Energy News Beat

Services are big, and that one-month outlier was massive, and it drove down Core CPI and overall CPI.

By Wolf Richter for WOLF STREET.

The Consumer Price Index for May, on a month-to-month basis, was pushed down by the continued sharp drop in durable goods prices, a drop in energy prices, flat food prices, and “core services” prices that rose at the smallest pace since late 2021 in a stunning whiplash-inducing outlier move, according to data from the Bureau of Labor Statistics today. So, we’ll start with that outlier because it’s so big, and because core services are so big — they account for 65% of total CPI — and because that outlier drove everything else.

Stunning outlier: Core services CPI increased by 2.7% annualized in May from April (0.22% not annualized), the smallest increase since October 2021 (blue line). These kinds of outliers don’t make a trend; they’re soon reversed, as all other outliers in core services have shown. This massive one-month outlier drove down the six-month reading.

The six-month core services CPI rose by 5.5% annualized, the first deceleration since October 2023 (red).

Month-to-month core CPI driven down by outlier in services.

Core CPI rose by 2.0% annualized (0.163% not annualized) in May from April, the smallest increase since August 2021 (blue line in the chart below). The month-to-month squiggles can be wild, and this one was driven by the whiplash-inducing outlier in core services CPI.

The six-month core CPI, which irons out most of the month-to-month zigzags, rose by 3.7% annualized, the first deceleration, after five months of accelerations in a row.

Year-over-year CPI measures, summary:

Core services CPI increased by 5.2% year-over-year in May, roughly the same hot pace for the eighth month in a row (red line).

Durable goods CPI – after the spike during the pandemic – has been falling across the board since mid-2022, led by the plunge in used-vehicle prices. In May, durable goods CPI was down 3.8% year-over-year, the biggest drop in 20 years (green).

Core CPI, which excludes food and energy, rose by 3.4% year-over-year, continuing its deceleration, slowed by the sharp drop in durable goods (blue).

Overall CPI rose by 3.3% year-over-year. It has been in essentially the same narrow range since June 2023 when it hit the cycle-low of 3.0% (yellow):

The housing components of core services CPI.

Rent of Primary Residence CPI rose by 4.8% annualized in May from April, an acceleration from the prior month (blue).

The three-month reading rose by 4.7%, the smallest increase since October 2021.

The Rent CPI accounts for 7.6% of overall CPI. It is based on rents that tenants actually paid, not on asking rents of advertised units for rent. The survey follows the same large group of rental houses and apartments over time and tracks the rents that the current tenants actually paid in these units.

The Owners’ Equivalent of Rent CPI rose by 5.3% annualized in May from April, an acceleration from the prior month. It remains in the range of which August 2023 had been the low point (+5.1%).

The three-month OER CPI also rose by 5.3% annualized, roughly the same as in the prior month.

The OER index accounts for 26.6% of overall CPI. It is designed to estimate inflation of “shelter” as a service for homeowners – as a stand-in for the services that homeowners pay for, such as interest, homeowner’s insurance, HOA fees, maintenance, and property taxes. As an approximation, it is based on what a large group of homeowners estimates their home would rent for, the assumption being that a homeowner would want to recoup cost increases by raising the rent.

“Asking rents…” The Zillow Observed Rent Index (ZORI) and other private-sector rent indices track “asking rents,” which are advertised rents of vacant units on the market. Because rentals don’t turn over that much, the ZORI’s spike in 2021 through mid-2022 never fully translated into the CPI indices because not many people actually ended up paying those asking rents.

The ZORI rose by 0.2% in May from April, seasonally adjusted, and by 3.4% year-over-year.

The chart shows the CPI Rent of Primary Residence (blue, left scale) as index value, not percentage change; and the ZORI in dollars (red, right scale). The left and right axes are set so that they both increase each by 55% from January 2017. The ZORI was up by 49% from January 2017, and the CPI Rent was up by 38% over the same period.

Rent inflation vs. home-price inflation: The red line in the chart below represents the CPI for Rent of Primary Residence (actual rents paid by tenants) as index value. The purple line represents the Case-Shiller 20-Cities Home Price Index (see our “Most Splendid Housing Bubbles in America”). Both indexes are set to 100 for January 2000:

Services related to motor vehicles.

Motor-vehicle insurance costs have soared during the pandemic largely because used-vehicle prices have spiked, which translates into higher replacement costs. And motor-vehicle maintenance costs have surged because wages of auto-repair technicians have surged, and because prices of replacement parts have surged.

But that spike during the pandemic seems to be backing off at the moment.

Motor-vehicle insurance CPI:

In May from April annualized: -1.4%
Three-month annualized: +18.3%
Year-over-year: +20.3%
Since January 2022: +46%

Motor-vehicle maintenance CPI 

In May from April annualized: +3.3%
Three-month annualized: +8.3%
Year-over-year: +7.2%
Since January 2020: +35%

Food away from Home CPI – often called food services – includes full-service and limited-service meals and snacks served away from home, food at cafeterias in schools and work sites, food served at stalls, etc.

In May from April annualized: +4.3%
Year-over-year: +4.0%
Since January 2020: +27%

Major Services ex. Energy Services
Weight in CPI
MoM
YoY
Core Services
64%
0.2%
5.2%
Owner’s equivalent of rent
26.6%
0.4%
5.7%
Rent of primary residence
7.6%
0.4%
5.3%
Medical care services & insurance
6.5%
0.3%
3.1%
Food services (food away from home)
5.3%
0.4%
4.0%
Education and communication services
5.0%
0.4%
2.9%
Motor vehicle insurance
2.9%
-0.1%
20.3%
Admission, movies, concerts, sports events, club memberships
1.8%
0.3%
4.7%
Other personal services (dry-cleaning, haircuts, legal services…)
1.5%
-0.3%
4.1%
Lodging away from home, incl Hotels, motels
1.5%
-0.1%
-1.4%
Motor vehicle maintenance & repair
1.2%
0.3%
7.2%
Public transportation (airline fares, etc.)
1.1%
-3.1%
-4.7%
Water, sewer, trash collection services
1.1%
0.1%
4.8%
Video and audio services, cable, streaming
0.9%
-1.3%
2.8%
Pet services, including veterinary
0.4%
0.4%
5.9%
Tenants’ & Household insurance
0.4%
0.5%
4.3%
Car and truck rental
0.1%
-1.2%
-8.8%
Postage & delivery services
0.1%
0.3%
3.8%

Core services price level. Since January 2020, the core services CPI has increased by 21%. The steepness of the curve indicates the rate of inflation.

