Category: Nieuws

The geopolitically critical positioning of the UAE’s Fujairah as an alternative global crude oil storage facility and transit hub to the perennially troublesome Strait of Hormuz route continued last week, with the announcement that deliveries have now begun on the Fujairah Terminal expansion by Abu Dhabi (AD) Ports Group.

According to comments by the company’s commercial director-ports, Julian Skyrme, the AED1 billion (US$272 million) investment in the expansion has added container capacity of 720,000 twenty-foot equivalent units and general cargo capacity of 1.3 million metric tonnes. 

This push from Fujairah comes after the finalisation in July 2021 of Iran’s own game-changing crude oil storage, transport and delivery mechanism, the Jask Oil Terminal and the 42-inch Guriyeh-Jask pipeline.

As analysed in depth in my new book on the global oil markets, the significance of this new Iranian crude oil export terminal can barely be overstated, as it allows Iran to transport huge quantities of oil and petrochemicals from its major oil fields via Guriyeh in the Shoaybiyeh-ye Gharbi Rural District of Khuzestan Province, 1,100 kilometres to Jask port in Hormozgan province, which is perfectly strategically placed on the Gulf of Oman. 

At the same time, the Guriyeh-Jask pipeline allows Tehran the option of disrupting all other oil supplies that travel through the Strait of Hormuz – around 35 percent of the world’s total.

“Even before U.S. sanctions were re-introduced [in 2018], the Kharg terminal accounted for around 90 percent of all of Iranian oil export loadings, with the remaining loads going through terminals on Lavan and Sirri, which made obvious and easy targets for the U.S. and its proxies to cripple Iran’s oil sector and therefore its economy,” a senior oil and gas industry source who works closely with Iran’s Petroleum Ministry exclusively told OilPrice.com.

“In addition, the extreme narrowness of the Strait of Hormuz means that oil tankers have to travel very slowly through it, so pushing up the transit costs and delaying revenue streams,” he said.

“Conversely, Iran wants to be able to use the threat – or reality – of closing the Strait of Hormuz for political reasons without also completing destroying its own oil exports revenue stream,” he added.

It was precisely such an incident – the 2011/12 Strait of Hormuz Dispute – that the once fanciful notion of Fujairah (one of the UAE’s smallest and lesser known emirates) becoming one of the world’s great oil storage and trading hubs alongside the Far East’s Singapore hub, Europe’s ARA (Amsterdam-Rotterdam-Antwerp), and the U.S.’s Cushing gained real momentum.

This Dispute began in December 2011 when Iran threatened to cut off oil supply through the Strait should economic sanctions limit, or halt, Iranian oil exports, and it included a 10-day military exercise in international waters near the chokepoint. 

Fujairah at that point was recognised as having an extremely strategically advantageous position to deal with such potential supply disruptions, being located both outside the Persian Gulf and a healthy 160 kilometres away from the Strait of Hormuz.

It was also seen as not aligned to any possibly pro-Iranian country, such as Oman, which at that time was considering plans with Iran to co-operate in Tehran’s build-out of a world-class liquefied natural gas (LNG) sector.

An additional advantage that Fujairah offered in that 2011/2012 analysis was that it affords international oil companies the facility to do business in the same generally transparent and non-corrupt legal framework found across the UAE. 

Various stages of Fujairah’s expansion plans were subject to delays prior to the onset of the major downturn in global oil prices in 2020, due to lower forward oil prices making hydrocarbons storage a less attractive option.

However, each element of the project to make Fujairah the pre-eminent Middle Eastern storage hub – termed ‘Black Pearl’ – gradually came into line. The pace of this picked up after the 380 kilometre Abu Dhabi Crude Oil Pipeline from the Habshan onshore field in Abu Dhabi to Fujairah city became operational in June 2012, capable of transporting 1.8 million bpd and allowing for the smooth movement of UAE crude to the global market. 

At that time, Fujairah also expedited the rolling out of a wide range of the corollary services required in a global storage hub. These included facilities for the loading and discharge of partially laden very large crude carriers (VLCCs) for crude oil and refined products, the blending of crude oil, fuel oil and clean products, the storage and supply of bunker fuel, and inter- and intra-tank cargo transfer.

Within a relatively short time, the Fujairah port’s jetties had the capacity to accommodate both small barge vessels – 3000 deadweight tonnage (DWT) – and the larger VLCCs (up to 300,000 DWT).

In 2015, Vopak Horizon Fujairah also announced that it was building five crude oil storage tanks with total capacity of 478,000 cubic metres at the port and intended to expand that number. 

