Dragon dance
After meeting Venezuelan officials in Caracas Energy Minister Stuart Young expressed confidence that Trinidad and Tobago would successfully conclude and execute a deal to receive gas from Venezuela’s Dragon Field, but his update lacked details owing to ongoing negotiations.
Challenges before first gas are not to be underestimated. The two-year waiver by the US Treasury Department is a tiny window in the timelines of petroleum extraction and the limitations on payment to Venezuela are an additional constraint.
In this file photo, Energy Minister Stuart Young greets Venezuelan President Nicolas Maduro in Caracas in June 2022. –
The deal relaxes severe sanctions the US placed on Venezuela and the terms may offer an opportunity for TT, which exists to serve the needs of the US amid energy constraints from the invasion of Ukraine.
It is unclear how long Russia will wage war, how long Ukraine will resist and what the US plans for relaxation of sanctions would be in the complex circumstances likely to exist at the end of the licence by the Treasury Department’s Office of Foreign Assets Control (OFAC).
A PDVSA resource discovered in 1985, the giant Dragon field, comprises an estimated 4.2 trillion cubic feet of natural gas reserves, idled under US sanctions, that borders mature but active Hibiscus field off north-western Trinidad.
In 2018, TT negotiated for access to the field, which has the potential to deliver significant supply to Trinidad’s under-utilised LNG production facilities when tighter US sanctions scuttled talks.
Leading the development of the project, gas pioneer Shell operates Hibiscus and has a long and frustrating history of trying to exploit the field for decades since the Mariscal Sucre project.
The US cleverly positioned the deal as a step forward for energy security for the Caribbean Basin, targeting Jamaica, paternal homeland of the US VP. Estimated yield from Dragon is 150-350 million cubic feet of gas per day, a production capacity that will surge past regional needs to northern markets.
TT requested a ten-year guarantee of access to the field but the US insists that it must continue to act the OFAC way, having overturned severe policy decisions regarding Venezuela in its own interests. TT must also protect its interests to avoid being stranded .
Venezuela is largely silent about the OFAC deal, perhaps mulling the real-world value of the hardline restriction on cash payments and what it means for value revenue as payment for its natural resource.
President Nicolas Maduro dismissed the limitation as modern-day colonialism but the troubled country cannot afford to ignore the lifeline.
Shell gas pipeline from Venezuela to Trinidad
Shell 17 Km gas pipeline from gas field Dragon to gas field Hibiscus
(NB Date)…Petroleum world 03 17 2017
Shell 17 Km gas pipeline from gas field Dragon to gas field Hibiscus
Oil and gas giant Royal Dutch Shell is expected to build a 17 kilometre (10.6 mile) pipeline from Venezuela’s shallow-water Dragon gas field to its Hibiscus platform off the north coast of Trinidad, following agreements signed Wednesday in Caracas, according to Venezuelan government statements.
Minister in the Office of the Prime Minister Stuart Young is expected to make the announcement today at the weekly post-Cabinet press briefing in Port of Spain.
On Wednesday in Parliament, he said he “just came off a plane” and would make an announcement within 24 to 48 hours on what Government is doing to help the declining oil and gas sector.
Hours before, he was excused from the Lower House sitting by Speaker Bridgid Annisette-George who said he was out of the country.
At a press conference in Caracas yesterday, Young said he wanted “to also welcome to the table, Shell, who have shown themselves to be a willing partner with both the Government of Venezuela as well as the Government of Trinidad and Tobago, and to emphasise and to concur with my fellow minister, his excellency (Venezuela’s Oil) Minister (Nelson) Martinez in telling Shell that we want to contract and crunch the time frame and to make this happen as quickly as possible and you have the full support of both Governments and our respective teams to make this a reality.”
Venezuela’s State-owned oil and gas company Petroleos de Venezuela (PdV) President Eulogio del Pino said at the press conference: “We’ve signed an agreement to supply gas to Trinidad through the National Gas Company of T&T (NGC) and Shell, and also to build a gas pipeline between Venezuela and Trinidad.”
US$100m investment
NGC Chairman Gerry Brooks signed on behalf of NGC while del Pino signed on behalf of PdV and Port of Spain-based Luis Prado, on behalf of Shell. NGC President Mark Loquan was also on the one-day trip to La Campina, Caracas. Young signed on behalf of the Government of T&T while Martinez signed on behalf of the Government of Venezuela. The agreements were not shared with the media. However, Young was quoted in one of the Venezuelan Government’s statements as saying the development of the project could entail an investment of more than US$100 million.
The agreements cover “the construction, operation and maintenance of a gas pipeline from Dragon field, located in the north-east of the Paria Peninsula, Sucre State, to Trinidad’s Hibiscus platform,” a Venezuelan Government statement said.
“After this pipeline is completed, natural gas will be supplied to the Trinidadian domestic market and to a gas plant on the island, from where it is expected to be sold to the international market,” the Bolivarian Government said.
“The initial idea is to start producing for Trinidad and Tobago, between two to three years, some 200 or 300 million (standard) cubic feet of gas (per day),” (mmscfd) Martinez said at the press conference at PdV headquarters in Caracas. Martinez said the gas to be exported to T&T “has the potential to be transformed into liquefied natural gas (LNG) or any kind of raw material,” suggesting both Atlantic, majority-owned by Shell, and Point Lisas could benefit.
Enough to supply T&T plus export
“The Dragon field is the closest to Trinidad and has a very interesting perspective, since it can generate gas for the domestic market and for export. Gas exports are of particular interest,” Martinez said. He said Venezuela has the gas potential – around 197.1 trillion cubic feet (tcf) of proven natural gas reserves – to fully satisfy T&T’s domestic market and still have leftover to export.
From Wednesday, a team of experts from Shell, PdV and the NGC will work together to define the operational, commercial and legal parameters that will govern the project, Martinez said.
“We already have the infrastructure on the Trinidad side and we have the willingness to accept this challenge. The benefit for the two countries is very clear,” he said.
The Dragon field is one of the four fields that make up the 14.7 tcf Mariscal Sucre Project (MSP) to the north of the Paria Peninsula, which aims to produce in the long term, 1.2 billion cubic feet (bcf) of gas and up to 28 thousand barrels of oil per day. Other fields in the MSP are the Patao, Mejillones and Rio Caribe fields.
After the signing, Young paid a courtesy call on Venezuelan Foreign Affairs Minister Delcy Rodriguez, and then flew to Piarco, whence, according to Opposition Leader Kamla Persad-Bissessar, he was whisked with “flashing blue lights” to Parliament to contribute to a bill to make borrowing from the Corporacion Andina de Fomento (CAF) legal.
Rowley: Dragon at ‘Business Plan’ stage
On March 6, Opposition Member of Parliament for Caroni Central Dr Bhoendradatt Tewarie asked: “Would the prime minister provide an update on the status of negotiations with Venezuelan authorities regarding the Dragon Field Project and advise this House on his assessment of progress made up to this point?”
Prime Minister Dr Keith Rowley responded: “Madam Speaker, as you know, these are very delicate negotiations, except to say that we have made some progress. We are at the stage of finalizing the kinds of documents that would put us on a path to move from concept to business plan, but I do not want, at this stage, to publicly discuss where we are at, given that these are very delicate and sensitive negotiations.”
An improved gas-reservoir delineation from seismic-derived impedance and density interpretation at Dragon field, Venezuela
Authors:César Vasquez and Wilmer Ochoa
https://doi.org/10.1190/tle33070764.1
Abstract
Dragon field of Norte de Paria, offshore eastern Venezuela, was discovered in the 1980s and offers a good opportunity for production of gas methane. Since 2008, several development wells have been drilled for production of gas reserves. After analysis of exploratory well E1 and development well D1, gas was found in the former and water in the latter. A recent study showed that analysis and interpretation of seismic amplitudes can differentiate fluids that saturate rocks and thus can optimize the production of hydrocarbons. Seismic amplitudes show significant differences in the same stratigraphic level, depending on the presence of different fluids — brine, gas, or a mixture of the two. Differences are associated with density and compressibility of fluid under the pressure and temperature conditions of the reservoir. After computing Poisson’s ratio and acoustic impedance from analyzed wells, it was observed that those values were lower at the gas-bearing sands than for the encasing rock. Based on that result, an acoustic-inversion exercise was performed over the existing seismic data to interpret lateral heterogeneities associated with gas saturation. However, the well-known effect of low gas saturation on seismic velocities introduces an appreciable uncertainty in interpretation. To overcome this issue, it is proposed to estimate densities from an elastic inversion of the seismic data and to interpret fluid distribution in the reservoirs at Dragon field using this attribute.
Shell
Nearly 115-year-old British energy giant Shell reported its highest annual profit ever—nearly $40 billion in 2022, after record announcements from American heavyweights Chevron and Exxon Mobil as the industry capitalizes on energy prices and market upheaval caused by Russia’s invasion of Ukraine.
Shell announces fourth quarter 2022 results
02 Feb 2023
Shell released its fourth quarter results and fourth quarter interim dividend announcement for 2022.
Chief Executive Officer, Wael Sawan, said:
‘Our results in Q4 and across the full year demonstrate the strength of Shell’s differentiated portfolio, as well as our capacity to deliver vital energy to our customers in a volatile world.
We believe that Shell is well positioned to be the trusted partner through the energy transition. As we continue to put our Powering Progress strategy into action, we will build on our core strengths, further simplify the organisation and focus on performance. We intend to remain disciplined while delivering compelling shareholder returns, as demonstrated by the 15% dividend increase and the $4 billion share buyback programme announced today.’
STRONG RESULTS, DISCIPLINED CAPITAL ALLOCATION
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- Strong performance in a continuing uncertain economic environment. Q4 2022 Adjusted Earnings of $9.8 billion, with Adjusted EBITDA of $20.6 billion, despite lower oil and gas prices compared with Q3 2022, with higher LNG trading and optimisation results.
- 15% dividend per share increase for the fourth quarter. $4 billion share buybacks announced, expected to be completed by Q1 2023 results announcement.
- 2022 full year shareholder distributions $26 billion. Total distributions in excess of 35% of CFFO for 2022.
- Strengthening the portfolio with the announced acquisition of Nature Energy (Denmark), a renewable natural gas producer, winning the wind tender for Hollandse Kust (west) VI as part of the Ecowende joint venture and further simplifying the portfolio with the merger of Shell Midstream Partners (USA).
- 2023 cash capex outlook: $23 – 27 billion.
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(1) Income/(loss) attributable to shareholders for Q4 2022 is $10.4 billion. Reconciliation of non-GAAP measures can be found in the unaudited results, available on www.shell.com/investors.
Source: Shell
Shell sets record as profits more than double to $40bn
Shell hit a new all-time earnings high after the supermajor more than doubled year-on-year profits.
Shell PLC (SHEL) Q4 2022 Earnings Call Transcript
Feb. 02, 2023
Q4: 2023-02-02 Earnings Summary
EPS of $2.60 beats by $0.29 | Revenue of $101.30B (18.79% Y/Y) beats by $59.98B
Shell PLC (NYSE:SHEL) Q4 2022 Earnings Conference Call February 2, 2023
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- Company Participants
- Wael Sawan – CEO & Director
- Sinead Gorman – CFO & Director
- Conference Call Participants
- Oswald Clint – Sanford C. Bernstein & Co.
- Biraj Borkhataria – RBC Capital Markets
- Christopher Kuplent – Bank of America Merrill Lynch
- Amy Wong – Crédit Suisse
- Irene Himona – Societe Generale
- Lucas Herrmann – BNP Paribas Exane
- Henri Patricot – UBS
- Peter Low – Redburn
- Alastair Syme – Citigroup
- Lydia Rainforth – Barclays Bank
- Giacomo Romeo – Jefferies
- Michele Vigna – Goldman Sachs Group
- Jason Gabelman – Cowen and Company
- Christyan Malek – JPMorgan Chase & Co.
- Paul Cheng – Scotiabank
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Operator
Welcome to Shell’s Fourth Quarter 2022 Financial Results Announcement. Shell’s CEO, Wael Sawan; and CFO, Sinead Gorman, will present the results, then host a Q&A session. [Operator Instructions]. We will now begin the presentation.
Wael Sawan
Hi. I’m Wael Sawan, and I’m pleased to present to you for the first time as Shell’s CEO. Today, alongside Sinead, we’ll be presenting Shell’s fourth quarter and full year results. I’d like to start by thanking Ben for his leadership over the last 9 years and for building the strong foundations that I now inherit. We have a world-class organization with exceptional people, a leading portfolio and the right strategy, all of which, I believe, position us very well for the future.
