- In the past few years, the pipeline for U.S. offshore wind generation has quickly expanded and totaled 26 gigawatt (GW) as of the end of 2019.
- We believe this power source's levelized costs of energy (LCOE) are still uneconomic in the U.S., at more than $85 per megawatt hour (MWh; or $65/MWh with a tax credit), compared with those of competing technologies.
- Yet, there's tremendous investor interest due to the complementary nature of offshore wind generation with its onshore counterpart.
- State mandates are also increasing, given that offshore wind could foster local economic development and mitigate dependence on natural gas.
- The potential for cost declines from technological innovations is substantial, as seen in Europe's experience.
- However, infrastructure-related risks, associated with venturing offshore, are meaningful.
- Nearly half of the offshore wind LCOE gap between Europe and the U.S. stems from costs related to hardening of onshore transmission networks and development of offshore transmission.
- Our ratings will incorporate the fully contracted nature of revenues, but also the potential logistics bottlenecks during construction, and potentially higher operations and maintenance (O&M) costs than for European offshore farms during operations.
Legend has it that in picking the name for his rock band, The Doors, Jim Morrison was inspired by the title of one of Aldous Huxley's books, "The Doors of Perception". The title itself was derived from a line in William Blake's "The Marriage of Heaven and Hell" poem: "If the doors of perception were cleansed, everything would appear to man as it is, infinite".
S&P Global Ratings doesn't profess to know the infinite, or for that matter, what will happen in the long term. But we have views on the current and medium-term trends. Over the next several weeks, in a series of articles titled "Foresight Is 2020," we will provide our views on some major themes in the power sector, such as the latest developments in battery economics and technologies, and in contracts in renewable power that include merchant tails. This article will focus on developments in, and key credit drivers for, offshore wind in the U.S.
Latest Developments In The U.S. Offshore Wind Industry
Renewable energy standards (RPS) or carbon reduction goals are driving market activity in states--such as California and Hawaii--without offshore wind procurement targets. However, this article focuses on developments in the Northeast, because most queries that we receive from investors are largely limited to this region.
Despite only one operating offshore wind farm, Block Island (30 megawatt [MW] in output), the U.S. currently has an aggregate pipeline of more than 26 GW in offshore wind capacity in federal lease areas. Out of this pipeline, developers expect 14 offshore wind projects totaling 9.1 GW to be operational by 2026 (see table 1). All market consultants with whom we spoke agree that the capacity could exceed 12 GW by 2030, but regulatory uncertainty will influence the speed of build-outs. (Vineyard Wind's permitting has been delayed at least until March 2021).
|Pipeline Of U.S. Offshore Wind Projects|
|Project name||Sponsors||Size (MW)||COD||Offtake mechanism||Pricing ($/MWh)||Counterparties||Term (years)||Location and turbines||Remarks|
|Vineyard Wind 1 (Martha's Vineyard project)||Avangrid/Coppenhagen Infrastructure Partners||804||2022||PPA||$74/MWh for 400 MW (2022) then $65 for the next 400 MW (2023) with a 2.5% escalation per year||Eversource, Unitil, National Grid||20||South of Massachusetts’ Martha’s Vineyard island. MHI Vestas will supply 84 of its V164-9.5MW turbines.||Nominal levelized at $84.23/MWh over contract period. It may still qualify for the 21% ITC as permitting delays can possibly be recognised 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.|
|Block Island||Deepwater (Orsted)||30||2016||PPA||$244/MWh with a 2.5% escalation pace||National Grid||20||3.5 miles from Block Island in the Atlantic. Five Alstom Haliade 150-6-MW turbines.||Contributing to the project’s support in 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 and Eversource||400||2023||PPA||$98.4/MWh||National Grid||20||Deepwater ONE North zone||704 MW between the Connecticut and Rhode Island PPAs.|
|Revolution Wind 1 & 2||Ørsted and Eversourse||304||2023||PPA||$94.0/MWh||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 agreed to buy 200MW at $94/MWh and an additional 100MW with pricing set to be made public.|
|Park City Wind||Avangrid/Coppenhagen Infrastructure Partners||804||2025||PPA||Currently being negotiated||Eversource and United Illuminating||20||23 miles off the coast of Massachusetts|
|Ocean Wind||Ørsted and PSEG||1100||2024||Offshore Wind Renewable Energy Credits (ORECs)||$98.10 OREC price escalates at 2% through 2045. 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||15 miles off Atlanctic City's coastline. 90 GE Haliade-X 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 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 3 tranches of 368 MW each in partnership with PSEG.|
|Empire Wind||Equinor (formerly Statoil)||816||2024||OREC||$83.36/MWh with an OREC offset of $25.14/MWh. Payments rise and fall based on a composite average of energy and caapacity 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 $3 billion 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.|
|Sunrise Wind||Bay State Wind, LLC (Orsted and Eversource)||880||2024||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||90||2022**||PPA||Undisclosed||Long Island Power Authority||20||Deepwater ONE North zone off the coasts of Rhode Island and Massachusetts. Siemens Gamesa a conditional contract to supply 8MW SG 8.0-167 turbines.|
|US Wind||Renexia Spa||248||2020||OREC||Maryland awarded ORECs for 20 years at $131.94/MWh (one OREC for each MWh delivered to the grid)||20||32 turbines; 17 miles off Ocean City||Each year, 913, 945 ORECs 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 ORECs will be sold at a levelized price of $131.94/MWh.|
|Coastal VA offshore wind||Utility owned||12||2022||PPA||$780/MWh||Vepco|
|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 orginally funded under the DOE advanced technology demonstartion project program **Still require some federal permits.|
Projects progressing through the offtake and permitting approval process continue to be primarily located in the Northeast, where state-level procurement drives the market and project development. Six states have targeted nearly 6.3 GW of offshore wind capacity through state-issued solicitations. Multiple projects also made significant progress with electricity offtake agreements and environmental permitting at both the state and federal level.
