Sundance Energy Australia

Published : August 04th, 2015

Edited Transcript of SEA.AX earnings conference call or presentation 31-Jul-15 4:30am GMT

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Edited Transcript of SEA.AX earnings conference call or presentation 31-Jul-15 4:30am GMT

South Australia Aug 4, 2015 (Thomson StreetEvents) -- Edited Transcript of Sundance Energy Australia Ltd earnings conference call or presentation Friday, July 31, 2015 at 4:30:00am GMT

TEXT version of Transcript

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Corporate Participants

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* Eric McCrady

Sundance Energy - CEO, Managing Director

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Conference Call Participants

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* Tim Masters

Canaccord - Analyst

* Sam Berridge

Perennial Value - Analyst

* Scott Simpson

GMP Securities - Analyst

* Mark Hume

Colonial First State - Analyst

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Presentation

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Operator [1]

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Good day, ladies and gentlemen and welcome to the Sundance Energy Second Quarter Earnings Call.

At this time all participants are in a listen-only mode. Later we will conduct a question and answer session, and instructions will follow at that time.

I'd like to turn the call over to your host Eric McCrady, Managing Director and CEO of Sundance Energy. Please go ahead.

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Eric McCrady, Sundance Energy - CEO, Managing Director [2]

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Thanks, Patrick. And thank you all for joining Sundance's Second Quarter Earnings Call.

World oil prices obviously continue to pose significant challenges and coupled with high debt loads in the US are changing the dynamics in the industry in which we operate. Fortunately Sundance is in the unique position to capitalize on these changing dynamics.

We have a high quality asset base well located in the valuable oil window of the Eagle Ford with strong existing production at top-tier cost structure with operating cash flows sufficient to grow share growth value during the cycle.

We have a clean balance sheet and limited forward commitments that can be met within cash flows. These characteristics allow us to grow shareholder value opportunistically during this cycle.

Sundance today has about 38,000 acres located primarily in the volatile oil window of the Eagle Ford [pro forma] for the new standard transaction that was announced in June, we have about $21 million of BOE of approved reserves. And second quarter Eagle Ford production of 7,300 BOE a day.

This puts the Company in a strong position to continue growing through the drill bit as commodity prices recover and give us a good footprint in the valuable part of the Eagle Ford trend to capitalize on the opportunities that we see coming out during this downturn.

During the second quarter Sundance achieved a total production rate for the year, year to date of 8,500 BOE a day. During the quarter our production rate was about 7,500 BOE a day.

The primary driver of the decrease in the production rate from the first quarter to the second quarter was shutting in wells associated with bringing an amine facility online to treat H2S to us in our McMullen County project. The McMullen County project is now substantially 100% of flowing gas to sales.

From a cash flow standpoint the Company achieved approximately $22 million -- sorry, $41 million in EBITEX for the full year and $19 million for the second quarter.

Our margins respectively were 75% and 73%. It's particularly impressive that our operations and financial groups were able to maintain margins above 75%, 73% despite over a 50% decrease in commodity prices during the period.

The primary driver behind these improved margins was decreased field costs which were just under $9 of BOE for the year. These were driven by slight improvements in these operating costs, reductions in taxes, and also from a total cash cost standpoint an additional reduction in G&A during the quarter.

We've continued to focus on growing the business so that we're able to dilute the G&A load within the Company, and anticipate that we'll be able to maintain this cost structure moving forward throughout the year.

Capital expenditures during the quarter on an accrual basis were about $21.5 million. So during the quarter we cash flowed about $19 million and had capital expenditures of about $21.5 million.

Significantly the drilling and completion capital expenditures during the quarter were only about $14 million. So our forward growth was funded during the quarter out of cash flows.

On the year to date basis total capital expenditures was just over $50 million, on operating cash flows of about $41 million.

If we exclude facilities spend our capital expenditures were actually about $37 million, so again, our drilling and completion capital expenditures were funded out of operating cash flows for the first half of the year.

We anticipate being able to continue this trend moving into the third and the fourth quarter, and in fact expect that we'll be able to maintain and slightly grow the business within cash flows during 2016 and likely into 2017 even at current stripped prices.

There's two other significant transactions that occurred during the quarter. First, we announced an acquisition of New Standard Energies, Eagle Ford and Cooper Basin Assets.

There's some other, some additional assets that we are acquiring along with that acquisition, at approximately at 12% stake in Elixir Petroleum, approximately 28,000 barrels or 28,000 puts covering 28,000 barrels of hedges at a average price of about $78. And some current assets and current liabilities associated with these standard assets.

