, not absolute growth in production EBITDA and net asset value. We think 2019 sets up to be a very strong year to accomplish that. And the change in our development plan also positions the company to consistently create free cash flow and also per share growth in 2020 and beyond. We think this shift in the pace of development should really set us up to be a long-term sustainable business that can create shareholder value over time.

I -- to touch back on 2018, really our ability to do this in 2019 is set up by the execution that we demonstrated in 2018, which is a very transformative year. Early in the year, in early Q2, we closed the acquisition of about 22,000 net acres from Pioneer, which improved the quality of our inventory and extended the life of our inventory. Secondly, it put us in a position to generate significant EBITDA growth and EBITDA per share growth through the year. We achieved our full year EBITDA target of just over $100 million for the year. Now it means that in Q4, we generated about $48 million in EBITDA. And we exited the year with about $50 million in liquidity.

From a risk management standpoint, at the end of the year and moving into this year, in accordance with our strategy, we had a strong hedging profile that was protecting just under 7,000 barrels a day in 2019, about 5,000 barrels a day in 2020. We're continuing to execute that strategy. And so as we commit capital to new wells, we're putting hedging in place to protect the cash flow and the returns on that cash flow once that capital has been committed.

And I think lastly, excluding transient gains and losses such as unrealized hedging gains for the year, we generated return on capital in the second half, annualized return on capital of just about 10%, which is a significant improvement over our performance in the first half and in 2017. We generated free cash flow on our total invested capital of somewhere around 11%. And so while executing a strong growth plan and executing a significant capital markets transaction to fund the acquisition growth, we were still able to generate good full cycle returns off the balance sheet. And we do anticipate those returns being able to improve as we move into 2019.

So the fourth quarter results really concluded a transformational 2018. We exceeded the high end of our full year production guidance, producing just over 10,300 BOE a day with $100 million in EBITDA. From a development capital standpoint, we had guided the low end was $175 million and actual development capital was $176.1 million. So at the low end of the range. So during the year, despite executing a significant step change in the company's growth profile, we were able to control costs. We're able to bring wells online on schedule, and those wells performed, I think, exceptionally well versus what we were expecting.

As we move forward into 2019, we expect to be able to grow the business within cash flow. And we'll talk through the first quarter and the remainder of the year as we go through the presentation. And we will flex the program down if necessary, if prices drop for some reason, to ensure that we do operate within cash flow for the year and that we do generate some free cash flow as the year progresses. And as we move forward, philosophically, our goal with our cash flow is to use -- to prudently increase shareholder value. In the short term, that means, I think, reducing our net debt position either by holding cash or paying down the revolver or looking at other investment opportunities over time as free cash flow becomes available to do that.

Our high-quality asset base in the Eagle Ford is well understood. We're well located to consuming markets on the Gulf Coast in the U.S., which gives us access to the water and Brent pricing and also to the Gulf Coast refining complex in the U.S. And some of our assets, particularly in Live Oak and Southern Atascosa, are generating well results that are competitively some of the best wells, I think, not only in the Eagle Ford but some of the better wells that we've seen, I think, in the Lower 48 in the shale play.

That inventory, for the next handful of years, lets us drill our deep inventory of wells that have full cycle breakeven cost of around $30 a BOE, which means that we generate, I think, good and improving full cycle economics on the capital that we're investing this year and going forward and also gives us quite a bit of sustainability in the event there is another drop or continued depression in oil prices going forward. And if oil prices are higher, that also gives us the ability, obviously, to increase our profitability and generate incremental free cash flow to the business.

And that $30 a BOE number includes all the costs associated with acquiring the assets that we control today. So recovery of acquisition costs. It includes all of the development costs, transportation, marketing, infrastructure costs that we have to bear, all the operating costs, overheads. So it's really a full cycle cost before capital costs, before financing costs and really lets us generate, I think, strong profitability in a variety of different price scenarios going forward.

