From the Daily Caller News Foundation

By David Blackmon

What if they gave an oil price spike and nobody came? That is admittedly kind of a lame play on an old saying about parties, but it’s exactly what has happened over the two weeks since June 12, when Israel launched its initial assault on Iran.

At that day’s close of trading, the domestic U.S. WTI price sat at $68.04 per barrel. As of this writing on June 24, the price stands at $64.50. That’s not just the absence of a price spike, it is the opposite of one, a drop of 5% in just two weeks.

So, what happened? Why didn’t crude prices spike significantly? For such a seemingly complex trading market that is impacted daily by a broad variety of factors, the answer here is surprisingly simple, boiling down to just two key factors.

• Neither Israel nor the United States made an effort to target Iran’s refining or export infrastructures.
• Despite some tepid, sporadic saber rattling by Iranian officials, they mounted no real effort to block the flow of crude tankers through the region’s critical choke point, the Strait of Hormuz.

Hitting Iran’s infrastructure could have taken its substantial crude exports – which the International Energy Agency estimates to be 1.7 million barrels per day – off the global market, a big hit. Shutting down the Strait of Hormuz, through which about 20% of global crude supplies flow every day, would have been a much bigger hit, one that would have set prices on an upward spiral.

But the oil kept flowing, muting the few comparatively small increases in prices which did come about.

Respected analyst David Ramsden-Wood, writing at his “HotTakeOfTheDay” Substack newsletter, summed it up quite well. “Oil is still structurally bearish. U.S. producers are in PR mode—talking up ‘Drill, baby, drill’ while actually slowing down. Capex is flat to declining. Rig counts are down. Shareholders want returns, not growth. So we’re left with this: Tension in the Middle East, no supply impact, and U.S. production that’s quietly rolling over. Oil shrugged.”

There was a time, as recently as 10 years ago, when crude prices would have no doubt rocketed skywards at the news of both the commencement of Israel’s initial June 12 assault on Iran’s military and political targets and of last Saturday’s U.S. bombing operation. In those days, we could have expected crude prices to go as high as $100 per barrel or even higher. Markets used to really react to the “tension in the Middle East” to which Ramsden-Wood refers, in large part, because they had no real way to parse through all the uncertainties such events might create.

Now it’s different. Things have changed. The rise of machine learning, AI and other technological and communications advancements has played a major role.

In the past, a lack of real-time information during any rise in Middle East tensions left traders in the dark for some period of time – often extended periods – about potential impacts on production in the world’s biggest oil producing region. But that is no longer the case. Traders can now gauge potential impacts almost immediately.

That was especially true throughout this most recent upset, due to President Donald Trump’s transparency about everything that was taking place. You were able to know exactly what the U.S. was planning to do or had done just by regularly pressing the “refresh” button at Trump’s Truth Social feed.

Tim Stewart, President of the D.C.-based U.S. Oil and Gas Association, has a term for this. “The Markets are becoming much better at building the ‘47 Variable’ into their short-term models,” he said in an email. “This is not a Republican Administration – it is a Disrupter Administration and disruption happens both ways, so the old playbooks just don’t apply anymore.  Traders are taking into account a President who means what he says, and it is best to plan for it.”

Add to all that the reality that a high percentage of crude trading is now conducted via automated, AI-controlled programs, and few trades are any longer made in the dark.

Thus, the world saw a price spike which, despite being widely predicted by many smart people, didn’t happen, and the reasons why are pretty simple.

David Blackmon is an energy writer and consultant based in Texas. He spent 40 years in the oil and gas business, where he specialized in public policy and communications.

(Featured Image Media Credit: Screen Capture/PBS NewsHour)

Wells at the Clive carbon capture, utilization and storage project near Red Deer, Alta. Photo courtesy Enhance Energy

From the Canadian Energy Centre

By Deborah Jaremko

Inside Clive, a model for reducing emissions while adding value in Alberta

It’s a bright spring day on a stretch of rolling farmland just northeast of Red Deer. It’s quiet, but for the wind rushing through the grass and the soft crunch of gravel underfoot.

The unassuming wellheads spaced widely across the landscape give little hint of the significance of what is happening underground.

In just five years, this site has locked away more than 6.5 million tonnes of CO₂ — equivalent to the annual emissions of about 1.5 million cars — stored nearly four CN Towers deep beneath the surface.

The CO₂ injection has not only reduced emissions but also breathed life into an oilfield that was heading for abandonment, generating jobs, economic activity and government revenue that would have otherwise been lost.

This is Clive, the endpoint of one of Canada’s largest carbon capture, utilization and storage (CCUS) projects. And it’s just getting started.

Rooted in Alberta’s first oil boom

Clive’s history ties to Alberta’s first oil boom, with the field discovered in 1952 along the same geological trend as the legendary 1947 Leduc No. 1 gusher near Edmonton.

“The Clive field was discovered in the 1950s as really a follow-up to Leduc No. 1. This is, call it, Leduc No. 4,” said Chris Kupchenko, president of Enhance Energy, which now operates the Clive field.

Over the last 70 years Clive has produced about 70 million barrels of the site’s 130 million barrels of original oil in place, leaving enough energy behind to fuel six million gasoline-powered vehicles for one year.

