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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.

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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.

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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

The European gas crunch has been hogging headlines for months now, and with good reason – the continent is still struggling to secure enough energy for its winter needs. But there may be a worse crunch looming over the world, and that would be an oil crunch.

The signs are there for everyone to see should they bother to look: OPEC’s spare capacity is dwindling, new discoveries are at historic lows, and banks are growing increasingly reluctant to engage with the oil and gas industry because of the rise of ESG investing.

Meanwhile, supermajors are curbing their output as they focus on growing their low-carbon business.

A capacity crisis?

“Shrinking global spare capacity underscores the need for increased investments to meet demand further down the road,” the International Energy Agency said in its October 2021 Oil Market Report, after noting that as OPEC ramped up production under its return-to-normal deal, its spare production capacity will fall considerably, potentially reaching just 4 million bpd by the fourth quarter of this year. That would be down by more than half from 9 million bpd at the start of 2021.

Spare capacity is an important indicator of production flexibility in the oil world. The IEA defines it as production that can be launched within 90 days and sustained over an extended period of time. The U.S. Department of Energy defines spare capacity as production that can be tapped within 30 days and sustained for 90 days. According to the EIA, OPEC’s spare capacity could fall to 5.11 million bpd by the end of this year.

The IEA does not seem to be sure what it wants – more investments in oil or more investments in renewable energy. It called for both on different occasions last year. But based on oil price developments, it seems the shrinking spare capacity of the world’s oil cartel is indeed a cause for concern despite the planned shift to low-carbon energy.

What fuels this concern even further is that some members of the extended cartel OPEC+ are nearing the limit of their spare capacity, and Russia is among them. One of the world’s top producers, according to reports, is finding it difficult to return production to pre-pandemic levels at a time when other OPEC+ members are dealing with the same problem. This means that even if demand continues to grow at the current solid rate, supply may not be as quick to catch up.

Wanted: new oil discoveries

New oil and gas discoveries may have hit their lowest level in 75 years, Norwegian energy consultancy said in a December report. Total newly discovered resources last year stood at some 4.7 billion barrels of oil equivalent, which was down from 12.5 billion barrels of oil equivalent discovered during the first pandemic year.

At the same time, European supermajors are deliberately reducing their oil production in line with the strategy to move toward renewable energy under pressure from shareholders, activists, and governments. So, on the one hand, we have less money being spent on new supply and on the other, we have a deliberate reduction in existing supply.

The low level of discoveries means that reserve replacement rates have fallen, too, and low reserve replacement rates in the oil and gas industry are bad news for future supply. Saudi Arabia warned last year that underinvestment in new oil production could lead to an energy crisis, but since everyone expects Saudi Arabia to say something like that, not a lot of attention was paid to the warning. And even if it was, boosting the rate of new oil discoveries is not as easy as it once was.

Banks on an ESG rampage

The rise of the ESG investor has made quite a splash in the financial industry. Returns are still a priority, but it is no longer the single ultimate priority. These days, investors want to know that their money is being used in a responsible way, for the good of the planet. And this means that they are increasingly reluctant to see this money going to the oil industry.

Because of this trend, banks and asset managers are rethinking their own business strategies. Asset managers are requiring their clients to make emission reduction commitments, threatening to drop them otherwise. Banks are refusing to lend to the oil industry and also threatening to drop clients that generate a lot of carbon dioxide emissions.

It isn’t just pressure from shareholders that is guiding lenders’ hands. Regulators are also turning up the heat on banks, requiring new risk assessments based on climate change scenarios and tightening capital requirements accordingly. To avoid being hamstrung by regulations, lenders are cutting their exposure to the apocalypse-bringing oil and gas industry.

Meanwhile, demand for oil appears to be as healthy as ever, and oil price forecasts are pointing to a solid upward potential. The thing that oil bears who cite the energy transition as the reason for their bearishness seem to be forgetting is that it will take a lot more than a couple of years.

It will also be tough, as Oil Price Information Service’s Tom Cloza wrote in an opinion piece for CNN. 

“Once we really start moving away from fossil fuels, it will be expensive and painful. To deny that expense is as disingenuous as denying climate change,” Cloza wrote. To argue with this and with the fact that we will continue needing millions upon millions of barrels of oil for the observable future would be a waste of time.

