By Stuart Turley, host of the Energy News Beat podcast  

October 18, 2026 - Filling a 30-gallon pickup with diesel this weekend will cost about $190. A year ago, the same fill-up cost about $109. Filling a 15-gallon tank with regular gasoline costs about $65, up from $46. These figures use AAA prices and Energy News Beat (ENB) calculations.

The national average diesel price is $6.33 per gallon. That is $2.69, or 74%, higher than a year ago and just 20 cents below the September 22 record. Regular gasoline averages $4.31 per gallon, up $1.26 from a year earlier, according to AAA.

If you heat your home with oil, the U.S. Energy Information Administration (EIA) expects your winter bill to be about 21% higher than last year. Homes heated with natural gas or propane, which account for about half of American homes, are expected to spend a little less. Homes using electric heat—about 40% of the country—are expected to spend about 4% more.

It is the same country facing the same crisis, but households are seeing different results. That difference runs through this analysis: fuels that must pass through a war zone are expensive, while fuel produced at home remains much cheaper.

Readers keep asking four questions:

• How long will $100 oil last?
• How will natural gas and liquefied natural gas (LNG) markets rebalance?
• Is coal really making a comeback?
• Which shipping chokepoints should we watch?

We gathered the latest figures from the EIA, International Energy Agency (IEA), OPEC, major banks, ship trackers and market data providers. Where their findings differ, we explain those differences.

The 60-second version

Oil: Brent settled at $109.86 on Friday, up 3.7%. Futures prices remain above $100 through the March 2027 contract. EIA expects Brent to fall below $100 in December and average $84 in 2027. Morgan Stanley forecasts $105 this quarter. Goldman Sachs expects $90 by December. Citi’s September forecast was $70.

Strait of Hormuz: Ship transits remain about 70% below pre-war levels, and 12 attacks were reported last week. Oil flows through the strait recovered to 10.9 million barrels per day in September—about half the pre-war level of 20.9 million barrels per day, according to an ENB comparison.

Natural gas and LNG: Asian LNG reached $29.30 per million British thermal units (Btu), its highest level since December 2022. Europe’s TTF benchmark is approximately $28.77 per million Btu, based on ENB’s conversion. Both are about nine times the U.S. Henry Hub benchmark of $3.12. Qatar’s October LNG exports are on track to reach just 0.6 million metric tons.

Coal: Global demand is expected to reach a record 8.94 billion metric tons this year. Newcastle coal is trading at $150.40 per metric ton, near its 52-week high.

U.S. production and exports: Crude oil exports are averaging 4.26 million barrels per day this year, up about 10%. LNG exports are forecast to reach 17.6 billion cubic feet per day, up 16%. ENB estimates that about 21.5 billion cubic feet per day of new U.S. LNG capacity is operating, under construction or approved for investment.

ENB’s assessment: Plan for oil to remain around $100 through the winter. Keeping prices below $90 for an extended period would require an open Strait of Hormuz, and nobody can promise when that will happen.

Part 1: How long will $100 oil last?

Where Brent prices have been

Figures reflect October 16 futures settlements and October 14 EIA Dated Brent spot prices.

On February 27, the last trading day before the war, Dated Brent closed at $71.32, according to EIA. U.S. and Israeli strikes on Iran began the following day. On March 2, Iran’s Revolutionary Guard announced that it was closing the Strait of Hormuz, according to Anadolu and WorkBoat.

Spot Brent rose above $100 on March 12 and peaked at $138.21 on April 7. An April ceasefire and a June framework agreement brought the price down to $68.53 by July 2, according to EIA.

Prices then climbed again. September attacks on Saudi Arabia’s East-West pipeline, along with an increase in tanker attacks, pushed them higher, according to the IEA and Kpler.

Physical Dated Brent reached $126.55 on October 14. The IEA said it was trading around $134 when the agency prepared its October report. ENB’s count of EIA data shows that spot Brent closed at $100 or more on 82 of the 158 trading days since March 1.

Futures prices—the prices most headlines quote—are lower than physical oil prices because they cover delivery at a later date. December Brent settled Friday at $109.86, up $3.94, after touching $110 for the first time since May, according to CNBC and The National. November West Texas Intermediate (WTI) settled at $101.41, up $3.44, according to CNBC.

