This report does not constitute a rating action.
Key Takeaways
- While we expect technology-led cost reductions in the longer term, over the next two to three years, cost inflation appears an increasingly key issue.
- We continue to expect execution risks with potential for timeline delays due to the complex nature of projects that have seasonal timing restrictions and multiple parallel processes.
- Despite inflationary pressures, we still expect offshore wind costs to decline in the long term to $3,250-$3,500 per kilowatt (/kW) as supporting infrastructure (vessels, ports, transmission) expands and turbine technology improves. We anticipate average unsubsidized levelized costs will decline 30%-35% by 2035-2037.
This is the second of a two-part commentary on offshore wind. Here, we discuss salient credit factors that we see as key in the debt financing of these large capital projects.
What we think: Wading into the deep has its specific challenges. Cost inflation will remain a key risk for offshore wind projects. We highlight some here.
Why it matters: Offshore wind could be a meaningful addition to the recourse mix as economic challenges are overcome. Cost inflation and execution risks have the potential to cause timeline delays.
Relevant Credit Factors
In discussions with industry experts about offshore wind projects, what was most important was factoring in costs of upgrading onshore transmission, the placement of projects in independent system operator queues to interconnect on time, and the areas for offshore cables to tie into. Integrating the proposed offshore wind projects will require the development of networked offshore grids and approximately 3,000 miles of offshore transmission lines. We list some of the major credit factors below and also discuss how we factor these into our rating assessment in a sidebar at the end of the commentary.
Offshore power purchase agreement (PPA) pricing is significantly higher than pricing for gas-fired generation
Earlier this January, Equinor ASA and BP PLC (BP) cancelled the offshore wind renewable energy certificate agreement they had with the New York State Energy Research and Development Authority (NYSERDA) for the 1,260 megawatt (MW) second phase of the Empire project. That move followed the New York Public Service Commission's rejection of petitions filed by BP, Equinor, and other offshore wind developers to raise the contracted offtake price for the projects due to the impact of supply chain bottlenecks, inflated costs, and higher interest rates. It isn't the first project derailed by those forces. In New Jersey, Orsted A/S pulled out of the Ocean Wind projects in November 2023 because of similar pressures.
In March 2024, the NYSERDA competitively selected two offshore wind projects: Empire Wind 1, developed by Equinor (810 MW), and Sunrise Wind, developed by Ørsted (924 MW) in its fourth offshore wind solicitation. Prices for New York offshore wind projects are now $145-$150 per megawatt hours (/MWh) compared with $107-$118/MWh for the now-cancelled contracts reached in 2019-2021.
For now, policy objectives in the Northeast and Mid-Atlantic support offshore wind initiatives, but prices of offshore wind PPA contracts remain well above current power market prices and are materially higher than onshore renewables PPAs. These prices haven't yet cascaded to customer rates because none of the U.S. power markets have any material offshore wind integrated into the grid. However, that will change in the second half of the decade on the Eastern seaboard as offshore comes online with concomitant conventional generation retirements.
We expect higher regulatory risks, especially if the integration of intermittent renewable power to the grid continues to result in more frequent outages. Because offshore wind contract prices are above-market, customers could begin to question the price impact of offshore wind.
Costs could rise through 2026
While we see technology-led cost reductions in the longer term, over the next two to three years, cost inflation appears an increasingly critical issue given the recent 30% increase in raw materials.
Steel prices retreated through 2023 into 2024, albeit still above pre-pandemic levels, providing some reprieve to fabricators and buyers. Beyond 2024, we expect steel prices to moderately increase. Mills are cutting production in response to low prices, which will eventually tighten supply and allow price to rebound. We also expect labor costs to rise alongside a shortage of skilled workers. Sponsors assert that most costs will likely be transferred to suppliers in the near term given contract contingencies. However, we continue to view cost inflation as a risk for offshore wind in the medium term.
For example, cost escalation could occur if the distance and depth of the offshore site requires the commissioning of more mid-spin reactive compensation stations (MRCSs). Given the greater depth of the Eastern Seaboard compared with the North sea, offshore substations will have to collect the power generated by the wind farm's turbines, convert it to high voltage, and send it to the onshore grid via the MRCS, which are installed between the offshore wind farm and the shore. The MRCS compensates for the reactive power generated in the wind farm power system.
Other ways costs could climb include greater marshalling areas than estimated, more berthing strips, and higher costs for developing the waterfront staging area. As a rule of thumb, a 1 gigawatts (GW) project requires about 54 acres (22 hectares) of marshaling area over two years.
However, by 2026, we expect higher capacity factors due to increasing turbine size and innovations. In addition, improved operation and maintenance (O&M) practices and digitalization will also improve plant availability via reduced downtime, while a better understanding of wind regimes will result in more effective use of sites.
Construction delays
While onshore and offshore turbines share the basic design, the differences in magnitude, materials, and components are substantial and influence the manufacturing footprint. To get a sense of the construction scope involved, consider this: offshore blades are typically 100 meters long and weigh about 60 metric tons per blade, while the turbine can weigh 600 metric tons. Towers rise 150 meters and weigh about 850 tons, with monopiles weighing 1,500 tons. So the entire offshore structure is 3,500-4,000 tons. The scale is simply massive relative to its onshore counterpart.
We continue to see execution risks with potential for timeline delays due to the complex nature of projects that have seasonal timing restrictions and multiple parallel processes. In particular, we view two-year construction timelines as aggressive given that initial supply chain channels are largely from Europe. There are also parallel efforts to open ports and install onshore interconnects even as sponsors implement aggressive construction schedules.
We believe delays are likely--even potentially protracted delays for some projects--given the construction window is mostly between May and October. In particular, projects are timing restricted--the piling of monopiles must be in the May-October period given whale-related environmental considerations. In this context, some projects have been delayed due to permitting or regulatory delays as the fishing industry challenged developers on windfarm spacing and layout.
Equipment supply chains pose another challenge given the large amount of steel needed for construction, particularly as equipment becomes larger and more efficient. This is especially challenging in the U.S. since it lacks the port infrastructure required to handle the massive construction efforts. In addition, construction processes are not sequential, providing less latitude as delays in permitting or final approvals of construction and operations plans can push schedules out of the summer construction cycle.
We do expect increased capability by 2026, driven in part by local content requirements. Transportation constraints are also driving the shift to coastal tower manufacturing facilities and upgrading of port facilities. Progress is being made at several areas that have existing infrastructure, likely from the decommissioning of older fossil assets. For example, construction is starting this year on the site of the Old Salem Harbor Station in Massachusetts, a former oil- and coal-fired power plant. The station will support clean energy initiatives by creating and storing parts essential to the region's offshore wind energy sites. Another example is the partnership between U.S Wind Inc. with Haizea Wind Group to manage and operate Sparrows Point Steel, Maryland's first permanent offshore wind factory. The new facility in Baltimore County will manufacture steel components for the U.S offshore wind industry, including towers and monopiles. The facility, with significant marshaling and storage land, as well as considerable quayside access and an adjacent dry dock, has the potential to be one of the largest offshore wind staging ports, with commissioning slated for 2025.
