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The Energy Transition: Offshore Wind Picks Up

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The Energy Transition: Offshore Wind Picks Up

Although offshore wind power does not currently screen well relative to other established technologies, interest in it from states has increased dramatically largely because of the following factors:

  • Meeting renewable portfolio standards (RPS) goals and weaning away from natural gas.
  • Expectations of substantial decline in costs due to innovations.
  • Local economic development and job creation.
  • Increasing demand for environmental, social, and governance (ESG) initiatives and climate goals from investors.

We've examined offshore wind generation plans and projects in the U.S. While 100% RPS targets, or carbon reduction goals, are prompting market activity in states without offshore wind procurement targets, here we focus largely on developments in the Northeast where most of the ongoing activities are located. We also consider the key credit factors for project financings of these assets as most investor queries are of that nature. (See related research for a similar consideration for the European landscape.)

North American Offshore Wind Developments

As of August 2021, state-backed targets and mandates have continued to build momentum with about 29.0 GW of offshore wind procurement targets established to date (see table 1). This compares with just 8 GW in mid-2018 (see charts 1 and 2) and is roughly a third of the 86 GW of total U.S. offshore wind capacity forecast by the Department of Energy through 2050. All market consultants we spoke to agree that the potential for the market is about 15 GW by 2030 but regulatory uncertainty will affect the speed of buildout. We note that the Biden Administration has set a nationwide goal of 30 GWs by 2030 and 110 GWs by 2050.

Table 1

State Mandates For Offshore Wind Projects
State Nearest RPS goal RPS year Offshore capacity commitment (MW) Statutory authority Capacity awarded (MW) Year enacted
NY 70% 2030 9,000 Case 18-E-0071 4,320 2017
Climate Leadership And Community Protection Act 2019
NJ 50% 2030 7,500 Executive Order 8; Executive Order 92, Assembly Bill 3723 3,758 2018
2019
MA 35% 2030 1,600 House Bill 4568 to promote energy diversity 1,600 2016
1,600 House Bill 4857 to advance clean energy 2018
CT 44% 2030 300* House Bill 7036 1,108 2017
2,000 House Bill 7156 2019
VA 100% 2050 5,200 Executive Order 43 2,640 2019
MD 50% 2030 1,200 Senate Bill 516 set targets 370 2019
NC 12.5% 2021 2,800 Executive Order 218 - 2021
RI 100% 2030 1,100 Executive Order 20-01 400 2017
Notes: RPS goals are staged over time. Only nearest goals are included. We have only included signed executive orders. Mandates are fast increasing. For example, NC and MA would soon likely be 8 GW and 5.6 GW, respectively. *100 MW came from technology-neutral auctions. Source: S&P Global Ratings and state websites.

The industry got a significant fillip in September 2019, when Virginia Governor Northam issued an executive order calling for 2.5 GW of offshore wind in the state by 2026. Shortly after, Dominion Energy Inc. announced plans to build and own a 2.6 GW offshore project, the largest project announced in the U.S. to date. Dominion Energy's plan will expand the offshore footprint further south where states like North Carolina, South Carolina, and Georgia currently do not have offshore mandates. We expect Maryland and North Carolina to be the next states where we would see increasing activity, particularly as a frontrunner developer in these states has not been established.

We expect the Bureau Of Ocean Energy Management (BOEM) to step up its reviews of pending projects, after several fits and starts related to the first approval for the Vineyard Wind project. Projects progressing through the offtake and permitting approval process are so far primarily located in the Northeast where state level procurement boosts project development. Multiple projects also made significant progress with electricity offtake agreements and environmental permitting at both the state and federal level.

To date, BOEM has held 8 competitive lease sales and issued 17 active commercial offshore wind leases on the Atlantic from Massachusetts to North Carolina. In addition, the BOEM has indicated that it plans to complete review of at least 16 pending Construction and Operations Plans (COPs) by 2025, representing more than 19 GW.

Chart 1

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Chart 2

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By fourth-quarter 2021, we expect to see auction awards in Maryland (400 MW to 1,200 MW), Rhode Island (about 600 MW), and Massachusetts (up to 1,600 MW). We expect an auction off the coast of California next year for 4.5 GW. Similarly, auctions off the states of North Carolina and Maine and along the Gulf of Mexico are possible in 2022.

