Suriname's Offshore Oil Discoveries Spark Global Interest

By Felicity Bradstock - Nov 07, 2024

Suriname's recent offshore oil discoveries have attracted significant investment from major international oil companies.

TotalEnergies is leading the development of Suriname's Block 58, with a focus on low-carbon oil production.

Suriname's government is committed to responsible fiscal management of its oil resources, ensuring long-term economic benefits for the country.




The small Caribbean country of Guyana has caught most of the world’s attention for the rapid development of its oil and gas resources, but its lesser-known neighbour – Suriname, is also a rising star in the world of oil and gas. Several oil majors have signed agreements to expand exploration in Suriname and expect to see huge oil and gas output as early as the 2030s. The fossil fuel development in Guyana and Suriname is expected to propel the Caribbean region to become a world leader in oil and gas in the coming decades.

Suriname is South America’s smallest country in terms of both size and population, however, it has significant potential to become a major international energy power and grow its economy substantially in the coming years. Until recently, Suriname’s oil production was dominated by state-owned Staatsolie’s onshore activities, with an output of around 17,000 bpd. However, offshore oil discoveries made in late 2019 and 2020 have helped garner the interest of several oil majors.

In 2021, Suriname’s government licensed offshore blocks for the first time, which resulted in the signing of production sharing contracts (PSC) with Chevron and QatarEnergy. In May 2023, Suriname finalised a 30-year PSC between Staatsolie, TotalEnergies, and QatarEnergy for the two neighbouring blocks 6 and 8. Staatsolie holds a 40 percent share in the blocks through its subsidiary Paradise Oil Company. The first phase of exploration is expected to take around six years.

As seen in the case of Guyana, most international oil majors are looking to solidify the future of their oil and gas activities. Several of the world’s most famous oilfields are gradually being depleted, following decades of production. In addition, many existing oil operations are extremely carbon-intensive, at a time when governments are putting pressure on companies to decarbonise. Numerous oil and gas companies are, therefore, pursuing oil projects in emerging oil regions, such as Africa and the Caribbean. Developing operations in these regions could ensure the longevity of their crude production, as multiple countries have been found to hold massive untapped oil reserves. It also provides them with an opportunity to develop lower-carbon oil operations.

In October, France’s TotalEnergies announced $10.5 million in investment to develop a giant oil project in Block 58 around 140 km off the coast of Suriname. The construction and installation phases are expected to take around four years, with the potential for the oilfield to open around 2028. Suriname’s offshore Gran Morgu field has estimated recoverable resources of 700 million barrels of oil equivalent. The field is adjacent to Exxon Mobil's giant 11-billion-barrel discovery in neighbouring Guyana.

TotalEnergies aims to decarbonise operations in Block 58 by incorporating new technologies into its activities. For example, it will use an all-electric floating production, storage, and offloading (FPSO) unit, optimised power usage with a waste heat recovery unit, and optimised water cooling for improved efficiency. The firm has also stated it will not flare gas and will reinject associated gas into the reservoirs. In addition, it will install a permanent methane detection and monitoring system to spot leaks.

Suriname and neighbouring Guyana could provide competitive LNG supplies from early next decade, according to a recent report from Wood Mackenzie. The report states that two countries could deliver up to 12 million metric tonnes per annum of LNG by the 2030s. Guyana's Haimara cluster and Suriname's Block 52 (Sloanea) are estimated together to hold 13 trillion cubic feet of discovered non-associated gas.

In September, Staatsolie signed a memorandum of understanding (MoU) with Brazilian state-owned oil and gas giant Petrobras to deepen their energy cooperation. The two powers are expected to work together in the exploration and production of hydrocarbons, carbon capture and storage, renewable energy, the exchange of knowledge and expertise, and contingency response planning and execution. Meanwhile, this November, Norway’s subsea services provider Argeo announced it had entered into an eight-year data agreement with Staatsolie, for the acquisition, processing, and sales of multi-client data in Suriname.

Suriname expects its oil and gas industry to grow rapidly thanks to impressive discoveries in recent years and several new deals with international oil majors. Staatsolie believes Suriname’s new oil activities could bring in as much as $26 billion once developed. However, in October, Suriname’s Minister of Finance and Planning of Suriname, Stanley Raghoebarsing, stated that the country would not be borrowing more money against future oil production. Raghoebarsing said the country is not considering loans that are guaranteed by those revenues. He stated, “In no way do we want to pre-sell oil that we still have to lift, and collateralise that for easy money that will burden the next generation.”

