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Operated by the Alliance for Sustainable Energy, LLC

This report is available at no cost from the National Renewable Energy

Laboratory (NREL) at www.nrel.gov/publications.

Contract No. DE-AC36-08GO28308

Assessment of Offshore Wind 

Energy Leasing Areas for the 

BOEM Massachusetts Wind 

Energy Area

W. Musial, Z. Parker, J. Fields, G. Scott, 

D. Elliott, and C. Draxl

National Renewable Energy Laboratory

Produced under direction of the Bureau of Ocean Energy 

Management (BOEM) by the National Renewable Energy Laboratory 

(NREL) under Interagency Agreement M13PG00002 and Task No.

WFS3.1000

Technical Report

NREL/TP-5000-60942

December 2013
NREL is a national laboratory of the U.S. Department of Energy

Office of Energy Efficiency & Renewable Energy

Operated by the Alliance for Sustainable Energy, LLC

This report is available at no cost from the National Renewable Energy

Laboratory (NREL) at www.nrel.gov/publications.

Contract No. DE-AC36-08GO28308

National Renewable Energy Laboratory

15013 Denver West Parkway

Golden, CO 80401

303-275-3000 • www.nrel.gov

Assessment of Offshore Wind 

Energy Leasing Areas for the 

BOEM Massachusetts Wind 

Energy Area

W. Musial, Z. Parker, J. Fields, G. Scott, 

D. Elliott, and C. Draxl

Prepared under Task No. WFS3.1000

Technical Report

NREL/TP-5000-60942

December 2013
NOTICE

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Contract No. DE-AC36-08GO28308 with the U.S. Department of Energy. This report was prepared as an account 

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Cover Photos: (left to right) photo by Pat Corkery, NREL 16416, photo from SunEdison, NREL 17423, photo by Pat Corkery, NREL 16560, 

photo by Dennis Schroeder, NREL 17613, photo by Dean Armstrong, NREL 17436, photo by Pat Corkery, NREL 17721.

Printed on paper containing at least 50% wastepaper, including 10% post consumer waste.
iii

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Acknowledgments

The National Renewable Energy Laboratory (NREL) would like to acknowledge the support and 

cooperation of the Bureau of Ocean Energy Management (BOEM). Additionally, as part of this 

work, NREL received cooperative assistance from the Massachusetts Clean Energy Center, 

Massachusetts Office of Coastal Zone Management, and other members of the BOEM 

Massachusetts Renewable Energy Task Force. 

The following NREL reviewers and contributors are acknowledged: Sheri Anstedt, Ian BaringGould, Donna Heimiller, Fort Felker, Pat Moriarty, Brian Smith, and Suzanne Tegen. 
iv

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at www.nrel.gov/publications.

Executive Summary

The U.S. Department of Energy’s (DOE) National Renewable Energy Laboratory (NREL), under 

an interagency agreement with the Bureau of Ocean Energy Management (BOEM), is providing 

technical assistance to identify and delineate leasing areas for offshore wind energy development 

within the Atlantic Coast Wind Energy Areas (WEAs) established by BOEM. This report 

focuses on NREL’s development of three delineated leasing area options for the Massachusetts 

(MA) WEA and the technical evaluation of these leasing areas. 

The overarching objective of this study is to develop a logical process by which the MA WEA 

can be subdivided into non-overlapping leasing areas for BOEM’s use in developing an auction 

process in a renewable energy lease sale. NREL worked with BOEM to identify an appropriate 

number of leasing areas and proposed three delineation alternatives within the MA WEA based 

on the boundaries announced in May 2012. A primary output of the interagency agreement is this 

report, which documents the methodology, including key variables and assumptions, by which 

the leasing areas were identified and delineated. 

As part of the study, NREL researchers: 

1. Developed a process and criteria to create four to five leasing areas within the BOEM 

MA WEA announced by BOEM in May 2012. 

2. Presented their preliminary methodology and technical approach for analysis at a webinar 

with the intergovernmental BOEM Massachusetts Task Force on May 15, 2013 (Musial 

2013). 

3. Reviewed and assessed the proposed development parameters provided in eight responses 

to the 2011 BOEM Massachusetts Request for Interest (RFI) and in 10 responses to the 

February 2012 Call for Information and Nominations (the “Call”). 

4. Revised the methodology to delineate the MA WEA and addressed feedback received 

from the intergovernmental BOEM Massachusetts Task Force, BOEM, Massachusetts 

Clean Energy Center, and Massachusetts Office of Coastal Zone Management. 

5. Identified three alternatives for delineating the MA WEA (Figure ES2) into four to five 

leasing areas and conducted analyses to compare and evaluate the different delineation

scenarios. 

6. Evaluated potential phased developments using one and two 500-megawatt (MW) 

projects in each leasing area (one earlier in shallower water and one later in deeper water) 

and the effect of different turbine spacing scenarios on wake losses, energy production, 

and potential development challenges. 

7. Prepared this report summarizing the NREL technical approach and final 

recommendations to BOEM for leasing area delineations within the MA WEA and the 

effects of different turbine spacing and water depth scenarios on potential development 

and energy production. 

8. Will present the final results of this report in a live webinar to the intergovernmental 

BOEM Massachusetts Task Force in late 2013. 
v 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 

at www.nrel.gov/publications.

In addition to the references in Section 9, NREL reviewed and used information from the 

following sources for this report: 

• The RFI published by BOEM in the Federal Register in December 2010 for offshore 

Massachusetts and eight responses to the RFI 

• The Call published by BOEM in the Federal Register in February 2012 and 10 responses 

to the Call

• The MA WEA coordinates that were developed by BOEM and provided to NREL for the 

delineation analysis

• Presentations delivered at the Massachusetts Renewable Energy Task Force webinar held 

on May 15, 2013 

• Verbal input received from a conference call with the Massachusetts Clean Energy 

Center and Massachusetts Office of Coastal Zone Management on May 20, 2013 and 

follow-up discussions. 

As a result of discussions at the Massachusetts Renewable Energy Task Force webinar on May 

15, 2013, and follow-up correspondence with the Massachusetts Clean Energy Center, 

Massachusetts Coastal Zone Management, and BOEM, NREL obtained feedback that was used 

in developing the final methodology and delineation options for the analysis of the MA WEA. 

The final methodology included: 

• Development of delineation alternatives for a four leasing area (Alternative 1) and a five

leasing area scenario (Alternative 2) with equal division of shallower water [less than 50 

meters (m)] in each leasing area

• Development of a third delineation option (Alternative 3) for five leasing areas consisting of 

four leasing areas with equal division of shallower water less than 50 meters and one leasing 

area with deeper water (greater than 50 m) 

• Evaluation and comparison of the full development nameplate potential capacity (based on 

total area) of the leasing areas in all three delineation alternatives using turbine array spacing 

in rotor diameters (D) of 8 D x 8 D, 8 D x 12 D, and 8 D x 15 D 

• Evaluation and comparison of phased developments of two 500-MW projects in each leasing 

area (one built earlier in 6−8 years in shallower water and one built later in 10−16 years in 

deeper water) and the effect of different turbine spacing configurations (8 D x 8 D, 8 D x 12

D, and 8 D x 15 D) on wake losses, energy production, and development challenges. 

For each of the delineation options, several quantitative evaluation criteria were examined and 

other qualitative criteria were considered. These criteria are listed in Table ES1. 
vi 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 

at www.nrel.gov/publications.

Table ES1. Evaluation Criteria Used to Assess the Massachusetts (MA) WEA

(Source: NREL)

Quantitative Evaluation Criteria Qualitative Evaluation Criteria 

Total area (km2 and acres) Distance from shore

Maximum nameplate capacity [megawatts (MW)] Technology challenges

Bathymetry [meters (m)] Development cost

Annual average wind speed and direction [meters per 

second (m/s)]

Interconnection logistics 

500-MW phased developments Development timing

Wake losses (%) and array efficiency

Array orientation angle (degrees)

Turbine spacing within array [rotor diameters (D)]

Capacity factor after wake losses (%)

Annual energy production [gigawatt-hours (GWh)]

The water depth, or bathymetry, map in Figure ES1 shows that water depths range from about 35 

m to 65 m across the MA WEA.

Figure ES1. Water depth map for the MA WEA

(Source: NREL)
vii 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 

at www.nrel.gov/publications.

The average water depth was about 50 m for the entire MA WEA. Deeper water (50 m and 

above) is prevalent over the southern parts of the WEA and shallower water is found in the 

northern portions of the WEA. Most of the MA WEA leasing areas will be affected significantly 

by the water depth in terms of cost and development challenges. Note also that the prevailing 

wind direction, shown in the wind rose in the upper right corner of Figure ES1, is perpendicular 

to the isobaths (lines of constant depth) in Figure ES1 and parallel to the delineation lines in 

Figure ES2. 

The three alternatives were discussed and agreed upon with BOEM over several iterations and 

are shown in Figure ES2. The criteria for selecting these delineations were based on the 

following assumptions and constraints: 

• Number of leasing areas. The leasing process was limited to a maximum of five nonoverlapping leasing areas that would together make up the total area of the MA WEA.

• Equalizing shallow water resource. The delineations attempted to equalize the amount of 

shallow water below 50 m in each of the leasing areas.

• Minimizing external wake effects. Delineation lines were drawn at a 45-degree southwestto-northeast diagonal to be approximately parallel to the prevailing southwest wind direction 

(see wind rose in Figure ES1).

• Wind resource. Average wind speed in each leasing area was considered across the MA 

WEA and found to vary between 9.2 and 9.4 meters per second (m/s). These variations are 

low and as a result average wind speed did not play a major role in delineation boundary 

decisions. 

The three delineation options are shown in Figure ES2. 
viii

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 

at www.nrel.gov/publications.

Figure ES2. The three leasing area delineation options that NREL analyzed include: Alternative 1, 

four diagonal leasing areas; Alternative 2, five diagonal leasing areas; Alternative 3, five leasing 

areas with one deep area. The lighter green color indicates water depths below 50 m and the 

darker green color indicates water depth above 50 m. The MA WEA wind rose is shown at the top 

right.

(Source: NREL)

Table ES2, Table ES3, and Table ES4 provide a summary of the quantitative results for the three 

different delineation alternatives assessed by NREL for the MA WEA in Figure ES1. The 

analysis was conducted primarily with the use of the AWS Truepower OpenWind Enterprise tool 

(AWS Truepower 2012). Wind turbine array modeling was based on the NREL 5-MW reference 

turbine (Jonkman et al. 2009). 
ix

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 

at www.nrel.gov/publications.

Table ES2. MA WEA Delineation Analysis for Alternative 1 

(Source: NREL)

Delineation Alternative 1

Parameter Leasing 

Area 1

Leasing 

Area 2

Leasing 

Area 3

Leasing 

Area 4

Total area (km2) 759 676 1,004 569

Total area (<50m) 407 415 408 395

Ave. depth (m) 47.6 51.8 47.9 49.8

Bathymetry – depth range (m) 36.0−61.0 37.6−63.0 34.0−62.0 33.0−61.4

Ave wind speed at 90 m (m/s) 9.3 9.3 9.4 9.2

8 D x 8 D Full Development

Wake losses (%) 10.6 12.3 12.4 10.5

Gross capacity factor (CF) after wake 

losses (%) 45.2 44.4 44.4 46

Potential capacity (MW) 3,430 2,715 4,450 2,505

Annual energy production (GWh) 13,590 10,557.6 17,331.8 10,094.9

8 D x 12 D Full Development

Wake losses (%) 8.3 9.9 10 8.3

Gross CF after wake losses (%) 46.4 45.6 45.7 47.2

Potential capacity (MW) 2,305 1,855 2,955 1,695

Annual energy production (GWh) 9,366 7,411.7 11,836.3 7,006.1

8 D x 15 D Full Development

Wake losses (%) 7.2 8.7 8.8 7.3

Gross CF after wake losses (%) 46.9 46.2 46.3 47.7

Potential capacity (MW) 1,850 1,455 2,360 1,360

Annual energy production (GWh) 7,601.6 5,891.5 9,574.3 5,684.2

8 D x 8 D Phase 1 (500 MW each)

Wake losses (%) 6 6.9 5.7 5.4

Gross CF after wake losses (%) 47.7 47.4 48.2 48.8

Potential capacity (MW) 500 500 500 500

Phase 1 depth range (m) 33.0−45.0 36.0−42.0 37.6−45.0 34.0−44.0

Annual energy production (GWh) 2,091 2,078.3 2,114.3 2,138.3

8 D x 8 D Phase 1 and 2 (1,000 MW each)

Wake losses (%) 6.3 8.3 7 6.3

Gross CF after wake losses (%) 47.5 46.6 47.4 48.2

Potential capacity (MW) 1,000 1,000 1,000 1,000

Phase 2 depth range (m) 44.7−51.0 43.0−50.0 45.0−51.0 46.0−50.0

Annual energy production (GWh) 4,162.3 4,083.9 4,159.2 4,229.1
x 

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8 D x 12 D Phase 1 (500 MW each)

Wake losses (%) 5.2 6.2 5.1 4.9

Gross CF after wake losses (%) 48.1 47.8 48.5 49

Potential capacity (MW) 500 500 500 500

Phase 1 depth range (m) 33.0−47.0 36.0−45.0 37.2−46.0 34.6−46.0

Annual energy production (GWh) 2,109.7 2,093.8 2,127.9 2,148

8 D x 12 D Phase 1 and 2 (1,000 MW each)

Wake losses (%) 5.9 7.3 6.4 5.7

Gross CF after wake losses (%) 47.7 47 47.7 48.5

Potential capacity (MW) 1,000 1,000 1,000 1,000

Phase 2 depth range (m) 46.0−53.0 46.0−53.3 48.0−54.0 47.0−59.0

Annual energy production (GWh) 4,179.6 4,119.6 4,180.4 4,253.5

8 D x 15 D Phase 1 (500 MW each)

Wake losses (%) 5 5.8 4.9 4.5

Gross CF after wake losses (%) 48.3 47.9 48.6 49.2

Potential capacity (MW) 500 500 500 500

Phase 1 depth range (m) 34.0−48.0 37.0−47.8 37.2−47.3 32.9−46.0

Annual energy production (GWh) 2,115.7 2,101.3 2,130.6 2,156

8 D x 15 D Phase 1 and 2 (1,000 MW each)

Wake losses (%) 5.7 6.8 6.3 5.4

Gross CF after wake losses (%) 45.6 45.7 47.2 46.4

Potential capacity (MW) 1,855 2,955 1,695 2,305

Phase 2 depth range (m) 47.0−54.0 46.0−56.0 48.0−54.0 49.0−62.2

Annual energy production (GWh) 7,411.7 11,836.3 7,006.1 9,366
xi

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at www.nrel.gov/publications.

Table ES3. MA WEA Delineation Analysis for Alternative 2

(Source: NREL)

 Delineation Alternative 2

Parameter Leasing 

Area 1

Leasing 

Area 2

Leasing 

Area 3

Leasing 

Area 4

Leasing Area 

5 

Total area (km2) 642 484 792 644 445

Total area (<50m) 324 325 328 323 326

Ave depth (m) 50 47 51 51 48

Bathymetry – depth range (m) 33.0−61.0 36.1−55.6 37.0−62.0 37.0−63.2 34.0−61.5

Ave wind speed at 90 m (m/s) 9.3 9.3 9.3 9.4 9.4

8 D x 8 D Full Development

Wake losses (%) 10 11.9 12.4 11.8 10.2

Gross CF after wake losses (%) 45.5 44.6 44.3 44.9 46.2

Potential capacity (MW) 2,755 1,830 3,375 2,675 2,015

Annual energy production (GWh) 10,985.9 7,151.3 13,109.5 10,536 8,162.4

8 D x 12 D Full Development

Wake losses (%) 7.9 9.4 9.9 9.3 7.9

Gross CF after wake losses (%) 46.7 45.9 45.7 46.3 47.5

Potential capacity (MW) 1,910 1,220 2,240 1,795 1,315

Annual energy production (GWh) 7,812.2 4,908.4 8,966.3 7,279.8 5,470

8 D x 15 D Full Development

Wake losses (%) 6.9 8.2 8.8 8.2 6.9

Gross CF after wake losses (%) 47.1 46.4 46.2 46.7 47.9

Potential capacity (MW) 1,530 965 1,790 1,430 1,050

Annual energy production (GWh) 6,312.4 3,925.7 7,244.8 5,860.3 4,406.9

8 D x 8 D Phase 1 (500 MW each)

Wake losses (%) 6.1 7.8 7.1 6.5 5.8

Gross CF after wake losses (%) 47.7 46.9 47.4 47.9 48.6

Potential capacity (MW) 500 500 500 500 500

Phase 1 depth range (m) 33.0−46.0 36.1−45.7 37.0−44.0 37.0−47.0 34.0−46.0

Annual energy production (GWh) 2,089.3 2,054 2,076.9 2,100.8 2,130.2

8 D x 8 D Phase 1 and 2 (1,000 MW each)

Wake losses (%) 6.5 8.8 8.4 7.8 6.9

Gross CF after wake losses (%) 47.3 46.2 46.6 47.1 48

Potential capacity (MW) 1,000 1,000 1,000 1,000 1,000

Phase 2 depth range (m) 47.0−51.0 45.0−55.0 47.0−53.0 48.0−52.0 45.0−51.0

Annual energy production (GWh) 4,150.3 4,049.9 4,081.5 4,132.5 4,206.6
xii

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8 D x 12 D Phase 1 (500 MW each)