Table 2

Pipeline Of U.S. Offshore Wind Projects
Project name Sponsors Size (MW) COD Offtake mechanism Pricing ($/Mwh) Counterparties Term (years) Location and turbines Remarks
Massachusetts
Vineyard Wind 1 (Martha's Vineyard project) Avangrid/Copenhagen Infrastructure Partners 804 2024 PPA $74/MWh for 400 MW (2022 $) then $65 for the next 400 MW (2023 $) with a 2.5% escalation per year Eversource, Unitel, National Grid 20 South of Massachusetts’ Martha’s Vineyard island. MHI Vestas will supply 84 of its V164-9.5 MW turbines. Nominal levelized at $84.23/MWh over contract period. It may still qualify for the 21% ITC as permitting delays can possibly be recognized by tax authorities as a valid reason to maintain pre-qualified tax-credit levels.
Mayflower Shell Oil and EDP Renewables 804 2025 PPA Being negotiated but likely below levelized cap of $84.3/MWh Eversource, Unitel, NSTAR 20 26 nautical miles south of Martha’s Vineyard and 20 nautical miles south of Nantucket The original enabling legislation mandated that for each round of offshore wind procurement, the cost must come in lower than for previous procurements. Given the expiration of the ITC and the low price in Vineyard Wind’s winning bid in 2018, it was determined that future bids could be for higher amounts, provided that the increased cost was accounted for and justified. Bladt and Semco to supply a 1.2GW offshore substation.
Rhode Island
Block Island Deepwater (Orsted) 30 2016 PPA $244/MWh with a 2.5% escalator National Grid 20 3.5 miles from Block Island, R.I., in the Atlantic. Five Alstom Haliade 150-6-MW turbines Contributing to the project’s support is that it connects Block Island to the New England grid, allowing it to avoid high cost diesel generation that the island otherwise relied upon
Revolution Wind Ørsted & Eversource 400 2025 PPA $98.4/MWh National Grid 20 Deepwater ONE North zone 704 MW between the Connecticut and Rhode Island PPA's
Connecticut
Revolution Wind Ørsted and Eversource 304 2025 PPA $98.43/MWh for 200 MW and $99.5/MWh for 104 MW with no escalation Eversource and United Illuminating 20 Deepwater ONE North zone. Siemens Gamesa won a conditional supply contract for 8MW SG 8.0-167 turbines Eversource and United Illuminating earlier agreed to buy 200MW at $94/MWh and an additional 100MW with pricing set to be made public. Project delayed to 2025 from 2023.
Park City Wind Avangrid/Copenhagen Infrastructure Partners 804 2025 PPA Currently being negotiated Eversource and United Illuminating 20 23 Miles off the coast of Massachusetts
New Jersey
Ocean Wind 1 Ørsted (75%) & PSEG (25%) 1100 2024 OREC $98.10 OREC price escalates at 2% through 2045 (levelized price of $86/MWh). Equates to a nominal levelized price of $116.82/MWh. However, the levelized net OREC cost--which represents the actual ratepayer OREC costs after refunds of capacity and certain other revenues--is estimated at $46.46/MWh over the contract life. PSEG 20 90 GE Haliade-X 12 MW turbines The NJ BPU’s OREC funding mechanism is largely based on the procurement of a bundled energy, environmental attribute and capacity product. The use of an OREC adds complexity with respect to the administration of the ORECs and risk to developers (e.g., variances between actual and forecast output) and in our opinion could be more simply administered with stronger performance incentives with a PPA that procured energy and environmental attributes. The project will be developed in three tranches of 368 MW each in partnership with PSEG. 15 miles off the Atlantic City coast. We expect first production no earlier than 2025.
Atlantic Shores Offshore Wind EDF-RE Offshore Development, LLC and Shell New Energies US LLC, 1510 2028 OREC Based on the estimated levelized net OREC cost of $58.51/MWH, which is the cost per megawatt hour after revenues generated by the project are returned to ratepayers . TBD 20
