Slower-than-expected power sales growth hits net carbon intensity target

Targets 15%-20% Scope 3 emissions cut by 2030 from oil products vs 2021

Comes amid focus on growth of low-carbon fuel sales such as SAF, hydrogen

Shell weakened its main 2030 carbon reduction target March 14 but said it remains focused on net-zero emissions by 2050, despite a slower pace of power sales growth amid an ongoing shift away from traditional oil-based fuels.

In the first update to its main energy transition targets since 2021, Shell said it will target a 15%-20% cut in the net carbon intensity of its energy products by 2030 compared with 2016 levels. It had previously aimed for a 20% cut by 2030. The company said it now plans to reduce the net carbon intensity of the energy products it sells by 9-12% by 2024, 9-13% by 2025, 15-20% by 2030, and 100% by 2050.

In line with our shift to prioritizing value over volume in power, we are concentrating on select markets and segments,” Shell said. “One example is our focus on commercial customers more than retail customers. Given this focus on value, we expect growth in total power sales to 2030 will be lower than previously planned.”

Europe’s biggest integrated energy major also scrapped a 2035 target of a 45% reduction in net carbon intensity, citing “uncertainty in the pace of change in the energy transition.”

But Shell set itself a new target to cut the carbon emissions from the use of its oil products by 2030 as it sells less gasoline and diesel and ramps up production of low-carbon products such as biofuels and hydrogen.

Shell said it plans to reduce customer, or Scope 3, emissions from the use of its oil products by 15%-20% by 2030 compared with 2021 levels. The cut would mean a fall of more than 40% in Scope 3 emissions from its oil products compared with 2016 levels, Shell said.

“Achieving this ambition will mean reducing sales of oil products, such as petrol and diesel, as we support customers as they move to electric mobility and lower-carbon fuels, including natural gas, LNG and biofuels,” Shell said in its latest energy transition strategy.

Operating emissions

Under its previous energy transition targets, Shell was planning to reduce its production of traditional fuels by 55% by 2030 as it provides more low-carbon fuels such as biofuels for road transport and aviation, and hydrogen. Shell is also shrinking its global refining footprint to four core, integrated energy and chemicals sites by repurposing its remaining refineries.

Like many of its energy major peers, Shell plans to grow its production and sales of biofuels in the coming years, including premium biofuels such as sustainable aviation fuel, renewable diesel and renewable natural gas. Shell is already one of the world’s largest energy traders and blenders of biofuels, selling more low-carbon fuels than it produces. In 2023, around 9.7 billion liters of biofuels went into Shell’s road fuels worldwide, compared with 9.5 billion liters in 2022, according to the company.

Shell estimates that some 15%-20% of its total oil products are used for non-energy products such as lubricants and chemical products, which do not generate Scope 3 emissions.

On its central emission targets, Shell said it continues a drive to halve emissions from its operations (Scope 1 and 2) by 2030, compared with 2016 on a net basis. By the end of 2023, Shell said it had achieved more than 60% of this target and reduced the net carbon intensity of the energy products it sells by 6.3% compared with 2016, the third consecutive year it hit the target.

However, Shell maintained its overall target of achieving net-zero emissions by 2050 across all its operations and energy products to help support the Paris Climate Agreement goals.

“Today the world must meet growing demand for energy while tackling the urgent challenge of climate change,” CEO Wael Sawan said in a statement. “I am encouraged by the rapid progress in the energy transition in recent years in many countries and technologies, which reinforces my deep conviction in the direction of our strategy.”

Shell also confirmed it will invest $10 billion-$15 billion between 2023 and the end of 2025 in low-carbon energy solutions, which include spending on business lines such as electric vehicle charging, biofuels, renewable power, hydrogen and carbon capture and storage.

LNG, carbon credits

The energy major’s net carbon intensity in 2023 fell to 74 grams of CO2e/Megajoules, down by 2.6% and 6.3% from 2022 and 2016, respectively.

This fall was mainly achieved through a reduction in the average intensity of power sold and the use of carbon credits.

Most oil companies do not have Scope 3 emissions targets but instead have set net carbon intensity metrics.

Carbon intensity is seen as a less ambitious measure as net emissions can simply be lowered by selling more clean energy alternatives such as wind or solar power.

As it looks to expand its LNG business by 20%-30% by 2030 it will focus on reducing the carbon intensity of these operations, it added.

In its LNG joint venture in Canada, it plans to use use natural gas and renewable electricity while in the North Field Expansion project in Qatar it hopes to use CCS.

“We expect LNG will play a critical role in the transition,” said Sawan. “It continues to provide a secure supply of energy in many European countries. It also offers flexibility to electricity grids as wind and solar power grow, and opportunities to lower carbon emissions from industries such as cement and steel by replacing coal.”

