9 Wind Energy: Grid Integration Challenges
April 2009
Copyright © 2009 by ScottMadden, Inc. All rights reserved.
Wind Energy: Grid Integration Challenges
EXECUTIVE SUMMARY
As heightened renewable portfolio standards are mandated across the United States, wind
energy has moved to the forefront of the renewable power discussion. Wind is a clean source
of energy, and its lack of reliance on fossil fuels makes it even more attractive as the country
tries to reduce the impact of carbon-based fuels through renewable portfolio standards and
emerging federal carbon constraints. Wind has proven relatively inexpensive to operate and
maintain compared to conventional generation resources; however, there are integration costs
that must be taken into consideration when assessing it. At the end of 2008, the United States
had 25 GW of installed wind capacity, led by Texas and followed by Iowa.
Wind power is materially different than conventional generation resources. It cannot be
dispatched on demand, and it is nearly impossible to forecast with precision. Because of
these characteristics, wind power presents a number of challenges for system operators, and
additional reserves are typically required to maintain system adequacy.
We reviewed a number of studies performed over the past six years to analyze the impact of
wind power on reserve requirements and to calculate the associated costs, but there is
relatively little information on actual reserve increases due to wind. Two of the studies
reported specific findings—the addition of 1,500 MW and 3,300 MW of wind (15% and 10%
penetration, respectively) resulted in increased regulation requirements of 8 MW and 36 MW.
The remainder of the reports only noted that increases in regulation requirements were
“modest.” Because the forecasted increases in reserve capacity were minimal, there was
limited discussion of firming capacity with new combustion turbines (which, for reference,
have a projected capital cost of $670 per KW as of March 2009). Instead, discussions
centered around utilization of current resources—both spinning and non-spinning reserves—
to address the additional capacity needs.
For the studies surveyed, integration costs to incorporate wind power ranged from $0.45 to
$8.84 per MWh generated, with an average of $4.56. The integration costs consistently
comprised less than 10% of the wholesale value of wind energy, and those areas with higher
wind penetrations tended to have higher costs per MWh. In addition, new transmission
infrastructure will likely be required, and recent studies show a median estimate of $15 per
MWh for capital construction costs. Each of these estimates, in addition to the changes in
reserve requirements, rely heavily on a number of site-specific and operator-specific factors,
including wind plant location, correlation with load profiles, forecasting capabilities, and
conventional generation resources located within the balancing area.
While the published reports address a number of important issues, we feel there are key
components missing from the analyses. None of the studies were modeled on a capacity
constrained grid. The assumption was made that reserves will come from current grid
resources; however by the time wind generation is in place, those resources may not be
available, and peaking capacity may need to be built. In addition, systems for demand
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Wind Energy: Grid Integration Challenges
response and grid-stability control are not addressed. Each of these issues, omitted by the
studies, will likely raise integration costs above the published findings—perhaps significantly.
For more information on this and other efficient energy topics, please contact us:
Jere “Jake” Jacobi
Partner
3495 Piedmont Road, Building 10, Suite 805
Atlanta, GA 30305
404.814.0020
Michael Anckner
Managing Associate
3495 Piedmont Road, Building 10, Suite 805
Atlanta, GA 30305
404.814.0020
Raleigh Office
2626 Glenwood Avenue, Suite 480
Raleigh, NC 27608
919-781-4191
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Wind Energy: Grid Integration Challenges
INTRODUCTION
All electric systems must maintain a balance between the aggregate demand for power and
the total power fed into the system. This is a complicated task that requires detailed planning,
automatic controls, and experienced operators who have thorough knowledge of the operating
characteristics of power plants in the control area. Because power supply must match
demand at all times, and because there is a greater-than-zero probability of an interruption in
generation supply from conventional resources, sufficient reserves must be established and
maintained to ensure integrity of the system. These reserves consist of both spinning and
non-spinning generation, and along with reactive power and regulation, are known as the
ancillary services needed to support grid operation.
Wind generation is a factor of wind availability and speed, and, consequently, it must be
utilized “as delivered.” Because wind generation cannot be dispatched on demand, other
conventional resources must be used to fill the gap between available wind power and total
demand of the system. In addition, these same conventional resources must provide reserve
capacity and ancillary services, ensuring that supply meets demand at all times.