Ocean Wind Project 2 Ørsted 1148 2029 OREC Offshore Renewable Energy Credit (OREC) award at the $84.03 price. The rate based on the estimated levelized Net OREC cost of $42.30 which is the cost per megawatt hour after revenues generated by the project are returned to ratepayers. TBD 20 GE Haliade-X turbines
New York
Empire Wind Equinor (formerly StatOil) 816 2024 OREC $83.36/MWh with an OREC offset of $25.14/MWh. Empire's nominal price is about $99/MWh in year 1, rising to $159/MWh in year 25). Sunrise if about $110/MWh. Payments rise and fall based on a composite average of energy and capacity prices. Nyserda will buy ORECs from Equinor and resell them to load-serving entities to meet their obligations under the state's Offshore Wind Standard Nyserda 25 The $3bn project will employ 80 turbines in a triangular segment of the Hudson North zone facing Long Island. Strike prices are assessed by: (1) an Index OREC price and; (2) a Fixed OREC price. The Index OREC price will vary monthly based on the value of Index OREC Strike Price specified minus the monthly Reference Energy Price and the monthly reference capacity price. The fixed OREC price is based on the fixed price specified by the proposer. The Index OREC price is a contract for difference that considers relevant energy and capacity prices, thereby providing a market price hedge. The Index OREC price is given a weight of 0.9 and the fixed OREC price a weight of 0.1 to establish the weighted strike price. COD revised to 2025 from last quarter 2024 but still dependent on when the project gets into BOEM's notice of intent
Sunrise Wind Bay State Wind, LLC (Orsted and Eversource) 880 2025 OREC Nyserda 25 Developed adjacent to the Revolution and South Fork projects in the Deepwater ONE North zone, about 48km (30 miles) east of Montauk Point, Long Island. Siemens 8MW SG 8.0-167 turbines
South Fork Ørsted and Eversource 130 2023 PPA Nominal $138/MWh Long Island Power Authority 20 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. Expanded from 90 MW. COD may get delayed to 2024
Empire Wind 2 Equinor Wind US LLC (Equinor). 1260 2027 TBD To be decided TBD TBD TBD Our estimate of COD is no earlier than 2027. Power from the New York Bight with planned delivery to Nassau County at the Barrett Substation in Oceanside, building out the back half of Equinor’s New York Bight lease area
Beacon Wind 1 Equinor Wind US LLC (Equinor). 1230 2028 TBD To be decided TBD TBD TBD Proposed interconnection into New York City through the Astoria Substation in Queens, supporting the retirement of aging fossil fuel plants as part of a transition to clean energy. Located over 60 miles east of Montauk Point, Beacon Wind will be the first offshore wind project in the U.S. to utilize High Voltage Direct Current (HVDC) transmission technology.
Maryland
US Wind Toto Holdings 248 2023 OREC Maryland awarded Offshore Wind Renewable Energy Credits (ORECs) for 20 years @ $131.94/MWH (one OREC for each MWh delivered to the grid) 20 32 turbines; 17 miles off Ocean City Each year, 913, 945 OREC's will be sold at a levelized cost of $131.94/MWh
Skipjack Ørsted 120 2023 OREC $131.94/MWh 20 Off the coast of Delaware. Ten 12MW GE Hallide -X turbines. Each year, 455,482 OREC's will be sold at a levelized price of $131.94/MWh.
Virginia
Dominion Utility owned 2600 2025-2026 Undisclosed; indications of $78/MWh Vepco
*Included only projects past permitting phase. These projects exclude others like Icebreaker (Ohio) and Aqua Ventas (Maine), which are relatively small and were originally funded under the DOE advanced technology demonstration project program. Source: S&P Global Ratings and state websites.