And then we do have, on top of that, about $6 a BOE -- just over $6 a BOE of interest costs that we spend, which means that in terms of the fundamental breakeven on the assets, we need oil to be around $38 a barrel to break even. And anything above that, obviously, we generate a profit. And from a -- and inclusive of paying our interest costs, we need oil to be somewhere in the low 40s to be able to break even inclusive of our interest costs.

So I think that gives us a very sustainable business model with our hedge position and our clean balance sheet to execute a growth plan for shareholders going forward. We do have -- we had about 50 -- just under $50 million of short-term liquidity at the end of the year. As I alluded to, we will use -- we will draw about $25 million in debt in Q1 to pay for development activity that occurred in the fourth quarter.

So from a cash flow standpoint, we will use some debt in Q1. But the accrual basis CapEx this year, so the capital cost and the liabilities associated with capital we incurred this year should be at or below what our cash flow number is for the year. And when we're looking at cash flow we're looking at EBITDA less interest costs in terms of being able to break even or generate free cash flow within that metric.

And then we do have a strong hedge book with over -- with about a $60 a barrel floor that protects the capital we're investing. And we've continued to add to that hedge book this year, and we'll continue to do so throughout the year to protect capital in the investment program.

Looking at the year in a little bit more detail on Slide 6. We did grow our EBITDA in Q4 to just under $50 million. So a run rate of about $192 million for the full year, which is a significant deleveraging for the company. On the last quarter annualized basis, debt to EBITDA, sitting at about 1.6x. We expect it to remain in sort of the 1.6x to 1.8x level this year. Prices are a little softer than our hedge book was in Q4. But we still anticipate being able to generate in the neighborhood of $175 million in EBITDA without increasing our debt on a full year basis in 2019.

Our production base grew pretty significantly in the fourth quarter. We produced above -- just under 14,200 BOE a day. We are shifting how we guide production. We historically guided production inclusive of flared volumes, and going forward, we'll be guiding to sales volumes. So there's a bridge in the last presentation we put out and in this presentation that shows the production and the sales volumes at relative periods. Going forward, we will just be showing sales volumes because we think that should make our results more transparent for investors.

We exited the year just under 16,000 BOE a day. We do anticipate production in Q1 decreasing a bit for 2 reasons. First, we significantly cut development activity moving into the first quarter. We effectively brought 2 wells online in early January. We have 2 wells coming online in late March. So there's very limited impact to Q1 production from new wells. So we'll have declines from the wells we brought online in the second half of last year.

And then secondly, we've had some constraints in our midstream facility in the Live Oak area that have cost us between 1,500 and 2,000 BOE a day of production and curtailments. Those facilities are being expanded. We've signed a letter of agreement with the midstream processor whereby we expect those curtailments to be lifted. They've starting to be lifted now, but we expect the final -- the project to be finalized likely between mid and late April. And so far, to date, that project is on track.

We're effectively adding 2 compressors to reduce line pressures around the project area and increase the processing capacity of the facility up to about 18 million cubic feet of gas a day. And we can bring, because of that, the associated liquid volumes in to be able to meet our midstream needs in Q1 and likely through the remainder of this year. We do anticipate, as the year progresses, we will likely have another expansion project agreed with the midstream provider. We'll provide more details of that as we come.

And in this agreement, the midstream provider is obligated to incur capital to meet the supply increases as we bring product there, up to $10 million in total capital spend. We don't anticipate exceeding that $10 million contingent asset this year or in the foreseeable future. So we anticipate that the capital spend associated with the facilities expansion will be handled by the midstream provider.

As I mentioned, we generated about $48 million of EBITDAX in the fourth quarter, allowing us to achieve our full year EBITDA target guidance. And our EBITDA margin for the quarter was about 73%, which was higher than the full year EBITDAX margin of 61%. It was a combination of a couple of things -- really 3 things. First, our strong hedge book allowed us to realize a higher price in Q4 than we did earlier in the year, inclusive of hedging. Secondly, we reduced our lease operating costs during the quarter. And then finally, we reduced our overhead costs and overhead expenses on a per barrel basis in the quarter. And primarily, we had staffed the business earlier in the year from an overhead perspective to execute this year's development plan. And so as volumes have come online, those fixed costs had been diluted across a larger production base throughout the year.

