An Assessment of the Economic Potential of Offshore Wind in the United States from 2015 to 2030

Report

Title: An Assessment of the Economic Potential of Offshore Wind in the United States from 2015 to 2030
Publication Date:
March 01, 2017
Document Number: NREL/TP -6A20- 67675
Pages: 77
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Document Access

Website: External Link
Attachment: Access File
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Citation

Beiter, P.; Musial, W.; Kilcher, L.; Maness, M.; Smith, A. (2017). An Assessment of the Economic Potential of Offshore Wind in the United States from 2015 to 2030. Report by National Renewable Energy Laboratory (NREL). pp 77.
Abstract: 

This study describes an assessment of the site-specific variation of levelized cost of energy (LCOE) and levelized avoided cost of energy (LACE) to understand the economic potential of fixed-bottom and floating offshore wind technologies in major U.S. coastal areas between 2015 and 2030. The detailed methodology, assumptions, and context of this study are documented in A Spatial-Economic Cost Reduction Pathway Analysis for U.S. Offshore Wind Energy Development from 2015–2030 (Beiter et al. 2016). This earlier report focused on the development of a geospatial cost model of the offshore wind technical resource area in the United States and the relationship of geospatial and temporal parameters on the cost of energy up to 2030. The present study builds on the Beiter et al. (2016) analysis to document in detail the variation in economic potential across more than 7,000 U.S. coastal locations by comparing site-specific LCOE and LACE. In particular, this study offers insights into the available U.S. offshore wind resource by region at different levels of LCOE and an assessment of the present and future economic potential of that resource capacity out to 2030. The Crown Estate (2012) cost reductions assumed for this study should be considered in context of recent cost declines indicated by European offshore wind winning tenders. However, determining if and to what extent these recent European cost reductions will continue and how they can be translate d to a U.S. market context is beyond the scope of this study.

 

LCOE is the total cost of generating a unit of electricity and is commonly expressed in dollars per megawatt-hour (MWh) over the expected lifetime of the offshore wind electricity-generating plant. It varies by location because of spatial differences in energy production (e.g., average wind speed variations) and capital expenditures (e.g., varying sea states, distance from shore, water depth, soil and substructure suitability, and availability of critical infrastructure). However, LCOE alone is not sufficient to assess economic viability because it does not capture the electric system value that can be attributed to a generation source. Therefore, this analysis draws on a “simplified” version of LACE as a metric to capture the system value of a generation technology. LACE is a metric to approximate the electric system value of a generation technology over its expected lifetime and commonly expressed in dollars per-MWh as well. LACE varies by location because of differences in the system value of new electricity, which is determined by a range of factors, including the cost of competing generation technologies, the resource mix, demand patterns, and transmission constraints. The difference between LCOE and LACE at a given location (denoted in this report by “ net value”) can help inform an initial understanding of the economic potential of a new offshore wind project at a high geospatial resolution. For this analysis, policy-related factors that may influence LACE or LCOE (and hence, the “net value” of a renewable energy project) were not considered explicitly. For instance, renewable energy support mechanisms (e. g., the production tax credit, Renewable Portfolio Standards), energy sector and environmental regulations (e.g., carbon pricing), or benefits from portfolio diversification (Energy Information Administration [EIA] 2015) may increase the “net value” and economic potential. Conversely, regulatory uncertainty and market barriers (see e.g., DOE 2016) may decrease the “net value” and economic potential.

 

A series of data sources and reports were used to derive the assumptions and data for the underlying analysis documented in Beiter et al. (2016), including market reports (e.g., Moné et al. [2015]; Smith, Stehly, and Musial [2015]), U.S. electricity cost benchmark reports (e.g., EIA Annual Energy Outlook [AEO] 2014), offshore wind cost-reduction pathway studies (e.g., Beiter et al. (2016) ; Valpy et al. [2014]; Catapult [2015]; E.C. Harris [2012]; The Crown Estate [2012]; The Crown Estate [2015]), geospatial data layers, and expert elicitation.