In 2019, state-backed targets and renewable mandates for clean energy continued to build momentum with about 26 GW of offshore wind procurement targets established to date. (To be clear, the pipeline of offshore wind projects and state-backed mandates for such power source generation are separate from each other, but are coincidentally 26 GW each). This capacity, compared with just 8 GW in mid-2018 (see chart 1), will account for about 30% of the 86 GW of total U.S. offshore wind capacity, according to the Department of Energy' (DOE) forecast through 2050.
We expect Maryland and North Carolina to be the next states where we could see increasing activity, particularly as a frontrunner developer in these states hasn't been established.
The industry got yet another fillip in September 2019 following Virginia governor's executive order calling for 2.5 GW in offshore wind capacity in the state by 2026. Shortly after, Dominion Energy, Inc. announced plans to build and own a 2.6 GW offshore wind farm, the largest project announced in the U.S. to date. The latter will extend the offshore footprint further south along the eastern coastal states, whereas North Carolina, South Carolina, and Georgia have yet to announce mandates for such power generation. There's also a rising interest in developing projects along the Pacific Coast and the Great Lakes region. The West Coast, especially northern California and southern Oregon, has good wind resource but will likely require floating installations because water depths are deeper.
On the federal level, the Department of Interior's Bureau of Ocean Energy Management (BOEM) has issued 15 active commercial wind energy leases so far. In 2020, we expect additional solicitations, because Massachusetts, New Jersey, and North Carolina possess substantial offshore wind resources. BOEM is currently in the planning stages for areas off the coasts of California, Hawaii, New York, and South Carolina, and the agency expects to hold lease auctions for new lease areas off the coasts of California and New York later this year.
U.S. Offshore Wind Is Currently Uneconomical
Our estimate for the LCOE for U.S. offshore wind, excluding an investment tax credit (ITC), is about $85/MWh. A 30% ITC lowers our estimates to about $65/MWh (see table 2). Our major assumptions for overnight capital costs and capacity factors are $3,600 per kilowatt (kW) and 44%, respectively, for the initial projects. Nevertheless, some projects in Europe along with those for competing technologies, have lower LCOEs.
The table below shows in more detail our assumptions, which are influenced by O&M costs, debt equity ratios, financing costs, depreciation methods, etc. For example, we may be conservative on capacity factors, but somewhat aggressive on O&M cost assumptions.
Skeptics point to offshore wind projects' current economics and the infrastructure needs, and costs, while proponents allude to a rapid pace of innovations in the industry. We acknowledge that our LCOE outcomes could vary widely because of a number of variables. But we believe our analysis provides relevant guidance on what could drive both the opportunity and the risks for offshore wind generation. In discussions with industry experts and acknowledging the potential for significantly lower costs, we're cautiously optimistic about prospects for offshore wind energy output. However, given these estimates, the onus is on the industry to convince us of offshore wind's potential from a credit perspective.
For transparency, we have presented our detailed assumptions in the appendix. We believe our sensitivities capture the wide range of possibilities, based on which we make the following observations:
- Without ITC, the current LCOE levels for offshore wind are substantially higher than those for alternative energy sources, such as natural gas peakers and onshore wind at $68/MWh and $40/MWh, respectively.
- Unlike renewable energy sources such as onshore wind or solar PV, competitiveness of which against natural gas- and coal-fired generation has risen on the LCOE basis, offshore wind currently doesn't fare well; a point which NextEra Energy Inc. underscores in its criticism, which we will get to later in the article.
- O&M costs vary widely. In our model, a 30% increase in O&M costs to $125/kW per year increases the LCOE requirement by $5/MWh.
- Yet, the levelized value of merchant payments from wholesale power--say about $40/MWh, capacity at $5/MWh, and renewable energy credits at $25/MWh--could be similar to the contract price for the Vineyard Wind project, implying that states wouldn't be paying a significant premium for meeting renewable targets in 2023-2025.
- LCOEs for offshore wind facilities have shown two broad trends: a secular decline in prices, but countered by the persistence of price disparity among various markets. The price differentiation is somewhat structural, given that the scope of projects varies across markets; i.e. generation only versus generation and transmission.
- The ITC and technological innovations substantially contribute in driving down offshore wind LCOE towards those of conventional technologies. For instance, we believe a 10% increase in capacity factors, or the reintroduction of a 30% ITC, drops LCOE by $20/MWh, while other factors remain unchanged.
But Investors And Lenders Are Taking Much Greater Interest
At a recent industry forum, a banker noted that there were more than 50 financing entities that have a 'real interest' in lending to offshore wind projects in the U.S. Given that most market participants agree that offshore wind has yet to post a competitive challenge to other energy sources, that level of interest is counterintuitive. Nevertheless, we believe investors' interest stems from the following factors:
- The potential for a dramatic decline in costs once the industry scales up, as seen in Europe's experience.
