- Offshore driller balance sheets are stronger after a wave of bankruptcies in 2020 and 2021.
- Increased offshore spending will continue to support healthy drilling activity and ancillary services as utilization and dayrates rebound.
- Nascent offshore wind industry has long-term growth potential with limited near-term impact.
- Ratings will be relatively stable for offshore drillers under our assumption of $85 per barrel Brent.
After years of turbulence, many global offshore drilling companies returned to capital markets. Bankruptcy was the theme for offshore drillers following the last oil and gas downturn in 2015-2016. Leading up to that period, offshore drilling companies went on huge spending sprees to build out deepwater rigs. However, the severe commodity decline in 2015 and increased momentum behind lower-cost short-cycle shale oil severely limited offshore spending, resulting in a massive oversupply of shallow and deepwater rigs and a particularly protracted downturn. Excess supply gradually worked off through consolidation, retirements, and natural attrition while the 2020 commodity price drop proved to be the final nail in the coffin as most of the top offshore players filed for bankruptcy protection, other than Transocean Ltd. Companies emerged into a healthier hydrocarbon commodity cycle with substantially lower debt levels and industrywide discipline on new build spending. Rated companies like Noble Corp., Valaris Ltd., Seadrill Ltd., and Diamond Offshore Drilling Inc., returned to the capital markets over the past six months to establish more traditional capital structures post-bankruptcy, with debt still significantly below pre-bankruptcy levels.
Offshore Spending On The Rise
We expect the renewed focus on offshore development will push offshore exploration and production (E&P) spending to 35% of global spend next year. Offshore accounted for about 29% of total global E&P spending in 2022, in line with the long-term average of 30% going back to 2003. In 2022, offshore spending grew an impressive 21% to $148 billion led by growth in Latin America (LatAm; 31%; includes Guyana) and Asia-Pacific (APAC; 21%). Latam and APAC were the largest components of global offshore spending in 2022 at 28% and 26%, respectively. We expect double-digit growth in offshore spending this year and next, in contrast with relatively flat onshore spending for the same period. We expect 20% growth in 2023 to be fairly broad from a regional perspective, led by renewed interest in Africa (45%). Next year, we expect 14% growth will be buttressed by Latam (18%), APAC (14%), and Africa (25%).
Increased offshore spending growth could be supported by longer-term structural characteristics like maturing, short-cycle U.S. shale, which has an approximate 35%-40% annual decline rate that must be replaced compared to longer-term offshore projects with lower decline rates of approximately 10%-15%. On the policy front, elevated geopolitical tensions over the past 12-24 months have reintroduced energy security as a top global priority, which must be balanced with country specific emissions reductions targets. In our view, offshore could benefit from this renewed prioritization for companies with limited onshore options.
Increased exploration spending above 2014 highs portends healthy offshore activity. Global offshore exploration spending reached $19.2 billion in 2022, approaching 2014 highs; however, this time, led by LatAm (32%) and APAC (22%) instead of Europe and Africa as seen in the last cycle. We expect offshore exploration spending to grow 21% in 2023 and 6% in 2024. We anticipate that the broad spending growth seen this year will be more targeted in 2024 when growth will be led by APAC and a resurgent Africa. We still expect LatAm to remain the largest contributing region at around 32% of exploration spending.
We expect offshore spending growth to result in robust activity for drillers as well as ancillary service providers. Drilling and service spending is the largest component of offshore spending, followed by topside engineering procurement, and construction (EPC). Drilling and service spending was $67 billion in 2022, which was 46% of global offshore spending. We anticipate this to increase to 51% ($91 billion) in 2023, approaching 2014 highs, and remain above the long-term average of 42% across our forecast period.
Floater Supply Improved
Supply dynamics have significantly improved since the offshore downturn, which supports better day rates. The estimated floater supply of 191 is about half the supply at the peak in 2014. Global fleet quality also improved over the period. In 2014, the fleet had roughly a third of lower specification (spec) midwater rigs (rated to a maximum depth of 3,000 feet) with two thirds higher spec deepwater rigs (+7,500 feet). After the downturn, companies decreased the number of midwater rigs and now most of the supply consists of deepwater rigs. LatAm is the largest deepwater market with about 25% of total supply.
