• Borr Drilling acquires five Mexican jackups from Paratus Energy (Fontis Finance) for $287mm (excluding working capital), with a $237mm seller's note to a newly formed JV introducing incremental credit complexity for Paratus bondholders

• Following the jackup sale, Paratus’ remaining asset is its 50% stake in the Seagems PLSV JV, with a strong contract book through 2027–2028 in an attractive Brazilian market

• Constellation Oil Services' earnings call flagged two near-term Brazilian catalysts: conclusion of Petrobras' Renecon efficiency program in early April and pending Buzios multi-rig tender results. Also Foresea’s new 6G ODN I contract

Before diving in, the Middle East conflict has removed an estimated 7–10 million bpd from global oil supply, an extraordinary volume that excludes Qatari LNG disruption. For deepwater, the impacts are not immediate given long-cycle capex lead times, but the energy security implications are constructive for the market over the medium term. The recent Brazilian contract awards discussed below reflect 2025 market conditions — these tenders are roughly nine months old — and while dayrates are soft, they should be read in that context. Lower crude prices through 2025 pressured oil major cash flows and contributed to project delays, constraining rig demand which is a headwind that is abating with Brent near $100/bbl, which should support capital budget expansion and incremental drilling activity in 2027.

On March 23, 2026, Borr announced the acquisition of five jackup rigs in Mexico from Fontis Finance (Paratus Energy) for $287mm, inclusive of over $100mm in associated receivables, for a total transaction value of approximately $400mm. Paratus will receive $148–163mm in cash and a $237mm seller's note as consideration. The seller’s note is essentially secured bridge financing to BC Ventures Limited, a newly formed 50/50 JV between Borr and its Mexican well construction partner, carrying a 2.5-year maturity with a step-up coupon: 10% in year one, 12% in months 13–18, and 14% thereafter. Borr already has a presence in Mexico and acquiring 5 competing jackups in the region will be positive for its pricing power in the region.

Borr was a logical acquirer following Paratus's public signaling of its intent to divest its jackup fleet, particularly given Borr's stated plans to deploy proceeds from its $200mm equity offering in early July. In August 2025, prior analysis noted potential for a Borr/Paratus jackup transaction with an estimated $280-$300mm price range, making the $287mm headline figure (excluding working capital) within the expected range. However, the consideration structure is less clean than an all-cash deal. The $237mm seller's note from a newly formed JV with a 2.5-year maturity is clearly less ideal than cash, although BC Ventures is incentivized to refinance given the step-up coupon.

Given BC Ventures' JV structure, how the entity refinances this note will be worth watching — particularly whether it taps the USD bond market or finances separately against the new collateral pool. A standalone structure would likely carry an elevated coupon given the limited collateral and heavy Mexico concentration (for now). Separately, a $150mm seller's note from Noble's January 2026 rig acquisition also remains outstanding, secured by five rigs and subject to its own eventual refinancing but does not have a JV structure.

Paratus has designated the transaction a 'Material Asset Sale' under its 2029 bond indenture, requiring bondholder amendment to permit a seller's note in lieu of full cash proceeds — a negotiation worth monitoring given the credit implications. Strictly from a credit perspective (not bond pricing and early redemption), if I’m a Paratus bondholder I want to be paid down in cash from an asset sale, not a seller’s note from a newly created JV with a non-IG credit profile. The seller's note is secured by the five rigs, but the obligor is BC Ventures, a newly formed JV with a credit profile distinct from Borr consolidated. On balance, both JV partners contributed $25mm in cash equity, reflecting meaningful alignment, and the Mexican jackup market appears positioned for cyclical recovery after recent softness. With two rigs currently idle, a refinancing of the seller's note will likely follow recontracting.

The current war in the Middle East has had an impact on the shallow water jackup market, which accounts for 35-40% of global demand. Borr enters 2H26 with 48% of its fleet open at a $139k average dayrate. Diversification across the GoM, West Africa, SE Asia and Europe should support utilization at current oil prices, though dayrates may depend on conflict duration and whether Mid East rigs are ultimately relocated, which is not currently expected to a material extent.

The Middle East conflict should support jackup demand in Mexico, and Borr's consolidation of five additional rigs in the region strengthens its pricing power, a key strategic rationale for the acquisition in an elevated oil price environment. While short-cycle jackup demand should improve in 2026, longer-term Mexico’s deepwater market is looking intriguing…

While Mexico's Gulf production is predominantly shallow, deepwater potential is emerging — Shell's Perdido and Whale developments in Alaminos Canyon and Transocean's Deepwater Thalassa, currently drilling Woodside's Trion project on the Mexican side, sit in close proximity and signal growing ultra-deepwater activity along the Perdido fold belt on both sides of the maritime boundary.

Woodside operates Trion at 60% alongside PEMEX at 40%. Strong project performance could validate the Perdido fold belt's extension into Mexican waters as a credible exploration frontier, potentially commanding a growing share of PEMEX's deepwater budget. Given the long-cycle nature of deepwater capex, potential projects beyond Trion are unlikely to compete meaningfully against PEMEX short-cycle jackup demand over the next 12 months. However, the region’s material prospectivity makes it worth watching toward decade-end.

Brazilian Deepwater Offshore Market

Turning to the Brazilian market — following the jackup divestiture, Paratus' remaining assets are through its 50% interest in the Seagems JV, which owns six PLSVs that install subsea pipelines connecting wellheads to FPSOs. This is a distinct vessel class from offshore supply vessels (Tidewater focus), where Subsea7, DOF, and TechnipFMC as the primary competitors. Paratus's PLSV fleet carries a strong contract book extending into 2027–2028, with exposure concentrated in Brazilian deepwater E&P capex.

The PLSVs are arguably the stronger assets, and a pure-play PLSV strategy appears to be Paratus' goal. Exposure to Brazil's Santos and Campos basins is an attractive position given pre-salt field productivity, though the outlook beyond the Buzios ramp-up in 2027 is less certain. Petrobras capex toward decade-end and into the 2030s remains an open question, as the next growth legs in Brazil are underexplored with a wide range of potential outcomes.

The Brazilian deepwater floater market came into sharper focus Tuesday when Constellation Oil Services (seven owned rigs, including one 7G drillship) held its earnings call, flagging two near-term catalysts: Petrobras' Renecon capital efficiency program is expected to conclude in early April, likely through blend-and-extend agreements on contracted rigs, with the long-awaited Buzios multi-rig, multi-year tender results to follow. Constellation announced a 1,042-day extension on an undisclosed rig at an implied dayrate of ~$255k ($266mm backlog), believed to be a lower-tier unit rather than the 7G Brava Star. Notably, the extension carries no associated capex or downtime.

Also on Wednesday, regional driller Foresea announced a 1,443-day contract for the 6G drillship ODN I with Petrobras on the Mero tender, commencing early 2027 at $280–300k per day (depending on additional services), with an early termination option at 1,078 days. The rate reflects both the lower operating cost structure of regional drillers, lower utilization outlook in 2025 when tenders began and the depth of competition in the Brazilian market, where Petrobras has its choice among the major international contractors (Transocean/Valaris, Seadrill and Noble) alongside several regional players, most notably including Constellation and Foresea.

Petrobras benefits from a group of regional drillers with low to mid-level spec deepwater rigs that value utilization over dayrate, as emphasized by Constellation’s conference call on Tuesday where they discussed the ~$255k dayrate (no capex, no downtime) dayrate on a likely 6G semisub.

However, a mid-$200k contract through 2029 is unfavorable dayrate duration. In the Paratus graphic above, all six of their PLSV’s are contracted at dayrates above $255k despite arguably costing materially less to build than Constellation’s semisubs. If the unnamed rig is Gold Star, with its current contract expiring in 1Q26, near-term idle exposure ahead of major tender commencements in 1Q27 likely weighed on the blended dayrate. While Constellation has more size than its regional peers, the smaller drillers seem to value utilization over dayrate. These are arguably subsidizing Petrobras’ E&P capex returns but this is a market dominated by one player which has a variety of drilling contractor choices with the regionals in the country.

A key rate watch in the Buzios tender is Brava Star, Constellation's only 7G drillship. The rig is expected to be included in Petrobras' Buzios tender for up to four rigs beginning 1H 2027 on approximately 3–4 year terms, a process that has been outstanding since at least summer 2025. The delay is attributable in part to Petrobras' efficiency program, and the eventual results will likely reflect the weaker conditions that prevailed when the tender was live. Regional drillers bidding aggressively for utilization are expected to suppress regional dayrates into the mid-to-upper $300k range. Seadrill’s 7G West Carina is also a potential drillship to be included in the Buzios tender, although has also been marketed internationally. These rates should not be read as indicative of the broader global 7G market, which is meaningfully healthier — particularly post Transocean-Valaris merger — but Brazil is a distinct dynamic where Petrobras commands a competitive, multi-operator market and effectively extracts the benefit of that competition through lower contracted dayrates.

The Buzios tender is a significant market event and likely represents a cyclical trough in deepwater dayrates given the extended award lag, considering it began when floater utilization rates were low. The field's importance extends well beyond contracting — by 2027, three FPSOs with nameplate capacity of 225k bpd each are scheduled to come online, with Petrobras recently signaling efforts to push that figure toward 270k bpd per unit. If any deepwater field can deliver that kind of productivity enhancement at scale, Buzios is it.

• High Yield Relative Value: Transocean, Azule Energy, Comstock Resources (shale), Foresea, and Borr

• Tidewater’s acquisition of Wilson Sons Ultratug Offshore

• RIG/VAL Post-Merger Capital Structure Thoughts

• Jubilee (Ghana) deepwater field update for Kosmos

Deepwater driller credits are performing well. The pain of 2H24-2025 was primarily driven by project delays and resulting rig idle time. In Midyear 2025 Outlook, cautious optimism on the drillship market existed regarding projects moving forward although it was too soon to celebrate because project slippage was still possible. Since then, the picture has improved materially, with DS-12 (Egypt), Gerry de Souza (Nigeria), Capella (Malaysia), Skyros (Australia) and others all securing contracts, and good visibility on additional multiyear awards moving forward without material delay.

Underpinning this constructive backdrop, Oil majors — particularly European players without significant US shale exposure — have remained constructive on E&P capex, with long-cycle deepwater projects largely insulated from budget cuts. While lower oil prices have prompted some capex reductions, the pullback has been concentrated in alternative energy rather than E&P, as reserve replacement has become an increasing focus after years of gradual decline.

• Transocean’s unsecured 2029s and 2031s (Caa1/B-) rallied by ~110 bps after the all-stock Valaris acquisition was announced on February 9th. Noble/NEFINA and VAL 2030s both trade inside of 200 bps and I believe better relative value opportunities exist. Within offshore drilling, Odfjell’s new secured 2031s offer 50-60 bps more of spread and have high-quality collateral rigs.

• Azule Energy (B2) is a 50/50 BP/Eni JV formed in 2022 and a first-time high yield issuer as of January 2025. The ~$3.5B EBITDA E&P produces primarily from Angola's Block 15/06, neighboring ExxonMobil and TotalEnergies' production hubs, and operates PEL 85 in Namibia where its Capricornus discovery is arguably the basin's best to date. Further, Rhino reported 'excellent reservoir deliverability' at the Volans-1 well on PEL 85, advancing the discovery toward potential development although gas levels are an early concern and discoveries still require appraisal. Azule commands a spread premium given its concentrated portfolio and new issuer status, though early execution has been strong — most notably delivering the Agogo FPSO six months ahead of schedule. More to follow on Azule in the future.

• Comstock Resources (B3/B) is a Haynesville pure-play E&P whose unsecured bonds widened 80-100 bps since its 2026 capex guide came in at ~$1.5-1.6B, well above the ~$1.1-1.3B consensus as it aggressively develops its higher-upside Western Haynesville acreage. Leveraged but well-positioned near Gulf Coast LNG export infrastructure, the spread widening may represent an attractive entry point for investors constructive on natural gas and LNG export demand.

• Foresea (B2/B+) announced a distribution to shareholders in early February to be funded by a tap of its 2030 secured notes, which saw the bonds’ credit spreads widen from ~380 bps to ~425 bps as of February 22, 2026. Foresea is a regional driller in Brazil with five 6G rigs contracted to Petrobras. Foresea holds a strong incumbent position in Brazil, though the company is rumored to have recently been marketing a 6G drillship internationally.

• While shallow-water driller Borr (B3/B) has seen its bonds rally from oversold levels in 2025, the bonds still carry meaningful spread premium over the large deepwater drillers. In December 2025, Borr acquired five jackup rigs from Noble for $360mm — three of which were uncontracted for 2026. To offset carry costs on the idle rigs, Borr structured part of the purchase with a seller's note that PIKs interest for the first 18 months — 7.5% for the first 12, stepping up to 10.5% thereafter.

Tidewater Acquires Wilson Sons Ultratug Offshore

On Sunday, Tidewater announced the $500mm acquisition of Wilson Sons Ultratug Offshore, a Brazilian OSV operator, which includes assuming $261mm of debt and the remaining funded with cash. The equity market’s initial reaction was positive given its all-cash nature and post-close leverage is expected to remain below 1.0x net debt/EBITDA.

While the deal carries no expected cost synergies, Tidewater gains more than 22 Brazilian-built OSVs and also gains option value to market its international fleet within Brazil, where local laws favor domestic service providers which it now qualifies for with Wilson Sons.

Brazil is the world’s largest deepwater services market, with near-term growth supported by the Búzios field ramp-up in 2027 although the growth trajectory beyond that remains less certain given the absence of other obvious mega-field FIDs. The most consequential exploration activity is on Brazil’s Equatorial Margin, though the high-profile Morpho well has faced delays since spudding in September 2025, underscoring the region’s execution risk.

Tidewater has long targeted Americas fleet expansion and younger average fleet age. While Wilson Sons does not reduce the fleet age, it achieves improved Brazilian market access via the acquired fleet and marketing option value for its existing fleet. A US Gulf acquisition (i.e. Hornbeck or Harvey Gulf) was effectively ruled out on the Q&A call. Grupo CBO would have been a larger bite into the Brazilian OSV market, but its large size and higher debt levels (~3.3x net leverage) would have consumed more balance sheet with the debt potentially eating into future budget for buybacks, opportunistic M&A and future capex investments. Wilson Sons achieves improved access into Brazil at a lower balance sheet cost — arguably the more attractive outcome for both credit and equity.

As noted above, acquiring younger high-spec OSVs is a challenge. With average industry fleet age around 14-15 years, a newbuild cycle is definitely not urgent today but the industry needs to begin planning for one toward decade-end as assets approach 20 years. Vessels will operate beyond that threshold, but escalating maintenance costs make a prolonged deferral risky if it results in a compressed newbuild cycle in the 2030’s. Below 1.0x net leverage today, Tidewater is well-positioned but M&A options to meaningfully reduce fleet age are limited.

RIG/VAL: What Does the Post-Merger Capital Structure Look Like?

Transocean's all-stock merger with Valaris is expected to be materially deleveraging, with close anticipated in 2H 2026 pending shareholder and regulatory approvals. A post-close refinancing of RIG's capital structure appears likely. The existing secured debt stack is a significant impediment to shareholder returns, with secured bond indentures requiring at least $322.5mm in principal amortization during 2026 (more including a shipyard loan on Atlas) and hundreds of millions locked up in restricted cash.

February 2027 could be an ideal time to refinance its secured bonds as call premiums reduce, but the big question is what will Transocean’s new debt stack look like? Will the high yield market support an all-unsecured capital structure?

As an asset-heavy company with potentially unencumbered high-spec rigs, Transocean could use the secured market to reduce its cost of capital although the ultimate attractiveness will depend heavily on the terms credit investors demand.

While I previously viewed the borrower-friendly ~$1.5T leveraged loan market as effectively closed to Transocean, the Valaris merger and technological disruption to software credits could open this as a viable financing option post-close. CLOs absorb roughly two-thirds of leveraged loan supply, but their historically poor experience with offshore drillers, structural aversion to cyclical oilfield services companies and especially Transocean's current Caa1 rating make them unlikely buyers today — CLOs face penalties once Caa-rated loans exceed 7.5% of collateral.

A post-merger upgrade from Moody’s Caa1-rating appears likely and the timing may be favorable. Software & Services represents ~11.4% of CLO collateral (Eagle Point, September 2025), and as the weakest borrowers face CCC-downgrade risk from technological disruption, CLO managers will reduce those exposures. With LBO-driven supply constrained since the Fed began hiking rates, CLOs are actively hunting for quality exposure elsewhere. While I recognize the challenges, I believe a combined RIG/VAL is stronger credit quality than many others in the LevLoan space. A B2/B rated post-merger entity could be a compelling fit given Transocean avoided bankruptcy (important for CLO’s) and is fundamentally in a stronger industry position than a decade ago.

The typical Term Loan B offers borrower-friendly terms: 7-year maturity, 1% amortization, minimal financial covenants, and only 6-month call protection versus the 2-year non-call standard in high yield. Transocean would likely face amortization above the 1% TLB floor, though well below the 7% in Odfjell's most recent secured bond, but would be an attractive source of secured financing given its looser terms.

Kosmos - Jubilee Field Update

I first covered the Jubilee Field in Ghana as an example of deepwater reservoir technology management with publicly observable results to follow. Operator Tullow faced significant production challenges from investment deferrals and related reservoir management missteps, but has since embraced 4D seismic and OBN technology alongside a targeted infill drilling program using the Noble Venturer (7G drillship). Early results are encouraging.

The first infill well (J72) came online in July 2025 producing ~10k bopd, followed by J74 which exceeded expectations, ramping to ~13k bopd. This has lifted gross Jubilee production to over 70k bopd month-to-date in February. The J75 well encountered ~40m of net pay across three zones — consistent with J72 and J74 — and is expected to begin producing by end of March

Another 4-5 wells remain in 2026 with Venturer contracted through August. Legacy well decline rates of ~20% annually will continue to weigh on overall production, but the field is demonstrating meaningful remaining productivity with two successful producers, a promising third and more wells still ahead.

• The all-stock structure is materially deleveraging, pulling shareholder returns significantly closer for RIG equity holders

• A key feature of the combination at closing is Transocean would have control of all six of the industry’s coldstacked 7G drillships. This is positive for the market structure and dayrate trajectory

• Efficiency gains via ~$200mm of cost synergies, as well as improved industry pricing discipline

• Transocean says it intends to keep Valaris’ jackup fleet, although could provide option value in the future for potential shareholder returns or deleveraging

In late September 2025, Transocean raised $421 million (net of fees) through an equity offering, using the proceeds to pay down debt after its stock price had appreciated significantly. As a natural consolidator given its scale, Transocean likely recognized that using shares as acquisition currency for M&A is far more capital-efficient than issuing equity for cash after recent share price strength. The Valaris merger achieves three objectives simultaneously: deleveraging (acquiring Valaris' underleveraged balance sheet), capturing $200 million in annual cost synergies and consolidating pricing power.

(1) Transocean is the industry’s most disciplined contract driller, earning premium dayrates through fleet quality and marketing discipline. Valaris, by contrast, often accepts weaker economics to maximize utilization—the recent DS-8 contract with Shell in Brazil at ~$375k exemplifies this, pricing a 7G drillship well below the >$400k threshold it should command even in softer markets. Valaris' post-bankruptcy capital structure enables this aggressive pricing, but consolidating their fleet under Transocean's commercial discipline should reduce competitive undercutting and support stronger dayrates industrywide, benefiting Noble and Seadrill as well.

(2) Transocean management stated on its call today: ‘We know our debt level negatively impacts our equity value.’ Offshore drillers operate like equipment lessors or financial entities—equity value depends on earning higher returns on long-lived rig assets than the cost of debt financing. Transocean owns industry-leading assets generating industry-leading dayrates, but due to its leveraged balance sheet, its creditors demand debt terms that consume most of its free cash flow, arguably making bonds more attractive than equity to various institutional investors. The proposed Valaris merger is the biggest swing Transocean can take to address this for its equity investors. By acquiring Valaris’ underleveraged balance sheet alongside 12 seventh-generation drillships and 31 jackups, Transocean’s leverage immediately reduces upon closing with net leverage gradually reducing to ~2x by year-end 2027—well below the previously communicated 3.5x threshold required to enable dividends and buybacks. This is a big step toward generating value for equity investors.

(3) Why would Valaris shareholders want RIG shares? They gain exposure to the industry’s premier fleet without expensive capital outlays. The deal delivers two 8G drillships and seven NCS-qualified semisubs—high-value segments VAL does not currently participate in. Noble just announced plans to spend ~$160mm upgrading GreatWhite for NCS access; VAL shareholders get that market exposure immediately. They also acquire RIG’s ‘7G+’ drillships, which while less differentiated versus VAL’s 7G fleet than the 8Gs or harsh-environment semisubs, still add fleet depth without diluting economics through upgrade capex such as Noble accepted in 1Q25 via contracts with Shell.