The Wall Street Journal linked Friday’s increase to renewed Ukrainian strikes on Russian refineries as well as risks around Hormuz. Brent futures are up about 81% this year, based on Yahoo Finance data and ENB calculations.

Chart 1: Brent prices since the war began and where forecasters expect them to go. Sources: U.S. EIA; ICE through CNBC and Yahoo Finance; Goldman Sachs; Morgan Stanley; Citi. ENB combined the banks’ scenarios into a forecast range.

What the futures curve tells us

October 16 settlements, checked at 8:24 a.m. Central Time on October 17.

The futures curve offers the clearest market-based answer to how long high prices may last.

Traders are paying $109.86 for December 2026 oil but only $86.69 for December 2027 oil. That $23.17 difference is called backwardation. It means buyers are paying a substantial premium for oil available sooner because current supplies are tight, according to CNBC and ENB calculations.

Every contract through March 2027, priced at $101.53, remains above $100. April 2027 is the first contract below that level, at $99.41.

OPEC’s monthly report also shows how tight near-term supplies have become. In September, the first Brent contract averaged $8.24 more than the third contract and $15.08 more than the sixth.

There are two cautions. First, futures are market prices, not guaranteed forecasts. They have been wrong in both directions this year. Second, the current curve already assumes conditions will improve. If Hormuz remains restricted, prices for later delivery could rise again.

Chart 2: The Brent futures curve shows prices above $100 through March 2027. Source: ICE Brent settlements for October 16, 2026, through CNBC. ENB calculation.

What forecasters expect

Forecasts can become outdated quickly during a war. The dates below show when each forecast was made.

The agencies agree on the general direction but disagree about the size of the change.

The IEA expects global oil demand to fall by 2.6 million barrels per day in 2026, to 102.4 million barrels per day. It expects the market to remain undersupplied through the end of the year, with a possible surplus emerging in 2027.

OPEC still expects demand to grow by 200,000 barrels per day this year, reaching 105.7 million barrels per day, according to OPEC and Enerdata.

That leaves a difference of more than 3 million barrels per day between their estimates, although the two agencies measure demand on different bases. OPEC represents producers, while the IEA represents importing countries. Readers should keep those perspectives in mind.

Three possible paths

ENB grouped the published forecasts into three scenarios. These are groupings of other organizations’ forecasts, not ENB forecasts.

Path 1: Hormuz reopens and the agreement holds—$62 to $80 oil.

Citi forecasts $70 this quarter and $65 next year if flows return to normal and the market moves into surplus. Goldman’s low-price scenario is in the low $70s, according to Yahoo Finance.

QatarEnergy’s chief executive says LNG operations could return to normal within weeks of reopening the strait, although repairing damaged production units would take years, according to Baird Maritime.

Julius Baer’s Norbert Rucker argues that the world is not running out of oil because Middle Eastern flows have largely recovered, according to The National.

Path 2: Hormuz remains restricted—$95 to $110 oil.

This is closest to current conditions and broadly matches the EIA, Morgan Stanley and the futures curve: approximately $105 this quarter and $95 to $100 early next year.

Kpler’s ship tracking helps explain why. Preliminary figures show that oil moving through Hormuz reached about 68% of its pre-war baseline in the week ending October 13. Tanker crossings averaged 13 per day, compared with 50 before the war.

Kpler cautions that its early counts are usually revised upward by a factor of 1.5 to two.

Path 3: The conflict escalates—$115 to $140 oil.

Goldman’s high-price scenario puts Brent at $125 by December, according to Yahoo Finance. Spot Brent has already reached $138, according to EIA.

On Saturday, Al Jazeera reported that both the United States and Iran were claiming control of the strait amid new attacks on ships. Kpler also reported an October 13 strike on Aramco’s headquarters in Dhahran.

Chart 3: Three possible paths for Brent, based on published forecasts. Sources: Citi; Goldman Sachs; U.S. EIA; Morgan Stanley. ENB groupings, not ENB forecasts.

What can soften the shock?

Based on the IEA’s October 14 Oil Market Report, EIA data for the week ending October 9 and the IEA’s October 15 statement.

Spare production capacity is largely trapped behind the strait.

Saudi Arabia can theoretically produce 12.11 million barrels per day, but September production was 8.3 million barrels per day. The IEA estimates that effective spare capacity across OPEC+ is only 270,000 barrels per day.

ENB’s interpretation is that unused Gulf production capacity offers limited help when the oil must still pass through a war zone.