Unfortunately for grid operators, wind generation does not function in a similar fashion to
conventional generation resources. Wind exhibits both variability and uncertainty. The
variability of wind generation impacts all time horizons of power system operations—seconds,
minutes, hours, and days. In addition, wind (as well as solar generation) is not a load-following
resource. These two issues, combined with the fact that it is nearly impossible to precisely
forecast wind at any given point in time, create grid stability concerns for operators and the
need for operational flexibility.
One option to achieve this flexibility is to increase operating reserves for the system. Higher
reserves allow more flexibility for operators to maneuver should wind generation ramp up or
ramp down more quickly than previously forecast. An alternative view is that relatively small
additional operating reserves are required if the capacity value of wind plants is properly
discounted. In either case, increasing reserves creates additional costs. To address grid
frequency issues, one option is the addition of short-term energy storage devices such as
those based on flywheel technology. There are currently multiple pilots in Regional
Transmission Organizations (RTOs) (CALISO, PJM, and NYISO) for a flywheel technology
solution to improve grid frequency stability. The U.S. Department of Energy (DOE) is
reviewing a loan guarantee grant for Beacon Power to develop their flywheel technology for
the express purpose of grid stabilization. In contrast to reserve costs, the costs for short-term
energy storage devices are not included in any available wind penetration study to date.
Although existing wind penetration studies acknowledge that increasing amounts of wind
generation on the transmission grid create the need for additional capacity, the prevalent view
is that this capacity will be accessed from another resource on the grid. It is our opinion that
these alternative sources of capacity are becoming increasingly scarce and may not be
available in several years when there is a larger contingent of wind generators on the grid.
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Wind Energy: Grid Integration Challenges
The needed capacity is likely to come from new combustion turbines (CTs). These costs are
also not accounted for in any available wind penetration study.
As will be explored, studies that have tried to estimate the impact of wind penetration have not
been made for a capacity constrained grid. Despite the economic slowdown, the margin of
reserves in various NERC regions has declined and is projected to continue that descent,
especially as the current recessionary pressures begin to abate. As an example, published
NERC data indicates that by 2013, capacity in the Reliability First NERC region (RFC) will fall
below the NERC reference level and below the reference level including adjusted capacity
resources in 2017. For the Midwest Reliability Organization NERC region (MRO), the
comparable dates are 2010 and 2017. Other NERC regions are projected to experience
differing levels of decline for capacity reserves, but project reserve shortfalls are expected in
many areas.
Figure 1: RFC-MISO Summer Capacity Margin Comparison
Source: NERC 2008 Long-Term Reliability Assessment 2008-2017
We will use RFC as a reference point. In RFC, current wind penetration studies do not take
into account the role of planned demand response on grid capacity. There is no projected
increase in load-demand management in RFC from 2008 to 2017, but 6,000 MW of curtailable
load (mostly from large industrial customers) and 1,000 MW of direct control small devices
(water heaters, home appliances, etc.) are currently available in the region.
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Wind Energy: Grid Integration Challenges
INTEGRATION COSTS
A number of studies have shown that the variability and uncertainty of wind generation
increase operating costs for an electric system due primarily to the challenge created for
ancillary services. This increased burden is referred to as integration costs. As wind
penetration rates increase, so do the integration costs for the system.
To properly understand the impact of wind generation, three grid operating parameters must
be analyzed:
• Regulation: time horizon of one minute to one hour (1- to 5-second increments)
• Load following: time horizon of one hour to several hours (5- to 10-minute increments)
• Unit commitment: time horizon of several hours to one week (1-hour increments)
A number of studies have been completed over the last six years to assess the financial
impact of integrating wind generation into the grid and delineate that impact across these
operating parameters. The studies have documented a wide range of potential integration
costs with an average of $4.56 per MWh. Costs are higher in more recent studies, with those
from 2007 averaging $6.59 per MWh. The results can be seen in Figure 2 below.