While Transocean lacks an existing shareholder return program, Valaris recent track record is underwhelming—just $75mm in buybacks during 2025, funded by an asset sale. An all-stock merger accelerates the timeline to shareholder returns for Transocean given the deal’s deleveraging nature.

(4) Odfjell Drilling trades at >$550mm per rig, the industry’s highest valuation primarily due to its positive dividend growth story. The NCS operator deleveraged from >3x Debt/EBITDA in 2022 to ~2.5x by 3Q23 through EBITDA growth and debt reduction, then initiated dividends that have grown steadily while its leverage has reduced to below 2.0x.

Transocean is tracking a similar trajectory to Odfjell, though a few years behind. RIG has deleveraged through contracted cash flows and the $421mm equity raise in 3Q25. The all-stock Valaris acquisition accelerates this path, potentially reaching ~2x net leverage by year-end 2027—a level that clearly supports shareholder returns at the combined company’s scale.

(5) The merger's most strategically interesting element may be control of three cold-stacked 7G drillships: DS-13, DS-14 and DS-11. Valaris faced criticism for premature rig reactivations years ago—rational from a cash flow optimization perspective but market-negative, as early supply additions capped dayrate recovery before utilization tightened sufficiently.

Transocean has demonstrated greater supply discipline and would control all six of the industry’s coldstacked 7G drillships. The DS-13 and DS-14 are rumored to be involved in current marketing efforts and it seemed as though Valaris was eager to reactive DS-11 which could have suppressed market dayrates. Critically, Transocean is more likely to only reactivate when dayrates justify the capital investment—Valaris has publicly stated the same but actions often speak louder than words. This consolidation benefit alleviates investor concerns about sidelined 7G capacity flooding the market prematurely, particularly after TPAO’s acquisition of previously coldstacked 7G drillships Dorado and Draco in July 2025.

(6) The industry is closer to avoiding inefficient capital upgrade cycle. Noble’s recent floater upgrades (GreatWhite, Voyager, Venturer) highlighted an industry concern of mine: Valaris pursuing similar capex upgrades to access premium markets. These upgrades divert cash flows from shareholders to equipment vendors, funded through either direct capex, reduced dayrates or operator options post-initial contract. Transocean is much less likely to invest in substantial upgrades to Valaris’ 7G drillships—they’re already capable for Africa, East Med and Brazil work. This removes upgrade risk for former VAL shareholders who faced potential capital diversion to keep up with competitors, which was a meaningful concern in a less consolidated industry.

(7) Valaris operates 31 jackups across Saudi Arabia, UK North Sea and other markets. While Transocean currently has a deepwater focus—where exploration discoveries arguably drive stronger growth trajectories (my opinion)—management emphasized on the call that it values the jackup fleet. The jackup fleet diversifies cash flows across different markets and customer bases than deepwater, and historically is less cyclical. The jackup fleet may provide eventual strategic optionality: potential asset sales could fund further deleveraging and/or share repurchases.

As a part of the acquired jackup fleet, Valaris has ~$1B in potential newbuild obligations through 2030 via its ARO JV with Saudi Aramco. However, not all may be required, and the JV has historically funded deliveries through available cash and third-party financing rather than parent equity. Completed newbuilds come with multiyear contracts in a strategically important market. The ARO JV is a concern of mine on this transaction but shallow water market in Saudi Arabia is improving in recent months.

(8) The merger is subject to global regulatory approval, but regulatory risk does not appear to be substantial per Transocean commentary today. On drillships, Transocean has a different class of premium “7G+” drillships most heavily demanded in the US Gulf, while Valaris’ 7G drillship fleet tends to have more exposure to Africa, the East Med and Brazil. Additionally, Valaris’ semisubmersible fleet generally targets different markets than Transocean’s, and Valaris’ 31 jackup rigs represent an entirely new asset class for Transocean.

(9) Could Transocean achieve investment grade ratings again? Unlikely! The rating agencies are likely to keep offshore drillers in the high-yield bucket for years, penalizing the industry’s historical volatility regardless of absolute leverage levels. Even if Transocean could reach IG by maintaining sub-1.5x leverage, shareholders won’t support the conservative capital allocation required. Instead, equity holders will demand dividends and buybacks funded by robust free cash flow—capex needs are minimal with no newbuild cycle on the horizon—making the pursuit of IG ratings both unlikely and strategically misaligned.

(10) The merger is expected to generate $200 million in cost synergies, which unfortunately means headcount reductions—though this industry has meaningful room for efficiency gains. Many institutional investors avoid offshore drilling because these companies consistently struggle to earn their true cost of capital: the industry needs ~$600k dayrates to generate adequate true returns, yet recent drillship contracts are pricing around $400k. Long-term deepwater demand fundamentals remain constructive, but this is a volatile industry. Consolidation of two large players like Transocean and Valaris is a key step in the right direction of improving capital returns from the value they provide to E&P clients and eventually enabling consistent shareholder returns to the combined entity.

Odfjell and Noble: Noble announced entry into the Norwegian semisub market with a 3-year AkerBP contract for the GreatWhite at an estimated ~$430k dayrate. The rig will require at least ~$160mm of upgrades to meet Norwegian standards, reflecting its unique position as a Moss CS60 design that is technically similar to Norway-eligible semisubs but was not originally built for NCS operations and thus requiring meaning capex spend. While expensive, Noble is buying much stronger utilization visibility on GreatWhite with this unique transaction. As detailed in Outlook 2025: Semisubs, being eligible to work in Norway is important for harsh environment rigs.

Noble’s Ocean GreatWhite is currently stacked in Norway with limited near-term opportunities amid lower oil prices and continued weakness in the UK North Sea due to unfavorable tax policy. While Norway is a high-cost operating market, E&P capex remains resilient with a positive outlook through 2030. Noble’s entry adds a single rig to this high-barrier market—modestly negative for Odfjell—but Odfjell’s premium semisubs remain top-tier, as reflected by $460–470k dayrates secured for Aberdeen and Nordkapp in December 2025.

I view Noble’s upgrade decision as defensible given my constructive outlook on Norwegian E&P capex, though risks remain that upgrade costs exceed $160mm and that future five-year special surveys prove costly. Separately, I believe Noble should prioritize increasing shareholder returns from 2027 onward and limit further costly rig upgrades, which it has increasingly pursued over the past three quarters.

GreatWhite’s entry into Norway does not immediately impact Odfjell’s fully contracted fleet, with 100% utilization through 1Q27 and rising realized dayrates. Odfjell’s semisubs remain highly marketable and the dividend growth story intact. However, incremental supply into the Norwegian market—including GreatWhite and potentially others—modestly lowers long-term terminal value via dividend growth assumption adjustments related to long-term dayrate upside.

Credit Relative Value: Noble’s 8.0% unsecured 2030s trade around 104 at ~200 bps spreads, reflecting strong backlog momentum but Noble’s cash flow statement will have material uses of cash in 2026 with capex for rig upgrades and likely (non-recurring) working capital draws for contract startups on various rigs. Positively, also had its four 7G drillships in Guyana extended through February 2029 by Exxon, which is great, although I do not expect credit investors to view Noble’s 2026 cash flow statement favorably. Additionally, the multiyear contracts with Shell (U.S. Gulf) and TotalEnergies (Suriname) include meaningful incentive structures that introduce risk to future EBITDA levels if not achieved. Shell is reportedly funding the Voyager and Venturer upgrades, though Noble is receiving lower fixed compensation due to incentive-heavy contract structure.

By contrast, Odfjell’s 7.25% secured 2031s trade near 102 at ~270 bps—roughly 50–70 bps wider—with exposure concentrated in Norway, a low-risk jurisdiction supported by investment-grade counterparties (Equinor, AkerBP). While I view Noble’s credit favorably, its bonds trade at tight levels for unsecured offshore drilling risk near ~200 bps of spread. For investors willing to sacrifice some liquidity, I believe Odfjell’s secured 2031s offer more attractive relative value at current levels with additional 50-70 bps.

On Wednesday, Noble and Borr closed the previously announced $360mm sale of five modern jackups, with Noble receiving $210mm in cash and $150mm in a 6-year seller’s note that PIKs the first three semiannual payments. While the transaction aligns with Noble’s strategy to focus on deepwater assets, the seller’s note is a modest credit negative. The note features a step-up coupon—7.5% (PIK) initially, rising to 10.5% after year one and up to 15% in the final year—designed to incentivize Borr to refinance the seller note. The collateral rigs are modern, marketable JU-3000N units but were uncontracted for 2026, explaining the PIK structure. The note is likely refinanced ahead of Borr’s November 2028 secured maturity, effectively making Noble a bridge creditor to a high-yield borrower rather than receive full cash proceeds, which appears to be delayed until 2027 at earliest.

Borr: Jackup drillers saw the sharpest sell-off in high-yield credit during the 2Q25 “Liberation Day” risk-asset drawdown, driven primarily unfavorable supply conditions tied to Saudi Aramco’s prior rig suspensions discussed here. Those suspensions increased warm jackup supply by more than 10% in a short period, pressuring jackup utilization and dayrates. While Aramco has begun gradually adding rigs back, the initial reduction exceeded 40 units and recent tenders have been comparatively limited in scale, leaving the market well short of 2023 tightness. That said, the deterioration has stabilized and utilization rates are improving. While I prefer deepwater floaters given stronger long-term demand growth, jackups typically offer more cyclical stability.

Borr’s secured 2028s (10.0%) and 2030s (10.375%) trade around 102.5, offering attractive mid-400s to low-500s spreads. Notably, Borr’s bonds are callable at ~102.5 on November 15, 2026. These bonds trade more than 100 bps wider than Transocean’s 2029 and 2031 unsecureds—credits I also like—highlighting compelling relative value in Borr’s secured paper. The wider spread reflect Borr’s weaker 2026 contract coverage, driven in part by jackups’ shorter-cycle contracting versus the longer lead times typical of deepwater projects. Borr faces weaker counterparty credit quality than Transocean, pressuring cash collections, but improved contracting—helped by Aramco gradually adding back rigs—should support a refinancing of these bonds.

Murphy Oil: This mid-sized E&P is Ba2/BB+ and typically trades tight, supported by a conservative financial policy and a diversified reserve base. Murphy’s boe production in 2025 was 40% Canada Onshore (Montney), 39% Offshore (mostly U.S. Gulf) and 21% US Onshore (Eagle Ford). While the lack of scale across its global reserve base draws criticism from some equity investors, that diversification is a credit positive for high yield investors. Murphy’s Tupper Montney assets are short-cycle gas reserves in a high-quality basin and would likely attract strong buyer interest if ever monetized, supporting credit quality in a downside deleveraging scenario as a source of cash.

Announcing its 4Q25 earnings Thursday, Murphy’s production guidance for 2026 of 167-175k boepd was below 182k boepd achieved in 2025. U.S. Gulf E&Ps typically factor hurricane-related downtime into guidance; 2026 reflects this assumption, while 2025 results were unaffected due to the absence of hurricane disruptions. Lower 2026 production guidance also reflects timing impacts, as the high-impact Chinook #8 well in the U.S. Gulf is expected to come online in the second half of 2026 (~15k boepd), pushing those lumpy volumes toward end of the 2026.

Murphy has had high profile exploration and appraisal outcomes recently in Vietnam and Côte d’Ivoire. In early January, Murphy reported appraisal success at the Hai Su Vang-2 well (shallow water), encountering 429 feet of net oil pay across two reservoirs and lifting recoverable resource estimates to the high end of—and potentially above—the previously stated 170–430 MMBOE range. Murphy has two more appraisal wells left in Vietnam. Murphy is targeting FID by year-end 2027, with first oil potentially in 2031. The project could be comparable in scale to Murphy’s Eagle Ford production, with upside pending further appraisal drilling.

In Côte d’Ivoire, Murphy’s first of three deepwater wells, Civette, encountered oil pay across multiple reservoirs but not at commercial quantities. The remaining Caracal (CI-102) and Bubale (CI-709) wells—to be drilled by Transocean’s Deepwater Skyros—are independent prospects with no read-through from Civette, though Civette had the highest gross resource potential. While greenfield deepwater projects can concern credit investors given the upfront capex, discoveries function as option value for Murphy, providing potential strategic flexibility by using them as a currency. Eni, which is active in Côte d’Ivoire, would be a logical potential farm-in partner for any development of Murphy’s assets in the country but Civette results likely reduce that probability.

Murphy had two near-infrastructure discoveries in the U.S. Gulf in late 2025 in addition to visible project runway through 2029. Relevant to the 2030s, a key outcome of Lease Sale 262 was Murphy’s winning bids in the prospective Alaminos Canyon, a new area for the E&P. With Shell’s Perdido and Whale developments nearby and Woodside’s Trion project set to begin drilling in April 2026, Murphy’s entry into the ultra-deepwater Perdido Belt is an emerging area to watch as a potential future hub.

Kosmos Energy’s bonds trade at distressed levels, though the issues are small and illiquid. Its unsecured 2028s and 2031s trade at spreads above 1,500 bps, largely reflecting production challenges at the Jubilee field in Ghana in addition to weak crude oil and LNG prices.

While Tullow operates Jubilee, Kosmos holds a 38.6% interest and reported 4Q25 gross production of 59 kbpd, with output expected to start 2026 near 70 kbpd following the J-74P well coming online, though actual rates remain unconfirmed. Legacy Jubilee wells are declining at ~20% annually, implying 1Q26 production of ~65–66 kbpd absent new wells. Tullow/Kosmos have contracted the 7G drillship Noble Venturer through August 2026 to drill four additional production wells and one injector.

While expensive capital, Kosmos recently successfully raised $350mm of secured debt using its 27% interest in the Greater Tortue Ahmeyim LNG project (BP operator) to address its 2027 maturities. While I had my doubts whether they could raise debt against these assets given the geopolitical risk, GTA is now operating at capacity after coming online in 1Q25 and they recently raised a $350mm Nordic secured bond due 2031 at an 11.25% coupon, paired with a tender for $250mm of the May 2027 notes. Separately in 2H25, KOS raised $250mm in a Shell-backed secured loan against its US Gulf assets to fund ‘26 maturities. These financings extended Kosmos’ liquidity runway, allowing time for improved market conditions and better asset performance at Jubilee.

Noble’s recent $1.3B backlog update included a 50-day U.S. Gulf workover well for Beacon using the BlackRhino drillship. Given Kosmos’ disclosure in 3Q25 that the Winterfell-4 well was abandoned due to casing collapse—and that Beacon operates Winterfell with Kosmos holding a 25% non-operated interest—the award likely relates to a Winterfell workover. If confirmed, this would be a modest positive for Kosmos following the negative 3Q25 update. The workover well is schedule to commence in March 2026.

Kosmos is expected to report 4Q25 earnings in late February, providing a clearer update on the new J-74P well at Jubilee and broader production trends. While the company has made progress addressing key investor concerns around Jubilee, GTA, and near-term maturities, it remains highly exposed to oil and LNG prices. Free cash flow in 4Q25 has potential to be negative, but with Brent now near $70/bbl, both equity and debt are increasingly leveraged to recently improving commodity prices.

Tidewater: The 9.125% 2030 notes currently trade around 107–108. Debt-financed M&A risk is elevated as Tidewater has publicly expressed interest in acquiring a competitor, potentially with existing debt, though any transaction is unlikely to materially strain the balance sheet given its capacity for incremental leverage. I recommend subscribing to Misadventures in Shipping if you’re following Tidewater—the sector is opaque and specialized, and Ed covers it well.

Noble announced several contracts Monday, with the standout being a new three-year Aker BP contract in Norway at ~$430k/day for the GreatWhite semisub, requiring ~$160mm of capex as a “strategic entry into the Norwegian floater market.”

Noble’s ~$160mm capex to upgrade GreatWhite for NCS compliance is a near-term cash outflow that may disappoint shareholders, but it’s a defensible strategic decision. GreatWhite is currently idle, with a weaker UK North Sea outlook due to politics and competition in other markets. By upgrading for Norway, Noble is effectively buying utilization, as the NCS offers longer-term contracts, unlike the choppier outlook GreatWhite would face elsewhere over the next five years.

GreatWhite is a Moss CS60 design semisub, the same design as a few other semisubs operating on the NCS. However, it has not met Norway’s stricter regulatory standards and has instead been most recently working in the UK North Sea. Achieving NCS compliance is expensive but unlocks access to a more resilient Norwegian E&P capex environment and a structurally tighter floater market, positioning the rig for high utilization and sustaining dayrates above $400k, which supports a materially higher long-term asset valuation.

Semisub Arbitrage: While GreatWhite faces downtime risk through 2027 with only sporadic work thereafter, Noble likely took note of Odfjell Drilling’s $480mm acquisition of the Deepsea Bollsta (the same Moss CS60 design) in December 2025. Odfjell’s pure-play NCS semisubs are also valued at roughly $550–575mm per rig on the Oslo exchange as of January 26, 2026. With GreatWhite currently idle and at risk of prolonged cold-stacking without Norway access, the ~$160mm upgrade appears value-accretive relative to the rig’s depressed standalone valuation. An upgraded GreatWhite will not command an Odfjell-like valuation, but after the upgrade its sits in a strong market as a credible mid-tier NCS-eligible semisub though will depend on its future performance.

The question will be if Noble can truly upgrade GreatWhite for only $160mm. While numbers are often thrown around loosely, I previously heard about $200mm as the rumored cost for a GreatWhite upgrade. I initially questioned Noble allocating that much capex to GreatWhite instead of buybacks, but Odfjell Drilling’s equity performance serves as a clear proxy for the NCS semisub market, where strong fundamentals have driven meaningful share-price appreciation (>250% over last 3 years) and unquestionably played a role in Noble’s upgrade decision.

The $160mm upgrade cost may prove optimistic. Norway is costly to operate in, and Noble will now likely face elevated SPS spend. Odfjell recently completed its five-year SPS at ~$50mm per rig with strong execution; given GreatWhite’s lack of prior Norway operations and an upgrade cost below rumored ~$200mm, future SPS costs could be higher and will require careful management. Strong NCS utilization should support future capex funding, though execution will be important to monitor.

A year ago, a modest weakness in Noble’s fleet was its heavy exposure to 7G drillships, non-Norway-eligible semisubs and jackups. Since then, Noble has upgraded two 7G rigs to “7G+” under incentive-heavy Shell contracts and has now entered the attractive Norway semisub market using a unique opportunity with GreatWhite. While these moves improve fleet quality and diversification, equity investors are unlikely to reward ongoing upgrade cycles without incremental shareholder returns beyond the current dividend.

Norway Semisub Market Impact

Noble’s entry into Norway is modestly negative for incumbents like Odfjell and Transocean, though the impact is limited given it’s only one rig. NCS utilization remains very strong, supporting dividends at Odfjell and cash flows for Transocean bondholders, even as non-Norway markets face weaker utilization into 2026. Norway E&P capex has been resilient, as evidenced by dayrates down only mid-single digits despite oil price weakness.

While recent semisub exits tightened the NCS semisub market, GreatWhite signals some supply returning after Bollsta’s (now named Bergen) return in 2025. One rig alone is unlikely to disrupt fundamentals but does limit dayrate upside. Additional supply is possible—Transocean has three semisubs internationally, Northern Ocean has Mira, and stranded NCS-spec newbuild supply exists—though reactivation and mobilization would be costly. Overall, the NCS semisub market remains healthy and cash-generative, but sustained dayrates above $500k appear constrained. Comparatively, drillships arguably have more dayrate upside potential but with a wider variance of market outcomes.

Capex Funding and Other Contract Wins

In early December, Noble sold six jackups for $360mm, receiving $210mm in cash and a $150mm six-year seller’s note to Borr. Notably, the $210mm cash proceeds closely align with Noble’s planned upgrade and contract-prep spending—$160mm for GreatWhite and roughly $50mm across other rigs. While the seller’s note to a high-yield issuer is less appealing, the transaction sharpens Noble’s focus on deepwater and appears to fund these upgrades, including a potential MPD upgrade for the 6G drillship Gerry de Souza.

Gerry de Souza (6G Drillship): Noble secured a two-year Exxon contract in Nigeria at a $400k headline dayrate (including MPD), with up to three years of options, starting mid-2026. After West Africa delays weighed on the drillship market in 2025, this multiyear award is a positive signal—not just for Noble, but for overall drillship demand in a region that has driven recent idle time.

Guyana: Noble operates four 7G drillships in Guyana supporting Exxon’s Stabroek Block and recently secured a two-year extension through February 2029 for the Sam Croft, Don Taylor, Tom Madden, and Bob Douglas. The contracts use a variable dayrate structure that resets semiannually rather than fixed disclosed rates.

Noble Endeavor (Semisub): This older semisub (built 1975, upgraded 2009) had been operating in the UK and was viewed as a potential retirement candidate, but instead secured an ~11-well contract on the Falklands’ Sea Lion project at roughly $300k/day. It’s a solid multi-year win for Noble, though the market had hoped the rig might retire. That said, Sea Lion represents incremental demand, limiting the impact on the global rig market.