Durable goods CPI.

The durable goods CPI fell by 5.6% annualized (-0.48% not annualized) in May from April, and by 3.8% year-over-year, as overall price declines accelerated, except in used vehicles.

New and used vehicles dominate this index, which also includes information technology products (computers, smartphones, home network equipment, etc.), appliances, furniture, fixtures, etc. All categories have been experiencing price declines starting in late 2022, after the ridiculous price spike during the pandemic.

From January 2020 to the peak in August 2022, durable goods prices spiked by 23%. Since then, they have dropped by 5%, having unwound only one-quarter of the pandemic spike. Compared to January 2020, the index is still up 18%.

Major durable goods categories
MoM
YoY
Durable goods overall
-0.5%
-3.8%
New vehicles
-0.5%
-0.8%
Used vehicles
0.6%
-9.3%
Information technology (computers, smartphones, etc.)
-1.9%
-8.1%
Sporting goods (bicycles, equipment, etc.)
-0.3%
-0.3%
Household furnishings (furniture, appliances, floor coverings, tools)
0.0%
-2.5%

New vehicles CPI fell 5.8% annualized in May from April (-0.49% not annualized), the fifth month-to-month decline in a row, and the steepest yet. Year-over-year, the index fell by 0.8%.

After a long plateau, prices are now finally heading south, as inventories of new vehicles have built up into what amounts to a glut at many dealers, and automakers are having to offer big incentives and discounts to sell the vehicles.

In the years before the pandemic, the new vehicle CPI zigzagged along a flat line, though vehicles were getting more expensive. This is the effect of “hedonic quality adjustments” applied to the CPIs for new and used vehicles and other products (detailed explanation of hedonic quality adjustments in the CPI).

Used vehicle CPI rose by 7.5% annualized in May from April (+0.60% not annualized), seasonally adjusted (red); not seasonally adjusted (blue), the index rose by 5.8% annualized (+0.47% no annualized).

These price increases in May diverge from wholesale prices that continued to drop in May.

Used vehicle CPI has now given up a big portion of the 53% spike from January 2020 through January 2022, but is still 30% higher than in January 2020.

Food Inflation.

Inflation of “Food at home” – food purchased at stores and markets and eaten off premises – has cooled, with no increase in May from April, and a 1.0% increase year-over-year, after the massive spike during the pandemic.

MoM
YoY
Food at home
0.0%
1.0%
Cereals, breads, bakery products
0.2%
0.7%
Beef and veal
-0.3%
5.7%
Pork
0.9%
2.6%
Poultry
0.4%
1.2%
Fish and seafood
-0.5%
-1.0%
Eggs
-0.4%
3.0%
Dairy and related products
-0.5%
-1.0%
Fresh fruits
0.4%
-0.2%
Fresh vegetables
-0.4%
0.8%
Juices and nonalcoholic drinks
-0.5%
2.0%
Coffee, tea, etc.
-0.6%
-2.5%
Fats and oils
-0.3%
2.2%
Baby food & formula
-1.3%
2.5%
Alcoholic beverages at home
0.2%
1.4%

The CPI for food at home, after the pandemic spike, is up 25% from January 2020. Prices have flattened out, but have not come down.

Energy.

The CPI for energy covers energy products and services that consumers buy and pay for directly:

CPI for Energy, by Category
MoM
YoY
Overall Energy CPI
-2.0%
3.7%
Gasoline
-3.6%
2.2%
Electricity service
-0.2%
4.7%
Utility natural gas to home
-0.8%
0.2%
Heating oil, propane, kerosene, firewood
-1.0%
2.8%

Gasoline prices (account for about half of the energy price index) are very seasonal, with the lowest prices in December or January and the highest prices during driving-season in the summer. Seasonally adjusted prices (red) and not seasonally adjusted prices (blue) declined in May from April:

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The post Beneath the Skin of CPI Inflation: A Stunning Outlier Services CPI Drove Down Everything Else appeared first on Energy News Beat.

Energy News Beat

Higher for longer becomes formalized one meeting at a time, as projections for “longer-run” federal funds rate keep getting raised.

By Wolf Richter for WOLF STREET.

FOMC members voted unanimously today to maintain the Fed’s policy rates unchanged, as Fed governors have uniformly telegraphed in their speeches:

Federal funds rate target range: 5.25% – 5.5%.
Interest it pays the banks on reserves: 5.4%.
Interest it pays on overnight Reverse Repos (ON RRPs): 5.3%.
Interest it charges on overnight Repos: 5.5%.
Primary credit rate: 5.5% (banks’ costs to borrow at the “Discount Window”).

To douse Rate-Cut Mania, starting at the January meeting, the Fed had added new language to its statement. At today’s meeting, it repeated that language for the fourth time:

“In considering any adjustments to the target range for the federal funds rate, the Committee will carefully assess incoming data, the evolving outlook, and the balance of risks.”

“The Committee does not expect it will be appropriate to reduce the target range until it has gained greater confidence that inflation is moving sustainably toward 2 percent.”

And it repeated what it had said since the rate hikes started: “The Committee is strongly committed to returning inflation to its 2 percent objective” – with which the Fed whacks back at folks that are pushing it to raise its inflation target to 4% or whatever.

The FOMC statement maintained the new language on the labor market being in “better balance” that it had introduced in May:

“The Committee judges that the risks to achieving its employment and inflation goals have moved toward better balance over the past year.”

The “dot plot,” Oh MY! Rate Cuts dialed down to just 1 cut in 2024.

In its updated “Summary of Economic Projections” (SEP) today, which includes the infamous “dot plot,” each of the FOMC’s 19 participants jots down where they see various economic metrics – the Fed’s policy rates, unemployment rates, GDP growth, PCE inflation, etc. – by the end of 2024, by the end of 2025, etc. The median value of these projections (the value in the middle) becomes the headline projection for that metric. These median projections are not a decision by the Fed, nor a commitment. They’re a summary of how the 19 participants are seeing the economy evolve.

The median projection for the federal funds rate at the end of 2024 was 5.125%: only 1 rate cut of 25 basis points in 2024 — down from the three cuts envisioned since the December meeting — bringing the Fed’s target to a range between 5.0% and 5.25%.

Four of the 19 participants saw no rate cuts in 2024, seven saw 1 rate cut, and 8 saw 2 cuts. None (zero) of the 19 participants saw 3 cuts or more in 2024. This is a hawkish dial-down from the last dot plot in March, when 10 participants saw 3 or more cuts.