Part of the positive backdrop for the continued expansion of the Fujairah hub was always expected to be the trade flows coming out of the Dubai Multi-Commodities Centre, with more storage capacity allowing traders greater flexibility in their deals, and a very supportive financial infrastructure created by the Fujairah authorities.

This proved to be the case and Fujairah further stands to benefit from the ongoing rise in volumes traded over the recently established Abu Dhabi-based ICE Futures Abu Dhabi (IFAD), with its focus on the trading of futures contracts for the light, sweet Murban crude oil that constituted around half of the UAE’s total near-4 million bpd crude oil production before the outbreak of the COVID-19 pandemic in 2020.

OilPrice by Simon Watkins, February 9, 2022

Investments in renewables-based electricity networks and technologies like carbon capture, utilisation and storage (CCUS) are needed this decade to accelerate China’s energy transition and put the country on course to reach carbon neutrality by 2060, Shell said.

A new report by the company, Achieving a carbon-neutral energy system in China by 2060, lays out a pathway to achieve net-zero emissions from energy production and use. In this scenario, Shell sees the share of electricity in China’s total energy consumption rising to almost 60pc in 2060 from 23pc today, with sectors such as buildings and passenger road transport largely electrified.

China is the world’s largest consumer of coal, which currently accounts for 60pc of its power use. A power crisis late in 2021 has prompted Beijing to plan a steadier energy transition and avoid abrupt coal plant closures that could threaten its energy security.

Shell recommends investing in flexible low-carbon sources of power generation, large-scale energy storage, and transmission network reinforcement and interconnections to manage demand fluctuations and ensure stable supply. Electricity market structures must also be improved to manage intermittency in a high-renewables power system, the report said.

Electricity demand is likely to be driven by the need for green hydrogen produced by electrolysis using renewable power. Hydrogen scales up from negligible levels today to more than 17 exajoule/yr by 2060, equivalent to 580mn t of coal equivalent, or 16pc of final energy consumption.

Hydrogen will mainly be used in sectors such as heavy industry, road transport, short-haul aviation and shipping, and more than 85pc of it will be green hydrogen produced from electrolysis. Hydrogen alone will add 25pc to electricity demand by 2060, so China’s electricity system needs to be scaled up to almost four times its current size, Shell said.

China is the world’s largest hydrogen producer. But most of it is brown hydrogen produced from fossil fuels, with coal accounting for 62pc of feedstock compared with 18pc globally. Only 4pc of China’s hydrogen uses renewable-based electricity. China produced over 21mn t of hydrogen in 2019, out of 70mn t produced globally.

Shell also sees electricity generated from biomass, combined with CCUS, providing a source of negative emissions for the energy system from 2053 onwards.

Carbon capture

Scaling up CCUS is key to carbon neutrality, with Shell seeing it as a way of keeping Chinese coal-fired power plants in operation.

Integrating a CCUS system into the coal-fired power and industrial sector can reduce emissions without the need to retire these facilities, Shell said. China has great geological potential for CCUS, with an estimated storage capacity of 2.4 trillion t. The country currently has more than 40 CCUS pilot projects with a total capacity of 3mn t. Under Shell’s net zero scenario, CCUS capacity needs to increase by more than 400 times in the next 40 years.

A carbon pricing mechanism is also needed for China to achieve net-zero emissions by 2060, Shell said. China already has an emissions trading scheme (ETS), covering 4.5bn t/yr of CO2 across around 2,200 coal- and gas-fired power plants. China expects all eight key emissions-intensive sectors such as steel, petrochemicals, non-ferrous metal and aviation to be included in the national ETS by 2025.

Shell estimates these steps will require investments of around $12.5 trillion in the next 40 years, with more than half of this required in the next two decades. But an enhanced energy system with the required flexibility could bring about net savings of up to $132bn/yr by 2050, with electricity prices reduced by up to 18pc on lower capital costs and declining solar and wind capacity installation costs.

Argus Media by Prethika Nair, January 31, 2022

We are halfway through the first month of the new year, and oil’s bull run is showing no signs of slowing. Oil futures have vaulted 12% in the first two trading weeks of the new year, boosted by several catalysts, including supply constraints, worries of a Russian attack on neighboring Ukraine, and growing signs the Omicron variant won’t be as disruptive as feared.

Brent crude futures settled $1.59, or 1.9%, higher in Friday’s session at a 2-1/2-month high of $86.06 a barrel, gaining 5.4% in the week, while U.S. West Texas Intermediate crude gained $1.70, or 2.1%, to $83.82 per barrel, rising 6.3% in the week. Both Brent and WTI futures have now entered overbought territory for the first time since late October.

