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Earnings Call Transcript 2020-Q3

[David Cook, executive]

[Audio Gap]

everyone, and thank you for joining Noreco's 3Q release presentation. I'm David Cook, Noreco's CEO. And I'm with Euan Shirlaw, our CFO.

Please note that after we go through the presentation today, we'll have time for some questions and answers at the end. These can be typed in and submitted through our presentation.

Our 3Q outcomes are very positive, financially and operationally. Production has remained reliable and predictable quarter-on-quarter, with 3Q averaging almost 29,000 barrels of oil equivalent a day, at the top end of our guidance.

Our realized oil price in excess of $75 per barrel sees us continuing to reap the benefits of our hedging strategy, especially in light of an actual market price closer to $43 per barrel for the quarter.

When combined with our production guarantee, we ended the quarter with revenues of $157 million and an adjusted EBITDA of $104 million. The result in operating cash flow was $111 million for the quarter, and we ended the quarter with $263 million on the balance sheet.

In Tyra, we took our first delivery from the yards and successfully installed 2 new jackets, per the original plan. Yet, as was announced last week, we have, with the DUC operator, announced that the first gas has shifted to Q3 2023 as a result of COVID-19 impacts in fabrication. The project nonetheless remains on budget.

Operationally, in offshore, our manning levels have been steadily returning towards plan. And at the end of 3Q, we had personnel offshore in line with our expectations. Our operations as a whole have been very stable. And planned activities around maintenance and well services were successfully executed for the plan. We had 1 unplanned compressor outage at Dan in 3Q, but that has been resolved with minimal impact to production for the quarter. Looking forward, we are expecting our fourth quarter production to look like our third quarter. So we offer the same guidance of 27,000 to 29,000 barrels of oil equivalent per day looking forward.

In Tyra, in the redevelopment, as I mentioned, we have completed 3 of our main milestones with a temporary shut-in of Tyra back in 2019, the abandonment and removal of 2 of the topsides in 2020 and then the delivery and the installation of the jackets just in 3Q. With the delay that we've announced, we now will take delivery and sail-away of topsides in '21 and '22, with completion of installation of all topsides in 2022, targeting the first gas in Q3 of 2023.

We're providing here a look at the 2020 Tyra cost outlook, where we expect total spend in the range of $290 million to $305 million combined CapEx and ABEX, with about $65 million, $75 million of that left to spend in Q4. Looking forward for the rest of the project in 2021, 2022 and 2023, we expect to see, respectively, somewhere between 45% and 55% of the spend in '21, 30% to 40% of the spend in 2022 and the remaining spend, 10% to 20%, primarily through hookup and commissioning in 2023.

With that summary and operational outlook, I pass this to Euan, who will take you through a financial review.

[Euan Shirlaw, executive]

Thank you, David. So to start from focusing on the performance of the business during the third quarter, I think there are 2 elements that are on Slide 9, the financial summary that I would like to cover. So the first part is our performance in Q3, and the second element is the financial positioning of our business as we continue through the Tyra redevelopment period.

Starting off looking at the third quarter, as David has touched upon, I think it's fair to say that we have recognized strong performance during the quarter. And it's a consistent message for us. Our business model has continued to demonstrate significant resilience in what continues to be a challenging market environment for E&P companies and oil and gas companies more generally. Our price and volume hedging arrangements have provided significant protection against both lower commodity prices and variability in operational performance.

Our price hedging, which has been well documented to the market, has driven a realized price of $75.3 per barrel in the third quarter, and that's a premium of more than 75% to the underlying Brent price. Our volume hedging, which is the arrangement that we have in place with Shell that guarantees a minimum level of liquids production from the assets, has delivered a contribution to us from cash flow of $22 million in the third quarter. This has enabled us to report strong EBITDA and cash flow generation. Our reported EBITDA of $79 million and including the contribution of our volume guarantee, that rises to $104 million in the third quarter. It's based on this that we've been able to generate operating cash flow of $111 million over the prior 3 months.