From a production and sales standpoint, in 2019, we anticipate producing in the neighborhood of 14,000 to 15,000 BOE a day versus our sales volumes this year. And that represents almost 50% -- or about a 50% increase versus what we achieved in the full year of 2018. It also represents an increase over the fourth quarter of just under 25%. And doing that within cash flow and without changing the shape of the balance sheet from the start to the end of the year, we think that, that represents pretty significant growth for our shareholders on a per share basis.

As I mentioned, we have curtailed about 1,500 to 2,000 a day volumes in Q1, due to midstream capacity constraints. Those constraints have started to be lifted here late in the first quarter, and the remainder of the project to be finished in mid to late April.

Slide 8 in the deck shows our more detailed guidance. You can see the first quarter of 2019 numbers there where we'll be selling midpoint of about 12,000 BOE a day. We're only bringing 4 wells online. But as I mentioned, there's pretty limited contribution from 2 of those wells during the quarter, and we are getting impacted by capacity constraints, the midstream facility, which will get alleviated by mid to late April. We will draw, again, about $25 million in debt this quarter to pay current liabilities we incurred in Q4 to finish our 2018 development program.

Beyond that, our accrual basis CapEx, we expect to be about $30 million, which we believe will roughly match up with cash flow in Q1. And then we expect that as we move forward the remainder of the year, and we'll provide more granular quarterly guidance as we come up to the quarters, we should be able to generate a little bit of free cash flow as we move into the second half of the year. And the $25 million in debt that we draw in Q1, we expect to be able to repay through the remainder of 2019. While we're looking at that, we're using a $55 million -- sorry, $55 oil price for WTI and $2.75 for gas.

For full year, we expect to sell about 14,500 BOE a day on about 25 new wells. Capital guidance is $135 million to $155 million range. We anticipate being able to achieve that -- those numbers and generate in the ballpark of $170 million, $175 million of EBITDA, which allows us to generate a little bit of free cash flow net of our interest expense for the year.

Skipping ahead to Slide 10. You can see where our assets are located at Eagle Ford. We currently sell through 2 different markets, which diversifies our customer base and the basis under which we sell. So about 30% -- 35% of our volumes today flow through Corpus Christi and are exported into the Brent market, where we receive Brent minus about $6.95. The remainder of our volumes flow through an agreement with enterprise up to the Houston Ship Channel, where currently we're getting a netback of WTI plus about $5. So all in, we're receiving a premium to WTI today that blends out to be in the neighborhood of $3.50 or $4 per barrel, which does generate, I think, strong economics for the wells that we're bringing online because of that strong well performance and also because of the strong environment under which we sell.

Slide 11 just gives a quick overview of our debt position. I think the 2 key things to take away from our leverage profile at the end of the year are, first, last quarter annualized debt to EBITDA was 1.6x, which represents about half of what our debt to EBITDA profile was at the end of 2017. So we went from about 3.2x to about 1.6x through the year. So a pretty significant deleveraging of the company. And then secondly, our proved PV-10 of our SEC reserves are about 3.5x our total outstanding debt. So we have about 3.5x asset coverage, which again, I think we have a very substantial and valuable asset base that effectively -- I think very effectively covers the debt and has delevered the company significantly through the acquisition and development of those assets during 2018.

Slide 12 looks at our 2019 plan versus some of our small-cap peers. First, you can see our leverage profile for the full year this year is really right down the middle of the U.S. peer set. So I think we're very comfortably levered for the year. And then secondly, you can see that our EBITDA multiple -- EV to EBITDA multiple based on this year's guidance is significantly below how the majority of our small-cap peers are trading. And we obviously believe that, that discount is unwarranted today. I think we generate similar or better returns than most of our peers. I think we're generating likely a higher per share growth profile -- or have a higher per share growth profile in production, cash flow and net asset value in 2019. And we believe as we execute this plan, that the multiple should expand over time in line with our peers.