“People looking at the big picture realize that the global supply versus demand situation is very tight and that’s giving the market a solid boost,” Phil Flynn, senior analyst at Price Futures Group, has told Reuters.

“When you consider that OPEC+ is still nowhere near pumping to its overall quota, this narrowing cushion could turn out to be the most bullish factor for oil prices over the coming months,” PVM analyst Stephen Brennock has said.

Indeed, several banks have forecast oil prices of $100 a barrel this year, with demand expected to outstrip supply, thanks in large part to OPEC’s limited capacity.

Morgan Stanley predicts that Brent crude will hit $90 a barrel in the third quarter of this year, while JPMorgan has forecast oil to hit $125 a barrel this year and $150 in 2023. Meanwhile, Rystad Energy’s senior vice-president of analysis, Claudio Galimberti, says if OPEC was disciplined and wanted to keep the market tight, it could boost prices to $100.

OPEC+ has lately come under pressure to ramp up production at a faster clip from several quarters, including the Biden administration so as to ease supply shortages and rein in spiraling oil prices. But the organization is scared of spoiling the oil price party by making any sudden or big moves with last year’s oil price collapse still fresh on its mind.

But maybe we have been overestimating how much power the cartel has to jack up production on the fly.

According to a recent report, at the moment, just a handful of OPEC members are capable of meeting higher production quotas compared to their current clips.

Amrita Sen of Energy Aspects has told Reuters that only Saudi Arabia, the United Arab Emirates, Kuwait, Iraq, and Azerbaijan are in a position to boost their production to meet set OPEC quotas, while the other eight members are likely to struggle due to sharp declines in production and years of underinvestment.

Underinvestments stalling recovery

According to the report, Africa’s oil giants Nigeria and Angola are the hardest hit, with the pair having pumped an average of 276kbpd below their quotas for more than a year now.

The two nations have a combined OPEC quota of 2.83 million bpd according to Refinitiv data, but Nigeria has failed to meet its quota since July last year and Angola since September 2020.

In Nigeria, five onshore export terminals run by oil majors with an average production clip of 900,000 bpd handled 20% less oil in July than the same time last year despite relaxed quotas. The declines are due to lower production from all the onshore fields that feed the five terminals.

In fact, only French oil major TotalEnergies‘(NYSE:TTE) new deep offshore oilfield and export terminal Egina has been able to quickly ramp up production. Turning the taps back on has been proving to be a bigger challenge than earlier thought due to a shortage of workers, huge maintenance backlogs, and tight cash flows.

Indeed, it could take at least two quarters before most companies can work through their maintenance backlogs which cover everything from servicing wells to replacing valves, pumps, and pipeline sections. Many companies have also fallen behind on plans to do supplementary drilling to keep production stable. 

Angola has not been faring any better.

In June, Angola’s oil minister, Diamantino Azevedo, lowered its targeted oil output for 2021 to 1.19 million bpd, citing production declines at mature fields, drilling delays due to COVID-19 and “technical and financial challenges” in deepwater oil exploration. That’s nearly 11% below its 1.33 million bpd OPEC quota and a far cry from its record peak above 1.8 million bpd in 2008.

The southern African nation has struggled for years as its oil fields steadily declined while exploration and drilling budgets failed to keep up. Angola’s largest fields began production about two decades ago, and many are now past their peaks. Two years ago, the country adopted a string of reforms aimed at boosting exploration, including allowing companies to produce from marginal fields adjacent to those they already operate. Unfortunately, the pandemic has stunted the impact of those reforms, and not a single drilling rig was operational in the country by May, the first time this has happened in 40 years.

So far, just three offshore rigs have resumed work.

Shale decline

But it’s not just OPEC producers that are struggling to boost oil production.

In an excellent op/ed, vice chairman of IHS Markit Dan Yergin observes that it’s almost inevitable that shale output will go in reverse and decline thanks to drastic cutbacks in investment and only later recover at a slow pace. Shale oil wells decline at an exceptionally fast clip and therefore require constant drilling to replenish lost supply. 

Indeed, Norway-based energy consultancy Rystad Energy recently warned that Big Oil could see its proven reserves run out in less than 15 years, thanks to produced volumes not being fully replaced with new discoveries.

According to Rystad, proven oil and gas reserves by the so-called Big Oil companies, namely ExxonMobil, BP Plc. (NYSE:BP), Shell (NYSE:RDS.A), Chevron (NYSE:CVX), TotalEnergies SE (NYSE:TTE), and Eni S.p.A (NYSE:E) are all falling, as produced volumes are not being fully replaced with new discoveries.