- Some risk-offsetting features compared with onshore wind generation.
- Resource characteristics that mitigate other types of risks.
We will discuss the potential for lower LCOE later in the article, but we underscore the risk-mitigation potential of offshore wind.
Risk comparison among renewable power sources
Revenue contracts. Risks for offshore wind farms are different from those that onshore counterparts face. Due to several years of experience under the belt--in terms of construction, turbine performance, O&M cost predictability, and track record of power generation--risks for the onshore wind asset class has substantially subsided. Consequently, sponsors are now introducing merchant tails in onshore wind financings in the U.S. and a similar trend is taking shape in Europe's offshore wind industry. In contrast, we expect offshore wind output in the U.S. to be largely contracted, but such facilities will bear construction and O&M risks. Offshore wind farms also grapple with intricacies of tax-credit qualifications and turbine risks, although the latter are largely borne by turbine manufacturers.
Resource characteristics. Not only onshore wind generates lesser volume of energy, location of such facilities is often far from major load centers. In contrast, offshore resource is closer to major load centers and higher-priced wholesale power markets. However, we believe production forecasts could be affected by 'blockage' and 'wake' effects (see notes at the end of the article). These factors could affect the estimates of third-party data providers during forecasting for resource levels.
Expected capacity factors. As a rule of thumb, the industry expects offshore wind capacity factors of 40%-50%, about 10% higher than those of onshore wind farms. At these levels, offshore wind matches the capacity factors of gas- or coal-fired generation in many regions. Moreover, capacity factors for offshore wind farms are the highest in the evening (typically 45%-50%) and coincide with peak power prices during that period. Offshore wind capacity factors are also highest in the winter months (50%-55%)than in the summer (25%-30%). Importantly, while offshore wind's availability is still variable, its hourly variability is markedly lower than that of solar PV. It typically fluctuates at about 20% from hour to hour, compared with 40% for solar PV.
These metrics point to offshore wind's potentially higher efficiency than that of onshore wind and PV solar generation. Yet, the track record of an offshore wind asset, particularly in seabed conditions is currently unknown: wind farms in Europe have been operational only for 10 years.
States Are Mandating Offshore Targets
Although offshore wind has a long way to go to challenge other energy sources, interest has increased dramatically at the U.S. state level in recent years, largely because of the following factors:
- Meeting RPS goals and shifting away from natural gas- or coal-based power;
- Expectations of a substantial decline in costs due to innovations; and
- The lure of boosting local economic development and job creation.
Attaining RPS goals
Reliance on natural gas generation among states with offshore wind output targets is higher than the national average of 35%. For instance, such power generation accounts for about 50% of New Jersey and Massachusetts' total output. While gas-fired generation in New York is about 35% because New York City relies on the Indian Point nuclear power plant for 15%-38% of its needs, while the state plans to shutter this plant in 2020 and 2021, and its output has been already replaced by two 1,000 MW CCGTs.
According to table 5 in the appendix, our calculations show that the Northeast could reduce its natural gas usage by more than 2.5 billion cubic feet per day if the currently announced offshore wind mandates of 26 GW are implemented. We made the simplifying assumption that the gas-fired plants with an average heat rate of 8,500 British thermal units per kilowatt hour operating at a 50% capacity factor, are displaced at the same rate as an offshore wind farm (with the same capacity factor) is brought online.
In addition to helping states in attaining RPS targets, offshore wind generation helps wean these states away from natural gas, enabling them to reach their regional greenhouse gas initiative (RGGI) targets.
The potential for falling costs due to innovations
According to the International Energy Agency (IEA), global average overnight capital costs (including transmission) are projected to decline to $2,500/kW by 2030 from $4,350/kW in 2018. This is based on assumptions that capital costs fall 15% each time the global capacity doubles. The global offshore wind market grew nearly 30% per year between 2010 and 2018. WindEurope, an association that promotes the use of wind power, estimates that capital costs for offshore wind farms (excluding transmission) for 2018 on the continent were about $2,870/kW, a 45% reduction since 2015.
The industry expects that roughly half of the decline in future costs will come from efficiency gains by using larger turbines. This will reduce the number of turbines to be installed and serviced, lowering the balance-of-plant costs, and raising the energy per unit of area. Manufacturers have reportedly been able to increase the turbine structure without lifting its unit cost. The average offshore turbine size rose to 5.5 GW in 2018 from 3.0 GW in 2010. In 2018, the largest installed turbine was MHI-Vestas 8.8 MW. Moreover, the trend of upscaling existing turbine platforms was disrupted by plans to roll out prototypes with larger rotor diameters (such as GE's 12 MW Haliade-X and Siemen's SG 10.0-193 DD) in 2021-2022. The industry is targeting even larger, 15-20 MW, turbines by 2030. Similarly, as the power capacity of turbines continues to rise, wind developers and operators are increasingly shifting to the 66–kV array cable technology from the conventional 33-kV systems, leading to lower electrical infrastructure costs. Table 6 in the appendix contains our assumptions, showing how larger rotor diameters improve turbine production and reduce costs.
The potential to bolster local economic development
The plot thickened after NextEra, a large electric utility and renewable energy proponent, came out strongly against offshore wind last year. However, at about the same time, Dominion Energy announced an $8 billion investment in offshore wind farms. We actually think both positions have merit, despite the apparent contrarian positions.