Slide 13 just looks at the full cycle breakeven cost that we touched on earlier. It's about $30 a BOE all in to recover what we paid for the assets we're growing this year plus all the development costs and all the operating expenses. This gives a strong breakeven profile of about $38 a barrel for breaking even on the asset base. And so with oil trading in the upper $50s on a WTI basis, obviously we're generating pretty significant full cycle profits when we invest capital in developing our assets today.

14 gives an overview of our hedge book. We have added some hedging this year, as I mentioned, and we'll continue to do so. Our target is to be somewhere between 50% and 80% of our planned development program hedged out anywhere from 24 to 36 months. We do expect to continue increasing our hedge book in the second half of 2019, 2020 and 2021. We're not particularly price-sensitive from a hedging standpoint. We're hedging to protect invested capital. And so if we're making an investment decision to drill a well and we like the economics we achieve at strip, then we'll put hedging in to protect a significant portion of the cash flows both to recover the capital we invested and also to generate a return on the capital that we invested.

Slide 15 shows some of the wells that we brought online in 2018 versus some of our peer Eagle Ford wells. On a per 1,000-foot basis, our IP30, I think, stacks up with some of the best in the basin. We're using a conservative choke measurement strategy. So we're not inflating our IPs by cannibalizing future productivity of the wells. We're using a conservative choke opening strategy. And our high asset quality, the good quality of the rock and also our completion design are generating, I think, very good results that show our asset base sits really in the core of Eagle Ford. And so I think today, we have the ability to generate some of the best returns for our shareholders amongst peers in the Eagle Ford and some of the other basins onshore in the U.S.

So finally, to summarize on Slide 17. Sundance today has a strong asset base. We have 17 years of drilling inventory with low breakevens, and that lets us drive shareholder value creation and push our growth and production cash flow and net asset value in a variety of different oil price assumptions. We think that's a -- we think that we can generate a pretty significant shareholder value by executing a plan within free cash flow. We have a free cash flow neutral program designed for this year, and we have the ability to flex that program down as prices drop.

We don't have -- I think this year, we have 4 obligation wells, and the remaining 21 wells we're bringing online this year are completely discretionary for the company. For us to break even and to hold production flat this year, I think we have to bring on about 14 wells during the year -- 14 to 15 wells for the year to hold production flat from our exit rate of 2018 and to be flat for the entire year of 2019. So our maintenance capital is about 65% or so of our total capital budget for the year. The assets are located in a good spot both from a geologic standpoint and also from a pricing and midstream standpoint.

And finally, we've had a significant deleveraging through executing our program in 2018 with debt to EBITDA on a last quarter basis of 1.6x, 3.5x asset coverage from a proved reserve standpoint and expect to be generating free cash flow on the second half of 2019 and then likely able to increase that free cash flow generation as we move into 2020.

So, again, thank you for joining the earnings call and I'm happy to take any questions you guys may have.

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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 John Aschenbeck with Seaport Global.

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John W. Aschenbeck, Seaport Global Securities LLC, Research Division - Former MD & Senior Analyst [2]

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I just wanted to follow up on your prepared remarks around liquidity, which were great. There was a lot there. I just want to make sure I'm thinking of it correctly. So outside of the $25 million working capital draw, in Q1 you expect to be free cash flow positive for the remainder of the year assuming a $55 oil price going forward. Did I get that correct?

And then secondly, I was hoping you could provide some additional color on the options you have to enhance your current liquidity position.

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

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Sure. Yes, the plan this year is that after that $25 million draw, our program this year is cash flow neutral in the first half and then generates a bit of cash flow in the second half, which we'll use to effectively reduce our net debt position likely through repay the revolver.