Although Guyana may have attracted more attention in recent years, Suriname has been steadily expanding its oil and gas operations, with great optimism for new exploration projects in collaboration with international oil majors. The development of its offshore reserves could see the small South American country quickly become a major international oil producer, supported by huge investments from the likes of TotalEnergies and QatarEnergy.

By Felicity Bradstock for Oilprice.com

Suriname is located in northern South America. Suriname is bordered by the Atlantic Ocean to the north, French Guiana to the east, Guyana to the west, and Brazil to the south.

TotalEnergies Starts Natural Gas Production From Argentinian Offshore Field

By Tsvetana Paraskova - Sep 20, 2024

French supermajor TotalEnergies announced on Friday the start of natural gas production from the Fenix gas field offshore in southern Argentina.

The Fenix field has been developed to have a production capacity of 10 million cubic meters per day, or 70,000 barrels of oil equivalent per day, (boe/d). The field, 60 km (37 miles) off the coast of Tierra del Fuego in Southern Argentina, consists of a new unmanned platform and is connected to the existing facilities at the Cuenca Marina Austral 1 (CMA-1) concession, which TotalEnergies operates.

The natural gas produced at Fenix is sent through a subsea pipeline to the TotalEnergies-operated Véga Pléyade platform and is subsequently treated onshore at the Río Cullen and Cañadon Alfa facilities, which are also operated by the French company.

According to TotalEnergies, Fenix is a low-cost, low-emissions development, with a carbon intensity of 9 kg CO2e/boe, which uses existing infrastructure.“Fenix will contribute to maintaining our gas production plateau in Tierra del Fuego and ensure a reliable supply to the Argentinean gas market,” said Javier Rielo, Senior Vice President Americas, Exploration & Production at TotalEnergies.

“With its low break-even and low carbon intensity, Fenix perfectly matches the Company's low-cost and low-emission strategy,” Rielo added.

TotalEnergies has been operating in Argentina since 1978, and has interests offshore, onshore, and in the Neuquen province, home to the Vaca Muertra shale.

Argentina plans to raise oil and gas output and exports from Vaca Muerta in the coming years.

Supertankers could begin docking in Argentina to load oil from the country’s shale patch after a pipeline is set to connect Vaca Muerta with a terminal at Punta Colorada port capable of handling the so-called very large crude carriers (VLCCs).

Argentina is also moving a step closer to exporting LNG and monetizing its huge resource in Vaca Muerta after maritime LNG infrastructure firm Golar LNG signed a 20-year deal with Pan American Energy (PAE) for the deployment of a Floating Liquefied Natural Gas (FLNG) vessel in Argentina.

By Tsvetana Paraskova for Oilprice.com

TotalEnergies Set to Develop $9 Billion Suriname Oil Resources

By Charles Kennedy - Sep 20, 2024

French supermajor TotalEnergies has started to scour the market for deepwater rigs and support vessels to begin development of massive resources discovered offshore Suriname, anonymous sources with knowledge of the tenders told Bloomberg on Friday.

Exploration and resource development in the Atlantic Basin is now alive more than ever, following the huge developments offshore Guyana led by ExxonMobil and the plans of TotalEnergies to tap the discovered resources in Guyana’s neighbor, Suriname.

TotalEnergies, which partners with APA Corp offshore Suriname, has already made several discoveries in the area. The companies are expected to make as early as next month the final investment decision (FID) to develop part of the resources, according to Bloomberg’s sources.

TotalEnergies has reportedly ordered a hull for a 200,000-bpd production vessel, the clearest sign yet that the French supermajor would be moving to develop the project.

“They have reserved this hull,” Annand Jagesar, managing director of Suriname’s state oil company, Staatsolie, told Bloomberg.

“You’re not going to pay a lot of money for that to have it sitting around,” Jagesar added.

TotalEnergies and APA plan to make the final investment decision on the Block 58 project by the end of 2024, targeting first oil in 2028.