Shell is an active participant in the voluntary carbon markets and in 2023, its net carbon intensity accounted for 20 million carbon credits, of which 4 million were linked to the sale of energy products, it said.

By: spglobal / Robert Perkins, 14 Mar 2024.

Investments in new oil production have been stalling since about 2014. This has led many to suggest that higher prices for longer are on the cards, supported by anti-oil industry energy policies in key jurisdictions that are home to the largest private producers.

Yet a case might be made that although lower, the oil industry’s investments over the past decade have become better targeted at prospects with a good chance of a discovery. Either that, or they have become luckier than usual. Nowhere is this clearer than in Africa.

Earlier this month, French TotalEnergies said that it would buy a 33% stake in an exploration block offshore South Africa. Its partner QatarEnergy was also taking part in the acquisition in Block 3B/4B, with a 24% interest. The acquisition is part of the French supermajor’s exploration campaign in South Africa’s neighbor Namibia, which shares the Orange Basin with South Africa.

The Orange Basin has recently become something of a hot spot rivaling Guyana. The last couple of years have seen a string of discoveries revealing reserves estimated at around 5 billion barrels so far. And the rate of success has been unusually high, with 15 confirmed discoveries of commercial volumes of hydrocarbons in 17 exploration wells drilled since February 2022, per the Financial Times.

The largest discovery so far was made by TotalEnergies in the Venus field offshore Namibia, with estimated reserves of 3 billion barrels. No wonder the company is expanding in the area—even as forecasts for peak oil demand persist.

“Following the Venus success in Namibia, TotalEnergies is continuing to progress its Exploration effort in the Orange Basin,” the senior vice president for exploration at the French company, Kevin McLachlan, said last week, following the news of the South Africa investment.

“South Africa’s side of the Orange Basin resembles those of Namibia, it is highly prospective with at least two prospects in the northern region of the basin potentially containing millions of barrels of oil and associated gas,” according to Jonathan Salomo, who is the lead geologist for the West coast of South Africa at the country’s Petroleum Agency.

TotalEnergies and QatarEnergy are not alone in their pursuit of Africa’s hitherto untapped oil and gas riches. In January this year, a Canadian company specifically focused on Africa and named accordingly—Africa Oil Corp—completed the  purchase purcha of additional acreage in the same Orange Basin block that TotalEnergies and the Qatari state oil company are planning to expand into.

The block is estimated to contain prospective resources equal to some 4 billion barrels of oil equivalent, Offshore Energy reported back in January, with success probability ranging between 11% and 39% for the 24 prospects in the block.

Southern Africa is a hotspot, then, but it is not the only one in Africa. Offshore Energy again reported this month that a Houston-based energy company had struck a deal struck a deal to buy a Swedish exploration player to gain access to an offshore block in the Ivory Coast.

The target company, Svenska Petroleum Exploration, holds a 27% stake in the Baobab field offshore the Western African country that is most famous for its cocoa. The Baobab field is a producing one, yielding some 4,500 gross barrels of oil equivalent daily, with plans to expand this and extend the productive life of the field.

Oil is not the sole focus of international investors, either. Liquefied natural gas has become a priority for many as Europe joined the big buyers’ club two years ago, providing a huge boost to exploration, including in Africa, which already produces some LNG but could produce a lot more.

The Greater Tortue Ahmeyim LNG project, for instance, is about to enter operation in the third quarter of this year. Located on the border between Senegal and Mauritania, the project is led by BP in partnership with Kosmos Energy and the state energy companies of the two countries. GTA LNG will have an annual capacity of 2.3 million tons initially, to be expanded to 10 million tons over three phases.

Next year could also see the pre-final investment decision on the Tanzania LNG terminal, which aims to tap the country’s offshore gas resources. The price tag of the project is $42 billion and it is being developed by an all-star cast including Equinor, Shell, and Exxon. The capacity of the project is seen at a minimum of 10 million tons annually, potentially turning Tanzania into a sizeable player in the LNG market.

Oil and gas exploration in Africa is booming, in part because the continent contains a lot of the hitherto undiscovered global hydrocarbon reserves and in part because local governments appear to be a lot more open to the idea than the governments in Big Oil’s home countries and nearby jurisdictions.

Wood Mackenzie calculated last year that the energy industry is investing a total $800 billion in African oil and gas. The investment cycle began in 2010, the firm’s upstream research director said at an industry event in October, and will end with Africa emerging as a leading producer of LNG from floating terminals and a growing source of deepwater oil.

By Oilprice.com / Irina Slav, March 12, 2024

Hydrogen is traditionally used to produce methanol and refine petroleum. Currently, around 51% of hydrogen used in the economy goes to refineries, and 43% is used as an input for ammonia synthesis, primarily for production of fertilizers.1 The most common process for producing hydrogen is steam methane reforming. Fossil fuel-based, it consumes around 6% of the world’s natural gas and 2% of its coal.