Developments In U.S. Offshore Wind

We've examined the latest developments in offshore wind activities. We also list updates on projects that have been announced (see table 2). We think the notable developments are the notice to proceed for Vineyard Wind as well as extension of tax credits.

Vineyard Wind 1 approval

Undoubtedly, the key development was BOEM's approval in May 2021 of the Vineyard Wind 1 project. Sponsors Avangrid and Copenhagen Infrastructure Partners (CIP) had signed a lease agreement in August 2020 for the Bedford, Mass., terminal to be used as the primary staging and deployment base for construction of Vineyard Wind 1 even as initial equipment and monopiles will arrive directly from Europe. In March 2021, Vineyard announced a contract with DEME Offshore U.S., which will bring a wind turbine installation vessel (WTIV) from its mother company in Denmark, and cooperate with the FOSS Maritime Co. of Seattle, Wa., which will bring in Jones Act compliant vessels.

Separately, the BOEM has filed a notice of intent (NOI) to prepare an environmental impact statement (EIS) for the COP submitted by Avangrid's 804 MW Park City Wind offshore in Connecticut. The NOI kicks off the two-year clock for ruling on the project COP.

Extension of tax credits.  As part of the signed Consolidate Appropriations Act in December 2020, the U.S. government extended the investment tax credit (ITC) eligibility timeline for offshore wind projects commencing construction prior to Jan. 1, 2026, while increasing the rate to 30%. Also the Treasury and IRS extended safe harbor to 10 years from 4 years for offshore wind projects that meet the "under construction" requirements by 2025. The safe harbor applies to both ITCs and production tax credits (PTC). The prior rules phased out the ITCs in 2020 at an 18% rate, subject to a four-year safe harbor requirement. This means that current projects can avail of the 30% rate, which previously may have embedded an 18% ITC rate in their forecasts.

Other salient developments over the past year include the following:

New York lease sales.  In August 2021, the BOEM announced the availability of a draft environmental assessment (EA) and the potential for offshore wind power in the New York Bight (between Long Island and New Jersey), with the lease area's total capacity expected to support up to 7.5 GWs. The announcement initiated a competitive lease sale of eight areas and we expect the new lease auctions to attract significant interest. New bidders were required to submit materials by Aug. 13, 2021. A final sales notice will likely be published with specific dates for the lease sale.

New Jersey solicitation No. 2.  New Jersey continues to move forward with its goal of 7.5 GWs of offshore wind by 2035--now at over 3.7 GWs. In September 2020, New Jersey's Board of Public utilities (BPU) issued its second solicitation with a procurement target of 1,200 MW to 2,400 MW of capacity. Only two entities had bid in this solicitation--Ørsted and EDF/Shell.

In June 2021, the BPU awarded a total of 2,658 MW to two projects, Atlantic Shores Offshore Wind (1,510 MW), a joint venture between EDF-Renewables Offshore Development LLC and Shell New Energies US LLC, and Ocean Wind II (1,148 MW), to be developed by Ørsted's Ocean Wind II LLC. The New Jersey BPU plans on running a third offshore wind solicitation for at least 1.2 GWs in 2022.

Agreement between BOEM and Army Corps of Engineers.  The formal agreement, signed in June 2021, allows the Corps to provide BOEM more scientific and technical resources needed to evaluate offshore wind projects in the Atlantic. Specifically, the BOEM now has access to the Corps' technical expertise while planning new leasing in the Atlantic and reviewing National Environmental Policy Act documents and COP proposals.

North Carolina Executive Order.  In June 2021, Gov. Roy Cooper issued an executive order setting offshore wind targets of 8 GW by 2040, with an interim target of 2.8 GW of offshore wind resources by 2030. We note Duke's recent integrated resource plans included the option to build 2,650 MW of offshore wind in the state, while Avangrid has proposed to build the 2,500 MW Kitty Hawk Offshore Wind project.

Introduction of Offshore Wind Bill in California.  In May 2021, the Biden Administration and California agreed to consider wind development off the state's coast. Initially, projects would be built 20 miles offshore with room for about 380 wind turbines. In May, the California Senate Energy, Utilities, and Communications Committee approved AB 525, which will direct state agencies to set statewide goals for offshore wind. We note that the Pacific Ocean is deeper than the Atlantic and will require floating wind turbines. We think that introduction of a bill on a second coast underscores the potential expansion of the U.S. offshore wind market.

New York awarded a second round.  In the state's second solicitation for offshore wind, the New York State Energy Research and Development Authority (NYSERDA) selected two projects for contract negotiation: Empire Wind 2 and Beacon Wind, both from Equinor Wind US LLC (Equinor). Combined, the projects will deliver 2,490 MW. We note that with these awards, New York now has five offshore wind projects in active development totaling more than 4,300 MW and representing nearly 50% of the capacity needed to meet New York's goal of 9,000 MW by 2035.