Wake losses (%) 5.6 6.7 6.3 5.8 5.3

Gross CF after wake losses (%) 48 47.4 47.8 48.3 48.8

Potential capacity (MW) 500 500 500 500 500

Phase 1 depth range (m) 34.0−46.0 37.0−48.0 36.4−48.0 36.0−48.4 33.0−48.6

Annual energy production (GWh) 2,102.7 2,075.9 2,096 2,114.8 2,140.3

8 D x 12 D Phase 1 and 2 (1,000 MW each)

Wake losses (%) 6.3 7.3 7.5 7.1 6

Gross CF after wake losses (%) 47.5 46.9 47 47.4 48.4

Potential capacity (MW) 1,000 960 1,000 1,000 900

Phase 2 depth range (m) 46.0−54.0 47.5−55.0 48.0−54.0 49.0−58.0 48.0−62.0

Annual energy production (GWh) 4,160.5 3,944.3 4,118.5 4,157.8 3,817.7

8 D x 15 D Phase 1 (500 MW each)

Wake losses (%) 4.7 6.1 6 5.4 4.8

Gross CF after wake losses (%) 48.4 47.6 47.9 48.4 49.2

Potential capacity (MW) 500 500 500 500 500

Phase 1 depth range (m) 34.0−50.0 36.1−48.2 37.0−48.0 38.0−49.0 35.0−50.0

Annual energy production (GWh) 2,120.4 2,087.4 2,101.2 2,123.1 2,155

8 D x 15 D Phase 1 and 2 (1,000 MW each)

Wake losses (%) 5.7 6.8 7 6.6 5.563291

Gross CF after wake losses (%) 47.7 47.2 47.1 47.6 48.58987

Potential capacity (MW) 1,000 790 1,000 1,000 790

Phase 2 depth range (m) 50.0−59.0 49.0−55.0 50.0−56.0 50.0−62.0 48.0−61.0

Annual energy production (GWh) 4,180 3,266.3 4,132.9 4,175.3 3,366.4
xiii

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Table ES4. MA WEA Delineation Analysis for Alternative 3

(Source: NREL)

Delineation Alternative 3

Parameter Leasing 

Area 1

Leasing 

Area 2

Leasing 

Area 3

Leasing 

Area 4

Leasing 

Area 5

Total area (km2) 531 496 844 569 567

Total area (<50m) 407 411 408 395 4

Ave depth (m) 47 45 50 48 56

Bathymetry – depth range (m) 33.0−54.0 36.0−54.0 37.6−62.0 34.0−62.0 50.0−62.0

Ave wind speed at 90 m (m/s) 9.3 9.3 9.3 9.4 9.3

8 D x 8 D Full Development

Wake losses (%) 10.8 12.1 12.5 10.3 9.5

Gross CF after wake losses (%) 45.2 44.6 44.5 46.1 45.5

Potential capacity (MW) 2,255 1,845 3,430 2,425 2,265

Annual energy production (GWh) 8,927.4 7,206.7 13,378.9 9,798.7 9,042.1

8 D x 12 D Full Development

Wake losses (%) 8.5 9.6 10 8.2 7.5

Gross CF after wake losses (%) 46.4 45.8 45.7 47.2 46.6

Potential capacity (MW) 1,470 1,220 2,295 1,660 1,585

Annual energy production (GWh) 5,975 4,900.6 9,201.9 6,869.9 6,472.2

8 D x 15 D Full Development

Wake losses (%) 7.4 8.4 8.9 7.1 6.5

Gross CF after wake losses (%) 46.9 46.4 46.3 47.7 47.1

Potential capacity (MW) 1,170 970 1,840 1,330 1,250

Annual energy production (GWh) 4,812.2 3,946.8 7,473.2 5,566.9 5,158.5

8 D x 8 D Phase 1 (500 MW each)

Wake losses (%) 6 6.9 5.7 5.4 N/A

Gross CF after wake losses (%) 47.7 47.4 48.2 48.8 N/A

Potential capacity (MW) 500 500 500 500 N/A

Phase 1 depth range (m) 33.0−45.0 36.0−42.0 37.6−45.0 34.0−44.0 N/A

Annual energy production (GWh) 2,091 2,078.3 2,114.3 2,138.3 N/A

8 D x 8 D Phase 1 and 2 (1,000 MW each)

Wake losses (%) 6.9 8.7 7.3 6.3 6.4

Gross CF after wake losses (%) 47.2 46.4 47.3 48.2 47.1

Potential capacity (MW) 1,000 1,000 1,000 1,000 1,000

Phase 2 depth range (m) 44.7−51.0 43.0−50.0 45.0−51.0 46.0−50.0 46.0−50.0

Annual energy production (GWh) 4,133.6 4,064.2 4,146.3 4,228 4,129.3
xiv

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8 D x 12 D Phase 1 (500 MW each)

Wake losses (%) 5.2 6.2 5.1 4.9 N/A

Gross CF after wake losses (%) 48.1 47.8 48.5 49 N/A

Potential capacity (MW) 500 500 500 500 N/A

Phase 1 depth range (m) 33.0−47.0 36.0−45.0 37.2−46.0 37.2−46.0 N/A

Annual energy production (GWh) 2,109.7 2,093.8 2,127.9 2,148 N/A

8 D x 12 D Phase 1 and 2 (1,000 MW each)

Wake losses (%) 6.7 8 6.8 5.7 6.3

Gross CF after wake losses (%) 47.3 46.6 47.5 48.5 47.2

Potential capacity (MW) 1,000 1,000 1,000 1,000 1,000

Phase 2 depth range (m) 46.0−53.0 46.0−53.3 48.0−54.0 47.0−59.0 51.0−60.0

Annual energy production (GWh) 4,143.3 4,086.1 4,166.7 4,252.1 4,134.3

8 D x 15 D Phase 1 (500 MW each)

Wake losses (%) 5 5.8 4.9 4.5 N/A

Gross CF after wake losses (%) 48.3 47.9 48.6 49.2 N/A

Potential capacity (MW) 500 500 500 500 N/A

Phase 1 depth range (m) 34.0−48.0 37.0−47.8 37.2−47.3 32.9−46.0 N/A

Annual energy production (GWh) 2,115.7 2,101.3 2,130.6 2,156 N/A

8 D x 15 D Phase 1 and 2 (1,000 MW each)

Wake losses (%) 6.4 7.1 6.6 5.4 5.6

Gross CF after wake losses (%) 47.4 47.1 47.6 48.6 47.5

Potential capacity (MW) 1,000 790 1,000 955 1,000

Phase 2 depth range (m) 47.0−54.0 46.0−53.0 48.0−54.0 49.0−62.2 50.0−60.0

Annual energy production (GWh) 4,154.3 3,263.8 4,169.3 4,067.7 4,164.6

The data shown in Table ES2, Table ES3, and Table ES4 summarize the analyses that were

performed for all three alternatives and turbine spacing scenarios of 8 D x 8 D, 8 D x 12 D, and 8 

D x 15 D. However, the figures and graphs in this report do not always include all cases analyzed 

because of space limitations. In general, a turbine spacing of 8 D x 12 D was used by NREL for 

the MA WEA as a baseline case to illustrate all cases. This compares to 8 D x 8 D spacing for

the Rhode Island/Massachusetts area of mutual interest and Maryland WEA (Musial et al. 2013a, 

Musial et al. 2013b), and 10 D x 12 D spacing used in the New Jersey WEA (Musial et al. 

2013c), and what is commonly used in European wind facilities (see Table 3). NREL believes 

that bathymetry, wake effects, access to export cable routes, and wind direction are the most 

important variables in the MA WEA. Other siting issues, such as environmental and competing 

use factors, may also influence array density as site development progresses. 

As shown in Figure ES2, all of the leasing areas except for the deep water only leasing area in 

Alternate 3 have roughly the same shallow water area (less than 50 m), although the area in 

deeper water (above 50 meters) varies considerably. This size variation in the leasing areas was 

allowed to preserve the straight diagonal delineations and allow the lessees to control the wind 

fetch in the prevailing direction. 
xv

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The wake losses for the full development scenario, using 8 D x 12 D spacing, range from 8.3% 

to 10.0% in Alternative 1, 7.9% to 9.9% in Alternative 2, and 7.5% to 10.0% in Alternative 3. 

Over Alternatives 2 and 3, the five leasing area options’ maximum nameplate development 

potential ranged from 1,220 MW to 2,295 MW. For the four leasing area option, the maximum 

nameplate development potential ranged from 1,695 MW to 2,955 MW; however, neither of 

these full development capacity assessments reflect realistic development scenarios and should 

only be used to compare leasing areas and understand trends. A more realistic, phased

development strategy was recommended by NREL. In Section 5, NREL assessed each leasing 

area and assumed that two 500-MW wind facilities would be built over a time frame of 6 to 16 

years. This would result in a total maximum capacity of the entire WEA of 5,000 MW. Phase 1 

assumed that one 500-MW project was installed in 6 to 8 years in shallower water, and phase 2 

installed another 500-MW project in 10 to 16 years in each leasing area in deeper water. The 

development time periods were derived from review of the Call nominations. The 500-MW 

phase 1 projects were analyzed first (in the absence of phase 2 projects), and then both phase 1 

and 2 were assessed together in all leasing areas.

The results of these analyses are given in Table ES2, Table ES3, and Table ES4 and are further 

summarized in Table ES5. Table ES5 gives the array efficiencies for all of the OpenWind wake 

analyses conducted by NREL. The array efficiency values that are presented in Table ES3

provide a measure of how well the array is performing as a whole than how it would be expected 

to perform if each turbine were operating with perfect exposure to the freestream wind with no 

obstructions from other wind turbines. 

Table ES5. MA WEA Array Efficiency Analysis for Three Leasing Area Alternatives and Three 

Turbine Grid Spacing Geometries 

(Source: NREL)

Array Efficiency (%)

Full Development Alternative 1 Alternative 2 Alternative 3

8 D x 8 D 88.6 88.7 89.0

8 D x 12 D 90.9 91.1 91.2

8 D x 15 D 92.0 92.2 92.3

Phased Development Phase 1

500 MW

Phase 2 

1,000 MW

Phase 1

500 MW

Phase 2 

1,000 MW

Phase1 

500 MW

Phase 2 

1,000 MW

8 D x 8 D 94.0 93.0 93.3 92.3 94.0 92.9

8 D x 12 D 94.7 93.7 94.1 93.2 94.7 93.3

8 D x 15 D 95.0 94.0 94.6 92.3 95.0 93.8
xvi 

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Key Findings

Below are the key findings of NREL’s assessment of the MA WEA, which provide 

considerations for BOEM, policy makers, and stakeholders involved in the Massachusetts

offshore wind energy development process. 

• Massachusetts is the largest BOEM WEA under consideration at this time (3,006.7 km2) and

can feasibly accommodate at least ten 500-MW wind projects (5,000 MW) under a phased

development scenario using up to five leasing areas. 

• The biggest challenge for offshore wind developers in the MA WEA will be water depths

that range between 35 and 65 m.

• The MA WEA can be delineated into four to five leasing areas with equitable divisions of 

shallower water (less than 50 m), wind resource potential, and exposure to unobstructed free 

stream prevailing wind (Alternative 3 is an exception, with leasing area 5 presenting a 

potential upwind obstruction). 

• The leasing areas in the western part of the MA WEA may have a greater advantage if export 

cable interconnection points off Cape Cod and the islands are favored. It may be prudent for 

state or federal regulators to consider options for coordinating cable routing strategies and 

possible easements among the leasing areas. Within the MA WEA, interconnect access could 

be a strong driver in appraising leasing area value.

• The maximum nameplate development capacity for Alternatives 2 and 3, the five leasing area 

options, ranged from 1,220 MW to 2,295 MW. For Alternative 1, the four leasing area 

option, the maximum nameplate development potential ranged from 1,695 MW to 2,955 

MW. This represents a large overall disparity in total area per lease area, even though the 

shallower water (less than 50 m) is balanced to within 5% for each alternative.

• Diagonal delineations (45 degrees to the BOEM leasing grid) appear to offer the most 

efficient delineation strategy to create equitable divisions of water by depth, and to minimize 

inter-array conflicts caused by wake effects. 

• The average annual wind speed for the MA WEA ranged from 9.2 m/s to 9.4 m/s, with the 

highest wind speeds in the eastern areas and the lowest wind speeds in the western areas. For 

each alternative, this corresponds to a typical range of capacity factors between 45% and 

47% across the WEA after wake losses are subtracted using 8 D x 12 D spacing for a full 

development scenario. 

• Total wake losses from projects developed at 8 D x 12 D spacing in all leasing areas of the 

MA WEA were computed to range between 6% and 8% when 1,000 MW in two 500-MW 

phases were installed in each leasing area. Wake losses in the MA WEA appear to be lower 

than other areas studied in the mid-Atlantic because of higher average wind speeds and a 

distribution of more unidirectional prevailing winds (Musial et al. 2013b and Musial et al. 

2013c). 

• The grid orientation angle was found to have a negligible impact on array efficiency (<0.1%)

using the OpenWind model with 8 D x 12 D spacing and 10% turbulence intensity. The best 

grid orientation angle was 60 degrees for the 8 D x 12 D array, but the true impacts of 
xvii 

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variable turbulence intensity are not effectively captured in OpenWind. A more rigorous 

array analysis approach is recommended for developers in this area.

• Wake losses increased with decreased turbine spacing, as expected. For the full development 

scenarios in each alternative, wake losses averaged 7.8% for the 8 D x 15 D spacing and 

11.2% for the 8 D x 8 D spacing. Most of this impact can be accounted for by lower array 

power density with the wider spacing.

• Additional turbine spacing may have diminishing benefits when multiple large arrays are 

sited near each otherthis is because the benefits of turbine spacing are offset by reductions 

in the buffers that separate neighboring wind plants. 

• Additional development cost will be introduced with wider spacing as the result of longer 

cable length, greater water depths, and farther distances from shore. These costs should be 

carefully weighed against the added energy from higher array efficiency.

Recommendations

NREL’s recommendations for the MA WEA are as follows.

• Of the three alternatives, NREL prefers Alternative 2 because it is believed that the 

development potential of the WEA would be maximized while minimizing the effects of 

neighboring projects on adjacent wind plants. With the five leasing area option, each area 

could support at least two 500-MW projects, and some could support three, depending on the 

spacing.

• Any of the alternatives assessed in this report would be feasible and may be preferable to 

Alternative 2 for a given set of objectives.

• NREL recommends that BOEM consider methods to discount the deepest aliquots to address 

the probable time lag in development caused by added cost and complexity of building 

turbines in deeper water. 

The analysis in this report is coarse by industry standards, therefore it is recommended that 

prospective lessees conduct more rigorous analysis on wake losses before judging the values 

of these leasing areas. This enhanced analysis should consider diurnal, seasonal, and annual 

variations as well as a full cost assessment to examine the additional cost of added cable 

length. In addition, NREL recommends conducting further analysis on wake losses with 

respect to atmospheric stability conditions.
xviii

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Table of Contents

Acknowledgments ..................................................................................................................................... iii

List of Figures ........................................................................................................................................ xviii

List of Tables ............................................................................................................................................. xx

1 Project Background ............................................................................................................................. 1

1.1 Summary of NREL Task Work ....................................................................................................... 1

1.2 MA WEA and Leasing Areas .......................................................................................................... 2

2 Literature Review.................................................................................................................................. 4

2.1 NREL Review of the Massachusetts RFI and Call .......................................................................... 4

3 Overview of MA WEA Delineation Results....................................................................................... 11

3.1 Introduction .................................................................................................................................... 11

3.2 Overview of NREL Methodology ................................................................................................. 12

4 Physical Assessment and Delineation Analysis............................................................................. 19

4.1 Bathymetry Considerations ............................................................................................................ 19

4.2 Wind Resource ............................................................................................................................... 22

4.3 Delineation Strategy....................................................................................................................... 25

5 Wake and Array Analysis................................................................................................................... 36

5.1 Analysis Tool: OpenWind Enterprise ............................................................................................ 36

5.2 NREL Analysis of MA WEA Using Open Wind .......................................................................... 37

5.3 Maximum Development Capacity ................................................................................................. 40

5.4 Capacity Factor after Wake Losses ................................................................................................ 41

5.5 Wake and Array Losses ................................................................................................................. 41

6 Qualitative Considerations................................................................................................................ 54

7 Key Findings ....................................................................................................................................... 55

8 Recommendations ............................................................................................................................. 57

9 References .......................................................................................................................................... 58

List of Figures

Figure ES1. Water depth map for the MA WEA.......................................................................................vi

Figure ES2. The three leasing area delineation options that NREL analyzed include: Alternative 1,

four diagonal leasing areas; Alternative 2, five diagonal leasing areas; Alternative 3, five leasing 

areas with one deep area. The lighter green color indicates water depths below 50 m and the 

darker green color indicates water depth above 50 m. The MA WEA wind rose is shown at the top 

right. .........................................................................................................................................................viii

Figure 1. Massachusetts (MA) Wind Energy Area (WEA) as defined in February 2012 ...................... 3

Figure 2. Evolution of the MA WEA boundaries from February 2011 to the present.............................