However, this is changing as the production of green hydrogen (see sidebar) becomes a more viable option, and to some extent, an essential one as fossil fuels become more expensive, more unacceptable due to climate change and a bargaining tool in geopolitical conflicts. The world is looking to more sustainable energy production and ways to reach net zero emissions by the year 2050,2 and using hydrogen as fuel for heavy transport applications like trucks, buses and cars is an increasingly popular topic of conversation. However, using green hydrogen comes with its own challenges, including how to store and transport it and how to test and validate it where no standard testing and

Green hydrogen is used to describe hydrogen gas that is completely carbon-neutral and produced using renewable energy sources in a process called electrolysis. Here are its key characteristics:

1. Renewable energy source: Green hydrogen is produced using electricity generated only from renewable energy sources, such as wind, solar, hydroelectric or geothermal power.

2. Electrolysis: Green hydrogen is produced in an electrolyzer, which uses renewable energy to split water (H2O) into hydrogen (H2) and oxygen (O2) using an electric current.

3. Zero greenhouse gas emissions: Because the electricity used in the electrolysis process comes from renewable sources, the overall carbon footprint of green hydrogen production is minimal or even zero.

4. Versatile applications: Green hydrogen can be used in a wide range of applications, including fuel cell vehicles, industrial processes, electricity generation and energy storage. It can serve as an energy carrier, helping to store and transport renewable energy efficiently.

Sealing & Storage

Achieving a reliable seal involves using advanced materials and engineering techniques that can withstand the challenges posed by hydrogen’s small molecular size, which makes it difficult to seal and store as it can permeate through many materials. For certain applications, sealing materials must demonstrate a high level of compatibility and permeation resistance to prevent loss.

Another related issue is rapid gas decompression (RGD). In a high-pressure system, the small hydrogen molecules can be absorbed into a seal material. If the pressure in the system is suddenly relieved, gas trapped in the seal material can expand to match the new ambient pressure, potentially causing the seal to blister and crack as the gas tries to escape.

Finally, seals for different hydrogen systems need to withstand seriously tough environments, including high pressures of up to 14,504 pounds per square inch (psi) (e.g., in high-pressure valves) and extreme low temperatures down to -418 F (e.g., in liquid hydrogen storage and transportation).

Hydrogen: The Facts (Sidebar)

Hydrogen is a gas with an average atomic mass of 1.00794.

It is the first and most abundant element on the periodic table.

It is a constituent of most organic compounds, making up about 75% of the universe’s overall mass.

Hydrogen is colorless, odorless and tasteless.

The lightest of all elements, hydrogen consists of the smallest of all molecules, which means it can permeate through many materials.

Hydrogen is rarely available in its pure form on Earth, so it requires extraction from compounds containing hydrogen. Any compound with ‘H’ in its chemical formula has hydrogen as one of its constituents.

It is in hydrocarbons, methane (CH4) and water (H2O).

Setting the Standard

The evolving nature of the hydrogen market and value chain creates a demand for fuel storage standards. Experts are looking to existing standards for similar storage applications such as those used for oil and gas, which define acceptable characteristics for polymers in arduous conditions relative to permeation, RGD and general media compatibility. However, no existing standards provide a perfect fit, because they do not account for the conditions seen in typical applications throughout the hydrogen value chain.

Hydrogen is an explosive gas, and it must be tested with great care. Many seal manufacturers use third-party testing facilities. Helium is often used as a proxy for safer testing, and results are converted to hydrogen values. However, helium is not a perfect substitute, and some companies are investing in their own rigs that are approved to test hydrogen. These facilities offer comprehensive, hydrogen-specific standards and validation processes, and their experts can create custom solutions for whatever the user needs.

Seals are tested to International Organization for Standardization (ISO) 17268 for RGD, EC79 for components intended for hydrogen-powered vehicles, SAE J2600 for fueling connectors, nozzles and receptacles of compressed hydrogen surface vehicles, along with some permeation testing. Other tests include verification for a wide range of static sealing cross sections, including cyclic pressure, with pressure ranges from 101 to 10,877 psi and temperature ranges
from -65 F to 266 F.   

The current and future market needs for hydrogen sealing across the entire value chain production, transportation, storage and end use are broad, ranging from standard components to highly engineered solutions. Few OEMs have extensive experience in these areas, making a hydrogen component and sealing partner essential.

 By: pumpsandsystems / James Simpson, 03/12/2024.

Europe is pivoting away from Russian natural gas to hydrogen. Germany’s role will be key.

In Ancient Rome, roads converged on Italy. In 21st-century Europe, new hydrogen pipelines to ensure European energy security will lead to Germany.