Figure 2: Summary of Wind Power Integration Studies (Costs in $/MWh)
Wind
Capacity
Penetration
Regulation
Load
Following
Unit
Commitment
Gas Supply
Total
($/MWh)
Date
Study
2003
Xcel-UWIG
3.5%
$0
$0.41
$1.44
n/a
$1.85
2003
We Energies
29%
$1.02
$0.15
$1.75
n/a
$2.92
2004
Xcel-MNDOC
15%
$0.23
n/a
$4.37
n/a
$4.60
2005
PacifiCorp
20%
$0
1.60
$3.00
n/a
$4.60
2006
CA RPS*
4%
$0.45
Trace
Trace
n/a
$0.45
2006
Xcel-PSCo
15%
$0.20
n/a
$3.32
$1.45
$4.97
2006
31%
n/a
n/a
n/a
n/a
$4.41
2007
MN-MISO**
Puget Sound
Energy
10%
n/a
n/a
n/a
n/a
$5.50
2007
AZ Public Service
15%
$0.37
$2.65
$1.06
n/a
$4.08
2007
Avista***
30%
$1.44
$4.40
$3.00
n/a
$8.84
2007
Idaho Power
20%
n/a
n/a
n/a
n/a
$7.92
*Regulation costs represent three-year average
**Highest over three-year evaluation period
***Unit commitment includes cost of wind forecast error
Source: Berkeley Lab, based in part on data from NREL
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Wind Energy: Grid Integration Challenges
COST ESTIMATION METHODOLOGIES
Before discussing the results of the wind integration studies, it is important to understand how
the costs were calculated. The studies use a variety of methods to calculate integration costs.
For regulation, one such method is based on “opportunity cost.” This process computes the
opportunity cost of reserving incremental capacity that could otherwise be utilized in the
market:
• First, a number of statistical methodologies are employed to determine the increase in
reserves needed for each time horizon
• Second, the reserves are converted into potential MWh that could be generated in a
given year
• Third, potential MWh are multiplied by an appropriate profit margin to determine wouldbe profit (or total opportunity cost)
• Finally, the calculated profit is divided by a capacity-discounted estimate of annual wind
generation to determine the opportunity cost per MWh
For example, in the 2004 Xcel-MNDOC study, the incremental regulation cost of installing
1,500 MW of wind generation was calculated to be $0.23 per MWh using the following steps:
• Statistical models determined the necessary increase in regulation reserves to account
for wind variability was approximately 7.8 MW
• 7.8 MW was multiplied by 8,760 hours per year to determine potential generation of
68,328 MWh associated with the reserves
• 68,328 MWh was then multiplied by a profit margin of $15 per MWh to determine a total
opportunity cost of $1,024,920
• The total opportunity cost was then divided by total MWh for 1500 MW of wind
generation with a 35% capacity factor (~4.5 million MWh)
• The result is an incremental regulation cost of $0.23 per MWh
An alternative method is to base the calculation on capacity value. This technique yields
similar results to the opportunity cost example discussed above. As for unit commitment
costs, they are typically defined as a total of the incremental production, priced at hour-ahead
energy costs, divided by the total amount of wind energy delivered during the study period.
While each study varied slightly with the method employed for calculating integration costs,
the results were not materially different and are comparable for discussion purposes.
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Wind Energy: Grid Integration Challenges
KEY OBSERVATIONS FROM THE STUDIES
Each referenced integration study was performed for a specific utility or location, but there are
some consistent themes throughout the results. The key observations from the studies and a
brief discussion of each are noted below.
1. Integration costs increase as wind penetration rates increase
As more wind generation is introduced to an electric system, variability and uncertainty
increase on a system-wide basis. This creates the need for additional operational
flexibility in the form of increased reserves and leads to higher integration costs. Figure
3 compares integration costs per MWh to wind penetration rates from the 11 studies
listed in the table.
Figure 3: Wind Integration Cost per MWh vs. Penetration Rate
$10.00
$8.00
$6.00
$4.00
$2.00
$0.00
0%
5%
10%
15%
20%
25%
30%
35%
Though the studies show a wide range of results, integration costs trend upward as
penetration rates increase. It is important to note that both location and system
dynamics can play a large role in incremental costs.
2. Total integration costs comprise less than 10% of power costs on average
While integration costs can vary across regions due to a number of factors, this has
been a consistent finding from all the studies performed over the last 10 years with
wind penetrations of 20% or less.
3. The majority of integration costs are driven by the unit commitment time horizon
Conventional generation resources are scheduled by system operators to maximize
their efficiency and deliver the lowest cost of energy produced. When wind is
introduced into an electric system, the imprecision of its day-ahead forecasting can
create ramp-up situations where reserve power must be deployed to follow the load
and sub-optimal generation sources are used, thereby driving up costs.