Noble Developer (Semisub): Secured a 240-day BP contract in Trinidad at $375k/day starting 1Q27. While previously slated for TotalEnergies’ Suriname work, that program will now be handled by the very similar semisub Noble Discoverer, commencing in 2H26.

Despite persistent concerns about oil price weakness, the deepwater drilling market has defied pessimistic forecasts throughout 2025. The long-cycle nature of deepwater contracting provides nearly a year of visibility, aligning with equity markets’ 12-month forward focus. Drilling equities weakened from September 2024 amid rising idle time, pressuring earnings as outlined in the Drillship 2026 Outlook. Despite weak oil markets, equities recovered from 4Q24–2Q25 lows as 7G drillship utilization stabilized, supported by a rebound in West Africa. While near-term Petrobras tender awards are unlikely to show dayrate improvements as some drillers prioritize utilization, markets are forward-looking, with utilization expected to recover in 2H26 and into 2027—suggesting low-to-mid-80% utilization represents the mid-cycle trough and should support future dayrates.

Pareto Securities, a well-regarded Nordic investment bank, released a client survey in early May 2025 polling “Dayrate expectations on upcoming 7G/leading-edge contracts,” with responses as follows; $200k (7%), $250k (53%), $350k (40%) and $400k (0%).

The negative sentiment was apparently driven by extrapolating the prior cycle (2015-2016) downturn when dayrates fell from the $600k range to the $200k’s. The major difference in the current cycle vs the last cycle is the market had to absorb a newbuild cycle that overestimated drillship demand when orders were made – oil was $100/bbl in 2011-2013. When OPEC increased production in late 2014, oil prices fell to the $40’s and newbuild deliveries overwhelmed the market for years. Further, E&Ps began to favor short-cycle, flexible capex as the Permian Basin was about to add >3 million bpd of production as a lower cost source of oil production. This was a very unfavorable supply-demand imbalance that caused substantial downward pressure on dayrates. Unlike the prior cycle, today’s market is not burdened by a large speculative newbuild overhang, materially improving supply discipline.

The drillship market in 2025 was not strong but exhibited far better fundamentals and therefore dayrates did not come close to matching Pareto’s survey whereby their 60% of their clients expected dayrates between $200k-$250k. Since then, 7G drillship dayrates have ranged from $350k to $450k with a weighted average (by term) of ~$401k. Importantly, drillers have mostly maintained price discipline in 2025.

Pareto’s survey reflected excessive pessimism — a hurdle that has now been cleared. Since then, sentiment has improved although the global oil price markets remain fairly weak given concerns about supply in 2026. While all future contracts will reflect regional, project and rig specifics, dayrates are likely to stabilize in the current range waiting for utilization rates to firmly improve.

While 7G drillship dayrates have clearly declined from their most recent peak (as of announcement date) in the $480k-$490k range in mid-2024, they appear to have largely bottomed around the $400k level (average). Note that in deepwater floaters, a meaningful lag exists from negotiation to contract announcement that can span two to three quarters. While near-term Petrobras awards are unlikely to show pricing improvement as drillers prioritize utilization, equity markets remain forward-looking, with utilization expected to recover into 2H26 and 2027

Drillers expect utilization to improve, but meaningful dayrate upside requires firmer utilization and oil price stability to restore negotiating leverage. A return toward ~$500k/day is unlikely in 2026, though a plausible path exists for 7G drillships in 2027, contingent on multiple variables.

(1) Transocean 7G+ Drillship Contracting

Transocean’s 7G+ drillships Asgard, Conqueror and Proteus are key follows for early 2026, as their current contracts are scheduled to roll off. The primary distinction between 7G+ and standard 7G drillships is higher hookload capacity—1,400 short tons versus ~1,250—which enables greater drilling efficiency. Chevron currently operates Asgard and Conqueror and has only one deepwater rig contracted in the U.S. Gulf beyond 4Q26. Given Chevron’s public commentary on Permian maturation and its stated plans to drill 10–15 exploration wells in the Gulf of America, the IOC is likely to maintain its regional rig count, implying potential demand for additional drillships beyond 2026.

A key open question is whether Chevron prioritizes 7G+ capability or lower-cost contracting. Chevron has historically favored the highest-specification rigs in the U.S. Gulf, including the 8G Deepwater Titan at Anchor, which achieved first oil in 2025. The decision will likely hinge on whether Chevron extends its existing 7G+ units (Asgard and Conqueror) or adds standard 7G drillships at lower dayrates.

In April 2025, Noble signed two four-year contracts with Shell for Voyager and Venturer, including equipment upgrades that effectively reclassify both rigs as 7G+. Shell, historically the primary operator of Transocean’s 7G+ fleet since the mid-2010s, now appears to be shifting away from two Transocean units in favor of the upgraded Noble rigs. Shell is funding the upgrades and, in return, secured performance-linked contracts with approximately 20% of contract value contingent on meeting operational metrics. A key 2026 watch item is whether additional standard 7G drillships (e.g., Seadrill or Valaris units) are upgraded to 7G+.

(2) Standardize and Simplify: Deepwater's Cost Revolution

Capital efficiency in deepwater E&P has improved materially over the last decade. Unlike the prior cycle, when projects often underwent multiple, bespoke engineering phases, today’s developments emphasize simplified, repeatable designs that reduce engineering costs and shorten time to first oil, improving time-value-of-money on multi-billion-dollar investments. Industry focus on “standardize and simplify” is well illustrated by Shell’s Vito project, where costs were reduced by ~70% from the original design and over 80% of that design was replicated for the subsequent Whale development in the U.S. Gulf. Once floating production infrastructure is installed, incremental infill drilling further benefits from lower-cost brownfield capex.

(3) Seadrill remains the most likely consolidation target

In 4Q24, the upcoming year of 2025 was viewed to be weak with the first half of 2026 also expected to be soft. The market appears to have avoided persistent multiyear project delays thanks to progress in West Africa. Generally, soft market conditions create opportunities for consolidation where room exists for meaningful efficiency gains. While the deepwater drilling market has already successfully closed on consolidation, most IOCs continue to exhibit capital discipline where they are very cautious with capex spend (ie demand for offshore drilling rigs). While the expectation is for 7G drillship utilization rates to improve into 2026-2027, the negative carry costs while idle costs burden shareholder returns for drillers — effectively subsidizing capex flexibility and option value for their E&P customers. While this is typical for oilfield service companies, idle time on rigs contribute to pricing pressure on dayrates.

News sources, including Bloomberg, have noted Seadrill as a rumored candidate for consolidation. Seadrill has an active share repurchase plan but is not generating enough internally generated cash flows to use it without spending down its cash — prior repurchases were funded by the sale of three jackup rigs in 2024. As shown in Seadrill's 3Q25 cash flow statement, the driller has struggled to generate recurring cash flow for shareholder returns.

Seadrill’s cash flow has been hurt by legacy 7G contracts signed in 2021 that are only now rolling to higher dayrates, alongside recent start-up costs as rigs transition to new work. As noted in the cash flow statement, its operating cash flow generation remains insufficient to cover capex, notably including ~$76mm of SG&A incurred through the first nine months of 2025 (~$14mm of this was paid in shares), limiting Seadrill’s ability to self-fund shareholder returns without balance sheet deterioration. Noble realized ~$100mm of synergies from its Diamond acquisition, suggesting similar upside could exist in a Seadrill takeout by a larger player such as Transocean, Noble or Valaris. For Transocean, Seadrill’s low-leverage balance sheet would be deleveraging in a share-based deal and could accelerate a path toward recurring shareholder returns.

Complicating potential M&A, Seadrill has outstanding lawsuits. One with Eldorado Drilling and another with SFL where an appeal process is expected to commence in April 2026. Additionally, Seadrill is rumored to want to have a contract on its currently idle West Capella drillship to receive appropriate value for the asset. Capella is believed to be close to being awarded a contract in Malaysia with PTTEP with an announcement expected in coming weeks.

If Seadrill remains independent, the offshore drilling market still offers roll-up potential among sub-scale contractors with 1–3 rigs, which could benefit overall market structure. These smaller players are more vulnerable to idle time and thus more likely to bid aggressively for utilization, while larger drillers such as Transocean, Valaris, and Noble can better absorb idle periods due to broader, diversified fleets.

(4) “Scrap, Baby, Scrap”?

In 2025, Transocean, Valaris, and Noble collectively scrapped or retired at least 14 floating rigs. Notable retirements included Transocean’s Henry Goodrich, GSF Development Driller I, and several Discoverer-class units; Valaris’ DPS-3, DPS-5, and DPS-6; and Noble’s Pacific Scirocco, Pacific Meltem, and Globetrotter II.

While 14 retirements represent roughly ~10% of the global floater fleet (depending on definition), the market impact was limited. The majority of these rigs were cold-stacked, lower-specification units with minimal realistic prospects for reactivation. In practice, only three retirements were commercially relevant: Valaris’ DPS-5 and Noble’s Globetrotter II, both of which had drilled relatively recently, and Pacific Meltem, which—despite being cold-stacked—was a 7G drillship and therefore notable from a future capacity perspective.

Overall, while the headline number of retirements appears constructive, most removed capacity was low probability of re-entering the market, limiting the immediate tightening effect.

(5) Norway’s Offshore Strength Expected to Continue into 2026

The best offshore rig market of 2025 was the Norwegian Continental Shelf (“NCS”), as evidenced by Odfjell Drilling’s >60% equity return in 2025 despite Brent crude oil prices declining by $13/bbl in the year. The NCS is a supply-constrained market where eligible rigs must meet strict technical standards. Additionally, E&P capex in Norway is predominantly infrastructure-led, which is lower cost as it leverages existing infrastructure which supports the market’s resiliency.

The NCS is a mature oil and gas province, producing approximately 1.9 million bpd as of November 2025. NCS-eligible semisubmersibles operate under stringent regulatory standards—supporting higher costs—but benefit from a stable operating environment, extensive existing infrastructure, and predominantly brownfield development. E&P investment is further supported by Norway’s favorable tax regime, which incentivizes drilling and underpins long-term hydrocarbon supply to Europe.

(6) Greenfield Deepwater FID’s

Namibia: Following ExxonMobil’s success in Guyana, major discoveries by TotalEnergies and Shell in 2022 raised expectations that Namibia could follow a similar trajectory. However, Namibia is unlikely to replicate Guyana’s outcome—where capacity is expected to exceed 1.4 MMbpd by 2029—given higher development costs and later timing; reaching even half of Guyana’s production would be a favorable outcome.

A key 2025 development was Galp’s marketing of its Mopane discovery and the selection of TotalEnergies as a farm-in partner. Total acquired a 40% stake in Mopane, contributed a 10% interest in Venus, and agreed to carry 50% of Galp’s initial Mopane development costs. While the deal modestly tempers long-term deepwater floater upside—given disclosures that Mopane trails Venus by ~2–3 years—TotalEnergies appears closer to FID on Venus, discovered in 2022 versus Mopane in 2024.

Venus faces challenges, including low permeability, ~3,000 m water depth, and associated gas, while Mopane benefits from better reservoir quality and shallower water depth, partially offset by the cost impact of the carry structure. Venus FID remains pending and will hinge on fiscal stability and royalty certainty.

Greater clarity on Mopane is expected following appraisal drilling likely in 2026, likely beginning with appraising the Mopane-3 discovery in 2025 in a more oil-prone area of the field. Separately, Rhino Resources and Azule Energy have made three discoveries in PEL 85—including Capricornus-1X, one of the basin’s strongest exploration results to date—and, with appraisal likely in 2026, could deliver first oil ahead of Mopane, supported by their rapid execution track record at Angola’s Agogo project.

Indonesia: While Namibia draws headlines, arguably the strongest deepwater project is Eni–Petronas’ Kutei Basin gas development, anchored by Geng North and related discoveries. Backed by existing infrastructure and a self-funding JV, the project is expected to reach FID in 2026 with up to two multi-year drilling contracts—potentially including the 7G Deep Value Driller. With an existing LNG plant and short shipping distances to Asian markets, Kutei is a rich-gas project likely to reach market faster and with better economics than Namibia.

Mozambique: After the security situation has stabilized in key deepwater LNG projects, TotalEnergies and its partners lifted force majeure on Mozambique LNG in October 2025; while the region remains sensitive, Exxon and TotalEnergies appear to be progressing projects following Eni’s FID on Coral North FLNG.

This article reviews my thoughts on contracting opportunities and risks for Proteus (7G+), Mykonos (6G), Skyros (7G) , KG2 (6G) and Equinox (NCS HE Semi).

As discuss in Transocean’s Capital Structure, RIG has room to gain value for its equity via improving its restrictive debt terms, and securing multi-year contracts for rigs coming open next year could strengthen its position to refinance on better pricing and terms when it eventually hits debt capital markets. Transocean’s 7G+ drillship fleet remains highly marketable and could secure multi-year contracts at healthy dayrates—a continuation of a few 10-year fixtures that helped the company avoid bankruptcy during the 2015–2021 downturn.

In recent months, 7G drillships have had multiyear contracts announced in the high $300k-to-low $400k range (depending on various adjustments). We have yet to see Transocean announce a 7G+ dayrate in 2025 — is this a sign of prudent price discipline or misjudging the market?

Transocean’s fleet includes eight 7G+ drillships with enhanced 1,400-ton hookload capacity, offering improved deepwater efficiency over standard 7G units (1,250-ton hookload). These rigs led the >$500k/day rate surge in 2024, typically earning a modest premium over standard 7G units. Transocean hasn’t announced any new 7G+ drillship contracts in the past year, leaving price discovery pending, with Proteus (May 2026), Asgard (June 2026), and Conqueror (Sept 2026) set to roll off within the next year.

In April 2025, Noble signed four-year Shell contracts in the U.S. Gulf for the Voyager (2Q26) and Venturer (4Q27), including hookload upgrades to 1,400 tons, elevating both to 7G+ status. As of November 2025, Shell utilizes four 7G+ drillships from Transocean, but Noble’s new deals could displace Proteus (May 2026) and/or Pontus (Oct 2027). To offset risks from newly upgraded rigs, Shell offered incentive-heavy terms that Transocean is unlikely to match. Notably, other IOC’s likely have meaningful appetites for high spec drillships in the US Gulf.

7G+ Drillships (Proteus, Asgard and Conqueror): Transocean has the industry leading fleet and they are likely to contract Proteus, Asgard and Conqueror at healthy rates on multiyear term, but they run the risk of overplaying their hand in a softer services market. As seen via Noble, there’s not a high barrier-to-entry in the 7G+ drillship upgrades, with Valaris or Seadrill having potential to do the same.

The first half of 2026 will be key for Transocean as it seeks to refinance and ease its restrictive debt terms through new capital market deals. Securing multi-year 7G+ contracts in the U.S. Gulf could reassure lenders and improve financing terms. While Transocean retains pricing power with its fleet, softer oil prices are making IOCs more selective; thus, locking in long-term utilization may add more value via debt capital market execution than chasing marginal dayrate gains.

Deepwater Mykonos’ contract with Petrobras is scheduled to conclude in Jan 2026 with a priced option through April 2026. Petrobras currently has at least two tenders outstanding, one for Buzios (likely 3 or 4 rigs) and another for Mero (~1 rig). Mykonos has been working the Mero field in the Santos Basin (~500k bpd production) for at least the last year and a half. While a 6G drillship, Mykonos is MPD-ready and a strong candidate for Petrobras to extend.

Dhirubhai Deepwater KG2 (6G): KG2 has operated in Petrobras’ Campos and Santos basin rig “pool,” moving between fields as needed. While Petrobras’ Búzios tender (3–4 rigs) is nearing award, other rigs appear to be better positioned contenders. Additional opportunities exist in Brazil—Shell’s Orca/Gato do Mato and Equinor’s Bacalhau—though these IOCs typically favor higher-spec units than KG2. KG2’s outlook is uncertain but prolonged idle time seems unlikely. It will likely find work in Brazil, though perhaps with some idle time and rates well below its current $446k/day.

Deepwater Skyros (7G): After finishing TotalEnergies’ Angola campaign, Skyros will move to Côte d’Ivoire for Murphy’s three-well program through March 2026 (priced option for April 2026), after which it faces idle-time risk. With only one BOP, its marketability is limited compared to other 7G’s, although it could return to Angola or other African work at competitive rates.

Shell recently signed an Angola exploration agreement (Reuters)—a logical fit for Skyros given its local experience—though start-up is rumored for 2027. Remaining in Côte d’Ivoire is a possibility but would include idle time as multiyear work for Eni likely won’t begin until early 2027, suggesting Skyros may need to seek interim work elsewhere.

Transocean Equinox: This midwater semisub acquired via the Songa acquisition in 2018 was moved across the globe from Norway all the way to southern Australia. Equinox is firm at $540k through December 2026 and has multiple priced options at $540k dayrates through August 2027, options that may depend on the success of the current Otway Basin exploration campaign.

Summary: Transocean is likely to find multiyear work on its 7G+ drillships (Proteus first availability) and I believe Mykonos is a strong candidate for a likely multiyear extension with Petrobras. Skyros and KG2 have idle time risk and Transocean would likely be wise to bid these two for utilization rather than chasing dayrate, as these rigs face competition for work in a period when IOC and NOC’s are budget-conscious. Transocean has value to gain via execution in the debt markets by showing strong utilization with its lower spec assets. Its unlikely both Skyros and KG2 face extended periods of idle time, but both appear likely to face some idle time which can be a normal occurrence in deepwater contract drilling.

Kosmos: The Jubilee field in Ghana is a source of rig demand that I follow. It has had real challenges with production that I believe are correctable although that is to be determined by the current infill drilling program I previewed here — Tullow & Kosmos: Jubilee’s Mid-Life Crisis. Following Kosmos’ 3Q25 earnings, an update is below:

Along with operator Tullow, Kosmos plans five new infill wells, up from the four previously expected—a modest positive. Following 4D seismic analysis, Tullow/Kosmos have identified targets, each expected to produce 5–10 kbpd. However, with Jubilee’s ~20% annual decline, new wells will offset but not reverse falling output

Jubilee’s gross output rose from 55,300 bpd in 2Q25 to 62,500 bpd in 3Q25. Accounting for decline and the planned five new infill wells, Kosmos could lift production to ~80,000 bpd gross if results are modestly successful. However, Kosmos’ 3Q25 earnings were a reminder that deepwater oil production can be challenging, as it communicated its Winterfell-4 well in the Gulf of America was abandoned due to completion challenges “arising from the collapse of the production casing” — a disappointment after investors anticipated this well to begin producing in 3Q. Noble’s Ocean BlackRhino was the drillship operating this well.

The news on Jubilee was generally OK, although the example of Winterfell is a reminder to never count your chickens before they hatch. The market will be closely following the Jubilee infill drilling campaign now underway.

Kosmos secured a $250 mm loan from Shell (interesting), backed by its U.S. Gulf assets, to address 2026 bond maturities. The company may also raise secured debt against its GTA assets for 2027 maturities, although remains to be seen. Ideally, strong Jubilee performance and Brent in the $70s would support refinancing its 2027–2028 debt.

The question on Jubilee (Ghana) is if the field is structurally challenged, or if recent challenges reflect a “mid-life crisis” that can be corrected via better reservoir management aided by fresh, new 4D and OBN seismic shoots. I tend to believe the latter and better Jubilee production will support refinancing 2027-2028 maturities, although operational risk exists on executing on the drilling program. Kosmos’ E&P assets are mid-tier, to put it politely, although I believe Jubilee’s production problems can be adequately addressed with the current infill drilling campaign.

(1) Secured High Yield Bonds: Transocean’s secured bonds are inefficiently offered to investors: single-asset bonds (Poseidon, Titan and Aquila) amplify idiosyncratic risk and represent over half of RIG’s secured debt. Rolling them into a diversified, multi-rig secured bond would reduce concentration risk and likely ease amortization demands.

Current trading levels demonstrate investor preference for the diversified Secured 2030s (five collateral rigs) over the single-asset Titan and Aquila bonds. While bond pricing can be choppy, the current market preference is rational and suggests Transocean could win better pricing and terms by consolidating single-asset bonds into a diversified pool.

While info on the $269mm Atlas shipyard loan is limited, the Poseidon, Titan and Aquila secured bonds are now callable. Rolling them into a single, 2030s-style multi-rig secured bond (Pontus/Proteus/Thalassa/Enabler/Encourage) could ease the structure via lighter amortization and reduced debt service reserve/restricted cash.

The collateral rigs are all high specification rigs that competitors do not currently have. At least five rigs securing Transocean’s debt rank comfortably in my global top-10. BP recently exercised a $635k/day option on the 8G Deepwater Atlas (my #2) for 2029–2030, and the 8G Deepwater Titan (my #1) is on Chevron with April 2028 availability. Given scarce 8G supply and leading specs, Titan’s follow-on will command a strong rate.