The 5,500 acres that we're acquiring in the Eagle Ford come with just under 200 BOE a day of production. And importantly there's two well bores that have been drilled but not completed.

We anticipate completing both of those well bores in the second half of the year. And expect that those investments will be highly accretive for our shareholders given that the drilling expenditures have already been incurred. We're anticipating that that transaction will close within the next approximately 10 days.

With the Cooper Basin asset, while we haven't done an initial technical review of the asset, we do anticipate divesting those assets at some point in the near future.

Sundance is primarily focused on growing the business in the Eagle Ford, and so, while we like the Cooper Basin assets and the prospectivity of the PEL-570 license, it's an asset that over the next six to twelve months we expect that we will divest and invest the proceeds in our Eagle Ford assets.

And the second significant transaction during the quarter was the refinancing of our credit facilities with Morgan Stanley. The credit facility -- the new credit facility effectively provides the Company with about $100 million in total liquidity to pursue small acquisitions in our core area of the Eagle Ford and to fund when oil prices recover some additional development moving forward.

So we're very happy with the deal with Morgan Stanley. Pricing on the transaction, really, there's two components. There's a second lien term loan for $125 million that's priced at LIBOR plus 700 basis points. And a first lien revolver of $75 million that's priced at LIBOR plus 200 to 300 basis points depending on the amount drawn.

There's also a $50 million accordion term loans that's committed and available subject to covenant compliance. Again, that's primarily available to restart drilling or for small bolt on acquisitions in our current core area.

Morgan Stanley is a relatively new entrant to the E&P lending space and set the business up with an eye to capitalizing on -- capitalizing on the downturn, and also taking advantage of some new banking regulations in the US that they've structured -- that they structure around adequately.

From a production standpoint the second quarter production decreased moving into May and June due to the shut-in of wells around the amine facility. So effectively we have seen increased H2S levels in our McMullen County project and we're flaring gas to mitigate or to allow us to produce oil out of the wells.

The amine facility is a low-cost solution to treat the gas for H2S. That facility went operational in mid to late June. And is running very well today and treating gas from about 20 wells that are located around the facility.

In early May we've made a decision to shut those wells in an advance of the amine facility, really for two reasons. First, just to ensure we got the facility up and running safely. And second, to preserve some of the gas revenue that we expect that we'll recover later in the second, and moving into the third and the fourth quarter from the wells that were shut in.

The impact of the shut-ins from the amine facility were approximately 1,000 BOE a day across the quarter. And so, you can see from a production standpoint on the first quarter we produced about 9,500 to 9,600 BOE a day. April was about 9,100 BOE a day.

And then you can see the impact of the well shut-ins as you move into May and June.

The majority of those wells have now been brought back online. The gas is being treated through the amine facility and they're generating cash flow.

We do still have a handful of wells shut in for facility improvement projects and we expect that those wells will be brought back online late in the third quarter.

For the remainder of the year we do reaffirm our production guidance, of the midpoint of about 8,150 BOE a day. And we anticipate the third and fourth quarter production will be between 7,500 and 8,500 BOE a day each quarter. So we expect production to increase slightly from the second quarter and then remain relatively flat throughout the remainder of the year.

Moving into 2016 we expect again that we'll be able to meet our development obligations and our leases that are economic and grow the business slightly within cash flow.

As you can see on the chart on slide 9 this year we're expecting to have total CAPEX of about $90 million, and cash flows are sitting right around $90 million as well at strip.

And moving into 2016 our cash flows are actually slightly higher than our expected drilling complete budget. And so, we do have the ability next year to grow production. Actually it's about 10% from the exit rate this year to the exit rate next year within cash flows.

The reason that we're able to do that is because of our clean cost structure, our tight cost structure and our clean balance sheet and our focus on oil. Even though oil has dropped, we're still price advantaged to be focused on oil compared to gas.

The increase in production on an annual basis does provide significant cash flows for the business going forward. We've grown production just under 25% on a year over year basis despite the drop in pricing without out-spending cash flows for the entirety of the year.

The capital budget this year represents about a 70% decrease, so the fact that we're actually able to grow production speaks to the quality of the asset base and the forward potential as prices recover for us to out-perform from a growth standpoint.

