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OPEC Statement to the UN Climate Change Conference (COP 26/CMP 16/CMA 3)
Delivered by HE Mohammad Sanusi Barkindo, OPEC Secretary General, at the to the UN Climate Change Conference (COP 26/CMP 16/CMA 3), 10 November 2021, Glasgow, United Kingdom.
https://www.opec.org/opec_web/en/6704.htm
This is no ordinary time. It is a landmark COP, where the future of humanity is at stake.
With negotiations of such magnitude and consequence, we must remember the often ignored scientific fact: climate change and energy poverty are two sides of the same coin.
The delicate balance between reducing emissions, energy affordability and security requires comprehensive and sustainable policies, with all voices being heard, and listened to. Focusing on only one of these over the others can lead to unintended consequences; market distortions, heightened volatility and energy shortfalls.
We need to ensure energy is available and affordable for all; we need to move towards a more inclusive, fair and equitable world in which every person has access to energy, aligned with SDG 7; and we need to reduce emissions.
It is an energy sustainability trilemma, with each piece having to move in unison.
The science tells us that tackling emissions has many paths. There is no one-size-fits-all solution, for countries or industries. The narrative that the energy transition is from oil and other fossil fuels to renewables is misleading and potentially dangerous to a world that will continue to be thirsty for all energy sources.
The capacities, national circumstances, and development priorities of developing countries must be taken into account.
The adverse socio-economic impacts on developing countries due to mitigation activities should be considered, to identify remediation measures and share best practices.
Financing is critical to reach climate targets set in developing countries’ NDCs. Developing countries have underscored the need for enhanced support, including financial resources, technological development and transfer, and capacity building, as well as a new collective goal for climate finance, to aid adaptation and back increased ambitions for climate mitigation action.
OPEC advocates putting multilateralism at the centre of energy, climate and sustainable development. We remain committed to the UNFCCC process, particularly the core elements of equity, common-but-differentiated responsibilities and national circumstances.
The oil and gas industry can foster its resources and expertise to help unlock a low-emissions future, through its role as a powerful innovator in developing more efficient technological solutions.
OPEC subscribes to a sustainable path forward; one that works for us all.
11/12/2021 GOM Offshore Rig Count increased 15% from the previous week and is currently reflecting 15 rigs. The Total US Oil and Gas Rig Count shows 556 rigs an increase of 6 rig, 2 of which were for GOM waters. All of Gulfslope’s prospects are in GOM Louisiana offshore waters.
http://www.dnr.louisiana.gov/assets/TAD/data/drill_weekly/WeeklyRigCountUpdate.pdf
http://www.dnr.louisiana.gov/assets/TAD/data/drill_weekly/ogj_rig_count.pdf
Mrs. Smith
Gulfslope is always tight with information, and never seems to have communications as a top priority beyond complying with SEC regulations.
Additionally, considering all the Covid turmoil, there has not been a lot going on in the energy industry. Without confirmation on a Tau rig contract, I am not sure what Gulfslope would talk to us about.
I do believe the timing of all the events resulting from the turmoil in the industry has a great deal to do with it. Also, do not overlook the current administration’s hostile stance towards domestic oil and gas production and it’s effects on trying to organize a drilling program.
All this is speculation on my part and just my opinion. Why do you think it is?
Mrs. Smith
EIA Weekly Petroleum Status Report, Release Date: 11/10/2021, Data for week-ending: 11/05/2021
Full Report: https://www.eia.gov/petroleum/supply/weekly/pdf/wpsrall.pdf
Report Tables: https://ir.eia.gov/wpsr/overview.pdf
Highlights
U.S. crude oil refinery inputs averaged 15.4 million barrels per day during the week ending November 5, 2021 which was 343,000 barrels per day more than the previous week’s average. Refineries operated at 86.7% of their operable capacity last week. Gasoline production decreased last week, averaging 10.1 million barrels per day. Distillate fuel production increased last week, averaging 4.9 million barrels per day.
U.S. crude oil imports averaged 6.1 million barrels per day last week, down by 63,000 barrels per day from the previous week. Over the past four weeks, crude oil imports averaged about 6.1 million barrels per day, 14.3% more than the same four-week period last year. Total motor gasoline imports (including both finished gasoline and gasoline blending components) last week averaged 587,000 barrels per day, and distillate fuel imports averaged 278,000 barrels per day.
U.S. commercial crude oil inventories (excluding those in the Strategic Petroleum Reserve) increased by 1.0 million barrels from the previous week. At 435.1 million barrels, U.S. crude oil inventories are about 7% below the five year average for this time of year. Total motor gasoline inventories decreased by 1.6 million barrels last week and are about 4% below the five year average for this time of year. Finished gasoline inventories increased while blending components inventories decreased last week. Distillate fuel inventories decreased by 2.6 million barrels last week and are about 6% below the five year average for this time of year. Propane/propylene inventories decreased by 1.3 million barrels last week and are about 14% below the five year average for this time of year. Total commercial petroleum inventories decreased by 1.2 million barrels last week.
Total products supplied over the last four-week period averaged 20.2 million barrels a day, up by 6.1% from the same period last year. Over the past four weeks, motor gasoline product supplied averaged 9.4 million barrels a day, up by 11.2% from the same period last year. Distillate fuel product supplied averaged 4.0 million barrels a day over the past four weeks, up by 3.0% from the same period last year. Jet fuel product supplied was up 45.2% compared with the same four-week period last year.
The West Texas Intermediate crude oil price was $81.25 per barrel on November 5, 2021, $2.25 below last week’s price but $44.28 more than a year ago. The spot price for conventional gasoline in the New York Harbor was $2.458 per gallon, $0.079 less than last week’s price but $1.337 above a year ago. The spot price for No. 2 heating oil in the New York Harbor was $2.315 per gallon, $0.027 below last week’s price but $1.252 over a year ago.
The national average retail regular gasoline price was $3.410 per gallon on November 8, 2021, $0.020 per gallon more than last week’s price and $1.314 over a year ago. The national average retail diesel fuel price was $3.730 per gallon, $0.003 above last week’s price and $1.347 over a year ago.
Oil Prices Soar On Surprise Crude Draw
By Julianne Geiger - Nov 09, 2021, 3:58 PM CST
https://oilprice.com/Latest-Energy-News/World-News/Oil-Prices-Soar-On-Surprise-Crude-Draw.html
WTI $84.56/bbl December Contract 20:20 PM CDT 11/9/2021: https://oilprice.com/oil-price-charts/#WTI-Crude
Note: The U.S. Energy Information Administration (EIA) will release their data tomorrow.
The American Petroleum Institute (API) on Tuesday reported its first crude oil inventory draw in six weeks, even as the United States ventures well on the other side of the typical driving season. This week, the API estimated the inventory draw for crude oil to be 2.485 million barrels.
Despite the six previous weeks of builds, U.S. crude inventories are still 60 million barrels below where they were at the beginning of the year—and low enough to continue to press upwards on prices.
Analyst expectations for the week were for a build of 1.90-million barrels for the week.
In the previous week, the API reported a build in oil inventories of 3.594-million barrels, compared to the 1.567-million-barrel build that analysts had predicted.
Oil prices were trading up on Tuesday in the runup to the data release, with WTI rising to $83.96 and Brent trading around $84.57 per barrel. WTI was up less than $.50 week on week at 2:13 p.m. EST, while Brent was essentially flat on the week.
U.S. oil production for the week ending October 29—the last week for which the Energy Information Administration has provided data—rose 200,000 bpd to 11.5 million bpd—still 1.6 million bpd below the all-time high of 13.1 million bpd reached right before the pandemic took hold in the United States.
The API reported a draw in gasoline inventories as well, of 552,000 barrels for the week ending November 5—compared to the previous week's 552,000-barrel draw.
Distillate stocks saw an increase in inventories of 573,000 barrels for the week, on top of last week's 573000-barrel increase.
Will A Strategic Petroleum Release Bring Down U.S. Gasoline Prices? By Tsvetana Paraskova - Nov 09, 2021, 5:00 PM CST
https://oilprice.com/Energy/Crude-Oil/Will-A-Strategic-Petroleum-Release-Bring-Down-US-Gasoline-Prices.html
Excerpts from article linked above:
Selling millions of barrels from the SPR may do precious little to impact the price of gasoline directly, traders and analysts say.
U.S. may be able to release up to a tenth of the current stockpile in the SPR, traders have told Bloomberg. That wouldn’t be enough to bring down gasoline prices as much as the Administration possibly hopes, they warn.
Moreover, most of a potential sale could consist of sour crude grades, which currently are not the favorite of refiners because they need more natural gas—whose prices are much higher now—to process those sour grades into fuels.
Meanwhile, U.S. gasoline prices continued to climb despite the end of driving season two months ago.
In the week to November 8, “The price at the pump continued its slow climb, rising two cents on the week, with the national average for a gallon of gas hitting $3.42,” AAA said on Monday. That’s the highest since September 2014.
The latest decision by OPEC and its oil-producing allies to maintain their planned gradual increase in output will not help lessen supply constraints, so any relief will most likely have to come from the demand side,” according to AAA.
If the Administration were to opt for an SPR sale to increase the availability of crude, it could likely release up to 60 million barrels of crude oil.
As of November 5, the SPR held 609.4 million barrels of crude oil, of which 252.5 million sweet crude and 356.9 million sour crude.
Arelease of up to 60 million barrels in theory would cover around three days worth of total U.S. petroleum consumption, which was 20.5 million barrels per day (bpd) in the pre-pandemic 2019, per EIA data.
According to analysts, an SPR sale wouldn’t do much to reduce prices at the pump and relieve the burden on households amid inflationary pressure for all other goods.
November 2021 EIA Short-term Energy Outlook STEO Forecast: Release Date: November 9, 2021 | Forecast Completed: November 4, 2021 | Next Release Date: December 7, 2021
FULL REPORT WITH EXCELLENT GRAPHS: https://www.eia.gov/outlooks/steo/pdf/steo_full.pdf
ALL FIGURES AND DATA: https://www.eia.gov/outlooks/steo/data.php?type=figures
WTI $83.77/bbl up 2.23% December Contract 12:53 PM CDT 11/9/2021:https://oilprice.com/oil-price-charts/#WTI-Crude
FORECAST HIGHLIGHTS:
Global liquid fuels
• The November Short-Term Energy Outlook (STEO) remains subject to heightened levels of uncertainty related to the ongoing recovery from the COVID-19 pandemic. U.S. gross domestic product (GDP) declined by 3.4% in 2020 from 2019 levels. This STEO assumes U.S. GDP will grow by 5.4% in 2021 and by 4.2% in 2022. The U.S. macroeconomic assumptions in this outlook are based on forecasts by IHS Markit. In addition to uncertainty about macroeconomic conditions, the evolving effects of consumer behavior on energy demand because of the pandemic present a wide range of potential outcomes for energy consumption. Supply uncertainty in the forecast results from the production decisions of OPEC+ along with the rate at which U.S. oil and natural gas producers increase drilling at forecast price levels.
