Earnings Call: Q1 2021

May 11, 2021

Hello and welcome to Noreco's Q1 release. Thank you for joining us today. I'm David Cook, CEO. I'm joined by John Hung, our COO and Ewen Shirla, our CFO, to walk you through this quarter's performance. Please note, we encourage you to send questions as we go through the presentation. With that, let's get started. The top highlights for the quarter start with our production at just under 26,000 barrels of oil equivalent per day within guidance, although slightly below the midpoint. That was impacted by a Q1 one off issue that was resolved quickly. John will cover that a little bit later. Nonetheless, it shows our continued reliable performance supporting our operational cash flow. We've also seen a realized oil price of $56 per barrel. This is helping to underpin our pre tariff cash flows through the ongoing hedging arrangements and secures the predictability in our outcomes. The RBL increase was also announced in 1Q with an increase to 1,100,000,000 and subsequently completed that increase in May. We believe this is a testimony to the strength of our asset portfolio. It's also left us in a strong liquidity position following completion of the RBL with circa $320,000,000 available liquidity providing further surety in our forward finances. We're excited that we've had the arrival of the Noble Sam Turner rig, now on-site to support production through planned workover and maintenance programs. This will continue to enhance our production outcomes and protect the integrity in our subsurface and wells. And finally, we have the Tyra redevelopment progressing with significant milestones forthcoming later this year. It's exciting to see the continued progress in this project, which will have certain positive impact for Noreko, the DUC and for Denmark. With that quick summary of the highlights, I'll hand it over to John to walk through the operational review and then Ewan will bring us to the finances following that. John, please. Thank you, David. So As Dave mentioned on production, 1st quarter averaged 25,800 barrels of oil equivalent per day. This was at the lower range of our guidance. If you look at the chart on the bottom right hand side of the slide, you'll see a 6 day shutdown there. So we had a very strong January And then we had this 6 day shutdown on Gorm. Now Gorm itself wouldn't have been such a massive impact, but the half down our largest producer, the crude stabilization occurs on the Gorm platform. So that was also shut down. Now had we not had this 6 day shutdown. We would have been just above the midpoint of our guidance and it would have been a better quarter and those numbers are in the operational efficiency that you see. As Dave also mentioned, the Noble Sam Turner, You can see the rig on the right hand side there currently at the Danf platform. We're very pleased to have the rig back. We've got a number of wells in Dan and Half Dan That need restored to production to bring our numbers back up. The last time we had a rig on-site was March 2020 and so This program has been delayed and we've already had a good start to a 5 to 6 well workover program. They're going to bring the rates up Quite significantly from where we are today. Next slide, please. So in terms of Tyra, Story is very similar to previous presentations. We have some very large milestones upcoming that will de risk this project. Accommodation module, the 5,000 metric ton project out of Italy will sail away and look to install in the second half of this year Along with the Tara East wellhead platform. So of the 8 platforms, we'll be installing 4 of them this year. And then the remaining work will continue and flow into 2022 where we continue with the very large gas processing facility And the Tara West wellhead platform and riser platforms through to first production in Q2 2023 following the huck up and commissioning campaign. CapEx and FX, most of the abandonment or a lot of the abandonment has been done now. We're $53,000,000 for the quarter and the remaining spend for Tara is fairly evenly split between 2021 and 2022, Then 10% to 20% in 2023, depending how much of the hookup commissioning and the final cost to bring this field and these fields and facilities online. Moving on to reserves. So you may have seen the published reserves report, which was in March this year. This is our independent third party assessment of reserves, our certified practitioners report, And this is completed by RISC in London. The reserves are completed according to internationally accepted guidelines, the SPEPRMS, that's Society of Petroleum Engineers, Petroleum Resource Management System. So this is a very solid set of independent external reserves. And if you look at the chart on the top right, we have our 1P proven reserves at 131,000,000 barrels of oil equivalent. Our 2P proven plus probable, this is our 50 percentile at 201,000,000 barrels and our 3P proven plus probable plus possible at 246,000,000 barrels. If we focus on the 2P reserves for a moment, the breakdown there is 101,000,000 barrels developed and on production and that is basically the 3 producing hubs we have now. So Halfdan, Dan and Gorm hubs. The under development component is 76,000,000 barrels and that is the northern fields that will all be back online as soon as the Tara development is complete. And we have 24,000,000 barrels in there for 3 future projects that we have passed FDP and are moving towards FID for Halftand