...................................................................................................................................................................... 5

Figure 3. Average turbine array density for 18 European offshore wind power projects. Red lines 

indicate the array density for the spacing scenarios used in the MA WEA assessment.................... 9

Figure 4. Three delineation options used in the MA WEA assessment. Alternative 1: Four leasing 

areas with diagonal delineation; Alternative 2: Five leasing areas with diagonal delineations; 

Alternative 3: Five leasing areas with deep water carve out................................................................13

Figure 5. Water depth map for the MA WEA...........................................................................................20

Figure 6. Current offshore wind projects in Europe: installed, under construction, contracted, and 

approved as a function of expected commercial operation date.........................................................21

Figure 7. Histogram of water depths for the MA WEA showing water depths ranging from 30 m to 

65 m for the total WEA using May 2012 boundaries (3,006.7 km2

) ......................................................22
xix

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Figure 8. (top) MA WEA showing the annual average wind speed in 0.10 m/s increments and 

(bottom) the wind frequency rose with prevailing winds from the southwest direction...................24

Figure 9. Alternative 1: Four leasing areas with approximately equal shallow water area less than 

50 m ............................................................................................................................................................28

Figure 10. Alternative 1: Distribution of area among four leasing areas showing approximately 

equal shallow water less than 50 m (maximum variation of shallow water area = 5%).....................28

Figure 11. Alternative 1: Plot showing depth distribution for each leasing area over the entire MA 

WEA. Shaded area indicates depths that are greater than 50 m..........................................................29

Figure 12. Alternative 2: Five leasing areas with approximately equal division of shallow water 

area less than 50 m ...................................................................................................................................31

Figure 13. Alternative 2: Distribution of area among five leasing areas showing approximately 

equal shallow water less than 50 meters (Maximum 1.58% variation) ................................................31

Figure 14. Alternative 2: Plot showing depth distribution for each leasing area over the entire 

depth range. Shaded area indicates depths that are greater than 50 m. ............................................32

Figure 15. Alternative 3: Five leasing areas with four approximately equal shallow areas and one 

area containing only deep water .............................................................................................................34

Figure 16. Alternative 3: Distribution of area among five leasing areas showing approximately 

equal shallow water less than 50 m in leasing areas 1−4 with a maximum variation of 5% .............34

Figure 17. Alternative 3: Depth distribution for five leasing areas with four approximately equal 

shallow areas and one area containing only deep water. Shaded area indicates water depth 

greater than 50 m. .....................................................................................................................................35

Figure 18. MA WEA layout map for the 8 D x 12 D full build (development) scenario using the 

Alternative 3 delineation scenario showing the maximum nameplate capacity, wake losses, and 

expected annual energy production for each of the five leasing areas ..............................................40

Figure 19. Horns Rev I wind farm ............................................................................................................43

Figure 20. OpenWind uses the BOEM leasing grid as a reference frame for the grid orientation 

angle of the turbine array. The example shown is for 8 D x 8 D spacing with a 75-degree grid angle. 

The MA WEA grid angles were found to be 60 degrees for minimum wake losses...........................44

Figure 21. Comparison of OpenWind array efficiency results for the two five leasing area 

delineation alternatives of the MA WEA using 8 D x 12 D turbine spacing under a full development 

scenario......................................................................................................................................................47

Figure 22. Alternative 2 delineation layouts for phase 1 and phase 2 development building two 

500-MW projects per leasing area. Projects are shown with 8 D x 8 D, 8 D x 12 D, and 8 D x 15 D 

spacing.......................................................................................................................................................49

Figure 23. Alternative 3 delineation layouts for phase 1 and phase 2 development building two 

500-MW projects per leasing area. Projects are shown with 8 D x 8 D, 8 D x 12 D, and 8 D x 15 D 

spacing.......................................................................................................................................................50

Figure 24. MA WEA for Alternative 2 leasing area delineation showing the effect of turbine spacing 

and buffers on array efficiencies with two 500-MW projects in each leasing area: (A) 8 D x 8 D 

spacing; (B) 8 D x 12 D spacing; and (C) 8 D x 15 D spacing...............................................................51

Figure 25. MA WEA for Alternative 3 leasing area delineation showing the effect of turbine spacing 

and buffers on array efficiencies with two 500-MW projects in each leasing area: (A) 8 D x 8 D 

spacing; (B) 8 D x 12 D spacing; (C) 8 D x 15 D spacing ......................................................................51
xx 

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List of Tables

Table ES1. Evaluation Criteria Used to Assess the Massachusetts (MA) WEA .................................. vi

Table ES2. MA WEA Delineation Analysis for Alternative 1 .................................................................. ix

Table ES3. MA WEA Delineation Analysis for Alternative 2.................................................................. xi

Table ES4. MA WEA Delineation Analysis for Alternative 3................................................................ xiii

Table ES5. MA WEA Array Efficiency Analysis for Three Leasing Area Alternatives and Three 

Turbine Grid Spacing Geometries .................................................................................................... xv

Table 1. Summary of RFI Statistics from the Eight Massachusetts (MA) Wind Energy Area (WEA) 

Responses............................................................................................................................................. 6

Table 2. Summary of Call Statistics from 10 MA WEA Responses........................................................ 7

Table 3. List of 18 of the Largest Offshore Wind Power Projects (>200 MW Capacity) and Average 

Turbine Density Used By Each Project............................................................................................ 10

Table 4. Evaluation Criteria Used by NREL to Assess the MA WEA ................................................... 11

Table 5. MA WEA Delineation Analysis for Alternative 1...................................................................... 14

Table 6. MA WEA Delineation Analysis for Alternative 2...................................................................... 16

Table 7. MA WEA Delineation Analysis for Alternative 3...................................................................... 18

Table 8. Alternative 1: Four Leasing Area Delineation for the MA WEA ............................................. 27

Table 9. Alternative 2: Five Leasing Area Diagonal Delineation for the MA WEA.............................. 30

Table 10. Alternative 3: Five Leasing Area Alternative with Separate Deep Water Site Delineation 

for the MA WEA................................................................................................................................... 33

Table 11. Summary of Array Spacing Analysis Conducted to Assess Wake Losses and Energy 

Production Potential for the MA WEA .............................................................................................. 38

Table 12. MA WEA Array Efficiency Analysis for Three Leasing Area Alternatives and Three 

Turbine Grid Spacing Geometries .................................................................................................... 45
1 

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1 Project Background

Since 2009, the U.S. Department of the Interior’s Bureau of Ocean Energy Management 

(BOEM) has been working with intergovernmental task forces to identify the most appropriate 

areas for commercial wind energy leasing on the Outer Continental Shelf (OCS) off the Atlantic 

Coast. To date, BOEM has identified six Wind Energy Areas (WEAs) on the OCS that are

considered appropriate for commercial offshore wind energy development, with a goal of 

minimizing conflicts with existing uses and the environment. BOEM is currently considering 

issuing leases for five WEAs through a competitive process: 1) Virginia, 2) Rhode 

Island/Massachusetts, 3) New Jersey, 4) Maryland, and 5) Massachusetts. On July 31, 2013, 

BOEM held the first of these competitive lease auctions for the Rhode Island/Massachusetts 

WEA (U.S. Department of the Interior 2013). The second auction was held for the Virginia

WEA on September 4, 2013. The WEAs that have multiple leasing areas within their boundaries 

(all but Virginia) require further analysis using engineering tools and site-specific WEA data to 

ensure that the leasing areas are appropriately divided.

1.1 Summary of NREL Task Work

The U.S. Department of Energy’s (DOE) National Renewable Energy Laboratory (NREL), under 

an interagency agreement between DOE and BOEM, is providing technical assistance to identify 

and delineate offshore leasing areas for wind energy development within the Atlantic Coast 

WEAs.

The overarching objectives of the interagency agreement are as follows: 

1. Develop a logical process by which WEAs can be subdivided into non-overlapping 

leasing areas for BOEM’s use in developing auction processes in a renewable energy 

lease sale

2. Identify the appropriate number of leasing areas recommended for lease within each 

WEA

3. Delineate the boundaries of the leasing areas within each WEA 

4. Document the methodology (i.e., variables and assumptions) by which the leasing areas 

are identified and delineated for each state.

The work being performed by NREL for each WEA is based on a predetermined scope of work 

and uses physical site-specific data and characteristics obtained by NREL and general 

information and leasing parameters provided by BOEM. For Massachusetts, the interagency 

agreement work scope comprises several tasks to assist BOEM in making the final determination 

for delineating the Massachusetts (MA) WEA into leasing areas that are each capable of 

supporting a commercially viable project. The expectation is that the proposed delineations will

provide sufficient area for modifications to the facility layout based on the results of geophysical, 

geological, and biological surveys that will be conducted by the developer. 
2 

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First, NREL was asked to conduct a review of information submitted in response to relevant 

BOEM Federal Register notices. NREL researchers, based on their expertise, were asked to

determine the relevance of the information provided to the leasing area identification and 

delineation methodology and incorporate the information as appropriate. 

Second, NREL was asked to propose a methodology for delineation of the leasing areas and the 

factors used to identify the number of leasing areas and the proposed delineation boundaries. On

May 15, 2013, NREL made a presentation to the Massachusetts Renewable Energy Task Force

to fulfill this portion of the Massachusetts work tasks (Musial 2013). The presentation described 

the proposed method for identifying and evaluating multiple potential leasing areas within the 

MA WEA and performing an independent analysis on the different delineation options. As a 

result of discussions at the Massachusetts Renewable Energy Task Force webinar on May 15, 

2013, and follow-up conference calls that included representatives of the Massachusetts Clean 

Energy Center and Massachusetts Office of Coastal Zone Management, NREL obtained 

feedback that was used in developing the final methodology and delineation options for the MA 

WEA analysis.

The updated methodology included: 

• Development of delineation alternatives for a four leasing area (Alternative 1) and a five

leasing area scenario (Alternative 2) with equal division of shallower water [less than 50 

meters (m)] in each leasing area

• Development of a third delineation option (Alternative 3) for a five leasing area scenario 

consisting of four leasing areas with equal division of shallower water less than 50 m and one 

leasing area with all deeper water (greater than 50 m) 

• Evaluation and comparison of the full development nameplate capacity potential (based on 

area) of the leasing areas in all delineation alternatives [in rotor diameters (D)] using 8 D x 8

D, 8 D x 12 D, and 8 D x 15 D turbine spacing 

• Evaluation and comparison of phased developments of two 500-MW projects in each leasing 

area (one built earlier in 6−8 years in shallower water and one built later in 10−16 years in 

deeper water) and the effect of different turbine spacing configurations (8 D x 8 D, 8 D x 12

D, and 8 D x 15 D) on wake losses, energy production, and development challenges. 

NREL researchers used the input from BOEM and other collaborators to help guide the analysis 

and subsequently worked with BOEM to integrate the findings into this report. 

Finally, NREL researchers will present the findings to the BOEM Massachusetts Renewable 

Energy Task Force in late 2013. 

1.2 MA WEA and Leasing Areas

BOEM has been working with the BOEM Massachusetts Renewable Energy Task Force to 

identify the most appropriate area for leasing offshore Massachusetts since 2009. In December 

2010, BOEM published a request for interest (RFI) in the Federal Register to gauge specific 

interest in obtaining commercial wind leases in an area on the OCS offshore Massachusetts.

BOEM received eight expressions of interest from companies potentially seeking a commercial 
3 

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lease for offshore wind energy. Working with the task force, BOEM refined the area and 

published a Call for Information and Nominations (referred to in this document as the “Call”) in 

the Federal Register in February 2012. BOEM received 10 nominations of interest from 

companies potentially seeking a commercial lease for offshore wind energy in response to the 

Call. BOEM refined the area further and announced the identification of the MA WEA in May

2012. The MA WEA (area analyzed in this report) comprises 742,974 acres, or 3,006.7 square 

kilometers (km2), and is shown in Figure 1. It is intended to provide for the protection of 

ecologically sensitive areas and minimize user conflicts while making an appropriate area 

available for commercial offshore wind energy development. BOEM is proposing to hold a lease 

sale to auction the MA WEA and issue leases that correspond to the entire identified WEA. 

Figure 1. Massachusetts (MA) Wind Energy Area (WEA) as defined in May 2012 

(Source: BOEM) 

BOEM provided NREL with the MA WEA coordinates for evaluation and recommended that 

NREL assess multiple potential offshore wind development leasing areas within the WEA. 

NREL’s evaluation of the proposed leasing area delineations focused on relevant technical

criteria included total energy production capacity, wake losses, project size, array density, and 

water depth, as well as several qualitative criteria listed in Table 3. 
4 

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2 Literature Review

In addition to the references cited in Section 9 of this report, NREL researchers reviewed the 

following documents and communications: 

• The RFI published by BOEM in the Federal Register in December 2010 for offshore 

Massachusetts and eight responses to the RFI 

• The Call published by BOEM in the Federal Register in February 2012 and 10 responses to 

the Call

• The final MA WEA coordinates developed by BOEM and announced in May 2012 

• Presentations delivered at the Massachusetts Renewable Energy Task Force webinar held on 

May 15, 2013 

• Verbal input received from the Massachusetts Clean Energy Center and Massachusetts 

Office of Coastal Zone Management on May 20, 2013, and follow-up discussions. 

2.1 NREL Review of the Massachusetts RFI and Call

NREL was granted confidential access to the eight responses to the 2010 RFI that were 

submitted in February 2011, and 10 responses to the 2011 Call that were submitted in March 

2012. These nominations provided insight into the commercial sector considerations for offshore 

development and wind energy leasing area delineation in the MA WEA. The number of 

responses generally demonstrated that there is interest in the MA WEA and revealed aspects 

about broad-scale development project size, turbine size placement, and to some degree, the type 

of technology that might be used. 

A major caveat in the interpretation of data extracted or derived from the MA developers’ 

responses is that the three areas: 1) the RFI area, 2) the Call area, and 3) the May 2012 WEA, 

which is analyzed in this report, all differ in size and characteristics. Figure 2 shows how the MA 

WEA boundaries evolved from the time that the RFI was released in December 2010 (far left) to 

the present area of analysis (May 2012 far right). For this report, NREL assumed developers 

would not necessarily have anticipated these changes to the WEA, and that they probably 

believed their projects could be adapted relatively easily to unforeseen modifications within 

similar boundaries. 
5 

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Figure 2. Evolution of the MA WEA boundaries from February 2011 to November 2013 

(Source: BOEM)

Aside from the large reduction in the size of the WEA from the RFI boundaries, one significant 

change that occurred during the MA WEA modifications was that all of the areas with water 

depths below 30 m were excluded. Most of the RFI and Call responses referred to projects that 

were intended to be located in these shallower water lease blocks using conventional foundation 

and substructure technology. However, with these shallow lease blocks removed in the present 

WEA (May 2012), it is uncertain how these projects would be adapted. It is also important to 

note that the RFI and Call responses were based on the undelineated WEA without knowledge of 

how neighboring wind projects might encroach upon their facility. Developer interests might 

differ significantly from the responses to the RFI and Call under an auction process when 

constrained by specific leasing area boundaries. As a result, extrapolations based on these

responses may not accurately predict all the current MA WEA development scenarios. 

Nevertheless, NREL found the evaluations of the RFI and Call nominations to be informative. 

Although, the information provided varied significantly and typically did not contain a high level 

of detail about the technology or expected turbine performance, the responses were useful in 

highlighting trends related to siting constraints, turbine size, support structure technology (e.g., 

fixed bottom or floating), project capacity, development schedule, array density, and 

interconnection points. NREL researchers also considered other factors, such as meteorological 

information and distance from shore; however, researchers did not consider potential competing 

use conflicts with organizations like the U.S. Department of Defense and U.S. Coast Guard, or 

with fisheries or other existing stakeholders that have the potential to introduce further 

unforeseen use restrictions that could be imposed at a later date and affect the potential value of 

the lease areas. 
6 

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A summary of the RFI and Call data statistics is shown in Table 1 and Table 2. Because of 

confidentiality requirements, the project data from the individual industry responses were 

reduced to statistical averages and maximum and minimum values. The latter indicate a wide 

variety of specifications for the proposed projects. The statistical averages were compared to the 

nominal values used in the NREL analysis. In many cases, the individual responses did not 

contain all of the information reported in Tables 1 and 2, or the data could not be found. 

Therefore, only the responses that contained these data are represented in the table. 

Table 1. Summary of RFI Statistics from the Eight Massachusetts (MA) Wind Energy Area (WEA)

Responses

(Source: NREL)

Average Maximum Minimum NREL 

Values

Project nameplate capacity in megawatts 

(MW) 1,503 3,000 507 5,000

Turbine nameplate capacity (MW) 4.9 6.0 3.6 5.0

Wind speed (m/s) at hub height 9.34 9.75 8.9 9.35

Net capacity factor (%) 41 43 40 45-48

Project area (km2) 1,112 2,004 240 3,006.7

Array power density (MW/km2) 2.36 5.34 0.6 1.66

Turbine array spacing

8.5 x

10.5

8 x 12 9 x 9 8 x 8; 8 x

12; 8 x 15

Project development time (years) 8.4 12 6 NA

Notes: 

• NREL values represent Alternative 2 and 3 only, the five leasing area delineations 

• The net capacity factor reported in the NREL values is the gross capacity factor after 

subtracting wake losses only (e.g., electrical losses not included) 

• NREL used the whole wind energy area
7 

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Table 2. Summary of Call Statistics from 10 MA WEA Responses

(Source: NREL)

Average Maximum Minimum NREL 

Values

Project nameplate capacity (MW) 1,524 3,000 1,000 5,000

Turbine nameplate capacity (MW) 5.63 7.0 5.0 5.0

Wind speed (m/s) at hub height 9.3 9.75 8.8 9.35

Net capacity factor (%) 40 40 40 45−48

Project area (km2) 1,026 2,004 240 3,006.7

Array power density (MW/km2) 2.27 4.33 0.54 1.66

Turbine array spacing 8.5 x 10.5 8 x 12 9 x 9 8 x 8; 8 x

12; 8 x 15

Project development time (years) 9.1 16 7 NA

Notes:

• NREL values represent Alternatives 2 and 3 only, the five leasing area delineations

• The net capacity factor reported in the NREL values is the gross capacity factor after 

subtracting wake losses only (e.g., electrical losses not included) 

• NREL used the whole wind energy area

Note that project sizes in the responses tended to be large, with a range from 1,000 megawatts 

(MW) to 3,000 MW for individual developers. These data indicate a desire for developers to 

build large multi-phased facilities rather than clusters of small projects as was seen in the early 

years of offshore wind in Europe. 

