Methodology
Rating Wind Power Projects
october 2012
CONTACT INFORMATION
Eric Beauchemin, CFA
Managing Director
Co-Head Global Corporate
Tel. +1 416 597 7552
[email protected]
Kent Wideman, CFA
Chief Credit Officer
Tel. +1 416 597 7535
[email protected]
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Rating Wind Power Projects
October 2012
Rating Wind Power Projects
TABLE OF CONTENTS
Introduction to DBRS Methodologies
Overview
Introduction
Structure
Construction Period Risk
General
Contract Structure
TSA Contract and Turbines
EPC Contract and Contractor
Construction Period Contractor Credit Enhancement
IE Opinions for Construction Phase
Operating Period Risk
Overview
Fundamentals of the Wind Resource
Site Selection
Measurement Plan
Conversion of Wind Resource Forecast to Power Forecast
Technology Risk
Operation and Maintenance
Independent Engineer
Resource Consultant Report
Legal and Financial Structure
Legal and Regulatory
Power Purchase Agreement
Sponsor Risk
Financial Risk
Metrics
Key Debt Terms
Scenario and Breakeven Analysis
Appendix A – Technical Description of Wind Resource Measurement, Data Quality
and Forecasting
Wind Volume Measured Over Different Time Horizons
Wind Volume Adjusted for Topography, Wake Interference and Wind Shear
The Measurement Plan – Measurement, Anemometers, Quality Assurance, Verification
Measurement
Anemometers
Quality Assurance and Control
Validation and Audit Trail
Conclusion
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Introduction to DBRS Methodologies
DBRS methodologies are provided to assist issuers, investors and other market participants with additional insight into the rationale behind DBRS’s rating opinions in a transparent fashion. In addition to
general business and financial risk considerations, this methodology reviews a number of industry-specific
rating considerations and outlines key financial metrics used in the DBRS analysis of individual entities
within this sector.
In general terms, DBRS ratings are opinions that reflect the creditworthiness of an issuer, a security or
an obligation. They are opinions based on an analysis of historic trends and forward-looking measurements that assess an issuer’s ability and willingness to make timely payments on outstanding obligations
(whether principal, interest, dividend or distributions) with respect to the terms of an obligation.
DBRS rating methodologies include consideration of general business and financial risk factors applicable
to most industries in the corporate sector as well as industry-specific issues, regional nuances as well as
other more subjective factors and intangible considerations. Our approach is not based solely on statistical analysis but includes a combination of both quantitative and qualitative considerations.
The considerations outlined in DBRS methodologies are not intended to be exhaustive. In certain cases, a
major strength can compensate for a weakness and, conversely, there are cases where one weakness is so
critical that it overrides the fact that the company may be strong in most other areas.
DBRS rating methodologies are underpinned by a stable rating philosophy, which means that in order to
minimize rating changes due primarily to economic cycles, DBRS strives to factor the impact of a cyclical
economic environment into its ratings as applicable. Rating revisions do occur, however, when it is clear
that a structural change, either positive or negative, has transpired or appears likely to transpire in the
near future.
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Overview
INTRODUCTION
While an active rated bond market for wind projects has only begun to develop in the last several years,
the commercial application of wind power technology has become a more significant share of global
power supply in the last decade. This methodology outlines key factors for rating on-shore utility-scale
wind project bonds and covers both greenfield and operating wind assets. (A utility-scale wind project has
an installed capacity greater than 50 megawatts (MW).) In DBRS’s opinion, wind projects can potentially
achieve low investment grade credit ratings, if properly structured, and are likely to be limited to the BBB
range.
This global wind project methodology is based on consultation with market participants, market research,
as well as previous preliminary ratings assignments. This document should be considered within the
general framework of the DBRS methodology Rating Project Finance (April 2011) and provides productspecific guidance for an emerging bond market asset class.
Wind project risk has many elements in common with other energy project finance transactions but also
has unique aspects that are separately considered. The high total cost of wind power is an important
economic reality underlying the legal and financial framework. Wind generation is more competitive on a
total cost per kilowatt hour basis than solar power, but is still not at parity with most traditional sources
of electricity. The sector often benefits from some form of public-sector support in order to generate sufficient economic return to equity investors. Above-market tariffs have been one approach to the need for
policy support and subsidy. Some jurisdictions offer favourable tax treatment, including tax credits or
accelerated depreciation rates, in order to stimulate investment in wind assets. They may also have legislation requiring that a certain percentage of electricity generated must come from renewable assets, which
is also supportive of their development.
STRUCTURE
Wind projects, like most power project financings, are typically structured as special-purpose entities that
service debt solely from project cash flow and have no recourse to their equity sponsors. In a typical wind
power project, the project company (ProjectCo) enters into a power purchase agreement (PPA) to sell
electricity to the PPA counterparty. For greenfield projects, an engineering, procurement and construction (EPC) contractor typically assumes responsibility for non-turbine balance of project completion by
a certain date at a fixed price. A separate turbine supply agreement (TSA) commits a turbine vendor to
a schedule of deliveries, also at a fixed price. During operations, an operation and maintenance (O&M)
agreement engages a contractor (which may be an affiliate of the equity sponsor or a third-party provider)
to operate the asset until contract maturity.
A typical wind project is structured with certain limitations and protections including, inter alia: (1)
scope of business limited to operation of the project assets, (2) permitted indebtedness and distribution
tests, (3) comprehensive insurance to cover perils not within control of the project, (4) no recourse to
equity sponsors and (5) bankruptcy remoteness from equity sponsors. DBRS project ratings separate the
analysis into construction and operating phases, with the weaker of the two phases generally determining
the rating.
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Wind Project Structure
PPA
Counterparty
Electricity
Electricity Payments
PPA
Dividends
Sponsors
Debt Service
Lenders
Project Co
Financing
Equity
EPC Contract
O&M Agreement
Turbine Supply
Agreement
Equipment
Payments
O&M Payments
Construction Payments
EPC Contractor
Turbine
Supplier
O&M
Contractor
Note: EPC stands for engineering, procurement and construction.
In its analysis of wind projects, DBRS considers a wide range of factors, broadly grouped into the following categories: (1) construction period risks, (2) operating period risks and (3) the legal and financial
structure of the project. Wind projects are generally distinguished by the following core risk elements:
(1) low-to-moderate construction risk, (2) a variable wind resource and energy production forecasts
that have historically over-estimated output, (3) operating risk related to equipment performance, and
(4) contracted revenue, typically with investment grade counterparties. Of these, the impact of wind
volume projections and estimated turbine performance on the base case energy forecast are considered
the primary project risks.