U.S. Offshore Wind Projects Are Costly For Now, But Economics Are Improving

Our estimate for the levelized cost of energy (LCOE) without the benefit of any investment tax credit (ITC) is about $85/MWh. At the other end of the bookend, a 30% ITC reintroduction, lower our estimates to about $65/MWh (see table 3). Our major assumptions relate to overnight capital costs and capacity factors. In discussions with industry experts we see onshore infrastructure issues and supply chain issues bringing capital costs to levels closer to $3,800-$4,200/KW for the initial projects, and higher than what sponsors are currently guiding to. Conversely, we see capacity factors higher at the 48%-50% range, up from our February 2020 assumption of about 44%.

The sensitivities below are illustrative and are also influenced by assumptions relating to O&M costs, debt equity ratios, financing costs, and depreciation method. For example, we think we may be conservative on capacity factors but somewhat aggressive on O&M cost assumptions.

Table 3

image

Skeptics point to the current costs of offshore wind projects and infrastructure needs, while proponents allude to rapid innovations in the industry. We acknowledge that our LCOE outcomes could vary widely as a number of variables are at play. We think our analysis provides relevant guidance on both the opportunities and the risks for offshore wind. Given these are estimates under U.S conditions, it is for the industry to convince us of its potential and the bankability of transactions from a credit perspective.

For transparency, we have presented our detailed assumptions in the appendix. We think our sensitivities capture the gamut of possibilities, based on which we make the following observations:

  • Unlike renewables like onshore wind or solar PV, which have become competitive with natural gas generation on a LCOE basis, offshore wind does not currently screen well.
  • O&M costs vary widely. In our model, a 30% increase in O&M costs to $125/KW-year, increased LCOE's by $5/MWh.
  • Yet the levelized value of merchant payments from wholesale power, say, about $35/MWh, capacity at $5/MWh and renewable energy credits (REC) at ($25/MWh) could be in the vicinity of the Vineyard Wind contract, implying that states would not be paying a significant premium for meeting renewable targets in 2023-2025.
  • Levelized offshore wind prices have shown two broad trends: a secular decline in prices, countered by the persistence of price disparity among various regional markets. This price differentiation is somewhat structural, as the scope of projects differs across markets; for example, generation-only versus generation/transmission. That is why our overnight capital costs estimate specifies whether it is inclusive of, or ex-transmission.
  • Benefits like the ITC, and technological innovations are extremely important to the decline in LCOEs toward conventional technologies. For instance, we think a 10% increase in capacity factors, and the 30% ITC improves LCOE economics by $18-$20/MWh, each, all else equal.

Yet There Is Substantial Interest From Investors And Lenders

Given that most market participants agree that offshore wind generation is uncompetitive the level of interest is counterintuitive. Even as offshore wind is currently uneconomical, we think investors have interest in taking offshore wind exposure on their books for the following reasons:

  • The potential of a dramatic decline in costs once the industry scales up based on the European experience.
  • Offsetting risk profile compared with onshore wind.
  • Resource characteristics that offer other risk mitigants.
  • Tax credit support.

We will discuss the potential risks and rewards for LCOE improvement elsewhere in the commentary but underscore here the relevant points noted above.

Onshore wind and solar PV risk offset

Revenue contract.  Offshore risks are different from the risks its onshore counterparts are exposed to. With buildout (construction), turbine performance (operations), balance-of-plant (O&M cost predictability), and resource risk (track record) demonstrated, the uncertainties the onshore wind asset class faces are substantially reduced. Consequently, sponsors are introducing merchant tails in onshore wind financings. In contrast, offshore wind will be largely contracted but retain construction and O&M risks.

Resource characteristics.  Not only is the onshore resource relatively smaller, it is often far from major load centers. In contrast, offshore resource is closer to major load centers and higher-priced wholesale power markets.

Expected capacity factors.  As a rule of thumb, the industry expects offshore capacity factors about 15% higher than onshore wind, or about 48%-50%. At these levels, offshore wind matches the capacity factors of gas-fired, or coal-fired, generation in many regions. Moreover, capacity factors for offshore wind are the highest in the evening, and coincident with evening peak power prices. Offshore wind is also seasonal. In the winter, when energy needs in New England peaks, capacity factors can reach 65%-70%, compared with capacity factors of 20%-25% in the summer. Thus, offshore resource risk complements natural gas deliverability, which is not constrained in the Northeast during the summer, but is tighter in the winter. Importantly, while offshore wind is still variable, its hourly variability is markedly less so than solar PV. It typically fluctuates in a narrower band of about 20% from hour-to-hour, compared with 40% for solar PV.