Imported components and supply chain limitations
Not surprisingly, significant gaps in the U.S. offshore supply chain exist that prevent the realization of cost savings that European projects are achieving. Currently, the U.S. supply chain is not well inventoried and lacks the necessary workforce and port facilities. Almost all of the offshore wind components, including rotors and turbines, are currently manufactured in Europe. One specific component that could be a bottleneck is high-voltage direct current (HVDC) transmission links that are primarily manufactured by Hitachi Ltd., Siemens Gamesa Renewable Energy S.A., and General Electric Co. The current lead time for these components is about 40 months.
While vendors can engineer even larger turbines, associated offshore wind supply chains are struggling to keep up with this constant flux in technology, especially ports and vessels. As a result, Western original equipment manufacturers (OEMs) have slowed the size race and are industrializing a handful of models rated up to 15 MW. In contrast, Chinese OEMs are still engaged in developing larger sizes and have announced new offshore models rated up to 20 MW. Broadly, the offshore wind supply chain is emphatically bifurcating into China and ex-China, with mainland China driving global oversupply in wind component manufacturing (although not all of that capacity is geared for exports).
New entrants from oil and gas yards and shipyards also continue to secure large offshore substation contracts. Yards in Asia-Pacific and the Middle East have extensive experience with jacket fabrication and compete aggressively on cost. A shortage of monopiles is driving steel providers, shipyards, and tower manufacturers to enter the monopile segment.
Other subcomponents that pose a challenge to domestic component manufacturing include:
- Flanges and other large cast or forged components;
- Steel plates that are rolled into monopiles or towers;
- Electrical systems for offshore substations; and
- Mooring chains, and pitch bearings.
Market experts estimate a domestic supply chain that can supply 4-6 GW of projects per year will likely require an investment of at least $22.0 billion in ports, large installation vessels, and manufacturing facilities. Geographic concentration of the supply chain would further reduce offshore wind costs because proximity decreases transportation costs and fosters better communication between supply chain members. This clustering strategy also allows for more robust project management and top-to-bottom collaboration on wind energy projects.
As we mentioned above, states are announcing their commitments to offshore wind so that this supply chain will come to them.
Costs For Grid Infrastructure Hardening May Be Underestimated
There is a meaningful complexity to the grid. For transmission operators, its position in the queue ultimately dictates what upgrade costs will be onshore. In New York, for instance, the wind resource is 15-30 miles offshore, and access to it is limited by shipping lanes emanating from New York City. Given congestion is typical in New York, there are limited interconnection opportunities with the onshore grid.
Requirements for injection points include the availability of injection into the 340 kilovolt system, marshalling ports, berthing strips, adequate cable connections, and appropriate geology. We are aware of only three significant injection points in New York City--one each near Astoria, Ravenswood, and Consolidated Edison Inc.'s Brooklyn's Clean Energy hub.
For New England, onshore interconnection points are further from the offshore sites compared with New York. As a result, interconnection points with retired coal-fired power plants (such as Brayton Point) are vital and will require onshore transmission buildout for grid reliability purposes. Similarly, in southern New Jersey, beyond Oyster Creek, the onshore grid is fairly weak, likely requiring significant reinforcements of the onshore grid at local landing points or building offshore connections to more robust--but more distant--landing points in northern New Jersey.
Sidebar 1: The Industry's Self-Help Approach
U.S. offshore wind projects in the pipeline are at risk of being delayed beyond 2030 because of limited port and vessel infrastructure and domestic manufacturing. Deploying 30 GW by 2030 requires at least 2,100 wind turbines and foundations, along with a significant number of supporting system components, vessels, and workforce. In the interim, the need for import components remains high until domestic production ramps up. Additional development will be required after 2030 as floating wind platform deployment becomes more prevalent.
We believe the following risks are common to all renewable investments but substantially higher for the offshore wind segment because of its larger scale:
- Permitting and policy: The process is typically complex and slow because of lack of detailed maritime spatial planning and expensive leasing auction rounds.
- High upfront investments: This is a combination of high equipment cost and cost of financing, a tenacious higher commodity price cycle, equipment shortages, and high demand for local content.
- Installation challenges due to lagging dedicated port infrastructure, installation, and O&M vessels.
- Integration: Inadequate onshore and offshore transmission infrastructure
To address these issues, some key investment themes have emerged that the industry developed as a self-help approach to risk allocation. We believe these approaches will eventually de-risk the sector.
- Global independent power producers and oil & gas (O&G) majors have shown increased interest in U.S. offshore wind. The O&G majors in particular are focusing on auction bids where they can cross-utilize their expertise in securing and developing O&G acreage. In 2022, the New York Bight bids resulted in awards to Shell and TotalEnergies. These companies typically de-risk the lease acreage before farming down exposure to other investors.
- Some of the largest private-equity and alternative asset managers are investing in offshore wind projects: for example, Global Infrastructure Management LLC (GIP) announced a deal in February 2024 to take over Eversource Energy's 50% interest in two of the utility's joint offshore wind farms with Ørsted. The following week, Dominion Energy announced its intent to sell a 50% stake in the 2.6 GW CVOW project to Stonepeak Partners L.P. We believe private equity does well when some of the initial development work has been accomplished. They come alongside the developer and provide funding to take the project across the finish line.
- Others are partaking directly in port infrastructure and logistics: Increasingly, states granting permits are requiring developers to invest in port facilities for staging, fabrication, operations, and maintenance. Morgan Stanley Infrastructure Partners is investing in repurposing and operating existing ports in the Northeast and leasing them to developers for storage, assembly, and manufacturing of windfarm components through a joint venture with Crowley Maritime Corp. Crowley Maritime also owns vessels compliant with the Jones Act, under which only U.S.-flagged vessels can operate out of the country's ports.
- There are also consortiums focusing on transmission and injection points into the onshore grid: As an example, in April 2023, a New York Public Service Commission's order invited transmission proposals to meet a Jan. 1, 2033, in-service date, with projects capable of interconnecting a minimum of 4.77 GW of offshore wind with Consolidated Edison's distribution system. The solicitation allows developers to submit proposals for up to 8 GW of transmission capacity. The New York Power Authority (NYPA) and LS Power have submitted a proposal in response to that solicitation.
Offshore transmission
Although projects can achieve significant efficiencies, they require significant cooperation, which is slowly emerging (see sidebar 1). Interconnect could thus be an overlooked risk given the amount of coordination needed and various complexities (i.e., cabling risks), as well as the onshore aspects and challenges that could arise given the issue of large towers in coastal communities. This could also delay construction alignment. At the same time, a key benefit of offshore wind is the avoidance of the transmission issues faced by onshore renewables given the opposition to construction of larger transmission projects.
