Earnings Call: Q4 2020

Feb 18, 2021

Good afternoon or good morning to everyone who is joining us. Thank you very much for joining the Noreco 4th quarter results for 2020. Just a Quick reminder that as we go through the presentations, you will be able to ask questions via the site, which we will then be addressing at the end of the presentation. Go ahead and go to the next slide, please. Just a quick set of highlights for the quarter. It's been another solid quarter for Norco. We've had very solid production and we've ended the year with our net Production out of the DUC at above 28,000 barrels of oil equivalent a day. We continue to see that the 3 currently producing hubs are providing very stable production, very low decline rates and will continue to sort of carry us through the Tyra redevelopment period in 2023. We also have seen that the risk mitigation of our successful hedging strategy has given us a 4th quarter price In excess of $63 a barrel equivalent and that as a result has delivered a $73,000,000 EBITDA, adjusted EBITDA for the quarter. Yuen will be covering all these as we go through the financial summary and financial review today, but I think one of the most important things to point out is this has given us $96,000,000 in the quarter in operating cash flow leaving us cash on the balance sheet of $259,000,000 We also have announced the new schedule for the redevelopment of the Tyra Hub and that will now be targeted for 1st gas in Q2 2023. This has been done to mitigate the risks of the past and ongoing impact of the COVID pandemic. We also subsequent to the quarter have announced that we have a fully underwritten $1,100,000 RBL with an additional 2 year extension, which has been a huge piece of positive news for us going forward. Again, these will be covered as we go through the financial review. Next slide. A quick review of the operations, as I've already noted, we did have we did conclude the year with very strong production And we continue to see a very low decline rate as we go forward. Therefore, we are quite confident in this in the cash generation that we will be able to get through 1,000 barrels of oil equivalent a day. Our operating efficiency was at approximately 82%. This is a bit lower than we would be desiring but of course this has had significant COVID impact in 2020. What we did do however is identify and ultimately add an additional 200 barrels of oil equivalent a day just in Q4 through gas lift optimization, Something that we're on the back of that success we'll be looking to try to apply throughout the rest of the assets where it's applicable. We also as of October have been able to return our offshore manning to about to the pre COVID levels. Therefore, we'll be able to get back fully on track with our programs. On the back of the 28,500 barrels of oil equivalent a day coming out of 2020, We'll be guiding to somewhere between 25.5% to 27.5% going through 2021 in our production. The hydrocarbon split will be approximately 80% to oil and 20% to gas. This is A ratio that will pretty much be consistent through again the beginning of the Tyra of when we will see a greater proportion of gas. Next slide please. On the Tyra redevelopment just to give people a sense of where we are, the year ahead is actually An exciting year actually, a lot of work to be done, fabrication continuing in the yards and we have the sail away of 3 of our main Components with the accommodation, the TEH sail away as well as 2 of the wellhead riser platforms in Q3 of 2021. That will also therefore begin the initiation of our overall offshore hookup campaign. These are significant milestones and the achievement of these will be a great indication of the project's pace and delivery per schedule. We'll have one last significant sale away in 2022, an awful lot of the brownfield and hookup and commissioning work that then goes on through 2022 as well. And again, targeting 1st gas in Q2 of 2023. We hit our 2020 spend estimate for Tyra very much right in the middle With approximately $291,000,000 of costs throughout the year, that's given us if you want to work up your own Foreign exchange rates, the spend to date on the project since FID of about DKK13,300,000,000. We expect if you see in the lower right corner, the spend going out for the remainder of the project to be Somewhere, well, very much front end loaded between 2021 2022 with the finish of the work in the yards and the fabrication and the sale of ways and the initiation of hookup. What will be left as we go into 2023 will be just be the last part of the hookup and installation and then we'll have the 1st gas. We thought it was important to look at The project is once we see that initiation of 1st gas in 2023. So we've benchmarks against via Rysted Energy's data Benchmarked against the other North Sea projects that are out there right now and I think it's very, very clear that the value of Tyra To the DUC, to Denmark, into the North Sea is clearly top of the line where we see a forward NPV from First Gas or from project