In terms of enhancing liquidity, I think, there's a handful of options the company has. First, we've seen a pretty significant increase in the value of our producing reserve base. I think that we may have an opportunity to increase our borrowing base with our syndicate of first-lien banks through the year. It's not necessarily a high priority in the short term. But over the course of the year, I think that opportunity may present itself. Secondly, we are -- we have been marketing our Dimmit County asset for sale. We do -- we have removed the production volume of that asset now from our forecast this year starting in May. And we are negotiating a purchase and sale agreement with a potential buyer. There's no guarantee that we can get that PSA done. Obviously, PSA negotiations don't always end up in getting an asset sold. But we are negotiating a PSA at this point with a buyer that we believe has the capability to close on the deal. Thirdly, depending on market conditions, I do think high-yield markets here in the U.S. may be supportive of the company later this year. Effectively, we'll be using high-yield markets to refinance existing indebtedness. Again, that's completely contingent on market conditions. And it wouldn't be increasing our total debt position. It would simply be refinancing and terming out our existing debt to free up short-term liquidity under the borrowing base. Those are probably the 3 main areas that we have to increase liquidity as we look at 2019 here.

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John W. Aschenbeck, Seaport Global Securities LLC, Research Division - Former MD & Senior Analyst [4]

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Okay. Great. Appreciate that. And then one last follow-up for me, a higher-level question if you could entertain me. I was hoping you could share your thoughts on the value proposition of growth versus free cash flow generation, just especially as you think about those 2 options for a company the size of Sundance. And I guess I'm particularly interested in the -- I think you have a fairly unique background relative to most in our industry, more entrepreneurial in nature. So would just be interested to hear your thoughts on that front.

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

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Sure. Thanks again for the questions, John. I think that the industry today, I think, has to figure out ways to generate free cash flow and returns for shareholders. And so I think that the industry is really in an improvement phase. And I think when companies such as ourselves or others in the industry are able to prove that they can generate free cash flow, those that have been able to do that, I think, will have the privilege of potentially being able to accelerate their growth profile in the future. For a company like Sundance, if we generate $175 million in EBITDA next year, we can continue growing for a bit maybe next 5 years, 7 years within cash flow and generate some modest growth and generate some free cash flow. And then that should give us an opportunity to invest that cash flow either in other growth opportunities or in continuing to delever the balance sheet. But ultimately, we really need to continue growing the business or we need to look to join up with somebody else who's more effectively growing their business than we are. And so I think there has to be consolidation -- continued consolidation throughout the industry. It's been my view probably for the last 5 by 7 years. And I think that the industry should continue to consolidate. And so I think over time, a company like Sundance has to either grow or ultimately get consolidated. I think today, where our valuation sits, that's not our highest priority today. But over time, we need to execute on a per share growth plan. And then ultimately, either we'll have the privilege to grow faster or we'll end up being consolidated at some point down the road.

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Operator [6]

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Our next question comes from Lenny Raymond with Johnson Rice.

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Leonard Joseph Raymond, Johnson Rice & Company, L.L.C., Research Division - Research Analyst [7]

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I was just wondering if you could give us an update on possible timing of possibly switching listings to the U.S. exchange.

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

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Yes, we haven't made a firm commitment to switching listings. We have certainly spent a lot of time looking at it because we are concerned about our valuation metrics versus how our peers are valued given our relative performance. So we have spent a lot of time evaluating that in the background. We've seen a significant uptick in U.S. ownership. And so it may -- at some point, it may happen naturally anyway whether we do something about it or not. But it is -- we don't believe that the investment our shareholders have made in the company is being properly valued today. One of the numerous things we've looked at to improve that shareholder value proposition is a U.S. listing, but it's not something that we've committed to today. However, it's certainly on the table depending on what happens with our share price over time. Really our job is to create value for shareholders. And today, we're not doing an effective job of that at the moment. And so we need to figure out how to change what's happening with our share price and create value for our shareholders. So that's one of the things that we are looking at, along with a number of other fundamental and strategic options that we may have at our disposal.

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Operator [9]

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Our next question comes from Derrick Whitfield with Stifel.

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Derrick Lee Whitfield, Stifel, Nicolaus & Company, Incorporated, Research Division - MD of E&P and Senior Analyst [10]

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Eric, regarding your base decline comments, to what degree does the improvement in your base declines between year-end '18 and year-end '19 lower your maintenance capital for 2020?