These characteristics mean that offshore wind's system value could be generally higher than onshore wind's and more stable than PV solar.

Credit Factors We See As Relevant

In discussions with industry experts about offshore wind projects, the focus was not on resource risk or turbine performance. What was of utmost importance was factoring in costs of upgrading onshore transmission, placement of projects in ISO queues to interconnect on time, and the areas for offshore cables to tie into. Integrating 29 GW of already proposed offshore wind plants will certainly require the development of networked offshore grids and approximately 3,000 miles of offshore transmission lines.

Offshore PPA pricing is significantly higher

For now, policy objectives in the Northeast and Mid-Atlantic support offshore wind initiatives, yet prices of offshore wind PPA contracts remain well above current power market prices and are also 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 see 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.

We note that auction prices have fallen, which we expected to see as technology improved, but the recently awarded prices of $60-$90/MWh are materially lower than the $98-$135/MWh awards a few years back. While lenders are more comfortable with financing offshore wind projects, the industry has become more competitive with margins increasingly under pressure and the larger oil and gas companies starting to become involved.

Decline in costs due to innovations

The International Energy Agency (IEA) expects global average overnight capital costs (including transmission) to decline to $2,500/KW by 2030 from about $4,550/KW in 2018. This is based on an assumed learning rate that sees capital costs decline by 15% each time global capacity doubles. The global offshore wind market grew nearly 25% per year between 2010 and 2020. The U.S. Energy Information Agency currently estimates overnight capital costs at $4,300/KW.

The industry expects roughly half the decline in future costs from efficiency gains associated with larger turbines. Using higher rated turbines for a given project size reduces the number of turbines to be installed and serviced, effectively yielding lower balance of plant costs (faster installations, fewer turbines to be serviced) as well as more energy per unit of area. Manufacturers have reportedly been able to increase the turbine rating without increasing the unit cost of the turbine. The average turbine size used in offshore wind increased to 5.5 GW in 2018 from 3 GW in 2010. In 2018, the largest installed was the MHI-Vestas 8.8 MW turbine.

Turbine capacity has been a key factor in lowering costs; the first U.S. offshore wind project used 6 MW turbines in 2014-16, whereas the projects being planned will use 8-13 MW turbines. The trend of upscaling existing turbine platforms was disrupted by the announcements of larger prototypes with increased rotor diameters (GE's 12 MW Haliade-X; Siemen's SG 10.0-193 DD, etc.), which will be rolled out in 2022. Also, in 2020, Siemens Gamesa announced 14 MW turbines, with a 222-meter rotor diameter. The industry is targeting even larger 15-20 MW turbines by 2030.

Potential for cost escalation

Technology-led secular cost reductions are typically seen in the longer term with scale. Over the next two to three years, cost inflation appears an increasingly critical issue given the recent 10%-20% increases in raw materials. Sponsor Avangrid asserts that most of its costs for Vineyard Wind will likely be transferred to suppliers in the near term, given contract contingencies. However, we continue to see cost inflation as a risk for offshore wind in the medium term.

Construction delays

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 see two-year construction timelines as aggressive given 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 think delays are likely—even potentially protracted delays for some projects--given the construction windows is mostly between May and October. In particular, the principal timing-related restriction is that piling of monopiles must be in the May to 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, especially since the U.S. is lacking in the port infrastructure required to handle the massive construction efforts. Also, 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.

Often, sponsors remain confident about the construction schedule, while noting the timing windows for various aspects of their projects (for instance, piling of monopiles in the spring) add complexities largely due to regulations and environmental restrictions. We note that Eversource recently announced delays in the operations date for both Revolution Wind and Sunrise Wind. We expect the 800 MW Vineyard Wind project to start construction in second-half 2022, with operations starting 2023 and commercial operation date in 2024.

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.

Geographic concentration of the supply chain would further reduce offshore wind costs, as 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.

Separate, yet related, this ties back to our comment on the speed of state mandates. States are announcing their commitments to offshore wind so that this supply chain would come to them.

Costs For Hardening Of Grid Infrastructure May Be Underestimated

There is a meaningful complexity to the grid that cannot be wished away. For transmission operators, position in the queue ultimately dictates what upgrade costs will be onshore. In New York, for instance, the wind resource is about 15 to 30 miles offshore and access to it is limited by shipping lanes emanating from New York City. Given congestions that are typical in New York, there are limited interconnection opportunities with the onshore grid.