Gulf crude exports recovered to 13.9 million barrels per day in September, more than 75% of their pre-war level. That recovery included 5.6 million barrels per day of exports using routes that bypass Hormuz, according to the IEA.

That exceeds EIA’s estimate of 4.7 million barrels per day of normal bypass-pipeline capacity, suggesting those routes are operating near their limits. However, the agencies measure different things: the IEA’s bypass figure can include other ports and trucking as well as pipelines.

Emergency reserves are helping, but they cannot provide support indefinitely.

IEA members have released about 330 million barrels since March, with roughly 100 million remaining in the announced program. That includes more than 20 million barrels of diesel to be released as quickly as possible, according to the IEA and ENB.

The U.S. Strategic Petroleum Reserve has fallen to 283 million barrels, down from 407.7 million a year ago. EIA expects it to decline to about 243 million barrels by December, with refilling beginning in mid-2027.

Despite the releases, global inventories at the end of September were 509 million barrels below pre-war levels. On-land stocks were at their lowest level since at least 2016, according to the IEA.

Reduced demand is doing the rest.

The IEA estimates that demand fell year over year by 5 million barrels per day in the second quarter and 3.7 million in the third quarter. It expects a fourth-quarter decline of 2.5 million barrels per day. Goldman estimates the third-quarter drop at 3.3 million barrels per day.

Economists call this demand destruction: families, truckers and factories use less fuel because they cannot afford as much.

The IEA says diesel exceeded $200 per barrel in September. It warns that, without additional Middle Eastern supplies, further reductions in consumption—and the economic costs that come with them—may be necessary. ENB’s diesel outlook examines these pressures through 2027.

ENB’s answer to question one: The futures market suggests Brent will remain above $100 for about five more months, through the March contract. EIA expects about two more months. The banks with the most recent forecasts expect prices around $100 into the first quarter.

Keeping oil below $90 for a sustained period would require Hormuz to reopen, and nobody can give a firm date for that.

Part 2: How do natural gas and LNG markets rebalance?

The gap left by Qatar

Based on Kpler data reported by Reuters on October 12 and the IEA’s third-quarter 2026 Gas Market Report.

Before the war, about 11.4 billion cubic feet per day of LNG passed through Hormuz. That represented more than one-fifth of global LNG trade, almost all originating in Qatar and the United Arab Emirates, according to EIA.

Qatar alone has nearly 80 million metric tons of annual LNG capacity, approximately one-fifth of global supply, according to Reuters reporting carried by Cyprus Mail.

Missile attacks on March 18–19 damaged two production units, known as trains, at Ras Laffan. Together, those trains account for 12.8 million metric tons of annual capacity, or about 17% of Qatar’s total. QatarEnergy says repairs will take three to five years, according to the IEA’s full report and Baird Maritime.

Exports have fallen sharply.

Kpler data show that Qatar shipped 1.6 million metric tons in September, less than one-quarter of its pre-war monthly pace. About one-third went to Kuwait.

October exports are on track to reach approximately 600,000 metric tons, according to Reuters through Cyprus Mail. ENB calculates that this is roughly 9% of a normal month.

The IEA estimates that the war will cause cumulative LNG supply losses of about 140 billion cubic meters between 2026 and 2030.

Chart 4: Qatar’s monthly LNG exports have fallen to a small share of normal volumes. Sources: Kpler through Reuters; IEA; Baird Maritime. ENB calculation.

One world, three very different gas bills

Prices reflect October 16 settlements and assessments.

Asian spot LNG for December reached $29.30 per million Btu on Friday, its highest level since December 23, 2022. That was up from $26.50 a week earlier, according to Reuters through Pipeline & Gas Journal.

Europe’s TTF benchmark closed at €87.55 per megawatt-hour. ENB converts that to approximately $28.77 per million Btu using the October 16 euro-dollar closing exchange rate of 1.1213, with data from Yahoo Finance.

TTF is up about 211% this year.

U.S. Henry Hub futures for November settled at $3.116 per million Btu. December settled at $3.386 and January at $3.759, according to CNBC. Henry Hub futures are down about 15% this year, based on Yahoo Finance data and ENB calculations.

In simple terms, the European and Asian benchmarks are about nine times the U.S. benchmark.

EIA expects Henry Hub to average $3.48 this year and $3.16 next year. That helps explain why American homes heated with natural gas are expected to see some relief this winter while households elsewhere face much higher costs.