NextEra based its argument on its assessment of the potential for higher infrastructure costs, cost overruns, and timing delays. The company's views are premised on its success in the renewable space and the tried-and-tested economics of its onshore wind and solar PV businesses. The company believes that the U.S. has vast and still untapped onshore renewable resources. It also stated that the U.S. faces lower obstacles in expanding the onshore wind capacity than countries across the pond. Separately, yet related, we note that Florida has a lesser offshore wind resource and a coastline not as conducive for such a build (current offshore wind turbines are designed using IEC 61400-03 standards, which define a three-second maximum gust condition of 156 miles per hour).
On the other hand, once state officials decide that offshore wind is in the 'public interest', it's logical for the incumbent utilities to consider this source in their energy mix, given a likelihood of rate-based treatment. Dominion Energy's decision came soon after Virginia's executive order ushering in an offshore mandate. Given the European offshore wind farms' achievement of dramatic cost cuts underscores the U.S. players' willingness to jump on the bandwagon.
But there are other factors at play. States are announcing offshore wind renewable targets because at stake is an opportunity to also jumpstart a supply chain, estimated at $70 billion based on nearly 20 GW of offshore facilities that we expect to be constructed over the decade to meet state policy requirements. Indeed, it's a race; build them and they will come.
Many states on the East Coast already have a fairly robust maritime economy. For instance, Virginia boasts shipyards, large naval facilities (submarine manufacturing, etc.), Coast Guard, the fishing industry infrastructure, and coastal residential communities. Turbine manufacturers may consider such factors as sufficient to establish a supply chain on the Eastern Seaboard. These include new ports and expansions of existing ones, harbor redevelopments, and manufacturing facilities.
Incentives for local development are already incorporated in several auction outcomes. For example, in its 2019 auction, Massachusetts chose the bid package that had the lowest cost, while New Jersey chose the one that offered the highest local content. Massachusetts is somewhat unique among states procuring offshore wind projects, given that its bid evaluation process is driven almost entirely by costs. However, pressure is mounting on Massachusetts to consider the effects on local economic development. The ability to justify a higher cost and the drive to increase local content has prompted some wind developers to offer a range of options from strictly low-cost offerings to those
|Examples Of Local Incentives And Local Content|
|Project name||Local incentives/development|
|Mayflower||$3.7 billion of rate reduction and 10, 680 jobs over the project. $1.2 billion of spending in economically stressed regions. 75% of O&M jobs will be local.|
|Revolution Wind 1 and 2||A $93 million infrastructure upgrade. At least $15 million investment in the State Pier to allow substantial aspects of the project to be constructed in New London. Significant portions of construction and/or assembly will occur in New London, including foundation components and the offshore substation. Contracting with a Connecticut-based boat builder to construct one of the project’s crew transfer vessels in Connecticut.|
|Park City Wind||$890 million in direct economic development (local supply chain and bridgeport harbor), and includes redevelopment of an 18.3 acre waterfront industrial property.|
|Ocean Wind||The winning bid expects to generate $1.17 billion in economic benefits, in addition to creating about 15,000 jobs over the project life. New Jersey’s BPU said Ørsted won partly on the basis of having the most detailed plans for economic development in the state, including the strongest guarantees around local content and manufacturing. Among other commitments, Ørsted plans to open an operations and maintenance base for the project in Atlantic City.|
|Source: S&P Global Ratings.|
Given that certainty in state policy and commitment towards offshore wind generation is a pre-requisite, we believe development of such projects is likely in those states that pursue RPS targets aggressively, and have a relatively predictable political environment because offshore wind farms require meaningful time spanning from permitting to the completion of construction.
What Are Our Expectations?
We expect M&A activity to ramp up, both at a company and asset level. Despite losing to Vineyard Wind in Massachusetts' first offshore wind solicitation, Ørsted acquired a developer, Deepwater Wind, for $510 million. The purchase gave the company the largest footprint in the U.S. market, with offtake deals in New York, Connecticut, Rhode Island, New Jersey, and Maryland.
Developers are forging partnerships with incumbent utilities to ease the way in winning offtake contracts. With its partnerships with Public Service Enterprise Group (PSEG; Ocean Wind) and Eversource Energy (Revolution Wind and Sunrise Wind), we view Ørsted as a clear frontrunner at this stage. We expect other major developers--such as Equinor ASA, a subsidiary of Norway's Statoil ASA, and a joint venture between Shell Energy North America (US) LP and EDP Renewables--to continue exploring partnerships. Consolidated Edison, Inc. and Dominion Energy have yet to commit to a partner for a 2.6 GW project. Ørsted is developing a demonstration project off Virginia's coast in partnership with Dominion, but the latter has yet to make a decision.
Finally, Equinor recently won a New York solicitation, while Shell New Energies (a subsidiary of Royal Dutch Shell plc) is operating in Massachusetts through Mayflower Wind. It's no coincidence that a number of oil majors--Royal Dutch Shell, Statoil, and Eni SpA--are also offshore wind developers. These companies have many reasons to move into the industry. They've spent decades building oil projects offshore, and that business is winding down in areas where older fields have been depleting. Returns from wind farms are predictable and underpinned by long-term contracts. And oil giants want to get a piece of the clean-energy business amid forecasts that renewable energy will eat into their market shares.