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Eric P. McCrady, Sundance Energy Australia Limited - MD, CEO & Director [11]

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It should keep our maintenance capital at roughly 60% to 65% or 60% to 70% of our 2020 capital program. We're -- it's about where we are this year. It will probably increase slightly year-over-year. Had we executed the initial development plan, which should have been more in the neighborhood of 35- or 40-well program, our maintenance capital likely would have been -- instead of being somewhere around $100 million, our maintenance capital likely would have been more in the $175 million to $180 million range. So it's a pretty significant impact by taking about 15 new well IPs out of the development program this year. If you think about last year in 2017, we, I think, brought online somewhere in the neighborhood of 15 or 16 wells. We brought on about 22 wells last year. We grew year-over-year production by about 50%. And then this year, we're executing about 25-well program. So modest growth in well count. We're able to grow within cash flow. And so it moderated quite a bit just by changing the trajectory of growth. The downside, obviously, is it does push some of the cash flow out that we would generate from very strong investment options, very strong well performance and the cash flow we generate from that. So we get that cash flow at some point down the road versus getting it in the nearer term. Obviously, that is an impact or consideration from a valuation standpoint. But we think the ability to slow that decline, grow the business within cash flow and reduce that maintenance capital requirement moving into next year, we think, is invaluable for our shareholders. And then it preserves liquidity and it preserves the ability to accelerate that growth again down the road if there's a reason to do that, which today, we don't really see that reason the way we're valued or with where oil prices are today. But obviously, that may change in the future.

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Derrick Lee Whitfield, Stifel, Nicolaus & Company, Incorporated, Research Division - MD of E&P and Senior Analyst [12]

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Yes. That makes sense. And then referencing Slide 15, your '18 results are clearly impressive, as you've shown in that slide. Would it be fair to think or assume in 2019 and 2020 the result should be relatively comparable to that of 2018 given the current trajectory for growth?

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Eric P. McCrady, Sundance Energy Australia Limited - MD, CEO & Director [13]

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Yes. Our view is that Live Oak, Atascosa area, we have plus or minus 120 remaining locations. We're drilling, I want to say, about 18 of them this year. And so I think for the next 5 or 6 years while we're drilling those locations, our results, plus or minus, should be in the ballpark of what we've done here in 2018. The other area that we're excited about that we haven't tested yet is the La Salle acreage that we picked up from Pioneer. We may slide a couple of wells in the development program later this year in La Salle. Right now, because there aren't a lot of new IPs immediately offsetting that acreage with new completion designs, I think we're likely underestimating what those -- how those wells have performed. And so if that works, there's potentially another plus or minus 80 or 85 locations that we think could generate similar IP levels. We don't have enough information yet or confidence to really convert them and say that those wells will perform similarly yet to these La Salle -- or to these Live Oak, Atascosa wells. So I think at least the next 5 or 6 years, our results should be similar. And then I think as we move into La Salle, I think that has the opportunity to be similar as well. But we just can't say it with confidence yet.

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Operator [14]

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Our next question comes from Welles Fitzpatrick with SunTrust.

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Welles Westfeldt Fitzpatrick, SunTrust Robinson Humphrey, Inc., Research Division - Analyst [15]

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Did I hear correct that you expect the midstream constraints to be lifted, call it, in late April? And if I did, should we model that in as kind of a step change or maybe more gradually in to year-end?

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Eric P. McCrady, Sundance Energy Australia Limited - MD, CEO & Director [16]

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No, I think -- you did hear it correctly. We're -- we have 2 compressors getting installed right now. They're scheduled to be installed the week of 15 -- of April 15, and it should take likely 4 or 5 days to get the compressors installed. So I do think that's reasonable timing to bring those volumes online. I say mid to late April because capital projects have a tendency to take longer than we expect sometimes. And so, you know, I think late April is a very -- mid to late April is a very reasonable time frame to bring those volumes on. Right now, we're not -- in March -- as of March, we weren't seeing a real significant curtailment in oil volumes. We were electing to truck oil volumes from temporary facilities effectively to market to the pipeline. And so it costs us about an extra $0.75 a barrel at this point. And so it hasn't really curtailed the oil volume starting in March. What it does do is it costs us incremental flared volumes on the gas side. And so I think as we move into April, we should -- as the facility starts to be able to handle more gas, we should be able to reduce our flared volumes and start increasing our sales volumes. I would assume that change will be more gradual just because of the facility, as the capital project comes up, historically we've seen a few bumps and bruises from this facility when we brought more volumes online. But I think over the course of the second quarter, we should see flared volumes come down through that expansion. And then I think as we move into the third quarter, we should see pretty minimal flaring out of that Live Oak, Atascosa area through that facility.