Commercial applications for wind first developed in the mid-1970s but began to grow materially in the
early 1990s. Early projects often included much smaller turbines (100 kilowatts capacity) that were prone
to outages, undercapitalized vendors and problems with forecasting the wind resource. After several
generations of equipment development, turbines have become more reliable and rotors range in diameter
from 70 metres to 120 metres on towers that are 65 metres to 100 metres high at the hub with nameplate
capacities from 1 MW to 5 MW.1
However, forecasting wind resource and wind project power generation has been a significant obstacle
in the sector’s early development. U.S. wind projects commissioned prior to 2008 underperformed their
forecasts by 10% on average, owing primarily to wind resource variability, climate variability, plant availability and early operational issues.2 DBRS notes that forecasting performance has improved with greater
accuracy from better technologies and procedures for measurement including improved verification of
anomalous data values, estimating variations in wind at a particular height (wind shear), analyzing wake
interference, optimizing turbine configuration and accounting for known performance deficiencies during
the first-year start-up phase.
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1. DBRS research referred in detail to “Wind Resource Assessment: A Practical Guide to Developing a Wind Project” by
Michael C. Brower, et al., copyright 2012, John Wiley & Sons Ltd. and “Wind Energy Handbook” 2nd edition, Tony
Burton, Nick Jenkins, David Sharpe and Ervin Bossanyi, copyright 2011, John Wiley & Sons Ltd.
2. J. Deloney “Understanding U.S. Wind Fleet Underperformance,” North American Windpower, August 2008.
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A “backcasting” study by AWS Truepower LLC in 2012 estimates that wind project underperformance is
now 3.6% on average ± 1.4% statistical error3 and that two-thirds of the discrepancy (based on the AWS
project sample) is due to the variance of turbine production from their expected power curves and degradation of turbine blades. This suggests that wind resource forecasts and wind project power production
forecasts remain two significant sources of estimation error.
Global installed capacity at the end of 2011 was approximately 238 gigawatts (GW) with roughly 40.5
GW of new wind power added during that year, somewhat less than the average annual growth over the
last decade of approximately 28%. The incremental capacity in 2011 represented investment of more
than US$68 billion.4 China and India together accounted for just over 50% of global market growth in
2011. In the U.S., capacity increased by 6.8 GW on US$14 billion in new investment increasing cumulative capacity by 16% in 2011 to 47 GW.5
It is DBRS’s view that wind power projects, if properly structured, can potentially achieve investment grade
ratings. However, wind projects have historically been vulnerable to underperformance relative to base case
power production forecasts. This constrains the rating compared to the more mature hydroelectric and natural
gas-fired project types. Accordingly, at this stage in the development of a rated market for wind projects, DBRS
considers wind project ratings unlikely to exceed the BBB category. Investment grade project quality depends on:
(1) An experienced wind resource consultant and independent engineer with proven track records able to
credibly forecast wind resource volume and power production.
(2) A capable turbine supplier that is deemed investment grade or that benefits from structural enhancement to investment grade.
(3) Low-to-moderate construction risk substantially transferred to an experienced contractor.
(4) A robust PPA fully contracting project capacity with high credit quality counterparties.
(5) Moderate operating risk retained by an experienced sponsor or contracted to a qualified third party.
(6) An established and experienced equity sponsor.
(7) Fully-amortizing debt with financial metrics and financing structures that accommodate resource variability and are capable of withstanding downside scenarios.
Project elements most likely to reduce ratings below investment grade include, inter alia:
(1) An inexperienced wind resource consultant and/or independent engineer that has not met generally
accepted engineering standards in their wind resource and power production forecast.
(2) Non-investment grade or inexperienced counterparties, including sponsors, turbine suppliers and PPA
counterparties, where the financing lacks sufficient structural enhancement.
(3) Engineering, procurement and construction (EPC) contractors that have insufficient track record or
have weak financial or technical capability.
(4) Newer-generation turbines that may have limited track records or turbines with poor track records.
(5) Insufficient tariff and/or partial market risk in the PPA.
6) Insufficient coverage ratios unable to withstand wind variability, turbine underperformance and/or
other downside scenarios.
(7) Material flaws and/or omissions in financing or legal structure.
3. Statistical Error is a measure of uncertainty that decreases with increased sample size, also called standard error of the mean.
4. Global Wind Energy Council, “Global Wind Report: Annual Market Update 2011.”
5. U.S. Department of Energy, “2011 Wind Technologies Market Report”, August 2012.
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Construction Period Risk
GENERAL
The application of modern turbines in utility-scale wind projects is relatively recent, occurring over the
last few decades. Rapid growth in the mid-2000s led to supply shortages. As a result, some manufacturers
invested in new facilities or purchased major component suppliers, while others expanded and diversified
their supply chains.6 Since that time, rationalization of the market has led to consolidation of equipment
suppliers, although there are still new entrants to the market. The operating histories of turbine types currently deployed are approximately ten years long.
The construction of a utility-scale wind facility is less complex than for traditional project-financed power
assets, such as natural gas-fired power plants that have multiple, highly specified moving components
with more complex construction or hydro assets with complex design, excavation and civil construction
requirements. The construction task has more in common with other types of renewable projects, such
as solar, involving reasonably simple civil works and the assembly of components manufactured off site,
although DBRS does consider it to be somewhat more complex (than solar), given the scale of the turbines
and requirement for the precise assembly of moving parts.
Construction risk increases for more remote locations at greater distance from transmission infrastructure. Bottle-necks for turbine or balance of system equipment can be an issue in timely construction;
securing of “queue position” may seem administrative but it is material if turbine-generator deliveries
are delayed, and should be assessed by a project’s independent engineer (IE). The natural cure for queue
position delays is to negotiate the turbine supply agreement six to nine months in advance, secured by an
advance payment.
Wind projects have construction periods that are relatively short, at approximately one to two years
(depending on project size and case of access), versus three- to five-year construction periods for other
types of power assets. The shorter time requirement and low complexity of the work are key rating
considerations. However, a shorter construction period can also create greater pressure for timely replacement of a defaulted contractor or equipment manufacturer, although in general, the risk of cost over-run
and delays is considered low.
CONTRACT STRUCTURE
The construction of a wind project typically involves two key agreements: a TSA and an EPC contract.
The TSA is a fixed-price, date-certain undertaking from a turbine supplier to provide the turbines and
often the ancillary equipment to the site, with an associated warranty period. The TSA is typically 60%
to 70% of total project cost. The EPC contract generally involves construction of roads into the site,
civil work to provide concrete foundations, positioning of towers, installation of turbines, balance of
plant components and may also involve connection to the transmission grid. These contracts are usually
separate but occasionally the TSA wraps the balance of system contract. (It is very uncommon to see the
reverse where the EPC contract would wrap the TSA.) DBRS notes that the contract structure should
pass-down essentially all construction period risks to the TSA and EPC contractors. In some cases, interconnection risk may be retained by ProjectCo. Where this is the case, DBRS will assess the likelihood of
delays arising from the grid connection process and will also consider the findings of the IE’s review, but
notes that this could have a material impact on the rating.