• Brent crude oil spot prices averaged $84 per barrel (b) in October, up $9/b from September and up $43/b from October 2020. Crude oil prices have risen over the past year as result of steady draws on global oil inventories, which averaged 1.9 million barrels per day (b/d) during the first three quarters of 2021. In addition to sustained inventory draws, prices increased after OPEC+ announced in early October—and reaffirmed on November 4—that the group would keep current production targets unchanged. We expect Brent prices will remain near current levels for the rest of 2021, averaging $82/b in the fourth quarter of 2021. In 2022, we expect that growth in production from OPEC+, U.S. tight oil, and other non-OPEC countries will outpace slowing growth in global oil consumption and contribute to Brent prices declining from current levels to an annual average of $72/b.
• We estimate that 98.9 million b/d of petroleum and liquid fuels was consumed globally in October, an increase of 4.5 million b/d from October 2020 but 1.9 million b/d less than in October 2019. We revised up our forecast for consumption of petroleum and liquid fuels for the fourth quarter of 2021, partially as a result of fuel switching from natural gas to petroleum in the electric power sector in parts of Asia and Europe. This fuel switching is a result of increases in natural gas prices in Asia and Europe. We forecast that global consumption of petroleum and liquid fuels will average 97.5 million b/d for all of 2021, which is a 5.1 million b/d increase from 2020. We forecast that global consumption of petroleum and liquid fuels will increase by 3.3 million b/d in 2022.
• U.S. regular gasoline retail prices averaged $3.29 per gallon (gal) in October, up 12 cents/gal from September, and $1.13/gal higher than in October 2020. The October price was the highest monthly average since September 2014. We forecast that retail gasoline prices will average $3.32/gal in November before falling to $3.16/gal in December, which are 16 cents/gal and 11 cents/gal higher than our previous forecast, respectively.
• U.S. crude oil production averaged an estimated 11.4 million b/d in October, up from 10.7 million b/d in September as a result of production increases following disruptions from Hurricane Ida. We forecast production will rise to 11.6 million b/d in December. We forecast annual production will average 11.1 million b/d in 2021, increasing to 11.9 million b/d in 2022 as tight oil production rises in the United States. Growth will come largely as a result of onshore operators increasing rig counts, which we expect will offset production decline rates.
Natural Gas
• In October, the natural gas spot price at Henry Hub averaged $5.51 per million British thermal units (MMBtu), which was up from the September average of $5.16/MMBtu and up from an average of $3.25/MMBtu in the first half of 2021. The rising natural gas prices in recent months reflect U.S. natural gas inventory levels that are below the five-year (2016–20) average. Despite high prices demand for natural gas for electric power generation has remained relatively high, which along with strong global demand for U.S. liquefied natural gas (LNG) has limited downward natural gas price pressures.
• The Henry Hub spot price will average $5.53/MMBtu from November through February in our forecast and then generally decline through 2022, averaging $3.93/MMBtu for the year amid rising U.S. natural gas production and slowing growth in LNG exports. We forecast that U.S. inventory draws will be similar to the five-year average this winter, and we expect that factor, along with rising U.S. natural gas exports and relatively flat production through March, will keep U.S. natural gas prices near recent levels before downward price pressures emerge. Because of uncertainty around seasonal demand, we expect natural gas prices to remain volatile over the coming months with winter temperatures to be a key driver of demand and prices.
• We estimate that U.S. LNG exports averaged 9.8 billion cubic feet per day (Bcf/d) in October 2021, up 0.3 Bcf/d from September, supported by large prices differences between Henry Hub prices in the United States and spot prices in Europe and Asia. LNG exports resumed from Cove Point LNG in late October after that facility’s annual maintenance was completed. In our forecast LNG exports average 9.8 Bcf/d for all of 2021, up 50% from 2020. We expect that LNG exports will increase this winter, averaging 11.0 Bcf/d from November through March. We expect high levels of LNG exports to continue into 2022, averaging 11.5 Bcf/d for the year, up 17% from 2021. The forecast reflects our assumption that global natural gas demand remains high and several new natural liquefaction trains—the sixth train at Sabine Pass LNG and the first trains at the new LNG export facility, Calcasieu Pass LNG—enter service.
• U.S. natural gas inventories ended October 2021 at more than 3.6 trillion cubic feet (Tcf), 3% less than the five-year average for this time of year. Injections into storage this summer were below the previous five-year average, largely as a result of more electricity consumption in June because of hot weather and increased exports, even as domestic natural gas production has remained flat. However, in recent weeks, storage levels have moved closer to average levels as injections outpaced the five- year average in September and October. We expect natural gas inventories to fall by 2.1 Tcf this winter, ending March at 1.6 Tcf, which would be 4% less than the 2017–21 average for that time of year.
• We estimate dry natural gas production averaged 94.9 Bcf/d in the United States in October (up from 94.5 Bcf/d in September) and 91.9 Bcf/d in in the first half of 2021. Production in the forecast rises to an average of 95.2 Bcf/d during the rest of this winter (November–March) and averages 96.7 Bcf/d during 2022, driven by natural gas and crude oil prices, which we expect to remain at levels that will support enough drilling to sustain production growth.
Electricity, coal, renewables, and emissions
• The share of electricity generation produced by natural gas in the United States averages 36% in 2021 and 35% in 2022 in our forecast, down from 39% in 2020. In 2021, our forecast share for natural gas as a generation fuel declines in response to our expectation of a higher delivered natural gas price for electricity generators, which we forecast will average $5.12/MMBtu compared with $2.39/MMBtu in 2020. As a result of the higher expected natural gas prices, the forecast share of electricity generation from coal rises from 20% in 2020 to about 23% in 2021 and 22% in 2022. For renewable energy sources, new additions of solar and wind generating capacity are offset somewhat by reduced generation from hydropower this year, resulting in the forecast share of all renewables in U.S. electricity generation to average 20% in 2021, about the same as last year, before rising to 22% in 2022. The nuclear share of U.S. electricity generation declines from 21% in 2020 to 20% in 2021 and 2022.
• We expect coal consumption in the electric power sector to rise by 80 million short tons (MMst), or 18%, in 2021. The increase in the electric power sector’s use of coal reflects higher natural gas prices this year compared with last year. However, electricity generation from coal-fired power plants has not increased as much in response to rising natural gas prices as it has in the past or by as much as our models had forecast earlier this year. The lower price responsiveness of coal for electricity generation, which is likely the result of constraints on coal supply and low coal stocks, is contributing to upward pressure on natural gas prices.
• U.S. coal exports in our forecast rise by 20 MMst (29%) in 2021. Higher U.S. exports reflect rising global demand for coal amid high natural gas prices. We expect exports to remain relatively unchanged in 2022, when a 3 MMst increase in metallurgical coal exports is partly offset by a 2 MMst decline in steam coal exports. U.S. coal production growth has not kept pace with rising domestic demand for steam coal in the electric power sector and export growth, leading to a draw down in coal inventories held by the electric power sector.
• Planned additions to U.S. wind and solar capacity in 2021 and 2022 increase electricity generation from those sources in our forecast. We estimate that the U.S. electric power sector added 14.6 gigawatts (GW) of new wind capacity in 2020. We expect 17.0 GW of new wind capacity will come online in 2021 and 6.9 GW in 2022. Utility-scale solar capacity rose by an estimated 10.5 GW in 2020. Our forecast for added utility-scale solar capacity is 15.7 GW for 2021 and 18.2 GW for 2022. We expect significant solar capacity additions in Texas during the forecast period. In addition, we project that after increasing by 4.5 GW to 27.7 GW in 2020, small-scale solar capacity (systems less than 1 megawatt) will grow by 5.8 GW in 2021 and by 7.8 GW in 2022.
• U.S. energy-related carbon dioxide (CO2) emissions decreased by 11% in 2020 as a result of less energy consumption due to reduced economic activity and to end user responses to COVID-19. For 2021, we forecast energy-related CO2 emissions will increase about 7% from the 2020 level as economic activity increases and leads to rising energy use. We expect a 1% increase in energy-related CO2 emissions in 2022. We forecast that after declining by 19% in 2020, coal-related CO2 emissions will rise by 18% in 2021 and then fall by 5% in 2022.
Yes, a press release is how they have handled it in the past. We should not expect to see an 8-K.
Just to reiterate, without a press release, I am not saying this is definitely Gulfslope.
Mrs. Smith
I disagree.
Why did Gulfslope not file an 8-K, schedule 1.01 “Material Definitive Agreement” back in February 2018 for the execution of the Rowan Ralph Coffman rig contract? In addition, they referenced the Rowan Ralph Coffman rig contract on their 10-Q for the period ending 12/31/2017 which was filed with the SEC on 2/14/2018. However, Gulfslope did issue an 8K, schedule 7.01 “Regulation FD Disclosure” in February 2018 for their 2018 Company Presentation.
Secondly, why did Gulfslope not file an 8-K, schedule 1.01 “Material Definitive Agreement” when entering into the EnscoRowan (Valaris) rig contract? Instead they issued a June 19, 2019 Press Release. No reference was made to the “execution” of the EnscoRowan 102 rig contract on their next 10-Q or 10-K.
Let us agree to disagree.
Mrs. Smith
More thoughts.
1) “Undisclosed Operator” could be Gulfslope Energy or not.
2) Would Gulfslope be required to file a SEC 8-K schedule 1.01 “material definitive agreement” when entering into a rig contract since that would already be in their “normal course of business”? Gulfslope’s history on new “rig” contracts has been to issue a press release and reference the rig contract in their next 10-Q or 10-K. I suspect they are not required.
Mrs. Smith
I do not put much stock in the contract duration description on these fleet status reports. Many of the contract details are not even included in these summary fleet reports, as we have previously witnessed between Gulfslope Energy and the rig company (EnscoRowan) now Valaris.