Chart 5: Natural gas prices in Asia, Europe and the United States on October 16. Sources: NYMEX through CNBC; ICE Endex through Yahoo Finance; Reuters through Pipeline & Gas Journal. ENB conversions.

Europe’s winter supply picture

Based on GasRadar’s October 16 briefing using GIE AGSI+ data.

EU gas storage is 74.2% full, compared with a five-year mid-October average of about 90.2%. GasRadar’s middle-range scenario puts storage at approximately 26.1% on April 1.

Germany’s storage was 60.6% full for the October 15 gas day, according to GIE AGSI+.

ENB’s October 15 article, Europe’s Gas Prices Close to 2022 High as LNG Market Shifting, explains the competition behind these figures: Europe and Asia are bidding against each other for flexible LNG cargoes.

Morgan Stanley expects TTF to average around €90 this winter, with a higher-risk scenario of €135, according to Reuters through Pipeline & Gas Journal. Citi’s September forecast put fourth-quarter TTF in the mid-€50s.

That is a wide range. Winter temperatures will play a major role in determining the outcome.

Chart 6: EU gas storage heading into winter. Sources: GasRadar using GIE AGSI+ data, October 16, 2026; German storage figures from GIE AGSI+, October 15 gas day.

Asia buys less gas and burns more coal

Asia has adjusted through reduced consumption and fuel switching.

The IEA estimates that China’s natural gas demand fell about 4% year over year between March and June, while its LNG imports fell 12%. Across Asia, high prices prompted conservation measures and switches from gas to coal.

Fertilizer production has also been affected. Gulf fertilizer exports have largely stopped, while high natural gas prices have reduced fertilizer output in Bangladesh, India and Pakistan, according to the IEA.

Columbia University’s Center on Global Energy Policy described Asia’s response as a combination of coal use, reduced consumption and competition for LNG.

The coming wave of American LNG

Based on EIA’s October 6 Short-Term Energy Outlook, WorkBoat’s September 13 reporting and the IEA’s third-quarter 2026 Gas Market Report.

Additional supply will be central to restoring balance.

U.S. LNG exports averaged 17.4 billion cubic feet per day in the first half of 2026, up 23%, according to Rig & Refinery.

EIA expects exports to average 17.6 billion cubic feet per day in 2026 and 18.6 billion in 2027. By December 2027, exports are expected to reach approximately 21.1 billion cubic feet per day.

The IEA estimates that new projects in North America, Africa and Australia will add nearly 50 billion cubic meters of supply this year, largely offsetting the Gulf’s lost volumes.

The project schedule is as follows:

• Already operating: Venture Global’s Plaquemines is exporting at full capacity, while Cheniere’s Corpus Christi Stage 3 reached substantial completion on August 28. Together, they add about 4 billion cubic feet per day. Both were already exporting some LNG in 2025, according to WorkBoat. Golden Pass, owned by QatarEnergy and ExxonMobil, shipped its first cargo on April 22. Its second and third trains will follow, bringing total capacity to approximately 18 million metric tons annually, according to Golden Pass.
• Expected in 2027–2029: Rio Grande LNG expects its first LNG in the first half of 2027. Port Arthur targets 2027, with its second train in 2028. CP2 targets the second half of 2027, although there is a risk of delay into 2028. Corpus Christi Midscale Trains 8–9 are expected in the second half of 2028, followed by Woodside Louisiana in 2029, according to WorkBoat and EIA.
• New final investment decisions: A record six U.S. projects reached final investment decisions in 2025, according to Poten. These included Rio Grande Trains 4 and 5, according to NextDecade. Since March, CP2 Phase 2, Delfin’s first floating LNG vessel and Commonwealth LNG have also reached final investment decisions. Their expected starts are around 2030, according to the IEA.

ENB’s tally puts new U.S. LNG capacity that is operating, being built or approved for investment at approximately 21.5 billion cubic feet per day. ENB converted figures reported in million metric tons per year and billion cubic meters into billion cubic feet per day.

For comparison, U.S. LNG exports averaged 15.1 billion cubic feet per day in 2025. However, the figures overlap because Plaquemines and Corpus Christi Stage 3 were already exporting during 2025.

The IEA expects North American LNG export capacity to approach 340 billion cubic meters annually by 2030.