Clear scope definition in each of the two contracts is required to reduce the potential for interface miscues
and commercial disputes between turbine supplier, EPC contractor and ProjectCo. DBRS notes that a
track record of on-time, on-budget completion by the same EPC and turbine supply team is positive for
6. European Wind Energy Association (EWEA), “Supply Chain: The Race to Meet Demand”, January/February 2008, 29, 30, 34.
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credit quality. A “gap” review by the IE to determine the adequacy of scope definitions between the two
suppliers reduces the risk of coordination errors and is considered a material analysis that is reviewed by
DBRS and is viewed as essential for investment grade projects.
TSA CONTRACT AND TURBINES
The procurement of turbines and their installation costs are the largest construction period expenses
and the reliable delivery of turbines is critical to on-budget, on-schedule completion of the project. Some
turbine suppliers have very long operating histories, including some with over 20 years of experience.
Globally, in 2011, Vestas was the market leader with 12.9%, followed by Goldwind (9.3%) and GE
(8.8%). In the U.S., the top three suppliers (GE, Siemens and Vestas) are estimated to account for approximately 76% of the market with GE and Vestas at approximately 29% each and Siemens at 18%. Other
suppliers to the U.S. market include Suzlon and Mitsubishi (both at 5%, respectively), Nordex and Clipper
at 4% each, RE Power at 3% and Gamesa at 2%. In addition, there have been increasing numbers of new
market entrants over the last decade, with those manufacturing more than 1 MW increasing from five in
2005 to 20 in 2011.7
Some of the larger turbine manufacturers are investment grade, whereas others, while they may be quite
capable, may exhibit non-investment grade creditworthiness. For non-investment grade manufacturers,
DBRS will pay particular attention to the length of the warranty period and the extent of warranty obligations (especially with newer turbines). Where the credit quality of a turbine supplier is below investment
grade, or its track record of timely delivery and turbine performance is weak, structural enhancements
may be required to support its delivery and warranty obligations, in order for a project to achieve an
investment grade rating
Warranties are typically offered for a two-year period and encompass defects in workmanship and installation. In projects involving a new generation of turbines, longer warranties are typically offered (and
expected by DBRS), given the higher likelihood of encountering unexpected problems or teething issues.
However, in such cases, turbine manufacturers are typically incentivized to quickly deal with any problems
to ensure a successful product launch. Initial teething issues are typically addressed within the first two
years. The IE’s scope should include assessment of higher risk from new models and DBRS may penalize
projects involving new technology with a short history.
EPC CONTRACT AND CONTRACTOR
The EPC contractor performs low complexity construction on a lower value contract than the turbine
supply and is given less weight than the turbine supply contractor in the construction phase rating. While
the balance of system tasks performed by the EPC contractor may be of lower total value, its technical and
financial capability to complete the work is important and requires a proven track record. In addition,
interconnection requirements can be a source of delay and DBRS will review required approvals and the
IE’s assessment. The EPC contractor’s ability to complete the project on-time and on-budget is assessed.
If the EPC contractor is not publicly rated, DBRS will conduct an internal assessment of its credit quality.
The rating may then be notched up for potential performance security.
CONSTRUCTION PERIOD CONTRACTOR CREDIT ENHANCEMENT
Credit and performance enhancements can be used to provide uplift to a construction phase rating. These
may include (1) letters of credit (LCs), (2) performance bonds, (3) warranties of performance after commissioning and (4) parent guarantees. LCs issued by an acceptable financial institution (typically rated A
(high) or better) can lift the construction phase rating. For example, LCs of 5% to 10% can lift the rating
by one to two notches, respectively. DBRS notes that LCs are the most direct form of support for the
contractor and supplier credit profile during the construction phase.
7. U.S. Department of Energy, “2011 Wind Technologies Market Report.” August 2012.
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In addition, an EPC contract generally provides for liquidated damages (LDs) in case of delay in the construction schedule (typically 20% of contract value) covered by parent company guarantees up to 100%
of contract value. LDs should cover potential costs of delay or performance shortfalls, including debt
service to bondholders and penalties owed by the project to the PPA counterparty.
Performance bonds commit a surety to complete construction if the contractor defaults on its EPC obligations. An LC is viewed by DBRS as superior to a performance bond, which relies on the surety’s process of
assessing claims and selecting among numerous options for addressing a default. DBRS typically considers third-party credit enhancements, such as performance bonds and LCs, superior to liquidated damages
obligations of a contractor, unless a contractor is highly rated or supported by an LC. However, DBRS
notes that LCs are not typically used in wind projects.
Third-party guarantees, insurance or equipment warranties may be positive for credit quality, but require
assessment of the entities underwriting the risk. These forms of support benefit the project rating only if
their credit quality is superior to the risks assumed under the related warranty or insurance instrument.
Parent guarantees for affiliate contractor entities are a customary requirement. To be viewed as effective by DBRS, the guarantee should be irrevocable and not require exhaustion of recourse against the
subsidiary. The liability cap for a parent company guarantee is typically up to 100% of the respective
contractor’s contract value.
Trapping mechanisms that withhold progress payments to a contractor until delays or overruns are
resolved may form part of the financing structure. Contractors can also be subject to a periodic IE certification for value of work performed and not allowed to front-run drawdowns. DBRS notes that trapping
mechanisms do not represent surplus funding for the project and so while such mechanisms can help to
focus a contractor on the timely performance of its obligations, no rating uplift is given.
IE OPINIONS FOR CONSTRUCTION PHASE
The IE report will typically opine on the following construction-related items:
• Construction period budget and schedule.
• Technical capability and track record of the turbine supplier and balance of system EPC contractor.
• Complexity of interconnection requirements and process as well as proven track record of management
and completion by the EPC contractor.
• A “gap” analysis between the TSA and EPC to confirm that scope definitions are unambiguous and
minimize the risk of construction delays due to coordination error and potential commercial dispute.
• An analysis of overall project design including siting and turbine configuration.
• Review of power loss components: turbine down-time and underperformance, balance of system
problems and electrical system, turbulence, mechanical wear including blade degradation, wake effects,
weather extremes and icing.
• If the project is launching a new turbine model, requirements of increased vendor support including
more warranty coverage is assessed.
• Review of financial model confirming accurate capture of contractual requirements, correct reflection of
wind resource consultant estimates and arithmetic accuracy. (An independent model audit is preferred.)
Where the IE report notes any material concerns, these will likely preclude the assignment of an investment grade rating to the project.