North. The gas lift, had a half down CA platform and Valdemar both south development. The 2C number of 200,000,000 barrels is an internal company estimate, it's not externally validated. This is our view of potential upside in these assets and we look to move as much of the 2C into the 2P in the future as we can. All of these reserves, the 201,000,000 barrel 2P is based on a $60 price assumption. And if you look at the chart on the bottom right, we believe from an EV over 2P perspective That we're undervalued relative to our peers. We believe that the valuation of these barrels will increase as investor confidence increases And as we start to hit some of the key significant milestones such as Q3 this year with the installation phase on Tara. Thank you. Thank you, John. Turning now to focus on the financial position and performance of Noreco. I'd like to do that by walking you through from 2 perspectives. Firstly, our quarterly performance Before then moving on to our path to deliver the Tyro redevelopment project. Starting first with the 1st 3 months of 2021, Our financial performance continues to strongly reflect the hedging arrangements that we have in place. Our underlying operations through our 3 producing hubs Our profitable based on the $56 per barrel realized oil price during the quarter. Our hedging activities, which We will cover in a little bit more detail on our following slide our focus on ensuring that we maximize cash flow visibility for the company prior to Tyra starting up, while at the same time minimizing our exposure to commodity price volatility. Our operating cost during the quarter was $30.5 per barrel, down from $35.6 per barrel in the Q4 of 2020. Looking at this more holistically, it's key that the DUC has a relatively mature asset base, But with significant remaining potential, has an appropriate cost structure to both maximize economic recovery, but also drive performance for the decades to come. The additions of tire volumes from modern low cost facilities will, of course, support this objective, But our broader focus needs to be and is on ensuring that the overall DUC organization is fit for purpose both operationally and consequently financially. While the Q1 2021 downward OpEx trajectory is welcomed, We will continue to focus on driving efficiency gains, both onshore and offshore. From a working capital perspective, We made a payment during Q1 2021 of our Danish VAT liability for the full year of 2020. The timing and quantum of this payment reflected the COVID-nineteen measures that were put in place in Denmark And going forward, our VAT liability will be settled on a more regular basis, and we do not expect a buildup such as this to occur again going forward. However, cash flow from operations excluding changes in working capital remained positive in Q1 2021, reflecting the important ongoing contribution from our currently producing hubs while the Tyra redevelopment progresses. As we look forward through the remainder of 2021 and into 2022 and ultimately to Tyra First Gas, the completion of the RBL refinancing announced in May is an important milestone. As the RBL is the core of our capital structure, The process we have undertaken in 2021 to refinance is important as it provides an instrument that is fit for our business plan And has an extended maturity with a consequential shift in amortization profiles. It also delivers a substantial increase in borrowing capacity $1,000,000,000 at close, which supports our liquidity position when compared to the drawings under this facility at the end of Q1 of CAD151,000,000 In conclusion, our overall liquidity position with CAD319,000,000 of availability, Combined with the operating cash flow contribution that is expected from our existing production continues to build our fully funded position to deliver the Tyra redevelopment project. Moving on to the RBL and looking at that in a little bit more detail. We successfully completed the refinancing and our new $1,100,000,000 facility became on the 5th May 2021. This followed the announcement in February of this year of the underwritten amend, extend and increase And it replaces our existing $900,000,000 facility that was initially structured to fund the acquisition of our interest in the DUC from Shell. We continued throughout this process to benefit from the strong support of our existing bank group, and we also added a number of new names to our syndicate will strengthen our position going forward. The $400,000,000 accordion option provides a mechanism to support potential future commercial activities that we may choose to progress if they are sufficiently attractive and consistent with our overall strategic objectives. The 2 year maturity extension that underpins our increase in borrowing capacity demonstrates the long term value proposition of our position in the DUC And with amortization starting in 2024, we've strengthened our forward position with a year of contribution from Tyra prior to repayments starting under this facility. In addition, we also added ESG linkage to this facility. Well, the underlying margin remains constant versus our original RBL. The ESG linkage occurs through the inclusion of key performance indicators that will progressively adjust the margin payable by up to 10 basis points through the life of facility. The result of these KPIs, which will be driven by the progress we make in achieving our sustainability objectives, Will ultimately impact