1) The EnscoRowan ‘Valaris’ July 25, 2019 Fleet Status Report reflected the following: “awarded a one-well contract on the ENSCO 102 with GulfSlope Energy in the U.S. Gulf of Mexico that is expected to commence in October 2019.” See page 5 of the fleet report for Gulfslope Energy’s “Contract Start Date Oct. 19” and “Contract End Date Nov. 19”, which was only ONE MONTH too.
https://s1.q4cdn.com/651804090/files/Fleet_Status/2019/07/072519_Fleet-Status-Report.pdf
2) We now know Gulfslope Energy also had an option on their rig contract for an additional well, which was not referenced on the July 25, 2019 Fleet Status Report.
Excerpt from Gulfslope’s August 1, 2019 Press Release: “GulfSlope has contracted the Ensco 102 jackup rig to drill a subsalt test well at Vermilion 375 (Corvette Prospect) later this year, with an option for additional work. That rig is also suitable for drilling a second well at Tau.”
https://ir.gulfslope.com/press-releases/detail/148/gulfslope-energy-announces-key-lease-extension
Mrs. Smith
My first thoughts are.
From Gulfslope’s most recent 10-Q ”The Company has been conducting pre-drill operations for the Tau prospect which is anticipated to be re-drilled to a total depth of approximately 21,000 feet. The Exploration Plan has been filed with and approved by BOEM and the Application for Permit to Drill (“APD”) has been filed with BSEE and is pending approval. The Company plans to sign a rig contract, and arrange for bonding and insurance in conjunction with the approval of the APD.”
“VALARIS 144 awarded a 30-day contract with an undisclosed operator in the U.S. Gulf of Mexico. The contract is expected to commence late in the fourth quarter of 2021 or early in the first quarter of 2022.”
Valaris October 2021 Fleet Status Report pdf:
https://d18rn0p25nwr6d.cloudfront.net/CIK-0000314808/f9340fa3-94a7-4c04-a2e6-97d0ccf4f1e3.pdf
Note 1: Gulfslope Press Release 8/1/20019
“GulfSlope contracted the Valaris (Ensco) 102 jackup rig to drill a subsalt test well at Vermilion 375 (Corvette Prospect). That rig was also suitable for drilling a second well at Tau.”
Specificatons on Valaris 144 JU Standard Duty Modern “Undisclosed Operator 4Q21 or 1Q22”:
https://s23.q4cdn.com/956522167/files/doc_rigspecs/jackup/valaris-ju-144.pdf
Specifications on Valaris (Ensco) 102 JU Heavy Duty Harsh Environment - Stacked in the GOM:
https://s23.q4cdn.com/956522167/files/doc_rigspecs/jackup2021/VALARIS_102.pdf
Note 2: Hurricane season will end November 30, 2021 and not resume until June 1, 2022.
Mrs. Smith
The 11/5/2021 US Oil and Gas Rig Count reflects 550 rigs an increase of 6 rigs. The GOM Offshore Rig Count remained unchanged from the previous week and is currently showing 13 rigs.
http://www.dnr.louisiana.gov/assets/TAD/data/drill_weekly/ogj_rig_count.pdf
http://www.dnr.louisiana.gov/assets/TAD/data/drill_weekly/WeeklyRigCountUpdate.pdf
Mrs. Smith
November 2021 (MER) Monthly Economic Review
Source: Jack Kleinhenz, Ph.D., CBE Chief Economist National Retail Federation
For a clearer narrative click link to view graphs and full report: https://cdn.nrf.com/sites/default/files/2021-11/2021%20November%20MER.pdf
SYNOPSIS | Unwrapping the NRF Holiday Sales Forecast
A few excerpts from the synopsis:
NRF is forecasting that this year’s holiday sales will grow between 8.5 percent and 10.5 percent over 2020. That works out to between $843.4 billion and $859 billion. By comparison, holiday sales last year grew 8.2 percent from 2019 and totaled $777.3 billion. Our forecast includes online and other non-store sales, which we expect to increase between 11 percent and 15 percent to between $218.3 billion and $226.2 billion. That is up from $196.7 billion last year. We expect retailers will hire between 500,000 and 665,000 seasonal workers, up from 486,000 seasonal hires in 2020.
A savings buffer of roughly $2.5 trillion accumulated during the pandemic has supercharged consumer spending this year while income is growing in the form of more jobs, more hours and higher wages reflecting businesses’ competition for workers. Household wealth has risen strongly and set another record high in the second quarter (the latest data available). As wealth accumulates, consumer confidence increases and triggers consumer spending. Confidence also makes consumers comfortable using credit, and easily available credit could provide additional liquidity for spending this holiday season.
The strong growth in income and stockpiled savings should help spending overcome the inflationary environment that has become a big headache for both consumers and retailers. Inflation has been driven both by the jump in consumer demand and supply chain challenges in meeting that demand, and it is unclear when either will end. The challenge when – and if – sales begin to fall will be whether it is caused by weaker demand or reduced product availability.
U.S. households are expected to spend more money on heat this winter than last winter thanks to higher energy prices that could siphon off money that could otherwise go to holiday spending. Energy shortages and high demand have made the outlook uncertain, and a cold winter could make the problems even worse. American consumers have already been paying more for gasoline, and higher heating and electricity costs could follow.
The National Oceanic and Atmospheric Administration says there is a 70 percent to 80 percent chance that a La Niña will bring cold weather to the Northern Hemisphere this winter. That would be a repeat of last year, and the climate phenomenon has coincided with stronger retail sales in the past.
Biden's heating oil fiasco
By Linnea Lueken
During World War II, U.S. coal companies ran radio advertisements cautioning people to buy only what they needed for immediate use. The government anticipated needing to use much of the available coal to keep pace with the urgent demand for it by the military. Eventually, the U.S. government rationed gasoline and oil, too.
Eighty years later, electric utilities are once again warning Americans that we could be in for a long, cold, dark winter. However, the difference is, today's shortages are not due to a global conflict causing the consumption of more fuel than ever before.
Almost all countries are increasing energy consumption compared to last year. Yet it reflects a return to normal, not a historic increase.
As the world climbs out of government-inflicted COVID-19 shutdowns, energy demand is certain to climb. In fact, all energy sources and fuels are in high demand. Such is why the price of oil and natural gas continues to rise.
European utilities are even switching from natural gas back to coal power this winter, just to keep the lights on and the heat running. According to a report from Bloomberg Quint, American utility executives are warning that we may well do the same, and even then, we may still see blackouts in some areas.
The latest Energy Outlook report from the U.S. Energy Information Administration (EIA) explains that "[e]lectricity generation from coal-fired power plants has not increased as much in response to rising natural gas prices as it has in the past, or by as much as our models forecasted in recent STEOs. The lower price responsiveness of coal for electricity generation, which is likely the result of constraints on coal supply and low coal stocks, is contributing to upward pressure on natural gas prices."
EIA continues, explaining its predictions for the coming winter: "We forecast that average U.S. household expenditures for all major home heating fuels will increase significantly this winter primarily because of higher expected fuel costs as well as more consumption of energy due to a colder winter."
Even if it's not a particularly cold winter, EIA says your bill will still be higher: "Altering our assumptions for a 10% colder-than-expected winter significantly increases forecast expenditures, while a 10% warmer-than-expected winter still results in increased expenditures, because of price increases."
Although White House press secretary Jen Psaki makes snide jokes about "the tragedy of the treadmill that's delayed" (demonstrating a lack of awareness and tact that is becoming characteristic of the Biden administration), the reality is that there are essential materials and equipment that aren't reaching vital energy industries. Supplies used in offshore drilling and production, for example, that normally take only a few days to deliver now take weeks.
The Biden administration can make light of the supply chain situation all they want, often implying that it primarily affects the wealthy, who can afford to buy treadmills and other nonessential luxury goods. However, the downstream impact of supply shortages and delays will disproportionately harm America's poorest.
South Carolina residents are already being warned that their heating bills could rise by at least $11 per month this year and into next. That may not seem like much, but it matters for people who survive on tight or fixed budgets, especially when everything else they need is more expensive due to historic inflation. Gasoline, food, winter clothing, and practically every product in between is more expensive due to ever-increasing inflation.
As if our domestic problems were not enough, remember when Russia was our worst enemy ever? According to the left, Russia singlehandedly interfered with the 2016 election, helping Donald Trump defeat Hillary Clinton.
So why did President Biden allow completion of the Nord Stream 2 pipeline that Trump blocked, which will supply Germany with natural gas from Russia? This comes as we import a record amount of natural gas from Russia. Even worse, why did Biden kill the Keystone XL pipeline? And why does the administration impose increasingly strict regulations on our oil and gas industries?
In other words, Biden is suppressing U.S. energy production while buying energy from our rivals. When you also consider the Biden administration's unwavering devotion to moving away from coal and other fossil fuels, it's not hard to see why production is struggling to keep up with increased demand. In less than ten months, Biden has terminated U.S. energy independence.
Sadly, the supply chain crisis and fuel shortages that will harm Americans this winter and beyond have been created by dumb, but deliberate, government decisions, not natural market fluctuations, and not a world war.
Linnea Lueken (llueken@heartland.org) is a research fellow with The Heartland Institute.
OPEC+ disappoints Biden, sticks with current output plan
https://www.aljazeera.com/economy/2021/11/4/opec-sticks-to-plan-to-raise-oil-output-by-400000-bpd
Excerpts: “The Organization of the Petroleum Exporting Countries and its allies on Thursday ignored calls by the United States to boost oil output beyond its current plan and help ease soaring energy prices.
OPEC and its allies led by Russia, a grouping known as OPEC+, ended a meeting on Thursday with an agreement to stick to already-agreed plans to raise oil output by 400,000 barrels per day (bpd), sources told Reuters News Agency.”
OPEC+ Press Release:
https://www.opec.org/opec_web/en/press_room/6690.htm
The 22nd OPEC and non-OPEC Ministerial Meeting, held via videoconference, concluded on Thursday November 4 2021.
The meeting reaffirmed the continued commitment of the Participating Countries in the Declaration of Cooperation (DoC) to ensure a stable and a balanced oil market, the efficient and secure supply to consumers and to provide clarity to the market at times when other parts of the energy complex outside the boundaries of oil markets are experiencing extreme volatility and instability, and to continue to adopt a proactive and transparent approach which has provided stability to oil markets. In view of current oil market fundamentals and the consensus on its outlook, the Meeting resolved to:
1. Reaffirm the decision of the 10th OPEC and non-OPEC Ministerial Meeting on 12 April 2020 and further endorsed in subsequent meetings including the 19th OPEC and non-OPEC Ministerial Meeting on the 18 July 2021.