Crude oil discoveries in Suriname have opened access to some 2.4 billion barrels in reserves, Wood Mackenzie analysts have estimated. The consultancy also reported the South American nation holds some 12.5 trillion cubic feet in natural gas reserves.

A total of nine offshore discoveries have been made in Suriname in the last six years but commercial development of any of them is still in the future. 

Suriname is often seen as a candidate for a repeat of Guyana’s oil boom since the two neighboring countries share one hydrocarbon basin. However, exploration efforts have taken longer in Suriname and the colossal success of Exxon with the Stabroek Block and its dozen discoveries has yet to be replicated in Guyana’s neighbor.

By Charles Kennedy for Oilprice.com

 

ExxonMobil's Guyana Oil: A Trillion-Dollar Opportunity?

By David Messler - Aug 30, 2024,

ExxonMobil's Guyana oil production is rapidly expanding, with the potential to reach 2 million barrels per day by the early 2030s.

• The company's Permian Basin assets are also poised for growth, with production expected to reach 2 million barrels of oil equivalent per day by 2027.

• ExxonMobil is involved in a high-stakes dispute with Chevron over the latter's proposed acquisition of Hess, which could have significant implications for ExxonMobil's Guyana operations.

There are two main drivers for ExxonMobil, (XOM), in the face of crude’s relatively tight pricing band-low $70’s to low $80’s, for the most the past year. The first is the Guyana, Stabroek production ramp, and the related kerfuffle with Chevron, (CVX) over the nature of their proposed acquisition of Hess, (NYSE: HES). The second is the ongoing digestion of Pioneer assets and acceleration of Permian output toward 1.2 mm BOEPD.

XOM is a huge company with a lot of irons in the fire-LNG, chemicals, carbon capture, refining, biofuels, and heck, they’re even dabbling in lithium. None of these really matter to the stock in the near term. XOM moves with higher or lower oil and gas prices and is likely to perform in lockstep with these commodities well into the future. Darren Woods, CEO let loose with a pithy comment in the Q-2 call that reveals the firm priorities of this company, regardless of what other “ponds” into which, they dip their oars-

“Later this month, we'll publish our global outlook, which projects global energy demand 15% higher in 2050 than it is today. We see oil demand holding steady at around 100 million barrels per day in 2050, while demand for renewables and natural gas grows considerably.”

Let’s give Mr. Woods his due. As the CEO of a company producing ~4.3 mm BOPD of crude oil, it is fair and reasonable for us to assign a solid probability of his being right. In this article we will cover a tight focus on what we believe to be the key needle-movers for the company.

Guyana

As was noted in the early August, Bloomberg piece by Kevin Crowley the 2015 Liza discovery well almost didn’t happen. Guyana’s waters were a minefield of 40+ dry holes accumulated over the years and XOM management wasn’t convinced that this prospect met their capital allocation criteria. Even more critical was the fact that XOM’s concession was about to expire, if they were going to do it, it had to be then. Read Crowley’s piece for more of the back story, but the success of Liza changed the company and the country. Quoting Crowley from the article-

“Today, Liza is the world’s biggest oil discovery in a generation. Exxon controls a block that holds 11 billion barrels of recoverable oil, worth nearly $1 trillion at current prices. The find has transformed Guyana from one of South America’s poorest countries into one that will pump more crude per person than Saudi Arabia or Kuwait by 2027. Guyana is on track to overtake Venezuela as South America’s second-largest oil producer, after Brazil.”

Now with more than 30 discovery wells, 6-sanctioned projects, current daily production of ~650K BOPD rising to 750K in 2025 with the commissioning of Yellowtail, 1mm+ BOPD in 2027 with the commissioning of Whiptail, and up to 1.5 mm BOPD with the startup of the 7th project- Hammerhead, the company is growing Guyana production at a rate of about 20% annually. The “Guyana Effect” shows up in total return comparisons with key competitors and the overall S&P 500 index, as noted in the Crowley article.

Guyana appears to have a long ramp for future development in Stabroek, as reporting indicates that another two fields, Fangtooth-now under delineation drilling, and the  Haimara discovery-new appraisal wells planned for later this year, could take reserves well beyond the 11 bn BOIP now booked.

If the company can continue the pace of announcing a new project for Guyana every eighteen months or so, it’s not hard to imagine daily production hitting the 2.0 mm BOPD level in the XOM graph below in the early 2030’s.

