Drilling advances

If you're a drilling contractor, how you perceive the current U.S. market conditions depends on whether you're navigating an 18,000-ft lateral in Louisiana's Haynesville shale or landing a well in more than 9,000 ft of water in the Gulf of Mexico. 

If, as they say, location is everything, the near-term prospects are particularly dubious in the terra firma. A souring gas market has teamed up with persistent operator financial discipline to leave purveyors of land rigs with fingers crossed, hoping for a late-year pick-me-up. On the other end of the attitude spectrum, offshore contractors are unrestrained in their exuberance over a remarkable turnaround, especially in deep water.   

"Softness in natural gas pricing in the U.S. has had a dampening effect on current rig activity and is contributing to an increased level of contractual churn in the market, not only in terms of number of rigs, but also the increased idle time between contracts," said John Lindsay, president and CEO of major onshore driller Helmerich and Payne Inc, in an April 28 call.  

Compare that with this view from the C-suite of offshore contractor Noble Corp. "The fundamental set-up for our industry is arguably the best that it has looked in the past 20 years, based on a confluence of macro supply and demand factors," President and CEO Robert Eifler gushed on Feb. 27.  

“Mid-cycle pause.” In what Lindsay describes as "a challenging market environment,"  operators continue to stubbornly cling to commitments to funnel cash to shareholders, rather than invest in drilling programs. Add to that, a more than 81% drop in gas prices since August 2022, and it's easy to see why onshore drillers are not quite as buoyant as their offshore counterparts.  

Henry Hub spot gas prices sank to a thus-far yearly low of $1.85/MMBtu on June 9, down monumentally from the 2022 high of $9.85/MMBtu last August. Correspondingly, of the 665 active U.S. land rigs that Baker Hughes counted on June 16, only 130 of them were targeting gas, down from 154 rigs drilling for gas a year earlier.  The sharpest single-basin decline came in the dry gas Haynesville of northwestern Louisiana and far eastern Texas, with 51 rigs drilling ahead in June, down 18 rigs year-over-year. Of the Helmerich and Payne rigs laid down, roughly 70% were released by privately-held operators, nearly all drilling in gas basins, Lindsay said. 

Acknowledging the "challenging environment in the Lower 48," Nabors Industries President Tony Petrello singled out East Texas as particularly weak. "With respect to East Texas, there were a lot of private operators that came in and drove the activity increase. When the end of March came along, a lot of those guys just hit the pause button, and that's what's caused the air pocket we're seeing (in the gas market)," he told analysts on April 25.  

That said, contractors say they are not inclined to reduce day rates. "In some of the more challenged gas markets like the Haynesville, which have been more affected by gas prices coming down, either it makes sense to drill a well or it doesn't. And so us reducing the day rate on a rig by 10% or 15% is not going to boost the economics to get a well drilled," says William  Hendricks, president and CEO of Patterson-UTI Energy, Inc. 

Also, most see the current market as more of a temporary blip, with conditions likely improving as winter approaches and more liquefied natural gas (LNG) export capacity comes online along the Gulf Coast. A blistering start to summer across much of North America could help speed up a recovery. 

"The U.S. natural gas market has been particularly weak, due to excess supply following a relatively warm winter and offline LNG takeaway capacity. Both of which should be short-term transitory issues," Lindsay says. 

Hendricks agrees that the market will firm up as the year progresses. "Softness in natural gas prices, along with uncertainty regarding the future trajectory of oil prices, has led to what we believe to be a transitory and mid-cycle pause in activity," he said in an April 28 call. 

Full speed ahead offshore. For owners of high-spec floaters, there's no waiting around for a recovery. Most deepwater rig contractors have picked up where they left off last year, with demand continuing to spike and backlogs building to what could be record levels.  

"During the quarter, we booked nearly $900 million of contract backlog, disrupting the first-quarter lull observed in years past," Transocean CEO Jeremy Thigpen said in a May 2 earnings call.  "In fact, this is more than double the backlog added in the first quarter of 2022 and more than seven times what we added in the first quarter of 2021." 

In its April 18 fleet status report, Transocean listed 10 drillships active in the Gulf of Mexico, including the 8th Generation ultra-deepwater Deepwater Atlas and Deepwater Titan, engineered to handle 20,000-psi downhole pressure. Beginning in October, the two drillships went directly from the shipyard to work for Beacon Offshore Energy and Chevron, respectively, under $455,000/day contracts.   

"Based on our direct negotiations, we believe that there is sufficient future demand to bring one or two more rigs into the (Gulf of Mexico) region on long-term programs," Thigpen said.  

As of May 3, Noble was running five of the 21 deepwater drilling rigs that S&P Global's MarineBase counted as active in the Gulf. "Our backlog as of May 1 has increased to $4.6 billion, up from $3.9 billion at the beginning of the year. In addition to these recent contracts and commitments, we're optimistic that we should have some additional UDW (ultra-deepwater) contracts finalizing over the coming weeks," Eifler said.  

A year removed from its relisting on the New York Stock Exchange, Diamond Offshore has four drillships working in the Gulf, with current contracts ranging from August 2023 to February 2025.  

From all indications, the good times will not evaporate any time soon in the Gulf of Mexico and beyond. In a June 12 release, Wood Mackenzie said global deepwater rig utilization, which is now over 85%, should increase another 20% during 2024-2025, further pushing day rates that have doubled in the past two years for best-in-class floaters.  

"If it wasn't for the reactivations and anticipated reactivations, we would already be solidly into $500,000 today," says Diamond President and CEO Bernie Wolford. "I mean, in my mind, there's no doubt about that." 

About the Authors

Jim Redden

Contributing Editor

Jim Redden is a Houston-based consultant and a journalism graduate of Marshall University, has more than 40 years of experience as a writer, editor and corporate communicator, primarily on the upstream oil and gas industry.