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Earnings Call Transcript 2019-Q4

[David Cook, executive]

Welcome to Noreco's Fourth Quarter Presentation, and I'm here today with Euan Shirlaw, the CFO of the company; and Atle Sonesen, the COO.

And yes, we just move straightforward. Euan?

[Euan Shirlaw, executive]

I think I'll take over after the operational review. So...

[David Cook, executive]

Okay. Then it's Atle Sonesen.

[Atle Sonesen, executive]

Thank you very much, and a very warm welcome, and good morning to all of you here today. We are here to present a new quarter, even though we are well into the next one and a new year. And it's been another quarter, I will say, excitement, different from the previous quarter, but yet strong results as we go along.

So let's have a look at the headlines and some of the key numbers. You can see them on here. Starting out with a production of 31,700 barrels of oil equivalents per day on an average throughout the quarter, and which is in line with what we guided on, which was between 31,000 and 33,000.

So looking at the EBITDA, the adjusted EBITDA, $116 million, operating cash flow of $87 million and a net profit of $44 million. On the financing side, we were out and got a convertible bond, secured. It was issued USD 175 million with quite a broad and international interest, and it was substantially oversubscribed. Also when it comes to the lending part and the RBL facility, we renegotiated some terms and got an improvement in the availability of the lending facility of USD 30 million.

On the operational side, we see that there's been continuous maintenance and activities in terms of wells, simulations and so on and so forth, which is keeping Gorm, Halfdan and Dan running in the terms we expect. Whilst Tyra, on the other side, is completely shut in and has reached a so-called safe state of operation. I'll get back to the operational details in a minute.

So if we take the production first, break that down into the different hubs, you can see the comparison here between the previous quarter and the current quarter. So the big difference is, needless to say, it's Tyra. And this is according to the plan. Tyra is shut in. It means that the production ceased in September. And now this current state of Tyra is that it has been depressurized. It has been cleaned, purged, made hydrocarbon-free, and it is in so-called safe state. And it's moving forward with some activities we will see a little bit later on.

Halfdan is in line with what we expected so is Dan and so is Gorm. Many maintenance campaigns going on, some of them extending a bit more than anticipated. But yet, we are able to deliver on the site production.

Gorm. I want to highlight Gorm, which has also undergone quite a bit of heavy maintenance during the quarter. And in December, it actually sort of came up with a record high operational efficiency of close to 97%.

If we look forward, the same type of activities for the fields will -- are planned to take place, similar level, with continuous main things, programs, workovers, well interventions and so on and so forth. Nothing different from last year into 2020. And we foresee that the expected production for also Q1 2020 is going to be pretty much the same as the previous quarter. And we would like to offer a guiding on 31,000 to 33,000 barrels oil equivalents per day on an average.

Site production, a few more words on the on activities. If we look at the overall operational efficiency for the assets, as you can see in the annual or quarterly report as well, you can see it's maybe on the low side, in the mid, low 80s, but yet, we're able to deliver on the site production. On Halfdan, which is the biggest and most important producer, with stimulation of quite a lot of the key wells, bringing those back on production, maintaining the production level that we expect, in addition to that, there has been some temporary shutting in of the water production -- water injection system to maintain that. And that would also fully put back in production again. And of course, there's quite a bit of independency between Dan and Halfdan. And hence, if there's planned one maintenance shut on the other one, it may have then an impact on the other.

On Dan, producing 8.6 over the quarter, also planned maintenance and several work of activities on the wells to keep them up either for production purposes or for water injection and securing the water capacity that we need for maintaining the production of the wells.

On Gorm, which has the biggest maintenance campaign attached to this year, also including some valves, pipeline piggings and so on and so forth, it took a little bit longer than planned. But still, December was a very, very good month, and we hope to also see that into the future with operating efficiency of close to 97%. So quite a bit of activity, and that is also expected to continue into 2020.

Tyra. Tyra is an important project for Noreco. It's an important project for the Danish Underground Consortium. It's also an important project for Denmark. And during the quarter, progress went according to plan. Now we are sort of above -- global progress is just above 50%. And fabrication is going on at different sites. This picture here is from Dragados in Spain for the jackets for the accommodation unit and also for the processing unit.