Development time is another parameter that researchers evaluated from the RFI and Call 

responses. Development times ranged from 6 to 16 years for all of the RFI and Call nominations 

reviewed. Since most developers assumed that they would have access to shallower water, it is 

likely that these times could increase because deeper water can impose additional challenges to 

development. The NREL analysis assumes that development times will be shorter for shallower 

projects and longer for deeper projects as the costs are currently higher and the technology is less 

mature for deep sites.

Although not given in Table 1 and Table 2, the vast majority of the developers’ responses 

indicated a preference for fixed-bottom substructure technology even in the deeper waters. The 

absence of floating wind turbine technology proposals, which would be less depth-dependent, 

would indicate that even a multiphased project approach would tend to favor the more shallow 

regions of a given leasing area. We elaborate on this assumption later when it is used in 

developing the phased development of the 500-MW arrays and the siting scenarios used to 

calculate wake losses. 
8 

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In Table 1 and Table 2, the “NREL Values” are based on a standard set of assumptions that have 

been used in the previous delineation analyses and reports NREL conducted for BOEM, except 

for some unique parameters that were introduced specifically for Massachusetts. Specifically, the 

base-case turbine array spacing was chosen to be 8 D x 12 D for Massachusetts, which is wider 

spacing than the typical 8 D x 8 D spacing used for the gross resource estimations carried out in 

2010 (Schwartz et al. 2010) and which was used as the base case in the Rhode 

Island/Massachusetts and Maryland wind energy areas (Musial et al. 2013a, Musial et al. 2013b). 

For the New Jersey analyses, a wider base-case array spacing of 10 D x 12 D was used at the 

request of the New Jersey Renewable Energy Task Force (Musial et al. 2013c). Both the 8 D x 8

D spacing and the 8 D x 12 D spacing are comparable to the turbine array spacing that is typical 

for many European offshore wind facilities as shown in Figure 3. 

The RFI and Call notices did not specifically ask for the responses to quantify array spacing. 

Therefore, very few responses included this information, making it difficult to establish a clear 

trend in commercial project array spacing for Massachusetts. However, Figure 3 shows that 

when examining actual data from existing European projects, a preferred trend in array spacing 

is not apparent. In 17 European offshore wind projects and including Cape Wind (Cape Wind 

2013), ranging in size from 160 to 630 MW, the average wind turbine density ranges from 3.5 to 

8.8 MW/km2 (Figure 3 and Table 3) based on turbine array spacing only. These 18 projects 

represent all of the existing offshore wind plants over 200 MW in nameplate capacity for which 

turbine array spacing data were available. The mean turbine density for all 18 projects is 6.1 

MW/km2

. By comparison, the turbine density used in the MA WEA assessment is 5 MW/km2 for 

8 D x 8 D spacing, 3.3 MW/km2 for 8 D x 12 D spacing, and 2.6 MW/km2 for 8 D x 15 D 

spacing. Specifically, the 8 D x 12 D baseline spacing adopted by NREL for the MA WEA

assessment results in lower wake losses and provides a more conservative (lower) estimate of 

potential development capacity than the 8 D x 8 D spacing used by NREL in other similar 

studies. 

A better metric for comparison of array density may be total array power density (APD) as 

provided in Table 1 and Table 2. These data were available for all proposed projects in the RFI 

and Call responses as each developer specified the project nameplate capacity they are planning 

and the footprint it would occupy within the Call area. In many cases, individual developers 

specified the nameplate capacity in multiple phases. For this analysis, the APD values were 

derived simply from the total project nameplate capacity in megawatts divided by the total 

project area proposed for each project in kilometers squared. APD comprises both the array 

spacing and any additional buffer zones that the developer included. As such, these values 

indicate a lower density than the turbine array density, which just includes the spacing in 

between turbines. Wake loss findings shown in Section 5 indicate that losses are mitigated 

through a combined use of array spacing and buffers between projects. For the MA WEA Call 

responses in Table 2, the APD was computed by NREL to range between 0.54 MW/km2 and 4.33 

MW/km2, with an average of 2.2 MW/km2. This compares to NREL’s analysis of the MA WEA, 

which has an average overall APD of 1.66 MW/km2

. 
9 

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Figure 3. Average turbine array density for 18 European offshore wind power projects and Cape 

Wind. Red lines indicate the array density for the spacing scenarios used in the MA WEA 

assessment

(Source: NREL)

Mean of all 18 Wind Plants 
10 

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Table 3. List of 18 of the Largest Offshore Wind Power Projects (>200 MW Capacity) and Average 

Turbine Density Used By Each Project

(Source: NREL)

Country Name of Wind Farm

Installed 

Capacity 

(MW)

Area of 

Wind 

Farm 

(km2) 

Average 

Turbine 

Density 

(MW/km2) 

Commissioning 

Date (year)

United 

Kingdom London Array 1 630 100 5.5 2013

United 

Kingdom Gwynt y Mor 576 79 7.1 2014

United 

Kingdom Greater Gabbard 504 147 3.5 2012

United States Cape Wind 468 62 5.7 2015

Germany Bard 400 59 5.3 2013

Germany Borkum West 2 400 56 5.6 2013

Germany Global Tech 1 400 41 7.6 2013

Denmark Anholt 399.6 88 4.2 2013

United 

Kingdom Sheringham Shoal 316.8 35 5.5 2012

United 

Kingdom Thanet 300 35 7.5 2010

Germany Nordsee Ost 295.2 24 8.4 2014

Germany Baltic 2 288 30 7.5 2014

Germany Dantysk 288 66 4.4 2014

Germany

Meerwind Sud und 

Ost 288 42 5.2 2014

United 

Kingdom Lincs 270 35 5.9 2013

Belgium Northwind 216 14.5 8.8 2014

Denmark Horns Rev 2 209.3 33 4.9 2009

Denmark Rodsand 2 207 34 5.7 2010
11 

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3 Overview of MA WEA Delineation Results

3.1 Introduction

The primary objectives of the NREL interagency agreement were to: 

• Develop a technical methodology and approach to delineate leasing areas within the MA 

WEA, such that the leasing areaswhen aggregatedare equal to the total area within 

the WEA

• Evaluate different delineation options, which includes considering the various internal 

and external physical factors of the defined leasing areas, and identify the advantages and 

disadvantages of each option. 

As explained in Section 1, NREL obtained feedback that was used in developing the final 

methodology and delineation options for the analysis of the MA WEA following feedback from 

BOEM, the Massachusetts Renewable Energy Task Force, and Massachusetts state agencies of 

NREL’s proposed methodology. 

For each of the delineation alternatives, several quantitative and qualitative evaluation criteria 

were examined. These criteria are listed in Table 4. Some of these criteria relate to the physical 

characteristics of the MA WEA and are discussed in Section 4 while other criteria relate 

primarily to specific wake losses and array spacing assumptions and are covered in Section 5. 

Table 4. Evaluation Criteria Used by NREL to Assess the MA WEA

(Source: NREL)

Quantitative Evaluation Criteria Qualitative Evaluation Criteria 

Total area (km2 and acres) Distance from shore

Maximum nameplate capacity (MW) Technology challenges

Bathymetry (m) Development cost

Annual average wind speed and direction [meters per 

second (m/s)]

Interconnection logistics

500-MW phased developments Development timing

Wake losses (%) and array efficiency

Array orientation angle (degrees)

Turbine spacing within array (D)

Capacity factor after wake losses (%) 

Annual energy production [gigawatt-hours (GWh)]
12 

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For each leasing area option, NREL evaluated and compared the full development potential 

using 8 D x 8 D, 8 D x 12 D, and 8 D x 15 D turbine spacing. The full development of the entire 

WEA (without including internal buffers) was not considered a reasonable assumption for actual 

development, and NREL felt that decisions based solely on maximum development potential of 

the WEA could be misleading. Therefore, NREL also evaluated and compared phased 

developments of two 500-MW projects per leasing area (one in the 6−8 year time frame in 

shallower water and one later, in the 10−16 year time frame in deeper water). This additional 

analysis, described in Section 5, was added by NREL as a way to assess projects of a reasonable 

scale based on experience and data collected from European wind facilities. It should be noted 

that the MA WEA is larger than other WEAs assessed and its development potential is not 

limited exclusively by area. Bathymetry and wake effects caused by array density are important 

variables in the MA WEA. Other siting issues, such as environmental and competing use factors, 

may also influence array density as site development progresses. 

3.2 Overview of NREL Methodology

The MA WEA has a total area of 3,006.7 km2, which is capable of supporting at least four to five

separate leasing areas. NREL conducted analysis using specific criteria to examine delineation 

scenarios for the MA WEA.

NREL’s technical assessment included a comparison of key parameters, such as maximum 

development capacity, wind speed, bathymetry impacts, capacity factor (after wake losses), wind 

direction, wake losses, and energy production. To model these parameters, researchers created 

spatial maps using the WEA geographic information system (GIS) coordinates provided by 

BOEM and evaluated the delineation options using area, wind speed, wind direction, and 

bathymetry as the primary input source data. Three delineation options were developed having 

four to five leasing areas each. The initial delineations were reviewed and refined through 

collaboration with BOEM and an unpublished interim report was submitted to BOEM describing 

the final options. Gridded layouts were created using in the OpenWind Enterprise tool developed 

by AWS Truepower (AWS Truepower 2010). The layouts were then applied to the three 

delineation alternatives for evaluation and comparison. Researchers used the OpenWind tool to 

evaluate array effects, energy production capacity, and capacity factor.

Table 5, Table 6, and Table 7 provide comparisons of the quantitative results of offshore wind 

facility performance analysis for the three leasing area delineation options assessed by NREL as 

shown in Figure 4. Each option was assessed for a baseline turbine array spacing of 8 D x 12 D 

with full development. In addition, much of the analysis was focused on phased development, in 

which two 500-MW projects were placed in each of the five leasing area options. For the phased 

array analysis, 8 D x 8 D, 8 D x 12 D, and 8 D x 15 D turbine array spacing were evaluated for 

turbine placement wake losses versus water depth impact.

Under NREL’s phased development analysis, phase 1 assumes that one 500-MW project will be 

installed in each leasing area in the shallowest areas below 50 m. Phase 2 is assumed to be a 

second 500-MW project in each leasing area that is added at some future date. Phase 2 is 

assumed to have a 50-D internal buffer away from the phase 1 project and is built in the next 

shallowest sites in the same leasing area. In most cases, phase 2 is upwind from the phase 1 

projects and is in deeper water. It is assumed that both phases use fixed-bottom foundation 
13 

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technology but that the deeper waters of phase 2 will be more difficult and time-consuming to 

develop. The array spacing is varied to assess the impact on water depth of spreading the 

turbines further apart to reduce wake losses.

Figure 4. Three delineation options used in the MA WEA assessment. Alternative 1: Four leasing 

areas with diagonal delineation; Alternative 2: Five leasing areas with diagonal delineations; 

Alternative 3: Five leasing areas with deep water carve out

(Source: NREL)
14 

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Table 5. MA WEA Delineation Analysis for Alternative 1 

(Source: NREL)

Delineation Alternative 1

Parameter Leasing 

Area 1

Leasing 

Area 2

Leasing 

Area 3

Leasing 

Area 4

Total area (km2) 759 676 1,004 569

Total area (<50m) 407 415 408 395

Ave. depth (m) 47.6 51.8 47.9 49.8

Bathymetry – depth range (m) 36.0−61.0 37.6−63.0 34.0−62.0 33.0−61.4

Ave wind speed at 90 m (m/s) 9.3 9.3 9.4 9.2

8 D x 8 D Full Development

Wake losses (%) 10.6 12.3 12.4 10.5

Gross capacity factor (CF) after wake 

losses (%) 45.2 44.4 44.4 46

Potential capacity (MW) 3,430 2,715 4,450 2,505

Annual energy production (GWh) 13,590 10,557.6 17,331.8 10,094.9

8 D x 12 D Full Development

Wake losses (%) 8.3 9.9 10 8.3

Gross CF after wake losses (%) 46.4 45.6 45.7 47.2

Potential capacity (MW) 2,305 1,855 2,955 1,695

Annual energy production (GWh) 9,366 7,411.7 11,836.3 7,006.1

8 D x 15 D Full Development

Wake losses (%) 7.2 8.7 8.8 7.3

Gross CF after wake losses (%) 46.9 46.2 46.3 47.7

Potential capacity (MW) 1,850 1,455 2,360 1,360

Annual energy production (GWh) 7,601.6 5,891.5 9,574.3 5,684.2

8 D x 8 D Phase 1 (500 MW each)

Wake losses (%) 6 6.9 5.7 5.4

Gross CF after wake losses (%) 47.7 47.4 48.2 48.8

Potential capacity (MW) 500 500 500 500

Phase 1 depth range (m) 33.0−45.0 36.0−42.0 37.6−45.0 34.0−44.0

Annual energy production (GWh) 2,091 2,078.3 2,114.3 2,138.3

8 D x 8 D Phase 1 and 2 (1,000 MW each)

Wake losses (%) 6.3 8.3 7 6.3

Gross CF after wake losses (%) 47.5 46.6 47.4 48.2

Potential capacity (MW) 1,000 1,000 1,000 1,000

Phase 2 depth range (m) 44.7−51.0 43.0−50.0 45.0−51.0 46.0−50.0

Annual energy production (GWh) 4,162.3 4,083.9 4,159.2 4,229.1
15 

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8 D x 12 D Phase 1 (500 MW each)

Wake losses (%) 5.2 6.2 5.1 4.9

Gross CF after wake losses (%) 48.1 47.8 48.5 49

Potential capacity (MW) 500 500 500 500

Phase 1 depth range (m) 33.0−47.0 36.0−45.0 37.2−46.0 34.6−46.0

Annual energy production (GWh) 2,109.7 2,093.8 2,127.9 2,148

8 D x 12 D Phase 1 and 2 (1,000 MW each)

Wake losses (%) 5.9 7.3 6.4 5.7

Gross CF after wake losses (%) 47.7 47 47.7 48.5

Potential capacity (MW) 1,000 1,000 1,000 1,000

Phase 2 depth range (m) 46.0−53.0 46.0−53.3 48.0−54.0 47.0−59.0

Annual energy production (GWh) 4,179.6 4,119.6 4,180.4 4,253.5

8 D x 15 D Phase 1 (500 MW each)

Wake losses (%) 5 5.8 4.9 4.5

Gross CF after wake losses (%) 48.3 47.9 48.6 49.2

Potential capacity (MW) 500 500 500 500

Phase 1 depth range (m) 34.0−48.0 37.0−47.8 37.2−47.3 32.9−46.0

Annual energy production (GWh) 2,115.7 2,101.3 2,130.6 2,156

8 D x 15 D Phase 1 and 2 (1,000 MW each)

Wake losses (%) 5.7 6.8 6.3 5.4

Gross CF after wake losses (%) 45.6 45.7 47.2 46.4

Potential capacity (MW) 1,855 2,955 1,695 2,305

Phase 2 depth range (m) 47.0−54.0 46.0−56.0 48.0−54.0 49.0−62.2

Annual energy production (GWh) 7,411.7 11,836.3 7,006.1 9,366
16 

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Table 6. MA WEA Delineation Analysis for Alternative 2

(Source: NREL)

 Delineation Alternative 2

Parameter Leasing 

Area 1

Leasing 

Area 2

Leasing 

Area 3

Leasing 

Area 4

Leasing Area 

5 

Total area (km2) 642 484 792 644 445

Total area (<50m) 324 325 328 323 326

Ave depth (m) 50 47 51 51 48

Bathymetry – depth range (m) 33.0−61.0 36.1−55.6 37.0−62.0 37.0−63.2 34.0−61.5

Ave wind speed at 90 m (m/s) 9.3 9.3 9.3 9.4 9.4

8 D x 8 D Full Development

Wake losses (%) 10 11.9 12.4 11.8 10.2

Gross CF after wake losses (%) 45.5 44.6 44.3 44.9 46.2

Potential capacity (MW) 2,755 1,830 3,375 2,675 2,015

Annual energy production (GWh) 10,985.9 7,151.3 13,109.5 10,536 8,162.4

8 D x 12 D Full Development

Wake losses (%) 7.9 9.4 9.9 9.3 7.9

Gross CF after wake losses (%) 46.7 45.9 45.7 46.3 47.5

Potential capacity (MW) 1,910 1,220 2,240 1,795 1,315

Annual energy production (GWh) 7,812.2 4,908.4 8,966.3 7,279.8 5,470

8 D x 15 D Full Development

Wake losses (%) 6.9 8.2 8.8 8.2 6.9

Gross CF after wake losses (%) 47.1 46.4 46.2 46.7 47.9

Potential capacity (MW) 1,530 965 1,790 1,430 1,050

Annual energy production (GWh) 6,312.4 3,925.7 7,244.8 5,860.3 4,406.9

8 D x 8 D Phase 1 (500 MW each)

Wake losses (%) 6.1 7.8 7.1 6.5 5.8

Gross CF after wake losses (%) 47.7 46.9 47.4 47.9 48.6

Potential capacity (MW) 500 500 500 500 500

Phase 1 depth range (m) 34.0−46.0 37.0−47.0 37.0−44.0 36.1−45.7 33.0−46.0

Annual energy production (GWh) 2,089.3 2,054 2,076.9 2,100.8 2,130.2

8 D x 8 D Phase 1 and 2 (1,000 MW each)

Wake losses (%) 6.5 8.8 8.4 7.8 6.9

Gross CF after wake losses (%) 47.3 46.2 46.6 47.1 48

Potential capacity (MW) 1,000 1,000 1,000 1,000 1,000

Phase 2 depth range (m) 47.0−51.0 45.0−55.0 47.0−53.0 48.0−52.0 45.0−51.0

Annual energy production (GWh) 4,150.3 4,049.9 4,081.5 4,132.5 4,206.6
17 

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8 D x 12 D Phase 1 (500 MW each)