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Wind Energy: Grid Integration Challenges
4. Regulation costs are relatively low
While wind-forecasting error can create the need for reserve power on a more
consistent basis, the increase in required reserves has been found to be relatively
modest across the studies. Costs can vary based on a number of factors, including the
correlation of wind generation with system load and the type of reserves employed. If
the majority of wind generation scheduled is during non-peak hours, it may not be
necessary to increase reserves if a fluctuation would be relatively inconsequential. As
for the type of reserves, the decision whether to use spinning or non-spinning with
quick-start capability has been shown to influence regulation costs more than 50%.
5. Integration costs vary considerably by both month and year
The studies show that actual wind performance can vary significantly from month to
month and year to year. The Xcel-MNDOC study tracks hourly integration costs for the
two years included in the analysis. The costs range from a high of $11.01 per MWh in a
high-load month of Year One to a low of $1.64 per MWh in low-load month of Year
Two. Variability seems reasonable, since months with higher loads mean more
expensive generation is being called upon more frequently. Years with relatively higher
rainfall can allow increased hydro generation to help fulfill reserve requirements,
reducing costs.
6. Total production costs decrease as wind penetration increases
Although integration costs for installing wind generation in an electric system must be
considered, the total power production cost decreases as wind displaces conventional
generation. Wind reduces the need for fossil fuels, and wind plants have considerably
lower operations and maintenance (nonfuel O&M) costs than fossil plants. These lower
production costs provide a direct benefit to consumers, though there are some
disadvantages. Specifically, conventional power producers may see a rise in costs due
to inefficient operation of committed units that results from sub-optimal scheduling.
OPPORTUNITIES TO REDUCE INTEGRATION COSTS
The variability and uncertainty of wind generation will always result in integration costs as
wind power is incorporated into the grid. Fluctuations in wind speed throughout the day and
imprecise forecasting create an additional burden for ancillary services above and beyond the
level required for conventional generation. Studies have shown, however, that there are a
number of measures that can be taken to reduce these costs.
One such measure is increasing the geographic diversity of wind plants. Spreading wind
plants across various locations in a state or balancing area and installing more turbines at
each site can provide substantial “smoothing” of wind generation variations as the wind and
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Wind Energy: Grid Integration Challenges
output at various locations will not be perfectly correlated. This geographic diversity creates
an aggregate wind generation supply that functions more like a stable source of power. Figure
4 was taken from the 2007 NBSO Wind Power Integration Study completed for the Maritimes
provinces in Canada. It clearly shows a decrease in the hourly swing of total wind generation
when eight locations are used instead of a single site.
Figure 4: Wind Generation at a Single Site vs. Geographically Dispersed Sites
Source: NBSO, ERNB: Maritime Area Wind Power Integration Study – Final Report
While the variability is reduced, it is important to note that benefits begin to taper off as
additional sites are added. Figure 5 plots the standard deviation and average swing
magnitude for the same study. There are considerable benefits to adding the first three to four
sites, but as additional locations are included, the slope of the line decreases significantly,
indicating diminishing returns.
Figure 5: Diminishing Returns of Adding Additional Sites
Source: NBSO, ERNB: Maritime Area Wind Power Integration Study – Final Report
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Wind Energy: Grid Integration Challenges
Another opportunity to lower integration costs is to consolidate the balancing areas in which
wind plants are located. High wind output variations and steep ramp-ups/ramp-downs in wind
generation may be challenging for smaller balancing areas to accommodate. Larger areas
with more diverse generation resources are likely to have additional options to accommodate
variability. The diversity of options allows operators greater flexibility to schedule the most
efficient resources for generation and reserve capacity, thereby lowering costs.
In a similar manner, improved forecasting and better integration with control room operations
can also reduce costs. Day-ahead forecasting for wind generation is typically based on a
combination of historical data and forecasted weather conditions. In many cases, the historical
data may not align with weather patterns for the particular day, leading to a substantial
difference between forecast and actual generation. To mitigate this, it is important to monitor
wind speeds throughout the day and update forecasts on an hour-ahead basis with as much
real-time information as possible. Incorporating such hour-ahead forecasts into system
operations will allow operators to track a ramp-up or ramp-down in wind power more
effectively and mobilize the most efficient resource to accommodate wind generation swings.
