Hello, and welcome to BlueNord's Q1 Release. Thank you for joining us today. I'm David Cook, CEO. I'm joined by John Hulme, our COO, and Euan Shirlaw, 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 first quarter 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-Tyra 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 NOK 1.1 billion and we 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 NOK 320 million of 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. 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 Noreco, 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 Euan will bring us to the finances following that. John, please.
Thank you, David. As Dave mentioned on production, first quarter averaged 25.8 thousand 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 six-day shutdown there. We had a very strong January, and then we had this six-day shutdown on Gorm. Gorm itself wouldn't have been such a massive impact, but the Halfdan, our largest producer, the crude stabilization occurs on the Gorm platform. That was also shut down. Had we not had this six-day shutdown, we would've been just above the midpoint of our guidance, and it would've been a better quarter. Those numbers are reflected 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 Dan F platform. We're very pleased to have the rig back. We've got a number of wells in Dan and Halfdan that need restored to production to bring our numbers back up. The last time we had a rig on site was March 2020. This program has been delayed, and we've already had a good start to a five to six-well workover program that are going to bring the rates up quite significantly from where we are today. Next slide, please. In terms of Tyra, story is very similar to previous presentations. We have some very large milestones upcoming that will de-risk this project.
Our 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 Tyra East wellhead platform. Of the eight platforms, we'll be installing four 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 Tyra West wellhead platform and riser platforms, through to first production in Q2 2023 following the hookup and commissioning campaign. CapEx and OpEx, most of the abandonment or a lot of the abandonment has been done now.
We're at NOK 53 million for the quarter, the remaining spend for Tyra is fairly evenly split between 2021 and 2022, then 10%-20% in 2023, depending how much of the hookup and commissioning and the final cost to bring these fields and facilities online. Moving on to reserves. 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 practitioner's report, and this is completed by Ryder Scott in London. The reserves are completed according to internationally accepted guidelines, the SPE-PRMS. That's the Society of Petroleum Engineers Petroleum Resources Management System. 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 million barrels of oil equivalent.
Our 2P proven plus probable, this is our 50 percentile at 201 million barrels, and our 3P proven plus probable plus possible at 246 million barrels. If we focus on the 2P reserves for a moment, the breakdown there is 101 million barrels developed and on production, that is basically the three producing hubs we have now, so Halfdan, Dan, and Gorm hubs. The under development component is 76 million barrels, that is the northern fields that will all be back online as soon as the entire development is complete. We have 24 million barrels in there for three future projects that we have passed FDP and are moving towards FID for Halfdan North, the gas lift at Halfdan CA platform, and Valdemar Bo South development. The 2C number of 200 million barrels is an internal company estimate. It is 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 million barrel 2P is based upon a $60 price assumption. If you look at the chart on the bottom right, we believe from an EV/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 these key significant milestones, such as third quarter this year with the installation phase on Tyra. 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 two perspectives. Firstly, our quarterly performance, before moving on to our path to deliver the Tyra redevelopment project. Starting first with the first three months of 2021, our financial performance continues to strongly reflect the hedging arrangements that we have in place. Our underlying operations through our three producing hubs are 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 a following slide, are focused 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 fourth quarter of 2020. Looking at this more holistically, it's key that the DUC, as 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 Tyra 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-19 measures that were put in place in Denmark. 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 to $1 billion at close, which supports our liquidity position when compared to the drawings under this facility at the end of Q1 of $751 million. In conclusion, our overall liquidity position, with NOK 319 million 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 NOK 1.1 billion facility became effective on the 5th of May 2021. This followed the announcement in February of this year of the underwritten amend, extend, and increase, and replaces our existing NOK 900 million 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 that will strengthen our position going forward.
The NOK 400 million 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 two-year maturity extension that underpins our increase in borrowing capacity demonstrates the long-term value proposition of our position in the DUC.