As a final point on Guyana, low cost of supply is everything in long-term oil production. With supply costs of less than $35 per barrel, Stabroek fits nicely in the low-cost category assuring profitable production at any likely Brent prices.

The XOM, CVX, Hess kerfuffle

Chevron-CVX has lagged Exxon in reserves replacement over the last few years, as this OilNow article points out. Although down from 2018’s peak of ~24 bn bbls, XOM is comfortably ahead of Chevron with 16.9 bn bbls compared with 11.1 bn for CVX. Chevron’s motivation for its takeout offer for Hess, (HES) is pretty clear. With HES’ 30% stake in Stabroek, CVX saw an easy way to tack on several bn barrels on reserves with its $53 bn offer for HES. Shareholders for both companies approved the deal, but roadblocks began to crop up.

In late December of 2023, the FTC filed a request for more information on the deal but delayed any action pending the outcome of ExxonMobil’s objection to the merger. With the three-judge panel only recently confirmed recent reporting has a timeline well into 2025 for any resolution.

The core of the dispute lies in the interpretation of the Joint Operating Agreement-JOA, which contains a section on the Right of First Refusal-ROFR that governs the disposition of assets run by the consortium. XOM feels that the HES share should be offered to it under the ROFR language in the JOA. Chevron disagrees, and took pains in setting up the deal to provide for HES’ survival as an entity, effectively eliminating the “change of control” provisions of the JOA. Analysts feel the outcome will come down to the arbitration panel’s interpretation of the “intent” of the CVX/HES agreement as regards the asset. M&A expert, James English at law firm Clark Hill Law was quoted as saying-

"The crux here is whether a change of control even occurred. The three-person arbitration panel that will make the call must decide in part whether to focus on the language in the contract or to delve into Chevron's intent. “A plain language approach would be very favorable to Chevron, while if you go with the intent, Exxon may have a case," English said.”

There is no downside for XOM in this process, in my view. The valuation of the stake held by HES is a closely guarded secret, but we can make some assumptions and arrive at an estimate. 

A trillion dollar valuation has been put on the 11 billion worth of reserves already booked, implying a Brent price of $90-not out of line, but aspirational from current levels. That would put HES’ 30% share at ~$335 bn or so, 6X+ above the $53 bn takeout price. Depending on which estimate you use for the percentage ascribed to HES’ 30% as part of the CVX bid -60-80% according to experts cited in the Reuters article, it’s not hard to imagine a significant payday for XOM.

ExxonMobil is in the catbird’s seat in this scenario. They could make a counter offer for the HES stake, bid for a fraction of it, or take compensation from Chevron, if they prevail in arbitration. If it gets too pricey CVX would just walk away, accepting a $1.72 bn break-up fee from HES.

There’s no way to handicap the outcome of this dispute. As I noted there is no downside for XOM. A lot will come down to how the single word-intent, is interpreted.

The Permian

As the first full quarter of Pioneer assets operating under XOM’s umbrella approaches as Q-3 wraps we will get a peek at how efficiently this merger is being implemented. The company has put a big number on the bulletin board-$2 bn, in cost savings that will accrue from the merger annually. In a Bloomberg article, CEO Darren Woods noted that these savings will come from improved technology and extraction-fracking and cube development techniques, as well as the logistics advantages the merger provided in terms of lateral lengths and materials sourcing. XOM projects costs of supply at $35 per barrel from the Permian.

For full year 2024, XOM projects daily Permian production of 1.2 mm BOEPD across their 1.4 mm acre position in the basin. The company has a target of increasing Permian production to 2.0 mm BOEPD by 2027, implying a growth rate of 20% a year.

Your takeaway

XOM is trading at some fairly rich multiples at current prices. The EV/EBITDA is 7.65X, and the flowing barrel stat is $116K per barrel. Analysts rate the stock as Overweight with price targets ranging from $110-157.00 per share. The median is $130.00.

For those looking for well-covered shareholder returns, XOM is generating free cash of about $26.5 bn annually on a TTM basis. The company distributed $8.1 bn in dividends and repurchased $16.3 bn in stock for a modest free cash yield of ~5%. The company beat EPS estimates by ~5% in Q-2, and estimates have been raised for Q-3 to $2.14 per share. If they come in with a beat we could certainly see a move higher toward the midpoint of estimates. The inverse is also true.