Qatar is also expanding. Two people familiar with the plans told Reuters that the first train of the North Field East expansion should be ready to start in November, according to Baird Maritime. However, the IEA’s full report says the complete project, which would add 44 billion cubic meters annually, could be delayed by more than a year.

Chart 7: The U.S. LNG supply expansion by expected start date. Sources: U.S. EIA; WorkBoat; Golden Pass; Cheniere; NextDecade; Sempra; IEA. ENB conversions and groupings.

ENB’s answer to question two: Natural gas markets will rebalance in three stages.

This winter, high prices will force adjustments through lower Asian demand, greater coal use and withdrawals from European storage.

In 2027, new supply will arrive. ENB’s tally shows about 7 billion cubic feet per day of U.S. capacity scheduled for that year, alongside North Field East.

By 2028, if Hormuz is open, the supply expansion the IEA expected before the war could return, except for the damaged Qatari trains.

ENB’s June 24 analysis, The New Energy Boom: Data Centers, LNG and America’s Gas Advantage, examines the competition among LNG exports, data centers and domestic utility bills.

There is a reasonable counterargument: increasing exports connects U.S. natural gas prices more closely to global markets.

In January, the Industrial Energy Consumers of America, a manufacturing group that purchases natural gas, asked DOE to suspend spot LNG exports to reduce domestic gas and electricity prices. The group said it was not opposed to LNG exports generally.

For now, the figures support the exporters’ position: Henry Hub prices have fallen this year even as LNG exports, including first-half volumes, reached records, according to CNBC and WorkBoat.

Part 3: Is coal making a comeback?

Based on the IEA Coal Mid-Year Update published in September 2026 and Newcastle futures prices on October 16.

Yes—at least this year.

The IEA now expects global coal demand to rise 1.2% to a record 8.94 billion metric tons in 2026, reversing its earlier forecast of a decline.

The agency attributes the change to the Middle East war and an unusually strong El Niño. Expensive natural gas encouraged power producers to use more coal, while some countries temporarily permitted additional coal-fired generation.

If tensions ease, the IEA expects demand to slip slightly to 8.91 billion metric tons in 2027.

The regional picture varies:

• China: Demand is expected to rise about 1% to approximately 5 billion metric tons—more than half of global consumption. Strong electricity demand, weak wind generation and expensive LNG are supporting coal use, according to the IEA. September imports totaled 43.37 million metric tons, down 5.7% year over year but up 3% from August, as domestic coal prices approached a three-year high, according to OilPrice and SXCoal.
• India: Demand is expected to increase 4.2% to 1.353 billion metric tons, returning to its long-term growth trend, according to the IEA.
• Japan: Demand is expected to decline 1% to 161 million metric tons. However, expensive gas is keeping coal-fired generation higher than previously expected. The government also removed restrictions on which coal plants can receive capacity payments, according to the IEA. Rystad says Japanese coal imports in May were more than 20% above a year earlier.
• South Korea: Demand is expected to rise 6% to 119 million metric tons, reversing an earlier forecast of a decline. Coal-fired generation increased 30% year over year in the first quarter, according to the IEA. Rystad says May coal imports were more than 50% higher than a year earlier.
• Germany and Europe: The figures show a slower decline rather than a broad surge. Destatis data show German coal-fired generation fell 0.5% in the first half to 49.4 terawatt-hours, while gas-fired generation rose 6.4%, according to Clean Energy Wire. Hard-coal generation increased 23.5% in the second quarter to 5.7 terawatt-hours, according to SMARD. Reuters reported in September that European coal-fired generation could rise about 25% over six months if gas remained expensive. The IEA expects EU coal use of 276 million metric tons this year, a smaller decline than previously forecast. ENB’s European coal coverage examines these developments.
• United States: Coal use increased more than 9.5% to 410 million metric tons in 2025. The IEA expects a 7% decline in 2026 because U.S. natural gas remains inexpensive. Emergency orders and delayed plant retirements are slowing that decline.

Chart 8: Changes in coal demand by country in 2026. Source: IEA Coal Mid-Year Update 2026. U.S. tonnage calculated by ENB.

Coal prices

Newcastle thermal coal futures settled at $150.40 per metric ton on October 16, close to their 52-week high of $152.25 and above their low of $103.70, according to Investing.com.

The IEA says Newcastle prices averaged $139 per metric ton in June and $131 in August, with a late-August assessment of $136.