A key focus of the business during the second quarter and the remainder of the year has been optimizing field performance. And we've undertaken a review of our field operations inclusive of our facilities, our gathering systems, our pumping methodologies and a variety of other kind of day to day operations in the field.

And as we've evaluated those we've identified a number of opportunities to either increase revenue through new contracts, new sales contracts through treating H2S more effectively, or by more effectively producing the wells in the long term, and reduce the cost profile of the field.

Some of these include the amine facility installation of line power into the key producing regions in the field and optimization of the compressor system in the field that reduce line pressures. All of these projects have been kicked off and have various completion dates.

The average payout on these projects is running somewhere between or somewhere around six to nine months. And so, the capital is being spent in a very prudent manner that will generate significant benefit to our shareholders from a return standpoint.

Liquidity wise we have about $100 million in -- just under $100 million in liquidity at 30th of June. We have increased our hedging position as oil moved up into the low 60s for a while during the quarter.

We've significantly increased our hedging position using primarily broad [collars] to protect cash flows going forward.

The way we've looked at the hedging effectively was if we see a $10 drop in pricing below the floor of the hedging, that's equivalent in cash flows to a $10 increase above the ceiling of the pricing that we have in place.

And so, with oil today sitting around or just under $50 this provides some certainty for cash flow and allows us to execute our business plan going forward within cash flow.

And as mentioned in 2015 year over year productions of 14 to 15 production increases about 25% within cash flow. And then moving into 2016 within cash flow, we were able grow year over year production. And in particular exit rate production by about 10% moving into 2016 within cash flow.

Our position in the Eagle Ford is about 38,000 acres. The two primary assets are the McMullen position and the Dimmit position, both about 19,000 net acres.

Within the McMullen position we include our asset base in Southern Atascosa County that's primarily surrounded by EOG. So we do like the assets, both in McMullen and Atascosa.

The Dimmit assets are surrounded by -- primarily Anadarko and Chesapeake. We've seen good early results and have a couple of wells going, and we'll talk about it in a couple of slides here.

In the first half we've produced about 7,200 BOE a day in the Eagle Ford, and have only one remaining obligation well during the remainder of the year which is actually in Dimmit County.

With that obligation -- well, we've actually spud the well and I think we're actually pretty close to TD'ing it at this point. And then once the well is completed we likely won't -- sorry, once drilling is completed on that well we likely won't complete the well until early 2016.

And the McMullen County position to date we've drilled approximately 73 net wells, and then we've acquired an additional nine wells with the New Standard acquisition. So all in we have an extensive track record of successfully bringing wells under production here.

During the past two years we've been operating here. We've been able to reduce capital expenditures from the initial acquisition at about $12.4 million a well down to similar -- for a similar length, about six million a well a day or just under $6 million a well today. So we've reduced capital expenditures by about $6.5 million per well.

And during that time period we've increased the 2PEUR by about 100%. So when we acquired the asset the 2PEUR was about 250,000 to 275,000 BOE. And today the 2PEUR is about 500,000 to 510,000 BOE.

So we've seen a significant value of accretion in this project through our ability to execute. We do have extensive drilling inventory remaining in McMullen County, and are seeing significant opportunities to grow our position through direct leases with landowners and small bolt on acquisitions similar to the New Standard transaction that we announced back in June.

Dimmit County is an earlier stage project. We have about 2,300 gross, 19,000 net acres. We've drilled at eight wells. Four of those wells are producing, two of them are flowing back and two are waiting on completion.

Significantly the two wells that are flowing back are just under 10,000 foot laterals. We are able to drill those wells for approximately $8 million per well, with 10,000 for laterals. We pumped an average of 42 or 43 stages on each well.

If we had drilled the same spacing with two 5,000 foot laterals, our well cost would have been more like $10 million to $10.5 million. So by being able to drill one 10,000 foot lateral at this depth, as opposed to two 5,000 foot laterals we were able to carve an excess of $2 million a well off of the effective cost on a per foot basis. And that should significantly improve economics in the Dimmit County project going forward.

Those two 10,000 foot laterals have been completed and are fully back. We expect production results on these wells, at least initial production results to be available at some point here in the third quarter.

The other two 10,000 foot laterals are waiting on completion and we anticipate completing those wells later in the second half of 2015 here.

Lastly the economics in the project with the decrease in strip pricing still remain accretive with, you know, the strip slightly in contango. Both projects remain economic today. We are able to generate positive shareholder returns by turning the drill bit either in McMullen or Dimmit County.