2. Reconfirm the production adjustment plan and the monthly production adjustment mechanism approved at the 19th OPEC and non-OPEC Ministerial Meeting and the decision to adjust upward the monthly overall production by 0.4 mb/d for the month of December 2021, as per the attached schedule.
Link to schedule:
https://www.opec.org/opec_web/static_files_project/media/downloads/Production%20table%20(Nov%202021).pdf
3. Reiterate the critical importance of adhering to full conformity and to the compensation mechanism, taking advantage of the extension of the compensation period until the end of December 2021. Compensation plans should be submitted in accordance with the statement of the 15th OPEC and non-OPEC Ministerial Meeting.
4. Hold the 23rd OPEC and non-OPEC Ministerial Meeting on 2 December 2021.
Let us see where OPEC takes us today shall we?
WTI $83.22/bbl up 3.02% December Contract, 11/4/2021 8:34am CDT
https://oilprice.com/oil-price-charts/#WTI-Crude
Mrs. Smith
In an effort to improve everyone’s time management, I have chosen to list a few salient points from my research or just my opinion. Where appropriate I will include links for those wanting more detail.
1) Is OPEC+ playing cat and mouse? Would you produce more oil and risk lowering the price of crude? Or would you continue to ask top dollar per barrel and hold on to your oil reserves while still meeting your financial goals?
2) OPEC+ could change their minds and increase oil and gas production to maintain their market share, but I am not convinced they will. More likely they might agree to increase production, but then fail to follow through. I see oil and gas to continue trending up.
3) It is being reported OPEC+ fell short of meeting their October production increase obligation (400,000 million barrels per day) by over 200,000 million barrels per day (50%).
4) U.S. Commercial Crude Oil Inventories (excluding SPR) have increased six weeks in a row.
Weekly Petroleum Status Full Report for week ended October 29, 2021 released this afternoon with graphs and tables: https://www.eia.gov/petroleum/supply/weekly/pdf/wpsrall.pdf
Mrs. Smith
Transcript of Chair Powell’s Press Conference Opening Statement November 3, 2021:
https://www.federalreserve.gov/mediacenter/files/FOMCpresconf20211103.pdf
Video of Chair Powell’s FOMC Press Conference November 3, 2021:
https://www.federalreserve.gov/live-broadcast.htm
Mrs. Smith
OPEC Plus? Start Thinking OPEC Minus
By Julian Lee
November 2, 2021, 7:55 AM CDT
For tables and charts see link: https://www.bloomberg.com/news/articles/2021-11-02/opec-plus-start-thinking-opec-minus-oil-strategy?srnd=markets-vp
*Four Middle Eastern countries can pump beyond their baselines
*Most other producers can’t meet their OPEC+ baseline
The Organization of Petroleum Exporting Countries has taken many forms down the decades, with oil-producing countries joining and then leaving the cartel, and grand alliances formed to shore up crude markets.
The next iteration might come to be remembered as ‘OPEC Minus’, writes Bloomberg oil strategist Julian Lee.
Pressure -- both political and from customers -- is growing for producers to pump more crude, with prices above $80 a barrel and an energy crisis adding an unexpected source of additional petroleum consumption.
Oficially that demand can be met by 23 nations in the OPEC+ alliance. On paper, they have the capacity to pump 5.6 million barrels a day more than they are today -- the aggregation of baselines they were allowed to ramp up to under a pact to support oil prices.
The reality is that, yes, spare production capacity does exist, but far fewer nations can materially help if the clamor for crude intensifies.
While, Saudi Arabia, Iraq and the UAE can all add more than their OPEC+ baselines imply, others - notably Russia, Angola, Nigeria, Malaysia and Kuwait - can contribute a lot less than those numbers suggest. Yet under the terms of their agreement, those members with capacity to spare aren’t permitted to fill the gap left by their struggling allies.
Spare Capacity
Assessed production capacities give a very different picture from OPEC+ baselines of how much more member countries can pump.
The table below details my own assessment of spare production capacity in each of the 23 OPEC+ member countries, with an explanation of my reasoning for each in the paragraphs that follow.
Note: These are estimates of sustainable production capacity that can be maintained for several months; output in a single month may exceed these levels, but such levels cannot be sustained.
Note: Iran, Libya and Venezuela are exempt from the OPEC+ output deal and therefore were not assigned baseline production levels.
Algeria
Production has tracked the country’s quota both before and since the pandemic and there are no real reasons to doubt its OPEC+ baseline as an estimate of production capacity.
Angola
The gap between Angola’s crude production and its OPEC+ target is widening as natural decline erodes output.
Sustainable crude production capacity of 1.2 million barrels a day is based on the highest production level achieved in 2021.
Congo Republic
Congo pumped well above its target in 2021, but output was on a downward trend that has continued this year. Output decline hasn’t reversed with the country’s rising OPEC target, suggesting capacity limitations.
Equatorial Guinea
Shares the problem with other West African producers of lack of investment amid natural decline at offshore fields. Even when flouting its OPEC+ target earlier this year, production didn’t exceed 120,000 barrels a day.
Gabon
Production remained close to, or even above, its OPEC+ baseline since at least January 2020.
Iran
Until sanctions on oil exports are eased, production will remain constrained around its current level. If sanctions are eased, Iran could quickly add about 1.3 million barrels a day.
The sustainable crude production capacity estimate of 2.5 million barrels a day is based on current political conditions.
Iraq
One of few OPEC+ countries with spare capacity significantly above its OPEC+ baseline. Production peaked at close to 4.8 million barrels a day in 2019, well above its quota at the time.
Kuwait
Kuwait Oil Company reported declining production capacity for a third year in its 2020-21 annual report. Production in the Neutral Zone shared with Saudi Arabia remains well below its potential and will only rise if both countries agree to open the taps.
Sustainable crude production capacity, estimated at at 2.71 million barrels a day, includes Kuwait’s 50% share of restricted Neutral Zone production.
Libya
Exempt from the OPEC+ deal, Libya is already pumping all it can. Production risks are more heavily weighted to the downside, amid simmering tensions in the country and lack of investment in maintenance and drilling.
Nigeria
Like Angola, Nigeria’s production has been slipping, as lack of investment and repeated leaks at pipelines and export terminals undermines output. Situation has got so bad some refiners are shunning Nigerian crude.
In addition to crude, Nigeria pumps about 200,000 barrels a day that it classifies as condensates, which are outside the OPEC+ deal.
Saudi Arabia
Saudi Aramco declared a sustainable production capacity of 12 million barrels a day in its 2019 listing prospectus. Another 175,000 barrels was added in 2Q21, according to the company’s quarterly report. It is investing to lift capacity to 13 million barrels a day by 2027.
Absent a short-term emergency, it is unclear how close to this the country would be willing to pump, preferring to keep some in reserve.
UAE
Demanded a higher OPEC+ baseline to reflect its increased production capacity, bringing the output deal close to collapse. Continues to invest toward a goal of 5 million barrels a day by 2030.
Venezuela
Exempt from the OPEC+ deal, Venezuela is pumping all it can. It’s just not very much.
Azerbaijan
Output has failed to keep pace with rising target and was in decline before joining OPEC+.
Production at the flagship Azeri-Chirag-Deepwater Gunashli project slipped by 6.6% q/q to 452,000 barrels a day in 2Q21.
Bahrain
Most production comes from the Abu Safah field, shared with and operated by Saudi Arabia. The onshore Bahrain field has a capacity of about 45,000 barrels a day.
Brunei
Brunei was pumping about 120,000 barrels a day in the final months of 2019, which fell to 106,000 barrels in the first quarter of 2020.
Kazakhstan
Recent production levels were reduced by work at the Tengiz field, the country’s largest producer, so don’t give an accurate estimate of spare capacity.
Crude production rebounded to an 18-month high of 1.55 million barrels a day in October.
Malaysia
Another of the countries seeing production slide even as its OPEC+ target goes up. Latest dip appears to be due to unplanned maintenance work.
Mexico
Joined the OPEC+ cuts for only two months in May and June 2020, with plans to boost output. Subsequent production levels have remained below its baseline.
Oman
Was pumping about 870,000 barrels a day before joining the latest OPEC+ cuts, with a brief, but probably unsustainable, surge in March 2020.
Russia
Russia’s OPEC+ baseline of 11 million barrels a day, rising to 11.5 million barrels in April, bears no relation to past production levels. Peak production of 11.35 million barrels a day reached during the free-for-all in April 2020 included about 900,000 barrels a day of condensates, which the Energy Ministry doesn’t report separately.
South Sudan
Civil unrest has destroyed much surface infrastructure at fields and slashed production capacity from pre-war levels. Plans to boost output require internal stability.
Sudan
Sudan is seeking to more than double capacity by 2025, but needs to attract foreign investors.
Not sure I agree that WTI will be below $70/bbl next summer. With hyperinflation still a concern in that timeframe many wealthy individuals and countries will be buying up crude as a hedge, which will hold value better than currency. And crude is more liquid than gold. Many variables involved, but in my opinion crude should hold it’s valuation or increase as long as inflation is in play and demand stays on it’s current trajectory.
Reminder, OPEC will be meeting on Thursday.
Mrs. Smith
Chronic Underinvestment Could Send Energy Prices Higher For Longer By Irina Slav - Oct 31, 2021, 6:00 PM CDT
WTI $84.13/bbl December Contract, November 1, 2021, 8:03 am CDT: https://oilprice.com/oil-price-charts/#WTI-Crude
Wholesale Spot Petroleum Prices, 10/29/21 Close https://www.eia.gov/todayinenergy/prices.php
Crude Oil ($/barrel) Percent Change
WTI 83.50 +0.9
Brent 83.10 -0.4
Louisiana Light 83.70 +0.8:
For charts to article see attached link: https://oilprice.com/Energy/Energy-General/Chronic-Underinvestment-Could-Send-Energy-Prices-Higher-For-Longer.html
*Just two years ago, many forecasters predicted that oil and gas prices were likely to remain lower for longer.
*Thanks to a perfect mix of underinvestment and rebounding demand, energy prices are soaring.
*The next crunch could be caused by actual shortages of fossil fuels, just like this year’s record coal prices were caused as much by the sudden spike in demand.
Less than two years ago, the energy industry was being advised to get used to the fact that oil and gas prices would be lower for longer because there was so much supply. Coal was on its way out, and the future looked green and bright.
Fast forward to October 2021. We have record-high gas prices, oil over $80 per barrel, and a boom in coal demand that has led to a surge in prices that even a year ago was probably unthinkable for many. What’s next? Apparently, nobody knows.