initiation puts Tyra at the top of all these projects. It's one of the reasons we it as being so critical and it's one of the reasons we're very excited to actually finish the delivery of the project. Next slide, please. The other thing that's made some recent news in the Q4 was the Danish so called 2,050 North Sea agreement. This was the statement by the Danish government that they intended to cease all oil and gas production from the Danish Continental Shelf in 2,050. We think this actually provides tremendous visibility and stability for us, and it comes from statements we have made even before the 2,050 agreement was made. First thing to point out, of course, is this is 30 years ahead that we are talking and that's even 8 years beyond The end of the DUC concession inside of the Danish Continental Shelf. And although this does terminate licensing rounds going forward, it does not Top mini licensing rounds which are associated and tied to existing concessions and the us. Neighbor licenses are also to be permitted for application. We within and this is something I said long before the 2,050 agreement was ever announced. We within the DUC Have a significant number of low cost value accretive projects inside of our development portfolio. Therefore, these projects and these development opportunities are not going to be impacted by the 2,050 agreement nor will they be impacted by the lack of any forward licensing rounds. One of the other unique elements of the 2,050 agreement is the focus on how it promotes ESG And in particular, not only promotes but supports things like carbon capture and storage and agreements to be put in place for electrification of the offshore installations. Both of these are things that we feel may fit well within our portfolio and are certainly things when we speak of electrification in particular that we are not only will be but already are pursuing along with our DUC partners. So, overall, the 2,050 North Sea agreement in the Danish Continental Shelf, we find a tremendous piece of Forward stability for all of the industry, for all of the players in the Continental Shelf gives us not only predictability and certainty as to how this will all come to an end, But it gives us the framework for developing our existing DUC projects and development opportunities. With that quick overview of the operations and latest sort of conditions for us, I'd like to hand over to you and Shirla, We'll handle the financial review. Thank you very much, David. Firstly, I think it's worthwhile as we report our 2020 results today. Looking back and noting the unprecedented backdrop over the year that has impacted everybody, but not least the Oil and Gas Industry. It's probably not at this stage worthwhile emphasizing, but it is still helpful to note that I think COVID has created a number of challenges and obstacles that have had to be overcome, Risk to operations and people and also lower potential activity levels. It also led to and contributed to significant volatility In commodity prices in a broader uncertain macro environment, there were challenges in the physical oil markets. And bringing all of this together has created a context that has required swift and proactive management of the situation. It's also highlighted fundamentally the value of our approach to risk mitigation that we had already put in place Prior to the start of the current situation. In the DUC, as Dave has outlined, Total has done a good job of managing Managing the operations and mitigating risks. Costs were reduced both as a result of lower potential activity levels, But also a desire to frame spending in a way that was appropriate for the prevailing commodity price environment. For Norika specifically, we've benefited significantly throughout the year from our hedging arrangements. Over a period where the Brent prices ranged from $17 to $69 a barrel. And averaged 42 throughout the period. We have Significantly we have consistently received realizations that are significantly above where the market has been and our realizations over the period of averaged $67 and our realizations in Q4 particularly where $64 or 63.6 In addition to that, under the Shell Liquids Guarantee arrangement, we received a contribution from Shell of $98,000,000 throughout the course of 2020, Of which roughly a third or $31,000,000 was received in Q4. And that has reflected the level of production that was Achieved during the period. From a financial performance perspective, this has enabled us to report strong results through difficult circumstances. Our revenue for the year is $566,000,000 of which $146,000,000 was generated in Q4. We Had an adjusted EBITDA contribution of $358,000,000 with $73,000,000 in Q4 And operating cash flow of $346,000,000 with $96,000,000 of that coming in The Q4 of the year. Looking forward, the macro environment, certainly from a commodity price perspective, is improving. Well, COVID remains a risk that we all have to be conscious of within the record. I think we take comfort from the fact that during 