I would expect, I think in the second half of the year, we have nine wells scheduled for completion. And so, we will see some new production coming online as part of the business plan in the second half. And either very late this year or early next year, we'll pick up a rig again depending on what happens with the pricing to meet our 2016 obligations. Again, assuming that strip stays where it is or increases a bit from there.

So in summary Sundance has a good asset position in the volatile oil window of the Eagle Ford, covering about 38,000 net acres. We have existing production for the year of about 8,150 a day. And we're able to lift that production base, meet our capital expenditure plan for this year and next year out of cash flows.

We have a clean balance sheet with very limited forward commitments. And have the ability with our liquidity position to pick up small leasesin bolt-on transactions in the area to accretively grow shareholder value while prices are low.

So thank you for your time. And I'm happy to take any questions that any of you may have.

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Questions and Answers

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Operator [1]

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(Operator Instrucitons).

We have a question from Tim Masters with Canaccord. Your line is open.

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Tim Masters, Canaccord - Analyst [2]

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Hey, Eric, thanks for the call. I have a few quick questions. Just on your completions, I guess, can I just confirm that though that you only -- two, in Dimmit were the only wells that you completed the quarter.

And it looked like you only drilled one well as well?

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Eric McCrady, Sundance Energy - CEO, Managing Director [3]

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That's correct. We actually didn't bring -- we didn't have any new production come online during the second quarter.

We completed the two Dimmit wells late in the quarter and started flowing them back kind of late June and early July.

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Tim Masters, Canaccord - Analyst [4]

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Yes, okay. And then are you expecting to do nine additional completions through Q3 which I expect will be backend dated and into Q4, is that the way to think about the time?

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Eric McCrady, Sundance Energy - CEO, Managing Director [5]

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Yes, it's nine completions in the second half and that's two in Dimmit, three -- sorry, two in -- actually within that nine that's including the two -- the two Dimmit wells that we fracked in the second quarter but started flowing back in the third,. so technically seven new completions in the second half.

Sorry about that--

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Tim Masters, Canaccord - Analyst [6]

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Yes.

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Eric McCrady, Sundance Energy - CEO, Managing Director [7]

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But then, yes, it's two Dimmit wells, three McMullen wells on the [Hoskins] lease, and then the two wells that we acquired that were drilled, but not completed from New Standard.

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Tim Masters, Canaccord - Analyst [8]

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Yes, okay. And that should give you still some completions inventory then if that is including the New Standard inventory?

You probably have another - by my math, that's another 2.6 wells waiting on completion, going into 2016, is that right?

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Eric McCrady, Sundance Energy - CEO, Managing Director [9]

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Yes, I think just over that because we'll be drilling a well down at Dimmit County during this quarter as well.

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Tim Masters, Canaccord - Analyst [10]

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Yes. Okay, great. And on the Dimmit acquisitions previously is there still a cash out flow that needs to go through in association with that acquisition? Or earn-out which will come through when you complete -- I think it was your sixth wells?

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Eric McCrady, Sundance Energy - CEO, Managing Director [11]

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No, there's no -- Dimmit doesn't have any remaining acquisition cost and there's no earn-out on any of the Dimmit acreage -- the earn-outs on the -- is about 4,800 acres in McMullen that's subject to an earn-out. It's basically 2,000 an acre when we spud wells. And then it's 2,000 an acre when the project hits pay-out in McMullen County.

We're not expecting spudding any wells in McMullen, any wells on that project which is called the [Turb] canyon project or the Magnum project until 2016.

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Tim Masters, Canaccord - Analyst [12]

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Okay, great. And then just one final one, and the Anadarko production looks pretty strong. Obviously it's flat quarter on quarter, can you just provide a little bit of detail around, you know, decline rates and what you're seeing there.

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Eric McCrady, Sundance Energy - CEO, Managing Director [13]

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Yes. We have seen -- production has held in pretty well and in part due to some non-opt completions from earlier in the year.

But what we've generally seen type curve wise in Anadarko is relatively high IPs, relatively fast initial declines, and then very limited declines after that. So once the wells hit sort of, you know, 50 barrels a day or 30 to 50 barrels a day they stay pretty flat and don't really decline much at that point.

And so, we're in a position - at least at the operated production where we've come through the flush production. And there's been very limited decline in those wells.

Actually, the initial decline was faster than our early type curves and now the more terminal decline rates actually have been much slower than what our initial type curves suggested.