Oil demand was supposed to be nearing its peak, but now, forecasters are revising their forecasts because oil demand appears to be quite resilient to all attempts to stifle it artificially.
Gas demand is through the roof and so are prices. And, like on oil, analysts are split in their opinions of whether this is only a temporary, short-lived problem or whether it could extend over a longer period.
“This will be a crisis that is reoccurring over the next three or four years, simply because we don’t have a lot of new natural gas supply coming into the market in that period,” Richard Gorry from JBC Energy Asia told CNBC this week. “By 2025, the situation may change, but I think we definitely have a couple of years where we’re going to be looking at high energy prices,” he added.
Energy Aspects Amrita Sen goes further: in a recent opinion piece for the Financial Times, Sen argued that high fossil fuel prices are here to stay, but instead of trying to bring them down, stakeholders should embrace the fact. The reason: higher fossil fuel prices will help us move away from them and replace them with lower-carbon energy sources.
Others, however, believe the current price spike is a temporary occurrence. Citi Research’s head of energy strategy, Anthony Yuen, told CNBC that the current prices were the result of “a confluence of factors”. This, he said, could cause a decline in demand growth and push the market into a potential oversupply.
“Never say never,” he told CNBC. “It partly depends on [the] weather. But then, once you factor in a number of supply and demand factors, the situation probably will be much better.”
On the supply side, U.S. companies are planning billions of investments in another wave of LNG export facilities. Russia is pumping at a record pace and planning further production boosts. Qatar is expanding its gas production capacity substantially over the next few years, and Australia has set its sights on becoming the world’s largest LNG exporter.
Yet, according to Energy Aspects’ Sen, higher gas prices, at least in LNG, are here to stay because of the slowdown in new final investment decisions amid the recent glut. There’s underinvestment in both oil and gas, Sen wrote for the FT, and this may not change the way it changed during previous commodity cycles because of the ESG pressure investors are putting on the energy industry together with banks and other lenders.
“Today, investment in fossil fuel is vilified and financing has become sparse as big western banks withdraw,” Sen wrote, adding that we have not yet seen the full effect of that slowdown in oil and gas investments prompted by the rise of the ESG trend. This means that oil, gas, and coal prices still have higher to go. Because demand is sticking around.
Fossil fuels currently account for some 84 percent of global energy demand, according to Sen. This is the same figure as it was in 1980. This means that demand for oil and gas—and to a lesser extent, coal—is a stubborn one, and it can only be reduced with radical measures or natural trends such as underinvestment that leads to prohibitively high prices.
Yet planned investments in oil and gas are high enough to prompt the UN Environmental Program to warn they are too high for Paris Agreement comfort. In a recent report, the program warned that oil and gas production plans by the 15 biggest producers are at great odds with the Paris Agreement emission targets. In other words, these 15 biggest producers continue to bet on oil and gas, despite emission ambitions, including their own stated net-zero targets.
So, it will be a while before supply catches up with demand, but the price spike appears to be susceptible to the mitigating effect of news reports such as the one about Gazprom beginning to pump gas into European storage hubs after filling up the ones at home. This effect, by the way, has prompted suggestions that the energy crunch in Europe was not in fact caused by a shortage of gas but was more of a speculative nature and the result of trader jitters.
Yet if Energy Aspect’s Sen is right about the seriousness of underinvestment, the next crunch could be caused by actual shortages of fossil fuels, just like this year’s record coal prices were caused as much by the sudden spike in demand as the years of underinvestment as the developed world cheered the demise of the dirtiest fossil fuel.
“It’s alive!”: Offshore Drillers Start Resuscitating Idle Drillships, Released 10/29/2021, by Teresa Wilkie an offshore rig market analyst for Bassoe Analytics
See link for charts: https://www.oedigital.com/news/491698-it-s-alive-offshore-drillers-start-resuscitating-idle-drillships
We expected it to happen just not necessarily this soon. But now it’s official, several cold-stacked rigs are about to be reactivated for new jobs in the Golden Triangle, and Valaris is taking the lead. Just last week, the driller confirmed that it will reactivate 6th generation, ultra-deepwater drillship Valaris DS-4 for a minimum 580-day deal with Petrobras Brazil. The rig has been idle for over two years.
This follows other recent announcements from the same rig owner for 7th generation drillships Valaris DS-11, which will also be revived for a long-term deal off Brazil with Petrobras, and Valaris DS-16, which will undertake a two-year deal with OXY in the US Gulf of Mexico starting next year.
Last year the driller took a tough stance on its uncontracted fleet, preservation stacking a hefty 19 rigs (9 floaters and 10 jackups) due to the lack of opportunities in the market. Now it appears to be front of the queue to bring those rigs back out and take advantage of the recovering market.
Meanwhile, Seadrill will reactivate its 7th generation drillship West Jupiter, also for a multi-year deal with Petrobras Brazil, starting in late 2022. Additionally, stacked drillships Auriga and West Carina (both of which haven’t worked in over a year) will also be ramped up and put out to work in 2022 for long-term deals in the USA and Brazil, respectively.
Shrinking supply warrants resuscitations
So far, most reactivations have been confirmed for modern, ultra-deepwater drillships due to a rapid increase in competitive utilisation this year, a strong demand outlook for 2022 and 2023 with longer-term campaigns and at higher dayrates.
Additionally, supply in this segment has also plummeted since the last upcycle, according to Esgian Rig Service 44 drillships have been removed from the fleet since 2015. And not to mention the increased cold stacking that took place last year by the bigger rig players.
The drillship market is made up of 58 units currently drilling - as of October 20th - and 11 of the 16 hot/warm stacked assets now have future work in place.
With the pool of ready-to-go drillships shrinking, as shown in Figure 1, could this mean more of the remaining 18 cold stacked units will return to operation? We expect to see reactivations initially for rigs that have been idle for the least amount of time, that have been well maintained and that are still “top tier”, younger assets.
Semisub and jackup utilization have not yet reached levels comparable to drillships and therefore there has been limited rigs confirmed for reactivation on this side, but that doesn’t mean it may not happen further down the line if the market continues its recovery.
Youth versus experience
Stranded newbuilds are being considered again too, though there is still a preference to reactivate a rig with a proven track record than bringing out a newbuild that has never worked before, not to mention all the additional costs and potential issues that often come along with a newbuild shakedown.
Nevertheless, Saipem has confirmed a bareboat charter of the stranded 7th generation drillship Samsung Santorini, which will be brought out of the yard in South Korea and put to work for Eni in the US Gulf of Mexico next year, and rumors suggest a few other newbuilds are currently under discussion too.
And there are plenty to choose from, with 18 under construction or stranded assets still in yards and just three confirmed for delivery so far.
Reactivation economics could help set dayrate benchmarks
Valaris says that it will cost in the range of $30 to $45 million to reactivate each of its preservation stacked floaters and that in most cases it expects the initial contract to pay for these costs. Transocean, meanwhile, estimates that the total cash cost of reactivating a cold-stacked asset in its fleet starts at $60 million and could go upwards of $100 million.
Because most drillers will not reactivate unless they can be sure to recuperate costs, it may be that reactivation economics could become an important factor in setting drillship dayrates benchmarks in the coming months, especially if more cold rigs are brought into circulation.
Recent contracts fixed in the Golden Triangle have been as high as $300,000 per day for active rigs, although the majority have been around the mid- $200,000 mark. As can be seen by the estimated examples in Figure 2, ideally a reactivation will be based on receiving a contract on a higher dayrate (somewhere around the $300,000 mark) and a duration of two years or more, but it is still possible to pay back the investment with one or the other assuming rig operating costs of around $120,000 per day.
However, this may not be the case if reactivation costs are closer to Transocean’s estimates than Valaris’, in which case would likely require the $300,000 dayrate plus a multi-year duration to make the reactivation investment worthwhile.
The difference in reactivation costs can vary depending on how the rig has been maintained during its stacked period, but also very importantly, how long it has been idle for. The longer the stacked period, often the higher the cost of reactivation and hence the higher the dayrates must go before its worthwhile investing in putting them in the market.
Danger of oversupply returning?
Competitive drillship utilization has recovered by 17 percentage points since this time last year and is now sitting over 76%. Esgian Rig Service forecasts that this figure will rise above 80% before year-end making its way to the sweet spot of 85% by H1 2022, should all projects move ahead as planned.
Esgian reported in a previous article that idle rigs can pose a threat to recovery if too many are brought back to the market at once, resulting in an oversupply which puts pressure on utilization and dayrates.
Drillers must beware that this optimistic outlook could change quite quickly, and therefore caution must be taken.
However, so far there have been no reactivations on speculation and drillers appear to be sticking to their word about discipline. Rig restorations have only been confirmed for firm, long-term deals and due to the new rebound in deepwater demand the drillship market looks like it can handle the added capacity. For now, at least…
About the Author:
Teresa Wilkie is an offshore rig market analyst for Bassoe Analytics with 10 years of experience tracking the offshore rig and subsea vessel markets.
The 10/29/2021 US Oil and Gas Rig Count reflects 544 rigs an increase of 2 rigs. The GOM Offshore Rig Count remained unchanged from the previous week and is currently showing 13 rigs.
http://www.dnr.louisiana.gov/assets/TAD/data/drill_weekly/ogj_rig_count.pdf
http://www.dnr.louisiana.gov/assets/TAD/data/drill_weekly/WeeklyRigCountUpdate.pdf
Mrs. Smith
President Biden: "Disappointed" Saudis, Russians, and Chinese "Basically Didn't Show Up" For Climate Summit, Posted By Tim Hains On Date October 31, 2021
President Biden said during a press conference Sunday in Rome that the international climate summit about to take place in Scotland would have been better if Saudi Arabia (the top Oil producer), Russia (the top Natural Gas producer), and China (the top CO-2 emitter) had "showed up."
https://www.realclearpolitics.com/video/2021/10/31/biden_disappointed_that_russia_and_china_didnt_show_up_to_climate_summit.html
JEFF MASON, REUTERS: On climate and energy, can the world and others be confident that you will be able to follow, or make good on, the promises on climate change that you have made when you're at Glasgow without a vote having taken place on your bill?
And on the saum topic climate, some NGOs are already saying that the G-20 commitments today were underwhelming. How do you respond to their criticism that the G-20 response is not a good sign for COP-26?
PRESIDENT JOE BIDEN: I'll answer both questions.
Number one, I believe we will pass my Build Back Better plan and I believe we will pass the infrastructure bill. Combined they have $900 billion in climate resistance and dealing with climate and resilience and it's the largest investment in the history of the world that's ever occurred and it's going to pass, in my view, but we will see. We'll see. You know, you've all believed it wouldn't happen from the very beginning and the moment I announced it and you always seem amazed when it's alive again.