While secured debt investors with offshore drilling rig collateral may require amortization structures to support Loan-to-Value (LTV) ratios that protect their recoveries, Transocean could also potentially ease this cash flow burden via overcollateralization. In June 2024, Transocean acquired the remaining 67% of the Norge semisubmersible rig it did not already own in a transaction with Hayfin. Transocean conservatively exchanged shares as consideration for the purchase, instead of paying cash. If necessary, adding unencumbered Norge to a multi-rig secured bond would diversify the collateral pool and lower LTV as mitigating factor to support reduced amortization.

Norge is a high-spec, harsh-environment semisub certified for Norway, a designation that typically commands a valuation premium. It also diversifies Transocean’s asset mix: Norge’s demand is anchored in Norway and other harsh-environment markets, whereas drillships like Poseidon and Aquila target benign basins (US Gulf, Brazil, West Africa, etc.). Combining Norway semisubs with 7G+ drillships—as seen in the secured 2030s—yields a balanced package across lower-risk, OECD-weighted geographies debt investors like.

As detailed in the call schedule (above) of Transocean’s secured debt, the Aquila-secured bond’s call protection very rolled off on September 30th and is now eligible to be called at a price of 104, or a 4% premium to par value. While the 2030s are arguably prohibitively expensive to call early, Transocean can now refinance a portion of its secured debt although it is not clear on market receptivity on terms. Considering the secured bonds all trade above par, the investors in these deals may not even want the heavy amortization considering the debt payments are made at par (below the market price).

Separately, Transocean also has a conservatively structured revolving line of credit with covenants, including minimum liquidity ($200mm) and has ten rigs pledged as collateral. In addition to Norge, it appears Transocean also has Norway-eligible semisubs Equinox and Endurance as unencumbered collateral that may also be used in a secured debt offering. RIG may prefer not pledging its crown jewel 8G drillships as collateral (Titan and Atlas) for option value on them long-term.

(2) Term Loan B Market: First-lien, senior secured, floating-rate loans—common in ETFs like SRLN and BKLN—typically carry 7-year tenors, ~1% annual amortization, and largely cov-lite docs. Attractive on paper for Transocean but this market is likely not available to them.

CLOs drive the Term Loan B market—roughly ~70% of demand—and they avoid offshore drillers. Their structures are penalized by CCC concentrations and, especially, defaults, which can trip overcollateralization and/or interest coverage triggers and cut off equity cash flows. Even with wider spreads, CLO structures aren’t built for deep-cyclical risk and without CLO participation, placing a $1–2B TLB would be challenging.

Offshore drillers once tapped the Term Loan B market, but the bankruptcies of Ocean Rig UDW, Seadrill Partners, Pacific Drilling and others left lasting scar tissue with CLO managers. I covered deepwater driller Term Loan B’s for a CLO manager in 2015–2017—it was a bruising stretch.

(3) Deepwater CLO? Very unlikely but I would love it.

If the secured bond market continues insisting on heavy amortization and other creditor-friendly terms, the ~$70–80B CRE CLO market offers a useful analogue for offshore rigs. In CRE CLOs, pools of transitional/non-stabilized properties are financed on an interest-only basis; amortization is not required unless the pool breaches tests (e.g., interest coverage, overcollateralization), at which point cash is diverted to pay down the senior bonds to support LTV ratios. Borrowers pay up on spread but gain value from the structure’s flexibility.

Deepwater rigs carry risk, but Transocean is asset-heavy with collateral that generates substantial cash flow from predominantly investment-grade customers. As with bank-loan covenants, quarterly trustee-monitored structural tests protect creditors. If a test is breached, excess cash is diverted to amortize debt, delever the structure and protect noteholders.

A key CRE CLO feature is collateral substitution: if a property’s weak performance threatens coverage tests, the borrower may replace it with a stronger asset—so long as the replacement meets defined eligibility criteria and approvals. Applied to rigs, Transocean’s large rig fleet provides a sizable substitution bench, particularly if a few of the 10 rigs currently pledged as collateral to the $510 million revolver are released.

Key drawbacks are ratings and liquidity as the notes would likely be unrated and highly bespoke, limiting secondary-market depth—placing the deal squarely in private credit universe. That said, performance would be transparent, with coverage tests tied to rig-specific, publicly available data.

While unlikely, CLO-style structures offer borrower flexibility that can enhance equity returns. Transocean’s current secured debt is currently not shareholder-friendly. Improvements are likely in the secured high yield market, although if not a structured alternative—akin to CRE CLOs—could deliver the needed flexibility, as the >$70B CRE CLO market demonstrates.

(4) Other Options: Transocean could refinance its secureds with unsecureds, although it would require a deep unsecured bid and appears unlikely. Secured debt sometimes has strings attached to it, making unsecured more preferable although RIG may not be there yet. Sale Leaseback transactions could also be an alternative, although the company’s 10-K notes its secured credit facility places restrictions on these types of transactions.

Summary: I believe Transocean has the capacity to meaningfully improve its flexibility via refinancing transactions, although it will need the high yield credit and oil markets to cooperate.

As Transocean moves toward simplifying its capital structure, it very likely does not want something like a ‘Deepwater CLO’ but this type of financing is designed for borrower flexibility which is what Transocean needs to satisfy its equity investors long-term — its also fun to write about. They can likely achieve better terms via the Secured Bond market where they have an existing investor base.

The simplest way to achieve this appears to be combining its single asset bonds/loans (Poseidon, Titan, Aquila and Atlas) into a diversified collateral bond, and if needed also contributing recently acquired Norge (or another unencumbered rig) to improve LTV via overcollateralization. A lower LTV can justify lower debt amortization payments, offering a path for cash flows to gradually shift from secured debt holders and back toward equity investors after further deleveraging.

Tidewater’s recent equity-friendly refinancing transactions that better enabled share repurchases and M&A optionality offer a template for Transocean. RIG carries more debt because it never filed Chapter 11 so it will be a slower process to return to shareholder distributions, although the company merits credit investor recognition for honoring obligations through a brutal decade.

Transocean has different levels of debt with various covenants that I have not analyzed in depth (DYODD).

On September 24, 2025, Transocean announced an equity offering to raise at least $381mm in cash proceeds at roughly a 16% discount to the price of the equity before the offering. While clearly a debtor-friendly transaction, Transocean has the opportunity to gain material option value for equity via upcoming debt refinancing transactions if they execute in the fixed income capital markets.

Unlike its peers Noble, Valaris and Seadrill, Transocean never filed for bankruptcy in the downturn of 2015-2021. Accordingly, the company still had ~$6.6B of debt as of 6/30/2025. While avoiding Chapter 11 in a painful downturn is admirable, a debate exists if they would have been better off long-term had they filed because this debt is still constraining equity upside.

Leverage isn’t just the headline debt balance—the terms determine who holds the option value. In many high-yield and leveraged-loan deals, loose documents let sponsors extract value. Transocean is the opposite: creditor-friendly indentures and structural protections direct most operating cash flow to debt service and tightly limit leakage to equity (dividends/buybacks). In short, creditors—not equity—hold much of the value today.

Transocean’s equity has a debt structure problem. It’s not just the amount of leverage, it’s the terms of leverage being (currently) too debtor friendly. All of the cash flows deleveraging is from paying off secured debt. Specifically, Transocean had $502mm of scheduled principal amortization due in the next twelve months from secured bonds and a shipyard loan. RIG’s contracted cash flows support this debt repayment, but if paid as dividends they would translate to ~16% dividend yield based on September 26’s equity market cap of ~$3B.

Under the secured notes indentures, a Debt Service Reserve is required, mostly represented by $395mm of restricted cash as of 6/30/2025 (see below). With legacy unsecured bonds trading at discounts, Transocean would likely prefer to deploy liquidity toward those repurchases rather than secured note debt service. However, the reserve effectively ring-fences cash for secured creditors and limits leakage to unsecured creditors.

The secured debt’s (i) amortization schedule and (ii) Debt Service Reserves are favorable structural features to Transocean’s bond holders which currently limit meaningful option value to the company and its equity investors.

Transocean’s outstanding debt includes other covenants and constraints, but the two most apparent are the ~$500mm of annual amortization and the Debt Service Reserve Account (DSRA). Eliminating these (and related covenants) via a future refinancing would could potentially free trapped cash and reduce mandatory paydowns, creating immediate equity value. Transocean has other structural levers to improve equity value, but for simplicity I’m focusing on these two because they’re the most obvious.

In June 2025, Tidewater (OSV’s) refinanced its bonds, easing indenture terms—looser covenants and lower liquidity floors—freeing capacity for shareholder returns and M&A. With a meaningful amount of debt due in coming years, Transocean will have the opportunity to do the same but needs cooperation and to build favor with debt investors.

In the deepwater rig market, operators still point to 2H26–2027 for most multiyear project starts. Some examples of slippage are likely, but commencements largely appear on track. For Transocean, early 2026 is setting up as pivotal as a large portion of its secured debt becomes callable, and 2027 maturities roll into current liabilities.

I highlighted the appeal for the Secured 2030s in Dayrate Duration (April 2025) and RIG Credit: June 2025 Update, although these are at risk of being called in February 2026. Unlike the other single asset bonds, the Secured 2030s have five collateral rigs in USA and Norway, an 8.75% coupon with 3-year call protection (!) These become callable on February 15, 2025 at 104.375, a redemption price below the current market value ~105.

Credit investors may love the 2030 secureds, but equity holders shouldn’t. Refinancing these notes—and others with similar structures—easily could restore equity option value by loosening more market standard indenture terms. RIG will likely need to pay a call premium above par, but it would be money well spent.

The equity raise was painful, but it appears to be setting up a cash-in refi—injecting new equity to delever and enable a refinancing. In CMBS, the market often sees cash-in refis to back assets lenders disliked (malls, older offices, lower-tier hotels). Deepwater drilling rigs are included in this group. Earmarking proceeds to retire the 2027 notes should read well to high-yield investors when the company returns to market.

With >$6B of debt outstanding, Transocean needs a deep bid to refinance and must persuade many holders in a market where few generalist HY investors still underwrite offshore rigs post-downturn. Large issuers often use fixed-income investor decks; despite its strong technical reputation, Transocean could improve economics by marketing more directly to HY credit buyers.

Deepwater Market Signal or Idiosyncratic to RIG?

When the equity raise was announced, my first question was whether it signaled a defensive outlook or was simply RIG-specific. In September 2024, Transocean announced a ~$340mm sale of the Development Driller III and Inspiration rigs, but the deal collapsed in early 2025. Those foregone proceeds would have addressed the same 2027 maturities now targeted by this week’s $381mm equity raise.

The $340–$400mm cash raise is symbolic against the $395mm of restricted cash on RIG’s 6/30/2025 balance sheet. Most of that balance is the Debt Service Reserve, which ring-fences funds for secured debt service and can’t be used to retire subordinated debt like the 2027 unsecureds. If those terms were removed in a refi, the $381mm equity raise may have been unnecessary. Secured bondholders: you win—now equity wants you to go away.

The US Gulf has been an area of strength for Transocean, although I think the equity raise would not have been done if they had near-term news of a multiyear contract extension in the region on the 7G+ drillship fleet. I’m confident in this fleet’s marketability long-term but the equity raise may signal a project or two they were counting on slipping a couple quarters.

Transocean’s utilization and dayrates have stayed strong partly because it has limited West Africa exposure—the source of much of the ‘white space’ on Noble and Valaris fleet reports. Confidence is improving that projects in Nigeria and Côte d’Ivoire are progressing, which is positive for Transocean, though it has only one rig in the region (Skyros).

Lower crude prices compress IOC operating cash flow, shrinking discretionary budgets for buybacks and growth capex. If IOC’s and E&P’s continue to ‘live within cash flow,’ projects run the risk of delay although cancellation risk appears low. This week, TotalEnergies said it will reduce share repurchases, effectively prioritizing capex—a constructive signal for deepwater rigs given TotalEnergies’ role as a major demand driver. However, it’s unclear which projects are affected or whether rigs have already been assigned. Many IOC’s and E&P’s have yet to provide 2026 capital-budget guidance. Considering deepwater investments are long-cycle and less flexible than short-cycle U.S. shale, deepwater activity may prove more resilient than other land-based services.

RIG: Debt or Equity?

Since the ‘Liberation Day’ bottom in April, Transocean’s equity is up ~54.9% versus ~20% for the 2029 unsecureds. However, equity’s daily-return volatility has been roughly 4× higher, so on a risk-adjusted basis (Sharpe ratio) the debt has outperformed the equity over this period. For income-oriented investors, debt has clear appeal. While unsecured notes offer limited price upside, RIG paper still carries ~450–475 bps of credit spread—attractive in a pricey high-yield market given the company’s recent credit-positive actions.

The Equity bull case casts Transocean as an early-stage Odfjell Drilling: Odfjell is up >210% since Jan-2023 and valued at ~$500mm per rig, driven by dividend growth after successful deleveraging. Odfjell is a niche, Norway-focused player—where Transocean also has exposure but is more geographically diversified. If Transocean is successful reducing mandatory principal amortization on debt, cash can pivot to shareholder returns. However, Transocean has said it will need to get below 3.5x Net Leverage before returning cash, and not all debt amortization will flow to equity immediately. After the equity raise and 2027 note paydown, RIG is 4.0-4.3x Net Leverage, depending on how you treat Restricted Cash.

Summary: RIG equity still trades like a beta play on oil and risk sentiment, while the bonds offer steadier pricing, semiannual income and good credit spreads in a rich HY market. As RIG nears shareholder returns, the stock should trade with less volatility, all else equal. If refinancing shifts more cash flow to equity by loosening creditor-friendly structures, income-oriented investors may see value speculating on shareholder returns before announced they but work is still yet to be done.

What to Follow Next: If Transocean is able to successfully refinance debt and improve structural terms in coming quarters, it will be an important step toward potential shareholder returns. Contract announcements are also obviously important, but the potential debt refinancing will arguably be more impactful long term if successful.

Transocean has two classes of unsecured notes: Priority Guaranteed Notes (PGNs) and Legacy Guaranteed Notes (LGNs). In a downside or restructuring, PGNs should recover more because their guarantees sit closer to operating cash flows. If you don’t expect restructuring, LGNs may offer greater upside. The open question is whether Transocean will refinance the legacy notes or keep them if their terms are less burdensome than the senior secured notes. Do your own indenture diligence.

I have no positions in any securities referenced in this article.

Transocean announced a $381mm equity raise at a ~16% discount to closing price on September 24, 2025. Sharing quick thoughts as I’m traveling:

RIG’s stock jumped more than 10% Tuesday morning without any clear news catalyst, gave back some gains later in the day, and then rallied again on Wednesday. I noticed on my Twitter feed some of the buying was from technical charts people, as I was unaware of anything fundamental. My initial reaction was as though RIG had just announced two multiyear contracts in the US Gulf at $450k dayrates, but the buying appeared to be more technical in nature (??). RIG took this opportunity to raise equity, selling that rally. Not a great signal to equity investors but debt investors had to be pleased.

RIG has been using shares to pay down convertible notes and also to acquire the Norge semisubmersible rig — they’ve been acting in a debtor friendly way lately. For perspective, RIG has $6B of creditors and an equity valuation ~$3B as of this morning.

Transocean faces roughly $2.5 billion of debt maturities in 2027–2028. While they likely could have refinanced without the recent equity raise, the company still has significant refinancing ahead. This presents an opportunity to improve the structural terms of their debt — eliminating amortization would be a major step forward. The equity raise should also support potential credit rating upgrades (Moody’s still rates the unsecured debt at Caa1) and strengthen Transocean’s position in negotiating better terms.

Transocean’s equity story is constrained by its debt structure. A large share of its capital is tied up in secured bonds that carry about $400 million of scheduled annual amortization. While this is the company’s lowest-cost source of funding and would ideally be the last debt to repay, the bond terms mandate substantial semiannual principal payments — terms that are highly favorable to secured creditors.

If Transocean can eventually redirect the >$400 million in annual principal payments toward dividends, it would equate to a yield of over 12% at today’s equity value. These cash flows are backed by firm contracts on a leading offshore fleet by specification and geographical diversification.

The equity raise is an important step toward loosening bond terms and improving flexibility for future shareholder distributions. The next milestone will be executing refinancing transactions in the debt markets, a process the equity raise should meaningfully support although equity returns are still >12 months away.

Market Signal or Idiosyncratic Transocean Capital structure story?

In September 2024, Transocean announced the $340 million sale of the DD3 and Inspiration, but the deal fell through as market conditions weakened. Now, with the current equity raise bringing in $383 million, one can’t help but note the timing. This was covered in RIG Credit: Dayrate Duration.

Unlike Noble, Valaris, and Seadrill, Transocean never went through bankruptcy and still carries legacy debt. At times one might argue they’d have been better off restructuring, but they’ve consistently honored their obligations and treated creditors fairly. It’s now time for creditors to recognize that and support refinancing transactions with less restrictive terms

Unsecured creditors benefit from this equity raise, and their bonds should rally. That could set up a trade: sell into credit strength and buy equity on weakness, if you believe the ~$400 million in annual amortization tied to the secured bonds (Titan, Poseidon, Aquila, Secured 2030s) can be refinanced in upcoming transactions and eventually redirected to shareholders. If achieved, that’s a compelling return story—but likely more than 12 months out.

Borr completed a large equity raise in early July, which equity investors absorbed well given the reduced balance sheet risk. Broader risk assets have also traded strongly since then, but if Transocean can frame a constructive narrative around this raise, it may find similar support although the market’s current constructive risk asset appetite needs to cooperate.

Broader Deepwater Rig Market: As we approach capital budgeting season for the IOCs, some restraint is possible. Any delays could cap dayrate upside by dampening utilization, though that remains to be seen.

Key market item to watch: Petrobras’ Búzios tender. Unlike past tenders with a fixed rig count, Petrobras specified a range of 1–4 multiyear contracts. Outcomes matter: four awards would be excellent for Brazil’s market, three solid, two OK but underwhelming, and one clearly negative. 2-3 rigs awarded Buzios contracts should be good for that market given competing demand from Shell and Equinor. I expect 7G winners to secure dayrates in the upper $300k range—slightly below the recent ~$400k prints but still offering attractive returns. Búzios is a massive deepwater field. Its output adds to global oversupply concerns, but sustaining production requires deepwater rigs. While other tenders are underway globally, the Búzios award will be the headline event to watch

A major theme for deepwater rigs in 2H24–2025 has been idle time from project delays, with West Africa a main driver. IOC project delays in Nigeria have been the largest factor for 7G drillships, while Tullow’s January 2024 postponement of its Jubilee campaign in Ghana added to concerns. Tullow operates Jubilee with a 39% stake, while Kosmos holds a significant 38.6% non-operating interest.

Consider this article as a case study of how project delays have pressured Kosmos and Tullow’s securities, while showing the efficiency of 7G drillships and the risks of deferring drilling programs.

The Jubilee field has current oil production capacity of ~120k bpd although is operating well below this level currently, with only ~55k bpd averaged during 2Q25. Tullow has faced rising water cut at Jubilee, which reduces oil output and increases handling volumes on the FPSO. The added water processing burden has strained facilities and complicated operations, forcing the company to reprioritize reservoir management. Jubilee’s low production totals have also been adversely impacted by a 15 day FPSO shutdown for maintenance in March-April 2025, as well as the delayed infill drilling program.

Over the past 7–8 years, production and infill drilling have gradually altered Jubilee’s reservoir in ways Tullow arguably failed to track closely enough, given its last 4D seismic survey was in 2017. This lack of updated monitoring has arguably contributed to weaker recent infill drilling results. The current drilling campaign was deferred to ensure the next round of infill wells could be guided by a new 4D seismic survey, improving target selection and raising the probability of success.

The Bull case for Jubilee is the upcoming infill drilling campaign: low-cost, high-margin barrels added through the existing FPSO, which still has >45 kbpd of spare capacity. Unlike typical long-cycle deepwater projects, this six-well brownfield program delivers near-term production with minimal new infrastructure capex. The first well is already online at ~10 kbpd, with 4–5 more to follow over the next year.

Credit Distress: The production challenges at Jubilee, cost-overruns and delays at GTA Phase 1, Kosmos’ debt levels and general weakness in the oil markets have meaningfully contributed to the weakness in how the high yield credit markets are pricing risk in Kosmos and Tullow’s publicly traded debt.

Why the credit curve steepness on Kosmos with 2028 credit spreads >600 bps higher than 2026? Kosmos is in the process of raising a $250mm secured term loan using its Gulf of America assets as collateral. While not yet closed with funded cash in the bank, Kosmos is expected to use these funds to meet its $250mm of 2026 maturities. While I’m not certain about their additional secured debt raising capacity, concern exists regarding secured debt diluting a potential unsecured recovery in a bankruptcy scenario. The Gulf of America reserves are likely the highest valuation assets due to geopolitical risk associated with the rest of their assets in West Africa (Ghana, Senegal/Mauritania, Equatorial Guinea).