So we do anticipate production declining there. We're not really investing much capital there the remainder of this year. We have three growth wells that we've drilled that we haven't completed yet, that we'll likely complete early 2016.

So it's an outside job, and we'll do them in the fourth quarter if prices are strong. But most likely they're a 2016 completion, so we'd expect the season declines out of the Anadarko the remainder of the year. But we've overall actually been happy with the terminal decline rates we've seen from some of the older wells.

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Tim Masters, Canaccord - Analyst [14]

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Okay, brilliant, thanks a lot.

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Eric McCrady, Sundance Energy - CEO, Managing Director [15]

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Thanks, Tim.

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Operator [16]

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(Operator Instructions).

We have a question from Sam Berridge with [PVN]. Your line is open.

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Sam Berridge, Perennial Value - Analyst [17]

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Hey, good day, Eric, it's [Sam Berridge] from Perennial Value here.

I just wanted to ask with your gas hedging is there anything we need to do for the hedge price to reconcile back to your achieved price for the quarter just gone, or is it sort of a straight sort one to one comparison. There's no other sort of factors in between.

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Eric McCrady, Sundance Energy - CEO, Managing Director [18]

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Yes, there's no other major offsetting factors. We do pay a pipeline tariff and there's some shrink associated with moving gas through the line than -- I think in the current quarter there is actually some prior period adjustments from a revenue standpoint.

But overall the hedges are a mix of [Henry hub] and Houston ship channel, which is generally how we've marketed our gas. So, you know, generally speaking we're selling on an index and the hedges are on index so they match up from a risk management standpoint.

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Sam Berridge, Perennial Value - Analyst [19]

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Okay, got you, thanks. And just checking in the -- I think you guys are about $25 million CAPEX over the next quarter. I'm just curious as what's that going toward, saying that it looks like just stuff other than drilling.

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Eric McCrady, Sundance Energy - CEO, Managing Director [20]

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Yes, I think probably just under $25 million. So it's a mix. We're drilling one well. We'll be running, starting in sort of early August or running, you know, not a dedicated frack crew, but a lot of -- most of our frack crew the remainder of the year. So we'll likely frack or complete all or a portion of, you know, probably three to four wells in the third quarter.

And then as we've worked through the field optimization projects there's handful of CAPEX related pump changes and other facility changes that we're finishing up in the field, that we have incurred this quarter, and so, all liens in terms of drilling and completion capital during the quarter, I think we're expecting somewhere in the neighborhood of $16 million to $18 million. And then the facilities and others are sort of in the $7 million to $8 million range.

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Sam Berridge, Perennial Value - Analyst [21]

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Okay, got you. And just so last question I think previously I had you penciled in for some -- at about 62,000 barrels worth of hedging at about $90, but it's pretty small amount. But I'm just curious is that being cashed out and now sort of replaced with the new hedging that you've put in your presentation or is that still in place?

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Eric McCrady, Sundance Energy - CEO, Managing Director [22]

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No. It's still in place. We just presented a weighted average hedging as opposed to all the individual hedges.

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Sam Berridge, Perennial Value - Analyst [23]

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Okay. Beautiful. No worries. All right, thanks very much.

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Eric McCrady, Sundance Energy - CEO, Managing Director [24]

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Thanks, Sam.

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Operator [25]

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The next question comes from Scott Simpson with GMP Securities. Your line is open.

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Scott Simpson, GMP Securities - Analyst [26]

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Oh, yes, hi, Eric. [Good all on the results].

Just quickly on, I think you said here going into the second half of 75 to 85. And you can see from this quarter there's about, I think, you said 1,000 BOE a day of [shut] volume. And so, just bringing those back and brings you in line with that.

Then, I think there was about, what, 30 wells, no, no, a bunch of them was shut in for other facility upgrades. And you've got additional wells being tied in.

Just wondering if that sorts of looks conservative, or, I mean, is it just sort of factoring in decline across the production base?

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Eric McCrady, Sundance Energy - CEO, Managing Director [27]

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Yes, it's a mix. I mean, it's factoring in declines across the production base. And then, you know, that there is a component of conservatism in our forecasting. I mean, the primary factor is really just the declines coming in, you know, across the wells we brought online late last year. They got offset by some of the wells coming back online and by some of the new wells we're bringing online.

The Dimmit wells, generally, we don't see oil productions or 30 to 60 days after we complete them. We generally see a period of water flowback, frack water blwoback before we start seeing oil. And so, there's some delays in terms of getting new production out of the the Dimmit County wells factored into the -- factored into those numbers.