The corridors represent a grand endeavor designed to facilitate the production, importation, and transportation across Europe of hydrogen. They will form the backbone of a revolutionary pivot away from dependence on Russian gas. Hydrogen can complement intermittent renewable sources such as wind and solar power, providing a reliable energy supply.

The goal is ambitious: to enable the transportation of a total of 20 million tons of this gas per year by 2030. Six supply corridors that would be directly or indirectly connected to Germany. These corridors consist of pipelines, production and storage facilities, port terminals, and shipping lanes across seas, rivers, and land. Initially, the corridors will connect local supply and demand in different parts of Europe, before expanding and connecting Europe with neighboring regions. One of them, the Central European Hydrogen Corridor (CEHC), would pump this gas from Ukraine.

Germany needs an alternative to gas, given its large energy-intensive industries and its plans to phase out coal and lignite plants. H2 MOBILITY Germany is building a nationwide network of hydrogen filling stations. Gasunie and Thyssengas are setting up this gas’s transportation infrastructure connecting Germany’s North Sea coast with the industrial Ruhr Valley. This “hydrogen core network” aims to repurpose existing gas infrastructure and is meant to be completed by 2032.

Despite this progress, Germany’s ambitious energy plans still must overcome serious obstacles. Hydrogen can cause embrittlement in certain materials such as steel and cast iron out of which natural gas pipelines are typically made, leading to safety risks and pipeline degradation. Careful selection of pipeline materials, coatings, and design are required to mitigate this risk.

Another challenge is building out Europe’s hydrogen production capacity – while avoiding being undercut by China. Electrolyzers use electricity to split water into hydrogen and oxygen. Europe has traditionally held a strong position in the electrolyzer manufacturing industry, home to six out of the ten largest electrolyzer manufacturers. But Europe also used to be the world’s leader in solar power manufacturing, until cheap Chinese panels swept the market. Europe’s hydrogen strategy aims to maintain the region’s competitive strengths in electrolyzer manufacturing.

Investment and innovation also are required to boost hydrogen storage. New solutions such as underground caverns or innovative hydrogen carriers are needed.

If these challenges are met, demand for hydrogen will skyrocket. Germany alone will need to import around 50% – 70% of the energy it needs, forecast at 95 – 130 TWh in 2030. Denmark is eyeing production of 6GW, with most of the production exported to Germany via a hydrogen pipeline that will be operational in 2028. The UK’s leading electrolyzer manufacturer ITM Power, has set up a production site in Germany to bypass post-Brexit regulatory hurdles. Other countries might follow suit. Germany’s growing demand for hydrogen could incentivize hydrogen producers and exporters in my homeland, Poland.

Germany’s ambitious hopes could suck in imports from friendlier countries such as Namibia, Oman, or Kazakhstan, for which some of Europe’s hydrogen corridors are designed. By leading the way in hydrogen innovation and deployment, Germany can influence international standards and regulations.

Hydrogen is destined to play a pivotal role in Europe’s green transition. If Germany dominates, Berlin will gain great sway over the continent’s energy policy, worrying some neighbors But Germany’s central location makes it fit to serve as a hydrogen hub. It has the political will and economic strength to drive a European hydrogen revolution. Success will foster an interconnected, resilient European energy system, free of Russian influence.

Maciej Filip Bukowski is a 2022 CEPA James S. Denton fellow, a 2023 International Republican Institute Transatlantic Security Initiative fellow, and currently a senior international analysis expert at BGK, a Polish development bank. A graduate of Sorbonne and Cornell law schools, he is completing a Ph.D. thesis at the Jagiellonian University on the geopolitics of climate change.

Bandwidth is CEPA’s online journal dedicated to advancing transatlantic cooperation on tech policy. All opinions are those of the author and do not necessarily represent the position or views of the institutions they represent or the Center for European Policy Analysis.

By Maciej Bukowski, March 12, 2024

Hydrogen is a gas with an average atomic mass of 1.00794.

It is the first and most abundant element on the periodic table.

It is a constituent of most organic compounds, making up about 75% of the universe’s overall mass.

Hydrogen is colorless, odorless and tasteless.

The lightest of all elements, hydrogen consists of the smallest of all molecules, which means it can permeate through many materials.

Hydrogen is rarely available in its pure form on Earth, so it requires extraction from compounds containing hydrogen. Any compound with ‘H’ in its chemical formula has hydrogen as one of its constituents.

It is in hydrocarbons, methane (CH4) and water (H2O) has been a key driver in my portfolio and allowed me to outperform the market since 2020.

During the pandemic, I bought the stock dirt cheap close to $30, when the entire world was buying tech, growth, and alternative investments like crypto and pictures of rocks.

However, I sold Exxon Mobil and shifted my money to peers, like Canadian Natural Resources (CNQ), as I realized I had bet on the wrong horse.