As we look forward, our position remains robust as we continue through the Tyra redevelopment. We have over 12 million barrels of hedged volumes in place to date over the 2020 to 2022 period at a fairly consistent price of $56 per barrel. We have cash on the balance sheet at the end of the quarter of $263 million and undrawn RBL capacity based on our current borrowing base of $49 million, which provides us in total with over $300 million of available liquidity at the end of the period. Finally, to note, we have no short-term debt maturities and no capital repayments until Tyra is onstream.

Moving on to the financial positioning of the business as we look through the Tyra redevelopment period. I think it's important to note that Tyra remains key to our story. And enabling the delivery of this project was one of if not the key focuses when we set the capital structure for the business post the acquisition of Shell's interest in the DUC.

And with that in mind, there are 2 elements that are important to understand and be conscious of as we look to address the impact of the delay in first production to Q2 2023. Firstly, from a Tyra perspective, the report on Friday, the release on Friday that we made to the market, importantly noted that the project is expected to be delivered on budget in spite of the delay to first production. And on the side of the underlying business that we have from our 3P producing hubs, we continue to benefit from positive operating cash flow supported by the substantial hedge book at prices significantly above the current market.

While any of your future liquidity is obviously impacted by a number of variables, not least future commodity prices, the rephasing of Tyra CapEx, i.e., spent over a longer time and utilizing contingencies in the budget, coupled with the underlying operating cash flow generation that we have, strongly supports our ability to meet Tyra expenditure going forward.

Against this backdrop, I'd like to touch briefly on the capital structure that we have in place. We continue to benefit from the strong support of our bank group. In June 2020, against a period of significant market volatility, we delivered a material increase in our borrowing base. The financial position that we've built that I've outlined already on this page and as you can see from the numbers and the forward-looking position supports us as we look to build for the future and to deliver the first production from Tyra. And finally, I would say that the relationships that we have built with our banks indicate, on the basis of this position, we think will be strongly supportive as we look to move through the next 2.5 years.

We can move on to Slide 10. As Dave has already covered, our share of production from the DUC in the third quarter was 28,700 barrels a day of oil equivalent. That's at the upper end of our guidance. Based on our listing schedule during the third quarter, we recognized a small underlift of 1,100 barrels a day, and that has driven total sales in the period to be 27,600 barrels a day. The impact of our price hedging during the period resulted in a realized price of $75.3 per barrel. And that's significantly above the average spot price during the period of $43 per barrel. I think it's also worth noting as we look at Slide 10 that the realized price in the third quarter of 2020 is actually above the realized price that we received in the first quarter when the Brent market was significantly higher and was yet to undergo the correction that we have experienced in 2022 to date. Bringing all these pieces together, our sales -- or total revenue during the period was $157 million.

If we can turn on to Slide 11. Our hedge position continues to cover us to the end of 2022. In the remainder of 2020, we have 2.5 million barrels of oil hedges in place at a price of $58.8 per barrel on average. For 2021 and 2022, we have 5.9 million and 4.3 million barrels hedged, respectively, at a fairly consistent price of $56 per barrel. Going forward, we will remain compliant with the terms of our hedging requirement under our RBL, which require us to have volumes hedged for a 3-year forward period for 50%, 40% and 30% of expected production during those 3 years.

With regard to our volume hedging, the liquids protection agreement with Shell sets a minimum production level that we are commercially compensated from. During the third quarter, we received the benefit from this agreement of $22 million. And based on our internal production forecast, we expect to continue to be paid under this agreement until its expiry at the end of this year. So that is to say Q4 remaining.

Moving on to Slide 12. As you can see, we've presented the -- some more detailed figures on our financial performance in Q3 compared to Q3 2019. I would note at the outset that Q3 '19 was the final period prior to the shutdown of the Tyra field. So as a result, there is a natural decline between Q3 2019 and Q3 2020. However, I would note that, if you were to look at some of the high-level figures in that period, for example, our revenue is only $3 million lower in spite of a circa 12,500 barrels a day reduction in production, our adjusted EBITDA of $104 million is a reflection of reported EBITDA of $79 million, a $22 million contribution from the volume guarantee, giving us an adjusted EBITDA of $104 million. This has resulted in operating cash flow of $111 million. During the period, we invested in -- or continue to invest in the Tyra project, which has resulted in a net change in cash of $36 million. It is as a result of that, that we exit the period with $263 million of cash on our balance sheet and drawings under our RBL facility of $751 million.