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Operating Period Risk
OVERVIEW
The primary risks for the operating period are the accuracy of the wind resource forecast and the performance of turbines in accordance with the advertised turbine power curve. Operation and maintenance
costs are typically between 15% and 20% of revenue, consist of low-to-moderate complexity monitoring, repair and equipment maintenance tasks and are considered by DBRS to be a relatively low
risk. Performance monitoring of operational wind farms is typically done remotely. Risks assumed under
the PPA and the credit quality of the PPA counterparty are typically investment grade but are carefully
assessed. Long-term PPAs with investment grade counterparties that fully contract the project’s capacity
under a defined price schedule (and inflation adjustment) are consistent with an investment grade rating.
To assess the wind resource and power production forecasts, DBRS analyzes site selection, the measurement plan (for collecting site data and correlating with relevant nearby historical datasets), conversion of
the wind resource data to a power production forecast adjustments for uncertainty and power loss, and
equipment types and reliability. These elements are typically included in the IE’s scope.
FUNDAMENTALS OF THE WIND RESOURCE
Wind turbines use the kinetic energy of the wind to generate electricity. Wind is created by atmospheric
pressure differences that cause air to move from zones of high pressure to zones of low pressure. Such
pressure differences are created by temperature differentials on the earth’s surface. As the surface of the
earth rises in temperature, the air mass above it rises and pressure falls. Wind results when air moves to fill
the zone of low pressure. Temperature differences between ground surface, the ocean surface and surfaces
at different elevations also cause pressure gradients. Topography and “surface roughness” matter to wind
volume and long flat expanses are conducive to wind speeds.
Wind speed is important in quantifying and characterizing the ability to convert wind energy into power.
Wind project development is typically undertaken at sites with a mean wind velocity of 6.5 metres per
second (m/s) (which is about 14.5 miles per hour or 23.4 kilometres per hour) or better. However, measurement of wind speed is not sufficient, by itself. The wind resource is also described by wind direction
and changes in wind velocity and direction, wind shear, as well as atmospheric density, at different times
in the day for different durations and at each turbine location in a wind project.
Wind resource data are analyzed in the followingstages:
• Project siting.
• Location of measurement towers or masts.
• Determining the number of anemometers (wind measurement instrument).
• Types of anemometer and their vertical locations on measurement masts.
• Data collection and monitoring.
• Validation and verification of anomalous data values.
• Extrapolation of actual measured data to hub height.
• Adjusting actual data against long-term historical datasets.
• Wind flow modelling.
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SITE SELECTION
The site selection process is crucial and often begins with consultation of a wind map that identifies the
average wind speed for a particular height at a given location. The preliminary site selection process
reviews site access, the permitting process and other local regulations to ensure that no material impediments may be introduced into the construction process or grid interconnections. The regional track
record and degree of local support for wind projects should be taken into consideration, including the
following key items:
(1) Permitting.
(2) Approval of individual tower locations.
(3) Requirement for separate agreements with landowners (typically, an agreement to lease the land
during the data collection, monitoring and development phase, including an option to lease the land
afterwards if the project proceeds).
(4) Land use and other environmental rules.
(5) Local rules that may require prohibitive distances from residences.
(6) Potential for multiple local jurisdictions that may complicate the licensing and approvals requirements.
Other considerations for site selection include geotechnical factors, market conditions and pricing,
distance from transportation and grid infrastructure and the relevant government policies and regulatory
framework. Once a potential site has been selected, wind data gathering begins.
MEASUREMENT PLAN8
A detailed measurement plan is a key success factor for correctly characterizing the wind resource and
is assessed by DBRS, the resource consultant and IE as a first step in analysis of the ProjectCo’s base
case power forecast. The critical data for measurement of wind resource are wind speed, direction and
temperature. The industry standard is the recording of an average wind speed, direction and temperature
at ten minute intervals based on one to two second samplings. A “data logger” records the data, timestamps it and includes interval minimum and maximum values and standard deviation. One to three years
of ten minute or hourly data is the typical measurement campaign. DBRS notes that a minimum of three
years is preferred.
Anemometers are key to measurement of wind speed and direction. While anemometer performance has
improved they can be a source of error. Manufacturers publish error estimates for each anemometer type
although the manufacturer’s published error estimate is generated in controlled conditions and may be
affected by non-typical operating environments. The scopes of engagement for the resource consultant
and independent engineer typically include assessment of measurement error, including anemometer error.
The measurement plan should have a quality assurance and control plan including an operation and
maintenance plan for each monitoring station, procedures for equipment calibration and audit trail. Data
recovery is the percentage of total available measurement time that data is captured and reported, and
during the measurement campaign should be >90%, minimizing extended data gaps. In addition, there
should be protocols for data “scrubbing” or validation, transmission from the logger, storage of measurement data, analysis and internal audits. Quality control should be designed to detect and eliminate
obvious data anomalies caused by logger, anemometer and data transmission failures.
8. A detailed, more technical description of wind measurement, data quality control and forecasting is included as Appendix A.
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The adjustment of site data against long-term historical data is a check on forecast accuracy. Inter-year
variability of wind resource is also reviewed. The length of the historical reference period and homogeneity and quality of data over that reference period is assessed. While there may be 50 years of wind data
from near-by sources, only the most recent ten or 15 years may be sufficiently uniform without discontinuities caused by changes in collection procedures. The actual measured site data are correlated with the
long-term dataset.
CONVERSION OF WIND RESOURCE FORECAST TO POWER FORECAST
Proven wind flow modelling techniques extrapolate wind measurement data to each proposed turbine
location. Error estimates introduced by wind flow modelling should be identified by the resource consultant. Approved software tests various turbine configurations to optimize power output. The software uses
numerical wind flow model results as an input and applies estimates of wake interference and shear. An
overall error estimate for the wind resource forecasting should be calculated. For example, anemometer
measurements have an estimated uncertainty, assuming good data quality, of 1.5% to 2.5%. With redundancy of measurement (two anemometers per mast), this falls to between 1.1% and 1.8%.9
The wind resource forecast forms the basis for the power production forecast. A starting point for estimating the power output of a wind farm is the manufacturer’s turbine power curve. The turbine power
curve is a function relating power output to wind speed. The shape and location of the curve is defined
by: (1) the starting speed (also called the cut-in speed), which is about 3 m/s to 4 m/s and is the speed that
first causes the turbine to turn; (2) an operating range, which is represented by a rising positive slope as
output rises with increased speeds; (3) a maximum output at a maximum rated speed (typically 13 m/s to
15 m/s) where the turbine reaches its rated capacity; and (4) a cut-out speed, where wind velocity is too
high to generate electricity.