You may turn out to be right. Maybe it won't work, but I believe we'll see by the end of next week at home that it's passed.
With regard to -- and by the way, the infrastructure bill delivers an awful lot of things, in terms of everything from tax credits for electric vehicles, to making sure we are able to invest literally billions of dollars in everything from highways, roads, bridges, public transport, roads, et cetera, but we'll see.
And with regard to the disappointment. The disappointment relates to the fact that Russia and -- and -- and, including not only Russia, but China basically didn't show up in terms of any commitments to deal with climate change, and there's a reason why people should be disappointed in that.
I found it disappointing myself.
But what we did do, we passed a number of things here to end the subsidization of coal. We made commitments here from across the board, all of us, in terms of what we're going to bring to the G-26 and I think, you know, as that old trite saying goes, the proof of the pudding will be in the eating.
I think you'll see we've made significant progress and more has to be done but it's going to require us to continue to focus on what China is not doing, what Russia is not doing, and what Saudi Arabia is not doing.
MASON: You also met with energy consumers about supply. What steps are you considering taking if OPEC-plus does not raise supply, and do see any irony pushing them to production at the same time you're going COP-26 to urge people to lower emissions?
BIDEN: Well, on the surface it seems like an irony, but the truth you all know... is the idea that we're going to be able to move to renewable energy overnight, and from this moment on not use oil or gas or Hydrogen, it's just not rational.
Certain things we can wipe out... and we should get rid of, my proposal to end Methane to deal with a whole range of things. It does on the surface seem inconsistent. But it is not at all inconsistent. No one anticipated that this year we'd be in a position, or next year, that we're not use oil or gas or be engaged in any fossil fuels.
We're going to stop subsidizing fossil fuels, and it makes the argument that we should move more rapidly to renewable energy. Wind and solar and other forms of energy... I admit to you. We're going to COP to deal with renewable energy, and I'm saying, "Why are you guys cutting off oil and raising the price just to make it look harder for us? But, it's a legitimate question.
i think though that if anybody thinks about it, no one ever thought. For example, it will take us between now and 2030 to have half the vehicles in America electric vehicles, so the idea that we won't need gasoline for automobiles is just not realistic, but we will get to the point by 2050 we'll have zero emissions.
EIA projects non-OECD Asia to become the largest importers of natural gas by 2050
See link below for charts:
https://www.eia.gov/todayinenergy/detail.php?id=50017
In our International Energy Outlook 2021 (IEO2021), we project that non-OECD countries in Asia will collectively become the largest importers of natural gas by 2050. In 2020, the countries of OECD Europe were collectively the largest importers of natural gas, followed by Japan and South Korea combined, and then non-OECD Asia, which includes China and India.
All of these groups of countries import natural gas because their consumption exceeds their domestic supply. We project that continued economic growth in non-OECD Asia, led primarily by China and India, will more than double net imports of natural gas into the region by 2050. To meet the natural gas needs of these growing economies, we project that global natural gas production will increase steadily along with exports from the three largest natural gas producers: the United States, Russia, and the Middle East.
In our IEO2021 Reference case, the United States, Russia, and the Middle East continue to expand natural gas production through 2050, and the United States remains the largest natural gas producer worldwide, producing almost 43 trillion cubic feet (Tcf) in 2050 compared with 34 Tcf in 2020. The United States, Russia, and the Middle East all have large proven reserves of both natural gas and oil as well as the processing and transportation infrastructure to support production increases. Liquefied natural gas (LNG) terminals and transportation vessels create an outlet for natural gas produced in the United States and the Middle East to reach markets in Asia and Europe.
We project that Russia, in particular, will show the largest growth in net exports, more than doubling over the projection period to remain the largest net exporter of natural gas by 2050, at more than 14 Tcf. Close proximity to Europe and Asia will facilitate growth in Russia’s net natural gas exports through established pipeline infrastructure, potential future pipeline additions, and liquefied natural gas exports. During the next 10 years, we project that the United States will see its most rapid period of growth; net exports of U.S. natural gas nearly double as the United States expands its LNG infrastructure and produces natural gas at high volumes.
LNG demand to rise 25-50% by 2030: Morgan Stanley, Released October 28, 2021, Arabnews.com
https://www.arabnews.com/node/1954836/business-economy
SINGAPORE: Demand for liquefied natural gas is expected to rise by 25 to 50 percent by 2030, making it the fastest growing hydrocarbon over the next decade, analysts from Morgan Stanley Research said in a note on Monday.
Morgan Stanley has raised its long-term LNG price outlook to $10 per million British thermal units (mmBtu), expecting spot prices of the super-chilled fuel to average 40 percent higher over the next decade, versus the past five years.
Asian spot LNG prices hit a record above $56 mmBtu earlier this month as surging demand ahead of the northern hemisphere winter spurred by an economic rebound from the pandemic outstripped supply.
Morgan Stanley said at least 73 million tons per annum (mtpa) of new projects are needed to meet LNG demand by 2030. This will require an additional $65 billion of new projects, on top of the $200 billion of projects already under construction which were sanctioned since 2019.
“Contrary to investor expectations, the world is going to need more LNG in the initial phase of the energy transition,” the analysts said.
“Competing technologies for natural gas are not being developed fast enough, and there are significant benefits in reducing coal consumption while greener fuels are commercialized.”
Projects with lower emission intensity will be more sought after and are more likely to progress, they said.
While higher gas prices are likely to underpin further investment in LNG, supply will be slower to respond than in previous cycles, the analysts said.
What Happens With Oil Prices If Cushing Inventories Fall To Zero?, By Tsvetana Paraskova - Oct 28, 2021, 7:00 PM CDT
*Stocks At Cushing Have Halved Since April 2020 Market Rout
*Storage at Cushing alone has the potential to really rally the market to the moon
*The WTI-Brent spread is now at the narrowest it has been in just over a year
https://oilprice.com/Energy/Energy-General/What-Happens-With-Oil-Prices-If-Cushing-Inventories-Fall-To-Zero.html
Rebounding U.S. oil demand, a slow recovery of domestic production, and extreme weather-related events have drawn many barrels this year out of the key U.S. crude hub at Cushing, Oklahoma. Crude oil stocks at Cushing—the delivery hub for the WTI Crude futures contract—have more than halved since April 2020, when the market was fretting about high inventories as the pandemic forced governments to announce widespread lockdowns. Back then, a lack of storage at the Cushing delivery hub contributed to sending WTI Crude down to a negative price.
The picture is quite the opposite a year and a half later after U.S. oil demand recovered to pre-pandemic levels. At the same time, production remains stifled by strict capital discipline in most of the U.S. shale patch and by storms in the winter and hurricanes over the summer.
Stocks At Cushing Have Halved Since April 2020 Market Rout
From more than 60 million barrels of crude inventory at Cushing back in April 2020, crude stocks at the hub dipped to below 30 million barrels in the week to October 22, 2021, EIA data showed on Wednesday.
Crude stock at the Cushing hub fell by a massive 3.9 million barrels week on week to stand at 27.3 million barrels as of October 22, the EIA's weekly inventory report showed on Wednesday. Cushing crude inventories were down by 54.4 percent compared to the same week last year, and down by 40.6 percent compared to the same week in the pre-pandemic year 2019.
Last week's dip to below 30 million barrels marks the lowest level of Cushing crude inventories since the first week of October in 2018.
How Did We Get Here?
Demand in the U.S. has rebounded this year from the pandemic slump of 2020. Per the EIA data, total products supplied—a proxy for demand—over the last four-week period averaged 20.8 million barrels a day, up by 9.9 percent from the same period last year.
Total U.S. oil demand reached a record high for the month of September at 20.6 million bpd, API's Monthly Statistical Report (MSR), based on U.S. petroleum primary market data through September, showed.
The data "reinforced a combination of developments that has been recurrent so far in 2021 – that is, demand outpaced supply, inventories fell and, consequently, imports and prices rose," API's Chief Economist Dean Foreman wrote earlier this month.
At the same time, U.S. crude oil production has hovered around 11.3-11.4 million bpd in recent months, down from a peak of 13 million bpd just before the pandemic. The Texas Freeze and Hurricane Ida sent domestic crude production down to 10 million bpd for weeks in February and September, respectively.
Meanwhile, the U.S. shale patch has been cautious in ramping up activity, even at $80 oil. Instead, most producers, especially the listed ones, prioritized returns to shareholders over production growth.
Stocks Hitting Tank Bottoms?
The market was closely watching the Cushing data in EIA's weekly report as inventories at the delivery hub for the WTI futures contract could give it clues about where the U.S. benchmark is headed.
"[W]orries over hitting tank bottoms should continue to be constructive for WTI timespreads," Warren Patterson, Head of Commodities Strategy at ING, said on Thursday.
Ole Hansen, Head of Commodity Strategy at Saxo Bank, commented: “At this rate of decline Cushing could hit its operational floor within a few weeks. A stunning reversal from last year when the pandemic prompted a glut of crude oil so big that exhausted storage capacity briefly forced WTI below zero. Watch those WTI front end spreads."
HFI Research, an energy research service, noted that "It's not where we are today, it's where we are headed given the recent draw/builds. We see flat US crude storage through refinery maintenance season before draws resume into year-end."
"Storage at Cushing alone has the potential to really rally the market to the moon," Bob Yawger, director of energy futures at Mizuho, told Reuters.
Low Cushing Inventories Support WTI
Stocks at Cushing at a three-year low have resulted in a narrowing of the discount of the WTI Crude prices to Brent Crude prices. As of early Thursday, WTI Crude traded at a discount of $1.67 a barrel to Brent Crude with prices down, mostly due to Iran saying that nuclear talks would resume by the end of November. Prices were also weighed down by the inventory build of 4.3 million barrels in U.S. commercial crude stocks. In fact, the dip in Cushing stocks was the only bullish point in EIA's weekly report for the week to October 22.
Earlier in October, the WTI to Brent discount was more than $4 per barrel. The spread is now at the narrowest it has been in just over a year, since September 2020.
The WTI futures curve points to high short-term demand as the backwardation in the one-year time spread is now higher than $10 a barrel.
The WTI December 2021 contract traded at a premium of over $10.30 per barrel to the December 2022 contract early on Thursday, suggesting inventories at Cushing could stay at low levels for months as storing oil is uneconomical in such a steep premium for nearer-dated crude.