2022 was a year in which energy security was front and center. The world mobilized. We saw policy progress with Fit for 55 in Europe and the introduction of the Inflation Reduction Act in the U.S. This is evidence of moving from ambition into action. Despite this progress, the energy system still faces huge challenges, and it continues to need bold, decisive actions by companies, governments and society at large. The world requires a secure supply of affordable energy and, at the same time, needs this energy to be increasingly low carbon to make the transition to a net-zero emissions energy system.
In short, the world needs a balanced energy transition. Moving too fast by dismantling the current energy system before the new system is ready could worsen the situation. But moving too slowly could waste precious time and lose the momentum to build necessary solutions for low-carbon energy at scale. However, this transition will not be linear and will play out with different solutions needed at different times in different places across the world.
We at Shell will do our part. We will invest with discipline where we have differentiated capabilities. We aim to deliver the oil and gas that the world sorely needs today while also leveraging our unparalleled customer reach to develop the scalable and profitable low-carbon products that are urgently needed. Shell, under my leadership, will work to be the trusted partner of choice as the world’s energy systems transition for our customers, governments and investors. By doing so, we aim to deliver competitive returns and create significant shareholder value over the coming years.
Now let’s look at our Q4 and full year results and financial framework. And for that, let me hand over to Sinead.
Sinead Gorman
Thank you, Wael. By continuing to provide the energy our customers need, we have again produced strong results. Our safety performance was impressive. We made good progress in both personal and process safety year-on-year. We also made good progress on carbon. By the end of 2022, we were more than halfway towards achieving our target reduction of 50% by 2030 for Scope 1 and 2 emissions.
Moving to our financial performance. Our adjusted earnings for the fourth quarter were $9.8 billion, with strong contributions from our Integrated Gas business, and we generated $22.4 billion of cash flow from operations, including a positive inflow of $10.4 billion of working capital.
These strong quarterly results helped us to achieve our highest ever full year results, with adjusted earnings of some $40 billion, more than double those of last year and around $17 billion higher than in 2014 when Brent prices were similar. We delivered a full year cash flow from operations of over $68 billion. And our organic free cash flow was around $48 billion.
In 2022, our financials were impacted by additional taxes of around $2.3 billion. Of this, around $1.5 billion related to the EU solidarity contributions in the Netherlands, Germany and Italy, with cash outflows expected in 2023 and 2024. For the U.K. Energy Profits Levy, they impact us some $900 million.
And now on to our financial framework. Our strong performance over the year has allowed us to enhance our distributions to shareholders. Our total shareholder distributions for the year were around $26 billion in excess of 35% of our 2022 cash flow from operations. And today, we have announced a new $4 billion share buyback program, which we expect to complete on time of our Q1 results announcement. As planned, we have also increased our dividend per share by 15% in the fourth quarter.
Demonstrating discipline, our total cash capital expenditure for 2022 was $25 billion. And our outlook for 2023 is to maintain the $23 billion to $27 billion range, absorbing inflation. Our AA credit metrics ambition remains. We intend to continue to reduce our net debt as part of our robust financial framework. Finally, we will continue to target shareholder distributions of at least 20% to 30% of our cash flow from operations.
And now I’ll hand back to Wael.
Wael Sawan
As you’ve heard, our results for 2022 were strong in what was a volatile external environment. So what do we expect to see for 2023? The balance between global energy supply and demand remains extremely tight. Small changes on either side can have a significant impact. So volatility and uncertainty will continue to be the watch words in 2023. And how will Shell respond to that? With confidence in the direction of our strategy and the strength of our businesses and with discipline and a focus on value. We’ve worked hard over the years to strengthen our portfolio. We have a clear strategy empowering progress. Our focus now is to further operationalize and profitably deliver this strategy. We will build from our strengths, where we will prioritize value over volume while reducing carbon emissions.
In Upstream, we will continue to proudly deliver energy that the world needs while driving strong results with our high-graded portfolio. In Integrated Gas, we will leverage and extend our world-leading LNG position. And in Marketing, we will build on the robust performance that we have seen in recent years.
Performance will be top of mind. In every area of show, we aim to demonstrate progress at pace, not through words but through results, and we will continue to simplify our organization. One example of this is the more aligned and focused senior leadership structure that we announced earlier this week, with fewer rules and greater accountabilities, simplifying decision-making. By building on our strengths, focusing on performance and simplification, we intend to deliver compelling shareholder returns. Shell is already a great company, and we are determined to be a great investment. And to give you more insights on how we plan to do this, join us in New York for our Capital Markets Day in June. Thank you.
Question-and-Answer Session
Operator
A – Wael Sawan
Thank you for joining us today. We hope that after watching the presentation, you’ve seen how we delivered strong results and how we intend to further operationalize our Powering Progress strategy. Today, Sinead and I will be answering your questions. And now please, could we have just 1 or 2 questions each, so everyone has the opportunity. And with that, could we have the first one, please, Dan?
Operator
The first question is from Oswald Clint at Bernstein.
Oswald Clint
Thank you very much, and good afternoon to both of you, and welcome, Wael, to the Q&A interrogation. First one on capital investment, please. Spend levels looking into the year in line with your guidance. That’s good. I think Sinead mentioned the guide is also absorbing inflation. So I was curious just how much and where you’re experiencing those hot spots at the moment. It doesn’t imply any activity has to be phased or pushed back. And I see within CapEx, Marketing steps up a bit this year. I assume that’s Nature Energy. But I’m just looking at Marketing, wondering that the earnings there are still a little bit below trend. And does Asia reopening here really start to help the earnings trend within that Marketing business? That was the first question.
Secondly, I’d love to ask about Integrated Gas. Wael, you mentioned volatility, uncertainty, your watch words for this year. We obviously had one hiccup last year around this business around hedging. So curious to know what the lessons learned were from 2022 and what’s the hedging strategy for this year, if there’s any changes needed in that approach.
Wael Sawan
Super. Oswald, thank you for that, and I appreciate being here for the interrogation. I guess I’ll get used to it. Let me start by maybe giving you, Sinead, the floor on the Marketing question and maybe also the Integrated Gas learnings. I can reflect a bit on inflation in a moment.
Sinead Gorman
Certainly. So indeed, thank you for that, Oswald. So in terms of Marketing, so taking a step back for the moment. So 46 sites and regional sites, #1 in lubes, if anyone can make substantial returns out of this, it is us. We are well positioned for it. In saying that, I agree. $400 million of earnings for this quarter was a little bit disappointing. But if you take a step back and look at why.
So what we’re very comfortable with is seeing the fact that COVID has really not completely played out. So we’re still seeing the impact of that. And you’re right, you point out China as well. So we have great expectations with China opening up to be able to see that advance, and we’ve got green shoots already. And particularly in our lubes business, of course, we have a bit of a parachute effect. The normal where the high cost of the inputs, it takes a while for that to be passed through as well. So those combinations, including with our differentiated offerings, we’re pretty confident in terms of how you will start to see some of our marketing results begin to improve.
The second one was in relation to IG and the volatility around it. I’m just going to take a bit of an opportunity also to take that stuff back. We talked before about the fact that for IG, you really need — or Integrated Gas, you need to look at it over a series of quarters, not one specific quarter. We use price risk management. Our hedging is price risk management, and we use it to look at the exposures we have across the period, not specifically quarter by quarter by quarter. Of course, that does mean that you see different things play out.
You do see correlations becoming more or less effective. This quarter, you saw them being very effective because we didn’t see those dislocations between the EU and, in fact, JKM, et cetera. But those breakdowns are typically temporary, and that’s what you saw as it came through. So this quarter, hedging acting very much as intended, and that’s what we like.
Wael Sawan
Thanks for that, Sinead. And Oswald to your first question, just to play back. So the $23 billion to $27 billion includes a few things. One, we have said is it will include Nature Energy, which you know is to the tune of around $2 billion. Secondly, we’ve also said it includes general inorganics. So that’s also within that number. And then thirdly, indeed, there is inflationary pressure that we’re absorbing. The inflationary pressure we’re seeing at the moment is in the range of, say, 10% to 12%, typically. Of that, we’re being able to mitigate a decent portion of that but not all of it. Most of the mitigations come from long-term contracts with suppliers where we have these enterprise framework agreements that we can lean on because of the scale of our purchases with those suppliers. So that allows us to mitigate some of the exposure.
You talked about delaying projects and the like. There are examples of that, of course. We took the decision on Gato do Mato, which is our Brazilian offshore opportunity, to recycle that project because of the cost estimates that came in were higher than we were comfortable taking a final investment decision on. And so with a disciplined focus on our capital allocation, we said this is not the right time to do it. And therefore, we punt it until there is a better environment to be able to invest in. So hopefully, that just gives you a bit of a flavor of how our thinking has gone with that.
Oswald, thanks for the question.
Operator
The second question is from Biraj Borkhataria at RBC Capital Markets.
Biraj Borkhataria
I’ve got 2, please. The first one is a few days ago, there were some headlines around you looking to review your U.K. electricity business. I was just wondering, I know this is not a huge part of the portfolio, but is this part of a broader review of your low-carbon efforts? Or is it specific to this business? Because I guess if I look from the outside in, this is a fairly low-margin business that actually has needed quite a lot of capital given all the volatility in power prices. So just wanted to get a sense of what has triggered that review there.
And the second question is in the Upstream. So in 2020, 2021, you put out your emissions targets and all the targets related to the energy transition. And one of those was declining oil production, 1% to 2% per annum. If I look at the last 2 years, it’s down something like 10% to 12%. So clearly, you’ve moved a lot faster on some divestments and so on, and that’s been a part of that. So given you’re well ahead of where you intended to be on that front, what does this mean for Upstream volumes going forward? Should we expect more stable production now or even growth? Because I guess the realities of the energy market are very different to when you put those targets out there as well. So just some thoughts on that.
Wael Sawan
Super. Thank you for that, Biraj. I’ll take both of those and start off with the SERL one, so Shell Energy Retail. The broad — the review of SERL is specific to SERL. It’s not a broader review of low-carbon investments. Ultimately, we are looking at every single one of our investments in its own right and trying to understand whether we can totally unlock the value out of that investment opportunity.
For Shell Energy Retail, what we have found is despite a few years of trying to make that work as part of an integrated value chain, the market conditions are just structurally not there for us to be able to create the returns we expect. We have seen significant interventions from the government, including price caps, including windfall taxes. We have seen nationalization in that sector. And so it is not a structurally advantaged sector for us to play in here in the U.K.
It also meant we had to review our German and Dutch positions because they run off a lot of common infrastructure. It wouldn’t make sense to look at just one of them in isolation. That’s what triggers the review and our ability to be able to understand how we can — or what position we need to take going forward, and that will take a few months.
Our broader low-carbon opportunities will, again, like everything else, also in our Upstream, be assessed on their own merits. Opportunities that we can see running room in, we’re going to continue to scale up and invest in and grow. And we’ve seen some of these opportunities, and we can talk about that as well in the coming hour.
On the — on where we are with Upstream. Having had the privilege of being with Sinead in the Upstream business at the time when we set these targets, we have indeed moved very fast on being able to monetize the parts of the portfolio that we felt did not fit into the broader core of what we wanted in the Upstream. And just as a reminder, we’ve done a lot of work in the Upstream over the past several years to fundamentally high grade the quality of that asset base. I referenced earlier in the morning, the fact that in 2014, at the similar Brent price, we were delivering — we had in 2022, 7% less production than we had in 2014, yet we’re able to deliver some 80-plus percent free cash flow and 70-plus percent earnings. And therefore, the quality of the Upstream has significantly improved as a result of this focus on value over volume.
As we look into the future, longevity of Upstream and our Upstream resource is a key focus area for me and for Sinead. That’s going to be something we focus on. More on exactly how that looks, I think, is better discussed in our Capital Markets Day in June 2023. But longevity is a core part of our focus.
Thank you for that — for those two questions, Biraj.
Operator
The next question is from Christopher Kuplent at Bank of America Global Research.
Christopher Kuplent
Wael, let me take your last comment and ask you a very mean question. What else did you feel like you can’t tell us today that you’re going to focus on in June? So apologies already for that question. But maybe I might want to make a suggestion to review that payout ratio. How do you feel about the formal 20% to 30%? As you’ve highlighted, you’ve gone well beyond that. It seems a little outdated. So hopefully, we can look forward to an update on that front as well as the longevity point that you just made. So any other thoughts in terms of what keeps you busy as you prepare for June would be great. And I’m not asking for a full preview of that event.
And then a quick one, hopefully, for Sinead. Just wondering whether you can give us a little bit of detail in terms of what you expect into Q1, Q2 when it comes to both the net working capital potentially a bit reversing as well as those derivative margining costs that went the other way in Q4.
Wael Sawan
Thanks, Chris. I’m going to ask Sinead, if you want to cover Q1, Q2 and maybe also the point around distributions. The — and then I’ll come back and cover any other items on June.