TECHNOLOGY RISK
While wind turbine technology is relatively mature based on a number of model generations and increasing size and efficiency, with consolidation of market share by top manufacturers, it is expected to remain a
competitive sector with evolving technology. As such DBRS pays considerable attention to the technology
utilized including loss and availability assumptions, which. are based on the track record of the equipment and the supplier, the specific model type and expected performance of the maintenance program.
(Availability is the ratio of hours of normal turbine operation to hours of eligible operating wind conditions.) European system availability is estimated at 97%. North America system availability for new
projects is about the same, although it can be several percentage points lower for older wind projects.
DBRS notes that the IE’s opinion of the reasonableness of the maintenance program is particularly important in this regard. Insurance should be verified as consistent with market standards, reviewed by an
insurance consultant and evidenced by the provision of annual insurance certificates.
Turbine performance adjustments for field conditions can be between 2% and 3%, icing 0.5% and 1.0%,
and blade degradation between 0.5% and 1.0%. (These are annual levelized adjustments and not cumulative reductions in production that grow over time.) The resource consultant’s projection (reviewed by
the IE) estimates all sources of power loss as part of the overall forecast that forms a project base case.
As part of its assessment, DBRS reviews the reasonableness of loss assumptions as these can potentially
be a material source of error in the power production forecast. As such, projects already in operation
and with a meaningful period of production data (1 year) may be viewed somewhat more favourably by
DBRS as actual data may validate loss assumptions and reduce uncertainty estimates. Investment grade
projects are expected to utilize well-established technology with a track record of stable performance.
New technology would require a warranty significantly exceeding the standard two-year coverage and
even then would not likely support an investment grade rating.
9. Michael Brower, et al., p. 221.
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OPERATION AND MAINTENANCE
The O&M functions of a wind project are often performed by an affiliate of the equity sponsor but can
also be provided by a third-party operator. In each case, DBRS assesses the degree to which the O&M
contract incentivizes operator performance through rewards and penalties, although there is a fundamental alignment of operator interest with its parent equity sponsor in the case of an affiliate. In addition, this
affiliate approach, or owner-operator strategy, is a common practice for some of the most active market
participants with the largest portfolios of operating assets.
The owner-operator strategy benefits from centralized monitoring of wind project performance and economies of scale and expertise achieved by using the same operator entity for entire wind portfolios. Whether
or not the operator is an affiliate of the equity sponsor, DBRS will carefully assess the track record of the
operator and its financial and technical capability to perform and review the IE’s analysis of same. In certain
cases, turbine suppliers may provide long-term service contracts and these are viewed favourably by DBRS.
Mechanical systems generally degrade from ordinary wear and tear, require regular servicing, and have finite
lives ending in equipment replacement. Wind turbines have asset lives of up to 25 years and except for periodic
replacement of turbine blades and occasional replacement of other components, generally achieve stable performance of their respective power curves over the asset life. Operating period budgets typically include routine
maintenance costs, estimates for unplanned maintenance for overhaul or replacement of equipment. The
longer the particular equipment’s performance history the more observations the dataset is likely to contain.
Two periods are typically the most critical: the teething period at the beginning of the operating period and
the potential for equipment underperformance or failure near the end of the asset life. Maintenance reserves
based on look-back and look-forward tests increase confidence that performance will be optimized.
There are a number of sources of typical operating and routine maintenance costs, including the International
Energy Agency, the European Wind Energy Association and the National Renewable Energy Laboratory.
Estimated costs vary between US$10/MWh and US$15/MWh or approximately 10% to 20% of project
revenue, depending on installed capacity and the PPA tariff. As such, a project will generally show limited
sensitivity to moderate deviation in maintenance needs. Guidelines for major maintenance are prescribed by the manufacturer, checked by the IE and included in the base case budget. Turbine and balance
of system maintenance is not based on a schedule of checks triggered by specific total hours of operation, but
instead depends on anticipating and responding to underperformance or failure of equipment components.
INDEPENDENT ENGINEER
In addition to providing expert analysis and conclusions for project construction, the IE and resource consultant reports are important inputs to considering the risk for both construction and operating periods.
The IE and resource consultant usually generate separate reports and the IE may also review the wind
resource forecast and power production forecast of the resource consultant and its report. The IE report
should include the following key items in its scope of engagement:
• An audit of all material components of site wind data measurement and quality including:
– Number, location/altitude, calibration and mix of anemometers and sensors.
– Quality assurance program (or compliance with the program, if the project is not greenfield.
– Measurement system reliability (data recovery percentage).
– Security, storage and validation and verification of data.
• The production forecast should be revised after a year of operation as the project may now use actual
operating data instead of simulated figures. Greenfield projects may have higher forecast errors than
operating assets with several years of performance data.
• The O&M budget is reviewed for any location, capacity factor and equipment details that may affect
the O&M cost assumption.
• In addition to routine maintenance costs, the IE reviews proposed major maintenance and the frequency
and costs of overhaul and replacement.
• IE conclusions should include overall error estimates related to the forecast wind distribution and power production.
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Rating Wind Power Projects
October 2012
RESOURCE CONSULTANT REPORT
The resource consultant report should include the following key items in its scope of engagement:
• Confirmation of wind maps used in site selection and the quality of the methodology and data collection
for the wind maps.
• Assessment of data review for anomalies, turbulence and adjustments made for differences between
anemometer altitude and planned turbine altitudes.
• Audit of permanent record of key instrument settings, as well as logger instrument and converted data.
• Track record of vendors used in installation, maintenance, data validation and reporting.
• Comparison of site data years with long-term weather cycles, which are assessed to ensure that a sample
period is not occurring at a peak or a trough or a period that is otherwise anomalous.
• Analysis of correlation with nearby sites and broader regional data; if correlations are low, then longer
data samples may be required at the site.
• Review of accuracy of wake interference modelling, topography effects and adjustments to site data for
wind shear.
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Rating Wind Power Projects
October 2012
Legal and Financial Structure
LEGAL AND REGULATORY
Where debt service coverage ratios (DSCRs) are driven by above-market, feed-in-tariff PPAs there is a
theoretical risk of renegotiation of the PPA. In general, DBRS considers this to be a very low to minimal
risk. Renegotiation of PPAs in first world economies have few precedents. DBRS expects that any change
in government policy would be expected to grandfather high price PPAs due to implications of government-related counterparties repudiating contracts. Nonetheless, the government’s commitment to support
renewable forms of energy is reviewed. Preferred jurisdictions have policy frameworks granting priority
to wind transactions, such that they are not dispatched and can deliver power as it is generated. Other
forms of government support can include tax benefits, loan guarantees and renewable energy credits
or certificates. All permits, licenses and regulatory approvals should be in place prior to financial close
(except for those that can only be issued during construction or at completion of construction).