Don’t get me wrong! This article is not going to be a hit job on Exxon or a promotion of my holdings.

After having received countless questions from readers who asked me why I don’t own Exxon anymore, I will use this article to explain why I believe that Exxon is not the right place to be if investors want to bet on higher oil prices.

Nonetheless, I will also explain why I keep a Buy rating on the stock, as it’s not a bad company.

So, let’s get right to it!

When Oil Rises, Exxon Underperforms

While the company may have massive reserves and growth opportunities in markets like Guyana, on top of consistent dividend growth and a credit rating of AA-, it is somewhat stuck in the middle.

The company is not the best place to be for dividend income. Other companies have much more favorable distribution policies.
It’s not as undervalued as other oil companies, in case investors are looking for opportunities with potentially more capital appreciation.
The chart below confirms my case (I’ll give you more details in this article).

Below, we are looking at the ratio between the XOM stock price and the Energy Select Sector ETF (XLE). That’s the black line. The red line shows the price of oil – except that it’s inverted!

In other words, the fact that the XOM/XLE ratio tends to follow the red line over time shows that when oil prices fall, investors prefer XOM. That makes sense, as it comes with a lot of safety, including a balance sheet with an AA- rating.

However, when oil prices rise (the red line drops), XOM performs poorly compared to the XLE ETF.

Also, please bear in mind that Exxon accounts for roughly a quarter of the XLE ETF.

Exxon and Chevron (CVX) combined account for almost 40% of the entire ETF.

Including dividends, XOM has returned 76% over the past ten years, beating the XLE by roughly 28 points.
However, as the lower part of the chart above shows (it’s the XOM/XLE ratio again), outperformance has entirely vanished over the past five years.

The last time XOM was the “best place” to be in energy was between 2014 and 2021.

This period of subdued oil prices put pressure on US shale producers, benefiting XOM as a safe haven in a troubled industry compared to XLE.

Exxon Is Good, But Not Good Enough
With all of this in mind, Exxon isn’t a bad stock. If you have owned Exxon for many years and want to avoid taxes by not selling, I don’t think it hurts to stick around.

After all, Exxon is making progress.

For example, the company is rapidly investing in growth projects.

As we can see above, major projects, totaling $30 billion, were completed on time or ahead of schedule and within budget.

These projects included the Beaumont refinery expansion, the only major refinery expansion in the United States in recent years.

The EIA posted the chart below last year, which shows the significance of this project, especially in light of higher post-pandemic demand and prolonged underinvestment in the industry.

top 10 U.S. refineries by operable crude oil distillation capacity
Energy Information Administration

On top of expanding its downstream (refining) footprint, the company is improving its upstream capabilities (producing oil and gas).

The company has an emphasis on two major basins:

The Permian. This is America’s most attractive basin, with deep reserves and attractive breakeven prices.
Guyana. This country has massive offshore reserves. S&P Global (SPGI) estimates that this nation has more than 11 billion barrels of oil in reserves.
Image
S&P Global

For Exxon, these two projects boast a competitive cost of supply, positioned below $35 per barrel. This ensures profitability even in challenging market conditions.

In these two areas, Exxon is producing more than it initially expected.

So in the Permian, we had guided to 600,000 kind of oil equivalent barrels. We came in at 620,000. In Guyana, we had said 380,000, we came in at 390,000, right? And you think about where we’re at in Guyana today, and we’ve got prosperity, the third boat, which is in the Payara development already up to nameplate capacity as we stand here today. And that’s because we made the decision to drill more wells to ensure that we could get that boat up to capacity as quickly as possible in our organization absolutely delivered on that. – XOM 4Q23 Earnings Call

The company is also working on completing the acquisition of Pioneer Natural Resources (PXD), a deal I discussed in this article.

Exxon expects significant synergies from the acquisition, particularly in terms of increased resource recovery and capital efficiency. By combining resources and expertise, Exxon Mobil aims to unlock additional value and drive sustainable growth in the Permian Basin.

Essentially, the deal is all about resource recovery in the Permian Basin, an area where PXD has some of the best assets in the Midland.

XOM believes that by applying its development strategy and “operational excellence” to Pioneer’s assets, it can maximize the production of oil and gas from existing reservoirs.

This is very important, as the Permian is slowly moving toward peak production growth, a development that could be very bullish for oil prices, as the shale revolution was the reason why prices were often very subdued.

The Permian is expected to produce a record high 5.974 million barrels per day in February, though that will be the smallest month-over-month growth since July, EIA data showed. – Reuters

On top of that, Exxon is now going after Chevron. Exxon recently filed for arbitration in the International Chamber of Commerce in Paris, as it believes it has a right of first refusal over the Chevron/Hess (HES) deal.