Oilprice by Irina Slav, January 18, 2022

In 2020, as the coronavirus locked down country after country, many energy industry observers and even participants floated the argument that this was the end of the oil era. Demand, these commentators said, had peaked. From now on, it will be a downward spiral for it, they said. These predictions did not age well.

Just a year into the pandemic, economies were reopening, growing, and unsurprisingly for many, consuming more crude oil. Last September, Bloomberg reported that some of the world’s biggest economies had seen a rebound in oil demand to pre-pandemic levels and even further growth on top of these levels.

Now, two years into the pandemic and with hopes it could be the last one for infection waves, oil demand is still going strong despite the fresh scare of the Omicron variant. Analysts are predicting higher oil prices still, citing limited capacity, insufficient investment in new production, and the strength of demand.

The International Energy Agency this week expressed its surprise with this demand strength. The IEA, it seems, had assumed that for some reason or another, oil demand growth would slow down. Perhaps the assumption had something to do with the agency’s own energy forecasts that see massive growth in wind and solar power generation capacity and a strong increase in EV adoption, with the latter directly affecting oil demand. Yet its assumption proved to be quite wrong.

“Demand dynamics are stronger than many of the market observers had thought, mainly due to the milder Omicron expectations,” the IEA’s chief, Fatih Birol, said this week. Translated, this statement means that the IEA expected more national lockdowns to prevent the spread of the new coronavirus variant. Yet more severe lockdowns were quite unlikely this time around—even the wealthiest economies would find it hard to cope with another shutdown of their economies, so they are approaching this Omicron wave more carefully than previous ones.

“We see some of the key producers including Nigeria, Libya and also Ecuador that have serious supply disruptions,” Birol also said, echoing concern by analysts that the supply side of the global oil equation is as problematic as the demand side. Ecuador is already restoring production after it repaired two important pipelines. Libya continues to be a wild card, and Nigeria is struggling but determined to boost its oil production.

This is the present state of oil fundamentals. The future may look different. For one thing, the underinvestment problem is becoming increasingly grave. Both OPEC and the IEA—the latter which has rebranded itself as a champion of the energy transition—have warned that the world needs more new oil discoveries.

The only reason for this could be that demand is not dying as fast as hoped by all the champions of the energy transition. Yet Big Oil is curbing its oil output because of transition pressure, and this would mean not just fewer new discoveries because of lower investment in exploration but also lower output from some of the biggest producers out there. This would swing the burden of supply more to OPEC+ whose spare capacity is shrinking, just like European Big Oil’s output.

The oil demand outlook appears to be so bullish that even U.S. shale drillers have begun boosting their production despite a pandemic-induced rearrangement of priorities that saw them focus on returning cash to shareholders and forego production growth. With oil exports last year hitting record highs, failing to take advantage of the opportunity to supply a higher portion of the oil an energy-hungry world needs would have been a little odd.

“The consumption of oil and gas has to diminish, demand has to decline,” the IEA’s Birol said earlier this month in comments on a Canada-focused report. “There is no way out. But I wanted to make clear that a declining demand doesn’t mean tomorrow they will be zero.”

The statement echoes one made by President Biden when he was criticized for asking OPEC to pump more oil while at the same time pushing a green transition-heavy agenda at home. Biden argued the two were not mutually exclusive because the transition took time.

“On the surface, it seems like an irony,” Biden said earlier this month, referring to his call on OPEC+ to add more oil production while heading for COP26 to discuss the reduction of global emissions. “But the truth of the matter is … everyone knows that idea that we’re going to be able to move to renewable energy overnight … it’s just not rational.”

Indeed, despite calls from some more radical environmentalist groups to do exactly that, oil and gas production cannot be stopped overnight to ensure a clear path towards the 2050 net-zero goals. But even the decline that the IEA’s Birol correctly sees as essential for the achievement of the Paris Agreement goals might prove a tough nut to crack. Unless, of course, governments resort to a series of bans and mandates to point their citizens in the right direction. Come to think of it, some are already doing just that.

Oilprice by Irina Slav, January 18, 2022

For investors closely watching a key indicator of Saudi Arabia’s financial health, deciphering the ups and downs of its $447 billion foreign-currency reserves has become more about dividends than crude prices.

Sharp increases in the central bank’s net foreign assets now coincide with payouts from state-controlled oil producer Saudi Aramco. Disbursements of the company’s $18.75 billion quarterly dividend, almost all of which goes to the Saudi government, mean the reserves reflect less frequent but larger transfers of cash from the Dhahran-based firm.