Another challenge will be connecting offshore transmission to the onshore grid given limited interconnection points on land in addition to pushback from various stakeholders due to the environmental impact on coastal waters, wetlands, fishermen, and communities. With multiple 400-800 MW sized projects requiring ties to interconnection points, some cooperation will likely be necessary to avoid the proliferation of offshore transmission cables.
As a result, planning the offshore system ahead will be critical. In particular, the two factors that we view as key are:
- Choosing between offshore generation ties versus offshore grids.
- HVDC versus high-voltage alternating current (HVAC) station ties.
Generation ties are cost effective.
Broadly, generation ties to individual offshore wind plants that are within 30 miles from shore (and far from other plants) are more cost effective than offshore grids, in our view. On the other hand, offshore grids with open access can offer significant cost and competitive advantages for interconnecting large amounts of wind generation. This is particularly true for plants far from shore and relatively close to each other.
HVDC is preferable for longer distances.
HVDC solutions offer a 50% reduction in weight and volume, with higher efficiency and black start capabilities. While DC cables are generally less expensive per mile, they require relatively more expensive DC converter stations. As a rule of thumb, HVAC station are cheaper for distances that are less than 25 miles offshore.
Because of the noise (and alleged health hazards) associated with them, AC cables tend to be a less popular choice onshore. Other negatives include higher line losses, with the necessity of substation/booster stations. While HVDC is generally preferred for longer distances, there are longer order timelines given higher backlogs, with essentially only three suppliers at present.
Sidebar 2: HVDC Versus Offshore Transmission
The primary challenge will be connecting offshore transmission to the onshore grid given limited interconnection points on land, along with the pushback from various stakeholders due to environmental impacts on coastal waters, wetlands, and fishing and residential communities. With multiple 400 MW-800 MW wind farms requiring ties to interconnection points, some level of cooperation will likely be necessary to avoid the proliferation of offshore transmission cables. As a result, planning the offshore system ahead will be critical. In particular, the two factors that we view as key are the following:
- Choosing between offshore generation ties versus offshore grids; and
- HVDC versus HVAC station ties.
Generation-ties versus offshore grids Broadly, we figure generation ties to individual offshore wind plants that are within a 30-mile radius from the shore (and far from other plants) are more cost effective. On the other hand, offshore grids with open access can offer significant cost and competitive advantages for interconnecting large amounts of wind energy output. This is particularly the case for wind farms far from the shore and relatively close to each other.
HVDC versus HVAC It's ironic that almost 130 years later, we've made a full circle back to the Edison/Westinghouse argument, which Westinghouse/Tesla won the first time around (see the movie "Current Wars").
HVDC lines offer a 50% reduction in weight/volume, with higher efficiency and black start capabilities. While DC cables are generally less expensive per mile, they require costlier DC converter stations. As a rule of thumb, HVAC stations appear to be cheaper for distances that are less than 25 miles offshore.
Because of the noise, AC cables tend to be a less popular choice onshore. Other drawbacks include greater line losses, with the necessity of having substation/booster stations. While HVDC is generally preferred for longer distance transmission, there are longer order timelines because of extensive backlog with essentially only three suppliers in the market.
As an aside, projects in Belgium (and Norway) are now contemplating "artificial islands", where not only will the offshore grid tie but will also install electrolyzers to simultaneously produce hydrogen when the grid does not need wind power. The Princess Elisabeth Island will be the world's first. Located off the Belgian coast in the North Sea, the island will serve as an electricity hub that will bundle together the cables leading to wind farms in Belgium's second offshore wind zone, helping to bring the electricity they generate back to shore. It will also act as an intermediate landing point for interconnectors that link Belgium to other European countries.
Logistical Issues Are More Pronounced In The U.S. Relative To Europe
Depth and distance
Ideally, offshore projects should be located within a "goldilocks" distance to the shore; stay too close and the project risks public acceptance (especially in the U.S--for example, Cape Wind), but going too far may make the project costly and complex. We believe the ideal distance is about 25 miles.
In assessing a project's cost and complexity, we believe it is more relevant to consider the distance to critical infrastructure than the distance to shore. As more projects are permitted and built, developers may find it more difficult to find suitable grid connection points, thereby making export cable runs longer. Similarly, the distance to construction and service ports will be a strong cost factor because turbine access and construction and O&M costs are directly related.
We note U.S. projects will likely have higher depth (even on the Eastern Seaboard) than European projects. The European offshore landscape is enabled by the shallow bathymetry of the North Sea, where projects can be sited far from shore while still using fixed-bottom foundations.
Equipment installation creates yet another set of issues given the Jones Act. While it is possible to obtain waivers for the Jones Act, this remains a significant impediment, particularly for installation.
The Jones Act
The Jones Act requires any ship delivering goods from a U.S. port to a U.S. port to be U.S. made, flagged, and crewed by U.S. residents. The vessel that generally requires the highest capital investment is the offshore wind turbine installation vessel (WTIV). The shortage of U.S.-built WTIVs has led most projects to plan on using foreign-flagged WTIVs along with U.S.-flagged feeder vessels. These feeder vessels will transport wind turbine components to the sites from U.S. marshalling ports, as Foss Maritime Co. LLC and DEME Offshore US LLC have done for the support of Vineyard Wind 1. Building feeder barges in U.S. shipyards may be more feasible than WTIVs because they are smaller, less expensive, and less specialized.
In December 2020, Dominion Energy Inc. announced the construction of Charybdis, the first Jones Act-compliant WTIV, currently being constructed at Seatrium's Brownsville, Texas AmFELS shipyard. Upon completion, the vessel will mobilize to the East Coast, where it will be based out of Hampton Roads, Va. and will support construction activities for Dominion's Coastal Virginia Offshore Wind project.
Dominion Energy continues to make progress on construction of the Charybdis WTIV. During the second quarter of 2024, the vessel began sea trials and installed a crane boom. However, Charybdis underwent modifications, and Dominion Energy has indicated its construction costs have increased $90 million to about $715 million. We believe Charybdis remains on track to be delivered from late 2024 to early 2025.
Two service operation vessels are also under construction, one each by Crowley Logistics of Jacksonville, Fla., and ESVAGT (Denmark), and Edison Chouest Offshore (ECO) and Orsted A/S. Ørsted has a contract with ECO in Louisiana to build the ECO Edison, the first U.S.-built, U.S.-flagged service operation vessel.
While sponsors believe Gulf Coast shipyards available to build vessels necessary for the installation of offshore wind are efficient, the Cato Institute noted the lone WTIV currently under construction had an initial estimated price tag of approximately $550 million (now $715 million). In contrast, building a WTIV in South Korea with the same design (GustoMSC NG-16000X-SJ) but a more powerful crane costs $350 million-$400 million. The Cato Institute further notes the industry may need six to eight service operation vessels with estimated construction costs 80% higher than in Europe and 30-50 crew transfer vessels with an estimated 20% U.S.‐built cost premium.