Sinead Gorman
Super. Indeed. No. Thanks, Christopher. And specifically on working capital. So in terms of the working capital, we’ve had comments in the past about the fact that our working capital has been an outflow. And as you saw this quarter, it was a substantial inflow of over $10 billion as well. Volatility comes with working capital. Our working capital comes from volatility is probably a better way of putting it. And we are in a great position where we have the financial framework that allows us to take this and have the capability to make money from us, of course.
So as we play through that, what are we expecting to see? In terms of the working capital that occurred this quarter, there were a number of things. It was price that came down obviously impacted. We saw a change less outflows with respect to margin, which you referred to as well, and that was to active management. We really looked at what are the right returns we need for that side of things and for the margining. And the third one is some one-offs. So in those one-offs, we saw quite a few people actually prepaying us towards year-end, so their own form of active cash management. And we also saw, of course, some cash deposits from some of our joint ventures who have to pay tax in January rather than in December. So just a change in terms of how taxes are playing out for them.
As such, specifically to your question, how much do I expect to see? I’m probably seeing $4 billion to $5 billion of that number that came in, I would expect to see flow out. Now of course, that’s just simply about things that will reverse in Q1. How working capital will play out will depend on, as you well know, the pricing and the different deals that we do during that quarter. So I won’t speculate more than that. I would say that our margin, we’re very active in looking at, and we’re ensuring we have an appropriate return for it.
You also asked about the payout ratio, which I think you said was outdated. With respect to the payout ratio, as you know, we’ve been quite clear on this and the fact that we have 20% to 30% range of CFFO. And taking a step back from that as well, 20% to 30%, well, as you can see, when market conditions and economic conditions allow for it, we go beyond that. So you can see in the course of the year, we actually got to 35%. That’s not about being outdated. That’s about an effect of us having 20% to 30% through the cycle, and that’s why we are very, very clear on the fact that it is a soft ceiling and a hard floor if that helps.
Wael Sawan
Thanks for that, Sinead. Let me touch on the broader question of what to expect in June. I think Chris, it’s worthwhile to sort of restate here that I continue to believe that our Powering Progress strategy is the right strategy for us and that the focus that at least I’m really keen to bring is how we’re going to operationalize that strategy.
When we start from an incredibly privileged position; when you have something as strong as your current core Upstream business that is delivering significant value, higher margins, strong, strong performance overall; when you have this world-leading Integrated Gas business, of which we’ve been able to significant strength as well in 2022 with the many announcements we’ve made; and when you have the customer interface that we have with a very strong Marketing business, we start from a very strong position. And we recognize that as we move forward, we can continue to grow and strengthen that position while continuing to decarbonize our own assets and help our customers decarbonize their energy.
So that core is very, very strong. But there’s 2 pieces that I have said, and I’ll continue to reiterate. Our focus is going to be on performance and discipline. Performance is going to be very much about how do we continue to drive operational excellence in our business? How do we focus on making sure that we are getting the consistency and the predictability in our overall results? And so that has all sorts of elements around how we think about working capital and the like. But also how do we continue to be lean and fit in what is an inflationary environment? So those are all elements of the performance.
And why do we focus on performance? Because I think there’s a lot more running room in the company. I know we’ve left money on the table in my previous business in Integrated Gas this year, so we can do better. And that’s the aim. We want to really drive that performance.
And ultimately, to your question around distributions, if we can drive the performance to its full potential, we will have sufficient cash to be able to distribute even more to our shareholders. And that’s very much a core part of our focus. And when it comes to discipline, it’s about making sure we continue to be ruthless in our allocation of capital towards the value-enhancing opportunities we see there.
And so you’ll hear a lot more of that. I’ve given you a bit of a preview, and you’ll get a bit more of the details as we work them out over the coming few months. Chris, thank you for that question.
Operator
The next question is from Lydia Rainforth at Barclays.
Lydia Rainforth
Two questions, if I could. Firstly, Wael, on the exec committee changes, you’ve talked about making the business simpler and that pure interfaces mean greater cooperation, discipline and faith. What in practice are you changing about that capital allocation process? And what leaves it to be better effectively?
And then just picking up on what you’re thinking about the operational performance and particularly in Integrated Gas, it does look like that’s been disappointing certainly relative to history. What can actually be done to improve that performance? And I’m not asking you to give too much, but just in terms of any kind of gap that you think is really there that we need to look at.
Wael Sawan
Yes, sure. I think on the first one, on the executive committee changes, I just mentioned to Chris’ question there, Lydia, the fact that performance and discipline were key going forward. And those were the 2 that also played in the decisions around the executive committee changes. And let me elaborate on that. And through that, maybe pick up on the operational performance question as well.
The structure we are creating is one where we’re trying to minimize interfaces to be able to really allow the front line to deliver the value that’s needed with clear line of sight that the business directors have. In this case, our Upstream, Integrated Gas director as well as our Downstream and RES directors to have clear line of sight towards those business outcomes while the integration of our strategy as well as finance as well as M&A into one shop that will report into Sinead is meant to be able to allow us to ensure that strategy, capital allocation, the monitoring of performance to make sure that our capital is being allocated to where we see sustained strong performance, that loop has been sort of cut across 3 different parts of the organization comes together now. And so when we talk about discipline, it’s our ability to be able to look life cycle at the choices we make in the way we allocate capital and continue to improve the way we do that in an objective way, unemotional way, rather than leaving it to each business to sort of try to pitch for their own capital.
So that’s really a core part of it. In that strand, when you talk — when we talk about operational performance and coming to the Integrated Gas assets, I want to maybe correct a bit of an impression because there’s 2 things that we’re working on hard in Integrated Gas. There’s one element around feedstock in certain areas like Nigeria and Trinidad that has nothing to do with performance. The assets are doing very, very, very well. The problem is it’s really challenging in Nigeria, given sabotage of the pipelines and the like to be able to get sufficient gas into the system. If we can overcome some of those challenges, the machine runs well.
In Trinidad, it’s simply a lack of gas supply. And you’ve heard recently that the U.S. government has — OFAC has allowed now Trinidadian government and Shell to consider bringing gas from the Dragon field in Venezuela. So those are the sorts of solutions for that part of the problem.
The other challenge we’ve had is, in particular, Prelude has been a challenge, and that’s one that we are very focused on right now with the team, and the leadership in Australia is really looking forensically at what are the things that would potentially mitigate further challenges.
And that’s what I would say at the stage, Lydia, around where our focus has been. Thank you for the question.
Operator
The next question is from Michele Vigna from Goldman Sachs.
Michele Vigna
Really, congratulations for the excellent delivery in the quarter. I wanted to ask 2 questions. The first one is about the EU green taxonomy. It’s going to be one of the biggest new regulations from an ESG perspective in Europe. It’s far from perfect, but it still offers an interesting insight in change towards a greener company with especially the percentage of green CapEx. And I was wondering if you had an initial assessment of what percentage of your CapEx would be green taxonomy-aligned.
My second question relates to the gas market. You are one of the largest players worldwide. It seems to me like the market is getting a little bit too relaxed about the risks in the second half of the year. The price incentive is moving away from substitution. Gas-intensive industries are restarting in the EU. And I wonder if we run into a risk of potentially having another crisis this winter and how you think you can position yourself to be best positioned to benefit from that.
Wael Sawan
Thank you for those, Michele. Do you want to start off, Sinead, with EU green taxonomy?
Sinead Gorman
Indeed. So indeed, Michele, it’s a really interesting one, the EU green taxonomy because, as you know, it will play out and be delivered across just a different period of time. Whether you’re in the EU, whether you’re part of the U.K., the timing of that will change. What you can do is actually, if you look back at our annual report from last year, you can see where we actually showed a breakdown of how the taxonomy works. And actually, the spend that we would say fits very well, and we sort of described our points of why we didn’t feel the taxonomy was actually properly worded, et cetera. So that taxonomy is playing out. As you know, definitions are being challenged at the moment, and a variety of that will happen.
So I would say, look back at our one from last year. So from 2021, and you’ll get a very good indication of that. What I would say as well, of course, is that we want consistency. That’s the main thing. We have so many different regulations and rules that are coming, whether it’s from the U.S., whether it’s from the EU, whether it’s coming from the U.K., or a benefit to all of us is to have standardization, transparency where we all use the same definitions. And we’re very keen to do that as an industry.
Of course, what we’ve said before, and I described it this morning several times as well, was the fact that if you were to look at our CapEx and our OpEx together, we would say that 1/3 of that approximately at the moment is spent on low-carbon or zero-carbon investments or expenditure as well.
Wael Sawan
Thanks for that, Sinead. Michele, to your question around gas markets. When asked this morning in both CNBC and Bloomberg, my answer was the same that we are not out of the energy crisis in Europe. Far from, I think. And I would agree with your point that there seems to be some who feel that it’s all back to normal. This is, I think, a multiyear energy crisis, and we want to have to collectively figure out how we address that.
Why do I say that? I think just looking at some of the facts. So last year, what happened with Russia was roughly 2.5% of global gas demand was taken out because of the reduction in gas supplies from Russia into Europe. That caused havoc in the markets, as you know well.
What supported or what bridged the gap, of course, LNG played an important role. Mild weather played an important draw, and critically, demand destruction also played an important role. Let’s take the first one. There isn’t a huge amount of LNG coming into the market over the next 2 years. It’s around 20 million tonnes is what we see, but that’s about it. And that one shouldn’t also forget that many of these machines have been running hard now for a good year. And you’re beginning to see some of the challenges in just the reliability of the machines around the world. So that’s an issue.
The second issue, of course, is that China was the one that diverted roughly 50% of its LNG to come here to Europe or 50% of Europe’s needs was met with diverted LNG cargoes from China. That might change or is likely to change given where things are going with the recovery — the economic recovery in China.
So you look at that, you don’t want to be in a position to be depending on the weather as your savior or the fact that you’re going to destroy more demand. And so I do think this is a multiyear issue. We’ve been very vocal with governments here in Europe that we’re going to have to move faster. What the Shell do as a result of this, of course, our portfolio has typically been positioned for Northern Hemisphere winters. That’s where we typically have our . We, of course, work on significant support in storage this year — or last year, sorry, we invested in storage in Germany and in Austria, which was part of where we used our working capital, for example. We’re investing in projects right now. We have Pierce depressurization that’s coming on stream in Penguins in the U.K.
So we have a lot of opportunities to be able to supply the market and, of course, create value through the tremendous portfolio that we have in LNG. Thank you for the question, Michele.
Operator
The next question is from Christyan Malek at JPMorgan.
Christyan Malek
Congratulations on the results. So 2 questions from me. Just first, sort of slightly different topic but some related on the industrial and financial logic of renewables at this stage with energy transition. One of your peers sort of appears to be dialing back in renewables and into the returns proposition or the evolving returns. Can you share more views on the case to scale clean energy at this point, be it M&A or organic and so the time lines around how you think about the transition in the context of clean energy?
My second question is regarding the oil outlook specifically. What does it take for you to grab the bull by the horns in oil investment and break out of the range you provided? As it still seems somewhat in contrast, the U.S. majors who are leaning into low-growth . Yes, you framed the mood as more volatile and uncertain, and you’re talking about energy crisis again on the other hand. So I’m just trying to understand what are the key milestones we’re looking to see for you to step in on particularly the crude side.
Wael Sawan
Super. Thank you, Christyan, for those 2 questions. Sinead, do you want to start with the industrial and financial logic of how we’re thinking about renewables?
Sinead Gorman
Yes, indeed. I’ll keep it simple, Christyan. It sounds like you’re in an airport without a doubt. But what I am seeing on that is the logic is very simple for us. We look first at whether any of the investments that come to us are fitting our strategic way forward. And then we’re looking at very much how does it fit in terms of the returns profile. And we probably had this conversation before on that. Each investment has to fit both aspects of it. And on the return side, what we’re seeing, of course, is that we have many different projects that are open to us. So we’re not short of investment opportunities. It’s finding the right one where we can actually differentiate and we can get those specific returns. I’m very comfortable that we have the right strategy for that. So that’s where we’re going to.
But in terms of the — are we dialing back or any of that side of things, you can see from our capital investment, we have a very healthy budget within the side of things with respect to renewables, in respect to green. But it will depend, of course, on the returns that we see as those come through, and that will continue to be the case. At the moment, we’re seeing good opportunities, Nature Energy being a great one where, of course, it’s just a logic where it fits through. We’re good at molecules. We’re able to move those to different locations. And of course, having the sort of business that we have with a number of customers to be able to decarbonize them, it’s a very clear logic as well.
Wael Sawan
Thanks for that, Sinead. Let me take the oil bit, Christyan. I think first to step back, I think the strategy that we have is a very balanced strategy. I mean we’re playing the game for the short, medium and long term. So we’re looking at how do we create value for our shareholders today but also how do we create the value opportunities for 2040 when the energy system will be fundamentally different.