Chevron’s deal to buy Hess amounts to a circumvention of Exxon’s pre-emption rights, Chapman said. While the joint-operating agreement with Hess and other partners in Guyana is confidential, Exxon is “very, very confident” in its position, he said. – Bloomberg

While Exxon will try to buy Hess, it is likely that Chevron will terminate the deal before it comes to that.

Once that happens, it needs to be seen what Exxon will do.

For now, however, the key takeaway is that Exxon is becoming increasingly aggressive in both the Permian and Guyana, as it seems to capitalize on its ability to increase output in an industry that is increasingly focused on capital preservation.

So, what about its dividend?

Exxon has 41 years of consecutive annual dividend increases, making it one of the few Dividend Aristocrats in the industry.

After hiking its dividend by 4.4% on October 27, it now pays $0.95 per share per quarter. That’s a yield of 3.5%.

The five-year dividend CAGR is 2.6%, which is extremely low.
While the company did not cut its dividend during the pandemic, it seems to follow a strategy based on safety.

It knows that if it were to aggressively hike its dividend, it might have to cut once oil prices implode again.

However, instead of using special dividends, Exxon – like its major peers – is using buybacks to distribute cash. While that may benefit the per-share value of its business, it’s not necessarily what income-focused investors are looking for.

Especially in the energy sector, investors tend to be income-focused. I’m one of them.

Over the past three years, XOM bought back 6% of its shares.
This year, the company is expected to generate $32 billion in free cash flow. While this is highly dependent on oil prices, it indicates a free cash flow yield of 7%.

In other words, we can expect total distributions to be close to that number, potentially consisting of 50/50 dividends and buybacks.

Needless to say, that’s also dependent on future M&A and potential investments in growth.

Personally, I am not a fan of the buyback strategy and doubt we’ll see a shift to special dividends.

What I Prefer Instead Of Exxon
Buybacks make sense when a company is very cheap. This applies to a company like Cenovus (CVE), the Canadian integrated oil and gas player that has vowed to distribute all excess cash flow through buybacks in the future. I discuss CVE in this article.

CVE trades at less than 6x operating cash flow (“OCF”).

Exxon trades at a blended OCF ratio of 7.8x. Generally speaking, XOM has enjoyed a higher multiple, as it is simply a more stable business than most oil companies.

Its normalized OCF multiple is 9x, as we can see in the chart below (the blue line).

However, at current prices, I prefer a range of other companies:

Undervalued plays like Cenovus.
U.S. shale producers with a focus on special dividends and a very attractive valuation. In this segment, I like Devon Energy (DVN), which I discuss in this article.
Super-majors like EOG Resources (EOG). I often think of it as an on-shore version of Exxon. EOG uses special dividends to reward investors. I discussed EOG in this article. Especially premium drilling has allowed this company to boost shareholder returns. It now has a base dividend of 3%, a double-digit OCF yield, and a stock price that, I believe, is easily up to 30% undervalued in the current environment. The data in the chart below supports my thesis.
Image

I also prefer plays like Canadian Natural Resources, which just hit its leverage target and has pledged to return 100% of its free cash flow to shareholders.

CNQ is my largest upstream investment.

I also preferred Diamondback Energy (FANG), as it uses special dividends to distribute most of its cash to shareholders.

However, after the recent M&A announcement, the stock is not very cheap anymore, and we may see a focus on debt reduction.

Nonetheless, if FANG comes down, I will buy this one for a number of family accounts, likely also my personal dividend growth portfolio.
Over the next few years, I expect all of these stocks to beat XOM and deliver substantially more dividends – and buybacks.

However, these companies are more volatile than Exxon. Moreover, while CNQ has a somewhat similar volatility profile and a Dividend Aristocrat profile, it has CAD/USD currency risks and tax implications for some investors.

So, all things considered, I like Exxon. However, I do not like it enough to recommend it to the “average” investor looking for oil exposure.

While it certainly has benefits like consistent dividend growth, growth potential in Guyana and the Permian, and diversification through downstream operations, dividend growth is too slow, it’s not extremely cheap to warrant buybacks, and I expect the company to continue underperforming its average peers during oil price rallies.

Takeaway
While Exxon has historically been a stalwart in the energy sector, recent trends suggest it may not be the best bet for investors seeking exposure to higher oil prices.

Despite its solid fundamentals, including substantial reserves and growth projects, Exxon’s performance tends to lag behind during oil price upswings.

Moreover, the company’s cautious approach to dividend growth and reliance on buybacks may not appeal to income-focused investors.

Instead, alternatives like undervalued plays such as Cenovus or U.S. shale producers like Devon Energy offer more attractive prospects for dividend growth and capital appreciation.

While Exxon remains a viable option for some, it may not be the optimal choice for investors seeking elevated returns in the current energy environment.

However, I am giving the stock a Buy rating, as it’s still a good company that will benefit from potentially higher oil prices and measures to improve the business.