Granted, this is more of a long-term problem whose effects might not be felt soon. However, with the rising sentiment against oil and gas investments, it’s going to be hard to change this trend.

Experts are warning that the fossil fuel sector could remain depressed thanks to a big nemesis: the trillion-dollar ESG megatrend. There’s growing evidence that companies with low ESG scores are paying the price and are increasingly being shunned by the investing community.

According to Morningstar research, ESG investments hit a record $1.65 trillion in 2020, with the world’s largest fund manager, BlackRock Inc. (NYSE:BLK), with  $9 trillion in assets under management (AUM), throwing its weight behind ESG and oil and gas divestitures.

Michael Shaoul, Chairman and Chief Executive Officer of Marketfield Asset Management, has told Bloomberg TV that ESG is largely responsible for lagging oil and gas investments:

“Energy equities are nowhere close to where they were in 2014 when crude oil prices were at current levels. There are a couple very good reasons for that. One is it’s been a terrible place to be for a decade. And the other reason is the ESG pressures that a lot of institutional managers are on lead them to want to underplay investment in a lot of these areas.”

In fact, U.S. shale companies are now facing a real dilemma after disavowing new drilling and prioritizing dividends and debt paydowns, yet their inventories of productive wells continue falling off a cliff.

According to the U.S. Energy Information Administration, the United States had 5,957 drilled but uncompleted wells (DUCs) in July 2021, the lowest for any month since November 2017 from nearly 8,900 at its 2019 peak. At this rate, shale producers will have to sharply ramp up the drilling of new wells just to maintain the current production clip.

If we need any more proof that shale drillers are sticking to their newfound psychology of discipline, there is recent data from the EIA. That data shows a sharp decline in DUCs in most major U.S. onshore oil-producing regions. This, in turn, points to more well completions but less new well drilling activity. It’s true that higher completion rates have been leading to an uptick in oil production, particularly in the Permian; however, those completions have sharply lowered DUC inventories, which could limit oil production growth in the United States in the coming months.

That also means that spending will have to increase if we are to see shale keep pace with production declines. More will have to come online, and that means more money.

Crude oil has already gained 10 percent since the start of the year and has further to go, Vitol’s head of Asia told Bloomberg in an interview.

“These prices are justified,” said Mike Muller. “Strong backwardation is very much justified.”

The executive added that unlike natural gas, whose high price has already prompted lower consumption for some industrial users, oil has yet to reach that price level.

The latest in the gas sector “serves to remind us that people will abstain from buying expensive energy at some point,” Muller said at an industry webinar, adding, “The question is at what point that affects the oil market.”

Crude oil prices have posted four consecutive weeks of gains, which is the longest winning streak since October, in evidence that the demand recovery remains robust as fears about the effect of Omicron die down.

News that China will release oil from its strategic reserve next month had the potential to disrupt the rally but did not, with Brent crude reaching a two-month high last week and trading at over $86 per barrel at the time of writing. WTI was trading at over $84 per barrel.

“People looking at the big picture realize that global supply versus demand situation is very tight and that’s giving the market a solid boost,” Phil Flynn, Price Futures Group senior analyst, told Reuters last week.

Meanwhile, according to Vitol’s Muller, the White House may decide to release more crude oil from the strategic petroleum reserve, on top of the 50 million barrels announced in November last year.

“The market’s saying: ‘More, please,'” Muller said, as quoted by Bloomberg.

According to traders that Reuters interviewed, there is a strong appetite for future oil supply ahead of spring and summer, otherwise known as driving season in the northern hemisphere. There is also an element of anticipation of even tighter supply.

“With spring and summer on the horizon … people are getting prepared to enjoy a strong market,” one trader said.

“I think it’s more trying to get ahead of tightness they think is coming … back to a ‘herd of lemmings’ market dynamic,” said another.

OilPrice by Irina Slav, January 25, 2022

Kinder Morgan has an impressive portfolio of difficult to replace assets spanning tens of thousands of miles.

The company had strong 4Q earnings, proving a unique ability to generate substantial DCF even without the market fluctuations earlier in the year.

The company is planning roughly 8% in direct shareholder rewards through dividends plus share repurchases.

Additionally, the company is spending 3% on growth, showing continued investments in its businesses.The company’s debt is manageable and below the company’s target ranges.

I do much more than just articles at The Energy Forum: Members get access to model portfolios, regular updates, a chat room, and more.