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Welles Westfeldt Fitzpatrick, SunTrust Robinson Humphrey, Inc., Research Division - Analyst [17]

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Okay. Okay. No, that makes sense. And then when those compressors come on, can you talk to -- I mean, obviously, it seems like '19 is okay. I mean, is there some point in the future where you're worried that this could repeat? Or do you think you'll be pretty set once these facilities come on?

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Eric P. McCrady, Sundance Energy Australia Limited - MD, CEO & Director [18]

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I think we should be in pretty good shape. This takes us to about 18 million a day, which meets -- it's either at or very close to the peak of our gas volume curve this year. The stabilizers that we run the liquids and the oil through, they can handle 18,500 a day. We are working through some issues with stabilizers to make sure that they can handle the volumes. But worst case, we can truck around if we have to, although that's obviously not our preference. And so I think as we move into next year, I think our peak volume is expected to be in the -- off the top of my head and before we put up formal guidance, in the maybe 22 million to 25 million a day range. And so as we move into '19 -- or as we move into 2020, we do need some incremental capacity if we continue the pace of development in Live Oak and Atascosa. And we have a couple of options. One is adding some incremental compression, which we've already started working through with Enterprise for that facility. Secondly, we can shift some of the development to different assets, for example, our La Salle assets, if it's more economic to do that. And that reduces some of the capital needs at that Live Oak facility. So a couple different options to get us through this year. And then next year, we would need some incremental expansion but wouldn't expect that to be material capital cost for us.

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Welles Westfeldt Fitzpatrick, SunTrust Robinson Humphrey, Inc., Research Division - Analyst [19]

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Okay. Okay, that makes sense. And then I guess the implication there then is that after sort of midyear this year, the delta between sales volume and production volumes on Slide 7, that's essentially all going to be kind of low revenue per unit gas? Is it -- is that right?

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

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That's correct. That should be the majority of it. We'll -- I think we'll likely always have some flaring. And we do model some flaring in. But yes, it should be lower-value wet gas as opposed to having to curtail any oil volumes.

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Operator [21]

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And our next question comes from James Eginton from Tribeca.

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James Eginton, Tribeca Investment Partners Pty Ltd. - Investment Analyst [22]

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I guess from my point of view, I'm just curious, obviously, your guidance is going to be based on the type curve. I'm just looking at some of your IP60 rates that look quite impressive, particularly in the Live Oak, some of those wells brought online. I mean, what is the reason for the outperformance versus the type curve? And what potentially does it mean going forward in terms of what you're modeling on guidance versus what we're achieving on production?

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

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Sure. So the outperformance, I think, is driven by pumping modern completion designs in good rock. And so our type curves have been Ryder Scott's type curves are in compliance with SEC standards here in the U.S. And so we only have a year-end, in particular, we only had so much data from our wells. So I think we brought our first wells online in late August. And so we only had about just over 4 months of production data, which isn't really enough to make significant changes to type curves. And so at year-end, we did see some bump in the type curves from Ryder Scott. Although I do think, assuming the wells continue to perform, as we look forward into midyear, I do think there's room for pretty significant continued increases in the type curve volumes. And I think it's because the wells we're pumping were using, I guess, on average about 3x as much sand, about 3.5x as much water and pumping roughly 40% more stages than the offset wells that Pioneer brought online. They were pumping those frac designs in 2011, '12 and maybe early '13 before there's really a step change in frac designs in the Eagle Ford. And so I think we're benefiting from really good rock and pumping, I think, a good modern completion design that's generating, I think, good results.