Wake losses (%) 5.6 6.7 6.3 5.8 5.3

Gross CF after wake losses (%) 48 47.4 47.8 48.3 48.8

Potential capacity (MW) 500 500 500 500 500

Phase 1 depth range (m) 34.0−46.0 37.0−48.0 36.4−48.0 36.0−48.4 33.0−48.6

Annual energy production (GWh) 2,102.7 2,075.9 2,096 2,114.8 2,140.3

8 D x 12 D Phase 1 and 2 (1,000 MW each)

Wake losses (%) 6.3 7.3 7.5 7.1 6

Gross CF after wake losses (%) 47.5 46.9 47 47.4 48.4

Potential capacity (MW) 1,000 960 1,000 1,000 900

Phase 2 depth range (m) 46.0−54.0 47.5−55.0 48.0−54.0 49.0−58.0 48.0−62.0

Annual energy production (GWh) 4,160.5 3,944.3 4,118.5 4,157.8 3,817.7

8 D x 15 D Phase 1 (500 MW each)

Wake losses (%) 4.7 6.1 6 5.4 4.8

Gross CF after wake losses (%) 48.4 47.6 47.9 48.4 49.2

Potential capacity (MW) 500 500 500 500 500

Phase 1 depth range (m) 34.0−50.0 36.1−48.2 37.0−48.0 38.0−49.0 35.0−50.0

Annual energy production (GWh) 2,120.4 2,087.4 2,101.2 2,123.1 2,155

8 D x 15 D Phase 1 and 2 (1,000 MW each)

Wake losses (%) 5.7 6.8 7 6.6 5.563291

Gross CF after wake losses (%) 47.7 47.2 47.1 47.6 48.58987

Potential capacity (MW) 1,000 790 1,000 1,000 790

Phase 2 depth range (m) 50.0−59.0 49.0−55.0 50.0−56.0 50.0−62.0 48.0−61.0

Annual energy production (GWh) 4,180 3,266.3 4,132.9 4,175.3 3,366.4
18 

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Table 7. MA WEA Delineation Analysis for Alternative 3

(Source: NREL)

Delineation Alternative 3

Parameter Leasing 

Area 1

Leasing 

Area 2

Leasing 

Area 3

Leasing 

Area 4

Leasing 

Area 5

Total area (km2) 531 496 844 569 567

Total area (<50m) 407 411 408 395 4

Ave depth (m) 47 45 50 48 56

Bathymetry – depth range (m) 33.0−54.0 36.0−54.0 37.6−62.0 34.0−62.0 50.0−62.0

Ave wind speed at 90 m (m/s) 9.3 9.3 9.3 9.4 9.3

8 D x 8 D Full Development

Wake losses (%) 10.8 12.1 12.5 10.3 9.5

Gross CF after wake losses (%) 45.2 44.6 44.5 46.1 45.5

Potential capacity (MW) 2,255 1,845 3,430 2,425 2,265

Annual energy production (GWh) 8,927.4 7,206.7 13,378.9 9,798.7 9,042.1

8 D x 12 D Full Development

Wake losses (%) 8.5 9.6 10 8.2 7.5

Gross CF after wake losses (%) 46.4 45.8 45.7 47.2 46.6

Potential capacity (MW) 1,470 1,220 2,295 1,660 1,585

Annual energy production (GWh) 5,975 4,900.6 9,201.9 6,869.9 6,472.2

8 D x 15 D Full Development

Wake losses (%) 7.4 8.4 8.9 7.1 6.5

Gross CF after wake losses (%) 46.9 46.4 46.3 47.7 47.1

Potential capacity (MW) 1,170 970 1,840 1,330 1,250

Annual energy production (GWh) 4,812.2 3,946.8 7,473.2 5,566.9 5,158.5

8 D x 8 D Phase 1 (500 MW each)

Wake losses (%) 6 6.9 5.7 5.4 N/A

Gross CF after wake losses (%) 47.7 47.4 48.2 48.8 N/A

Potential capacity (MW) 500 500 500 500 N/A

Phase 1 depth range (m) 33.0−45.0 36.0−42.0 37.6−45.0 34.0−44.0 N/A

Annual energy production (GWh) 2,091 2,078.3 2,114.3 2,138.3 N/A

8 D x 8 D Phase 1 and 2 (1,000 MW each)

Wake losses (%) 6.9 8.7 7.3 6.3 6.4

Gross CF after wake losses (%) 47.2 46.4 47.3 48.2 47.1

Potential capacity (MW) 1,000 1,000 1,000 1,000 1,000

Phase 2 depth range (m) 44.7−51.0 43.0−50.0 45.0−51.0 46.0−50.0 46.0−50.0

Annual energy production (GWh) 4,133.6 4,064.2 4,146.3 4,228 4,129.3
19 

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8 D x 12 D Phase 1 (500 MW each)

Wake losses (%) 5.2 6.2 5.1 4.9 N/A

Gross CF after wake losses (%) 48.1 47.8 48.5 49 N/A

Potential capacity (MW) 500 500 500 500 N/A

Phase 1 depth range (m) 33.0−47.0 36.0−45.0 37.2−46.0 37.2−46.0 N/A

Annual energy production (GWh) 2,109.7 2,093.8 2,127.9 2,148 N/A

8 D x 12 D Phase 1 and 2 (1,000 MW each)

Wake losses (%) 6.7 8 6.8 5.7 6.3

Gross CF after wake losses (%) 47.3 46.6 47.5 48.5 47.2

Potential capacity (MW) 1,000 1,000 1,000 1,000 1,000

Phase 2 depth range (m) 46.0−53.0 46.0−53.3 48.0−54.0 47.0−59.0 51.0−60.0

Annual energy production (GWh) 4,143.3 4,086.1 4,166.7 4,252.1 4,134.3

8 D x 15 D Phase 1 (500 MW each)

Wake losses (%) 5 5.8 4.9 4.5 N/A

Gross CF after wake losses (%) 48.3 47.9 48.6 49.2 N/A

Potential capacity (MW) 500 500 500 500 N/A

Phase 1 depth range (m) 34.0−48.0 37.0−47.8 37.2−47.3 32.9−46.0 N/A

Annual energy production (GWh) 2,115.7 2,101.3 2,130.6 2,156 N/A

8 D x 15 D Phase 1 and 2 (1,000 MW each)

Wake losses (%) 6.4 7.1 6.6 5.4 5.6

Gross CF after wake losses (%) 47.4 47.1 47.6 48.6 47.5

Potential capacity (MW) 1,000 790 1,000 955 1,000

Phase 2 depth range (m) 47.0−54.0 46.0−53.0 48.0−54.0 49.0−62.2 50.0−60.0

Annual energy production (GWh) 4,154.3 3,263.8 4,169.3 4,067.7 4,164.6

4 Physical Assessment and Delineation Analysis 

4.1 Bathymetry Considerations

The water depth, or bathymetry, was considered a major variable in assessing the wind 

development potential of the MA WEA leasing area. Figure 5 shows a bathymetry map of the 

MA WEA. Data plotted in the figure were derived from the National Oceanic and Atmospheric 

Administration’s (NOAA’s) Coastal Relief Model (CRM) for New England. The native data are 

in a geographic coordinate system, and were reprojected to the wind resource projection (UTM 

zone 18) using a bilinear resampling method resulting in a 100-m spatial resolution.

NOAA’s CRM is a nationally comprehensive dataset, available at a relatively high spatial 

resolution (3 arc-seconds) for the coastal waters of the contiguous United States and 

Hawaii. NOAA has integrated data from the U.S. National Ocean Service Hydrographic 

Database, U.S. Geological Survey, Monterey Bay Aquarium Research Institute, U.S. Army 

Corps of Engineers, International Bathymetric Chart of the Caribbean Sea and the Gulf of 

Mexico, and various other academic institutions. Freely available to the public, NREL is able to 

distribute the data used in our analysis to our partners and stakeholders. The data is 

downloadable from NOAA’s National Geophysical Data Center at 
20 

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at www.nrel.gov/publications.

http://www.ngdc.noaa.gov/mgg/coastal/crm.html, which provides scientific stewardship for sea 

floor and lakebed geophysical data including bathymetry (NOAA 2013). 

Figure 5. Water depth map for the MA WEA

(Source: NREL)

Depth considerations are important with respect to project risk, cost, and expected development 

timing. Figure 6 shows a plot of the current projects installed, under construction, contracted, and 

approved in Europe as a function of the expected commercial commissioning date as of the end 

of 2012. The figure shows that the majority of the operating projects are installed in waters less 

than 30 m deep, with only a few of the newer projects pushing into depths of 35 m or greater 

[e.g., Alpha Ventus/Germany (average depth of 30 m) and Talisman Energy/Scotland (average 

depth of 45 m)]. Until now, European projects have remained in shallow water because shallow 

waters are more abundant in the North and Baltic Seas than in U.S. waters, and it was necessary 

for the industry to gain experience in shallower waters to gain confidence in the technology. 

European offshore wind developers are now beginning to venture into deeper waters and future 

projects are being planned and constructed in depths of up to 50 m, but these are not yet 

commissioned. 
21 

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Figure 6. Current offshore wind projects in Europe: installed, under construction, contracted, and 

approved as a function of expected commercial operation date 

(Source: NREL)

The analysis found that the MA WEA has a range of water depths between 35 m and 65 m, with 

an average depth of about 50 m. Figure 7 shows the distribution of depths across the MA WEA 

in a histogram. For the assessment, NREL assumed that there would be two development phases 

corresponding to water depth with the assumption that shallow water would be developed first 

and then deeper water at a later phase. Based on the data shown in Figure 6 and from the RFI and 

Call responses (Table 1 and Table 2 showing 6−16 year development time frames), the 

development time frame for phase 1 projects (<50 m) was assumed to be 6−8 years and 10−16 

years for phase 2 projects. This assumption was applied in Section 5, in which project capacity 

and wake effects were studied for 500-MW phased development scenarios with each leasing area 

consisting of one 500-MW project initially and then a second project at a later date.
22 

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Figure 7. Histogram of water depths for the MA WEA showing water depths ranging from 30 m to 

65 m for the total WEA using May 2012 boundaries (3,006.7 km2

) 

(Source: NREL)

4.2 Wind Resource 

4.2.1 Wind Source Data 

For this investigation, NREL surveyed a variety of data sources to find a high-quality dataset that 

embodies best industry practices. Ultimately, the wind resource data used for the MA WEA was 

a high-resolution, long-term record obtained from AWS Truepower that correlated well with 

local empirical observations. 

The mesoscale model, Mesoscale Atmospheric Simulations System, was used to simulate the 

atmosphere with a coarse, horizontal grid spacing of 20 km over the United States and 

immediately offshore (Manobianco et al. 1996). The Mesoscale Atmospheric Simulations 

System is a numerical weather model that has been developed over the past 20 years by MESO, 

Inc., in partnership with AWS Truepower. The mesoscale simulations were processed to produce 

a long-term time series of weather information called windTrends. The windTrends dataset is 

available from 1997 to the present and contains hourly approximations of several meteorological 

fields, including wind speed and direction. This data set was used to produce an annual average 

wind speed map at a resolution of 20,000 m (20 km) and a set of statistical files containing 

information about the wind resource. This information was then used as input to the microscale 

model, WindMap (Brower 1999), which interpolates the coarse 20-km grid data to a highresolution grid spacing of 200 m to simulate more localized effects. The outputs of WindMap are 

200-m mean annual wind speed maps and wind resource grid (WRG/B) files containing the wind 

speed, wind direction, and frequency distribution of the wind speed, at a hub height of 90 m. 
23 

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at www.nrel.gov/publications.

NREL researchers input these WRG/B files into the OpenWind model, where the wind speed 

gradients and directional distributions across the WEA were determined. 

As with any analytically based modeling process, significant uncertainties are embodied in the 

model data. Therefore, validation with empirical measurements is needed to gain sufficient 

confidence in the modeled results. We compared the 200-m high-resolution WindMap data to the 

well-established Modern-Era Retrospective Analysis (MERRA) data set produced by the 

National Aeronautics and Space Administration (NASA 2013). MERRA integrates a variety of 

observing systems with numerical models to produce a temporally and spatially consistent 

synthesis of observations and analyses of variables that are not easily observed. MERRA data 

confirmed the general wind speed and direction characteristics of the WRG/B data but it could 

not be used exclusively to accomplish the objectives of this study because it does not have the 

needed resolution. In addition, NREL usually compares modeled offshore data to measured data 

from buoys, but the MA WEA is not near any offshore buoys that could provide reliable 

validation points. We compared the MERRA data to measurements from two buoys belonging to 

the National Data Buoy Center: 44017, which is located approximately 100 km west of the MA 

WEA, and 44008, which is about 90 km to the southeast of the MA WEA. Both buoys confirmed 

the general pattern seen in MERRA and in the WRG of a southwesterly peak with lesser peaks 

from the northwest and northeast, although the distance to the WEA is too large for an accurate 

comparison (NOAA 2013). Given the lack of measurements available offshore and the coarse 

resolution of other modeled data sets, the WRG/B data files used for this study provided the best 

current wind climate information for the MA WEA.

4.2.2 Wind Resource Evaluation of the MA WEA 

The annual average wind speed determined from the AWS Truepower WRG/B data described in 

Section 3.2 is shown in the map in Figure 9 for the MA WEA. The figure shows that the wind 

speed varies from approximately 9.2 m/s to 9.5 m/s at 90 m, with highest wind speeds in the east 

and lowest speeds in the west. This wind speed gradient of about 0.3 m/s across the MA WEA 

could be significant in terms of energy production and capacity factor but is on the same scale as

the typical uncertainty of about +/-0.35 m/s that is often associated with modeled wind resource 

data for many areas of the United States (AWS Truepower 2012). 

The prevailing winds, indicated by the wind rose also shown in Figure 9, come largely from the 

southwest directions. Having a high percentage of the winds from a single prevailing direction 

sector simplifies the siting and layout optimization as opposed to more bimodal wind direction 

distributions seen in the mid-Atlantic, where projects may experience relatively higher wake 

losses and more difficultly in optimizing array layouts for power production. For the MA WEA, 

array layouts used in the analysis found that a grid orientation angle of 60 degrees provided the 

lowest wake losses.
24 

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Figure 8. (top) MA WEA showing the annual average wind speed in 0.10 m/s increments and

(bottom) the wind frequency rose with prevailing winds from the southwest direction 

(Source: NREL)
25 

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4.3 Delineation Strategy

BOEM, NREL, and the Commonwealth of Massachusetts have been discussing various 

strategies for delineating the MA WEA to create offshore leasing areas that can be auctioned in a 

future sale. This section provides the analysis used to assess possible strategies for delineating 

the MA WEA, which was presented to BOEM in an unpublished interim report on November 3, 

2013. 

The following three delineation alternatives were assessed (in no order of preference): 

• Alternative 1. Four leasing areas with diagonal delineation lines and approximately equal 

shallow area

• Alternative 2. Five leasing areas with diagonal delineation lines and approximately equal 

shallow area

• Alternative 3. Five leasing areas with four areas having approximately equal shallow area 

and one comprising mostly deep water greater than 50-m.

These alternatives were discussed and agreed upon with BOEM over several iterations and are 

shown in Figure 4. 

The criteria for selecting these delineations were based on the following assumptions and 

constraints: 

• Number of leasing areas. The leasing process was to be limited to a maximum of five nonoverlapping leasing areas that would together make up the total area of the MA WEA. With 

3,006.7 km2

, the MA WEA is a relatively large area than other BOEM WEAs as of this 

writing. This constraint ensured that the leasing areas would also be relatively large (445 km2

to 1,004 km2), with an area that is ample enough to mitigate wake losses and adapt to the 

most anticipated siting irregularities within their own boundaries. 

• Equalizing the shallow water resource. NREL found that the depth of the MA WEA 

ranged from 35 m to 65 m with the average depth at about 50 m. Researchers assumed that 

the shallower depths would be less costly and easier to develop and would therefore be more 

valuable. The delineations attempted to equalize the amount of shallow water below 50 m in 

each of the leasing areas. Cognizant that the areas cannot be perfectly equal, given the 

inherent nature of soundings data and the fact that BOEM would prefer not to sub-divide 

aliquots, BOEM asked that the range between the maximum and minimum shallow areas 

among leasing areas be kept to a minimal difference (i.e., 5%).

• Minimizing external wake effects. Delineation lines were drawn at approximately a 45 

degree southwest-to-northeast diagonal to be approximately parallel to the prevailing 

southwest wind direction shown in Figure 8. This strategy was developed to minimize 

potential conflicts between neighboring wind projects and to give the lessees the maximum 

control over their own area. The inefficiencies associated with drawing zigzag diagonal 

delineation lines along the north-south aliquot grid (which were important to avoid in areas 

such as Maryland) were relatively inconsequential in Massachusetts due to relatively large 

leasing areas (Musial et al. 2013). 
26 

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• Wind resource. Researchers considered average wind speed across the MA WEA and found 

that it varied between 9.2 m/s and 9.4 m/s, which is very low variability. As a result, average 

wind speed did not play a major role in delineation boundary decisions because the energy 

capture potential between areas was not impacted significantly by wind speed variations. 