The ERCOT event of February 26, 2008 provides a vivid example of how system operations
could benefit from improved forecasting. In that instance, system operators were forced to
initiate an Emergency Electric Curtailment Plan (EECP) to address a worsening imbalance
between load and generation and the resulting decline in system frequency. There were three
major contributions to the crisis: 1) an unexpected loss of conventional generation, 2) a fasterthan-expected evening load ramp-up, and 3) a large ramp-down in wind generation. ERCOT
relied on a day-ahead forecasting model that used data from the current day to predict
upcoming load. On February 26, 2008, the previous day’s load profile forecast did not match
the current day’s available generation. A deciding factor in this was the difference between
forecast and actual wind and, therefore, wind generation output.
Most short-term wind forecasts use sophisticated mathematical models that take a number of
factors into account, relying heavily on past results. Because there is a delay in information,
forecasts may anticipate the correct shape of the wind profile, but the timing of that profile
may be shifted forward or backward in time. This was the case for ERCOT. To improve
forecasting and load management, real-time wind observations from a number of different
sites around the operating area should be incorporated into the control room. System
operators should monitor this data, compare it to earlier forecasts, and make necessary
adjustments. This practice would facilitate utilization of the most efficient reserves.
A final suggestion for lowering integration costs is to use purchased power as an alternative to
internal resources for reserve capacity. Though day-ahead and hour-ahead markets need to
be further developed in many areas of the country, the wholesale energy market could serve
as a balancing source for wind energy and has significant potential to reduce integration
costs. For example, in day-ahead planning, it would be possible to schedule hourly
transactions consistent with the forecast variability of wind generation. On a shorter-term
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Wind Energy: Grid Integration Challenges
basis, hour-ahead purchases from the wholesale market could provide increased flexibility
when dealing with forecast errors, displacing the use of more expensive internal generation
resources. While this option presents a good opportunity, it is only viable if wholesale power is
available for purchase; and some predictions indicate this may not be likely in particular
regions once significant wind generation is in place.
TRANSMISSION IMPACT
In addition to concerns about the impact on operations and overall production costs, one of
the main barriers to wind power is integration into the transmission grid. The best locations for
wind generation are typically in remote areas, and in many cases there is not adequate
transmission infrastructure in place to access the wind resources. To complicate matters,
interconnect queues around the United States have recently seen all-time highs for both
requests and backlogs. Although queuing processes are being streamlined by RTOs, the
underlying problem is a lack of adequate transmission resources, coupled with long lead times
to increase resources, even if queues and backlogs are reduced substantially. Currently, we
seek to add wind faster than we can add the necessary transmission. In 2008, the DOE
estimated that there is a backlog of almost 300 GW of wind projects waiting to connect to the
grid due to inadequate transmission capacity.
It is difficult to estimate the incremental transmission costs for an individual utility without
studying the specific sites proposed for wind plants. A recent report by Berkeley National
Laboratory estimated incremental transmission capital costs for a number of different areas of
the country, including a median estimate of $15 per MWh of wind energy for new transmission
build. The report concluded that incremental transmission costs do not necessarily increase
with higher levels of wind generation. This is because cost per MWh is most influenced by the
cost of long transmission lines to access new wind generation. Figure 6 shows the results of
this study. Capital costs of transmission are plotted on the bottom axis, and total wind
generation analyzed for each region is plotted on the top axis.
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Wind Energy: Grid Integration Challenges
Figure 6: Unit Cost of Transmission for Wind ($/MWh)
Source: Berkeley National Labs: The Cost of Transmission for Wind Energy: A Review of Transmission Planning Studies
Additionally, a number of studies have been completed for the United States. One recent
report, developed through a collaborative effort of RTOs, estimated we would need to
construct more than 15,000 miles of new transmission lines to accommodate 20% wind
energy by 2024 in the Eastern Interconnection alone. This would cost approximately $80
billion.
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Wind Energy: Grid Integration Challenges
BENEFITS AND COSTS OF INCORPORATING WIND ENERGY
Though there are significant costs and challenges to integrate wind energy, most studies
indicate that potential benefits far outweigh the costs. Integration costs due to the variability
and uncertainty of wind are more than offset by the decrease in overall production costs as
fossil generation is displaced, providing a direct benefit to consumers.
