In what was one of the worst years in the history of the oil and gas industry, Chevron executive vice president of upstream Jay Johnson sees confirmation of the company’s adherence to capital and cost discipline.


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After a strong first quarter, the Covid-19 pandemic sank demand, creating a global surplus of crude.

Chevron responded by slashing its 2020 upstream budget from $17 billion to $11 billion annual rate, all in one quarter.

“We pulled it all back, because frankly, it just didn't make sense to continue to invest to develop new capacity when the world was so heavily oversupplied," Johnson tells Upstream.

"Our strategy shifted to one of maintaining existing production and getting the highest returns that we could, but at the same time preserving longer-term value.

"Because of the short-cycle nature of our investments, we can watch what is happening in the markets, and then build that activity level back up when it makes sense.”

Short cycle projects are focused on returning the operator’s investment more quickly.

These types of projects are on the other end of the investment spectrum, the opposite of the large high-risk, high-reward, long-cycle projects — or “mega” projects — that were common before the downturn of oil prices in 2014.

With short-cycle projects, there’s a flexibility that enables the quick response needed for unexpected market conditions, making it possible to defer projects that have yet to begin and focus funds on finishing projects already under construction.

“Our execution performance in short-cycle projects continues to be a strength where these types of investments have consistently met or exceeded expectations on cost, schedule, and most importantly full-cycle returns,” he says.

For 2021, the company has allocated about 60% of its capital spending on short-cycle investments, rising to 75% by 2025.

“When we talk about 60% of our capital going into short-cycle investments, those are predominantly in the shale and tight-oil category. That proportion of our resource base has increased every year,” he says.

Tuning investment

“It’s been a real advantage for us because rather than having to make big bets on future prices and future conditions, launching multibillion-dollar, long-term, long-dated projects — and hope you're right — we can actually tune our investment to the visions that we see evolving around us in a much closer time frame.”

Shorter-cycle projects have the advantage of being relatively simple and straightforward, Johnson says.

“They're within the capacity of the organisation to execute cleanly... we know [that] what we’re putting out there is needed and will operate reliably.

"We're now taking what we’ve learned and applying it to the longer-cycle projects," he adds.

Rather than very large, complex facilities designed to "try and get that last incremental bit of value out of the project," Chevron is opting for smaller-scope and simpler project execution to achieve its objectives.

“[This approach] focuses more on the capital efficiency and return than just simply maximising [net present value],” he says. “So, you see us building smaller facilities, like the one we selected for Anchor.”

According to Chevron, the Anchor field in the US Gulf of Mexico marks the industry’s first sanctioned deep-water development with technology capable of handling pressures of 20,000 pounds per square inch.

Anchor standards

The first stage of the project — located in the Green Canyon area 225 kilometres offshore Louisiana, in water depths of about 1500 metres — consists of a seven-well subsea development and a semi-submersible floating production unit.

“At our Anchor project, we went with a modest-sized, standardised facility that we can easily replicate. Initially, we will drill only a couple of wells in advance of putting the facility out there and starting up,” he says.

The planned facility has a design capacity of 75,000 barrels per day of crude and 28 million cubic feet per day of natural gas. First oil is anticipated in 2024.

“As we get production history from those first couple of wells, we’ll be able to history-match and fine-tune our reservoir models, [with] which we can continue a ‘drill-to-fill’ strategy to keep the facility full over a longer-period of time,” he says.

“We also will have better placement of wells into the reservoir due to the real-time data we’ll be getting from that production.”