the extent to which we benefit from that margin change. Moving on to hedging, As I mentioned at the outset, our hedging program is focused on maximizing certainty. We want to have a clear view of cash flow to Tyra First Gas And to have minimum exposure to uncertainty as we progress through the redevelopment. We benefited significantly from the arrangements that we had in place 2020, which represented a weaker oil price environment. And as we look forward, the hedging arrangements we have provide a floor on our expected realizations, With volumes significantly weighted to the pre tariff period. We currently have 13,100,000 barrels of price barrels of oil equivalent of price hedged volumes from Q2 2021 until the end of 2023, With 12,700,000 barrels of oil through this entire period at an average price of $54.5 per barrel, And during the Q1, we also added 600,000 megawatt hours of gas for delivery Q1 sorry, through Q2 and Q3 2021 at an average price of €17.4 per megawatt hour. As I mentioned, we added this gas hedging during the Q1 of 2021 to take advantage of the strong market conditions that we witnessed in the European gas markets and started hedging near term volumes. We expect to continue building our gas hedging portfolio as we approach Tyra First Gas. Finally, our capital structure, provides an overview of our current position. We've gone through the RBL in detail, but to summarize the key figures, this facility was CAD751,000,000 drawn at the end of Q1 and following completion of the enlarged facility, our availability is the full cash drawing capacity of 1,000,000,000 providing roughly $250,000,000 of undrawn borrowing capacity. The NORTH13 instrument is currently at $178,000,000 of principal, Our continued payment of PIK interest under this instrument NOR14 is the $175,000,000 unsecured note that we issued in 2019 and is due in 2026. Along with the deferred consideration of $25,000,000 in cash 70 at the end of our quarter. Our net debt on an accounting basis stood at 10.59 And 881 using our covenant methodology which excludes NOR13. With that, I will turn back to David for his closing reflections. Thank you, Ewan, and thank you, John. I think if we go to the last slide, in short here, We believe that Noreco continues to provide an extremely attractive value proposition. Slide 1 move one slide forward please. The messages that we have here are not different than what we've had in the last few quarters. We continue to sit on a material reserves and resource base. John has outlined that in some detail. This is a significant set of assets with significant running room. We already have substantial production. That base production is providing strong operational cash flow. We know the low decline rates are going to continue to help us by delivering cash flow to offset our forward investments and are reliable through well known reservoirs. Our near term growth is certain through the delivery of Tyra. And following that, we'll be producing on the order of 50,000 barrels of oil equivalent per day after Tyra comes on stream. The certainty is underpinned by the delivery of some 2021 milestones. And as John laid out, the final installation hookup and installations in 2022. We do have quality through choice through the spectrum of growth opportunities that sit inside the DUC. There are a number of low risk organic growth opportunities that have already been identified. These are low CapEx projects within the DUC and our advantageous tax balances continue to support both the organic and inorganic opportunities we have. We have a very predictable business in the sense that our pre tariff cash flow is continually secured by the hedging. And as Eunice just outlined, we have circa 14,000,000 barrels of price hedges in place from 2021 to 2023 in the order of mid-50s per barrel of oil equivalent. And the business is robust. We sit in a strong financial position with diversified sources of funding and especially now post the RBL, renewed RBL, We have no near term debt maturities or capital repayments due. With that, again, I'll close by saying we're very, very bullish, if you will, on what the company has to offer in our forward future. Look forward to taking your questions now. Thank you. Thank you, David. The first question goes to you. What are the advantages of forward sales versus buying put options? Thank you, Catherine. When we look at the hedging portfolio that we have and the objectives of that portfolio, as I mentioned, One of the principles that we're trying to achieve is effectively giving us cash flow certainty to Tyra First Gas. So I think that Points to a clear advantage of having effectively that certainty, which is provided through forward sales. The disadvantage of put options are off options as we look at them is frankly the fact that they are relatively expensive. They do give you more equity upside, but clearly as you move further out and particularly when you try and hedge longer term volumes, It is a balance that we are trying to strike between keeping the hedging program as efficient and cost effective as possible Well still also giving us the certainty that we are looking for around cash flow. I think what I would finally point to on the topic of hedging is that I think we do see a differentiation between the pre Tiara and post Tiara period. I think once we get beyond The development CapEx intensive phase that we are currently in, we will be looking to ensure that we have more