Pros & Cons
Reasons to like Exxon:

Historically stable investment in the energy sector.
Massive reserves and growth opportunities in Guyana and the Permian Basin.
Consistent dividend growth for 41 consecutive years.
Diversification through downstream operations.
Reasons to dislike Exxon:

Underperformance during oil price rallies compared to peers.
Slow dividend growth may not appeal to income-focused investors.
Reliance on buybacks instead of special dividends.
XOM is not as undervalued as some alternatives like Cenovus or Devon Energy.
I see a high likelihood of continued underperformance in the current energy environment.

By: seekingalpha / Leo Nelissen ,Mar. 11, 2024

U.S. crude oil exports dropped slightly for the week ending March 1 to 4.3 MMb/d from 4.4 MMb/d in the previous week.

This seems to continue the trend of increasing US exports, as can be seen from the 4 week moving average, (blue line in graph below). Though the topline number was about flat, it hid some significant changes.  First, Enterprise’s Houston Terminal set its monthly record in February, loading 24.6 MMbbl, topping January’s record which was 20.2 MMbbl, both of which are substantially more than 2023’s average rate of 13.7 MMbbl.

The second big change was in destination, with Europe and Asia switching places. Exports destined for Asia fell substantially last week to 5.5 MMbbl from 15.9 MMbbl the previous week. This is the lowest exports to Asia have been since early November. On the flip side, volumes to Europe were up by more than 7 MMbbl to 18 MMbbl, a number we’ve only witnessed one other time in the last several years.  With the troubles in the Red Sea choking Suez Canal volumes, this was predicted to happen, with US volumes thought to be replacing Mid East volumes that are headed east, to avoid paying the rather steep penalty of the Cape of Good Hope reroute.

By: RBN Energy / Albert Marc Passy, March 8, 2024

Enbridge has embarked on further enhancing its crude oil export capabilities at the US Gulf Coast through a combination of brownfield acquisitions and new build outs to accommodate growing output from the Permian Basin and Western Canada, senior company officials said March 6.

“Today we are announcing accretive new capital investments focused on our USGC strategy that include additional export docks and storage tanks at EIEC [Enbridge Ingleside Energy Center],” CEO Greg Ebel said on a webcast at the Enbridge Investor Day in New York. “These investments provide near-term growth in the USGC and set the stage for the future expansion through high-quality partnerships and embedded organic opportunities.”

The planned new projects include a 120,000-b/d expansion of the Gray Oak pipeline, for which an open season is currently underway, and the building of 2.5 million barrels of crude storage at EIEC, both estimated to cost $100 million, President of Liquids Pipelines Colin Gruending said on the same webcast.

The long-hail Gray Oak pipeline of nameplate capacity 1 million b/d ships light barrels from the Permian to the EIEC at the Port of Corpus Christi in Texas.

EIEC is Enbridge’s prime crude oil storage and terminal with access to a marine waterfront and hinterland pipeline connectivity to the Permian and Eagle Ford basins making it a cost-advantaged location for the storage and export of crude.

At present, Enbridge has been exporting about 1 million b/d of crude from its docks at the EIEC, Gruending said.

Enbridge sanctioned 2.5 million barrels of additional crude oil storage at EIEC, which will bring overall storage capacity to nearly 20 million barrels by 2025, the company said in a release, adding the timely addition of storage tanks at Ingleside supports higher crude throughput by ensuring customers have on-demand access to their export-ready crude supply.

New marine docks, Mainline status

Also, as part of adding new USGC export capacity, Enbridge has signed an agreement to acquire two marine docks and nearby land adjacent to EIEC from Flint Hills Resources for about $200 million with the deal expected to close in Q3, 2024, the company said.

The acquisition will facilitate Enbridge’s plans to fully integrate the waterfront between EIEC and the newly acquired docks, which will add immediate crude oil export capacity and streamline existing Ingleside operations by increasing VLCC windows on the primary facility docks, Enbridge said.

Looking ahead, the new Flint Hills docks can also be configured to export multiple products and Enbridge will retain the option to expand its existing Ingleside dock infrastructure as required, it said.

“With the acquisition, we will have more capacity to load VLCCs,” Ebel said without giving a figure on current loadings from EIEC.

These investments come in the wake of growing crude oil volumes from the Western Canadian Sedimentary Basin and the Permian, which Enbridge estimates to be 500,000 b/d and 1 million b/d respectively over the shorter term, Ebel said.

For the 3,000-mile Mainline pipeline system, Enbridge sees 2024 throughput being maintained at 3 million b/d, Gruending said. The system transports Canadian heavy and light barrels from Edmonton in Alberta to Gretna on the Canadian-US border where the volumes flow onto Enbridge’s Lakehead system that supplies crude oil to refineries in US Midwest and USGC.