The IEA estimates that about 40% of the full lifetime costs of an offshore wind project, including construction and maintenance, has synergies with the oil and gas sector. Given that offshore energy operations share technologies with offshore wind facilities, oil and gas companies started investing in offshore wind projects many years ago.
Risks Of Venturing Out Into The Deep Waters
Europe had little choice but to take the sea route due to lack of available land for further onshore wind power facilities. In the U.S., wind developers will also grapple with risks of constructing offshore platforms, because building the transmission infrastructure will be their responsibility (see sidebar 1). In discussions with industry experts, it became apparent that the major concern over U.S. offshore wind generation doesn't pertain to resource risk, turbine performance, or even construction. Instead, unplanned costs of upgrading onshore transmission, placement of projects in independent system operator (ISO) queues to interconnect on time, and the areas to tie in offshore cables became the larger focus. Integrating 26 GW of the proposed offshore wind output on the East Coast will almost certainly require the development of networked offshore grids and approximately 3,000 miles of offshore transmission lines.
Europe uses several models for developing offshore wind transmission. In the U.K., for instance, licenses for offshore transmission assets are granted through competitive auctions that require wind developers to build transmission lines, and then transfer them to the ISO or to a competitively appointed offshore transmission owner for operation. Such a mechanism affects construction, but not operational, costs.
In other European markets such as Germany, the Netherlands, France, and Denmark, the system operator currently provides the offshore grid connection, and in some cases, the offshore substations. Denmark has recently announced its intention to include the development of offshore transmission assets into its competitive bidding framework. On the other hand, under contract terms in Germany, a wind developer is only responsible for expenditures related to intra-array cabling and the offshore substations, but not for the rest of the export cable system. This has led to delays in connecting wind farms to the onshore grid initially, affecting the overall construction program, as seen in the high amounts of new capacity connecting to the grid starting in 2015. In the U.S, building out of the transmission access will be the developer's responsibility.
We classify offshore risks in the following matter:
- Ability to achieve capacity factors similar to European levels (energy production);
- Hardening of grid and existing infrastructure; and
- Logistics barriers: the Jones Act, import of components, and other O&M issues.
Ability to achieve capacity factors
Potential sites in the U.S. don't have as detailed data about geological, oceanographic, and meteorological conditions as European projects, which increases the initial development risks of wind farms, and consequently, the costs to finance them. With the development of projects and collection and verification of data, the uncertainty associated with these variables would diminish. From a credit perspective, there's no way to quantify this, and our analysis would likely incorporate a lower capacity factor (for example, 44%, compared with higher levels in Europe).
Hardening of onshore grid infrastructure and establishing offshore transmission
For transmission operators, position in the queue ultimately dictates what upgrade costs are necessary for onshore grid. 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 congestions that are typical in New York, there are limited interconnection opportunities with the onshore grid.
In New England, onshore interconnection are even further from the offshore sites than in New York. As a result, interconnections by using the existing transmission infrastructure at retired coal-fired power plants (such as Brayton Point) are vital and will require transmission build-out for grid reliability purposes. Similarly, at New Jersey's southern end, aside from the Oyster Creek nuclear power plant, the onshore grid is fairly weak, likely requiring significant reinforcements at local landing points, or building offshore connections to more robust--but more distant--landing points in the northern part of the state.
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 impact on coastal waters, wetlands, the 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
- High voltage direct current (HVDC) versus HVAC station ties.
Generation-ties versus offshore grids
Broadly, we have figured out that 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 after 130 years, we're 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 two suppliers in the market.
Depth and distance. Ideally, offshore wind farms should be located within a 'goldilocks' distance from the shore: not too close because of the potential of public backlash, as seen in the abandonment of the Cape Wind project, but not too far, because of greater costs and complexity. We believe the ideal distance is about 25 miles from the shore. This is also the distance at which the HVAC or HVDC decision becomes crucial. (Besides, 26 miles is equivalent to 42 kilometers, and 42 is the answer to the riddle of the universe).
We should mention that in assessing a project's cost and complexity, it's more relevant to consider the distance to critical infrastructure than that to the shore. As more projects are permitted and constructed, developers may run into more difficulty finding suitable grid connection points, requiring longer export cables. Nevertheless, the distance between the wind farm and service port will be a weighty cost factor, because access to turbines, as well as construction and O&M costs are directly related.
We note that U.S. projects will likely be built at a greater depth (even on the Eastern Seaboard) than their European counterparts. Northern Europe's sea landscape is characterized by the shallow bathymetry of the North Sea, allowing wind farms to be located far from the shore while still using fixed-bottom foundations.
Availability of barges for installations. We highlight that the availability of U.S.-made barges, which can transport offshore wind equipment to the foundation, is also in limited supply. Before a supply chain on the Eastern Coast is built out and/or a U.S.-made installation vessels are manufactured in sufficient numbers, we believe more capex and construction time must be budgeted into plans.