So there's a handful of things that go into it. We think the range is -- it's a reasonable range. And all things equal we would expect obviously 7,500 to 8,500 means, that our expectation is around 8,000 days for the remainder of the year.

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Scott Simpson, GMP Securities - Analyst [28]

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Sure. So I mean if you were to think about those nine additional operated [other] wells you're looking to bring on, and when will actually production hit the lines that you use that for -- you know, how would you think about it in terms of September quarter and December quarter and their contributions.

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Eric McCrady, Sundance Energy - CEO, Managing Director [29]

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Yes, so -- yes, the first two will likely start cutting to oil sometime in early September. So we'll probably have or three wells that start producing oil in September and the remainder will probably start kicking in, in the fourth quarter.

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Scott Simpson, GMP Securities - Analyst [30]

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Okay. That's good. And I might have missed the answer on this before, but in regards to New Standard acquisition in payment there, just run me through the, what was it, $14.6 million, was it pay-up essentially, there's also some additional working capital.

Has that been paid or is that in the upcoming quarter? In the kind of the August and September quarter?

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Eric McCrady, Sundance Energy - CEO, Managing Director [31]

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Yes, it will be in the September quarter. It will be, I think closing scheduled for the, what is it, the 6th of August off the top of my head. And so, we would settle the Credit Suisse note at closing. And then I would expect we'll close the farm-out on that transaction shortly thereafter.

It would probably within, either simultaneously or within a couple of weeks of finalizing the New Standard deal. We'll bring a partner in and that will offset 25% of the costs associated with the New Standard transaction.

We're actually able to do that at a promote, so our partner is coming at a premium to the price that we're paying for the New Standard assets. And then they are also picking up a portion of our Charlotte Ranch asset. It will really get into the -- around our cost basis or slightly of our cost basis on the Charlotte Ranch asset.

So, I think all in we're expecting to realize just under $8 million from the farm-out of that transaction for 25% of it.

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Scott Simpson, GMP Securities - Analyst [32]

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Right, so just to think about it from August, just putting a cash number in. That model's -- it's realizing -- I guess what you sort of all in cash outlay, you know, netting it out that quarter?

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Eric McCrady, Sundance Energy - CEO, Managing Director [33]

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Yes, it's probably -- it's probably about $15 million going out and at $8 million coming in from the farm-out.

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Scott Simpson, GMP Securities - Analyst [34]

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Okay. Yes. And I mean just essentially on the acreage I will just be interested in your views, I think, with sort of saying that previously, you know, I'm thinking sort of head, 20% or 30% around -- I think when I look through it at the overall process.

I mean, do you see some optimization you can work into the previous well designs. Is that the way you sort of looked at the transaction?

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Eric McCrady, Sundance Energy - CEO, Managing Director [35]

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Yes. There's two main leases, the [PELR] lease which is just under 2,000 acres, we think should be similar to the economics we are seeing at our McMullen project. It should be a little higher GOR than the other leases we acquired from New Standard.

And overall the PELR lease it's a pretty good lease. So I think we can generate reasonable economics there, even in somewhat low prices.

The other two leases, the [F-Bright] and the [All Right], I think are their names sit around our Charlotte Ranch acreage. We like the assets but they're not quite as high of quality as the McMullen asset base.

We do think by drilling longer laterals we can optimize the cost profile of the wells and likely improve recoveries with better fracks.

The key, really, the first key strategy operationally is to link the laterals, to drive down the effective cost per foot of drilling those wells.

There are other operators and sort of just north and east, I guess that we acquired, so there's a company called Cinco, it's a private company that sold to Atlas for $350 million. It has assets, you know, that lies just north and east of the Charlotte Ranch and the F Bright lease.

And by what we've seen out of that asset base is that they've extended laterals. They've seen no real degradation in reserves or recoveries per foot, and a significant drop in CAPEX per foot. And so, applying a similar strategy operationally should improve the economics on the leases in the area.

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Scott Simpson, GMP Securities - Analyst [36]

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Sure. And, say, how many, I guess, essential -- essentially how many well locations would you think about adding to the inventory. I think it was a sort of 50 to 60, I think it was a fair estimate. Is that what you're thinking?

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Eric McCrady, Sundance Energy - CEO, Managing Director [37]

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Yes. It's probably a little less than that since we're drilling longer laterals. And I think all in on a gross basis, I want to say we're planning 40 to 50 locations on the 5,500 acres.