 

Estimates of offshore wind costs were calculated for three focus years corresponding to commercial operation dates (CODs) of 2015, 2022, and 2027. In 2015, a baseline turbine rating of 3.4 megawatts (MW) was assumed as it reflect s the average turbine size of installed offshore wind power projects globally in 2014 (Smith, Stehly and Musial 2015). Informed by recent industry trends, turbine ratings of 6 MW and 10 MW were assumed as representative technologies for years 2022 and 2027, respectively. Corresponding to this assumed growth trajectory in turbine size, a set of cos t reductions and associated technology improvements were projected for 2015, 2022, and 2027 based on a recent assessment conducted by The Crown Estate, BVG Associates, and KIC InnoEnergy (The Crown Estate 2012; Valpy et al. 2014). Various assumptions were made to account for the nascent stage of the U.S. offshore wind industry and to project cost and technology parameters into the future. The first U.S. offshore wind power project came online for commercial operation in late 2016. As in this project, U.S. developers are expected to leverage European offshore wind technology, industry experience, and industrial capacity in early projects. Beiter et al. (2016) defined a scenario assuming that the U.S. offshore wind industry can leverage the recent European offshore wind technology and industry experience while addressing important physical, regulatory, and economic differences influencing U.S. projects. The cost-reduction pathway under this scenario applies projected cost reductions developed for European projects within the time frame from 2015 to 2027 and assumes sufficient domestic deployment and supply chain maturity to support these cost reductions in the United States during the analysis period.

 

Based on the methodology and assumptions from Beiter et al. (2016), this analysis provides detailed outputs of the following:

  • Maps showing spatial distribution of LCOE, LACE, and net value for five U.S. coastal regions including the Atlantic Coast, Pacific Coast, Gulf of Mexico, Great Lakes, and Hawaii for each of the focus years (2015, 2022, and 2027)
  • National and regional supply curves of offshore capacity ranked by LCOE for fixed-bottom and floating technology types
  • Estimated LCOE plotted by different water depths and distance from shore for fixed-bottom and floating offshore wind technology.

The results presented in this study are intended to inform a broad set of stakeholders to enable an initial assessment of offshore wind as part of energy development and energy portfolio planning. It provides information that federal and state agencies and planning commissions may use to inform initial strategic decisions about offshore wind development in the United States. Although this analysis is the first of its kind to provide a comprehensive assessment of the economic potential for offshore wind at a high geospatial resolution across major U.S. coastal regions, more detailed site-specific assessments are needed to inform actual offshore wind project planning.

 

This study finds that estimated reductions in LCOE over the next decade coincide with relatively high levels of LACE in some U.S. regions. By 2027, a considerable amount of economic potential was estimated for the Northeast and the e a stern shore of Virginia.

 

It is also observed that the supply and net value curves were relatively flat, indicating that even a small change in LCOE or LACE has the potential to trigger significant changes in the amount of economic potential calculated. This effect resulting from relatively flat supply curves would be most relevant in regions that have a net value close to zero, such as the Northeast, mid-Atlantic, Great Lakes, and Gulf Coast in 2027, or in regions where policies are in place to incentivize renewable energy, such as California. The relatively high degree of sensitivity to changes in LCOE and LACE also indicates a moderate amount of uncertainty in the quantity of actual resource found to have “economic potential.” As a result, the conclusions of this assessment should be re-evaluate d as market conditions or costs change.

 

Some general observations include:

  • Offshore wind sites with economic potential are located predominantly in the Northeast and e astern shore of Virginia
  • Across all regions, the number of sites with a positive net value (or a value close to a positive net value) increase over the time period considered
  • State policies have driven offshore wind development recently (e.g., in New York and Massachusetts); these policies may play a key role when assessing the economic viability of offshore wind but are not considered in this analysis
  • Further technology improvements are needed to achieve the cost reductions of this assessment
  • Some regions will likely require unique technology solutions (e.g., to address low wind speeds in the Gulf, icing in Great Lakes, and deep-water floating solutions in the Pacific and Hawaii)
  • The value of offshore wind to the electric grid system under some high-penetration renewable energy scenarios may not be fully represented by net value as calculated in this study.