While multiple marine engineering companies (such as GustoMSC B.V., Zentech Inc., and A.K. Suda Inc.) have drafted designs and conducted cost studies for U.S.-flagged installation vessels, very few offshore installers announced construction of a new vessel through 2018. In fact, only as recently as December 2019, the first U.S.-based offshore wind service operations vessel (SOV) to be compatible with the Jones Act was approved by the American Bureau of Shipping, a maritime classification body. The SOV, which Canada-headquartered Vard Marine developed, is designed to provide personnel accommodation, transfer technicians to offshore turbines, as well as storing spare parts and tools for U.S. offshore wind farms. According to the latest DOE report on offshore wind, the only known vessel development in 2018–2019 was Ørsted entering into partnership with WindServe Marine to construct two crew transfer vessels--one in North Carolina and the other in Rhode Island--for use at the Coastal Virginia Offshore Wind and Revolution Wind projects.
The Jones Act
The Jones Act requires any ship delivering goods from one port to another in the U.S. to be domestically made, and flagged and crewed by U.S. residents. However, 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.
Imported components. Not surprisingly, there are significant gaps in the U.S. offshore wind supply chain that prevent the realization of cost savings comparable to those in Europe. Currently, the U.S. supply chain is not well inventoried, and lacks necessary workforce, port facilities, etc. Almost all of the offshore wind components, including rotors and turbines, slated for the U.S. projects are currently manufactured in Europe. The supply chain expansion in the U.S. would further reduce costs, as proximity decreases transportation costs and fosters better communication between the supply chain members. This clustering strategy also allows for more robust project management and top-to-bottom collaboration on projects. This ties back to our comment on the speed of state mandates. States are announcing their commitments to offshore wind with the aim of attracting the supply chain members to set up shop near the sites.
What Does All This Mean For U.S. Offshore LCOEs?
To get a better insight of the potential for reducing costs, along with risks, we took a stab at comparing U.S. and European LCOEs. To do this, we incorporated our estimates for U.S. and European costs in our LCOE model. We bucketed the variables into one of the risks noted above. This helped us identify what factors need to improve most in order for U.S. costs to decline to European levels. So, for instance, enhancing existing infrastructure and grid connections would diminish the difference in our capital costs estimates, while costs associated with the Jones Act are captured in the differences in O&M costs. The table and chart below summarize our assumptions and results.
Information in table 4 is illustrative but shows where cost reductions would have to be achieved to reach European price levels. Note that this analysis doesn't assume any ITC benefits.
|Assumptions In Our LCOE Model|
|U.S. East Coast||Latest German auction||Remarks|
|Capacity factors (%)||44||50||Global offshore wind capacity factor averages have improved to 43% from 38% in 2018 and are likley to be higher. We have chosen 44% to account for the fact that a proven technology is being used at locations where resource data is not as robust as in Europe.|
|Overnight capital cost ($/kW)||3600||2850||Recall that German costs are ex-transmission. We capture the difference in grid connection and hardening of existing infrastructure costs here. While some projects would beat this estimate, we think that the 2022 estimates of $3,000/KW, assumed by a major project, are aggressive.|
|O&M costs ($/kW per year)||95||75||We capture logistics issues through this difference. Major items here would be costs associated with the Jones Act as well as import of components (currency differences and transportation costs). We think this assumption could be aggressive. U.S. projects would need to demonstrate ability to come in under this level.|
|Cost of equity (%)||12||12||European returns are lowering . We've assumed 12% is a return developers should be able to earn in Europe even as competition accelerates. While the U.S. is riskier, we've assumed no difference as developers are more interested in scaling.|
|Cost of debt (%)||5.5||3.5||Debt rates for global offshore wind financing remain at historically low levels, ranging between 3% and 4% for 15-year debt terms.|
|Risk premium (%)||8||Consultation with industry experts suggests that early commercial-scale U.S. projects might expect higher contingency levels relative to the established European offshore wind markets.|
|Source: S&P Global Ratings.|
As we mentioned earlier, in many countries, including Germany and France, wind developers are responsible solely for completing the wind farms. However, in the U.K, Japan, South Korea, and the U.S., developers are also responsible for building out transmission. Based on our assessment, about 50% of the cost difference stems from the higher infrastructure and grid connections costs, which we believe will be tough to address.
Wind developers in the U.S. could learn from the overseas experience. The industry has to avoid repeating the mistakes made by the oil majors during the LNG infrastructure construction in Australia, which experienced significant cost overruns due to duplication of infrastructure. This highlights the need to disperse the costs in a collaborative manner among developers and constructing offshore- and onshore-shared services wherever possible.
A step in the right direction is the partnership between Anbaric and the Ontario Teachers' Pension Plan, which filed an application with the BOEM in November 2019 to develop an open-access offshore transmission system that will connect up to 16 GW of offshore wind energy to southern New England states. The Southern New England OceanGrid project would be established on the outer continental shelf in order to link the existing wind lease areas in Massachusetts, Rhode Island, and Connecticut through a common system. Similarly, the New York/New Jersey OceanGrid 1,200 MW project proposes to minimize the number of cable routes through the connection of multiple wind farms to HVDC cables that run to the shore.
Our conclusions are consistent with those of the IEA's March 2019 "Special Report Offshore Wind Outlook 2040" regarding the differences between the European and U.S. LCOEs. The IEA notes that the U.S. would require supportive policies like the ITC--even as costs decline--to bridge the gap with Europe. The IEA captures the lower variability of the offshore wind resource in its value-adjusted LCOE.
How We Would Factor These Risks Into Our Project Finance Rating Assessments
Offshore wind farms are often project financed on a non-recourse 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.