By the way, by 2040, I’m still convinced you’re going to need oil and you’re going to need gas and you’re going to need a lot more renewables. And so our strategy is one that’s saying, how do we play across these multiple energy forms but really focus on the opportunities that create the most value for us, a bit like what we’ve done in Upstream, where we have gone to the core of 8 countries and really doubled down. And you’re seeing the benefits of that through margin expansion and our ability to really focus on value drive.
Does that mean we will continue to look at that? Absolutely, you’ve heard me say earlier as well, we will continue to look at how do we have longevity in our oil business. But I would also say I love the fact that we have a world-leading Integrated Gas business that actually has a significant portion, north of 70% of our term contracts indexed to Brent. I want to continue to grow that part of the business because I can get exposure to a business that we are uniquely differentiated in that gives Brent exposure and, at the same time, where we are able to have much more resilience as we go through the energy transition because of the lower-carbon footprint of that business.
That is at the core of the strategy. And so we will continue to follow that. And we’ve built on that in 2022, the North Field expansion, North Field South, our ability to be able to pick up significant volumes from the U.S. through Venture Global, Mexico Pacific Limited. And so we’re really putting that strategy into action to be able to grow without necessarily saying it just has to be oil, but oil exposure is a good thing for us as a company, and that’s what we’re really looking. That exposure to Brent is going to be important.
Thank you for the question, Christyan. Safe travels wherever you’re going as well.
Operator
The next question is from Irene Himona at Societe Generale.
Irene Himona
My first question, if I can go back to the cash payout ratio, please. You point to 20% to 30% through the cycle and 35% at current prices. To be fair that 35% was clearly helped by the proceeds from the Permian disposal. My question is, can you give us a sense and indication of what for you is the Brent oil price which you would consider as average through the cycle and which would, therefore, correspond to the 20% to 30%?
And then the second question, just a numerical one on RES. Capital employed more than doubled basically between Q2 and the end of the year. I presume this was due to the spike in power prices possibly more working capital for trading. Is that correct? Or is there anything else behind the increase?
Wael Sawan
Thanks. Do you want to take both?
Sinead Gorman
Yes. I’ll take both. So on the RES one, Irene, very simply put, there’s a mixture in there. You’re completely right. The working capital part of it is to do with power. But a large part of it is to do with the build into storage. So we talked about earlier, Germany and Austria, also some storage in the U.K., of course, as well. So you saw — between Q2 and Q3, you saw that go up. You saw a little bit of that come down in terms of the storage side of things as well as it played out. So that’s part of what occurs there. That will play out as we release out of storage as well.
If I were to look at the first one as well that you asked around the payout ratio, fundamentally, it’s — if you said Permian, it’s still above 30% as well. So I do acknowledge, yes, the Permian is in there. But of course, that’s part of the capital allocation that we have. We make choices about which assets we are best kept — best suited to keep and which should go out of the portfolio as well. Of course, that has implications on the CFFO as well that plays through. But we were over 30% in either way that you look at it.
We tend to look at in terms of price because you were quite specific on the price. I’m not going to be drawn on what specific price it is. As you can imagine, we look at scenarios. We don’t look at one specific price or strip probably quite sensible as you can imagine, given how volatile we’ve seen in the last year as well. So we look at the different aspects of that. And that’s how we play out as we plan beyond just next quarter but through the cycle as we look to invest.
Wael Sawan
Thank you for that, Sinead. Irene, thank you for the question.
Operator
The next question is from Henri Patricot at UBS.
Henri Patricot
A couple of questions from me. The first one, a follow-up on renewables and the changes to the executive committee. Can you expand on the rationale for grouping renewables with the Downstream and whether this has any implications for the strategy for renewables?
And then secondly, on Chemicals with the start-up of Shell Polymers Monaca, not just making full contribution. How long do you expect for that asset to ramp up to get to full contribution to earnings? And should we expect to [indiscernible] improvement in the first quarter? Or does that take a bit longer?
Wael Sawan
You want to take the second question [indiscernible]?
Sinead Gorman
Sure. Absolutely. No, indeed. And thank you, Henri. Yes, Shell Polymers Monaca, really great to see it actually starting up and beginning to run through. It’s quite exciting when you’re actually there and just see it. In terms of the ramp-up, you can imagine with anything of this size, I’d love to say we’d get up and running within a couple of months. It doesn’t. It always takes approximately 12 months by the time you run up, you get certified on the quality of the products, et cetera. So that’s what we’re seeing. So you’ll start to see it play out in the results more and more. Of course, we’re getting all of the costs coming through now that we’re operating, but the true value of it will take approximately 12 months to play out, and then you’ll really see it hitting.
Wael Sawan
Thank you, Sinead. Then on the first question, Henri, on the RES-Downstream grouping. Dial back to 2017 when we started the renewables business, it was really nascent. We were looking at how do we think about power, how do we think about hydrogen, how do we think about CCS. And so that’s been evolving. And what you have seen, in particular in 2022, we made some big moves, right? So we made a fine investment decision on a green hydrogen project in Rotterdam, leveraging our requirements in Pernis while, at the same time, being able to leverage our leading commercial road transport business as a potential sync for that green hydrogen and leveraging, of course, also the very strong incentives from the European government. We’ve made moves in India and in the U.S. around Sprng and Savion, respectively. And we continue to look at those opportunities.
So we have a good base. The reality, of course, is we’ve always talked about a customer-backed strategy, and the majority of our customers have traditionally sat in our more conventional business in Downstream. And so there has been quite a bit of an interface between renewables and Downstream, what products should we be selling to our customer and the like. And so what this is doing is actually it’s strengthening our ability to access customers with green products that we are developing in our renewables business. It also harmonizes things because, currently, biofuels, for example, sits in Downstream, doesn’t sit in renewables. EV charging sits in Downstream, even though the power generation and power trading sits in renewables. So this is bringing cohesion, removing interfaces and duplication and allowing us to make sure that we can deliver for our customers the decarbonized products that they want. And then being agnostic as to what green electron or green molecule they want just trying to maximize value for the group from doing that. Thank you for the question, Henri.
Operator
The next question is from Lucas Herrmann at Exane.
Lucas Herrmann
A couple, if I might. Sinead, this is probably directed at you because it’s LNG and it’s first quarter. And look, we’ve had a year of considerable volatility. You’re a month into the quarter. Price has obviously been volatile. But can you give us any help in terms of how we should be thinking about the way that the current quarter is likely to shape up in LNG? Sorry, it’s so short term.
And perhaps staying with gas, if I go back to last quarter, gas storage, a lot have gone into gas storage. You indicated the benefits of that would be seen through the fourth quarter, maybe the first quarter. Where are we in that process? Has it all been released? Have the benefits been seen? Please, just commentary around both those items.
Wael Sawan
Go for it both.
Sinead Gorman
Thank you. Indeed. Thanks a lot, Lucas. Indeed, so you’re commenting, first of all, and let’s start with the LNG one, specifically. So in terms of the volatility and what we expect to see coming into this quarter. So strong pricing. Now if you go back to what happens, we’ve talked about supply, seasonality and, in effect, the dislocations.
So in terms of the supply, you typically see us being a bit longer in terms of Q4 and Q1. And we would expect to see that playing out as well. Hedging will work as intended. I have enough sense to not try and go anywhere on that because it will depend on where the markets will play out at the same time. But seasonality and the supply side, we hope and expect to work for us on that.
Of course, it also comes down to how much third-party volumes we can actually access as well. And that’s — as Wael already discussed, it’s going well. And of course, the performance of our equity production as well. It’s great to see Prelude up and running and performing well at the moment.
In terms of the gas and referring to, basically, we talked about — last quarter, I talked about how we had been injecting into storage as well. We’ve seen some being drawn out of that, particularly around Austria, so that has come out in this quarter, but we still have quite a bit in storage as well. Of course, it’s mild at the moment in terms of the winter warmer, if you want to put it that way. So that will have to play out as it goes through as well. I hope that helps.
Wael Sawan
Thanks, Sinead. Thanks for that, Lucas.
Operator
The next question is from Paul Cheng at Scotiabank.
Paul Cheng
Two questions, please. First, Wael, as the new CEO, first, congratulations. That how you look at Europe in the long term as a part of their long-term portfolio given the political environment for your legacy business, I mean, you’ve been reducing your Upstream exposure in Europe by half over the past 5 years. The Downstream still has a lot of operations there. So I mean how do you look at that?
And secondly, that if we look at in the past, both Shell and your peers sort of target or accept the wind and solar on an absolute return will be lower than your legacy business, like that you will target 8% to 10%. But is that acceptable going forward? And as a new CEO, when you look at it, will you be willing to accept just because there’s no carbon that we generate a much lower return than your legacy business?
Wael Sawan
Thank you very much. Thanks for that, Paul. And let me take both. So on Europe, you’re right. We don’t have a huge amount of Upstream left in Europe. We still have, of course, positions in the U.K. We still have positions in Norway and Italy. But the majority, in particular, when you think deepwater is in the U.S. and in Brazil. And then we have strong positions, of course, in Kazakhstan, in Oman, in Brunei, Malaysia and so on. So you’re right to point out that it has shrunk over time. And we still have, indeed, in particular, when you think about our Energy and Chemicals Parks, we have the Energy and Chemicals Parks in the Netherlands as well as the one in Germany.
It is fair to say that there’s a couple of considerations around Europe. We see Europe much more going forward as an energy transition play. We see a lot more in terms of the incentives that play into Europe. We see our ability to be able to leverage our German and Dutch position in a way as well as our marketing positions in Europe in aviation, in commercial road transport, in passenger transport. Those lend themselves very well to be able to play in the energy transition, and it is in line with where Europe wants to go.
So I see a strong part of our focus, and you see it. You see it with the investments we’re making, for example, with offshore wind in the Netherlands, green hydrogen in the Netherlands looking at opportunities to continue to decarbonize customers in Germany, in Italy and so on and so forth. So there is more of that while we continue to be committed to our oil and gas businesses in other parts of the world as well as whatever we still have here. But definitely, I think the disproportionate share of capital that’s going into Europe is an energy transition theme.
The important thing I keep trying to remind the government in Europe is that, that capital that really needs to be — or I need to be comfortable that we see investment stability in the climate in Europe. And I have to say 2022 did not reinforce that confidence. We have seen ad hoc interventions in windfall taxes, in price caps, in some areas, nationalization and the like. Of course, these are extreme conditions. I fully understand that. But any time you start to move from trying to manage risk to trying to manage price creates all sorts of concerns in a company like ours that’s investing for the long term. So I would just leave that out there as well.
I think on low carbon, let me be, I think, categorical in this. We will drive for strong returns in any business we go into. We cannot justify going for a low return. Our shareholders deserve to see us going after strong returns. If we cannot achieve the double-digit returns in a business, we need to question very hard whether we should continue in that business. Absolutely, we want to continue to go for lower and lower and lower carbon, but it has to be profitable.
And so I recognize there’s a different risk profile. Let’s be clear, Upstream hasn’t always been in the 20% returns. On a commodity — or on a commodity basis, you find that the risk typically plays between the 10% to 15%. We need to be able to see those sorts of returns on an integrated value chain basis in the renewables as well, and that’s what we’re focused on. And we have great examples of that. We’ll share a bit more of that in Capital Markets Day through getting in at the right time, through diluting, through creating more value all the way down the value chain, but it is important to say we will continue to focus on value and returns.
Operator
The next question is from Amy Wong at Credit Suisse.
Amy Wong
A couple of questions from me. The first one is looking at your operating expenses. It seems like it’s been creeping up across the group. So could we get a bit more color on what’s happening with underlying OpEx and whether management has plans to address that?
And then my second question is unrelated, but it’s related, and it’s more about your Upstream and Integrated Gas business, particularly your exploration strategy. It’s not an area we hear a lot about on your exploration there. I mean a couple of years ago, you told us that you had a commercial resource base of over 20 years of production. I’m just kind of rolling that number forward. Where do we sit there?
Wael Sawan
Amy, thank you. Do you want to take both of these?
Sinead Gorman
Sure. So on the OpEx or operating expenditure, Amy. So for this year, it has gone up, where it’s sort of some 39 billion. What we’re seeing there is, number one, there’s a bit of a Q4 effect, which is always there related to just some of the costs that tend to come through. But if I take a step back because, of course, it’s one that I watch very closely. When you look at it for the full year, what are we seeing for that increase? We’re seeing inflation hitting. It really is. We’re seeing that come through in just across the different cost bases. We’re also seeing, of course, our D&R or decommissioning and restoration. We’re spending more in that space as well. That’s good expenditure, but it’s also an element of inflation in there as well.