Earlier this week, the premium of the WTI December 2021 contract to the December 2022 futures contract hit a high of $12.48 per barrel. This was the largest such premium since at least 2014, as per Refinitiv Eikon data cited by Reuters.
Weekly Petroleum Status Report, Release Date: 10/27/2021, Data for week-ending Oct 22, 2021
You must have more than a few smudges on your crystal ball. Better luck next time Sherlock.
Report Summary: https://ir.eia.gov/wpsr/wpsrsummary.pdf
Report Tables: https://ir.eia.gov/wpsr/overview.pdf
WTI $83.78/bbl Oct 27, 2021, 10:37 am CDT, Crude holding up nicely for now.
Summary of Weekly Petroleum Data for the week ending October 22, 2021
U.S. commercial crude oil inventories (excluding those in the Strategic Petroleum Reserve) increased by 4.3 million barrels from the previous week. At 430.8 million barrels, U.S. crude oil inventories are about 6% below the five year average for this time of year. Total motor gasoline inventories decreased by 2.0 million barrels last week and are about 3% below the five year average for this time of year. Finished gasoline inventories remained unchanged while blending components inventories decreased last week. Distillate fuel inventories decreased by 0.4 million barrels last week and are about 8% below the five year average for this time of year.. Propane/propylene inventories increased by 2.0 million barrels last week and are about 15% below the five year average for this time of year. Total commercial petroleum inventories increased by 4.4 million barrels last week.
U.S. crude oil refinery inputs averaged 15.0 million barrels per day during the week ending October 22, 2021 which was 58,000 barrels per day more than the previous week’s average. Refineries operated at 85.1% of their operable capacity last week. Gasoline production increased last week, averaging 10.1 million barrels per day. Distillate fuel production increased last week, averaging 4.6 million barrels per day.
U.S. crude oil imports averaged 6.3 million barrels per day last week, up by 430,000 barrels per day from the previous week. Over the past four weeks, crude oil imports averaged about 6.3 million barrels per day, 15.2% more than the same four-week period last year. Total motor gasoline imports (including both finished gasoline and gasoline blending components) last week averaged 493,000 barrels per day, and distillate fuel imports averaged 325,000 barrels per day.
Total products supplied over the last four-week period averaged 20.8 million barrels a day, up by 9.9% from the same period last year. Over the past four weeks, motor gasoline product supplied averaged 9.4 million barrels a day, up by 9.5% from the same period last year. Distillate fuel product supplied averaged 4.1 million barrels a day over the past four weeks, up by 3.6% from the same period last year. Jet fuel product supplied was up 44.9% compared with the same four- week period last year.
The U.S. API Weekly Crude Oil Stock figures released yesterday, October 26, 2021 reflected Forecast at 1.650M and Actual at 2.318M
Someone has already tried to answer one of those questions for you. See link below:
https://investorshub.advfn.com/boards/read_msg.aspx?message_id=165915098
This is the answer to your other question, which can be found on Gulfslope’s most recent 10-Q. ”The Company has been conducting pre-drill operations for the Tau prospect which is anticipated to be re-drilled to a total depth of approximately 21,000 feet. The Exploration Plan has been filed with and approved by BOEM and the Application for Permit to Drill (“APD”) has been filed with BSEE and is pending approval. The Company plans to sign a rig contract, and arrange for bonding and insurance in conjunction with the approval of the APD.”
Perfectly fine to be confused WG. We all understand.
Mrs. Smith
You show them who is the BOSS.
Texas Governor, Greg Abbott’s comment on Twitter 18 hours ago.
”Texas to United Nations: Pound Sand”
“The world is reeling from spiraling fuel costs caused by premature over-reliance on renewable energy.
High fuel costs punish middle class families & stoke the supply chain crisis.
Texas oil & gas is needed right now.”
Yes indeed!
Mrs. Smith
Interesting BOEM article: ‘U.S. takes step toward oil and gas auction off Alaska coast next year’
Reuters, October 22, 2021, Reporting by Nichola Groom
https://www.reuters.com/business/energy/us-takes-step-toward-oil-gas-auction-off-alaska-coast-next-year-2021-10-22/
Oct 22 (Reuters) - The Biden administration on Friday took a procedural step towards holding an auction for oil and gas drilling rights in the Cook Inlet off the coast of Alaska next year.
The move is the latest effort by the U.S. Department of Interior to comply with a court order to resume oil and gas lease sales that President Joe Biden paused shortly after taking office in January.
The Department of Interior's Bureau of Ocean Energy Management said it would kick off a 45-day public comment period for the proposed sale's draft environmental analysis. The comments will help the agency decide whether or not to hold the lease sale at all, it said.
Biden paused drilling auctions in January pending an analysis of their impacts on the environment and value to taxpayers. In June, however, a federal judge in Louisiana ordered a resumption of auctions, saying the government was required by law to offer acreage to the oil and gas industry, citing the Outer Continental Shelf Lands Act.
The administration will hold a lease sale for drilling rights in the Gulf of Mexico next month.
The Cook Inlet sale could include 224 blocks covering more than 1 million acres in federal waters in the northern part of the inlet, the Bureau of Ocean Energy Management said in a statement.
The draft environmental document estimates that activities that stem from the sale will emit 88.3 million metric tons of carbon dioxide equivalent during their three-decade lifecycle, the equivalent of a year of carbon emissions from 22 coal-fired power plants.
The analysis also projects slightly higher energy prices if the sale does not proceed.
‘Exploring the Role of Oil & Gas Companies in the Global Energy Transition’, by Grace Goodrich, Posted October 25, 2021, 12:00 pm
https://energycapitalpower.com/exploring-the-role-of-oil-gas-companies-in-the-global-energy-transition/
Despite the perception that fossil fuels are directly at odds with clean energy development, oil and gas companies have a prominent role to play within the energy transition. In fact, oil and gas majors are some of the few companies that possess the financial resources, skill sets and innovation to transform present-day energy and economic systems, and as a result, should be viewed as part of the solution when it comes to decarbonizing energy and non-energy industries alike.
First, oil and gas companies are diversifying and reorienting their business models to concentrate on end user and downstream opportunities, including fuel and chemical manufacturing, as well as cleaner-burning energy sources. Baker Hughes, for example, is expanding its existing operations within chemicals and nonmetallic materials, which carry a lower carbon footprint than traditional fossil fuel extraction. The Houston-based oilfield services firm is also expanding its use of digital technologies across its oilfield services and turbomachinery and process solutions segment, which houses its liquefied natural gas (LNG) operations. LNG has been positioned by global industry as a key transition fuel, as it releases less carbon dioxide from combustion than both coal and petroleum products.
Major operators have also been innovating and implementing deep decarbonization initiatives, including carbon capture, utilization, and storage (CCUS), methane efficiency, zero-emissions production and hydrogen. CCUS represents a critical pathway to global decarbonization, promising to extract carbon dioxide from the air or capture it from high-emitting sources like coal-fired plants, then reuse or store it in deep geologic formations. Last April, ExxonMobil announced its plans for a $100-billion carbon capture project, called the ‘Houston CCS Innovation Zone,’ to be located along the Houston Ship Channel. The U.S. major has over 30 years of experience in CCUS technology and was one of the first companies to capture more than 120 million tons of carbon dioxide. To commercialize its extensive low-carbon technology portfolio, ExxonMobil announced plans in February to invest three billion dollars through 2025 in a new low-carbon solutions venture that would advance plans for more than 20 new carbon capture projects globally. Houston-based Occidental Petroleum is also spearheading a large-scale carbon capture project in the Permian Basin. Upon completion, the direct air capture facility will be capable of eliminating one million metric tons of atmospheric carbon dioxide per year.
Another way in which oil and gas companies are engaging with the clean energy transition is by entering sectors with opportunities for low-carbon investment and fostering strategic partnerships and synergies within non-energy industries. Chevron, for example, has tripled its planned investments into the energy transition through 2028 and is targeting a number of diverse sectors that are able to contribute to decarbonization objectives. The U.S. supermajor signed a partnership with agriculture company Bunge to finance Bunge’s soybean processing facilities, which will act as a feedstock for renewable fuels. Chevron also forged a renewable gas partnership with Mercuria Energy to own and operate 60 compressed natural gas stations across the U.S.; with California Bioenergy to produce renewable natural gas from dairy farms; and with Google and Delta Airlines to produce and market sustainable aviation fuel. Finally, leading oil and gas majors have also been proactive in adopting progressive Environmental Social Governance (ESG) standards with a view to sustainability and environmental stewardship, and could serve as a strategic liaison between industry, government and public interests.
2021-22 U.S. EIA ”Winter Fuels Outlook PDF Report”
https://www.eia.gov/outlooks/steo/special/winter/2021_Winter_Fuels.pdf
‘EIA forecasts U.S. winter natural gas bills will be 30% higher than last winter’
https://www.eia.gov/todayinenergy/detail.php?id=50076
In our latest “Winter Fuels Outlook”, we forecast that U.S. households that primarily use natural gas for space heating will spend an average of $746 on heating this winter (October–March), which is $172, or 30%, more than last year.
Natural gas is the primary heating fuel for 48% of U.S. homes, according to the U.S. Census Bureau’s 2019 American Community Survey. Residential spending on winter natural gas bills is largely determined by the retail price of natural gas and the amount of natural gas consumed.
Higher retail natural gas prices are the primary driver for the expected increase in natural gas heating expenditures this winter. On average, retail natural gas prices in the United States are expected to rise from $10.17 per thousand cubic feet (Mcf) last winter to $12.93/Mcf this winter, the highest price since the 2005–06 winter average. We expect the largest increase in retail natural gas prices to occur in the Midwest, where prices rise to $11.28/Mcf, a 45% increase compared with last winter.
The increase in retail prices reflects rising natural gas spot prices over the past year. Changes in natural gas spot prices typically get passed along to retail rates over a period of months because of regulatory rate structures. Utilities generally cannot profit or lose money from natural gas commodity sales, whose costs are passed along directly to the consumer.
In addition to the steady rise in natural gas spot prices over the past year, many utilities had to raise prices for consumers following the February 2021 cold snap that affected most of the country, but particularly Texas and the Midwest. During the cold snap, many utilities had to purchase natural gas at spot prices that were higher than anticipated. However, because retail rates were already set for the month, utilities did not collect enough to cover the cost of the natural gas. To make up for this undercollection, many utilities opted to raise prices in subsequent months to spread out the costs to consumers over several months.