“By the late 1990s and early 2000s, production had gone almost to zero,” said Candice Paton, Enhance’s vice-president of corporate affairs.

“There was resource left in the reservoir, but it would have been uneconomic to recover it.”

Facilities at the Clive project. Photo courtesy Enhance Energy

Gearing up for CO2

Calgary-based Enhance bought Clive in 2013 and kept it running despite high operating costs because of a major CO2 opportunity the company was developing on the horizon.

In 2008, Enhance and North West Redwater Partnership had launched development of the Alberta Carbon Trunk Line (ACTL), one of the world’s largest CO2 transportation systems.

Wolf Midstream joined the project in 2018 as the pipeline’s owner and operator.

Completed in 2020, the groundbreaking $1.2 billion project — supported by the governments of Canada and Alberta — connects carbon captured at industrial sites near Edmonton to the Clive facility.

“With CO2 we’re able to revitalize some of these fields, continue to produce some of the resource that was left behind and permanently store CO2 emissions,” Paton said.

Map of the Alberta Carbon Trunk Line courtesy of Wolf Midstream

An oversized pipeline on purpose

Each year, about 1.6 million tonnes of CO2 captured at the NWR Sturgeon Refinery and Nutrien Redwater fertilizer facility near Fort Saskatchewan travels down the trunk line to Clive.

In a unique twist, that is only about 10 per cent of the pipeline’s available space. The project partners intentionally built it with room to grow.

“We have a lot of excess capacity. The vision behind the pipe was, let’s remove barriers for the future,” Kupchenko said.

The Alberta government-supported goal was to expand CCS in the province, said James Fann, CEO of the Regina-based International CCS Knowledge Centre.

“They did it on purpose. The size of the infrastructure project creates the opportunity for other emitters to build capture projects along the way,” he said.

CO2 captured at the Sturgeon Refinery near Edmonton is transported by the Alberta Carbon Trunk Line to the Clive project. Photo courtesy North West Redwater Partnership

Extending the value of aging assets

Building more CCUS projects like Clive that incorporate enhanced oil recovery (EOR) is a model for extending the economic value of aging oil and gas fields in Alberta, Kupchenko said.

“EOR can be thought of as redeveloping real estate,” he said.

“Take an inner-city lot with a 700-square-foot house on it. The bad thing is there’s a 100-year-old house that has to be torn down. But the great thing is there’s a road to it. There’s power to it, there’s a sewer connection, there’s water, there’s all the things.

“That’s what this is. We’re redeveloping a field that was discovered 70 years ago and has at least 30 more years of life.”

The 180 existing wellbores are also all assets, Kupchenko said.

“They may not all be producing oil or injecting CO2, but every one of them is used. They are our eyes into the reservoir.”

CO2 injection well at the Clive carbon capture, utilization and storage project. Photo for the Canadian Energy Centre

Alberta’s ‘beautiful’ CCUS geology

The existing wells are an important part of measurement, monitoring and verification (MMV) at Clive.

The Alberta Energy Regulator requires CCUS projects to implement a comprehensive MMV program to assess storage performance and demonstrate the long-term safety and security of CO₂.

Katherine Romanak, a subsurface CCUS specialist at the University of Texas at Austin, said that her nearly 20 years of global research indicate the process is safe.

“There’s never been a leak of CO2 from a storage site,” she said.

Alberta’s geology is particularly suitable for CCUS, with permanent storage potential estimated at more than 100 billion tonnes.

“The geology is beautiful,” Romanak said.

“It’s the thickest reservoir rocks you’ve ever seen. It’s really good injectivity, porosity and permeability, and the confining layers are crazy thick.”

Suitability of global regions for CO2 storage. Courtesy Global CCS Institute

CO2-EOR gaining prominence 

The extra capacity on the ACTL pipeline offers a key opportunity to capitalize on storage potential while addressing aging oil and gas fields, according to the Alberta government’s Mature Asset Strategy, released earlier this year.

The report says expanding CCUS to EOR could attract investment, cut emissions and encourage producers to reinvest in existing properties — instead of abandoning them.

However, this opportunity is limited by federal policy.

Ottawa’s CCUS Investment Tax Credit, which became available in June 2024, does not apply to EOR projects.

“Often people will equate EOR with a project that doesn’t store CO2 permanently,” Kupchenko said.

“We like to always make sure that people understand that every ton of CO2 that enters this project is permanently sequestered. And we take great effort into storing that CO2.”

The International Energy Forum — representing energy ministers from nearly 70 countries including Canada, the U.S., China, India, Norway, and Saudi Arabia — says CO₂-based EOR is gaining prominence as a carbon sequestration tool.

The technology can “transform a traditional oil recovery method into a key pillar of energy security and climate strategy,” according to a June 2025 IEF report.

Drone view of the Clive project. Photo courtesy Enhance Energy

Tapping into more opportunity

In Central Alberta, Enhance Energy is advancing a new permanent CO2 storage project called Origins that is designed to revitalize additional aging oil and gas fields while reducing emissions, using the ACTL pipeline.

“Origins is a hub that’s going to enable larger scale EOR development,” Kupchenko said.

“There’s at least 10 times more oil in place in this area.”

Meanwhile, Wolf Midstream is extending the pipeline further into the Edmonton region to transport more CO2 captured from additional industrial facilities.