Note that for the small wind speed gradient that does exist, the variations are generally from 

west to east. Therefore, variations of annual average wind speed only occur between leasing 

areas but not within leasing areas. 

Section 4.3 includes details on each of the alternatives with the pros and cons included in this 

section. For each alternative, there is a set of figures and tables that include: 

• A summary table that provides the water depths, areas, average wind speed, and generating 

capacity estimates. Water depths were estimated from the NOAA CRM model, which were 

reprojected to 100 m x 100 m cells in UTM zone 18 with bilinear resampling. Capacity 

estimates were based on assumed 8 D x 12 D turbine spacing using the NREL 5-MW, 126-m 

diameter rotor wind turbine. 

• A map showing the WEA with the proposed delineation boundaries (also see Figure 4). 

These figures all contain the wind rose from Figure 8 for the MA WEA to illustrate how the 

delineation boundaries are drawn parallel to the prevailing southwest wind direction. Each 

figure also shows two levels of water depth (bathymetry). The darker/brighter green color 

indicates depths greater than 50 m and the lighter green indicates depths less than 50 m.

• A bar chart comparing the amount of shallow water (less than 50 m) and the total area of 

each leasing area within each alternative. 

• A line graph comparing the water depths in 5-m increments for each leasing area. These

charts provide better resolution for identifying specific differences among the areas that 

might be important to developers. 

4.3.1 Alternative 1 

Alternative 1 divides the MA WEA along diagonal lines parallel to the prevailing wind direction 

and orthogonal to the isobaths using four leasing areas as shown in Figure 9. As indicated in

Table 5, the four leasing areas range in total area between 569 km2 and 1,004 km2 but have very 

similar areas sizes for water below 50 m ranging between 395 km2 and 415 km2. Using this 

alternative, each leasing area would be able to support at least one large near-term wind project 

using fixed-bottom technology in the areas less than 50 m deep. Table 5 shows that gross 

capacity is estimated between 1,294 MW and 1,361 MW for the area with water depths below 50

m using an 8 D x 12 D layout. The primary advantage of Alternative 1 is that the average depth 

of projects would be shallower and therefore easier to build at a lower cost (about the same as 

Alternative 3 in leasing areas 1−4). Compared to Alternative 2, the shallow region is larger in 

Alternative 1, which gives developers some additional flexibility to select the more optimal 

siting options. The upwind fetch for each leasing area in the prevailing direction would be 

controlled mostly by each respective lessee so inter-array wake effects would be minimized. The 

same assumptions would apply for Alternative 3 except the deeper water in leasing areas 1, 2, 

and 3 of Alternative 1 is carved off into a fifth deep water site in Alternative 3. 

Note that in Alternative 1, the total area varies significantly between leasing areas, which is due 

almost entirely to the area over the deeper aliquots as shown in Figure 10. The deeper regions 
27 

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may also be able to support an additional wind project in some of the leasing areas but the 

technology and cost to develop these regions may limit their commercially viability in the near 

term. 

Figure 11 shows the distribution of bathymetry over all of the Alternative 1 leasing areas. From 

this plot it can be seen that leasing area 2 has the best distribution of shallow water with more 

area concentrated in the shallower 35 m−40 m bin. 

Table 8. Alternative 1: Four Leasing Area Delineation for the MA WEA 

(Source: NREL)

Alternative 1

Leasing 

Area 1

Leasing 

Area 2

Leasing 

Area 3

Leasing 

Area 4

All 

Areas

Total area (km2) 759 676 1,004 569 3,008

Total area <50m (km2) 407 415 408 395 1,625

Estimated total gross 

capacity (MW)*

2,490 2,216 3,294 1,867 9,868

Estimated gross capacity 

less than 50 m (MW)*

1,337 1,361 1,340 1,294 5,332

Ave depth (m) 50 48 52 48 50

Ave depth <50 m (m) 46 44 46 45 45

Depth range (m) Area at depth (km2)

>60 4 3 64 19 90

55−60 110 54 225 70 459

50−55 237 204 307 86 834

45−50 226 174 218 167 785

40−45 143 140 166 189 638

35−40 32 101 24 36 193

<35 7 0 0 3 9

Average wind speed (m/s) 9.2 9.2 9.3 9.3 9.25
28 

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Figure 9. Alternative 1: Four leasing areas with approximately equal shallow water area less than 

50 m 

(Source: NREL) 

Figure 10. Alternative 1: Distribution of area among four leasing areas showing approximately 

equal shallow water less than 50 m (maximum variation of shallow water area = 5%) 

(Source: NREL)

0

200

400

600

800

1000

1200

1 2 3 4

Area km2

Leasing Area 

Total Area (km2)

Total Area (<50m)
29 

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Figure 11. Alternative 1: Plot showing depth distribution for each leasing area over the entire MA 

WEA. Shaded area indicates depths that are greater than 50 m. 

(Source: NREL) 

4.3.2 Alternative 2

Alternative 2 divides the MA WEA along diagonal southwest-to-northeast lines parallel to the 

prevailing wind direction and orthogonal to the isobaths using five leasing areas as shown in 

Figure 12. Similar to Alternative 1, each area has approximately the same total shallow water 

area in depths less than 50 m. In Table 6, the total areas range from 445 km2 to 792 km2 for all 

five leasing areas, with the shallow area below 50 m ranging from 323 km2 to 328km2. Using 

this alternative, each leasing area would be able to support at least one large near-term wind 

project using fixed-bottom technology in the areas less than 50 m deep. Table 6 shows that gross 

capacity is estimated between 1,058 MW and 1,075 MW for the WEA for water depths below 50 

m using an 8 D x 12 D layout. The primary advantage of Alternative 2 is that the number of 

auctionable leasing areas would be maximized (five) while providing prospective lessees with 

principal control over their respective upwind fetches. Compared to Alternative 1, the projects in 

shallower water would need to be constructed incrementally further out and in deeper water for 

the same turbine spacing. 

Note that in Alternative 2, the total area varies significantly between leasing areas, which is 

caused by the differences in area over the deeper aliquots as shown in Figure 13. The deeper 

regions may also be able to support an additional wind project, but technology and cost to 

develop these regions limit commercial viability in the near term.

Figure 14 shows the distribution of bathymetry over all five leasing areas. From this plot it can 

be seen that leasing area 2 and 3 have the best distribution of shallow water with more area 

concentrated in the 35-m to 40-m bin. 
30 

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Table 9. Alternative 2: Five Leasing Area Diagonal Delineation for the MA WEA 

(Source: NREL) 

Alternative 2

Leasing 

Area 1

Leasing 

Area 2

Leasing 

Area 3

Leasing 

Area 4

Leasing 

Area 5

All 

Areas

Total area (km2) 642 484 792 644 445 3,008

Total area <50m (km2) 324 325 328 323 326 1,625

Estimated total gross 

capacity (MW)*

2,107 1,588 2,599 2,113 1,461 9,868

Estimated gross capacity 

less than 50 m (MW)*

1,065 1,065 1,075 1,058 1,068 5,332

Ave depth 50 47 51 51 48 50

Ave depth <50 m (m) 46 44 45 46 45 45

Depth range (m) Area at depth (km2)

>60 4 0 29 52 6 90

55−60 110 1 172 127 49 459

50−55 204 158 264 143 65 834

45−50 189 143 139 181 133 785

40−45 116 106 135 122 159 638

35−40 13 76 54 20 31 193

<35 7 0 0 0 3 9

Average wind speed (m/s) 9.2 9.2 9.2 9.3 9.3 9.24

*Notes: Assumes 8 D x 12 D rotor spacing
31 

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Figure 12. Alternative 2: Five leasing areas with approximately equal division of shallow water 

area less than 50 m

(Source: NREL)

Figure 13. Alternative 2: Distribution of area among five leasing areas showing approximately 

equal shallow water less than 50 meters (Maximum 1.58% variation)

(Source: NREL)

0

100

200

300

400

500

600

700

800

900

1 2 3 4 5

Square Kilometers 

Leasing Area

total area

less than 50m
32 

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Figure 14. Alternative 2: Plot showing depth distribution for each leasing area over the entire 

depth range. Shaded area indicates depths that are greater than 50 m. 

(Source: NREL) 

4.3.3 Alternative 3

Alternative 3 divides the MA WEA along diagonal lines parallel to the prevailing wind direction 

and orthogonal to the isobaths using the four leasing areas described in Alternative 1, but 

creating a fifth leasing area by carving deeper water areas from leasing areas 1 through 3 as 

shown in Figure 15. In Table 7, the leasing areas range in total area between 496 km2 and 844 

km2. Leasing areas 1 through 4 have very similar areas sizes for water below 50 m that are nearly 

identical to the areas in Alternative 1, ranging between 395 km2

 and 411 km2 (note that a small 

amount of shallow water (4 km2) was transferred to leasing area 5 from leasing area 2). Using 

this alternative, each leasing area 1 through 4 would be able to support at least one large nearterm wind project using fixed-bottom technology in the areas less than 50 m deep. Table 7 shows 

that the gross capacity is estimated between 1,294 MW and 1,349 MW for the area with water 

depths below 50 m using an 8 D x 12 D layout in leasing areas 1 through 4. The primary 

advantage of Alternative 3 is that shallow projects would still be easier to build and 

incrementally lower in cost (about the same as Alternative 1), but developers in leasing areas 1 

through 3 would not be burdened with as much deep water, which could add significant cost to 

hold the lease. Compared to Alternative 2, the shallow region in each leasing area in 

Alternative 3 is larger, giving developers some flexibility to select the most optimal siting 

options. The disadvantage of this alternative, however, is that the upwind fetch would not be 

controlled by the lessees in leasing areas 1 through 3 because a developer in leasing area 5 would 

eventually install projects upwind. 
33 

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In Alternative 3, the total area varies the least of the three alternatives, but differences between 

leasing areas are still significant, as shown in Figure 16. The presence of leasing area 5 (deep 

site) may limit the ability of developers in leasing areas 1 through 3 to add a deeper phased 

development when the technology to develop these regions becomes commercially available 

(See phased analysis in Section 5).

Figure 17 shows the distribution of bathymetry over all of the leasing areas. From this plot, it can 

be seen that leasing area 2 still has the best distribution of shallow water with more area 

concentrated in the 35-m to 40-m bin. 

Table 10. Alternative 3: Five Leasing Area Alternative with Separate Deep Water Site Delineation 

for the MA WEA 

(Source: NREL)

Alternative 3

Leasing 

Area 1

Leasing 

Area 2

Leasing 

Area 3 

Leasing 

Area 4

Leasing 

Area 5

All 

Areas

Total area (km2) 531 496 844 569 567 3,008

Total area <50 m (km2) 407 411 408 395 4 1,625

Estimated total gross 

capacity (MW)*

1,744 1,626 2,770 1,867 1,862 9,868

Estimated gross capacity less 

than 50 m (MW)*

1,336 1,349 1,340 1,294 13 5,332

Average depth (m) 47 45 50 48 56 50

Average depth <50m (m) 46 44 46 45 50 45

Depth range(m) Area at depth (km2)

>60 0 0 19 19 52 90

55−60 0 0 113 70 276 459

50−55 124 84 304 86 236 834

45−50 226 170 218 167 4 785

40−45 143 140 166 189 0 638

35−40 32 101 24 36 0 193

<35 7 0 0 3 0 9

Average wind speed (m/s) 9.2 9.2 9.3 9.3 9.2 9.24

*Notes: Assumes 8 D x 12 D rotor spacing
34 

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Figure 15. Alternative 3: Five leasing areas with four approximately equal shallow areas and one 

area containing only deep water

(Source: NREL)

Figure 16. Alternative 3: Distribution of area among five leasing areas showing approximately 

equal shallow water less than 50 m in leasing areas 1−4 with a maximum variation of 5% 

(Source: NREL)

0

100

200

300

400

500

600

700

800

900

1 2 3 4 5

Area km2 

Leasing Area

Total Area (km2)

Total Area (<50m)
35 

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Figure 17. Alternative 3: Depth distribution for five leasing areas with four approximately equal 

shallow areas and one area containing only deep water. Shaded area indicates water depth 

greater than 50 m.

(Source: NREL)

4.3.4 Delineation Summary

NREL researchers evaluated the three leasing area alternatives presented in this paper. Each 

provides a reasonable approach with advantages and disadvantages to delineate the 

Massachusetts offshore wind energy area into four or five leasing areas. All of the alternatives 

are feasible and would allow offshore wind developers to install large-scale projects of at least 

500 MW with minimal obstruction from adjacent wind projects. 

Of the three alternatives, NREL prefers Alternative 2. The primary basis of this preference is 

because it is believed that it would maximize the development potential of the MA WEA while

minimizing the effects of neighboring projects on adjacent wind plants. With the five leasing 

area option, each area could support at least two 500-MW projects, and some with even more 

capacity, depending on the spacing (discussed further in Section 5). 

The overarching issue for the MA WEA is the greater water depths, compared to most European 

sites developed as of 2013, which will be a primary factor in driving the economics of this WEA. 

NREL recommends that BOEM consider methods to discount the deepest aliquots to reduce the 

burden on the lessees. 
36 

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5 Wake and Array Analysis

5.1 Analysis Tool: OpenWind Enterprise

The OpenWind Enterprise tool is a commercial wind energy facility design tool created by AWS 

Truepower and licensed to NREL. It has the capability to perform layout design, flow modeling, 

wake modeling, and energy assessment. OpenWind Enterprise was selected for its 

interoperability with GIS data as well as its capability to model deep array wake effects. The 

primary OpenWind components are described as follows. 

5.1.1 WindMap Flow Model 

The WindMap flow model within OpenWind is based on the NOABL code (Phillips 1979) and 

solves the conservation of mass equation to generate a three-dimensional wind flow map. The 

model accounts for moderate changes in terrain and surface roughness when used in conjunction 

with measured time series meteorological data.

5.1.2 OpenWind Wake Model

Wake models and scientific approaches for predicting the influence of upstream turbines are 

evolving rapidly. Generally, the accepted commercially available wake modeling codes have 

improved over the past decade but still carry a high degree of uncertainty because they do not 

include accurate physical models for some important phenomena, such as turbulence, 

atmospheric stability, wake meandering (unsteady transverse displacements of the disturbed flow 

downstream of the turbine), and fundamentals, such as the correct choice of freestream wind 

speed profile (Barthelmie et al. 2010). Even the most advanced techniques for wind turbine wake 

modeling carry a relatively high degree of uncertainty. More computationally intensive research 

methods are currently under development in research laboratories but are not yet practical for 

commercial use (e.g., large-eddy simulations) (Churchfield et al. 2012). Even though these 

methods may produce more accurate results, they are still under development and are 

computationally too expensive to be used for wind energy evaluations like the one conducted for 

this report. As a result, it is difficult to make an accurate comparison of the different wake 

models that are currently available.

The model used to perform the wake loss analysis for this report is the OpenWind Deep Array 

Fast Eddy-Viscosity Wake Model (DAWM). As of the writing of this report, it is one of the most 

widely used and accepted tools in the industry. NREL’s prior experience (mostly land-based) 

indicates that the OpenWind DAWM performs better than other models that are currently 

available. The DAWM module enhances the open-source version of OpenWind and provides 

additional accuracy in the modeling of the downwind effects of freestream- and turbinegenerated turbulence and predicts the recovery of the freestream wind flow field in the array. 

DAWM within OpenWind (AWS Truepower 2010) is a combination of the open-source standard 

Eddy-Viscosity (EV) model and a roughness effect associated with each turbine. 
37 

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5.1.3 OpenWind Layout Design

The gridded turbine layer function within OpenWind was used to create maximum capacity 

layouts to fill the WEA leasing areas using the turbine spacing specified by NREL. Square or 

triangular tiling was used with manually adjusted bearing, obliquity, and offset to obtain the 

desired number of turbines. Where the layouts are adjacent to the line of delineation between 

leasing areas, the layouts force a minimum setback of 8 D from the delineation line. This is 

realistic because developers in the leasing areas do not have control over adjacent layouts and a 

setback is required to ensure minimum turbine spacing from upwind turbines that may be 

installed outside their respective leasing areas. This is a practical requirement of layout design to 

maintain turbine spacing in each leasing area and is not viewed strictly as a buffer, although the 

setback does act in the same way as a buffer imposed to allow wakes to dissipate. Additional 

buffers will probably be needed to further reduce wake losses in the development of each leasing 

area, which could dictate more extensive setbacks. For the MA WEA, NREL assumed that 

setbacks of 50 D (6.3 km) were maintained between phased developments within the same 

leasing areas. The 50-D setback was adopted because it corresponded to less than a 1.0% 

increase of wake losses from upstream wind facilities of the same size. The 50-D setback rule 

was not applied, however, when the upstream project was in an adjacent leasing area, as it was 

assumed that developers would not necessarily have control over neighboring developments. 

Layouts can also be generated within OpenWind by optimizing for energy or cost, rather than 

using the gridded turbine layer function. This iterated optimization is commonly used for landbased projects in which many development constraints, as well as road and cable layers, can be 

optimized to produce a layout that evolves organically into the best fit for the situation. For this 

assessment, NREL used the gridded turbine layer function because it is more applicable to the 

open offshore environment and allows for a quick comparison of different layout scenarios. 