For New England, onshore interconnection points are even further from the offshore sites compared to 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 New Jersey, beyond Oyster Creek, the onshore grid in southern New Jersey 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.

Offshore transmission

Although significant efficiencies can be achieved, they require significant cooperation, which has yet to be witnessed. Interconnect could thus be an overlooked risk, given the amount of coordination needed and the various complexities (for instance, 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 result in delays in construction alignment. At the same time, a key benefit of offshore wind is the avoidance of the transmission issues faced by onshore renewables given 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 push back from various stakeholders due to the environmental impact on coastal waters, wetlands, fishermen, and communities. With multiple 400 MW to 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 see as key are:

  • Choosing between offshore generation ties versus offshore grids.
  • High voltage direct current (HVDC) versus HVAC station ties.

Gen-ties versus offshore grids.  Broadly, we have figured out that generation-ties to individual offshore wind plants that are within 30 miles from 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 generation. This is particularly the case with plants far from shore and relatively close to each other.

HVDC versus HVAC.  HVDC solutions 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 the relatively more expensive DC converter stations. As a rule of thumb, HVAC station appear to be 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 backlog with essentially only two suppliers at present.

Logistical Issues Are More Pronounced 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), yet going too far may make the project costly and complex. We think the ideal distance is about 25 miles.

In assessing a project's cost and complexity, we think 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, as well as construction and O&M costs, are directly related.

We note that U.S. projects will likely have higher depth (even on the Eastern seaboard) than European projects. 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.

Installation of equipment creates yet another set of issues, given the Jones Act, which states that if there is a vessel in transit between two U.S. ports, it must be U.S.-operated and constructed. While it is possible to obtain waivers for the Jones Act, this remains a significant impediment particularly for installation. Likelihood of receiving waivers varies, depending on the situation and the developer's ability to demonstrate prior efforts but inability to succeed.

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. Ørsted has been able to address this risk by striking a deal with Dominion Energy for a U.S. vessel in 2024-25, likely in time for its Northeast projects. In December 2020, Dominion Energy announced the construction of "Charybdis," the first Jones Act compliant offshore wind turbine installation vessel (WTIV), currently being constructed by the global marine shipbuilding company Keppel AmFELS at its Brownsville, Texas, shipyard. Two service operation vessels are also under construction one each by Crowley of Jacksonville, Fla., and ESVAGT (Denmark), and Edison Chouest Offshore (ECO) and Ørsted.

While sponsors believe Gulf Coast shipyards available to build vessels necessary for the installation of offshore wind are efficient, the Cato Institute noted that the lone WTIV currently under construction has an estimated price tag of approximately $500 million. In contrast, building a WTIV in South Korea with the same design (GustoMSC NG-16000X-SJ) but a more powerful crane costs $330 million. The Cato Institute further notes that the industry may need six to eight service operation vessels with estimated construction costs 80% higher than in Europe and 30 to 50 crew transfer vessels with an estimated 20% U.S.‐built cost premium.

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 note that the 30MW Block Island used a workaround to avoid contravening the Jones Act where a Fred Olsen Windcarrier installation vessel crossed the Atlantic with turbines and jackets but did not visit a U.S. port, instead offloading the components to a U.S.-flagged barge for transport to the offshore construction site off Rhode Island.

We highlight that 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 and/or a U.S. made jacked-up installation vessel is created, we see this as requiring more capital expenditures and time that must be already budgeted into plans.

Related Research

This report does not constitute a rating action.

Primary Credit Analysts:Aneesh Prabhu, CFA, FRM, New York + 1 (212) 438 1285;
aneesh.prabhu@spglobal.com
Kimberly E Yarborough, CFA, New York + 1 (212) 438 1089;
kimberly.yarborough@spglobal.com
Jason Starrett, New York + 1 (212) 438 2127;
jason.starrett@spglobal.com
Secondary Contacts:Massimo Schiavo, Paris + 33 14 420 6718;
Massimo.Schiavo@spglobal.com
Luqman Ali, CFA, Toronto + 1 (416) 5072589;
luqman.ali@spglobal.com
Matthew L O'Neill, New York + 1 (212) 438 4295;
matthew.oneill@spglobal.com

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