7G Drillship Noble Venturer is the rig on the current infill drilling campaign. The first well, J72-P, has been an initial success producing ~10k bpd. The next 4-5 wells will come after Venturer completes its 5-year SPS in Las Palmas, with drilling contracted to commence November 2025 through August 2026. Risk of failure and unexpected surprises are ever-present in the deepwater drilling industry, although Tullow has (i) completed a new 4D seismic campaign, (ii) will complete a new ocean bottom node survey in 4Q25, (iii) has recently completed maintenance on the FPSO and (iv) 7G drillships are designed for development drilling programs such as this.

The key debate is whether Jubilee is on structural decline or if its recent production issues are fixable. Operator Tullow has taken steps to address the challenges, while Ghana’s other deepwater field, TEN, has faced higher than expected decline rates. Unlike Jubilee, which is a single large accumulation with a stronger production track record, TEN is a cluster of three smaller fields (Tweneboa, Enyenra, Ntomme) that have struggled with weaker reservoir connectivity and lower output. I’m less optimistic on the future recovery on TEN as I am with Jubilee, although execution risk exists on Jubilee’s infill drilling campaign.

Summary: Opportunistic/Distressed debt and Equity investors seeking beta and alpha on Brent rallying to $80-$85/bbl in the next 1-3 years and and potential Jubilee performance should consider looking at Kosmos Energy. Kosmos’ equity is down ~73% from its 4Q23 average when Jubilee was producing >90k bpd and Brent averaged ~$82/bbl.

• Credit: Kosmos’ unsecured 2027s and 2028s have credit spreads of >1,000 bps. Equity: Kosmos’ equity is trading at a discount due to its balance sheet risk.

• Security pricing distress is mostly due to poor performance at the Jubilee field. While speculation, I believe this is primarily due to poor reservoir management by Tullow — they’ve since replaced their CEO. After 7-8 years since their last 4D seismic shoot in 2017, Tullow’s active production and injection drilling from 2017-2024 has gradually changed the reservoir, likely leading to weaker production drilling in the absence of better reservoir surveillance. Tullow just concluded a new 4D seismic campaign in 1Q25 and will complete a new ocean bottom node (OBN) program in 4Q25. The next 4-5 wells to be drilled are scheduled to begin in November 2025 and run through August 2026.

• Tullow and Kosmos’ upcoming campaign is infill drilling to support production to nearby FPSO with >45k bpd of capacity. At cash operating costs of ~$20/bbl, this incremental production to be brought online in the next 12 months is meaningful free cash flow even with Brent in the $60-$70/bbl range. Brownfield capex delivers high IRRs by leveraging existing infrastructure.

• This drilling campaign will be completed by 7G Drillship Noble Venturer. 7G drillships are designed for development drilling like this and have demonstrated efficiency. Venturer has already drilled the first well (J72-P) with success at ~10k bpd of initial production. Venturer is currently in Las Palmas, Spain completing its 5-year SPS and will return to Ghana in November 2025 for the next 4-5 wells. At first glance, the timing appears odd but gives Tullow and Kosmos more time to analyze the 4D seismic completed in 1Q25 with results of the ocean bottom node survey coming in 4Q25 — which should help probability of success.

• Tullow and Kosmos have publicly communicated plans to drill 3-4 infill wells per year to support future production at Jubilee after the current drilling campaign.

• How do you price the risk? My background is in oil and gas credit, asset valuation and economics. I’m not a geologist and used two separate AI platforms to gauge the risk tied to Tullow/Kosmos’ upcoming infill drilling campaign (see image below). Using >7k bpd as the definition of “success”, a 75-85% probability of success was estimated for each well. If 5 wells are drilled, that’s at least (probability-adjusted) 28k bpd incremental production with an additional ~10k bpd increase from J72-P already successfully drilled, partially offset by natural decline of existing wells. Absent additional FPSO maintenance shut-downs, this could support Jubilee’s production increasing to >80k bpd by late 2026.

  

Why Kosmos? This Substack is free and is meant to be an outlet for my bigger picture research on the deepwater energy industry. Kosmos leverages my research and experience better than Tullow because it has four separate deepwater regions. Additionally, (1) I believe Kosmos has a more “underwrite-able”/justifiable path to refinancing at par than Tullow, (2) I’m American and am more familiar with Kosmos (Dallas-based) and (3) I also believe Kosmos has another EBITDA growth driver through the start up of its Greater Tortue Ahmeyim Phase 1 project.

Greater Tortue Ahmeyim (“GTA”) Phase 1: After Kosmos’ deepwater gas discoveries of Tortue-1 in Mauritania (2015) and Guembu-1 in Senegal (2016), the GTA project was born via a joint development agreement between Mauritania and Senegal. BP eventually became operator on the project with Kosmos having a 26.8% interest in the project, with the majority of the capex already spent as the project is expected to ramp up production in late 2025 and into 2026. GTA Phase 1 has been an additional reason for Kosmos’ weak equity and debt security performance due to material delays, cost-overruns and funding a portion of the NOC’s capex (now a balance sheet receivable), however GTA Phase 1 is now operational and its three deepwater gas wells are performing in-line with expectations.

Those familiar with Golar LNG will recognize its role in Mauritania and Senegal, where the FLNG Gimi provides offshore liquefaction for gas from the deepwater GTA Phase 1 project. Golar’s model is midstream-like, earning a tolling fee for its FLNG capacity, while BP (56%, operator) and Kosmos (26.7%) remain the upstream partners responsible for exploration and production.

FLNG Gimi delivers liquefaction capacity for GTA Phase 1 gas production, while an FPSO handles gas processing and condensate extraction for sale into global markets. At ~2,800m water depth and in a remote setting, the project faced start-up challenges, but BP and Kosmos appear to have most of these issues behind them. Its location in offshore Senegal/Mauritania makes LNG exports to Europe attractive given shorter shipping distances. GTA has potential for Phase 2 and Phase 3, although given the issues with Phase 1 start-up, BP appears more focused on a smaller expansion of Phase 1 in 2027-2028. Geopolitical risk exists in Senegal regarding the 2024 election results whereby the President has communicated an interest in renegotiating oil contracts — thus making future investment less likely.

Equatorial Guinea: Kosmos has a 40.38% non-operator interest in the Ceiba and Okume deepwater fields whereby Trident Energy is the operator. While only producing 19-25k bpd of gross production, these mature fields are additional low-cost, brownfield expansion options for future infill drilling. While Kosmos’ Gulf of America interests are closed to being pledged as collateral on a $250mm secured debt raise to meet its April 2026 maturity, Kosmos’ interests in Equatorial Guinea are potential monetization options that would likely appeal to various buyers if necessary, albeit at a lower valuation.

Final Summary: Kosmos had $2.8B of Net Debt at 6.30.2025 with TTM EBITDA of $613mm, yielding Net Leverage of 4.6x. As a Deepwater E&P, it’s revenues are tied to a volatile commodity. It’s two primary assets have had production challenges (Jubilee) and start-up delays with cost overruns (GTA Phase 1).

Kosmos’ 7.5% coupon 2028 unsecured bonds trade at ~84-85 with YTW of 15.3%, a meaningful level of distress adversely impacting the equity valuation. Absent inherent commodity price volatility, the outcome of its infill drilling program at Jubilee will play a meaningful role regarding the Company’s ability to cover its $350-$400mm capex budget and estimated ~$220mm cash interest. Consensus analyst EBITDA estimates are $784mm for 2025 and $1,074mm for 2026 (Source: Bloomberg), although run the risk of error. At 6.30.2025, Kosmos had a $1.35B reserve-based lending facility with $350mm of available capacity. Kosmos recently amended a covenant on the RBL to better align the timing of revenues and operating expenses of the GTA Phase 1 project, and maintain access to the RBL facility.

A lot can go wrong in Deepwater E&P and recently Kosmos is no exception. However, if the Jubilee infill drilling campaign is successful, it would provide meaningful cash flow uplift via high-margin brownfield production, alongside GTA Phase 1 start-up where most of the capex has already been invested. I believe this is an underwrite-able path for Kosmos to eventually refinance its longer-dated maturities at par, although while the market waits for the Jubilee infill program to continue, risk exists for further production declines from existing wells before the next infill well is scheduled to begin drilling in November.

Kosmos appears to have sources of liquidity to make it through at least the next 12 months, at which point 7G drillship Noble Venturer should have completed the Jubilee infill program and GTA Phase 1 completing its first year of commercial operations. If Brent crude stays above $60/bbl (GTA Phase 1 breakevens are $50-$55/bbl), the credit should look better. If Brent is solidly above $75/bbl and risk asset sentiment is adequate, the equity has a justifiable path returning to its 2023 valuations.

Major deepwater projects set to commence drilling in the next 12–18 months generally offer strong economics. Where softness exists could be in shorter-cycle infill drilling, which often waits for higher oil prices before rigs are contracted. Lower prices also tighten IOC and E&P budgets, a familiar headwind for oilfield services. Even so, drillers consistently reinforced expectations that floater utilization will improve into late 2026, translating to reduced idle time, and these comments were further qualified by IOC commentary regarding their capex.

Transocean’s strong contract book shields it from the idle time weighing on peers and supports cash flow generation for further deleveraging. Its highest-value assets are concentrated in stable regions such as the U.S. Gulf and Norway, where lower-cost, infrastructure-led E&P capex generally supports a steady EBITDA base.

While Transocean’s odds of reactivating coldstacked 7G drillships Mylos, Apollo and Athena have materially diminished over the last 18 months, more attention should be focused on its warm fleet that has historically been driving industry dayrates higher. Notably, Proteus and Conqueror roll off contract in May and September 2026. Both are top-tier 7G+ drillships, ranked well within the global top 10, and are likely to to be re-contracted and I believe above recent standard 7G fixtures in the low-$400k range. In Brazil, the outlook for Transocean’s 6G drillships is less clear given Petrobras’ vague tender requirements. However, demand from other IOCs in the region should provide incremental support for utilization.

Odfjell Drilling has delivered strong operational and equity performance. Like Transocean today, Odfjell spent 2021–1H23 deleveraging its balance sheet before initiating dividends in 3Q23. Since then, its share price has risen more than 180%. While multiple factors contributed, Odfjell illustrates the bull case for Transocean: once it reaches its leverage target and initiates shareholder returns, equity upside could follow. Transocean has guided to a net leverage goal of ~3.5x, which appears achievable but likely requires another 12–24 months.

Odfjell reported earnings on August 19 and announced a dividend increase supported by strong cash flow growth visibility via (1) nearly 100% utilization through 2026, (2) anticipated contracted dayrate appreciation of ~15% over the next twelve months, (3) completion of the SPS program will reduce capex from $130mm to $45mm-$60mm sustainably for next three years and (4) should be able to reduce debt amortization by $25mm-$50mm annually to free up cash flow for equity returns after successfully deleveraging from 3.3x in 2021 to 1.3x currently.

Odfjell appears expensive on a per-rig basis compared to peers, although its strong cash flows are the basis for its valuation, with a ~8.6% dividend yield (76.90 NOK at Aug. 19, 2025) and visible growth potential from rising contracted dayrates and lower capex. Odfjell communicated confidence in extending its contracts with Aberdeen and Nordkapp into 2027. If an extension is awarded, the company guessed Nordkapp’s dayrate for 2027 to be between $450k and $500k.

Norwegian E&P demand remains resilient, driven by low-breakeven brownfield projects and a favorable tax regime for E&P capex. After Equinor recently extended Deepsea Atlantic firmly into mid-2027, Aker BP noted twice on its 2Q25 call that it is “rig constrained,” suggesting an appetite to extend Deepsea Nordkapp beyond 2026.

Noble: Following the Diamond acquisition in June 2024, Noble has already realized its $100mm annual synergy target—roughly equivalent to the EBITDA of a 7G drillship contracted at dayrates in the high $400ks. In April 2025, Noble secured four multiyear contracts for the Voyager, Valiant, Venturer, and Developer, and more recently extended the Stanley Lafosse with Murphy through August 2027. While these developments strengthen visibility, challenges remain: Voyager and Valiant are without work until late 2026, and the Ocean GreatWhite (UDW semisub) has recently gone idle.

In “Scrap, Baby, Scrap”, I argued Noble could save nearly $100mm in annual *potential* warm stacking costs (if idle) by scrapping various lower tier rigs while having minimal impact on its Net Asset Value. In my opinion, these non-core rigs include Globetrotter I, Globetrotter II, Apex, Endeavor, Reacher or Resolute and *maybe* one of their DSS21 semisubs.

Noble is unlikely to scrap rigs if they believe work can be attained, although these assets are generally not suited for the higher-value work of its 7G fleet. The cost of keeping them warm is limiting share repurchases, suggesting further fleet rationalization ahead—a move equity investors should welcome.

Noble’s operational cash flows in 1H25 were strong and comfortably covered shareholder returns, although will face pressure in the next twelve months due to idle time on core rigs. Consensus estimate for 2026 EBITDA is ~$1.05B and will need to cover capex of ~$450mm, cash interest of ~$160mm and ~$318mm of dividends for its ~7.5% dividend yield – Noble’s bonds do not have principal amortization. Working capital may also be a use of cash when Voyager, Valiant and Developer’s new projects commence in 2H26. Supporting its liquidity, Noble raised ~$105mm in cash via divestments of Highlander, Meltem and Scirocco.

Valaris: After repurchasing $325mm of stock in 2023–2024, Valaris has returned none of the >$100mm in 1H 2025 free cash flow to shareholders, despite $275mm remaining under its $600mm buyback program.

While Valaris’ nine warm (and three cold) 7G drillships are its core strength, ~35% of mid-cycle EBITDA is derived from its jackup fleet, a larger proportion and its peers. Management’s commentary on jackups has more cautious on public calls, reflecting the impact of Saudi Aramco’s suspensions which added >10% of global active supply to the market quickly - a particularly significant hit to benign-environment jackups where Valaris has more exposure than peer Noble. Its two semisubs also face uncertainty with both DPS-1 and MS-1 contracts ending in late 2025.

While the lack of share repurchases have disappointed, Valaris’ sale of jackup Valaris 247 for $108mm is scheduled to close in 2H25 and the press release specifically noted “return of capital to shareholders” as a potential use of cash from sale proceeds. Potential reasons for the lack of share repurchases are hypothesized below:

• Valaris, typically more conservative than peers, appears to be holding back on share buybacks amid global macro uncertainty. Valaris has idle time risk on its semisubs in Australia for 2026.

• Valaris’ large jackup fleet faces a shallow-water market still unsettled by Saudi Aramco’s suspensions.

• Valaris is building cash that could support an M&A deal, though it hasn’t signaled interest publicly. While I have no specific insight, Seadrill is often rumored, and Northern Ocean’s Bollsta and Mira would diversify Valaris’ drillship-heavy fleet.

• Valaris’ ARO JV faces $1.1B in commitments for newbuild jackups ordered by JV partner Saudi Aramco. These are expected to be funded through the JV’s cash flow or third-party financing, making direct contributions from Valaris unlikely, though the contingent liability remains notable.

• Valaris may have already used much of its discretionary capital with the $337mm purchase of stranded newbuild 7Gs DS-13 and DS-14 in Dec-2023. While attractive buys, both remain uncontracted, cold-stacked in Las Palmas, and each will need ~$100mm of activation capex before working.

Seadrill repurchased $532mm of shares in 2024, funded by (i) the $338mm sale of three jackups and (ii) reducing its cash balance from $697mm at year-end 2023 to $478mm at year-end 2024. Absent asset sale proceeds, no repurchases occurred in 1H25 as operating cash flow was negative before capex. The drag stems from four 7G drillships in Brazil locked into legacy contracts at mid-$200k dayrates through at least November 2025. Looking ahead, Seadrill has secured stronger contracts: Jupiter and Tellus at low-to-mid $400k beginning March and June 2026, respectively. Carina opens in Feb 2026 and is well positioned for new Brazil work, while Saturn remains tied to Equinor’s unusually favorable low-rate options running through 2030.

While Capella will be a key watch for competitive work in SE Asia, in the US Gulf semisub Sevan Louisiana benefits from reduced competition following Noble’s retirement of Globetrotter II, Globetrotter I’s temporary move to the Black Sea, and Valaris scrapping DPS-5. While not competing with top-tier drillships, it now faces less competition for P&A and intervention work.

Namibia hosted its oil and gas conference in Windhoek in mid-August, much of which is available on YouTube. Among frontier deepwater regions, Namibia’s Orange Basin stands out for its significant hydrocarbon potential and the attention it continues to attract. As a true greenfield deepwater oil and gas province, Namibia faces the various challenges of bringing first oil to market. However, the conference reinforced confidence that these complexities are being recognized and proactively addressed, highlighting the country’s professional and thoughtful approach to managing its emerging resources.

Las Palmas and Brunei Bay have long been storage hubs for idle floating rigs awaiting work or upgrades. Las Palmas still hosts Valaris DS-13 and DS-14, the stranded newbuilds acquired by Valaris. Brunei Bay, however, has seen notable progress: the formerly stranded 7G units Dorado and Draco (originally ordered by Seadrill around 2013) were acquired by Turkey’s NOC, TPAO. Both rigs have now departed Brunei Bay and are expected to relocate permanently to the East Mediterranean and Black Sea regions.

The floating rigs remaining in Brunei Bay include Seadrill’s West Capella, Vantage’s Platinum Explorer and Noble’s Deliverer. Vantage’s Platinum Explorer has announced conditional letter of award — the drillship has a history of operating in India and would be a potential destination as the country has growing demand. A few other higher profile projects exist in the region and could be potential fits for Capella and/or Deliverer. Ventura Offshore’s SSV Catarina is currently in Indonesia’s Kutei Basin, a promising region long-term.

“Big Positive Surprise”: On 2Q25 calls, Noble was the only driller to flag TPAO’s purchase of the Dorado and Draco drillships, calling it a “big positive surprise.” The acquisition notes Turkey’s shift from being a major gas importer to a potential producer, with discoveries in the Black Sea and sizable prospects in the East Med. Turkey may also deploy its new 7G units in partnership with recent initiatives in Libya.

Unlike other buyers, TPAO is expected to keep its fleet fully in-house rather than market the rigs globally. This effectively removes ~4% of the world’s 7G drillship supply from open competition; a notable tightening versus prior expectations that the units would be marketed internationally.

Energy Security and Geopolitics: A defining feature of the global deepwater market is that floating rigs are opening up previously untapped reserves in frontier and emerging countries. Turkey is a prime example: it is developing deepwater gas to reduce reliance on imports and could eventually emerge as a regional supplier, enhancing its geopolitical influence depending on the success of future exploration and appraisal. Turkey has also drilled in contested East Mediterranean waters before and could do so again.

Over the next 12–24 months, countries to watch include Turkey, Greece, Cyprus, and Libya—all with promising deepwater gas potential and overlapping maritime claims that carry geopolitical weight.

ADES acquires Shelf Drilling

It is unusual for a leveraged company to be acquired when its bonds trade at distressed levels, as a change-of-control provision typically requires the acquirer to repay the debt at par plus a premium. Distressed pricing often signals underlying issues, and buyers generally wait for a restructuring or bankruptcy to acquire assets free of the debt. Nonetheless, ADES announced the acquisition of Shelf Drilling this week, including its $1.3B debt load. ADES’ lower cost of capital gives it the option to refinance Shelf’s bonds at significantly lower rates.

While the 1L SHFLDI 9 5/8% 2029s traded at yield of 16% with a credit spread of ~1,200 basis points, Shelf had adequate liquidity and a decent contract book. I preferred the 1L BORRNO 10% 2028s due to the younger, higher specification jackup rig collateral package. The majority of Shelf’s best jackup rigs were collateral on the Shelf North Sea (SHLFNS) subsidiary bonds, leaving SHFLDI with a comparatively older fleet and meaningful downside recovery risk in a bear case scenario. Congratulations to the SHFLDI longs.

The 1L BORRNO 2028s rallied ~3 points on ADES’ acquisition of Shelf, tightening spreads by roughly 140 bps. Now quoted near 99.5, the bonds offer less pull-to-par from the heavy amortization schedule but still carry a 10% coupon.

More Jackup M&A Potential?

On its 2Q25 call, Borr hinted at the potential of an acquisition funded via the cash proceeds from its $200MM equity raise announced in early July. Based upon public information, a logical acquisition target is Paratus Energy Services’ jackup fleet of five in Mexico. At the Marine Money conference in June, Paratus’ CEO mentioned it would consider selling its jackup fleet. While Mexico has been an area of pain for jackup drillers in 2025, shallow water production is important source of energy production for the country and there should be a fairly resilient source of demand for jackup rigs through the decade.

Borr already has seven jackup rigs in Mexico and an acquisition of Paratus’ five jackups in the country would have a meaningful benefit as it relates to pricing power with less competition for work in 2026-2027.