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. While 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 during 2020, which represented a weaker oil price environment. As we look forward, the hedging arrangements we have provide a floor on our expected realizations, with volume significantly weighted to the pre-Tyra period. We currently have 13.1 million barrels of oil equivalent of price-hedged volumes from Q2 2021 until the end of 2023, with 12.7 million barrels of oil through this entire period at an average price of $54.50 per barrel. During the first quarter, we also added 600,000 MWh of gas for delivery through Q2 and Q3 2021 at an average price of EUR 17.4 per MWh . As I mentioned, we added this gas hedging during the first quarter of 2021 to take advantage of the strong market conditions that we witnessed in the European gas markets, started hedging near-term volumes.
We expect to continue building our gas hedging portfolio as we approach Tyra first gas. Our capital structure, which provides an overview of our current position. We've gone through the RBL in detail. To summarize the key figures, this facility was $751 million drawn at the end of Q1. Following completion of the enlarged facility, our availability is the full maximum cash drawing capacity of $1 billion, providing roughly $250 million of undrawn borrowing capacity. The NOR13 instrument is currently at $178 million of principal, reflecting our continued payment of PIK interest under this instrument. NOR14 is the $175 million unsecured note that we issued in 2019 and is due in 2026.
Along with the deferred consideration of NOK 25 million and cash of NOK 70 at the end of our quarter, our net debt on an accounting basis stood at $ 1,059 and $ 881 using our covenant methodology, which excludes NOR13. With that, I will turn back to David for his closing reflections.
Thank you, Euan, 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. Can we 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 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-Tyra cash flow is continually secured by the hedging.
As Euan has just outlined, we have circa 14 million barrels of price hedges in place from 2021- 2023, in the order of mid-50s per barrel of oil equivalent. The business is robust. We sit in a strong financial position with diversified sources of funding, and especially now post the renewed RBL, we have no near-term debt maturities or capital repayments due. With that, again, I'll close by saying we're 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 Euan. What are the advantages of forward sales versus buying put options?
Thank you, Cathrine. 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. I think that points to a clear advantage of having effectively that certainty, which is provided through forward sales. The disadvantage of put options, of options as we look at them, is frankly the fact that they are relatively expensive.
They do give you more equity upside, 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, while 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-Tyra and post-Tyra 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.
Euan, how much will the VAT payments in 2021 impact cash flow versus in 2020?
As I noted when we walked through the issue, or the impact of VAT that we had in Q1 2021 was driven by the COVID-19 measures that were put in place by the Danish government. We do not expect that to be a recurring effect or a recurring impact. As a result, 2021 VAT will be paid on a more regular schedule. The current VAT liability that exists at the end of the first quarter and reported on our balance sheet is $6 million. 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 first quarter.
John, what OpEx per barrel should we expect after Tyra first gas?
Thanks, Cathrine. 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. Sometimes it makes sense to spend a little more. We're continuously looking to optimize those. We see a number of opportunities going forward as we move towards Tyra coming online to improve the dollars per BOE on the existing hubs. Certainly, once Tyra 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 am not prepared to say where that will be at this point. Significant drop to the current numbers once Tyra is online in 2023.
Thank you. David, how do you view the current M&A opportunities on DCS?
Inside the Danish Continental Shelf, obviously we've seen a little bit of consolidation recently. I think what I'd focus on first 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&A spectrum. That being said, the last year's Danish 2050 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.
Euan, why are stated oil sales not the same as oil liftings?
We have a lifting schedule that determines effectively the revenue that we achieve 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. Through time, you would expect that to move to zero. 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. There is a lifting schedule around which you get paid for those volumes that are lifted. As a result of that, you build up temporary changes in over or under lift.
John, approximately what is the cost for the Noble Sam Turner workover program?
The rig is here for a number of years. 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 on the spread rates that we have. Just suffice to say that it's extremely competitive given the current state of the market. This is about as low as I've seen rig rates for a long time. This is an excellent opportunity to be doing this infield work to maximize increase in production via these workovers and maintenance opportunities.
Thank you. Euan, 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 Tyra 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 startup of Tyra, 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. Effectively, the pro rata economic share that 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. I think as we go forward, it will be a split that is more reflective of the underlying production volumes that we have once Tyra is on stream.
The final one is for you as well, Euan. 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. That concludes our Q&A session. Thank you for participating.