We’re also growing. So a number of those new investments that have come in, that OpEx for those new ones at the start is just more. We have to get on top of that, and it’s higher than we’re seeing in terms of the divestments that are coming through. So that’s flowing as well.
And then finally, just the same as everyone else, the utility costs, of course, have increased this year. We’re seeing it flow through our own results. Are we happy with it? No. Will it be an area of focus? Yes.
In terms of your second question, which was really around our exploration strategy, we have a great exploration team. And they’re still very much focused on various areas. You’re seeing some of the progress coming through in terms of Namibia and some other aspects as well. What you we’re talking about specifically, I’m going to take it back to sort of our reserves numbers there as well. So you’ll see our reserve replacement ratio, of course, at 120% for this year as well. But what I would look at there is we’ve often talked, of course, and you’ve heard us say many times about volume over value. But fundamentally, we want to see the longevity of our Upstream and IG businesses. These are fabulous businesses, and they’re generating great returns, and we’re very much focused on that.
The reserves numbers that we see coming through, those are very much around the requirements that you have, the SEC reporting, and we adhere very, very closely to that. Of course, it does mean that some of the things just don’t flow through in those numbers but are still producing and making us money. So very clearly, it is value over volume. Yes, so I hope that helps.
Wael Sawan
Thank you for that, Sinead. And thanks, Amy. Giacomo? Dan, I understand Giacomo is next.
Operator
Yes. The next question is from Giacomo Romeo at Jefferies.
Giacomo Romeo
Congratulations, Wael, for your excellent start of the new tenure here as CEO. Two questions left. First one is on Chemicals. We have seen a disappointing numbers and losses getting larger. Just wanted to understand whether there’s anything you can do there on the cost side to mitigate some of these effects and whether what you’re seeing in terms of the market right now if you start to see a little bit of an improvement.
The second question is on liquefaction. You give us a liquefaction guidance for the first quarter. And it looks just over the — what you reported for this — for Q4, and it’s — which was a quarter where you had quite a bit of hiccups. So I’m just wondering what shall we expect in terms of if this range you give for first quarter, it should be a reliable level of liquefaction that we can apply for the following quarters in 2023 or whether we could see an improvement there.
Wael Sawan
Thank you very much, Giacomo. Do you want to talk about liquefaction? I can touch on Chemicals.
Sinead Gorman
Sure. I’ll be very short on the liquefaction. We put it out quarter-to-quarter, of course, because it is the best estimate that we have at the time, Giacomo. So it’s a good estimate for where we are seeing for Q1. We obviously have a different phasing for turnarounds, et cetera. We don’t tend to bring — go out with those in advance. So you’ll see that play out over the year as it’s phased. But what you’re seeing is a very good estimate for Q1.
Wael Sawan
Thanks, Sinead. And Giacomo, with your question around Chemicals. I think there’s a couple of things that we’re looking at. Firstly, of course, we’re at the bottom of the cycle on Chemicals. So it’s painful where we are, but this is a cyclical sector, of course. The structural, there’s little we can do about at this stage. The performance we’re very focused on. So indeed, we’re looking at all opportunities to be able to pull levers that we can, whether that’s from a cost perspective or how do we enhance the top line. That’s what the team is focused on and continuing to drive hard at the moment.
In addition to that, we continue to play out the strategy that we have, which is shifting more and more away from commodity chemicals to intermediate and to performance chemicals. That’s an important part of it, and we have some good opportunities to continue to do that. Earlier, we talked about Shell Polymers Monaca. The whole point of continuing to certify these 40 grades is to continue to actually add value to the molecules we have and to the pellets we have and to be able to make sure that we maximize the return that we get from selling those. So all sorts of ideas being worked to ensure that we counter the cyclicality and are ready when we start to move back up the cycle to be able to maximize value for our shareholders from that.
Thank you, Giacomo, for the question.
Operator
The next question is from Peter Low at Redburn.
Peter Low
Just one and one more on Integrated Gas. Clearly, a very strong result. Is [indiscernible] say to help us try and quantify the contribution from trading and optimization. I guess what I’m trying to gauge to what extent this was an exceptional quarter versus being within the range of normal volatility you actually expect within that business. So yes, any color around that would be very helpful.
Wael Sawan
Okay. Thank you for that, as well, Peter. Do you want to say a word on that?
Sinead Gorman
Sure. I would say Q4 was a very strong trading quarter. It was exceptional in isolation, absolutely. But we tend to, as I’ve said before, really is good to look at it across the 12 months. So when you look at it across the 12 months, our Integrated Gas as an entirety to both the physical assets and the trading and optimization part have had a great year. It really is fabulous. And when you look at that, of course, trading and optimization has played a key role in that, but I wouldn’t look at it from quarter-to-quarter. As I said, it’s much, much better to look at it across the 12 months.
Operator
So the final question is from Jason Gabelman at Cowen.
Jason Gabelman
My phone actually cut out on the part of that question, so I may be asking the same question I was just asked, and if so, I apologize. I actually have 2. The first one is on Integrated Gas. And there’s clearly an elevated seasonality in the business, as you alluded to, that seems kind of underappreciated by the market. And I’m trying to understand how to quantify that. And I guess I’ll ask the question in this way. 4Q was very strong. If we had a similar environment in 2Q or 3Q, do you have any sense of how much different the earnings would have been? Can you give us an order of magnitude on that? And then my second question is on the…
Wael Sawan
Sorry, Jason, we lost you when you started to talk about the second question. Can you repeat the second one?
Jason Gabelman
Business model. The way it was kind of communicated was add a lot of options in optimizing those electrons [indiscernible] value chain, which I would have guessed included this retail energy business. If you decide to move away from retail energy in Europe and that removes one of the avenues to optimize those electrons, does that change how you think about the return profile potential of the renewable power business?
Wael Sawan
Thank you for that, Jason. I think I picked up the second one. Let me take a shot at both and build off what you said there, Sinead, on the first one. So Jason, I think the way to reflect on this and what Sinead had mentioned earlier is the importance of looking at this across 4 quarters. And what’s important is that we typically have a portfolio that is geared towards the Northern Hemisphere winter. So we try to go — to try to go longer in the Q4, Q1 months. And the way we do that typically is through supplementing our equity production with third-party volumes.
So the best way to look at some of the underlying performance is just look at the volumes we provide on a — over the last 2 years. And what you will see is quite some differences quarter-to-quarter in terms of that volume. Now I think what’s important to recognize is there’s different ways we create value in the Integrated Gas value chain. Of course, there is at the asset side, and you can see how much equity production we’re selling. We then create a significant amount of value at the T&O side. And then there’s a small piece that is also opportunistic as we play it.
My best advice is just look across the different quarters, look at the prices there, and you’ll get a good sense of it. This is not about us trying to not be transparent, but of course, as Sinead also said earlier, our hedging, the way we price manage our exposure is such that we look at it over an entire year and not simply quarter-by-quarter. We don’t manage it on a quarterly basis. And that’s why you can see sometimes the disruptions on a quarterly basis as you did in Q3. It doesn’t mean the fundamental business is not strong. It simply means that you have to look at it in a broader perspective.
On the — on our decision around Shell Energy Retail and the broader value chain, the strategy continues to hold, which is we believe we can create more value out of a green electron than simply selling a green electron through a PPA. We do that through a few ways. One is we have a balance sheet, and we have a trading organization that can take merchant risk — measured merchant risk, maybe 20%, 30%. And that allows us to be able to use that exposure to create incremental value beyond what a smaller operator can do.
We also have a huge B2B business that allows us to also cross-sell beyond the current molecules we’re selling those businesses. We could also provide them green electrons. And so that’s another avenue. A third avenue is indeed something like what we used to — want to do with Shell Energy Retail. That works in other markets. It works for us in Australia. It works for us in the U.S. at the moment. It is not working in the U.K., and that’s more to do with the structural nature of the market. So this is not a condemnation of B2C. It’s more a fundamental issue in the structure of the market that we are currently operating in, which has, therefore, necessitated this review that is still ongoing without any firm decisions taken at this stage.
Super. Jason, thank you for that. Dan, I think we’re done, aren’t we?
Operator
No. We do have one more question. We have a question from Alastair Syme at Citi.
Alastair Syme
Wael, can you talk a little bit about the Nature Energy acquisition, just the strategic rationale and any framework to help us think about the financials?
And then as a follow-up, I’m not sure I quite got the point you’re making on Upstream longevity. I guess the question is, do you think you can or want to grow your Upstream business? And I say that across the combined Upstream and IG [indiscernible].
Wael Sawan
Yes. Thanks for that, Alastair. Do you want to start maybe with Nature Energy? I’ll talk about the Upstream.
Sinead Gorman
Happy to. So indeed, thanks, Alastair. Glad we managed to fit it in. With respect to Nature Energy, so what do we see there? It was just a very logical strategic fit. When you look at the business that we have, so we have just such a huge customer base that is out there who have a strong need to decarbonize. And of course, you see that with both the convenience retail. You see that with aviation and stuff like that, but you also see beyond that. So what we’re seeing, of course, is that with Nature Energy when we bought it, it is both cash-accretive and earnings-accretive as well. So those 2 things play out as it goes through. It has a range of projects in the hopper, which are coming up to both FID, and the team has just set it up very well for growth. So we’re going to be able to take the amazing capability that they have in terms of actually generating these projects and be able to link it into the customers and create value in that sense.
Wael Sawan
Thanks, Sinead. Alastair, to the question around longevity. We will go after the most attractive projects that come our way. We don’t have a specific restriction where we’re not going to go into oil or into gas. Clearly, we think we have more gas opportunities at the moment because we’re able to add a lot of value. So yes, we are looking at growing our production in gas. And you can see it through our efforts on Integrated Gas, for example, what we did last year.
On oil, what we’re looking to do is to have just a much longer period of ability to be able to produce our oil profitably simply given where the world is. We continue to believe that oil has a role to play. A big part of what we announced a few years ago was how are we going to be able to move to actually prune the portfolio to high grade what we have as an Upstream business. I think we have done a lot of that, and therefore, what you see right now is a lot more strength and stability in that business, and I’d like to extend that strength and stability into the coming years.
Let me pause there, and thank you, Alastair, for the last question. And thank you all for your questions and for joining the call. Wishing you all a very pleasant end of the week and hope that you can join my team at our LNG outlook later this month as well as our annual ESG update in March. Thank you, everyone.
Shell Q4 Reflections
Feb. 02, 2023
Cavenagh Research
European IOC generated $39.9 billion of profits in 2022.
As exceptional Q4 2022 quarter highlights, European Oil Major Shell continues to make and distribute loads of cash. Supported by high energy prices, paired with robust demand, the IOCr generated $39.9 billion of profits in 2022.
On the backdrop of a demand tailwind coming from PRC, following the COVID reopening, as well as an improving economic environment in Europe, I expect oil prices to be elevated in 2023, and I expect Shell to write about $25 – $35 billion of profits.
I now calculate a fair implied share price of $101.47 (SHEL reference).
Thesis
As previously argued, Shell (NYSE:SHEL) delivered a blowout Q4, closing the year 2022 with a record performance. Supported by high energy prices, paired with robust demand, the European Oil Major generated $39.9 billion of profits in 2022 (as compared to a market capitalization of about $160 million).
On the backdrop of a demand tailwind coming from China, following the COVID reopening, as well as an improving economic environment in Europe, I expect oil prices to be elevated in 2023. Personally, I model the Brent benchmark to bounce within the range of $60 – $80. If this assumption would prove out correct, then Shell could likely write about $25 – $35 billion of profits in 2023. Reiterate ‘Buy’.
For reference, Shell stock is up approximately 11% for the past twelve months, as compared to a loss of about 10% for the S&P 500 (SPY)
Seeking Alpha
Shell’s Q4 Results Top Expectations
Shell closed the year 2022 with an exceptionally strong Q4 2022, beating analyst consensus estimates with regards to both revenue and EPS. During the period from September to end of December, Shell recorded total revenues of $101.3 billion, which compares to $85.3 billion for the same period one year earlier (a 18% YoY growth). For the FY 2022, revenues jumped to $381.3 billion, a 46% year over year expansion versus 2021.
On the backdrop of a strong topline, which was supported by rich energy prices, Shell’s profitability surged to the highest level ever (FY reference). For Q4 2022, the European Oil Major generated adjusted earnings of about $9.8 billion, which is almost $2 billion above analyst consensus estimates, which has pinned Q4 earnings at around $7.97 billion. For the FY 2022, the company’s bottom line ballooned to $39.9 billion.
Shell Q4 reporting
Shell’s exceptionally strong performance was mainly driven by two key drivers: Integrated Gas and Upstream. The company’s integrated gas adjusted earnings jumped to $16.1 billion, as compared to $9 billion in 2021; while the upstream business more than doubled, growing from $8 billion in 2021 to $17.3 billion in 2022.