The mid-point has been 5.375% since the July 2023 meeting. Here is how the 19 participants saw the rate scenario for 2024:

4 see 5.375%: No cuts (up from 2 participants in March)7 see 5.125%: 1 cut (up from 2 participants in March)8 see 4.875%: 2 cuts (up from 5 in March)0 see 4.625%: 3 cuts (down from 9 in March)0 see 4.375%: 4 cuts (down from 1 in March).

Higher-for-longer: The median projection for the “longer-run” federal funds rate rose to 2.8% from 2.6% in the March SEP, slowly but steadily advancing with every meeting along the higher-for-longer theme.

GDP growth projections: The median projection for GDP growth for 2024 remained at 2.1% (from 2.1% in the March SEP, and from 1.4% in the December SEP).

Higher inflation projections: The median projection for “core PCE” inflation by the end of 2024 rose to 2.8% (from 2.6% in March and from 2.4% in December).

Unemployment rate projections: The median projection for the unemployment rate remained at 4.0% by the end of 2024.

QT continues at the slower pace announced in May, to avoid the kind of mess the Fed experienced with the repo market blowout in September 2019 after QT-1.  “By going slower, you can get farther,” Powell had said at the press conference after the last meeting. The Fed has already shed over $1.7 trillion in assets since it started QT in July 2022. It will continue to shed assets but at a slower pace.

The slower pace of QT starts this month. The Treasury roll-off was reduced from $60 billion a month to $25 billion. On the other hand, the Fed removed the $35-billion cap from the MBS roll-off.

MBS come off the balance sheet via passthrough principal payments that result from mortgage payoffs, but mortgage payoffs have collapsed as refis have collapsed and homes sales have plunged, and these passthrough principal payments have become a trickle of around $17 billion a month. If the mortgage business ever picks up again so that more than $35 billion a month in MBS come off, these MBS will just come, and goodbye, but the excess over $35 billion will be replaced with Treasury securities.

Here is the whole statement:

Recent indicators suggest that economic activity has continued to expand at a solid pace. Job gains have remained strong, and the unemployment rate has remained low. Inflation has eased over the past year but remains elevated. In recent months, there has been modest further progress toward the Committee’s 2 percent inflation objective.

The Committee seeks to achieve maximum employment and inflation at the rate of 2 percent over the longer run. The Committee judges that the risks to achieving its employment and inflation goals have moved toward better balance over the past year. The economic outlook is uncertain, and the Committee remains highly attentive to inflation risks.

In support of its goals, the Committee decided to maintain the target range for the federal funds rate at 5-1/4 to 5-1/2 percent. In considering any adjustments to the target range for the federal funds rate, the Committee will carefully assess incoming data, the evolving outlook, and the balance of risks. The Committee does not expect it will be appropriate to reduce the target range until it has gained greater confidence that inflation is moving sustainably toward 2 percent. In addition, the Committee will continue reducing its holdings of Treasury securities and agency debt and agency mortgage‑backed securities. The Committee is strongly committed to returning inflation to its 2 percent objective.

In assessing the appropriate stance of monetary policy, the Committee will continue to monitor the implications of incoming information for the economic outlook. The Committee would be prepared to adjust the stance of monetary policy as appropriate if risks emerge that could impede the attainment of the Committee’s goals. The Committee’s assessments will take into account a wide range of information, including readings on labor market conditions, inflation pressures and inflation expectations, and financial and international developments.

Voting for the monetary policy action were Jerome H. Powell, Chair; John C. Williams, Vice Chair; Thomas I. Barkin; Michael S. Barr; Raphael W. Bostic; Michelle W. Bowman; Lisa D. Cook; Mary C. Daly; Philip N. Jefferson; Adriana D. Kugler; Loretta J. Mester; and Christopher J. Waller.

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Energy News Beat

Dirty coal is dead, and the future is renewable energy. Or so the heavily bankrolled green industrial complex would have us believe. Reality is starkly different, however, as the Global South’s embrace of fossil fuels demonstrates.

India is a prime example. Having the planet’s largest population, the country will register the world’s highest rise in power demand for this decade and is expected to do the same over next three decades. Meeting this need for electricity is good old coal, the energy workhorse of the West’s Industrial Revolution in the 19th and 20th centuries.

This pattern in the subcontinent is expected to hold at least until 2070, making a much ballyhooed decarbonization merely the wishful thinking of political and corporate elites who call on citizens to subsidize their net zero illusion.

In the first half of 2024 alone, India’s power consumption rose by 14%, with peak demand recently hitting 235,000 megawatts (MW). The country’s Central Electricity Authority forecasts the peak to reach an unprecedented 260,000 MW this year and 400,000 MW by 2030 or sooner.

On May 22, the State Load Dispatch Center in the capital city of Delhi reported a record demand of 8,000 MW, the highest in its history. Officials expected demand to continue climbing. Across the country, the peak demand in most days of April 2024 was higher than the previous year.

Such power needs can only be met by readily dispatchable energy sources like coal, gas and nuclear. Coal provided 80% of April’s historic energy demand in the country. Power generation at nuclear plants rose 21% during the period.

Despite its popularity, hydropower continues to disappoint. In fact, the lack of adequate hydropower is expected to cause a 14% shortfall in electricity generation in June 2024, the widest supply gap since 2009-2010.

The obvious benefits of coal over renewable sources are so great that even the Indian state of Rajasthan, which has the largest amount of solar capacity, is now gravitating toward coal. Rajasthan’s government has decided to speed up the sale of the state’s coal mining blocks. One cannot blame them, as residents in the state experienced 10-12 hours of power blackouts in recent days due to a shortage in production and supply.

With demand peaking to unprecedented levels, the Indian government has ordered mining units to ramp up production. Thermal plants now have 25% more coal in stockpiles than the previous year, yet expect fast depletion of supplies.

With a pithead stockpile of 85 million metric tons exceeding last year’s inventory by 30%, Coal India, Ltd., produces more than 80% of the country’s coal. The increase in output is partly the result of the government’s huge capital expenditure in additional mining capacity. Not quite halfway through 2024, coal production is up more than 7% compared to a year ago and power generation by coal-fired plants is nearly 9% higher.

Despite these efforts, a June shortfall in power generation is expected. In May, the power ministry invoked emergency powers for the first time to direct power plants fueled by natural gas and imported coal to operate at full capacity. The ministry also decided to revive 5,000 MW of idled coal plant capacity and defer maintenance closures at many other coal-fired generators.