So as you can see here, 2020 is going to be a year of removing the old big production platforms, the Tyra East and Tyra West from the North Sea and also the associated jackets, whereby 2021 is going to be dominated by putting things in place again. Both jackets in the early part of the year and then, also, in 2020, late part of the year, early into 2021, and 2021 is then going to put the wellhead and riser modules earlier in the year, and later in the year, the processing module, which is then being fabricated in Batam in Indonesia. So this is moving forward. It's in line with the plan, and it's in line also with the budget.

If we take a look at the reserves and the reserves maturation, which is really, I think, at the heart of Noreco's value proposal and look at it with sort of the large optics, we have -- will be talking about the in-place reserves. And the in-place reserves is a massive number. And we also know that the recovery factor on the Danish Continental Shelf is somewhat lower, which gives us -- compared to maybe the Norwegian benchmarks, which is also a fantastic opportunity to really -- to work on that.

And in addition to the 2P reserves that we had communicated earlier, we had a number of contingent resources of different maturity. And our purpose, together with the operator and the joint venture is to move those, to continue to mature them and move them into the tube with the 2P domain and, thereafter, into producing barrels.

In this category here, we have a number of projects. We are going to specify one today and show you some details about it. It's linked to Halfdan. And Halfdan is not just sort of one of the biggest and highest producers, but it's also the one with the lowest recovery factor and the biggest potential of our DUC portfolio. So in that sense, it's of particular importance to bring out projects and mature those for the Halfdan assets.

So what does that look like? Here are the Halfdan project. It's going to be a -- an unmanned tie-in on platform to a part of the system. It's an oil project, very, I would say, low-cost development, high value. Net to Noreco, we're talking about close to 15 million barrels with a significant upside. And in Noreco, we always, always pursue the upside.

FID early next year, and first oil is expected during 2023. So this is a project that is already a part in the concept select and is about to start the feed phase in these days. So it is really moving forward, and we're looking forward to that.

Two other projects. Example for that sort of bucket of mature projects, one oil and one gas. And as you can see there of similar character when it comes to low-cost and high-value projects. And if you look at some of these up, we're looking at projects of more than 40 million barrels net to Noreco coming on over the next 2 to 3 years. We're looking at production at 10,000 to 12,000 barrels a day net to Noreco coming on over the next 2 to 3 to 4 years.

So if you put that together, it may look something like that. And there are 3 things to, I think, to pay note of in this presentation. One is that with what we have and what is sanctioned, driven by 2 that are coming back in 2022, we are looking at a significant ramp-up of our production level from the 30-ish level we are today to the 50 mark. Secondly, the mature projects that we have in our portfolio that currently we and the joint venture and the operators working on will then take us the next 3 to 4 years at the 50 mark, if not above. And if you think 1 or 2 slides back, out of the 130-plus contingent resources, we have enough projects there to keep us at a 50 mark for the rest of the decade.

So with that, I'll leave the word to Euan and to talk about the financials.

[Euan Shirlaw, executive]

Perfect. Thank you, Atle, So what I'd like to do now is just move on to talk about the -- sorry, talk about the financial performance of the business during the quarter. So as we -- as Atle mentioned and as we've talked about before, this is the first quarter that truly reflects our ownership of the DUC assets, and it's also the first quarter that truly reflects the shut-in of Tyra for the period.

I think what we have witnessed as a company is the fact that on the basis of the strong underlying asset performance, coupled with the risk mitigation structures that we have in place with Shell and that we put on in the market in terms of price hedging, we've had strong financial results. So just to look at some of those highlights. We've generated material revenue, so production was 31,700 barrels a day. And we had a realized price of $77 for liquids. So that was significantly above where the Brent market price was during the period, and that's a result of the price hedging arrangements that we put in place with Shell in October of 2018. And that allowed us to generate hydrocarbon revenue of roughly $172 million.

We also generated significant profitability. So when we look at our measure of adjusted EBITDA, which incorporates the value of the volume floor that we have with Shell, we generated $116 million of EBITDA on that basis. And then finally, on this page, we also delivered significant cash flow generation. So our cash flow from operations was $87 million. And as Atle mentioned during the period, we also issued a senior unsecured note, which isn't actually convertible, but it's a senior unsecured note into the market, which generated significant institutional investor interest and has supported our financing position as we exit 2019 with $286 million of cash on the balance sheet.

Moving on to look at our production and sales and how that translated to revenue. As we've talked about, our production was 31,700 barrels a day. That reflects the fact that Tyra was shut in for the full quarter. We experienced a small underlift position during the period, roughly 2,200 barrels, which result in us having sold effectively 29,500 barrels during the period.