POWER PURCHASE AGREEMENT
An investment grade PPA counterparty with a contracted tariff schedule generating robust project DSCRs
is a significant rating strength. Where a PPA includes some component of exposure to market prices, sensitivity analysis will assess the ratings impact of merchant risk, although DBRS notes that even modest
merchant exposure is likely to cause a ratings impact given that electricity prices in PPAs are typically
well-above market. PPAs are assessed for the reasonableness of availability thresholds or minimum output
requirements, if any, and the term of the agreement should be six to 12 months greater than the project’s
debt maturity.
For a project with construction risk, the PPA should allow for a reasonable construction period delay
without immediately terminating. DBRS will consider the amount of time between the target completion/generation date and the point at which the PPA counterparty may terminate the PPA. If this period
is too short, ProjectCo may not be able to replace either a defaulting/non-performing EPC contractor,
turbine supplier or other subcontractors quickly enough to avoid a default. Wind projects that involve the
construction of new transmission may be exposed to risk of delays in interconnect approval and commissioning. Where new transmission is outside the project scope, the PPA should provide relief against grid
connection delays. A DBRS rating is provisional until approvals have been met and can only be finalized
once all required authorizations have been granted.
SPONSOR RISK
An established, reputable equity sponsor with previous experience as a wind project investor will bring
expertise to new projects and is more likely to closely monitor construction progress, provide guidance
to the project’s management and contribute a sense of urgency to early detection and timely resolution
of problems. Project credit is supported by a sponsor with a proven track record, a significant volume of
wind project completion and/or a portfolio of owned/managed wind assets and experience throughout
the wind power value chain (including turbine vendors, developers, financial equity and EPC market
participants). Sponsors that have worked closely with a number of suppliers and contractors and have
consistently completed wind projects on time and on budget will be viewed favourably.
A single controlling sponsor with a reputational or strategic stake in a project is also a rating strength
and is usually superior to multiple sponsor partners with limited and/or passive investment strategies.
Somewhat less satisfactory are investment grade companies with a track record in the power sector but
limited experience with wind asset development and ownership. DBRS expects a sponsor to be qualified
to manage the construction, operation and maintenance of a utility-scale wind project. When a sponsor
is not qualified or sufficiently experienced (particularly in the context of an owner-operator model) the
project may not be rateable. DBRS notes that the project’s rating does not incorporate any expectation of
sponsor financial support in excess of contractually obligated amounts.
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Rating Wind Power Projects
October 2012
FINANCIAL RISK
Wind projects are structured with many of the traditional project finance features. Analysis of financial
risk includes assessment of certain metrics, scenario and break-even analysis and key financial terms
based on a conservative approach to the early-stage wind project market. DBRS considers project metrics
and related scenario and break-even analysis in the context of all other critical rating factors. That is,
the overall profile of debt service coverage is a guide and does not, strictly by itself, determine a specific
rating.
METRICS
The primary metric for a BBB (low) rating is a minimum P90 DSCR of 1.35x for a greenfield project or
1.3x for an operating asset with one year’s operations and where the financial model has been validated
with a true-up process, adjusting the production forecast for actual instead of simulated performance.
These levels of coverage assume a 100% contracted single location project with no merchant risk.
DBRS confirms a base case using peer group data to support a most likely set of financial and operating
assumptions including resource volume, energy production and O&M costs.
The base case is used to evaluate the project’s minimum DSCR and ability to withstand downside scenarios. It is also used during the life of the project to assess actual performance versus the initial base case
forecast and the accuracy of critical assumptions.
Leverage is driven mainly by a specific jurisdiction’s revenue model, project cost structure and the desired
DSCR threshold. In markets with generous PPAs, equity contributions may be lower than in jurisdictions
that use tax incentives to provide more modest policy support. Where a project can achieve very low construction costs or for project bonds that fund acquisition of operating assets purchased at a low price, the
investment grade DSCR threshold may also be achieved with lower equity contributions.
In some cases, more highly levered transactions can achieve investment grade ratings, provided other
aspects of the project can compensate for the higher gearing including, but not limited to, a higher DSCR.
Where the project includes a construction period, equity should be contributed at financial close or be
backed by an LC issued by a financial institution acceptable to DBRS.
KEY DEBT TERMS
No Refinancing Risk:
Project debt is fully-amortizing with at least a six to 12 month tail (between debt maturity
and end of the PPA).
Debt Service Reserve:
Six to 12 months debt service reserve. The effect of additional debt service reserve may
make a ratings difference, depending on overall credit profile.
Cash Sweep Mechanisms:
In addition to increasing project flexibility, can be used to smooth the cash flow impact of
seasonal variation in the wind resource.
Distribution Test:
Permitted if DSCR ≥ 1.2x (historical and projected (P90)).
Additional Indebtedness:
Permitted if DSCR ≥ minimum base case DSCR (historical and projected (P90)).
Sculpting
Debt service payments can be sculpted to accommodate seasonal variation.
Cash Flow Waterfall:
Should be administered by a trustee, subject to trust indenture.
Maintenance Reserve:
Equal to six to 12 months of O&M costs.
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Rating Wind Power Projects
October 2012
SCENARIO AND BREAKEVEN ANALYSIS
Sensitivity and break-even analysis should include reasonable downside estimates for the following:
• Variance in wind resource.
• Variance in turbine performance, propeller degradation and other sources of power loss.
• Construction and operating cost overrun.
• Inflation.
Wind Power Projects – Summary of Primary Rating Drivers
Rating Criteria
Strength
18
BBB
BB
Adequate
Weak
Construction Period Risk
• Investment
grade
experienced
turbine supplier and investment grade experienced contractor with fixed-price
contracts.
• Non-investment grade supplier and/or
contractor but with robust protections
against delays, cost overruns and performance defaults.
• Positive IE report conclusions for design, schedule, budget and debt service
coverage.
• Established, experienced independent engineer and an IE report that drives conclusions with accurate, relevant data and
well-reasoned analysis.
• The project site is at a reasonable distance
from the transmission infrastructure
• Non-investment grade supplier or contractor with insufficient enhancements or
without fixed-price contract.
• Non-supportive or qualified IE report conclusions for design, schedule, budget and
debt service coverage.
• IE may be less experienced, or IE report
fails to support conclusions with accurate,
relevant data and well-reasoned analysis.
• The project site is located in a remote area
of significant distance from the transmission infrastructure.
Operating Period Risk
• Positive wind resource report and power
production conclusions confirming wind
energy volume estimates and projected
power generation.
• High-quality IE report with favourable
opinions for expected performance and
where IE has established track record.
• Conservative turbine performance assumptions with investment grade supplier and acceptable warranty or suitable
reserves, insurance or other credit
enhancements.