Bloomberg by Vivian Nereim, January 13, 2022

The recent talks between Oman’s Assistant to the Chief of Staff for Operations and Planning, Brigadier Abdulaziz Abdullah al-Manthri, and the Chief of Staff of Iranian Armed Forces, Major-General Mohammad Bagheri, may mark a new phase in the already deep and broad relationship between Oman and Iran, and in the Sultanate’s drift into the Iran-China axis.

“The two countries [Iran and Oman] have conducted several joint naval drills in recent years, within the scope of securing the waterway from the Persian Gulf through to the Gulf of Oman from smuggling and other threats, including terrorism, but these [recent] talks were concerned with expanding that cooperation both in terms of the armed services involved beyond just the navy and the scope of their joint activities beyond anti-smuggling and dealing with terrorist threats,” an Iranian source who works closely the Petroleum Ministry told OilPrice.com last week. 

The basic catch-22 for Oman that has expedited its move towards the Iran-China power axis is that it lacks the scale of natural resources to generate the financing required to keep its economy ticking over without any further industry but the industry that it is looking to diversify its economy with – petrochemicals – requires a lot of upfront financing before it pays off.

Consequently, with only around five billion barrels of estimated proved oil reserves (barely the 22nd largest in the world) and minimal natural gas reserves – Oman explored many options to bridge this financing gap but its budget problems were dramatically worsened by the Saudi Arabia-instigated Oil Price Wars of 2014-2016 and 2020. Even before the 2020 attempt by Saudi to severely disable the U.S.’s shale oil sector by using exactly the same strategy that had failed in 2014-2016 and had destroyed the budgets of its OPEC brothers as well, as analyzed in-depth in my new book on the global oil markets, Oman had been facing a budget deficit for that year alone of at least 18 percent of GDP and budget deficits averaging at least 15 percent per year over the next five years. 

In order to give it time to develop its answer to many of its financial problems – the rollout of the perennially-delayed but potentially game-changing Duqm Refinery Project and its corollary projects of a product export terminal in Duqm Port and Duqm refinery-dedicated crude storage tanks in Ras Markaz – Oman tried several options to raise money.

So determined was Oman to keep its fiscal deficit within manageable proportions that not only did it implement measures (including lower expenditure on wages and benefits, subsidies, defense, and capital investment by civil ministries) that reduced expenditure (in 2016 by around 8 percent of GDP) but also moved to rein-in hydrocarbons-related spending as well. In this context, the Sultanate’s Financial Affairs and Energy Resources Council formed a specialized working group to study public spending and the means by which to reduce it.

At the same time, it was made clear that the Omani government would apply zero-based budgeting in the ninth five-year plan of approving allocations for development projects only after all feasibility studies and real cost analysis of each of them had been completed. The Council also underlined that it aimed to avoid having any additional requests for funding from developers after any project had been started. 

However, Oman’s problems relating to the Duqm Refinery Project became worse in 2016 when the UAE’s International Petroleum Investment Company (IPIC) said that the Duqm project no longer fitted its overall investment strategy, in light of the impending merger at the time of IPIC with the Mubadala Development Company, and withdrew from the project.

Although this was followed in November by the signing of a memorandum of understanding between the Oman Oil Company (OOC) and the Kuwait Petroleum Corporation (KPC) for co-operation on the construction of the refinery, OilPrice.com understands that this was not even half of the then-estimated cost of US$6 billion.

Given the negative international credit ratings outlook, and ratings downgrades in previous years, Oman’s options to raise money through conventional bond offerings remained constrained, and so did the appetite of international investors to buy into any part-privatization of any of Oman’s state-owned companies, even the once much-fancied Oman Oil Refineries and Petroleum Industries Company’s (ORPIC).  

It was at this point that China saw its chance to expand its foothold in Oman, which is a key land and maritime hub in Beijing’s multi-generational power-grab project, ‘One Belt, One Road’ (OBOR). Specifically, at around the same time as IPIC withdrew from the project, the refinery operator – the Duqm Refinery & Petrochemical Industries Company (DRPIC) – in tandem with the OOC, appointed a number of global banks, led by regional heavyweight Credit Agricole, to advise on the optimal methods to obtain the funding for the project.