Power Minister Raj Kumar Singh said he would “not compromise” economic growth when it comes to securing adequate energy supplies.

Even Union Environment Minister Bhupender Yadav, who leads on climate issues, said, “While we are increasing our renewable capacity, we will also have to rely on coal power until we achieve the objective of a developed India.”

Westerners who have seen power prices spike and economies suffer under “green” policies might take a lesson from India, whose commitment to coal is rooted in its dedication to economic growth as a sovereign nation.

Source: Realclearenergy.org

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The post Coal Meets India’s Record Power Demand; Net Zero Sidelined appeared first on Energy News Beat.

Energy News Beat

Billionaire Warren Buffett bought almost 2.57 million common stocks from Occidental Petroleum Corp. last week for about $153.3 million.

The purchase, made in three tranches, has increased Berkshire Hathaway Inc’s common shares in the United States energy company to nearly 250.6 million, according to a Berkshire regulatory disclosure. Berkshire now owns nearly 28.3 percent of Occidental common shares, based on Occidental’s latest declared shares outstanding—over 886.6 million units as of April.

Berkshire bought the new shares at an average price of about $59.8 per share. Occidental, listed on the New York Stock Exchange, stayed above $59 per share on closing throughout last week.

Berkshire also holds nearly 85,000 preferred shares in the Houston, Texas-based oil, gas and chemicals producer. Berkshire is the only holder of preferred shares in Occidental.

On May 1 Occidental declared a regular quarterly dividend of $0.22 per share. It paid cash dividends of $332 million in the first quarter of 2024, including $170 million for preferred shares.

Berkshire started investing in Occidental in 2019 with $10 billion paid for preferred shares and common share warrants to aid the latter’s $55-billion acquisition of Anadarko Petroleum Corp. Berkshire began acquiring Occidental common shares in 2022.

Last year Occidental triggered its option to repurchase Berkshire’s preferred stake under the 2019 deal.

“As of March 31, 2024, our investment in Occidental preferred stock had an aggregate liquidation value of approximately $8.5 billion, which reflected mandatory redemptions by Occidental during 2023 of approximately $1.5 billion”, Berkshire said in its latest quarterly filing.

Occidental can also repurchase $1.2 billion worth of common shares remaining under a buyback program authorized 2023.

Occidental reported $718 million in net income for the first quarter, down by $265 million compared to the same three-month period a year ago due to weaker global oil prices and lower domestic petroleum volumes.

Despite the fall, which becomes steeper by prior-quarter comparison, Occidental beat the Zacks Consensus Estimate of earnings per share by 16.1 percent, helped by lower lease operating costs in the U.S.

However, first quarter 2024 earnings included a special net gain of $114 million from litigation settlements.

Occidental averaged 1.2 million barrels of oil equivalent per day in production in the January–March quarter, about the same as the opening quarter of 2023 and the previous quarter and at the midpoint of guidance despite an “extended third-party outage in the eastern Gulf of Mexico”, Occidental said.

Occidental ended the quarter with $8.3 billion in current assets—assets convertible to cash within a year—including $1.3 billion in cash and cash equivalents. Meanwhile, it owed $8.8 billion in current liabilities including $1.2 billion in current maturities as of end-March. Occidental held $720 million in quarterly free cash flow before working capital.

Source: Rigzone.com

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Energy News Beat

Crude oil prices moved lower today, after the U.S. Energy Information Administration reported an estimated inventory increase of 3.7 million barrels for the week to June 7.

The change compared with a weekly build of 1.2 million barrels for the previous week that was also accompanied by builds in fuel inventories, pressuring benchmarks.

Last week, the EIA estimated more builds in gasoline and middle distillate inventories.

In gasoline, the authority reported an inventory build of 2.6 million barrels for the seven days to June 7, with production averaging 10.1 million barrels daily. This compared with an inventory build of 2.1 million barrels for the prior week, when production stood at an average 9.5 million barrels daily.

In middle distillates, the EIA reported an estimated inventory increase of 900,000 barrels for the week to June 7, with production averaging 5 million barrels daily. This compared with an inventory increase of 3.2 million barrels for the previous week, when production averaged 5.1 million bpd.

A day before the EIA reported its latest inventory moves, the American Petroleum Institute estimated a crude inventory decline of 2.43 million barrels for the week to June 7, pushing oil prices higher after a weak start to the week.

The climb was also powered by two energy reports—by OPEC and by the EIA—which sounded an optimistic note on oil demand on Tuesday.

In its latest Short-Term Energy Outlook, the EIA revised up its oil demand growth outlook from 900,000 bpd to 1.1 million bpd for this year. OPEC, meanwhile, maintained its forecast for demand growth of over 2 million barrels daily.

“Despite announcing last week that it will start to phase out some of the voluntary cuts later this year, its forecasts suggest it should be easily accepted by the market,” ANZ analysts wrote in a note after the release of OPEC’s latest Monthly Oil Market Report, as quoted by Reuters.

Source: Oilprice.com

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The post Oil Drops on Inventory Build appeared first on Energy News Beat.

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HOUSTON, June 12 (Reuters) – Oil settled higher on Wednesday as ongoing tensions in the Middle East lent support to prices, but news that interest rate cuts could start as late as December capped gains, following the Federal Reserve’s statement concluding its two-day meeting.

Brent crude futures settled 68 cents, or 0.83%, higher at $82.60 a barrel, with U.S. West Texas Intermediate (WTI) crude futures up 60 cents, or 0.77%, to $78.50.

Prices had eased more than 2% last week after OPEC and its allies said they would phase out output cuts starting from October.

Palestinian militant group Hamas has proposed numerous changes, some unworkable, to a U.S.-backed proposal for a ceasefire with Israel in Gaza, U.S. Secretary of State Antony Blinken said on Wednesday, adding that mediators were determined to close the gaps.

At a press conference with Qatar’s prime minister in Doha, Blinken said some of the counter-proposals from Hamas, which has ruled Gaza since 2007, had sought to amend terms that it had accepted in previous talks.

The war has yet to materially affect global oil supply, but investors have priced in the risk, boosting crude futures prices.

Meanwhile, investors were left disappointed after the Federal Reserve pushed out the start of rate cuts to perhaps as late as December, with officials projecting only a single quarter-percentage-point reduction for the year amid rising estimates for what it will take to keep inflation in check.