Moving on to Slide 13, which provides an overview of our capital structure. This is -- this has been very stable between Q2 and Q3. Our RBL remains drawn at $751 million. We haven't drawn any more under the RBL during the period. And as a result, based on our borrowing base, we exit Q3 with $49 million of availability under our RBL. We have total interest-bearing debt of $1.1 billion. And net of cash on an accounting basis, our net interest-bearing debt is $852 million. And as we've noted previously, but for emphasis here, when we look at our covenants under our financial instruments, our convertible bond with its mandatory conversion to equity asset of 5 years is excluded, which gives an effective commercial interest-bearing debt number of $688 million.

And with that, I will head -- sorry, hand back over to David for his closing reflections.

[David Cook, executive]

Thank you, Euan. So with that summary of our 3Q outcome, come back and sort of remind everyone of the long-term value proposition that Noreco offers. We sit with a business with 2P reserves in excess of 200 million barrels. And our 2C resources are contingent with projects that are being progressed behind these of additional 200 million barrels. Our production is consistent and provides operational cash flow that supports our investments in the projects. The low decline rates of our reservoirs continue to offer additional opportunities, and we can offset some of the decline with our additional investment.

The near-term growth is clearly delivered through Tyra, where we expect to see in excess of 50,000 barrels of oil equivalent a day after restart. With the 2020 success of decommissioning and installation, we now are on track towards our shifted first gas date in 2Q of 2023.

As I mentioned, the contingent resources in our 200-plus million barrels of 2P provide low-risk organic growth opportunities. And these CapEx projects within the DUC have tremendous investment -- or I'm sorry, development cost per barrel. These -- we also have advantaged tax positions in Denmark and in the U.K. That will continue to drive our thoughts around inorganic value-additive growth.

We continue to have our liquids completely hedged through 2020 at prices significantly above the market. And as Euan has noted, we have material volumes already hedged at 2021 and 2022, seeing prices at approximately $56 per barrel. Our strong financial position remains with diversified sources of funding and with no near-term debt maturities or capital repayments, as Euan has outlined.

In short, we're proud and pleased with our 3Q. We're very impressed with our own performance in 2020 thus far. And we're looking forward to what we have to deliver to everyone as we move forward towards the completion of Tyra and the additional investments that we're making across the Noreco portfolio.

With that, we can open to questions.

[Unknown Executive]

First question is for you, David. How will the Tyra delay affect Noreco? And how certain are you that the project will remain on budget?

[David Cook, executive]

Thank you. I'm sure there's -- [indiscernible] I know there are several questions around Tyra. Let me try to consolidate some of the answers and give a view of where we are.

The shift to 2Q 2023 was a result of significant joint work between the operator and the partners inside of the DUC. After taking a look at what the cost and schedule and risks were, this was a detailed look at what the probabilistic outcomes were for the project.

This shift to 2Q 2023 allows us better control of the work, essentially building back some of the contingency that we had into the schedule. It allows us, as the operator and the partners, to closely monitor the progress and the performance of the supply chain and the delivery against the fabrication schedule in the yards.

And note that as we are now 60%-plus complete on the project, our visibility and our certainty on schedule and budget increases in line with this progress.

[Unknown Executive]

Thank you. Next question, also for you, David. Are there any force majeure clauses or anything of that kind with respect to the sliding time line on Tyra helping Noreco in any way?

[David Cook, executive]

Of course, we have all the usual contractual guarantees and securities in place, and we are working with our contractors to make sure that we -- that these are applied as important or as appropriate. We've not entered into any force majeure, although that is an option at the appropriate point, but that is not now. What we do pay attention to, of course, is the timing of milestone payments and liquidated damages, et cetera. But at this point, we're progressing per our schedule and have agreed with this shift in the time line to 2Q 2023.