2020, There have been successful mitigating actions taken and that provides us with a stable read through for the future. Looking at Noreco specifically as we go forward, we're well positioned going into 2021. We have significant liquidity with cash on the balance sheet of $259,000,000 And beyond that, we announced in February of this year an underwritten amend, extend and increase of our RBL To $1,100,000,000 This will enhance our funding profile, address The disconnect between Tyra startup and when RBL amortizations were scheduled to commence and therefore provide a strong foundation to deliver Tyra, Which as Dave has highlighted a couple of slides ago, is an extremely attractive project compared To compare to the alternatives that are within the North Sea peer set. It will also enable us to generate significant free cash flow from 2023 Moving on to cover the change in RBL in some more detail. As I as I mentioned, we announced an underwritten, new $1,100,000,000 facility, which is expected to close Towards the end of Q1 or early Q2 of this year, that is an amend extended increase of our existing 900 $1,000,000 facility that will have a maturity in 2028 and will amortize from The second half of twenty twenty four. It will also significantly increase our drawing capacity and support our liquidity profile. The expected drawing capacity on close will be $1,000,000,000 which will represent roughly $249,000,000 We have, as part of the RBL process, included a linkage to ESG goals as part of this facility. We will be able to communicate more on what exactly those are once the process of syndicating the loan has closed. But I think what we can see now is that the focus is on working towards, as Noreco, a clear and quantifiable path towards significant emissions reduction. More broadly, what the RBL increase demonstrates is that in a relatively difficult environment, there are probably 2 key messages. We continue to benefit significantly from the ongoing support of our existing bank group and it is also a testament to the long term Value proposition of Noreco's DUC assets. Well, first production from Tyra has moved into 2023. It's clear that that hasn't fundamentally altered the strength of Noreco's underlying case. The next slide, we have a summary of the, of effectively the operational performance and how that flows into the financial results That we have reported during Q4, we had production of 25,500 barrels of oil equivalent Per day and an over lift of 2.8, which led to sales of 28,300 barrels a day. Our realized liquids price in the quarter was $63.6 per barrel, and that compares to an average dated Brent price during the period of Roughly $46 per barrel that has allowed us to generate revenue of 146 $1,000,000 over the last 3 months. Moving on to cover our, hedging arrangements. As I've noted, we benefited significantly from the hedging arrangements that we had in place throughout 2020. We have a minimum hedging requirement from a price perspective under our RBL. Given the volatile conditions throughout 2020 and a recognition on both parts that we didn't want to hedge at the bottom or close to the bottom of the market. We received a waiver from the Bank Group in both June 2020 December 2020 off part of this minimum hedging requirement. So in June, we waived the 1st 6 months of 2023's hedging requirement. And in December 2020, we waived The entirety of 2023's hedging requirement. This waiver will remain in place until June of or the end of June of this Yeah. However, we have taken advantage of the uptick in oil prices during 2021 so far To put hedging in place for that 2023 period, we have placed 3,300,000 barrels of Brent hedges At an average price of roughly $52 per barrel. And as a result of that, from the 1st January 2021, Our hedge portfolio covers roughly 14,000,000 barrels over the next 3 years, at an average price that is significantly above The current market. Finally, on this page, the Shell volume guarantee, which was benefited from throughout 2020, Generated $31,000,000 of contribution in Q4 and the protection period under this agreement expired At the end of 2020. Moving on to Slide 14, This reflects a summary of the Q4 financial report, so I'm not going to run through it in a great amount of detail. I would Highlight again the fact that we have throughout the period both in terms of revenue and also our profitability and also cash flow generated Strong results and that's reflective of our overall performance in 2020 as a whole. We exit the period with a, a strong cash balance And a strong liquidity profile against the backdrop of, again, as I've Probably mentioned a couple of times now a challenging environment that we have faced during 2020. Moving on to the final Slide of the finance section, we have an overview here of the capital structure. I think most people should be familiar with it now, but we have a reserve based lending facility which was drawn at $751,000,000 at the end of 2020. We have agreed to, on an underwritten basis increase that to $1,100,000,000 and that