Sidebar 3: The Jones Act
The Merchant Marine Act of 1920, commonly referred to as the Jones Act, generally requires that all vessels transporting merchandise between two points in the U.S. be: U.S.-built, U.S.-flagged, U.S.-owned, and predominantly crewed by U.S. citizens or residents. Broadly, merchandise is defined as "goods, wares, and chattels of every description", including "valueless material" In relation to the offshore wind industry, the Jones Act effectively forbids foreign vessels from loading turbine components in a U.S. port and installing them in U.S. waters.
Once a monopile is permanently or temporarily attached to the seabed, it becomes a U.S. "point" for Jones Act purposes. The Jones Act would therefore apply to any vessel ferrying components from a U.S. port to an installed monopile on the U.S. outer continental shelf. Transferring merchandise by crane, however, does not constitute transportation under the Jones Act. A developer can therefore construct an offshore wind farm by using Jones Act vessels to ferry merchandise from a U.S. port to installed monopoles, and then using a foreign construction vessel's crane to construct the wind turbines.
The lack of specialized U.S.-flagged installation and support vessels will likely prompt wind developers to use foreign-flagged installation vessels and U.S.-flagged feeder barges. This was the case for the construction of the 30 MW Block Island wind farm. A Fred Olsen Windcarrier installation vessel carrying turbines and jackets crossed the Atlantic but didn't dock at a U.S. port. Instead, the ship offloaded the components to a U.S.-flagged barge, which then delivered them to the construction site off Rhode Island's coast.
This lack of specialized U.S.-flagged installation and support vessels will likely prompt initial commercial-scale projects to use foreign-flagged installations vessels and U.S.-flagged feeder barges.
We acknowledge the availability of U.S.-made barges that can transport offshore wind equipment to the foundation are in limited supply. Before a supply chain on the eastern coast is built out or a U.S.-made, jacked-up installation vessel is created, we believe this requires more capital expenditures and time that companies must already budget into plans.
Conclusion: Expect Headwinds To Ease By 2026
The offshore industry started about 30 years ago. Elkraft, one of the predecessors of DONG Energy (now Ørsted), began considering the installation of offshore turbines in the late 1980s. Eventually, the Vindeby offshore wind farm, the first in the world, started out with a survey of the waters around the Danish island of Lolland in 1989. Construction was commissioned off the coast of the town of Vindeby, and the project was commissioned in 1991.
This was also a momentous time in Europe with the promulgation of large-scale socioeconomic changes, and the fall of the Berlin Wall. In 1990, to commemorate the changes sweeping across Europe, Scorpions, the German rock band, released a single called 'Wind of Change'.
Offshore wind is indeed changing the European power landscape. In the first quarter of 2024, Europe had a total installed offshore wind capacity of 34.2 GW. That corresponds to 6,340 grid-connected wind turbines across 13 countries (please see our accompanying comment on European offshore wind linked in the related research section below).
While there have certainly been a few setbacks, there's a sense that the U.S. offshore wind industry is on a rebound. Even as there are near-term challenges, the long-term foundation of this industry appears to be back on track.
The power ballad by The Scorpions may as well have been written for the offshore wind industry: "The future's in the air, can feel it everywhere, blowing with the wind of change".
We'll see how this goes. Stay tuned.
Sidebar 4: Key Credit Considerations
Offshore wind farms are often project financed on a nonrecourse basis to the sponsor. This type of financing distances the sponsor from the project, which is often critical given the capital investment requirements and debt needed to finance such transactions. Here, we briefly highlight key factors for rating such projects in the U.S.
Permitting is typically a condition precedent to closing Permitting is usually not an issue because it's a condition precedent to closing. However, it's important to move through the process as quickly as possible because the politics surrounding the construction could change, as seen in the strong opposition the Cape Wind project encountered. The project was ultimately cancelled in 2017. Technological enhancements could also help during the lengthy securing of permits
Technology risk –turbine technologies are still evolving Amid the trend toward bigger turbines and foundations to increase the output efficiency, combined with greater distances from the shore and harsh sea conditions, technology risk will remain an important credit factor. This risk is accentuated by a difference between the technologies proposed at the bidding stage and the ones that are actually feasible during construction. We view construction difficulty as a continuum from simple to very difficult and measure it on a scale from 1 to 5, with 1 indicating the least difficulty and therefore lowest risk and 5 indicating the most difficulty and highest risk. We see offshore wind as heavy engineering and will score it no lower (better) than a 3.
Given the limited operational history of some newer turbines, if we believe any project-specific features increase construction complexity or cost when considered individually or in aggregate, we may raise the construction difficulty assessment by one notch to arrive at the construction phase business assessment. To achieve lower installed costs, manufacturers have been building larger turbines by leveraging existing technologies and adding new features.
Under our project finance criteria, we view enhancements as more credit supportive than new technologies, depending on the extent of the changes. In addition, we consider rigorous testing, verification, and certification as vital for new turbines. We assess only the turbine and foundation technologies that have an operational track record and support reliable long-term forecast, as proven.
Construction risk cannot be wished away- a recent offshore accident underscores the installation—and reputational—risk We combine construction, logistics, and interface risks and capture the extent to which the design of the project can cause unexpected variations during the construction phase. We note that evolutions in turbine technologies could be exposed to construction challenges as seen at the Vineyard wind facility where installation is progressing slower than expected, and has also witnessed damage to a wind turbine where a blade detached and fell into the ocean. These incidents can increase not only costs but also delay schedules should regulators order suspension of operations to assess root cause of events.
We also measure the effectiveness of the construction contract by assessing how well it transfers risks associated with cost overruns, delays, and project performance to the appropriate third parties, including the contractor, subcontractor, equipment supplier, concessionaire/grantor, and government, and how much risk the project retains. A well-structured engineering, procurement, and construction contract typically mitigates construction risks. Due to extensive experience of building wind farms in Europe, local participants have a better understanding of the risks, along with a more robust supply chain, enabling us to assume construction risk will abate for U.S. projects only when supply chains are fully established.
Our assessment takes into consideration not only the wind project's size and turbine capacity, but also the distance from the shore, neighboring projects, nearby ports, water depth, tidal range, and soil composition. The latter three factors are critical for foundation design (including boat landings), installation (piling activity), and operational strategy (including corrosion protection). We expect adequate contingencies in the construction budget, or equity infusion from the sponsor, to mitigate construction cost overruns.
Current technology requires larger installation vessels during the construction phase, which only a limited number of players are equipped to handle. In the U.S., availability of offshore wind purpose-built vessels could increasingly become a constraint because of the Jones Act. Compared with Europe, we could assign a higher construction difficulty assessment that underscores a more complex construction task despite simple design or construction characteristics.