U.S. consumer price data, published on Wednesday, had reinforced expectations of a Fed rate cut in September. Fed Chair Jerome Powell will hold a press conference later on Wednesday.

“It will be interesting to see what Powell says, I don’t think there is any doubt that they will leave rates where they are,” said Ben McMillan, a fund manager for IDX Advisors.

Higher borrowing costs tend to dampen economic growth, and could, by extension, limit oil demand.

“The market is holding its breath right now,” said Tim Snyder, economist at Matador Economics.

“If Powell talks outside of what the Fed publishes, there could be a little discord within the policy committee as to their direction on interest rates,” Snyder added.

Elsewhere, European Central Bank Vice President Luis de Guindos said the ECB must move “very slowly” in reducing interest rates, because of huge uncertainty over the inflation outlook.

U.S. crude stocks posted a surprise build last week, up by 3.7 million barrels to 459.7 million barrels, compared with expectations of a 1 million barrel-draw, the Energy Information Administration (EIA) said on Wednesday.

Gasoline stocks rose more than expected, up by 2.6 million barrels to 233.5 million barrels, the EIA said, compared with analysts’ expectations in a Reuters poll for a 900,000-barrel build.​

However, longer term, the EIA, the International Energy Agency (IEA) and the Organization of the Petroleum Exporting Countries this week updated their views on the global oil demand-supply balance for 2024, predicting declines in global oil inventories.

Their reports imply limited downside for prices in the second half of the year, said Tamas Varga of oil broker PVM, with the IEA seeing a larger depletion in inventories than the other two.

Source: Reuters.com

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Citi analysts have painted a bleak picture for the oil market, forecasting a significant price drop by 2025. According to their latest note, they anticipate a decline to $60 per barrel for Brent crude, marking a decrease of over 20% compared to current market expectations. The report suggests that while short-term volatility may lead to some upside risks, the long-term trend is bearish.

The expected surplus in the global oil market by 2025, despite efforts by OPEC+ to curtail production, is cited as the main reason behind the pessimistic outlook. Citi advises oil producers to hedge against potential price drops and recommends investors capitalize on short-term price increases by taking bearish positions.

Contrastingly, Citi’s outlook for copper is bullish, with a projected price surge to $12,000 per tonne by 2025. Factors such as constrained mine supply growth and increasing demand, particularly from China’s ongoing energy transition, are driving this optimism. The report emphasizes the significant difference in volatility between oil and copper, suggesting investors exploit this imbalance.

Recent market movements reflect the ongoing uncertainty. Crude oil prices dipped following reports of an inventory increase by the U.S. Energy Information Administration (EIA). Despite a decline, optimism spurred by optimistic oil demand forecasts from both OPEC and the EIA helped buoy prices.

The EIA’s revised oil demand growth outlook and OPEC’s maintenance of demand growth forecasts above 2 million barrels daily indicate a positive sentiment. However, concerns over rising inventories, as highlighted by the EIA’s recent report, underscore the challenges the oil market faces.

Crude oil prices were trending down on Wednesday morning after the EIA estimated a rise in crude oil inventory levels in the United States, climbing 3.7 million barrels in the week ending June 7.

Source: Oilprice.com

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US LNG shipped to Asia has a lower value-chain emissions footprint than coal-fired power generation, even over long distances.
Uncertainties regarding methane emissions and variations in emissions intensity between different sources and types of LNG and coal complicate the assessment.
Reducing methane leakages in the LNG value chain can widen the emissions gap between gas and coal, enhancing LNG’s role as a transition fuel.

The value-chain emissions of liquified natural gas (LNG) are lower on average than for coal-fired power generation, even when the fuel is shipped over long distances, according to new research from Rystad Energy. Natural gas that is produced and liquified in the US and shipped to Asia on return journeys of about 23,000 miles could emit up to 50% less than even the cleanest coal power plants. However, there are significant variations between US LNG sources, coal sources and types, and power plants, as well as uncertainties regarding methane emissions through both value chains.

Global natural gas production hit new highs last year – more than 4,000 billion cubic meters (Bcm) – and further growth is expected throughout this decade. Many view LNG as a core component of the energy transition and a way to wean the world off heavier fuels, especially coal, but questions over the fuel’s total value-chain emissions persist.

To help answer these questions, Rystad Energy has assessed total potential emissions for coal-to-power and LNG-to-power value chains, including carbon dioxide and methane, from extraction to end-use in power plants. This research sheds light on the various factors, uncertainties, and challenges influencing total value-chain emissions of the two fossil fuels. The individual stages of the two value chains are detailed at the end of this release.

For this research, we have focused on US LNG shipped to Asia, given the United States’ dominant role in the global LNG market. By 2030, global LNG supply is expected to approach 850 Bcm annually, around 30% of which will likely come from the US. Gas demand in Asian markets is expected to remain strong, and LNG will be a key competitor to coal in power generation.

Greenhouse gas emissions from the energy sector are high on the agenda among governments, operators, and other stakeholders. From a carbon dioxide perspective, the coal value chain has a significantly higher emission footprint than LNG, primarily due to end-use emissions. However, when adding methane emissions, major uncertainties are introduced. Historically, methane inventories have generally been calculated using engineering-based factors, but recent developments in measurement technologies, such as satellite imagery, have improved the accuracy. New measurement technologies have revealed that methane emissions are likely higher than anticipated in the oil & gas and coal value chains. The enduring uncertainties in methane monitoring are the main reason for varying outcomes and conclusions in recent studies of gas and coal value-chain emissions.

Discussions around leakage rates from upstream and midstream infrastructure and the potency of methane as a greenhouse gas can lead to different conclusions on using natural gas as a transition fuel. One of the key challenges in assessing methane emissions in the LNG and coal value chains is the lack of granular and high-quality measurement data. Even though the trend is positive with respect to on-site monitoring and other measurement technologies like satellite sensors, most available methane emissions data is modeled based on generic equipment and component factors. Rystad Energy’s emissions data supplements reported and modeled emissions data with global satellite methane plume analysis. There are still uncertainties and limitations with satellite monitoring, however, for instance related to the detection threshold as smaller methane plumes are not registered by satellites with global coverage.

Accurately quantifying emissions for any energy source is essential to understanding its full environmental impact. As the global focus swings towards methane emissions, and the wealth of credible data grows from more granular satellites and increased on-site measurements, the uncertainty within the methane data will begin to contract. With more data and measurement options for methane, consumers and buyers who want to ensure that gas cuts emissions compared to coal will be in a better position. With the introduction of emissions policies globally, such as methane regulations and potentially carbon border adjustment mechanisms, gas supplies from different sources could soon see price differences depending on carbon competitiveness.