We don't expect a large increase in supply for floaters because there are 21 newbuilds under construction or on order as of January 2023. Floating rig orders reached their peak in 2011 at just under 30, and there have been few orders since 2014. We expect any newbuild orders would be accompanied by a contract instead of on a speculative basis. Market commentary around newbuild drillships place the cost between $800 million and $1 billion and would take about five years to complete. We see this as a high hurdle for management teams and market participants to get comfortable with, and view newbuild activity as less likely. Relative to jackups, the global floater fleet is younger, partially because of attrition and the scrapping of older drillships since 2014 due to higher stacking (i.e., storage) costs.
Jackup Supply Remains Steady
Jackup supply was around 470 units in the first quarter of 2023 and has remained relatively steady since 2014. Unlike 2014, however, fleet quality has improved since higher-spec jackups rated to depths of over 300 feet now make up a majority of the global fleet. The largest jackup markets are the Middle East and APAC, which make up 38% and 30% of total supply, respectively.
We view jackup spending as more disciplined than in the past. We don't expect a large increase in supply given the small number of newbuilds (20 total; 18 uncontracted) in the shipyard and the lack of speculative jackup newbuild orders this cycle compared to a combined 120 orders in 2013 and 2014. There have been no new orders since 2015, except ARO Drilling in the Middle East--a 50/50 joint venture between Saudi Aramco and Valaris Ltd.--who ordered two jackups for contracted work in Saudi Arabia. As a result, the global jackup fleet also skews older with about 30% over 35 years old. Increased attrition is likely as older equipment is determined to be noncompetitive or it's repurposed for alternative use, indicative of disciplined supply.
Increased offshore demand has tightened the market and led to substantially higher utilization across jackups and floaters, which is the main driver of pricing power. Jackups and drillship utilization is just over 80% as of July 2023, recapturing the 2015 highs. Semisubmersible utilization is also healthy at about 70%.
We believe the risk for a near term drop in utilization is low, which would either be the result of lower demand or speculative reactivations of stacked rigs without a working contract. There haven't been many speculative reactivations yet in this cycle. The 25 warm stacked would be the first candidates for reactivation given the lower reactivation expense compared to cold stacked rigs; however, this represents only about 5% of total supply. Cold stacked rig count is more substantial at about 12% but most of the cold stacked rigs are lower spec and are less likely to be competitive.
Similar to the jackup market, warm stacked floaters only represent about 5% of total supply while cold stacked is about 13%. Again, we haven't seen speculative reactivations yet this cycle as management teams have remained disciplined by only reactivating rigs for contracted work. Cost and time are also constraining factors for reactivations, for example, Transocean Inc. estimates it would cost around $100 million to reactivate a drillship and would take 12-18 months. This results in more stable supply since it creates a higher hurdle for reactivations compared to past cycles.
Strong Day Rates
Day rates moved solidly higher over the past 18 months on an elevated commodity price environment, healthy offshore spending levels, and industry discipline around marginal rig supply. Floater day rates have recovered to 2014 levels, and earnings call commentary indicates leading edge floater day rates likely threaten $500,000, which is approaching the peak of the last offshore cycle.
For example, in the harsh environment, semisubmersible market, Transocean plans to relocate harsh environment semisubmersible Transocean Equinox to Australia from the North Sea, with customer options to extend the contract out to 2027 at day rates exceeding $500,000. Conversely, drillships are still waiting to see a more than $500,000 per day rate but the trends are positive. Contract bargaining power has shifted back to the contractors, and provisions like mobilization and reactivation reimbursements are also becoming more favorable.
Long-Duration Contracts Favored
As the markets continue to tighten, we expect drillers to add term contracts as operators scramble to lock in proven equipment. Instead of one-year contracts, we expect the trend of three- to five-year contracts to continue. We view longer contracts favorably since they provide better visibility of future cash flows and enhance credit support. The emergence of long-term contracts (out to 2027 or beyond) has been concentrated in the deepwater floater market resulting in higher backlogs.