Kpler argues that three separate shocks are changing the upper range of coal prices this winter.

America’s coal fleet and DOE emergency orders

Based on DOE’s Section 202(c) orders page, checked October 17.

The Department of Energy is using Section 202(c) of the Federal Power Act to keep plants available beyond their planned retirement dates.

Current coal-plant orders cover:

• J.H. Campbell, Michigan: Through November 14. The plant had been scheduled to close May 31, 2025.
• Centralia Unit 2, Washington: Through December 11.
• Schahfer Units 17 and 18 and Culley Unit 2, Indiana: Through December 18.
• Craig Unit 1, Colorado: Through December 25.
• Stanton Unit 1, Florida: Through November 30.

DOE’s latest order, 202-26-50, was issued to PJM on October 12.

Energy Bad Boys, the Always On Energy Research team of Isaac Orr and Mitch Rolling, is a think tank openly critical of wind and solar mandates.

Its June analysis of FERC data covering 82 plants found that existing coal plants generated electricity at an average cost of $45.57 per megawatt-hour. Nearly eight in 10 produced power for less than $60 per megawatt-hour. ENB republished that analysis.

The report identifies both low- and high-cost plants. Three are operating under DOE orders:

• Schahfer: The second-most expensive plant in the analysis, at $110.03 per megawatt-hour.
• Culley: $86.86 per megawatt-hour.
• Campbell: Among the least expensive, at $30.36 per megawatt-hour.

Energy Bad Boys argues that cost is not the only consideration, noting that Schahfer operated near full output when electricity supplies were tight. Its work on NERC’s blackout warnings and near-emergencies in regions such as SPP makes a similar case for reliability.

There are opposing arguments.

On September 11, the D.C. Circuit vacated DOE’s first Campbell order, finding that the agency had not demonstrated an imminent emergency.

Consumers Energy reported a net compliance cost of $259 million after receiving $239 million in MISO market revenues, according to Utility Dive.

Rystad Energy describes Asia’s increased coal use as a reality check for the energy transition rather than a lasting coal comeback.

ENB’s answer to question three: Coal is again absorbing shocks in the global energy system. Its use is rising in Asia this year, while Europe’s decline is slowing. In the United States, the main debate concerns keeping existing plants open.

How long this lasts depends on LNG prices, which in turn depend on Hormuz and the new supply expected in 2027. ENB examines that question in Coal Making a Comeback: How Fast and How Long?

Part 4: Shipping chokepoints to watch

Based on UKMTO weekly figures through October 14, reported by Anadolu on October 17, and other sources dated below.

About 80 million barrels of oil per day move by sea, according to EIA. Much of that traffic passes through a small number of narrow waterways.

The table combines EIA’s pre-war flow estimates with current conditions.

Chart 9: Normal oil flows through major chokepoints and their current status. Sources: U.S. EIA; UKMTO; Lloyd’s List Intelligence; German Navy Shipping Center; Strategic Energy Map; Anadolu; DataPortuaria.

Saudi Arabia’s alternative export route runs through the Red Sea.

Kpler shows Red Sea exports averaging approximately 3.25 million barrels per day over seven days, above a baseline of 2.8 million. Loadings at Yanbu resumed September 17 after the East-West pipeline attack.

However, that route passes the Houthis at Bab el-Mandeb. That means the same barrel can face risks at two separate chokepoints. ENB’s reporting on Hormuz escape routes and tanker attacks provides additional detail.

Before the war, the United States imported only about 400,000 barrels per day through Hormuz, according to EIA. Americans therefore feel the disruption mainly through global prices rather than empty import terminals.

Energy security starts at home

Based on EIA weekly figures for the week ending October 9 and its October 6 Short-Term Energy Outlook.

One lesson from 2026 is that energy security takes priority over policy goals when supplies are threatened.

U.S. crude exports have averaged 4.26 million barrels per day this year, up from 3.87 million in 2025. Petroleum product exports have averaged 7.55 million barrels per day, up from 6.84 million, based on EIA data and ENB averages.

U.S. crude production reached 13.68 million barrels per day last week. EIA expects production to reach 14.3 million barrels per day in 2027.

LNG exports are expected to rise 16% this year. Coal exports are forecast to increase about 11% to 102 million short tons, according to EIA.

Chart 10: U.S. energy exports during a year of crisis. Sources: EIA weekly data and Short-Term Energy Outlook. ENB calculations.