Higher-than-expected natural gas expenditures this winter also result from slightly higher-than-expected consumption compared with last year. For households that use natural gas as their primary space heating fuel, we expect average consumption this winter to be 57.7 Mcf, a 2.4% increase from last winter. The higher consumption is driven by a 2.6% forecast increase in the number of heating degree days (a measure of heating demand) compared with last winter. In our October Short-Term Energy Outlook (STEO), we estimate that U.S. natural gas inventories ended September at 3,304 Bcf, which is 5.5% below the five-year average for this time of year.
Principal contributors: Corrina Ricker, Stephen York
THE JOURNAL OF ENERGY AND DEVELOPMENT by Jude Clemente,
“Energy as a Foundation of Modern Life,”
Full Report with excellent graphs and data:
https://www.realclearenergy.org/docs/JEDFall2011.pdf
Summary of Study
Bottom Line: More energy is the foundation of a modern life. Examining the dangers of CO2 emissions must therefore factor in the benefits of using fossil fuels: they supply over 80% of the world’s energy. Oil, coal, and gas are cheaper and more reliable. The poor nations are therefore now understandably following the rich nations’ model in developing fossil fuel infrastructure to advance their own economies and populations.
Analysis of the dangers posed by society’s use of fossil fuels (oil, coal, natural gas) and the emission of greenhouse gases, particularly carbon dioxide (CO2), generally focuses on the potential for climate change impacts. It is vitally important, however, in the context of assessing the societal risk of CO2 emissions, to also examine the reasons why CO2 is even emitted in the first place.
CO2 is not released in a socioeconomic vacuum; it is emitted as the inevitable by-product of combusting fossil fuels. Meeting over 80% of the world’s energy needs for many decades, oil, coal, and gas are cheaper and more reliable.
While this energy production results in CO2 emissions, it also yields significant benefits for the health and welfare of the populations utilizing fossil fuels. Thus, it is important to strike a balance in the equation—both an assessment of the dangers posed to the atmosphere by CO2 emissions and the powerful benefits created by the energy usage that results in these emissions. This is especially true since fossil fuels are projected to still remain the main sources of energy for many decades to come, even under highly optimistic forecasts for renewables.
Fossil fuel energy has been a determining factor in economic development, critical to transforming agrarian societies to modern industrial ones. This societal transformation, driven by the accumulation of income and wealth, eliminates many contagious diseases, reduces child mortality, and lengthens adult life expectancy—indeed, a virtuous cycle that has been demonstrated over the past two centuries in dozens of countries around the world.
Fossil fuels have empowered modern industrial societies to improve the quality of life for billions of people. In turn, the still developing nations are now understandably turning to more fossil fuels to grow their economies and advance their populations.
High-level experts meet for 8th Joint IEA-IEF-OPEC Workshop on the Interactions between Physical and Financial Energy Markets
https://www.opec.org/opec_web/en/press_room/6670.htm
Vienna, Austria
21 Oct 2021
[Joint Press Release] The International Energy Agency (IEA), the International Energy Forum (IEF) and the Organization of the Petroleum Exporting Countries (OPEC) met today via videoconference for the 8th Joint IEA-IEF-OPEC Workshop on the Interactions between Physical and Financial Energy Markets.
The high-level Workshop was co-chaired by OPEC Secretary General, HE Mohammad Sanusi Barkindo, together with Mr. Joseph McMonigle, Secretary General of the IEF, and Keisuke Sadamori, Director of the Office for Energy Markets and Security at the IEA. The Workshop had over 110 participants.
In his opening remarks, HE Barkindo said “It is exactly these types of close collaboration that we will need to see more of in the weeks and months ahead as this industry continues to rise to the challenge of adapting to the paradigm shifts that are currently taking place.”
The Secretary General reminded participants that there was but a little over a week until the highly anticipated United Nations Climate Change Conference (COP26) in Glasgow and that investment would be one of the deciding issues for the industry in the years ahead. He added that “oil and gas will continue to play an important role in world energy supply on the medium to long term” and that “Meeting these rising energy requirements will be dependent on a steady flow of industry investment”, which would also be “essential to advancing innovation and technology that will be instrumental in further improving the environmental footprint and reducing emissions”.
Mr. McMonigle raised concerns with respect to energy investment, noting that global demand is rebounding after the COVID-19 pandemic but private sector investment has yet to respond adequately. This could lead to price fluctuations that will impact market stability, and derail a sustainable and inclusive recovery from the pandemic, he noted. Complex physical and financial energy market dynamics are better understood, better regulated, and more transparent since the three organisations launched the dialogue in response to the Global Financial Crisis more than a decade ago. The discussions of the trilateral work programme today have offered greater insight into market dynamics and will help producers and consumers assess if more concerted action is warranted, he added.
Mr. Sadamori stressed that the world is not investing enough to meet its future energy needs. Transition-related spending has gradually picked-up, but remains far short of what is required to meet rising demand for energy services in a sustainable way. The amount currently spent on oil appears to be geared towards a world of stagnant or falling demand. A surge in spending on clean energy transitions provides the way forward, but this needs to happen quickly or global energy markets are likely to be volatile for years to come.
Sadamori added that “an effective and orderly transition will be critical – not only to reach international climate targets but also to prevent serious supply disruptions and destabilising price volatility along the way”.
Discussions during the videoconference were structured into two sessions, focusing on financial markets, investment and the impact of the drive in ESG on the upstream oil industry.
The first session covered ‘Investment opportunities in the oil industry in light of recent trends in the global economy and financial markets’, which provided an overview of how investors across different asset classes are approaching investing in energy and how that translates into the outlook for oil markets. The second session delved further into the ‘Impact of the accelerated drive towards ESG (Environment, Social, Governance) on investment in E&P activity’.
The Joint Workshop is one part of the trilateral work programme established by the three organizations and endorsed by energy ministers at the 12th International Energy Forum in Cancún, Mexico, in March 2010. Since then, the joint IEA-IEF-OPEC meetings covering the evolving inter-linkages between physical and financial energy markets have developed into a unique, high-level dialogue event that brings together a diverse range of market participants to discuss issues that are not addressed in other high-level fora. To encourage open and informative discussion, the Workshop was held under Chatham House Rule.
In conclusion, the three organizers thanked all the participants for their committed and forthright discussions on these crucial and timely issues, and looked forward to convening the next Joint Workshop in 2022.
10/22/2021 GOM Offshore Rig Count increased 19% from the previous week and is currently reflecting 13 rigs. The Total US Oil and Gas Rig Count shows 542 rigs a decrease of 1 rig. All of Gulfslope’s prospects are in GOM offshore waters.
http://www.dnr.louisiana.gov/assets/TAD/data/drill_weekly/WeeklyRigCountUpdate.pdf
http://www.dnr.louisiana.gov/assets/TAD/data/drill_weekly/ogj_rig_count.pdf
WTI $84.84/bbl - November Contract, 10/25/2021, 10:33 am CDT
https://oilprice.com/oil-price-charts/45
Wholesale Spot Petroleum Prices, 10/22/21 Close
Crude Oil ($/barrel) Percent Change
WTI 84.53 +2.3
Brent 85.43 +1.0
Louisiana Light 84.63 +1.8
https://www.eia.gov/todayinenergy/prices.php
Mrs. Smith
”U.S”. Economic Activity Charts, Issued October 18, 2021, Federal Reserve Bank of Dallas
https://www.dallasfed.org/-/media/Documents/research/econdata/uscharts.pdf
Database of ”Global” Economic Indicators (Real, Price, Trade and Financial), Charts as of October 2021:
https://www.dallasfed.org/institute/dgei
Mrs. Smith
October 2021 Federal Reserve Bank of Dallas ”Energy Slideshow”, Released October 13, 2021
See link below for slideshow charts on Energy Prices, Global Petroleum Data, National Outlook Data, and Regional Activity:
https://www.dallasfed.org/-/media/Documents/research/energy/energycharts.pdf?la=en
Mrs. Smith
Summary of Weekly Petroleum Data for the week ending 10/15/2021, Release date October 20, 2021
Full Report with Graphs/Tables: https://www.eia.gov/petroleum/supply/weekly/pdf/wpsrall.pdf
HIGHLIGHTS
U.S. commercial crude oil inventories (excluding those in the Strategic Petroleum Reserve) decreased by 0.4 million barrels from the previous week. At 426.5 million barrels, U.S. crude oil inventories are about 6% below the five year average for this time of year. Total motor gasoline inventories decreased by 5.4 million barrels last week and are about 3% below the five year average for this time of year. Finished gasoline inventories increased while blending components inventories decreased last week. Distillate fuel inventories decreased by 3.9 million barrels last week and are about 10% below the five year average for this time of year. Propane/propylene inventories increased by 1.9 million barrels last week and are about 17%
below the five year average for this time of year. Total commercial petroleum inventories decreased by 9.8 million barrels last week.
U.S. crude oil refinery inputs averaged 15.0 million barrels per day during the week ending October 15, 2021 which was 71,000 barrels per day less than the previous week’s average. Refineries operated at 84.7% of their operable capacity last week. Gasoline production increased last week, averaging 10.1 million barrels per day. Distillate fuel production decreased last week, averaging 4.4 million barrels per day.
U.S. crude oil imports averaged 5.8 million barrels per day last week, down by 169,000 barrels per day from the previous week. Over the past four weeks, crude oil imports averaged about 6.4 million barrels per day, 19.5% more than the same four-week period last year. Total motor gasoline imports (including both finished gasoline and gasoline blending components) last week averaged 606,000 barrels per day, and distillate fuel imports averaged 202,000 barrels per day.
Total products supplied over the last four-week period averaged 20.9 million barrels a day, up by 14.0% from the same period last year. Over the past four weeks, motor gasoline product supplied averaged 9.4 million barrels a day, up by 9.8% from the same period last year. Distillate fuel product supplied averaged 4.1 million barrels a day over the past four weeks, up by 8.3% from the same period last year. Jet fuel product supplied was up 50.1% compared with the same four-week period last year.
The West Texas Intermediate crude oil price was $82.39 per barrel on October 15, 2021, $2.84 above last week’s price and $41.69 more than a year ago. The spot price for conventional gasoline in the New York Harbor was $2.574 per gallon, $0.134 more than last week’s price and $1.359 above a year ago. The spot price for No. 2 heating oil in the New York Harbor was $2.435 per gallon, $0.097 above last week’s price and $1.302 over a year ago.
The national average retail regular gasoline price was $3.322 per gallon on October 18, 2021, $0.055 per gallon more than last week’s price and $1.172 over a year ago. The national average retail diesel fuel price was $3.671 per gallon, $0.085 above last week’s price and $1.283 over a year ago.