Interface management of the main activities, such as foundation installation and cable installation, has improved in recent years. In earlier offshore wind project developments, cable installation typically occured after the substation foundations or topsides were installed. This occasionally postponed the cable installation program because of delays in the offshore substation construction. Many wind developers cite their European experience as key in constructing U.S. offshore projects. While experts cite a two-year timeline for 1 GW as achievable, we believe this is aggressive and possible only if everything goes as planned. We typically expect additional contingencies for projects that schedule a two-year construction window.
Operations risk The more complex the project's operations and technology, the higher (i.e., weaker) our asset class operations stability assessment:
We generally assign an asset class operation stability (ACOS) score of 5 to offshore wind projects. Our ACOS assessment encapsulates the risk that a project's cash flow will differ from expectations due to operational issues. In comparison, we assess onshore wind projects at 4. Overall, the more complex the project's operations and technology, the higher (i.e., weaker) the asset class operations stability assessment, ranked from 1 (the most stable) to 10 (the least stable). The difference between the assessment scores for offshore and onshore facilities stems from the wind farms' remote location. Given the greater difficulty maintaining projects offshore, we believe they face a greater likelihood of O&M cost overruns, weaker availability, and declining efficiency than their onshore peers.
Our assessment of projects' O&M profiles depend in large part on our understanding of the budget, often based on discussions with a technical expert:
We may assess offshore wind projects as having a less-certain O&M profile than those of onshore peers. We would consider a one-notch adjustment to the operations business risk assessment if the ratio of fixed operating expenses and routine--or major--maintenance expenses to revenue is significantly higher than that for the onshore counterparts.
As an example, we cite WindMW GmbH, a 'BBB-' rated 288 MW wind farm that began commercial operations in 2014 in the North Sea, 54 kilometers off Germany's coast. Three years into operations, inspections discovered erosion on the leading edge of blades on the SWT-3.6-120 turbines. Although the remediation, performed by the equipment supplier, Siemens Gamesa, is less disruptive than a full repair, it generates uncertainty over the blades' long-term performance and their likely duration.
Resource availability is better than onshore but is also more volatile (higher in winters and lower in summers):
Our resource risk assessments range from low to very high. We assess resource availability for all project financings, and for most of the projects we've rated to date, and we classify wind power projects as having either medium or high resource exposure, depending on the level of confidence in the project's resource forecasts.
As with onshore projects, we consider the extent of variability in wind resources when rating offshore projects to determine whether the resource or raw materials will be available in the quantity and quality needed to meet production and performance expectations. But perhaps as equally important is our understanding of the manner of collection, including the proximity, height, and duration of the data. For example, for WindMW, we used data collected during a four-year period, at hub height, approximately 1 kilometer away from the edge of the project's site. This information was backed up by several other data sets that were tabulated at more distant locations, but over a longer period (as much as 20 years).
If reliable data is available and shows predictability, we could consider a P(75) confidence level, as opposed to P(90), which is the typical resource level we assume in our financial base-case scenario for wind generation.
Counterparty risk could be important if considered nonreplaceable:
During the operational phase, a U.K.-based offshore wind project has exposure to a counterparty operating the transmission lines, which gets paid under an availability-based scheme. The wind farm would have to rely on its business interruption insurance if the transmission cables are down. In Germany's case, this risk is lower because TenneT, a transmission system operator, maintains the cables and compensates wind farms for downtime time. In the U.S., it's currently unclear whether wind farms would bear this risk or if they will transfer counterparty risk to transmission providers such as OceanGrid.
Furthermore, the O&M counterparty may also be important for U.S. offshore wind projects. While we generally consider the O&M counterparty for a conventional gas-fired or onshore renewable power plant as replaceable because it provides a relatively standard service at a competitive rate, the services rendered to an offshore wind farm could be more complex and therefore more difficult to replicate.
Table 1
| Pipeline of U.S. offshore wind projects | ||||||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Project name | Sponsors | Size (MW) | Commercial operation date (COD) | Offtake mechanism | Pricing ($/MWh) | Counterparties | Term (years) | Location and turbines | Remarks | |||||||||||
| Massachusetts | ||||||||||||||||||||
| Vineyard Wind 1 (Martha's Vineyard project) | Avangrid and Copenhagen Infrastructure Partners | 806 | 2024 | PPA | 2.5% escalation per year. Facility 1: $77.75 for 2024. Facility 2: $66.63 for 2024. | Eversource, Unitil, National Grid | 20 | Located south of Massachusetts’ Martha’s Vineyard. MHI Vestas will supply 84 of its V164-9.5 MW turbines. | Avangrid and Copenhagen Infrastructure Partners announced that they achieved power at 10 turbines totaling 136 MW at Vineyard Wind, making it the largest operating offshore wind farm in the U.S. Vineyard Wind has installed 47 foundations and 21 turbines thus far. This surpasses GIP and Ørsted's 130 MW Southfork project that went COD earlier this year (2024). On July 17, 2024, a turbine blade liberated and fell into the ocean, creating headline risk. | |||||||||||
| New England Wind 2 (formerly Commonwealth Wind) | Avangrid | 1,080 | 2029 | PPA | -- | Eversource, Unitil, National Grid | Located more than 20 miles off the coast of Martha's Vineyard. | On April 2, 2024, the Department of the Interior announced the approval of the New England Wind offshore wind project. We expect the project to generate up to 2.6 GW of electricity, sufficient to power more than 900,000 homes with clean renewable energy. The lease area is located about 20 nautical miles south of Martha’s Vineyard, Massachusetts, and about 24 nautical miles southwest of Nantucket, Massachusetts. The Record of Decision (ROD) documents the decision to approve the construction of up to 129 wind turbines within the lease area. | ||||||||||||