Shell Q4 reporting
Going Into 2023 With Confidence
In 2022, Shell has distributed close to $26 billion to shareholders, in form of dividends and buybacks. Notably, as compared to a market cap of about $160 billion, Shell’s equity return for 2022 reflects a proud 15%. And in my opinion, there is little reason to expect that a similar result will not be achieved also in 2023.
Although it is true that demand for energy prices is cyclical, there is little reason to assume that the market for fossil fuel, and energy prices in general, won’t continue to grow–even if the growth is only in line with the global nominal GDP growth. In addition, Shell now also boasts a solid renewable energy business, positioning itself as one of the top producers globally–with about 139,000 EV charging station and 6.4 GW of renewable energy production capacity.
Shell Q4 reporting
In any case, demand problems should not be Shell’s major concern, not even on a cyclical level. Investors should consider that the energy market was already stretched in 2022, despite the year-long lockdown in China. Now, as China has ended COVID, (and Europe is arguably also somewhat recovering), I expect a strong demand tailwind in the first half of 2023. Personally, I model the Brent benchmark to bounce within the range of $60 – $80. If this assumption would prove out correct, then Shell could likely write about $25 – $35 billion of profits in 2023. Reflecting on Shell’s acceptable net debt position of $44.8 billion, Shell could likely easily afford to distribute another 15% payout in 2023 — assuming my model is correct.
Too Cheap To Ignore
In any case, Shell stock is trading too cheap to ignore. The European Oil Major is currently valued at a FWD EV/Sales of about x0.7 and an EV/Ebit of x4.23.
Seeking Alpha
Target Price: Raise To $93
Expecting a sharp economic rebound in China, I estimate that SHEL’s EPS in 2023 will likely fall somewhere between $9.3 to $9.5. Moreover, I also update my EPS expectations for 2024 and 2025, to $8.1 and 7.9, respectively.
I continue to anchor on a 0% terminal growth rate (one percentage point higher than estimated nominal global GDP growth), as well as on a 9% cost of equity.
Given the EPS upgrades as highlighted below, I now calculate a fair implied share price of $101.47 (SHEL reference).
Shel valuation
Author’s EPS Estimates and Calculation
Below is also the updated sensitivity table.
Shel valuation sensitivity table
Author’s EPS Estimates and Calculation
Risks
As I see it, there has been no major risk-updated since I have last covered SHEL stock. Thus, I would like to highlight what I have written before:
My thesis is connected to the implication that there are no structural differences between European and US oil majors. This, however, is not necessarily true since the respective regulatory exposure is somewhat different. Arguably, the European Union is slightly more aggressive with regards to the green energy push and US stocks generally trade at a premium. Nevertheless, a 100% relative valuation discrepancy is not justified, in my opinion.
In addition, investors should note that I assume a sustainable oil price of about $60/barrel. While this might seem bearish for some readers, others might argue that the fair value for oil is much lower. As the 2020 COVID-19 induced sell-off has shown, oil can even trade at negative price-levels. If oil would break considerably below $60/share and does not recover within a sensible time-period, the bull thesis for Shell would break.
In addition, I would also like to highlight that Shell might suffer from higher tax rates, as European governments are stepping up their ‘windfall tax’ ambitions. And Shell CEO Ben van Beurden signaled that his company would be ready to ’embrace’ higher tax rates:
We should be prepared and accept that also our industry will be looked at for raising taxes in order to fund the transfers to those who need it most in these very difficult times … We have to embrace it.
While the ‘incremental tax risk’ cannot yet be quantified, investors should monitor the situation closely.
Conclusion
As Shell’s exceptional Q4 2022 quarter highlights, the European Oil Major continues to make and distribute loads of cash. And comparing a $160 billion market cap to close to $40 billion of adjusted earnings in 2022, the SHEL’s equity value appears mispriced. Personally, I am confident to reiterate a ‘Buy’ rating for SHEL stock. And on the backdrop of a strong energy demand tailwind going into 2023, I now calculate a fair implied share price of $101.47 (SHEL reference).
Shell chief reject calls for probe into alleged greenwashing
Chief executive defends transition strategy and claims biofuels and CCS investments are reported outside low carbon division
3 February 2023
By Andrew Lee in London
Shell chief executive Wael Sawan hit back at claims that the oil giant has “greenwashed” its investment in renewables as he defended the supermajor’s energy transition strategy.
On the day that Shell announced a record annual profit, largely due to a boom in revenues for its integrated gas division, Sawan was questioned over a complaint lodged by Global Witness to the US Securities and Exchange Commission alleging that Shell is misleading investors over the make-up of its Renewables and Energy Solutions (RES) reporting segment.
The campaign group claimed that the company’s RES group is focusing most of its capital expenditure on gas.
Sawan said: “I would refute the claim that what we have represented in the RES segment is misleading. We’ve been very clear that gas and power are symbiotic, you can’t separate the two because there is significant overlap in the way we run the businesses.” Sawan, who took the top job at the start of the year, said “energy transition” investments account for more than one third of planned annual investments of between $23 billion and $27 billion this year.
He also claimed the energy transition activities span more than the RES segment, with biogas and EV charging, for example, sitting within its marketing area. “We’ve been very transparent how we account for that.”
By way of example, Sawan pointed out that the $2 billion that Shell committed for the acquisition of Nature Energy Biogas in 2022 was accounted to the marketing reporting segment, while carbon capture and storage tends to straddle the chemicals and products and the upstream segments of the company.
He was backed up by finance chief Sinead Gorman, who said Shell allocated more than $4 billion of capex to renewables last year, while citing transition-related spending in other areas of the business.
Returns on renewables?
The Shell executives were also pressed on the returns available from renewables, amid reports that oil and gas peers, such as BP, are looking at softening their plans in the sector amid concerns at the profitability gap between green power projects and hydrocarbons.
Sawan said it was “folly” to try to characterise renewables and oil and gas by straightforward numbers for returns on investment. He said Shell was focused on “risk-adjusted returns. There will be certain projects within the renewables space that are significantly lower risk than, for example, the development of a hydrocarbon resource, and they may have a moderately lower return. That is a part of a portfolio we might like to have.”
In other cases “supply chain pressures or lack of a fiscal environment” could make projects less attractive, Sawan said without elaborating further.
Sawan spoke to discuss record annual results that saw Shell post adjusted profits of $40 billion swelled by soaring oil and gas prices, adding to pressure in its UK home market over the contrast with hard-pressed consumers.
(A version of this article first appeared in Upstream’s renewables sister publication, Recharge, on 2 February, 2023)
Shell Q4 profit reaches $9.8 billion, LNG sales rise
By LNG Prime Staff
February 2, 2023
Shell’s Q4 profit reaches $9.8 billion, LNG sales rise
LNG giant Shell reported a jump in its adjusted earnings in the fourth quarter while its LNG sales also rose when compared to the same period in the year before.
The firm said its adjusted earnings reached $9.81 billion in the quarter, a surge compared to $6.39 billion in the year before. Adjusted earnings rose 4 percent compared to $9.45 billion in the prior quarter.
Income attributable to Shell shareholders was $10.4 billion, compared with $11.46 billion last year and $6.74 billion in the previous quarter.
Quarterly income attributable to Shell shareholders also included net gains of $4.2 billion due to the fair value accounting of commodity derivatives, partly offset by charges of $1.9 billion related to the EU solidarity contribution and the UK Energy Profits Levy, and impairment charges of $0.7 billion, Shell said.
Compared with the third quarter, the rise of 54 percent was mainly due to higher LNG trading and optimization results and favorable deferred tax movements, it said.
Cash flow from operating activities for the fourth quarter reached $22.4 billion, and included working capital inflows of $10.4 billion, and tax payments of $4.4 billion.
Full year adjusted earnings rose 107 percent to record $39.8 billion while income attributable to Shell shareholders increased 110 percent to $42.3 billion on the back of high prices.
“Our results in Q4 and across the full year demonstrate the strength of Shell’s differentiated portfolio, as well as our capacity to deliver vital energy to our customers in a volatile world,” Shell’s new CEO, Wael Sawan, said in the statement.
“We intend to remain disciplined while delivering compelling shareholder returns, as demonstrated by the 15 percent dividend increase and the $4 billion share buyback program announced today,” he said.
LNG sales rise, liquefaction volumes down
Shell sold 16.82 million tonnes of LNG in the October-December period, a rise when compared to 16.72 million tonnes in the same period last year. Sales rose by 7 percent compared to 15.66 million tonnes in the prior quarter.
Full year LNG sales increased by 3 percent to 65.98 million tonnes.
However, liquefaction volumes dropped by 4 percent year-on-year from to 29.68 million tonnes in 2022.
Quarterly liquefaction volumes reached 6.78 million tonnes, down compared to 7.24 million tonnes in the previous quarter and 7.94 million tonnes in the same quarter in 2021.
Shell said lower liquefaction volumes mainly reflect the derecognition of Sakhalin-related volumes and longer-than-expected maintenance at Prelude and operational issues at QGC in Australia.
The firm expects liquefaction volumes to be about 6.6-7.2 million tonnes in the first quarter.
Integrated gas earnings
Earlier this month, Shell said it was expecting “significantly higher” trading and optimization results for its integrated gas business in the fourth quarter of 2022 compared to the previous quarter.
The company’s integrated gas segment reported adjusted earnings of $5.96 billion in the fourth quarter, compared to $4.03 billion in the same period a year ago and $2.31 billion in the prior quarter.
Shell said the increase of $2.85 billion compared to the third quarter reflected the net effect of higher contributions from trading and optimization and realized prices.
Shell profits could ‘come at a cost’ in form of ‘further windfall taxes’
News of Shell (LON: SHEL) recording record annual profits could come back to bite the oil and gas giant, as well as its counterparts.
Shell: Strong Dividend Growth Continues
Feb. 02, 2023
Jonathan Weber
Summary
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- The macro-environment for energy companies is favorable.
- Shell is very profitable with oil in the $80s and generates massive cash flows.
- A 4% dividend yield, a low valuation, and rapid buybacks make for an attractive combination.
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UK Creates Energy Security Department
by Andreas Exarheas|Rigzone Staff| February 08, 2023
The Department for Energy Security and Net Zero is one of four new departments established by Rishi Sunak on Tuesday.
UK Prime Minister Rishi Sunak created a new Department for Energy Security and Net Zero, tasked with securing long-term energy supply, bringing down bills and halving inflation.
The innovation recognizes the” significant impact of rising prices on households as a result of war in Ukraine, and the need to secure more energy from domestic nuclear and renewable sources as we seize the opportunities of net zero..”
The Department for Energy Security and Net Zero is one of four new departments established by Sunak . The other three comprise
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- a dedicated Department for Science, Innovation and Technology;
- a combined Department for Business and Trade; and
- a re-focused Department for Culture, Media and Sport.
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Grant Shapps, appointed Secretary of State for the newly created Department of Energy Security and Net Zero, said he was “delighted to become the first Secretary of State for the new Department for Energy Security & Net Zero. My focus will be securing our long-term energy supply, bringing down bills and thereby helping to halve inflation.”
Shapps was previously Secretary of State for Business, Energy and Industrial Strategy (BEIS). The Department for Energy Security and Net Zero is focused on the energy portfolio from the former BEIS, according to a segment dedicated to the new department on the government’s website.
“The Department for Energy Security and Net Zero will provide dedicated leadership focused on delivering security of energy supply, ensuring properly functioning markets, greater energy efficiency and seizing the opportunities of net zero to lead the world in new green industries.
“This year, the department will focus on easing the cost of living and delivering financial security by bringing down energy bills and keeping them down – better insulating consumers from external impacts. Longer term objectives include ensuring properly functioning energy markets, coordinating net zero objectives across government and bringing external delivery expertise to bear on its portfolio of major projects.”
email andreas.exarheas@rigzone.com
[ ECO commends the pragmatic prioritisation of energy and science in the land of Faraday, Newton and Kelvin. Public funds can be diverted to subjects aligned with national, majority interests from deleterious ideology and politics to change the destructive decolonial zeitgeist. ]
OEUK highlights talent behind transition
World Oil Staff January 24, 2023
(WO) – Offshore Energies UK (OEUK), the leading trade body for the UK’s offshore energies industry, released a documentary on Jan. 24 that shines a light on the UK workers leading the charge to net zero energy supply.
Cuba
Melbana Energy to drill first appraisal well in Block 9, onshore
24 Jan 2023
Highlights
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- Independently assessed volumes of the Amistad structure in Block 9 (Melbana 30%) are 1.9 billion barrels of Oil in Place and 109 million barrels of Prospective Resource (unrisked gross best estimate).
- Mobilisation notices for drilling this first appraisal well in Block 9, designated Alameda-2, to be given in March 2023.