Kinder Morgan (NYSE:KMI) is one of the largest energy infrastructure companies with a market capitalization of more than $40 billion. The company announced strong earnings to close out 2021, and, as we’ll see throughout this article, should perform well throughout 2022 generating strong shareholder returns for investors.

Kinder Morgan Overview

As oil and natural gas infrastructure gets harder to approve, Kinder Morgan’s asset portfolio gets harder to replace.

The company has spent decades building an unparalleled asset footprint. The company has ~70 thousand miles of natural gas pipelines and ~700 bcf of working storage capacity. The company has ~1200 miles of NGL pipelines and is the largest independent transporter of refined products with 1.7 million barrels and 6800 miles of pipelines.

The company is also the largest CO2 transporter and independent terminal operator. The company’s assets are incredibly well distributed and difficult to replace and essential to our modern standard of living.

Kinder Morgan 4Q 2021 Results

The company has turned this asset portfolio into strong 4Q 2021 results for shareholders.

The company earned $1.1 billion in DCF for the quarter, annualized at $4.4 billion. It was a weaker quarter YoY, however, overall, the company is near its 2022 forecast. Additionally, the company is still performing well even outside of its incredibly strong 1Q 2021 performance showing it can sustainability generate strong FCF.

The company’s strength is evidenced through its ability to continue investing in discretionary capital on top of maintenance capital. That’s on top of high single-digit direct shareholder rewards. The company’s results show the continued ability for reliable cash flow and performance from its assets.

Kinder Morgan 2022 Forecast

At the same time, the company has a strong forecast for 2022 which we expect it’ll be able to meet.

Kinder Morgan 2022 Forecast – Kinder Morgan Press Release

Kinder Morgan has a strong outlook for 2022 that we expect will support substantial shareholder returns. The company expects dividends of $1.11 / share (a roughly 6.4% yield) and 2022 DCF of $4.7 billion. The company expects to end with a net debt to EBITDA ratio of roughly $31 billion in long-term debt versus its $40 billion market capitalization.

The company’s expected 2022 DCF of $4.7 billion is a 12% DCF yield, where the company is paying out just over 50% to shareholders. That leaves shareholders with more than $2 billion that the company can use in a variety of ways. The company is spending $1.3 billion in discretionary capital which is a 3% growth spending ratio.

Combined that’s $0.7 left. That lines up with an expected $750 million in share buybacks, or an almost 2% share buyback yield. That means 8% direct shareholder returns and 3% in additional shareholder returns. The company is aiming to keep its debt constant since it’s already below the company’s ratio.

Kinder Morgan Shareholder Returns

Kinder Morgan is focused on strong shareholder returns for the long run.

The company is committed to its dividend which it’s been slowly growing at several % annualized. The company’s dividend for 2022 is expected to be roughly 6.5% showing a direct commitment to substantial cash returns to shareholders. It’s a dividend that the company can comfortably afford with its payout ratio at roughly 55%.

Additionally, the company is continuing to invest in buybacks. It’s planning to buy back $750 million in shares or almost 2%, that’ll save the company $45 million in annual dividends and enable continued overall high single-digit shareholder returns. This capital return strategy is enough to generate substantial shareholder rewards by itself at ~8-8.5%.

Lastly, the company is continuing to spend on growth. The company has $1.3 billion in planned 2022 growth spending, which should generate a double-digit return on capital, and we expect it to continue investing heavily in growth. That spending highlights how Kinder Morgan is a valuable investment for shareholders to pay attention to.

Kinder Morgan Risk

Kinder Morgan’s risk is a long-term decline in volumes. So far, there’s been no sign of that happening, and we see the company has been fairly isolated from that. However, as natural gas and oil are increasingly replaced by other sources of fuel, there’ll be less demand for the company’s assets which could hurt its ability to generate shareholder returns decades from now.

Conclusion

Kinder Morgan has a unique portfolio of assets supporting its $40 billion market capitalization and $70 billion enterprise value. The company had abnormally strong results in early-2021, as a result of Winter Storm Uri. However, through the rest of the year, the company proved an ability to generate strong results in a normal market.

The company is committing to a roughly 6.5% dividend yield and an almost 2% share buyback meaning direct shareholder returns in the high single digits. Additionally, the company is planning to spend several % on growth spending showing continued opportunities and a unique ability to continue generating shareholder rewards.

All of this makes Kinder Morgan a valuable investment.

The Energy Forum helps you invest in energy, generating strong income and returns from a volatile sector. Our included Income Portfolio helps you invest in the broader market, finding high-yield non sector-specific opportunities.