Our commentary titled "Offshore Wind: A Changing Sea Of Risk," dated Oct. 3, 2017 (see the Related Research section) presents a detailed explanation of how we would rate an offshore wind project. Here, we briefly highlight key factors for such projects in the U.S.
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 that the Cape Wind project encountered and which was ultimately cancelled in 2017. Technological enhancements could also help during the lengthy securing of permits
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.
Given the limited operational history of some newer turbines, our assessment of them might range from 'proven' to 'proven but not in this application'. 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 will assess only the turbine and foundation technologies, which have an operational track record and support reliable long-term forecast, as 'proven'.
We would combine construction, logistics, and interface risks here.
A well-structured engineering, procurement and construction (EPC) 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 that construction risk is abating. Not so initially for U.S. projects.
For this assessment, we take into consideration not only the wind project's size and turbine capacity, but also 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).
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 'construction difficulty' assessment, underscoring 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 would typically occur after the substation foundations or topsides were installed. This occasionally led to delays in the cable installation program because of delays in the construction of the offshore substation. 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 it's aggressive and possible only if everything goes as planned. We will likely expect additional contingencies for projects that schedule a two-year construction window.
Asset risk score. We generally assign a score of '5' to offshore wind projects with the asset class operation stability--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 consider that they face a greater likelihood of O&M cost overruns, weaker availability, and declining efficiency than their onshore peers.
Operating leverage (O&M costs). 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. Our determination would depend in large part on our understanding of the budget, often based on discussions with a technical expert.
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. We expect the offshore resource to be stronger and more predictable than the onshore one. Our resource and raw material risk assessments range from 'minimal' to '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 'modest' or 'moderate' 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 if 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 were able to use data collected during a four-year period, at hub height, approximately 1 km away from the edge of the project's site. This info 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.
Counterparty risks. During the operational phase, the 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 in the case 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.
Wind Of Change
The offshore industry started just 30 years ago. Elkraft, one of the predecessors of DONG Energy (now Ørsted), began considering 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 in the former USSR, and the fall of the Berlin Wall.
That brings us a full circle back to our musical references. In 1990, to commemorate the changes sweeping across Europe, Scorpions, the German rock band, released a single called 'Wind of Change'. The song topped the charts in Germany and across Europe and peaked at number 4 in the U.S. and number 2 in the U.K. The power ballad 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".
Offshore wind is indeed changing the European power landscape. It remains to be seen if the industry brings in sweeping changes to the power industry in the U.S.
- The Energy Transition: Is Offshore Wind Done Or Going For Other Bids?, Feb. 18, 2020
- Offshore Wind: A Changing Sea Of Risk, Oct. 3, 2017
- Offshore Wind Projects Take Off As Technology Improves And Costs Fall, June 2, 2017
- With Offshore Wind Projects Set To Take Flight, What Factors Will Move Ratings?, Feb. 12, 2016
Our Base-Case LCOE Assumptions (In Table 2 we have provided sensitivities)
Capacity factors: 44%
Initially, 44% in the U.S. to take account of the 'blockage' and 'wake' effects. Ørsted has noted that these can become significant. We will assume load factors at this level unless proven otherwise. We note that the industry assumes 48%, given that Block Island registered such a level. Ørsted has recently come to the same conclusion. We acknowledge that based on improving technologies, the industry has the potential to surpass these estimates.
Overnight capital costs: $3,600/KW
A recent National Renewable Energy Laboratory paper estimates overnight capital costs at about $3,800/kW, but notes that the range could be from $2,500/kW to $5,700/kW. Separately, DOE notes that global capital costs ranged between $2,500/kW and $6,500/kW in 2018. We view $3,600/KW of capital costs for the initial projects despite the sponsors' lower estimates.
Several factors may explain the variation in capital costs:
- Varying spatial conditions (e.g., water depth, distance to the port, point of interconnection, and wave height of sites that affect technical requirements of installing and operating a wind farm);
- Project size (typically 400 MW and higher have statistically lower capital costs);
- Various levels of supply chain shortages (e.g., components, vessels, and skilled labor); and
- Risk premium and bidding behavior (pricing strategies from equipment suppliers and installation contractors).
O&M costs: $95/kW per year or about $19/MWh
O&M cover all costs incurred after COD--but before decommissioning--that are required to operate the wind farm and maintain turbine availability to generate power. These expenditures are generally thought to contribute between 20% and 30% to life cycle costs, depending on site characteristics. The strongest drivers are distance from the O&M port, accessibility limits related to local meteorological conditions (e.g., wave height), and turbine rating (fewer, larger turbines mean lower O&M costs per MW). The estimate we used is 23%-25% of the overall lifetime costs. These are the toughest to estimate because they wary widely for existing projects---ranging from $65/kW per year to nearly $200/kW per year. We believe we may be a bit aggressive in our assumptions, and O&M costs could be higher for the initial projects.
Cost of debt: 5.5%
Debt interest rates for global offshore wind remain at historically low levels, ranging from 3% to 4% for 15-year debt terms. Initial projects will likely tap loans from banks because the latter are more flexible during construction period. This is our institutional market estimate for a 15-year financing. (In the U.S., lending is usually 7-10 years.)
Cost of equity: 12%
Revenue contracts have no merchant risk but permitting risks are significant. In the U.S., a federal, state, and local permit to construct and operate a wind power plant is not included in a lease award. This might introduce additional risks such as legal action, permitting delays, and stranded assets, compared with those of acquiring a fully permitted lease area.