| New England Wind 1 (formerly Park City Wind) | Avangrid | 791 | 2029 | PPA | -- | -- | -- | Located more than 20 miles off the coast of Martha's Vineyard. | The US BOEM completed an environmental review of the 2.6 GW New England Wind project in April 2024. The first phase could enter construction in 2025. | |||||||||||
| SouthCoast Wind 1 (Mayflower) | Ocean Winds North America (joint venture between EDP Renewables and ENGIE) | 2,400 | 2025 (prior to cancellation)-now before end of decade | PPA | Cancelled contract with Massachusetts utilities last year. | Eversource, Unitil, NSTAR | 20 | Located 26 nautical miles south of Martha’s Vineyard and 20 nautical miles south of Nantucket. | The project cancelled its contract with Massachussets utilities last year but plans to rebid in future offshore solicitations. On March 30, 2024, Shell sold its 50% equity share in SouthCoast Wind Energy to joint venture partner Ocean Winds North America (a joint venture between EDP Renewables and ENGIE). | |||||||||||
| Rhode Island | ||||||||||||||||||||
| Block Island | Deepwater (Ørsted) | 30 | 2016 | PPA | Escalator of 2.5% | National Grid | 20 | Located 3.5 miles from Block Island, RI, in the Atlantic. Five Alstom Haliade 150-6-MW turbines. | -- | |||||||||||
| Starboard (proposed) | Ørsted | 1,200 | Likely post-2030 | -- | -- | -- | -- | -- | Ørsted's proposed Starboard project (1.2 GW) in New England is likely COD post-2030. | |||||||||||
| Revolution Wind 2 | Ørsted and GIP | 304 | 2025 | -- | Cancelled. | Eversource and United Illuminating | -- | Located in the Deepwater ONE North zone. Siemens Gamesa won a conditional supply contract for 8MW SG 8.0-167 turbines. | Cancelled. In July 2023, Rhode Island Energy said it will not enter a PPA for the proposed Revolution Wind 2 project because the projected costs to electric customers are too high. Eversource sold its 50% share of South Fork and Revolution (totaling over 830 MW) to GIP. For ES’ sale, GIP shares equally with ES if its share of project costs rise above the current unspecified baseline up to $240 million ($480 million total project when including partner/Ørsted’s share), then ES pays 100% of overruns above the $240 million. | |||||||||||
| Revolution Wind 1 | Ørsted and GIP | 400 (704 total) | 2025 | PPA | Inflation-adjusted price (2023$/MWh): $114.1. | National Grid | 20 | Located in the Deepwater ONE North zone. Siemens Gamesa won a conditional supply contract for 8MW SG 8.0-167 turbines. | Eversource sold its 50% share of South Fork and Revolution (totaling over 830 MW) to GIP. For ES’ sale, GIP shares equally with ES if its share of project costs rise above the current unspecified baseline up to $240 million ($480 million total project when including partner/Ørsted’s share), then ES pays 100% of overruns above the $240 million. | |||||||||||
| Connecticut | ||||||||||||||||||||
| Revolution Wind 2 | Ørsted and GIP | 304 (704 total) | 2025 | PPA | Cancelled. | Eversource and United Illuminating | 20 | Located in the Deepwater ONE North zone. Siemens Gamesa won a conditional supply contract for 8MW SG 8.0-167 turbines. | Cancelled. In July 2023, Rhode Island Energy said it will not enter a PPA for the proposed Revolution Wind 2 project because the projected costs to electric customers are too high. Eversource sold its 50% share of South Fork and Revolution (totaling over 830 MW) to GIP. For ES’ sale, GIP shares equally with ES if its share of project costs rise above the current unspecified baseline up to $240 million ($480 million total project when including partner/Ørsted’s share), then ES pays 100% of overruns above the $240 million. | |||||||||||
| Park City Wind (Now New England Wind) | Avangrid and Copenhagen Infrastructure Partners | 804 | 2027 | PPA | Cancelled. | Eversource and United Illuminating | 20 | Located 23 miles off the coast of Massachusetts. | Avangrid, a member of the Iberdrola Group, and the Connecticut Electric Distribution Companies have agreed to terminate PPAs for the Park City Wind offshore project. The developer said it plans to rebid the 804 MW Park City Wind project in the upcoming auctions. | |||||||||||
| New Jersey | ||||||||||||||||||||
| Ocean Wind 1 | Ørsted | 1,100 | 2026 | OREC | Cancelled. | PSEG | 20 | 90 GE Haliade-X 12 MW turbines. | NJ BPU said it reached a settlement with Ørsted over the offshore wind developer’s cancellation of Ocean Wind 1 and 2 projects in November of 2023. The settlement is for $125 million, less than the $300 million that Ørsted had guaranteed for offshore wind industry development in the state last year prior to the surprise project cancellations. The lack of vessel availability under the new time frame would have led to recontracting with vendors at significantly higher costs and potentially pushing out COD. Originally, Ørsted (75%) & PSEG (25%). Ørsted bought PSEG out in January 2023. | |||||||||||
| Atlantic Shores Offshore Wind | EDF-RE Offshore Development LLC and Shell New Energies US LLC (50-50) | 1,510 | 2028 | OREC | -- | TBD | 20 | Turbines located nearly 9 miles offs southern New Jersey at their closest point. Includes 200 wind turbine generators to be connected to the state’s power grid by up to 10 offshore substations, with subsea transmission cables expected to make landfall in Atlantic City and Sea Girt. | We expect the project to become commercially operational no earlier than 2028. | |||||||||||
| Ocean Wind Project 2 | Ørsted | 1,148 | 2029 | OREC | -- | TBD | 20 | GE Haliade-X turbines. | NJ BPU said it reached a settlement with Ørsted over the offshore wind developer’s cancellation of Ocean Wind 1 and 2 projects in November 2023. | |||||||||||
| Attentive Energy 2 | Joint venture between TotalEnergies (70%) and Corio (30%) | 1,342 | 2031 | OREC | Awarded in the first quarter of 2024. Levelized OREC purchase prices stand at $165.14/MWh. Won New Jersy a guaranteed level of OREC revenue, with a first-year set price of $131/MWh after the start of commercial operations, inflated yearly by 3%, and the benefit of a 30% Inflation Reduction Act (IRA) tax credit. | NJ BPU | 20 | Located over 42 miles east of Seaside Heights in federal waters. Landfall at Sea Girt and interconnection at Larrabee Collector Station in Howell. | For Attentive 2, estimated energy production of about 5,100GWh/yr ($840 million/yr) joins Attentive 1’s production estimate of 5,300GWh/yr ($770M/yr) to present a combined annual revenue of estimate of $1.6 billion/yr, expected to power more than 600,000 homes and generate $12 billion in economic activity state-wide. In January 2024, the BPU announced winners of its third solicitation: the 1,342 MW Attentive Energy 2 and 2.4 GW Leading Light Wind projects. The BPU is currently conducting the fourth solicitation for 1.2-4.0 GW of offshore wind. A fifth solicitation is being advanced by the BPU to the second quarter of 2025. | |||||||||||
| Leading Light Wind | Invenergy and EnergyRe | 2,400 | 2031-2032 | OREC | Awarded in the first quarter of 2024. Levelized OREC purchase prices stand at $139.53/MWh. Won New Jersey a $112.50/MWh first-year set price for the Leading Light project. | NJ BPU | 20 | Located over 40 miles off the coast. | Energy production for Leading Light wind to be approximately 9000GWh/yr, equating to $1.25 billion in annual revenue. | |||||||||||