Two of Paratus’ jackup rigs are the same design as Noble Highlander, which was just sold for $65M, approximately 42% lower than Seadrill’s comparable transaction in 2024 of comparable jackup rigs (Castor, Telesto and Tucana). Without inspecting the rigs or knowing specific capex requirements, I believe $280mm-$300mm is a reasonable price range for this fleet given recent transactions and market dayrates. Subject to Mexican regulatory input regarding market competition, Borr would gain meaningful leverage to a potential recovery in this market although this is entirely speculation based on public info.

For those focused on the next 12 months, it’s starting to look better as we crawl toward increasingly visible mid-2026/2027 project commencements although we’re still not all the way there yet.

Equity markets are forward-looking. After concerns began emerging regarding deepwater project delays on 2Q24 driller conference calls, equity markets began to sell driller equities as they foresaw rig idle time in much of 2025 as multi-year projects were pushed into 2026. Then projects then began to leak into 2H26-2027, although commentary has been fairly consistent in recent months regarding multi-year drilling commencements still on track for 2H26-2027. While Noble and Valaris have been awarded some of these term contracts in the US Gulf, Suriname and West Africa, there are additional projects yet to be awarded in other regions of the world into 2027.

Drillships and semisubs have meaningful operating leverage from warm stacking costs that lead to negative rig-level EBITDA when idle. Warm stacking costs vary but I generally estimate as $50-$60k per day. Given project delays and related rig idle time for 2025, equity markets have been focused on the forward-looking negative earnings drag from idle time before multi-year project commencements begin in 2H26-2027. While 2025 is a year of negative operating leverage on EBITDA for most offshore drillers with idle time, transitioning idle rigs from warm stacking costs to positive cash flows while working at >$400k day is a meaningful boost to profitability. Note: Meaningful differences in specs exist among deepwater rigs — not all idle rigs will return to work.

Given offshore drilling’s long-cycle nature, earnings trajectories are often visible from 12-24 months away. The Aggregate Quarterly EBITDA chart below (NE+RIG+VAL+SDRL) reflects the anticipated EBITDA declines from 2025 into 1H2026, primarily due to rig idle time equity investors began to foresee in 2024. Earnings momentum investors focused on the next 12 months (full year) have likely appropriately viewed 2025 as a poor year by mid-2024, although visibility is improving for a 2H26-2027 recovery as of mid-2025.

Oilfield service stocks remain sensitive to oil price sentiment. In 2023, Brent above $80/bbl and OPEC+ market support drove positive investor sentiment. Since then, concerns have shifted to OPEC+ spare capacity, viewed as bearish for crude prices. As of mid-2025, OPEC+ is raising output by over 1 million bpd, with Brent holding in the mid-$60s—subdued, but better than feared. Importantly, spare capacity concerns are easing. While oil prices have been volatile in June, this is mostly in the spot market. Offshore drilling is more influenced by longer-dated futures, which remain relatively stable. Geopolitical developments have had little lasting impact on deepwater floater demand. Easing regional tensions may actually support rig demand in the Eastern Mediterranean, where Chevron is evaluating a potential expansion of its Leviathan deepwater gas project.

While oil prices have declined in the recent year, most deepwater projects are generally now lower cost compared to other sources and appear to be gaining share of IOC capex wallet. I expect this to continue for the next decade as US Shale matures. We have not seen deepwater project cancellations. We recently saw Suriname’s GranMorgu project eat up two deepwater rigs on multi-year contracts — there are more to come as deepwater has an impressive list of yet-to-be sanctioned FID’s with strong economics.

Light at the End of the Tunnel? As currently expected, if we continue to see multi-year project commencements in mid-2026 through 2027, the drag from negative operating leverage in 2025-early 2026 should abate and turn positive for 2H26-2027, as currently projected by consensus analyst estimates.

I believe the analysts are mostly accurate with their projections and we begin to see increased deepwater floater utilization into late 2026-2027…and beyond. Factors impacting the idle time in 2025 include delays in the FPSO supply chain, as well as other essential subsea equipment. FPSO’s (Floating Production, Storage and Offloading unit) are expensive, long-lead time infrastructure that are essential for development drilling campaigns. 7G drillships are mostly designed for development drilling and you cannot produce oil without FPSO’s and related infrastructure, so they have sat idle waiting for delivery. Reasons for FPSO delays are various and include financing availability, shipyard slot availability, equipment shipping delays and other factors. Further, the global offshore drilling supply chain was adversely impacted due to cost cuts in the painful downturn from 2015-2022 and ramping it back up has hit more than a few road bumps.

Longer-term contracts are a leading indicator of rising dayrates, as they reduce available supply of marketed high-spec floaters. While regional factors matter, continued multi-year awards should support future dayrate appreciation. Noble’s awards announced in April 2025 included four (4) separate floater contracts in the US Gulf and Suriname between 2.9 and 4 years each. Valaris also announced two separate 7G drillship contracts ranging from 11 months (w/ options) to 2 years in West Africa. While we will see some short-term contracts also announced in 2025, we should also expect to see more multi-year contract awards on larger projects which would be positive for market structure. Stay tuned.

An investor survey published in May 2025 by a well-respected Nordic capital markets and brokerage firm stated investors expected 7G drillship dayrates to be in the $250k-$350k range, with not a single vote for $400k and above! Considering all six (6) of the 7G drillship contracts inked in recent Noble and Valaris awards were comfortably above $400k, this was an example of excessive pessimism on the deepwater rig market.

Important to note these dayrates are for work commencing in mid-2026/early 2027. While rigs are idle in 2025, we are likely to see a couple contracts at weaker dayrates to keep rigs warm during in 2025, although are ultimately less relevant to market valuations given their shorter-term nature. Additionally, lower specification rigs facing risk of cold stacking (not 7G drillships) are likely to accept work at weaker dayrates in hope of finding more lucrative work on the following contract. Specifications are material to marketability on deepwater floaters and differences amongst them are material.

As noted in the chart below, consensus analyst estimate trailing twelve month (TTM) EBITDA levels expect to see anticipated declines in the next year, with an expected recovery if/when multi-year project commencements begin in 2H26/2027. Transocean (RIG) is the exception primarily due to their strong contract book supporting their EBITDA growth, primarily due to the Barents, Invictus, Conqueror and Atlas contracts at strong dayrates near ~$500k in the next 12-18 months (discussed in RIG Credit: Dayrate Duration, April 30th). I do not believe Transocean gets much credit from the equity market for its contract book, although some debt investors view it as a meaningful source of deleveraging. Transocean’s unsecured debt would trade at meaningfully worse levels if it had the same contract book as Noble, Valaris and Seadrill which sees meaningful idle time in 2025-early 2026. Good job by the Transocean contracting team.

Country to Watch: Mozambique.

In “Outlook 2025: Drillships” posted in December 2024, I noted Mozambique as a geopolitical wildcard that could be the source meaningful incremental drillship demand for multi-year work. Unlike some other countries where deepwater exploration and appraisal results are the primary driver of project sanctioning, Mozambique has already had major deepwater gas discoveries, it’s just a question of geopolitics if these projects are developed after TotalEnergies declared force majeure in 2021 due to a deadly insurgency.

Mozambique represents a significant wild card for global drillship demand growth beginning as soon as 2027-2028. If TotalEnergies’ Mozambique LNG and ExxonMobil’s Rovuma LNG projects are sanctioned, they could require multiple drillships on multiyear contracts, tightening a market with demand pull from other major deepwater projects around this time period. The resource base is large, with both development and possible concurrent exploration drilling needs, but timing remains uncertain due to persistent—albeit improving—security challenges in the Cabo Delgado region. The most immediate activity could stem from Eni’s Coral North FLNG project, potentially reaching FID in 2025, though it would demand only a single rig for a shorter term.

While Mozambique currently has no active offshore rigs, its long-term potential is notable—particularly if LNG projects proceed as planned. At peak activity, the country could account for meaningful portion of global 7G drillship demand. Recent affirmations of export credit agency financing, including from the U.S. Ex-Im Bank in March 2025, mark positive steps toward potential project sanctioning. If developed, these projects could contribute to tightening the global rig market and offer economic benefits to Mozambique. However, timelines remain uncertain and progress will depend on both security conditions and financial commitments aligning in the years ahead. TotalEnergies LNG project could be as large as $20B so this will be an important potential FID to watch in the next 12 months.

Semisubs in Norway

Transocean’s projected EBITDA growth has been supported by its seven-rig (7) harsh-environment semisub fleet, four (4) of which are active in Norway—a high-barrier to entry market inaccessible to the semisubs of Noble and Valaris, among others. While markets such as West Africa have been slower to develop, the Norwegian Continental Shelf (NCS) has remained resilient due to persistent capex from Norwegian E&P’s and others supported by strong in-place infrastructure, particularly in the North Sea, as well as supplying the European gas market.

Odfjell Drilling is a NCS semisubmersible pure-play and is the least speculative offshore contract driller given it’s positive near-term visibility to free cash flow growth in the next 24 months.

Odfjell’s free cash flow is expected to grow meaningfully through 2026, driven by (1) rising contracted EBITDA, (2) lower capex following completion of its 5-year SPS program, and (3) potential debt amortization relief if liability terms improve—which appears likely. While the market questions visibility into 2027, Equinor, Aker BP, and Vår Energi’s recent capital markets guidance suggests strong NCS E&P capex through decade-end. Norway’s tax regime further supports drilling activity by incentivizing capex even in weaker oil price environments. Given the quality of Odfjell’s UDW harsh-environment semisub fleet, its rigs are likely to be prioritized over competing units in Norway.

NCS Exploration: Aker BP’s highly anticipated Rondeslottet well, regarded as one of Norway’s highest-impact exploration prospects of 2025 with estimated in-place resources of ~800mmboe, delivered disappointing results last week and was deemed non-commercial. The well is among of a group of tight reservoir prospects in the NCS that likely require available technologies to overcome low-permeability challenges. The Norwegian Offshore Directorate views tight reservoirs as a source of long-term potential.

The volume of exploration wells on the NCS is ~20% higher than the 5-year average, although the success rate thus far in 2025 of 24% (YTD) is below the average of 48% since 2017. Given public commentary from NCS E&P’s, exploration activity is expected to remain elevated through the end of the decade. While exploration success is likely to gravitate higher toward long-term averages, the mature NCS may be experiencing increasing drilling intensity requiring more exploration and development drilling to maintain production levels particularly if producing more from more challenging reservoirs.

Rondeslottet was a high-risk, high-potential exploration well that would have been multiple years from FID if successful. The well’s failure has limited impact on the positive outlook through 2027+ on the NCS semisub market, although would have placed upward pressure on dayrates toward the end of the decade. Equinor, Aker BP, and Vår Energi plan elevated exploration activity in the coming years, supporting a pipeline of high-impact prospects, some of which likely involve tight reservoirs.

While the number of NCS discoveries remains encouraging, most have been smaller and only economic due to tiebacks—an area where Norwegian E&P excels. The NCS has recently lacked high-impact finds capable of supporting standalone developments, such as what Rondeslottet aimed to offer. Equinor’s Wisting project in the Barents Sea is the next major yet to be sanctioned project, although it is not likely to provide as strong of economic returns as Equinor’s Johan Castberg project also in the Barents Sea. Wisting does not appear to be a near-term project sanction in 2025 but is a source of potential future demand longer term.

Most of Norway’s E&P capex is directed to brownfield, infrastructure-led projects with high IRR’s and lower cash breakevens. On July 1, 2025, Equinor announced the $1.3B project sanction of Johan Sverdrup Phase 3 in the North Sea, a successful oil project with lower cost expansion capex leveraging existing infrastructure. The drilling contract associated is expected to be awarded later in 2025. Infrastructure-led expansion provides consistent demand with economic returns for the E&P, which have underpinned the recent strength of the Norwegian Continental Shelf.

OSV’s: I recommend reading Misadventures in Shipping for OSV coverage because Ed covers this opaque market very well, as well as other markets. My one take is OSV’s are demanded for many things, notably including PSV’s for multiyear development drilling campaigns. Drilling rigs and FPSO’s need supplies and it will be good for the PSV market as they transport essential supplies from shore when these projects commence beginning 2H26-2027.

Transocean’s debt has outperformed peers like Borr and Shelf, largely due to its stronger contract book, with 2023–2024 fixtures supporting cash flow and deleveraging through 2025–2026. The $655 million unsecured notes due February 2027 rallied ~220 bps in May and remain a key focus, though maturity is over 20 months out. Repayment options exist but may hinge on capital market conditions in 2025–2026.

Transocean has different classes of unsecured debt. In this article, I am only referencing the “priority guaranteed notes”. Transocean also has “legacy guaranteed notes” which are arguably one step further away from the cash flows of certain subsidiaries. Due you own due diligence on the structures.

Contracting Watch Items:

(1) As Transocean’s 7G Skyros (2013) concludes its work in Angola this September for TotalEnergies, it is one of a few warm drillships potentially available for two upcoming contracts in Cote d’Ivoire. (i) Murphy Oil’s three-well exploration campaign from 4Q25 to 2Q26 and (ii) VAALCO/CNRL’s Baobob Phase 5 program set to commence in mid-2026. The two jobs appear to have minimal downtime between them. VAALCO/CNRL is expected to award the rig contract in 2Q25. *EDIT on June 5, 2025* While not yet officially disclosed, Valaris’ recent DS-15 award in West Africa may have been this VAALCO/CNRL job. With most drillship demand expected to pick up in 2H26 and beyond, competition remains high for work commencing in the next 12 months. As a lower-spec 7G unit, Skyros is likely to be bid more aggressively (below $400k) than RIG’s premium fleet provided its eligible for work on these programs given Skyros has only 1 BOP.

(2) In the US Gulf, Transocean has 7G+ Proteus, 7G+ Asgard and 7G+ Conqueror with availability beginning from May 2026 through September 2026. Noble’s Voyager appears to have taken Shell’s work from Proteus, although the US Gulf is a large market with generally steady demand for high specification drillships. Transocean has a fleet of nine (9) high spec drillships in the US Gulf with a good operating history for major IOC’s and E&P’s. There may be some idle time in 2026, although these are marketable drillships that also likely have demand internationally for emerging ultra-deepwater projects. Venus?

(3) On its 1Q25 call, Transocean disclosed its harsh environment semisub Equinox (2016) had two of its options recently exercised at $540k for June 2026-August 2026, representing ~$23mm of EBITDA (estimate). Equinox has an additional dozen options at $540k through September 2027 for work in southern Australia. Transocean also noted 7G+ Asgard on its call regarding future work, although details were not clear.

(4) Future Contracting Watch Item: The proposed “One Big Beautiful Bill” would mandate at least 30 future lease sales in the U.S. Gulf through 2040, lower royalty rates, and streamline permitting. Under the prior administration, offshore lease sales in the US Gulf were frustratingly delayed due to a leasing pause, environmental reviews and legal challenges. While effects would be longer-term, the legislation represents a clear positive for offshore contract drilling, with Transocean poised to benefit most given its significant Gulf presence.

Secured Bonds: As of May 30, 2025, Transocean had $2.07B of secured bonds outstanding, including three single-asset bonds (Poseidon, Titan and Aquila) and one bond collateralized by a portfolio of five deepwater floaters (Pontus, Proteus, Thalassa, Enabler and Encourage). I believe these bonds have very low risk of impairment due to strong collateral and structure.

The rating agencies were lazy and assigned the same B1/B ratings to all four secured bonds, although I believe the 2030s are the strongest credit with a diversified portfolio of rigs in the US Gulf and Norwegian Continental Shelf (NCS).

Transocean’s scheduled debt reduction of $400-$500mm/year is heavily weighted toward paying down secured bonds via scheduled amortization. While the debt reduction is positive, the secured bonds are Transocean’s lowest cost of capital. At time of issuance, these secured bond investors required fairly aggressive amortization to support credit metrics such as Loan-to-Value and Debt-to-EBITDA on single asset bonds with naturally higher idiosyncratic risk.

Transocean has room to optimize the terms on its secured bonds, though meaningful refinancing optionality likely opens in February 2026, when the Titan notes' make-whole call steps down from 104.2 to 102.1. In future secured bond issuances, using multiple rigs as collateral rather than a single asset may be a way to reduce required principal amortization, which currently represents a significant use of cash.

At >5x Debt-to-EBITDA, why are Transocean Titan notes rated B1/B? Titan is the highest-spec drillship globally, equipped with a 1,700 st hookload and dual 20k psi BOPs. With only 1–2 comparable rigs worldwide, it commands strong pricing power. Demand is supported by the growing adoption of 20k psi completions, with at least four operators reaching FID and additional interest emerging both in the U.S. Gulf and internationally.

Chevron’s Anchor project, the first to deploy 20k psi BOP technology, achieved first oil in August 2025 and is producing over 30,000 bpd from its initial wells. On its 1Q25 call, Chevron signaled potential for a Phase 2. Additional nearby prospects and other potential developments across the U.S. Gulf further underscore the area’s growth opportunity.

With few 20k psi-capable drillships and very high upgrade costs, this is not a shale-scale breakthrough in terms of production potential, but it remains a high-return investment for IOCs and E&Ps with strong future potential.

OPEC+ Supply Hike: On May 31, 2025, OPEC+ agreed to raise output by 411,000 bpd for July, totaling a 1.37 million bpd increase since April. While bearish for short-cycle non-OPEC+ supply, deepwater rig demand is generally more influenced by longer-dated futures pricing, given the long-cycle nature of E&P capex.

U.S. shale, with its short-cycle nature, is highly sensitive to spot pricing. As of May 30, 2025, WTI trades at a $2.70/bbl discount to Brent. While shale production can begin within months of investment, deepwater projects typically take several years from FID to first oil demonstrating more sensitivity to futures prices than spot.

The current contango in the Brent curve signals a smaller relative impact on the deepwater market, as longer-dated futures have held up better than spot. While this supports some resilience in deepwater capex, lower oil prices still reduce IOC and E&P cash flows and pressuring budgets. Despite recent oil price weakness, we have yet to see projects pushed back meaningfully as deepwater projects are less flexible than US Shale. We may see a greenfield project face delay depending on how oil trades in coming months, although project cancellations appear quite unlikely as they tend to be some of the highest returning projects to replace IOC’s reserves. Many deepwater projects are brownfield that leverage off existing infrastructure to reduce costs.

In April 2025, the oil market faced bearish pressure from rising OPEC+ supply and heightened recession risks tied to U.S. protectionist trade policies. Since then, while OPEC+ supply has continued to grow, demand concerns have eased as the U.S. has softened its trade stance and signaled willingness to run large fiscal deficits (>6% of GDP), supporting near-term economic growth and demand for crude oil.

High yield credits generally sell-off when recession probabilities increase due to expectations of higher leverage via reductions in EBITDA. Oilfield services credits are some of the first to be sold given their exposure to volatile oil prices (especially if B-/Caa1 rated like RIG unsecured), although Transocean is actually projected to increase EBITDA and reduce debt through 2026.

Consensus analyst estimates (as of 4/29/25) are noted below. Net Debt-to-EBITDA estimates are based upon deleveraging via contracted cash flows, primarily through scheduled amortization on RIG’s secured bonds (~$450mm annually).

2024: $1.15B EBITDA, 5.3x Net Debt-to-EBITDA

2025e: $1.32B EBITDA, 4.3x Net Debt-to-EBITDA

2026e: $1.38B EBITDA, 3.8x Net Debt-to-EBITDA

Unlike short-cycle onshore services, deepwater capex is long-cycle. Contracts are often signed >12 months before drilling commencement. Despite recent weakness in oil markets, Transocean is scheduled to begin new multiyear projects from contracts signed in 2023-2024 with strong dayrates ranging from $465k to $530k (detailed later). Transocean appears set to benefit from positive Dayrate Duration from locked in dayrates on multiyear contracts signed in a stronger market. Deepwater capex is generally not as flexible spend as onshore services, meaning risk of contract cancellations is low considering the strategic nature of the IOC’s projects.

Offshore credit has a bad history. The industry understandably makes many PM’s uncomfortable and Moody’s unsecured rating of “Caa1” does not help although I disagree with their rating. I’ve always operated off requiring >10% returns to invest in oilfield services credits considering the downside potential. Regarding downside, a major difference today vs. ten years ago is the newbuild orderbook is essentially zero. About 4 “stranded newbuilds” still exist, although they were ordered >10 years ago. These stranded newbuild 7G drillships may limit upside in dayrate potential but this is nothing like the impending supply of to-be-delivered rigs we saw in 2015-2017. Since then, a lot of the older, less efficient rigs were scrapped to support a healthier supply/demand dynamic.

RIG Secured vs Unsecured

Secured: Transocean has ~$2B of secured bonds with higher specification assets pledged as collateral. These are generally well-structured bonds with Debt Service Reserve Accounts requiring Transocean to set aside liquidity in Restricted Cash a year ahead of debt payments due. This Restricted Cash account had $428mm at 3/31/25. The secured bonds have meaningful amortization schedules to pay debt back at par and support LTV. In my opinion, these have very low risk of impairment and purchases below par have the benefit of semi-annual amortization payments at par from funds via debt service reserve accounts. The 2030s are secured by five different rigs (three 7G+ drillships in US GoM and two HE semisubs in Norway) and are my preference over the single asset bonds due to collateral diversification.