Those exports show what energy dominance means in practice: European and Asian allies buying American fuel rather than waiting for shipments through a restricted strait.

They also help explain the difference in domestic energy bills. Natural gas and coal, which America produces in surplus, remain relatively inexpensive here. Crude oil and especially diesel trade at global prices and remain costly.

ENB has discussed these issues in the Energy Security Starts at Home podcast and The New Energy Boom.

There are reasonable counterarguments.

Supporters of wind and solar say the crisis demonstrates the value of domestic renewable energy because it requires no tankers. The IEA noted that stronger renewable generation helped reduce European gas use in the first half of the year.

ENB’s view is that weather-dependent generation still requires dependable backup during a crisis and that subsidies conceal its full cost to electricity customers. The Subsidy Cliff and Your Power Bill examines that argument.

Energy Bad Boys’ reliability research supports a similar position, although it comes from a think tank critical of renewable-energy mandates.

Others warn that new export facilities and refineries cannot be built quickly enough to help this winter. That is correct: new refining projects, including the planned Brownsville plant, remain years away, according to ENB.

Consumers and investors face different outcomes

Based on AAA prices at 8:25 a.m. Central Time on October 17 and Yahoo Finance closing prices on October 16.

Consumers

Pew Research Center found that 74% of Americans are very concerned about gas and energy prices.

Diesel is $2.69 per gallon more expensive than a year ago, while regular gasoline is up $1.26, according to AAA.

EIA forecasts diesel prices averaging $5.19 this year and $4.49 next year. Gasoline is expected to average $3.91 this year and $3.56 next year.

That suggests gradual relief.

Homes heated with natural gas are expected to fare better this winter, while oil-heated homes face higher bills. Homes using electric heat, representing more than 40% of households, are expected to spend about 4% more, according to EIA.

Investors

The Energy Select Sector fund, XLE, closed Friday at $68.24. Its price is up approximately 52.6% this year, or about 55.7% including dividends. That compares with roughly 11.9% for the S&P 500 fund, based on Yahoo Finance data and ENB calculations.

Wall Street remains divided about what comes next.

Morgan Stanley raised its oil forecast. Goldman sees significant risk from the Iran war but still expects oil prices to ease. Citi and Julius Baer take a more bearish view, according to the cited bank forecasts, Yahoo Finance and The National.

U.S. natural gas investors face the opposite situation from overseas consumers: Henry Hub futures are down about 15% this year.

None of this is investment advice.

Chart 11: Drivers pay more while energy shareholders gain. Sources: AAA; Yahoo Finance. ENB calculations. Not investment advice.

Drivers pay more while energy shareholders gain. Sources: AAA; Yahoo Finance. ENB calculations. Not investment advice.

Stu’s take

Folks, I want to begin where you begin: at the gas pump.

Diesel is $6.33 per gallon, and regular gasoline is $4.31. Brent settled at $109.86 on Friday, and the futures market is pricing oil above $100 through next March.

EIA expects it to fall below $100 by December. I hope that happens, but I would not count on it when planning my heating bill.

Here is my opinion. The world has just experienced a real-world test of energy policy, and energy security came first.

When Hormuz transits fell about 70%, people in Tokyo and Berlin needed fuel, not pledges. Asian LNG reached $29.30 per million Btu, while American natural gas was about $3.12.

That difference reflects pipelines, drilling rigs, export terminals and coal plants that remained available.

America is exporting approximately 4.26 million barrels of crude oil and 7.55 million barrels of petroleum products each day. LNG exports are headed toward 17.6 billion cubic feet per day. Another 21.5 billion cubic feet per day of new LNG capacity is operating, under construction or approved for investment.

Global coal demand is expected to reach a record 8.94 billion metric tons this year.

Those figures show energy dominance in practice, and it begins with domestic resources.

But there are weaknesses.

Our Strategic Petroleum Reserve holds 283 million barrels, down from approximately 408 million a year ago. Global inventories are 509 million barrels below pre-war levels. We still cannot build refineries quickly enough to fix $6 diesel this winter.

I have said there are only two ways to bring prices down: reduced demand or more refineries. Right now, we are getting reduced demand. I would prefer more refining capacity.

Watch Hormuz. Watch Qatar’s projected October exports of 600,000 metric tons. Watch EIA’s November 10 outlook.