- Primary objective is to evaluate quality and performance of the productive oil zones in the Amistad (shallowest) reservoir encountered by Alameda-1 in the previous drilling program.
- Amistad structure exhibited strong oil shows over a gross interval of 1,426mMD (with updip potential), fluorescence in samples and elevated mud gas readings.
- Alameda-2 has a planned total depth of 1,960mMD (1,840mTVD). Its general objective is to allow oil to flow from the three productive units encountered previously in Amistad and to, specifically:
- evaluate the quality of the recovered oil;
- assess the production characteristics of these reservoirs;
- take cores to determine petrophysical properties; and
- increase reported net oil and gas pay from the current estimate of 48 metres by successfully logging all of the section, including~290 metres of gross pay excluded previously.
- Melbana Energy has provided an update on preparations for its first appraisal well in Block 9 PSC (Melbana 30%).
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Preparations for the drilling of the Alameda-2 well to appraise the Amistad reservoir are advanced. Mobilisation notices will be given to contractors in early March and drilling operations will commence following the removal of the Alameda-1 wellhead and plugging and abandonment of that well.
Target Formation
Alameda-1, the first of two exploration wells completed in Block 9 last year, targeted a large compressional structure compose of stacked sheets of limestone separated by thrust faults. Oil was encountered within three gross intervals identified as Amistad, Alameda and Marti structures (see Figure 1). The Alemada-2 well, the first of two appraisal wells planned for this year, will test the Amistad interval which has been subdivided into three units. Mapping of these units reveal that Alameda-1 intercepted them downdip at all levels, thereby suggesting there is considerable updip potential above the established oil-bearing zones with each unit extending over a large prospective area.
The top of the Amistad interval demonstrated strong oil shows over a gross interval of 1,426mMD commencing almost immediately below the surface casing shoe at 466mMD, entered about a week after drilling commenced. Numerous influxes of oil into the wellbore were recorded when flow checks were conducted whilst drilling this interval, in addition to fluorescence within samples and elevated mud gas readings in excess of 40%.
A significant (~290 metres) of this interval did not produce satisfactory logs due to poor hole conditions and therefore could not be factored into the estimates for the volume of oil that may be present. Some of this interval saw the strongest oil influx into the well bore experienced whilst drilling this interval.
Regardless, the interval that was satisfactorily logged allow for an estimate of 48 net metres of oil and gas pay across 11 zones totalling 415 metres of gross section. This was later independently assessed to contain 2.5 billion barrels of oil in place with a combined 88 million barrels of Prospective Resource (gross unrisked Best Estimate)(1).
The second appraisal well, Alameda-3, will be drilled later in the year and will test the deeper Alameda and Marti intervals.
Drilling Plan
Alameda-2 is to be drilled off the same drill pad as was used for Alameda-1. The design of Alameda-2 has been modified to incorporate the lessons learned from drilling Alameda-1. The slimmer hole design now being employed should maintain better hole integrity, thus improving the likelihood of being able to log the sections where this was not possible previously. If successful, it is hoped this additional potential oil pay might allow for an increase of the previous estimates for oil in place and Prospective Resource contained in this interval. Otherwise, the trajectory if Alameda-2 is the same as Alameda-1, other than modifying the deviation to allow Unit 3 to be penetrated in an updip structural position.
The appraisal will include conducting flow tests in order to better understand the properties of the reservoir as well as take samples to ascertain the quality of the oil encountered therein. To aid in calibrating petrophysical properties and reservoir description, which will be valuable when planning further appraisal and production activities, three fully cored sections are planned within the thicker net pay zones identified whilst drilling Alameda-1.
If successful, allowance has been made to keep Alameda-2 as a future oil producer.
Civil Works
The access roads, camp and pad as were used for drilling Alameda-1 are to be used for drilling Alameda-2. Their physical conditions remain good, but Melbana’s civil contractors have completed any necessary remediation works and the site is now ready to accept mobilisation. Moreover, they have improved the Alameda pad in accordance with Melbana’s instructions to deliver certain operational efficiencies considered desirable given the experiences gained from the previous two well drilling campaign. The pad has also been expanded to accommodate tanks for storing the oil expected to be produced from flow testing and the creation of additional access corridors for the tanker fleet to transport the stored oil without interrupting drilling operations.
Permitting
All material permits for the commencement of drilling operations have been secured.
Contractors
Alameda-2 is to be drilled by the same contractors that drilled Melbana’s first two exploration wells in Block 9. This was considered optimum, given the considerable operational experience that has been gained and the enhancements effected to the rig spread for the conditions encountered subsurface. Maintenance and re-certification work for contractors’ equipment has been completed satisfactorily.
Melbana has also expanded its project management team in Cuba to ensure additional experienced engineering expertise is available for the management of the upcoming program, building on the experience of the existing team that now has good operating history in country. Additional HSE resources have also been engaged to allow for greater oversight of operations, community engagement and further minimisation of any environmental impact our operations may have on the local community.
Office renovations have also recently been completed to accommodate these additional personnel in the project management office in Varadero.
Materials and Inventory
The valuable experienced gained drilling the first two exploration wells in Cuba has been factored into the planning for this year’s appraisal wells. Sufficient materials are in inventory in country for the drilling of Alameda-2 and inventory not already in stores is well advanced and expected to be delivered to Cuba in advance of the projected start of drilling operations.
(1) See ASX announcement dated 14 March 2022
Source: Melbana Energy
Colombia/Ecuador
Gran Tierra Energy announces strong reserves replacement
and continued reserves growth
25 Jan 2023
Highlights
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- Added Total Company Reserves of 14 MMBOE 1P, 17 MMBOE 2P and 31 MMBOE 3P
- Achieved 126% 1P, 148% 2P and 280% 3P Reserves Replacement
- Fourth Consecutive Year of 1P Reserves Growth
- Exploration Discoveries Alone Added Company Reserves of 5 MMBOE 1P, 16 MMBOE 2P and 32 MMBOE 3P
- Achieved Three-Year Average Per Barrel Finding and Development Costs of $11.69 PDP and $14.51 1P
- Reserve Life Indexes of 7 (1P), 11 (2P) and 15 (3P) Years
- Net Present Value Before Tax Discounted at 10 Percent Increased to $2.1 Billion (1P), $3.0 Billion (2P) and $4.1 Billion (3P)
- 1P Net Asset Value per Share of $4.62 Before Tax, Up 77% from 2021
- 2P Net Asset Value per Share of $7.36 Before Tax, Up 56% from 2021
- Net Debt-Adjusted Production per Share Growth of 67% since 2021
- Net Debt-Adjusted Reserves per Share Growth of 56% (1P), 57% (2P) and 69% (3P) since 2021
- Future Net Revenue After Taxes and Capital Expenditures Forecast to be $1.4 Billion (1P), $1.7 Billion (2P) and $1.9 Billion (3P) Over the Next Five Years
- Strong Start to 2023 with Year-to-Date Total Company Average Production of Approximately 33,000 BOPD
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Gran Tierra Energy, focused on international oil exploration and production with assets currently in Colombia and Ecuador, announced 2022 year-end reserves as evaluated by independent qualified reserves evaluator McDaniel & Associates Consultants in a report with an effective date of December 31, 2022.
Gary Guidry, President and Chief Executive Officer , commented:
‘During 2022, Gran Tierra achieved strong 126% (1P), 148% (2P) and 280% (3P) reserves replacement through our successful results from our development and exploration drilling, waterflooding programs and field performance. We completed our 2022 development plan on-budget including waterflooding efforts and development drilling in the Acordionero, Costayaco and Moqueta oil fields. After reduced exploration activity during 2020 and 2021, the Company also made several key exploration discoveries during 2022. We believe our success on multiple fronts during 2022 demonstrates Gran Tierra’s ability to be a full-cycle oil and gas exploration, development and production company focused on value creation for all our stakeholders.
The success the Company achieved in 2022 also reflects our ongoing conversion of reserves from the Probable to the Proved category. With 115 booked Proved plus Probable Undeveloped future drilling locations, Gran Tierra is well positioned to continue to grow the Company’s production in 2023 and beyond.
During 2022, a combination of our ongoing reductions in debt and per well drilling, completion and workover costs, focus on maintaining low operating costs, strong rebound in oil prices and share buybacks allowed Gran Tierra to achieve net asset values per share* before tax of $4.62 (1P), up 77% from 2021, and $7.36 (2P), up 56% from 2021. With this significant growth in our net asset values per share* in 2022, we believe Gran Tierra is well positioned to offer exceptional long-term stakeholder value.
We have started 2023 strong with year-to-date average production of approximately 33,000 bopd, which is the midpoint of our 2023 production guidance. We also recently drilled the Moqueta-25 development well, which we expect to bring on production in the new few weeks. We have secured two drilling rigs for our 2023 Acordionero and Costayaco development drilling programs and expect to spud development wells in both fields in early February 2023. We also plan to continue to focus on the development of our existing assets, appraisal of new discoveries and new exploration drilling, while generating free cash flow to strengthen our balance sheet and return capital to shareholders through share buybacks.‘
An updated Corporate Presentation is available on Gran Tierra’s website.
Source: Gran Tierra Energy
ATOME Energy in Central America/Caribbean
02 Feb 2023
ATOME Energy, the only pure international green hydrogen and ammonia production company on the London Stock Exchange with current large scale projects in Europe and South America as well as hydrogen mobility projects, announces a new joint venture developing green ammonia and fertiliser projects with the focus on Central America and the Caribbean.
ATOME has entered into a joint venture with Cavendish, the renewable energy arm of Grupo Purdy S.A., one of the largest corporations in Costa Rica. ATOME and Cavendish have established a new enterprise, National Ammonia Corporation S.A (‘NAC’), owned equally with Cavendish and headquartered in San Jose, the capital of Costa Rica, and which has a mandate to develop projects across Central America and the Caribbean with its initial focus in Costa Rica.
Costa Rica is a democratic country and open economy and one of the greenest countries in the world. The country has a 99% penetration of renewable electricity and a strong agriculture sector which is one of the highest fertiliser consumers per hectare on the planet.
Cavendish, led by its CEO Silvio Heimann, is one of the the leading participants in the infant green hydrogen market in Costa Rica with complimentary aims and objectives to ATOME. The objectives of NAC align with ATOME which is focused on countries with renewable power resources and capabilities combined with access to both domestic and international end markets. Costa Rica’s favourable position with ports on both the Atlantic and Pacific only separated by some 200kms of landbridge make the country a logistically excellent location.
Through NAC, ATOME aims to capitalise on its capability to roll out its large scale hydrogen and ammonia production model now being implemented in Paraguay. In this regard, material and constructive discussions are already taking place with relevant stakeholders in the areas of focus for NAC.
Olivier Mussat, CEO of ATOME, commented: ‘We are excited as to the potential of NAC. The establishment of NAC shows the clear intent of ATOME to deploy its innovative business model and know-how in other geographies.’
‘With the Villeta Project in Paraguay, we have taken a significant industry lead that we are able to roll out and replicate under the right conditions. Our partnership with Cavendish, a company established by the founders and owners of Grupo Purdy, offers ATOME a very attractive opportunity with a strong local partner to accelerate the development of a pipeline of international scale projects with strong local demand for green fertilisers.’
Silvio Heimann, CEO of Cavendish, commented: ‘We are energised to join efforts with ATOME to deliver innovative solutions to the domestic and regional markets, as this combination of international expertise provided by ATOME´s team fits perfectly well with our ability to execute locally.’
Javier Quiros, partner in Cavendish SA and VP Grupo Purdy S.A., commented: ‘Cavendish was established by the Quiros Family to boost the development of the green hydrogen technology in Costa Rica and the region. We see this partnership with ATOME through NAC as a valuable opportunity to bring our vision to life’.
Source: ATOME Energy
Tullow January trading statement and operational update
25 Jan 2023
Tullow Oil issued a statement in advance of the Group’s 2022 Full Year Results scheduled for 8 March 2023. The information contained herein has not been audited and may be subject to further review and amendment.
Rahul Dhir, Chief Executive Officer, Tullow Oil plc, commented today:
‘Strong operational delivery, rigorous focus on costs and capital discipline, the increased equity in our key operated fields in Ghana and higher oil prices drove material, expectation-beating free cash flow generation in 2022, accelerating the Group’s deleveraging towards a net debt to EBITDAX ratio of 1.3 times by the year-end. In 2023, we expect Jubilee production to exceed 100 kbopd once the new wells drilled in the southeast of the field are brought on stream. Our capital investment this year, in particular in Ghana, is expected to support production growth through to 2025 and material free cash flow generation.’
2022 REVIEW
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- Revenue of c.$1.7 billion (including hedge costs of c.$313 million) at an average realised oil price (post hedging) of $87/bbl.