We expect stable oil and gas activity in the U.S. Gulf of Mexico. However, restrictive policy and legal challenges on environmental grounds for offshore lease sales adds uncertainty for the next several years. Lease sales have periodically been delayed but are still mandated by law to occur. We see limited, direct risk to current production levels because of this uncertain cadence but we expect it could be an emerging risk as companies manage inventory in years to come.
In the North Sea, we expect U.K. North Sea development activity to be somewhat more subdued relative to other basins due to the windfall tax policy, which introduced doubt to the future tax treatment of capital-intensive offshore projects. In the Norway North Sea, environmental, social, and governance (ESG)-related concerns have limited offshore tendering, which delayed development plans and pushed high-spec, harsh-environment semisubmersibles to demand markets like Australia where day rates have surged. Greater activity in Norway would require significantly higher day rates to incentivize a return of equipment to the region.
U.S. offshore wind energy production, with only 30 megawatts (MW) capacity, severely lags its U.K. counterpart, which had about 14 gigawatts (GW) capacity as of 2022. For now, the small market scale results in limited revenue contribution for traditional offshore oil and gas related companies. According to the U.S. Department of Energy's (DOE) Offshore Wind Market Report: 2023 Edition, 52,687 MW are in the U.S. offshore wind energy pipeline. As this market develops from its current nascent stage, we expect opportunities will unfold most directly for service providers such as subsea installation, transportation, and logistics companies to facilitate infrastructure build out. Appetite for these projects have remained focused on the U.S. East Coast instead of the Gulf of Mexico, which recently held its first offshore wind development rights auction with weak results. Two of the three lease areas received no bids and the remaining lease area commanded a winning bid of just $5.6 million. Therefore, while the Gulf presents a long-term opportunity, we believe current interest (and by extension benefits for service companies) remains limited.
Credit Quality Implications
We expect elevated offshore capital expenditures and disciplined spending by drilling contractors to support revenue growth and positive free cash flow generation next year as existing contracts roll off and step up to market rates. For the floater market, we expect continued momentum in Brazil, Australia, and West Africa, stable activity in the U.S. Gulf of Mexico, and relatively softer activity in the North Sea. Transocean remains the key swing supplier for stacked floaters with approximately eight stacked drillships, which could support outsized growth relative to peers' if demand continues to strengthen. We expect Transocean and its offshore peers to maintain disciplined behavior and only reactivate drillships on contract rather than speculatively. The industry has improved due to consolidation in recent years with Maersk merging into Noble Corp. and Seadrill's acquisition of Aquadrill in 2022, as well as Ensco's acquisition of Rowan in 2019 and subsequent renaming to Valaris.
For the jackup market, the Middle East will drive global demand. For example, ARO Drilling, Valaris' joint venture with Saudi Aramoco, plans to purchase 20 newbuild jackups over the next decade, with the first two slated for delivery this year. The rigs are backed by long-term contracts with Saudi Aramco, structured to return the cost of the rig in the initial six years. Unlike the floater market, the largest jackup contractors are dominated by national oil company (NOC)-related enterprises with presumably more strategic views on local demand, these include Advanced Energy (ADES; owned by the Public Investment Fund of the Kingdom of Saudi Arabia), state-owned China Oilfield Services, and ADNOC (the drilling arm of Abu Dhabi National Oil Co.).
Under our price deck assumption of $85 per barrel for Brent through 2026 and beyond, we expect healthy offshore demand and discipline around new supply will support higher utilizations and day rates leading to relatively stable ratings for offshore drillers. We also expect ancillary services companies with offshore exposure will benefit from the resulting higher activity levels.
This report does not constitute a rating action.
|Primary Credit Analyst:||Grant Schallock, CFA, New York 212-438-0794;|
|Secondary Contacts:||Thomas A Watters, New York + 1 (212) 438 7818;|
|Edward Murphy-Schwartz, New York + 1 (212) 438 1531;|
|Research Assistant:||Ashutosh B Sarda, Pune|
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