And, again, I think those are generally longer laterals. So on a -- and so, on a net basis I think we're adding sort of 30 to 38 net long lateral locations. But we have to go through the, you know, year end and we'll work through the exact location and (inaudible) slow. But internally that's about what we're -- it's about how we're working at the asset.

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Scott Simpson, GMP Securities - Analyst [38]

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Thanks, Eric. That's all I have.

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Eric McCrady, Sundance Energy - CEO, Managing Director [39]

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Great, thanks, Scott.

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Operator [40]

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Our next question comes from Mark Hume with Colonial First State. Your line is open.

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Mark Hume, Colonial First State - Analyst [41]

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Yes. Hi, I just wonder if you could help us understand where [PDP] decline rates are tracking, given that the slightly more [pampered] piece of growth (inaudible) lead to a shallow decline, making it vast easier to grow in the out years, that at least is what's happening with the (inaudible) standpoint.

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Eric McCrady, Sundance Energy - CEO, Managing Director [42]

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Yes. And in terms of initial declines, I think from a modeling standpoint today we're using a B of 1.1. And then I think, I want to say QI depending on the area that ranges between about 50% and 65%.

And that really kicks in three to six months into the well's life. The first three to six months we -- since we use a controlled choke the wells stay relatively flat. And then for a terminal I think we're using the 6% or 7% terminal depending on the area.

And so, obviously with a bunch of wells coming in on 2014 with new IPs, obviously the PDP component of the production base declines this year. And that's why we see a decrease in, you know, exit rate production. So exit rate was about 9,500 to 9,600 a dat last year.

This year with some new wells coming online we're expecting an exit rate that's about 7,500 to 7,800 a day. And so, with the new wells coming online I think the PDP base ends up being around 5,500 or .6,000 a day, sometimes about 5,500 a day. And so, the new wells make up the difference on a net basis.

--------------------------------------------------------------------------------

Mark Hume, Colonial First State - Analyst [43]

--------------------------------------------------------------------------------

And I guess slightly related question, huge swings and falls in (inaudible) particularly in North America, arguably with the export, better alignment than we're offering.

Where do you see the [PDP] falls striking? I guess, it's really to (inaudible) kind of (inaudible) CAPEX [stated] instead of (inaudible). You know, what was it that caused the inflation (inaudible)?

--------------------------------------------------------------------------------

Eric McCrady, Sundance Energy - CEO, Managing Director [44]

--------------------------------------------------------------------------------

Yes, so current FEs and obviously it depends on the lateral lengths. But what we're seeing today drilling costs surprisingly aren't all that tied to lateral links. We were able to drill the lateral pretty quickly.

And so, we're running, you know, drills, really, full site on drilling, cementing and casing, I think is running somewhere in the neighborhood of $2 million to $2.2 million today. And then we're running somewhere around $120,000 a stage, all in for the full -- for the full job inclusive of facilities and spread cost and all that stuff.

And so, for sort of -- and then on top of that for the actual service facilities, and when I say facilities I mean just all the infrastructure around the completion. And then the facilities are running 300,000 and 500,000 a well or something like that.

So, for a typical 6,000 foot well in McMullen today we're seeing -- I got a current AFE cost between about $5.5 million and $6 million. For longer laterals, the drilling cost obviously stays the same, and then it scales up. Really just on the completion side for additional stages, I think we're using 220 foot spacing or 200 foot spacing is a typical stage spacing.

And our forward modeling I think we're using basically a base 6,000 foot well at about $6 million a well. We've actually -- we have that modeled out so we actually have the specific locations defined. And so, we have it scaled up or down as a model based on the actual lateral length.

So current AFEs are tracking just under what we'd take into the forward capital plan. We also use a contingency factor, and the AFEs, about 5%. And while on a typical well we don't actually eat into the contingency. It seems like about 5% to 10% of the wells we either eat into the contingency or go slightly over it.

And so, it actually gets make up for across the portfolio of wells. So it's a long way of saying that, you know, a base 6,000 foot well today is about $5.8 million. We've modeled that same well with about $6 million, and that's captured probably 35% cost deflation.

Right now we're working with the service companies to walk in our 2016 and potentially 2017 program depending on the pricing that we can get, so that we can capture some of these lower costs going forward in the development program.

--------------------------------------------------------------------------------

Mark Hume, Colonial First State - Analyst [45]

--------------------------------------------------------------------------------

Okay, thank you.