• Experienced
and
creditworthy
O&M
operator.
• Fixed-price O&M contract with detailed
performance criteria
• Positive IE report conclusions on budget estimates for routine and unplanned
maintenance and equipment/parts replacement costs.
• Established technology or new technology with sufficient warranty support from
supplier.
• Negative or qualified wind resource report conclusions confirming wind energy
volume estimates and projected power
generation.
• Inadequate IE report with qualified opinions for expected performance or where IE
has insufficiently established track record.
• Weak turbine performance assumptions
with non-investment grade supplier and
weak warranty.
• Inexperienced O&M operator.
• Cost plus contract with operator not
adequately aligned with ProjectCo and
bondholder interests.
• New technology with insufficient warranty
support from supplier.
Legal and Regulatory Risk
• Investment grade PPA counterparty.
• Strong PPA with all conditions met by
closing (e.g., government approvals,
permits and transmission access).
• PPA with reasonable performance criteria
and tariff schedule sufficient to generate
adequate DSCRs.
• A transparent legal environment with a
record of supportive regulation and minimal change-in-law or contract repudiation.
• Non-investment grade PPA counterparty.
• PPA may leave outstanding exposure
to incomplete compliance with regulatory, permitting and transmission access
requirements.
• PPA with onerous performance criteria and
aggressive tariff schedule, likely to lead to
weaker DSCRs.
• A less reliable or opaque legal jurisdiction
with precedent for imperfect access to due
process and recourse to fair court judgments, inadequate dispute resolution and
an inability of bondholders to enforce their
rights.
Rating Wind Power Projects
October 2012
Wind Power Projects – Summary of Primary Rating Drivers
Rating Criteria
Strength
BBB
BB
Adequate
Weak
Sponsor
• Experienced, creditworthy sponsor(s) with • Sponsor(s) with limited or no track record
proven track record.
in the type of projects being developed
• Demonstrated sponsor commitment in the and financed.
project with reasonable equity contribu- • Sponsor(s) with weak credit quality.
tion and support.
• Multiple sponsors for which the investment
• Single sponsor or consortium with a strong has limited strategic importance.
leading sponsor.
Country and Political Risk
• Countries with reasonably stable political, • Countries with one or more political risk
regulatory or economic environments.
factors that are difficult to gauge or
• In cases where potential issues exist, mitigate due to weakness in the legal
these risks are well mitigated.
framework or uncertainty in political, regulatory or economic environments.
Financial Risk
• Typically a minimum P90 DSCR ≥ 1.35x
for a greenfield project or ≥ 1.3x for an
operating project with one year of operating data, assuming all other project
elements are consistent with investment
grade
• Leverage is assessed on a case-by-case
basis and is driven mainly by a specific
jurisdiction’s revenue model, project cost
structure and project DSCR.
• A minimum debt service reserve of six
months to 12 months.
• PPA term at least six months to 12
months greater than debt maturity.
• A maintenance reserve equal to six
months to 12 months of O&M costs.
• Distribution test of DSCR (historical)
≥ 1.2x.
• Normal investment grade standards for
key term sheet items have been met.
• Typically a minimum P90 DSCR < 1.35x
for a greenfield project or < 1.3x for an
operating project with one year of operating data.
• Equity contributions that are too low to
achieve target DSCR.
• Minimum debt service reserve is less
than six months or does not form part of
the financing structure.
• Minimum maintenance reserve is less
than six months of O&M costs or does
not form part of the financing structure.
• No tail at end of PPA term, or PPA expires
prior to maturity of long-term debt.
• No maintenance reserve.
• Distribution test of DSCR (historical)
≤ 1.2x.
• Not all key term sheet items are acceptable to an investment grade standard.
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Rating Wind Power Projects
October 2012
Appendix A – Technical Description of Wind Resource
Measurement, Data Quality and Forecasting10
WIND VOLUME MEASURED OVER DIFFERENT TIME HORIZONS
Wind volume is characterized, in part, by measurements over a series of different timeframes. Turbulence
is a factor in analyzing the wind resource. Turbulence represents changes in wind speed and direction
that occur over seconds or minutes. Short bursts of wind speed cannot be captured by turbines as energy
and also cause mechanical wear. Warranties for some turbines are limited to below a specific turbulence
threshold. Measuring turbulence is critical to accurate estimates of the resource.
Other wind dimensions include changes in volume and direction that occur over longer periods of minutes
to hours. These are usable by turbines and cause changes in energy production. This is a focus of shortterm wind energy forecasting and affects the way transmission grids manage the intermittent nature of the
resource. Between 12-hour and 24-hour time periods there is daily variation in temperature that affects
wind volume. Depending on height above the surface, wind volume is highest in mid-afternoon or at
night.
Seasonal variations are also measured and modelled. In mid-latitude regions the highest volume is from
late fall to spring. The revenue impact of seasonal variation can also be affected by whether the relevant
regional power market has higher prices in the summer or the winter. Inter-year variability in average
wind volume is also modelled. Actual data measurements from a planned site are adjusted against a
measure of long-term average resource volume.
WIND VOLUME ADJUSTED FOR TOPOGRAPHY, WAKE INTERFERENCE
AND WIND SHEAR
Topography and the configuration of turbines relative to each other affect energy production from wind.
In the measurement process before construction begins, location of anemometers becomes particularly
critical for uneven terrain. Turbines are typically spaced 200 m to 800 m apart and large wind farms can
span 20 km to 30 km in each direction. Spacing is determined by modelling wake interference and shear
effects that vary with altitude.
Each turbine generates a wake, which is a zone of lower speed and higher turbulence immediately behind
it. A turbine located within the wake of another turbine will produce less power. Estimating this factor is
one of the areas in which wind resource assessment is considered to have advanced in relation to earlier
attempts to classify the resource. Specialized wake models are employed and a detailed topographical
map is used to configure a project.
Other factors included in forecasting are (1) air density, which varies with altitude and temperature and
determines the amount of energy produced at a given wind speed, and (2) other affects, e.g., icing of
turbine blades, soiling effects, wear rates of the turbine blades and other sources of loss.
THE MEASUREMENT PLAN – MEASUREMENT, ANEMOMETERS, QUALITY
ASSURANCE, VERIFICATION
A detailed measurement plan is a key success factor for correctly characterizing the wind resource and
generating accurate forecasts. The measurement plan should be carefully analyzed as a first step in analysis
of the ProjectCo’s base case power forecast.
10. DBRS research referred in detail to “Wind Resource Assessment: A Practical Guide to Developing a Wind Project” by
Michael C. Brower, et al., copyright 2012, John Wiley & Sons Ltd. and “Wind Energy Handbook” 2nd edition, Tony
Burton, Nick Jenkins, David Sharpe and Ervin Bossanyi, copyright 2011, John Wiley & Sons Ltd.