- Underlying operating cash flow(1) of c.$1.0 billion and free cash flow(2) (FCF) of c.$267 million, ahead of guidance; based on the increased equity interest in Ghana ($126 million) and excluding the impact of the Norwegian arbitration payment ($76 million), free cash flow would have been c.$469 million in 2022.
- Year-end net debt reduced to c.$1.9 billion (2021: $2.1 billion), with expected cash gearing of net debt to EBITDAX of 1.3 times and liquidity headroom of c.$1.1 billion.
- Capital and decommissioning expenditure were c.$354 million and c.$72 million respectively.
- Group working interest production averaged 61.1 kboepd, in line with guidance following pre-emption of the Deep Water Tano component of the Kosmos
- Energy/Occidental Petroleum Ghana transaction.
- Strong operating, drilling and completion performance in Ghana, with facilities uptime of c.97% and four Jubilee wells and two Enyenra wells brought online.
- An Interim Gas Sales Agreement for 19 bcf of Jubilee gas was executed in December, representing the first commercialisation of Jubilee gas.
- A Letter of Intent was signed with the Ghana Forestry Commission in December for a nature-based carbon offset project. Final Investment Decision (FID) is expected in 2023.
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2023 OUTLOOK
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- Group working interest oil production guidance of 58 to 64 kbopd.
- Forecast capital expenditure of c.$400 million, of which c.$300 million in Ghana, and decommissioning spend of c.$90 million.
- Underlying operating cash flow(1) expected to be c.$900 million at $100/bbl (c.$800 million at $80/bbl) with free cash flow of c.$200 million at $100/bbl (c.$100 million at $80/bbl).
- Capital investment in 2023 in Ghana is expected to support production growth through to 2025 and free cash flow generation of $700-800 million(3) for the two years 2024 and 2025 at $80/bbl.
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(1) Cash flow from operating activities including lease payments, before capital investment, decommissioning expenditure and debt service.
(2) Free cash flow before debt amortisation and including a $75 million payment from TotalEnergies following Ugandan parliamentary approval of the Uganda Final Investment Decision (FID), a payment of $76 million to HiTec Vision in relation to the purchase of Spring Energy in 2013 and total consideration of $126 million for the pre-emption related to the sale of Occidental Petroleum’s interest in the Jubilee and TEN fields in Ghana to Kosmos Energy.
(3) Based on 2P reserves only.
Jubilee
Production from the Jubilee field averaged 83.6 kbopd (31.9 kbopd net) in 2022. A good operational efficiency of c.97% was achieved and production was supported by four new wells (one producer and three water injectors) brought online in early 2022.
Two wells were drilled in the Jubilee South East area in the second half of 2022 and a third well is currently being drilled. Primary target reservoir results are in line with expectations with some deeper reservoirs also penetrated that have encountered additional resources for future potential development. These wells will commence production in the second half of the year after the installation and tie-in to the Jubilee South East Project subsea infrastructure, scheduled for the middle of the year, in line with the initial project schedule. The completion of the Jubilee South East Project will mark the completion of the major infrastructure spend in the Jubilee area. The majority of future capex is expected to be focussed on drilling and completing new wells.
First oil from the Jubilee South East project will be a significant milestone, bringing previously undeveloped reserves to production. This project is being delivered on budget despite the inflationary environment and challenges associated with COVID-19 during 2020-22, highlighting Tullow’s project management strengths and ability to integrate deliverables across a global team.
The transition of operatorship to Tullow on the Jubilee FPSO took place in July 2022 and represented a major step in becoming a leading low-cost deep-water operator, realising improvements in safety, reliability and cost. Following the transition, FPSO uptime averaged c.99% in the second half of 2022, compared to c.95% in the first half. Operations and maintenance (O&M) costs were c.30% lower in the second half of the year compared to the first, and 2023 full year O&M costs are expected to be c.23% lower than in 2021, demonstrating the sustainability of the structural changes delivered through the transformation and helping mitigate the impact of inflation through the supply chain.
In December, an interim gas sales agreement for 19 bcf gross of Jubilee gas was executed, valued at $50c/mmbtu, utilising the price for TEN associated gas referenced in the 2017 TEN Gas Sales Agreement. The 19 bcf is expected to have been supplied by the middle of the year at an anticipated export rate in excess of 100 mmscfpd, adding c.7 kboepd net production during the first half of the year. Further gas export will be contingent on reaching agreement on acceptable commercial terms for future volumes.
In 2023, Jubilee oil production is expected to average c.95 kbopd (c.37 kbopd net), with a total of up to six new wells expected to come online, starting in the middle of the year. Gross oil production from the Jubilee field is expected to exceed 100 kbopd once all these wells have been brought online. The focus on operational excellence in production, drilling and major project delivery in recent years has yielded appreciable value and will continue to be an area of leverage for Tullow.
TEN
Production from the TEN fields averaged 23.6 kbopd (12.5 kbopd net) in 2022. A good operational efficiency of c.98% was achieved with overall production at the lower end of guidance.
Enyenra gross production averaged 6.8 kbopd for the full year, supported by a new production well (En21), which was brought online in September 2022 and will also contribute to production in 2023. Ntomme gross production averaged 16.8 kbopd for the full year. No new wells were brought online during the year but pressure support from gas and water injection resulted in steady production.
Two wells drilled in the Ntomme riser base area did not encounter economically developable resources and will not be completed in 2023 as originally intended, removing c.2.5 kbopd net from previously expected 2023 production.
The near-term focus on TEN is to sustain the strong operational uptime and improve gas handling on the FPSO this year. This will be implemented during a planned maintenance shutdown, scheduled for the third quarter of the year. Increased gas handling capacity will also facilitate a significant reduction in flaring and increased gas injection to support oil production.
The longer term plan is to monetise the significant remaining TEN resources through infill drilling particularly on Ntomme, phased development of new areas near existing infrastructure, development of the significant gas resources and drilling of prospective resources. Tullow expects to submit a plan of development to the Government of Ghana later this year.
In 2023, TEN production is expected to average c.20 kbopd (c.11 kbopd net), including the planned two week maintenance shutdown. A water injection well (En16) which was brought online in December 2022 is expected to provide pressure support for production from Enyenra in 2023. No new wells are planned to be added in TEN in 2023.
Non-operated
Production from Tullow’s non-operated portfolio was 16.7 kboepd net in 2022, supported by new wells brought online in Tchatamba, Ezanga and Etame.
2022 capital expenditure across the non-operated portfolio was c.$43 million, with approximately 60% on infrastructure projects, including the tie-back of the Wamba discovery for a long-term production test, which started in October and is expected to continue throughout 2023.
Production in 2023 is expected to average c.14 kboepd. Total capital expenditure is expected to be c.$40 million of which c.75% will be allocated to infrastructure projects to support future development and production. The remaining investment will be in new wells and workovers across the portfolio to sustain production levels.
Kenya
Tullow continues to focus on the process to secure a strategic partner for the development project in Kenya.
In parallel, Tullow and its JV Partners are working with the Energy and Petroleum Regulatory Commission Authority (EPRA) and the Ministry of Energy and Petroleum to finalise the FDP.
Exploration
In Côte d’Ivoire, Tullow has leveraged its differentiated understanding of the Tano Basin to secure a 90% interest in a new offshore exploration licence (CI-803) which, along with the Tullow operated CI-524 licence, provides Tullow with a strategic position in an area adjacent to the Group’s producing fields in Ghana.
In Gabon, Tullow continues to focus on selective infrastructure-led exploration (ILX) activities to underpin production. In the Perenco-operated Simba licence, Tullow and its JV Partners have matured several low-risk and compelling ILX options for drill readiness in 2023-25.
In the emerging basins of Guyana and Argentina, Tullow continues to seek opportunities to unlock value from the significant prospective resource base.
In 2022, capital expenditure on exploration activities was c.$45 million. In 2023, this is expected to be c.$30 million, which includes drilling costs for one non-operated well on Simba in Gabon.
ESG
In December 2022, Tullow signed a Letter of Intent (LoI) with the Ghana Forestry Commission (FC). The LoI is a key milestone for Tullow in developing a long-term supply of carbon offsets as part of its progress to reach Net Zero by 2030 and to support Ghana in meeting its Nationally Determined Contributions under the Paris Agreement. A Final Investment Decision (FID) is expected in 2023.
During 2022, Tullow supported STEM education through a range of programmes from primary to tertiary education across its countries of operation and created new entrepreneurship opportunities in Ghana and Kenya. Thousands of beneficiaries of these programmes are now leveraging new knowledge and skills as productive members of their communities.
Tullow’s multi-year flagship senior high school programme has provided accommodation for 2,850 pupils, more than 90% girls, and classroom facilities for 600 pupils, increasing general school enrolment. There has also been increased focus on local content in 2022 with several new initiatives with the supplier base in our host countries to raise awareness of business opportunities, provide practical assistance for businesses and enhance supply chain transparency. Tullow received the 2022 Ghana Oil and Gas Local Content award in recognition of these efforts.
FINANCIAL UPDATE
The Group generated total revenue, including the cost of hedging, of c.$1.7 billion, at a realised average oil price of c.$102/bbl before hedging and c.$87/bbl after hedging.
The additional equity in the Jubilee and TEN fields acquired through the pre-emption transaction in Ghana for $126 million has already paid back by 31 December 2022.
Full year capital expenditure was c.$354 million, c.$270 million in Ghana (of which $107 million in infrastructure), c.$31 million in Gabon, c.$12 million in Côte d’Ivoire and c.$45 million on exploration and appraisal activities. In Kenya, proceeds from Early Oil Pilot Scheme (EOPS) cargo sales have been recorded as a credit against capex, resulting in a net inflow of c.$4m. Decommissioning expenditure was c.$72 million.
Free cash flow for the full year 2022 is expected to be c.$267 million, ahead of guidance, with lower oil prices towards the end of the year offset by continued focus on cost control and deferrals of decommissioning costs and capital expenditure.
Net debt at the end of the year was c.$1.9 billion. Cash gearing of net debt to EBITDAX is expected to be 1.3 times at year-end 2022, ahead of guidance at the start of the year which was to reach less than 1.5 times by year-end 2023. Liquidity at year-end 2022 was c.$1.1 billion, consisting of c.$0.6 billion free cash and $0.5 billion available under the revolving credit facility. Tullow regularly reviews options for optimising its capital structure and may seek to retire or purchase outstanding debt from time to time through cash purchases or exchanges in the open market or otherwise.
In 2023, Tullow plans to invest c.$400million, of which c.$300 million in Ghana (primarily in Jubilee, including over $100 million in infrastructure), c.$40 million in Gabon, c.$20 million in Côte d’Ivoire, c.$10 million in Kenya and c.$30 million on exploration and appraisal activities. This is an increase of c.$50 million compared to 2022 as a consequence of deferrals from 2022, increased equity in Ghana for the full year, and ongoing infrastructure investment in Jubilee South East, which will account for c.40% of Ghana capital spend in 2023.
Decommissioning expenditure is expected to be c.$90 million in the UK and Mauritania, including deferrals from 2022, with less than $30 million of decommissioning liabilities in the UK and Mauritania remaining at the end of 2023. Additionally, starting in 2023, c.$30 million is expected to be paid annually into escrow for future decommissioning of currently producing assets in Ghana and parts of the non-operated portfolio.
Cash taxes are expected to be in excess of $300 million in 2023 (at $80/bbl) as historical capital allowances in Ghana will have been fully utilised in the first quarter of 2023. Tullow has received both revised and new tax assessments from the Ghana Revenue Authority throughout 2022, with these assessments not resulting in an increase to the overall exposure previously disclosed. Tullow believes these assessments are without merit and continues its active engagement with the Government of Ghana with the aim to resolve these disputes on a mutually acceptable basis.
Free cash flow for the full year 2023, post hedging, is expected to be c.$200 million at an average oil price of $100/bbl (c.$100 million at $80/bbl); this assumes revenue receipts for 15 cargos lifted from the Jubilee field and four cargos lifted from the TEN fields in Ghana during the year.
Capital investment in 2023, in particular in Ghana, is expected to support production growth through to 2025 and free cash flow generation of $700-800 million at 80/bbl for the two years 2024 and 2025 based on 2P reserves only, which will further reduce net debt and strengthen Tullow’s balance sheet.
Tullow’s commodity hedge portfolio provides oil price downside protection at $55/bbl for c.64% of forecast sales volumes to May 2023 and c.40% of forecast sales volumes from June 2023 through to May 2024. With the majority of hedges executed as part of the 2021 debt refinancing rolling off, Tullow will have increased exposure to higher oil prices from May 2023 onwards. Tullow plans to build out its commodity hedge portfolio for the second half of 2023 and into 2024, looking to maintain material upside exposure whilst securing protection against a severe oil price downturn.