Unsecured: Transocean has different classes of unsecured debt. My focus is on the Sr. Unsecured bonds (2027s, 2029s and 2031s). RIG also has subordinated unsecured bonds. Additionally, RIG has $234mm of convertible notes due December 2025. Read the indentures and complete your own due diligence on the unsecured structures.

The Unsecured 2027s have $655mm due in February 2027. In September 2024, RIG announced the sale of non-core rigs Inspiration and Development Driller III for ~$340mm in cash proceeds. This sale was presumably to support liquidity for maturities, although the sale was cancelled in late ‘24/early ‘25. RIG is seeking remedies although material risk exists the majority of the $340mm is not collected. Partially offsetting these concerns, Transocean announced on its 1Q25 call that it has identified ~$100mm of cost savings in 2025 and another ~$100mm in 2026 that could support maturing debt. Transocean also has ~$500mm of revolver capacity that could be tapped if necessary (DYODD on terms). Further, while limits exist on ability to raise secured debt in the bond market, the majority of their debt payments are on the secured bonds. As they secured debt pays down, it may open ability to raise new secured debt although DYODD on the bond structures. Transocean has unencumbered, valuable rigs it can use as collateral although debt structure terms may influence access to the secured market. DYODD.

By its nature, high yield debt heavily relies upon successful rolling of maturing debt through refinancing. Based on RIG’s current unsecured debt pricing, the high yield market is not currently receptive of refinancing the maturities. However, various multi-year development drilling projects are scheduled to commence in late 2026/2027 (with more to follow — see my articles on Namibia and Mozambique). Based upon commentary from Noble and Transocean’s calls on April 29, 2025, multiple awards are anticipated to be awarded this summer and more later in 2025. This has potential to improve sentiment and debt service capacity, especially if these are multi-year awards as expected. Depending upon capital markets health in 2026, its reasonable to see successful refinancing via the HY unsecured market before the $655mm is due in February 2027. If you expect the S&P 500 to be 4,500 and crude oil persistently in the $50’s through 2026, RIG unsecured may not be for you.

Transocean will likely have paid down an additional ~$500mm of debt by 2Q26. Further, while nothing is guaranteed in oilfield services, Transocean is likely to make progress contracting its geographically diversified fleet in the next year. Why?

Transocean has a differentiated fleet of high specification deepwater rigs. Approximately 80% of its contracted EBITDA (estimated) is derived from these rigs with an average remaining tenor of ~2.4 years. IOC’s and E&P’s demonstrate a preference for highest spec assets and Transocean’s strong EBITDA backlog is a function of their high quality, differentiated fleet. This is most notable from their 8G Drillships, 7G+ Drillships and Harsh Environment Semisubs (NCS eligible) where their American peers have very limited comparable assets.

8G Drillships: Strong pricing power. Transocean’s 8G Drillships (Titan, Atlas) are among a limited group of three drillships in the world capable of 20k psi completions in the emerging Paleogene play in US GoM. Atlas has earned a firm $635k dayrate (in 2028) and there’s likely upside beyond this longer term.

7G+ Drillships: Before Noble announced on April 29, 2025 it was upgrading two 7G drillships to effectively to 7G+ (hookload), Transocean controlled the 7G+ drillship market in US Gulf of Mexico with seven separate 7G+ drillships. In my opinion, the difference between 7G+ and 7G is not major but is worth a modest dayrate premium and higher utilization.

Harsh Environment Semisubs (NCS eligible): These HE Semis are often referred to as “6G” but these earn 7G type dayrates at better utilization due to short supply and a positive outlook on Norwegian Continental Shelf (NCS) demand. Transocean has seven of these, although after moving two to Australia and one to Romania, only four remain in Norway. Norway has high standards for its offshore drilling rigs and is a high barrier to entry market with strong demand profile through 2030 (at least). Odfjell Drilling is a pure-play on this market, but none of Noble, Valaris and Seadrill have these types of semisubs.

Opinion (DYODD): I believe Transocean’s fleet is industry-leading. It has scale, leading specifications and diversification by capability and geographical reach. While timing of liquidity and access to capital markets is uncertain, I believe the value of the fleet on a through-the-cycle basis comfortably exceeds its outstanding indebtedness. Not my base case, but if capital markets are unhealthy when Transocean needs them and unsecured debt (partially) converts to equity, owning converted equity of a deleveraged company likely has appeal to those constructive on the industry.

Long-Cycle Contracting: Deepwater contract drilling works with long lead times. This is very different from US Shale services that are short-cycle and more flexible capex.

Supporting its projected EBITDA growth, Transocean has various rigs embarking on multiyear contracts at strong dayrates that were announced in 2023-2024:

• Invictus ($485k from April ‘25-April ‘28)

• Barents ($465k from April ‘25-Sept ‘26)

• Conqueror ($530k from Oct ‘25-Sept ‘26)

In addition, Atlas begins $505k dayrate work in May ‘25-Dec’25 with a firm $580k dayrate from April ‘26-Sept ‘26. Further, Thalassa begins $480k from March ‘26-March ‘29. These rigs are all working generally high profile projects, including Barents drilling for Romania’s greenfield Neptun Deep offshore gas project in the Black Sea with additional growth potential in the area (including Bulgaria).

On the negative side, Skyros’ contract with TotalEnergies in Angola ends in September 2025 with likely idle time ahead of it but is a candidate for TotalEnergies’ Kaminho project in Angola after FID in 2024, or perhaps emerging work in Mozambique. Additionally, the Mykonos contract with Petrobras ends in October 2025 although likely finds work again in Brazil but unclear on timing. While Skyros is a “7G” drillship, it’s a lower tier 7G, and like Mykonos, Transocean is not likely to be able to push for rates on it and may instead value utilization on these workhorse rigs similar to its success with Dhirubhai KG1 in India ($347k-$410k through Nov ‘27).

Cash Flows: I recommend you DYODD modeling annual cash flows although consensus analyst estimates expect >$1.3B of EBITDA in 2025 and 2026. Successful execution on revenue efficiency and cost controls will impact ability to achieve these levels, although this EBITDA is generated through in-place, multiyear contracts with generally credit worthy counterparties. Transocean’s annual Net Cash Interest is ~$500mm, Principal Amortization is $450mm-$500mm and Capex is guided below $150mm annually. Working capital fluctuations can be volatile quarter-to-quarter and may be a net use of cash in 2025-2026, although Transocean appears capable of covering its fixed cash uses and paying down debt (Secured) in coming years.

Transocean’s equity does not yet have shareholder returns. The free cash flow from its existing contracts primarily goes to interest and scheduled secured bond amortization. I believe Transocean hopes to enable shareholder returns after further deleveraging through 2026, but until then the bondholders are most the direct beneficiaries of the cash flows from RIG’s industry-leading existing contract book.

Summary Opinion (DYODD): I believe Transocean’s deepwater fleet is industry-leading. It has scale, leading specifications and diversification by capability and geographical reach. While timing of liquidity and access to capital markets is uncertain, I believe the value of the fleet on a through-the-cycle basis comfortably exceeds its outstanding indebtedness. Not my base case, but if capital markets are unhealthy when Transocean needs them and unsecured debt (partially) converts to equity, owning converted equity of a deleveraged company very likely has appeal to those constructive on the industry.

Anadarko’s Windjammer-1 offshore exploration well in 2010 was a play opening deepwater gas discovery in northern Mozambique’s Rovuma basin (Area 1). Eni also made various Rovuma discoveries to the east in “Area 4” from 2011-2014. The large scale LNG potential of these discoveries attracted major IOC’s. In 2017, ExxonMobil acquired a 25% interest in Area 4 (Rovuma LNG) from Eni for $2.8B in cash. In 2019, TotalEnergies acquired a 26.5% interest in Area 1 (Mozambique LNG) from Anadarko for $3.9B in cash. Both IOC’s communicated plans for 13-15 million tons per annum (“mtpa”) for each of their respective projects, with meaningful expansion potential beyond the initial phases.

As of March 2025, neither TotalEnergies (Area 1) nor ExxonMobil (Area 4) have yet to sanction either project primarily due to security issues in the area. Mozambique only produces 3.4 mtpa via Eni’s Coral South FLNG that produced its first LNG cargo in November 2022. Eni appears likely to FID Coral North FLNG later in 2025 which will produce an additional ~3.4 mtpa if sanctioned. The substantially larger land-based LNG projects would not produce its first LNG cargoes until 2029-2030 if sanctioned via current schedule.

IOC’s can benefit from globally diversified LNG businesses as they can react to changes in regional LNG supply and demand conditions. Mozambique is potentially an attractive LNG export hub as it is relatively well-placed to serve demand markets in Europe and Asia with comparable shipping distances. Additionally, the Rovuma basin’s gas composition is said to be “well adapted to liquefaction”. Both TotalEnergies and ExxonMobil have communicated potential development deepwater gas wells are expected to be highly productive. Gas produced by TotalEnergies and/or ExxonMobil would be piped to onshore liquefaction and export terminals, whereas Eni’s production will remain offshore via Floating LNG infrastructure.

Offshore Drilling Rig Market Impact

There’s currently no drillships, semisubs or jackups operating in Mozambique. The discoveries are deepwater and most likely to demand drillships although a semisub may also fit. Jackups are not likely relevant in Mozambique due to the water depth of the discoveries to date. The Saipem 12000 drillship was utilized by Eni on Coral South FLNG a few years ago. Eni’s Coral North FLNG is a potential FID in 2025 and would be the most near-term project commencement although would likely only be a single rig job with less than a two year term. The Mozambique LNG and Rovuma LNG projects are more significant sources of potential drillship demand.

TotalEnergies and ExxonMobil would likely demand 7G drillships for their efficient development drilling on multiyear contracts. While the development drilling is good work for drillships, the resource base is very rich and may limit the amount of development wells needed to be drilled although is still to be determined. As noted in the ExxonMobil presentation below (from 2019), they originally planned an exploration campaign in 2020 although was put on hold due to the global pandemic and the Cabo Delgado insurgency in 2021. As noted in both presentations below, the resource potential exceeds the first potential development phase so there may be potential concurrent exploration and appraisal demand. Development drilling may not commence until 2028 although potential exploration work could begin modestly sooner. Timing will remain sensitive to fragile conditions in the Cabo Delgado region.

Eni’s Coral North FLNG project is smaller in scale but closer to potential FID and commencement. It would be a carbon copy of its Coral South FLNG project that produced its first LNG in late 2022.

Geopolitical Risks in Cabo Delgado

Mozambique’s offshore gas discoveries are ~2,500 km north of the capital in Maputo. While the Cabo Delgado region in the north is resource-rich, this underdeveloped region has been exposed to a deadly insurgency since 2017 that has tragically killed thousands and displaced nearly one million people. The insurgency escalated in March 2021 when terrorists launched a large-scale attack on the coastal town of Palma, known for its proximity to the LNG construction site. Shortly afterward, TotalEnergies declared force majeure to suspend all activities on the project.

In July 2021, the Rwandan army was deployed the region and has played a critical role in stabilizing parts of the region, along with help from other nations. As of March 2025, security conditions in the region have improved and stabilized although remain fragile. Palma appears to be the primary beneficiary of the security protection due to the LNG projects, although other towns in the area are more fragile and a large amount of people remain displaced. There’s still a lot of human tragedy and poor living conditions in the Cabo Delgado region.

Export Credit Agency Financing

In March 2025, the US Ex-Im Bank affirmed its $4.7B financing package on the Mozambique LNG project after its original commitment made in 2019. This was an important step toward potential project sanctioning. Japan, South Korea, UK, Italy, Netherlands and Thailand are among countries with similar export credit agencies that originally committed to the project. The majority of these countries have allegedly affirmed their original commitments as well but there may be 1-2 that have not yet. TotalEnergies has communicated the Mozambique LNG FID is contingent upon export credit agency support which is why the US Ex-Im Bank affirmation was an important development.

While original offshore gas discoveries were made in 2010-2014, the benefits to Mozambique have been limited to date. The Mozambican government established a sovereign wealth fund in 2024 with a primary source of funding from Eni’s Coral South FLNG 3.4 mtpa project that began production in late-2022. The long cycle nature of both deepwater and LNG capital investment stipulates long-lead time positive cash flows. Mozambique and Rovuma LNG is are also true greenfield projects which require time. Eni’s potential Coral North FLNG project may begin production sooner, although the largest sources of production tax revenues for Mozambique would be beginning in 2029-2030 from onshore LNG export facilities (3-4x larger than Eni’s FLNG projects). An ideal long-term outcome would be materially improving living conditions living in the region funded via production taxes although remains to be determined.

Emerging/Frontier Market Credit

Mozambique’s (Caa2/CCC+) fiscal crisis stems from the Tuna Bonds scandal, where $2 billion in secret loans—partly embezzled—led to debt default, currency depreciation, and loss of investor confidence. The country remains heavily indebted, with much of its budget tied to debt repayment rather than development. Legal wins have helped recover some funds, but borrowing costs remain high, limiting economic growth. In December 2024, the country’s top court affirmed the victory of the ruling party (Frelimo) after its October elections. The capital city of Maputo experienced violent and deadly protests that lasted months after the election. As of March 2025, security conditions in Maputo have since improved although the protests are a reminder of the country’s lack of stability.

Mozambique’s sovereign bonds trade at levels that indicate distress. The 2031 maturity bonds have a 13.4% yield to maturity (March 2025) and demonstrate the high cost of funding. In addition to natural gas resources, Mozambique is also a meaningful miner of rubies. Due to the long-cycle nature of deepwater and LNG (and security challenges), Mozambique’s natural gas discoveries only produce over 3 million tons per annum of LNG export cargoes as of 2025. If the Mozambique LNG and Rovuma LNG projects are sanctioned, LNG production may increase by as much as 28 million tons per annum. While other factors will influence Mozambique’s sovereign debt valuations, improved security conditions and the sanctioning of these LNG projects in Cabo Delgado would be materially positive for the country’s economy.

In October 2024, TotalEnergies sanctioned the GranMorgu (Block 58) deepwater oil project in Suriname (Caa1/CCC+). Suriname’s 2051s are structured differently but rallied from the low-to-mid 80’s to above par points when confidence grew regarding the GranMorgu project sanction. As the result of a prior restructuring, the Suriname 2051s also include a value recovery instrument, or more of a direct claim on oil royalties so would be more sensitive to the project sanction than Mozambique’s sovereign bonds, all else equal.

Mozambique is an important follow for the deepwater rig, LNG and OSV markets. It’s potential impact is material although the range of potential outcomes are wide and include potential for further delays depending upon geopolitical developments. ExxonMobil has recently stated a potential FID on Rovuma LNG could be announced in 2026. TotalEnergies has noted sensitivity toward further export credit agency support and may have a similar timeline as Exxon regarding a potential project sanction.

In the first half of 2022, when Brent crude oil prices exceeded $100 per barrel, Saudi Aramco initiated tenders for additional jackup rigs to support its capacity expansion from 12 million to 13 million barrels per day (bpd). Aramco had produced up to 11 million bpd that year. This expansion increased the shallow water jackup rig count from the low 50’s to approximately 90 rigs, representing 9–10% of total active supply. Coupled with rising global demand elsewhere, Aramco’s program significantly tightened the jackup market, driving dayrates from below $100,000 to the upper $100,000s by late 2023.

In response to weaker oil prices, during the first quarter of 2024 Saudi Arabia’s Minister of Energy directed Aramco to maintain capacity at 12 million bpd, effectively reversing the incremental demand for 9–10% of the global active jackup rig supply. Consequently, Aramco announced multiple rounds of jackup rig suspensions, expected to offset nearly all demand growth tied to the 13 million bpd expansion program. While most suspensions have been disclosed, a few additional rigs may still receive suspension notices. It’s unlikely this demand returns until crude oil prices are meaningfully higher given Saudi Arabia’s existing spare capacity appears more than adequate.

The jackup rig suspensions released a significant number of rigs into the market within a short period. While some have been re-contracted, many are still seeking work in various regions. Unlike the floater market, the jackup sector is more fragmented, with smaller players contributing to competitive bidding and potential dayrate pressure. The market is still absorbing this supply with further price discovery on dayrates and margins ahead.

Deepwater floater demand has experienced delays for multi-year development drilling projects, but no project cancellations or rig suspensions. Deepwater E&P capex tends to be longer-cycle with longer lead times than shorter-cycle projects demanding jackup rigs. Additionally, while all deepwater projects are unique, most of them work with Brent at $65 and futures curve hedging allows IOC’s to look in these prices.

The credit markets are demonstrating a more constructive on deepwater floater demand outlook. Idle time for 2025 is a reality but we’ve had positive news from Sub-Saharan Africa regarding future multi-year drillship demand from Cote d’Ivoire, Nigeria, and Mozambique in recent weeks. Slow emergence in West Africa has been a problem for 7G drillship demand in 2025 but recent weeks have provided “green shoots” of future demand in this important market.

• Cote d’Ivoire: Some optimism exists that Deep Value Driller (7G drillship) may extend work in Cote d’Ivoire when its current program completes. In addition to Eni’s potential appraisal work on the Calao discovery of 2024 (and longer term Baleine Phase 3, Murphy has a three-well exploration program in the country to begin late 2025 and VAALCO has a development drilling program with 2026 commencement. Murphy’s upcoming exploration program will be a key follow.

• Nigeria: TotalEnergies out with tender for work in Nigeria as soon as 1Q 2026. Other major IOC’s have development projects in Nigeria that likely have commencements in 2026-2027 although timing is uncertain.

• Mozambique: This week TotalEnergies’ Mozambique LNG project received approval on external financing, an important step in a long-awaited potential FID. ExxonMobil’s Rovuma LNG project is also a potential FID in 2026. Security conditions have improved in the Cabo Delgado region. This is a potential multi-drillship market.

A key catalyst to watch for the drillship market will be potential project awards with multi-year terms, particularly in Africa, East Med and SE Asia. Dayrates are obviously a key follow, but contract term will be very important. While idle time is a problem in 2025, the delays are for multi-year drilling projects that should reduce future idle time concerns.

While we likely see more scrapping of floaters in 2025-2026, this is expected to be relevant to mostly lower tier rigs which is not expected to include warm 7G drillships. Not immune to idle time in 2025, 7G drillships are efficient offshore drilling rigs that remain in demand as evidenced by recent optimism tied to Deep Value Driller’s contracting outlook in Cote d’Ivoire along with Saipem’s potential purchase option of $300mm for the rig.

Saipem’s purchase option of $300mm will be a key watch for valuation purposes, although Saipem’s proposed merger with Subsea7 may complicate exercising this purchase option. Importantly, Deep Value Driller is a very similar 7G drillship to some 7G’s in Valaris and Noble’s drillship fleet.

The secured jackup bonds have meaningfully wider credit spreads than Transocean unsecured debt, mostly a reflection of (i) relative weakness and/or uncertainty in jackups tied to the Saudi rig suspensions, (ii) this 9-10% of total active supply’s leverage to sustained >$85 Brent prices if/when Saudi Aramco seeks to grow capacity, (iii) Transocean’s strong contract backlog that supports visible deleveraging through 2026 and (iv) concerns tied to Pemex and its jackup demand and payments. Further, Valaris, Noble and Seadrill bonds are all trading well showing support for deepwater floater outlook. Transocean’s secured bonds have traded resiliently thus far, although unsurprisingly the unsecured bonds have sold off a few points in recent weeks as PM’s de-risk on energy credits on recent oil price weakness especially considering Moody’s “Caa1” rating on RIG unsecured debt (whether you agree or not).

Jackups work on shorter cycle projects and while Borr has some rigs contracted into 2026, the driller’s 2026 contract book fairly open. Accordingly, Borr’s contracting for 2026 will be a key follow in coming quarters. On its 4Q24 conference call, Borr noted leading edge benign environment jackup dayrates were in the $120k-$130k range although also noted a recent $150k award in West Africa. Borr’s jackup fleet is high quality although the current market is competitive in benign jackups.

The chart above implies a linear relationship to Borr’s full year EBITDA based on market dayrates (EBITDA = 8.34*(dayrate) - 519.8) with an assumption of 95% utilization. Considering the amount of supply that has hit the jackup market from Saudi rig suspensions, an 85% utilization rate may be more appropriate to underwrite.

Borr’s fixed uses of cash include approximately $400mm/year of capex, cash interest and principal amortization. While an estimate subject to other variables, Borr needs dayrates of approximately $115k/day at 85% utilization to cover fixed cash uses in 2026 (~$400mm EBITDA). It may need higher dayrates to support its current dividend. This also assumes cash collections which have been a challenge recently with Pemex in Mexico. In its February 2025 fleet status report, Borr noted five of its jackup rigs were utilized by Pemex in Mexico making this a relevant watch item on Borr’s cash flows and liquidity (EBITDA does not equate to cash collections). Borr recently did a good job on a recent factoring arrangement to support cash collections from Pemex A/R. While the fallout from the Saudi jackup rig suspensions may be beyond its control, I believe Borr has a good management team. More work to be done.