This displacement also creates diversification of the energy portfolio and helps protect
consumers from price volatility that can occur with fossil resources. Illustrating this price
volatility risk, the average Texas household saw its annual electric bill increase by more than
$750 from 1998 to 2006 as the price of natural gas tripled. In Texas, natural gas provides half
of the state’s electricity. Since wind requires no feedstock or fossil fuels, the price of its power
remains relatively constant over time and helps smooth such price spikes.
In addition to reducing overall costs, wind provides substantial environmental benefits.
Greenhouse gas emissions are reduced as a direct result of lower fossil generation. In a study
by the DOE, results show that achieving 20% wind penetration in the United States by 2030
would reduce electric sector CO2 emissions by 825 million tons annually. With the new
administration in Washington, DC and emerging federal carbon constraints (either through
EPA regulation or legislation), these lower emissions could provide substantial value to
producers.
Another environmental benefit is reduced water consumption. Water scarcity has become an
issue throughout the United States over the past several years due to persistent drought
conditions. Electric generation accounts for nearly 50% of all water withdrawals, and while
power producers recycle most of the water they withdraw, an average of 2% to 3% is lost
through evaporation. Even with this relatively minor amount, the DOE estimates that more
four trillion gallons of water could be saved (a cumulative 8% reduction) if the United States
achieves 20% wind penetration by 2030.
On the flip side, there is little documentation that captures the true cost of wind integration into
the transmission grid and wholesale generating markets.
CONCLUSION
Wind power presents a number of challenges for system operators. Its variability and
uncertainty create the need for more careful operation of an electric system, as well as the
requirement to hold additional reserves. Each of these requirements contributes to the overall
integration costs of wind power, which continue to increase as more recent studies are
completed. In 2007, the average wind integration cost per MWh rose to $6.59 from a six-year
average of $4.56, in addition to the capital cost of any required transmission. The amount of
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Wind Energy: Grid Integration Challenges
required reserves is difficult to estimate and is specific to a particular balancing area, though
in most cases the studies assumed that current generation resources could be used to
provide this capacity and no new facilities were needed. This report concludes that there has
not been an adequate representation of wind integration costs in a reserve constrained
environment.
In summary, the available studies on wind penetration allude to, but do not adequately
quantify, costs for significant wind penetration. Although it is recognized that wind is an
energy-only resource, the general conclusion regarding firming capacity is that capacity will be
available from existing resources interconnected to the grid. This is a dangerous assumption,
at best. We believe that the need for incremental reserve capacity must be taken into account.
Moreover, existing studies generally apply to small amounts of wind additions; they conclude
little need for only supplementary resources. For a significant amount of wind penetration in a
transmission-constrained zone, there should be a clearer picture outlined for incremental
resource and cost requirements. There is a step-function change in requirements when
transmission capacity is constrained, reserve margins are reduced, and wind additions are
significant.
Lastly, although this report indicates that the costs of wind integration have been largely
underestimated, there is no clear set of decision rules regarding who will pay for the
incremental costs. Cost allocation of transmission is currently the subject of a vigorous public
policy discussion. In the case of firming capacity, the costs will likely be borne by the entity
building the peaking gas capacity. In the case of short-term storage devices such as flywheel
technology used for frequency control, the cost may be borne by an RTO or a utility that
manages its own balancing authority and allocated to individual market participants or
customers, or be borne by a single utility or group of utilities.
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Integration Challenges of Wind Energy
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Design and Operation of Power Systems; Results of IEA Collaboration; Conference
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Wind Energy: Grid Integration Challenges
REFERENCES (CONT’D)
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Authority); March 2005.
23. Finn, Dennis: Roping the Wind – Firming the Wind with Natural Gas; Douglas,
Wyoming, January 2008.
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Brunswick, Canada, April 2007.
25. Milligan, M: Modeling Utility-Scale Wind Power Plants Part 1: Economics; June 2000.
26. Electrotek Concepts: Characterizing the Impacts of Significant Wind Generation
Facilities on Bulk Power System Operations Planning – Xcel Energy – North Case
Study Final Report; May 2003.
27. Minnesota Transmission Owners: Dispersed Renewable Generation Transmission
Study – Volume I; Prepared for Minnesota Department of Commerce Office of Energy
Security, June 2008.
28. EnerNex Corporation, Zavadil, R: Wind Generation Technical Characteristics for the
NYSERDA Wind Impacts Study; November 2003.
29. Jorgenson, J, Mohrlen, C: AESO Wind Power Forecasting Pilot Project; Denmark, May
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