As I mentioned before from a hedging perspective, our realized liquid's price is significantly above the market. So dated Brent average during the quarter was $62.5 per barrel, and our realized price was $77. That's largely a function of the hedging that we put in place in October 2018, which was in a, I think it's fair to say, a different oil price environment that was more supportive. But it also reflects the fact that after Tyra was shut in, we have experienced some positive development of the DUC premium, which is the premium that our Brent receives. And also, we have benefited from the rollover of hedges from previous periods that were at higher prices. Bringing all those components together, our revenue was $172 million.

What I wanted to do briefly also was just touch on our production expenses during the quarter because there's a couple of elements there that it's worthwhile just focusing on, particularly as it refers to one-off items. So our production expense is related to the direct lifting and transportation of our production, was $72 million, which equates to roughly $24.7 per barrel during the period. And that is, again, as I think the message is from a lot of the financials, that reflects the fact that during this period Tyra was fully shut in. Once Tyra is back on stream, we expect that measure of field operating cost to decrease to roughly $12 a barrel. And that's what we see from our perspective. As we go through the Tyra redevelopment, that's what we see as being our recurring level of OpEx.

On top of that, in Q4, there are some adjustments that's worthwhile just touching on. Based on the methodology that we set out in Q3 for how we are measuring internally our unit OpEx per field, we have excluded changes in inventory and costs or benefits associated with an under or overlift position.

During Q4, we also had some accruals and adjustments based on timing. So we received effectively billings that weren't -- or charges were authorized that weren't billed during the period. And also, we adjusted some of the costs between Q3 and Q4. But I think the main point to touch on is probably just the exceptional costs of $22 million at the bottom here.

So these are one-off charges related to the DUC. Roughly $11 million of that was exceptional, related to restructuring. And that's an exercise that's being carried out by Total to make sure that the organization is fit-for-purpose as we go through the Tyra of redevelopment and also once Tyra is back on stream. That's related to Q4 only. We don't expect it to be recurring. And I think similarly, we expect to see a benefit from that, frankly, as we go through the forward period in terms of where our level of OpEx is with an organization that is set at the right size and with the right people.

In addition to that, we also had a stock scrap expense, which recognized the fact that Total wrote down the value of some inventory in line with net realizable value. And I think that's something that is -- it's fundamentally an accounting change that is to bring the value that we see in line with what is reported in our accounts. But I think the main message to take away from this is that as we look at what we think our OpEx will be going forward, we're comfortable with the level around the top sort of field operating costs, which is recurring.

Moving on to the hedging. I think everybody here is probably aware that we have in place some pretty material hedging arrangements with Shell and also now in the market. What that's enabled us to do is generate or realize a higher price than has been in the market. So we have a set of price hedging arrangements that were put in October 2018. And you can see when we look at Q1 2020 and then 2020 overall that we expect to continue to benefit from that relative to where the price is in the market today throughout the remainder of 2020.

From 2021 onwards, we've put in place additional hedging in line with the requirements of our RBL facility, which has a hedging requirement as part of it, which is 50%, 40% and 30% of 1-, 2- and 3-year forward production. And we're clearly in compliance with that.

We also have the liquids protection agreement, which essentially sets a minimum level of oil production that will be compensated for commercially. That during the period, we recognized a contribution from that agreement of $33 million.

Sorry, do you want to?

[Atle Sonesen, executive]

No, no.

[Euan Shirlaw, executive]

Sorry.

[David Cook, executive]

Did you say something about...

[Euan Shirlaw, executive]

So the -- actually, sorry, just to finish off the point on the volume agreement. We have in place a volume protection agreement with Shell, which is the minimum level oil production that will be compensated for. We recognize $33 million for that in Q4. And based on our internal estimates of production, we expect to continue to benefit from that through 2020.

One other point to note in terms of where our forward price hedging portfolio is relative to the price that we realize, the prices that we outlined here are based on dated Brent. So effectively, it's the market price for Brent. The DUC oil production sells at a premium -- to a premium to Brent. During the quarter, it's been roughly -- I mean it's roughly $1.50 per barrel. And I think we have experienced some positive uplift in that premium as a result of Tyra coming off stream and effectively an improvement in the quality of the blend. So I think what that means is that from a forward price perspective, the price that we're expected to realize in our accounts is likely to be higher than where we are from our price hedging portfolio.

Moving on to our financial statements. And I think the key thing here is really just to highlight some key areas of focus. For adjusted EBITDA, our reported EBITDA is $59 million. And there are some adjustments to that, that we make to bring that more in line with what we see as the underlying reality of the performance of the business in terms of what we're compensated for commercially.