will, as I've noted, add significant liquidity and borrowing capacity. We have 2 publicly traded bond instruments, North 13, which is a mandatory convertible bond, Has a principal of $171,000,000 that reflects the payment of a PIK interest coupon during the period And NOR14, which is a senior unsecured bond with a principal of $175,000,000 and a maturity in 2026. Bringing that together with our cash balance of $259,000,000 we have net interest bearing debt on an accounting basis of $862,000,000 And Given the structure of the convertible bond as a mandatory conversion to equity that is excluded from the Covenants that we are, that we operate under. So our net interest bearing debt excluding that convert, North 13 is $692,000,000 I think I just close by, really re emphasizing some of the messages that I've provided throughout this overview, but We have generated robust financial performance throughout 2020 and we exit the year with significant liquidity and a strong forward profile Based on both the position of the business at the end of the year and also the revised RBL structure that we have announced in early 2021. And with that, I will hand back over to David for some closing reflections. Very good. Thank you, Ewan. Again, I think we've been able to show and highlight a very strong quarter for Norco, bringing out a close to the rather unprecedented and challenging 2020. Nonetheless, I think we've come through that year is about as good as we could have hoped. But what's really important, I think, in the excitement is when we look forward in the long term value that sits inside of Noreco. We continue to sit on a very large In material reserves and resource base, our 2P reserves still in excess of 200,000,000 barrels equivalent And we have that 2C resource of another almost 200. That 2P is helping us to deliver very consistent production, which therefore drives the operational cash flow that Ewan's been able to outline and we continue to see the reservoirs and the overall Performance from the DUC delivered very low decline rates and we do have opportunities within that DUC to further offset the decline through additional investment. We've outlined and is actually supported through that 2050 North Sea agreement that we do have near term growth opportunities. We expect to grow through Tyra by almost 70 percent to 50,000 barrels of oil equivalent a day. We have a lot of milestones that are going to be demonstrating Success of that project coming up through 2021 as I've highlighted as well. So, very exciting year ahead. We do have this We set a growth opportunities that sit within our own backyard, sit within the DUC. We've identified these as high value and we see that they're actually low development cost projects. This includes projects like Halfdan North, Baltimore Bow South and several others that we have sitting inside of our portfolio. We also sit in a place where we have advantageous tax balances working to support some of not only the work we have in Denmark, but potential inorganic value added Opportunities. Our cash flow has been and we continue to mitigate the risk of the market through our hedging program With almost 14,000,000 barrels of price hedges already in place from 2021 to 2023, an average hedge price of 56 Dollars per barrel of oil equivalent in 2021 2022 and just over 50 in 2023 when we see the Tyra startup. All this is underpinned by a very strong financial position. We have a diversified set of diversified sources of funding in place And we have no near term debt maturities or capital repayments coming due, which gives us great confidence in our position going forward. With that, I'll close this simply with the statement that it's a pleasure to be able to speak to you. We look forward to answering questions. We continue to be very confident in what we can bring forward for Noreko and to our investors. With that, I'll hand over to Catherine so we can receive and address questions. Thank you, David. The first question goes to you. How should we think about OpEx going forward? With slightly lower production, is this quarter a proxy for what we should expect? The production impact we saw in 4Q was impacted by Primarily a 3rd party pipeline shutdown in part of some of our deliveries. Therefore, if you will, We did have the denominator lower than we would have liked. We are doing a lot of activity to sort of Continue to do catch up from COVID and that does mean getting the people offshore and getting the work in place again. I don't think we're going to see significant changes in our OpEx level as we go through 2021. We're doing everything we can to optimize not only that spend, but in particular the barrels that we're able to bring back from that. So As a full proxy, I think that's probably and up through at least 2021 while we recover, not far off And that's exactly we'll certainly want to be transparent on that as we go forward. With raw material prices sharply rising, how does this impact the Tyreba redevelopment costs? We continue to forecast the project as sort