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By SeekingAlpha, January 24, 2022

USD Partners LP (NYSE:USDP) (the “Partnership”) announced it has entered into a five-year Terminal Services Agreement with a minimum monthly throughput commitment with a major ethanol producer at its West Colton, CA terminal, effective January 1, 2022.

This contract replaces an existing short-term contract at the terminal and is expected to add incremental Net Cash from Operating Activities and Adjusted EBITDA of approximately $1.0 million to $1.5 million per year, subject to changes in expected throughput.

Additionally, the Partnership has commenced renewable diesel operations at its West Colton Terminal and the previously announced five-year Terminal Services Agreement with USD Clean Fuels LLC (“USDCF”) became effective December 1, 2021.

As previously stated, this agreement is supported by a minimum throughput commitment to USDCF from an investment-grade rated, refining customer as well as a performance guaranty from US Development Group, LLC, the Partnership’s sponsor.

“We are excited to announce this renewed long-term partnership at our West Colton Terminal. We believe the extended contract term, combined with the expansion and long-term commitment in renewable diesel handling, speaks to our strategically advantaged portfolio of assets,” said Brad Sanders, Executive Vice President and Chief Commercial Officer for USD.

“We are committed to the transition into sustainable fuels and see our USD Clean Fuels business as a strong growth platform for USD and potentially, the Partnership. We look forward to future announcements of continued growth within clean fuels.”

About USD Partners LP

USD Partners LP is a fee-based, growth-oriented master limited partnership formed in 2014 by US Development Group, LLC (“USD”) to acquire, develop and operate midstream infrastructure and complementary logistics solutions for crude oil, biofuels and other energy-related products.

The Partnership generates substantially all of its operating cash flows from multi-year, take-or-pay contracts with primarily investment grade customers, including major integrated oil companies and refiners.

The Partnership’s principal assets include a network of crude oil terminals that facilitate the transportation of heavy crude oil from Western Canada to key demand centers across North America. The Partnership’s operations include railcar loading and unloading, storage and blending in on-site tanks, inbound and outbound pipeline connectivity, truck transloading, as well as other related logistics services. In addition, the Partnership provides customers with leased railcars and fleet services to facilitate the transportation of liquid hydrocarbons and biofuels by rail.

About USD

USD and its affiliates, which own the general partner of USD Partners LP, are engaged in designing, developing, owning, and managing large-scale multi-modal logistics centers and energy-related infrastructure across North America. USD solutions create flexible market access for customers in significant growth areas and key demand centers, including Western Canada, the U.S. Gulf Coast and Mexico. Among other projects, USD is currently pursuing the development of a premier energy logistics terminal on the Houston Ship Channel with capacity for substantial tank storage, multiple docks (including barge and deepwater), inbound and outbound pipeline connectivity, as well as a rail terminal with unit train capabilities.

Adjusted EBITDA

The Partnership defines Adjusted EBITDA as Net Cash Provided by Operating Activities adjusted for changes in working capital items, interest, income taxes, foreign currency transaction gains and losses, and other items which do not affect the underlying cash flows produced by the Partnership’s businesses.

Adjusted EBITDA is a non-GAAP, supplemental financial measure used by management and external users of the Partnership’s financial statements, such as investors and commercial banks, to assess:

the Partnership’s liquidity and the ability of the Partnership’s businesses to produce sufficient cash flows to make distributions to the Partnership’s unitholders; and

the Partnership’s ability to incur and service debt and fund capital expenditures.

The Partnership believes that the presentation of Adjusted EBITDA in this press release provides information that enhances an investor’s understanding of the Partnership’s ability to generate cash for payment of distributions and other purposes.

The GAAP measure most directly comparable to Adjusted EBITDA is Net Cash Provided by Operating Activities. Adjusted EBITDA should not be considered an alternative to Net Cash Provided by Operating Activities or any other measure of liquidity presented in accordance with GAAP. Adjusted EBITDA exclude some, but not all, items that affect Net Cash Provided by Operating Activities and this measure may vary among other companies.

Due to the uncertainty and inherent difficulty of predicting the occurrence and future impact of certain items, which could be significant, the Partnership is unable to provide a quantitative reconciliation of the estimated Adjusted EBITDA contribution from the agreement to Net Cash Provided by Operating Activities.

Cautionary Note Regarding Forward-Looking Statements

This press release contains forward-looking statements within the meaning of U.S. federal securities laws, including statements with respect to the Net Cash from Operating Activities and Adjusted EBITDA impact of the agreement and the ability of the Partnership and USD to achieve growth in its clean fuels business. Words and phrases such as “expect,” “progressing on,” “plan,” “intent,” “believes,” “projects,” “begin,” “anticipates,” “subject to” and similar expressions are used to identify such forward-looking statements.