Wind turbine array modeling used the NREL 5-MW reference turbine (Jonkman et al. 2009) in 

all analysis that has a rotor diameter of 126 m. This turbine is representative in nameplate 

capacity of the turbines being proposed and is considered conservative with respect to current 

technology in terms of rotor diameter, power performance, and capacity factor.

5.1.4 OpenWind Energy Assessment

The energy capture function in OpenWind sums the energy produced by the turbines using 72 

direction sectors and 71 wind speed steps. It calculates and stores the energy yield, capacity 

factor, and wake losses associated with each turbine. Losses other than those caused by the wake 

effects can be accounted for by directly entering assumptions or calculating from other layers. 

5.2 NREL Analysis of MA WEA Using OpenWind 

In Section 4, NREL researchers concluded that there are advantages and disadvantages for each 

of the delineation alternatives and that any of the three options would be feasible for BOEM to 

implement (depending on specific objectives). Of the three alternatives, NREL prefers 

Alternative 2. The primary basis for this preference is because it is believed that this layout

would maximize the development potential of the WEA while minimizing the effects of 

neighboring projects on adjacent wind plants. Each area could support at least two 500-MW 

projects, and some areas could support three depending on the spacing. Five areas could 

maximize the potential diversity among developers and therefore the potential economic benefits 
38 

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for Massachusetts. The overarching issue for the MA WEA is the greater water depths, which 

will be a primary factor in driving the economics of this WEA. 

For the MA WEA, the turbine spacing and the spacing between major project phases (i.e., the 

buffers) will determine the energy losses caused by turbine wakes, the depth at which turbines 

are installed, and the cost of the inter-array cables. This section shows how trade-offs can be 

made among these variables within the three delineation scenarios. Based on a review of historic 

and future European offshore wind plants and the information contained in the Call nominations, 

described in Section 2, full development of the MA WEA would not be expected as a full build 

of all of the available area. Instead, developers are expected to judiciously exploit the shallowest 

water areas first. To maximize energy output and minimize the consequences of deep array 

turbulence, developers would be expected to provide internal buffer zones within their leasing 

area that separate projects in unit phases. However, a study of full development nameplate 

capacity, in which all available area within the leasing area is assumed to be populated with 

turbines, does provide a good basis for comparing one area to another. However, it would 

probably overestimate wake losses. As such, NREL researchers conducted both full development 

and 500-MW unit project size analyses.

A summary of these analyses is shown in Table 11. 

Table 11. Summary of Array Spacing Analysis Conducted to Assess Wake Losses and Energy 

Production Potential for the MA WEA

(Source: NREL)

Analysis Performed Alternative 1: 

Four Leasing Area 

Scenario 

(Diagonal) 

Alternative 2: 

Five Leasing Area 

Scenario 

(Diagonal)

Alternative 3:

Five Leasing Area 

Scenario (four shallow 

and one deep leasing 

area)

Full Development Analysis

8 D x 8 D spacing

(max capacity)

  

8 D x 12 D spacing 

(max capacity)

  

8 D x 15 D spacing 

(max capacity)

  

Phased 500-MW Unit Development

8 D x 8 D 500-MW 

phased development

  

8 D x 12 D 500-MW 

phased development

  

8 D x 15 D 500 MW 

phased development

  
39 

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The analysis, summarized in Table 11, includes both full development scenarios and phased 

development. For all of the analysis cases, NREL researchers used three turbine spacing 

scenarios: 8 D x 8 D, 8 D x 12 D, and 8 D x 15 D. The numerical results of these analyses are 

shown in Table 5, Table 6, and Table 7. Some of these analyses are also shown graphically in the 

following sections to illustrate key points. The base case in most of the graphical illustrations 

was 8 D x 12 D spacing, although all spacing scenarios are represented throughout the report. In 

the Rhode Island/Massachusetts WEA and the Maryland WEA studies conducted by NREL as 

part of the WEA analyses conducted for BOEM, a baseline spacing of 8 D x 8 D was used, 

which is representative of the industry average (Figure 3, Table 3) and the resource assessment 

studies of the United States (Musial and Ram 2010, Musial 2013a, Musial et al. 2013b). For the 

New Jersey analysis, NREL used a reference spacing of 10 D x 12 D as requested by New Jersey 

(Musial et al. 2013c). The 8 D x 12 D spacing is conservative in estimating total capacity than

the 8.5 D x 10.5 D average spacing proposed by developers in the Massachusetts Call (Table 1

and Table 2). 

A 500-MW project size is typical unit capacity for what developers are proposing for offshore 

wind projects in a single phase, even though Table 1 and Table 2 show the average total 

nameplate project capacity to be over 1,500 MW. This is because most projects are envisioned 

by the developers to be installed in multiyear phases. The 500-MW scale has also been used as a 

standard reference for DOE offshore wind project cost modeling (Tegen 2012) and is considered 

a scale in which offshore wind cost economies of scale could be reached (Maples 2012). Using 

array densities that are indicative of the Call nominations (see Table 1 and Table 2), NREL 

researchers determined that each leasing area in Massachusetts could support at least two 500-

MW wind projects or a total of 5,000 MW for the entire WEA. It was assumed that each leasing 

area would deploy one 500-MW project in the near term under phase 1 (6−8 year time frame), 

and a second phase of another 500-MW project would be deployed using deeper water 

technology (10−16 year time frame). These time frames are consistent with the time frames 

found in the RFI and Call responses. 

The analysis approach assumed that phase 1 projects were deployed first, and the performance 

and wake loss analysis were conducted without the presence of phase 2 turbines. Then the phase 

2 projects were assumed to be deployed 50 D upwind of the phase 1 project, and their relative 

impacts on the original array were examined. A 50-D setback (6.3 km) from phase 1 projects was 

imposed on the phase 2 development based on a general finding that wake losses introduced by 

the upstream wind project in Phase 2 were limited to about 1% of annual energy using the 

OpenWind analysis program. By comparison, a similar analysis showed that 80 D (10.1 km) 

resulted in about 0.7% additional wake losses. The 80-D setback criterion was not used because 

it pushed the phase 2 turbines into the deepest waters, which could add significant additional 

cost. Although the rationale for selecting a 50-D setback was arbitrary, the researchers estimated 

that a 1% loss was a reasonable tradeoff, and that additional benefits from further spacing would 

be marginal. A more rigorous analysis is recommended for establishing actual setback and buffer 

requirements.
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5.3 Maximum Development Capacity

NREL researchers evaluated the development capacity of the total MA WEA for each of the 

delineation and turbine spacing scenarios using the NREL 5-MW reference turbine (Jonkman et 

al. 2009) to create full development layouts that maximized the nameplate capacity of installed 

turbines without imposing further siting constraints for attributes such as water depth. One 

exception was the assumption that developers would self-impose an internal setback buffer of 8

D from the delineation line, anticipating that neighboring developers could feasibly place 

turbines near the delineation boundary. This is consistent with NREL’s analysis for the Rhode 

Island/Massachusetts, Maryland, and New Jersey WEAs (Musial et al. 2013a, Musial et al. 

2013b, and Musial et al. 2013c). A layout map with the 8-D setback buffers is shown in Figure 

18. In this figure, an 8 D x 12 D full build analysis is shown for Alternative 3; however, the same 

data for Alternatives 1 and 2 can be found in Table 5, Table 6, and Table 7. The maximum 

nameplate capacity for this delineation alternative of the MA WEA determined to be about 8,230 

MW for the total WEA. On average, each leasing area can support between 1,220 MW and 2,295 

MW. By comparison, the five leasing area diagonal option can support an upper limit of 8,480 

MW, with a range between 1,220 MW and 2,240 MW per leasing area. The four leasing area 

option yielded a maximum nameplate capacity of 8,810 MW, with a range per leasing area 

between 1,695 MW and 2,955 MW. The variability between leasing areas was mostly because of

area differences in the deeper water (greater than 50 m). This is because equitable distribution of 

area in shallow water depths (below 50 m) was given a much higher weighting than achieving an 

overall area balance (see Section 4). 

Figure 18. MA WEA layout map for the 8 D x 12 D full build (development) scenario using the 

Alternative 3 delineation scenario showing the maximum nameplate capacity, wake losses, and 

expected annual energy production for each of the five leasing areas

(Source: NREL)
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As mentioned earlier, because development is not expected to follow a maximum capacity 

scenario, the full development capacities should be considered a theoretical upper bound for the 

MA WEA under the specific spacing scenarios prescribed. 

NREL’s comparison of all of the leasing areas analyzed for the MA WEA shows a reasonable 

balance in terms of potential development challenges and cost among the delineated leasing 

areas in each alternative, but there are some differing characteristics that could have an impact on 

developability. One important aspect (although not fully evaluated) is the distance to possible 

interconnection sites and cable routes that may require easements through neighboring leasing 

areas. Many developers indicated a preference or need to direct their power off-take cables 

toward the northwest, either to Buzzards Bay, Narragansett Bay, or points in eastern Connecticut 

or Long Island power grids, although some developers did indicate that their export cables could 

land in Cape Cod and the islands. If there is a preference to export power toward the more 

populated parts of Massachusetts, Rhode Island, and New York, leasing areas on the west side 

would have an advantage. In any case, it may be prudent to consider options for coordinating 

cable routing strategies and possible easements. Within the MA WEA this could be a strong 

driver in appraising leasing area value.

5.4 Capacity Factor after Wake Losses

The gross capacity factor is the average energy output (before any losses outside the turbine 

itself are considered) as a percentage of the maximum possible energy output if the turbines were 

operating continuously at their rated power output, which is 5 MW per turbine for this analysis. 

For each delineation option, the gross capacity factor was calculated using the OpenWind 

analysis tool, and methods and layouts described in Section 5.1 and Section 5.2. Table 5, Table 

6, and Table 7 provide the gross capacity factors for all of the leasing areas and delineation 

options after wake losses are subtracted. These capacity factors after wake losses are estimated to 

be in the range of 45% to 49%, depending on the leasing areas and the turbine layout. The 

capacity factors generally range about 1% lower in the western leasing areas. Furthermore, the 

capacity factors reported in this analysis should not be confused with the net capacity factor 

(NCF), which is based on actual power delivered on shore and would account for such things as 

electrical losses in transmitting the power to shore, blade soiling, and other operating 

inefficiencies. NCF values would likely be nearer to 40% as estimated by some of the RFI and 

Call nominations shown in Table 1 and Table 2. 

5.5 Wake and Array Losses

5.5.1 Introduction

Wind turbine wakes within an array can result in losses in energy production and increases in 

structural fatigue loading. The severity of wake conditions is affected by climatic conditions, 

such as the ambient wind speed, ambient turbulence intensity, atmospheric stability conditions, 

and prevailing wind directions. Wake characteristics are also strongly influenced by the physical 

parameters of the wind facility including the number of turbines in operation, their spacing, and 

the wind plant layout. Further wake losses can also be induced by the presence of neighboring 

wind plants. 

Atmospheric stability is a measure of the wind’s tendency to rise and fall vertically as it flows in 

the horizontal direction. When the atmosphere is stable, the thermal layers of the atmosphere are 
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stratified, which means that heavier, cooler air is at the lowest layer and the warmer air is aloft.

In this case, the flow generally stays in horizontal layers and has little tendency to mix vertically. 

If the temperature differential is reversed and the warmer air is below and cooler air is aloft, then 

the atmosphere is unstable. In this case, the two layers have a tendency to mix, with the cooler 

air descending and the warmer air rising. This vertical movement results in turbulence in the 

flow. When this type of unstable condition is present, the turbulent mixing of layers increases the 

available energy to the wind turbines by dissipating the wakes more rapidly and bringing more 

kinetic energy into the array. This is a complex condition of the atmosphere that is difficult to 

model and may not be fully represented by the current wind plant layout tools (including 

OpenWind). 

Figure 19 is a photo of the Horns Rev I offshore wind facility off the west coast of Denmark. The 

photo was taken on a day when fog was formed because of special atmospheric conditions 

resulting from a layer of cold humid air moving above a warmer sea surface (Hasager et al. 

2013). The vapor trails allow wind flow visualization throughout the array and illustrate the 

creation of wakes downstream of the turbines. The photo shows that the wind is coming from the 

lower left corner and blows down the rows of the array. As the wakes propagate downstream 

they expand, and mix with wakes from turbines deeper in the array. This leads to increased 

turbulence and lower wind speeds deeper in the array and reduces power output at turbines 

downstream. Horns Rev I uses a symmetrical gridded array with 7 D x 7 D turbine spacing and a 

turbine array density of 6.4 MW/km2

, compared to 5.0 MW/km2 for the 8 D x 8 D spacing, 3.3 

MW/km2 for the 8 D x 12 D spacing, and 2.6 MW/km2 for the 8 D x 15 D spacing analyzed in 

this report.
43 

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Figure 19. Horns Rev I wind farm

(Source: Vattenfall, Photo by Christian Steiness) 

5.5.2 Effect of Grid Orientation

Prevailing wind directions must be considered when orienting the turbines to minimize the wake 

effects. NREL researchers used OpenWind to determine the grid orientation that provided the 

lowest wake losses for each grid array spacing scenario considered. For a gridded array, the 

orientation is described in OpenWind by a bearing angle, or a grid orientation angle. The grid 

orientation angle uses the BOEM leasing area Outer Continental Shelf block grid as a reference 

frame, as illustrated in Figure 20. 
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Figure 20. OpenWind uses the BOEM leasing grid as a reference frame for the grid orientation 

angle of the turbine array. The example shown is for 8 D x 8 D spacing with a 75-degree grid angle. 

The MA WEA grid angles were found to be 60 degrees for minimum wake losses. 

(Source: NREL)

NREL performed the analysis in OpenWind using the wind rose shown in Figure 8 to rotate the 

grid orientation at 5-degree increments to find the angle relative to the leasing grid and the 

prevailing wind with the lowest wake losses. The results revealed that the modeled wake losses, 

based on capacity factor, varied by only 0.1% over the full range of grid rotation under a full 

build scenario. This variation indicated that, for the 8 D x 12 D grid array spacing, the grid 

orientation angle was relatively unimportant in determining the total plant losses.

The grid orientation angle that yielded the lowest wake losses was found to be at 60 degrees for 

the 8 D x 12 D spacing in the MA WEA. This orientation is rotated 15 degrees clockwise from 

45-degree diagonals of the leasing area delineation boundaries.

5.5.3 Wake Loss Summary

Measurements of annual average wake losses at some offshore wind power plants in European 

waters have been in the range of 10% to 20% (Barthelmie 2013; Hansen et al. 2012) based on 

available wake measurement data. As part of the MA WEA wake analysis, NREL researchers 

examined the array efficiency (100% ideal efficiency – % wake losses) for the three delineation 

alternatives in Figure 4. A summary of the analysis results is given in Table 12. 
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Table 12. MA WEA Array Efficiency Analysis for Three Leasing Area Alternatives and Three 

Turbine Grid Spacing Geometries 

(Source: NREL)

Array Efficiency (%)

Full Development Alternative 1 Alternative 2 Alternative 3

8 D x 8 D 88.6 88.7 89.0

8 D x 12 D 90.9 91.1 91.2

8 D x 15 D 92.0 92.2 92.3

Phased Development Phase 1

500 MW

Phase 2 

1,000 

Phase 1

500 MW

Phase 2 

1,000 

Phase1 

500 MW

Phase 2 

1,000 

8 D x 8 D 94.0 93.0 93.3 92.3 94.0 92.9

8 D x 12 D 94.7 93.7 94.1 93.2 94.7 93.3

8 D x 15 D 95.0 94.0 94.6 92.3 95.0 93.8

The array efficiency values that are presented in Table 12 give a measure of how well the array is 

performing as a whole, compared to how it would be expected to perform if each turbine were 

operating with perfect exposure to the freestream wind with no obstructions from other wind 

turbines. As expected, the efficiencies for the three full development scenarios are the lowest, 

because the turbine array density and array power density1 is larger (e.g., more turbines per 

square kilometer). For the phased development cases, the array power densities are essentially 

held constant because each area builds either 500 MW or 1,000 MW and only the spacing 

(turbine array density) is varied. Because the size of the leasing area is held constant, the phased 

development analysis is essentially examining the tradeoff between turbine spacing and intraarray buffer zones; as the spacing increases, the size of the buffers gets smaller. The result is that 

the impact of array spacing on total losses is tempered. In a remote array, one might expect a 

trend where wider spacing results in lower losses or conversely greater array efficiencies; 

however, this trend is not as evident in the presence of multiple wind plants. This result suggests 

that the benefits of additional spacing may have diminishing returns when multiple large arrays 

are sited near each other.

Most developers (especially when responding to the RFI and Call) did not consider that their 

project would be next to another project and could experience diminished capacity as a result of 

 

1 Array power density is defined here as the total area in kilometers squared (km2

) of the leasing area divided by the 

nameplate capacity in megawatts. Turbine array density is determined only by the spacing between turbines. 
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wakes from those adjacent projects. Therefore, in the context of competitive multiproject 

development, offshore wind developers should consider the balance between array spacing and 

additional buffer zones (especially when siting within multileasing area WEAs such as 

Massachusetts) to be a zero-sum tradeoff between turbines array spacing and the area between 

arrays (buffer zones). 

For the MA WEA under 1 and 2 phase development, the difference in overall array efficiency 

were relatively close, within 1% of each other. The data in Table 12 verify that the overall 

variation in array efficiency with turbine spacing is small. As such, other factors like cable length 

and water depth might play a larger role in the overall economics. However, the authors caution 

that the absolute quantities predicted by OpenWind should be reassessed with higher definition 

tools and more rigorous analysis. 