XOM should be a part of every long-term energy investor’s portfolio for growth and income. Currently, it is trading near the top of its one-year range-$97-$123.00. Recent weakness in oil and gas prices would certainly argue for a judicious entry point that might come when Q-3 earnings are released in November.

By David Messler for Oilprice.com 

Major Oil Surplus Seen This Decade as Demand Hits Peak, IEA Says


Grant Smith
Wed, Jun 12, 2024

(Bloomberg) -- Global oil markets face a “major” surplus this decade as the shift away from fossil fuels causes demand to hit a plateau amid plentiful supply growth, the International Energy Agency said.

World consumption will “level off” at 105.6 million barrels a day in 2029, about 4% higher than last year’s level, amid surging sales of electric vehicles and improved fuel efficiency, the Paris-based policy adviser said in its annual medium-term outlook.

Meanwhile, oil production capacity continues to surge. Led by the US, it will be a “staggering” 8 million barrels a day higher than demand by the end of the decade, leaving the biggest buffer of spare output since the depths of the Covid-19 lockdowns.

“As the pandemic rebound loses steam, clean energy transitions advance, and the structure of China’s economy shifts, growth in global oil demand is slowing down,” said Fatih Birol, the IEA’s executive director. “Rising oil supplies could potentially weigh on prices through the end of the decade.”

International oil prices have traded near $80 a barrel this year as robust demand, conflict in the Middle East and supply restraint by OPEC+ are countered by a flood of new output from the Americas and concerns over China’s economic growth.

World oil consumption will continue to expand for several years, adding about 4 million barrels a day by the end of the decade amid economic expansion in India and China, and growing use by the aviation and petrochemical industries, the IEA said.

But use of the commodity will continue its “decades-long decline” in developed economies, sinking from last year’s 46 million barrels a day to 43 million a day by 2030 — the lowest level since 1991. Even Chinese demand will plateau by the end of the decade at about 18 million barrels a day, according to the report.

“Oil companies may want to make sure their business strategies and plans are prepared,” Birol said.

Majors such as BP Plc and Shell Plc have tempered plans to diversify from hydrocarbons into renewable energy, while others like Exxon Mobil Corp. remain solidly focused on oil and gas.

Patchy Record

In the past, some of the IEA’s predictions have gone astray.

A decade ago, the agency repeatedly warned of a looming oil supply “crunch” that never materialized as America’s shale boom shattered expectations. In 2022 it forecast an immediate collapse in Russian output that also didn’t occur, and in recent months has revised demand projections for 2024 both down and up.

In a separate monthly report also released on Wednesday, the agency lowered consumption projections for this year by 100,000 barrels a day to 960,000 barrels a day. “Flagging oil demand growth and inventory builds” point to a “comfortably-supplied market,” it said.

One risk to the IEA’s forecast is if the transition to clean energy is slower than expected. In a separate report on Wednesday, BloombergNEF slashed its sales estimates for electric vehicles and warned that the auto industry is falling off the track toward decarbonization.

US Republican leaders criticized the IEA’s projections in a letter in March, claiming its forecasts have been clouded by pressures to fulfill climate change goals. The IEA has said that investment in new oil and gas projects would need to stop in order to comply with the target of net zero carbon emissions by 2050.

Growth in new oil supplies outside the Organization of Petroleum Exporting Countries and its partners will overtake demand as soon as next year, according to the report.

Producers across the Americas led by the US will add about 4.8 million barrels a day of capacity this decade, eclipsing the growth in consumption. The US will account for 2.1 million barrels of the expansion, with the remainder provided by Argentina, Brazil, Canada and Guyana. Even more could come onstream if tentative projects are approved. About 45% of the global capacity expansion will come from natural gas liquids and condensates.

This tide of new oil stands to erode the market share of the OPEC+ alliance led by Saudi Arabia and Russia. Last weekend, the 22-nation group announced a plan for reviving halted supplies later this year, but has signaled that the hike could be postponed. Earlier this year, the Saudis paused plans for a major expansion in its production capacity.