Learn more with Rystad Energy’s Emissions Solution.

Rystad Energy has created high-case and low-case scenarios for both LNG and coal emissions to illustrate the complexities of the evaluation. The low case for US-Asia LNG is an estimate of the lowest potential value-chain emissions, with upstream production in the Appalachian basin, processing at an electrified liquefaction plant, shipping through the Panama Canal to minimize sailing distance, and end-use power generation at an ultra-efficient power plant. The high case assumes upstream production and liquefaction at above-average emissions intensity, a shipping route avoiding the Panama Canal, and end-use power generation by a less-efficient gas turbine plant. For coal, the low case assumes domestically sourced, high-quality coal and a modern ultra-supercritical designed power plant. The high-case coal scenario assumes low-quality domestically produced coal supplying an inefficient and aging subcritical coal power station.

Most US-Asia LNG-to-power deliveries have a lower value-chain emission footprint than domestic coal-to-power. This holds true even when assuming high methane leakage rates. There are, however, some Asian coal-power stations that could have lower value-chain emissions than some of the high-emitting LNG sources. For the high-case LNG scenario, leakage rates in the natural gas value chain would have to be above 4% to equal the low-case coal scenario emissions. However, several studies have revealed that methane emissions in the coal extraction process are much greater than previously thought, meaning actual leakage rates in the gas value chain would need to be significantly higher – potentially between 6% and 10% – for low-case coal to be favored over high-case LNG from an emissions perspective. Most US LNG cargoes, however, are understood to be supplied by gas from basins with low methane emissions, like the Haynesville, and associated gas from large operators in the Permian basin, which tends to have substantially lower methane intensity than the worst performers.

For the LNG industry, it is vital for operators and other stakeholders in the value chain to reduce methane leakages and, in that way, widen the emissions gap between gas and coal. This would allow natural gas to play its most optimal role as a transition fuel when coal is being phased out. Increasing scrutiny of methane leakages, along with growth in methane monitoring and identification technologies, will help reduce methane emissions throughout the LNG value chain. On the other hand, coal-to-power, which is dominated by end-use combustion at less efficient power plants, has fewer and less impactful opportunities to crimp its value-chain emissions footprint. As a result, the LNG value chain will likely continue to increase its emissions competitiveness over time.

End-use emissions

Most modern gas power stations use combined-cycle turbines, allowing for very high efficiencies with emission rates of typically less than 400 grams CO2 per kilowatt-hour (kWh) – well below the 700 g CO2 per kWh at the best-performing coal power stations.

Replacing more carbon-heavy fossil fuels with natural gas has often been stated as a mechanism to reduce carbon emissions. In electricity generation, for example, natural gas performs substantially better than coal-fired power stations for final end-use combustion. The full value-chain emissions are also set to come down as improved leak monitoring allows producers to better pinpoint measures to reduce emissions at the upstream and midstream stages.

Value-chain emissions

The natural gas value chain begins with upstream production, followed by processing to separate liquids, remove impurities, and sweeten the gas before it is transported to its destination. For LNG, the value chain continues to liquefaction, where the gas is cooled to less than -160 degrees Celsius and loaded onto LNG vessels as a liquid. At the end destination, the LNG is converted back into a gaseous state at a regasification facility before being charged and sent into the importing country’s natural gas grid.

The value chain for coal is highly dependent on the end-use purpose and coal quality. However, the processes can be simplified to initial production at a mine (underground or open pit) before selection, washing, and transportation to the end-use destination by railroad, ship, or truck.

Source: Oilprice.com

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DALLAS–(BUSINESS WIRE)–Jun. 12, 2024– Matador Resources Company (NYSE: MTDR) (“Matador” or the “Company”) today announced that a wholly-owned subsidiary of Matador has entered into a definitive agreement to acquire a subsidiary of Ameredev II Parent, LLC (“Ameredev”), including certain oil and natural gas producing properties and undeveloped acreage located in Lea County, New Mexico and Loving and Winkler Counties, Texas (the “Ameredev Acquisition”). The Ameredev Acquisition also includes an approximate 19% stake in Piñon Midstream, LLC (“Piñon”), which has midstream assets in southern Lea County, New Mexico. The consideration for the Ameredev Acquisition will consist of a cash payment of $1.905 billion, subject to customary closing adjustments. Ameredev is a portfolio company of EnCap Investments L.P. (“EnCap”).

The Ameredev Acquisition is subject to customary closing conditions and is expected to close late in the third quarter of 2024 with an effective date of June 1, 2024. A short slide presentation summarizing the Ameredev Acquisition is also included on the Company’s website at www.matadorresources.com on the Events and Presentations page under the Investor Relations tab. Matador’s management will host a live conference call to discuss the Ameredev Acquisition on Wednesday, June 12, 2024 at 10:00 am Central Time. Further details are provided at the end of this press release.

Joseph Wm. Foran, Matador’s Founder, Chairman and CEO, commented, “Matador is very excited to work with EnCap again on this strategic bolt-on opportunity (see Exhibit A). As with the successful Advance Energy deal we completed in April of 2023, we view the Ameredev transaction as another unique opportunity to work with EnCap and another value-creating opportunity for Matador and its shareholders. We evaluated this opportunity based on the high rock quality, the strong existing production and cash flow profile, the significant reserves additions, the high-quality inventory, the strategic fit within our existing portfolio of properties and the expansion of our midstream footprint with an ownership interest in Piñon. The equity and debt securities offerings and the revolving credit facility amendment we completed earlier this year, together with our historical balance sheet conservatism, have provided Matador with the opportunity to acquire these high-quality assets and continue Matador’s consistent history of profitable growth at a measured pace.”

Transaction Highlights

On a pro forma basis following closing of the acquisition, Matador expects to have over 190,000 net acres in the Delaware Basin, approximately 2,000 net locations, production of over 180,000 barrels of oil and natural gas equivalent (“BOE”) per day, proved oil and natural gas reserves of over 580 million BOE and an enterprise value in excess of $10 billion (see Exhibit B)
Expected to generate forward one-year Adjusted EBITDA1 of approximately $425 to $475 million at strip prices as of late May 2024, which represents an attractive purchase price multiple of 4.2x for the upstream assets:

Strip prices for the remainder of 2024 averaged $77 per barrel of oil and $2.76 per MMBtu of natural gas.