In terms of our guidance -- and I think to quantify the upside, you know, I think we could see type curves increase by, over time, if wells continue to perform the way they are, maybe anywhere from 15% to 25% in that Live Oak and Atascosa area. Again, assuming the wells continue to perform the way we're seeing them today. I think in terms of our guidance, we're using, I guess, a hybrid curve between what Ryder Scott is using and our internal curves. So we do take some of the upside in our internal modeling. We need to do that for a variety of reasons. Obviously, planning cash flow and then also planning for facility needs as we move forward into 2019 and beyond. I think that the biggest impact on our forecast given our size is still just timing. And so I think type curve outperformance -- and if we outperform what we're using to forecast our production guidance by 25% or 30%, that can still get blown out of the water by a pad coming online 2 or 3 weeks later than what we expect. And so I wouldn't -- while I do think net asset value should be higher over time as the wells continue to outperform, and over time, and as we run a more consistent development program, the timing should become less of an issue. And so therefore, over time, I think that production guidance should be conservative. But in the short term, I would caution anybody looking at the numbers that we have baked risking in. But we've done that for a reason, we're running a one-rig program, which means at 25 wells, means we have about half of a frac crew for the year. So that can create scheduling challenges. And that's the biggest impact to our -- the timing of our production versus wells outperforming.

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James Eginton, Tribeca Investment Partners Pty Ltd. - Investment Analyst [24]

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And just a quick one around Dimmit. I assume all the guidance around liquidity is based on sort of an as-is case. And what's sort of the impact if you do sell Dimmit? Will you see some liquidity increase? I guess there's obviously some loss from some reserves lost. But what is the impact then from the Dimmit sale on that liquidity position?

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

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Yes. We've -- in terms of liquidity, we have not assumed in our liquidity forecasting sale of Dimmit, although we have removed the cash flow from the assets starting in May. I think if we do realize proceeds from that sale, I think, again, we would likely use that to reduce our net debt position for the year. And I think it would help smooth out, I think, some of the cash flow -- the normal cash flow bumps from month-to-month or quarter-to-quarter. But I think we haven't forecasted that improving our liquidity during the year aside from pulling up the cash flow. And so it would benefit our potential liquidity position this year if we can successfully sell that asset.

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James Eginton, Tribeca Investment Partners Pty Ltd. - Investment Analyst [26]

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And then from that perspective, would it change anything on the development over the -- I mean, at this point in time? Or what oil price do you start looking at changing the development program?

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Eric P. McCrady, Sundance Energy Australia Limited - MD, CEO & Director [27]

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Yes. Right now, we look every quarter at the development program. And we look at our free cash flow and our cash flow and liquidity position and the run economics on what we want to drill and then commit capital and hedge it. Right now, we're not really expecting to flex this year's development program based on increases in the oil price. I think that would increase our free cash flow position. And that free cash flow could potentially, down the road, be used to change the pace of development or it could be used for retirement of debt. It can be used for potentially a return of capital. It can be used to look at acquiring bolt-on leases of other assets. And so I think if oil prices do go higher, we'll treat any incremental free cash flow with respect and figure out the best way that we can deploy that to improve shareholder value. And so I wouldn't expect us to materially change the development program if oil ticked up for a quarter by $10 or something like that. I think if oil continued to tick up and our stock price is performing, then maybe we would be incentivized to relook at development as a use of some of that incremental free cash flow. But the way it sits today, the focus would be let's just generate that free cash flow and then use it to reduce our net debt position, which increases liquidity. And that gives us more optionality down the road.

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Operator [28]

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(Operator Instructions) And I'm showing no further questions at this time. I'd like to turn the call back to Mr. Eric McCrady for closing remarks.

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Eric P. McCrady, Sundance Energy Australia Limited - MD, CEO & Director [29]

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Thanks, Catherine, and thank you for all your time and participation in the call. We look forward to executing on the program in 2019, generating free cash flow and significantly growing per share value. So thank you again for all your participation.

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Operator [30]

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