| New York | ||||||||||||||||||||
| Empire Wind | Equinor | 816 | 2027 | OREC | Empire Wind 1 and Sunrise Wind will earn $150.15/MWh under the new 25-year contracts, far higher than the $110.37/MWh price awarded to Sunrise Wind in 2019. The contracts are also indexed to inflation and include measures to share grid connection costs. | Synedra | 25 | The $3 billion project will employ 80 turbines in a triangular segment of the Hudson North zone facing Long Island. | NYSERDA launched the fourth expedited offshore wind solicitation in December 2023, allowing companies to re-offer planned projects at higher prices and exit their old contracts. NYSERDA recently executed offshore wind contracts with Ørsted’s Sunrise 1 and Equinor’s Empire 1, both of which were selected in New York's offshore wind Round 4 auction this past February. The specified OREC strike prices for the 25-year contracts were roughly in line with the weighted-average all-in development cost number previously disclosed--$146/MWh for Sunrise (924 MW) and $155/MWh for Empire (810 MW). The BOEM approved the COP plan in February 2024. | |||||||||||
| Sunrise Wind | Ørsted | 924 | 2026 | OREC | Empire Wind 1 and Sunrise Wind will earn $150.15 per megawatt hour under the new 25-year contracts, far higher than the $110.37MW/h price awarded to Sunrise Wind in 2019. The contracts are also indexed to inflation and include measures to share grid connection costs.[CONTENT IS REPEATED FROM ABOVE] | Synedra | 25 | Developed adjacent to the Revolution and South Fork projects in the Deepwater ONE North zone, about 30 miles east of Montauk Point, Long Island. Siemens 8MW SG 8.0-167 turbines. | On June 21, 2024, the BOEM gave Ørsted final approval to begin constructing this largest NY offshore wind project. NYSERDA launched the fourth expedited offshore wind solicitation in December 2023, allowing companies to re-offer planned projects at higher prices and exit their old contracts. Empire Wind and Sunrise Wind were elected. Sunrise represents Ørsted’s largest remaining U.S. project. The weighted average all-in development cost of the awarded offshore wind projects over the life of the contracts is $150.15/MWh, which is on par with the latest market prices. Sunrise reached FID in March 2024 and will advance with onshore construction activities. On July 9, 2024, Eversource and Ørsted announced the closure of Eversource’s 50% stake in Sunrise Wind to Ørsted. Ørsted is now the 100% owner of Sunrise Wind, to which NYSERDA recently awarded a 25-year contract with a $146/MWh OREC strike price, after NY’s offshore wind Round 4 auction. We expect the project to reach COD in 2026. The specified OREC strike prices for the 25-year contracts were roughly in line with the weighted-average all-in development cost number previously disclosed--$146/MWh for Sunrise (924 MW) and $155/MWh for Empire (810 MW). The project broke ground July 17, 2024. | |||||||||||
| South Fork | Ørsted and GIP | 130 | 2024 | PPA | Nov 2023: $137 nominal awarded price. January 2020: price on the Long Island Power Authority’s PPA for the South Fork project is reported at $160/MWh for the first 90 MW and $86/MWh for the additional 40 MW. | Long Island Power Authority | 20 | Located in the Deepwater ONE North zone off the coasts of Rhode Island and Massachusetts. Siemens Gamesa has a conditional contract to supply 8MW SG 8.0-167 turbines. | Eversource sold its 50% share of South Fork and Revolution (totaling over 830 MW) to GIP. For ES’ sale, GIP shares equally with ES if its share of project costs rise above the current unspecified baseline up to $240 million ($480 million total project when including partner/Ørsted’s share), Then ES pays 100% of overruns above the $240 million. More farm-downs are expected in the U.S. offshore wind space in the near term, including Ørsted’s plans to sell down its 50% stake in South Fork and Revolution to 25% and its soon-to-be 100% stake in Sunrise back down to 50%. | |||||||||||
| Empire Wind 2 | Equinor Wind US LLC | 1,260 | 2027 | TBD | Will be bid into a future auction but the contract was cancelled in January. | TBD | TBD | TBD | BP and Equinor cancelled this offshore wind contract near New York. The project was expected to be installed 15-30 miles off the coast of Long Island and had already received important permits. The cancellation was caused by "inflation, interest rates, and supply chain disruptions," Equinor said in a statement. The cost of materials like steel has soared over the past two years, cutting into the margins that wind developers expect to make on these projects. The announcement doesn’t necessarily mean the Empire Wind 2 project is dead. The companies still hold federal leases on thousands of acres of ocean bedrock, as well as some permits. | |||||||||||
| Beacon Wind 1 | BP | 1,230 | 2028 | TBD | Contract cancelled. | TBD | TBD | TBD | Beacon 1 cancelled its contract in January 2024 after Equinor and BP became full owners of the Empire and Beacon projects, respectively. Also in January, BP and Equinor announced a swap in their joint interests in Empire Wind and Beacon Wind; BP now owns 100% of Beacon and Equinor owns 100% of Empire Wind 1-2. | |||||||||||
| Attentive Energy 1 | TotalEnergies and Rise | 1,404 | 2030 (expected) | -- | $145.07/MWh (nominal/strike price). | -- | -- | -- | NYSERDA announced it cancelled three projects it provisionally awarded in its third offshore wind solicitation due to "material modifications" to the projects, including GE Vernova’s pivot away from an 18-MW turbine model and to a 15.5-16.5 MW platform. The technical and commercial complexities between provisional awardees and their partners caused material changes to projects proposed in the New York Offshore Wind 2022 solicitation. The three projects cancelled are the 1,404-MW Attentive Energy One, the 1,314-MW Community Offshore Wind and the 1,314-MW Excelsior Wind--a total of 4 GW of capacity. If this eventually proceeds, the project will include a fossil repurposing plan in Queens, which seeks to retire fossil fuel power generation in the heart of New York City. | |||||||||||
| Community 1 | RWE and National Grid | 1,314 | 2030 (expected) | -- | $145.07/MWh (nominal/strike price). | NYSERDA | -- | -- | See notes for Attentive Energy. However, if this project proceeds, the project includes utilization of new grid interconnection being developed by Con Edison in downtown Brooklyn, made possible by the Public Service Commission Order Approving Cost Recovery for Clean Energy Hub to maximize delivery of clean electricity into New York City. | |||||||||||
| Excelsior | Vineyard Offshore and CIP | 1,314 | 2030 (expected) | -- | $145.07/MWh (nominal/strike price). | -- | -- | -- | This is among the three cancelled projects by NYSERDA. Developed by Vineyard Offshore and Copenhagen Infrastructure Partners, the project includes proposed cable route options providing robust energy deliverability to Long Island, leveraging the electric grid expansion provided through the Long Island Public Policy Transmission. | |||||||||||
| Maryland | ||||||||||||||||||||