Accretive to relevant key financial and valuation metrics
Significant increase in high quality pro forma drilling locations in primary development zones (see Exhibit C)
PV-10 (present value discounted at 10%)2 at May 31, 2024 of $1.46 billion on total proved oil and natural gas reserves utilizing strip pricing as of late May 2024. The PV-10 of $1.46 billion does not include the interest in Piñon or certain undeveloped but prospective locations included in Matador’s valuation of the Ameredev assets:

PV-10 of proved developed (PD) oil and natural gas reserves at May 31, 2024 of $1.20 billion, or approximately $47,100 per flowing BOE, utilizing strip pricing as of late May 2024.

Preserves Matador’s strong balance sheet with pro forma leverage expected to be approximately 1.3x at closing and back below 1.0x by the middle of 2025 based upon current commodity prices, allowing Matador to maintain operational and financial flexibility while continuing to return value to shareholders through its fixed quarterly dividend and protecting cash flows through its appropriate commodity hedges
Expanding Matador’s midstream footprint with an approximate 19% stake in Piñon, which allows for increased coordination between Matador and Piñon in gathering, transporting and treating natural gas from the Ameredev properties

Ameredev Asset Highlights

Estimated production in the third quarter of 2024 of 25,000 to 26,000 BOE per day (65% oil)
Approximately 33,500 highly contiguous net acres (82% held by production; over 99% operated) in the northern Delaware Basin, most of which is located in Matador’s Antelope Ridge asset area in southern Lea County, New Mexico and Matador’s West Texas asset area in Loving and Winkler Counties, Texas (see Exhibit A again)
Adds 431 gross (371 net) operated locations (86% working interest) identified for future drilling, including prospective targets throughout the Wolfcamp and Bone Spring formations

Locations are consistent with Matador’s methodology for estimating inventory with typically three to four (or fewer) locations per section, or the equivalent of 160-acre (or greater) spacing, in all prospective completion intervals

Prior to transaction closing, Matador expects Ameredev to operate one drilling rig and to continue operations on 13 drilled but uncompleted (DUC) wells with one completion crew:

The prospectivity of the Ameredev acreage immediately competes for development capital with Matador’s existing acreage (see Exhibit C again), so Matador expects to continue operating a total of nine drilling rigs for the immediate future on the combined approximately 192,000 net acres of the Matador-Ameredev properties.
The additional ninth drilling rig and the associated Ameredev activities are not expected to increase the range of Matador’s estimated drilling, completing and equipping (“D/C/E”) capital expenditures of $1.10 to $1.30 billion for 2024. More information regarding the capital expenditures associated with the Ameredev Acquisition and its impact on Matador’s guidance for 2024 will be included in Matador’s press release announcing its second quarter 2024 results, which is expected to be issued in late July 2024.

Matador estimates total proved oil and natural gas reserves associated with the Ameredev properties of 118 million BOE (60% oil) at May 31, 2024. The pro forma combined company is estimated to have 578 million BOE, a 26% increase from Matador’s total proved reserves at December 31, 2023 of 460 million BOE (see Exhibit D). PV-10 of the proved oil and natural gas reserves of the Ameredev properties at May 31, 2024 was approximately $1.66 billion using the same unweighted arithmetic average first-day-of-the-month price methodology for the previous 12-month period being used to value the Company’s reserves, which are $74.91 per barrel of oil and $2.35 per MMBtu of natural gas. The PV-10 of $1.66 billion does not include the interest in Piñon or certain undeveloped but prospective locations included in Matador’s valuation of the Ameredev assets. Matador expects to add future proved reserves and reserves value as a result of the development of the Ameredev properties going forward. These reserves estimates were prepared by Matador’s engineering staff and audited by Netherland, Sewell & Associates, Inc., independent reservoir engineers, as of May 31, 2024.

Mr. Foran further commented, “We took significant strides during and shortly after the first quarter of 2024 to strengthen our balance sheet and allow us to participate in another special opportunity like this one. The specific location and quality of the Ameredev assets, the strong existing cash flow, the multi-pay potential and the cost savings associated with developing these assets via longer laterals on multi-well pads on blocky acreage were key features that attracted us to this unique opportunity and significantly enhance our already strong Delaware Basin portfolio and prospect inventory. This acquisition also positions Matador for continued success and growth throughout 2024, 2025 and into the future as one of the top ten producers in the Delaware Basin (see Exhibit E).

“To assist in financing this all-cash transaction, Matador has received firm commitments from PNC Bank, the lead bank under our reserves-based credit facility, to provide at closing (i) a 50% increase in the elected commitment under our credit facility from $1.5 billion to $2.25 billion and (ii) a $250 million Term Loan A under our credit facility to provide additional liquidity following the closing of the transaction. Importantly, this acquisition should not significantly impact Matador’s leverage profile in the long-term, as we expect our pro forma leverage ratio to return to a ratio below 1.0x by the middle of 2025 based upon current commodity prices. We especially appreciate PNC Bank for their leadership and support in arranging this financing commitment and the confidence and support we have received from the other members of our bank group.

“This transaction marks the second significant deal Matador has done with EnCap in the last 18 months. Gary Petersen, one of EnCap’s Founders, and I have known each other for many years. Similar to the Advance Energy transaction we closed in April of 2023, the long relationship with Gary and EnCap was critical to the smooth negotiation of this transaction. Thank you to Gary, the other senior members of the EnCap team, Parker Reese and the rest of the Ameredev team and the Matador team for their hard work and integrity in efficiently reaching a deal that we believe is a positive development for all parties. We also appreciate the support of our other friends, shareholders, bankers and vendors in making this deal happen. We look forward to the additional commercial opportunities and free cash flow that this new acreage and production will provide for Matador.”

Conference Call Information

Management will host a live conference call to discuss the Ameredev Acquisition on Wednesday, June 12, 2024 at 10:00 am Central Time. To access the live conference call by phone, you can use the following link https://register.vevent.com/register/BI43dafc62d9a54c13a8b9fab5e226a923 and you will be provided with dial-in details after registering. To avoid delays, it is recommended that participants dial into the conference call at least 15 minutes ahead of the scheduled start time.

The live conference call will also be available through the Company’s website at www.matadorresources.com on the Events and Presentations page under the Investor Relations tab. The replay for the event will be available on the Company’s website at www.matadorresources.com on the Events and Presentations page under the Investor Relations tab for one year following the date of the conference call.

Advisors

Baker Botts LLP served as legal advisor to Matador for the transaction. Vinson & Elkins LLP served as legal advisor and JP Morgan served as financial advisor to Ameredev and EnCap.