[Unknown Executive]

Thank you. Euan, could you please add some color on the remaining CapEx on Tyra in U.S. dollar terms?

[Euan Shirlaw, executive]

Of course. So perhaps just starting by setting the context. The budget for the Tyra project in total, which is CapEx plus ABEX, is DKK 21 billion. We noted at the end of 2019 that the expenditure to date on Tyra had been DKK 8.1 billion, therefore indicating that there is DKK 12.9 billion still to be spent within the budget.

I think when we look at forecasting CapEx going forward, I think we've given a good indication of how we expect that to be phased. And taking into account of the CapEx that has been spent to date and the CapEx budget, I think you can infer from that what the capital is on both the Danish kroner and U.S. dollar basis, and we've now also provided the CapEx phasing for that as well.

[Unknown Executive]

Thank you. Euan again. Could you please provide some color on the RBL amortization schedule? How will the Tyra redevelopment affect this? And further, your basket for dividends before Tyra redevelopment, do you find this likely to be utilized in light of the delay on Tyra start-up?

[Euan Shirlaw, executive]

So starting with the RBL, as I noted at the start of my presentation, the capital structure that we put in place when we set the acquisition or when we completed the acquisition was set fundamentally around one of the key objectives being clearly that delivery of the Tyra project was essential to the Noreco story going forward. And that position certainly hasn't changed.

So as we look at it from an RBL bank perspective particularly, the amortization schedule that we have previously agreed with the banks has amortization starting in H2 2022. And I think the color around that is that, that was clearly set to be -- to have amortizations starting once Tyra has started up.

I think going forward -- and I don't want to overemphasize the point around the relationship that we have with our bank group and the strength of support that we have there, but I think we will be in a position where we will be working with our banks to both understand the impact of the delay from a financing perspective and from an amortization perspective. And I think the -- based on the initial discussions, I think the position that we're in is that we will be looking at the amortization schedule clearly as the Tyra project has moved in first gas -- in first gas date, and that is something where I think we will certainly be looking at and focusing on.

[Unknown Executive]

David, in light of the delay on Tyra, how do you now think about the organic growth projects that have been discussed earlier?

[David Cook, executive]

I think, Euan, in some degree, helped to answer that with his previous answer. Obviously, we have to be spending time and looking closely at the liquidity we have inside the company. And the first priority is the delivery of Tyra.

We're comfortable with our ability to do so. We're also comfortable that we have a strong financing position. And for the right opportunities, if we see things that actually will accent and -- accentuate, I'm sorry, the value we can return to the shareholders and into the equity, then we still need to be identifying and pursuing those. Obviously, we do that within the constraints that we have, but we believe we've got a strong position to start.

[Unknown Executive]

Another question for you, David. What is your opinion on current share price?

[David Cook, executive]

This is a regular question. So I'm never satisfied. I guess, as part of it, what the right price is, in a way, that's what you tell us. However, when we look at the value inside the company, when we look at our delivery of cash, when we look at the growth options we have even in our own backyard inside the DUC, when we look at the fact that there is certainty in Tyra delivery and the value that would bring, I think the current undervaluation, although the market is certainly challenged, especially in our sector and especially in the ongoing COVID world, but I still think the current undervaluation speaks for itself. And I -- I, along with the team, and everyone else will be striving to show that there is additional value that should be put into our share price.

[Unknown Executive]

Euan, will Noreco buy back shares? And what about dividends?

[Euan Shirlaw, executive]

I -- yes. Sorry. I think I actually missed the answer to that question of one of the previous responses. We have a small remaining bucket under our financing agreements with both the banks and NOR14, which covers the potential for distributions. I think, given the position announced with Tyra, and I think we are all very focused on delivery of Tyra being key to the equity story, I think it is too early to give a view, frankly, on whether during the Tyra redevelopment period, we will have any intention of commencing a buyback or dividend program during this period.