Bloomberg Businessweek

 

"Mixed Bag" Outlook for Offshore Energy

While renewables stagnate, it’s full speed ahead for offshore oil and gas.

PUBLISHED MAY 24, 2024 11:32 AM BY SEAN HOGUE

 

(Article originally published in Mar/Apr 2024 edition.)

The “energy transition." You know the term, but where did it come from? While interest in alternative energy sources can be traced back to the oil crisis of the 1970s, it was during the 2015 Paris Agreement that the first hard goals were placed toward limiting global warming to below 2oC compared to pre-industrial levels. 

“Energy transition” refers to a shift from fossil fuels — including oil, natural gas and coal — to renewable energy sources like wind and solar as well as power storage driven by lithium-ion technology. The push for electrification and improvements in energy storage are all key facilitators of the transition.

In the marine space, a sector notably excluded from the Paris Agreement though responsible for approximately three percent of total greenhouse gasses globally, most of the recent attention has been on IMO 2050 — the International Maritime Organization’s Greenhouse Gas Strategy, which sets a target of net-zero emissions by 2050.

These goals — net-zero emissions, less than 2oC — impact investment strategy, operating procedures and equipment selection. Ultimately, they provide a lens through which the entire offshore energy sector can be viewed as investors and regulators prioritize environmental, social and governance (ESG) factors.

State of Renewables

Offshore wind has long been touted as a viable solution, yet 2023 found the sector battling stormy seas.

On the U.S. East Coast, 2023 saw major projects cancelled due to macroeconomic factors such as skyrocketing inflation, increasing interest rates and supply chain issues that impacted the entire industry. Moving forward means more favorable terms are needed for developers, but those terms will come with higher energy costs to the already squeezed consumer.

On a potentially positive note, previous windfarm partnerships were dissolved earlier this year with Equinor and bp splitting their joint ventures. Equinor will take full ownership of the Empire Wind 1 and 2 projects while bp assumes full ownership of the Beacon Wind project. Likewise, Ørsted is vying for full ownership of Sunrise Wind, working to acquire Eversource’s 50 percent stake in the project.

Sole control over these projects should allow developers to make better business decisions while gaining negotiating leverage over regulators. Because despite the noble intentions of the transition, “If it don’t make dollars, it won’t make sense.”

M&A Market

While companies are moving apart in the renewables space, they’re consolidating upstream.

Both Exxon and Chevron have made massive investments of around $60 billion each, acquiring Pioneer and Hess, respectively. Chevron’s purchase of Hess looks to future inventories, specifically the Stabroek Block in Guyana, which is core to Chevron’s future production plans.

Talos Energy recently completed its acquisition of QuarterNorth, adding production of approximately 30 thousand barrels of oil equivalent per day (Mboe/d).

In the natural gas space, Chesapeake Energy and Southwestern Energy announced a $7.4 billion all-stock merger at the start of the year that will create the largest natural gas producer in the U.S. “This powerful combination redefines the natural gas producer,” stated Chesapeake President & CEO Nick Dell’Osso, “forming the first U.S.-based independent that can truly compete on an international scale.” Dell’Osso will head the combined company. 

Investing in 2024

The energy industry is off to a strong start, largely thanks to high oil prices, which will allow the upstream industry to maintain its 2023 hydrocarbon investment level of about $580 billion and generate over $800 billion in free cash flow in 2024. These investments are driven by expected stable oil prices from 2023 with WTI crude expected to average $78.84 per barrel.

This isn’t all positive for renewables, though.

A 2023 Deloitte survey of O&G executives found that investment in low-carbon projects would be made if returns on those projects exceeded 12 to 15 percent. Yet 2022 returns on major renewable electricity projects ranged from six to eight percent. This means the 2024 focus is more likely to be on (1) addressing operational efficiency and reducing direct emissions, and (2) alternative, low-carbon fuels such as natural gas, biofuels and hydrogen.

But if investment in renewable projects is sitting this inning out, there were major upstream projects greenlighted in 2023 that will bolster the industry in 2024.

In the U.A.E., ADNOC group awarded contracts for development of the Hail and Ghasha offshore gas fields. This is an interesting project as it’s the world’s largest offshore sour gas development, and it aims to operate with net-zero CO2 emissions. The design aims to capture 1.5 million tons of CO2 per year by transporting it onshore and storing it underground – a truly integrated solution.