About Matador Resources Company

Matador is an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. Its current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. Matador also operates in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. Additionally, Matador conducts midstream operations in support of its exploration, development and production operations and provides natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties.

For more information, visit Matador Resources Company at www.matadorresources.com.

Forward-Looking Statements

This press release includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. “Forward-looking statements” are statements related to future, not past, events. Forward-looking statements are based on current expectations and include any statement that does not directly relate to a current or historical fact. In this context, forward-looking statements often address expected future business and financial performance, and often contain words such as “could,” “believe,” “would,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “should,” “continue,” “plan,” “predict,” “potential,” “project,” “hypothetical,” “forecasted” and similar expressions that are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. Such forward-looking statements include, but are not limited to, statements about the consummation and timing of the Ameredev Acquisition, the anticipated benefits, opportunities and results with respect to the acquisition, including the expected value creation, reserves additions, midstream opportunities and other anticipated impacts from the Ameredev Acquisition, as well as other aspects of the transaction, guidance, projected or forecasted financial and operating results, future liquidity, the payment of dividends, results in certain basins, objectives, project timing, expectations and intentions, regulatory and governmental actions and other statements that are not historical facts. Actual results and future events could differ materially from those anticipated in such statements, and such forward-looking statements may not prove to be accurate. These forward-looking statements involve certain risks and uncertainties, including, but not limited to, the ability of the parties to consummate the Ameredev Acquisition in the anticipated timeframe or at all; risks related to the satisfaction or waiver of the conditions to closing the Ameredev Acquisition in the anticipated timeframe or at all; risks related to obtaining the requisite regulatory approvals; disruption from the Ameredev Acquisition making it more difficult to maintain business and operational relationships; significant transaction costs associated with the Ameredev Acquisition; the risk of litigation and/or regulatory actions related to the Ameredev Acquisition, as well as the following risks related to financial and operational performance: general economic conditions; the Company’s ability to execute its business plan, including whether its drilling program is successful; changes in oil, natural gas and natural gas liquids prices and the demand for oil, natural gas and natural gas liquids; its ability to replace reserves and efficiently develop current reserves; the operating results of the Company’s midstream oil, natural gas and water gathering and transportation systems, pipelines and facilities, the acquiring of third-party business and the drilling of any additional salt water disposal wells; costs of operations; delays and other difficulties related to producing oil, natural gas and natural gas liquids; delays and other difficulties related to regulatory and governmental approvals and restrictions; impact on the Company’s operations due to seismic events; its ability to make acquisitions on economically acceptable terms; its ability to integrate acquisitions; disruption from the Company’s acquisitions making it more difficult to maintain business and operational relationships; significant transaction costs associated with the Company’s acquisitions; the risk of litigation and/or regulatory actions related to the Company’s acquisitions; availability of sufficient capital to execute its business plan, including from future cash flows, available borrowing capacity under its revolving credit facilities and otherwise; the operating results of and the availability of any potential distributions from our joint ventures; weather and environmental conditions; and the other factors that could cause actual results to differ materially from those anticipated or implied in the forward-looking statements. For further discussions of risks and uncertainties, you should refer to Matador’s filings with the Securities and Exchange Commission (“SEC”), including the “Risk Factors” section of Matador’s most recent Annual Report on Form 10-K and any subsequent Quarterly Reports on Form 10-Q. Matador undertakes no obligation to update these forward-looking statements to reflect events or circumstances occurring after the date of this press release, except as required by law, including the securities laws of the United States and the rules and regulations of the SEC. You are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this press release. All forward-looking statements are qualified in their entirety by this cautionary statement.

1 Adjusted EBITDA is a non-GAAP financial measure. The Company defines Adjusted EBITDA as earnings before interest expense, income taxes, depletion, depreciation and amortization, accretion of asset retirement obligations, property impairments, unrealized derivative gains and losses, certain other non-cash items and non-cash stock-based compensation expense and net gain or loss on asset sales and impairment. The most comparable GAAP measures to Adjusted EBITDA are net income or net cash provided by operating activities. The Company has not provided such GAAP measures or a reconciliation to such GAAP measures because they would be preliminary and prospective in nature and would not be able to be prepared without estimation of a number of variables that are unknown at this time.
2 PV-10 is a non-GAAP financial measure, which differs from the GAAP financial measure of “Standardized Measure” because PV-10 does not include the effects of income taxes on future income. The income taxes related to the acquired properties is unknown at this time because the Company’s tax basis in such properties will not be known until the closing of the transaction and is subject to many variables. As such, the Company has not provided the Standardized Measure of the acquired properties or a reconciliation of PV-10 to Standardized Measure.

Source: Matadorresources.com

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Abu Dhabi’s national oil company ADNOC has taken the final investment decision to move forward with the Ruwais LNG project, which will more than double the existing LNG production capacity in the United Arab Emirates.

ADNOC took on Wednesday the FID for the Ruwais LNG project, which will consist of two 4.8 million metric tons per annum (mmtpa) LNG liquefaction trains with a total capacity of 9.6 mmtpa. This would more than double ADNOC’s existing UAE LNG production capacity to around 15 mmtpa, as the company builds its international LNG portfolio.

The project, located in Al Ruwais Industrial City in the Al Dhafra region of Abu Dhabi, will be the first LNG export facility in the Middle East and North Africa (MENA) region to run on clean power, making it one of the world’s lowest-carbon intensity LNG plants, ADNOC says.

The UAE state energy giant also awarded on Wednesday an Engineering, Procurement, and Construction (EPC) contract for the project valued at approximately $5.5 billion (20.2 billion UAE dirhams).

ADNOC has been betting big on LNG in recent months, seeking to expand its domestic production and export capacity and buying minority stakes in LNG projects overseas, including in the United States.

Last month, ADNOC bought an 11.7% stake in Phase 1 of NextDecade’s Rio Grande LNG export project in Texas, announcing its first strategic investment in the U.S.

Rio Grande LNG near Brownsville, Texas, is the first U.S. LNG project offering expected emissions reduction of more than 90% through its proposed carbon capture and storage (CCS) project, ADNOC noted.

ADNOC has also signed a 20-year LNG offtake agreement from Rio Grande LNG Train 4 with NextDecade.

The Abu Dhabi group also announced last month the acquisition of a 10% interest in an LNG project offshore Mozambique as it continues to expand its international natural gas operations.

Source: Oilprice.com

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