We assumed no ITC in our LCOE calculations. In the scenario where we used 30% ITC benefits, debt/equity was rebalanced to 50%/50%.
Asset life: 25 years
The longest offtake contracts (New York) are for this term. Most are 20 years.
Depreciation: we used MACRS
Projects with the COD prior to 2022 can use 100% bonus depreciation with a phase down. We didn't, to be conservative.
Risk premium: 8%
Installation and operation contingencies. Consultations with industry experts suggest that early commercial-scale U.S. projects might expect higher contingency levels relative to the established European offshore wind markets. These serve to account for lesser experience in the U.S. offshore wind power plant installation and operation with the risk of incurring delays and interruptions in the supply chain, marine logistics, and permitting processes.
Investment tax credits
We didn't consider them, but they would be an upside. Two bills in Senate—the Markey-Whitehead six-year extension of a 30% credit, and Carper-Collins extension of the 30% credit through 2027, or 3 GW installed, whichever comes first. An additional consideration affecting project economics is whether offshore export cables qualify for ITC inclusion. The issue is whether the cable is considered a part of the generating equipment of an offshore wind farm. Vineyard Wind may likely qualify for the 21% ITC, given that permitting delays can possibly be recognized by tax authorities as a valid reason to maintain pre-qualified tax-credit levels.
|Regional Natural Gas Displacement|
|Amount of Gas displaced (Bcf/d)|
|Capacity factor (%)||50%||b|
|Hours in a year (Hr)||8,760||c|
|Average heat rate of displaced Units (mmBTU/MWh)||8.5||d|
|Energy produced (MWh)||4,380,000||e=a*b*c|
|Gas needs (mmBTU)||37,230,000||f=e*d|
|Days in a year||365||g|
|Natural gas displaced (BCf/d)||0.102||h=f/(g*1000000)|
|Displacement of 26 GW (bcf/d)||2.65||h*26|
|1 mmBTU= 1 MCf 1=BCf= 1,000,000 Mcf. Source; S&P Global Ratings.|
|Turbine Blade Efficiencies To Lead To Cost Reductions|
|Diameter of the rotor blade||90||220|
|Area of the circle swept (m2)||6,359||37,994||b=∏ * a2|
|Speed of air (m/s)||10||10||c||20 miles/hr; converted from mtr/sec to miles/hr|
|density of air (kg/m3)||1||1||d|
|Mass of air in kg/sec||63,585||379,940||e=b*c|
|Kinetic Energy (joules/sec)||3,179,250||18,997,000||0.5 *m*v2||kinetic energy of the wind|
|Kinetic Energy (in Watts)||3.2||19.0||MW||joules/sec= Watts|
|Efficiency of a turbine blade||45%||45%||See note on maximum efficiency of 59%|
|Power (MW)||1.43||8.55||MW||Scaled up 6x by only doubling the rotor diameter|
|Source: S&P Global Ratings.|
|Current State Offshore Wind Mandates|
|State||Nearest RPS goal||RPS year||Offshore capacity commitment (MW)||Statutory authority||Year enacted|
|6,600||Climate Leadership And Community Protection Act||2019|
|NJ||50%||2030||3,500||Executive Order 8; Assembly Bill 3723||2018|
|3,500||Executive Order 92||2019|
|MA||35%||2030||1,600||House Bill 4568 to promote energy diversity||2016|
|1,600||House Bill 4857 to advance clean energy||2018|
|CT||31%||2030||300*||House Bill 7036||2017|
|2,000||House Bill 7156||2019|
|VA||2,500||Executive Order 43||2019|
|MD||50%||2030||1,200||Senate Bill 516 set targets||2019|
|RI||38%||2035||1,100||No specific statuatory Bill|
|Notes: RPS goals are staged over time. Only nearest goals are included. *100 MW came from technology-neutral auctions|
The 'blockage' effect arises from the wind slowing down as it approaches the wind turbines. There's an individual blockage effect for every turbine position and a global effect for the entire wind farm, which is larger than the sum of the individual effects.
The 'wake' effect is the slowing in wind speed, occurring in the individual wind farm and between neighboring ones. The phenomenon is caused by a turbine. But as the wind flow continues, the wake effect diminishes and the wind speed recovers.
In 1919, a German physicist, Albert Betz calculated that the most efficiency that you extract from a wind turbine is 59%. To explain this, imagine a turbine that could extract 100% of the kinetic energy from the wind flow. No kinetic energy left in the wind means no velocity left in the wind. If the velocity leaving the blades is zero, then the air wouldn't be leaving at all. As a result, the air after the blades won't be getting out of the way of the incoming air, and no air flowing through the turbine blades would mean no power. In order to keep the wind moving through the turbine, there has to be some velocity in the air after going through the blades to make way for the incoming air. This is why the machine's efficiency can't be 100%. So according to Mr. Betz's calculations, a perfect wind turbine would be able to convert about 59% of the power in the wind into mechanical rotating power. In practice, this power coefficient ranges between 35% and 45%.
This report does not constitute a rating action.
|Primary Credit Analysts:||Aneesh Prabhu, CFA, FRM, New York (1) 212-438-1285;|
|Luisina Berberian, Madrid +(34) 91-788-7200;|
|Sunneva Bernhardsdottir, Toronto + 416 507 3258;|
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