In the U.K., both Equinor and Ithaca confirmed investment decisions for the controversial Rosebank Field, finally approved by the North Sea Transition Authority. The project targets an estimated 300 million barrels of oil and will tie back subsea wells to a redeployed FPSO. Production is expected to begin in 2026 or 2027.

The Gulf of Mexico saw multiple projects getting the green light including Woodside Energy’s Trion project in the Perdido Basin. The project will use a floating production unit (FPU) connected to a floating storage and offloading (FSO) vessel. Shell made the decision to move forward with the Dover project in the Mississippi Canyon block, tying back to the Appomattox production hub. It also greenlit the Sparta project, which includes eight production wells tied back to a semisubmersible FPU.

And in Guyana the Stabroek Block continues to heat up with ExxonMobil sanctioning its fifth development project – Uaru. It includes up to ten drill centers and 44 production and injection wells.

FPSO Development

Increased production and investments in field developments are relying heavily on Floating Production Storage and Offloading (FPSO) units with many of them planned for Guyana.

The FPSO Errea Wittu, which means “abundance,” will be deployed approximately 200 kilometers offshore Guyana at a water depth of 1,690 meters and storage capacity of two million barrels of crude. It will be “one of the most sustainable FPSOs in the world, using an energy production system with a combined cycle turbine on board.” 

The mooring preinstallation contract has been awarded to Jumbo Offshore Installation Contractors by MODEC Guyana. The FPSO mooring system consists of nineteen legs with suction anchors, 8,800 meters of chain sections and 43,168 meters of polyester rope. Jumbo’s heavy lift vessel Fairplayer is uniquely designed with large amounts of cargo space to perform the transport and installation with a minimal number of voyages.

Igor Rijnberg, Head of Sales & Business Development Subsea at Jumbo Offshore, said, “The Jumbo Offshore team is very grateful to MODEC for this opportunity. We will use the extensive deep-water mooring installation experience gained over the last years to deliver a reliable, smart and efficient project execution.”

OSV Market

Growing EPC (engineering, procurement and construction) spend and increasing scarcity of premium vessel supply (less than 15 years old) could see OSV utilization rates reach 83 percent by the end of 2024, says Westwood Global Energy Group.

The active global OSV fleet totaled 3,077 vessels in 2023 with around 250 premium vessels still laid up. These will continue to be brought out of layup as the year progresses. Vessel day rates have also become more attractive with increases of nearly 70 percent since the recovery began in 2021. 

Despite this, however, rates still don’t justify newbuilds due to the increased costs of vessel construction. An analysis by Tidewater suggests rates need to increase to $38,000/day with utilization at 90 percent to justify ordering a $65 million newbuild to achieve its cost of capital over a 20-year life.

No newbuilds, rising demand and limited supply mean both vessel costs and day rates will continue to climb.

Limited vessel supply also means that those on the market need to operate more efficiently with full visibility for ESG requirements, and ABS has been working with operators such as Edison Chouest Offshore (ECO), which operates a fleet of nearly 300 vessels, on its decarbonization journey with greenhouse gas inventory and sustainability reporting services.

Carbon accounting, also known as a greenhouse gas (GHG) inventory, is the process by which organizations quantify their GHG emissions. Quantifying emissions provides insights to organizations so they can understand their climate impact and set goals to limit emissions. This helps manage carbon compliance risks, meets the requirement for emissions reporting and addresses stakeholder expectations.

“It’s ECO and ABS’s collective commitment to transparency and environmental and social stewardship that led us to collaborate with ABS on sustainability reports that set a new standard in corporate responsibility,” stated Bryan Rousse, ECO’s Sustainability Coordinator.

2024 and Beyond

While renewables are working through a rough patch, overall the offshore energy industry is looking strong into 2024 and beyond. Future investment in infrastructure and storage technologies will play a key role in accelerating the transition while continued investment offshore will keep the home fires burning.

The energy mix, still driven primarily by oil and gas, is benefiting from operational efficiencies and the smart use of assets. GHG planning helps offshore assets operate more cleanly and efficiently than any other time in history.

The future is looking bright.

 

Sean Hogue is Senior Vice President of Operations for Baker Energy Solutions.