of at budget. A lot of what we've done has A lot of the fabrication and supply chain and procurement has already been completed. So I think we are not anticipating significant impact From that piece, the contracts we've had around the project have been in place for some time. What's really left is the work in the yard. It's the man hours and bringing the necessary kit and equipment in to get it in place so we can make our sail away dates. Less Directly concerned with the actual raw material prices at this point in time due to the position of existing contracts. Next question, do you have any cost guidance for 2021? I think if I can handle that one, David, I think what we have guided in terms of cost is around particularly the Tyra CapEx are in the development project. So we have guided that roughly 40% to 50% of the remaining CapEx on the project will come During, 2021. And that's a fairly good proxy for where we will be spending our CapEx during the coming 12 months. And the next one is for Ewen as well. When you talk about drawing capacity of SEK 1,000,000,000 under the RBL, does that mean your borrowing Base is at least that much. Yes. I think it's the simple answer, yes. The borrowing base is over $1,000,000,000 yes. And for David, your guidance implies a 7% decline rate. You also said that your decline rate is very low. Are these two statements consistent? Yes, they are. We have seen a decline through 2019 to 2020 of almost exactly 7.5%. If we can hit the top end of our range, then that decline sits at closer to 5, 4% to 5%. The bottom end, we're still around 9% or a little more. And this is a testimony, if you will, to types of reservoirs we have, if you look at overall North Sea decline rates, if we can be sitting in single digits, in particular, if we can be sort of in that 5% to 8% or 9% decline rate. That's what we would expect and that is indeed a low decline rate through these reservoirs. Total has previously indicated some interest in potentially electrifying parts of its Danish production. And you also mentioned that parts of the RBL could be linked to ESG milestones in the previous press release. Can you elaborate on these milestones and what your view is on potential electrification? I think that almost gets picked up by both of us. As Ewan noted, we will speak more to The specific milestones associated or ESG milestones associated with the RBL a little bit in the future. Overall, we are very aligned with both with Total and the North Sea Fund on our direction for the DUC and we do see tremendous opportunities for electrification. We sit in probably One of the greatest renewable economies in the world in the backyard of Denmark and so given that the source of much of their power is already through renewables, We would want to be able to tap on to that if at all possible and it's something we're already very much focused on and spending time on. I don't know you and anything further on the RBL you'd like to add on that? I not particularly. I think as I mentioned, we'll be able to give further guidance on specifically the RBL metrics Once the facility has closed, I think the only thing I would add is that, you know, clearly from As Dave has highlighted, the sort of the overall backdrop around the direction of travel or the push towards A continuation of the kind of the broad ESG goals that we have. I think there is still, you know, there are still steps being taken and scoping Work to be done around what those specific projects look like. And I think it's quite difficult to comment or give any specific indication You know, how that will manifest itself through our business as we move forward. I think what I would say though, certainly from our perspective is that we are conscious of the fact that, Well, you know, we're very clearly consistent and want to operate consistently with The kind of sustainability or ESG outlook that we think is important to have, we also do recognize the importance of balancing that against capital requirements for these projects as they come up. And I think that's why, as I pointed to the scoping work in terms of determining what The options and what the forward plan looks like is very important. Contribution from volume guarantee is €31,000,000 when this expired end of 2020, you will lose a major contributor for the next 1.5 years. How do you see this? Just to clarify on that point. So the contribution in terms of the protection period expired at the end of 2020. That has added significant there has been a significant benefit from that agreement throughout 2020. I think it is always worthwhile when we look at the volume guarantee from bearing in mind the fact that that was something that was put in place where Our contribution from that agreement doesn't necessarily reflect underperformance of the assets from our side. The Levels that were guaranteed were higher than where I think we would have set our forecasts from an asset perform An asset performance perspective as we were looking forward. So it is clearly something that we have benefited