Borr’s secured notes have structural protections, including but not limited to, a cash sweep and required ~7% annual amortization at par. Given the Borr secured bonds trade below par, the required semi-annual amortization at par is a nice protection for bond investors buying the debt below par (current dollar price is ~94). Borr also has a $150mm super senior revolving facility.

Shelf Drilling Holdings’ secured bonds traded at the widest credit spreads, likely due to its older jackup fleet. While Shelf has some good term on its jackup rigs (including its older rigs), it arguably has more exposure to higher crude oil prices longer-term given its fleet. The Shelf North Sea bonds are secured by premium harsh environment jackup rigs which are more immune from the Saudi rig suspensions.

There is no denying offshore credit has a poor history. I’m very aware of it from my experience in 2015-2016. Some investors will never find this industry attractive and that is respectable. However, the major difference in today’s market vs. the peak distress in 2016 is the orderbook is substantially better than it was in the last cycle which should be supportive for quality assets. Buying offshore bonds at or near par exposes investors to downside risk in a volatile industry, although the lack of new supply entering the market will provide support unlike in the last cycle when the story was the exact opposite.

CEO’s in the rig industry love to see competitors scrapping their capacity so this is a biased view but Norwegians know the offshore drilling industry as well as anyone. The global rig market has some lower tier rig capacity that can be reduced while saving drillers meaningful funds on warm stacking costs without materially impacting Net Asset Value calculations. I don’t think the industry needs a lot of scrapping, but there’s maybe ~10% of global floating rig supply that can be reduced given the efficiency of 7G drillships.

SpareBank 1 Markets Offshore Drilling Panel (March 2025): Panel discussion begins at 32:30

(High level takeaways for those that don’t have time to listen)

Norway Harsh Environment Semisubs: This is the exclusive country club of offshore drilling. Dues are expensive but it is a high barrier to entry market due to strict Norwegian standards on drilling rigs. Norway E&P capex looks good through the end of the decade. This is a high utilization market with good dayrates for years to come. Odfjell is a 100% pure-play on these semisubs. Transocean has an underappreciated fleet of seven (7) Norway capable semisubs, although three are international. Northern Ocean is also a pure-play UDW HE Semisub driller with Bollsta and Mira although is still working on improving its balance sheet (progress has been made lately).

Drillships: Waiting on multi-year development projects with commencements in 2026 and beyond leading to 2025 idle time. Waiting on FPSO deliveries and subsea equipment. While Norway E&P’s are in reserve replacement mode, some larger IOC’s are also focused on shareholder returns at this stage. Unfortunately, 2025 will be soft for new project commencements but 7G drillships are key ingredients to FID’s and do not need Brent prices above $75/bbl to support IOC capex.

Jackups: These shallow water rigs are more sensitive to high oil prices than most realize because of how meaningful Saudi Aramco demand has become to jackups. More to come on Borr and Shelf high yield credit analysis as their debt has traded poorly in recent weeks.

Offshore Supply Vessels: Not discussed on the panel but a key to watch for OSV’s will be rig scrapping activity in 2025. OSV’s do a lot of things but servicing offshore drilling rigs is meaningful business for them, particularly PSV’s. If there are fewer active rigs in 2026 and beyond, it may pressure OSV rates and utilization. Stay tuned.

Underwriting Noble’s ~8.1% Dividend Yield

Noble’s equity dividend yield of ~8.1% now exceeds the YTM on its 8% coupon high yield bonds due 2030 (~7.8%) trading modestly above par. I have no financial interest in Noble although as a bond investor, Noble’s dividend gets my attention because it is fundamental cash flow that can be underwritten like debt service on a bond. Investors naturally question the sustainability of dividend yields this high, although Noble’s existing contract book appears capable of sustaining these dividends. DYODD.

The strength of Noble’s fleet includes fourteen (14) 7G drillships, a nice portfolio of jackup rigs and few semisubmersibles. That’s where the majority of its Net Asset Value is attributed. Their fleet also has two (arguably obsolete) Globetrotter drillships, as well as two older generation semisubs uncontracted after Aug ‘25 they acquired as “throw-ins” via the Diamond acquisition in 2024. Noble also maybe has another spare semisub (none are eligible for Norway) and a jackup rig or two they’d prefer to keep long-term, but are possible scrapping candidates if no long-term contracts are attainable. Analysts modeling earnings at the rig-level hate the idle time because its warm stacking costs are meaningful, arguably ~$30mm of annual negative cash flow per warm rig. I believe Noble can save ~$100mm/year of warm stacking cash costs scrapping some of its lower tier fleet while having minimal impact on its Net Asset Value.

Due Your Own Due Diligence: The EBITDA bridge below is my Downside case for Noble and assumes minimal new contracting. Importantly, Noble’s high yield debt does not require principal amortization which provides meaningful cash flow support for the dividend. Absent working capital fluctuations, Noble appears capable of covering its dividend with minimal new contracting although cash savings via scrapping warm, idle rigs may be needed in 2026 considering ~$878mm of projected cash uses via capex, interest and dividends.

Will Noble achieve consensus EBITDA estimate of ~$1.3B in 2026? I believe scrapping a few lower tier assets would likely help although the big question is tied to the timing of demand. Noble may win some multi-year development drilling projects that commence in 2026, but the first full year of EBITDA contribution may be 2027. These projects may be awarded in 2H25 so visibility toward that $1.3B level maybe become available in coming quarters. Noble’s four 7G drillships working for Exxon in Guyana through at least August 2028 have a frame agreement subject to market-based repricing twice a year, making market level dayrates relevant to future EBITDA realization.

Noble’s unsecured HY debt due 2030 (~7.7% YTW) does not require principal amortization payments. While Noble would likely need better clarity on contracting before engaging in buybacks, the driller announced an additional $400mm buyback program in November 2024. Noble is arguably more incentivized to scrap idle rigs to save on warm stacking costs given its potential to buy back equity at low valuations, as opposed to some other drillers that would otherwise use the cash flow savings to pay back debt at par (no discount). Offshore drilling is a volatile industry and Noble does have ~$2B of debt which it can service, but buybacks are likely more prudent if/when contracting progress is made on rigs for 2026 and beyond.

Flattening Futures Curve: As the oil market has become concerned about 2025 supply with the likely addition of modest OPEC+ supply growth, the Brent futures curve has flattened with spot dropping materially more than futures prices. If supply overwhelms demand, the curve most likely shifts into Contango where futures prices exceed spot. In Contango, flexible, short-cycle shale barrels likely reduce with long cycle barrels from Deepwater less impacted from potentially oversupplied markets in 2025, although sensitivity to longer-term futures pricing remains.

In 2015-2016, short-cycle US Shale barrels could grow with IRR’s >10% with WTI in the mid-$50’s. USA’s Permian Basin began its growth trajectory in 2017 when WTI was in the $50-$60/bbl range and accelerated in 2018 when WTI was in the $60’s and low $70’s. These short cycle barrels crowded out demand for deepwater projects at the time. The days of Permian growth with WTI in the $60’s are most likely over although it’s not a stretch to envision Permian growth with WTI above the mid-$70’s. Also, deepwater project costs have reduced meaningfully over the last decade and are arguably barrels that will challenge shale production as the lower cost barrels in future years.

OPEC+ Supply Growth

OPEC+ stated this week its “gradual (production) increase may be paused or reversed subject to market conditions…to support oil market stability”. This is a materially different statement from the aggressive price war announced in November 2014 which caused excruciating pain in following years for the oilfield services industry in both shale and offshore. However, all else equal, the additional barrels from OPEC+ pressure crude oil prices in 2025 although many variables are at play in the volatile oil market. How USA handles Iran regarding sanction relief under a different administration will be a key to watch in global oil markets. Additionally, the Federal Reserve Bank of Atlanta’s GDPNow estimate for USA GDP in 1Q25 is -2.4% as of March 8, 2025. While inventory swings can lead to quarter-to-quarter GDP volatility, if the USA reduces the fiscal stimulus it provided via deficit spending to cushion the blow from monetary policy tightening in 2022-2023, it may pressure oil demand in the short-term. I remain positive on the long-term outlook for offshore energy production although oil price sentiment may be choppy in 1H25 depending on how global supply and demand markets play out.

Equity markets are wary of idle drilling rigs, seeing excess downtime in 2025 models. In contrast, credit markets remain stable, with deepwater drillers’ high-yield debt well bid due to a longer-term investor outlook. However, oilfield service equities, driven by earnings momentum, face consensus expectations of a soft 2025 for rigs rolling off contract.

While consensus seems to exist on a soft 2025, debate exists on how 2026/2027 is shaping up for demand. Outlooks for 2026 and beyond vary meaningfully by market across the globe.

US Gulf of Mexico: New project commencements will be very light in 2025, so drillships rolling off contract in 2025 face a high probability of idle time. However, this is an infrastructure-led capex market with good visibility into 2026 so this should not be persistent idle time unless a lower tier rig (i.e. Noble’s Globetrotter rigs).

Norway: This midwater/deepwater semisub market is doing just fine with very stable E&P demand from infrastructure led capex through the end of the decade. Equinor, Var Energi and Aker BP made this very clear a month ago. Odfjell has a great UDW HE Semisub niche in Norway.

West Africa: This is the market where demand has been slow to materialize. Nigeria has an inventory of multiple IOC projects with term in coming years, including Shell’s recently sanctioned Bonga SW. Exxon, Chevron and TotalEnergies also have projects with multiyear term potential. However, timing is uncertain on these projects. Côte d’Ivoire is country to watch with two projects likely in late 2025-2026 (Murphy, VAALCO/CNRL) along with long term potential with Eni’s Baleine (Phase 3 likely FID in 2025) and Calao (more prospective).

West Africa remains a wildcard, but subsea leader TechnipFMC stated this week it expects stronger-than-anticipated offshore demand in this region. This will be key for 7G drillship demand.

Geopolitics Matter in Offshore: In oilfield services, U.S. shale relies on short-cycle, price-sensitive capex, while deepwater operates on long-cycle capex with more influence from geopolitics due to its global nature.

East Mediterranean coming back to life? This was a growth area for deepwater gas production but slowed down as war broke out in the region in late 2023. Importantly, this region has existing infrastructure to leverage with recent discoveries Deepwater drilling activity has increased in Egypt and Cyprus in 2H24 with five rigs working recently in the East Mediterranean region. Chevron’s Leviathan gas project in Israel has expansion prospects in a few years. Libya also has off potential as well. After a quiet first 2-3 quarters in 2024, the East Med region could be some demand to keep rigs in this region with term.

Indonesia’s Kutei Basin took a step forward this week as Eni and Petronas announced MOU for a partnership on developing recent gas discoveries (Geng North). Infrastructure led investment with meaningful exploration upside with apparent government support. There’s also been other discoveries in Indonesia’s Andaman Sea which would be more greenfield developments with longer time horizons but were impressive recent gas discoveries.

India: Activity has increased in recent quarters, as India seeks energy security from offshore sources to support its economy’s needs. ONGC, Reliance and Oil India have likely rig demand in this emerging region. After formally announcing E&P capex growth plans, BP may also have potential in the country.

Mozambique: The Cabo Delgado region has substantial deepwater LNG potential although instability in the region has slowed this development. The region has stabilized thanks to support from the Rwandan army. As geopolitical risks reduce in the region, FID potential increases after cautiously optimistic references on recent conference calls.

Colombia: The recent Sirius gas discovery highlights growing offshore potential, with Petrobras as a partner. Colombia's domestic production has declined due to unfavorable political conditions since 2022, although prospects appear likely to improve in the 2026 election. This is potentially late 2027-2028 demand.

Eni stated at its Capital Markets Day on Thursday the development of Cronos in Cyprus’ Block 6 will tie into Zohr’s existing infrastructure, which has additional capacity, enabling a fast-tracked, capital-efficient solution. An agreement between Cyprus and Egypt facilitates this development, initially addressing Egypt’s critical gas shortages while also supporting potential export opportunities to the European LNG market longer term. Egypt faced severe gas shortages in 2024 due to declining domestic production, leading to energy blackouts and reliance on costly LNG imports. Production at the Zohr gas field, which began in 2018, declined due to deferred reinvestment caused by delayed payments to IOCs. However, financial support from the IMF, EU, World Bank, and UAE in 2024 helped Egypt resume payments, revitalizing investment in gas production.

Cronos was a pleasant surprise of an announcement at Eni’s Capital Markets Day this week. In February 2024, the Cronos-2 appraisal well confirmed the lateral extension of the Cronos-1 discovery in August 2022. This has a net reservoir thickness of 115 meters and the production test “confirmed an excellent gas deliverability of the well.” Two additional discoveries, Calypso-1 (2018) and Zeus-1 (2022) were made on the same block. Cyprus is a high potential deepwater gas market and its access to Zohr infrastructure in Egypt helps accelerate its development.

Greenfield Demand for 2028 and Beyond: TotalEnergies’ Venus project in Namibia is a potential FID in 2026, but is not the only greenfield project in the country. Galp’s Mopane exploration and appraisal program is arguably the most exciting of its kind in the world. In 2022-2023, a former Galp executive described PEL 83 as “the best zip code” in offshore Namibia. After the first five wells, it has delivered.

Galp announced very good Mopane-3X results this week and a few days later announced a share buyback program. In April 2024, Galp announced 10B boe in-place estimate after its initial Mopane-1X and Mopane-2X wells. Distinct from other offshore discoveries in Namibia, Galp has consistently communicated the discoveries demonstrating high pressure, good porosity, good-to-high permeability. Permeability was a challenge with Shell’s write-down in 2H24.

Mopane-1A confirmed the extension and reservoir quality of AVO-1. This increased FID probability to high.

Mopane-2A tested primarily AVO-3 which was described as high quality reservoir characteristics but as “gas condensate”. We are trying to find the oil window so while this gave good info, not likely an early FID.

Mopane-3X tested a separate development area 18 km to the southeast. It tested two separate targets that yielded positive results. AVO-10 is significant column of light oil and gas condensate. AVO-13 is light oil but apparently smaller. The reservoir log measures confirm “good porosities, high pressures and high permeabilities”. This has good potential for being a second FPSO development although requires appraisal.

Galp seems to have focused its early exploration wells on targets with multiple AVO’s. It has not yet provided reservoir thickness in its public disclosures. Eni disclosed at its Capital Markets Day that Rhino’s Sagittarius-1X well was 90 meter gross thickness, a strong measure. Given its proximity to Galp’s block, it’s a potential read into Mopane but given the strong reservoir characteristics they don’t need to be as thick as 90 meters to justify development. Galp is focusing on testing extensions rather than targeting sweet spots, aiming to hit two AVOs per well to maximize seismic insights while maintaining capital efficiency.

Namibia is often compared to Guyana on its greenfield potential. Namibia has yet to have its first FID announcement, although is tracking positively on that with TotalEnergies (Venus) and Galp (Mopane). With Mopane-3X results, Galp may have found its second FPSO project within 14 months of initial discovery which is ahead of ExxonMobil’s schedule which took 18 months with its Payara discovery in Guyana. More appraisal drilling will be required.

Namibia is a greenfield deepwater market with meaningful sustained development drilling potential for multiple rigs, although potential project commencements would likely not occur until 2028. If they occur, the could really swing the rig market positively with demand. Until then, the Orange Basin is likely an exploration and appraisal market with shorter-term fixtures although there’s a lot of prospects to drill including potential work in South Africa for 2026.

The valuation difference between a warm and cold drillship is substantial given cold reactivation costs of $125-$200mm and operator preference for warm rigs with track records (Meltem never drilled). Meltem’s value to Noble was mostly long-term option value, although cannibalizing her for parts has benefits. Large drillers like Noble can make use of Meltem’s parts and inventory, which has modest cost savings estimated between $15-$50mm but can also be leveraged to minimize warm fleet downtime by recertifying spare parts. Cannibalizing Meltem may also have benefits for the warm fleet’s 10 and 15 year special periodic surveys.

Noble’s 7G drillships Stanley Lafosse (fka Sharav) and Faye Kozack (fka Khamsin) share similar equipment and design with Meltem, as do four (4) other drillships with a similar design. Noble’s Scirocco is also similar to 6G drillship, Gerry de Souza (fka Santa Ana).

While Noble had one cold stacked 7G drillship, Transocean has three cold 7G’s in Greece today from its acquisition of Ocean Rig and its ~8 drillships in 2018. Today, four of these are operating in Brazil and Angola with three coldstacked 7G drillships in Greece since 2016-2017.

After inheriting a distressed loan portfolio of oilfield services borrowers 2015, I have taken a keen interest in following the former Ocean Rig drillships over the last decade. While Seadrill Partners and Pacific Drilling also had 1st lien loans in the broadly syndicated loan market at the time, the majority of my time was spent on the two Ocean Rig secured loans noted below.

Ocean Rig filed for Chapter 11 bankruptcy in 2017 and Transocean acquired the assets in 2018. Four of these drillships have worked in Brazil and Angola and three of the 7G drillships acquired have remained coldstacked into early 2025. These cold 7G drillships are Mylos, Athena and Apollo (collateral on a separate loan).

In 2016, I assumed these drillships could potentially reactivated by 2021-2022 with dayrates around $400k. In 2023, momentum was building toward reactivation however this began to die down in 2024 due to slower to materialize demand in West Africa and elevated reactivation costs. Full reactivation costs of a coldstacked drillship may be $125-$200mm when including important upgrades such as MPD ($30mm). IOC operators are unlikely to fund this out of their own pocket without taking a significant equity stake in the ship. Reactivation possibilities have gradually reduced, particularly as these drillships approach 10 years of ide time.

A meaningful difference also emerged in recent years. Compared to the environment when many 7G drillship orders were made in 2013-2014, major oil companies have reduced capital expenditures in favor of shareholder returns. Accordingly, the deepwater fleet was heavily rationalized in 2016-2020, although may have a few more to go given IOC/NOC shareholder return preferences.

Noble’s decision to retire Meltem is a signal that other coldstacked drillships may have more value to warm fleets through cannibalization and removing them from the drilling fleet (retiring supply). Cannibalizing cold stacked 7G drillships for spare parts and inventory for the warm fleet’s use can save money. Value can be realized by recycling parts and through more efficient recertification processes to limit downtime. Many of these drillships produce ~$250k/day in free cash flow so reducing downtime matters.

IOC’s have not been expanding their balance sheets to accommodate growth capex. While most of them have positive outlooks on future deepwater FID’s with growing capex allocations to deepwater, further fleet rationalization on higher cost, coldstacked 7G’s would be beneficial to the drillship market long-term.

Potential remains for Transocean reactivating at least one of its coldstacked 7G’s, however there’s 4-5 drillships that would be activated before Mylos, Athena or Apollo which is years away. Reactivating any of these cold drillships also introduces more supply to a market placing pressure on dayrates. Retiring the cold 7G fleet constrains future supply and benefits long-term dayrates and utilization.

While a Transocean/Seadrill merger is only a RUMOR, Transocean’s cold 7G drillship fleet arguably has unique value to Seadrill. Mylos, Athena and Apollo have the same Samsung 12000 design as Seadrill’s seven 7G drillships along with having very similar NOV equipment. As Seadrill’s fleet approaches various 10 and 15 year SPS’s, cannibalizing Transocean’s cold 7G’s could reduce capex, reduce downtime and extend the lives of the Seadrill 7G drillships. Transocean’s fleet has limited matches beyond Skyros.

While cannibalizing at least a portion of Transocean’s cold 7G fleet does not provide the attractive, direct returns as reactivation, the potential benefits to Seadrill’s fleet may help facilitate a merger that would bring (i) $75-$100mm of annual synergies, (ii) accelerate Transocean’s deleveraging and potential shareholder returns and (iii) improve LT cash flows of Seadrill’s 7G fleet.

Why would Seadrill shareholders accept a merger proposal from Transocean? The benefits of scale and fleet diversification are good places to start, although Transocean has three separate classes of deepwater floating rigs that have earned >$500k dayrate awards in 2024 of which Seadrill has no comparable assets. The 8G drillships capable of the 20k psi completions in the US GoM are very unique, high specification assets that have been awarded >$600k dayrates. Transocean’s 7G+ drillships and Norway eligible harsh environment semisubs all have strong utilization rates.

While Seadrill does not have any warm comparable assets to the Transocean floaters noted above (after cold stacking West Phoenix), Valaris and Noble do not have any 8G, 7G+ or Norway eligible harsh environment semisubmersible rigs either. Transocean also does not have much standard 7G drillship (1,250 st hookload capacity) presence in Brazil and West Africa, which Seadrill’s existing warm fleet would provide in any potential merger.