The Offshore Drilling Comeback Takes the Road Less Profitable

Although offshore drilling demand is slowly getting better, headwinds remain.

Idled old rigs, such as the Valaris DPS-3 docked at Pelican Island near Galveston, are a damper on day rates, though many will be scrapped.
Source: Stephen Rassenfoss.

The hottest market for offshore rig demand for the coming year is one that even locals wouldn’t likely try to predict.

That market is the North Sea, according to an outlook from Westwood Global Energy Group, based on the expected days of work next year where it ranks first for jackups and second for floating drilling platforms.

“The fact that the North Sea is the second-highest on floaters required might surprise some people in the UK,” said Terry Childs, director of Westwood’s Riglogix database service and research.

A big part of the demand is from plugging and abandonments (P&A) reflecting the fact that the North Sea is an old basin, “but there is a lot of drilling going on,” Childs said, adding, it “could be a rebound year for the North Sea market.”

In basin after basin, the drilling data firm reported continued improvement with the number of rigs working around the levels reached in 2019, making it a “decent year” in a sector of the oil business where activity last year was little changed by the oil price bust.

The news of the day—Noble’s announcement that it would acquire Maersk Drilling—highlighted the fact that success in offshore drilling requires a fleet of rigs in high-demand sectors of the market and tight cost management.

The Noble-Maersk deal combines fleets that are each strong in a sector where the supply of rigs is tight. Noble has nine drillships working off Guyana and in the Gulf of Mexico—regions where 100% of the drillships are working. Nearly 75% of its 38-rig fleet is active, according to a Noble presentation.

Maersk has six jackups designed for ultraharsh conditions working in the North Sea which command day rates comparable to drillships. The day rates range from an average of around $280,000 with some contracts exceeding $300,000, Westwood said.

In comparison, the average jackup commands $82,000/day in the North Sea and $68,000/day in the Gulf of Mexico.

The rates are better than average, but a prime selling point for the Noble-Maersk deal is that the combination is expected to reduce expenses by $125 million by eliminating overlapping corporate operations.

Another telling detail: Noble used stock to pay for most of the cost—cash payments were limited to $1,000 per shareholder—a plus when cash flow remains limited.

Childs predicted “more consolidation on the way,” listing Diamond Offshore, Seadrill, and Valaris, which was created by combining Rowan and Ensco, as likely candidates, adding that “other contractors are certainly in play.”

In this business, though, financial engineering can only do so much. All of those companies and Noble too, slashed their interest expenses by filing for bankruptcy protection in 2020.

Two of the surviving big names in the business, Seadrill and Diamond Offshore, have recently been trading for 20 cents/share or less despite slashing their interest costs, highlighting the need for higher day rates.

Utilization for the most in-demand equipment is reaching the level where rates could pop next year. While talking about the African market, Childs said “85% utilization is where you start seeing a significant increase in day rates.

“We have seen $350,000 drillship rates. Will there be something with a 4 on the front of it … that wouldn’t surprise me,” he said.

But there is a limit. “There is some room to move up. I do not think we will see the $600,000/day rates we saw in 2012.”

One barrier to higher rates is the large inventory of idled equipment overhanging the market. Childs pointed out that 12 coldstacked drillships have gotten contracts lately, expanding the supply.

Oil prices around $80/bbl are pushing up demand, but there is downside: “When the market improves, contractors slow attrition,” he said. The number of rigs scrapped dropped from 46 in 2020 to 28 this year, according to Westwood.

While the shakeout has slowed, Childs repeatedly said, “With attrition it is a question of when, not if.”

A chart breaking down the supply of idle rigs based on how long they have been stacked shows there is a large supply of old rigs that will never go back into service.

Of the 201 rigs Westwood counted, nearly one third have been stacked for 3 years or longer. Seventy-four percent of those have been coldstacked, meaning they have received limited maintenance and will require cost and time to get back into working order.

They are competing with 38 rigs idled for 6 months or less, 92% of which are hot- or warmstacked, meaning they can be quickly activated at a limited cost. Of the rigs idled 6 to 12 months, 64% have been warm- or hotstacked.

All these projections come with a big “if:” “This all assumes $80 to $85/bbl will remain in place,” Childs said.

That seems like a good bet based on OPEC+’s recent decision to stick with its deal to slowly add oil production. But the US Energy Information Administration recently predicted rising production by OPEC+ and the US will cause inventories to grow again, which it said could mean Brent crude prices in the low $70s next year.

That’s not as good as $80, but after 5 years of oil prices in the $50s or lower, it’s hard to say that’s going to be “bad” for drilling.