from. I think as we as we look forward, the work that we have done around forecasting the think the outlook for the business clearly takes account of the fact that that agreement will no longer exist. And I think to frame it Slightly differently rather than being something that we have lost and will not benefit from going forward. I think we have to on the fact that we have benefited from something that typically you wouldn't have expected to as part of an M and A transaction over the Effectively, the 17 months that we've owned the assets up to the end of Q4. Thank you. David, yesterday, Total announced that they have sent in plans for new wells on the Hofdan North and Waldemar. Can you please comment on this? Yes, both Haftand North and Veldemorbo South are some of these high value, low cost development projects we've talked about sitting inside our DUC backyard. We have done the scoping work to the point that we can and have Submitted for these two fields, field development plans to the Danish Energy Agency. Upon approval of that, Then there would be a choice and a final decision for investment made by the partnership. That step test to be taken before we move any further. But in both of these cases, we're talking about putting in unmanned platforms which basically tie into our existing infrastructure That will produce not only new volumes, but produce volumes at significantly lower carbon footprint. We expect these to be Somewhere in the order of 30% lower in terms of admissions versus the existing portfolio in the DUC. So both of these have very attractive looking development opportunities. We need the DEA to approve the FDPs. We then as a partnership need to finalize the details and make a decision whether we will FID these and take them forward. David, do you have any OpEx cost guidance for 2021? I think the short answer is we're not going to provide guidance on that Other than I think what we heard was the proxy that we've seen from 2020 is not too far off for what we'll be dealing with. I think the other thing to point out is if we look at the long term trend, we've brought OpEx to a Significantly lower number than it was historically inside of the DUC, but there is a period where we're still dealing with The development without the benefit of Jaira. And so I think what the proxy has mentioned earlier is probably the best guidance that we can offer at this time. In what countries or regions could inorganic growth be relevant? Again, we need to look and make sure that there would this would be smart investment. We have the opportunity and Primarily, we would focus on where we see potential tax balances. That really limits us specifically to the North Sea. Obviously, Denmark in the UK is where we hold specific tax balances. So that's probably the best focus I can give as you know. We're going to look first in our backyard. We're going to then look at where we have our tax balances. We're not looking at doing anything beyond sort of the North Sea. And the final question. Production G and A for the quarter was €18,000,000 That implies Almost SEK 50,000,000 on a 100 percent basis for the field. Can you please give us a sense of what the major components of this are and why these costs Are going up. Euros 50,000,000 seems like a lot for G and A for a field for 1 quarter. I think if I can start on that one, David. I think one of the underlying points that's important to know and we haven't actually touched on this particularly in the presentation so far, but a substantial portion of the costs that we experience in the DUC or that we pay on the DUC are denominated in Danish kroner. So as a result of the strengthening of the So as a result of the strengthening of the currency over the Q4 period, which was quite material, We have had a sort of underlying headwind around an increasing cost. So I think that is One element to bear in mind, I think as an overall point, I mean, I think it is fair to recognize that as you highlight that Cost is relatively high for the current environment and the current level. I think what we can say is, you know, we are taking As active steps as we can to look at ways in which the organization that, is in place around the DUC could be improved or could be enhanced. It does also reflect the fact that there is an organization within the DUC that is effectively for A 4 hub, relatively large scale infrastructure asset base. And that has a cost associated with it. And I think, clearly, it is a number that is at the upper end of what you would expect. When Tyra is on stream, obviously that will be spread across a larger production base. But I think it's I think what I would say as a sort of conclusion on that point is that it is, you know, fair to say that it's also something that we recognize as part of our OpEx Level as a whole and that is an area where there is certainly scope for further improvement and that is something that we are very much focused on achieving as we go forward. Thank you. That concludes the Q and A session. Thank you for participating.