However, the absence of these words does not mean that a statement is not forward-looking. Forward-looking statements relating to the Partnership are based on management’s expectations, estimates and projections about the Partnership, its interests, USD’s projects and the energy industry in general on the date this press release was issued.

These statements are not guarantees of future performance and involve certain risks, uncertainties and assumptions that are difficult to predict. Therefore, actual outcomes and results may differ materially from what is expressed or forecast in such forward-looking statements.

Factors that could cause actual results or events to differ materially from those described in the forward-looking statements include the impact of the novel coronavirus (COVID-19) pandemic and related economic impact and changes in general economic conditions and commodity prices, as well as those factors set forth under the heading “Risk Factors” and elsewhere in the Partnership’s most recent Annual Report on Form 10-K and in the Partnership’s subsequent filings with the Securities and Exchange Commission (many of which may be amplified by the COVID-19 pandemic and the significant volatility in demand for, and fluctuations in the prices of, crude oil, natural gas and natural gas liquids).

The Partnership is under no obligation (and expressly disclaims any such obligation) to update or alter its forward-looking statements, whether as a result of new information, future events or otherwise, except as required by law.

By YahooFinance, January 24, 2022

Refinery closures outweighed new capacity in 2021, leading to a drop in global capacity for the first time in 30 years, the International Energy Agency said in its latest monthly report Jan. 19.

Global capacity fell by 730,000 b/d last year as close to 1.6 million b/d was shut or converted into bio-refineries and only 850,000 b/d new capacity came online.

For 2022 the IEA forecasts 1.2 million b/d of new additions, while runs will rise by 3.7 million b/d to 81.2 million b/d.

However, the reduced capacity last year led to improved refining margins, which “reached multi-year highs in Singapore and Europe at the end of 2021.”

Last year thus ended “on a high note” for the global refining industry, the IEA said, as both runs and margins improved “amid continuously tight product markets” in the last quarter of the year.

Overall, 2021 gained 4.9 million b/d in terms of global refinery crude throughput to 80.2 million b/d.

The IEA revised upwards its November global refinery crude throughput estimates by almost 1 million b/d to 80.8 million b/d “on stronger-than-expected activity in China, India and Europe.” However, December runs are likely to ease by 500,000 b/d to 80.3 million b/d as refineries in China reduce their processing.

Although runs increased in the fourth quarter, the agency estimated an “implied draw” of 1.3 million b/d in refined products as the increase was from a “low base” in the third quarter.

However, new additions in 2022 and the subsequent increase of global runs could outpace the demand growth for refined products, “possibly leading to an unwinding of some of the refinery margin gains from late last year,” it said

New additions, closures

New capacity is already coming up in China, according to S&P Global Platts data. China’s privately held refining complex Shenghong Petrochemical is likely to start to feed crudes into its newly built 16 million mt/year crude distillation unit at the end of January. The refinery had initially planned to start up at the end of August.

Private refiner Zhejiang Petroleum & Chemical fully started up commercial operations at it 400,000 b/d phase 2 refining and petrochemical project in early January.

Elsewhere in Asia-Pacific, Pengerang Refining and Petrochemical integrated complex, also known as PRefChem, is expected to resume operations in the second quarter, possibly in May, after previously planning a 2021 restart. The refinery, also known as RAPID refinery, delayed its restart several times following a fire that broke out at the diesel unit in March 2020.

Nigeria’s Dangote refinery is on track to be operational from early this year despite some delays caused by shipping constraints.

Two new additions in the Middle East — Saudi Arabia’s Jazan and Kuwait’s Al-Zour — appear to be on track for a full start in 2022.

In January, Iran launched the first phase of a 70,000 b/d extra heavy crude plant on Qeshm island in the Persian Gulf.

The new capacities follow a spate of closures or capacity reductions and conversions in 2020 and 2021.

Gunvor mothballed its Antwerp refinery and shuttered the two crude processing units at Rotterdam.

Petroineos’ Grangemouth refinery in Scotland saw its capacity reduced by 30% to around 150,000 b/d after the closure of a CDU and the FCC.

TotalEnergies’ Grandpuits stopped crude processing in early 2021, ahead of conversion, while Portugal’s Porto and Finland’s Naantali also halted crude processing early last year and Norway’s Slagen in mid-2021.

Australia is now left with only two refineries after the closure of Altona and Kwinana, while New Zealand will see its only refinery Marsden Point convert into an import terminal from April.