exposure to the commodity price markets. And, Johan, how much will the VAT payments in 2021 impact cash flow versus in 2020. So as I noted when we walked through the issue or the impact The VAT that we had in Q1 2021 was driven by the COVID-nineteen measures that were put in place by the Danish government. We do not expect that to be a recurring effect or a recurring impact. And as a result, 2021 VAT will be paid on a more regular schedule. The current VAT liability that Exists at the end of the Q1 and reported on our balance sheet is $6,000,000 And that will be paid on a regular basis as we go through. There will not therefore be the same level of one off payment that we experienced in the Q1. And John, what OpEx per barrel should we expect after Tayraf or Scas? Thanks, Catherine. OpEx is an area I've been focused on since I started work here in March. First on the existing hubs, Dan, Halfdan and Gorm, we are continuously looking, I would say, not just at cost cutting or OpEx cutting, but at productivity. We're looking for production opportunities that make sense because you can improve the dollar per barrel equation by both pushing the barrels or reducing the cost or some combination and sometimes it makes sense to spend a little more. So we are continuously looking to optimize those. We see number of opportunities going forward as we move towards Tara coming online to improve the dollars per BOA on the existing hubs. Certainly, once Tara comes online, we will have a significant drop in the OpEx. I'm not prepared to commit To what that number is yet, I'm not ready to disclose that forward statement. It will have a teen in it, but I'm not prepared to say where that will be at this point. But significant drop to the current numbers once Tara is online in 2023. Thank you. And David, how do you view the current M and A opportunities on DCS? Inside the Danish continental shelf, obviously we're seeing we've seen a little bit of consolidation recently. I think what I'd focus on 1st and foremost is what we talked about is within the DUC we have a significant portfolio of undeveloped opportunities and that gives us great quality through choice without having to step into a broader, if you will, M and A spectrum. That being said, the last year's Danish 2,050 North Sea agreement really created stability for investment into the DCS. And we have great clarity on sort of what the terms are for everyone participating. And I have to believe that that's going to continue to incentivize investment and opportunity development across that entire DCS inside the DUC as well as out. And Ewen, why are stated oil sales not the same as oil liftings. We have a lifting schedule that determines the Effectively the revenue that we achieved from the oil and the lifting schedule does not directly correspond to the underlying production. However, it is Effectively driven by the underlying production that delta between the lifting schedule and the production volumes drives The over or under lift that we also report on our balance sheet and through time you would expect that to move to 0, But effectively it is a function of the fact that the volumes that are produced are not able to be exactly split 36.8% to Noreco And the remaining to the other partners. So there was a lifting schedule around which you get paid for those volumes that are lifted. And as a result of that, you Build up temporary changes in over or under lift. John, approximately, what is cost for the Noble Sam Turner Work Cover Program? I mean, the rig is here for a number of years and there is a combination of CapEx and OpEx costs. I don't have a detailed breakdown. I'm not sure I can disclose the rig rates. I think that's confidential in the spread rates that we have. Just suffice to say that it's competitive given the current state of the market. This is about as low as I've seen rig rates for a long time and This is an excellent opportunity to be doing this in field work to maximizing increasing production via these workovers and maintenance opportunities. Thank you. Johan, do you have a level of gas hedging you want to build towards? Or is gas hedging more opportunistic compared to your oil hedging approach? In the near term, our gas hedging approach prior to the startup of Tyre will be more opportunistic and will be driven by where we see that there are attractive opportunities in the market. As we get closer to the start up of tire, our overall hedging approach is driven by the principle that we would like to have Effectively our hedging policy be split between oil and gas on an economic basis. So effectively the pro rata economic share The oil and gas provides. Given the differential that we have at the moment between the volumetric and economic value of oil and gas volumes on an oil equivalency basis. Volumetrically, the oil Hedging will always probably represent more of the portfolio, but I think as we go forward, it will be a more It will be a more it will be a split that is more reflective of the underlying production volumes That we have once we once Tyra is on stream. And the final one is for you, as well, Ian. Can you please highlight upcoming payments of a one off structure that we should be aware of? There are no material one off upcoming payments within the business that aren't captured within our sort of typical operations or reported on our balance sheet. Thank you. And that concludes our Q and A session. Thank you for participating.