A number of limitations and opportunities for further work are indicated throughout this report. The results from the Beiter et al. (2016) assessment utilized in this study were produced with innovative models and assumptions, which may be refined as new tools and validation data become available. For this national-scale assessment, a number of simplifications and uncertainties exist that may affect the accuracy from reported results at any individual location. These simplifications and uncertainties range from the development of first-order tools that do not capture the entire set of parameters taken into account for a detailed site assessment, the suitability and availability of technology during the time period considered, and general uncertainty related to the formation of a domestic supply chain and macroeconomic factors. Limitations and corresponding caveats are discussed in Beiter et al. (2016). Some of the most important caveats from Beiter et al. (2016) include the following:

  • To achieve the modeled cost reductions in the United States, a key assumption is that there will be continued investments in technology innovation, developments, and the market visibility of a robust domestic supply chain commensurate with the established European offshore wind supply chains during the analysis period from 2015 to 2027 and sustained domestic offshore wind development (U.S. Department of Energy [DOE] 2015; Navigant 2012; European Commission 2016).
  • The Crown Estate (2012) cost reductions assumed for this study should be considered in context of recent cost declines indicated by European offshore wind winning tenders. However, determining to what extent these recent reductions in European winning bids will continue in the future and how they translate to a U.S. context is beyond the scope of this study.
  • This analysis includes a preliminary assessment of LACE limited by available data and a set of simplifying assumptions. It does not consider competition among technologies, dynamic feedback from increasing renewable deployment on wholesale electricity prices, export or import situations, or the alleviation of electricity system constraints (e.g., transmission constraints) over time. Further refinement and additional data could improve this indicator.
  • In this study, LACE was estimated based on annual averages of marginal generation prices and a constant capacity value. This specification does not take into account the subhourly, hourly, or seasonal coincidence of offshore wind generation profiles with marginal generation prices or capacity value. For instance, if an offshore wind site produced electricity during times when it is in high demand (e.g., during peak load events in the late afternoon), the revenue opportuni ties (as represented by marginal generation prices or capacity value) would likely be higher. Such an assessment was not within the scope of this study.
  • The validity of LACE varies by region because of spatial differences in data availability. As described in Section 2.2, a hierarchy of data sources was compiled to proxy marginal generation prices. This may be a particular concern in the Pacific Northwest coastal regions where neither locational margin price, market marginal cost, or partial locational margin price data w ere available and marginal generation prices were derived from neighboring regions in California and Nevada and regions in the Pacific Nor thwest with partial locational margin price data only.
  • As applied here, policy-related factors that may influence LACE or LCOE (and hence, the “net value” of a renewable energy project) were not considered explicitly. For instance, renewable energy support mechanisms (e.g., the production tax credit, renewable portfolio standards), energy sector and environmental regulations (e.g., carbon pricing, loan guarantee programs), or benefits from portfolio diversification (Energy Information Administration [EIA] 2 015) may increase the “net value” and economic potential. Conversely, regulatory uncertainty and market barriers (see e.g., DOE 2016) may decrease the “net value” and economic potential.
  • As a result of how competing use areas were applied in Beiter et al. (2016) and Musial et al. (2016) (as a share of competing use and environmentally sensitive areas), some of the least-cost LCOE sites identified in this study may not be available in practice for offshore wind development because of human use trade-offs (e .g., conflicting use related to viewshed concerns, shipping lines, marine protected areas and fishing [see e.g., DOE 2016]).
  • The calculation of economic potential should not be used as a prediction for actual project deployment. Economic potential indicate s that the revenue at a given site may exceed its costs in the local energy market, but it does not guarantee that the technology will be selected. Conversely, a negative net value indicating the lack of economic potential at a given site does not necessarily imply that economic viability is not achievable because of general modeling uncertainty related to the development of future costs, electricity prices, policy, and renewable targets (see Section 2.3).
  • This study only assesses the economic potential of offshore wind and is not a metric of profitability. For a full sectorwide assessment of economic competitiveness, the economic potential from all competing technologies would have to be taken into consideration (see e.g., EIA 2014). For instance, another generation technology may exhibit a net value that is greater than the estimates for offshore wind at any of the assessed sites.
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