In the Philippines, Tabanagao refinery was shut in 2020 and converted into a terminal.

Similarly in South Africa, Engen’s Durban refinery has been offline throughout 2021 to be converted into a terminal.

However, in 2022 another refinery in South Africa, Astron Energy’s Cape Town, is expected to restart.

Meanwhile, a number of refineries in North America, including Cheyenne, Rodeo, Martinez are converting into bio-refineries.

S&P Global by Elza Turner

Norway is determined to squeeze every last drop of oil from its continental shelf as it attempts to keep up with the growing demand for crude

Despite being a leading player in the renewable energy sector, Norway has made it clear that oil and gas will be vital in driving the energy transition

Equinor has already announced that it will be drilling around 25 exploration wells in Norwegian waters this year and has already announced its first discovery this year.

Norway’s oil majors as well as the country’s government and oil regulator hope to get every last drop of oil out of the North Sea before global demand eventually wanes. Continuing with its plan to run low-carbon oil operations worldwide for decades to come, while also focusing on developing its clean energy sector, Norway is making more oil discoveries and expects to maintain, or even increase, output so long as demand remains high.  In December last year, Equinor announced it would be drilling around 25 exploration wells in Norwegian waters throughout 2022, in a bid to find more oil. The oil major intends to continue drilling for crude in Europe’s biggest oil and gas producing country, as other companies transition away from fossil fuels. 

Jez Averty, Equinor’s senior vice president for subsurface stated of the major’s strategy, “Our plan, basically, is to make sure that the Norwegian continental shelf has the last drops, the last molecules, the last barrels to survive in that competition.”

Despite the potential for Norway to be a leader in the move away from oil and gas, thanks to its existing oil wealth and early adoption of renewable energy technologies, the government continues to back fossil fuels. It is one of the European countries, along with Russia, that has supported the rest of the continent by supplying natural gas during a time of severe shortages. In addition, it sees LNG as the low-carbon fossil fuel needed to meet global energy demand until alternatives are more widely available. 

Equinor believes it can help bridge the gap until enough renewable energy output is available by producing low-carbon oil. It hopes to achieve this by incorporating carbon capture and storage technologies into its projects as well as through the electrification of platforms from onshore hydropower. In addition, Equinor has already moved away from more carbon-intensive ventures, shifting operations to parts of the world where it can create and build new low-carbon markets.

The new Labour Party-led coalition government hopes to decrease net carbon emissions by 55 percent by 2030, from 1990 levels. Yet it has made its stance on oil and gas clear, backing long-term production. This is not surprising considering the petroleum sector continues to contribute around 40 percent of the country’s exports and 14 percent of its GDP. The government does intend to raise carbon taxes on the oil industry in order to counteract emissions, increasing the rate to $230 per tonne.

This January, Equinor announced its first oil discovery of the new year along with partner Wellesley. Preliminary studies suggest a potential 33 million barrels of recoverable oil equivalent in the Troll and Farm area of the Toppand prospect. The firm has made several discoveries in this region in recent years, suggesting that mature areas have the potential to be rejuvenated thanks to modern exploration technologies.

Geir Sortveit, senior vice president for exploration and production west operations at Equinor, stated, “We are pleased to see that our success in the Troll- and Fram area continues. We also regard this discovery to be commercially viable and will consider tying it to the Troll B or Troll C platform.” Further, “Such discoveries close to existing infrastructure are characterized by high profitability, a short payback period and low CO2 emissions,” he explained.

Norway’s oil regulator, the Norwegian Petroleum Directorate (NPD), plans to support the ongoing development of the sector by encouraging the greater use of data across operations.

As a data manager, it believes using data will help add value to the sector. The NPD intends to gain a better understanding of what is most important for oil companies looking forward and then collect the relevant data. Compiling data sets from across the sector could help streamline future energy projects. The regulator is planning to hold a workshop with representatives from across the oil industry on January 21, 2022, including service providers, academia, and related parties, to begin the process.  

May Karin Mannes, the NPD’s Director for shelf analyses and data management explains, “having the right data available at the right time and in the right format can have a huge impact for the future of the Norwegian shelf.” 

Oil firms, the Norwegian government, and the country’s oil regulator appear to be working hand-in-hand in an effort to prolong the shelf-life of Norway’s crude, while at the same time adding greater value to the sector and reducing carbon emissions – the triple whammy. Despite criticism over its long-term oil strategy, if Norway is successful in its aims, it could establish a flourishing green energy sector from its oil revenues and taxes while continuing to meet the global oil demand with low-carbon options. 

Oilprice by Felicity Bradstock, January 18, 2022