“North America is now long on oil and we see a resilient demand of 2 million b/d from sole-sourced refiners on the way of the Mainline system, [besides a growing demand for exports to the USGC]” Gruending said. “Despite the start up of TMX, the Mainline will not be losing a ton of volumes. The mainline has been pretty full and the system is competitive along with the demand pull.”

On March 4, Enbridge said the Canada Energy Regulator had approved the Mainline tolling negotiated settlement.

The settlement sets tariffs for crude oil and liquids shipments that start in Western Canada and are delivered across Canada and North America, Ebel said.

On Dec. 15, 2023, Enbridge filed an application with the Canada Energy Regulator for approval of the Mainline tolling settlement that covers both the Canadian and US portions of the Mainline and sees the pipeline as a common carrier system available to all shippers on a monthly nomination basis.

The settlement term is seven and a half years through the end of 2028, with new interim tolls effective on July 1, 2023.

Under the deal the new toll is be a combination of the following: C$1.65 ($1.23)/b for the Canadian portion; $2.57/b for the US section; and $0.77/b as Line 3 Replacement surcharge.

New Louisiana gas pipeline

Separately, Enbridge and Shell Pipeline have extended their relationship through additional investment in growing Gulf of Mexico offshore plays, the former said, adding a newly formed joint venture, Oceanus Pipeline Co., to develop and construct a 60-mile, 18-inch oil pipeline and a 15-mile, 10-inch gas pipeline to serve Shell and Equinor’s offshore Sparta development.

The projects are consistent with Enbridge’s low risk business model and are backed by long-term fixed payment contracts, with an estimated cost of $200 million and expected to be in service in 2028, Enbridge said.

By: S&P Global /Ashok Dutta, March 8, 2024

Vitol’s subsidiary ViGo Bioenergy has acquired PitPoint.LNG, the Dutch joint venture between TotalEnergies and SHV Energy.

Oaklins, who acted as the exclusive M&A sell-side advisor to TotalEnergies and SHV, revealed the deal in a statement on Thursday.

The company did not provide further details regarding the acquisition.

With this deal, Germany’s ViGo expands its international station network for alternative fuels and strengthens its European LNG and bio-LNG position.

According to its website, PitPoint.LNG currently operates 12 heavy-duty LNG stations in the Netherlands, Belgium, and Germany, and one bunkering station for inland waterway vessels in Cologne, Germany.

On the other hand, ViGo recently launched a bio-LNG station for vehicles in Germany’s Braunschweig and now has 28 stations in operation with more planned.

Back in 2021, energy trader Vitol bought Berlin-based LNG firm Liquind, now renamed ViGo Bioenergy.

Germany hosts the largest number of LNG fueling stations for trucks.

Recent data by Gmobility, previously known as NGVA Europe, showed that Germany had 185 LNG filing stations, while Italy had 146 such stations.

Last year, European network of LNG fueling stations for vehicles reached 700 stations due to a growing demand for LNG and bio-LNG in the transport sector.

By: LNG Prime Staff, March 8, 2024

Bloom Energy Inc. has partnered with Shell Plc. (Shell) to explore decarbonization solutions, leveraging Bloom’s innovative hydrogen electrolyzer technology.

Together, Bloom and Shell aim to develop replicable, large-scale solid oxide electrolyzer (SOEC) systems capable of producing hydrogen for potential utilization across Shell’s assets.

KR Sridhar, founder, chairman, and CEO of Bloom Energy, expressed optimism about the transformative potential of this technology in decarbonizing hard-to-abate industry sectors. He emphasized Bloom’s position as a world leader in solid oxide electrolyzer technology, poised to provide customers with American-made energy technology to reduce carbon footprints while sustaining economic growth.

Bloom’s SOEC technology enables the production of clean hydrogen at scale, offering a sustainable alternative to fossil fuel-powered “grey” hydrogen production methods. By utilizing water electrolysis and renewable energy sources, Bloom’s technology produces clean or “green” hydrogen, effectively eliminating greenhouse gas emissions.

The demand for Bloom Electrolyzer®, manufactured in California and Delaware, has been steadily increasing due to growing interest in the low-carbon economy. Independent analysis indicates that Bloom now boasts the world’s largest operating electrolyzer manufacturing capacity among all electrolysis technologies, surpassing its closest competitor by double. A highly successful demonstration in May 2023 showcased the world’s largest solid oxide electrolyzer, with a capacity of 4 Megawatts, producing 2.4 metric tons of hydrogen per day at NASA Ames research facility in Mountain View, California. This high-temperature, high-efficiency unit outperformed commercially demonstrated lower temperature electrolyzers such as proton electrolyte membrane (PEM) or alkaline electrolyzers in terms of hydrogen production per megawatt (MW).

By: Solar Quarter / Kavitha , March 8, 2024