| MarWin | Us Wind | 270 | 2025 | OREC | -- | -- | 20 | Up to 22 turbines located more than 20 miles from shore. | U.S. Wind plans to construct two projects with a combined 1,100 MW of capacity, according to the company. Both the Ocean City Offshore Wind Project (Marwin) and Momentum Offshore Wind Project, which are due to come online in 2025 and 2026, respectively, have been awarded ORECs by the state of Maryland. Project FID expected in 2024. Sparrows Point Steel works to provide all monopiles. | |||||||||||
| Momentum Offshore Wind | US Wind | 808 | 2026 | OREC | -- | -- | 20 | Up to 55 turbines located more than 15 miles from shore. | Operational life expectancy of more than 25 years. | |||||||||||
| Skipjack | Ørsted | 120 | 2026 | OREC | -- | -- | 20 | Located off the coast of Delaware. Ten 12MW GE Haliade -X turbines. | Ørsted cancelled the offtake deal for its combined 966 MW Skipjack Wind 1 and 2 development off the Delmarva peninsula as it seeks to rebid. Following consultation with the State of Maryland, Ørsted has withdrawn from the Maryland Public Service Commission Orders approving the Skipjack projects, but the project intends to continue advancing project development and permitting. The cancellation came amid changing market conditions including high inflation, high interest rates, and supply chain constraints. The project will be positioned for future offtake opportunities. | |||||||||||
| Skipjack 2 | Ørsted | 846 | 2027 | OREC | -- | -- | -- | Located off the coast of Delaware. Ten 12MW GE Haliade -X turbines. | Ørsted cancelled the offtake deal for its combined 966 MW Skipjack Wind 1 and 2 development off the Delmarva peninsula as it seeks to rebid. Following consultation with the State of Maryland, Ørsted has withdrawn from the Maryland Public Service Commission Orders approving the Skipjack projects, but the project intends to continue advancing project development and permitting. The cancellation came amid changing market conditions including high inflation, high interest rates, and supply chain constraints. | |||||||||||
| Virginia | ||||||||||||||||||||
| CVOW | Dominion and Stone Peak | 2,640 | 2025-2026 | -- | -- | Vepco | -- | Virginia is mitigating turbine installation risk by building its own Jones Act-compliant vessels (Charybdis), which is 89% completed and expected by late 2024 or early 2025. | Dominion's CVOW project (2.6 GW) received its major permits to begin construction this past January of 2024, including BOEM’s COP permit and Army Corps of Engineers permit. The project appears to be on budget and on schedule. Monopile installation has begun and COD is targeted for late 2026. The Orion WTIV continues to deploy monopiles in the CVOW seabed, and has installed 42 monopiles. The company has until the end of October to reach its 2024 installation target of 70-100 monopiles. 50% share of Dominion’s CVOW (2.6 GW) has been announced for sale, to be completed in the fourth quarter of 2024, to Stone Peak. Both owners share equally in the capital expenditure up to $11.3 billion (current budget is $9.8 billion); Stone Peak gets more ownership of cash flow for every incremental dollar over $11.3 billion. | |||||||||||
| Other states and leasing activity | ||||||||||||||||||||
| North Carolina | ||||||||||||||||||||
| CVOW-South | Dominion | 800 | 2030s | -- | -- | -- | -- | Located some 40 kilometers south of the under-construction Coastal Virginia Offshore Wind project. | 40,000-acre lease, currently known as Kitty Hawk North Wind, will be renamed CVOW-South and could support 800 MW of offshore wind generation capacity in the 2030s. In the COP submitted to BOEM, Avangrid (former sponsor) detailed the plan for the CVOW area off North Carolina to be built in phases, with the first phase having an installed capacity of 800 MW and the entire development a total generation capacity of up to 2.6 GW, once all phases are built. | |||||||||||
| Carolina Long Bay | TotalEnergies | 667 | Expected early 2030s | -- | -- | -- | -- | -- | In May 2022, TotalEnergies won a bid (Lease OCS-A 0545) to develop an offshore wind farm at Carolina Long Bay. Today, TotalEnergies Carolina Long Bay is a wholly-owned subsidiary of TotalEnergies, a multi-energy company present in the U.S. since 1957 and with operations across 34 states. Production is likely to commence in 2026. | |||||||||||
| Source: S&P Global Ratings. MW--Megawatt. MWh--Megawatt hour. PPA--Power purchase agreement. OREC--Offshore wind renewable energy certificates. TBD--To be determined. | ||||||||||||||||||||
Other activity:
- Oregon: On April 30, 2024, the Department of Interior announced proposed auction details and lease terms for two areas offshore the Oregon coast for offshore wind energy development. The proposed Brookings Wind Energy Area consists of 133,792 acres and is located approximately 18 miles from shore. The proposed Coos Bay Wind Energy Area consists of 61,203 acres and is located approximately 32 miles from shore. These areas have the potential to provide up to 3.1 GW and power over 1.1 million homes with clean energy.
- Louisiana: Two foreign companies have signed agreements to build the first offshore wind farms in Louisiana waters. Danish firm Vestas was granted nearly 60,000 acres off Cameron Parish and Mitsubishi-owned Diamond Offshore Wind was approved for a 6,162-acre area off Terrebonne and Lafourche parishes, the state Department of Natural Resources announced.
- California: There are five leases in California. Northern CA leases include RWE Offshore Wind Holdings LLC (OCS-P 0561) and California North Floating LLC, (OCS-P 0562). Central Coast leases include Atlas Offshore Wind LLC (OCS-P 0563)--after lease issuance, record title interest changed from Equinor Wind US LLC--Golden State Wind LLC (OCS-P 0564)--name changed after lease issuance from Central California Offshore Wind LLC--and Invenergy California Offshore LLC (OCS-P 0565).
- Leasing activity: The Bureau of Ocean Energy Management (BOEM) issued records of decision for nine lease areas comprising 12 projects as of July 2024. Seven additional wind projects have submitted construction and operations plans that are awaiting final approval by BOEM. BOEM announced the approval of its ninth offshore wind project, Atlantic Shores South, on July 2, 2024, marking the agency's approval of more than 13 GW of clean energy from offshore wind energy projects.
Related Research
- Power Sector Update: The U.S. Offshore Wind Industry Has Not Harnessed Its Full Potential Yet, Aug. 2, 2024
- Power Sector Update: The Piper At The Gates Of Dawn, April 1, 2024
- Inflation Reduction Act Update: Between Cheap, Firm, And Clean Power--Pick Any Two, Sept. 8, 2022
| Primary Credit Analyst: | Aneesh Prabhu, CFA, FRM, New York + 1 (212) 438 1285; aneesh.prabhu@spglobal.com |
| Secondary Contacts: | Vishal H Merani, CFA, New York + 1 (212) 438 2679; vishal.merani@spglobal.com |
| Luqman Ali, CFA, New York (1) 212-438-0557; luqman.ali@spglobal.com | |
| Viviane Gosselin, Toronto + 1 (416) 5072542; viviane.gosselin@spglobal.com | |
| Research Assistant: | Helena Lara, New York |
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