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Rating Wind Power Projects
October 2012
MEASUREMENT
The critical data for measurement of wind resource are wind speed, direction and temperature. The
industry standard is the recording of an average wind speed, direction and temperature at ten minute
intervals based on a one second to two second sampling. A data logger records the data, time-stamps it
and includes interval minimum and maximum values and standard deviation (a measure of turbulence,
which is not usable by turbines, as well as usable wind variability). Data loggers can transfer data on
an automated basis to permit remote monitoring, subject to a reliable telecommunications capability.
Remote monitoring allows more frequent data review than field visits and increases detection of equipment malfunction but is more expensive. Standard deviation data is used in data scrubbing and validation
to detect instrument error. Maximum and minimum data can be used to eliminate certain turbine models.
ANEMOMETERS
Equipment requirements and decision criteria (cost versus quality) are an important component of a measurement plan. For example, there are three types of anemometer: (1) cup instrument, (2) propeller (better
at recording lower speeds) instrument and (3) sonic sensors (better recording of swift changes in direction
and speed but more expensive). Cup instruments require a separate wind vane to measure direction and
must be mounted 1 m to 2 m below the speed sensor. Selection of the anemometer mix can include the
following considerations:
(1) Duration of measurement period — longer measurement periods may require replacement of an
mometers, particularly if significant portions are sonic instruments.
(2) Differences in durability — a long measurement period may require higher replacement costs of
certain anemometer types.
(3) Weather extremes — some instruments experience increased wear in cold and ice.
(4) Responsiveness to sudden changes in wind speed — cup instruments with lower responsiveness to
changes in wind speed can tend to overestimate average wind spend in turbulent conditions. Sonic anemometers are best in this regard.
(5) Unheated anemometers — are better than heated;.
(6) Adjustment for vertical wind — turbines can’t use vertical wind and in certain terrain wind has a
vertical component. Sonic and propeller instruments are best while certain cup anemometers can generate
data errors by capturing vertical wind speed.
(7) Sensor calibration — instruments where sensors can be periodically calibrated may be more accurate
than those that rely on a default calibration of a whole model type.
The IEC has standards for anemometers and there is a list of models that pass the standards. To reduce
errors caused by use of a single model type, multiple models can be installed on each monitoring tower.
Ambient air temperature sensors are often mounted 2 m to 3 m above ground, near hub height or at both
levels. (Air temperature determines air density, which determines wind volume and energy produced at a
given wind speed.)
Anemometers can be a source of measurement error, and error estimates are published by the manufacturer
for each instrument type. The error estimate is typically the standard deviation of errors observed for a large
sample size of that model. However, the manufacturer’s published error estimate is generated in controlled
conditions and may be affected by non-typical operating environments. In addition to reviewing the error
estimate for an entire wind project, the operating phase risk review should include measurement system
reliability, which refers to the ability to operate constantly without equipment failure and outage. Vendors
estimate this but the best data generally comes from developer surveys. Reliability also depends on correct
application of the user manual by the user so those factors are considered in the project analysis.
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Rating Wind Power Projects
October 2012
Ground-based remote sensing systems are often a component of collecting the required site data. SODAR
(Sonic Detection and Ranging) and LIDAR (Light Detection and Ranging) systems can measure the wind
resource to heights of 150 m or more. Employment of these methods becomes particularly necessary if
certain parts of a site are not feasible for towers. The sensors can be deployed and moved easily compared
to towers and can measure across the full rotor plane of current large sized turbines. These systems generally reduce uncertainty in estimating wind shear and direction shear (called “veer”), and provide more
data on turbulence.
QUALITY ASSURANCE AND CONTROL
The measurement plan should have a quality assurance (QA) plan including an operation and maintenance plan for each monitoring station, procedures for equipment calibration, frequency and audit trail,
as well as protocols for data validation, storage, analysis and internal audits. The quality assurance plan
should be approved by the project manager and its application and oversight during data collection and
monitor ing should be conducted by a dedicated QA officer. Quality control is the process of detecting
and eliminating obvious data anomalies caused by logger and sensor failures, and data transmission
failures. This is done regularly, and immediately after every data transfer from the logger to a remote
central computer.
Data recovery (the percentage of total available operating time that data is captured and reported) should
be >90% and there should be no extended data gaps during the site measurement period. This requires
the ability to quickly detect and resolve equipment outages requiring responsive monitoring to detect
problems, trained staff, spare parts, protocols and checklists for minimizing downtime. Frequent site
visits and regular review of data also minimize duration of outages and resulting data gaps.
Counterparty risks for suppliers of equipment and services during installation, maintenance, data validation and reporting of the measurement campaign should have been reviewed by the sponsors, wind
resource consultant and IE.
VALIDATION AND AUDIT TRAIL
Data validation goes further. It reviews data for gaps and inconsistencies and detection of any suspect or
obviously erroneous value. Data validation processes may miss bad values or reject good values and so
introduce their own error estimate in the vetting process. Data conversion is transfer of the logger’s raw
data to an analyzable format. Both forms of data (raw binary data of the logger instrument and the converted data) should be stored as an auditable permanent record. Cellular telephone service quality should
be confirmed for remote data transmission as errors in transmission can cause data gaps.
The audit of site data extends even to the confirmation of certain detailed equipment settings. This may
seem a minimal risk but material errors can occur at this step and review of data quality requires proof
that these setting errors were avoided. There are three key settings: (1) wind vane deadband (a blind spot
in the measurement field that eliminates the detection of certain wind direction data), (2) anemometer
transfer function requiring a permanent record of certificates of calibrations for each sensor or a so-called
consensus calibration and (3) time zone. Boom settings and orientation, sensor heights and magnetic declinations all have to be set accurately.
The first phase of data validation is done with automated algorithms to detect suspect data values (e.g.,
a series of increases in wind speed all sharply higher than data before and after). The algorithm is typically biased toward false positives, creating the need for a follow-on human review of each suspect value
detected by the automated algorithm to determine if it has been correctly identified. In the example above,
comparison with another sensor on the same mast may provide a way to check a material blip.
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Rating Wind Power Projects
October 2012
CONCLUSION
A robust measurement plan requires sufficient budget to ensure a high quality data set, minimum downtimes (e.g., data recovery > 90%), and careful, auditable oversight of defined collection and quality
assurance standards. A high standard for siting of data collection instruments, with anemometer redundancy (to achieve the data recovery target) and multiple height placements to improve the accuracy of
shear estimates, as well as advanced data control, validation and verification techniques are required.
Personnel should have sufficient training to implement the quality assurance protocols including previous
field measurement experience.
23
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