5.5.4 Wake Losses for Full Development

Array efficiency was estimated using OpenWind to range from 88.6% with 8 D x 8 D spacing to 

92% for 8 D x 15 D (see Table 9) for the full development scenarios of Alternative 1. For 

Alternative 2, the range was from 88.7% to 92.2%, and for Alternative 3, the range was from 

89% to 92.3%. These efficiencies are higher than what has been seen in Europe, but at an 

expected range considering that the spacing in this analysis is generally wider than most 

operating European projects currently providing field data. 

Figure 21 shows the individual turbine placement in the full development layouts for 

Alternatives 2 and 3, and the five leasing area alternatives using 8 D x 12 D turbine spacing. 

(Alternative 1 is not shown). Color coding indicates the efficiency of each turbine while 

operating in the array, with each turbine represented by a single dot. The colors indicate the 

magnitude in which the turbine is under-performing in the array as compared to how it would 

perform in an unobstructed freestream wind. Note how the strong degradation in the wind project 

interior dominates the chart for delineation scenarios, with the largest degradation occurring in 

leasing area 3, which has the poorest exposure to freestream prevailing wind because of the 

presence of adjacent leasing areas on both sides. Although losses for each leasing area were still 

less than 10% for all areas under full development with 8 D x 12 D spacing, individual turbines 

in the deep array are experiencing much higher losses. For large arrays, wake losses appear to be 

driven mostly by deep array effects and are largely independent of the grid orientation. 

Researchers also investigated the variability in the leasing area array efficiencies between 

Alternative 2 and Alternative 3. One concern was that Alternative 3 could potentially introduce 

wake losses in leasing areas 1, 2, and 3 as a result of upwind turbines in leasing area 5. For the 8 

D x 12 D full development scenario, the computed wake losses for Alternative 2 were 7.9%, 

9.4%, and 9.9% for leasing areas 1, 2, and 3, respectively. For the same scenario, the computed 

wake losses for Alternative 3 were 8.5%, 9.6%, and 10.0% for leasing areas 1, 2, and 3, 

respectively. These differences do not suggest a strong effect from the upwind leasing area on 

the downwind projects as might be expected. Although the Alternative 3 delineation would 

diminish the output of leasing areas 1, 2, and 3 after development in leasing area 5 occurs, this 

potential wake impact is probably mitigated by other effects. One effect is that in Alternative 3, 

leasing areas 1, 2, and 3 are wider and shorter than in Alternative 2. Therefore, the arrays are less 

deep in the prevailing wind direction, leading to lower inter-array losses that tend to offset the 

additional external array losses.
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Figure 21. Comparison of OpenWind array efficiency results for the two five leasing area

delineation alternatives of the MA WEA using 8 D x 12 D turbine spacing under a full development

scenario 

(Source: NREL)

Although the characteristics of the individual leasing areas vary in terms of the array efficiencies, 

all of the delineation scenarios appear to be approximately equivalent for overall wake losses. 

Using the 8 D x 12 D spacing scenario, the computed array efficiencies of Alternative 1, 2, and 3 

are 90.9%, 91.1%, and 91.2%, respectively. This is not significant relative to the other 

uncertainties associated with the analysis. However, as mentioned earlier, full development 

scenarios are not the best way to judge overall wake effects because these development scenarios 

are unlikely.
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5.5.5 Wake Losses for Phased Development

For the phased development, NREL analyzed a scenario where ten 500-MW wind projects were 

built over a 16-year time frame in two time phases by five independent developers. This was a 

hypothetical case that addresses the reality of how projects are actually planned and executed in 

discrete units. As mentioned earlier, 500 MW was chosen to represent a typical unit capacity for 

what developers are expected to deploy on a large scale in the future for a single phase under 

multiyear, multiphase development scenarios. The 500-MW scale is also used as the standard 

reference for DOE offshore wind project cost modeling (Tegen 2012) and is considered a scale 

in which offshore wind cost economies of scale could be reached (Maples 2012). 

For simplicity, there are two development time phases, with the assumption that the shallowest

water sites would be developed first, and the deeper water would be developed at a later phase

with a 50-D buffer between projects. Based on the industry depth trend data shown in Figure 6 

(Section 4) and the RFI and Call responses (Table 1 and Table 2 showing 8−16 year 

development time frames), the development time frame for phase 1 projects (water depths less 

than 50 m) was assumed to be 6−8 years. Similarly, the phase 2 development time frame was 

assumed to be 10−16 years.

Figure 22 and Figure 23 show the array layouts for the ten 500-MW projects after phase 1 and 2

development has occurred for Alternative 2 and 3 delineation layouts. Figure 22 shows the 

layouts for Alternative 2, the five leasing area diagonal delineation option, and Figure 23 shows 

the layouts for Alternative 3, the five leasing area configuration with four areas in shallower 

water and one in all deep water. For both configurations, 8 D x 8 D, 8 D x 12 D, and 8 D x 15 D 

spacing scenarios are used. Phase 1 development was assumed to deploy the turbines in the 

shallowest sites available until 100 turbines (500 MW) were installed. Phase 2 developments 

followed phase 1 starting in the next shallowest sites after a 50-D buffer was implemented.

In Figure 22, there are five projects in both phases; however, in Figure 23, leasing area 5 is in 

deep water and was assumed to be installed in the phase 2 time frame. Therefore, only phase 1 

included four projects under the Alternative 3 delineation scenario. Also, the 50-D setback was 

not observed between the leasing area 5 projects and the projects downwind in leasing areas 1, 2, 

and 3, because developers do not have control over neighboring wind plants. Only the 8-D 

spacing setback was observed in these cases. 
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Figure 22. Alternative 2 delineation layouts for phase 1 and phase 2 development building two 

500-MW projects per leasing area. Projects are shown with 8 D x 8 D, 8 D x 12 D, and 8 D x 15 D 

spacing.

(Source: NREL)
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Figure 23. Alternative 3 delineation layouts for phase 1 and phase 2 development building two 

500-MW projects per leasing area. Projects are shown with 8 D x 8 D, 8 D x 12 D, and 8 D x 15 D 

spacing.

(Source: NREL)
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Figure 24 and Figure 25 are plots of the array efficiencies on a turbine-by-turbine basis for 

Alternative 2 and 3 delineations under the phased development analysis, respectively. The plots 

compare the array efficiencies for the three spacing scenarios: 8 D x 8 D, 8 D x 12 D, and 8 D x 

15 D. The progression of plots shows how the array efficiencies improve as the spacing increases 

from 8 D x 8 D to 8 D x 15 D.

A B C

Figure 24. MA WEA for Alternative 2 leasing area delineation showing the effect of turbine spacing 

and buffers on array efficiencies with two 500-MW projects in each leasing area: (A) 8 D x 8 D 

spacing; (B) 8 D x 12 D spacing; and (C) 8 D x 15 D spacing 

(Source: NREL)

A B C 

Figure 25. MA WEA for Alternative 3 leasing area delineation showing the effect of turbine spacing 

and buffers on array efficiencies with two 500-MW projects in each leasing area: (A) 8 D x 8 D 

spacing; (B) 8 D x 12 D spacing; (C) 8 D x 15 D spacing 

(Source: NREL)

For the 8 D x 15 D spacing, the 50-D buffer that was imposed earlier could not be maintained in 

some cases because the turbines consume the buffer area with extra wide spacing.

Generally, turbine array spacing is increased for the primary purpose of reducing wake losses 

within a given array, and the biggest tradeoff of this is often between lost energy and added cable 

cost. However, as the array spacing is increased, a significant tradeoff also appears between 

wake losses and water depth. The increased space between the turbines means that more area is 

needed to build a 500-MW plant. The analysis of the MA WEA shows that wider spacing 

requires that the arrays be built in deeper water. So in addition to longer cables, there may be 
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additional construction cost because of the water depth associated with wider spacing. For the 8 

D x 8 D spacing, the maximum depth range of phase 1 was 44 m−47 m for Alternative 2 and 

42.0 m−45.0 m for Alternative 3. By comparison for the 8 D x 15 D spacing, the maximum depth 

ranges were 48.0 m−50.0 m for Alternative 2 and 46 m−48.0 m for Alternative 3, an increase of 

3 m to 4 m. Note that phase 1 of Alternative 1 would have the same characteristics as Alternative 

3 because the delineation boundaries are identical except for the carve-out of leasing area 5 in 

Alternative 3. When the comparison was made between the 8 D x 8 D and 8 D x 15 D array 

spacing options for the two-phase development the ranges increased. For the 8 D x 8 D spacing, 

the maximum depth range was 51 m−55 m for Alternative 2 and 50 m−51.0 m for Alternative 3. 

By comparison for the 8 D x 15 D spacing, the maximum depth ranges were 55.0 m−62.0 m for 

Alternative 2 and 53 m−62.2 m for Alternative 3, an increase of up to 10 m in some 

leasing areas.

In addition, installing turbines into deeper water in the MA WEA means that the turbines are 

farther from shore. Therefore, as array spacing increases, the average turbine’s distance-to-shore 

also increases. This is likely to have implication for operations and service, as well as the cost of 

the export cable. As a result, for a unit 500-MW project in the MA WEA, the cost to add extra 

cable length and perform construction and service at greater water depths and distances from 

shore should be weighed against the increased energy capture of lower wake losses caused by

higher array spacing. 

5.5.6 Effect of Turbulence Intensity on Wake Losses

Studies have shown that the turbulence intensity of the wind flow can have a significant effect on 

the wake losses in offshore wind power plants (Barthelmie et al. 2013; Hansen et al. 2012). 

Measurements of power production and wakes in European offshore wind power plants have 

verified that wake losses are typically greatest for low turbulence intensity wind flow conditions 

and lowest for high turbulence intensity wind flow conditions. In the Baltic Sea offshore areas, 

where high-quality tall-tower measurement data have been analyzed, the annual average 

turbulence intensity at turbine heights is typically less than 6% and decreases with height 

(Hansen et al. 2012). Furthermore, turbulence intensities have been shown to be lowest at wind 

speeds between 8 and 12 m/s. This implies that for wind speeds in the frequently occurring range 

of 8−12 m/s, in which wake losses are relatively high, low turbulence intensity can potentially 

delay dissipation of turbine wakes and further increase wake losses.

Although turbulence intensity and how it might affect wake losses and wake dissipation under 

varying atmospheric conditions may be critical in modeling wind turbine array efficiency and 

structural loading in the deep array, no high-quality wind measurements on turbulence intensities 

and atmospheric stability were available for the MA WEA study. Therefore, the lack of good, 

site-specific metocean data and a high-fidelity model to properly represent the physical effects of 

turbulence and atmospheric stability remains a potentially significant source of error and 

uncertainty in the OpenWind analyses and this study. 

Some 60-m data measured offshore in the U.S. Atlantic northeast region indicates that the annual 

average turbulence intensity is approximately 6%, with turbulence intensities from the southwest 

directions averaging between 4.5% and 6%. Moreover, as observed at the European sites, the 

lowest turbulence intensities are found at wind speeds between 8 and 12 m/s. Turbulence 
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intensities typically decrease with height, and are expected to be slightly lower at the 90-m hub 

height than those measured at 60 m. 

For this study, NREL conducted a preliminary analysis of the sensitivity of the OpenWind model 

simulations of wake losses for a large array of 8 D x 8 D spacing to different turbulence intensity 

values of 5%, 10%, and 15%. This analysis did not show any significant differences caused by

turbulence intensity. However, the large array and resultant deep array effects on the wake losses 

may have overwhelmed any effects caused by freestream turbulence intensity in the simulations. 

Further simulations using smaller arrays and more open spacing should be evaluated using 

different turbulence intensities to examine if the results are similar or not to the preliminary 

findings. In the absence of data for this region and generally low model sensitivity to turbulence 

intensity, NREL assumed an average turbulence intensity of 10% for the model simulations of 

the wake losses and energy production. 
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6 Qualitative Considerations

There are several other criteria that could influence the leasing area value and the ability to 

develop the MA WEA, but most of these criteria, such as fisheries, military use, ecological 

impacts, and traffic were not considered as part of this study by NREL and did not influence the 

delineation strategy.

Sites with longer distances to shore will likely add project development cost because of the extra

export cable length needed and longer transport times to and from the turbines for construction 

and service. An analysis of this factor would require a specific definition of where the land-based 

grid connections are made or specifics on ports and harbor staging areas but are not covered in 

this report extensively. 

Technology challenges and development cost as the result of deeper water are covered in various 

sections in this report and conclude that deeper water will add costs to project development; 

however, cost increases may be non-linear with depth because technology challenges often occur 

in steps as vessel specifications are often exceeded at specific depth increments. 

Finally, development timing is covered in Section 2, under the phased development scenario in 

Section 5, and in Figure 6. Generally, the deeper water technology will slow the shallower water 

development, but researchers remain optimistic because technology is constantly advancing (see 

Figure 6). 
55 

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7 Key Findings

Below are the key findings of the NREL analysis for the assessment of the MA WEA and

provide considerations for BOEM, policy makers, and stakeholders involved in the 

Massachusetts offshore wind energy development process. 

• Massachusetts is the largest BOEM WEA under consideration at this time (3,006.7 km2) and 

can feasibly accommodate at least ten 500-MW wind projects (5,000 MW) under a phased 

development scenario using up to five leasing areas.

• The biggest challenge for offshore wind developers in the MA WEA will be water depths 

that range between 35 m and 65 m.

• The MA Wind Energy Area can be delineated into four to five leasing areas with equitable 

divisions of shallower water (less than 50 m), wind resource potential, and exposure to 

unobstructed freestream prevailing wind (Alternative 3 is an exception, with leasing area 5 

presenting a potential upwind obstruction). 

• The leasing areas in the western part of the MA WEA may have a greater advantage if export 

cable interconnection points off Cape Cod and the islands are favored. It may be prudent for 

state or federal regulators to consider options for coordinating cable routing strategies and 

possible easements among the leasing areas. Within the MA WEA, interconnect access could 

be a strong driver in appraising leasing area value.

• The maximum nameplate development capacity for Alternatives 2 and 3, the five leasing area 

options, ranged from 1,220 MW to 2,295 MW. For Alternative 1, the four leasing area 

option, the maximum nameplate development potential ranged from 1,695 MW to 2,955 

MW. This represents a large overall disparity in total area per lease area even though the 

shallower water (less than 50 m) is balanced to within 5% for each alternative.

• Diagonal delineations, which are 45 degrees to the BOEM leasing grid, appear to be the most 

efficient delineation strategy to create equitable divisions of water by depth, and to minimize 

inter-array conflicts caused by wake effects.

• Average annual wind speed for the MA WEA ranged from 9.2 m/s to 9.4 m/s, with the 

highest wind speeds in eastern areas and lowest wind speeds in western areas. For each 

alternative, this corresponds to a typical range of capacity factors between 45% and 47% 

across the WEA after wake losses are subtracted using the 8 D x 12 D spacing for a full 

development scenario.

• Total wake losses from projects developed at the 8 D x 12 D spacing in all leasing areas of 

the MA WEA were computed to range between 6% and 8% when 1,000 MW (in two 500- 

MW phases) were installed in each leasing area. Wake losses in the MA WEA appeared to be 

lower than other areas studied in the mid-Atlantic because of higher average wind speeds and 

a distribution of more unidirectional prevailing winds (Musial et al. 2013b and Musial et al. 

2013c). 

• The grid orientation angle was found to have a negligible impact on array efficiency (<0.1%) 

using the OpenWind model with 8 D x 12 D spacing and 10% turbulence intensity. The best 

grid orientation angle was 60 degrees for the 8 D x 12 D array, but the true impacts of 
56 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 

at www.nrel.gov/publications.

variable turbulence intensity are not well captured in OpenWind. A more rigorous array 

analysis approach is recommended for developers in this area.

• Wake losses increased with decreasing turbine spacing, as expected. For the full development 

scenarios in each alternative, wake losses averaged 7.8% for the 8 D x 15 D spacing and 

11.2% for the 8 D x 8 D spacing. Most of this impact can be accounted for by lower array 

power density with the wider spacing. 

• Additional turbine spacing may have diminishing benefits when multiple large arrays are 

sited near each other. This reduction in the impact of spacing is because additional turbine 

spacing tends to reduce buffers that separate neighboring wind plants. 

• Additional development cost will be introduced with wider spacing because of longer cable 

length, greater water depths, and farther distances from shore. These costs should be 

carefully weighed against the added energy from higher array efficiency.
57 

This report is available at no cost from the 

National Renewable Energy Laboratory (NREL) 

at www.nrel.gov/publications.

8 Recommendations

NREL’s recommendations for the MA WEA are as follows.

• Of the three alternatives, NREL prefers Alternative 2 because it is believed the development 

potential of the WEA would be maximized while the effects of neighboring projects on 

adjacent wind plants would be minimized. With the five leasing area option, each area could 

support at least two 500-MW projects, and some could support three (depending on the 

spacing). 

• Any of the alternatives assessed in this report would be feasible and may be preferable to 

Alternative 2 for a given set of objectives.

• NREL recommends that BOEM consider methods to discount the deepest aliquots to address 

the probable time lag in development caused by the added cost and complexity of building 

turbines in deeper water. 

• The analysis in this report is coarse by industry standards, therefore it is recommended that 

prospective lessees conduct more rigorous analysis on wake losses before judging the values 

of these leasing areas. This enhanced analysis should consider diurnal, seasonal, and annual 

variations as well as a full cost assessment to examine the additional cost due to added cable 

length. In addition, NREL recommends conducting further analysis on wake losses with 

respect to atmospheric stability conditions.
58 

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National Renewable Energy Laboratory (NREL) 

at www.nrel.gov/publications.

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at www.nrel.gov/publications.

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