I think what I can say is that it's certainly fair that we recognize that there is a focus on the return of capital to shareholders. But clearly, there is also a balance when we look at ensuring that we have a strong financial position to deliver what is a key project for us and what is, frankly, a material step change in both production and cash flow from 2023 onwards.

[Unknown Executive]

David, is there approximately a one-to-one relationship between project completion and CapEx?

[David Cook, executive]

No. It's not quite one-to-one. The spend -- why we still are in the fabrication yards and why we have the activities associated with [ an optimum ] sail-away will carry a slightly higher burden of the capital versus when we are in the point of sort of restoring operations, completing hookup and commissioning and reconnecting the wells. There will be a slight skewing, but it's not significant, I think, is probably the way to look at it. And remember, our payments into the yards are under a schedule, so we have reasonable control on this.

[Unknown Executive]

Euan, you have reported USD 22 million within the volume protection agreement that expires in 2020. Is this not a warning that the volume have continuously been below expected levels? How will this affect the company, the income and the liquidity situation after the guarantee period has ended?

[Euan Shirlaw, executive]

So let's start by just looking at what the volume guarantee agreement actually is and how it was set. So that was set as part of the acquisition, which was announced in 2018. And effectively, the production levels upon which that were based -- or upon which that agreement is based where set at that time. So as you would expect, there has been some natural evolution of the forecast production over that period.

I think the way I would position the liquids protection agreement has been that it is an agreement that we have benefited from throughout our ownership of the assets and subsequent signing of the SPA, but it is not an agreement that ultimately has been set at a level that reflected either our expectation around production at the time of signing the SPA or our expectation of production levels throughout the period when we have owned the assets.

And I would point to the fact that we have been fairly clear in messaging throughout the period when we have been in control or in ownership of the assets that we have always pointed towards the fact that we expected a material contribution from the liquids protection agreement.

And that plays into the second part of that question, which is how we affect it to -- how we expect it to impact our income and liquidity situation going forward. When we talk about our position today and look forward and talk about our positions through the Tyra period, we are forecasting based on our current estimates, which reflect the fact that they are lower than where the liquids protection agreement effectively offers us commercial compensation for production.

So it doesn't reflect an under -- the fact that we benefit from that agreement doesn't reflect an underperformance in production versus our expectations. It reflects an underperformance versus the production levels that Shell set in their sales case effectively when they divested the assets. So it isn't something that has a negative impact going forward in the sense of providing any indication around the underperformance of the assets relative to how we expected them. But clearly, it is a contribution that we will no longer have from 2020 onwards.

But I think the way to look at that is, frankly, more to focus on the fact that it has supported our liquidity and production position through the period when we have benefited from that agreement rather than reflecting on the fact that it has any impact on our ability to forecast the production levels under the DUC or reflecting an underperformance relative to what we had expected.

[Unknown Executive]

Euan, do you have any color on non-Tyra CapEx for 2021 to 2023?

[Euan Shirlaw, executive]

I think what we can say, I mean, we haven't guided to a CapEx number outside of Tyra. And frankly, based on the information we have, we haven't guided to a specific U.S. dollar number for CapEx, either on Tyra in its own or in totality over the period. So I think it's difficult to firmly guide on that, but what I think we can safely say is that -- and this actually goes back a little bit to the answer to the question around the incremental growth projects. There is optionality within the portfolio. And ultimately, the non-Tyra CapEx will be dependent on further development decisions that we take. So it's not something that we can really give a firm view on now.

What I can say, though, is as we look at the position today, there is not a material amount of non-Tyra CapEx that we would expect in '21, '22 or 2023 while Tyra is ongoing. The vast majority of the CapEx is focused on the Tyra project. But clearly, the extent to which there is non-Tyra CapEx will be largely dependent on how we look at other development decisions within the portfolio.

And I would add just on top of that, that there are projects that we have highlighted to the market, and there is clearly a scale in terms of how they are from both a materiality of investment and materiality of the reserves that we recover from those projects. And I think it is clearly a question around how and when we sanction those going forward that will be the key determinant of CapEx over that period.

[Unknown Executive]

And that concludes the Q&A session and the third quarter earnings call. Thank you for listening.