So the benefit for us from the Shell volume guarantee was $33 million during the quarter. And that doesn't flow through our P&L because it's measured as a reduction in the purchase price, so it shows up in our cash flow statement. But I think, again, it's fundamentally related to the underlying performance of the business, and it's something that we'll continue to see throughout 2020.

We've also excluded the exceptional DUC operating cost. So that's the stocks scrape and the restructuring and a small proportion of transaction costs related to our bond issue and our RBL. And that leads us to an adjusted EBITDA number of $116 million for Q4.

Our net result for the period was $44 million. And I think one thing just to highlight there is that during Q4, we have adopted hedge accounting. So that will be the policy going forward. That effectively allows us to recognize the benefit of realized hedges as they roll off as part of our revenue. But the change in value of our hedge book as we look forward comes through the other comprehensive income line.

And I think one other point just to touch on here, cash flow from financing. That reflects the fact that we have -- we issued a bond during the quarter, which we'll touch on in the next page, but $175 million of external financing from institutional international investors.

And then finally for me, an overview of our capital structure. So our RBL continues to be drawn to $746 million. As I mentioned, we issued the NOR14 bond during the quarter. That's $175 million instrument with a coupon of 9% and a tenure of 6.5 years. That was strongly oversubscribed as part of the issue, which I think is good verification of the Noreco story from a debt perspective. I think it also allowed us to -- I think a market is perhaps not the right word but certainly meet additional investors and build on the story in terms of our public perception. And we have used the proceeds or will continue to use the proceeds to strengthen financial position and also provide us with additional flexibility as we look to sanction projects like, for example, Halfdan North that we see as being value additive as the opportunities arise.

And then finally, from a net interest-bearing debt perspective, we talked about this last quarter, but there is a distinction to be made between how we look at that on an accounting basis and how we look at from a covenant perspective. We have a convertible bond, which has a forced or a mandatory conversion to equity. It also has a number of equity-like features and has the option for us to pay interest on a PIK basis. As a result of that, from a covenant perspective, we exclude the convert from our net debt calculation when we're measuring our leverage going forward. And as a result of that, our -- effectively our covenant net debt or the way that we looked at net debt internally was $661 million at the end of the quarter on the basis of our $286 million of cash.

So I think, again, just to summarize, I think it's been a strong quarter of financial performance driven by both the agreements that we have in place but also the underlying performance of the assets. And we exit the quarter in a strong financial position as we move into the Tyra redevelopment in 2020.

Time for some Q&A.

[Unknown Analyst]

[indiscernible] Markets. Your product guidance for Q1, could you say something about your full year expectation for 2020? Will that also be in the 31,000 to 33,000 range?

[Euan Shirlaw, executive]

I think, Atle, do you want to comment on that one for production.

[Atle Sonesen, executive]

No. Go ahead.

[Euan Shirlaw, executive]

So our -- we are at the moment only guiding on Q1. I think it's fair to say that the -- during the period, based on the operations that we've seen, we've seen strong performance in Q1 so far. I think 31,000 to 33,000 is a good level for Q1. I think, as you would expect, there is a small natural decline on the portfolio. So overall, we're not expecting any material changes. But I think we're only guiding specifically on Q1 at the moment.

[Unknown Analyst]

Okay. And then just on the Tyra redevelopment. In light of the pretty soft gas prices we have seen in Europe, has that changed anything around how you think around the Tyra redevelopment?

[Euan Shirlaw, executive]

No, I think we -- I mean I think fundamentally, we still see the Tyra redevelopment as being both a key project for us and for Denmark. I think the economics are still positive. Total has come out and said that the project remains on time and on budget.

I think also, if we look at the gas prices, given we're 2 years away from first production, I think there's plenty of scope for the market to move. But fundamentally, there's no change in our view on Tyra over the last -- as a result of the current market environment.

[Cathrine Torgersen, executive]

Okay. So we have one question online. It's relating to future capital allocation. After the start-up of Tyra in 2022, how do you intend to balance investments in projects with potential dividends? Should investors expect a combination?

[David Cook, executive]

I think we will -- in today's environment, we will focus on substantial dividends as part of the free cash flow. And I think we haven't gone out with a fixed mix of that. But it's a bit early days, but I will be surprised if dividends would not be much higher than investments.

Okay. Thank you, everybody.