These overtures found particular favor with China, which as part of a broad-based investment into Oman pledged the required funding to cover the completion of the Duqm Refinery. However, it came with the usual Chinese caveats of it being allowed to build massive far-reaching infrastructure projects. 

Already accounting for around 90 percent of Oman’s oil exports and the vast majority of its petrochemicals exports, China was quick to leverage this by further pledging US$10 billion immediately for investment into the Duqm Refinery Project’s adjunct oil refinery – just after the implementation of the nuclear deal with Iran at the beginning of 2016.

At that point, Oman announced that the budget for the Duqm Refinery Project was being increased from the longstanding figure of US$6 billion to a combined US$18 billion for all elements of the Project. This, Oman’s government announced, would enable downstream production to increase from its current 15 million tonnes to 24 million tonnes by 2030, while the commodity sales volumes would nearly double from 21 million tonnes to 40 million tonnes by the same date.

Although further investment from China was geared towards completing the Duqm Refinery – including the export terminal in Duqm Port and the crude storage tanks of the Ras Markaz Oil Storage Park – Chinese money was also funneled towards the construction and building out of an 11.72 square kilometer industrial park in Duqm in three areas – heavy industrial, light industrial, and mixed-use. This has enabled China to secure deeply strategic areas of land in the geopolitically vital Sultanate vitally important Oman, which has long coastlines along the Gulf of Oman and along the Arabian Sea, away from the extremely politically sensitive Strait of Hormuz.

It also offers largely unfettered access to the markets of South Asia, West Asia, and Africa, as well as to those of its neighbors in the Middle East. Following the usual Chinese template of investment, it has also given China the opportunity to populate these areas its own people, from project managers to security personnel.

In line with these developments, the addition of Oman to its Middle East territorial acquisitions means that Beijing can fast-track the transport routes between Iran and Oman.  A long-mooted adjunct to China’s direct plans in this context has been the utilization by Iran of Oman’s unused liquefied natural gas (LNG) capacity.

This plan, long talked about between Tehran and Muscat, is part of Iran’s plans to become an LNG superpower based on its massive South Pars and North Pars non-associated gas fields. Oman for its part would allow Iran to use 25 percent of the Sultanate’s total 1.5 million tons per year LNG production capacity at the Qalhat plant. This could be done as part of a broader plan to build a 192-kilometer section of 36-inch pipeline running along the bed of the Oman Sea at depths of up to 1,340 meters from Mobarak Mount in Iran’s southern Hormuzgan province to Sohar Port in Oman for gas exports.

This, in turn, would re-open the possibilities for further pipeline routes running from Iran to Oman and then into Pakistan and then into China, and the other way around, all under the security protection of China, irrespective of any plans that the U.S. might have in the southern part of the Shia crescent of power in the region, as also analyzed in-depth in my new book.

Oilprice by Simon Watkins, January 11, 2022

The National oil company of Mexico, Pemex, is exporting ~1mb/d of crude oil, with ~60% flowing to the US and gulf-coast refineries, but the current CEO wants to change that.

At a press conference in Mexico City yesterday, CEO Octavio Romero shared plans to cut exports to ~430kb/d in 2022 and eliminate them entirely by 2023, as Pemex refineries ramp up to consume the domestic crude.

The Dos Bocas refinery, a 340kb/d plant currently under construction, will be fully operational in 2023 and account for ~1/3 of increased domestic crude consumption.

The Pemex downstream system processed ~1.2mb/d from 2010-2014 before utilization dropped to as low as 690kb/d in 2020.

Currently processing ~800kb/d, the Pemex system could increase runs ~400kb/d by simply returning existing refineries to historic utilization rates.

Cutting exports by the full 1mb/d appears to be a challenge, as running the legacy system at rates not seen in half a decade, and running the new Dos Bocas refinery at capacity would only reduce exports by ~780kb/d.

Nevertheless, 780kb/d of increase in oil production in Mexico and the Gulf region would cut into share for US Gulf Coast refiners like Valero (NYSE:VLO), Phillips (NYSE:PSX) and Marathon (NYSE:MPC), as well as reducing margins for integrated companies like Exxon (NYSE:XOM) and Chevron (NYSE:CVX).

In addition to cutting into market share, reduced Mexican exports would reduce the supply of heavy crude oil to the Gulf Coast system, leaving US refiners in search of additional heavy barrels from Canada, Venezuela and the Middle East.

Seeking Alpha by Nathan Allen, January 11, 2022