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Eric McCrady, Sundance Energy - CEO, Managing Director [46]

--------------------------------------------------------------------------------

Thanks, Mark.

--------------------------------------------------------------------------------

Operator [47]

--------------------------------------------------------------------------------

We show no other questions in queue. I will turn it back to management for closing remarks.

--------------------------------------------------------------------------------

Eric McCrady, Sundance Energy - CEO, Managing Director [48]

--------------------------------------------------------------------------------

Great. Thanks for everybody's time. Again, we've got premier in the Eagle Ford, strong production and cash flow base, and significant capacity to capitalize on this downturn to create shareholder value.

So thank you for all your time.

--------------------------------------------------------------------------------

Operator [49]

--------------------------------------------------------------------------------

Ladies and gentlemen, thanks for participating in today's program. This concludes the program. You may all disconnect.

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Sundance Energy Australia

CODE : SEA.AX
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Sundance Energy is a and oil exploration company based in United states of america.

Sundance Energy holds various exploration projects in Australia and in USA.

Its main exploration properties are ARKOMA BASIN in USA and COOPER EROMANGA BASIN and WILLISTON BASIN in Australia.

Sundance Energy is listed in Australia. Its market capitalisation is AU$ 206.1 millions as of today (US$ 139.7 millions, € 126.9 millions).

Its stock quote reached its highest recent level on August 22, 2014 at AU$ 1.42, and its lowest recent point on December 12, 2018 at AU$ 0.04.

Sundance Energy has 1 249 350 016 shares outstanding.

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Annual reports of Sundance Energy Australia
2007 Annual Report
2006 Annual Report
Nominations of Sundance Energy Australia
12/16/2008 Appoints New Chairman
Project news of Sundance Energy Australia
4/23/2008(May-jon) Extends US Oil and Gas Interest with May-Jon Prospect
4/17/2008(North Washington)Extends US Oil and Gas Interest with North Washington Prospe...
Corporate news of Sundance Energy Australia
8/1/2016Acquisition of Eagle Ford Assets Completed
8/1/2016Acquisition of Eagle Ford Assets no Re-Fracturing Partnershi...
8/1/2016Quarterly Activities and Cashflow Report
6/22/2016Acquisition of Eagle Ford Assets
5/27/2016Chairman's Report AGM
5/23/2016Borrowing Base Reaffirmed
4/29/2016Quarterly Activities and Cashflow Report
1/29/2016Quarterly Activities and Cashflow Report
11/2/2015Edited Transcript of SEA.AX earnings conference call or pres...
10/30/2015Sundance Energy Australia Limited Reports Third Quarter 2015...
10/29/2015Quarterly Activities and Cashflow Report
10/26/2015Quarterly Earnings Call
9/10/2015Half Year Accounts
8/10/2015Cleansing Notice
8/10/2015Acquisition of Eagle Ford and Cooper Basin Assets
8/10/2015Sundance Energy Australia Limited Closed on Acquisition of N...
8/4/2015Edited Transcript of SEA.AX earnings conference call or pres...
7/31/2015Sundance Energy Australia Limited Reports Second Quarter 201...
7/31/2015Quarterly Activities and Cashflow Report
7/29/2015Quarterly Earnings Call
4/27/2015Notice of Annual General Meeting/Proxy Form
3/31/2015Annual Report 2014
3/9/2015Investor Presentation
1/30/2015Operations Update
1/30/2015Quarterly Activities and Cashflow Report
1/29/2015Quarterly Earnings Call
1/29/2015Reserve Upgrade
10/31/2014Operations Update
10/30/2014Quarterly Earnings Call Presentation
5/12/2014Sundance Energy Australia Limited Files Form 15F to Terminat...
2/5/2014Sundance Energy Australia Limited Announces Launch of Initia...
11/13/2012s
10/31/2012s
10/16/2012s
9/26/2012s
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12/17/2009to Participate in Bakken/Three Forks Test Well
11/30/2009to Appoint Reg Nelson as a Director
3/10/2009Company and Development Update
11/27/2008Development Update
11/13/2008AGM address and presentation
8/12/2008Revenue and Developement Update
6/17/2008Another Extension of US Oil and Gas Interest with Colorado C...
6/4/2008 2008 Development Campaign Update
4/15/2008 Spuds Second Well at Phoenix Prospect
1/2/2008Closes Drilling Deal for Phoenix Prospect
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